Safety Evaluation Report

Related to the License

Renewal of Fermi 2

Docket Number 50-341

DTE Electric Company

Office of Nuclear Reactor Regulation

NUREG-2210

 
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Safety Evaluation Report

Related to the License

Renewal of Fermi 2

Docket Number 50-341

DTE Electric Company

Manuscript Completed: October 2016

Date Published: December 2016

Office of Nuclear Reactor Regulation

NUREG-2210

iii 

ABSTRACT 

This safety evaluation report (SER) documents the technical review of the Fermi 2 Nuclear 

Power Plant (Fermi 2) license renewal application (LRA) by the U.S. Nuclear Regulatory 

Commission (NRC) staff (the staff). By letter dated April 24, 2014, DTE Electric Company (DTE 

or the applicant) submitted the LRA in accordance with Title 10 of the Code of Federal 

Regulations Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power 

Plants” (10 CFR Part 54). DTE requests renewal of the Fermi 2 operating license (Operating 

License No. NPF-43) for a period of 20 years beyond the current expiration at midnight on 

March 20, 2025. 

Fermi 2 is located on the western shore of Lake Erie at Lagoona Beach, Frenchtown Township, 

in Monroe County, Michigan. The NRC issued the operating license on March 20, 1985. 

Fermi 2 is a single-cycle, forced-circulation boiling water reactor (GE-BWR 4). General Electric 

Company (GE) furnished the nuclear steam supply system. Fermi 2’s licensed power output is 

3,486 megawatts thermal with a turbine-generator net electrical output of approximately 

1,170 megawatts electric. 

The decommissioned Enrico Fermi Atomic Power Plant (Fermi 1) is within the Fermi 2 Owner 

Controlled Area. Fermi 1 (Operating License No. DPR-9) was a sodium-cooled fast breeder 

reactor. It is permanently shut down, in SAFSTOR status. The nuclear fuel has been shipped 

offsite. 

This SER presents the status of the staff’s review of information submitted through 

May 30, 2016. The one open item identified in the SER with open items, issued 

January 28, 2016, has been closed (see Section 1.5); therefore, no open items remain to be 

resolved. On the basis of its review of the LRA, the staff determines that the requirements of 

10 CFR 54.29(a) have been met (see Section 5).

 

v 

TABLE OF CONTENTS 

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

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

LIST OF TABLES ........................................................................................................................ ix

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

INTRODUCTION AND GENERAL DISCUSSION ............................................. 1-1

1.1 Introduction ....................................................................................................................... 1-1

1.2 License Renewal Background ........................................................................................... 1-2

1.2.1 Safety Review ....................................................................................................... 1-3

1.2.2 Environmental Review ........................................................................................... 1-4

1.3 Principal Review Matters ................................................................................................... 1-5

1.4 Interim Staff Guidance ...................................................................................................... 1-6

1.5 Summary of Open Items ................................................................................................... 1-7

1.6 Summary of Confirmatory Items ....................................................................................... 1-8

1.7 Summary of Proposed License Conditions ....................................................................... 1-9

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW .................................................................................. 2-1

2.1 Scoping and Screening Methodology ............................................................................... 2-1

2.1.1 Introduction ............................................................................................................ 2-1

2.1.2 Summary of Technical Information in the Application ........................................... 2-1

2.1.3 Scoping and Screening Program Review .............................................................. 2-1

2.1.4 Plant Systems, Structures, and Components Scoping Methodology .................... 2-6

2.1.5 Screening Methodology ....................................................................................... 2-19

2.1.6 Summary of Evaluation Findings ......................................................................... 2-24

2.2 Plant-Level Scoping Results ........................................................................................... 2-24

2.2.1 Introduction .......................................................................................................... 2-24

2.2.2 Summary of Technical Information in the Application ......................................... 2-24

2.2.3 Staff Evaluation ................................................................................................... 2-25

2.2.4 Conclusion ........................................................................................................... 2-25

2.3 Scoping and Screening Results: Mechanical Systems .................................................. 2-25

2.3.1 Reactor Coolant System ..................................................................................... 2-26

2.3.2 Engineered Safety Features ................................................................................ 2-34

2.3.3 Auxiliary Systems ................................................................................................ 2-42

2.3.4 Steam and Power Conversion ............................................................................. 2-83

2.4 Scoping and Screening Results: Structures ................................................................... 2-92

2.4.1 Reactor/Auxiliary Building and Primary Containment .......................................... 2-93

2.4.2 Water-Cooled Structures ..................................................................................... 2-97

2.4.3 Turbine Building, Process Facilities, and Yard Structures .................................. 2-99

2.4.4 Bulk Commodities ............................................................................................. 2-101
 

vi 

2.4.5 Fire Barriers Portion of Bulk Commodities ........................................................ 2-102

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems ........................................................................................................................ 2-107

2.5.1 Electrical and Instrumentation and Control Components and Commodity 

Groups ............................................................................................................... 2-108

2.6 Conclusion for Scoping and Screening ......................................................................... 2-110

AGING MANAGEMENT REVIEW RESULTS .................................................... 3-1

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report ....................................... 3-1

3.0.1 Format of the License Renewal Application .......................................................... 3-2

3.0.2 Staff’s Review Process .......................................................................................... 3-3

3.0.3 Aging Management Programs ............................................................................... 3-7

3.0.4 QA Program Attributes Integral to Aging Management Programs .................... 3-192

3.0.5 Operating Experience for Aging Management Programs .................................. 3-195

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant System .......... 3-200

3.1.1 Summary of Technical Information in the Application ....................................... 3-200

3.1.2 Staff Evaluation ................................................................................................. 3-201

3.1.3 Conclusion ......................................................................................................... 3-247

3.2 Aging Management of Engineered Safety Features Systems ...................................... 3-247

3.2.1 Summary of Technical Information in the Application ....................................... 3-247

3.2.2 Staff Evaluation ................................................................................................. 3-247

3.2.3 Conclusion ......................................................................................................... 3-277

3.3 Aging Management of Auxiliary Systems ...................................................................... 3-277

3.3.1 Summary of Technical Information in the Application ....................................... 3-277

3.3.2 Staff Evaluation ................................................................................................. 3-277

3.3.3 Conclusion ......................................................................................................... 3-352

3.4 Aging Management of Steam and Power Conversion Systems ................................... 3-352

3.4.1 Summary of Technical Information in the Application ....................................... 3-353

3.4.2 Staff Evaluation ................................................................................................. 3-353

3.4.3 Conclusion ......................................................................................................... 3-379

3.5 Aging Management of Structures and Component Supports ........................................ 3-379

3.5.1 Summary of Technical Information in the Application ....................................... 3-380

3.5.2 Staff Evaluation ................................................................................................. 3-380

3.5.3 Conclusion ......................................................................................................... 3-436

3.6 Aging Management of Electrical and Instrumentation and Controls System ................ 3-436

3.6.1 Summary of Technical Information in the Application ....................................... 3-437

3.6.2 Staff Evaluation ................................................................................................. 3-437

3.6.3 Conclusion ......................................................................................................... 3-452

3.7 Conclusion for Aging Management Review Results ..................................................... 3-452

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

4.1 Identification of Time-Limited Aging Analyses .................................................................. 4-1

4.1.1 Summary of Technical Information in the Application ........................................... 4-2
 

vii 

4.1.2 Staff Evaluation ..................................................................................................... 4-3

4.1.3 Conclusion ........................................................................................................... 4-20

4.2 Reactor Vessel Neutron Embrittlement ........................................................................... 4-20

4.2.1 Reactor Vessel Fluence ...................................................................................... 4-20

4.2.2 Adjusted Reference Temperatures (ARTs) ......................................................... 4-22

4.2.3 Pressure-Temperature Limits .............................................................................. 4-27

4.2.4 Upper-Shelf Energy ............................................................................................. 4-29

4.2.5 Reactor Vessel Circumferential Weld Inspection Relief ...................................... 4-34

4.2.6 Reactor Vessel Axial Weld Failure Probability .................................................... 4-39

4.2.7 Reactor Pressure Vessel Core Reflood Thermal Shock Analysis ....................... 4-42

4.3 Metal Fatigue .................................................................................................................. 4-45

4.3.1 Class 1 Fatigue Analyses .................................................................................... 4-45

4.3.2 Non-Class 1 Fatigue Analyses ............................................................................ 4-56

4.3.3 Effects of Reactor Water Environment on Fatigue Life ....................................... 4-60

4.4 Environmental Qualification (EQ) Analyses of Electric Equipment ................................. 4-70

4.4.1 Summary of Technical Information in the Application ......................................... 4-70

4.4.2 Staff Evaluation ................................................................................................... 4-71

4.4.3 UFSAR Supplement ............................................................................................ 4-72

4.4.4 Conclusion ........................................................................................................... 4-72

4.5 Concrete Containment Tendon Prestress Analyses ....................................................... 4-72

4.5.1 Summary of Technical Information in the Application ......................................... 4-72

4.5.2 Staff Evaluation ................................................................................................... 4-73

4.5.3 UFSAR Supplement ............................................................................................ 4-73

4.5.4 Conclusion ........................................................................................................... 4-73

4.6 Containment Liner Plate, Metal Containment, and Penetrations Fatigue Analyses ........ 4-73

4.6.1 Primary Containment ........................................................................................... 4-73

4.6.2 Vent Line Bellows ................................................................................................ 4-78

4.6.3 Refueling and Drywell Seal Bellows .................................................................... 4-79

4.6.4 Traversing Incore Probe Penetration Bellows ..................................................... 4-81

4.6.5 Containment Penetrations ................................................................................... 4-82

4.7 Other Plant-Specific TLAAs ............................................................................................ 4-86

4.7.1 Erosion of the Main Steam Line Flow Restrictors ............................................... 4-86

4.7.2 Determination of High-Energy Line Break Locations .......................................... 4-88

4.7.3 Jet Pump Auxiliary Spring Wedge Assembly ...................................................... 4-90

4.7.4 Jet Pump Slip Joint Repair Clamps ..................................................................... 4-93

4.7.5 Flaw Evaluations for the Reactor Pressure Vessel ............................................. 4-95

4.7.6 Main Steam Bypass Lines Cumulative Operating Time ...................................... 4-97

4.7.7 Crane (Heavy Load) Cycles ................................................................................ 4-99

4.8 Conclusion for TLAAs ................................................................................................... 4-100
 

viii 

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS .................................................................................................. 5-1

CONCLUSION ................................................................................................... 6-1

APPENDICES 

FERMI 2 LICENSE RENEWAL COMMITMENTS ............................................ A-1

CHRONOLOGY ................................................................................................ B-1

PRINCIPAL CONTRIBUTORS ......................................................................... C-1

REFERENCES .................................................................................................. D-1
 

ix 

LIST OF TABLES 

Table 1.4-1 Current Interim Staff Guidance ........................................................................... 1-6

Table 2.3-1 Service Water System Piping Continuations Not within the Scope of 

License Renewal .............................................................................................. 2-48

Table 2.3-2 Emergency Diesel Generator System Piping Continuations Not within 

the Scope of License Renewal ......................................................................... 2-66

Table 2.3-3 Plant Drains System Piping Continuations Not within the Scope of 

License Renewal .............................................................................................. 2-71

Table 2.3-4 Plant Drains System Seismic or Equivalent Anchors Not within the 

Scope of License Renewal ............................................................................... 2-71

Table 2.3-5 Primary Containment Monitoring and Leakage Detection System Piping 

Continuations Not within the Scope of License Renewal ................................. 2-76

Table 2.3-6 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2) Piping 

Continuations Not within the Scope of License Renewal ................................. 2-79

Table 2.3-7 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2) Piping 

Continuations Not within the Scope of License Renewal ................................. 2-81

Table 2.3-8 Feedwater and Standby Feedwater System Piping Continuations Not 

within the Scope of License Renewal ............................................................... 2-86

Table 2.3-9 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License 

Renewal ........................................................................................................... 2-88

Table 2.3-10 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License 

Renewal ........................................................................................................... 2-90

Table 2.3-11 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License 

Renewal ........................................................................................................... 2-91

Table 2.3-12 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License 

Renewal ........................................................................................................... 2-91

Table 3.0-1 Fermi 2 Aging Management Programs ............................................................... 3-7

Table 3.1-1 Staff Evaluation for Reactor Vessel, Internals, and Reactor Coolant 

System Components in the GALL Report ...................................................... 3-202

Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems Components 

in the GALL Report ......................................................................................... 3-248

Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report ....... 3-279

Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems 

Components in the GALL Report ................................................................... 3-354

Table 3.5-1 Staff Evaluation for Structures and Component Supports Components 

in the GALL Report ......................................................................................... 3-381

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls in the 

GALL Report .................................................................................................. 3-438

Table 4.6.5-1 Transients Considered for Feedwater A/B Penetrations X-9A/B ...................... 4-83

 
 

x 

Table A.1-1 Appendix A: Fermi 2 License Renewal Commitments ..................................... A-2

Table B.1-1 Appendix B: Chronology ................................................................................... B-1

Table C.1-1 Appendix C: Principal Contributors.................................................................... C-1

Table D.1-1 References ........................................................................................................ D-1
 

xi 

ABBREVIATIONS 

AAI applicant action item 

AC alternating current 

ACI American Concrete Institute 

ACRS Advisory Committee on Reactor Safeguards 

ADAMS Agencywide Documents Access and Management System 

AERM aging effect requiring management 

AFW auxiliary feedwater 

AISC American Institute of Steel Construction 

AMP aging management program 

AMR aging management review 

ANSI American National Standards Institute 

APCSB Auxiliary Power Conversion System Branch 

ART adjusted reference temperature 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials 

ATWS anticipated transient without scram 

BDBEE beyond design basis external events 

BTP Branch Technical Position 

BWR boiling water reactor 

°C degrees Celsius 

CARD Condition Assessment Resolution Document 

CASS cast austenitic stainless steel 

CBF cycle-based fatigue 

CCHVAC Control Center heating, ventilation, and air conditioning 

CE Combustion Engineering Company 

CECO Central Component (database) 

CFR Code of Federal Regulations

CLB current licensing basis 

CO2 carbon dioxide 

CRD control rod drive 

CRT condensate return tank 

CST condensate storage tank 

CTG combustion turbine generator 

Cu copper 

CUF cumulative usage factor 

CUFen environmentally assisted fatigue cumulative usage factor 

DBA design basis accident 

DBE design basis event 

DC direct current 

DG diesel generator 

DO dissolved oxygen 

DTE DTE Electric Company 

EAF environmentally assisted fatigue 

ECCS emergency core cooling system 

EDG emergency diesel generator 
xii 

EDGSW emergency diesel generator service water 

EECW emergency equipment cooling water 

EESW emergency equipment service water 

EFPY effective full-power year 

EPRI Electric Power Research Institute 

EPU extended power uprate 

EQ environmental qualification 

ESF engineered safety features 

°F degrees Fahrenheit 

Fen environmentally assisted fatigue correction factor 

FERC Federal Energy Regulatory Commission 

Fermi 2 Fermi 2 Nuclear Power Plant 

FOST fuel oil storage tank 

FPCCS fuel pool cooling and cleanup system 

FPEE fire protection engineering evaluation 

FR Federal Register

FSAR final safety analysis report 

FSER final safety evaluation report 

ft foot (feet) 

ft-lb foot-pound 

FW feedwater 

GALL Generic Aging Lessons Learned (Report) 

GE General Electric Company 

GEH General Electric-Hitachi 

GEIS Generic Environmental Impact Statement 

GL generic letter 

gpm gallons per minute 

GSI generic safety issue 

GSW general service water 

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 controls 

I&E inspection and evaluation 

I&FE inspection and flaw evaluation 

IASCC irradiation-assisted stress corrosion cracking 

ID inside diameter 

IER Institute of Nuclear Power Operations Event Report 

IGSCC intergranular stress corrosion cracking 

ILRT integrated leak rate testing 

IN information notice 

INPO Institute of Nuclear Power Operations 

IPA integrated plant assessment 

ISG interim staff guidance 

ISI inservice inspection 

ISP integrated surveillance program 
 

xiii 

ksi kilopound per square inch 

KV or kV kilovolt 

lb pound(s) 

LBB leak-before-break 

LCO limiting condition of operation(s) 

LLRT local leakage rate testing 

LOCA loss-of-coolant accident 

LPCI low-pressure coolant injection 

LRA license renewal application 

LR-ISG license renewal interim staff guidance 

LTOP low-temperature overpressure protection 

μg/cm2 micrograms per centimeter squared 

MC metal containment 

MDCT mechanical draft cooling tower 

MEB metal enclosed bus 

MeV million electron volt(s) 

MoS2 molybdenum disulfide 

mpy mil(s) per year 

MSIV main steam isolation valve 

MUR measurement uncertainty recapture 

MUR/TPO measurement uncertainty recapture/thermal power optimization 

mV millivolt 

MWe megawatts electric 

MWt megawatts thermal 

n/cm2 neutrons per square centimeter 

NACE National Association of Corrosion Engineers 

NDE nondestructive examination 

NEI Nuclear Energy Institute 

NFPA National Fire Protection Association 

Ni nickel 

NPS nominal pipe size 

NRC U.S. Nuclear Regulatory Commission 

O2 oxygen 

OBE operating-basis earthquake 

ODSCC outside-diameter stress corrosion cracking 

PCAC primary containment atmosphere cooling 

PCM primary containment monitoring 

PCP primary containment pneumatics 

pH potential of hydrogen 

PM preventative maintenance 

PORV power-operated relief valve 

ppm parts per million 

psi pounds per square inch 

psig pound(s) per square inch gauge 

PSPM Periodic Surveillance and Preventive Maintenance 

P-T pressure-temperature 
xiv 

PTLR pressure-temperature limits report 

PTS pressurized thermal shock 

PVC polyvinyl chloride 

PWR pressurized water reactor 

PWSCC primary water stress corrosion cracking 

QA quality assurance 

radwaste radioactive waste 

RAI request for additional information 

RBCCW reactor building closed cooling water 

RCIC reactor core isolation cooling 

RCP reactor coolant pump 

RCPB reactor coolant pressure boundary 

RCS reactor coolant system 

RFO refueling outage 

RG regulatory guide 

RHR residual heat removal 

RHRSW residual heat removal service water 

RPV reactor pressure vessel 

RTNDT reference temperature nil ductility transition 

RVI reactor vessel internal 

RWCU reactor water cleanup 

SA stress allowables 

SBA small break accident 

SBO station blackout 

SBF stress-based fatigue 

SC structure and component 

SCC stress corrosion cracking 

scfh standard cubic feet per hour 

SE safety evaluation 

SER safety evaluation report 

SC structure and component 

SGTS standby gas treatment system 

SLC standby liquid control 

SLC/core ∆P standby liquid control system/core ∆P 

S-N stress-number 

S&PC steam and power conversion 

SRP Standard Review Plan 

SRP-LR Standard Review Plan for Review of License Renewal Applications for 

Nuclear Power Plants 

SRV safety relief value 

SSC system, structure, and component 

SSE safe-shutdown earthquake 

TIP traversing incore probe 

TLAA time-limited aging analysis 

TR Technical Report 

TRM Technical Requirements Manual 

TS Technical Specification(s) 
 

xv 

UFSAR updated final safety analysis report 

USE upper-shelf energy 

UT ultrasonic testing 

UUSE unirradiated upper-shelf energy 

UV ultraviolet 

V volt(s) 

VAC volts alternating current 

VDC volts direct current 

yr year 

Zn zinc 

1/4 T one-fourth of the way through the vessel wall measured from the internal 

surface of the vessel 

1-1 

 

INTRODUCTION AND GENERAL DISCUSSION 

1.1 Introduction 

This document is a safety evaluation report (SER) on the license renewal application (LRA) for 

Fermi 2 Nuclear Power Plant (Fermi 2) as filed by DTE Electric Company (DTE, or the 

applicant). By letter dated April 24, 2014, DTE submitted its application to the U.S. Nuclear 

Regulatory Commission (NRC) for renewal of the Fermi 2 operating license for an additional 

20 years. The NRC staff (the staff) prepared this report to summarize the results of its safety 

review of the LRA for compliance with Title 10, Part 54, “Requirements for Renewal of 

Operating Licenses for Nuclear Power Plants,” of the Code of Federal Regulations

(10 CFR Part 54). The NRC project managers for the license renewal review are Ms. Daneira 

Meléndez-Colón and Ms. Lois James. Ms. Meléndez-Colón may be contacted by telephone at 

301-415-3301 or by electronic mail at Daneira.Melendez-Colon@nrc.gov. Ms. James may be 

contacted by telephone at 301-415-3306 or by electronic mail at Lois.James@nrc.gov. 

Alternatively, written correspondence may be sent to the following address: 

Division of License Renewal 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

Attention: Daneira Meléndez-Colón, Mail Stop O11-F1 

Lois James, Mail Stop O11-F1 

In its April 24, 2014, submission letter, as amended, the applicant requested renewal of the 

operating license issued under Section 103 (Operating License No. NPF-43) of the Atomic 

Energy Act of 1954, as amended, for Fermi 2 for a period of 20 years beyond the current 

expiration at midnight on March 20, 2025. Fermi 2 is located on the western shore of Lake Erie 

at Lagoona Beach, Frenchtown Township, in Monroe County, Michigan. The NRC issued the 

operating license on March 20, 1985. Fermi 2 is a single-cycle, forced-circulation boiling water 

reactor (GE-BWR 4). General Electric Company (GE) furnished the nuclear steam supply 

system. Fermi 2’s licensed power output is 3,486 megawatts thermal with a turbine-generator 

net electrical output of approximately 1,170 megawatts electric. The updated final safety 

analysis report (UFSAR) shows details of the plant and the site. 

The license renewal process consists of two concurrent reviews, a review of safety issues and 

an environmental review. The NRC regulations in 10 CFR Part 54 and 10 CFR Part 51, 

“Environmental Protection Regulations for Domestic Licensing and Related Regulatory 

Functions,” respectively, set forth requirements for these reviews. The safety review for the 

Fermi 2 license renewal is based on the applicant’s LRA and responses to the staff’s requests 

for additional information (RAIs). The applicant supplemented the LRA and provided 

clarifications through its responses to the staff’s RAIs in audits, meetings, and docketed 

correspondence. The staff reviewed and considered information submitted through 

May 30, 2016. The public may view the LRA and all pertinent information and materials, 

including the UFSAR, at the NRC Public Document Room located on the first floor of One White 

Flint North, 11555 Rockville Pike, Rockville, MD 20852-2738 (301-415-4737/800-397-4209), 

and at the Ellis Library and Reference Center, 3700 South Custer Road, Monroe, MI 48161. In 

addition, the public may find the LRA, as well as materials related to the license renewal review, 

on the NRC website at http://www.nrc.gov. 
1-2 

This SER summarizes the results of the staff’s safety review of the LRA and describes the 

technical details considered in evaluating the safety aspects of the unit’s proposed operation for 

an additional 20 years beyond the term of the current operating license. The staff reviewed the 

LRA in accordance with NRC regulations and the guidance in NUREG-1800, Revision 2, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants” 

(SRP-LR), dated December 2010. 

SER Sections 2 through 4 address the staff’s evaluation of license renewal issues considered 

during the review of the application. SER Section 5 is reserved for the report of the Advisory 

Committee on Reactor Safeguards (ACRS). The conclusions of this SER are in Section 6. 

SER Appendix A is a table showing the applicant’s commitments for renewal of the operating 

license. SER Appendix B is a chronology of the principal correspondence between the staff and 

the applicant regarding the LRA review. SER Appendix C is a list of principal contributors to the 

SER and Appendix D is a bibliography of the references in support of the staff’s review. 

In accordance with 10 CFR Part 51, the staff prepared a draft plant-specific supplement to 

NUREG-1437, “Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants (GEIS)” (“Generic Environmental Impact Statement for License Renewal of Nuclear 

Plants: Supplement 56 Regarding Fermi 2 Nuclear Power Plant,” issued October 27, 2015). 

This supplement discusses the environmental considerations for license renewal for Fermi 2. 

The final, plant-specific GEIS Supplement 56 is scheduled to be issued in 2016. 

1.2 License Renewal Background 

Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating 

licenses for commercial power reactors are issued for 40 years and can be renewed for up to 

20 additional years. The original 40-year license term was selected based on economic and 

antitrust considerations rather than on technical limitations; however, some individual plant and 

equipment designs may have been engineered for an expected 40-year service life. 

In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power 

plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear 

plant aging research. From the results of that research, a technical review group concluded that 

many aging phenomena are readily manageable and pose no technical issues precluding life 

extension for nuclear power plants. In 1986, the staff published a request for comment on a 

policy statement that would address major policy, technical, and procedural issues related to 

license renewal for nuclear power plants. 

In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56, 

page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The staff 

participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot 

plant and to gain the experience necessary to develop implementation guidance. To establish a 

scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to 

license renewal; however, during the demonstration program, the staff found that adverse aging 

effects on plant systems and components are managed during the period of initial license and 

that the scope of the review did not allow sufficient credit for management programs, particularly 

the implementation of 10 CFR 50.65, “Requirements for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants,” which regulates management of plant-aging 

phenomena. As a result of this finding, the staff amended 10 CFR Part 54 in 1995. As 

published May 8, 1995, in 60 FR 22461, amended 10 CFR Part 54 establishes a regulatory 
 

1-3 

process that is simpler, more stable, and more predictable than the previous 10 CFR Part 54. 

In particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging 

effects rather than on the identification of age-related degradation unique to license renewal. 

The staff made these rule changes to ensure that important systems, structures, and 

components (SSCs) will continue to perform their intended functions during the period of 

extended operation. In addition, the amended 10 CFR Part 54 clarifies and simplifies the 

integrated plant assessment process to be consistent with the revised focus on passive, 

long-lived structures and components (SCs). 

Concurrent with these initiatives, the staff pursued a separate rulemaking effort (61 FR 28467, 

June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the review of environmental 

impacts of license renewal in order to fulfill NRC responsibilities under the National 

Environmental Policy Act of 1969. 

1.2.1 Safety Review 

License renewal requirements for power reactors are based on two key principles: 

(1) The regulatory process is adequate to ensure that the licensing bases of all currently 

operating plants maintain an acceptable level of safety with the possible exceptions of 

the detrimental aging effects on the functions of certain SSCs, as well as a few other 

safety-related issues, during the period of extended operation. 

(2) The plant-specific licensing basis must be maintained during the renewal term in the 

same manner and to the same extent as during the original licensing term. 

In implementing these two principles, 10 CFR 54.4, “Scope,” defines the scope of license 

renewal as including those SSCs that (1) are safety-related, (2) whose failure could affect 

safety-related functions, or (3) are relied on to demonstrate compliance with the NRC’s 

regulations for fire protection, environmental qualification (EQ), pressurized thermal shock 

(PTS), anticipated transient without scram (ATWS), and station blackout (SBO). 

In accordance with 10 CFR 54.21(a), a license renewal applicant must review all SSCs within 

the scope of 10 CFR Part 54 to identify SCs subject to an aging management review (AMR). 

Those SCs subject to an AMR perform an intended function without moving parts or without 

change in configuration or properties and are not subject to replacement based on a qualified 

life or specified time period. In accordance with 10 CFR 54.21(a), a license renewal applicant 

must demonstrate that the aging effects will be managed so that the intended function(s) of 

those SCs will be maintained consistent with the current licensing basis (CLB) for the period of 

extended operation. However, active equipment is considered to be adequately monitored and 

maintained by existing programs. In other words, detrimental aging effects that may affect 

active equipment can be readily identified and corrected through routine surveillance, 

performance monitoring, and maintenance. Surveillance and maintenance programs for active 

equipment, as well as other maintenance aspects of plant design and licensing basis, are 

required throughout the period of extended operation. 

In accordance with 10 CFR 54.21(d), the LRA is required to include a UFSAR supplement with 

a summary description of the applicant’s programs and activities for managing the effects of 

aging and an evaluation of time-limited aging analyses (TLAAs) for the period of extended 

operation. 
1-4 

License renewal also requires TLAA identification and updating. During the plant design phase, 

certain assumptions about the length of time the plant can operate are incorporated into design 

calculations for several plant SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must 

either show that these calculations will remain valid for the period of extended operation, project 

the analyses to the end of the period of extended operation, or demonstrate that the aging 

effects on these SSCs will be adequately managed for the period of extended operation. 

In 2005, the NRC revised Regulatory Guide (RG) 1.188, “Standard Format and Content for 

Applications to Renew Nuclear Power Plant Operating Licenses.” This RG endorses Nuclear 

Energy Institute (NEI) 95-10, Revision 6, “Industry Guideline for Implementing the Requirements 

of 10 CFR Part 54 – The License Renewal Rule,” dated June 2005. NEI 95-10 details an 

acceptable method of implementing 10 CFR Part 54. The staff used the SRP-LR to review the 

LRA. 

In the LRA, the applicant stated that it used the process defined in NUREG-1801, Revision 2, 

“Generic Aging Lessons Learned (GALL) Report,” dated December 2010. The GALL Report 

summarizes staff-approved aging management programs (AMPs) for many SCs subject to an 

AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and 

resources for LRA review can be greatly reduced, improving the efficiency and effectiveness of 

the license renewal review process. The GALL Report summarizes the aging management 

evaluations, programs, and activities credited for managing aging for most of the SCs used 

throughout the industry. The report is also a quick reference for both applicants and staff 

reviewers to AMPs and activities that can manage aging adequately during the period of 

extended operation. 

1.2.2 Environmental Review 

Part 51 of 10 CFR contains environmental protection regulations. In December 1996, the staff 

revised the environmental protection regulations to facilitate the environmental review for 

license renewal. The staff prepared the GEIS to document its evaluation of possible 

environmental impacts associated with nuclear power plant license renewals. For certain types 

of environmental impacts, the GEIS contains generic findings that apply to all nuclear power 

plants and are codified in Appendix B, “Environmental Effect of Renewing the Operating License 

of a Nuclear Power Plant,” to Subpart A, “National Environmental Policy Act – Regulations 

Implementing Section 102(2),” of 10 CFR Part 51. In accordance with 10 CFR 51.53(c)(3)(i), a 

license renewal applicant may incorporate these generic findings in its environmental report. In 

accordance with 10 CFR 51.53(c)(3)(ii), an environmental report also must include analyses of 

environmental impacts that must be evaluated on a plant-specific basis (i.e., Category 2 issues). 

In June 2013, the NRC staff issued a final rule revising 10 CFR Part 51 to update the potential 

environmental impacts associated with the renewal of an operating license for a nuclear power 

reactor for an additional 20 years. Revision 1 to the GEIS was issued concurrently with the final 

rule. The revised GEIS specifically supports the revised list of environmental issues identified in 

the final rule. Revision 1 to the GEIS and the 2013 final rule reflect lessons learned and 

knowledge gained during previous license renewal environmental reviews. 

In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the staff 

reviewed the plant-specific environmental impacts of license renewal, including whether there 

was new and significant information not considered in the GEIS. As part of its scoping process, 

the staff held a public meeting on July 24, 2014, at the Monroe County Community College, in 

Monroe, Michigan, to identify plant-specific environmental issues. The draft, plant-specific GEIS 
 

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Supplement 56 documents the results of the environmental review and makes a preliminary 

recommendation on the license renewal action. The staff held another public meeting on 

December 2, 2015, at the Monroe County Community College in Monroe, Michigan, to discuss 

the draft, plant-specific GEIS Supplement 56. After considering comments on the draft, the staff 

will publish the final, plant-specific GEIS Supplement 56 separately from this report. 

1.3 Principal Review Matters 

Part 54 of 10 CFR describes the requirements for renewal of operating licenses for nuclear 

power plants. The staff’s technical review of the LRA was in accordance with NRC guidance 

and 10 CFR Part 54 requirements. Section 54.29, “Standards for Issuance of a Renewed 

License,” of 10 CFR sets forth the license renewal standards. This SER describes the results of 

the staff’s safety review. 

In accordance with 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit 

general information, which the applicant provided in LRA Section 1. The staff reviewed LRA 

Section 1 and finds that the applicant has submitted the required information. 

In accordance with 10 CFR 54.19(b), the NRC requires that the LRA include “conforming 

changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the 

expiration term of the proposed renewed license.” On this issue, the applicant stated in the 

LRA: 

10 CFR 54.19(b) requires that license renewal applications “... include 

conforming changes to the standard indemnity agreement, 10 CFR 140.92, 

Appendix B, to account for the expiration term of the proposed renewed license.” 

Item 3 of the Attachment to the current indemnity agreement (No. B-20) for 

Fermi 2, as revised by Amendment No. 27, lists Fermi 2 facility operating license 

number NPF-43 with no expiration date for the license. Therefore, no changes to 

the indemnity agreement are deemed necessary as part of this application. 

Should the license number be changed by NRC upon issuance of the renewed 

license, DTE requests that NRC amend the indemnity agreement to include 

conforming changes to Item 3 of the attachment and other affected sections of 

the agreement. 

The staff intends to maintain the original license number upon issuance of the renewed license, 

if approved. Therefore, conforming changes to the indemnity agreement need not be made and 

the 10 CFR 54.19(b) requirements have been met. 

In accordance with 10 CFR 54.21, “Contents of Application – Technical Information,” the NRC 

requires that the LRA contain (a) an integrated plant assessment, (b) a description of any CLB 

changes during the staff’s review of the LRA, (c) an evaluation of TLAAs, and (d) a UFSAR 

supplement. LRA Sections 3 and 4 and Appendix B address the license renewal requirements 

of 10 CFR 54.21(a), (b), and (c). LRA Appendix A satisfies the license renewal requirements of 

10 CFR 54.21(d). 

In accordance with 10 CFR 54.21(b), the NRC requires that, each year following submission of 

the LRA and at least 3 months before the scheduled completion of the staff’s review, the 

applicant submit an LRA amendment identifying any CLB changes to the facility that affect the 

contents of the LRA, including the UFSAR supplement. By letter dated May 9, 2016, the 
1-6 

applicant submitted an LRA update that summarizes the CLB changes that have occurred 

during the staff’s review of the LRA. This submission satisfies 10 CFR 54.21(b) requirements. 

In accordance with 10 CFR 54.22, “Contents of Application – Technical Specifications,” the 

NRC requires that the LRA include changes or additions to the Technical Specifications (TS) 

that are necessary to manage aging effects during the period of extended operation. In LRA 

Appendix D, the applicant stated that it had not identified any TS changes necessary for 

issuance of the renewed Fermi 2 operating license. This statement adequately addresses the 

10 CFR 54.22 requirement. 

The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in 

accordance with NRC regulations and SRP-LR guidance. SER Sections 2, 3, and 4 document 

the staff’s evaluation of the LRA technical information. 

As required by 10 CFR 54.25, “Report of the Advisory Committee on Reactor Safeguards,” the 

ACRS will issue a report documenting its evaluation of the staff’s LRA review and SER. SER 

Section 5 is reserved for the ACRS report when it is issued. SER Section 6 documents the 

findings required by 10 CFR 54.29. 

1.4 Interim Staff Guidance 

License renewal is a living program. The staff, industry, and other interested stakeholders gain 

experience and develop lessons learned with each renewed license. The lessons learned 

address the staff’s performance goals of maintaining safety, improving effectiveness and 

efficiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance 

(ISG) is documented for use by the staff, industry, and other interested stakeholders until 

incorporated into such license renewal guidance documents as the SRP-LR and GALL Report. 

Table 1.4-1 shows the current set of ISGs, as well as the SER sections in which the staff 

addresses them. 

Table 1.4-1 Current Interim Staff Guidance 

ISG Issue 

(Approved ISG Number) Purpose SER Section 

“Aging Management of Stainless 

Steel Structures and Components in 

Treated Borated Water,” Revision 1 

(LR-ISG-2011-01) 

This LR-ISG clarifies the staff’s 

existing position on aging 

management in treated borated water 

environments. 

Not applicable for the SER 

“Aging Management Program for 

Steam Generators” 

(LR-ISG-2011-02) 

This LR-ISG evaluates the suitability 

of using Revision 3 of NEI 97-06 for 

implementing the licensee’s steam 

generator aging management 

program. 

Not applicable to BWRs 

“Changes to the Generic Aging 

Lessons Learned (GALL) Report 

Revision 2 AMP XI.M41, ‘Buried and 

Underground Piping and Tanks’” 

(LR-ISG-2011-03) 

This LR-ISG gives additional 

guidance on managing the effects of 

aging on buried and underground 

piping and tanks. 

SER Sections 3.0.3.1.2 and 3.0.3.2.7
 

1-7 

ISG Issue 

(Approved ISG Number) Purpose SER Section 

“Updated Aging Management Criteria 

for Reactor Vessel Internal 

Components of Pressurized Water 

Reactors” 

(LR-ISG-2011-04) 

This LR-ISG updates the GALL 

Report, Revision 2, and SRP-LR, 

Revision 2, to ensure consistency 

with MRP-227-A for the aging 

management of age-related 

degradation for components of 

pressurized water reactor vessel 

internal components during the term 

of a renewed operating license. 

Not applicable to BWRs 

“Ongoing Review of Operating 

Experience” 

(LR-ISG-2011-05) 

This LR-ISG clarifies the staff’s 

existing position in the SRP-LR that 

acceptable license renewal AMPs 

should be informed and enhanced 

when necessary, based on the 

ongoing review of both plant-specific 

and industry operating experience. 

SER Section 3.0.5.2 

“Wall Thinning Due to Erosion 

Mechanisms” 

(LR-ISG-2012-01) 

This LR-ISG gives additional 

guidance on managing the effects of 

wall thinning due to erosion 

mechanisms. 

SER Section 3.0.3.2.11 

“Aging Management of Internal 

Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and 

Corrosion Under Insulation” 

(LR-ISG-2012-02) 

This LR-ISG gives guidance on 

managing the effects of aging for 

internal surfaces, fire water system, 

atmospheric storage tanks, and 

corrosion under insulation. 

SER Sections 3.0.3.1.1, 3.0.3.1.11, 

3.0.3.2.7, 3.0.3.2.10, 3.0.3.3.1, 

3.3.2.1.14, and 3.3.2.3.3 

“Aging Management of Loss of 

Coating or Lining Integrity for Internal 

Coatings/Linings on In-Scope Piping, 

Piping Components, Heat 

Exchangers, and Tanks” 

(LR-ISG-2013-01) 

This LR-ISG gives guidance on aging 

management for coating or lining 

integrity for internal coatings/linings 

on in-scope piping, piping 

components, heat exchangers, and 

tanks. 

SER Sections 3.0.3.2.24, 3.2.2.3.2, 

3.3.2.1.1, 3.3.2.3.3, and 3.4.2.3.3 

“Changes to Buried and Underground 

Piping and Tank Recommendations” 

(LR-ISG-2015-01) 

This LR-ISG replaces GALL Report 

AMP XI.M41, “Buried and 

Underground Piping and Tanks,” and 

the associated final safety analysis 

report summary description. The 

LR-ISG provides revised guidance on 

managing aging effects associated 

with buried and underground piping 

and tanks. 

SER Section 3.0.3.1.2 

1.5 Summary of Open Items 

As a result of its review of the LRA, including additional information submitted through 

May 30, 2016, the staff closed the following open item previously identified in the “Safety 

Evaluation Report with Open Items Related to the License Renewal of Fermi 2,” dated 

January 28, 2016 (Agencywide Documents Access and Management System (ADAMS) 

Accession No. ML16020A440). No other open items remain to be addressed. An item is 

considered open if, in the staff’s judgment, it does not meet all applicable regulatory 

requirements at the time of the issuance of this SER. A summary of the basis for the open item 

closure is presented here. 
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Open Item 4.3.3-1 Effects of Reactor Water Environment on Fatigue Life 

By letter dated September 24, 2015, the applicant provided its response to RAI 4.3.3-3. In this 

letter, the applicant stated that there are locations where the environmentally assisted fatigue 

(EAF) correction factors (Fen) were recalculated using average transient temperatures or 

maximum operating temperatures. The RAI 4.3.3-3 response also states that these Fen factors 

were recalculated in a manner consistent with NUREG/CR-6909, “Effect of LWR Coolant 

Environments on the Fatigue Life of Reactor Materials.” 

The staff and applicant held a telephone conference call on December 15, 2015, to discuss and 

clarify the applicant’s response to RAI 4.3.3-3. Specifically, the topic of the telephone 

conference was to clarify the manner in which the average temperatures were calculated to 

confirm consistency with NUREG/CR-6909. During the telephone conference call, the applicant 

described the methods used to calculate average temperatures. Based on these descriptions, 

the staff determined that the applicant’s average temperature calculations were not always 

consistent with the guidance in NUREG/CR-6909 when the minimum temperature is below the 

temperature threshold for a given material. This may result in the underestimation of both the 

Fen factors and the resulting EAF cumulative usage factors (CUFen) for some locations. A 

summary of the telephone conference is provided in the NRC’s letter dated January 8, 2016 

(ADAMS Accession No. ML16005A399). By letter dated January 14, 2016, the staff issued 

RAI 4.3.3-3a requesting that the applicant assess the impact of revising the evaluations to use 

the correct determination of average temperature in a manner consistent with NUREG/CR-6909 

and submit a description of the impact of this revision to the previous screening and Fen

evaluation results for staff review. The staff stated that the assessment should include a 

description of whether the revised average temperature calculations impact the selection of 

sentinel locations. 

By letter dated March 10, 2016, the applicant provided its response to RAI 4.3.3-3a. The NRC 

staff finds that the applicant has demonstrated that, pursuant to 10 CFR 54.21(c)(1)(iii), the 

effects of environmentally assisted fatigue due to the reactor water environment on the intended 

functions of the American Society of Mechanical Engineers (ASME) Class 1 reactor pressure 

vessel boundary will be adequately managed for the period of extended operation. Additionally, 

it meets the acceptance criteria in SRP-LR Section 4.3.2.1.3 because the applicant has 

addressed the staff recommendation for the closure of GSI-190, “Fatigue Evaluation of Metal 

Components for 60-Year Plant Life.” The applicant has identified high-fatigue usage locations, 

including those in NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to 

Selected Nuclear Power Plant Components,” and has evaluated these locations using the 

formulas, fatigue curves, and guidance in NUREG/CR-6909. The applicant is managing the 

effects of cumulative fatigue damage on the intended functions of the applicable components 

using the Fatigue Monitoring Program. The staff’s review of the Fatigue Monitoring Program 

appears in SER Section 3.0.3.2.8. Open Item 4.3.3-1 is closed. 

1.6 Summary of Confirmatory Items 

As a result of its review of the LRA, including additional information submitted through 

May 30, 2016, the staff determines that no confirmatory items exist that would require a formal 

response from the applicant. 
 

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1.7 Summary of Proposed License Conditions 

Following the staff’s review of the LRA, including subsequent information and clarifications from 

the applicant, the staff identified three proposed license conditions. 

License Condition No. 1: 

The information in the UFSAR supplement, submitted pursuant to 10 CFR 54.21(d), as revised 

during the license renewal application review process, and licensee commitments as listed in 

Appendix A to the “Safety Evaluation Report Related to the License Renewal of Fermi 2,” are 

collectively the “License Renewal UFSAR Supplement.” This supplement is henceforth part of 

the UFSAR which will be updated in accordance with 10 CFR 50.71(e). As such, the licensee 

may make changes to the programs, activities, and commitments described in this Supplement, 

provided the licensee evaluates such changes pursuant to the criteria set forth in 10 CFR 50.59, 

“Changes, Tests and Experiments,” and otherwise complies with the requirements in that 

section. 

License Condition No. 2: 

The License Renewal UFSAR Supplement, as updated by license condition [1] above, 

describes certain programs to be implemented and activities to be completed before the period 

of extended operation, as follows: 

(a) The applicant shall implement those new programs and enhancements to existing 

programs no later than 6 months prior to the period of extended operation [PEO]. 

(b) The applicant shall complete those activities by the 6-month date before the PEO or the 

end of the last refueling outage prior to the PEO, whichever occurs later. 

The applicant shall notify the NRC in writing within 30 days after having accomplished item (a) 

above and include the status of those activities that have been or remain to be completed in 

item (b) above. 

License Condition No. 3: 

DTE shall fully implement the Boraflex rack replacement approved in Amendment No. 141 

before the period of extended operation (i.e., March 20, 2025), so that the Boraflex material in 

the spent fuel pool will not be required to perform a neutron absorption function. DTE shall 

submit a letter to the NRC, within 60 days following completion of the removal of the Boraflex 

material and installation of the Boral material, as described in Amendment No. 141, confirming 

the removal of the Boraflex material and discontinued reliance on its neutron absorption 

function. 

2-1 

 

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW 

2.1 Scoping and Screening Methodology 

2.1.1 Introduction 

Title 10, Section 54.21, “Contents of Application – Technical Information,” of the Code of 

Federal Regulations (10 CFR 54.21), requires the applicant to identify the structures, systems, 

and components (SSCs) within the scope of license renewal in accordance with 

10 CFR 54.4(a). In addition, the license renewal application (LRA) must contain an integrated 

plant assessment (IPA) that identifies and lists those structures and components (SCs), 

contained in the SSCs identified to be within the scope of license renewal, that are subject to an 

aging management review (AMR). 

2.1.2 Summary of Technical Information in the Application 

LRA Section 2.0, “Scoping and Screening Methodology for Identifying Structures and 

Components Subject to Aging Management Review and Implementation Results,” provides the 

technical information required by 10 CFR 54.21(a). LRA Section 2.0 states, in part, that the 

applicant had considered the following in developing the scoping and screening methodology 

described in LRA Section 2.0: 

 Part 54 of 10 CFR, “Requirements for Renewal of Operating Licenses for Nuclear Power 

Plants” (the Rule) 

 Nuclear Energy Institute (NEI) 95-10, Revision 6, “Industry Guideline for Implementing 

the Requirements of 10 CFR Part 54 – The License Renewal Rule,” dated June 2005 

(NEI 95-10) 

LRA Section 2.1, “Scoping and Screening Methodology,” describes the methodology used by 

DTE Electric Company (DTE or the applicant) to identify the SSCs at Fermi 2 within the scope 

of license renewal (scoping) and the SCs subject to an AMR (screening). 

2.1.3 Scoping and Screening Program Review 

The U.S. Nuclear Regulatory Commission (NRC or the staff) evaluated the applicant’s scoping 

and screening methodology in accordance with the guidance in NUREG-1800, Revision 2, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants” 

(SRP-LR), Section 2.1, “Scoping and Screening Methodology.” The following regulations 

provide the basis for the acceptance criteria that the staff used to assess the adequacy of the 

scoping and screening methodology the applicant used to develop the LRA: 

 10 CFR 54.4(a), as it relates to the identification of SSCs within the scope of the Rule 

 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs within 

the scope of the Rule 
2-2 

 10 CFR 54.21(a), as it relates to the methods used by the applicant to identify plant SCs 

subject to an AMR 

The staff reviewed the information in LRA Section 2.1 to confirm that the applicant described a 

process for identifying SSCs that are within the scope of license renewal in accordance with 

10 CFR 54.4(a) and for identifying SCs that are subject to an AMR in accordance with 

10 CFR 54.21(a). 

In addition, the staff conducted a scoping and screening methodology audit at the Fermi 2 

facility located in Monroe County, Michigan, during the week of August 4-7, 2014. The audit 

focused on ensuring that the applicant had developed and implemented adequate guidance to 

conduct the scoping and screening of SSCs in accordance with the methodology described in 

the LRA and with the requirements of the Rule. The staff reviewed the project-level guidelines, 

technical basis documents, and implementing procedures that described the applicant’s scoping 

and screening methodology. The staff conducted detailed discussions with the applicant on the 

implementation and control of the license renewal methodology, the quality practices used by 

the applicant during the LRA development, and the training of the applicant’s staff that 

participated in the LRA development. 

On a sampling basis, the staff performed a review of scoping and screening results reports and 

supporting current licensing basis (CLB) information for portions of the emergency equipment 

service water (EESW) system and residual heat removal (RHR) complex support equipment 

and corresponding structures. In addition, the staff performed walkdowns of selected portions 

of those systems and structures as a part of the sampling review of the implementation of the 

applicant’s 10 CFR 54.4(a)(2) scoping methodology. 

2.1.3.1 Implementation Procedures and Documentation Sources Used for Scoping and 

Screening 

 Summary of Technical Information in the Application 

The applicant had developed implementing procedures used to identify SSCs within the scope 

of license renewal and SCs subject to an AMR to implement the processes described in LRA 

Sections 2.0 and 2.1. Additionally, the applicant’s implementing procedures provided guidance 

on the review and consideration of CLB documentation sources relative to the requirements in 

10 CFR 54.4, “Scope” and 10 CFR 54.21. 

LRA Section 2.1 listed the following information sources for the license renewal scoping and 

screening process: 

 Fermi 2 Central Component (CECO) database 

 updated final safety analysis report (UFSAR) 

 maintenance rule basis documents 

 design basis documents 

 fire hazards analysis 

 safe shutdown analysis 

 station drawings 
2-3 

 Staff Evaluation 

Scoping and Screening Implementation Procedures. The staff reviewed the applicant’s scoping 

and screening methodology implementing procedures, including license renewal guidelines, 

documents, and reports, as documented in the staff’s audit report, to ensure that the guidance is 

consistent with the requirements of the Rule, the SRP-LR, and Regulatory Guide (RG) 1.188, 

“Standard Format and Content for Applications to Renew Nuclear Plant Operating Licenses,” 

Revision 1, dated September 2005, which endorses the use of NEI 95-10. The staff determined 

that the overall process used to implement the 10 CFR Part 54 requirements described in the 

implementing procedures, including license renewal guidelines, documents, and reports, is 

consistent with the Rule, the SRP-LR, and the endorsed industry guidance. 

The applicant’s implementing procedures contain guidance for determining plant SSCs within 

the scope of the Rule and for determining SCs contained in systems within the scope of license 

renewal that are subject to an AMR. During the review of the implementing procedures, the 

staff focused on the consistency of the detailed procedural guidance with information in the 

LRA, including the implementation of the staff’s positions documented in the SRP-LR, and with 

information in the applicant’s responses, dated November 18, 2014, to the staff’s requests for 

additional information (RAIs), dated October 20, 2014. After reviewing the LRA and supporting 

documentation, the staff determined that the scoping and screening methodology instructions 

are consistent with the methodology description provided in LRA Section 2.1. The staff also 

determined that the methodology is sufficiently detailed in the implementing procedures to 

provide concise guidance on the scoping and screening process to be followed during the LRA 

activities. 

Sources of Current Licensing Basis Information. The regulation at 10 CFR Part 54.21(a)(3) 

requires, for each SC determined to be subject to an AMR, the applicant to demonstrate that the 

effects of aging will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation. The regulation at 

10 CFR Part 54.3(a) defines the CLB, in part, as the set of NRC requirements applicable to a 

specific plant and a licensee’s written commitments for ensuring compliance with, and operation 

within, applicable NRC requirements and the plant-specific design bases that are docketed and 

in effect. The CLB includes applicable NRC regulations, orders, license conditions, exemptions, 

technical specifications, and design basis information (documented in the most recent UFSAR). 

The CLB also includes licensee commitments remaining in effect that were made in docketed 

licensing correspondence, such as licensee responses to NRC bulletins, generic letters, and 

enforcement actions, and licensee commitments documented in NRC safety evaluations or 

licensee event reports. The staff considered the scope and depth of the applicant’s CLB review 

to verify that the methodology is sufficiently comprehensive to identify SSCs within the scope of 

license renewal and as SCs that are subject to an AMR. 

During the scoping and screening methodology audit, the staff confirmed that the applicant’s 

detailed license renewal program guidelines specified the use of the CLB source information in 

developing scoping evaluations. The staff reviewed pertinent information sources used by the 

applicant including the Fermi 2 CECO database, the UFSAR, maintenance rule basis 

documents, design basis documents, fire hazards analysis, safe shutdown analysis, and station 

drawings. 

During the audit, the staff discussed the applicant’s administrative controls for the CECO 

database and the other information sources used to verify system information. These controls 

are described and implemented by plant procedures. Based on a review of the administrative 
2-4 

controls and on a sample of the system classification information contained in the applicable 

documentation, the staff determined that the applicant has established adequate measures to 

control the integrity and reliability of system identification and safety classification data; 

therefore, the staff determined that the information sources used by the applicant during the 

scoping and screening process provided a controlled source of system and component data to 

support scoping and screening evaluations. 

In addition, the staff reviewed the implementing procedures and results reports used to support 

identification of SSCs that the applicant relied on to demonstrate compliance with the 

requirements of 10 CFR 54.4(a). The applicant’s license renewal program guidelines provided 

a listing of documents used to support scoping evaluations. The staff determined that the 

design documentation sources, required to be used by the applicant’s implementing procedures, 

provided sufficient information to ensure that the applicant identified SSCs to be included within 

the scope of license renewal consistent with the plant’s CLB. 

 Conclusion 

Based on its review of LRA Sections 2.0 and 2.1, the scoping and screening implementing 

procedures, and the results from the scoping and screening audit, the staff concludes that the 

applicant’s use of implementing procedures and consideration of document sources, including 

CLB information, is consistent with the Rule, the SRP-LR, and NEI 95-10 guidance and, 

therefore, is acceptable. 

2.1.3.2 Quality Controls Applied to License Renewal Application Development 

 Staff Evaluation 

The staff reviewed the quality controls used by the applicant to ensure that the scoping and 

screening methodology used to develop the LRA were adequate for the activity. The applicant 

used the following quality control processes during the LRA development: 

 The license renewal team coordinated and reviewed all license renewal activities. 

 Subject matter experts, supervisors, and managers prepared and reviewed basis 

documents, reports, and the LRA. 

 The nuclear quality assurance organization performed a surveillance of LRA 

development activities. 

 Industry peers reviewed the draft LRA. 

 The onsite safety review organization and nuclear safety review group reviewed the 

LRA. 

The staff performed a review of implementing procedures and guides, examined the applicant’s 

documentation of activities in reports, reviewed the applicant’s activities performed to assess 

the quality of the LRA, and held discussions with the applicant’s license renewal management 

and staff. The staff determines that, through its activities, the applicant has provided assurance 

that the LRA was developed consistent with its license renewal program requirements. 
2-5 

 Conclusion 

Based on its review of pertinent LRA development guidance and review of the applicant’s 

documentation of the activities performed to assess the quality of the LRA, the staff concludes 

that the applicant’s quality assurance activities are adequate to ensure that LRA development 

activities were performed in accordance with the applicant’s license renewal program 

requirements. 

2.1.3.3 Training 

 Staff Evaluation 

The staff reviewed the training process used by the applicant for license renewal project 

personnel to confirm that it was appropriate for the activity. As specified by the license renewal 

implementing procedures, the applicant has required training and qualification of personnel 

performing activities supporting the development of the LRA, including identification of SSCs 

within the scope of license renewal, identification of SCs subject to an AMR, and documentation 

of the information in reports. 

Training included the following topics and activities: 

 Fermi 2 License Renewal Project Plan 

 license renewal overview 

 operating experience review 

 industry guidelines for implementation of 10 CFR Part 54 

 NRC SRP-LR 

 NUREG-1801, Revision 2, “Generic Aging Lessons Learned (GALL) Report” 

 system and structure scoping 

 mechanical system screening and AMR 

 structural screening and AMR 

 electrical system screening and AMR 

 evaluation of aging management programs (AMPs) 

 time-limited aging analyses and exemptions evaluation 

 LRA development 

The staff discussed training activities with the applicant’s management and license renewal 

project personnel and performed a sampling review of applicable documentation. The staff 

determines that the applicant has developed and implemented adequate controls for the training 

of personnel performing LRA activities. 

 Conclusion 

Based on discussions with the applicant’s license renewal personnel responsible for the scoping 

and screening process and its review of selected documentation in support of the process, the 

staff concludes that the applicant has developed and implemented adequate procedures to train 

personnel to implement the scoping and screening methodology described in its implementing 

procedures and the LRA. 
2-6 

2.1.3.4 Conclusion of Scoping and Screening Program Review 

Based on its review of information provided in LRA Sections 2.0 and 2.1, review of the 

applicant’s scoping and screening implementing procedures, discussions with the applicant’s 

license renewal personnel, review of the quality controls applied to the LRA development, 

training of personnel participating in the LRA development, and the results from the scoping and 

screening methodology audit, the staff concludes that the applicant’s scoping and screening 

program is consistent with the SRP-LR and the requirements of 10 CFR Part 54 and, therefore, 

is acceptable 

2.1.4 Plant Systems, Structures, and Components Scoping Methodology 

LRA Section 2.1 describes the applicant’s methodology used to identify SSCs within the scope 

of license renewal pursuant to the criteria in 10 CFR 54.4(a). The LRA states that the scoping 

process identified the SSCs that (1) are safety related, (2) perform and support an intended 

function for responding to a design basis event (DBE), (3) are nonsafety related whose failure 

could prevent accomplishment of a safety-related function, or (4) support a specific requirement 

for one of the regulated events applicable to license renewal. In addition, the LRA states that 

the scoping methodology used was consistent with 10 CFR Part 54 and with the industry 

guidance in NEI 95-10. 

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1) 

 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(1) in LRA Section 2.1.1.1, “Application of 

Safety-Related Scoping Criteria,” which states: 

A system or structure is within the scope of license renewal if it performs a safety 

function during and following a design basis event as defined in 

10 CFR 50.49(b)(1). Design basis events are defined in 10 CFR 50.49(b)(1) as 

conditions of normal operation, including anticipated operational occurrences, 

design basis accidents, external events, and natural phenomena for which the 

plant must be designed to ensure functions identified in 10 CFR 54.4(a)(1)(i) 

through (iii). A Fermi 2 engineering procedure provides the criteria and 

methodology for determining and evaluating the safety and quality classification 

of systems, structures, and components. 

 Staff Evaluation 

Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs that are 

relied on to remain functional during and following a DBE to ensure the following functions: 

(1) the integrity of the reactor coolant pressure boundary (RCPB), (2) the ability to shut down 

the reactor and maintain it in a safe shutdown condition, or (3) the capability to prevent or 

mitigate the consequences of accidents that could result in potential offsite exposures 

comparable to those referred to in 10 CFR 50.34(a)(1); 10 CFR 50.67(b)(2); or 10 CFR 100.11, 

“Determination of Exclusion Area, Low Population Zone, and Population Center Distance,” as 

applicable. 
2-7 

With regard to identification of DBEs, SRP-LR Section 2.1.3, “Review Procedures,” states: 

The set of design basis events as defined in the rule is not limited to Chapter 15 

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

described in this chapter include external events, such as floods, storms, 

earthquakes, tornadoes, or hurricanes, and internal events, such as a high 

energy line break. Information regarding design basis events as defined in 

10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, the 

Commission’s regulations, NRC orders, exemptions, or license conditions within 

the CLB. These sources should also be reviewed to identify systems, structures, 

and components that are relied upon to remain functional during and following 

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

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

During the audit, the applicant stated that it evaluated the types of events listed in NEI 95-10 

(anticipated operational occurrences, design basis accidents (DBAs), external events, and 

natural phenomena) that were applicable to Fermi 2. The staff reviewed the applicant’s basis 

documents, which described design basis conditions in the CLB, and addressed events defined 

by 10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The UFSAR and basis documents discussed 

events, such as internal and external flooding, tornados, and missiles. The staff concludes that 

the applicant’s evaluation of DBEs was consistent with the SRP-LR. 

The staff determined that the applicant has performed scoping of SSCs for the 

10 CFR 54.4(a)(1) criterion in accordance with the license renewal implementing procedures 

that provide guidance for the preparation, review, verification, and approval of the scoping 

evaluations to ensure the adequacy of the results of the scoping process. The staff reviewed 

the implementing procedures governing the applicant’s evaluation of safety-related SSCs and 

sampled the applicant’s reports of the scoping results to ensure that the applicant applied the 

methodology in accordance with the implementing procedures. In addition, the staff discussed 

the methodology and results with the applicant’s personnel who were responsible for these 

evaluations. 

The staff reviewed the applicant’s evaluation of the Rule and CLB definitions pertaining to 

10 CFR 54.4(a)(1). The staff noted the applicant’s CLB definition of safety related met the 

definition of safety related as specified in the Rule with the exception that it did not include a 

reference to the 10 CFR 50.67(b)(2) alternate source term related to potential offsite exposure 

criteria. The staff reviewed LRA Section 2.1.1, “Scoping Methodology,” which states that the 

applicant had reviewed the applicability of 10 CFR 50.67, “Accident Source Term,” and 

determined that the applicant had credited the use of alternate source term in the fuel-handling 

accident and loss-of-coolant accident (LOCA) analyses and had identified one additional SSC, 

the standby liquid control (SLC) system, which was included within the scope of license 

renewal. The staff determined that the applicant had reconciled the difference between the CLB 

definition of safety related and the definition in 10 CFR 54.4(a)(1). 

The staff reviewed a sample of the license renewal scoping results for portions of the EESW 

system and RHR complex support equipment and corresponding structures to provide 

additional assurance that the applicant adequately implemented its scoping methodology with 

respect to 10 CFR 54.4(a)(1). 

The staff verified that the applicant had developed the scoping results for each of the sampled 

systems consistently with the methodology, identified the SSCs credited for performing intended 
2-8 

functions, and adequately described the basis for the results and the intended functions. The 

staff also confirmed that the applicant had identified and used pertinent engineering and 

licensing information to identify the SSCs required to be within the scope of license renewal in 

accordance with the criteria in 10 CFR 54.4(a)(1). 

 Conclusion 

Based on its review of the LRA, the applicant’s implementing procedures and reports, and the 

review of two systems on a sampling basis, the staff concludes that the applicant’s methodology 

for identifying safety-related SSCs relied on to remain functional during and following DBEs and 

including them within the scope of license renewal is consistent with the SRP-LR and 

10 CFR 54.4(a)(1) and, therefore, is acceptable. 

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2) 

 Summary of Technical Information in the Application 

The applicant addressed the methods that it used to identify SSCs included within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(2). 

LRA Section 2.1.1.2, “Application of Criterion for Nonsafety-Related SSCs Whose Failure Could 

Prevent the Accomplishment of Safety Functions,” states, in part: 

Functional Support for Safety-Related SSC 10 CFR 54.4(a)(1) Functions. At 

Fermi 2, systems and structures required to perform a function to support a 

safety function are classified as safety-related and have been included in the 

scope of license renewal per Section 2.1. For the exceptions where 

nonsafety-related equipment is required to remain functional to support a safety 

function (e.g., support the fuel pool cooling and cleanup system in removing 

decay heat from fuel assemblies stored in the fuel pools), the system containing 

the equipment has been included in scope, and the function is listed as an 

intended function for 10 CFR 54.4(a)(2) for the system. 

Connected to and Provide Structural Support for Safety-Related SSCs. For 

nonsafety-related SSCs directly connected to safety-related SSCs (typically 

piping systems), components within the scope of license renewal include the 

connected piping and supports up to and including the first seismic or equivalent 

anchor beyond the safety-nonsafety interface, or up to a point determined by 

alternative bounding criteria (such as a base-mounted component, flexible 

connection, or the end of a piping run). 

Potential for Spatial Interactions with Safety-Related SSCs. Moderate- and lowenergy systems have the potential for spatial interactions of spray and leakage. 

Nonsafety-related systems and nonsafety-related portions of safety-related 

systems with the potential for spray or leakage that could prevent safety-related 

SSCs from performing their required safety function are within the scope of 

license renewal and subject to aging management review. 

The review used a spaces approach for scoping of nonsafety-related systems 

with potential spatial interaction with safety-related SSCs. The spaces approach 

focuses on the interaction between nonsafety-related and safety-related SSCs 
2-9 

that are located in the same space. A space is defined as a room or cubicle that 

is separated from other spaces by substantial objects (such as wall, floors, or 

ceilings). The space is defined such that any potential interaction between 

nonsafety-related and safety-related SSCs, including flooding, is limited to the 

space. Nonsafety-related systems that contain water, oil, or steam with 

components located inside structures containing safety-related SSCs are 

potentially in scope for possible spatial interaction under criterion 

10 CFR 54.4(a)(2). These systems were evaluated further to determine if system 

components were located in a space such that safety-related equipment could be 

affected by a component failure. 

 Staff Evaluation 

RG 1.188, Revision 1, endorses the use of NEI 95-10, Revision 6, which discusses the 

implementation of the staff’s position on 10 CFR 54.4(a)(2) scoping criteria, to include 

nonsafety-related SSCs that may have the potential to prevent satisfactory accomplishments of 

safety-related intended functions. Such SSCs include nonsafety-related SSCs connected to 

safety-related SSCs, nonsafety-related SSCs in proximity to safety-related SSCs, and mitigative 

and preventive options related to nonsafety-related and safety-related SSCs interactions. LRA 

Section 2.0 states that the applicant’s methodology is consistent with the guidance in 

Appendix F to NEI 95-10, Revision 6. 

In addition, the staff’s position (as discussed in the SRP-LR Section 2.1.3.1.2) is that the 

applicant should not consider hypothetical failures; instead, it should base its evaluation on the 

plant’s CLB, engineering judgment and analyses, and relevant operating experience. NEI 95-10 

further describes operating experience as all documented plant-specific and industry-wide 

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

include NRC generic communications and event reports; plant-specific condition reports; 

industry reports, such as safety operational event reports; and engineering evaluations. The 

staff reviewed LRA Section 2.1.1.2 and subsections in which the applicant described the 

scoping methodology for nonsafety-related SSCs pursuant to 10 CFR 54.4(a)(2). In addition, 

the staff reviewed the applicant’s implementing procedure and results report, which documented 

the guidance and corresponding results of the applicant’s scoping review pursuant to 

10 CFR 54.4(a)(2). 

Nonsafety-Related SSCs Required to Perform a Function That Supports a Safety-Related SSC. 

The staff reviewed LRA Section 2.1.1.2.1, “Functional Failures of Nonsafety-Related SSCs,” 

and the applicant’s 10 CFR 54.4(a)(2) implementing procedure that describes the method used 

to identify those nonsafety-related SSCs required to perform a function that supports a 

safety-related SSC intended function, within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2). The staff confirmed that the applicant had reviewed the UFSAR, plant 

drawings, the CECO database, and other CLB documents to identify the nonsafety-related 

systems and structures that function to support a safety-related system whose failure could 

prevent the performance of a safety-related intended function. The staff determined that the 

applicant had identified the nonsafety-related SSCs that performed a safety function or 

supported a safety system that would require the nonsafety-related SSC to be included within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

The staff determined that the applicant’s methodology for identifying nonsafety-related systems 

that perform functions that support safety-related intended functions for inclusion within the 
2-10 

scope of license renewal was in accordance with the guidance in SRP-LR and the requirements 

of 10 CFR 54.4(a)(2). 

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The staff reviewed LRA 

Section 2.1.1.2.2, “Physical Failures of Nonsafety-Related SSCs,” and the applicant’s 

10 CFR 54.4(a)(2) implementing procedure that describes the method used to identify 

nonsafety-related SSCs, directly connected to safety-related SSCs, within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(2). The applicant had reviewed the safety-related 

to nonsafety-related interfaces for each mechanical system in order to identify the 

nonsafety-related components located between the safety- to nonsafety-related interface and 

license renewal structural boundary. 

The staff determined that the applicant had used a combination of the following to identify the 

portion of nonsafety-related piping systems to include within the scope of license renewal: 

 seismic anchors 

 equivalent anchors 

 bounding conditions described in Appendix F to NEI 95-10, Revision 6 

(i.e., base-mounted component, flexible connection, inclusion to the free end of 

nonsafety-related piping, inclusion of the entire piping run, or a branch line off of a 

header where the moment of inertia of the header is greater than seven times the 

moment of inertia of the branch) 

The staff determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs, directly connected to safety-related SSCs, within the scope of license 

renewal was in accordance with the guidance in SRP-LR and the requirements of 

10 CFR 54.4(a)(2). 

The staff determined that additional information would be required to complete its review. 

RAI 2.1-1, dated October 20, 2014, states, in part: 

During the on-site scoping and screening methodology audit the staff reviewed 

the implementing document used by the applicant to identify nonsafety-related 

SSCs with the potential to affect safety-related SSCs, for inclusion within the 

scope of license renewal. The applicant’s implementing document states that 

only nonsafety-related SSCs that had not been included within the scope of 

license renewal based on the potential for spray or leakage needed to be 

reviewed for nonsafety-related SSCs directly attached to safety-related SSCs to 

identify the portion of the nonsafety-related SSC up to the first anchor, equivalent 

anchor, or bounding condition, past the safety-related/nonsafety-related 

interface. The staff required additional information to determine that the 

applicant had identified the portion of the nonsafety-related SSC, past the 

safety-related/nonsafety-related interface, to be included within the scope of 

license renewal, up to and including an anchor, equivalent anchor or bounding 

condition in accordance with 10 CFR 54.4(a)(2). 

By letter dated November 18, 2014, the applicant responded to RAI 2.1-1, which states, in part: 

During the audit, it was discussed that previous license renewal applications 

have shown that the identification of nonsafety-related fluid-filled SSCs within 
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scope due to spatial interaction per LRA Section 2.1.1.2.2(2) has typically 

enveloped the nonsafety-related SSCs meeting the criteria of LRA 

Section 2.1.1.2.2(1). This is because the seismic boundary is typically within the 

same space as the nonsafety-to-safety interface and all of the fluid-filled, 

nonsafety-related SSCs in that space are already included due to potential for 

spray or leakage. 

In order to provide verification that the nonsafety-related fluid-filled SSCs 

necessary for seismic support of safety-related SSCs are included within scope 

and subject to aging management review, a review of the scoping and screening 

of the safety-to-nonsafety interfaces was performed. The review utilized the 

method described in detail below, consistent with the statements in LRA 

Sections 2.1.1.2.2(1) and 2.1.2.1.2. 

The LRA drawings were reviewed to identify instances where nonsafety-related 

fluid-filled SSCs are directly connected to safety-related SSCs. For each 

instance, the seismic boundaries were identified as (1) a seismic anchor, (2) an 

equivalent anchor, (3) a flexible connection, end of piping run, or base-mounted 

component, or (4) the seismic boundaries used for the design calculation. The 

seismic or equivalent anchors or other components credited for providing the 

boundaries were then located on piping isometrics. The locations of these 

boundary points on the piping isometrics were used to identify the corresponding 

locations on the LRA drawings. Then the LRA drawings were reviewed to 

determine if all the piping and components up to the boundary points were 

marked (highlighted) as subject to aging management review per 

10 CFR 54.4(a)(2). 

The results of the review confirmed that, for each safety-to-nonsafety interface, 

the connected fluid-filled piping and supports up to and including the first seismic 

or equivalent anchor (or up to a point determined by the alternative bounding 

criteria) were included as in scope and subject to aging management review in 

accordance with 10 CFR 54.4(a)(2). No new SSCs were identified as subject to 

aging management review as a result of this review. The review was performed 

consistent with the methodology described in LRA Sections 2.1.1.2.2(1) and 

2.1.2.1.2. Therefore, no changes to the LRA are necessary. 

The staff reviewed the response to RAI 2.1-1 and determined that the applicant had performed 

a review and had verified that fluid-filled, nonsafety-related SSCs attached to safety-related 

SSCs had been included within the scope of license renewal up to and including an anchor, 

equivalent anchor, or bounding condition in accordance with 10 CFR 54.4(a)(2). The staff’s 

concern in RAI 2.1-1 is resolved. 

Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. 

The staff reviewed LRA Section 2.1.1.2.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

procedure that describes the method used to identify nonsafety-related SSCs, with the potential 

for spatial interaction with safety-related SSCs, within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2). The staff determined that the applicant had used a spaces 

approach to identify the portions of nonsafety-related systems with the potential for spatial 

interaction with safety-related SSCs. The spaces approach focused on the interaction between 

nonsafety-related and safety-related SSCs that are located in the same space, which was 

described in the LRA as a structure containing active or passive safety-related SSCs. 
2-12 

The staff determined that the applicant had identified all nonsafety-related SSCs containing 

liquid or steam that are located in spaces containing safety-related SSCs and had included the 

nonsafety-related SSCs within the scope of license renewal, unless the applicant had evaluated 

a nonsafety-related SSC and had determined that its failure would not result in the loss of a 

10 CFR 54.4(a)(1) intended function. The staff also determined that, based on plant and 

industry operating experience, the applicant excluded the nonsafety-related SSCs containing air 

or gas from the scope of license renewal, with the exception of portions that are attached to 

safety-related SSCs and are required for structural support. 

The staff determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs, with the potential for spatial interaction with safety-related SSCs, within 

the scope of license renewal was in accordance with the guidance in SRP-LR and the 

requirements of 10 CFR 54.4(a)(2). 

 Conclusion 

Based on its review of the LRA and the applicant’s implementing procedures and reports, 

selected system reviews and walkdowns, and the response to RAI 2.1-1, the staff concludes 

that the applicant’s methodology for identifying and including nonsafety-related SSCs, whose 

failure could prevent satisfactory accomplishment of the intended functions of safety-related 

SSCs, within the scope of license renewal is in accordance with the requirements of 

10 CFR 54.4(a)(2) and, therefore, is acceptable. 

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3) 

 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(3). 

LRA Section 2.1.1.3, “Application of Criterion for Regulated Events,” states: 

The scope of license renewal includes those systems, structures, and 

components relied on in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the Commission’s regulations for fire 

protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), 

pressurized thermal shock (10 CFR 50.61), anticipated transients without scram 

(10 CFR 50.62), and station blackout (10 CFR 50.63). This section discusses 

the approach used to identify the systems and structures within the scope of 

license renewal based on this criterion. 

 Staff Evaluation 

The staff reviewed LRA Section 2.1.1.3 that describes the method used to identify and include 

within the scope of license renewal those SSCs relied on in safety analyses or plant evaluations 

to perform a function that demonstrates compliance with the Commission’s regulations for fire 

protection (10 CFR 50.48, “Fire Protection”), environmental qualification (EQ) (10 CFR 50.49, 

“Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power 

Plants”), anticipated transients without scram (ATWS) (10 CFR 50.62, “Requirements for 

Reduction of Risk from Anticipated Transients without Scram (ATWS) Events for 

Light-Water-Cooled Nuclear Power Plant”), and station blackout (SBO) (10 CFR 50.63, “Loss of 
2-13 

All Alternating Current Power”). The staff noted that pressurized thermal shock (PTS) 

(10 CFR 50.61, “Fracture Toughness Requirements for Protection against Pressurized Thermal 

Shock Events”) was not applicable to Fermi 2, a boiling water reactor. 

As part of this review, during the scoping and screening methodology audit, the staff reviewed 

implementing procedures and the technical basis documents, license renewal drawings, and 

scoping results reports. The staff determined that the applicant had evaluated the CLB to 

identify SSCs that perform functions addressed in 10 CFR 54.4(a)(3) and included these SSCs 

within the scope of license renewal as documented in the scoping reports. In addition, the staff 

determined that the scoping report results referenced the information sources used for 

determining the SSCs credited for compliance with the events. 

Fire Protection. The staff reviewed the applicant’s implementing procedure and technical basis 

document that described the method used to identify SSCs within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(3) (fire protection (10 CFR 50.48)). The implementing 

procedure described a process that considered CLB information, including the UFSAR and the 

fire hazards analysis and safe shutdown analyses. The staff reviewed applicable portions of the 

LRA, CLB information, and license renewal drawings to verify that the appropriate SSCs were 

included within the scope of license renewal. In addition, the staff reviewed a selected sample 

of scoping reports for the systems and structures identified in technical documents. Based on 

its review of the CLB documents and the sample reports review, the staff determined that the 

applicant’s methodology was adequate for identifying and including SSCs credited in performing 

fire protection functions within the scope of license renewal in accordance with 

10 CFR 54.4(a)(3). 

Environmental Qualification. The staff reviewed the applicant’s implementing procedure and 

technical basis document that describes the method used to identify SSCs within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(3) (EQ (10 CFR 50.49)). The implementing 

procedure described a process that considered CLB information, including the UFSAR and the 

EQ technical basis document. The staff reviewed applicable portions of the LRA, CLB 

information, EQ program documentation, and license renewal drawings to verify that the 

appropriate SSCs were included within the scope of license renewal. In addition, the staff 

reviewed a selected sample of scoping reports for the systems and structures identified in the 

EQ technical documents. Based on its review of the CLB documents and the sample reports 

review, the staff determined that the applicant’s methodology was adequate for identifying and 

including SSCs credited in performing EQ functions within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(3). 

Anticipated Transients without Scram. The staff reviewed the applicant’s implementing 

procedure and technical basis document that described the method used to identify SSCs within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(3) (ATWS (10 CFR 50.62)). 

The implementing procedure describes a process that considered CLB information, including 

the UFSAR and the ATWS implementing documents. The staff reviewed applicable portions of 

the LRA, CLB information, and license renewal drawings to verify that the appropriate SSCs 

were included within the scope of license renewal. In addition, the staff reviewed a selected 

sample of scoping reports for the systems and structures identified in the ATWS technical 

documents. Based on its review of the CLB documents and the sample reports review, the staff 

determined that the applicant’s methodology was adequate for identifying and including SSCs 

credited in performing ATWS functions within the scope of license renewal in accordance with 

10 CFR 54.4(a)(3). 
2-14 

Station Blackout. The staff reviewed the applicant’s implementing procedure and technical 

basis document that describes the method used to identify SSCs within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(3) (SBO (10 CFR 50.63, “Loss of All Alternating 

Current Power”)). The implementing procedure described a process that considered CLB 

information, including the UFSAR and the SBO technical documents. The staff reviewed 

applicable portions of the LRA, CLB information, and license renewal drawings to verify that the 

appropriate SSCs were included within the scope of license renewal. In addition, the staff 

reviewed a selected sample of scoping reports for the systems and structures identified in the 

SBO technical basis document. Based on its review of the CLB documents and the sample 

report review, the staff determined that the applicant’s methodology was adequate for identifying 

and including SSCs credited in performing SBO functions within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(3). 

 Conclusion 

Based on its review of the LRA, the applicant’s implementing procedures and reports, and 

systems on a sampling basis, the staff concludes that the applicant’s methodology for identifying 

and including SSCs relied on to remain functional during regulated events is consistent with the 

SRP-LR and 10 CFR 54.4(a)(3) and, therefore, is acceptable. 

2.1.4.4 Plant-Level Scoping of Systems and Structures 

 Summary of Technical Information in the Application 

System and Structure Level Scoping. The applicant described the methods used to identify 

SSCs included within the scope of license renewal in accordance with 10 CFR 54.4(a) in LRA 

Section 2.1.1, which states: 

NEI 95-10, Industry Guideline for Implementing the Requirements of 

10 CFR Part 54 - License Renewal Rule (Ref. 2.1-6), provides industry guidance 

for determining what SSCs are in the scope of license renewal. The process 

used to determine the systems and structures within the scope of license renewal 

for Fermi 2 followed the recommendations of NEI 95-10. Consistent with 

NEI 95-10, the scoping process developed a list of plant systems and structures 

and identified their intended functions. Intended functions are those functions 

that are the basis for including a system or structure within the scope of license 

renewal (as defined in 10 CFR 54.4(b)) and are identified by comparing the 

system or structure function with the criteria in 10 CFR 54.4(a). 

The Fermi 2 Central Component (CECO) database was used to develop a list of 

plant systems. The equipment database is a controlled list of plant systems and 

components, with each component assigned to one plant system. 

 Staff Evaluation 

The staff reviewed the applicant’s methodology for identifying SSCs within the scope of license 

renewal to verify that it met the requirements of 10 CFR 54.4. The applicant had developed 

implementing procedures that described the processes used to identify the systems and 

structures that are subject to 10 CFR 54.4 review, to determine whether the system or structure 

performed intended functions consistent with the criteria in 10 CFR 54.4(a), and to document 

the activities in scoping results reports. The process defined the plant in terms of systems and 
2-15 

structures and was completed for all systems and structures onsite to ensure that the entire 

plant was assessed. 

The staff determined that the applicant had identified the SSCs within the scope of license 

renewal and documented the results of the scoping process in reports in accordance with the 

implementing procedures. The reports included a description of the structure or system, a 

listing of functions performed by the system or structure, identification of the intended functions 

of the system or structure, the 10 CFR 54.4(a) scoping criteria met by the system or structure, 

references, and the basis for the classification of the intended functions of the system or 

structure. During the audit, the staff reviewed a sampling of the implementing documents and 

reports and determined that the applicant’s scoping results contained an appropriate level of 

detail to document the scoping process. 

 Conclusion 

Based on its review of the LRA, implementing procedures, and a sampling of system scoping 

results reviewed during the audit, the staff concludes that the applicant’s methodology for 

identifying systems and structures within the scope of license renewal and their intended 

functions is consistent with the requirements of 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.5 Mechanical Component Scoping 

 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify mechanical SSCs within the scope of 

license renewal in accordance with 10 CFR 54.4(a). 

LRA Section 2.1.1 states: 

For mechanical system scoping, a system is defined as the collection of 

mechanical components in the equipment database assigned to the system 

code. System functions are determined based on the functions performed by 

those components. Defining a system by the components in the database is 

consistent with the evaluations performed for maintenance rule scoping and for 

the determination of system safety functions. 

LRA Section 2.1.1 also states: 

Intended functions for structures and mechanical systems were identified based 

on reviews of applicable plant licensing and design documentation. Documents 

reviewed included the UFSAR, site Technical Specifications, the Fire Hazards 

Analysis (Appendix 9A.4 of the UFSAR), the Safe Shutdown Analysis, 

Maintenance Rule Basis documents, design basis documents, and station 

drawings as necessary. Each structure and mechanical system was evaluated 

against the criteria of 10 CFR 54.4 as described in the following sections [of the 

LRA]. Section 2.1.1.1 discusses the evaluation against the safety-related 

criterion in 10 CFR 54.4(a)(1). Section 2.1.1.2 discusses the evaluation of 

nonsafety-related SSCs against the criterion of 10 CFR 54.4(a)(2). 

Section 2.1.1.3 discusses the evaluation against the regulated events criterion, 

10 CFR 54.4(a)(3). 
2-16 

 Staff Evaluation 

The staff reviewed LRA Section 2.1.1, implementing procedures, reports, and the CLB source 

information associated with mechanical scoping. The staff determined that the CLB source 

information and the implementing procedure guidance used by the applicant were acceptable to 

identify mechanical SSCs within the scope of license renewal. The staff conducted detailed 

discussions with the applicant’s license renewal project personnel and reviewed documentation 

pertinent to the scoping process during the scoping and screening methodology audit. The staff 

assessed whether the applicant had appropriately applied the scoping methodology outlined in 

the LRA and implementing procedures and whether the scoping results were consistent with 

CLB requirements. The staff determined that the applicant’s procedure was consistent with the 

description provided in LRA Section 2.1.1 and the guidance in SRP-LR Section 2.1 and was 

adequately implemented. 

On a sampling basis, the staff reviewed the applicant’s scoping reports for portions of the EESW 

system and RHR complex support equipment and the process used to identify mechanical 

components that met the scoping criteria in 10 CFR 54.4. The staff reviewed the implementing 

procedures, verified that the applicant had used pertinent engineering and licensing information, 

and discussed the methodology and results with the applicant. As part of the review process, 

the staff evaluated the system’s documented intended functions and the process used to 

identify system component types. The staff verified that the applicant had identified and 

highlighted license renewal drawings to identify the license renewal boundaries in accordance 

with the implementing procedure guidance. Additionally, the staff determined that the applicant 

had independently verified the results in accordance with the implementing procedures. The 

staff confirmed that the applicant’s license renewal personnel tasked with verifying the results 

had performed independent reviews of the scoping reports and the applicable license renewal 

drawings. The staff confirmed that the systems and components identified by the applicant 

were evaluated against the criteria in 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff verified 

that the applicant had used pertinent engineering and licensing information in order to determine 

that systems and components were included within the scope of license renewal in accordance 

with the 10 CFR 54.4(a). 

 Conclusion 

Based on its review of information in the LRA, implementing procedures, and the sampling 

review of scoping results, the staff concludes that the applicant’s methodology for identifying 

mechanical SSCs within the scope of license renewal is in accordance with 10 CFR 54.4 and, 

therefore, is acceptable. 

2.1.4.6 Structural Component Scoping 

 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify structural SSCs within the scope of 

license renewal in accordance with 10 CFR 54.4(a). 

LRA Section 2.1.1 states: 

As the starting point for structural scoping, a list of plant structures was 

developed from a review of the UFSAR, plant layout drawings, Fire Hazard 

Analysis (Appendix 9A.4 of the UFSAR), design basis documents, and 
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Maintenance Rule Basis documents. The structures list includes structures that 

potentially support plant operations or could adversely impact structures that 

support plant operations (i.e., seismic Il/I). In addition to buildings and facilities, 

the list of structures includes other structures that support plant operation 

(e.g., foundations for freestanding tanks and electrical manholes). Tables 2.2-4 

and 2.2-5 [of the LRA] list the plant structures evaluated for inclusion within the 

scope of license renewal. 

LRA Section 2.1.1 also states: 

Intended functions for structures and mechanical systems were identified based 

on reviews of applicable plant licensing and design documentation. Documents 

reviewed included the UFSAR, site Technical Specifications, the Fire Hazards 

Analysis (Appendix 9A.4 of the UFSAR), the Safe Shutdown Analysis, 

Maintenance Rule Basis documents, design basis documents, and station 

drawings as necessary. Each structure and mechanical system was evaluated 

against the criteria of 10 CFR 54.4 as described in the following sections [of the 

LRA]. Section 2.1.1.1 discusses the evaluation against the safety-related 

criterion in 10 CFR 54.4(a)(1). Section 2.1.1.2 discusses the evaluation of 

nonsafety-related SSCs against the criterion of 10 CFR 54.4(a)(2). 

Section 2.1.1.3 discusses the evaluation against the regulated events criterion, 

10 CFR 54.4(a)(3). 

 Staff Evaluation 

The staff reviewed LRA Section 2.1.1, implementing procedures, reports, and the CLB source 

information associated with structural scoping. The staff determined that the CLB source 

information and the implementing procedure guidance used by the applicant were acceptable to 

identify structural SSCs within the scope of license renewal. The staff conducted detailed 

discussions with the applicant’s license renewal project personnel and reviewed documentation 

pertinent to the scoping process during the scoping and screening methodology audit. The staff 

assessed whether the applicant had appropriately applied the scoping methodology outlined in 

the LRA and implementing procedures and whether the scoping results were consistent with 

CLB requirements. The staff determined that the applicant’s procedure was consistent with the 

description provided in LRA Section 2.1.1 and the guidance in SRP-LR Section 2.1 and was 

adequately implemented. 

On a sampling basis, the staff reviewed the applicant’s scoping reports for portions of the EESW 

system and RHR complex support equipment and corresponding structures and reviewed the 

process used to identify structural SSCs that met the scoping criteria in 10 CFR 54.4. The staff 

reviewed the implementing procedures, verified that the applicant had used pertinent 

engineering and licensing information, and discussed the methodology and results with the 

applicant. As part of the review process, the staff evaluated the structure’s documented 

intended functions and the process used to identify structural component types. Additionally, 

the staff determined that the applicant had verified the results in accordance with the 

implementing procedures. The staff confirmed that the applicant’s license renewal personnel 

verifying the results had performed independent reviews of the scoping reports and the 

applicable license renewal drawings. The staff confirmed that the SSCs identified by the 

applicant were evaluated against the criteria in 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff 

verified that the applicant had used pertinent engineering and licensing information in order to 

determine that systems and components were included within the scope of license renewal in 
2-18 

accordance with 10 CFR 54.4(a). In addition, the staff performed a general walkdown of the 

exterior of site structures and of the interior portion of selected site structures. 

The staff determined additional information would be required to complete its review. RAI 2.1-2, 

dated October 20, 2014, states that, during the onsite scoping and screening methodology 

audit, the staff determined that the outage building, which is immediately adjacent to, and in 

contact with, the reactor building (included within the scope of license renewal in accordance 

with 10 CFR 54.4(1)), was not included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2). The staff requested that the applicant provide a basis for not including the 

outage building, which is located adjacent to, and in contact with, the reactor building, within the 

scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

The applicant responded to RAI 2.1-2, by letter dated November 18, 2014, which states, in part, 

that the portion of the reactor building that the outage building encompasses (personnel airlock), 

or is adjacent to (reactor building exterior wall), was designed to withstand impact loading 

attributable to tornado-generated missiles. The impact loading on the reactor building due to 

the postulated collapse of the outage building is bounded by the loading from tornado-generated 

missiles, as described in UFSAR Section 3.5.2.1, and would not impact the ability of the reactor 

building to perform its 10 CFR 54.4(a)(1) intended functions. Therefore, the outage building 

was not included within the scope of license renewal. 

The staff reviewed the applicant’s response to RAI 2.1-2 and determined that the applicant had 

provided a technical basis indicating that the failure of the nonsafety-related outage building 

could not impact the ability of the safety-related reactor building to perform its intended 

functions; therefore, the nonsafety-related outage building was not included within the scope of 

license renewal in accordance with 10CFR 54.4(a)(2). The staff’s concern in RAI 2.1-2 is 

resolved. 

 Conclusion 

Based on its review of information in the LRA, implementing procedures, the sampling review of 

scoping results, and the applicant’s response to RAI 2.1-2, the staff concludes that the 

applicant’s methodology for identifying structural SSCs within the scope of license renewal is in 

accordance with 10 CFR 54.4 and, therefore, is acceptable. 

2.1.4.7 Electrical Component Scoping 

 Summary of Technical Information in the Application 

LRA Section 2.1.1 states: 

For the purposes of system level scoping, plant electrical and I&C systems are 

included within the scope of license renewal by default. Electrical and I&C 

components in mechanical systems are included in the evaluation of electrical 

and I&C components, regardless of whether the mechanical system is included 

in scope. Intended functions for electrical and I&C systems are not identified 

since the bounding (i.e., included by default) scoping approach makes it 

unnecessary to determine if an electrical and I&C system has an intended 

function. Switchyard equipment, which is not part of the plant’s electrical and 

I&C systems, was reviewed for station blackout (SBO) intended functions based 

on NRC guidance in NUREG-1800, Section 2.5.2.1.1 (Ref. 2.1-2). 
2-19 

 Staff Evaluation 

The staff reviewed LRA Section 2.1.1 implementing procedures, reports, and the CLB source 

information associated with electrical scoping. The staff determined that the CLB source 

information and implementing procedure guidance used by the applicant was acceptable to 

identify electrical SSCs within the scope of license renewal. The staff conducted detailed 

discussions with the applicant’s license renewal project personnel and reviewed documentation 

pertinent to the scoping process during the scoping and screening methodology audit. The staff 

assessed whether the applicant had appropriately applied the scoping methodology outlined in 

the LRA and implementing procedures and whether the scoping results were consistent with 

CLB requirements. The staff determined that the applicant’s procedure was consistent with the 

description provided in LRA Section 2.1.1 and the guidance in SRP-LR Section 2.1 and was 

adequately implemented. 

The staff noted that, after the scoping of electrical and instrumentation and control (I&C) 

components was performed, the in-scope electrical components were categorized into electrical 

commodity groups. Commodity groups include electrical and I&C components with common 

characteristics. Component-level intended functions of the component types were identified. 

As part of this review, the staff discussed the methodology with the applicant, reviewed the 

implementing procedures developed to support the review, and reviewed the scoping results for 

a sample of SSCs that were identified within the scope of license renewal. The staff determined 

that the applicant’s scoping included appropriate electrical and I&C components and electrical 

and I&C components contained in mechanical or structural systems within the scope of license 

renewal on a commodity basis. 

 Conclusion 

On the basis of its review of information in the LRA, implementing procedures, and the sampling 

review of scoping results, the staff concludes that the applicant’s methodology for identifying 

electrical SSCs within the scope of license renewal is in accordance with 10 CFR 54.4 and, 

therefore, is acceptable. 

2.1.4.8 Conclusion for Scoping Methodology 

Based on its review of information in the LRA, implementing procedures, and a sampling review 

of scoping results, the staff concludes that the applicant’s scoping methodology is consistent 

with the guidance in SRP-LR and identifies those SSCs (1) that are safety related, (2) whose 

failure could affect safety-related intended functions, and (3) that are necessary to demonstrate 

compliance with the NRC regulations for fire protection, EQ, ATWS, SBO, and PTS. (The staff 

determined that PTS was not applicable to Fermi 2, a boiling water reactor; therefore, 

10 CFR 50.61 was not applicable.) The staff concludes that the applicant’s methodology is 

consistent with the requirements of 10 CFR 54.4(a) and, therefore, is acceptable. 

2.1.5 Screening Methodology 

2.1.5.1 General Screening Methodology 

After identifying systems and structures within the scope of license renewal, the applicant 

implemented a process for identifying SCs subject to an AMR in accordance with 10 CFR 54.21. 
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 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify SCs included within the scope of license 

renewal that are subject to an AMR in accordance with 10 CFR 54.21. LRA Section 2.1.2, 

“Screening Methodology,” states: 

NEI 95-10 (Ref. 2.1-6) provides industry guidance for screening structures and 

components to identify the passive, long-lived structures and components that 

support an intended function. The screening process for Fermi 2 followed the 

recommendations of NEI 95-10. 

Within the group of systems and structures that are in scope, passive long-lived 

components or structural elements that perform intended functions require aging 

management review. Components or structural elements that support an 

intended function do not require aging management review if they are either 

active or subject to replacement based on a qualified life. 

Although the requirements for the integrated plant assessment are the same for 

each system and structure, in practice the screening process differed for 

mechanical systems, electrical systems, and structures. 

 Staff Evaluation 

Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies SCs within the scope 

of license renewal and that are subject to an AMR. The IPA must identify components that 

perform an intended function without moving parts or a change in configuration or properties 

(passive), as well as components that are not subject to periodic replacement based on a 

qualified life or specified time period (long lived). In addition, the IPA must describe and justify 

the methodology used to identify passive and long-lived SCs and must demonstrate that the 

effects of aging on those SCs will be adequately managed so that the intended function(s) will 

be maintained under all design conditions imposed by the plant-specific CLB for the period of 

extended operation. 

The staff reviewed the methodology used by the applicant to identify the mechanical, structural, 

and electrical SSCs within the scope of license renewal that are subject to an AMR. The 

applicant implemented a process for determining which SCs were subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). The staff determined that the screening process 

evaluated the component types and commodity groups included within the scope of license 

renewal to determine which ones were long lived and passive and therefore subject to an AMR. 

The staff reviewed on a sampling basis the screening results reports for the EESW system and 

RHR complex support equipment and corresponding structures. The applicant provided the 

staff with a detailed discussion of the processes used for each discipline and provided 

administrative documentation that described the screening methodology. Sections 2.1.5.2, 

2.1.5.3, and 2.1.5.4 of this safety evaluation report (SER) discuss specific methodology for 

mechanical, structural, and electrical SCs. 

 Conclusion 

Based on its review of the LRA, implementing procedures, and a sampling of screening results, 

the staff concludes that the applicant’s screening methodology is consistent with the guidance 

contained in the SRP-LR and is capable of identifying passive, long-lived components, within 
2-21 

the scope of license renewal, that are subject to an AMR. The staff concludes that the 

applicant’s process for determining the SCs that are subject to an AMR is consistent with the 

requirements of 10 CFR 54.21 and, therefore, is acceptable. 

2.1.5.2 Mechanical Component Screening 

 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify mechanical SCs included within the 

scope of license renewal that are subject to an AMR in accordance with 10 CFR 54.21. LRA 

Section 2.1.2.1, “Screening of Mechanical Systems,” states: 

Within the system, components are subject to aging management review if they 

perform an intended function without moving parts or a change in configuration or 

properties and if they are not subject to replacement based on a qualified life or 

specified time period. 

In making the determination that a component performs an intended function 

without moving parts or a change in configuration or properties, it is not 

necessary to consider the piece parts of the component. However, in the case of 

valves, pumps, and housings for fans and dampers, the valve bodies, pump 

casings, and housings may perform an intended function by maintaining the 

pressure boundary and may therefore be subject to aging management review. 

Replacement programs are based on vendor recommendations, plant 

experience, or any means that establishes a specific service life, qualified life, or 

replacement frequency under a controlled program. Components that are 

subject to replacement based on qualified life or specified time period are not 

subject to aging management review. Where flexible elastomer hoses/expansion 

joints or other components are periodically replaced, these components are not 

subject to aging management review. 

 Staff Evaluation 

The staff reviewed the applicant’s methodology used for mechanical component screening as 

described in LRA Section 2.1.2.1, implementing procedures, basis documents, and the 

mechanical scoping and screening reports. The staff determined that the applicant used the 

screening process described in these documents along with the information in Appendix B to 

NEI 95-10 and the SRP-LR to identify the mechanical SCs subject to an AMR. 

The staff determined that the applicant had identified SCs that were found to meet the passive 

criteria in accordance with the guidance in NEI 95-10. In addition, the staff determined that the 

applicant had evaluated the identified passive commodities to determine that they were not 

subject to replacement based on a qualified life or specified time period (long lived) and that the 

remaining passive, long-lived components were subject to an AMR. 

The staff performed a sample review to determine whether the applicant had adequately 

implemented the screening methodology outlined in the LRA and implementing procedures. 

The staff reviewed portions of the EESW system and RHR complex support equipment 

screening reports and basis documents, conducted discussions with the applicant, and verified 

proper implementation of the screening process. 
2-22 

 Conclusion 

Based on its review of information in the LRA, implementing procedures, and the sampled 

mechanical screening results, the staff concludes that the applicant’s methodology for 

identification of mechanical SCs, within the scope of license renewal and subject to an AMR, is 

in accordance with 10 CFR 54.21(a)(1) and therefore, is acceptable. 

2.1.5.3 Structural Component Screening 

 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify structural SCs included within the scope 

of license renewal that are subject to an AMR in accordance with 10 CFR 54.21. LRA 

Section 2.1.2.2, “Screening of Structures,” states: 

For each structure within the scope of license renewal, the structural components 

and commodities were evaluated to determine those subject to aging 

management review. This evaluation (screening process) for structural 

components and commodities involved a review of site design documents 

(UFSAR, design basis documents, design specifications, site procedures and 

drawings, etc.) to identify specific structural components and commodities that 

make up the structure. Structural components and commodities subject to aging 

management review are those that (1) perform an intended function without 

moving parts or a change in configuration or properties, and (2) are not subject to 

replacement based on qualified life or specified time period. 

 Staff Evaluation 

The staff reviewed the applicant’s methodology used for structural component screening as 

described in LRA Section 2.1.2.2, implementing procedures, basis documents, and the 

structural scoping and screening reports. The staff determined that the applicant used the 

screening process described in these documents along with the information contained in 

Appendix B to NEI 95-10 and the SRP-LR to identify the structural SCs subject to an AMR. 

The staff determined that the applicant had identified structural SCs that were found to meet the 

passive criteria in accordance with NEI 95-10. In addition, the staff determined that the 

applicant evaluated the identified passive commodities to determine that they were not subject 

to replacement based on a qualified life or specified time period (long lived) and that the 

remaining passive, long-lived components were determined to be subject to an AMR. 

The staff performed a sample review to determine whether the applicant adequately 

implemented the screening methodology outlined in the LRA and implementing procedures. 

The staff reviewed portions of the EESW system and RHR complex support equipment and 

corresponding structures, conducted discussions with the applicant, and verified proper 

implementation of the screening process. 

 Conclusion 

Based on its review of information in the LRA, implementing procedures, and the sampled 

structural screening results, the staff concludes that the applicant’s methodology to identify 
2-23 

structural SCs, within the scope of license renewal and subject to an AMR, is in accordance with 

10 CFR 54.21(a)(1) and therefore, is acceptable. 

2.1.5.4 Electrical Component Screening 

 Summary of Technical Information in the Application 

The applicant addressed the methods used to identify electrical SCs included within the scope 

of license renewal that are subject to an AMR in accordance with 10 CFR 54.21. LRA 

Section 2.1.2.3, “Electrical and Instrumentation and Control Systems,” states: 

The electrical and I&C aging management review evaluates commodity groups 

containing components with similar characteristics. Screening applied to 

commodity groups determines which electrical and I&C components are subject 

to aging management review. An aging management review is required for 

commodity groups that perform an intended function, as described in 

10 CFR 54.4, without moving parts or without a change in configuration or 

properties (passive) and that are not subject to replacement based on a qualified 

life or specified time period (long-lived). 

 Staff Evaluation 

The staff reviewed the applicant’s methodology used for electrical component screening as 

described in LRA Section 2.1.2.3, implementing procedures, basis documents, and the electrical 

scoping and screening reports. The staff confirmed that the applicant had used the screening 

process described in these documents along with the information in Appendix B to NEI 95-10 

and the SRP-LR to identify the electrical SSCs subject to an AMR. 

The staff determined that the applicant had identified electrical commodity groups that were 

found to meet the passive criteria in accordance with NEI 95-10. In addition, the staff 

determined that the applicant evaluated the identified passive commodities to determine which 

ones were not subject to replacement based on a qualified life or specified time period (long 

lived) and that the remaining passive, long-lived components are subject to an AMR. 

The staff performed a sample review of electrical commodity groups to determine whether the 

applicant had adequately implemented the screening methodology outlined in the LRA and 

implementing procedures. The staff determined that the electrical commodity groups (i.e., high 

voltage insulators, cables and connections, fuse holders, and the electrical portion of 

penetration assemblies) that the applicant had identified as passive, long-lived were subject to 

an AMR. During the scoping and screening methodology audit, the staff reviewed the electrical 

screening report and basis documents for these components, discussed the report with the 

applicant, and verified proper implementation of the screening process. 

 Conclusion 

Based on its review of information in the LRA, implementing procedures, and the sampled 

electrical screening results, the staff concludes that the applicant’s methodology to identify 

electrical and I&C SCs, within the scope of license renewal and subject to an AMR, is in 

accordance with 10 CFR 54.21(a)(1) and, therefore, is acceptable. 
2-24 

2.1.5.5 Conclusion for Screening Methodology 

Based on its review of the LRA, the screening implementing procedures, and a sample review 

of screening results, the staff concludes that the applicant’s screening methodology is 

consistent with the guidance in the SRP-LR and identifies those passive, long-lived components 

within the scope of license renewal that are subject to an AMR. The staff concludes that the 

applicant’s methodology is consistent with the requirements of 10 CFR 54.21(a)(1) and, 

therefore, is acceptable. 

2.1.6 Summary of Evaluation Findings 

Based on its review of the information presented in LRA Section 2.1; the supporting information 

in the scoping and screening implementing procedures and reports; the information presented 

during the scoping and screening methodology audit; sample system reviews; and the 

applicant’s response, dated November 18, 2014, to the staff’s RAIs dated October 20, 2014, the 

staff confirms that the applicant’s scoping and screening methodology is consistent with the 

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also concludes that the 

applicant’s description and justification of its scoping and screening methodology are adequate 

to meet the requirements of 10 CFR 54.21(a)(1). Based on this review, the staff concludes that 

the applicant’s methodology for identifying systems and structures within the scope of license 

renewal and SCs that require an AMR is acceptable. 

2.2 Plant-Level Scoping Results 

2.2.1 Introduction 

In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the 

scope of license renewal. In LRA Section 2.2, “Plant Level Scoping Results,” the applicant used 

the scoping methodology to determine which SSCs must be included within the scope of license 

renewal. The staff reviewed the plant-level scoping results to determine whether the applicant 

has properly identified all systems and structures that are relied on to mitigate DBEs, as 

required by 10 CFR 54.4(a)(1); systems and structures whose failure could prevent satisfactory 

accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2); and systems 

and structures that are relied on in safety analyses or plant evaluations to perform functions, as 

required by 10 CFR 54.4(a)(3). 

2.2.2 Summary of Technical Information in the Application 

In LRA Table 2.2-1, “Mechanical Systems within the Scope of License Renewal,” the applicant 

listed plant mechanical systems within the scope of license renewal. In LRA Table 2.2-3, “Plant 

Electrical and I&C Systems within the Scope of License Renewal,” the applicant listed plant 

electrical and I&C systems within the scope of license renewal. In LRA Table 2.2-4, “Structures 

within the Scope of License Renewal,” the applicant listed the structures that are within the 

scope of license renewal. Based on the DBEs considered in the plant’s CLB, other CLB 

information on nonsafety-related systems and structures, and certain regulated events, the 

applicant identified plant-level systems and structures within the scope of license renewal, as 

defined by 10 CFR 54.4. 
2-25 

2.2.3 Staff Evaluation 

In LRA Section 2.1, the applicant described its methodology for identifying systems and 

structures within the scope of license renewal and subject to an AMR. The staff reviewed the 

scoping and screening methodology; SER Section 2.1 includes the staff’s evaluation. To verify 

that the applicant properly implemented its methodology, the staff focused its review on the 

implementation results shown in Table 2.2-1; Table 2.2-2, “Mechanical Systems Not within the 

Scope of License Renewal”; Table 2.2-3; Table 2.2-4; and Table 2.2-5, “Structures Not within 

the Scope of License Renewal” (as amended by letter dated May 9, 2016) of LRA Section 2.1 to 

confirm that there were no omissions of plant-level systems and structures within the scope of 

license renewal. 

The staff determined whether the applicant properly identified the systems and structures within 

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed systems and 

structures that the applicant did not identify as being within the scope of license renewal to 

verify whether the systems and structures have any intended functions that require their 

inclusion within the scope of license renewal. The staff conducted its review of the applicant’s 

implementation in accordance with the guidance in SRP-LR Section 2.2, “Plant-Level Scoping 

Results.” On the basis of its review, the staff did not identify the need for additional information. 

2.2.4 Conclusion 

The staff reviewed LRA Section 2.2, as amended by letter dated May 9, 2016, and UFSAR 

supporting information to determine whether the applicant failed to identify any systems and 

structures within the scope of license renewal. On the basis of its review, the staff concludes 

that the applicant has appropriately identified the systems and structures within the scope of 

license renewal in accordance with 10 CFR 54.4. 

2.3 Scoping and Screening Results: Mechanical Systems 

This section documents the staff’s review of the applicant’s scoping and screening results for 

mechanical systems. Specifically, this section discusses the following items: 

 reactor coolant system (RCS) 

 engineered safety feature (ESF) systems 

 auxiliary systems 

 steam and power conversion (S&PC) systems 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list those 

passive, long-lived SCs that are within the scope of license renewal and that are subject to an 

AMR. To verify the applicant properly implemented its methodology, the staff focused its review 

on the implementation results. This focus allowed the staff to verify that the applicant identified 

the mechanical system SCs that met the scoping criteria and that were subject to an AMR, thus 

confirming that there were no omissions. 

The staff’s evaluation of mechanical systems was performed using the evaluation methodology 

described in SRP-LR Section 2.3 and took into account the system function(s) described in the 

UFSAR. The objective was to determine whether the applicant, in accordance with 

10 CFR 54.4, has identified components and supporting structures for mechanical systems that 

meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant’s 
2-26 

screening results to verify that all passive, long-lived components are subject to an AMR, as 

required by 10 CFR 54.21(a)(1). 

In its scoping evaluation, the staff reviewed the LRA, applicable sections of the UFSAR; license 

renewal boundary drawings; and other licensing basis documents, as appropriate, for each 

mechanical system within the scope of license renewal. The staff reviewed relevant licensing 

basis documents for each mechanical system to confirm that the LRA specified all intended 

functions defined by 10 CFR 54.4(a). The review then focused on identifying any components 

with intended functions defined by 10 CFR 54.4(a) that the applicant may have omitted from the 

scope of license renewal. 

After reviewing the scoping results, the staff evaluated the applicant’s screening results. For 

those SCs with intended functions delineated under 10 CFR 54.4(a), the staff verified that the 

applicant properly screened out only (1) SCs that have functions performed with moving parts or 

that have a change in configuration or properties or (2) SCs that are subject to replacement 

after a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For SCs not 

meeting either of these criteria, the staff identified the remaining SCs subject to an AMR, as 

required by 10 CFR 54.21(a)(1). The staff issued an RAI to resolve any omissions or 

discrepancies identified. 

2.3.1 Reactor Coolant System 

LRA Section 2.3.1 identifies the reactor vessel, internals, and RCS SCs subject to an AMR for 

license renewal. The applicant described the supporting SCs of the reactor vessel, internals, 

and RCS in the following LRA sections: 

 LRA Section 2.3.1.1, “Reactor Assembly” 

 LRA Section 2.3.1.1.1, “Reactor Pressure Vessel and Appurtenances” 

 LRA Section 2.3.1.1.2, “Reactor Vessel Internals” 

 LRA Section 2.3.1.2, “Reactor Coolant Pressure Boundary” 

 LRA Section 2.3.1.3, “Nuclear Boiler” 

 LRA Section 2.3.1.4, “Reactor Recirculation” 

 LRA Section 2.3.1.5, “Neutron Monitoring” 

 LRA Section 2.3.1.6, “Fuel and Reloads” 

 LRA Section 2.3.1.7, “Miscellaneous Reactor Coolant Systems in Scope for 

10 CFR 54.4(a)(2)” 

SER Sections 2.3.1.1 – 2.3.1.7 include the staff’s findings on its review of LRA 

Sections 2.3.1.1 – 2.3.1.7, respectively. 

2.3.1.1 Reactor Assembly 

 Summary of Technical Information in the Application 

LRA Section 2.3.1.1 states that the reactor assembly system consists of the reactor pressure 

vessel (RPV) and appurtenances, including RPV internals components, such as the core, 

shroud, steam separator and dryer assemblies, and jet pumps. 
2-27 

The RPV and its appurtenances make up a fission product barrier and provide support to 

withstand adverse combinations of loading and forces resulting from normal, abnormal, and 

emergency conditions. The RPV is also part of the RCS pressure boundary. RPV 

subcomponents also provide structural support to safety-related equipment. The major 

subcomponents of the RPV include the shell, bottom head, top head, flanges, studs, nuts, 

bushing, nozzles, caps, welds, and safe ends. 

LRA Table 2.3.1-1, “Reactor Vessel Components Subject to Aging Management Review,” 

identifies the component types that are within the scope of license renewal and that are subject 

to an AMR. 

The RPV internals provide a continuous internal circulation path for the core coolant flow; direct 

the flow of coolant water from various sources; separate moisture from the steam leaving the 

vessel; sense the differential pressure across the core support plate; and locate laterally, and 

support, the fuel assemblies, control rod guide tubes, and steam separators. Some of the 

reactor vessel internals include the following: 

 core spray lines and spargers 

 differential pressure and standby liquid control line 

 feedwater spargers 

 fuel supports 

 jet pump assembly 

 top guide assembly 

LRA Table 2.3.1-2, “Reactor Vessel Internals Components Subject to Aging Management 

Review,” identifies the component types that are within the scope of license renewal and that 

are subject to an AMR. 

The intended functions of the reactor assembly component types that are within the scope of 

license renewal include the following: 

 to provide structural integrity for reactor vessel internals 

 to provide a volume in which the core can be submerged in coolant 

 to provide a floodable inner volume following a LOCA 

 to provide a barrier to the release of radioactive materials 

 to maintain the RCPB 

 to maintain reactor core geometry 

 to provide a floodable volume in which the core can be adequately cooled in the 

event of a breach in the RCPB external to the reactor vessel 

 to provide correct coolant distribution 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function (steam dryer assembly) 
2-28 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.1.1 and the UFSAR using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the reactor assembly system functions described in the 

LRA and UFSAR to verify that the applicant has included within the scope of license renewal all 

components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those components that the applicant identified as being within the scope of license renewal to 

verify that it has included all passive and long-lived components subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

reactor assembly system, RPV and appurtenances, and reactor vessel internals components 

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant has adequately identified the reactor assembly system, RPV and 

appurtenances, and reactor vessel internals components subject to an AMR, as required by 

10 CFR 54.21(a)(1). 

2.3.1.2 Reactor Coolant Pressure Boundary 

 Summary of Technical Information in the Application 

LRA Section 2.3.1.2 states that the RCPB consists of all pressure-containing components that 

include pressure vessels, piping, pumps, and valves. However, the RCPB does not include the 

reactor vessel and its internals as it was described in the previous section. These listed 

components are described as follows: 

 part of the RCS, or 

 connected to the RCS, up to and including any and all of the following: 

 the outermost containment isolation valve in system piping, which penetrates 

primary reactor containment 

 the second of the two valves normally closed during normal reactor operation in 

system piping, which does not penetrate primary reactor containment 

 the RCS safety relief valves (SRVs) 

The major components for RCPB for scoping and screening review consist of the recirculation 

loop piping, pumps, and valves; feedwater piping and valves; main steam piping, valves, and 

SRVs; and portions of multiple systems connected to the reactor vessel. 

The intended function of the systems for the RCPB includes maintaining the integrity of the 

RCPB. 

LRA Table 2.3.1-3, “Reactor Coolant Pressure Boundary Components Subject to Aging 

Management Review,” identifies the component types that are within the scope of license 

renewal and that are subject to an AMR. 
2-29 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.1.2 and the UFSAR using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the RCPB functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

RCPB components within the scope of license renewal, as required by 10 CFR 54.4(a). The 

staff also concludes the applicant has adequately identified the RCPB components subject to an 

AMR, as required by 10 CFR 54.21(a)(1). 

2.3.1.3 Nuclear Boiler 

 Summary of Technical Information in the Application 

LRA Section 2.3.1.3 states that the nuclear boiler system provides the steam transport path 

from the reactor vessel to the second main steam isolation valve (MSIV). The nuclear boiler 

system also consists of the feedwater piping from the feedwater isolation valves to the reactor 

vessel. The nuclear boiler system is part of the RCPB and supplies steam for the high-pressure 

coolant injection (HPCI) and reactor core isolation cooling (RCIC) pump turbines. 

The major components for the nuclear boiler system are as follows: 

 two trains of feedwater piping from the isolation valves to the RPV inlet nozzles 

 feedwater isolation valves on each feedwater loop 

 four main steam lines from the RPV steam outlet nozzles to the MSIVs 

 main steam flow elements located on each steam line inside containment 

 two MSIVs on each main steam line 

 15 SRVs mounted on the main steam lines 

 SRV discharge piping 

 vacuum break valves on each SRV discharge line 

 quenching devices installed at the ends of the SRV discharge lines in the suppression 

pool 
2-30 

The intended functions of the nuclear boiler system component types within the scope of license 

renewal include the following: 

 to prevent over-pressurization of the RCPB by using a pressure relief system 

 to limit the coolant blowdown rate from the reactor vessel in the event of a main steam 

line break outside the containment 

 to control radioactive material release and exposure to plant personnel during planned 

operations, abnormal operational transients, and accidents 

 to provide a coolant injection path for the HPCI, RHR, RCIC, and reactor water cleanup 

system 

 to support primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

LRA Sections 2.3.1.2, 2.3.2.1, 2.3.3.6, 2.3.3.16, and 2.3.1.7 identify the components types that 

are within the scope of license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.1.3 and license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

 Conclusion 

Based in its evaluation, the staff concludes that the applicant has appropriately identified the 

nuclear boiler system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

nuclear boiler system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.1.4 Reactor Recirculation 

 Summary of Technical Information in the Application 

LRA Section 2.3.1.4 states that the reactor recirculation system pumps reactor coolant through 

the reactor core and controls reactor power levels through the effects of coolant flow rate on the 

moderator void content. The reactor recirculation system contains two external loops, each 

consisting of a single stage, variable speed, centrifugal pump; suction and discharge gate 

valves; flow measuring element; controls and instrumentation; and associated piping. A 

motor-generator set provides power of variable frequency and voltage to the electric motor that 
2-31 

drives the recirculation pump for each loop. The reactor recirculation system loops are located 

inside the primary containment. 

The intended functions of the reactor recirculation system component types within the scope of 

license renewal include the following: 

 to provide a flow path for shutdown cooling and for low-pressure coolant injection (LPCI) 

into the vessel 

 to support emergency equipment cooling water (EECW) system pressure boundary 

 to maintain the integrity of the RCPB 

 to support primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Sections 2.3.1.2, 2.3.3.6, 2.3.3.5, and 2.3.1.7 identify the components that are within the 

scope of license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.1.4 and license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

reactor recirculation system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

reactor recirculation system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.1.5 Neutron Monitoring 

 Summary of Technical Information in the Application 

LRA Section 2.3.1.5 states that the neutron monitoring system provides indication of neutron 

flux that can be correlated to power level for all flux condition ranges that occur in the reactor 

core. The system consists of incore detectors and out-of-core electronic monitoring equipment. 

The six major subsystems are: 

 source range monitors 

 intermediate range monitors 
2-32 

 local power range 

 traversing incore probes 

 average power range monitors 

 rod block monitors 

The intended functions of the neutron monitoring system component types within the scope of 

license renewal include the following: 

 to maintain the integrity of the RCPB 

 to support primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

LRA Sections 2.3.1.1.2, 2.3.2.6, and 2.3.1.7 identify the components types that are within the 

scope of license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.1.5 and UFSAR Sections 7.1.2.1.4 and 7.6.1.13 using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

neutron monitoring system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

neutron monitoring system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.1.6 Fuel and Reloads 

 Summary of Technical Information in the Application 

LRA Section 2.3.1.6 states that the fuel and reloads system represents the 764 fuel assemblies 

in the reactor core. The fuel assemblies are high-integrity components containing the 

fissionable material that sustains the nuclear reaction when the reactor core is made critical. 

The intended function of the fuel and reloads system within the scope of license renewal is to 

maintain the integrity of reactor fuel assemblies. 

UFSAR Sections 4.1.2 and 4.2 provide additional details for components. The fuel and reloads 

system is not subject to an AMR because the fuel assemblies are replaced periodically. 
2-33 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.1.6 and UFSAR Sections 4.1.2 and 4.2 using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

fuel and reloads system components within the scope of license renewal, as required by 

10 CFR 54.4(a). 

2.3.1.7 Miscellaneous Reactor Coolant Systems in Scope for 10 CFR 54.4(a)(2) 

 Summary of Technical Information in the Application 

LRA Section 2.3.1.7 summarizes scoping and screening for miscellaneous nonsafety-related 

RCSs or components that are within the scope of license renewal for 10 CFR 54.4(a)(2) 

because of potential physical interactions with safety-related components. These physical 

interactions could cause failure by causing a loss of structural or mechanical integrity of the 

safety-related SSC. The LRA also states that any functional failures of these nonsafety-related 

SSCs were identified and discussed within individual systems’ evaluations of LRA Section 2.3.1 

and are not evaluated in this section (i.e., Section 2.3.1.7). 

LRA Section 2.3.1.7 lists the following systems as within the scope of license renewal based on 

the criteria in 10 CFR 54.4(a)(2) for physical failure: 

 nuclear boiler 

 reactor recirculation 

 neutron monitoring 

UFSAR sections for the nuclear boiler system, reactor recirculation system, and neutron 

monitoring system provide additional details for components subject to an AMR. 

LRA Table 2.3.1-4-1, “Nuclear Boiler System Nonsafety-Related Components Affecting 

Safety-Related Systems Components Subject to Aging Management Review”; LRA 

Table 2.3.1-4-2, “Reactor Recirculation System Nonsafety-Related Components Affecting 

Safety-Related Systems Components Subject to Aging Management Review”; and LRA 

Table 2.3.1-4-3, “Neutron Monitoring System Nonsafety-Related Components Affecting 

Safety-Related Systems Components Subject to Aging Management Review,” identify the 

component types that are within the scope of license renewal and that are subject to an AMR 

based on potential physical interactions. 
2-34 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.1.7 and UFSAR sections for the nuclear boiler system, 

reactor recirculation system, and neutron monitoring system (as described in SER 

Sections 2.3.1.3, 2.3.1.4, and 2.3.1.5, respectively) using the evaluation methodology described 

in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

miscellaneous RCS components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

miscellaneous RCS components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2 Engineered Safety Features 

LRA Section 2.3.2 identifies the ESF SCs subject to an AMR for license renewal. The applicant 

described the supporting SCs of the ESFs in the following LRA sections: 

 LRA Section 2.3.2.1, “Nuclear Pressure Relief” 

 LRA Section 2.3.2.2, “Residual Heat Removal” 

 LRA Section 2.3.2.3, “Core Spray 

 LRA Section 2.3.2.4, “High Pressure Coolant Injection” 

 LRA Section 2.3.2.5, “Reactor Coolant Isolation Cooling” 

 LRA Section 2.3.2.6, “Containment Penetrations” 

 LRA Section 2.3.2.7, “Standby Gas Treatment” 

 LRA Section 2.3.2.8, “Miscellaneous ESF Systems in Scope for 10 CFR 54.4(a)(2)” 

SER Sections 2.3.2.1 – 2.3.2.8 include the staff’s findings on its review of LRA 

Sections 2.3.2.1 – 2.3.2.8, respectively. 

2.3.2.1 Nuclear Pressure Relief 

 Summary of Technical Information in the Application 

LRA Section 2.3.2.1 states that the nuclear pressure relief system (NPRS) is part of the nuclear 

boiler system and that its purpose is to limit any overpressure that occurs during abnormal 

operational transients. Pressure-operated SRVs are put in place to protect against 

overpressure by discharging steam from the nuclear supply system to the suppression pool. 

The SRVs are located on the main steam lines between the RPV and the first isolation valve 

within the drywell. The main protection functions provided by the SRVs are overpressure relief 

operation, overpressure safety operation, automatic depressurization system operation, and 

post-fire depressurization operation. 
2-35 

The intended functions of the NPRS component types within the scope of license renewal 

include the following: 

 to prevent over-pressurization of the RCPB by use of a pressure relief system 

 to reduce reactor vessel pressure in a LOCA situation in which the HPCI system fails to 

maintain the reactor vessel water level 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

LRA Table 2.3.2-1, “Nuclear Pressure Relief System Components Subject to Aging 

Management Review,” identifies the component types that are within the scope of license 

renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.1 and license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

NPRS components within the scope of license renewal, as required by 10 CFR 54.4(a). The 

staff also concludes that the applicant has adequately identified the NPRS components subject 

to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2.2 Residual Heat Removal System 

 Summary of Technical Information in the Application 

LRA Section 2.3.2.2 states that the RHR system provides RHR capability during normal 

shutdown and restores and maintains the coolant inventory in the reactor vessel to adequately 

cool the reactor core following a LOCA. The RHR system removes heat from primary 

containment to reduce containment pressure and temperature by providing post-LOCA cooling 

for the drywell and suppression pool. The RHR system is also the ultimate heat sink for cooling 

of the safety-related plant equipment. The four modes of operation for the RHR system are 

shutdown cooling, containment cooling (containment spray and suppression pool cooling), 

LPCI, and fuel pool cooling assist. 

The RHR system consists of two heat exchangers and four main system pumps that make two 

loops. Each RHR system loop has a heat exchanger, two main system pumps in parallel, and 

associated piping. The two loops of the RHR system are cross-connected by a single header, 

which makes it possible to supply either loop from the pumps in the other loop. 
2-36 

The intended functions of the RHR system component types within the scope of license renewal 

include the following: 

 to restore and maintain water level in the reactor vessel for cooling after a LOCA 

 to transfer reactor core decay heat and sensible heat from the containment to the RHR 

service water system after a LOCA 

 to reduce containment pressure by spraying water into the suppression chamber 

 to remove decay and sensible heat from the reactor core to cool down and maintain the 

reactor in a cold shutdown condition 

 to assist the fuel pool cooling and cleanup system (FPCCS) in removing decay heat from 

fuel assemblies stored in the fuel pool 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.2-2, “Residual Heat Removal System Components Subject to Aging 

Management Review,” identifies the component types that are within the scope of license 

renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.2; UFSAR Sections 5.2.1.1.10, 5.5.7, 6.2.2, 6.3.2, 

7.1.2.1.27, 7.3.1.2.4, and 7.4.1.3; LRA Table 2.3.2-2; and license renewal drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and updated 

final safety analysis report (UFSAR) to verify that the applicant has included within the scope of 

license renewal all components with intended functions delineated under 10 CFR 54.4(a). The 

staff then reviewed those components that the applicant identified as being within the scope of 

license renewal to verify that it has included all passive and long-lived components subject to an 

AMR, in accordance with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

RHR system components within the scope of license renewal, as required by 10 CFR 54.4(a). 

The staff also concludes that the applicant has adequately identified the RHR system 

components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2.3 Core Spray 

 Summary of Technical Information in the Application 

LRA Section 2.3.2.3 states that the core spray system provides low-pressure coolant flow to the 

core fuel elements following a LOCA. The core spray system gives protection to the core when 

the reactor vessel water level cannot be maintained during a large break in the nuclear system. 

Core spray, in regards to small breaks, provides protection when the reactor vessel water level 
2-37 

cannot be maintained and the automatic depressurization system has operated to lower the 

reactor vessel pressure so that LPCI and core spray systems can provide core cooling. 

The core spray system consists of two independent loops pumping cooling water from the 

suppression pool to independent spray spargers over the core. Each core spray loop consists 

of two motor-driven pumps with suction and discharge connected in parallel, a spray sparger in 

the reactor vessel above the core, piping and valves to convey water from the suppression pool 

to the pumps and to the sparger, and the associated controls and instrumentation. 

The intended functions of the core spray system component types within the scope of license 

renewal include the following: 

 to supply water to the reactor vessel for core cooling after a LOCA 

 to maintain the integrity of the RCPB 

 to support primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.2-3, “Core Spray System Components Subject to Aging Management Review,” 

identifies the component types that are within the scope of license renewal and that are subject 

to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.3 and license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

core spray system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the core 

spray system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2.4 High Pressure Coolant Injection 

 Summary of Technical Information in the Application 

The HPCI system provides reactor core cooling in the event of a small break LOCA that does 

not result in a rapid depressurization of the RCS. The HPCI system maintains adequate reactor 
2-38 

water inventory until the reactor is depressurized to a pressure at which the LPCI system or 

core spray system can be placed in operation. The HPCI system consists of a steam turbine 

assembly; booster pump; gear reducer; main pump; barometric condenser; lubrication and 

control oil system; and associated piping valves, controls, and instrumentation. 

The intended functions of the HPCI system component types within the scope of license 

renewal include the following: 

 to provide reactor core cooling in the event of a small break LOCA that does not result in 

rapid depressurization of the RCS 

 to maintain the integrity of the RCPB 

 to support primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

LRA Table 2.3.2-4, “High Pressure Coolant Injection System Components Subject to Aging 

Management Review,” identifies the components types that are within the scope of license 

renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.4 and license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

HPCI system components within the scope of license renewal, as required by 10 CFR 54.4(a). 

The staff also concludes that the applicant has adequately identified the HPCI system 

components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2.5 Reactor Core Isolation Cooling 

 Summary of Technical Information in the Application 

LRA Section 2.3.2.5 states that the RCIC system provides makeup water for core cooling if the 

reactor is isolated coupled with a loss of feedwater flow from the reactor feedwater system. The 

RCIC system consists of a steam-driven turbine-pump unit and associated valves and piping to 

deliver makeup water to the RPV. The pump suction for the RCIC system is usually lined up to 
2-39 

the condensate storage tank (CST) but is automatically switched to the suppression pool on a 

low CST level or when the suppression pool level is high. 

The intended functions of the RCIC system component types within the scope of license 

renewal include the following: 

 to provide makeup water to the reactor vessel following a reactor vessel isolation 

 to maintain the integrity of the RCPB 

 to support primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

LRA Table 2.3.2-5, “Reactor Core Isolation Cooling System Components Subject to Aging 

Management Review,” identifies the component types that are within the scope of license 

renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.5 and license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

RCIC system components within the scope of license renewal, as required by 10 CFR 54.4(a). 

The staff also concludes that the applicant has adequately identified the RCIC system 

components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2.6 Containment Penetrations 

 Summary of Technical Information in the Application 

LRA Section 2.3.2.6 states that there are two passive provisions for containment of possible 

post-accident airborne contamination: (1) the primary containment system and (2) the 

secondary containment system. The primary containment penetrations are designed for peak 

transient conditions expected during a LOCA. They will withstand, or are shielded from, the 

forces caused by impingement of fluid from the rupture of the largest local pipe or connection. 

Penetrations in the primary and secondary containments provide openings for equipment or 

personnel to pass through the containment boundaries while still maintaining containment 
2-40 

integrity. This review includes mechanical components associated with primary and secondary 

containment penetrations that were not reviewed with other systems. 

LRA Table 2.3.2-6, “Containment Penetrations Components Subject to Aging Management 

Review,” identifies the component types that are within the scope of license renewal and that 

are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.6, UFSAR Section 6.2, and LRA Table 2.3.2-6 using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

containment penetrations components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concluded that the applicant has adequately identified the 

containment penetrations components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2.7 Standby Gas Treatment 

 Summary of Technical Information in the Application 

LRA Section 2.3.2.7 states that the purpose of the standby gas treatment system (SGTS) is to 

minimize the release-related offsite dose rates by permitting the venting and purging of both the 

primary and the secondary containment atmospheres under accident or abnormal conditions 

while containing any airborne particulate or halogen contamination that might be present. 

A severe accident that is beyond the design basis of the plant may result in over-pressurization 

of the primary containment. The SGTS valves may be lined up to relieve this overpressure from 

the primary containment torus through the torus hardened vent system that discharges directly 

to the environment. 

The intended functions of the SGTS component types within the scope of license renewal 

include the following: 

 to minimize the release-related offsite dose rates 

 to limit the unfiltered air from the secondary containment during periods of primary and 

secondary containment isolation 

 to support the primary and secondary containment pressure boundaries 
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 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.2-7, “Standby Gas Treatment System Components Subject to Aging 

Management Review,” identifies the remaining component types that are within the scope of 

license renewal, that are subject to an AMR, and that were not included in other system 

components reviews. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.2.7; UFSAR Sections 6.2.3, 7.1.2.1.16, and 7.3.6; and LRA 

Table 2.3.2-7 using the evaluation methodology described in SER Section 2.3 and the guidance 

in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

SGTS components within the scope of license renewal, as required by 10 CFR 54.4(a). The 

staff also concluded that the applicant has adequately identified the SGTS components subject 

to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.2.8 Miscellaneous ESF Systems in Scope for 10 CFR 54.4(a)(2) 

 Summary of Technical Information in the Application 

LRA Section 2.3.2.8 summarizes scoping and screening for miscellaneous nonsafety-related 

ESF systems or components that are within the scope of license renewal for 10 CFR 54.4(a)(2) 

because of potential physical interactions with safety-related components. These physical 

interactions could cause failure by causing a loss of structural or mechanical integrity of the 

safety-related SSC. The LRA also states that any functional failures of these nonsafety-related 

SSCs were identified and discussed within individual systems’ evaluations of LRA Section 2.3.2 

and are not evaluated in this section (i.e., Section 2.3.2.8). 

LRA Section 2.3.2.8 lists the following systems as being within the scope of license renewal 

based on the criteria in 10 CFR 54.4(a)(2) for physical failure: 

 RHR 

 core spray 

 HPCI 

 RCIC 
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 primary containment penetrations 

 SGTS 

LRA Tables 2.3.2-8-1 – 2.3.2-8-6 identify the component types that are within the scope of 

license renewal and that are subject to an AMR for 10 CFR 54.4(a)(2) based on potential for 

physical interactions. 

 Staff Evaluation 

The staff reviewed the miscellaneous ESF systems in scope for 10 CFR 54.4(a)(2) functions 

described in LRA Section 2.3.2.8 and UFSAR sections (as described in SER Sections 2.3.2.2 – 

2.3.2.7) using the evaluation methodology described in SER Section 2.3 and the guidance in 

SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

miscellaneous ESF systems and components within the scope of license renewal for 

10 CFR 54.4(a)(2), as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

has adequately identified the miscellaneous ESF systems in scope for 10 CFR 54.4(a)(2) 

components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.3 Auxiliary Systems 

LRA Section 2.3.3 identifies the auxiliary systems SCs subject to an AMR for license renewal. 

The applicant described the supporting SCs of the auxiliary systems in the following LRA 

sections: 

 LRA Section 2.3.3.1, “Control Rod Drive” 

 LRA Section 2.3.3.2, “Standby Liquid Control” 

 LRA Section 2.3.3.3, “Service Water” 

 LRA Section 2.3.3.4, “Fuel Pool Cooling and Cleanup” 

 LRA Section 2.3.3.5, “Emergency Equipment Cooling Water” 

 LRA Section 2.3.3.6, “Compressed Air” 

 LRA Section 2.3.3.7, “Fire Protection – Water” 

 LRA Section 2.3.3.8, “Fire Protection – Carbon Dioxide and Halon” 

 LRA Section 2.3.3.9, “Combustion Turbine Generator” 

 LRA Section 2.3.3.10, “Emergency Diesel Generator” 

 LRA Section 2.3.3.11, “Heating, Ventilation, and Air Conditioning” 

 LRA Section 2.3.3.12, “Control Center Heating, Ventilation, and Air Conditioning” 

 LRA Section 2.3.3.13, “Containment Atmospheric Control” 

 LRA Section 2.3.3.14, “Plant Drains” 

 LRA Section 2.3.3.15, “Fuel Oil” 
2-43 

 LRA Section 2.3.3.16, “Primary Containment Monitoring and Leakage Detection” 

 LRA Section 2.3.3.17, “Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2)” 

SER Sections 2.3.3.1 – 2.3.3.17 include the staff’s findings on its review of LRA 

Sections 2.3.3.1 – 2.3.3.17, respectively. 

2.3.3.1 Control Rod Drive 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.1 states the purpose of the control rod drive (CRD) hydraulic control system 

is to provide reactivity control by positioning the control rods to control power generation in the 

core. The CRD system is designed to insert the control rods, when required, with sufficient 

speed to prevent fuel damage from any abnormal operating transient. The control rods are part 

of the reactor assembly. 

The CRD system includes the CRD mechanisms and the supporting hydraulic components, 

including pumps, accumulators, piping, valves, instruments, and controls. 

The intended functions of the CRD system within the scope of license renewal include the 

following: 

 to insert all control rods into the core to quickly shut down the reactor in response to a 

manual or automatic signal 

 to maintain the integrity of the RCPB 

 to support the primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support ATWS (10 CFR 50.62), fire protection (10 CFR 50.48), and SBO 

(10 CFR 50.63) requirements 

LRA Table 2.3.3-1, “Control Rod Drive System Components Subject to Aging Management 

Review,” identifies the component types that are within the scope of license renewal and that 

are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.1, UFSAR Sections 4.5.2.2 and 7.6.1.18, and the license 

renewal boundary drawings using the evaluation methodology discussed in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 
2-44 

The staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. The staff noted on license renewal 

boundary drawing LRA-M-5449 (H-6) that it could not locate a seismic or equivalent anchor on 

nonsafety-related line M-5881-1 continued to drawing LRA-M-2032-1 (D-7) from drawing 

LRA-M-2088 (B-4) and then continued to 1-2400-07 (D-8) and to safety-related valve F180. By 

letter dated November 26, 2014, the staff issued RAI 2.3.3.1-1 requesting that the applicant 

provide additional information to locate the seismic or equivalent anchor between the 

safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.1-1, the applicant provided the 

location of a seismic anchor between the safety-related to nonsafety-related class change and 

safety-related valve F180 on license renewal drawing LRA-M-5449 (H-6). The piping 

encompassing the anchor is in scope per the criterion in 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.1-1 acceptable 

because it has provided the location of the seismic anchor which demonstrates an appropriate 

boundary between the safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping 

boundary. Therefore, the staff’s concern described in RAI 2.3.3.1-1 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI response, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

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

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

system components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). 

2.3.3.2 Standby Liquid Control 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.2 states that the purpose of the SLC system is to provide an alternate 

method of reactor core reactivity control in the event that the CRD system is not available. The 

system is sized to counteract the positive reactivity effect in decreasing power from rated power 

to the cold shutdown condition. The SLC system is also credited for injecting sodium 

pentaborate into the RCS after a design basis LOCA in order to control the emergency core 

cooling system (ECCS) water pH to prevent iodine re-evolution. The SLC system can be 

manually initiated to provide this function. 

The major components of the SLC system consist of a storage tank, two positive displacement 

pumps, two explosive valves, and two check valves between the explosive valves and the 

reactor. 

The intended functions of the SLC system within the scope of license renewal include the 

following: 

 to provide the capability of controlling suppression pool pH following a LOCA in the 

event of fuel failure 

 to maintain the integrity of the RCPB 

 to support the primary containment pressure boundary 
2-45 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support ATWS (10 CFR 50.62) and fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.3-2, “Standby Liquid Control System Components Subject to Aging Management 

Review,” identifies the SLC system component types that are within the scope of license 

renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.2; UFSAR Sections 1.2.2.10.1, 7.1.2.1.21, 4.5.2.4, 

7.4.1.2, 5.2.1.1.9, 4.5.1.2.11, 7.7.1.2.3.1, 15.3, 3.9, and 15.8.1; and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff noted on license renewal 

boundary drawing LRA-M-2082 (F-5) that it could not locate a seismic or equivalent anchor on 

nonsafety-related line M-3584 continued to drawing LRA-M-2678 and to safety-related valve 

F014. By letter dated November 26, 2014, the staff issued RAI 2.3.3.2-1 requesting that the 

applicant provide additional information to locate the seismic or equivalent anchors between the 

safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.2-1, the applicant provided the 

location of an equivalent anchor between the safety-related to nonsafety-related class change 

and safety-related valve F014 on license renewal drawing LRA-M-2082 (F-5). The piping 

encompassing the anchor is in scope per the criterion in 10 CFR 54.4(a)(2). 

The staff finds the applicant’s response to RAI 2.3.3.2-1 acceptable because it provided the 

location of an equivalent anchor. The staff’s concern described in RAI 2.3.3.2-1 is resolved. 

In addition, the staff noted on license renewal boundary drawing LRA-M-2082 (F-3) that it could 

not locate a seismic or equivalent anchor on nonsafety-related line M-3584 continued from 

drawing LRA-M-2678 and the plant air system to safety-related storage tank (C4101A001). By 

letter dated November 26, 2014, the staff issued RAI 2.3.3.2-2 requesting that the applicant 

provide additional information to locate the seismic or equivalent anchor between the 

safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.2-2, the applicant stated that the 

safety-related storage tank C4101A001 is a base-mounted component and does not rely on the 

attached nonsafety-related piping to ensure seismic support. 
2-46 

The staff finds the applicant’s response to RAI 2.3.3.2-2 acceptable because it explained why a 

seismic or equivalent anchor was not required. Therefore, the staff’s concern described in 

RAI 2.3.3.2-2 is resolved. 

By letter dated May 20, 2015, the staff issued RAI 4.1-4a, Parts a, b, and c, to the applicant. 

RAI 4.1-4a, Parts a and b, requested that the applicant justify why the structural integrity of the 

internal portions of the standby liquid control and core differential pressure (SLC/core ∆P) line 

has not been identified as an intended function for license renewal and would not be required to 

be within the scope of license renewal. Additionally, in RAI 4.1-4a, Part c, the staff requested 

that the applicant state the applicable aging effects requiring management that apply to the 

components and justify how it will manage these aging effects during the period of extended 

operation. This SER section documents the staff’s evaluation of the applicant’s response to 

RAI 4.1-4a, Parts a and b. SER Section 3.0.3.2.3 documents the staff’s evaluation of the 

applicant’s response to RAI 4.1-4a, Part c. 

By letter dated July 6, 2015, the applicant responded to RAI 4.1-4a. The applicant also 

provided a supplemental response to RAI 4.1-4a by letter dated August 20, 2015. In response 

to Parts a and b, the applicant stated that, for the purpose of license renewal, it will assume that 

the SLC/core ∆P line internal to the reactor vessel does perform a license renewal intended 

function per 10 CFR 54.4(a)(3). Because the SLC system is within the scope of license renewal 

and because the SLC/core ∆P line internal to the vessel performs an intended function, the line 

is subject to an AMR. The SLC/core ∆P line internal to the vessel is stainless steel and is 

exposed to an environment of treated water greater than 140 °F. Based on this 

material/environment combination, the applicable aging effects requiring management are loss 

of material and cracking. The loss of material and cracking will be managed by the Water 

Chemistry Control – BWR Program as verified by the One-Time Inspection Program. The 

applicant also stated that it will manage cracking using the BWR Vessel Internals Program and 

will perform opportunistic inspections of the SLC/core ∆P line internal to the reactor vessel 

during the period of extended operation. SER Section 3.0.3.2.3 documents the staff’s full 

evaluation of RAI 4.1-4a, Part c. 

The staff finds the applicant’s response acceptable because it stated that the SLC/core ∆P line 

internal to the vessel performs a license renewal intended function per 10 CFR 54.4(a)(3). The 

applicant also stated that because the SLC system is within the scope of license renewal and 

because the SLC/core ∆P line internal to the vessel performs an intended function, the line is 

subject to an AMR. The staff’s concern described in RAI 4.1-4a, Parts a and b, is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI responses, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the standby liquid control system components within the scope of license renewal, as required 

by 10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

system components subject to an AMR in accordance with 10 CFR 54.21(a)(1). 

2.3.3.3 Service Water 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.3 includes the EESW system, residual heat removal service water (RHRSW) 

system, and RHR complex support equipment. 
2-47 

The EESW system provides cooling water to the EECW heat exchangers and transfer heat to 

the ultimate heat sink. The system consists of two cooling water flow trains, Division I and 

Division II, that supply cooling water to the corresponding Division I and II EECW heat 

exchangers. Heat from the EECW heat exchangers is rejected to the reservoir heat sink or to 

the atmosphere through the mechanical-draft cooling towers. 

The RHRSW system consists of two redundant cooling water flow trains, Division I and 

Division II, that supply cooling water to the corresponding Division I and II RHR heat 

exchangers. A cross-tie in Division II is provided at the discharge of a pair of RHRSW pumps 

and the RHR heat exchanger shell side discharge piping to facilitate flooding of the reactor 

vessel in the unlikely event that all RHR (LPCI) and core spray pumps fail to operate following a 

postulated LOCA. 

The RHR complex consists of a water supply reservoir; a means for heat rejection (cooling 

towers); a makeup and decanting system; and associated pumps, piping, and instrumentation. 

The RHR complex also includes a standby power source comprising four emergency diesel 

generators (EDGs) and the related EDG service water (EDGSW) pumps and EESW pumps and 

the related components. The RHR complex reservoir consists of two one-half capacity 

reinforced-concrete structures. The reservoirs are connected by redundant valve lines to permit 

access to the combined inventory of the two reservoirs to either division in the event of a 

mechanical failure in one of the divisions. 

A two-cell induced-draft cooling tower is located over each division reservoir. Each tower cools 

one division of the plant load (return flow from one RHRSW loop, one EESW loop, and two 

EDGSW loops). 

The intended functions of the service water system within the scope of license renewal include 

the following: 

 to transfer heat from the EECW and RHR heat exchangers to the ultimate heat sink 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

 to provide cooling of service water returned from safety-related plant equipment 

 to maintain a source of cooling water for the RHRSW, EESW, and EDGSW systems 

LRA Table 2.3.3-3, “Service Water System Components Subject to Aging Management 

Review,” identifies the service water system component types that are within the scope of 

license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.3, UFSAR Sections 9.2.2 and 9.2.5, and the license 

renewal boundary drawings using the evaluation methodology discussed in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 
2-48 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff noted during its review of the 

drawings and locations in Table 2.3-1 below, that it could not locate continuation of piping within 

the scope of license renewal; therefore, the staff could not verify the scoping of SSCs. By letter 

dated November 26, 2014, the staff issued RAI 2.3.3.3-1 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. In addition, the staff requested the 

following information: (1) if the continuation cannot be shown on license renewal boundary 

drawings, provide additional information describing the extent of the scoping boundary, 

(2) identify any additional component types subject to an AMR between the continuation and the 

termination of the scoping boundary, and (3) if the scoping classification of a piping section 

changes over the continuation, provide additional information to clarify the change in 

classification. 

Table 2.3-1 Service Water System Piping Continuations Not within the Scope of License 

Renewal 

LRA Drawing Location Continuation Issue

LRA-M-2083 C-8 In-scope continuation to drawing 

I-2400-04. Drawing I-2400-04 was 

not provided. 

LRA-M-2084 D-2 In-scope continuation to drawing 

I-2400-04. Drawing I-2400-04 was 

not provided. 

In its response letter dated December 30, 2014, to RAI 2.3.3.3-1, the applicant stated that 

drawing I-2400-04 shows the two piping lines from drawings LRA-M-2083 and LRA-M-2084 

continuing through valves, then continuing through sample roughing coolers, and then 

terminating at a sample panel. The piping, valves, and sample roughing coolers are in scope 

and subject to an AMR under “piping,” “valve body,” and “cooler housing.” There are no 

additional component types subject to an AMR between the continuation to drawing I-2400-04 

and the sample panel. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.3-1 acceptable 

because it provided the location of the scoping boundary and component types between the 

continuation and scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.3-1 is 

resolved. 

The staff noted on license renewal boundary drawing LRA-M-2083 (C-8) and LRA-M-2084 (D-2) 

that it could not locate seismic or equivalent anchors on the 10 CFR 54.4(a)(2) 

nonsafety-related line continued from safety-related valve F080B to drawing I-2400-04 (D-4) 

and from safety-related valve F080A to drawing I-2400-04 (D-2). By letter dated 

November 26, 2014, the staff issued RAI 2.3.3.3-2 requesting that the applicant provide 

additional information to locate the seismic or equivalent anchors between the safety-nonsafety 

interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.3-2, the applicant stated that the 

seismic design analysis demonstrates that the seismic boundaries are just past valves F080B 
2-49 

and F080A, respectively. There is a transition to 1⁄4-inch tubing just beyond valves F080A and 

F080B, and the seismic design analysis excludes the 1⁄4-inch tubing based on the moment of 

inertia ratio. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.3-2 acceptable 

because it provided the basis for not needing a seismic anchor. The staff’s concern described 

in RAI 2.3.3.3-2 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI responses, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the service water system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant has adequately 

identified the system components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). 

2.3.3.4 Fuel Pool Cooling and Cleanup System 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.4 includes the FPCCS and the fuel-service and -handling equipment. 

LRA Section 2.3.3.4 states that the purpose of the FPCCS is to remove the decay heat 

produced by stored spent fuel assemblies. The FPCCS cools the spent fuel pool by transferring 

decay heat through heat exchangers to the reactor building closed cooling water (RBCCW) 

system. The system consists of two fuel pool cooling pumps; two heat exchangers; two filter 

demineralizers; two skimmer surge tanks; and associated piping, valves, and instrumentation. 

The normal makeup water source for the system is provided from the CST to the skimmer surge 

tanks. The FPCCS does not serve any safety function. 

The fuel-service and -handling equipment system consists of equipment used for moving fuel 

during refueling and other outage inspections and tasks, as well as spent fuel storage. Fermi 2 

uses two types of high-density spent fuel storage racks. The Joseph Oat Corporation (OAT) 

racks use Boraflex as a neutron absorber; the Holtec International racks use Boral. The reactor 

vessel fuel storage equipment system includes the nonsafety-related new fuel racks, which 

provide structural support for new fuel. 

The intended functions of the FPCCS within the scope of license renewal include the following: 

 to backup makeup and cooling for spent fuel storage pool from the RHR system 

 to support the secondary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to provide neutron absorption in the spent fuel pool 

 to provide structural support of fuel assemblies in the spent fuel pool 
2-50 

LRA Table 2.3.3-4, “Fuel Pool Cooling and Cleanup System Components Subject to Aging 

Management Review,” identifies the FPCCS component types that are within the scope of 

license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.4; UFSAR Sections 1.2.2.15.2, 9.1.2.2.2, 7.6.1.15, 

9.1.4.2, 9.1.3, and 12.1.1.1; Table 9.1-5, “Tools and Servicing Equipment,” in the UFSAR; and 

the license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff noted on license renewal 

boundary drawing LRA-M-2048 (H-4) that it could not locate seismic anchors on 

nonsafety-related lines M-3631 (C-3) and M-3629 (B-5) to line M-3363 to safety-related valve 

F011. By letter dated November 26, 2014, the staff issued RAI 2.3.3.4-1 requesting that the 

applicant provide additional information to locate the seismic or equivalent anchors between the 

safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.4-1, the applicant provided the 

location of a seismic anchor between the safety-related to nonsafety-related class change and 

safety-related valve F011 on license renewal drawing LRA-M-2048. The piping encompassing 

the anchor is in scope per the criterion in 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.4-1 acceptable 

because it provided the location of the seismic anchor. Therefore, the staff’s concern described 

in RAI 2.3.3.4-1 is resolved. 

The staff also noted during its review of drawing LRA-M-2048 (E-8) that the continuation of 

piping within the scope of license renewal was not provided for line M-3608. By letter dated 

November 26, 2014, the staff issued RAI 2.3.3.4-2 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. In addition, the staff requested the 

following: (1) if the continuation cannot be shown on license renewal boundary drawings, 

provide additional information describing the extent of the scoping boundary, (2) identify any 

additional component types subject to an AMR between the continuation and the termination of 

the scoping boundary, and (3) if the scoping classification of a piping section changes over the 

continuation, provide additional information to clarify the change in classification. 

In its response letter dated December 30, 2014, to RAI 2.3.3.4-2, the applicant stated that the 

pipe line from LRA-M-2048 continues to the hotwell and that there are no additional component 

types subject to an AMR between the continuation and the hotwell. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.4-2 acceptable 

because it provided the location of the scoping boundary and stated that there were no new 
2-51 

component types between the continuation and the scoping boundary. Therefore, the staff’s 

concern described in RAI 2.3.3.4-2 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI responses, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the FPCCS mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

system components subject to an AMR in accordance with 10 CFR 54.21(a)(1). 

2.3.3.5 Emergency Equipment Cooling Water System 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.5 states that the purpose of the EECW system is to supply cooling water to 

ESF equipment and other equipment required for a safe shutdown of the reactor. The EECW 

system consists of two cooling water flow trains, Division I and Division II, supplying cooling 

water to safety-related and select nonsafety-related equipment. Each division can be supplied 

with cooling water from a circulating EECW pump and EECW heat exchanger or from the 

RBCCW pumps and RBCCW heat exchangers. 

Normally, the nonsafety-related RBCCW system supplies cooling water to both safety-related 

and nonsafety-related components supplied by the EECW piping system. Under normal 

operating conditions, the EECW pumps and heat exchangers are in standby mode. 

The intended functions of the EECW system within the scope of license renewal include the 

following: 

 to supply cooling water to ESF equipment and other equipment required for a safe 

shutdown of the reactor 

 to support the primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.3-5 identifies the EECW component types that are within the scope of license 

renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.5; UFSAR Sections 1.2.2.9.21, 7.1.2.1.18, and 9.2.2; and 

the license renewal boundary drawings using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 
2-52 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, and license renewal boundary 

drawings, the staff concludes that the applicant has appropriately identified the EECW 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant has adequately identified the system components subject to an 

AMR, as required by 10 CFR 54.21(a)(1). 

2.3.3.6 Compressed Air System 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.6 addresses three systems as follows: 

 station air, control air, and emergency breathing air systems 

 reactor/auxiliary building superstructure, which includes compressed air components 

supporting the reactor building railroad airlock doors 

 primary containment pneumatics (PCP) system, which includes both compressed air and 

compressed nitrogen components 

LRA Section 2.3.3.6 states that the purpose of the station air and control air systems is to 

provide the plant with a reliable source of clean, dry, oil-free compressed air for plant operation. 

The station air system provides air for nonessential uses, such as for routine maintenance 

operations or in equipment process cycles, such as demineralizer backwashing. The control air 

system supplies air for I&C applications. The purpose of the emergency breathing air system is 

to provide breathing air to control room personnel if a potentially hazardous environment exists 

in the control room. 

The control air system is divided into two parts: (1) interruptible and (2) non-interruptible. The 

non-interruptible control air supplies air to safety-related instruments and controls required to 

effect a safe reactor shutdown and control during long-term recovery. 

The reactor/auxiliary building superstructure includes safety-related mechanical components 

that support the operation of the reactor building railroad airlock doors. These doors form part 

of the secondary containment pressure boundary. 

The purpose of the PCP system is to provide pneumatic pressure for the activation of 

safety-related valves and other equipment inside the drywell. Supplied equipment includes 

nuclear pressure relief valves, containment isolation valves, testable/exercisable check valves, 

and the traversing incore probe purge valve assembly and indexing mechanism. 

The intended functions of the compressed air systems within the scope of license renewal 

include the following: 

 to provide sufficient air storage by safety-related accumulators to supply essential 

equipment during and following a postulated LOCA 

 to provide an emergency source of breathing air for control room personnel use 
2-53 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

 to support the primary and secondary containment pressure boundaries 

 to provide pneumatic pressure for the activation of safety-related equipment 

LRA Table 2.3.3-6, “Compressed Air Systems Components Subject to Aging Management 

Review,” identifies the compressed air system component types that are within the scope of 

license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.6; UFSAR Sections 6.4.2.5, 7.6.1.17, 7.1.2.1.32, 9.3.1, 

6.2.1.2.2, 5.2.2.2, and 9.3.6; and the license renewal boundary drawings using the evaluation 

methodology discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. The staff noted during its review of 

drawings that it could not locate continuations of piping within the scope of license renewal; 

therefore, the staff could not verify the scoping boundary of SSCs. Drawing LRA-M-4615 shows 

that safety-related control air system lines are in scope for 10 CFR 54.4(a)(1). However, 

portions of lines at several locations throughout the drawing show continuations to dampers 

(D-3, D-4, and C-6); to instrument racks (with comment “to IR” at C-3, C-5, D-5, and D-7); to 

solenoid valves (with comment “to E/V” at locations D-5 through D-7 and C-8); and to 

positioners (B-4 and B-8) without clear representation of the components; therefore, the staff 

could not verify the scoping boundary of SSCs. By letter dated November 26, 2014, the staff 

issued RAI 2.3.3.6-1 requesting that the applicant provide sufficient information to locate the 

license renewal boundary. In addition, the staff requested the following: (1) if the continuation 

cannot be shown on license renewal boundary drawings, provide additional information 

describing the extent of the scoping boundary, (2) identify any additional component types 

subject to an AMR between the continuation and the termination of the scoping boundary, and 

(3) if the scoping classification of a piping section changes over the continuation, provide 

additional information to clarify the change in classification. 

In its response letter dated December 30, 2014, to RAI 2.3.3.6-1, the applicant stated that there 

are no additional component types subject to an AMR between the continuations to the 

dampers, instrument racks, solenoid valves, and the positioners and their corresponding license 

renewal boundaries. The passive compressed air pressure boundary components (valves, 

tubing, and piping) supporting the dampers or the boundary up to the racks are subject to an 

AMR, and there are no scoping changes across those continuations. 
2-54 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.6-1 acceptable 

because it provided the location of the license renewal boundaries and component types 

between the continuation and the scoping boundary. Therefore, the staff’s concern described in 

RAI 2.3.3.6-1 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI response, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the compressed air system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant adequately identified 

the system components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). 

2.3.3.7 Fire Protection – Water 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.7 states that the purpose of the fire protection system is to provide fire 

protection for all potential fire hazards. The fire protection system provides prompt fire 

detection, alarm, and suppression. Included in the fire protection system are a fire protection 

water supply and distribution system, fixed water spray and automatic sprinkler systems, 

gaseous extinguishing systems, and a fire detection and alarm system. 

The water-based fire protection consists of manually operated hose stations and fire hydrants 

and manual and automatic sprinkler and water spray systems. All of these are supplied with 

water from an underground distribution loop that surrounds the Fermi 2 plant. The normal 

source of water to the fire water distribution loop is from the general service water (GSW) 

system via a jockey pump that takes suction from the GSW pump discharge header and 

pressurizes the fire protection water distribution loop. There are two fire water pumps located in 

the GSW pump house that automatically supply water directly from Lake Erie if the fire water 

loop pressure drops below pre-set limits. 

The fire protection water system includes components from the GSW biocide injection system. 

The purpose of the GSW biocide injection system is to treat the GSW system with a biocide to 

inhibit slime and algae growth and to control organic and inorganic fouling of heat exchanger 

and piping surfaces. 

The intended functions of the fire protection system with the scope of license renewal include 

the following: 

 to support the safety-related pressure boundary of the control center heating, ventilation, 

and air conditioning (HVAC) system 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.3-7, “Fire Protection – Water System Components Subject to Aging Management 

Review,” identifies the fire protection system component types that are within the scope of 

license renewal and that are subject to an AMR. 
2-55 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.7 and relevant LRA drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 

also reviewed UFSAR Sections 9.5.1 and 9A, which describes the fire protection program for 

Fermi 2, and the guidelines of Appendix A to Branch Technical Position (BTP), “Auxiliary Power 

Conversion System Branch (APCSB) 9.5-1.” 

The staff also reviewed the following fire protection documents cited in the CLBs listed in the 

Fermi 2 Operating License Condition 2.C(9): 

 NUREG-0798, Supplement 5, “Safety Evaluation Report Related to the Operation of 

Fermi 2,” dated March 1985 

 NUREG-0798, Supplement 6, “Safety Evaluation Report Related to the Operation of 

Fermi 2,” dated July 1985 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive or long-lived components subject to an AMR, in accordance with 

10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The applicant responded to the staff’s 

RAIs as discussed below. 

The staff noted that LRA boundary drawing LRA-M-4548 shows Halon 1301 (Halon) and 

FM-200 (or clean agent) subfloor zone fire protection systems at locations C5 and E2 as not 

defined within the scope of license renewal (i.e., not colored in green). 

By letter dated October 29, 2014, the staff issued RAI 2.3.3.7-1 requesting that the applicant 

verify whether the above Halon and FM-200 fire protection systems/components are within the 

scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an 

AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license 

renewal and are not subject to an AMR, the staff requested that the applicant provide 

justification for the exclusion. 

In its response dated December 1, 2014, to RAI 2.3.3.7-1, the applicant stated the following: 

Specific Halon fire protection system components in drawing LRA-M-4548 

location C-5 are in scope and subject to an AMR while the components in 

location E-2 are not in scope and not subject to an AMR. Drawing LRA-M-4548 

location C-5 depicts a typical Halon configuration for four sub-floor zones. Of 

these four zones represented by this typical configuration, only zone 13, the 

computer room sub-floor in the auxiliary building, performs a license renewal 

intended function. Although the components at location C-5 are not highlighted, 

those components associated with the computer room sub-floor in the auxiliary 

building are subject to an AMR and the component types and intended functions 

are included in LRA Table 2.3.3-8. LRA Table 3.3.2-8 provides the 

corresponding AMR results. The remaining sub-floor zones shown on drawing 
2-56 

LRA-M-4548 locations C-5 and E-2 perform no license renewal intended function 

as they are not required for compliance with 10 CFR 50.48. These zones do not 

protect areas with safety-related equipment or equipment required for safeshutdown. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.7-1 acceptable 

because it clarified that the Halon fire protection system components in drawing LRA-M-4548 

location C-5 are within the scope of license renewal and subject to an AMR. The Halon fire 

protection system components in drawing LRA-M-4548 location E-2 are not within the scope of 

license renewal and are not subject to an AMR. Furthermore, the applicant explained that 

location C-5 in the drawing LRA-M-4548 Halon system consists of four zones, of which only one 

zone (zone 13) Halon fire suppression system and associated components are within the scope 

of license renewal and are subject to an AMR. The remaining three subfloor Halon fire 

suppression systems are not within the scope of license renewal because they perform no 

license renewal intended function and are not required for compliance with 10 CFR 50.48. 

These zones do not protect areas with safety-related equipment or equipment required for safe 

shutdown. Therefore, since there is no intended function associated with 10 CFR 54.4(a), the 

Halon fire suppression system and associated components at locations E-2 and C-5 (three 

subzones) were correctly excluded from the scope of license renewal and are not subject to an 

AMR. Therefore, the staff’s concern described in RAI 2.3.3.7-1 is resolved. 

The staff noted during its review that use of the FM-200 fire protection system or the clean 

agent fire suppression system is limited to the radwaste building for various administrative 

areas, which do not include any systems or circuits credited for reactor shutdown in the event of 

a fire. Therefore, activation of the clean agent fire suppression system will not adversely affect 

the plant’s ability to achieve and maintain shutdown in the event of a fire (UFSAR 

Section 9.5.1.2.3.6). 

In RAI 2.3.3.7-2, dated October 29, 2014, the staff stated that LRA Section 2.3.3.7, on 

page 2.3-107, states that “the control center Heating, Ventilation and Air Conditioning (HVAC) 

makeup filter and recirculating filter charcoal adsorber units are each provided with water spray 

protection supplied from the fire water system...” The water spray fire protection system does 

not appear in LRA drawings as being within the scope of the license renewal and subject to an 

AMR. The staff requested that the applicant verify whether the above water spray fire protection 

system is within the scope of license renewal in accordance with 10 CFR 54.4(a) and is subject 

to an AMR in accordance with 10 CFR 54.21(a)(1). If the system is excluded from the scope of 

license renewal and is not subject to an AMR, the staff requested that the applicant provide 

justification for the exclusion. 

In a letter dated December 1, 2014, the applicant responded to RAI 2.3.3.7-2 by stating the 

following: 

The control center HVAC makeup filter charcoal adsorber unit is within the scope 

of license renewal and subject to an AMR. As shown on drawing LRA-M-2135-1 

(F-2), zone 38 is the control center HVAC makeup filter charcoal adsorber unit. 

The isolation valve (F180) for zone 38 water spray system is shown as subject to 

an AMR on drawing LRA-M-2135 (F-5). Water spray system components are not 

shown on an LRA drawing, but are included in LRA Table 2.3.3-7. 

The control center HVAC recirculating filter charcoal adsorber unit is within the 

scope of license renewal and subject to an AMR. As shown on drawing 
2-57 

LRA-M-2135-1 (F-2), zone 39 is the control center HVAC recirculating filter 

charcoal adsorber unit. The isolation valve (F179) for zone 39 water spray 

system is shown as subject to an AMR on drawing LRA-M-2135 (F-5). Water 

spray system components are not shown on an LRA drawing, but are included in 

LRA Table 2.3.3-7. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.7-2 acceptable 

because it clarified that the zone 38 and zone 39 control center HVAC makeup filter and 

recirculating filter charcoal adsorber unit’s water spray protection systems and associated 

components are included within the scope of license renewal and subject to an AMR. 

Therefore, the staff’s concern described in RAI 2.3.3.7-2 is resolved. 

In RAI 2.3.3.7-3, dated October 29, 2014, the staff stated that LRA Tables 2.3.3-7 and 3.3.2-7, 

“Fire Protection – Water System Summary of Aging Management Evaluation,” do not include 

the following fire protection components: 

 GSW biocide injection system components 

 fire hose stations, fire hose connections, and hose racks 

 pipe fittings, pipe supports, hangers, and couplings 

 standpipe risers 

 water spray nozzles 

 floor drains for removal of fire water 

 fuel storage tank for diesel fire pump 

 turbine building roof smoke and heat vent housings 

The staff requested that the applicant verify whether the fire protection components listed above 

are within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they 

are subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the 

scope of license renewal and are not subject to an AMR, the staff requested that the applicant 

provide justification for the exclusion. 

In its response, dated December 1, 2014, to RAI 2.3.3.7-3, the applicant stated the following: 

GSW biocide injection system has no intended function for 10 CFR 54.4(a)(1) or 

(a)(2), but does perform an (a)(3) function for fire protection (10 CFR 50.48). 

GSW biocide injection system components are not required for 10 CFR 50.48 

except for valve F069 shown on drawing LRA-M-2135-1 (C-2) of the biocide 

injection system which is included within the scope of license renewal as it 

supports the pressure boundary of the fire water system. This valve is included 

in LRA Table 2.3.3-7 under the component type “Valve body” with AMR results in 

LRA Table 3.3.2-7. 

Fire hose stations are within the scope of license renewal and subject to an 

AMR. Hose stations are included in the structural AMR as component type “Fire 

hose reels.” This item is included in LRA Table 2.4-4 with AMR results in LRA 

Table 3.5.2-4. Fire hose connections are within the scope of license renewal and 

subject to an AMR as indicated in LRA Table 2.3.3-7 under the component type 

“Piping” with AMR results in LRA Table 3.3.2-7. Hose racks are within the scope 

of license renewal and subject to an AMR. Hose racks are included in the 

structural AMR as component type “Fire hose reels.” This item is included in 

LRA Table 2.4-4 with AMR results in LRA Table 3.5.2-4. 
2-58 

Pipe fittings are within the scope of license renewal and subject to an AMR. As 

stated in LRA Section 2.0, the term piping in component lists includes pipe and 

pipe fittings. Pipe fittings are included in LRA Table 2.3.3-7 under the component 

type “Piping” with AMR results in LRA Table 3.3.2-7. Pipe supports and hangers 

are within the scope of license renewal and subject to an AMR. Pipe supports 

and hangers are included in the structural AMR as support members. This item 

is included in LRA Table 2.4-4 AMR results in LRA Table 3.5.2-4. Couplings are 

within the scope of license renewal and subject to an AMR. Couplings are 

included in LRA Table 2.3.3-7 under the component type “Piping” with AMR 

results in LRA Table 3.3.2-7. 

Standpipe risers are within the scope of license renewal and subject to an AMR. 

Standpipe risers are included in LRA Table 2.3.3-7 under the component type 

“Piping” with AMR results in LRA Table 3.3.2-7. 

Water spray nozzles are within the scope of license renewal and subject to an 

AMR. Water spray nozzles are included in LRA Table 2.3.3-7 under the 

component type “Sprinkler” with AMR results in LRA Table 3.3.2-7. 

Floor drains for removal of fire water are within the scope of license renewal and 

subject to an AMR. Floor drains are included in LRA Table 2.3.3-14 under the 

component type “Drain” with AMR results in LRA Table 3.3.2-14. 

The fuel storage tank for the diesel fire pump is within the scope of license 

renewal and subject to an AMR. The fuel storage tank is included in LRA 

Table 2.3.3-15 under the component type “Tank” with AMR results in LRA 

Table 3.3.2-15. 

Turbine building roof smoke and heat vent housings are within the scope of 

license renewal and subject to an AMR. The roof vent housings are included in 

the structural AMR as vents and louvers as part of component type 

“Miscellaneous steel.” This item is included in LRA Table 2.4-4 with AMR results 

in LRA Table 3.5.2-4. 

In reviewing the applicant’s response to the RAI, the staff finds that the applicant had addressed 

and resolved each item in the RAI, as discussed in the following paragraphs. 

The applicant indicated that only valve F069 associated with biocide injection system GSW 

shown on drawing LRA-M-2135-1, location C2, is included within the scope of license renewal. 

This valve is included in LRA Table 2.3.3-7 under the component type “Valve body” with AMR 

results in LRA Table 3.3.2-7. 

Although the description of the “fire hose stations” and “hose racks” line items in LRA 

Table 2.3.3-7 does not list these components specifically, the applicant stated that it considers 

these line items to be included with the “Fire hose reels” in LRA Table 2.4-4, “Bulk Commodities 

Components Subject to Aging Management Review,” with AMR results in LRA Table 3.5.2-4, 

“Bulk Commodities Summary of Aging Management Evaluation.” Fire hose connections are 

included in the category of “Piping” in LRA Table 2.3.3 7 with AMR results provided in LRA 

Table 3.3.2-7. 
2-59 

The pipe fittings, couplings, and standpipe risers are included in LRA Table 2.3.3-7 with AMR 

results in LRA Table 3.3.2-7 under component type “Piping.” Pipe supports and hangers are 

included in LRA Table 2.4-4 with AMR results in LRA Table 3.5.2-4 under “Structural support 

members.” 

Water spray nozzles are included in LRA Table 2.3.3-7 under the component type “Sprinkler” 

with AMR results in LRA Table 3.3.2-7. 

The floor drains are included in LRA Table 2.3.3-14, “Plant Drains System Components Subject 

to Aging Management Review,” under the component type “Drain” with AMR results in LRA 

Table 3.3.2-14, “Plant Drains Summary of Aging Management Evaluation.” 

The fuel storage tank is included in LRA Table 2.3.3-15, “Fuel Oil System Components Subject 

to Aging Management Review,” under the component type “Tank” with AMR results in LRA 

Table 3.3.2-15, “Fuel Oil Systems Summary of Aging Management Evaluation.” 

The turbine building roof smoke and heat vent housings are included in the structural AMR as 

vents and louvers as part of component type “Miscellaneous steel.” This item is included in LRA 

Table 2.4-4 with AMR results in LRA Table 3.5.2-4. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.7-3 acceptable 

because it provided clarification that the fire protection system and components listed above are 

within the scope of license renewal and subject to an AMR as required by 10 CFR 54.4(a) and 

10 CFR 54.21(a)(1), respectively. The staff’s concern described in RAI 2.3.3.7-3 is resolved. 

In RAI 2.3.3.7-4, dated December 17, 2014, the staff stated that LRA Section 2.3.3.7, “Fire 

Protection – Water,” acknowledges that fire damper housings mounted in ductwork that are 

needed for compliance with 10 CFR 50.48 are addressed in LRA Section 2.3.3.11, “Heating, 

Ventilation, and Air Conditioning.” LRA Table 2.3.3-11, “Heating, Ventilation and Air 

Conditioning System Components Subject to Aging Management Review,” and LRA 

Table 3.3.2-11, “Heating, Ventilation and Air Conditioning Systems Summary of Aging 

Management Evaluation,” include the component type “Damper housing” as a component 

subject to an AMR and list the intended function as “pressure boundary.” 

GALL Report Table IX.B, “Selected Definitions & Use of Terms for Describing and Standardizing 

Structures and Components,” defines “ducting and components” as including fire dampers. 

However, the SRP-LR and the GALL Report do not differentiate between air control or air flow 

dampers and fire dampers that are needed for compliance with 10 CFR 50.48. If the fire 

damper assemblies are required for compliance with 10 CFR 50.48, then the appropriate 

intended function should be identified and maintained during the period of extended operation. 

The staff requested that the applicant state whether the fire damper assemblies form part of the 

plant fire barriers. If so, the staff requested that the applicant explain why it did not identify fire 

damper assemblies as a fire barrier intended function in accordance with 10 CFR 54.4(b). 

In a letter dated January 15, 2015, the applicant responded to RAI 2.3.3.7-4 by stating the 

following: 

The fire damper assemblies form part of the plant fire barriers. Fire damper 

housings are within the scope of license renewal. Where the fire dampers are in 

a wall, they are covered as a structural component as discussed in the response 
2-60 

to RAI 2.4.4-2. Where fire damper housings are in duct work, they are covered in 

the HVAC systems as the component type “damper housing” as shown in LRA 

Tables 2.3.3-11 and 2.3.3-12. As shown in LRA Tables 3.3.2-11 and 3.3.2-12, 

the effects of aging on damper housings are managed by the External Surfaces 

Monitoring Program and Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. This treatment is consistent with NUREG-1801, which 

includes housings for fire dampers in the category of “Ducting and components.” 

Damper housings within ductwork are not included in the scope of NUREG-1801 

XI.M26, Fire Protection. Ducting is included in XI.M36, External Surfaces 

Monitoring of Mechanical Components, and XI.M38, Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components. 

Further, the applicant stated that in LRA Section 2.1.1, Fermi 2 scoping was 

performed on a system and structure basis. LRA-Sections 2.3.3.11 and 2.3.3.12 

both identify that the HVAC systems perform a function that demonstrates 

compliance with the Commission’s regulations for fire protection (10 CFR 50.48). 

This is one of the functions that is the basis for including the systems within the 

scope of license renewal. At the component level, fire damper housings are 

assigned the pressure boundary intended function. Managing the effects of 

aging to assure the pressure boundary function of the damper housings ensures 

that the fire dampers remain capable of supporting the fire protection system 

level function that was the basis for inclusion in the scope of license renewal. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.7-4 acceptable 

because it clarified that the fire damper assemblies forming part of the plant fire barriers are 

included within the scope of license renewal and are subject to an AMR. The staff confirmed 

that the fire damper housings are included in HVAC systems in LRA scoping and screening 

Tables 2.3.3-11 and 2.3.3-12, “Control Center HVAC System Components Subject to Aging 

Management Review,” under the structural component type “Damper housing.” Furthermore, 

the staff confirmed that the effects of aging on damper housings are managed by the External 

Surfaces Monitoring Program and Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program and are included in LRA Table 3.2.1, “Summary of Aging Management 

Programs for Engineered Safety Features Evaluated in Chapter V of NUREG-1801,” under 

component type “Steel piping and components (internal surfaces), ducting and components 

(internal surfaces) exposed to air – indoor, uncontrolled (internal)” (item 3.2.1-44). The aging 

effects of damper housings within the HVAC ducting are managed under GALL Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” and GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components.” The staff’s concern described in RAI 2.3.3.7-4 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR Sections 9.5.1 and 9A, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the fire protection system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 
2-61 

2.3.3.8 Fire Protection – Carbon Dioxide and Halon 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.8 states that the gaseous-based fire protection consists of carbon dioxide 

(CO2) and Halon 1301 (Halon) suppression systems and manually operated CO2 hose stations. 

The CO2 suppression systems protect the EDGs in the RHR complex and areas in the auxiliary 

building. All of the systems normally operate fully charged up to a closed master valve. Halon 

suppression systems protect areas located in the auxiliary and service buildings, guard house, 

and office building annex. All of the systems normally operate fully charged up to an automatic 

discharge valve, which is closed. 

The intended function of the CO2 and Halon suppression systems within the scope of license 

renewal include the following: 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.3-8, “Fire Protection – Carbon Dioxide and Halon System Components Subject 

to Aging Management Review,” identifies the CO2 and Halon suppression system component 

types that are within the scope of license renewal and subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.8 and relevant LRA drawings using the evaluation 

methodology described in the SER Section 2.3 and the guidance in SRP-LR Section 2.3. The 

staff also reviewed UFSAR Sections 9.5.1 and 9A and the guidelines of Appendix A to 

BTP APCSB 9.5-1. 

The staff also reviewed the following fire protection documents cited in the CLBs listed in the 

Fermi 2 Operating License Condition 2.C(9): 

 NUREG-0798, Supplement 5, “Safety Evaluation Report Related to the Operation of 

Fermi 2,” dated March 1985 

 NUREG-0798, Supplement 6, “Safety Evaluation Report Related to the Operation of 

Fermi 2,” dated July 1985 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The applicant responded to the staff’s 

RAIs as discussed below. 

In RAI 2.3.3.8-1, dated October 29, 2014, the staff stated that UFSAR Section 9.5.1.2.1, on 

page 9.5-5, states that “automatic CO2 extinguishing systems are provided for diesel generator 

rooms, SGTS charcoal filters, switchgear room and selected cable tray areas.” The CO2
2-62 

extinguishing systems in SGTS charcoal filters and selected cable tray areas do not appear in 

LRA drawings as being within the scope of license renewal and subject to an AMR. The staff 

requested that the applicant verify whether the above CO2 extinguishing systems are within the 

scope of license renewal in accordance with 10 CFR 54.4(a) and are subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). If these systems are excluded from the scope of license 

renewal and not subject to an AMR, the staff requested that the applicant provide justification for 

the exclusion. 

In a letter dated December 1, 2014, the applicant responded to RAI 2.3.3.8-1 by stating the 

following: 

SGTS charcoal filter CO2 systems are within the scope of license renewal in 

accordance with 10 CFR 54.4(a) and subject to an AMR as shown on drawings 

LRA-I-2649-1 (charcoal adsorbers at locations E-5 and B-5) and LRA-M-2709 

(SGTS filter units at G-2/G-3). The cable tray area automatic CO2 system is 

within the scope of license renewal in accordance with 10 CFR 54.4(a) and 

subject to an AMR as shown on drawing LRA-M-4548 (cable tray area elevation 

631 feet at location G-8). This one area is the only cable tray area (8AB) 

provided with an automatic CO2 extinguishing system. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-1 acceptable 

because it verified that the CO2 extinguishing systems in SGTS charcoal filters and in cable tray 

areas are within the scope of license renewal and are subject to an AMR. The staff confirmed 

that these components are highlighted in LRA drawings LRA-I-2649-1, LRA-M-2709, and 

LRA-M-4548. Therefore, the staff’s concern described in RAI 2.3.3.8-1 is resolved. 

In RAI 2.3.3.8-2, dated October 29, 2014, the staff stated that LRA Tables 2.3.3-8 and 3.3.2-8, 

“Fire Protection – CO2 and Halon System Summary of Aging Management Evaluation,” do not 

include the following fire protection components: 

 strainer and filter housing 

 pipe fittings, supports, and couplings 

 manually operated CO2 hose stations 

The staff requested that the applicant verify whether the fire protection components listed above 

are within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they 

are subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded from the 

scope of license renewal and are not subject to an AMR, the staff requested that the applicant 

provide justification for the exclusion. 

In a letter dated December 1, 2014, the applicant responded to RAI 2.3.3.8-2 by stating the 

following: 

There are no strainers or filter housings in the gaseous fire protection systems. 

Pipe fittings are within the scope of license renewal and subject to an AMR. As 

stated in LRA Section 2.0, the term piping in component lists includes pipe and 

pipe fittings. Pipe fittings are included in LRA Table 2.3.3-8 under the component 

type “Piping” with AMR results in LRA Table 3.3.2-8. 
2-63 

Supports are within the scope of license renewal and subject to an AMR. 

Supports are included in the structural AMR support members. This item is 

included in LRA Table 2.4-4 with AMR results in LRA Table 3.5.2-4. Couplings 

are within the scope of license renewal and subject to an AMR. Couplings are 

included in LRA Table 2.3.3-8 under the component type “Piping,” with AMR 

results in LRA Table 3.3.2-8. 

Manually operated CO2 hose stations are within the scope of license renewal 

and subject to an AMR. Hose stations are included in the structural AMR as 

component type “Fire hose reels.” This item is included in LRA Table 2.4-4 with 

AMR results in LRA Table 3.5.2-4. 

In reviewing the applicant’s response to the RAI, the staff finds that the applicant had addressed 

and resolved each item in the RAI, as discussed in the following paragraphs. 

The pipe fittings and coupling are included in LRA Table 2.3.3-8 with AMR results in LRA 

Table 3.3.2-8 under the component type “Piping.” Supports are included in LRA Table 2.4-4 

with AMR results in LRA Table 3.5.2-4 under “support members; welds; bolted connections; 

support anchorage to building structure.” Hose stations associated with the manually operated 

CO2 system are included in LRA Table 2.4-4 with AMR results in LRA Table 3.5.2-4, under the 

component type “Fire hose reels.” 

The applicant indicated that there are no strainers or filter housings in the gaseous fire 

protection systems. 

The staff finds the applicant’s response to RAI 2.3.3.8-2 acceptable because it clarified that the 

fire protection system and components listed above are within the scope of license renewal and 

are subject to an AMR as required by 10 CFR 54.4(a) and 10 CFR 54.21(a)(1), respectively. 

The staff’s concern described in RAI 2.3.3.8-2 is resolved. 

 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

fire protection system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.3.9 Combustion Turbine Generator 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.9 states that the purpose of the auxiliary electrical peaker combustion turbine 

generator (CTG) system is to provide an independent source of electrical power. The CTG 

system is used as an alternate source of power for SBO and for safe shutdown following a fire 

as part of the alternate shutdown system. The CTG system includes four oil-fired turbine 

generators; fuel oil storage tanks (FOSTs); a starting diesel for CTG 11-1; a standby diesel 

generator (DG) used to start CTG 11-2, 11-3, and 11-4; and associated support equipment, 

instruments, and controls. 

CTG 11-1 is black start capable. CTG 11-1 is used as the alternate alternating current (AC) 

source for an SBO event and is used to support the dedicated shutdown panel’s response to an 
2-64 

Appendix R, “Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 

1979,” to 10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities,” fire. 

CTG 11-2, 11-3, or 11-4 also can be used as an alternate source of AC power; however, these 

alternate CTG units are not credited for SBO or for Appendix R safe shutdown. 

The intended functions of the CTG system within the scope of license renewal include the 

following: 

 to support fire protection (10 CFR 50.48) and station blackout (10 CFR 50.63) 

requirements 

LRA Table 2.3.3-9 identifies the CTG system component types that are within the scope of 

license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.9 and UFSAR Sections 7.5.2.5.2, 9A.4.7.11.2, 8.2.1.2, 

9A.4.7.9.1, and 8.4 using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, and license renewal boundary 

drawings, the staff concludes that the applicant has appropriately identified the CTG system 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant has adequately identified the CTG system components subject to 

an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.3.10 Emergency Diesel Generator 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.10 states that the purpose of the EDG system is to provide power in the 

event of a loss of offsite power to the ESF electrical loads for safe reactor shutdown and to 

mitigate the consequences of a DBA. Standby AC power is supplied by four DGs. Each 

division is supplied by two DGs. The DG starts automatically on loss of voltage to its respective 

bus or following a LOCA indicated by low reactor water level or high drywell pressure. All EDGs 

start on low reactor water level or a high drywell pressure LOCA signal. However, if the ESS 

bus voltage is normal during a LOCA, the DGs will idle at synchronous speed and rated voltage 

with the EDG output breakers open. 
2-65 

Each EDG unit is rated for a continuous electric capacity of 2,850 kW. Each EDG unit is 

housed in its own room in the RHR complex. The supporting subsystems include fuel oil, air 

start, service water, jacket cooling water, lubricating oil, and combustion air and exhaust. 

The intended functions of the EDG system within the scope of license renewal include the 

following: 

 to provide power, in the event of a loss of offsite power, to the ESF electrical loads for 

safe reactor shutdown and to mitigate the consequences of a DBA 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.3-10, “Emergency Diesel Generator System Components Subject to Aging 

Management Review,” identifies the EDG system component types that are within the scope of 

license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.10; UFSAR Sections 8.3.1.1.8, 9.5.5, 9.2.5.2.3, 9.5.6, 

9.5.4, and 9.5.7; and the license renewal boundary drawings using the evaluation methodology 

discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. During its review of the drawing 

and locations (indicated in Table 2.3-2 below), the staff noted that it could not locate 

continuations of piping within the scope of license renewal; therefore, the staff could not verify 

the scoping boundary of SSCs. By letter dated November 26, 2014, the staff issued 

RAI 2.3.3.10-1 requesting that the applicant provide sufficient information to locate the license 

renewal boundary. In addition, the staff requested the following: (1) if the continuation cannot 

be shown on license renewal boundary drawings, provide additional information describing the 

extent of the scoping boundary, (2) identify any additional component types subject to an AMR 

between the continuation and the termination of the scoping boundary, and (3) if the scoping 

classification of a piping section changes over the continuation, provide additional information to 

clarify the change in classification. 
2-66 

Table 2.3-2 Emergency Diesel Generator System Piping Continuations Not within the 

Scope of License Renewal 

LRA Drawing Location Continuation Issue

LRA-M-N-2052 F-7, F-6, F-5 (two places), F-4, and 

C-7 

Drawing continuations are not 

provided to the “RHR Reservoir” or 

“RHRSW.” 

LRA-M-N-2053 F-5, F-4 (two places), F-3, F-2, and 

D-3 

Drawing continuations are not 

provided to the “RHR Reservoir” or 

“RHRSW.” 

In its response letter dated December 30, 2014, to RAI 2.3.3.10-1, the applicant stated that all 

the above continuations are open-ended piping lines that discharge directly into the RHR 

reservoir and that there are no additional component types subject to an AMR or scoping 

classification changes between the continuations and the end of the scoping boundary. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.10-1 acceptable 

because the continuations to the RHR reservoir are open-ended piping lines that discharge 

directly into the RHR reservoir and because there are no additional component types or scoping 

classification changes. Therefore, the staff’s concern described in RAI 2.3.3.10-1 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI response, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the EDG system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the EDG 

system components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). 

2.3.3.11 Heating, Ventilation, and Air Conditioning 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.11 states that the HVAC components are divided into separate systems. 

These separate systems are the dedicated shutdown systems, the reactor/auxiliary building 

ventilation systems, the primary containment atmosphere cooling (PCAC) system, and the RHR 

complex and office service building (OSB) HVAC systems. 

The purpose of the dedicated shutdown system is to provide a means to cool down and 

depressurize the reactor should a fire occur. 

The purpose of the reactor/auxiliary building HVAC systems is to provide the required ambient 

environment for plant equipment, to provide a comfortable working environment for plant 

personnel, and to control airborne radioactivity. 

The purpose of the PCAC system is to maintain the temperature of the drywell atmosphere 

within design conditions. The PCAC system is not credited for post-accident cooling. 

The purpose of the RHR complex and OSB HVAC systems is to provide the required ambient 

environment for plant equipment and a comfortable working environment for plant personnel. 
2-67 

The intended functions of the HVAC system within the scope of license renewal include the 

following: 

 to support the suppression pool, secondary containment, and EECW system pressure 

boundaries 

 to provide cooling to maintain ESF equipment within design limits 

 to prevent buildup of hydrogen in the ESF battery rooms 

 to provide isolation capability of a plant heating steam line break 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.3-11 identifies the component types that are within the scope of license renewal 

and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.11; UFSAR Sections 1.2.2.15.18, 1.2.2.15.4, 7.5.2.5, 

9.3.3, 9.4.2, 9.4.3.2, 9.4.5, 9.4.6, 9.4.7, 9.4.8, 9.4.9, and 9.4.11; and LRA Table 2.3.3-11 using 

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, and license renewal boundary 

drawings, the staff concludes that the applicant has appropriately identified the HVAC system 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant has adequately identified the HVAC system components subject to 

an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.3.12 Control Center Heating, Ventilation, and Air Conditioning 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.12 states that the purpose of the control center HVAC system is to provide 

ventilation, heating, and cooling and to limit the relative humidity in the control center envelope 

during normal operation and following an accident. The control center envelope includes the 

main control room, office and conference room, cable spreading room, relay room, computer 

room, and mechanical equipment rooms. The SGTS rooms are included in the envelope during 

normal operation but are isolated from the envelope during emergency modes. The system has 

four modes of operation: (1) normal, (2) purge, (3) recirculation, and (4) chlorine. 
2-68 

The intended functions of the control center HVAC system within the scope of license renewal 

include the following: 

 to maintain the control center environment to support continued operation of 

safety-related equipment and operator habitability following a DBA 

 to limit the introduction of chlorine gas and airborne radioactivity into the control room 

and remove airborne radioactivity from the control room environment 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.3-12 identifies the component types that are within the scope of license renewal 

and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.12; UFSAR Sections 1.2.2.9.24, 6.4, and 9.4.1; and LRA 

Table 2.3.3-12 using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, and license renewal boundary 

drawings, the staff concludes that the applicant has appropriately identified the control center 

HVAC system components within the scope of license renewal, as required by 10 CFR 54.4(a). 

The staff also concluded that the applicant has adequately identified the control center HVAC 

system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.3.13 Containment Atmospheric Control 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.13 states that the purpose of the containment atmospheric control system is 

to control the concentration of hydrogen and oxygen inside primary containment below 

combustible levels. Combustible gas control of the primary containment is provided by two 

separate subsystems: (1) the nitrogen inerting system and (2) the post-LOCA combustible gas 

control system. The nitrogen inerting system reduces oxygen inside the primary containment 

during normal operation by creating and maintaining a nitrogen atmosphere. The post-LOCA 

combustible gas control system may be used to limit the hydrogen and oxygen created following 

an accident by means of thermal recombination. 
2-69 

The intended functions of the containment atmospheric control system within the scope of 

license renewal include the following: 

 to support primary containment and secondary containment pressure boundaries 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

LRA Table 2.3.3-13, “Containment Atmospheric Control System Components Subject to Aging 

Management Review,” identifies the component types that are within the scope of license 

renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.13; UFSAR Sections 1.2.2.9.22, 6.2.5, and 9.3.6; and 

LRA Table 2.3.3-13 using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, and license renewal boundary 

drawings, the staff concludes that the applicant has appropriately identified the containment 

atmospheric control system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concluded that the applicant has adequately identified the 

containment atmospheric control system components subject to an AMR, as required by 

10 CFR 54.21(a)(1). 

2.3.3.14 Plant Drains 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.14 states that “plant drains” is the collective name for floor and equipment 

drains. The plant drains system includes components from system floor and equipment drains, 

radioactive waste, RHR complex drains, and OSB potable water. 

The purposes of the plant drain systems are as follows: 

 The purpose of the floor and equipment drains system is to collect and remove all waste 

liquids from their points of origin to a suitable disposal area in a controlled and safe 

manner. 

 The purpose of the liquid radioactive waste, or radwaste, system is to segregate, collect, 

and process liquid waste generated throughout the plant. 
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 The purpose of the solid radwaste system is to handle and package solid waste. 

 The purpose of the RHR complex drains and OSB potable water system is to provide 

miscellaneous drainage and plumbing equipment. 

The radioactive waste systems include components that support the primary containment 

pressure boundary. The system also includes nonsafety-related components that prevent 

backflow from the radwaste building into the reactor building during the probable maximum 

meteorological event. 

The intended functions of the plant drains system within the scope of license renewal include 

the following: 

 to support the primary and secondary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

 to prevent backflow from the radwaste building into the reactor building during the 

probable maximum meteorological event 

LRA Table 2.3.3-14 identifies the plant drains system component types that are within the scope 

of license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.14; UFSAR Sections 9.3.3, 1.2.2.14.4, 1.2.2.14.5, 

3.4.4.4.2, 9.3.3, 9A.5, 11.2, 11.5, 9.2.4, and 9.3.3.2; and the license renewal boundary drawings 

using the evaluation methodology discussed in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. During its review of the drawing and 

locations (indicated in Table 2.3-3 below), the staff noted that it could not locate continuations of 

piping within the scope of license renewal; therefore, the staff could not verify the scoping 

boundary of SSCs. By letter dated November 26, 2014, the staff issued RAI 2.3.3.14-1 

requesting that the applicant provide sufficient information to locate the license renewal 

boundary. In addition, the staff requested the following: (1) if the continuation cannot be shown 

on license renewal boundary drawings, provide additional information describing the extent of 

the scoping boundary, (2) identify any additional component types subject to an AMR between 

the continuation and the termination of the scoping boundary, and (3) if the scoping 

classification of a piping section changes over the continuation, provide additional information to 

clarify the change in classification. 
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Table 2.3-3 Plant Drains System Piping Continuations Not within the Scope of License 

Renewal 

LRA Drawing Location Continuation Issue

LRA-M-2032 G-7 and G-4 Drawings indicated by REF-I and 

REF-8 at location G-7 and REF-8 and 

REF-18 at location G-4 do not 

provide sufficient information to 

locate the license renewal boundary. 

LRA-M-2032 D-2 Continuations from drawings M-2259 

and M-4797; drawings M-2259 and 

M-4797 were not provided. 

LRA-M-2032-1 D-4 Continuation was not provided for 

origin of M-2547 to turbine building 

equipment. 

LRA-M-2223 B-6 and B-7 Continuations of five lines on 

drawings M-2048 and M-2833; 

drawings M-2048 and M-2833 were 

not provided. 

In its response letter dated December 30, 2014, to RAI 2.3.3.14-1, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.14-1 acceptable 

because it provided sufficient information to locate the license renewal boundary and stated that 

there are no additional component types subject to an AMR between the continuation from, and 

the end of, the scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.14-1 is 

resolved. 

The staff also noted on the license renewal boundary drawings listed in Table 2.3-4 below that 

the staff could not locate seismic or equivalent anchors on 10 CFR 54.4(a)(2) nonsafety-related 

lines continued from safety-related lines as indicated in the table. By letter dated 

November 26, 2014, the staff issued RAI 2.3.3.14-2 requesting that the applicant provide 

additional information to locate the seismic or equivalent anchors between the safety-nonsafety 

interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

Table 2.3-4 Plant Drains System Seismic or Equivalent Anchors Not within the Scope of 

License Renewal 

LRA Drawing Location Issue 

LRA-M-2032 D-4 and E-4 On drawing LRA-M-2032 (D/E-4) 

10 CFR 54.4(a)(2), the 

nonsafety-related line continues from 

safety-related valve F 1409 in the 

reactor building to the turbine building 

and then to the radwaste building 

where it is taken out of scope. The 

staff could not locate a seismic or 

equivalent anchor on the 

10 CFR 54.4(a)(2) nonsafety-related 

line continued to drawing M-2040 

(G-8). 
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LRA Drawing Location Issue 

LRA-M-2032 H-6 On drawing LRA-M-2032, location 

H-6, and drawing LRA-M-2032-1, 

location H-6, 10 CFR 54.4(a)(2) 

nonsafety-related lines continue from 

safety-related valves F600 and F018, 

respectively, to the not in-scope 

drywell floor drain pumps 

(G1101C00A and B and G110IC006A 

and B). The staff could not locate 

seismic or equivalent anchors on the 

10 CFR 54.4(a)(2) nonsafety-related 

lines. 

LRA-M-2032-1 H-6 

In its response letter dated December 30, 2014, to RAI 2.3.3.14-2, the applicant stated that 

valves F1407, F1408, and F1409 on drawing LRA-M-2032 and valves F1410, F1411, and 

F1412 on drawing LRA-M-2032-1 are not safety-related valves; therefore, there are no 

safety-nonsafety interfaces at the specified locations on those drawings. 

The applicant provided additional information to locate seismic anchors at location H-4 on 

drawing LRA-M-2032. In addition, the applicant provided information to locate seismic and 

equivalent anchors at locations D-4 and D-6, respectively, on LRA-M-2032-1. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.14-2 acceptable 

because it provided the location of the seismic anchors or provided an explanation as to why the 

anchors were not needed. Therefore, the staff’s concern described in RAI 2.3.3.14-2 is 

resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI responses, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the plant drains system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the plant 

drains system components subject to an AMR, in accordance with 10 CFR 54.21(a)(1). 

2.3.3.15 Fuel Oil 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.15 states that the purpose of the fuel oil system is to transfer fuel oil to the 

EDGs, auxiliary electrical peaker CTG system, and fire protection system. 

The EDG system includes fuel oil for operation of the DG and stores sufficient fuel for 

continuous operation of the EDG for 7 days. Each DG set is supplied by a 42,000-gal diesel 

fuel storage tank. Two redundant motor-driven fuel-oil transfer pumps deliver fuel from the 

storage tank to a 550-gal fuel oil day tank. Fuel flows by gravity from the day tank to the suction 

of the engine-driven fuel pump. 

The CTG system (specifically CTG 11-1) is used as an alternate source of power for SBO and 

safe shutdown following a fire as part of the alternate shutdown system. Diesel fuel is 

maintained in the CTG fuel oil tank with a fuel level maintained by plant procedures to ensure 

nominal fuel availability for 72 hours of operations for a single CTG unit at a 10-MW load. 
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The fire pump diesel is provided with fuel oil from a 275-gal fuel oil tank for 8 continuous hours 

of operation. The diesel fire pump is a 2500-gpm diesel-driven fire pump located in the GSW 

pump house. 

The intended functions of the fuel oil system within the scope of license renewal include the 

following: 

 to provide power, in the event of a loss of offsite power, to the ESF electrical loads for 

safe reactor shutdown and to mitigate the consequences of a DBA 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

LRA Table 2.3.3-15 identifies the fuel oil system component types that are within the scope of 

license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.15; UFSAR Section 9.5.1, 9.5.4 and 7.5.2.5.2; and the 

license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff noted on drawing 

LRA-M-N-2048, locations E-6 and E-3, and drawing LRA-M-N-2049, locations E-6 and E-3, that 

it could not locate seismic anchors on the four nonsafety-related 4-inch-diameter lines to the 

safety-related diesel fuel oil tanks (R3000A002, R3000A001, R3000A004, and R3000A003). By 

letter dated November 26, 2014, the staff issued RAI 2.3.3.15-1 requesting that the applicant 

provide additional information to locate the seismic or equivalent anchors between the 

safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.15-1, the applicant stated that, for 

all four locations, the Seismic II/I design analysis demonstrates that the seismic boundary is at 

the wall penetration from the RHR complex out into the yard. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.15-1 acceptable 

because it provided the location of the seismic anchors. Therefore, the staff’s concern 

described in RAI 2.3.3.15-1 is resolved. 

The staff also noted that LRA Table 2.2-1, “Mechanical Systems within the Scope of License 

Renewal,” does not list Section 2.3.3.15, “Fuel Oil,” as a system within the scope of license 

renewal. By letter dated November 26, 2014, the staff issued RAI 2.3.3.15-2 requesting that the 
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applicant provide additional information to clarify why LRA Section 2.3.3.15 is not included in 

LRA Table 2.2-1. 

In its response letter dated December 30, 2014, to RAI 2.3.3.15-2, the applicant stated that 

Table 2.2-1 lists systems by plant system number. There is no plant system number associated 

with fuel oil. The components containing fuel oil are part of other plant systems. For this 

reason, “fuel oil” is not listed as a separate system in LRA Table 2.2-1. LRA Section 2.3.3.15 

includes the review of fuel oil components from the fire protection system, the auxiliary electrical 

peaker CTG system, and the EDG system. These three systems are separately listed in LRA 

Table 2.2-1. Within those sections, a reference to LRA Section 2.3.3.15 is provided for the AMR 

of components containing fuel oil. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.15-2 acceptable 

because it explained why the fuel oil system was not listed in LRA Table 2.2-1. Therefore, the 

staff’s concern described in RAI 2.3.3.15-2 is resolved. 

 Conclusion 

Based on its evaluation discussed and on a review of the LRA, UFSAR, RAI responses, and 

license renewal boundary drawings, the staff concludes that the applicant has appropriately 

identified the fuel oil system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant has adequately 

identified the fuel oil system components subject to an AMR, in accordance with 

10 CFR 54.21(a)(1). 

2.3.3.16 Primary Containment Monitoring and Leakage Detection 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.16 states that the primary containment monitoring (PCM) and leakage 

detection system includes components from the following systems: 

 PCM 

 reactor protection 

 reactor water cleanup 

 main and reheat steam 

 nuclear boiler 

 main turbine generator and auxiliaries 

 process sampling 

The purpose of the PCM is to provide sufficient information to plant operators to permit normal 

operation, to assist in the assessment of consequences of an accident or incident, and to 

determine the effectiveness of control actions taken to mitigate the effects of the postulated 

event. 

Leakage into systems that are directly or indirectly connected to the RCPB is detected by the 

leak detection system. 
2-75 

The intended functions of the PCM and leakage detection systems within the scope of license 

renewal include the following: 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

 to support the sensing line pressure boundary of the turbine first-stage pressure 

transmitters 

 to monitor system flows to determine system leakage 

 to maintain piping and component integrity to support post-accident plate-out of fission 

products from MSIV leakage 

 to support operation of the reactor protection system (RPS) turbine first-stage pressure 

transmitters 

LRA Table 2.3.3-16, “Primary Containment Monitoring and Leakage Detection System 

Components Subject to Aging Management Review,” identifies the PCM and leakage detection 

systems component types that are within the scope of license renewal and that are subject to an 

AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.3.16; UFSAR Sections 6.2.1.5, 3.6.2.2.5, 7.1.2.1.22, 

5.5.8.2, 7.6.1.12, 7.6.1.8.8, 3.1.2.2.1, 1.2.2.15.13, 7.2, 9.3.2, and 11.4.4; and the license 

renewal boundary drawings using the evaluation methodology discussed in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. During its review of the drawings 

and locations (indicated in Table 2.3-5 below), the staff noted that it could not locate 

continuations of piping within the scope of licensing renewal; therefore, the staff could not verify 

the scoping boundary of SSCs. By letter dated November 26, 2014, the staff issued 

RAI 2.3.3.16-1 requesting that the applicant provide sufficient information to locate the license 

renewal boundary. In addition, the staff requested the following: (1) if the continuation cannot 

be shown on license renewal boundary drawings, provide additional information describing the 

extent of the scoping boundary, (2) identify any additional component types subject to an AMR 

between the continuation and the termination of the scoping boundary, and (3) if the scoping 

classification of a piping section changes over the continuation, provide additional information to 

clarify the change in classification. 
2-76 

Table 2.3-5 Primary Containment Monitoring and Leakage Detection System Piping 

Continuations Not within the Scope of License Renewal 

LRA Drawing Location Continuation Issue

LRA-M-2002 C-5 and D-5 Continuation was not provided for 

four 10 CFR 54.4(a)(2) lines to 

drawings I-2314-03 (location G-3), 

I-2336-05 (location C-6), and 

I-2346-08 (location D-6). Drawings 

were not provided. 

LRA-M-2002 F-7, H-7, E-6, and F-5 Six in-scope 10 CFR 54.4(a)(2) drain 

lines continuing to LRA-M-2985 

locations G-8, H-8, F-6, and G-6; 

could not locate continuations on 

LRA-M-2985. 

LRA-M-2002 E-4 and F-5 Four in-scope 10 CFR 54.4 lines 

continuing to drawing LRA-M-2003 

(F-3); review of drawing LRA-M-2003 

could not locate continuations from 

drawing LRA-M-2002. 

LRA-M-2002 F-5 10 CFR 54.4(a)(2) line continuing 

from unspecified drawing (and 

location) to valve F815. 

LRA-M-2046 C-3, F-4, H-3, and F-6 Four in-scope 10 CFR 54.4(a)(2) 

lines to drawing I-2400-04, locations 

E-6, F-4, F-4, and F-4; drawing 

I-2400-04 was not provided. 

In its response letter dated December 30, 2014, to RAI 2.3.3.16-1, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.16-1 acceptable 

because it provided the location of the scoping boundaries and component types between the 

continuation and scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.16-1 

is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI response, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the PCM and leakage detection system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant has 

adequately identified the PCM and leakage detection system components subject to an AMR, in 

accordance with 10 CFR 54.21(a)(1). 

2.3.3.17 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2) 

 Summary of Technical Information in the Application 

LRA Section 2.3.3.17 summarizes scoping and screening for miscellaneous nonsafety-related 

auxiliary systems or components that are within the scope of license renewal for 

10 CFR 54.4(a)(2) because of potential physical interactions with safety-related components. 
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These physical interactions could cause failure by causing a loss of structural or mechanical 

integrity of the safety-related SSC. The LRA also states that, except for the following systems, 

any functional failures of these nonsafety-related SSCs were identified and discussed within 

individual systems’ evaluations of LRA Section 2.3.3 and are not evaluated in this section 

(i.e., Section 2.3.3.17): 

 process radiation monitoring 

 torus water management 

 local panel and racks 

 off-gas process and vacuum 

 potable water 

 post-accident sampling 

 GSW 

 reactor building closed cooling water 

 turbine building closed cooling water 

 supplemental cooling chilled water 

 auxiliary boiler 

 waste oil 

 online noble chemistry injection 

 zinc injection 

 storage pools 

 turbine building HVAC 

 turbine building potable water and plumbing 

 beyond design basis external event mitigation (Fukushima) 

LRA Section 2.3.3.17 also discusses the following miscellaneous auxiliary systems (i.e., in 

addition to the ones immediately above) as being within the scope of license renewal based on 

the criteria in 10 CFR 54.4(a)(2) for physical failure (these systems are discussed elsewhere in 

the LRA): 

 CRD 

 SLC 

 radioactive waste 

 reactor water cleanup 

 fuel pool cooling and cleanup 

 process sampling 

 emergency equipment cooling water 

 emergency equipment service water 

 station air, control air, and emergency breathing air 

 fire protection 

 EDGs 

 reactor/auxiliary building 

 reactor/auxiliary building HVAC 

 floor and equipment drains 

 containment atmospheric control 

 PCP 

 PCM 

 RHR complex and OSB HVAC 

 RHR complex drains and OSB potable water 
2-78 

LRA Tables 2.3.3-17-1 – 2.3.3-17-37 identify the component types that are within the scope of 

license renewal and that are subject to an AMR for 10 CFR 54.4(a)(2) based on potential 

physical interactions. 

 Staff Evaluation 

The staff reviewed the miscellaneous auxiliary systems in scope for 10 CFR 54.4(a)(2) functions 

described in LRA Section 2.3.3.17 and UFSAR sections 11.4, 9.2.8, 11.3.2.7, 9.2.4, 11.4.4, 

1.2.2.15.8.2, 9.2.1, 7.6.1.14.1.1, 9.2.2, 7.6.1.14.1.2, 9.2.7, 9.2.9, 1.2.2.15.16, 9.4.8, 10.4.11, 

5.2.3.4, 10.4.9, 9.4.4, and Table 3.10-3, (as described in SER Sections 2.3.3.1 – 2.3.3.17) using 

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR, in accordance 

with 10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff noted on drawing 

LRA-M-2271 (E-6) that it could not locate seismic or equivalent anchors on nonsafety-related 

line M-3691 to safety-related valve F600, location E-6, or on the nonsafety-related line 

downstream of safety-related valve F601, location E-6. By letter dated November 26, 2014, the 

staff issued RAI 2.3.3.17-1 requesting that the applicant provide additional information to locate 

the seismic or equivalent anchors between the safety-nonsafety interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-1, the applicant stated that a 

review of isometric drawings shows that there are expansion joints located on both sides of 

valves F600 and F601 and that the small-bore piping and the 6-inch piping lines going to valves 

F228 and F216 are excluded from the seismic design analysis based on the moment of inertia 

ratio. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-1 acceptable 

because there are expansion joints located on both sides of valves F600 and F601 and because 

the small-bore piping is excluded from the seismic design analysis based on the moment of 

inertia ratio. Therefore, the staff’s concern described in RAI 2.3.3.17-1 is resolved. 

One review method used by the staff is to confirm the inclusion of all components subject to an 

AMR by reviewing the results of the screening of components within the license renewal 

boundary. During its review of drawings and locations, the staff noted that it could not locate 

continuations of piping within the scope of license renewal; therefore, the staff could not verify 

the scoping boundary of SSCs. Drawing LRA-M-2271 (E-3) has an in-scope continuation “To 

Service Building.” A drawing continuation is not provided for this continuation downstream of 

valve F187. By letter dated November 26, 2014, the staff issued RAI 2.3.3.17-2 requesting that 

the applicant provide sufficient information to locate the license renewal boundary. In addition, 

the staff requested the following: (1) if the continuation cannot be shown on license renewal 

boundary drawings, provide additional information describing the extent of the scoping 

boundary, (2) identify any additional component types subject to an AMR between the 
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continuation and the termination of the scoping boundary, and (3) if the scoping classification of 

a piping section changes over the continuation, provide additional information to clarify the 

change in classification. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-2, the applicant stated that the 

piping shown is in the turbine building. The continuation beyond valve F187 is to the OSB. The 

continuation is not in scope from the point where it leaves the TB and goes to the OSB. The 

OSB is a structure that is not within the scope of license renewal. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-2 acceptable 

because it provided sufficient information to locate the license renewal boundary and stated that 

there are no additional component types subject to an AMR between the continuation from, and 

the end of, the scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.17-2 is 

resolved. 

During its review of the drawings and locations (indicated in Table 2.3-6 below), the staff noted 

that it could not locate continuations of piping within the scope of license renewal; therefore, the 

staff could not verify the scoping boundary of SSCs. By letter dated November 26, 2014, the 

staff issued RAI 2.3.3.17-3 requesting that the applicant provide sufficient information to locate 

the license renewal boundary. In addition, the staff requested the following: (1) if the 

continuation cannot be shown on license renewal boundary drawings, provide additional 

information describing the extent of the scoping boundary, (2) identify any additional component 

types subject to an AMR between the continuation and the termination of the scoping boundary, 

and (3) if the scoping classification of a piping section changes over the continuation, provide 

additional information to clarify the change in classification. 

Table 2.3-6 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2) Piping 

Continuations Not within the Scope of License Renewal 

LRA Drawing Location Continuation Issue

LRA-M-2017-lA D-5 Has an in-scope continuation to 

drawing M-3804. Drawing M-3804 

was not provided. 

LRA-M-2017-2 G-1 Has an in-scope continuation to 

drawing I-2181-2. Drawing I-2182-2 

was not provided. 

LRA-M-2017-2 H-7 Has an in-scope continuation to the 

off-gas oxygen (O2) analyzer. 

Drawing continuation is not provided 

for the continuation to the off-gas O2

analyzer. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-3, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-3 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation from, 

and the end of, the scoping boundaries. Therefore, the staff’s concern described in 

RAI 2.3.3.17-3 is resolved. 
2-80 

During its review of drawings as supplied by the applicant, the staff noted that it could not locate 

continuations of piping within the scope of license renewal. Drawing LRA-I-2400-10, locations 

C-3, G-6, and D-6, has three in-scope continuations to drawing 61721-2400-11. The applicant 

did not provide drawing 61721-2400-11. By letter dated November 26, 2014, the staff issued 

RAI 2.3.3.17-4 requesting that the applicant provide sufficient information to locate the license 

renewal boundary. In addition, the staff requested the following: (1) if the continuation cannot 

be shown on license renewal boundary drawings, provide additional information describing the 

extent of the scoping boundary, (2) identify any additional component types subject to an AMR 

between the continuation and the termination of the scoping boundary, and (3) if the scoping 

classification of a piping section changes over the continuation, provide additional information to 

clarify the change in classification. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-4, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-4 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation from, 

and the end of, the scoping boundaries. Therefore, the staff’s concern described in 

RAI 2.3.3.17-4 is resolved. 

In addition, the staff noted on drawing LRA-M-4100 that it could not locate seismic or equivalent 

anchors on nonsafety-related lines attached to safety-related valves F601 (location F-8), F603 

(location D-6), F605 (location G-6), and F607 (location E-8). By letter dated 

November 26, 2014, that staff issued RAI 2.3.3.17-5 requesting that the applicant provide 

additional information to locate the seismic or equivalent anchors between the safety-nonsafety 

interfaces and the end(s) of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-5, the applicant provided the 

location of the seismic anchors. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-5 acceptable 

because it provided the location of the seismic anchors which demonstrates an appropriate 

boundary between the safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping 

boundary. Therefore, the staff’s concern described in RAI 2.3.3.17-5 is resolved. 

Furthermore, during its review of drawings and locations (indicated in Table 2.3-7 below), the 

staff noted that it could not locate continuations of piping within the scope of license renewal; 

therefore, the staff could not verify the scoping boundary of SSCs. By letter dated 

November 26, 2014, the staff issued RAI 2.3.3.17-7 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. In addition, the staff requested the 

following: (1) if the continuation cannot be shown on license renewal boundary drawings, 

provide additional information describing the extent of the scoping boundary, (2) identify any 

additional component types subject to an AMR between the continuation and the termination of 

the scoping boundary, and (3) if the scoping classification of a piping section changes over the 

continuation, provide additional information to clarify the change in classification. 
2-81 

Table 2.3-7 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2) Piping 

Continuations Not within the Scope of License Renewal 

LRA Drawing Location Continuation Issue 

LRA-M-4100 E-3 Drawing LRA-M-4100, location E-3, 

has an in-scope continuation to 

drawing 1-2400-03, location D-3. 

Drawing 1-2400-03 was not provided.

LRA-M-2008-1 B-7 Drawing LRA-M-2008-1, location B-7, 

has an in-scope continuation to 

drawing 1-2400-06, locations D-4 and 

D-5. Drawing 1-2400-06 was not 

provided. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-7, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-7 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation from, 

and the end of, the scoping boundaries. Therefore, the staff’s concern described in 

RAI 2.3.3.17-7 is resolved. 

On drawing LRA-M-2008, location C-6, the scoping boundary ends at valves F847 and F848. 

By letter dated November 26, 2014, the staff issued RAI 2.3.3.17-8 requesting that the applicant 

provide additional information to clarify why lines 3314 and 3312 downstream of valves F847 

and F848 are not within the scope of license renewal. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-8, the applicant stated that 

lines 3314 and 3312 past valves F848 and F847 transition to the OSB, which is not in scope. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-8 acceptable 

because it stated that the lines upstream of valves F848 and F847 transition to the OSB, which 

is not in scope. Therefore, the staff’s concern described in RAI 2.3.3.17-8 is resolved. 

The staff confirms the inclusion of all components subject to an AMR by reviewing the results of 

the screening of components within the license renewal boundary. On license renewal drawing 

LRA-M-2008-1 (D-2) the bus cooler (S1200B001) is not subject to an AMR. Similar 

components are included within the scope of license renewal and are subject to an AMR. By 

letter dated November 26, 2014, the staff issued RAI 2.3.3.17-9 requesting that the applicant 

provide additional information to clarify why bus cooler SJ 200B001 is not subject to an AMR as 

other coolers on drawing LRA-M-2008-1 are. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-9, the applicant stated that the 

other similarly depicted coolers are shell and tube coolers. Bus cooler S1200B001 is an open 

cooler housing that has turbine building closed cooling water (TBCCW) system piping inside the 

open housing. LRA Table 3.3.2-17-15, “Turbine Closed Cooling Water System 

Nonsafety-Related Components Affecting Safety-Related Systems – Summary of Aging 

Management Evaluation,” addresses the piping inside the open housing. 
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Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-9 acceptable 

because it stated that this cooler is an open cooler versus shell and tube coolers. Therefore, 

the staff’s concern described in RAI 2.3.3.17-9 is resolved. 

Furthermore, during its review of drawings as supplied by the applicant, the staff noted that it 

could not locate continuations of piping within the scope of license renewal; therefore, the staff 

could not verify the scoping boundary of SSCs. Drawing LRA-M-2042 has eight in-scope 

continuations to and from drawing I-2314-02. The applicant did not provide drawing I-2314-02. 

By letter dated November 26, 2014, the staff issued RAI 2.3.3.17-10 requesting that the 

applicant provide sufficient information to locate the license renewal boundary. In addition, the 

staff requested the following: (1) if the continuation cannot be shown on license renewal 

boundary drawings, provide additional information describing the extent of the scoping 

boundary, (2) identify any additional component types subject to an AMR between the 

continuation and the termination of the scoping boundary, and (3) if the scoping classification of 

a piping section changes over the continuation, provide additional information to clarify the 

change in classification. 

In its response letter dated December 30, 2014, to RAI 2.3.3.17-10, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-10 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation from, 

and the end of, the scoping boundaries. Therefore, the staff’s concern described in 

RAI 2.3.3.17-10 is resolved. 

By letter dated May 19, 2016, the applicant added a new system “Beyond Design Basis External 

Event Mitigation (Fukushima)”, to the scope of LRA Section 2.3.3.17. This new system is 

intended to be used as part of the Flexible and Diverse Coping Strategy (FLEX) to mitigate 

beyond design basis external events (BDBEE) in response to NRC Order EA-12-049. The NRC 

staff reviewed the UFSAR drawings included with the May 26, 2016, submittal of Revision 20 to 

the Fermi 2 UFSAR and held a conference call with the applicant on June 9, 2016, to confirm 

the staff’s understanding of the license renewal boundaries. In UFSAR Figures 5.5-13, sheets 1 

and 2, corresponding with LRA drawings M-2083 and M-2084 respectively, the LRA boundary 

between the safety-related RHR system and non-safety BDBEE mitigation (Fukushima) system 

change at the inlet side of valves F621A and F621B. The piping and components downstream 

of these boundary valves, including the boundary valve, is subject to the same AMP as RHR 

piping and components. The piping and components upstream of the boundary valves is 

subject to the summary of aging management evaluation in Table 3.3.2-17-37, BDBEE 

Mitigation (Fukushima) System Nonsafety-Related Components Affecting Safety-Related 

Systems Summary of Aging Management Evaluation. The UFSAR drawings also indicated a 

new piping connection, including normally closed isolation valves, between the HPCI test line 

piping and the GSW piping. In the June 9, 2016, conference call, the applicant informed the 

NRC staff that the entire connecting line, including the normally closed isolation valves, are in 

the scope of the aging management evaluation in Table 3.3.2-17-37. Based on the review of 

the UFSAR drawings and the clarification provided by the applicant, the NRC staff confirms the 

inclusion of all components subject to an AMR by reviewing the results of the screening of 

components within the license renewal boundary. 
2-83 

 Conclusion 

Based on its evaluation and review of the LRA, UFSAR, RAI responses, and license renewal 

boundary drawings, the staff concludes that the applicant has appropriately identified 

miscellaneous auxiliary systems within the scope of license renewal for 10 CFR 54.4(a)(2), as 

required by 10 CFR 54.4(a). The staff also concludes that the applicant has adequately 

identified the miscellaneous auxiliary systems in scope for 10 CFR 54.4(a)(2) components 

subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.3.4 Steam and Power Conversion 

LRA Section 2.3.4 identifies the S&PC systems SCs subject to an AMR for license renewal. 

The applicant described the supporting SCs of the S&PC systems in the following LRA sections: 

 LRA Section 2.3.4.1, “Condensate Storage and Transfer” 

 LRA Section 2.3.4.2, “Feedwater and Standby Feedwater” 

 LRA Section 2.3.4.3, “Miscellaneous Steam and Power Conversion Systems in Scope 

for 10 CFR 54.4(a)(2)” 

The staff’s findings on review of LRA Sections 2.3.4.1 – 2.3.4.3 are in SER Sections 2.3.4.1 – 

2.3.4.3, respectively. 

2.3.4.1 Condensate Storage and Transfer 

 Summary of Technical Information in the Application 

LRA Section 2.3.4.1 states that the purpose of the condensate storage and transfer system is to 

store and distribute condensate and demineralized water for use throughout the plant during 

normal and shutdown plant conditions. The system provides condensate to the HPCI, RCIC, 

CRD, standby feedwater, and core spray systems and to the main condenser hotwell. 

The condensate storage and transfer system includes two 600,000-gal storage tanks, the CST 

and the condensate return tank (CRT), a 50,000-gal demineralized makeup water storage tank, 

and three pumps with associated receiving and distribution lines. The CST standpipe is 

designed so that the last 150,000 gal is reserved for use by the HPCI or RCIC systems. 

The intended functions of the condensate storage and transfer system within the scope of 

license renewal include the following: 

 to support the flow path from the CST to the HPCI and RCIC systems 

 to support the primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

LRA Table 2.3.4-1, “Condensate Storage and Transfer System Components Subject to Aging 

Management Review,” identifies the condensate storage and transfer system component types 

that are within the scope of license renewal and that are subject to an AMR. 
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 Staff Evaluation 

The staff reviewed LRA Section 2.3.4.1, UFSAR Sections 8.4 and 9.2.6, and license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

The staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. On drawing LRA-M-2678 (E-2), the 

staff could not locate seismic or equivalent anchors on the 10 CFR 54.4(a)(2) nonsafety-related 

line continued from safety-related valve 3120. The nonsafety-related line at E-2 continues to 

drawing I-2400-7, location D-4. The applicant did not provide drawing I-2400-7. The same 

10 CFR 54.4(a)(2) nonsafety-related line from safety-related valve 3120 branches and 

continues to valves F314 and F315 at LRA-M-2678 (G-6 and F-6) and continues to M-5498 

(H-3) and I-2400-06 (C-4), respectively. The applicant did not provide drawings M-5498 (H-3) 

and I-2400-06 (C-4). By letter dated November 26, 2014, the staff issued RAI 2.3.4.1-1 

requesting that the applicant provide additional information to locate the seismic or equivalent 

anchors between the safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping 

boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.4.1-1, the applicant stated that there 

is a seismic anchor located in area E-3 on the 6-inch line (2152 and 2808) before valve V8-2789 

and that this anchor exists before the tee intersection that leads to valves V23-2016, F314, and 

F315. Hence, the continuations are not required for seismic support of the safety-related piping. 

The piping encompassing the anchor is in scope in accordance with 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.1-1 acceptable 

because it provided the location of the seismic anchor. Therefore, the staff’s concern described 

in RAI 2.3.4.1-1 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI response, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the condensate storage and transfer system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant has 

adequately identified the condensate storage and transfer system components subject to an 

AMR in accordance with 10 CFR 54.21(a)(1). 

2.3.4.2 Feedwater and Standby Feedwater 

 Summary of Technical Information in the Application 

LRA Section 2.3.4.2 states that the purpose of the feedwater and standby feedwater system is 

to provide feed flow to the RPV. The feedwater system supplies heated feedwater to the 
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reactor during normal plant power operation, and the standby feedwater system functions as a 

separate means of providing flow to the reactor from the CST. 

The feedwater system consists of the reactor feed pumps, the sixth-stage high-pressure 

feedwater heaters, piping, valves, controls, and instrumentation. The standby feedwater system 

provides condensate from the CST to the feedwater system downstream of the sixth-stage 

feedwater heater. The standby feedwater system consists of two motor-driven pumps, piping, 

valves, controls, and instrumentation. The standby feedwater system can support plant 

shutdown from the dedicated shutdown panel. 

The intended functions of the feedwater and standby feedwater system for license renewal 

include the following: 

 to support the RCPB 

 to support the primary containment pressure boundary 

 to maintain the integrity of nonsafety-related components so that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety 

function 

 to support fire protection (10 CFR 50.48) requirements 

LRA Table 2.3.4-2, “Feedwater and Standby Feedwater System Components Subject to Aging 

Management Review,” identifies the feedwater and standby feedwater system component types 

that are within the scope of license renewal and that are subject to an AMR. 

 Staff Evaluation 

The staff reviewed LRA Section 2.3.4.2; UFSAR Sections 9A.3.1.2, 7.1.1.2, 10.4.7, 7.1.2.1.9, 

10.4.8, and 7.7.1.3; UFSAR Figure 7.1-1; and the license renewal boundary drawings using the 

evaluation methodology discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff noted on drawing 

LRA-M-2023 (F-8) that a 10 CFR 54.4(a)(2) nonsafety-related line continues from drawing 

LRA-M-2004-01 (H-2). The staff could not locate seismic or equivalent anchors on the 

10 CFR 54.4(a)(2) nonsafety-related line continued from LRA-M-2004-01 (H-2). This line 

continues to 10 CFR 54.4(a)(1) safety-related valves F076A and F076B at locations F-1 and 

F-2. By letter dated November 26, 2014, the staff issued RAI 2.3.4.2-1 requesting that the 

applicant provide additional information to locate the seismic or equivalent anchors between the 

safety-nonsafety interface and the end of the 10 CFR 54.4(a)(2) scoping boundary. 

In its response letter dated December 30, 2014, to RAI 2.3.4.2-1, the applicant stated that, for 

LRA-M-2023, the seismic analysis ends in areas H-2 and H-1 where the 24-inch lines (3131) 
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from valves F076A and F076B connect to the 36-inch manifold (3103). There are equivalent 

anchors on the 24-inch lines before the connection to the manifold. 

The staff finds the applicant’s response to RAI 2.3.4.2-1 acceptable because it provided the 

location of the equivalent anchors. Therefore, the staff’s concern described in RAI 2.3.4.2-1 is 

resolved. 

One review method used by the staff is to confirm the inclusion of all components subject to an 

AMR by reviewing the results of the screening of components within the license renewal 

boundary. During its review of the drawings and locations (indicated in Table 2.3-8 below), the 

staff noted that it could not locate continuations of piping within the scope of license renewal; 

therefore, the staff could not verify the scoping boundary of SSCs. By letter dated 

November 26, 2014, the staff issued RAI 2.3.4.2-2 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. In addition, the staff requested the 

following: (1) if the continuation cannot be shown on license renewal boundary drawings, 

provide additional information describing the extent of the scoping boundary, (2) identify any 

additional component types subject to an AMR between the continuation and the termination of 

the scoping boundary, and (3) if the scoping classification of a piping section changes over the 

continuation, provide additional information to clarify the change in classification. 

Table 2.3-8 Feedwater and Standby Feedwater System Piping Continuations Not within 

the Scope of License Renewal 

LRA Drawing Location Continuation Issue 

LRA-M-2035 E-8 Could not find continuation from 

drawing LRA-M-2035, location E-8, to 

drawing LRA- M-2089, location H-4. 

LRA-M-5715-4 D-4 and D-7 Continuations to and from 

LRA-M-5715-4 to and from drawing 

M-5715-3, locations D-6 and D-4, 

respectively, could not be found 

because M-5715-3 was not provided.

In its response letter dated December 30, 2014, to RAI 2.3.4.2-2, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-2 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation from, 

and the end of, the scoping boundaries. Therefore, the staff’s concern described in 

RAI 2.3.4.2-2 is resolved. 

 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI responses, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the feedwater and standby feedwater system components within the scope of license renewal, 

as required by 10 CFR 54.4(a). The staff also concludes that the applicant has adequately 

identified the feedwater and standby feedwater system components subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). 
2-87 

2.3.4.3 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) 

 Summary of Technical Information in the Application 

LRA Section 2.3.4.3 summarizes scoping and screening of miscellaneous nonsafety-related 

S&PC systems or components that are within the scope of license renewal for 

10 CFR 54.4(a)(2) because of the potential for physical interactions with safety-related 

components. These physical interactions could cause failure by causing a loss of structural or 

mechanical integrity of the safety-related SSC. The LRA also states that any functional failures 

of these nonsafety-related SSCs were identified and discussed within individual systems’ 

evaluations of LRA Section 2.3.4 and are not evaluated in this section (i.e., Section 2.3.4.3). 

LRA Section 2.3.4.3 lists the following systems as being within the scope of license renewal 

based on the criteria in 10 CFR 54.4(a)(2) for physical failure: 

 main and reheat steam 

 condensate 

 feedwater and standby feedwater 

 heater drains 

 main turbine generator and auxiliaries 

 condenser and auxiliaries 

 circulating water 

 condensate storage and transfer 

 drips, drains, and vents 

LRA Tables 2.3.4-3-1 – 2.3.4-3-9 identify the component types that are within the scope of 

license renewal and that are subject to an AMR for 10 CFR 54.4(a)(2) based on potential for 

physical interactions. 

 Staff Evaluation 

The staff reviewed the miscellaneous S&PC systems in scope for 10 CFR 54.4(a)(2) functions 

described in LRA Section 2.3.4.3; UFSAR Sections 6.2.6, 9.2.1.2, 10.1, 10.2, 10.3, and 10.4; 

and the license renewal boundary drawings using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. During its review of the drawings as 

supplied by the applicant, the staff noted that it could not locate continuations of piping within 

the scope of license renewal; therefore, the staff could not verify the scoping boundary of SSCs. 

Drawing LRA-M-2007 (D-5 through E-5, and D-6) has in-scope 10 CFR 54.4(a)(2) lines 

continuing to drawing I-2400-03 at four locations. The applicant did not provide drawing 

I-2400-03. By letter dated November 26, 2014, the staff issued RAI 2.3.4.3-1 requesting that 
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the applicant provide sufficient information to locate the license renewal boundary. In addition, 

the staff requested the following: (1) if the continuation cannot be shown on license renewal 

boundary drawings, provide additional information describing the extent of the scoping 

boundary, (2) identify any additional component types subject to an AMR between the 

continuation and the termination of the scoping boundary, and (3) if the scoping classification of 

a piping section changes over the continuation, provide additional information to clarify the 

change in classification. 

In its response letter dated December 30, 2014, to RAI 2.3.4.3-1, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-1 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation from, 

and the end of, the scoping boundaries. Therefore, the staff’s concern described in 

RAI 2.3.4.3-1 is resolved. 

One review method used by the staff is to confirm the inclusion of all components subject to an 

AMR review by reviewing the results of the screening of components within the license renewal 

boundary. During its review of the drawings and locations (indicated in Table 2.3-9 below), the 

staff noted that it could not locate continuations of piping within the scope of license renewal; 

therefore, the staff could not verify the scoping boundary of SSCs. By letter dated 

November 26, 2014, the staff issued RAI 2.3.4.3-2 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. In addition, the staff requested the 

following: (1) if the continuation cannot be shown on license renewal boundary drawings, 

provide additional information describing the extent of the scoping boundary, (2) identify any 

additional component types subject to an AMR between the continuation and the termination of 

the scoping boundary, and (3) if the scoping classification of a piping section changes over the 

continuation, provide additional information to clarify the change in classification. 

Table 2.3-9 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License Renewal 

LRA Drawing Location Piping Continuation Issue

LRA-M-2011 H-4 An in-scope 10 CFR 54.4(a)(2) line 

continuing to drawing 6M721-2004 

(drawing LRA-M-2004), location C-3. 

Could not locate the continuation 

from LRA-M-2011 on drawing 

LRA-M-2004. 

LRA-M-2011 G-2, G-4, G-6, G-8, and D-3 In-scope 10 CFR 54.4(a)(2) lines to 

sample sink drain drawings on 

drawings I-2400-3 and I-2400-06. 

Drawings I-2400-3 and I-2400-06 

were not provided. 

LRA-M-2011-1 H-2 An in-scope 10 CFR 54.4(a)(2) line 

continuing to drawing M-3007. 

Drawing M-3007 was not provided. 

In its response letter dated December 30, 2014, to RAI 2.3.4.3-2, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 
2-89 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-2 acceptable 

because it provided sufficient information to locate the continuations and stated that there are 

no additional component types subject to an AMR between the continuation and the termination 

of the scoping boundaries. Therefore, the staff’s concern described in RAI 2.3.4.3-2 is resolved. 

In addition, during its review of the drawings and locations as supplied by the applicant, the staff 

noted that it could not locate continuations of piping within the scope of license renewal; 

therefore, the staff could not verify the scoping boundary of SSCs. Drawing LRA-M-2017-1 

(D-5) has a 2-inch diameter 10 CFR 54.4(a)(2) line continuing to an unspecified drawing (and 

location) with a note “At Condenser.” By letter dated November 26, 2014, the staff issued 

RAI 2.3.4.3-3 requesting that the applicant provide sufficient information to locate the license 

renewal boundary. In addition, the staff requested the following: (1) if the continuation cannot 

be shown on license renewal boundary drawings, provide additional information describing the 

extent of the scoping boundary, (2) identify any additional component types subject to an AMR 

between the continuation and the termination of the scoping boundary, and (3) if the scoping 

classification of a piping section changes over the continuation, provide additional information to 

clarify the change in classification. 

In its response letter dated December 30, 2014, to RAI 2.3.4.3-3, the applicant stated the 2-inch 

diameter 10 CFR 54.4(a)(2) line continues to connection No. 101 on the condenser shell. A 

similar continuation can be seen at location F-5 from the west preheater at location F-5; the 

isometric for this piping is indicated as 4149. M-4149-1 shows the piping to the condenser 

connection No. 101. There are no additional component types subject to an AMR or scoping 

classification changes between the continuation and the termination of these lines. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-3 acceptable 

because it provided sufficient information to locate the scoping boundary and stated that there 

are no additional component types subject to an AMR between the continuations from, and the 

end of, scoping boundary. Therefore, the staff’s concern described in RAI 2.3.4.3-3 is resolved. 

In addition, during its review of the drawings and locations (indicated in Table 2.3-10 below), the 

staff noted that it could not locate continuations of piping within the scope of license renewal; 

therefore, the staff could not verify the scoping boundary of SSCs. By letter dated 

November 26, 2014, the staff issued RAI 2.3.4.3-4 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. The staff also requested the 

following: (1) if the continuation cannot be shown on license renewal boundary drawings, 

provide additional information describing the extent of the scoping boundary, (2) identify any 

additional component types subject to an AMR between the continuation and the termination of 

the scoping boundary, and (3) if the scoping classification of a piping section changes over the 

continuation, provide additional information to clarify the change in classification. 
2-90 

Table 2.3-10 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License Renewal 

LRA Drawing Location Piping Continuation Issue 

LRA-M-2985-1 F-3, D-4, and E-6 Drawing LRA-M-2985-1 has three 

in-scope 10 CFR 54.4(a)(2) lines 

continuing to drawings M-4352, 

I-2314-3, and l-2314-3. Drawings 

M-4352 and l-2314-3 were not 

provided. 

LRA-M-2985-1 G-6 Drawing LRA-M-2985-1 (G-6) has a 

10 CFR 54.4(a)(2) line continuing to 

drawing LRA-M-2017-1, location A-7. 

Review of drawing LRA-M-2017-1 

could not locate the continuation from 

drawing LRA-M-2985-1. 

LRA-M-2985-1 E-2 and E-3 Drawing LRA-M-2985-1 (E-2 and 

E-3) has two 10 CFR 54.4(a)(2) lines 

continuing to drawing LRA-M-2017-1 

(F-6 and D-5). Review of drawing 

LRA-M-2017-1 could not locate the 

continuations from drawing 

LRA-M-2985-1. 

In its response letter dated December 30, 2014, to RAI 2.3.4.3-4, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-4 acceptable 

because it provided sufficient information to locate the continuations and identify the license 

renewal boundaries and stated that none of these continuations have a change in scoping 

classification. Therefore, the staff’s concern described in RAI 2.3.4.3-4 is resolved. 

Furthermore, during its review of the drawings and locations (indicated in Table 2.3-11 below), 

the staff noted that it could not locate continuations of piping within the scope of license 

renewal; therefore, the staff could not verify the scoping boundary of SSCs. By letter dated 

November 26, 2014, the staff issued RAI 2.3.4.3-5 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. In addition, the staff requested the 

following: (1) if the continuation cannot be shown on license renewal boundary drawings, 

provide additional information describing the extent of the scoping boundary, (2) identify any 

additional component types subject to an AMR between the continuation and the termination of 

the scoping boundary, and (3) if the scoping classification of a piping section changes over the 

continuation, provide additional information to clarify the change in classification. 
2-91 

Table 2.3-11 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License Renewal 

LRA Drawing Location Piping Continuation Issue 

LRA-M-2003 F-4 Drawing LRA-M-2003 (F-4) has an 

in-scope 10 CFR 54.4(a)(2) line 

continuing to drawing M-4504-1. 

Drawing M-4504-1 was not provided. 

LRA-M-2003 E-5 and F-5 Drawing LRA-M-2003 (E-5 and F-5) 

has an in-scope 10 CFR 54.4(a)(2) 

line continuing to drawing I-2314-03 

(H-3). Drawing I-2314-03 was not 

provided. 

In its response letter dated December 30, 2014, RAI 2.3.4.3-5, the applicant provided sufficient 

information to locate the license renewal boundaries and stated that there are no additional 

component types subject to an AMR or scoping classification changes between the continuation 

and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-5 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation and 

the license renewal boundaries. Therefore, the staff’s concern described in RAI 2.3.4.3-5 is 

resolved. 

One review method used by the staff is to confirm the inclusion of all components subject to an 

AMR by reviewing the results of the screening of components within the license renewal 

boundary. During its review of the drawings and locations (indicated in Table 2.3-12 below), the 

staff noted that it could not locate continuations of piping within the scope of license renewal; 

therefore, the staff could not verify the scoping boundary of SSCs. By letter dated 

November 26, 2014, the staff issued RAI 2.3.4.3-6 requesting that the applicant provide 

sufficient information to locate the license renewal boundary. In addition, the staff requested the 

following: (1) if the continuation cannot be shown on license renewal boundary drawings, 

provide additional information describing the extent of the scoping boundary, (2) identify any 

additional component types subject to an AMR between the continuation and the termination of 

the scoping boundary, and (3) if the scoping classification of a piping section changes over the 

continuation, provide additional information to clarify the change in classification. 

Table 2.3-12 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) Piping Continuations Not within the Scope of License Renewal 

LRA Drawing Location Continuation Issue 

LRA-I-2336-05 C-2, E-4, E-5, and E-6 Drawing LRA-I-2336-05 has four 

in-scope 10 CFR 54.4(a)(2) lines to 

drawings M-2165 and I-2334-20. 

Drawings M-2165 and I-2334-20 

were not provided. 

LRA-I-2336-06 B-7 and B-8 Drawing LRA-I-2336-06 (B-7 and 

B-8) has two in-scope 

10 CFR 54.4(a)(2) lines continuing to 

drawing I-2333-07. Drawing I-2333-

07 was not provided. 
2-92 

LRA Drawing Location Continuation Issue 

LRA-I-2336-26 E-4 Drawing LRA-I-2336-26 (E-4) has an 

in-scope 10 CFR 54.4(a)(2) line 

continuing to drawing I-2334-05. 

Drawing I-2334-05 was not provided. 

LRA-I-2336-26 D-4 Drawing LRA-I-2336-26 (D-4) has an 

8-in.-diameter 10 CFR 54.4(a)(2) line 

continuing from an unspecified 

drawing (and location) with a note 

“From Guard Piping.” 

LRA-I-2346-05 E-7 Drawing LRA-I-2346-05 (E-7) has an 

in-scope 10 CFR 54.4(a)(2) line 

continuing to drawing I-2346-06. 

Drawing I-2346-06 was not provided. 

LRA-I-2346-05 F-4, E-4, and D-4 Drawing LRA-I-2346-05 has three 

10 CFR 54.4(a)(2) lines continuing to 

unspecified drawings with notes “To 

Portable Drum,” “To Main Oil Tank,” 

and “To Waste Oil Tank.” 

In its response letter dated December 30, 2014, to RAI 2.3.4.3-6, the applicant provided 

sufficient information to locate the license renewal boundaries and stated that there are no 

additional component types subject to an AMR or scoping classification changes between the 

continuation and the termination of the scoping boundaries. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3-6 acceptable 

because it provided sufficient information to locate the license renewal boundaries and stated 

that there are no additional component types subject to an AMR between the continuation from, 

and the end of, the scoping boundaries. Therefore, the staff’s concern described in 

RAI 2.3.4.3-6 is resolved. 

 Conclusion 

Based on its evaluation and review of the LRA, UFSAR, RAI responses, and license renewal 

boundary drawings, the staff concludes that the applicant has appropriately identified the 

miscellaneous S&PC systems and components within the scope of license renewal for 

10 CFR 54.4(a)(2), as required by 10 CFR 54.4(a). The staff also concludes that the applicant 

has adequately identified the miscellaneous S&PC systems in scope for 10 CFR 54.4(a)(2) 

components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.4 Scoping and Screening Results: Structures 

This section documents the staff’s review of the applicant’s scoping and screening results for 

containments, structures, and component supports evaluated as a commodity. Specifically, this 

section describes the following structures and structural components that are within the scope of 

license renewal: 

 reactor/auxiliary building and primary containment 

 water-control structures 

 turbine building, process facilities, and yard structures 

 bulk commodities 
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In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs that are within the scope of license renewal and that are subject to an AMR. To 

verify that the applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

structures and components that meet the scoping criteria and that are subject to an AMR. 

The staff’s evaluation of the information in the LRA was the same for all structures. The 

objective was to determine whether the applicant has identified, in accordance with 

10 CFR 54.4, components and supporting structures for structures that appear to meet the 

license renewal scoping criteria. Similarly, the staff evaluated the applicant’s screening results 

to verify that all passive, long-lived SCs were subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on 

components that have not been identified as being within the scope of license renewal. The 

staff reviewed relevant licensing basis documents, including the UFSAR, for each structure to 

determine whether the applicant has omitted from the scope of license renewal components 

with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed the licensing 

basis documents to determine whether the LRA specified all intended functions delineated 

under 10 CFR 54.4(a). The staff issued RAIs to resolve any omissions or discrepancies 

identified. 

After its review of the scoping results, the staff evaluated the applicant’s screening results. For 

those SCs with intended functions, the staff sought to determine whether (1) the functions are 

performed with moving parts or with a change in configuration or properties or (2) the SCs are 

subject to replacement after a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that 

these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff issued RAIs 

to resolve any omissions or discrepancies identified. 

2.4.1 Reactor/Auxiliary Building and Primary Containment 

2.4.1.1 Summary of Technical Information in the Application 

LRA Section 2.4.1 describes the reactor/auxiliary building and primary containment structures. 

The reactor building is a seismic Category I concrete structure designed to maintain its 

structural integrity during and following postulated DBAs. The purpose of the reactor building is 

to serve as primary containment during reactor refueling and maintenance operations when the 

primary containment is open and as a secondary containment barrier when the primary 

containment is functional. The substructures and exterior walls of the building, up to the 

refueling floor, consist of poured-in-place reinforced concrete, which provides tornado missile 

protection, above which is steel framed with insulated metal siding with sealed joints. The 

purpose of the auxiliary building is to support the SGTS exhaust stack located on the roof and to 

house major plant systems and components. 

The reactor/auxiliary building houses the primary containment structure. The purpose of the 

primary containment is to provide a heat sink during a DBE and to limit the release of fission 

products in the event of a postulated DBA. The steel primary containment is a General Electric 

Mark I low-leakage pressure suppression containment design consisting of a drywell, torus, and 

connecting vent system. 
2-94 

The torus (or suppression chamber) is a leak-tight steel pressure vessel situated below and 

encircling the drywell. The vent system connects the drywell to the torus to conduct flow from 

the drywell to the torus. 

The intended functions of the reactor/auxiliary building and primary containment system within 

the scope of license renewal include the following: 

 to provide shelter, support, and protection for safety-related equipment and 

nonsafety-related equipment 

 to support the Appendix R safe shutdown analysis, fire protection (10 CFR 50.48), 

ATWS (10 CFR 50.62), SBO (10 CFR 50.63), and EQ (10 CFR 50.49) requirements 

 to provide radiation-shielding barriers to limit offsite radiation exposure 

 to limit the release of radioactive materials and fission products 

 to maintain the integrity of nonsafety-related structural components so that safety 

functions are not affected 

 to provide heat sink for any postulated transient or accident condition in which the 

normal heat sink is unavailable 

 to provide sufficient water to supply ECCS requirements and to refill the spent fuel pool if 

normal makeup water is not available 

LRA Table 2.4-1, “Reactor/Auxiliary Building and Primary Containment Components Subject to 

Aging Management Review,” identifies the component types that are within the scope of license 

renewal and that are subject to an AMR. 

2.4.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.1 and the applicable sections from the LRA and UFSAR, 

including the evaluation methodology described in Table 2.2-4 and Table 2.2-5 of LRA 

Section 2.0, using the evaluation methodology described in SER Section 2.4 and the guidance 

in SRP-LR Section 2.4. The staff also reviewed UFSAR Chapter 3 to identify structures 

classified as seismic Category I. 

During its review, the staff evaluated the structural component functions described in the LRA 

and UFSAR to verify that the applicant has included within the scope of license renewal all 

components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those components that the applicant identified as being within the scope of license renewal to 

verify that it has included all passive and long-lived components subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). 

Structural commodities that are unique to the reactor/auxiliary building and primary containment 

are included in this review, whereas those that are common to in-scope systems and structures 

are reviewed in SER Section 2.4.4, “Bulk Commodities.” 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. The staff noted that UFSAR 

Section 3.4.4, “Flood Protection,” and UFSAR Section 3.4.4.1, “Reactor Building Structure,” 

discuss the use of watertight seals and water stops for flood protection of Category I structures. 
2-95 

However, a review of the tables in the LRA did not identify such components for in-scope 

structures as being credited for flood protection and subject to an AMR. 

By letter dated September 26, 2014, the staff issued RAI 2.4-2 requesting the applicant to clarify 

the location within the LRA where they are addressed, the corresponding AMR and, if it was not 

included in the LRA, to justify its exclusion from the scope of license renewal pursuant to 

10 CFR 54.4. 

In its response letter dated October 24, 2014, to RAI 2.4-2, the applicant stated, in part, the 

following: 

Consistent with UFSAR Sections 3.4.4 and 3.4.4.1, watertight seals and water 

stops are credited for providing flood protection of Category I structures. 

Accordingly, they are included in the scope of license renewal. The watertight 

seals are elastomeric components used in doors and penetrations through the 

outside walls below the design flood elevation. They are included in LRA 

Table 3.5.2-4 line items “Penetration seals” and “Seals and gaskets (doors, 

manways and hatches)” with an intended function of flood barrier. The water 

stops are polymer components embedded in concrete at construction joints. 

They are inaccessible and protected from the environment by concrete (in the 

same manner as reinforcing steel). The water stops are treated as a 

subcomponent of reinforced concrete as is reinforcing steel. Therefore, water 

stops are not listed as a separate line item in an LRA table. 

The staff finds the applicant’s response acceptable because it verified the use of watertight 

seals and water stops for flood protection included within the scope of license renewal. The 

staff’s concern described in RAI 2.4-2 is resolved. 

The staff also noted that LRA Table 2.3.2-2, “Residual Heat Removal System,” does not list 

expansion joint bellows as a component subject to an AMR. However, LRA Table 2.4-4 lists 

“compressible joints and seals” as a component subject to an AMR. By letter dated 

September 26, 2014, the staff issued RAI 2.4-1 requesting that the applicant confirm that this 

component includes the use of expansion joint bellows and, if they are installed in the RHR 

system, provide the locations where they are covered and whether they are subject to an AMR 

pursuant to 10 CFR 54.21(a)(1)(i). 

In its response dated October 24, 2014, to RAI 2.4-1, the applicant stated, in part, the following: 

There are no bellows in the RHR system. [C]ontainment penetration bellows are 

considered part of the related structure rather than the process system. 

[I]nstead, the containment penetration bellows are described in LRA 

Section 2.4.1 and covered under the component type “penetration bellows” which 

is listed in LRA Table 2.4-1. The aging management review results for this 

component type are provided in LRA Table 3.5.2-1. 

The licensee also stated the following: 

The bulk commodities listed in LRA Section 2.4.4 and shown in LRA Table 2.4-4 

are those that are common to in-scope SSCs. Therefore, the entry in LRA 

Table 2.4-4 for “compressible joints and seals” is not related to the containment 

penetration bellows discussed above. 
2-96 

The staff finds the applicant’s response acceptable because it confirmed that there are no 

bellows in the RHR system and because it clarified that containment penetration bellows are 

considered part of the related structure and are not part of the process system. The applicant 

also provided the LRA section and table that describe the containment penetration bellows and 

their AMR results. The staff’s concern described in RAI 2.4-1 is resolved. 

In addition, the staff noted that UFSAR Section 6.2.5.2.5, “Containment Purge,” states that 

“debris screens have been provided for the purge valves inside the drywell to prevent debris 

from becoming entrained in the valves.” However, LRA Section 2.4.1, “Reactor/Auxiliary 

Building and Primary Containment,” does not discuss or include such a component in LRA 

Table 2.4-1. By letter dated September 26, 2014, the staff issued RAI 2.4-4 requesting the 

applicant to identify the section of the LRA where debris screens are covered, the applicable 

aging effects, and the AMP related to this component or to justify its exclusion from the scope of 

license renewal pursuant to 10 CFR 54.4. 

In its response dated October 24, 2014, to RAI 2.4-4, the applicant stated, in part, the following: 

[D]ebris screens are provided for the purge valves inside the drywell to prevent 

debris from becoming entrained in the valves. There are two debris screens 

[identified as “strainer” component type] that are part of the Containment 

Atmospheric Control (CAC) system (T48) [as described in LRA Section 2.3.3.13]. 

...The aging management evaluation is provided in LRA Table 3.3.2-13 under 

the “strainer” component type. As shown in LRA Table 3.3.2-13, strainers are 

stainless steel in an indoor air environment. Thus there is no aging effect 

requiring management. The material for the debris screens was determined to 

be stainless steel based on information from the vendor the screens may be 

either carbon or stainless steel supplemented by photographs of the screens 

showed a shiny surface indicative of stainless steel. 

However, as described in LRA Section 2.3.3.13, one drywell exhaust isolation 

valve of the CAC system is reviewed as part of the Standby Gas Treatment 

(SGT) system in LRA Section 2.3.2.7. One of the debris screens is located near 

this valve and was intended to be reviewed as part of the SGT system as 

indicated on drawing LRA-M-2709. The discussion in LRA Section 2.3.2.7 does 

not include the debris screen and no “strainer” component type is included in 

LRA Tables 2.3.2-7 and 3.2.2-7. 

The applicant revised the LRA tables to include the “strainer” component type. The applicant 

also stated the following: 

Following the LRA revision, one of the debris screens will be addressed in the 

section and tables associated with the CAC system and the other will be 

addressed in the section and tables associated with the SGT system. This will 

ensure consistency with the LRA drawings. As described above, the debris 

screens are stainless steel in an indoor air environment such that there are no 

aging effects requiring a management and thus no impact on any aging 

management program. 

The staff finds the applicant’s response acceptable because it identified the LRA section where 

debris screens are covered and it confirmed that the debris screens are stainless steel in an 
2-97 

indoor air environment, and, for this reason, there are no applicable aging effects requiring 

management. In addition, the applicant revised the LRA to ensure consistency with the LRA 

drawings. The staff’s concern described in RAI 2.4-4 is resolved. 

2.4.1.3 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, RAI responses, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the reactor/auxiliary building and primary containment components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant has 

adequately identified the reactor/auxiliary building and primary containment components subject 

to an AMR, as required by 10 CFR 54.21(a)(1). 

2.4.2 Water-Cooled Structures 

2.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.4.2 states that the water-control structures consist of the GSW pump house, 

RHR complex, and shore barrier. 

The purpose of the GSW pump house is to prevent fire from damaging both fire protection 

pumps and to house the circulating water makeup pumps, GSW pumps, and associated 

electrical equipment. The structure consists of a metal-clad building founded on a reinforced 

concrete intake structure and concrete block interior walls. Traveling screens and stationary 

racks are provided to keep floating debris from entering the GSW intake pit. 

The purpose of the RHR complex is to provide a source of cooling water for safe shutdown of 

the plant. The RHR complex, which is the ultimate heat sink, is a Category I structure and 

consists of the RHR service water system, the emergency equipment service water system, the 

DG service water system, the mechanical draft cooling towers, the emergency AC power 

system, and the reservoir. The RHR complex is a reinforced concrete and concrete block 

structure supported on a base mat. 

The RHR complex includes a two-cell, mechanical-induced draft cooling tower constructed of 

Category I fireproof materials located over each division reservoir of the RHR complex. The 

complex also consists of two one-half capacity reinforced concrete Category I structures 

(reservoirs) founded on bedrock and connected to permit access to the combined inventory of 

water from the two reservoirs from either RHR division. Four EDGs are also part of the complex 

and are housed in separate rooms designed to withstand fire and missiles. 

The shore barrier, a Category I structure consisting of a rubble-mound structure with an armor 

cover of stone, protects the shoreline adjacent to the plant from erosion resulting from wave 

action, preserves the integrity of the plant site fill placed to elevation 583 feet, and protects the 

main plant portion of the site against wave forces. 

The intended functions of the water-control structures components within the scope of license 

renewal include the following: 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

 to provide physical support, shelter, and protection for safety-related SSCs 
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 to provide a source of cooling water for safe shutdown of the plant 

 to provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of functions identified for 

10 CFR 54.4(a)(1) 

LRA Table 2.4-2, “Water-Control Structures Components Subject to Aging Management 

Review,” identifies the component types that are within the scope of license renewal and that 

are subject to an AMR. 

2.4.2.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.2, the applicable sections from the LRA and UFSAR, and 

LRA Tables 2.2-4 and 2.2-5 using the evaluation methodology described in SER 2.4 and the 

guidance in SRP-LR Section 2.4. The staff also reviewed UFSAR Section 3.8.4 to identify 

structures classified as seismic Category I. 

During its review, the staff evaluated the structural component functions described in the LRA 

and UFSAR to verify that the applicant has included within the scope of license renewal all 

components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those components that the applicant identified as being within the scope of license renewal to 

verify that it has included all passive and long-lived components subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). 

Structural commodities that are unique to water-control structures are included in this review, 

whereas those that are common to in-scope systems and structures (e.g., anchors, 

embedments, equipment supports, instrument panels, racks, cable trays, and conduits) are 

reviewed in SER Section 2.4.4. 

The staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. The staff noted that LRA 

Section 2.4.2, “Water-Control Structures,” and UFSAR Section 9.2.1, “General Service Water 

System,” state that “traveling screens and stationary racks are provided to keep floating debris 

from entering the GSW intake pit.” However, such components are not included in LRA 

Table 2.4-2 or LRA Table 2.4-4. By letter dated September 26, 2014, the staff issued RAI 2.4-3 

requesting the applicant to identify the section of the LRA where traveling screens and 

stationary racks are covered, the applicable aging effects, and the AMP related to these 

components. If they are not included in the LRA, the staff requested the applicant to justify their 

exclusion from the scope of license renewal. The staff also requested that the applicant clarify 

whether there are any additional trash racks, basket strainers, traveling screens, or any other 

debris prevention or removing mechanisms that are part of any in-scope structures subject to 

10 CFR 54.4. 

In its response dated October 24, 2014, to RAI 2.4-3, the applicant stated, in part, the following: 

The traveling screens and stationary racks (and any other debris prevention or 

removing mechanisms) are not considered part of the structure of the GSW 

pump house. These components are nonsafety-related and their failure could 

not impact any safety-related function since there is no safety-related equipment 

inside the GSW pump house. Therefore, the traveling screens and racks are not 

in-scope for license renewal. ...For this reason, the components were not 

included in either LRA Tables 2.4-2 or 2.4-4. 
2-99 

The RHR complex and shore barrier are the other water-control structures 

addressed in LRA Section 2.4.2. There are no additional trash racks, basket 

strainers, traveling screens or other debris prevention or removal mechanisms 

that are part of these in-scope structures. 

The staff finds the applicant’s response acceptable because it justified the exclusion of traveling 

screens and stationary racks from the scope of license renewal. The applicant also clarified that 

there are no additional trash racks, basked trainers, traveling screens, or any other debris 

prevention or removing mechanisms that are part of any in-scope structures subject to 

10 CFR 54.4. The staff’s concern described in RAI 2.4-3 is resolved. 

2.4.2.3 Conclusion 

Based on its evaluation and on a review of the LRA, UFSAR, and RAI response, the staff 

concludes that the applicant has appropriately identified water-control structures components 

within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also concludes 

that the applicant has adequately identified the water-control structures components subject to 

an AMR, as required by 10 CFR 54.21(a)(1). 

2.4.3 Turbine Building, Process Facilities, and Yard Structures 

2.4.3.1 Summary of Technical Information in the Application 

LRA Section 2.4.3 describes the turbine building, process facilities, and yard structures 

including the various structures within each category. 

The turbine building houses the turbine generator, power conversion equipment, associated 

auxiliaries, and offsite power cables affecting CTG 11-1 and Division I and II cables associated 

with HPCI and RCIC. The turbine building is separate from the reactor/auxiliary building and is 

classified as a nonsafety-related structure. 

The turbine building consists of reinforced concrete exterior walls, a superstructure that 

supports the turbine building cranes, and a concrete shield wall that surrounds the turbine 

generator. Interior walls are reinforced concrete or masonry block designed to provide radiation 

shielding and fire protection. The turbine pedestal is a reinforced concrete structure supported 

by a foundation that is separate and independent from the foundation mat of the turbine 

building. 

The radwaste building is identified as a process facility. The purpose of the radwaste building is 

to house the liquid and solid waste processing equipment, offsite power cables affecting 

CTG 11-1, and RHR instrumentation equipment and cable. The building is structurally part of 

the turbine building and is constructed of reinforced concrete and concrete block and is 

equipped with Class A, B, and C fire doors. Penetrations through the walls of the turbine 

building are sealed to provide a 3-hour fire barrier. 

The following structures are included within yard structures: 

 CTG 11-1 structure 

 condensate storage and return tanks foundations and retaining barrier 

 CTG-11 FOST foundation 

 independent spent fuel storage installation rail transfer pad 
2-100 

 manholes, handholes, and duct banks 

 relay house and 120-kV switchyard 

 relay house and 345-kV switchyard 

 transformer and switchyard support structures and foundations 

The CTG 11-1 provides AC electric power for distribution to the DTE grid to meet peak power 

demands and provides electric power as an alternate power source for Fermi 2 to cope with a 

SBO and to operate alternate safe shutdown equipment. 

The purpose of the CST and CRT foundations and retaining barrier is to provide support for the 

CST/CRT, which provides a water source for standby feedwater, HPCI, CRD, RCIC, and core 

spray systems. Each tank foundation consists of a circular reinforced concrete foundation 

supported on consolidated structural backfill with all valves located in separate reinforced 

concrete valve pits at the base of each tank integral to their foundation. The tanks and 

foundations are located inside a 3-ft-high reinforced concrete wall dike area designed to collect 

the contents in the event of a tank spill or overflow and to prevent exposure to fire or heat from 

an exposure fire. 

The CTG-11 FOST foundation provides support for the 800,000-gal FOST for the Fermi 1 

combustion turbine units. The foundation is a nonsafety-related structure located approximately 

1/3 mile from Fermi 2 and safety-related plant structures. The foundation consists of a circular 

reinforced concrete foundation supported on consolidated backfill. 

The independent spent fuel storage installation rail transfer pad is a reinforced concrete 

roadway that provides for transfer of dry fuel casks and provides missile protection for the 

Division I and Division II safety-related duct banks located below the roadway. 

Manholes, handholes, and duct banks allow underground routing of cables and certain piping. 

Manholes and handholes consist of reinforced concrete rectangular box structures buried 

underground with a reinforced concrete panel on top to allow access. Duct banks are used to 

route cables between structures and switchyard areas and comprise multiple raceways encased 

in concrete in an excavated trench backfilled with soil or engineered compacted backfill. 

The 120-kV and 345-kV relay houses are nonsafety-related structures separated from 

safety-related SSCs so that its failure would not affect a safety function. The 120-kV relay 

house is a prefabricated metal building founded on a reinforced concrete foundation. The 

345-kV relay house structure consists of unreinforced concrete block walls with a composite 

roof construction founded on a reinforced concrete foundation. 

The purpose of the transformer and switchyard support structures and foundations is to provide 

structural support to SSCs that are relied on in safety analysis or plant evaluations to perform a 

function that supports SBO (10 CFR 50.63) requirements. 

The intended functions of the turbine building, process facilities, and yard structures within the 

scope of license renewal include the following: 

 to provide physical support, shelter, and protection for nonsafety-related SSCs whose 

failure could prevent satisfactory accomplishment of functions identified for 

10 CFR 54.4(a)(1) 
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 to maintain the integrity of nonsafety-related structural components so that safety 

functions are not affected 

 to support fire protection (10 CFR 50.48) and SBO (10 CFR 50.63) requirements 

 to provide physical support, shelter, and protection for safety-related SSCs within the 

scope of license renewal 

LRA Table 2.4-3, “Turbine Building, Process Facilities and Yard Structures Components Subject 

to Aging Management Review,” identifies the component types that are within the scope of 

license renewal and that are subject to an AMR. 

2.4.3.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.3, the applicable sections from the LRA and UFSAR, and 

LRA Tables 2.2-4 and 2.2-5 using the evaluation methodology described in SER Section 2.4 

and the guidance in SRP-LR Section 2.4. The staff also reviewed UFSAR Chapter 3 to identify 

structures classified as seismic Category I. 

During its review, the staff evaluated the structural component functions described in the LRA 

and UFSAR to verify that the applicant has included within the scope of license renewal all 

components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed 

those components that the applicant identified as being within the scope of license renewal to 

verify that it has included all passive and long-lived components subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). 

Structural commodities that are unique to the turbine building, process facilities, and yard 

structures are included in this review, whereas those that are common to in-scope systems and 

structures (e.g., anchors, embedments, equipment supports, instrument panels, racks, cable 

trays, and conduits) are reviewed in SER Section 2.4.4. 

2.4.3.3 Conclusion 

Based on its evaluation and on a review of the LRA and UFSAR, the staff concludes that the 

applicant has appropriately identified the turbine building, process facilities, and yard structure 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

concludes that the applicant has adequately identified the turbine building, process facilities, 

and yard structure components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.4.4 Bulk Commodities 

2.4.4.1 Summary of Technical Information in the Application 

LRA Section 2.4.4, “Bulk Commodities,” describes bulk commodities subject to an AMR as 

structural components or commodities that perform or support intended functions of SSCs within 

the scope of license renewal. The LRA also states that bulk commodities unique to a specific 

structure were included within individual structures’ evaluations of LRA Sections 2.4.1, 2.4.2, 

and 2.4.3 and are not evaluated in this section (i.e., Section 2.4.4). 

Bulk commodities evaluated in LRA Section 2.4.4 support both safety-related and 

nonsafety-related equipment during normal and accident conditions in the event of external 
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events, such as tornadoes, earthquakes, floods and missiles, and internal events (e.g., pipe 

breaks and a LOCA). 

The intended functions of the bulk commodities within the scope of license renewal include the 

following: 

 to provide support, shelter, and protection for safety-related equipment and 

nonsafety-related equipment within the scope of license renewal 

 to maintain the integrity of nonsafety-related structural components so that safety 

functions are not affected 

 to support safe-shutdown analysis, fire protection (10 CFR 50.48), EQ (10 CFR 50.49), 

ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) requirements 

LRA Table 2.4-4 identifies the component types that are within the scope of license renewal and 

that are subject to an AMR. 

2.4.4.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.4 and the applicable sections from the LRA using the 

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4. 

During its review, the staff evaluated the structural component functions described in the LRA to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

2.4.4.3 Conclusion 

Based on its evaluation and review of the LRA and UFSAR, the staff concludes that the 

applicant has appropriately identified the bulk commodities components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also concludes that the applicant has 

adequately identified the bulk commodities components subject to an AMR, as required by 

10 CFR 54.21(a)(1). 

2.4.5 Fire Barriers Portion of Bulk Commodities 

2.4.5.1 Summary of Technical Information in the Application 

LRA Section 2.4 provides scoping and screening results of structures. Specific structures are 

included in the review in LRA Sections 2.4.1, 2.4.2, and 2.4.3. LRA Tables 2.4-1, 2.4-2, and 

2.4-3 list all credited fire barrier types and license renewal intended functions. 

Bulk commodities are structural components that support the various intended functions 

performed by the structures in which they are located. These functions include the following: 

 to provide support, shelter, and protection for safety-related equipment and 

nonsafety-related equipment within the scope of license renewal 
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 to maintain the integrity of nonsafety-related structural components so that safety 

functions are not affected 

 to support safe shutdown analysis and fire protection (10 CFR 50.48) requirements 

2.4.5.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.4 (i.e., only the scoping and screening results of fire 

barriers) and the relevant LRA drawings using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4. The staff also reviewed UFSAR 

Sections 9.5.1 and 9A and the guidelines in Appendix A to BTP APCSB 9.5-1. 

The staff also reviewed the following fire protection documents cited in the CLBs listed in the 

Fermi 2 Operating License Condition 2.C(9): 

 NUREG-0798, Supplement 5, “Safety Evaluation Report Related to the Operation of 

Fermi 2,” dated March 1985 

 NUREG-0798, Supplement 6, “Safety Evaluation Report Related to the Operation of 

Fermi 2,” dated July 1985 

To perform its evaluation, the staff reviewed the applicable LRA sections and focused its review 

on fire barriers and components that had not been identified as being within the scope of license 

renewal. 

The staff reviewed UFSAR Sections 9.5.1 and 9A for each structure to verify that the applicant 

has included within the scope of license renewal all components with intended functions 

delineated under 10 CFR 54.4(a). The staff also verified that all intended functions delineated 

under 10 CFR 54.4(a) were specified in the LRA. 

The staff’s review identified areas in which additional information was necessary to complete the 

review of the applicant’s scoping and screening results. By letter dated October 29, 2014, the 

staff issued RAI 2.4.4-1 stating that LRA Section 2.4.4 provides the scoping and screening 

results of various structural components that are within the scope of license renewal and that 

are subject to an AMR. LRA Table 2.4-4, includes fire barriers (e.g., doors; fire protection 

components and miscellaneous steel, including framing steel; penetration seals (end caps) and 

sleeves; manways, hatches, manhole covers, and hatch covers; structural fire barriers; wall, 

ceiling, floor slabs, curbs, and dikes; fire stops; fire wrap; and penetration seals). However, 

scoping and screening results do not provide the type of fire barriers present in various fire 

areas of the plant. The staff requested that the applicant provide a summary of the list of 

buildings or structures where fires barriers are credited and the specific types of barriers at 

these locations in Fermi 2 fire protection program. 

In addition, the staff stated that LRA Table 2.4-4 does not include the following types of fire 

barriers or fire protection features: 

 fire retardant coating for exposed structural steel 

 solid metal cable tray covers 

 radiant energy shields 

 outdoor oil-filled transformer fire barriers 
2-104 

The staff requested that the applicant verify whether the fire barriers or fire protection features 

listed above are within the scope of license renewal in accordance with 10 CFR 54.4(a) and 

whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are 

excluded from within the scope of license renewal and are not subject to an AMR, the staff 

requested that the applicant provide justification for the exclusion. 

In its response dated December 1, 2014, to RAI 2.4.4-1, the applicant provided a summary of 

the list of buildings or structures described in LRA Sections 2.4.1, 2.4.2, and 2.4.3 for which fire 

barriers are credited in the Fermi 2 fire protection program, as follows: 

 LRA Section 2.4.1: reactor/auxiliary building 

 LRA Section 2.4.2: GSW pump house and RHR complex 

 LRA Section 2.4.3: turbine building, radwaste building, CST/CRT retaining barrier, 

manholes, handholes, and duct banks 

Furthermore, the applicant provided specific types of fire barriers located at these locations in 

the Fermi 2 fire protection program, as follows: 

 carbon steel railroad airlock doors and masonry walls in the reactor/auxiliary building as 

shown in LRA Section 2.4.1 and LRA Table 2.4-1 

 masonry walls in the RHR complex and GSW pump house as shown in LRA 

Section 2.4.2 and LRA Table 2.4-2 

 carbon steel roof decking or floor decking and masonry walls in the turbine building and 

radwaste building as shown in LRA Section 2.4.3 and LRA Table 2.4-3 

 concrete manholes and hand holes as shown in LRA Section 2.4.3 and LRA Table 2.4-3 

 concrete retaining barrier of the CST/CRT structure as shown in LRA Section 2.4.3 and 

LRA Table 2.4-3 

The applicant stated the following: 

There are also other types of fire barriers that are common to the buildings or 

structures above but are not listed in the individual LRA Sections 2.4.1, 2.4.2, 

and 2.4.3. Consistent with application of bulk commodities described in LRA 

Section 2.4.4, these common fire barriers are considered bulk commodities and 

are included in LRA Section 2.4.4, “Bulk Commodities.” They perform a fire 

barrier intended function and are shown in LRA Table 2.4-4. 

In regard to the fire barrier features, the applicant responded to RAI 2.4.4-1 by stating the 

following: 

Fire retardant coatings, solid metal cable tray covers, radiant energy shields, and 

outdoor oil-filled transformer fire barriers are in the scope of Fermi 2 license 

renewal and are subject to aging management review (AMR). They are shown in 

the LRA tables as described below. 

Fire retardant coatings on exposed structural steel were not identified during 

preparation of the LRA and subsequent reviews have not identified fire retardant 

coatings being credited as a fire barrier for exposed structural steel. Fire 
2-105 

retardant coatings are generically included in LRA Table 2.4-4 under “Other 

Materials” as component type “Fire wrap” with an intended function of “Fire 

barrier.” The AMR results for the fire wrap components are provided in LRA 

Table 3.5.2-4. This ensures that any potential use of fire retardant coatings will 

be in scope and subject to aging management review. 

“Solid metal cable tray covers” are included in LRA Table 2.4-4 under Steel and 

Other Metals as component type “Fire protection components – miscellaneous 

steel, including framing steel” with an intended function of “Fire barrier.” The 

material of the component is carbon steel and AMR results for the carbon steel 

components are provided in LRA Table 3.5.2-4. 

“Radiant energy shields” are included in LRA Table 2.4-4 under Steel and Other 

Metals as component type “Fire protection components – miscellaneous steel, 

including framing steel” with an intended function of “Fire barrier.” The material 

of the component is carbon steel and AMR results for the carbon steel 

components are provided in LRA Table 3.5.2-4. 

“Outdoor oil-filled transformer fire barriers” are included in LRA Table 2.4-4 under 

Concrete as component type “Structural fire barriers; walls, ceilings, floor slabs, 

curbs, dikes” with an intended function of “Fire barrier.” The material of the 

component is concrete and AMR results for this concrete component are 

provided in LRA Table 3.5.2-4. 

The staff finds the applicant’s response to RAI 2.4.4-1 acceptable because it identified the types 

of fire barriers present in various fire areas of the plant and provided a list of buildings and 

structures where fires barriers are credited, including the specific types of barriers at these 

locations in the Fermi 2 Fire Protection Program. Furthermore, the applicant indicated that the 

following types of fire barriers are credited in the reactor/auxiliary building, GSW pump house, 

RHR complex, turbine building, radwaste building, CST/CRT retaining barrier, manholes, 

handholes, and duct banks: (1) masonry walls, (2) concrete retaining barrier of CST/CRT 

structure, (3) concrete manholes and handholes, (4) carbon steel railroad airlock doors, and 

(5) carbon steel roof decking or floor decking. 

In addition, the applicant had addressed, in its response, the staff’s RAI concerning types of fire 

barriers or fire protection features. The applicant indicated that the fire retardant coatings on 

exposed structural steel were not credited as a fire barrier for exposed structural steel. The 

applicant also stated that LRA Table 2.4-4, under “Other Materials” and component type “Fire 

wrap,” included fire retardant coatings with an intended function of fire barrier. Further, the 

applicant indicated that the AMR results for the “Fire wrap” are provided in LRA Table 3.5.2-4; 

this ensures that any potential use of fire retardant coatings will be in scope and subject to an 

AMR. 

The applicant indicated that the radiant energy shields are included in LRA Table 2.4-4 under 

“Steel and Other Metals” as component type “Fire protection components – miscellaneous steel, 

including framing steel,” with an intended function of fire barrier. The material of the component 

is carbon steel, and AMR results for the carbon steel components are provided in LRA 

Table 3.5.2-4. Fire barriers associated with the outdoor oil-filled transformer are included in 

LRA Table 2.4-4 under “Concrete” as component type “Structural fire barriers; walls, ceilings, 

floor slabs, curbs, dikes,” with an intended function of fire barrier. The material of the 
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component is concrete, and AMR results for this concrete component are provided in LRA 

Table 3.5.2-4. 

Based on its review, the staff finds the applicant’s response to RAI 2.4.4-1 acceptable because 

it clarified that the fire protection system and components listed above are within the scope of 

license renewal and are subject to an AMR as required by 10 CFR 54.4(a) and 

10 CFR 54.21(a)(1), respectively. The staff’s concern described in RAI 2.4.4-1 is resolved. 

By letter dated December 17, 2014, the staff issued RAI 2.4.4-2 stating that LRA 

Section 2.3.3.7, “Fire Protection – Water,” indicates that fire dampers mounted in walls 

(for compliance with 10 CFR 50.48) are addressed in LRA Section 2.4.4; however, LRA 

Section 2.4.4 does not mention damper housings as a component type that is subject to an 

AMR. Similarly, LRA Section 2.4.2, “Water-Control Structures,” Residual Heat Removal 

Complex subsection, also refers to fire dampers in walls; however, LRA Table 2.4-2 does not 

include any damper housings as a component type subject to an AMR. Table IX.B of the 

GALL Report defines “ducting and components” as including fire dampers. However, the 

SRP-LR and the GALL Report do not differentiate between air control or air flow dampers and 

fire dampers that are needed for compliance with 10 CFR 50.48. 

Furthermore, the staff asked if all fire damper assemblies in fire barriers (walls, ceiling, and 

floors) have been appropriately identified as a component type as being within the scope of 

license renewal and subject to an AMR. 

The staff requested that the applicant verify whether the fire damper assemblies mounted in fire 

barriers (i.e., not in HVAC ductwork) are within the scope of license renewal (e.g., in the RHR 

complex) in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). If they are not within the scope of license renewal and are 

not subject to an AMR, the staff requested that the applicant provide justification for the 

exclusion. 

By letters dated January 15, 2015, and April 10, 2015, the applicant responded to RAI 2.4.4-2 

by stating the following: 

The fire damper assemblies mounted in fire barriers (walls, ceilings, and floors) 

outside of HVAC ductwork are within the scope of license renewal in accordance 

with10 CFR 54.4(a) and are subject to an AMR in accordance with 

10 CFR 54.21(a)(1). The fire dampers perform an active function and are not 

subject to an AMR. The fire damper housings are passive long-lived 

components subject to an AMR. The fire damper housings are included with the 

component type “Fire protection components – miscellaneous steel including 

framing steel” with a fire barrier intended function as shown in LRA-Tables 2.4-4 

and 3.5.2-4. 

Based on its review, the staff finds the applicant’s response to RAI 2.4.4-2 acceptable because 

it clarified that the fire damper assemblies mounted in fire barriers (walls, ceilings, and floors) 

outside of HVAC ductwork are within the scope of license renewal and are subject to an AMR 

(i.e., only the passive part of the fire damper assemblies (housings)). The staff confirmed that 

the fire damper housings are included in LRA Table 2.4-4 as being subject to an AMR in LRA 

Table 3.5.2-4. The staff’s concern described in RAI 2.4.4-2 is resolved. 
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2.4.5.3 Conclusion 

Based on its evaluation and review of the LRA, UFSAR Sections 9.5.1 and 9A, and license 

renewal boundary drawings, the staff concludes that the applicant has appropriately identified 

the fire barrier commodities components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the fire 

barrier commodities components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems 

This section documents the staff’s review of the applicant’s scoping and screening results for 

electrical and I&C systems. Specifically, this section discusses: 

 electrical and I&C component and commodity groups 

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

electrical and I&C system components that meet the scoping criteria and that are subject to an 

AMR. 

The staff’s evaluation of the information in the LRA was the same for all electrical and I&C 

systems. The objective was to determine whether the applicant has identified, in accordance 

with 10 CFR 54.4, components and supporting structures for electrical and I&C systems that 

appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the 

applicant’s screening results to verify that all passive, long-lived components were subject to an 

AMR in accordance with 10 CFR 54.21(a)(1). 

In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on 

components that have not been identified as being within the scope of license renewal. The 

staff reviewed relevant licensing basis documents, including the UFSAR, for each electrical and 

I&C system to determine whether the applicant has omitted from the scope of license renewal 

components with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed 

the licensing basis documents to determine whether the LRA specified all intended functions 

delineated under 10 CFR 54.4(a). The staff issued RAIs to resolve any omissions or 

discrepancies identified. 

After its review of the scoping results, the staff evaluated the applicant’s screening results. For 

those SCs with intended functions, the staff sought to determine whether (1) the functions are 

performed with moving parts or with a change in configuration or properties or (2) the SSCs are 

subject to replacement after a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that 

these SSCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff issued RAIs 

to resolve any omissions or discrepancies identified. 
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2.5.1 Electrical and Instrumentation and Control Components and Commodity Groups 

2.5.1.1 Summary of Technical Information in the Application 

LRA Section 2.5 describes the electrical and I&C systems/components. Interface of these 

components with mechanical or civil/structural components and active electrical components 

with passive mechanical functions are covered in the mechanical or civil/structural sections. 

The bounding approach was the method used in determining the scope of the electrical and I&C 

systems in the license renewal. The scope includes all plant electrical and I&C components, 

including those electrical and I&C components in mechanical systems. The applicant stated, in 

part, that the bounding approach method eliminates the need for unique identification of 

individual components and specific component locations and precludes improper exclusion of 

components from the AMR. The scoping method includes identifying the electrical and I&C 

systems and their design functions and reviewing them against the criteria in 10 CFR 54.4. 

The electrical and I&C components that were identified as being within the scope of license 

renewal have been grouped by the applicant into component commodity groups. The applicant 

has applied the screening criteria in 10 CFR 54.21(a)(1)(i) and 10 CFR 54.21(a)(1)(ii) to this list 

of component commodity groups to identify those that perform their intended functions without 

moving parts or without a change in configuration or properties and to remove the component 

commodity groups that are subject to replacement based on a qualified life or specified time 

period. 

The following list identifies the component and commodity groups that are subject to an AMR 

and their intended functions: 

 Electrical Conductors. The function of electrical conductors is to provide electrical 

continuity. 

 transmission conductors and connections 

 electrical/cable connections 

 fuse holders: metallic clamps 

 switchyard bus and connections 

 metal enclosed bus: bus/connections 

 metal enclosed bus: enclosure assemblies 

 Electrical Insulation. The function of electrical insulation is to insulate and support 

electrical conductor. 

 conductor insulation for inaccessible power (400-V to 13.8-kV) cables 

(e.g., installed underground in conduit, in duct bank, or through direct burial) not 

subject to 10 CFR 50.49 EQ requirements 

 insulation material for electrical cables and connections (including terminal blocks 

and fuse holder) not subject to 10 CFR 50.49 EQ requirements 

 insulation material EIC penetration cables and connections not subject to 

10 CFR 50.49 EQ requirements 

 insulation material for electrical cables not subject to 10 CFR 50.49 EQ 

requirements used in instrumentation circuits 

 high-voltage insulators (for SBO recovery) 
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 fuse holders: insulation material 

 Metal Enclosed Bus: insulation, insulators 

LRA Table 2.5-1, “Electrical and Instrumentation and Control Systems Components Subject to 

Aging Management Review,” identifies electrical and I&C system component types that are 

within the scope of license renewal and are subject to an AMR. 

2.5.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.5 and UFSAR Sections 7 and 8 using the evaluation 

methodology described in SER Section 2.5 and the guidance in SRP-LR Section 2.5. 

During its review, the staff evaluated the system functions described in the LRA and UFSAR to 

verify that the applicant has included within the scope of license renewal all components with 

intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as being within the scope of license renewal to verify 

that it has included all passive and long-lived components subject to an AMR in accordance with 

10 CFR 54.21(a)(1). 

General Design Criteria 17, “Electric Power Systems,” of Appendix A, “General Design Criteria 

for Nuclear Power Plants,” to 10 CFR Part 50 requires that electric power from the transmission 

network to the onsite electric distribution system is supplied by two physically independent 

circuits to minimize the likelihood of their simultaneous failure. In addition, the staff noted that 

the guidance provided by letter dated April 1, 2002, “Staff Guidance on Scoping of Equipment 

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

Renewal (10 CFR 54.4(a)(3))” (Agencywide Documents Access and Management System 

Accession No. ML020920464), states: 

For purposes of the license renewal rule, the staff has determined that the plant 

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

offsite power source should be included within the scope of the rule. This path 

typically includes switchyard circuit breakers that connect to the offsite system 

power transformers (startup transformers), the transformers themselves, the 

intervening overhead or underground circuits between circuit breaker and 

transformer and transformer and onsite electrical system, and the associated 

control circuits and structures. Ensuring that the appropriate offsite power 

system long-lived passive SSCs that are part of this circuit path are subject to an 

AMR will assure that the bases underlying the SBO requirements are maintained 

over the period of extended license. 

The applicant included the complete circuits between the onsite circuits and up to and including 

switchyard breakers (which includes the associated controls and structures) supplying the 

auxiliary transformer SS 65 and the auxiliary transformer SS 64 within the scope of license 

renewal. Both auxiliary transformers supply 4160-V and 480-V buses. The first source of offsite 

power is fed from the DTE electric/energy transmission and distribution system and received 

through three 345-kV circuit breakers (BM, CF, and DF), which supply the auxiliary 

transformer SS 65. These circuit breakers are the scoping boundary for the first source of 

offsite power. The second source of offsite power is fed from the DTE electric/energy 

transmission and distribution system and received through one 120 kV circuit breakers (A), 

which supply the auxiliary transformer SS 64. This circuit breaker is the scoping boundary for 

the second source of offsite power. Based on its review of the applicant’s scoping analysis, the 
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staff concludes that the scoping is consistent with the guidance provide by letter dated 

April 1, 2002, and later incorporated into SRP-LR Section 2.5.2.1.1. 

The staff’s review identified an area in which additional information was necessary to complete 

the review of the applicant’s scoping and screening results. By letter dated December 19, 2014, 

the staff issued RAI 2.5-1 requesting that the applicant verify whether the CTG 11-1 unit system 

electrical components are within the scope of the license renewal in accordance with 

10 CFR 54.4(a)(3) and are subject to an AMR in accordance with 10 CFR 54.21(a)(1). In 

RAI 2.5-1, the staff also requested that the applicant provide a justification for exclusion if the 

CTG system electrical components are not within the scope of the license renewal. In its 

response to RAI 2.5-1, dated January 20, 2015, the applicant stated that the CTG 11-1 unit 

system electrical components are within the scope of license renewal in accordance with 

10 CFR 54.4(a)(3) and are subject to an AMR in accordance with 10 CFR 54.21(a)(1). The 

applicant also stated that the following passive commodities associated with SBO are subject to 

an AMR and are included in LRA Table 2.5-1: 

 control circuit cables and connections (under the type “cable connections”) 

 high-voltage insulators 

 medium-voltage cables and connections (under the type “cable connections”) 

 metal enclosed bus 

 switchyard bus and connections 

In its response to RAI 2.5-1, the applicant revised LRA Table 2.5-1 to clarify that the 

high-voltage insulators and switchyard bus and connections are included for SBO and for SBO 

recovery, and it provided the associated LRA markup. 

The staff finds the applicant’s response to RAI 2.5-1 acceptable because (1) the applicant 

clarified that the CTG 11-1 unit system electrical components, which provide alternate AC power 

during SBO, are within the scope of license renewal in accordance with 10 CFR 54.4(a)(3) and 

are subject to an AMR in accordance with 10 CFR 54.21(a)(1) and (2) the applicant made 

changes to LRA Table 2.5-1 to clarify that high-voltage insulators and switchyard bus and 

connections are included for SBO and for SBO recovery. The staff’s concern described in 

RAI 2.5-1 is resolved. 

2.5.1.3 Conclusion 

Based on its evaluation, the staff concludes that the applicant has appropriately identified the 

electrical and I&C system components within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also concludes that the applicant has adequately identified the 

electrical and I&C system components subject to an AMR, as required by 10 CFR 54.21(a)(1). 

2.6 Conclusion for Scoping and Screening 

The staff reviewed the information in LRA Section 2, “Scoping and Screening Methodology for 

Identifying Structures and Components Subject to Aging Management Review and 

Implementation Results.” The staff determines that the applicant’s scoping and screening 

methodology was consistent with 10 CFR 54.21(a)(1) and the staff’s positions on the treatment 

of safety-related and nonsafety-related SSCs within the scope of license renewal. The 

applicant’s methodology on SCs subject to an AMR is consistent with the requirements of 

10 CFR 54.4 and 10 CFR 54.21(a)(1). 
2-111 

On the basis of its review, the staff concludes that the applicant has adequately identified those 

systems and components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and those subject to an AMR, as required by 10 CFR 54.21(a)(1). 

The staff concludes that there is reasonable assurance that the applicant will continue to 

conduct the activities authorized by the renewed licenses in accordance with the CLB and any 

changes to the CLB made in order to comply with 10 CFR 54.21(a)(1), in accordance with the 

Atomic Energy Act of 1954, as amended, and in accordance with NRC regulations. 

3-1 

 

AGING MANAGEMENT REVIEW RESULTS 

This section of the safety evaluation report (SER) evaluates aging management programs 

(AMPs) and aging management reviews (AMRs) for Fermi 2 Nuclear Power Plant (Fermi 2) by 

the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff). 

In Appendix B to its license renewal application (LRA), DTE Electric Company (DTE or the 

applicant) described the 45 AMPs that it relies on to manage or monitor the aging of passive, 

long-lived structures and components (SCs). 

In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA 

Section 2 as within the scope of license renewal and subject to an AMR. 

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report 

In preparing its LRA, the applicant credited NUREG-1801, Revision 2, “Generic Aging Lessons 

Learned (GALL) Report,” dated December 2010. The GALL Report contains the staff’s generic 

evaluation of the existing plant programs and documents the technical basis for determining 

where existing programs are adequate without modification and where existing programs should 

be augmented for the period of extended operation. The evaluation results documented in the 

GALL Report indicate that many of the existing programs are adequate to manage the aging 

effects for particular license renewal SCs. The GALL Report also contains recommendations on 

specific areas for which existing programs should be augmented for license renewal. An 

applicant may reference the GALL Report in its LRA to demonstrate that its programs 

correspond to those reviewed and approved in the report. 

The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or 

monitor the aging of SCs subject to an AMR. If an applicant commits to implementing these 

staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, 

thereby improving the efficiency and effectiveness of the license renewal review process. The 

GALL Report also serves as a quick reference for applicants and staff reviewers to AMPs and 

activities that the staff has determined will adequately manage or monitor aging during the 

period of extended operation. 

The GALL Report identifies the following: 

 structures, systems, and components (SSCs) 

 SC materials 

 environments to which the SCs are exposed 

 aging effects of the materials and environments 

 AMPs credited with managing or monitoring the aging effects 

 recommendations for further applicant evaluations of aging management for certain 

component types 

The staff performed its review in accordance with Title 10 of the Code of Federal Regulations

Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants” 

(10 CFR Part 54); the guidance provided in NUREG-1800, Revision 2, “Standard Review Plan 
3-2 

for Review of License Renewal Applications for Nuclear Power Plants” (SRP-LR), dated 

December 2010; and the guidance provided in the GALL Report. 

In addition to its review of the LRA, the staff conducted an onsite audit of selected AMPs during 

the weeks of September 15 and September 29, 2014, as described in the Audit Report entitled, 

“Aging Management Programs Audit Report Regarding the Fermi 2 Nuclear Power Plant,” dated 

February 11, 2015. The onsite audits and reviews are designed to maximize the efficiency of 

the staff’s LRA review. The applicant can respond to questions; the staff can readily evaluate 

the applicant’s responses; and the need for formal correspondence between the staff and the 

applicant is reduced, resulting in a more efficient review. 

3.0.1 Format of the License Renewal Application 

The applicant submitted an application that follows the standard LRA format agreed upon by the 

staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003. 

The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presents 

the results of AMR information in the following two table types: 

(1) Table 1s: Table 3.x.1, where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, and “1” indicates that this table type is the 

first in LRA Section 3. 

(2) Table 2s: Table 3.x.2-y, where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, “2” indicates that this table type is the second 

in LRA Section 3, and “y” indicates the system table number. 

In its Table 1s, the applicant summarized the portions of the application that it considered to be 

consistent with the GALL Report. In its Table 2s, the applicant identified the linkage between 

the scoping and screening results in LRA Section 2 and the AMRs in LRA Section 3. 

3.0.1.1 Overview of Table 1s 

Each Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with the 

corresponding tables in the SRP-LR. The table is essentially the same as Tables 1 through 6 in 

the SRP-LR, except that the “Type” column has been replaced by an “Item Number” column and 

the “Item Number in GALL” column has been replaced by a “Discussion” column. The “Item 

Number” column is a means for the staff reviewer to cross-reference Table 2s with Table 1s. In 

the “Discussion” column, the applicant provided clarifying information. The following are 

examples of information that might be contained within this column: 

 further evaluation recommended (information or reference to where that information is 

located) 

 name of a plant-specific program 

 exceptions to the GALL Report assumptions 

 discussion of how the line is consistent with the corresponding AMR item in the GALL 

Report when the consistency may not be obvious 

 discussion of how the item is different from the corresponding AMR item in the GALL 

Report (e.g., when an exception is taken to a GALL Report AMP) 

The format of each Table 1 allows the staff to align a specific row in the table with the 

corresponding SRP-LR table row so that the consistency can be checked easily. 
3-3 

3.0.1.2 Overview of Table 2s 

Each Table 3.x.2-y (Table 2) provides the detailed AMR results for those components identified 

in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or 

components within a system grouping (e.g., reactor coolant systems (RCSs), engineered safety 

features (ESFs), and auxiliary systems). For example, the ESF group contains tables specific to 

the containment spray system, containment isolation system, and emergency core cooling 

system. Each Table 2 consists of the following nine columns: 

(1) Component Type: The first column lists LRA Section 2 component types subject to an 

AMR in alphabetical order. 

(2) Intended Function: The second column identifies the license renewal intended 

functions, including abbreviations, where applicable, for the listed component types. 

Definitions and abbreviations of intended functions are in LRA Table 2.0-1. 

(3) Material: The third column lists the particular construction material(s) for the component 

type. 

(4) Environment: The fourth column lists the environments to which the component types 

are exposed. Internal and external service environments are indicated with a list of 

these environments in LRA Tables 3.0-1, 3.0-2, and 3.0-3. 

(5) Aging Effect Requiring Management (AERM): The fifth column lists AERMs. As part of 

the AMR process, the applicant determined any AERMs for each combination of material 

and environment. 

(6) AMPs: The sixth column lists the AMPs that the applicant uses to manage the identified 

aging effects. 

(7) The GALL Report Item: The seventh column lists the GALL Report item(s) identified in 

the LRA as similar to the AMR results. The applicant compared each combination of 

component type, material, environment, AERM, and AMP in LRA Table 2 with the GALL 

Report items. If there were no corresponding items in the GALL Report, the applicant 

left the column blank to identify the AMR results in the LRA tables corresponding to the 

items in the GALL Report tables. 

(8) Table 1 Item: The eighth column lists the corresponding summary item number from 

LRA Table 1. If the applicant’s LRA Table 2 AMR result item is consistent with the GALL 

Report, the Table 1 AMR item summary number should be listed in LRA Table 2. If 

there is no corresponding item in the GALL Report, column eight is left blank. In this 

manner, the information from the two tables can be correlated. 

(9) Notes: The ninth column lists the corresponding notes used to identify how the 

information in each Table 2 aligns with the information in the GALL Report. The notes, 

identified by letters, were developed by an NEI working group and are used in this LRA. 

Any plant-specific notes identified by numbers provide additional information about the 

consistency of the AMR item with the GALL Report. 

3.0.2 Staff’s Review Process 

The staff conducted the following three types of evaluations of the AMRs and AMPs: 

(1) For items that the applicant stated are consistent with the GALL Report, the staff 

conducted either an audit or a technical review to determine consistency. 
3-4 

(2) For items that the applicant stated were consistent with the GALL Report with 

exceptions, enhancements, or both, the staff conducted either an audit or a technical 

review of the item to determine consistency. In addition, the staff conducted either an 

audit or a technical review of the applicant’s technical justifications for the exceptions or 

the adequacy of the enhancements. 

The SRP-LR states that an applicant may take one or more exceptions to specific GALL 

Report AMP elements; however, any exception to the GALL Report AMP should be 

described and justified. Therefore, the staff considers exceptions as being portions of 

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

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

all the program elements defined in the GALL Report AMP. However, the applicant may 

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

before the period of extended operation. Therefore, the staff considers these 

augmentations or additions to be enhancements. Enhancements include, but are not 

limited to, activities needed to ensure consistency with the GALL Report 

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

(3) For other items, the staff conducted a technical review to verify conformance with 

10 CFR 54.21(a)(3) requirements. 

These audits and technical reviews of the applicant’s AMPs and AMRs determine whether the 

effects of aging on SCs can be adequately managed to maintain the intended functions 

consistent with the plant’s current licensing basis (CLB) for the period of extended operation, as 

required by 10 CFR Part 54. 

3.0.2.1 Review of AMPs 

For those AMPs for which the applicant had claimed consistency with the GALL Report AMPs, 

the staff conducted either an audit or a technical review to confirm that the applicant’s AMPs 

were consistent with the GALL Report. For each AMP that had one or more deviations, the staff 

evaluated each deviation to determine whether the deviation was acceptable and whether the 

AMP, as modified, would adequately manage the aging effect(s) for which it was credited. For 

AMPs that were not addressed in the GALL Report, the staff performed a full review to 

determine their adequacy. The staff evaluated the AMPs against the following 10 program 

elements defined in SRP-LR Appendix A: 

(1) “scope of program”—should include the specific SCs subject to a license renewal AMR. 

(2) “preventive actions”—should prevent or mitigate aging degradation. 

(3) “parameters monitored or inspected”—should be linked to the degradation of the 

particular structure or component intended function(s). 

(4) “detection of aging effects”—should occur before there is a loss of structure or 

component intended function(s). This includes aspects, such as method or technique 

(i.e., visual, volumetric, surface inspection), frequency, sample size, data collection, and 

timing of new and one-time inspections to ensure timely detection of aging effects. 

(5) “monitoring and trending”—should provide predictability of the extent of degradation, as 

well as timely corrective or mitigative actions. 
3-5 

(6) “acceptance criteria”—these criteria, against which the need for corrective actions will be 

evaluated, should ensure that the structure or component-intended function(s) are 

maintained under all CLB design conditions during the period of extended operation. 

(7) “corrective actions”—these actions, including root cause determination and prevention of 

recurrence, should be timely. 

(8) “confirmation process”—should ensure that preventive actions are adequate and that 

appropriate corrective actions have been completed and are effective. 

(9) “administrative controls”—should provide for a formal review and approval process. 

(10) “operating experience”—this experience of the AMP, including past corrective actions 

resulting in program enhancements or additional programs, should provide objective 

evidence to support the conclusion that the effects of aging will be adequately managed 

so that the SC intended function(s) will be maintained during the period of extended 

operation. 

Details of the staff’s audit evaluation of program elements 1 through 6 and 10 are documented 

in the AMP Audit Report and summarized in SER Section 3.0.3. 

The staff reviewed the applicant’s quality assurance (QA) program and documented its 

evaluations in SER Section 3.0.4. The staff’s evaluation of the QA program included an 

assessment of the “corrective actions,” “confirmation process,” and “administrative controls” 

program elements. 

The staff reviewed the information on the “operating experience” program element and 

documented its evaluation in SER Sections 3.0.3 and 3.0.5. 

3.0.2.2 Review of AMR Results 

Each LRA Table 2 contains information concerning whether the AMRs identified by the 

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed 

the intended function, material, environment, AERM, and AMP combination for a particular 

system component type. Item numbers in column seven of the LRA, “NUREG-1801 Item,” 

correlate to an AMR combination as identified in the GALL Report. A blank in column seven 

indicates that the applicant was unable to identify an appropriate correlation in the GALL Report. 

The staff also conducted a technical review of combinations not consistent with the GALL 

Report. The next column, “Table 1 Item,” refers to a number indicating the correlating row in 

Table 1. 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which it does not recommend further evaluation, the staff determined, on 

the basis of its review, whether the plant-specific components of these GALL Report component 

groups were bounded by the GALL Report evaluation. 

The applicant noted for each AMR item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with notes A through E 

indicating how the AMR is consistent with the GALL Report. 

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 
3-6 

The staff audited these items to verify consistency with the GALL Report and to confirm the 

validity of the AMR for the site-specific conditions. 

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff audited these items to verify consistency with the GALL Report and confirmed 

that the identified exceptions to the GALL Report AMPs have been reviewed and accepted. 

The staff also determined whether the applicant’s AMP was consistent with the GALL Report 

AMP and whether the AMR was valid for the site-specific conditions. 

Note C indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with that in the GALL Report for material, environment, and aging effect. 

In addition, the AMP is consistent with the GALL Report AMP. This note indicates that the 

applicant was unable to find a listing of some system components in the GALL Report; however, 

the applicant identified in the GALL Report a different component with the same material, 

environment, aging effect, and AMP as the component under review. The staff audited these 

items to verify consistency with the GALL Report. The staff also determined whether the AMR 

item of the different component was applicable to the component under review and whether the 

AMR was valid for the site-specific conditions. 

Note D indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with that in the GALL Report for material, environment, and aging effect. 

In addition, the AMP takes some exceptions to the GALL Report AMP. The staff audited these 

items to verify consistency with the GALL Report. The staff verified whether the AMR item of 

the different component was applicable to the component under review and whether the 

identified exceptions to the GALL Report AMPs have been reviewed and accepted. The staff 

also determined whether the applicant’s AMP was consistent with the GALL Report AMP and 

whether the AMR was valid for the site-specific conditions. 

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect but credits a different AMP. The staff audited these items to 

verify consistency with the GALL Report. The staff also determined whether the credited AMP 

would manage the aging effect consistently with the GALL Report AMP and whether the AMR 

was valid for the site-specific conditions. 

3.0.2.3 UFSAR Supplement 

Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed 

the updated final safety analysis report (UFSAR) supplement, which summarizes the applicant’s 

programs and activities for managing aging effects for the period of extended operation, as 

required by 10 CFR 54.21(d). 

3.0.2.4 Documentation and Documents Reviewed 

In performing its review, the staff used the LRA, LRA supplements, the SRP-LR, the GALL 

Report, and requests for additional information (RAI) responses. 

During the onsite audit, the staff examined the applicant’s justifications, as documented in the 

audit summary report, to verify that the applicant’s activities and programs will adequately 

manage the effects of aging on SCs. The staff also conducted detailed discussions and 
3-7 

interviews with the applicant’s license renewal project personnel and others with technical 

expertise relevant to aging management. 

3.0.3 Aging Management Programs 

SER Table 3.0-1 below presents the AMPs credited by the applicant and described in LRA 

Appendix B, “Aging Management Programs and Activities.” The table also indicates (a) whether 

the AMP is an existing or new program, (b) the GALL Report AMP with which the applicant 

claimed consistency, (c) the SER section that documents the staff’s evaluation of the program, 

and (d) the staff’s final disposition of the AMP. 

Table 3.0-1 Fermi 2 Aging Management Programs 

Applicant 

AMP 

LRA 

Sections 

New or 

Existing 

Program 

LRA Initial

Comparison to the 

GALL Report 

GALL Report AMPs SER Section 

(Disposition) 

Aboveground 

Metallic Tanks 

A.1.1 

B.1.1 

New Consistent XI.M29, “Aboveground Metallic 

Tanks” 

3.0.3.1.1 

(Consistent) 

Bolting 

Integrity 

A.1.2 

B.1.2 

Existing Consistent with 

Enhancements and 

Exception 

XI.M18, “Bolting Integrity” 3.0.3.2.1 

(Consistent 

with 

Enhancements 

and 

Exceptions) 

Boraflex 

Monitoring 

A.1.3 

B.1.3 

Existing Consistent with 

Enhancement 

XI.M22, “Boraflex Monitoring” 3.0.3.2.2 

(Deleted) 

Buried and 

Underground 

Piping 

A.1.4 

B.1.4 

New Consistent with 

Exception (exception 

added after initial 

LRA) 

XI.M41, “Buried and 

Underground Piping and 

Tanks”, as modified by 

LR-ISG-2015-01 

3.0.3.1.2 

(Consistent 

with Exception)

BWR CRD 

Return Line 

Nozzle 

A.1.5 

B.1.5 

Existing Consistent XI.M6, “BWR Control Rod 

Drive Return Line Nozzle” 

3.0.3.1.3 

(Consistent 

with an 

Enhancement) 

BWR 

Feedwater 

Nozzle 

A.1.6 

B.1.6 

Existing Consistent XI.M5, “BWR Feedwater 

Nozzle” 

3.0.3.1.4 

(Consistent 

with an 

Exception) 

BWR 

Penetrations 

A.1.7 

B.1.7 

Existing Consistent XI.M8, “BWR Penetrations” 3.0.3.1.5 

(Consistent) 

BWR Stress 

Corrosion 

Cracking 

A.1.8 

B.1.8 

Existing Consistent XI.M7, “BWR Stress Corrosion 

Cracking” 

3.0.3.1.6 

(Consistent 

with an 

Exception) 

BWR Vessel 

ID Attachment 

Welds 

A.1.9 

B.1.9 

Existing Consistent XI.M4, “BWR Vessel ID 

Attachment Welds” 

3.0.3.1.7 

(Consistent) 

BWR Vessel 

Internals 

A.1.10 

B.1.10 

Existing Consistent with 

Enhancements 

XI.M9, “BWR Vessels 

Internals” 

3.0.3.2.3 

(Consistent 

with 

Enhancements)
3-8 

Applicant 

AMP 

LRA 

Sections 

New or 

Existing 

Program 

LRA Initial

Comparison to the 

GALL Report 

GALL Report AMPs SER Section 

(Disposition) 

Compressed 

Air Monitoring 

A.1.11 

B.1.11 

Existing Consistent with 

Enhancements and 

Exception 

XI.M24, “Compressed Air 

Monitoring” 

3.0.3.2.4 

(Consistent 

with 

Enhancements 

and an 

Exception) 

Containment 

Inservice 

Inspection – 

IWE 

A.1.12 

B.1.12 

Existing Consistent with 

Enhancements 

XI.S1, “ASME Section XI, 

Subsection IWE” 

3.0.3.2.5 

(Consistent 

with 

Enhancements)

Containment 

Leak Rate 

A.1.13 

B.1.13 

Existing Consistent XI.S4, “10 CFR Part 50, 

Appendix J” 

3.0.3.1.8 

(Consistent) 

Diesel Fuel 

Monitoring 

A.1.14 

B.1.14 

Existing Consistent with 

Enhancements 

XI.M30, “Fuel Oil Chemistry” 3.0.3.2.6 

(Consistent 

with 

Enhancements)

Environmental 

Qualification 

(EQ) of Electric 

Components 

A.1.15 

B.1.15 

Existing Consistent X.E1, “Environmental 

Qualification (EQ) of Electric 

Components” 

3.0.3.1.9 

(Consistent) 

External 

Surfaces 

Monitoring 

A.1.16 

B.1.16 

Existing Consistent with 

Enhancements 

XI.M36, “External Surfaces 

Monitoring of Mechanical 

Components” 

3.0.3.2.7 

(Consistent 

with 

Enhancements)

Fatigue 

Monitoring 

A.1.17 

B.1.17 

Existing Consistent with 

Enhancements and 

Exception 

X.M1, “Fatigue Monitoring” 3.0.3.2.8 

(Consistent 

with 

Enhancements 

and an 

Exception) 

Fire Protection A.1.18 

B.1.18 

Existing Consistent with 

Enhancements 

XI.M26, “Fire Protection” 3.0.3.2.9 

(Consistent 

with 

Enhancements) 

Fire Water 

System 

A.1.19 

B.1.19 

Existing Consistent with 

Enhancements 

XI.M27, “Fire Water System” 3.0.3.2.10 

(Consistent 

with 

Enhancements 

and 

Exceptions) 

FlowAccelerated 

Corrosion 

A.1.20 

B.1.20 

Existing Consistent with 

Enhancements 

XI.M17, “Flow-Accelerated 

Corrosion” 

3.0.3.2.11 

(Consistent 

with 

Enhancements)

Inservice 

Inspection 

A.1.21 

B.1.21 

Existing Consistent XI.M1, “ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC, and 

IWD” 

3.0.3.1.10 

(Consistent) 

Inservice 

Inspection – 

IWF 

A.1.22 

B.1.22 

Existing Consistent with 

Enhancements 

XI.S3, “ASME Section XI, 

Subsection IWF” 

3.0.3.2.12 

(Consistent 

with 

Enhancements)
3-9 

Applicant 

AMP 

LRA 

Sections 

New or 

Existing 

Program 

LRA Initial

Comparison to the 

GALL Report 

GALL Report AMPs SER Section 

(Disposition) 

Inspection of 

Overhead 

Heavy Load 

and Light Load 

(Related to 

Refueling) 

Handling 

Systems 

A.1.23 

B.1.23 

Existing Consistent with 

Enhancements 

XI.M23, “Inspection of 

Overhead Heavy Load and 

Light Load (Related to 

Refueling) Handling Systems” 

3.0.3.2.13 

(Consistent 

with 

Enhancements)

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

A.1.24 

B.1.24 

New Consistent XI.M38, “Inspection of Internal 

Surfaces in Miscellaneous 

Piping and Ducting 

Components” 

3.0.3.1.11 

(Consistent) 

Masonry Wall A.1.25 

B.1.25 

Existing Consistent with 

Enhancements 

XI.S5, “Masonry Walls” 3.0.3.2.14 

(Consistent 

with 

Enhancements)

Metal Enclosed 

Bus Inspection 

A.1.26 

B.1.26 

New Consistent XI.E4, “Metal Enclosed Bus” 3.0.3.1.12 

(Consistent) 

NeutronAbsorbing 

Material 

Monitoring 

A.1.27 

B.1.27 

Existing Consistent with 

Enhancements 

XI.M40, “Monitoring of 

Neutron-Absorbing Materials 

Other than Boraflex” 

3.0.3.2.15 

(Consistent 

with 

Enhancements)

Non-EQ Cable 

Connections 

A.1.28 

B.1.28 

New Consistent XI.E6, “Electrical Cable 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements” 

3.0.3.1.13 

(Consistent) 

Non-EQ 

Inaccessible 

Power Cable 

(400 V to 

13.8 kV) 

A.1.29 

B.1.29 

New Consistent XI.E3, “Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements” 

3.0.3.1.14 

(Consistent) 

Non-EQ 

Instrumentation Circuits 

Test Review 

A.1.30 

B.1.30 

New Consistent XI.E2, “Insulation Material for 

Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements 

Used in Instrumentation 

Circuits” 

3.0.3.1.15 

(Consistent) 

Non-EQ 

Insulated 

Cables and 

Connections 

A.1.31 

B.1.31 

New Consistent XI.E1, “Insulation Material for 

Electrical Cables and 

Connections Not Subject to 

10 CFR 50.49 Environmental 

Qualification Requirements” 

3.0.3.1.16 

(Consistent) 

Oil Analysis A.1.32 

B.1.32 

Existing Consistent with 

Enhancements 

XI.M39, “Lubricating Oil 

Analysis” 

3.0.3.2.16 

(Consistent 

with 

Enhancements)

One-Time 

Inspection 

A.1.33 

B.1.33 

New Consistent XI.M32, “One-Time Inspection” 3.0.3.1.17 

(Consistent) 

One-Time 

Inspection – 

Small-Bore 

Piping 

A.1.34 

B.1.34 

New Consistent XI.M35, “One-Time Inspection 

of ASME Code Class 1 

Small-Bore Piping” 

3.0.3.1.18 

(Consistent) 
3-10 

Applicant 

AMP 

LRA 

Sections 

New or 

Existing 

Program 

LRA Initial

Comparison to the 

GALL Report 

GALL Report AMPs SER Section 

(Disposition) 

Periodic 

Surveillance 

and Preventive 

Maintenance 

A.1.35 

B.1.35 

Existing Plant Specific with 

Enhancements 

N/A 3.0.3.3.1 

(Plant Specific 

with 

Enhancements)

Protective 

Coating 

Monitoring and 

Maintenance 

A.1.36 

B.1.36 

Existing Consistent with 

Enhancements 

XI.S8, “Protective Coating 

Monitoring and Maintenance” 

3.0.3.2.17 

(Consistent 

with 

Enhancements)

Reactor Head 

Closure Studs 

A.1.37 

B.1.37 

Existing Consistent with 

Enhancements and 

Exceptions 

XI.M3, “Reactor Head Closure 

Stud Bolting” 

3.0.3.2.18 

(Consistent 

with 

Enhancements 

and 

Exceptions) 

Reactor Vessel 

Surveillance 

A.1.38 

B.1.38 

Existing Consistent with 

Enhancement and 

Exception 

XI.M31, “Reactor Vessel 

Surveillance” 

3.0.3.2.19 

(Consistent) 

RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated 

with Nuclear 

Power Plants 

A.1.39 

B.1.39 

Existing Consistent with 

Enhancements 

XI.S7, “RG 1.127, Inspection of 

Water-Control Structures 

Associated with Nuclear Power 

Plants” 

3.0.3.2.20 

(Consistent 

with 

Enhancements)

Selective 

Leaching 

A.1.40 

B.1.40 

New Consistent XI.M33, “Selective Leaching” 3.0.3.1.19 

(Consistent) 

Service Water 

Integrity 

A.1.41 

B.1.41 

Existing Consistent with 

Enhancements 

XI.M20, “Open-Cycle Cooling 

Water System” 

3.0.3.2.21 

(Consistent 

with 

Enhancements)

Structures 

Monitoring 

A.1.42 

B.1.42 

Existing Consistent with 

Enhancements 

XI.S6, “Structures Monitoring” 3.0.3.2.22 

(Consistent 

with 

Enhancements)

Water 

Chemistry 

Control – BWR 

A.1.43 

B.1.43 

Existing Consistent XI.M2, “Water Chemistry” 3.0.3.1.20 

(Consistent 

with an 

Exception) 

Water 

Chemistry 

Control – 

Closed Treated 

Water Systems 

A.1.44 

B.1.44 

Existing Consistent with 

Enhancements 

XI.M21A, “Closed Treated 

Water Systems” 

3.0.3.2.23 

(Consistent 

with 

Enhancements 

and an 

Exception) 

Coating 

Integrity 

A.1.45 

B.1.45 

New Consistent with 

Exceptions 

XI.M42, “Internal 

Coatings/Linings for In-Scope 

Piping, Piping Components, 

Heat Exchangers, and Tanks” 

3.0.3.2.24 

(Consistent 

with 

Exceptions) 
3-11 

3.0.3.1 AMPs Consistent with the GALL Report 

In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL 

Report: 

 Aboveground Metallic Tanks 

 Buried and Underground Piping 

 BWR Control Rod Drive Return Line Nozzle 

 BWR Feedwater Nozzle 

 BWR Penetrations 

 BWR Stress Corrosion Cracking 

 BWR Vessel ID Attachment Welds 

 Containment Leak Rate 

 Environmental Qualification (EQ) of Electric Components 

 Inservice Inspection 

 Internal Surfaces in Miscellaneous Piping and Ducting Components 

 Metal Enclosed Bus Inspections 

 Non-EQ Cable Connections 

 Non-EQ Inaccessible Power Cable (400 V to 13.8 kV) 

 Non-EQ Instrumentation Circuits Test Review 

 Non-EQ Insulated Cables and Connections 

 One-Time Inspection 

 One-Time Inspection – Small-Bore Piping 

 Selective Leaching 

 Water Chemistry Control – BWR 

 Aboveground Metallic Tanks 

Summary of Technical Information in the Application. LRA Section B.1.1, as amended by letter 

dated April 10, 2015, describes the new Aboveground Metallic Tanks Program as consistent 

with GALL Report AMP XI.M29, “Aboveground Metallic Tanks,” as modified by License Renewal 

Interim Staff Guidance (LR-ISG)-2012-02, “Aging Management of Internal Surfaces, Fire Water 

Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” The LRA states that 

the AMP addresses carbon steel and aluminum outdoor tanks constructed on soil or concrete to 

manage the aging effects of loss of material and cracking. The LRA also states that the AMP 

proposes to manage these aging effects through periodic visual; surface; and volumetric 

inspections of interior and exterior surfaces, including the tank tops, bottoms, and under 

insulation. The LRA further states that the tank inspections will be conducted in accordance 

with LR-ISG-2012-02 Table 4a, “Tank Inspection Recommendations,” and applicable Table 4a 

notes. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M29. 

For the “preventive actions” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below. 

The “preventive actions” program element in GALL Report AMP XI.M29, as revised by 

LR-ISG-2012-02, recommends that sealant or caulking be applied to outdoor tanks at the 
3-12 

external interface between the tank and concrete foundation unless the plant-specific 

configuration precludes the accumulation of water in this area. However, during its audit, the 

staff found that the applicant’s Aboveground Metallic Tanks Program states that, “[i]n 

accordance with installation and design specifications, the tanks do not employ caulking or 

sealant at the concrete/tank interface.” The staff also noted that the top surface of the concrete 

ring is not sloped to prevent water and moisture intrusion at the outside interface of the ring 

foundation. By letter dated December 17, 2014, the staff issued RAI B.1.1-1 requesting that the 

applicant state how the aging effects of loss of material and cracking of the aluminum in the 

proximity of the interface between the tank and concrete foundation will be managed for the 

condensate storage tank (CST) during the period of extended operation. 

In its response dated January 20, 2015, the applicant stated that the insulation on the CST is 

expected to prevent the intrusion of water and moisture at the interface between the tank and 

concrete foundation because the insulation prevents access to the interface. LRA 

Sections A.1.1, B.1.1, and Commitment No. 3 were revised to perform a volumetric examination 

consisting of four 1-ft sections of the interface between the tank and concrete foundation before 

Fermi 2 enters the period of extended operation. The RAI response also stated that, although 

caulking was not included in the design and installation specifications for the CST, caulking 

appears to be present at some locations along the tank/concrete interface. 

The staff noted that the response did not provide a basis for why the insulation is expected to 

prevent the access of water and moisture to the tank/concrete interface and prevent loss of 

material from occurring during the period of extended operation. By letter dated 

March 13, 2015, the staff issued RAI B.1.1-1a requesting that the applicant state the basis and 

justification for why the insulation on the CST will prevent water and moisture from having 

access to the tank/concrete interface and why it is an appropriate preventive action to manage 

loss of material. 

In its response dated April 10, 2015, the applicant stated that neither the insulation nor caulking 

is credited as a moisture barrier. The response also stated that external inspections are not 

adequate to manage the aging effect of loss of material at the tank/concrete interface and 

removed the inspections added by letter dated January 20, 2015. LRA Sections A.1.1, B.1.1, 

and Commitment No. 3 were revised to include volumetric inspections in the proximity of the 

tank/concrete interface to manage loss of material. The inspections will be conducted from the 

inside of the tank and performed on a minimum of 25 percent of the interface. The inspection 

frequency is consistent with Table 4a in LR-ISG-2012-02. The inspections will be performed 

using a 2-inch grid or less, depending on the inspection technology used. These inspections 

are in addition to the tank bottom inspections already in Table 4a of LR-ISG-2012-02. 

The response also states that the CST is fabricated from aluminum alloy 5454 and the aging 

effect of cracking due to stress corrosion cracking (SCC) does not need to be managed 

because the alloy is not susceptible to the aging effect. LRA Sections A.1.1 and B.1.1 are 

revised to remove cracking as an aging effect that needs to be managed for the CST. 

The staff finds the applicant’s response acceptable because loss of material at the 

tank/concrete interface is being managed by additional inspections. Direct inspection of the 

material in the proximity of the concrete/tank interface is an acceptable alternative to inspecting 

the caulk at the interface because the additional inspections are capable of detecting a loss of 

material in the area of interest. The staff’s concern described in RAI B.1.1-1a is resolved. 
3-13 

The staff also finds the applicant’s statement that the CST does not need to be managed for 

cracking due to SCC acceptable. The 5xxx series aluminum alloys are not susceptible to SCC 

unless the magnesium content is 3.5 weight percent or greater (1, 2). Aluminum alloy 5454 has 

a maximum magnesium content of 3.0 weight percent (3) and is not susceptible to cracking due 

to SCC. The staff referenced the following three documents to confirm that aluminum alloy 

5454 is not susceptible to cracking due to SCC: 

(1) B.F. Brown, “Stress-Corrosion Cracking in High Strength Steels and in Titanium and 

Aluminum Alloys,” Naval Research Laboratory, 1972 

(2) J.R. Davis, “Corrosion of Aluminum and Aluminum Alloys,” ASM International, 1999 

(3) American Society for Testing and Materials (ASTM) B209, “Standard Specification for 

Aluminum and Aluminum-Alloy Sheet and Plate” 

Based on its audit and review of the applicant’s response to RAIs B.1.1-1 and B.1.1-1a, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M29, as revised by LR-ISG-2012-02. 

Operating Experience. LRA Section B.1.1 summarizes operating experience related to the 

Aboveground Metallic Tanks Program. The LRA describes instances in which pitting and minor 

deficiencies were discovered in the carbon steel combustion turbine generator fuel oil tank 

during inspections conducted in 2000 and 2005. The LRA also describes instances in which 

deficiencies in flashing, insulation, screening, and painted surfaces were identified on the 

aluminum CST. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, which resulted in the issuance of an RAI, as discussed below. 

The staff noted, during review of the past 10 years of plant-specific operating experience, that 

there have been multiple instances of degradation of the insulation and jacketing on the roof of 

the CST, including separations in the sheet metal seams, loss of flashing, and loss of insulation 

due to weather. In 2013, the CST roof insulation was completely removed and prefabricated 

insulation was installed. The as-found condition of the aluminum roof was not documented in 

the work order. The aluminum roof of the CST has been exposed to weather on multiple 

occasions, and it is unclear if there is any degradation under the prefabricated insulation. By 

letter dated December 17, 2014, the staff issued RAI B.1.1-2 requesting an assessment of the 

condition of the CST roof under the prefabricated insulation. Additionally, RAI B.1.1-2 

requested that the applicant state the basis for why the proposed bare metal inspections of the 

CST roof will be sufficient to provide reasonable assurance that the CST will meet its CLB 

intended functions during the period of extended operation if the condition of the roof under the 

prefabricated insulation is unknown or degraded. 
3-14 

In its response dated January 20, 2015, the applicant stated that the roof of the CST was 

visually examined before installing the prefabricated insulation in 2013 and that no abnormalities 

were identified, although the examination was not documented. 

The staff finds the applicant’s response acceptable because visual examinations found that the 

condition of the roof was not degraded after being exposed to weather and because the CST 

will be inspected in accordance Table 4a in LR-ISG-2012-02. 

Based on its audit, review of the application, and review of the applicant’s response to 

RAI B.1.1-2, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M29 was 

evaluated. 

UFSAR Supplement. As amended by letter dated April 10, 2015, LRA Section A.1.1 provides 

the UFSAR supplement for the Aboveground Metallic Tanks AMP. The staff reviewed this 

UFSAR supplement description of the program against the recommended description for this 

type of program as described in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02, and 

noted that it contains a commitment (Commitment No. 3) to implement the program “[p]rior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025.” The 

implementation schedule for the program is not consistent with LR-ISG-2012-02 Table 3.0-1, 

“FSAR Supplement for Aging Management of Applicable Systems,” which recommends that 

inspections commence in the 10-year period before the period of extended operation. The CLB 

for this program for the period of extended operation may not be adequate if the applicant does 

not incorporate this information in its UFSAR supplement. By letter dated December 17, 2014, 

the staff issued RAI B.1.1-3 requesting that the applicant state the basis for why the 

implementation schedule for the Aboveground Metallic Tanks Program does not state that 

inspections will commence in the 10-year period before the period of extended operation. 

In its response dated January 20, 2015, the applicant revised Commitment No. 3 in LRA 

Section A.4 to initiate inspections within the 10 years before the period of extended operation. 

The staff finds the applicant’s response acceptable because the implementation schedule is 

consistent with SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. Therefore, the UFSAR 

supplement for the Aboveground Metallic Tanks Program is consistent with the corresponding 

program description in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. The staff’s 

concern described in RAI B.1.1-3 is resolved. 

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

April 10, 2015, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Aboveground Metallic Tanks 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 
3-15 

 Buried and Underground Piping 

Summary of Technical Information in the Application. On February 4, 2016, the staff issued 

LR-ISG-2015-01, “Changes to Buried and Underground Piping and Tank Recommendations.” 

By letter dated April 12, 2016, the applicant revised its Buried and Underground Piping Program 

to address the changes in LR-ISG-2015-01. As modified by letter dated April 12, 2016, LRA 

Section B.1.4 describes the new Buried and Underground Piping Program as consistent with 

GALL Report AMP XI.M41, “Buried and Underground Piping and Tanks,” as modified by 

LR-ISG-2015-01 with one exception. The LRA states that the AMP addresses aluminum, 

carbon steel, gray cast iron, and stainless steel piping exposed to buried and underground 

environments to manage the effects of loss of material and cracking. The LRA also states that 

the AMP proposes to manage these aging effects through periodic excavated direct visual 

inspections and preventive actions, including coatings, backfill quality, and cathodic protection. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03, “Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, 

‘Buried and Underground Piping and Tanks.’” 

For the “detection of aging effects” and “acceptance criteria” program elements, the staff 

determined the need for additional information, which resulted in the issuance of RAIs, as 

discussed below. 

The “detection of aging effects” program element in GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03, recommends that the condition of coatings be evaluated in order to determine 

the number of inspections to be conducted for instances in which the cathodic protection system 

has not met availability or effectiveness goals. During its audit, the staff found that the applicant 

had classified the coatings on two excavated pipes as being in fair condition despite extensive 

holidays that exposed bare metal. Classifying the coatings as being in fair condition makes the 

conduct of fewer inspections than that recommended by the GALL Report possible. By letter 

dated December 17, 2014, the staff issued RAI B.1.4-1 requesting that the applicant state the 

basis for why it classified the condition of the coatings on these pipes as being in fair condition. 

In its response dated January 15, 2015, the applicant stated that the classification of the 

coatings was related to existing inspections conducted under the scope of NEI 09-14, “Guideline 

for the Management of Underground Piping and Tank Integrity.” The classification cited in the 

inspection reports was established based on a comparison of the level of degraded coatings to 

that assumed during the original design of the cathodic protection system. If the observed 

degradation would result in exceeding the design input value of bare metal for the cathodic 

protection system, the coatings would be classified as significantly degraded. The applicant 

also stated that, when the Buried and Underground Piping Program is implemented, the 

inspection category (i.e., Category C, E, or F) will be based on the criteria in LR-ISG-2011-03, 

as it relates to meeting the effectiveness of the cathodic protection system and the results of 

inspections (e.g., pipe wall loss). The staff noted that subsequent to the response to this RAI, 

the applicant revised its Buried and Underground Piping Program to be consistent with 

LR-ISG-2015-01. 

The staff finds the applicant’s response acceptable because when the Buried and Underground 

Piping Program is implemented, the applicant will use the criteria from LR-ISG-2015-01 to 

establish the inspection category, which ensures that an appropriate number of inspections are 
3-16 

conducted to verify the condition of buried piping based on effectiveness of the cathodic 

protection system and existing inspection results. Additionally, the applicant stated that the 

coatings on the two excavated pipes that were classified as being in fair condition were using a 

classification system that differed from that in LR-ISG-2011-03, “Changes to the Generic Aging 

Lessons Learned (GALL) Report Revision 2 Aging Management Program (AMP) XI.M41, 

‘Buried and Underground Piping and Tanks.’” The staff’s concern described in RAI B.1.4-1 is 

resolved. 

The “acceptance criteria” program element in GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03, recommends that, if a 100 millivolt (mV) polarization criterion is used in lieu of 

negative 0.85 volt (V) to assess the performance of the cathodic protection system, the LRA 

should include the basis for why adequate protection is provided for steel components exposed 

to a mixed potential environment. However, during its audit, the staff found that the acceptance 

criteria in the applicant’s cathodic protection plant-specific procedure include negative 0.85 V 

and 100 mV of cathodic polarization. In addition, the procedure includes an acceptance 

criterion of less than 0.85 V in high-resistivity soils that are well drained and well aerated. The 

applicant did not provide the basis for these alternative acceptance criteria. By letter dated 

December 17, 2014, the staff issued RAI B.1.4-2 requesting that the applicant state the basis for 

the alternative acceptance criteria. 

In its response dated January 15, 2015, the applicant stated that, “[i]f the new program, when 

developed, allows for the use of the -100 mV criterion for piping within the scope of the Buried 

and Underground Piping AMP, then the program will address why the effects of mixed potentials 

are minimal and why the most anodic metal in a system for which this criteria is used is 

adequately protected as required by Note 2 of Table 6a of GALL Report AMP XI.M41 as 

modified by LR-ISG-2011-03.” The applicant also stated, in regard to the less than 0.85 V in 

high-resistivity soils that are well drained and well aerated, that when the program is 

implemented, the acceptance criteria will be consistent with Table 6a, “Cathodic Protection 

Acceptance Criteria.” 

The staff finds the applicant’s response acceptable in part because the applicant stated that its 

acceptance criteria will be consistent with Table 6a and will not include the use of criterion less 

negative than 0.85 V. However, the applicant did not provide the basis for using the 100 mV 

cathodic polarization. Table 6a, Footnote 2, states that “applicants must explain in the 

application why the effects of mixed potentials are minimal and why the most anodic metal in 

the system is adequately protected.” Because the applicant did not provide the basis for use of 

the 100 mV polarization criterion, the staff could not complete its evaluation of the “acceptance 

criteria” program element. By letter dated March 11, 2015, the staff issued RAI B.1.4-2a 

requesting that the applicant state the basis for why the effects of mixed potentials will be 

minimal and why the most anodic metal in the system will be adequately protected if this 

criterion is used. 

In its response dated April 10, 2015, the applicant stated that as an alternative to the -850 mV 

polarized potential criterion, it will use either a minimum of 100 mV polarization or empirically 

verified criteria to demonstrate that the cathodic system has been providing effective protection. 

The use of the alternative acceptance criteria is based on the following actions: 

 Uncoated electrical resistance probes (ERP) will be installed in the immediate vicinity of 

buried piping based on locations selected by a National Association of Corrosion 

Engineers (NACE)-qualified Cathodic Protection Specialist. Two probes will be installed: 

one connected to the cathodic protection system, and one installed without protection. 
3-17 

The probes will be constructed of the most anodic metal in the system. Permanent 

reference cells and reference metal will be installed near the piping that is being 

monitored. 

 NACE International Publication 05107, “Report on Corrosion Probes in Soil or Concrete,” 

will be referenced during the application, installation, and use of ERPs. However, the 

specific details will be in accordance with vendor, manufacturer, and NACE-qualified 

Cathodic Protection Specialist recommendations. The specialist will evaluate the effects 

of site features (e.g., exposed large surface area tank bottoms, heavily congested areas 

of other buried piping, and very large diameter pipes). In areas in which these adjacent 

site features could affect the ERP data, cathodic protection effectiveness at the existing 

test point will not be evaluated by use of data from the ERPs. Soil sampling results 

(e.g., moisture content, pH (potential of hydrogen), and resistivity) will be considered for 

placement of ERPs. 

 The corrosion rate of the ERP will be used to determine the effectiveness of the cathodic 

protection system in the areas being monitored. An acceptance criterion of 1 mil 

(0.001 inch) per year (1 mpy) will be established with a comparison of semi-annual 

measurements to the past year of measurements. If the corrosion rate exceeds 1 mpy 

in a given surveillance year, a remaining life calculation will be performed. If the 

measured corrosion rate is such that the component’s remaining life will exceed the life 

of the plant, it will be concluded that the cathodic protection system provided effective 

protection for that surveillance year. If the measured corrosion rate does not 

demonstrate that the component’s intended function will be met throughout the period of 

extended operation, it will be concluded that the cathodic protection system had not 

provided effective protection for that surveillance year and that the measurement will 

count against the effectiveness determination in accordance with LR-ISG-2011-03 

Table 4a, “Inspections of Buried Pipe.” 

 Service life calculations will be based on either the difference between (a) nominal wall 

thickness and minimum wall thickness or (b) measured wall thickness and minimum wall 

thickness. For piping segments without pre-existing minimum wall calculations, critical 

piping characteristics (e.g., piping specifications and design information) will be reviewed 

in order to compare the characteristics to piping that have been analyzed. If the 

calculations or comparison do not demonstrate that the buried in-scope piping will 

remain functional after a loss of 60 mils and after the material loss of 12.5 percent of the 

nominal wall thickness, the allowable corrosion rate will be adjusted. 

 An acceptance criterion of no higher than -1,200 mV pipe-to-soil potential will be 

established to limit potential coating damage. 

As amended by letter dated April 12, 2016, the applicant revised LRA Sections A.1.4 and B.1.4 

to state that “[w]hen using the 100 mV, -750 mV or -650 mV polarization criteria as an 

alternative to the -850 mV criterion, for steel piping, electric resistance probes” will be used. In 

its response dated April 10, 2015, the applicant also stated that (a) ERPs will be installed in 

locations determined by a NACE-qualified Cathodic Protection Specialist, (b) the ERPs will be 

made of the most anodic metal in the system, (c) permanent reference cells and reference 

metal will be installed, (d) the ERPs will be uncoated and placed in the immediate vicinity of the 

buried piping that it is representing, and (e) two probes will be installed in each location with one 

connected to the cathodic protection system and with the other left unprotected. 
3-18 

The staff noted the following: 

 Based on a review of NACE International Publication 05107, ERPs are capable of 

measuring corrosion rates of the probe by correlating increases in electrical resistance to 

a loss of material of the probe. The rate of corrosion of the probe provides a direct 

indication of the effectiveness of the cathodic protection system in the vicinity of the 

probe. 

 NACE International Publication 05107 provides guidance on the installation and use of 

ERPs, including material type, size of probe, soil contact, proximity to the piping that it is 

representing, circuit configurations, corrosion rate calculation formulas, and acceptance 

criteria. Use of the guidance in this publication in conjunction with vendor, manufacturer, 

and NACE-qualified cathodic protection expert recommendations can result in effectively 

determining the corrosion rate of buried components. 

 The 1 mpy acceptance criterion is consistent with NACE International Publication 05107. 

The twofold acceptance criterion (i.e., 1 mpy and remaining life calculation) is sufficient 

to determine that either local cathodic protection is effective or ineffective and, therefore, 

provides reasonable assurance that a buried in-scope component will be capable of 

meeting its intended function. 

 NACE offers four levels of qualification consisting of cathodic protection tester, cathodic 

protection technician, cathodic protection technologist, and cathodic protection specialist 

(NACE Courses CP1 through CP4). The staff noted that the NACE website at 

http://www.naceinstitute.org/Certification/ (accessed March 19, 2015) states that the 

NACE CP4 Cathodic Protection Specialist is “geared toward those persons involved in 

the design, installation, and maintenance of cathodic protection systems.” 

 The upper -1,200 mV is consistent with LR-ISG-2011-03 Table 6a. 

The staff finds the applicant’s proposal to use ERPs to assess the effectiveness of localized 

adequacy of cathodic protection and its response to RAI B.1.4-2 and RAI B.1.4-2a acceptable 

for the following reasons: 

 ERPs are capable of providing localized corrosion rates that can be assessed against an 

acceptance criterion in order to demonstrate the effectiveness of a cathodic protection 

system. 

 Soil corrosion data will be factored into the placement of ERPs to ensure that the probe 

data are not misleading due to potential soil impacts on corrosion rates. 

 The applicant identified appropriate factors to consider for site structural impacts 

(e.g., exposed large surface area tank bottoms, heavily congested areas of other buried 

piping, and very large diameter pipes). 

 An acceptance criterion of 1 mpy is an industry-accepted value, and the applicant will 

verify that the associated piping has sufficient margin to allow this rate of corrosion, or 

the allowed corrosion rate will be adjusted. 

 NACE International Publication 05107 provides appropriate guidance on the installation 

and use of ERPs. 

 Personnel who provide input for the location of ERP and who use soil corrosion probe 

data will be appropriately qualified. 
3-19 

 The use of soil corrosion probes as an alternative to the -850 mV polarization criterion 

for cathodic protection is consistent with the “acceptance criteria” program element of 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01. 

The staff’s concern described in RAI B.1.4-2 and RAI B.1.4-2a is resolved. 

As amended by letter dated April 12, 2016, the applicant stated an exception to the “preventive 

actions” program element of GALL Report AMP XI.M41, as modified by LR-ISG-2015-01. The 

applicant stated that (a) there are two underground stainless steel pipes between the CST vault 

and the turbine building that may not have been coated, (b) the buried portion outside of the 

vault might not be coated, (c) “an inspection will be performed of both of these stainless steel 

pipes that are routed between the CST and the Turbine Building every 10 years, commencing in 

the 10 years prior to the period of extended operation,” (d) “[i]f during the first inspection, the 

stainless steel piping is determined to be coated, then future inspection will be at a rate of one 

inspection per 10-year interval, consistent with Table XI.M41-2,” and (e) the groundwater 

monitoring program provides additional means of monitoring for degradation of piping in this 

area. 

The staff noted that Table XI.M41-1, “Preventive Actions for Buried and Underground Piping 

and Tanks,” recommends that buried stainless steel piping be coated. Table XI.M41-2, 

“Inspection of Buried and Underground Piping and Tanks,” recommends that one inspection be 

conducted in each 10-year period for buried stainless steel piping. The staff finds the exception 

acceptable because the applicant will double the number of visual inspections of the subject 

buried piping in each 10-year interval. The extra inspections and the groundwater monitoring 

could be sufficient to detect any through-wall pitting or crevice corrosion or cracking before a 

loss of intended function. 

Based on its audit; review of the applicant’s responses to RAIs B.1.4-1, B.1.4-2, and 

RAI B.1.4-2a; and the applicant’s changes to its program submitted by letter dated 

April 12, 2016, the staff finds that program elements 1 through 6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M41, as modified by LR-ISG-2015-01. The staff also reviewed the 

exception associated with the “preventive actions” program element, and its justification, and 

finds that the AMP, with the exception, is adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.4 summarizes operating experience related to the 

Buried and Underground Piping Program. The LRA describes instances in which inspections 

and soil sampling were used to determine the condition of buried piping. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 
3-20 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M41, as modified by LR-ISG-2011-03, was evaluated. 

UFSAR Supplement. As amended by letter dated May 9, 2016, LRA Section A.1.4 provides the 

UFSAR supplement for the Buried and Underground Piping Program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1, as modified by LR-ISG-2015-01. 

The staff had noted that the applicant committed (Commitment No. 6) to implement the new 

Buried and Underground Piping Program “[p]rior to September 20, 2024, or the end of the last 

refueling outage prior to March 20, 2025, whichever is later” for managing the effects of aging 

for applicable components. However, GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03, recommends that inspections should commence in the 10-year period before 

the period of extended operation. By letter dated December 17, 2014, the staff issued 

RAI B.1.4-3 requesting that the applicant state the basis for why the implementation schedule 

for the Buried and Underground Piping Program does not state that inspections will commence 

in the 10-year period before the period of extended operation. 

In its response dated January 15, 2015, the applicant revised Commitment No. 6 to state that it 

will conduct initial inspections and soil testing (if testing is used to reduce the number of 

inspections) in the 10-year period before March 20, 2025. 

The staff finds the applicant’s response acceptable because the Buried and Underground Piping 

Program will be implemented in the 10-year period before the period of extended operation, as 

recommended in LR-ISG-2011-03 and LR-ISG-2015-01. The staff’s concern described in 

RAI B.1.4-3 is resolved. 

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

May 9, 2016, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Buried and Underground 

Piping Program, the staff concludes that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exception and its justification and determines that the AMP, with the exception, is adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 BWR CRD Return Line Nozzle 

Summary of Technical Information in the Application. LRA Section B.1.5, as revised by letter 

dated May 19, 2015, describes the existing BWR CRD Return Line Nozzle Program as 

consistent, with an enhancement, with GALL Report AMP XI.M6, “BWR Control Rod Drive 

Return Line Nozzle.” The LRA states that the program manages cracking of the control rod 

drive (CRD) return line nozzle through preventive measures and inservice inspection (ISI) 

activities that are in accordance with American Society of Mechanical Engineers (ASME) Boiler 

and Pressure Vessel Code Section Xl, Table IWB-2500-1, and the applicant’s existing 

commitments to implement recommendations from NUREG-0619, “BWR Feedwater Nozzle and 

Control Rod Drive Return Line Nozzle Cracking,” dated November 1980. The LRA also states 

that the CRD return line nozzle was capped before plant operation. 
3-21 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M6. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with the enhancement to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of this enhancement 

follows. 

Enhancement. LRA Section B.1.5 includes an enhancement to the “detection of aging effects” 

program element. In this enhancement, the applicant stated that procedures, as necessary, 

would be revised to ensure that ultrasonic testing (UT) would be used to ensure the detection of 

applicable aging effects. The staff reviewed this enhancement against the corresponding 

program element in GALL Report AMP XI.M6 and finds it acceptable because, when 

implemented, it will make the applicant’s AMP consistent with the guidance provided in the 

GALL Report AMP. The staff noted that the “detection of aging effects” program element of 

GALL Report AMP XI.M6 states that the extent and schedule of inspections should be such that 

the effects of cracking are detected before loss of intended function. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M6. The staff also reviewed the enhancement associated 

with the “detection of aging effects” program element and finds that, when implemented, it will 

make the AMP adequate to manage the applicable aging effect. 

Operating Experience. LRA Section B.1.5 summarizes operating experience related to the 

BWR CRD Return Line Nozzle Program. The LRA states that the applicant inspected the CRD 

return line nozzle in 2003 and 2012 with satisfactory results. These inspections involved an 

ultrasonic examination of the nozzle-to-shell and nozzle-to-cap welds with a visual examination 

of the nozzle inner radius. The LRA also states that, through a self-assessment, the applicant 

found that the 2012 nozzle inner radius examination did not completely fulfill the necessary 

coverage requirements. As a result, the applicant revised the procedure to provide better 

guidance and planned to perform the examination again during an upcoming refueling outage 

(RFO). 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M6 was evaluated. 

UFSAR Supplement. LRA Section A.1.5, as revised by letter dated May 19, 2015, provides the 

UFSAR supplement for the BWR CRD Return Line Nozzle Program. The staff reviewed this 
3-22 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed to revise its program procedures to perform ultrasonic examinations, as necessary, 

before the period of extended operation. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s BWR CRD Return Line 

Nozzle Program, the staff concludes that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancement and confirmed that its implementation before the period of extended operation will 

make the AMP adequate to manage the applicable aging effects. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 BWR Feedwater Nozzle 

Summary of Technical Information in the Application. LRA Section B.1.6, as revised by letter 

dated May 19, 2015, describes the existing BWR Feedwater Nozzle Program as consistent, with 

an exception, with GALL Report AMP XI.M5, “BWR Feedwater Nozzle.” The LRA states that 

the program manages cracking due to cyclic loading of the reactor vessel feedwater nozzles. 

The program manages this aging effect through periodic inspections of certain critical regions of 

the feedwater nozzles. The LRA states that these inspection activities follow the 

recommendations and inspection schedule from General Electric (GE)-NE-523-A71-0594-A, 

Revision 1, “Alternate BWR Feedwater Nozzle Inspection Requirements,” dated May 2000, and 

NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking,” 

dated November 1980. According to the LRA, the inspections conducted under the BWR 

Feedwater Nozzle Program augment those inspections specified by ASME Code Section XI. 

The LRA also states that the feedwater nozzles at Fermi 2 were never cladded and that they 

use an improved triple-sleeve sparger design. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M5. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with the exception to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this exception follows. 

Exception. LRA Section B.1.6 includes an exception to the “detection of aging effects” program 

element. In this exception, the applicant stated that the inspection schedule in the GALL Report 

is in accordance with Table 6-1 of GE-NE-523-A71-0594-A, Revision 1. 

GE-NE-523-A71-0594-A, Revision 1, states that the examination schedule specified in 

Table 6-1 is applicable until such time that 10 CFR 50.55a, “Codes and Standards,” is revised to 

require implementation of ASME Code Section XI, Appendix VIII. The applicant stated that the 

inspection frequency in its program is based on ASME Code Section XI rather than Table 6-1 of 

GE-NE-523-A71-0594-A, Revision 1; therefore, it identifies it as a program exception. The staff 

reviewed this exception and noted that the inspection frequency referred to in the applicant’s 

program is based on ASME Code Section XI and will provide an acceptable level of quality and 
3-23 

safety by using more stringent qualification and acceptance criteria. The staff also noted that 

the “detection of aging effects” program element of GALL Report AMP XI.M5 states that the 

extent and schedule of the inspection prescribed by the program are designed to ensure that 

aging effects are discovered and repaired before the loss of intended function of the component. 

The staff further noted that the inspection frequency, as implemented, ensures that aging effects 

will be adequately managed before the loss of intended function of the component. Therefore, 

the staff finds the exception acceptable. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M5. 

Operating Experience. LRA Section B.1.6 summarizes operating experience related to the 

BWR Feedwater Nozzle Program. The LRA states that three of the six feedwater nozzles were 

subject to manual, ultrasonic examinations of the nozzle inner radius and bore each RFO. In 

2000, the LRA states that the applicant began to use a qualified and automated ultrasonic 

technique to assess the integrity of the feedwater nozzle inner radius and bore in accordance 

with GE-NE-523-A71-0594-A, Revision 1. The LRA states that no indications of cracking have 

been discovered in the feedwater nozzles, and no recordable indications have been identified 

from past inspections of the feedwater spargers. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M5 was evaluated. 

UFSAR Supplement. LRA Section A.1.6 provides the UFSAR supplement for the BWR 

Feedwater Nozzle Program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s BWR Feedwater Nozzle 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 
3-24 

 BWR Penetrations 

Summary of Technical Information in the Application. LRA Section B.1.7 describes the existing 

BWR Penetrations Program as consistent with GALL Report AMP XI.M8, “BWR Penetrations.” 

The LRA states that the program manages cracking due to cyclic loading and SCC and 

intergranular stress corrosion cracking (IGSCC) of BWR instrument penetrations, CRD housing 

and incore housing penetrations, standby liquid control (SLC) nozzles, and core plate differential 

pressure nozzles. The LRA also states that the program manages cracking through periodic 

inspections of certain critical regions of the penetrations and nozzles. These inspection 

activities follow the recommendations and inspection schedule in BWRVIP-49-A, “BWR Vessel 

and Internals Project, Instrument Penetration Inspection and Flaw Evaluation Guidelines,” dated 

March 2002; BWRVIP-47-A, “BWR Vessel and Internals Project, BWR Lower Plenum 

Inspection and Flaw Evaluation Guidelines,” dated June 2004; BWRVIP-27-A, “BWR Vessel 

and Internals Project, BWR Standby Liquid Control System/Core Plate ∆P Inspection and Flaw 

Evaluation Guidelines,” dated August 2003; and the requirements in ASME Code Section XI. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M8. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M8. 

Operating Experience. LRA Section B.1.7 summarizes operating experience related to the 

BWR Penetrations Program. The LRA states that VT-2 inspections of the instrumentation 

nozzles were performed in 2003, and no failures were identified. The LRA also summarizes the 

baseline inspections of the CRD housing that were performed in accordance with the guidance 

in BWRVIP-47-A. The LRA states that all of the recommended inspections were completed by 

the end of Refueling Outage No. 14. No indications of cracking were identified; however, a 

manufacturing discontinuity was found on one weld. This condition was evaluated and 

accepted in accordance with ASME Code Section XI. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M8 was evaluated. 

UFSAR Supplement. LRA Section A.1.7 provides the UFSAR supplement for the BWR 

Penetrations Program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff finds that the information in the UFSAR supplement is an adequate summary description of 

the program. 
3-25 

Conclusion. On the basis of its audit and review of the applicant’s BWR Penetrations Program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 BWR Stress Corrosion Cracking 

Summary of Technical Information in the Application. LRA Section B.1.8 describes the existing 

BWR Stress Corrosion Cracking Program as consistent with GALL Report AMP XI.M7, “BWR 

Stress Corrosion Cracking.” The program manages IGSCC in nickel alloy, stainless steel, and 

cast austenitic stainless steel (CASS) reactor coolant pressure boundary piping and piping 

welds that are 4 inches or larger in nominal diameter containing reactor coolant at a 

temperature above 200 degrees Fahrenheit (°F) during power operation regardless of code 

classification. This program performs scheduled volumetric examinations that provide timely 

detection of IGSCC and leakage of coolant in accordance with the methods, inspection 

guidelines, and flaw evaluation criteria described in the ASME Code; NUREG-0313, Revision 2, 

“Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure 

Boundary Piping,” dated January 1988; NRC Generic Letter (GL) 88-01, “NRC Position on 

IGSCC in BWR Austenitic Stainless Steel Piping,” dated January 25, 1988, and its 

Supplement 1; NRC-approved BWRVIP-75-A, “BWR Vessel and Internals Project, Technical 

Basis for Revisions to Generic Letter 88-01 Inspection Schedules,” dated October 2005; and 

other requirements in 10 CFR 50.55a with NRC-approved alternatives. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M7. For the “detection of aging 

effect” program element, the staff determined the need for additional information, which resulted 

in the issuance of RAIs, as discussed below. 

GALL Report AMP XI.M7, “BWR Stress Corrosion Cracking,” states that the comprehensive 

program to manage IGSCC in BWR coolant pressure boundary piping is outlined in 

NUREG-0313, Revision 2, and GL 88-01 with its Supplement 1. The “detection of aging effects” 

program element of GALL Report AMP XI.M7 also states that modifications of the extent and 

schedule of inspection in GL 88-01 are allowed in accordance with the inspection guidance in 

staff-approved BWRVIP-75-A. LRA Section B.1.8 states that the applicant’s BWR Stress 

Corrosion Cracking Program is consistent with GALL Report AMP XI.M7. 

During the audit, the staff noted that the applicant implemented risk-informed ISI for the current 

(third) inservice inspection interval. The staff also noted that GL 88-01 Category A welds 

(i.e., IGSCC-resistant welds) are subsumed in the applicant’s risk-informed ISI. The staff further 

noted that the LRA and onsite program evaluation report do not describe what percentage of the 

Category A welds are inspected by the applicant’s program. It was not clear to the staff whether 

the percentage of Category A welds, which the applicant’s program inspects, is consistent with 

the guidance described in GL 88-01 and BWRVIP-75-A. 

By letter dated December 4, 2014, the staff issued RAI B.1.8-1 requesting that the applicant 

provide the percentage of Category A welds that the program will inspect during the period of 
3-26 

extended operation. The staff also requested that, if the extent of the inspection for Category A 

welds is different from the guidance in GL 88-01 and BWRVIP-75-A, the applicant justify why 

the program is adequate to manage the aging effect of IGSCC for the Category A welds. 

In its response dated January 5, 2015, the applicant indicated that its program inspects 

10 percent of the GL 88-01 Category A welds, consistent with the inspection guidelines in 

BWRVIP-75-A for the welds protected by hydrogen water chemistry. The applicant also clarified 

that it has 38 Category A welds and 4 of those welds are inspected during each ISI interval to 

meet the inspection extent (i.e., 10 percent). The applicant further clarified that two welds are 

inspected during the first inspection period, and one weld is inspected in each of the following 

two periods of the 10-year ISI interval. The applicant stated that the inspection schedule is 

consistent with the guidance in BWRVIP-75-A Section 3.1.1 and that 50 percent of the selected 

welds should be examined during the first 6 years of the ISI interval. 

The staff finds the applicant’s response acceptable because the applicant clarified that the 

inspection extent and schedule for Category A welds are consistent with the guidance in 

BWRVIP-75-A. In addition, the staff noted that the applicant’s operating experience indicates 

the absence of IGSCC in the piping and piping welds within the scope of the program, as 

described below. The plant-specific operating experience also supports the adequacy of the 

applicant’s inspection extent and schedule for IGSCC-resistant Category A welds. The staff’s 

concern described in RAI B.1.8-1 is resolved. 

In its review of the applicant’s program and related information, the staff noted that the following 

references indicate that the applicant’s condensate and feedwater systems include 

24 Category D welds in accordance with GL 88-01 (i.e., welds with materials nonresistant to 

IGSCC with no stress improvement process): 

 Letter dated July 29, 1992, from the Detroit Edison Company to the NRC 

(NRC-92-0090), Subject: Fermi 2 Response to GL 88-01, Supplement 1, NRC Position 

on Intergranular Stress-Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel 

Piping 

 Letter dated December 18, 1992, from the NRC to the Detroit Edison Company, Subject: 

Fermi-2 Removal of 24 Condensate and Feedwater System Welds from the Inservice 

Inspection Nondestructive Examination (ISI-NDE) Program (TAC No. M84177) 

The staff also noted that the following LRA tables describe the applicant’s AMR items for the 

condensate and feedwater systems: 

 Table 3.4.2-3-2, “Condensate System, Nonsafety-Related Components Affecting 

Safety-Related Systems” 

 Table 3.4.2-2, “Feedwater and Standby Feedwater System” 

 Table 3.4.2-3-3, “Feedwater and Standby Feedwater System, Nonsafety-Related 

Components Affecting Safety-Related Systems” 

The AMR tables for the condensate and feedwater systems in the LRA do not include AMR 

items to manage IGSCC for the Category D welds that were identified in the 1992 

communications between the Detroit Edison Company and the NRC. Therefore, the staff could 

not determine the adequacy of the applicant’s program and AMR results without additional 

information to justify the omission of relevant AMR items. 
3-27 

In addition, the staff noted that the 1992 communications indicate that these Category D welds 

are located outboard of the containment isolation valves and that at least 10 percent of these 

welds should be inspected during each RFO as part of the applicant’s ISI. The staff also noted 

that the extent and frequency of the application’s inspections are different from the inspection 

guidance in GL 88-01 and BWRVIP-75-A. For example, BWRVIP-75-A states that, in the case 

of the implementation of hydrogen water chemistry, 100 percent of Category D welds should be 

inspected every 10 years and that at least 50 percent of these welds should be inspected in the 

first 6 years. 

By letter dated December 4, 2014, the staff issued RAI B.1.8-2 requesting that the applicant 

clarify whether the condensate and feedwater systems include GL 88-01 Category D welds. 

The staff also requested that the applicant provide adequate justification for why the LRA AMR 

tables for the condensate and feedwater systems do not include AMR items to manage IGSCC 

for the Category D welds. The staff further requested that the applicant clarify why the LRA 

does not identify the inspection extent and frequency for Category D welds as a program 

exception to GALL Report AMP XI.M7. In addition, the staff requested that the applicant 

provide technical justification for why the inspection extent and frequency for Category D welds 

are acceptable for adequate aging management. The staff requested that, as part of the 

response, the applicant discuss whether the plant-specific operating experience, including 

inspection results, justifies the adequacy of aging management for Category D welds. 

In its response dated January 5, 2015, the applicant summarized the 1992 communications 

between the Detroit Edison Company and the NRC by stating that: 

In letter NRC-92-0090 dated July 29, 1992, Fermi 2 proposed deleting the 

24 Category D welds since they do not contain reactor coolant as defined in NRC 

regulations, and the welds were not likely susceptible to IGSCC based on the 

operating environment. The NRC did not completely agree with that position 

because the water was the same water that would enter the reactor pressure 

vessel (RPV). Instead, in the response dated December 18, 1992 

(TAC No. M84177) the NRC stated, “These welds may be susceptible to IGSCC. 

Therefore, the 24 welds should not be removed from the Fermi-2 ISI-NDE 

Program.” The correspondence also stated, “the staff has determined that the 

same staff position delineated in GL 88-01, Supplement 1 for reactor water 

cleanup (RWCU) piping outboard of the containment isolation valves should be 

applied to those 24 welds.” GL 88-01, Supplement 1 was issued to discuss 

some unnecessary hardships created by GL 88-01. One specific hardship was 

inspection of susceptible nonsafety-related piping outside the containment 

isolation valves. Therefore, the NRC correspondence concluded that the staff 

determined that “an inspection of the subject piping on a sampling basis of at 

least 10 percent of the weld population should be performed during each 

refueling outage.” 

As discussed above, the applicant clarified that the condensate and feedwater systems include 

Category D welds and that these welds are located outside the containment isolation valves. In 

its response, the applicant revised LRA Table 3.4.2-2 for the feedwater system and 

Table 3.4.2-3-2 for the condensate system to include AMR items for the Category D welds, 

consistent with the 1992 communications. The AMR items that have been added confirm that 

the BWR Stress Corrosion Cracking Program is used to manage IGSCC for the Category D 

welds. 
3-28 

The applicant clarified that the extent and frequency of these inspections are based on the NRC 

determination that 10 percent of these Category D welds should be inspected each outage as 

specified in the NRC letter dated December 18, 1992. The applicant also indicated that, 

because the inspection guidance in GL 88-01, Supplement 1, for the RWCU system was 

applied to other systems (i.e., feedwater and condensate systems at Fermi 2), LRA 

Sections A.1.8 (UFSAR supplement) and B.1.8 (program description) are revised to state that 

this is a program exception. The applicant further clarified that, because no IGSCC has been 

observed from these Category D welds in the inspections performed to date, the operating 

experience supports that cracking due to IGSCC in feedwater and condensate piping will be 

adequately managed. 

The staff found the applicant’s response, including the program exception, acceptable because 

(1) the applicant adequately revised the LRA to include AMR items for the Category D welds, 

(2) the applicant clarified that the inspection extent and frequency for the feedwater and 

condensate piping welds are consistent with the CLB that are based on the guidance in NRC 

GL 88-01, Supplement 1, and the staff’s determination, and (3) the applicant’s operating 

experience, including inspection results, confirms that no IGSCC has been observed in these 

welds. The staff’s concern described in RAI B.1.8-2 is resolved. 

Based on its audit and review of the applicant’s responses to RAIs B.1.8-1 and B.1.8-2, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M7. 

Exception. In its response to RAI B.1.8-2, dated January 5, 2015, the applicant provided a 

revision to LRA Section B.1.8 to identify an exception to the “detection of aging effects” and 

“monitoring and trending” program elements. In this exception, the applicant indicated that the 

inspection extent and frequency for Category D welds in the feedwater and condensate systems 

are 10 percent each RFO. 

As previously discussed, the staff noted that the applicant identified this exception because the 

inspection extent and frequency are based on the guidance in GL 88-01, Supplement 1, which 

addresses the inspections of RWCU piping outside containment isolation valves. The staff finds 

the exception acceptable because (1) the applicant’s Category D welds in the feedwater and 

condensate systems are located outside the containment isolation valves, consistent with the 

RWCU piping that is addressed in GL 88-01, Supplement 1; (2) the inspection extent and 

frequency are also consistent with the CLB that are based on the staff’s determination (as 

described in the NRC letter dated December 18, 1992); and (3) the applicant’s operating 

experience confirms that no IGSCC has been observed in these welds. 

Operating Experience. LRA Section B.1.8 summarizes the operating experience related to the 

BWR Stress Corrosion Cracking Program. The LRA states that no plant-specific AMP issues 

have been identified for the applicant’s facility. The LRA also states that it uses online noble 

metal chemistry to mitigate SCC. The LRA further indicates that the use of proven methods for 

inspections and water chemistry control provides assurance that the effects of aging will be 

managed such that components will continue to perform their intended functions, consistent with 

the CLB through the period of extended operation. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 
3-29 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its AMP audit and review, the staff identified operating experience for 

which it determined the need for additional clarification and the issuance of an RAI, as 

discussed below. 

The staff noted that the applicant’s Condition Assessment Resolution Document 

(CARD) 13-23127 addresses the Institute of Nuclear Power Operations Event Report 

(IER) 13-17, “Main Condenser Cooling Water Inleakage.” The staff also noted that 

CARD 13-23127 states that, since January 2011, events have been reported in which 

condenser cooling water inleakage resulted in scrams, a forced shutdown, and outage 

extensions. The staff noted that CARD 13-23127 also states that IER 13-17 indicates that the 

condenser inleakage events caused the introduction of sodium, chloride, sulfate, and other 

contaminants into the RCS and contributed to out-of-specification reactor water chemistry, 

requiring operations personnel to enter abnormal operating procedures more frequently. 

In addition, the staff noted that CARD 11-21607 states that during the startup on 

February 10, 2011, the applicant’s plant was shut down due to main condenser tube inleakage 

and associated water chemistry excursions. The staff also noted that CARD 11-21607 indicates 

that inspections of all condenser water boxes identified the ejection of tube plugs from receptive 

condenser tubes. 

The staff noted that another of the applicant’s CARD (CARD 08-26361) indicates that 

condenser cooling water inleakage occurred at the applicant’s plant at an estimated inleakage 

rate of 40 to 50 gal per day. CARD 08-26361 also states that pressure testing and inspections 

identified the leaking condenser tube, and the tube was plugged along with several other tubes. 

In its review, the staff identified the concern that the ingress of chloride, sulfate, and other 

contaminants into the RCS due to main condenser inleakage can promote IGSCC in BWR 

piping and piping welds. The staff noted that LRA Section B.1.8 and the onsite program 

evaluation report for the applicant’s BWR Stress Corrosion Cracking Program do not clearly 

address the potential impact of condenser cooling water inleakage on the effectiveness of the 

applicant’s program. Therefore, additional information is necessary to confirm that the 

applicant’s assessment of the operating experience regarding condenser inleakage ensures the 

effectiveness of its program. 

By letter dated December 4, 2014, the staff issued RAI B.1.8-3 requesting that the applicant 

clarify whether the main condenser inleakage and associated water chemistry excursions 

contributed to IGSCC in the piping and piping welds that are within the program scope. The 

staff also requested that the applicant explain whether previous occurrences of IGSCC, if any, 

were attributed to water chemistry control issues. In addition, the staff requested that the 

applicant discuss the assessment of industry and plant-specific operating experience regarding 

condenser cooling water inleakage and provide adequate justification for why there is no need 

to enhance the applicant’s program. 

In its response dated January 5, 2015, the applicant stated that chemistry excursions have not 

contributed to initiation of IGSCC because no cracking has been detected to date in any piping 

within the scope of the applicant’s program. The applicant also stated that site water chemistry 

monitoring procedures and processes manage water chemistry in accordance with Electrical 

Power Research Institute (EPRI) guidance that is based on industry-wide operating experience, 

which has shown that the guidance is effective. The applicant further stated that, if a water 
3-30 

chemistry parameter is out of specification, it addresses and corrects the issue by promptly 

taking action when condenser tube leakage is identified. The applicant indicated that hydrogen 

water chemistry and noble metal chemical addition are applied as part of the site plan to 

mitigate the environmental conditions and that volumetric inspections are performed in 

accordance with the staff-approved guidance to detect and manage IGSCC in a timely manner if 

it were to occur. The applicant stated that no changes to inspection population or inspection 

frequency are necessary based on the assessment of industry and plant-specific operating 

experience regarding condenser cooling water inleakage. 

The staff finds the applicant’s response acceptable because (1) the applicant clarified that no 

IGSCC has been observed to date in any piping within the scope of the Fermi 2 BWR Stress 

Corrosion Cracking Program, (2) operating experience supports the determination that water 

chemistry excursions have not contributed to IGSCC in the BWR piping at the applicant’s 

facility, and (3) the applicant clarified that it addresses and corrects any excursions out of water 

chemistry specifications in a timely manner in accordance with the industry guidelines for BWR 

water chemistry control. The concern described in RAI B.1.8-3 is resolved. 

Based on its audit, review of the application, and the applicant’s response to RAI B.1.8-3, the 

staff finds that the applicant has appropriately evaluated the plant-specific and industry 

operating experience and that implementation of the program has resulted in the applicant 

taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M7 was 

evaluated. 

UFSAR Supplement. LRA Section A.1.8 provides the UFSAR supplement for the BWR Stress 

Corrosion Cracking Program. As previously discussed, in its response to RAI B.1.8-2, the 

applicant adequately amended the UFSAR supplement to clarify that the Category D welds in 

the feedwater and condensate water systems are included in the scope of the program. 

Therefore, the UFSAR supplement for the BWR Stress Corrosion Cracking Program is 

consistent with the corresponding program description in SRP-LR Table 3.0-1. The staff finds 

that the information in the UFSAR supplement, as amended by letter dated January 5, 2015, is 

an adequate summary the program. 

Conclusion. On the basis of its audit and review of the applicant’s BWR Stress Corrosion 

Cracking Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the 

exception and its justification and determines that the AMP, with the exception, is adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 BWR Vessel ID Attachment Welds 

Summary of Technical Information in the Application. LRA Section B.1.9 describes the existing 

BWR Vessel ID Attachment Welds Program as consistent with GALL Report AMP XI.M4, “BWR 

Vessel ID Attachment Welds.” The LRA states that the program manages cracking in structural 

welds for BWR reactor vessel internal integral attachments using inspections, scheduling, 

acceptance criteria, and flaw evaluation in conformance with the requirements of ASME Code 
3-31 

Section XI and guidelines of BWRVIP-48-A, “BWR Vessel and Internals Project Vessel ID 

Attachment Weld Inspection and Flaw Evaluation Guidelines,” dated June 2004. The LRA 

further states that the program includes welds between the vessel wall and vessel inside 

diameter (ID) brackets that attach components to the vessel. The LRA also states that the 

internal attachment weld can be a simple weld or a weld buildup pad on the vessel. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M4. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M4. 

Operating Experience. LRA Section B.1.9 summarizes operating experience related to the 

BWR Vessel ID Attachment Welds Program. The LRA states that inspections were performed 

on the in-scope welds during RFO 8 in 2001 in accordance with the guidelines of 

BWRVIP-48-A. No indications of cracking were detected. The LRA also states that 

examinations were performed on shroud support welds in 2005, and other inspections were 

conducted on reactor vessel internal welds. The LRA section further states that portions of 

shroud support welds were last inspected during RFO 15 in 2012. No indications of cracking 

were detected. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification, which resulted in the issuance of an RAI, as 

discussed below. 

The staff noted that the LRA section states that shroud support weld examinations were 

performed in 2005. However, the staff’s review found no record of these examinations 

performed in 2005. By letter dated December 17, 2014, the staff issued RAI B.1.9-1 regarding 

this discrepancy. The RAI requested that the applicant provide clarification as to whether the 

subject inspections have been performed and, if so, provide the results and state whether any 

flaws were detected. 

In its response dated January 20, 2015, the applicant stated that discussion on the “2005” 

inspections in the LRA section actually should have been “2006.” The applicant stated that it 

performed the shroud support visual and ultrasonic examinations during RFO 11 in 2006. The 

applicant further stated that no relevant indications have been noted during any of the 

examinations for the shroud support welds. In addition, the applicant revised LRA Section B.1.9 

to change “2005” to “2006.” 

The staff noted that the applicant’s response corrected the error in the year in which the 

inspection was performed. The staff also noted that no indications of cracking were detected 

during the inspection. The staff finds the applicant’s response acceptable because the applicant 

corrected the error and revised the LRA section accordingly. The staff’s concern described in 

RAI B.1.9-1 is resolved. 
3-32 

Based on its audit and review of the application and review of the applicant’s response to 

RAI B.1.9-1, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M4 was 

evaluated. 

UFSAR Supplement. LRA Section A.1.9 provides the UFSAR supplement for the BWR Vessel 

ID Attachment Welds Program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s BWR Vessel ID Attachment 

Welds Program, the staff concludes that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Containment Leak Rate Program 

Summary of Technical Information in the Application. LRA Section B.1.13 describes the 

existing Containment Leak Rate Program as consistent with GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J.” The applicant stated that the program consists of tests 

performed in accordance with the requirements of Option B, “Performance-Based 

Requirements,” of Appendix J, “Primary Reactor Containment Leakage Testing for 

Water-Cooled Power Reactors,” to 10 CFR Part 50, “Domestic Licensing of Production and 

Utilization Facilities.” The applicant also stated that, under Option B, it follows the guidance of 

Regulatory Guide (RG) 1.163, “Performance-Based Containment Leak-Test Program,” dated 

September 1995; the referenced NEI 94-01, “Industry Guideline for Implementing 

Performance-Based Options of 10 CFR Part 50, Appendix J”; and the American National 

Standards Institute (ANSI)/American Nuclear Society 56.8, “Containment System Leakage 

Testing Requirements.” 

The applicant stated that, under Option B of Appendix J to 10 CFR Part 50, the program 

performs Type A or integrated leakage rate testing (ILRTs) and Type B and Type C local 

leakage rate testing (LLRTs) at the peak calculated loss-of-coolant accident (LOCA) 

containment pressure and applicable frequencies to periodically demonstrate the performance 

of containment pressure-retaining boundary components and isolation barriers. The applicant 

also stated that the parameters monitored are leakage rates of the steel containment vessel and 

associated welds, penetrations, fittings, access openings, and age-related degradation in 

material properties of seals, gaskets, O-rings, and packing materials. The applicant further 

stated that the program, through satisfactory leakage rate tests and with the additional 

implementation of an acceptable containment ISI program as described in ASME Code 

Section XI, Subsection IWE, ensures the leak tightness and structural integrity of the 

containment. 
3-33 

The applicant stated that the leakage rate acceptance criteria are in accordance with Option B 

of Appendix J to 10 CFR Part 50 and are defined in the plant’s Technical Specifications (TS). 

The applicant also stated that the program documents and trends test results and demonstrates 

that these results meet the requirements in the acceptance criteria. 

The applicant stated that evaluations are performed for test or inspection results that do not 

satisfy established criteria and that corrective actions are initiated to document the issues in 

accordance with plant administrative procedures. The applicant also stated that the corrective 

action program under Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and 

Fuel Reprocessing Plants,” to 10 CFR Part 50 ensures that conditions adverse to quality are 

corrected in accordance with applicable plant procedures that meet the requirements of 

Option B of Appendix J to 10 CFR Part 50. The applicant further stated that the cause of 

deficiencies significantly adverse to quality is determined and that an action plan is developed to 

prevent the recurrence of these deficiencies. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S4. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S4. 

Operating Experience. LRA Section B.1.13 summarizes operating experience related to the 

Containment Leak Rate Program. The included operating experience in the LRA indicates that, 

through proper implementation of ILRTs, LLRTs, and IWE ISIs, collectively, there is a 

reasonable assurance the leak tightness and structural integrity of the primary containment are 

maintained and will continue to be maintained during the period of extended operation. For 

example, the applicant stated that, from 2003 to 2013, all of the “as-found” Type B tests 

performed at penetrations yielded acceptable leakage rate results. An exception occurred in 

2009 when the “as-left” leakage rate of an equipment hatch was above the acceptance criteria 

due to faulty seals. However, it was considered acceptable as is because the sum of individual 

LLRT results was below the acceptance limit. The applicant promptly replaced the failing seals 

during the following RFO in 2010. The ILRT performed in 2007 yielded acceptable “as-found” 

leakage rate results before factoring in the leakage rates of the feedwater check valves. The 

applicant found that the cause of the excessive leakage of four check valves was related to the 

erosion of their soft valve seats. The applicant then replaced the seats and subsequently 

retested the valves; these actions satisfied the LLRT acceptance criteria before the unit’s 

restart. To prevent recurrence, the replacement frequency of all feedwater check valve soft 

seats was increased to every RFO. Upon further review of the situation, it was determined that 

the intended function of the primary containment associated with the containment isolation 

valves was not impacted. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 
3-34 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S4 was evaluated. 

UFSAR Supplement. LRA Section A.1.13 provides the UFSAR supplement for the Containment 

Leak Rate Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

finds that the information in the UFSAR supplement is an adequate summary description of the 

program. 

Conclusion. On the basis of its audit and review of the applicant’s Containment Leak Rate 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Environmental Qualification (EQ) of Electric Components 

Summary of Technical Information in the Application. LRA Section B.1.15 describes the 

existing Environmental Qualification (EQ) of Electric Components Program as consistent with 

GALL Report AMP X.E1, “Environmental Qualification (EQ) of Electric Components.” The LRA 

states that the AMP addresses Criterion 4, “Environmental and Dynamic Effects Design Bases,” 

of Appendix A, “General Design Criteria for Nuclear Power Plants,” to 10 CFR Part 50, and 

10 CFR 50.49, “Environmental Qualification of Electric Equipment Important to Safety for 

Nuclear Power Plants,” which specifically requires the establishment of an EQ program to 

demonstrate that certain electrical components located in a harsh environment (i.e., those areas 

of the plant that could be subject to the harsh environmental effects of a LOCA, high-energy line 

breaks (HELBs), or high radiation) are qualified to perform their safety function in those harsh 

environments. The LRA also states that 10 CFR 50.49 requires the applicant to address the 

effects of significant aging mechanisms as part of EQ. Further, the applicant stated that, as 

required by 10 CFR 50.49, EQ components are refurbished or replaced, or their qualification is 

extended before they reach the aging limits established in the evaluation. LRA Section B.1.15 

notes that the reanalysis of an aging evaluation addresses attributes of the analytical methods, 

data reduction and collection methods, underlying assumptions, acceptance criteria, and 

corrective actions. The LRA also states that some aging evaluations for EQ components are 

time-limited aging analyses (TLAAs) for license renewal. Finally, the applicant indicated that 

continued implementation of the Environmental Qualification (EQ) of Electric Components 

Program provides reasonable assurance that equipment qualification will be maintained and 

that the effects of aging will be managed so that components crediting this program can perform 

their intended function consistent with the CLB during the period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP X.E1. 
3-35 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP X.E1. 

Operating Experience. LRA Section B.1.15 summarizes operating experience related to the 

Environmental Qualification (EQ) of Electric Components Program. For Fermi 2, the applicant 

referenced an EQ-program-focused self-assessment that identified one strength and 

12 corrective action documents containing deficiencies and recommendations. As described in 

the LRA, none of the deficiencies involved failure to maintain equipment EQ. The applicant also 

referenced an example of completed corrective actions, including updating the plant equipment 

database, as a result of missing EQ bases documentation discovered during the EQ 

reconstitution project of 2012. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

Operating experience reviewed included confirmation of EQ program updates resulting from 

revised environments associated with an extended power uprate and a measurement 

uncertainty recapture (MUR) power uprate. The staff also reviewed quarterly EQ program 

health reports issued for 2011, 2012, 2013, and 2014. The self-assessment results for 2011 

resulted in an overall score of “white.” The same was noted for self-assessments performed in 

2012 and for 2013 but with three of four categories rated as “green” for 2013. The first quarter 

health report for 2014 improved to an overall rating of “green” attributed, in part, to the 

qualification of additional personnel and resolution of self-assessment deficiencies. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP X.E1 was evaluated. 

UFSAR Supplement. LRA Section A.1.15 provides the UFSAR supplement for the 

Environmental Qualification (EQ) of Electric Components Program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed to ongoing implementation of the existing Environmental Qualification (EQ) of 

Electric Components Program for managing the effects of aging for applicable components 

during the period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Environmental Qualification 

(EQ) of Electric Components Program, the staff concludes that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB for the 
3-36 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

 Inservice Inspection 

Summary of Technical Information in the Application. LRA Section B.1.21 describes the 

applicant’s existing Inservice Inspection (ISI) Program as consistent with GALL Report 

AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD.” The 

LRA states that the program manages loss of material, cracking, and reduction in fracture 

toughness for ASME Code Class 1, 2, 3 pressure-retaining components, which include welds; 

pump casings; valve bodies; integral attachments; and pressure-retaining bolting using 

volumetric, surface, and/or visual examinations and leakage testing, as specified in ASME Code 

Section XI with NRC-approved alternatives. 

In addition, the LRA states that the ISI Program includes limitations, modifications, and 

augmented inspection described in 10 CFR 50.55a. The LRA further states that the program is 

updated every 10 years to the latest ASME Code Section XI edition and addenda approved by 

the NRC in 10 CFR 50.55a. The LRA also states that the ISI program is consistent with the 

program described in GALL Report Section XI.M1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD.” 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M1. As discussed in the Audit 

Report, the staff confirmed that each element of the applicant’s program is consistent with the 

corresponding element of GALL Report AMP XI.M1. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M1. 

Operating Experience. LRA Section B.1.21 summarizes operating experience related to the 

applicant’s ISI Program. The applicant stated that, in 2008, an in-depth self-assessment for its 

second 10-year interval of the ISI nondestructive examination (NDE) program plan was 

performed. The applicant also stated that, as a result of these assessments, issues and 

recommendations were identified that were entered into the corrective actions program and that 

actions related to these corrective actions and recommendations were completed. The 

applicant further stated that the self-assessment concluded that the second interval NDE plan 

was comprehensive and met the objectives of ASME Code Section XI. 

LRA Section B.1.21 also provides specific examples of the applicant’s operating experience. 

The LRA states that, during the performance of thickness examinations by UT of the diesel 

generator service water piping during the RFO of 2010, it identified sections of piping with 

significant wall thickness reductions. The applicant also stated that this identification resulted in 

the degraded condition being entered into the corrective actions program, which required 

engineering evaluations to determine acceptability for further service or replacement. The 

applicant further stated that, in 2012, 44 components were examined and no significant issues 

were identified. The applicant further stated that based on the history of identification of 

degradation and initiation of corrective actions before loss of intended function, its Inservice 

Inspection Program provides assurance that future inspections will continue to remain effective 
3-37 

such that components will perform their intended functions through the period of extended 

operation. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M1 was evaluated. 

UFSAR Supplement. LRA Section A.1.21 provides the UFSAR supplement for the Inservice 

Inspection Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. 

Conclusion. On the basis of its audit and review of the applicant’s ISI Program, the staff 

concludes that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Internal Surfaces in Miscellaneous Piping and Ducting Components 

Summary of Technical Information in the Application. LRA Section B.1.24 describes the new 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program as consistent with 

GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” as modified by LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire 

Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation.” The LRA states 

that the AMP will manage fouling, cracking, loss of material, and changes in material properties 

of the internal surfaces of metallic and nonmetallic piping and components in environments 

other than open-cycle cooling water, closed treated water, and fire water. The LRA also states 

that the AMP proposes to detect these aging effects through visual inspections, physical 

manipulation, and pressurization. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M38, as modified by 

LR-ISG-2012-02. For the “detection of aging effects” program element, the staff determined the 

need for additional information, which resulted in the issuance of an RAI, as discussed below. 
3-38 

Although the frequency and size of the representative inspection sample for this program is 

consistent with the “detection of aging effects” program element in GALL Report AMP XI.M38, 

this program is being used to manage the air side of several room coolers that are within the 

scope of GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” 

dated July 18, 1989. LRA Section B.1.24 states that a 20-percent sample will be inspected 

during each 10-year period, at a minimum. However, GL 89-13 specifies a minimum test 

frequency of 5 years for each safety-related heat exchanger cooled by open-cycle service water 

and includes air-side inspections for heat exchangers that are not tested. It was unclear to the 

staff whether the air-side inspection frequency of the room coolers would be consistent with the 

guidance provided in GL 89-13. By letter dated December 19, 2014, the staff issued 

RAI B.1.24-1 requesting that the applicant provide information on the aging management 

activities for the room coolers. 

In its response dated January 28, 2015, the applicant stated that Enclosure B of the Fermi 2’s 

Engineering Support Conduct Manual MES52, “GL 89-13 Safety-Related Service Water 

Monitoring Program,” controls the frequency of the preventive maintenance (PM) activities 

associated with the air-side inspections for each ESFs fan coil unit. In addition, the applicant 

verified that the inspection frequency is at least once every 5 years and meets the requirements 

of GL 89-13. The staff finds the applicant’s response acceptable because the frequency of the 

air-side inspections to detect fouling in the room coolers is at least once every 5 years and 

continues to be specified through the site procedure associated with GL 89-13. The staff’s 

concerns described in RAI B.1.24-1 are resolved. 

In reviewing the program for consistency with the GALL Report, the staff notes that the 

applicant’s program includes fouling as an aging effect requiring management and that 

management of fouling is not consistent with GALL Report AMP XI.M38. The program 

proposes to manage reduction of heat transfer due to air-side fouling of heat exchanger fins and 

tubes by using periodic visual inspections. The staff notes that GL 89-13 identifies periodic 

air-side visual inspections to ensure cleanliness of air-to-water heat exchangers as an 

acceptable approach for verifying heat transfer capability. The staff finds that cleanliness of 

heat exchanger tubes and fins can be readily identifiable through periodic visual inspections 

during system inspections and walkdowns. Based on the discussion above and SER 

Section 3.3.2.3.6, the staff finds that the visual inspections in this program are capable of 

detecting fouling of air-side heat exchanger surfaces before loss of the intended function. 

Based on its audit and review of the applicant’s response to RAI B.1.24-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.M38. 

In addition, the staff reviewed the additional aging effect being managed by this program and 

finds that the associated effects of aging will be adequately managed. 

Operating Experience. LRA Section B.1.24 summarizes operating experience related to the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The LRA states 

that the new program is based on GALL Report AMP XI.M38, which industry operating 

experience has demonstrated to be adequate to manage the applicable aging effects. LRA 

Section B.0.4, “Operating Experience,” also states that future plant-specific and industry 

operating experience will be reviewed on an ongoing basis to evaluate the program’s 

effectiveness, and the first evaluation will be performed within 5 years of implementing the new 

program. 
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The staff reviewed operating experience information during the audit to determine whether the 

applicable aging effects and industry and plant-specific operating experience were reviewed by 

the applicant. As discussed in the Audit Report, the staff conducted an independent search of 

the plant operating experience information to determine whether the applicant had adequately 

evaluated and incorporated operating experience related to this program. During its review, the 

staff did not identify any operating experience that would indicate that the applicant should 

consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M38 was evaluated. 

UFSAR Supplement. LRA Section A.1.24 provides the UFSAR supplement for the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. The staff 

also noted that the applicant committed to implement the new Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program before the period of extended 

operation for managing the effects of aging for applicable components. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program, the staff concludes that those 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent. The staff concludes that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

 Metal Enclosed Bus Inspection 

Summary of Technical Information in the Application. LRA Section B.1.26 describes the new 

Metal Enclosed Bus Inspection Program as consistent with GALL Report AMP XI.E4 “Metal 

Enclosed Bus.” The applicant stated that the Metal Enclosed Bus Inspection Program is a new 

condition monitoring program that will provide for the inspection of the internal and external 

portions of the metal enclosed bus (MEB) to identify age-related degradation of the bus and bus 

connections, the bus enclosure assemblies, and the bus insulation and insulators. The program 

will inspect the MEB between combustion turbine generator (CTG) transformer CTG 11-1 and 

peaker bus 1-2B located in the 120-kV switchyard. The MEB associated with the CTG 11-1 is 

used as the alternate alternating current (AC) source for a station blackout event, and it 

supports response by the dedicated shutdown panel to an Appendix R (“Fire Protection 

Program for Nuclear Power Facilities Operating Prior to January 1, 1979,” to 10 CFR Part 50) 

fire. 

The applicant stated that the Metal Enclosed Bus Inspection Program is a new program. 

Industry and plant operating experience will be considered in the implementation of this 

program. Plant operating experience will be gained as the program is implemented and will be 

factored into the program via the confirmation and corrective action elements of the Fermi 2 QA 

program under Appendix B to 10 CFR Part 50. 
3-40 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E4. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.E4. 

Operating Experience. LRA Section B.1.26 summarizes operating experience related to the 

Metal Enclosed Bus Inspection Program. The staff reviewed operating experience information 

in the application and during the audit to determine whether the applicable aging effects and 

industry and plant-specific operating experience were reviewed by the applicant. As discussed 

in the Audit Report, the staff conducted an independent search of the plant operating 

experience information to determine whether the applicant had adequately evaluated and 

incorporated operating experience related to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. Based on its audit and review of the 

application, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.E4 was 

evaluated. 

UFSAR Supplement. LRA Section A.1.26 provides the UFSAR supplement for the Metal 

Enclosed Bus Inspection Program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to implementing the new Metal 

Enclosed Bus Inspection Program before September 20, 2024, or the end of the last RFO 

before March 20, 2025, whichever is later, for managing the effects of aging for applicable 

components. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Metal Enclosed Bus 

Inspection Program, the staff concludes that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Non-EQ Cable Connections 

Summary of Technical Information in the Application. LRA Section B.1.28 describes the new 

Non-EQ Cable Connections Program as consistent with GALL Report AMP XI.E6, “Electrical 

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” 

The LRA states that the AMP is a one-time inspection on a sample of connections that must be 

completed before the period of extended operation. Cable connections in this AMP are those 

connections susceptible to age-related degradation resulting in increased resistance due to 

thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, 

corrosion, or oxidation that are not subject to the EQ requirements of 10 CFR 50.49. The 
3-41 

factors considered for sample selection are application (i.e., medium and low voltage defined as 

less than 35 kV), circuit loading (i.e., high loading), connection type, and location (e.g., high 

temperature, high humidity, and vibration). The representative sample size will be based on 

20 percent of the connection population with a maximum sample of 25. Inspection methods 

may include thermography, contact resistance testing, or other appropriate testing methods 

without removing the connection insulation (e.g., heat shrink tape, sleeving, and insulation 

boots). 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E6. 

For the “parameters monitored or inspected” program element, the staff determined the need for 

additional information, which resulted in the issuance of RAI B.1.28-2, as discussed below. 

The “parameters monitored or inspected” program element in GALL Report AMP XI.E6 

recommends testing a representative sample of electrical cable connections. The following 

factors are considered for sampling: voltage level (i.e., medium and low voltage), circuit loading 

(i.e., high load), connection type, and location (e.g., high temperature, high humidity, and 

vibration). The technical basis for the sample selection is documented. 

The applicant’s “detection of aging effects” program element of the LRA AMP basis document 

states that “the technical basis for the sample selected will be documented.” However, the 

sample selection methodology and the technical basis were not developed by the applicant and 

were not available for the staff to review at the time of the audit. 

During the AMP audit, the staff requested the operating experience associated with the tap box 

connections, including records of maintenance activities performed. The applicant did not find 

any maintenance activities or reported operating experience for tap box connections. In 

addition, the applicant’s PM program did not include the tap box connections. Further, it was 

not clear to the staff that these in-scope connections would be included in the sample population 

or considered as a sampling program connection type. By letter dated January 14, 2015, the 

staff issued RAI B.1.28-2 requesting that the applicant justify that a one-time test, on a sampling 

basis, in accordance with LRA AMP B.1.28, is adequate to ensure that in-scope tap box 

connection intended functions will be maintained consistent with the CLB for the period of 

extended operation. The staff also requested that the applicant explain whether a 

representative number of tap box connections will be included in the overall population and will 

be represented as a sampling program connection type as part of applicant’s sampling 

methodology. 

In its response dated February 12, 2015, the applicant stated that the tap boxes are uniquely 

designed and will be grouped as a specific connection type for the purpose of sample selection. 

The applicant will revise LRA Sections A.1.28 and B.1.28 to identify the tap box connections as 

a specific group in the sample selection criteria. The applicant also stated that for electrical 

connections that are not part of electrical components requiring routine or periodic maintenance 

(i.e., tap box connections), a one-time test and connection disassembly and reassembly will 

confirm that the existing design and installation and maintenance practices have been effective. 

Further, in response to an industry event report, the applicant developed cable bus PM that 

includes inspection of the tap box connections. The cable bus PM are coordinated with the 

12-year transformer and switchgear PM. 
3-42 

The staff finds the applicant’s response acceptable because the tap box electrical connections 

will be included in the connection population and treated as a specific group in the LRA 

AMP B.1.28, “Non-EQ Cable Connections,” sample selection criteria consistent with GALL 

Report AMP XI.E6 sampling program guidance. In addition, tap box connection PM has been 

developed and coordinated with transformer and switchgear PM. The staff’s concern described 

in RAI B.1.28-2 is resolved. 

Based on its audit and review of the applicant’s response to RAI B.1.28-2, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.E6. 

Operating Experience. LRA Section B.1.28 summarizes operating experience related to the 

Non-EQ Cable Connections Program. The Non-EQ Cable Connections Program is a new 

program with industry and plant operating experience considered in the implementation of the 

program. The LRA states that plant operating experience will be gained as the program is 

implemented and will be factored into the program via the confirmation and corrective action 

elements of the Fermi 2 QA program under Appendix B to 10 CFR Part 50. Further, the LRA 

states that the Non-EQ Cable Connections Program applies to potential aging effects for which 

there is no operating experience at Fermi 2, indicating the need for a Non-EQ cable connections 

AMP. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its onsite audit, the staff reviewed plant maintenance procedures that included 

procedures for verifying the torque of bolted electrical connections. The staff found that the 

applicant’s procedures were inconsistent with the guidelines in EPRI TR-104213, “Bolted Joint 

Maintenance & Applications Guide,” concerning verification of the proper torque of bolted 

electrical connections. 

Therefore, by letter dated January 14, 2015, the staff issued RAI B.1.28-1 requesting that the 

applicant explain why plant procedures specify the re-torqueing of bolted connections versus 

the recommended practice referenced in EPRI TR-104213 not to re-torque bolted electrical 

connections once the fastener is in service. 

In its response dated February 12, 2015, the applicant stated that re-torqueing will not be used 

as an alternative to thermography or resistance checks for the detection of aging effects on 

bolted electrical connections. The applicant will revise LRA Sections A.1.26, A.1.28, B1.26, and 

B.1.28 to clarify that torque checking will not be used as an alternative method to thermography 

or resistance checks. 

The staff finds the applicant’s response acceptable because the concerns over re-torqueing of 

electrical connections have been alleviated. The applicant’s revisions to LRA Sections A.1.26, 

A.1.28, B1.26, and B.1.28 prevent potential harm due to re-torqueing. The staff’s concern 

described in RAI B.1.28-1 is resolved. 
3-43 

UFSAR Supplement. LRA Section A.1.28 provides the UFSAR supplement for the Non-EQ 

Cable Connections Program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. 

The staff also noted that the applicant committed (Commitment No. 21) to implement the new 

Non-EQ Cable Connections Program before September 20, 2024, or at the end of the last RFO 

before March 20, 2025, whichever is later for managing the effects of aging for applicable 

components. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Non-EQ Cable Connections 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Non-EQ Inaccessible Power Cable (400 V to 13.8 kV) 

Summary of Technical Information in the Application. LRA Section B.1.29 describes the new 

Non-EQ Inaccessible Power Cables (400 V to 13.8 kV) Program as consistent with GALL 

Report AMP XI.E3, “Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements.” The LRA states that the Non-EQ Inaccessible Power Cables 

(400 V to 13.8 kV) Program is a condition monitoring program that will manage the aging effect 

of reduced insulation resistance on inaccessible power cables (400 V to 13.8 kV) that have a 

license renewal intended function. The in-scope cables identified by the LRA are routed 

underground in conduit or duct bank or are directly buried. The applicant further stated that 

industry and plant-specific operating experience will be considered in the implementation of this 

program and factored into the program via the applicant’s corrective action program. 

The applicant also stated that in-scope inaccessible power cables exposed to significant 

moisture will be tested every 6 years to provide an indication of the conductor insulation with the 

first tests occurring before the period of extended operation. The tests are to be proven and 

commercially available for detecting deterioration of the cable insulation. The applicant’s 

program includes periodic inspections for water accumulation in manholes at least once a year, 

including manhole inspections after events, such as heavy rain or flooding. The program allows 

the inspection frequency to be adjusted as necessary based on evaluation of inspection results. 

The LRA states that the Non-EQ Inaccessible Power Cables (400 V to 13.8 kV) Program will be 

implemented before the period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E3. 
3-44 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.E3. 

Operating Experience. LRA Section B.1.29 summarizes operating experience related to the 

Non-EQ Inaccessible Power Cables (400 V to 13.8 kV) Program. The applicant stated that 

plant operating experience will be gained as the program is implemented and will be factored 

into the program via the confirmation and corrective action elements of the Fermi 2 QA program 

under Appendix B to 10 CFR Part 50. The applicant identified actions taken in response to 

industry and plant-specific operating experience. Actions included the installation of sump 

pumps, periodic pumping and monitoring of cable vaults and manholes, manhole and vault 

repair, emergency diesel generator (EDG) raceway and cable replacement, and 

cable-monitoring procedure development. 

The applicant’s response to GL 07-01, “Inaccessible or Underground Power Cable Failures That 

Disable Accident Mitigation Systems or Cause Plant Transients,” dated February 7, 2007, 

identified three power cable failures. The failures included, (1) the normally energized station 

blackout combustion turbine generator transformer cooler backup 480-VAC power cable, (2) a 

260-V direct current (DC), normally energized 130-V DC circulating water pump house 

distribution panel power cable, and (3) a 260-V DC, normally energized, 130-V DC general 

service water pump house power cable. Of the three power cable failures, the LRA identified 

the normally energized station blackout combustion turbine generator transformer cooler backup 

480-VAC power cable as within the scope of license renewal. The LRA noted that this cable 

had been in service for approximately 39 years and that the probable cable cause of the failure 

was degraded conduit or degraded cable insulation. 

As described in Fermi 2 Power Plant, Unit 2, Integrated Inspection Report 05000341/2011005 

(Agencywide Documents Access and Management System (ADAMS) Accession 

No. ML120300106), the inspection selected underground bunkers/manholes subject to flooding 

that contained cables whose failure could disable risk-significant equipment. The inspectors 

determined that the cables were not submerged, splices were intact, and appropriate cable 

support structures were in place. In those areas where dewatering devices were used, the 

device was operable and level alarm circuits were set appropriately to ensure that the cables 

would not be submerged. In those areas without dewatering devices, the inspectors verified 

that drainage of the area was available or that the cables were qualified for submergence 

conditions. The inspectors also reviewed the licensee’s corrective action documents with 

respect to past submerged cable to verify the adequacy of the corrective actions. The 

inspectors performed a walkdown of underground bunkers/manholes 16552 and 16950 with 

safety-related and security-related cables. No findings were identified during the inspection. 

Fermi 2 Integrated Inspection Reports 05000341/2009005 (ADAMS Accession 

No. ML100340164) and 05000341/2012005 (ADAMS Accession No. ML13028A454) include the 

evaluation of selected underground bunkers/manholes subject to flooding that contained cables 

whose failure could disable risk-significant equipment. The inspection determined that cables 

were not submerged, splices were intact, and appropriate cable support structures were in 

place. Dewatering devices were operable and level alarm circuits were set appropriately to 

ensure the cables would not be submerged. In those areas without dewatering devices, the 

inspectors verified that drainage of the area was available or that the cables were qualified for 

submergence conditions. Corrective actions with respect to past submerged cable issues were 

evaluated to verify the adequacy of the corrective actions. Walkdowns were performed on 

security cable manholes and residual heat removal (RHR)/EDG manholes. Additionally, 
3-45 

Integrated Inspection Reports 05000341/2013002 (ADAMS Accession No. ML13127A206) and 

05000341/2013003 (ADAMS Accession No. ML13210A073) evaluated work orders for weekly 

performance of manhole water level monitoring. NRC Inspection Manual, Inspection 

Procedure 71111, Attachment 06, Section 02.02, “Inspection Activities,” clarifies that “[i]f neither 

dewatering devices nor drainage have been installed, verify that the operational environment of 

the cables is consistent with the manufacturer’s design specifications and qualification criteria.” 

No findings were identified during the inspections. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E3 was evaluated. 

UFSAR Supplement. LRA Section A.1.29 provides the UFSAR supplement for the Non-EQ 

Inaccessible Power Cables (400 V to 13.8 kV) Program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed 

(Commitment No. 22) to implement the new Non-EQ Inaccessible Power Cables (400 V to 

13.8 kV) Program before September 20, 2024, or at the end of the last RFO before 

March 20, 2025, whichever is later for managing the effects of aging for applicable components. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Non-EQ Inaccessible Power 

Cables (400 V to 13.8 kV) Program, the staff concludes that those program elements for which 

the applicant claimed consistency with the GALL Report are consistent. The staff concludes 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Non-EQ Instrumentation Circuits Test Review 

Summary of Technical Information in the Application. LRA Section B.1.30 describes the new 

Non-EQ Instrumentation Circuits Test Review Program as consistent with GALL Report 

AMP XI.E2, “Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.” The 

applicant stated that this is a new performance monitoring program to manage aging of in-scope 

cable and connection insulation for the following monitoring systems: 
3-46 

 neutron monitoring 

 intermediate range channels 

 average power range monitors (includes local power range monitor detector 

strings) 

 process radiation monitoring 

 Control Center emergency air inlet radiation monitors 

 fuel pool ventilation exhaust radiation monitors 

 main steam line radiation monitors 

The applicant described the Non-EQ Instrumentation Circuits Test Review Program as an AMP 

that will manage reduced insulation resistance of conductor and connector insulation material 

used in high-voltage, low-current instrumentation signal applications. As discussed in the LRA, 

the Non-EQ Instrumentation Circuits Test Review Program age manages non-EQ sensitive 

instrumentation circuits subjected to adverse localized environments caused by heat, radiation, 

and moisture. The applicant stated that the program consists of the review of instrumentation 

circuit calibration results or that the findings of surveillance testing programs will provide 

sufficient indication for corrective actions based on instrument calibration and test acceptance 

criteria. The LRA also states that the Non-EQ Instrumentation Circuits Test Review Program 

review of calibration results or findings of surveillance testing programs will be performed once 

every 10 years with the first review occurring before the period of extended operation. 

The LRA program description and AMP basis document also state that cable system testing will 

be performed for in-scope sensitive instrument cables that are disconnected during instrument 

calibration. The applicant further stated that when detectors are disconnected during 

calibration, the cable system test will use a proven method for detecting reduced insulation 

resistance of the instrumentation cable and connection insulation system. The first test will be 

completed before the period of extended operation and subsequent tests will occur at least 

every 10 years. 

The applicant stated that industry operating experience will be considered in the implementation 

of the program and that plant operating experience will be gained as the program is executed 

and factored into the program via the Fermi 2 QA program under Appendix B to 

10 CFR Part 50, as discussed in LRA Section B.0.4. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E2. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.E2. 

Operating Experience. LRA Section B.1.30 summarizes operating experience related to the 

new Non-EQ Instrumentation Circuits Test Review Program. The LRA states that Fermi 2 has 

experienced failures with cables and connections of neutron monitoring, and a review of these 

failures showed that aging mechanisms are consistent with those addressed in GALL Report 

AMP XI.E2. 
3-47 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff’s review of plant-specific operating experience also noted corrective 

actions associated with cable and connector insulation degradation. However, during its review, 

the staff did not identify any operating experience that would indicate that the applicant should 

consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.E2 was evaluated. 

UFSAR Supplement. LRA Section A.1.30 provides the UFSAR supplement for the Non-EQ 

Instrumentation Circuits Test Review Program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. 

The staff also noted that the applicant committed (Commitment No. 23) to implement the new 

Non-EQ Instrumentation Circuits Test Review Program before September 20, 2024, or at the 

end of the last RFO before March 20, 2025, whichever is later for managing the effects of aging 

for applicable components. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Non-EQ Instrumentation 

Circuits Test Review Program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Non-EQ Insulated Cables and Connections 

Summary of Technical Information in the Application. LRA Section B.1.31 describes the new 

Non-EQ Insulated Cables and Connections Program as consistent with GALL Report 

AMP XI.E1, “Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements.” The LRA states that the new 

Non-EQ Insulated Cables and Connections Program is a condition monitoring program that 

provides reasonable assurance that the intended functions of insulated cables and connections 

exposed to adverse localized environments caused by heat, radiation, and moisture can be 

maintained consistent with the CLB through the period of extended operation. The LRA further 

states that accessible insulated cables and connections within the scope of license renewal 

installed in an adverse localized environment will be visually inspected for cable and connection 

jacket surface anomalies, such as embrittlement, discoloration, cracking, melting, swelling, or 

surface contamination. The applicant concluded that inspection of accessible cables will 
3-48 

represent, with reasonable assurance, all cables and connections in an adverse environment. 

The applicant noted that an adverse localized equipment environment is a plant-specific 

condition that will be determined on a plant spaces approach. The applicant determines the 

plant space adverse localized environment based on the most limiting temperature, radiation, or 

moisture condition for the cable and connection insulation within that plant space. As a new 

program, the applicant stated that industry operating experience will be considered in the 

implementation of this program and that plant-specific operating experience will be gained as 

the program is executed and factored into the program through the Fermi 2 QA program under 

Appendix B to 10 CFR Part 50. Finally, the Non-EQ Insulated Cables and Connections 

Program as described in the LRA will visually inspect accessible cables in an adverse localized 

environment at least every 10 years with the first inspection before the period of extended 

operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.E1. For the “parameters 

monitored or inspected” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below. 

The “parameters monitored or inspected” program element in GALL Report AMP XI.E1 

identifies an adverse localized environment as a plant-specific condition; therefore, the applicant 

should clearly define how this condition is determined. The applicant should determine and 

inspect the adverse localized conditions for each of the most limiting temperature, radiation, or 

moisture conditions for the accessible cables and connections that are within the scope of 

license renewal. 

GALL Report AMP XI.E1 states that adverse localized environments can be identified through 

the use of an integrated approach. This approach may include, but is not limited to, (a) the 

review of EQ zone maps that show radiation levels and temperatures of various plant areas, 

(b) consultations with plant staff who are cognizant of plant conditions, (c) utilization of infrared 

thermography to identify hot spots on a real-time basis, and (d) the review of relevant 

plant-specific and industry operating experience. Additionally, SRP-LR Section 2.5.1 states that 

an applicant may use the so-called “plant spaces” approach instead of identifying specific 

electrical and instrument and control components. 

During its audit, the staff observed that the applicant’s Non-EQ Insulated Cables and 

Connections Program “plant spaces” approach is not part of the integrated approach referenced 

by GALL Report AMP XI.E1 or the SRP-LR. Additionally, the use of a “plant spaces” approach 

on its own may not consider relevant plant-specific or industry operating experience or other 

aspects for the identification of an adverse localized environment, as described in GALL Report 

AMP XI.E1. 

By letter dated December 22, 2014, the staff issued RAI B.1.31-1 requesting that the applicant 

explain how the use of the “plant spaces” scoping and screening approach, as described in 

SRP-LR Section 2.5.1, “Areas of Review,” was adopted to identify adverse localized 

environments consistent with the integrated approach described in GALL Report AMP XI.E1, 

including the use of EQ zone map reviews, consultations with plant staff, plant-specific and 

industry operating experience, inspection, and testing (e.g., thermography). 

In its response dated January 30, 2015, the applicant stated that it revised the description in 

LRA Section B.1.31, “Non-EQ Insulated Cables and Connections,” to clarify how adverse 
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localized environments can be identified using an integrated approach. The method described 

in the LRA for identifying adverse localized environments, as revised, is consistent with the 

GALL Report. 

The staff finds the applicant’s response acceptable because the applicant provided a revision to 

LRA Section B.1.31 that combines the “plant spaces” approach with the integrated approach 

recommended in GALL Report AMP XI.E1. With the revision to LRA Section B.1.31, the staff 

concludes that the applicant’s Non-EQ Insulated Cables and Connections Program is consistent 

with GALL Report AMP XI.E1, “Insulation Material for Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The staff’s concern 

described in RAI B.1.31-1 is resolved. 

During the audit, the staff noted that a Calvert cable bus was installed in the station 

blackout/offsite power recovery path from the SS 65 transformer to 4160 bus 65 but was not 

identified in the applicant’s LRA or basis documents as being age managed during the period of 

extended operation. The staff also observed a large number of birds on and around the Calvert 

cable bus, SS 64 transformer, and 4160 bus 65 that, if left unmanaged, could potentially result 

in accelerated age degradation of these components due to bird-debris contamination. 

The staff requested that that the Region III consider the above concerns when developing the 

71002 inspection. Subsequently, as part of the inspection, the staff requested that the applicant 

address the potential for bird debris to degrade the Calvert cable bus, metallic tray structure, 

spacers, and insulators and identify the LRA AMP(s) intended to manage the potential aging 

mechanisms and effects. As documented in Inspection Report 05000341/2015109 (ADAMS 

Accession No. ML15162B041), the applicant committed to update adverse localized 

environments to include chemical contamination from bird droppings. The applicant issued 

CARD 15-23107, “Revisions to LRA Resulting from April 2015 NRC Inspection 71002,” to 

resolve the issue. By letter dated May 19, 2015, the applicant submitted NRC-15-0056, 

“Response to NRC RAI for the Review of the Fermi 2 LRA – Set 32.” Under Enclosure 5, 

“Additional License Renewal Application Revisions from April 2015 NRC Inspection,” the 

applicant revised the LRA to include contamination (e.g., bird debris in contact with cable in the 

bus enclosure) as a condition resulting in an adverse localized environment. Specifically, the 

applicant incorporated the following changes to the Non-EQ Insulated Cables and Connections 

Program: 

 a revision to Supplement A.1.31, “Non-EQ Insulated Cables and Connections Program,” 

to the final safety analysis report (FSAR) that includes “chemical contamination (i.e., bird 

droppings)” as an adverse localized environment 

 a modification to the LRA Section B.1.31, “Non-EQ Insulated Cables and Connections 

Program,” description that includes “chemical contamination (i.e., bird droppings)” as an 

adverse localized environment 

 a revision to LRA Section A.4, Commitment No. 24, “Non-EQ Insulated Cables and 

Connections,” that includes “chemical contamination (i.e., bird droppings)” as an adverse 

localized environment 

Inspection Report 05000341/2015109 (ADAMS Accession No. ML15162B041) concludes that 

implementation of the Non-EQ Insulated Cables and Connections Program as described in the 

LRA, should provide reasonable assurance that aging effects will be managed, consistent with 

the license basis, for the period of extended operation. The staff finds the applicant’s response 

acceptable because the applicant modified LRA Section B.1.31, “Non-EQ Insulated Cables and 
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Connections Program”; revised FSAR Supplement A.1.31, “Non-EQ Insulated Cables and 

Connections Program”; and revised LRA Section A.4, Commitment No. 24, “Non-EQ Insulated 

Cables and Connections,” to include chemical contamination (bird droppings) as an adverse 

localized environment. With the addition of chemical contamination, the potential aging 

mechanism of bird debris will be adequately age managed during the period of extended 

operation. The staff’s concern described in Inspection Report 05000341/2015109 (ADAMS 

Accession No. ML15162B041) is resolved. 

Based on its audit and review of the applicant’s response to RAI B.1.31-1, and response letter 

dated May 19, 2015, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.E1. 

Operating Experience. LRA Section B.1.31 summarizes operating experience related to the 

Non-EQ Insulated Cables and Connections Program. The LRA identified plant operating 

experience examples. A summary of the operating experience is given below. 

In 2009 cable heat damage was identified in the limit switch compartment of a feedwater heater 

inlet isolation valve. Degraded and damaged cables were replaced, and surrounding cables 

were inspected and evaluated in the subsequent corrective action work order in 2010. 

Age-related cable brittleness was identified in 2006. Work requests were initiated to replace 

degraded cables on the turbine valve unitized actuators. Cable replacements were completed 

in 2009 and 2012. 

The staff’s review of plant operating experience identified corrective actions, including 

performing cable condition walkdowns to identify cables in close proximity to high-temperature 

equipment, the identification of cables that may be operating above ampacity limits, the 

replacement of motor operator heat-damaged control cable, and the establishment of a 

cable-monitoring program. 

The staff reviewed operating experience information during the audit to determine whether the 

applicable aging effects and industry and plant-specific operating experience were reviewed by 

the applicant. As discussed in the Audit Report, the staff conducted an independent search of 

the plant operating experience information to determine whether the applicant had adequately 

evaluated and incorporated operating experience related to this program. During its review, the 

staff did not identify any operating experience that would indicate that the applicant should 

consider modifying its proposed program. 

Based on its audit and review of the application, and response letter dated May 19, 2015, the 

staff finds that the applicant has appropriately evaluated plant-specific and industry operating 

experience. In addition, the staff finds that the conditions and operating experience at the plant 

are bounded by those for which GALL Report AMP XI.E1 was evaluated. 

UFSAR Supplement. LRA Section A.1.31 provides the UFSAR supplement for the Non-EQ 

Insulated Cables and Connections Program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. 

The staff also noted that the applicant committed (Commitment No. 24) to implement the new 

Non-EQ Insulated Cables and Connections Program before September 20, 2024, or at the end 
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of the last RFO before March 20, 2025, for managing the effects of aging for applicable 

components. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Non-EQ Insulated Cables 

and Connections Program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 One-Time Inspection 

Summary of Technical Information in the Application. LRA Section B.1.33, as amended by 

letters dated April 27, 2015, and June 9, 2015, describes the new One-Time Inspection Program 

as consistent with GALL Report AMP XI.M32, “One-Time Inspection.” The LRA states that the 

AMP consists of one-time NDEs of selected components for each material-environment-aging 

effect population to verify that unacceptable degradation is not occurring. The specific aging 

effects addressed by the program are loss of material, reduction of heat transfer, and cracking. 

The LRA also states that the AMP will verify the effectiveness of Diesel Fuel Monitoring, Oil 

Analysis, and Water Chemistry Control BWR programs. In addition, the AMP will include 

inspections of the stainless steel reactor vessel flange leak-off piping, valve body, the 

mechanical draft cooling tower (MDCT) galvanized spray headerspray piping, and a 

representative sample of internal and external surfaces of core spray, RHR, high-pressure 

coolant injection (HPCI) turbine exhaust, nuclear pressure relief, and reactor core isolation 

cooling piping that passes through the waterline region of the suppression pool. Additionally, 

the LRA states that a representative sample of internal surfaces of the normally dry suppression 

chamber spray piping that is periodically wetted by the RHR system testing will be inspected by 

the One-Time Inspection Program. The one-time inspections will be conducted in the 10 years 

before entering the period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M32. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M32. 

Operating Experience. LRA Section B.1.33 states that the One-Time Inspection Program is a 

new program and that industry operating experience will be considered during implementation. 

The staff reviewed operating experience during the audit to determine whether the applicable 

aging effects and industry operating experience were reviewed by the applicant. As discussed 

in the Audit Report, the staff conducted an independent search of the plant operating 

experience. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. The staff finds that 
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the conditions and operating experience at the plant are bounded by those for which GALL 

Report AMP XI.M32 was evaluated. 

UFSAR Supplement. LRA Section A.1.33, as amended by letters dated April 27, 2015, and 

June 9, 2015, provides the UFSAR supplement for the One-Time Inspection Program. The staff 

reviewed this UFSAR supplement description of the program and noted that it is consistent with 

the recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed to conduct the inspections covered by the One-Time Inspection Program within the 

10 years before March 20, 2025. The staff finds that the information in the UFSAR supplement 

is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 One-Time Inspection – Small-Bore Piping 

Summary of Technical Information in the Application. LRA Section B.1.34 describes the new 

One-Time Inspection – Small-Bore Piping Program as consistent with GALL Report 

AMP XI.M35, “One-Time Inspection of ASME Code Class 1 Small-Bore Piping.” The applicant 

stated that this program will augment ASME Code Section XI requirements and will be 

applicable to ASME Code Class 1 piping and components with a nominal pipe size (NPS) 

diameter less than 4 inches and greater than or equal to 1 inch in systems that have not 

experienced cracking. The applicant also stated it has not experienced cracking of ASME Code 

Class 1 small-bore piping due to stress corrosion, cyclical loading, thermal stratification, and 

thermal turbulence. The applicant further stated that the program will provide for a one-time 

volumetric or opportunistic destructive (for socket welds only) inspection of weld locations that 

are susceptible to cracking. The applicant stated that because it does not have more than 

30 years of operation at the time of submitting its LRA, its inspections would include 10 percent 

of the weld population or a maximum of 25 welds from each type of weld (e.g., full penetration 

or socket weld). 

In addition, the applicant stated that volumetric examinations will be performed using a 

demonstrated technique capable of detecting cracking. The applicant further stated that the 

program will include pipes, fittings, branch connections, and full and partial penetration welds. 

The applicant also stated that the program’s sampling approach will be based on susceptibility 

to stress corrosion; cyclic loading, including thermal, mechanical, and vibration fatigue; thermal 

stratification; thermal turbulence; and failure history. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared elements 1 through 6 of the applicant’s program to the 

corresponding elements of GALL Report AMP XI.M35. For the “detection of aging effects” 

program element, the staff determined the need for additional information, which resulted in the 

issuance of an RAI, as discussed below. 
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The staff noted that the LRA does not provide the total population of in-scope welds. GALL 

Report AMP XI.M35 states under the “detection of aging effects” program element that “[t]his 

inspection should be performed at a sufficient number of locations to ensure an adequate 

sample. This number, or sample size, is based on susceptibility, inspectability, dose 

considerations, operating experience, and limiting locations of the total population of ASME 

Code Class 1 small-bore piping locations.” It was not clear to the staff how the inspection 

sample will be selected and thus whether a sufficient number of locations will be inspected to 

ensure that cracking will be adequately managed. 

By letter dated December 19, 2014, the staff issued RAI B.1.34-1 requesting that the applicant 

provide the population of in-scope small-bore piping welds for each weld type (e.g., butt welds 

and socket welds). The applicant was asked to justify the adequacy of the selected sample size 

for each type of weld based on the population of in-scope welds. 

In its response dated January 28, 2015, the applicant stated that, in total, there are 

approximately 4,200 in-scope small-bore piping welds. The applicant also stated that 4,000 of 

those are socket welds, whereas 200 are butt welds. The applicant further stated that EPRI 

TR-107514, “Age Related Degradation Inspection Method and Demonstration,” describes a 

sampling program. The applicant stated that, by using the mathematical analysis in EPRI 

TR-107514, it was determined that, in order to provide a 90-percent confidence that 90 percent 

of a given population has no degradation, an inspection plan for a large population should have 

a sample size of 25. The applicant stated that based on this analysis, 25 is the maximum 

number of inspections recommended for each weld type. 

The staff noted that the applicant’s response provided specific information on the total number 

of small-bore piping weld populations for butt welds and socket welds. The staff also noted that 

the applicant provided justification on its sampling methodology to adequately select the proper 

inspection sample size for the population of its small-bore piping welds. The staff finds the 

applicant’s response acceptable (1) because, based on the applicant’s plant-specific operating 

experience (i.e., less than 30 years of operation at the time of application for license renewal 

and no incidence of failures observed for its ASME Code Class 1 small-bore piping), its sample 

size is consistent with the guidance provided in GALL Report AMP XI.M35, which recommends 

that the inspection plan should include 10 percent of the weld population or a maximum of 

25 welds for each weld type, and (2) because the applicant justified its inspection sample size 

for its weld population through analyses. The staff’s concern described in RAI B.1.34-1 is 

resolved. 

Based on its audit and review of the applicant’s response to RAI B.1.34-1, the staff finds that 

elements 1 through 6 for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M35. 

Operating Experience. LRA Section B.1.34 summarizes operating experience related to the 

One-Time Inspection-Small-Bore Piping Program. The applicant stated that it does not have 

any operating experience related to cracking of ASME Code Class 1 small-bore piping. The 

LRA states that industry operating experience will be considered in its application of the 

program. The LRA also states that plant-specific operating experience will be gained as the 

program is executed and will be factored into the program through its corrective action and QA 

programs. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 
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experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience that would indicate 

that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M35 was evaluated. 

UFSAR Supplement. LRA Section A.1.34 provides the UFSAR supplement for the One-Time 

Inspection – Small-Bore Piping Program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the corresponding program 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed to 

implementing the new One-Time Inspection – Small-Bore Piping Program within 6 years before 

entering the period of extended operation. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection – 

Small-Bore Piping Program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Selective Leaching 

Summary of Technical Information in the Application. LRA Section B 1.40 describes the new 

Selective Leaching Program as consistent with GALL Report AMP XI.M33, “Selective 

Leaching,” as modified by LR-ISG-2011-03. The LRA states that the program addresses gray 

cast iron and copper alloy (with greater than 15-percent zinc or greater than 8-percent 

aluminum) components susceptible to selective leaching exposed to raw water, treated water, 

waste water, or soil to manage the effects of loss of material. The LRA also states that it will 

manage this aging effect through a one-time visual inspection of a selected sample population 

of each material and environment combination, coupled with a hardness measurement or other 

mechanical examination techniques. The LRA states that the inspection population will consist 

of 20 percent of each population with the same material and environment with a maximum size 

of 25 components. The LRA also states that, where practical, the components would be 

selected from those bounding or leading components most susceptible to aging due to time in 

service, severity of operating condition, and lowest design margin. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M33. Based on its audit, the staff 

finds that program elements 1 through 6 for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M33. 
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Operating Experience. LRA Section B.1.40 summarizes operating experience related to 

selective leaching and states that no occurrences of selective leaching have been identified at 

Fermi 2. The staff reviewed operating experience information in the application and during the 

audit to determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience, and the program, 

when implemented, will adequately manage the effects of aging due to selective leaching. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M33 was evaluated. 

UFSAR Supplement. LRA Section A.1.40 provides the UFSAR supplement for the Selective 

Leaching Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to implement the new Selective Leaching Program 

within the 5 years before the period of extended operation. The staff finds that the information 

in the UFSAR supplement is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Selective Leaching Program, 

the staff concludes that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Water Chemistry Control – BWR 

Summary of Technical Information in the Application. LRA Section B.1.43, as amended by 

letter dated June 26, 2015, describes the existing Water Chemistry Control – BWR Program as 

consistent, with an exception, with GALL Report AMP XI.M2, “Water Chemistry.” The LRA 

states that the AMP manages loss of material, cracking, and fouling in components exposed to 

a treated water environment. The AMP proposes to manage these aging effects through 

monitoring and control of water chemistry parameters consistent with guidance in EPRI 

Report 3002002623, “BWRVIP-190: BWR Vessel and Internals Project, BWR Water Chemistry 

Guidelines – 2015 Revision.” The LRA also states that one-time inspections of a representative 

sample will be performed, including components in low and stagnant flow areas, to verify the 

effectiveness of the Water Chemistry Control – BWR Program. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M2. 

Exception. LRA Section B.1.43 includes an exception to the “Program Description” of the Water 

Chemistry Control – BWR Program. In this exception, the applicant stated that “EPRI reports 
3-56 

such as ‘BWR Water Chemistry Guidelines’ are industry reports, which are reviewed and 

revised by industry experts to incorporate recent industry operating experience and best 

practices.” Additionally, the applicant stated that Fermi 2 will be using EPRI Report 

3002002623, BWRVIP-190, “BWR Water Chemistry Guidelines,” Revision 1, rather than the 

GALL Report recommendation BWRVIP-190, EPRI 1016579. The staff reviewed this exception 

against the corresponding program elements in GALL Report AMP XI.M2 and finds it 

acceptable because Revision 1 to the BWRVIP-190, “BWR Water Chemistry Guidelines,” 

incorporates the latest industry operating experience and best practices. Additionally, the 

BWRVIP-190, “BWR Water Chemistry Guidelines,” Revision 1, does not take away or relax any 

of the relevant guidelines from the previous revision. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M2. The staff also reviewed the exception associated with 

the “Program Description” of the Water Chemistry Control – BWR Program and the justification 

and finds that the AMP, with the exception, is adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.43 summarizes operating experience related to the 

Water Chemistry Control – BWR Program. A few of the recent examples are summarized 

below. 

In 2011, during startup from a planned outage, chemistry samples indicated an increase in 

condensate chlorides and conductivity. These levels continued to increase, indicating 

circulating water inleakage to the main condenser. In accordance with the plant’s chemistry 

guidelines, an orderly plant shutdown was initiated, and subsequent repairs were made to the 

main condenser. 

In 2011, the online noble chemistry durability coupon was analyzed to determine platinum 

deposition, and results were compared with industry data. The measured platinum deposition 

was 0.02 μg/cm2 and is midrange within the industry database. Testing was performed to 

determine the optimum hydrogen water chemistry concentration. 

An evaluation was performed in March 2012 to document the impact of October 2010 to 

March 2012 chemistry transients against vessel internals, Class 1 piping, and nuclear fuel. The 

evaluation concluded that the impact of the Fermi 2 chemistry transients on the RPV, vessel 

internals, stainless steel piping (such as recirculation piping), control rod blade components, and 

fuel components was negligible. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 
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addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M2 was evaluated. 

UFSAR Supplement. LRA Section A.1.43 provides the UFSAR supplement for the Water 

Chemistry Control – BWR Program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry Control – 

BWR Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or Enhancements 

In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with 

the GALL Report, with exceptions or enhancements: 

 Bolting Integrity 

 Boraflex Monitoring 

 BWR Vessel Internals 

 Compressed Air Monitoring 

 Containment Inservice Inspection – IWE 

 Diesel Fuel Monitoring 

 External Surfaces Monitoring 

 Fatigue Monitoring 

 Fire Protection 

 Fire Water System 

 Flow-Accelerated Corrosion 

 Inservice Inspection – IWF 

 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

 Masonry Wall 

 Neutron-Absorbing Material Monitoring 

 Oil Analysis 

 Protective Coating Monitoring and Maintenance 
3-58 

 Reactor Head Studs 

 Reactor Vessel Surveillance 

 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

 Service Water Integrity 

 Structures Monitoring 

 Water Chemistry Control – Closed Treated Water Systems 

 Coating Integrity 

For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s) 

and/or enhancement(s), the staff performed an audit and review to confirm that those attributes 

or features of the program for which the applicant claimed consistency with the GALL Report 

are indeed consistent. The staff reviewed the exceptions to the GALL Report to determine 

whether they are acceptable and adequate. The staff also reviewed the enhancements to 

determine whether they will make the AMP consistent with the GALL Report AMP to which it is 

compared. The results of the staff’s audits and reviews are documented in the following 

sections. 

 Bolting Integrity 

Summary of Technical Information in the Application. LRA Section B.1.2, as revised by letters 

dated January 20, 2015, and February 12, 2015, describes the existing Bolting Integrity 

Program as consistent, with exceptions and enhancements, with GALL Report AMP XI.M18, 

“Bolting Integrity.” The LRA states that the AMP addresses safety-related and nonsafety-related 

accessible closure bolting of pressure-retaining components to manage the effects of loss of 

preload, cracking, and loss of material. The LRA also states that the AMP proposes to manage 

these aging effects through preventive actions and inspection activities, including using 

materials that have an actual yield strength that is less than 150 ksi, restricting the use of 

molybdenum disulfide (MoS2) lubricant, applying an appropriate preload, and checking 

uniformity of gasket compression. The AMP also proposes to manage these aging effects 

through visual examinations made during periodic system walkdowns and inspections 

performed at least once per RFO. The AMP supplements the inspection activities required by 

ASME Code Section XI for ASME Code Class 1, 2, 3 bolting and uses the GALL Report 

recommended guidance in NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting 

Degradation or Failure in Nuclear Power Plants,” dated June 1990; EPRI NP-5769, 

“Degradation and Failure of Bolting in Nuclear Power Plants,” dated April 1988; and EPRI 

TR-104213, “Bolted Joint Maintenance & Applications Guide,” dated December 1995. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M18. For the “parameters 

monitored or inspected” and “detection of aging effects” program elements, the staff determined 

the need for additional information, which resulted in the issuance of an RAI, as discussed 

below. 

The “parameters monitored or inspected” program element in GALL Report AMP XI.M18 

recommends that “bolting for safety-related pressure retaining components [be] inspected for 

leakage, loss of material, cracking, and loss/of preload [...]. Bolting for other pressure retaining 

components is inspected for signs of leakage.” The “detection of aging effects” program 
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element recommends that periodic inspections of pressure-retaining closure bolting should be 

performed at least once per refueling cycle for signs of leakage to ensure the detection of 

age-related degradation due to loss of material and loss of preload. During its audit, the staff 

found that the applicant’s Bolting Integrity Program states that it “manages loss of preload, 

cracking, and loss of material for accessible closure bolting for safety-related and 

nonsafety-related pressure components.” The LRA also states that periodic system walkdowns 

and inspections of accessible bolting will ensure the identification of loss of preload (leakage), 

cracking, and loss of material. The staff noted that GALL Report AMP XI.M18 does not make a 

distinction between accessible and inaccessible closure bolting in its recommendations to 

inspect and detect the effects of aging in closure bolts. The staff noted that there appeared to 

be a distinction made in the applicant’s Bolting Integrity Program that the program would 

manage aging effects for accessible closure bolting. The staff could not determine whether the 

applicant planned also to manage the effects of aging on inaccessible pressure-retaining 

closure bolting within the scope of license renewal, consistent with the recommendations in the 

“parameters monitored or inspected” and “detection of aging effects” program elements of GALL 

Report AMP XI.M18. Therefore, by letter dated December 19, 2014, the staff issued 

RAI B.1.2-1 requesting that the applicant clarify whether the Bolting Integrity Program will 

manage the aging effects for inaccessible pressure-retaining closure bolting consistent with the 

recommendations in GALL Report AMP XI.M18. If inaccessible closure bolting would not be 

managed consistent with the recommendations in GALL Report AMP XI.M18, the staff also 

requested that the applicant explain what is considered inaccessible closure bolting and 

describe how the effects of aging will be adequately managed. 

In its response dated January 20, 2015, the applicant stated that, for the management of the 

aging effects of safety-related and nonsafety-related pressure-retaining closure bolting under 

the Bolting Integrity Program, no distinction will be made between accessible and inaccessible 

bolting. The applicant also stated that closure bolting will be inspected for leakage, evidence of 

past leakage, and other signs of degradation during walkdowns and maintenance activities of 

systems within the scope of license renewal as recommended by GALL Report AMP XI.M18. 

The applicant also revised LRA Sections A.1.2 (UFSAR supplement); B.1.2; and Table A.4, 

“License Renewal Commitment List,” Commitment No. 4, to remove the word “accessible” from 

the description and enhancements to the Bolting Integrity Program. The staff finds the 

applicant’s response acceptable because it clarified that the Bolting Integrity Program will follow 

GALL Report AMP XI.M18 recommendations to inspect accessible and inaccessible closure 

bolting for loss of material, cracking, and loss of preload and to periodically inspect for leakage. 

The staff finds that this is consistent with the “parameters monitored or inspected,” and 

“detection of aging effects” program elements of GALL Report AMP XI.M18. The staff’s concern 

described in RAI B.1.2-1 is resolved. 

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “corrective actions,” and “administrative controls” 

program elements associated with the exceptions and enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these exceptions and enhancements follows. 

Exception 1. LRA Section B.1.2 includes an exception to the “detection of aging effects” 

program element. In this exception the applicant stated that buried bolting in the fire water 

system “is inspected if excavated for maintenance or other activities.” The exception includes a 

note stating that the bolting in the buried fire water system is only managed for loss of preload 

and that the Bolting Integrity Program has been effective in managing this aging effect through 

preventive measures that are taken before burial, including (1) verifying correct material, 
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(2) checking uniformity of the gasket compression after assembly, (3) using preventive coating, 

and (4) applying an appropriate preload. The staff reviewed LRA Section B.1.4, “Buried and 

Underground Piping,” and LRA Section B.1.19, “Fire Water System,” and noted that these 

AMPs will be consistent with the recommendations in GALL Report AMPs XI.M41, “Buried and 

Underground Piping and Tanks,” and XI.M27, “Fire Water System,” respectively. The staff’s 

evaluation of the Buried and Underground Piping Program and Fire Water System Program are 

discussed in Sections 3.0.3.1.2 and 3.0.3.2.10, respectively. The staff noted that buried piping 

system bolting will be managed for loss of material under the new Buried and Underground 

Piping Program. Through the Buried and Underground Piping Program the applicant will 

perform visual examinations to detect the aging effect of loss of material in buried piping system 

bolting whenever the associated piping becomes accessible. The staff also noted that the 

existing Fire Water System Program continuously monitors the required operating pressure of 

the fire water system consistent with the guidelines in the National Fire Protection Association 

Standard 25, “Standard for the Inspection, Testing, and Maintenance of Water-Based Fire 

Protection Systems” (NFPA 25) (2011 Edition), and that corrective actions are taken whenever 

loss of system pressure is detected to ensure that the system maintains its intended function. 

The staff reviewed this exception against the corresponding program element in GALL Report 

AMP XI.M18 and finds it acceptable because of the following three factors: 

(1) The Bolting Integrity Program has preventive measures in place that are consistent with 

GALL Report AMP XI.M18 to prevent loss of preload. 

(2) As recommended by GALL Report AMP XI.M41, the buried bolts will be visually 

inspected for the aging effect of loss material through the Buried and Underground 

Piping Program. 

(3) The actions taken to prevent loss of preload and the opportunistic inspections for loss of 

material in combination with the GALL Report-recommended Fire Water System 

Program continuous monitoring of the fire water system pressure provide reasonable 

assurance that degradation associated to the buried bolts that may affect the system 

pressure (e.g., leakage) will be identified and that corrective actions will be taken before 

there is a loss of the intended function. 

Exceptions 2 and 3. LRA Section B.1.2, as revised by letter dated February 12, 2015, includes 

two exceptions to the “detection of aging effects” program element. Exception 2 states that the 

lube oil pump bolting and other submerged bolting in the safety-related control center heating, 

ventilating, and air conditioning (CCHVAC) system, which has an external environment of lube 

oil, will be inspected during scheduled disassembly and PM activities. Exception 3 states that 

the nonsafety-related CTG system lube oil pump bolting and other submerged closure bolting in 

the lube oil sump will be inspected on an opportunistic basis. The staff noted that these are 

exceptions to GALL Report AMP XI.M18 recommendation to perform periodic inspections, at 

least once per RFO, of closure bolting to detect loss of material and loss of preload. The GALL 

Report Table XI.D, “Selected Definitions & Use of Terms for Describing and Standardizing 

Environments,” states that steel, when exposed to lubricating oil with some water, will have 

limited susceptibility to aging degradation due to general or localized corrosion. Before the 

applicant’s addition of these exceptions to the LRA, the staff identified concerns regarding how 

the program will be capable of detecting loss of material and loss of preload in the submerged 

bolts before a loss of intended function and, by letter dated January 14, 2015, issued 

RAI 3.3.2.9-1. The staff’s concerns associated with RAI 3.3.2.9-1 are resolved, and SER 

Section 3.3.2.3.9 documents its discussion of these concerns. The staff reviewed these 

exceptions against the corresponding program element in GALL Report AMP XI.M18. Based on 
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its review of the exceptions and information provided in the applicant’s response to 

RAI 3.3.2.9-1, the staff finds Exceptions 2 and 3 acceptable because of the following: 

 The Bolting Integrity Program has preventive actions in place, such as selection of 

materials and lubricants, application of the appropriate preload, and checking for 

uniformity of gasket compression, which are consistent with GALL Report AMP XI.M18 

recommendations to prevent loss of material and loss of preload. 

 As stated in the GALL Report, steel components exposed to lubricating oil have limited 

susceptibility to general and localized corrosion. 

 The submerged closure bolts will be subject to opportunistic visual inspections under the 

Bolting Integrity Program, and these visual inspections will be capable of detecting the 

aging effects of loss material and loss of preload. 

 As discussed in SER Section 3.3.2.3.9, the periodic monitoring of the lube oil pressure 

every 12 hours for the CCHVAC system pump and once a month for the CTG system 

pump in combination with the preventive actions taken and opportunistic inspections to 

be performed under the Bolting Integrity Program provide reasonable assurance that 

degradation associated to the submerged bolts will be identified and that corrective 

actions will be taken before there is a loss of intended function. 

Enhancement 1. LRA Section B.1.2 includes an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that the Bolting Integrity Program 

procedures will be revised to make sure that, when high strength bolting material is acquired, its 

actual yield strength is considered and also to monitor acquired closure bolting of 

pressure-retaining components for cracking if its actual yield strength is greater than or equal to 

150 ksi. The “preventive actions” program element of GALL Report AMP XI.M18 recommends 

using bolting material with an actual measured yield strength limited to less than 150 ksi. GALL 

Report AMP XI.M18 also recommends that high strength bolting with actual yield strength 

greater than or equal to 150 ksi be monitored for cracking. The staff noted that the applicant 

also has enhanced the “parameters monitored or inspected” (Enhancement 2) and “detection of 

aging effects” (Enhancement 3) program elements of the Bolting Integrity Program to monitor for 

cracking and perform volumetric examinations consistent with the ASME Code Section XI for 

closure bolting with actual yield strength greater or equal to 150 ksi. The staff reviewed this 

enhancement against the program elements in GALL Report AMP XI.M18. The staff finds this 

enhancement acceptable because, although it may not preclude the use of high strength bolting 

with actual yield strength greater than or equal to 150 ksi, when implemented, the applicant will 

consider the actual yield strength of acquired high strength closure bolts and, if it is equal or 

greater than 150 ksi, will monitor the high strength closure bolts for cracking consistent with the 

recommendations in GALL Report AMP XI.M18. 

Enhancement 2. LRA Section B.1.2, as revised by letter dated January 20, 2015, includes an 

enhancement to the “parameters monitored or inspected” program element. In this 

enhancement, the applicant stated that the procedures of the Bolting Integrity Program will be 

revised to state that safety-related closure bolting for pressure-retaining components “is 

inspected for leakage, loss of material, and loss of preload/loss of prestress.” The 

enhancement also states that closure bolting with actual yield strength greater or equal to 

150 ksi will be monitored for cracking. The “parameters monitored or inspected” program 

element of GALL Report AMP XI.M18 recommends that safety-related closure bolting be 

inspected for leakage, loss of material, and loss of preload/loss of prestress. GALL Report 

AMP XI.M18 also recommends that high strength closure bolting with yield strength greater than 
3-62 

or equal to 150 ksi should be monitored for cracking. The staff reviewed this enhancement 

against the corresponding program element in GALL Report AMP XI.M18 and finds it 

acceptable because, when it is implemented, the Bolting Integrity Program will inspect for 

leakage, loss of material, and loss of preload/loss of prestress of safety-related closure bolting 

and will inspect for cracking of high strength closure bolting consistent with the 

recommendations in GALL Report AMP XI.M18. 

Enhancement 3. LRA Section B.1.2, as revised by letter dated January 20, 2015, includes an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the procedures of the Bolting Integrity Program will be revised to do the 

following: (1) implement the recommendations in NUREG-1339, EPRI NP-5769, and EPRI 

TR-104213 for closure bolting of pressure-retaining components, (2) state that ASME and 

non-ASME Code Class bolted connections will be inspected at least once per refueling cycle, 

and (3) include volumetric examination for closure bolting with actual yield strength greater or 

equal to 150 ksi, in accordance with ASME Code Section XI, Table IWB-2500-1, “Examination 

Categories,” and regardless of code classification. The “detection of aging effects” program 

element of GALL Report AMP XI.M18 recommends bolting inspections to include the applicable 

guidance for pressure boundary bolting in NUREG-1339, EPRI NP-5769, and EPRI TR-104213. 

GALL Report AMP XI.M18 “detection of aging effects” program element also recommends 

periodic system inspections (at least once per RFO) of ASME Code and non-ASME Code Class 

bolting, as well as volumetric inspections of high strength closure bolting (actual yield strength 

greater than or equal to 150 ksi), in accordance with ASME Code Section XI, 

Table IWB-2500-1. The staff reviewed this enhancement against the corresponding program 

element in GALL Report AMP XI.M18 and finds it acceptable because, when it is implemented, 

the Bolting Integrity Program will (1) include guidance from staff and industry documents for the 

inspection of closure bolting, (2) perform inspections of closure bolting at least once per RFO, 

and (3) perform volumetric inspection of high strength bolts, consistent with the 

recommendations in GALL Report AMP XI.M18. 

Enhancement 4. LRA Section B.1.2 includes an enhancement to the “detection of aging effects” 

program element. In this enhancement, the applicant stated that the procedures of the Bolting 

Integrity Program will be revised to inspect, at least once every RFO, the RHR service water 

(RHRSW), emergency equipment service water (EESW), and emergency diesel generator 

service water (EDGSW) systems’ pump and valve bolting submerged in the RHRSW reservoir. 

GALL Report AMP XI.M18 recommends periodic inspections (at least once per refueling cycle) 

of closure bolting for signs of leakage to ensure the detection of age-related degradation due to 

loss of material and loss of preload. During its onsite review of the program basis documents, 

the staff noted that the program lacked information regarding how the inspections will detect the 

applicable aging effects on a submerged environment. The staff noted that a submerged 

environment limits the ability to detect leakage of submerged bolted connections; therefore, it is 

not clear how the program will detect loss of material and loss of preload in the submerged 

bolted connections before a loss of intended function. By letter dated December 19, 2014, the 

staff issued RAI B.1.2-2 requesting that the applicant describe how the program will detect loss 

of material and loss of preload in the submerged closure bolts within the scope of license 

renewal. The staff also requested that the applicant describe how the proposed bolting 

inspections will detect loss of material in crevice locations (e.g., threaded regions or the shank 

below the bolt heads) that are not readily visible. 

In its response dated January 20, 2015, the applicant stated that the loss of material and loss of 

preload aging effects in the submerged bolts will be adequately managed through the following 

activities: 
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 The applicant will take preventive measures that are consistent with the GALL Report, 

such as selecting material and lubricants, applying an appropriate preload, and checking 

for uniformity of the gaskets compression to reduce the potential of the aging effects. 

 The applicant will perform periodic visual inspections of the submerged bolting. Based 

on the applicant’s operating experience, these visual inspections, using divers, have 

been capable of detecting both loss of material and loss of preload and have resulted in 

corrective actions taken (e.g., bolt replacement, selection of new bolting material, and 

changes to service water chemical addition process to reduce corrosion) before a loss of 

intended function. 

 Trending of pump performance parameters during quarterly surveillance runs of the 

RHRSW, EESW, and EDGSW pumps would result in corrective actions being taken 

when there is pump degradation. Corrective actions would lead to pump maintenance 

(i.e., repair or refurbishment), during which the associated bolting, including bolting 

threads, would be inspected. 

As part of its response, the applicant also revised LRA Sections A.1.2, A.4 (Commitment No. 4), 

and B.1.2 to state that its enhancement (Enhancement 4) to the Bolting Integrity Program 

“detection of aging effects” program element will also include a revision to the AMP procedures 

to opportunistically inspect the threads of the submerged bolting in the RHRSW reservoir during 

maintenance activities. The staff reviewed the applicant’s response and noted that an 

opportunistic inspection approach may result in inspections not being done frequently enough to 

detect degradation of the bolt thread area of the submerged bolts before there is a loss of 

intended function or possibly not being done at all if no opportunity arises. SRP-LR 

Section A.1.2.3.10 states that the AMP frequency of inspections may be linked to plant-specific 

or industry wide operating experience, and a discussion should provide justification that the 

frequency is adequate to detect the aging effects before there is a loss of SC intended 

functions. The staff needed additional information to understand how opportunistic inspections 

based on pump maintenance activities will be adequate to detect loss of material in the thread 

region of the submerged bolts before there is a loss of intended function. Therefore, by letter 

dated April 2, 2015, the staff issued followup RAI B.1.2-2a requesting that the applicant provide 

the following information: 

(1) the number of times (including year) that maintenance activities (e.g., pump repair or 

refurbishment) have been performed for the RHRSW, EESW, and EDGSW systems with 

submerged bolting 

(2) the technical basis as to how the proposed inspections will ensure that the aging effects 

for the threaded area of the submerged bolting will be detected in a timely manner and 

will be adequately managed before there is a loss of intended function 

By letter dated April 27, 2015, the applicant provided its response to followup RAI B.1.2-2a. In 

its response to RAI B.1.2-2a, Part (1), the applicant provided the maintenance history for the 

pumps with submerged bolting by stating the following: 

 The RHRSW system pumps A, B, C, and D were replaced once in November 2005, 

July 2009, April 2010, and March 2011, respectively. 

 The EESW system pumps A and B were replaced once in February and October 2006, 

respectively. 
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 The EDGSW system pumps 11, 12, 13, and 14 were replaced once in November 2008, 

February 2005, May 2008, and October 2007, respectively. 

The applicant also stated that, although the systems’ pumps had no other significant repair or 

refurbishment, periodic inspections have resulted in corrective actions taken involving the 

replacement of individual submerged bolts. In Part (2) of the response the applicant stated that 

the current periodic inspections are capable of visually inspecting the head and exposed 

threads of some bolts. The applicant stated that because a portion of the bolt threads protrude 

beyond the flange, it is possible to perform visual inspections of those bolt thread areas. These 

visual inspections will be performed every RFO during the period of extended operation. In its 

response, the applicant provided photographs showing the configuration of a bolt joint 

connection with bolt threads protruding from the joint. The photographs also showed an 

example of the degradation found on a bolt. The applicant stated that degradation of the bolt 

heads and exposed threads have been identified through visual inspections and that corrective 

actions were taken to remove and replace the bolts. The applicant also stated the following: 

Visual inspection of the degraded bolts after their removal has indicated that the 

worst degradation occurs on the bolt head and threads that are exposed. [...]. 

As a result, the exposed bolt head and threads that are visually inspected on a 

periodic basis provide the leading indication of degradation and bound the 

condition of the bolt threads in the non-exposed, load-bearing portion of the bolts 

(i.e., inside the flange). For this reason, aging effects in the threaded area of the 

submerged bolting will be detected in a timely manner and adequately managed 

prior to loss of intended function. When degradation of the exposed bolting is 

discovered during periodic inspections, the bolting will be replaced in accordance 

with the corrective action program [...]. 

The applicant further stated that maintenance activities of the RHRSW, EESW, and EDGSW 

pumps have been done at least once in the first 25 years of plant operation; therefore, “it is 

expected that pump maintenance will occur again during the period of extended operation.” 

During this maintenance, the applicant will opportunistically inspect the submerged bolting, 

including the bolt threads in the non-exposed region. 

The staff finds the enhancement and applicant responses to RAIs B.1.2-2 and B.1.2-2a 

acceptable because of the following: 

 Preventive actions, such as selecting material and lubricants, applying an appropriate 

preload, and checking for uniformity of the gaskets compression, will be taken consistent 

with GALL Report AMP XI.M18 recommendations to minimize the potential of loss of 

preload and lubricant-related degradation. 

 Periodic visual inspections of the leading areas of submerged bolting degradation 

(i.e., bolt head and exposed bolt threads) at Fermi 2 are capable of detecting loss of 

material and loss of preload and will be performed at least once every RFO consistent 

with GALL Report AMP XI.M18 recommendations. 

 Monitoring and trending of pump performance parameters during quarterly surveillance 

runs can result in the detection of age-related degradation of the submerged bolting. 

 Based on the applicant’s operating experience associated with the maintenance 

activities of the pumps, it is likely that the opportunistic inspection of the bolts, including 
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the non-exposed area of the bolt threads, will be performed at least once during the 

period of extended operation. 

 The staff has reasonable assurance that the combination of activities described above 

are able to detect and adequately manage the aging effects for the submerged bolts in 

the RHRSW, EESW, and EDGSW systems before there is a loss of intended function. 

The staff’s concerns associated to RAIs B.1.2-2 and B.1.2-2a are resolved. 

Enhancement 5. LRA Section B.1.2 includes an enhancement to the “corrective actions” 

program element. In this enhancement, the applicant stated that the procedures of the Bolting 

Integrity Program will be revised to include the recommendations in EPRI NP-5769 and EPRI 

TR-104213 for the replacement of ASME Code Class bolting and other (i.e., non-ASME Code 

Class) pressure-retaining bolting, respectively. The “corrective actions” program element of 

GALL Report AMP XI.M18 recommends using the additional guidance of EPRI NP-5769 for the 

replacement of ASME Code pressure-retaining bolting and using the guidelines of EPRI 

TR-104213 for the replacement of other pressure-retaining bolting. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M18 and 

finds it acceptable because, when it is implemented, the Bolting Integrity Program procedures 

will incorporate the guidance in EPRI NP-5769 and EPRI TR-104213 for the replacement of 

ASME and non-ASME Code Class pressure-retaining bolting, consistent with the 

recommendations in GALL Report AMP XI.M18. 

Enhancement 6. LRA Section B.1.2 includes an enhancement to the “administrative controls” 

program element. In this enhancement, the applicant stated that the procedures of the Bolting 

Integrity Program will be revised “to stipulate that administrative controls are in accordance with 

the Fermi 2 10 CFR [Part] 50 Appendix B Quality Assurance Program.” The “administrative 

controls” program element of GALL Report AMP XI.M18 states that the requirements of 

Appendix B to 10 CFR Part 50 are acceptable to address the administrative controls. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.M18 and finds it acceptable because, when it is implemented, the administrative 

controls of the Bolting Integrity Program will be in accordance with Appendix B to 

10 CFR Part 50, consistent with the recommendations in GALL Report AMP XI.M18. 

Enhancements 7 and 8. LRA Section B.1.2, as revised by letter dated February 12, 2015, 

includes an enhancement to the “detection of aging effects” program element. In 

Enhancement 7, the applicant stated that to ensure that loss of material in crevice locations can 

be detected, the AMP procedures will be revised to ensure that loss of material in crevice 

locations can be detected and to perform opportunistic inspections of the CCHVAC system 

safety-related closure bolting, including the bolting threads, exposed to a lube oil environment. 

In Enhancement 8, the applicant stated that the AMP procedures will be revised to “perform 

opportunistic inspections for CTG system nonsafety-related pressure-retaining bolting in a lube 

oil external environment.” 

The staff noted that GALL Report Table IX.D states that steel, when exposed to lubricating oil 

with some water, will have limited susceptibility to aging degradation due to general or localized 

corrosion. Before the applicant’s addition of these enhancements to the LRA, the staff identified 

concerns regarding how the program will be capable of detecting loss of material and loss of 

preload in the submerged bolts before a loss of intended function and, by letter dated 

January 14, 2015, issued RAI 3.3.2.9-1 to request additional information. The staff’s concerns 
3-66 

associated with RAI 3.3.2.9-1 are resolved, and SER Section 3.3.2.3.9 documents its discussion 

of these concerns. 

The staff reviewed Enhancements 7 and 8 against the corresponding program element in GALL 

Report AMP XI.M18. Based on its review of the enhancements and information provided in the 

applicant’s response to RAI 3.3.2.9-1, the staff finds Enhancements 7 and 8 acceptable 

because of the following: 

 The Bolting Integrity Program has preventive actions in place, such as selecting material 

and lubricants, applying an appropriate preload, and checking for uniformity of the 

gaskets compression, that are consistent with GALL Report AMP XI.M18 to prevent loss 

of material and loss of preload. 

 As stated in the GALL Report, steel components exposed to lubricating oil have limited 

susceptibility to general and localized corrosion. 

 The submerged closure bolts will be subject to opportunistic visual inspections under the 

Bolting Integrity Program, and these visual inspections will be capable of detecting the 

aging effects of loss of material and loss of preload. 

 As discussed in SER Section 3.3.2.3.9, the periodic monitoring of the lube oil pressure 

every 12 hours for the CCHVAC system pump and once a month for the CTG system 

pump, in combination with the preventive actions taken and opportunistic inspections 

that will be performed under the Bolting Integrity Program, provides reasonable 

assurance that degradation associated to the submerged bolts will be identified and that 

corrective actions will be taken before there is a loss of the intended function. 

Based on its audit and review of the applicant’s responses to RAIs B.1.2-1, B.1.2-2, B.1.2-2a, 

and 3.3.2.9-1, the staff finds that program elements 1 through 6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M18. The staff also reviewed the exceptions associated with the 

“detection of aging effects” program element and their justification and finds that the AMP, with 

the exceptions, is adequate to manage the applicable aging effects. In addition, the staff 

reviewed the enhancements associated with the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “corrective actions,” and “administrative controls” 

program elements and finds that, when implemented, they will make the AMP adequate to 

manage the applicable aging effects. 

Operating Experience. LRA Section B.1.2 summarizes operating experience related to the 

Bolting Integrity Program. The LRA states that, in 2003, during a dive inspection of the RHR 

reservoir, divers identified corroded bolts on the flanges of all Division 1 RHR complex service 

water pumps. Corrective actions were taken to (1) replace the submerged bolts, (2) establish a 

PM activity for pump refurbishment or replacement that includes the selection of new material 

for replacement bolts, and (3) change the chemical addition process to reduce corrosion. The 

LRA also states that, during an ISI, loose bolting was discovered on a pressure valve seal 

bonnet. The applicant, consistent with IWB-2430, expanded the sample size to bolting in 

13 additional valves and found loose bolting in the seal bonnet of a second valve. The applicant 

entered the issue in its corrective action program, repaired the leaking valve bonnets, and 

revised the post-maintenance testing to ensure that pressure valves bolting torque requirements 

were met. A 2007 followup review of the pressure valves found no reoccurrence of loose bolts. 
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The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff determined the need for additional clarification, 

which resulted in the issuance of an RAI, as discussed below. 

GALL Report AMP XI.M18 states that MoS2 should not be used as a lubricant due to its 

potential contribution to SCC, especially for high strength bolts (actual yield strength greater 

than or equal to 150 ksi). The GALL Report also states that the applicant should evaluate 

applicable operating experience to support the conclusion that the effects of aging are 

adequately managed. During its onsite audit, the staff reviewed the AMP basis documents and 

confirmed that the bolting procedures had been revised to prohibit the use of MoS2 as a 

lubricant for bolting; however, it was not clear whether MoS2 lubricants have been used at 

Fermi 2 before plant procedures were revised to prohibit their use. By letter dated 

December 19, 2014, the staff issued RAI B.1.2-3 requesting that the applicant clarify whether 

MoS2 lubricants have been used on any high strength closure bolts or any high strength 

structural bolts in sizes greater than 1-inch nominal diameter within the scope of license renewal 

and, if so, explain how the affected bolts will be managed for age-related degradation during the 

period of extended operation. 

In its response dated January 20, 2015, the applicant stated that the use of MoS2 has been 

restricted by its chemical control procedure since May 27, 1997. The applicant also stated that 

bolting maintenance procedures, including an original procedure dating back to 1983 (before 

plant startup) required that bolts be cleaned of old lubricant, inspected, and lubricated with 

Fel Pro N-5000, N-7000, Dag Dispersion 156, and other lubricants, none of which contain MoS2. 

Pipe erection specifications, dating back to May 1975 and used during plant construction, 

required the use of specific lubricants (e.g., Fel Pro N-5000, N-7000, Dag Dispersion 156, and 

Crane Company screw thread lubricant) that did not contain MoS2. The applicant further stated 

that its maintenance procedure references NUREG-0943, “Threaded Fastener Experience in 

Nuclear Power Plants,” dated January 1983, which discusses the bolting degradation and 

failures caused by MoS2. The staff finds the applicant’s response acceptable because 

maintenance procedures and pipe specifications used during construction and maintenance at 

Fermi 2 did not prescribe the use of MoS2 lubricants; therefore, there is reasonable assurance 

that the adverse degradation effects (e.g., SCC) in high strength bolts that can be caused by the 

use of MoS2 lubricants will not be present at Fermi 2. The staff’s concern described in 

RAI B.1.2-3 is resolved. 

Based on its audit and review of the application and review of the applicant’s response to 

RAI B.1.2-3, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.M18 was 

evaluated. 

UFSAR Supplement. LRA Section A.1.2 provides the UFSAR supplement for the Bolting 

Integrity Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 4) to implement the enhancements to 

the program 6 months before the period of extended operation. The staff finds that the 
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information in the UFSAR supplement, as amended by letters dated January 20, 2015, and 

February 12, 2015, is an adequate summary description of the program. 

Conclusion. Based on its audit and review of the applicant’s Bolting Integrity Program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the exceptions and their justification 

and determines that the AMP, with the exceptions, is adequate to manage the applicable aging 

effects. In addition, the staff reviewed the enhancements and confirmed that their 

implementation before the period of extended operation will make the AMP adequate to manage 

the applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Boraflex Monitoring 

Summary of Technical Information in the Application. LRA Section B.1.3, as amended by 

applicant letters through September 24, 2015, originally described the existing Boraflex 

Monitoring Program as consistent, with an enhancement, with GALL Report AMP XI.M22, 

“Boraflex Monitoring.” The LRA originally stated that (a) the AMP manages the aging effect of 

reduction in neutron-absorbing capacity in the Boraflex material affixed to spent fuel racks, 

(b) the AMP is implemented to ensure that no unexpected degradation of the Boraflex material 

compromises the criticality analysis in support of the design of spent fuel storage racks, and 

(c) that the AMP uses the RACKLIFE computer predictive code to calculate the gamma dose 

absorbed by, and the amount of boron carbide loss from, the Boraflex panels. The AMP 

originally included (1) quarterly sampling and analysis for silica levels in the spent fuel pool 

water and trending of the results by using the RACKLIFE code, (2) performing periodic physical 

measurements and neutron attenuation testing of surveillance coupons, and (3) areal boron 10 

density measurement testing of the spent fuel storage racks, such as BADGER testing, at a 

frequency of at least once every 5 years. As described below, by letter dated 

September 24, 2015, the applicant withdrew crediting of this AMP and committed to not rely on 

Boraflex panels in the spent fuel pool for neutron absorption during the period of extended 

operation. 

Staff Evaluation. In a letter dated September 24, 2015, the applicant provided supplemental 

information on the continued use of the Boraflex material in the Fermi 2 spent fuel pool. The 

applicant stated that the Boraflex currently used in the spent fuel racks will not be credited for 

neutron absorption during the period of extended operation. Accordingly, the Boraflex 

Monitoring Program will not be relied on during the period of extended operation. The applicant 

revised LRA Sections A.1.3 and B.1.3 to no longer credit the Boraflex material or the Boraflex 

Monitoring Program for the period of extended operation. The applicant stated that all 

neutron-absorbing materials in the spent fuel pool will be managed during the period of 

extended operation by the Neutron Absorbing Material Monitoring Program AMP. The staff’s 

review of this AMP is in SER Section 3.0.3.2.15. 

Operating Experience. LRA Section B.1.3 originally provided operating experience related to 

the Boraflex Monitoring Program, which was subsequently deleted by the applicant in its 

September 24, 2015, letter. The staff’s evaluation of this operating experience follows below in 

order to provide more details of the staff’s review and the issues addressed. 
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 In 2013, the applicant performed BADGER testing on 60 Boraflex panels in the spent 

fuel pool. Three panels were reported to have fallen below the acceptance criteria limit. 

The applicant conducted a criticality sensitivity analysis to determine the margin needed 

to maintain the required 5-percent subcriticality margin. The applicant took actions to 

preclude placing fuel in the cells adjacent to the three panels. A corrective action 

document was written to evaluate impacts of the BADGER testing results on the 

Boraflex Monitoring Program. 

 In 2012, the LRA states that NRC Information Notice (IN) 2012-13, “Boraflex 

Degradation Surveillance Programs and Corrective Actions in the Spent Fuel Pool,” 

dated August 10, 2012, was reviewed regarding surveillance programs and corrective 

actions at Turkey Point Nuclear Generating Station and Peach Bottom Atomic Power 

Station with regards to Boraflex degradation monitoring. Based on the review, revisions 

were made to RACKLIFE inputs to ensure that the model will provide more conservative 

calculations. 

 In 2011, coupon testing was performed on four Boraflex surveillance coupons at 

Pennsylvania State University. The LRA indicated that the coupons satisfied all 

applicable test criteria. 

 In 2009, the applicant observed that the silica level in the spent fuel pool was above that 

observed in previous cycles. Preparations were initiated to perform BADGER testing, 

which was performed in 2013. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, which resulted in the issuance of an RAI, as discussed below. 

In a letter dated December 23, 2014, the staff issued RAI B.1.3-1, which requested that the 

applicant provide the 2013 BADGER test report to the staff for review and assessment of the 

condition of the Boraflex material and the effectiveness of the Boraflex Monitoring Program. 

In a letter dated January 26, 2015, the applicant provided the 2013 BADGER test report to the 

staff. The staff reviewed the 2013 report and determined that further information was needed to 

determine whether the program provides reasonable assurance that it can detect unexpected 

degradation of the Boraflex material in the spent fuel pool. In a letter dated March 13, 2015, the 

staff issued RAI B.1.3-1a, which requested that the applicant provide clarification on the 

information provided in the 2013 BADGER test report. 

In a letter dated April 10, 2015, the applicant provided supplemental information on the Boraflex 

Monitoring Program. In the stated letter, the applicant references several documents/reports 

that are the basis for its discussion on the acceptable use and performance of the Boraflex 

material (i.e., a sensitivity study, criticality safety analysis, and Boraflex degradation projection). 

The staff reviewed the April 10, 2015, letter and determined that further information was 

needed. On August 17, 2015, the staff held a conference call with the applicant to discuss the 
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applicant’s long-term strategy to provide reasonable assurance that it will be able to manage 

Boraflex degradation and to maintain the spent fuel pool subcriticality requirements. 

In a letter dated September 24, 2015, the applicant provided supplemental information on the 

continued use of the Boraflex material in the Fermi 2 spent fuel pool. The applicant stated that 

the Boraflex currently used in the spent fuel racks will not be credited for neutron absorption 

during the period of extended operation. The applicant also indicated that the Boraflex 

Monitoring Program will not be relied on during the period of extended operation. The applicant 

further noted that the Neutron Absorbing Material Monitoring Program will be used to manage 

all the neutron-absorbing material that will be credited during the period of extended operation 

(including, but not limited to, Boral). The applicant revised LRA Sections 2.3.3.4, 3.3.2.1.4, 

A.1.3, B.1.3, and LRA Tables 3.3.1 (item 3.3.1-51), 3.3.2-4, A.4 (item 5), B-1, B-2, and B-3 to no 

longer credit the Boraflex material or the Boraflex Monitoring Program for the period of extended 

operation. The applicant committed (Commitment No. 5) to not require the current Boraflex 

panels in the spent fuel pool to perform a neutron-absorption function during the period of 

extended operation. 

The staff reviewed this letter and finds the revisions regarding Boraflex acceptable because the 

applicant will discontinue reliance on the Boraflex neutron-absorbing material during the period 

of extended operation. In addition, the staff reviewed Commitment No. 5 and finds it acceptable 

because the applicant has identified that the Boraflex material is degrading and that the 

techniques used to determine the rate of degradation do not correlate well. Hence, the reliability 

of the Boraflex material to perform its intended function during the period of extended operation 

cannot be accurately projected or managed. The staff’s concerns described in RAI B.1.3-1 and 

RAI B.1.3-1a are resolved. 

UFSAR Supplement. LRA Section A.1.3 provides the UFSAR supplement for the Boraflex 

Monitoring Program. In its letter dated September 24, 2015, the applicant provided 

supplemental information stating that the Boraflex currently used in the spent fuel racks will not 

be credited for neutron absorption during the period of extended operation. The applicant also 

indicated that the Boraflex Monitoring Program will not be relied on during the period of 

extended operation. The applicant stated that all neutron-absorbing materials in the spent fuel 

pool will be managed during the period of extended operation by the Neutron Absorbing 

Material Monitoring Program AMP. The applicant revised LRA Section A.1.3 to no longer credit 

the Boraflex material or the Boraflex Monitoring Program for the period of extended operation. 

The staff reviewed the revisions to the UFSAR supplement regarding the Boraflex Monitoring 

Program and Commitment No. 5 and finds the changes acceptable because the applicant will 

discontinue reliance on the Boraflex neutron-absorbing material during the period of extended 

operation. The staff also noted that the applicant committed to implement Commitment No. 5 

before September 20, 2024, or the end of the last RFO before March 20, 2025. 

Conclusion. In its letter dated September 24, 2015, the applicant provided supplemental 

information stating that the Boraflex currently used in the spent fuel racks will not be credited for 

neutron absorption during the period of extended operation. The applicant also indicated that 

the Boraflex Monitoring Program will not be relied on during the period of extended operation. 

The applicant stated that all neutron-absorbing materials in the spent fuel pool will be managed 

during the period of extended operation by the Neutron Absorbing Material Monitoring Program 

AMP. The staff’s review of the acceptability of this AMP is in SER Section 3.0.3.2.15. The 

applicant revised LRA Section B.1.3 to no longer credit the Boraflex material or the Boraflex 

Monitoring Program for the period of extended operation. The staff reviewed the changes and 
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finds the revisions regarding the Boraflex neutron-absorbing material acceptable because the 

applicant will discontinue reliance on the Boraflex during the period of extended operation. 

 BWR Vessel Internals 

Summary of Technical Information in the Application. LRA Section B.1.10 describes the 

existing BWR Vessel Internals Program as consistent, with enhancements, with GALL Report 

AMP XI.M9, “BWR Vessel Internals.” The BWR Vessel Internals Program addresses BWR 

vessel internal components to manage cracking, loss of material due to wear, and reduction of 

fracture toughness through inspection and flaw evaluation. The LRA states that the program’s 

inspection schedule, aging effect detection, NDE inspection techniques, acceptance criteria, 

flaw evaluation, and repair/replacement corrective actions are based on applicable industry 

standards and NRC-approved BWRVIP documents. Three enhancements to the BWR Vessel 

Internals Program will be implemented before the period of extended operation, and no 

exceptions will be taken. 

LRA Appendix C lists the following BWRVIP reports that are credited for the BWR Vessel 

Internals Program that have NRC safety evaluations for license renewal: 

 BWRVIP-14-A, “Evaluation of Crack Growth in BWR Stainless Steel RPV Internals” 

 BWRVIP-18-A, Revision 2, “BWR Core Spray Internals Inspection and Flaw Evaluation 

Guidelines,” (Updated to Revision 2 in the annual update of May 9, 2016) 

 BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines” 

 BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines” 

 BWRVIP-27-A, “BWR Standby Liquid Control System/Core Plate ∆P Inspection and 

Flaw Evaluation Guidelines” 

 BWRVIP-38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines” 

 BWRVIP-41, Revision 3, “BWR Jet Pump Assembly Inspection and Flaw Evaluation 

Guidelines” 

 BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines” 

 BWRVIP-48-A, “Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines” 

 BWRVIP-49-A, “Instrument Penetration Inspection and Flaw Evaluation Guidelines” 

 BWRVIP-74-A, “BWR Reactor Vessel Inspection and Flaw Evaluation Guidelines” 

 BWRVIP-76, Revision 1-A, “BWR Core Shroud Inspection and Flaw Evaluation 

Guidelines” (Updated to Revision 1-A in the annual update of May 9, 2016) 

 BWRVIP-100-A, “Updated Assessment of Fracture Toughness of Irradiated Stainless 

Steel for BWR Core Shroud” 

LRA Appendix C also contains the applicant’s responses to license renewal action items that 

were identified in the NRC’s safety evaluations for the applicable BWRVIP reports. The 

responses include three license renewal action items applicable to all BWRVIP reports and 

several other license renewal action items applicable to specific BWRVIP reports. The staff’s 

evaluation of the applicant’s responses to these action items are documented in the staff 

evaluation section for this AMP. 
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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M9. 

For the “scope of program” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below. The 

recommendations in GALL Report AMP XI.M9, “BWR Vessel Internals,” state that the CRD 

housing and lower plenum components are subject to the guidelines in BWRVIP-47-A for 

inspection and evaluation (I&E). GALL Report AMP XI.M9 also states that BWRVIP-58-A 

provides guidelines for the repair design criteria of the CRD housing and that BWRVIP-57-A 

provides guidelines for the repair design criteria of the lower plenum components. However, 

during the AMP audit, the staff noted that the program documents reference BWRVIP-58-A and 

BWRVIP-57-A as guidelines for the repair design criteria of the CRD housing and the lower 

plenum components. The program also references BWRVIP-55-A as repair design criteria 

guidelines for these components. However, the plant procedures only reference BWRVIP-55-A. 

The staff was unclear about the inconsistency in the plant documents regarding these 

guidelines. By letter dated December 17, 2014, the staff issued RAI B.1.10-1 requesting that 

the applicant (a) identify the specific BWRVIP guidelines that are being used for repairs of the 

CRD housings and the lower plenum components in the plant design, (b) clarify whether these 

guidelines are within the scope of the BWR Vessel Internals Program for the LRA and whether 

the guidelines have been incorporated into the specific plant procedure that will be used to 

implement the BWR Vessel Internals Program during the period of extended operation, and 

(c) identify any additional BWRVIP guidelines being relied on for the BWR Vessel Internals 

Program beyond those in GALL Report AMP XI.M9 and provide any applicable license renewal 

applicant action items (AAIs). 

In its response dated January 20, 2015, the applicant stated that the plant uses BWRVIP-55-A, 

BWRVIP-57-A, and BWRVIP-58-A as guidelines for the repair design criteria of the CRD 

housing and the lower plenum components. In its response, the applicant also provided a list of 

the BWRVIP reports that the plant implements that contain “mandatory” or “needed” guidance. 

The applicant also confirmed that all of the BWRVIP guidelines with license renewal AAIs have 

been identified in LRA Appendix C, including responses. 

The staff finds the applicant’s response acceptable because the applicant clarified which 

BWRVIP guidelines are used for the repair design criteria of the CRD housing and the lower 

plenum components and because it will update its plant procedures appropriately. The 

applicant also confirmed that all applicable BWRVIP license renewal AAIs have been provided 

in the LRA. The staff’s concern described in RAI B.1.10-1 is resolved. 

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with enhancements to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of these enhancements follows. 

Enhancements 1 and 2. LRA Section B.1.10 includes Enhancement 1 to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the susceptibility to 

neutron and thermal embrittlement for reactor vessel internal components composed of CASS 

and X-750 alloy will be evaluated. 

LRA Section B.1.10 includes Enhancement 2 to the “detection of aging effects” program 

element. In this enhancement, the applicant stated that BWR Vessel Internals Program 

procedures will be revised as follows: 
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Portions of the susceptible components determined to be limiting from the 

standpoint of thermal aging susceptibility, neutron fluence, and cracking 

susceptibility (i.e., applied stress, operating temperature, and environmental 

conditions) will be inspected, using an inspection technique capable of detecting 

the critical flaw size with adequate margin. The critical flaw size will be 

determined based on the service loading condition and service-degraded 

material properties. The initial inspection will be performed either prior to or 

within five years after entering the period of extended operation. If cracking is 

detected after the initial inspection, the frequency of re-inspection will be justified 

based on fracture toughness properties appropriate for the condition of the 

component. The sample size for the initial inspection of susceptible components 

will be 100 percent of the accessible component population, excluding 

components that may be in compression during normal operations 

The staff reviewed Enhancement 1 against the corresponding program elements in GALL 

Report AMP XI.M9 and finds it acceptable because, when it is implemented, it will manage the 

effects of neutron and thermal embrittlement of CASS and X-750 alloy reactor vessel internal 

components consistent with the recommendations in the GALL Report to ensure that the 

intended functions will be maintained during the period of extended operation. 

The staff reviewed Enhancement 2 against the corresponding program elements in GALL 

Report AMP XI.M9 and finds it acceptable (a) because it provides the details of how the 

susceptibility evaluation in Enhancement 1 will be performed and (b) because, when it is 

implemented, it will ensure that susceptible vessel internals components will be inspected for 

evidence of any cracking that could cause failure due to the loss of the material’s fracture 

toughness caused by thermal or neutron embrittlement. The staff confirmed that when 

Enhancements 1 and 2 are implemented in conjunction with each other, the applicant’s basis 

will be consistent with the “detection of aging effects” program element in GALL Report 

AMP XI.M9. 

Enhancement 3. LRA Section B.1.10 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that BWR Vessel Internals 

Program procedures will be revised as follows: 

In accordance with an applicant action item for BWRVIP-25 safety evaluation: 

(a) install core plate wedges prior to the period of extended operation, or 

(b) complete a plant-specific analysis that justifies no inspections are required or 

to determine acceptance criteria for continued inspection of core plate hold-down 

bolts in accordance with BWRVIP-25 and submit the inspection plan, along with 

the acceptance criteria and justification for the inspection plan, to the NRC two 

years prior to the period of extended operation. 

By letter dated April 27, 2015, the applicant amended Enhancement 3. This amendment was a 

result of the staff’s evaluation of the applicant’s response to Action Item 4 in BWRVIP-25, as 

documented in the section entitled, “Review of License Renewal Applicant Action Items – 

Appendix C,” of this evaluation. The staff reviewed Enhancement 3 against the corresponding 

program elements in GALL Report AMP XI.M9 and finds it acceptable because (a) it ensures 

that an analysis justifying its inspection basis or elimination of inspections will be submitted to 

the NRC and (b) it ensures that loss of preload/stress relaxation in the core plate rim hold-down 

bolts will be managed during the period of extended operation. The staff confirmed that when 
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Enhancement 3 is implemented, the applicant’s basis will be consistent with the “detection of 

aging effects” program element in GALL Report AMP XI.M9. 

Enhancement 4. LRA Section B.1.10, as amended by letter dated June 9, 2015, includes an 

enhancement to the “detecting of aging effects” and “corrective actions” program elements. 

This enhancement was added to the BWR Vessel Internals Program as a result of the 

applicant’s response to RAI B.1.10-3, as documented in the staff’s evaluation of the applicant’s 

response to Action Item 4 in BWRVIP-26-A in the section entitled, “Review of License Renewal 

Applicant Action Items – Appendix C,” of this evaluation. The enhancement states that the 

BWR Vessel Internals Program procedures will be revised to include how the three 

conditions/limitations associated with BWRVIP-183 are addressed to justify its use of the flaw 

evaluation methodology. The staff reviewed Enhancement 4 against the corresponding 

program elements in GALL Report AMP XI.M9 and finds it acceptable because the applicant 

addressed the three conditions/limitation of the use of BWRVIP-183 and justified that it will 

conservatively account for stress loads for potential flaws near component discontinuities, flaw 

growth assumptions, and severed beam locations such that the flaw evaluation methodology will 

not be negatively impacted. 

Enhancement 5. LRA Section B.1.10, as amended by letter dated August 20, 2015, includes an 

enhancement to the “detecting of aging effects” program element. This enhancement was 

added to the BWR Vessel Internals Program as a result of the applicant’s supplemental 

response to RAI 4.1-4a, as documented in the staff’s evaluation of the applicant’s response to 

Action Item 4 in BWRVIP-27-A in the section entitled, “Review of License Renewal Applicant 

Action Items – Appendix C,” of this evaluation. The enhancement states that the BWR Vessel 

Internals Program procedures will be revised to perform opportunistic inspections of the 

differential pressure and SLC line inside the reactor vessel when the line becomes accessible. 

The staff reviewed Enhancement 4 against the corresponding program elements in GALL 

Report AMP XI.M9 and finds it acceptable because these inspections will be performed in 

addition to the aging management activities of the Water Chemistry Control – BWR Program 

and One-Time Inspection Program to provide additional assurance that cracking will be 

detected and appropriate corrective actions will be performed before loss of intended function. 

Based on its audit and review of the applicant’s response to RAI B.1.10-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.M9. In 

addition, the staff reviewed the enhancements associated with the “detection of aging effects” 

program element and finds that, when implemented, they will make the AMP adequate to 

manage the applicable aging effects. 

Review of License Renewal Applicant Action Items – Appendix C: The LRA references the 

BWRVIP reports, which have been reviewed and approved by the staff, as part of its AMPs for 

the reactor vessel and its internal components. As part of the staff’s approval of these BWRVIP 

reports, the staff’s safety evaluations on the reports included a number of AAIs that were to be 

addressed as part of the basis for applying the reports to the CLB. Those BWR applicants 

applying for license renewal of their facilities were requested to include their responses to the 

AAIs items in their LRAs. 

Several of BWRVIP documents credited for Fermi 2 license renewal have common action items 

in the NRC safety evaluation reports for license renewal. The applicant provided the following 

responses to the three common license renewal action items: 
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(1) Fermi’s AMP for the reactor vessel internal components is bounded by the BWRVIP 

reports. 

(2) The UFSAR supplement addresses a summary of the programs and activities specified 

in the applicable BWRVIP reports. 

(3) Fermi 2 states that no TS changes have been identified as a result of implementing the 

AMP for the reactor vessel internal components. 

For the first common license renewal action item, the staff confirmed that the BWRVIP reports 

incorporated by the applicant bound the BWR Vessel Internals Program. 

For the second common license renewal action item, the staff verified that the LRA includes a 

UFSAR supplement summary description (LRA Section A.1.10) for the BWR Vessel Internals 

Program and that the summary description adequately explains how the applicable BWRVIP 

inspection, evaluation, and repair criteria reports will be used to manage aging in the reactor 

internals at Fermi 2, Unit 2. 

For the third common license renewal action item, the staff confirmed that the applicant would 

not need to add any new TS requirements for the reactor internals or to modify any existing TS 

requirements that may apply to reactor internal components. 

In addition to these three common action items, the LRA provides the applicant’s responses to 

the report-specific license renewal action items that were specified by the staff in its safety 

evaluation reports for BWRVIP reports credited for the BWR Vessel Internals Program. The 

following paragraphs address the staff’s evaluation of the applicant’s responses to these 

report-specific action items. 

For Action Item 4 in BWRVIP-18-A, Revision 1, the applicant is requested to identify and 

evaluate any potential TLAA issues that may impact the structural integrity of the subject reactor 

pressure vessel internal components. The applicant’s response states that TLAA issues were 

identified and evaluated for core spray components that are part of the reactor vessel internals, 

which is discussed in LRA Section 4.3.1.4. The staff evaluated the applicant’s TLAA for 

managing the effects of fatigue on the reactor vessel internals, as discussed in LRA 

Section 4.3.1.4, and finds the applicant’s response to the action item acceptable. The staff’s 

evaluation of LRA Section 4.3.1.4 is documented in SER Section 4.3.1.4. 

In the applicant’s annual update of May 9, 2016, the applicant updated the version of 

BWRVIP-18 being used for the core spray lines to BWRVIP-18, Revision 2, and indicated that 

the response to Action Item 4 is applicable to this version of the BWRVIP report. The staff 

noted that BWRVIP-18, Revision 2, was approved in an NRC safety evaluation dated 

February 22, 2016 (ADAMS Accession No. ML16011A190). The staff also noted that use of 

BWRVIP-18, Revision 2, would not alter the applicant’s response basis for Action Item 4 above 

because the metal fatigue TLAA for the core spray lines is still applicable to the plant design and 

the methodology in BWRVIP-18, Revision 2. Therefore, based on this review, the staff finds the 

use of BWRVIP-18, Revision 2, to be acceptable because: (a) the report has been approved in 

the referenced safety evaluation, and (b) the applicant’s basis for resolving Action Item 4 

remains within the scope of the plant design and the approved methodology in BWRVIP-18, 

Revision 2. The staff evaluates the fatigue TLAA-related action items for the core spray lines in 

SER Section 4.1. 
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For Action Item 4 in BWRVIP-25, the applicant is requested to identify and evaluate the 

projected stress relaxation of the rim hold-down bolts as a potential TLAA issue. The 

applicant’s response states that the BWR Vessel Internals Program will be enhanced to either 

(a) install core plate wedges or (b) submit an inspection plan and acceptance criteria analysis to 

the staff. The response also states that the analysis of loss of preload on the rim hold-down 

bolts is not a TLAA because it does not involve time-limited assumptions defined by the current 

term of operation. The staff’s evaluation of the applicant’s determination that this analysis was 

not a TLAA is documented in SER Section 4.1. The staff noted concerns regarding Option (b) 

of the proposed enhancement and issued RAI 4.1-2, by letter dated December 23, 2014, 

requesting that the applicant provide further clarifications and justifications relative to Option (b) 

of the proposed enhancement. 

By letter dated February 5, 2015, the applicant responded to RAI 4.1-2. In its response, the 

applicant amended the enhancement to clarify how it would implement the enhancement and 

commitment as part of the CLB. However, the staff noted that under the amendment of this 

commitment, the applicant would only need to submit an inspection plan to the NRC for 

approval if the EPRI BWRVIP’s future updated I&E guideline bases for BWR core plate rim 

hold-down bolts would continue to call for inspections of these components. The staff’s full 

evaluation of the applicant’s response to RAI 4.1-2 is documented in SER Section 4.1. The staff 

determined that the amended enhancement did not provide an adequate basis for managing 

loss of preload/stress relaxation in the core plate rim hold-down bolts because (a) the proposed 

action in the option is based on the applicant’s speculation that the BWRVIP will be updating its 

inspection guidance for core plate rim hold-down bolts, which has yet to be done (including 

proper regulatory review by the NRC), and (b) the proposed action in the option does not 

indicate that the inspection plan for the core plate rim hold-down bolts, along with the supporting 

loss of preload/stress relaxation analysis and justification, will be submitted to the NRC for staff 

approval at least 2 years before entering into the period of extended operation, regardless of 

whether inspections of the bolts will be implemented or eliminated in the updated I&E guidelines 

for the components. 

By letter dated March 26, 2015, the staff issued RAI B.1.10-2 (followup to RAI 4.1-2), requesting 

that the applicant address the staff’s issues with the aging management basis in Option (b) of 

the enhancement to the BWR Vessel Internals Program. Specifically, the staff asked the 

applicant to justify why the amended enhancement did not firmly commit to submittal of an 

inspection plan of the core plate rim hold-down bolts, along with a supporting loss of 

preload/stress relaxation analysis and justification, for NRC approval at least 2 years before 

entering into the period of extended operation, regardless of whether the submitted basis 

proposes inspections or justifies elimination of inspections for the core plate rim hold-down 

bolts. 

By letter dated April 27, 2015, the applicant responded to RAI B.1.10-2. The applicant amended 

the enhancement to state the following: 

(a) install core plate wedges prior to the period of extended operation, or 

(b) complete a plant-specific analysis that justifies no inspections are required, or 

(c) complete a plant-specific analysis to determine acceptance criteria for continued 

inspection of core plate hold-down bolts in accordance with BWRVIP-25. 

This amendment is reflected in LRA Sections B.1.10, A.1.10 and A.4 and in LRA Appendix C. 

The applicant further stated that the analysis performed under Option (b) or (c) of this 
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enhancement will address loss of preload due to stress relaxation in the core plate rim 

hold-down bolts and will quantify the loss of preload/stress relaxation that will occur in these 

bolts during the period of extended operation and that it will be submitted to the NRC 2 years 

before entering the period of extended operation. The applicant also stated that it will determine 

whether the analysis will meet the criteria for a TLAA and that it will revise the UFSAR 

accordingly 2 years before entering the period of extended operation. The staff finds the 

applicant’s response acceptable because the amended enhancement will ensure that an 

analysis justifying its inspection basis or elimination of inspections will be submitted to the NRC. 

The staff has reasonable assurance that loss of preload/stress relaxation in the core plate rim 

hold-down bolts will be managed during the period of extended operation. The staff’s concerns 

in RAI B.1.10-2 are resolved. Therefore, the staff finds the applicant’s response to Action Item 4 

in BWRVIP-25 acceptable. 

For Action Item 5 in BWRVIP-25, the applicant is requested to continue to perform inspections 

of the rim hold-down bolts. The applicant’s response states that inspection techniques are not 

viable to inspect the integrity of the bolts and requests a deviation from the inspections. 

However, as stated in its amended response to Action Item 4 in BWRVIP-25, the applicant will 

submit a plant-specific analysis that either (a) justifies that no inspections are required or 

(b) determines acceptance criteria for continued inspection of core plate hold-down bolts in 

accordance with BWRVIP-25. This analysis will be submitted to the NRC 2 years before 

entering the period of extended operation. Therefore, the staff finds the applicant’s response 

acceptable because the applicant will evaluate the need for inspections or the acceptance 

criteria for continued inspections for the core plate rim hold-down bolts and will submit this 

response to the NRC. This action will ensure that loss of preload/stress relaxation in the core 

plate rim hold-down bolts will be managed during the period of extended operation. 

For Action Item 4 in BWRVIP-26-A, the applicant is requested to identify and evaluate the 

projected accumulated neutron fluence as a potential TLAA issue. The applicant’s response 

states that BWRVIP-26-A does not constitute a TLAA because it was not used to make any 

safety determination or to justify reducing the number of inspections. The staff’s evaluation of 

the applicant’s determination that this analysis was not a TLAA is documented in SER 

Section 4.1. The staff noted that, in Appendix B to the BWRVIP-26-A report, the EPRI BWRVIP 

included a generic flaw analysis for postulated cracks in BWR top guide grid beam components. 

The staff noted that this flaw analysis uses a proprietary upper bound fluence value as the basis 

for establishing the critical stress intensity value for BWR top guide components in the industry. 

Therefore, it was not evident to the staff why the neutron fluence-dependent irradiation-assisted 

stress corrosion cracking (IASCC) analysis for the top guide grid beam locations would not need 

to be identified as a TLAA, especially if the applicant is currently relying on the flaw evaluation in 

BWRVIP-26-A to justify the conservatisms and validity of the augmented inspection methods 

and frequencies that will be applied to the top guide grid beam locations at Fermi 2. By letter 

dated December 23, 2014, the staff issued RAI 4.1-3, requesting that the applicant provide 

additional clarification on the flaw evaluation methodology for BWR top guide grid beam 

locations. 

The applicant responded to RAI 4.1-3 in a letter dated February 5, 2015. In its response, the 

applicant stated that Appendix B to BWRVIP-26-A provides a sample flaw evaluation for 

selected BWR top guide grid beam locations. The applicant also clarified that the sample flaw 

evaluation in BWRVIP-26-A is not relied on to justify the conservatisms and validity of 

augmented inspection methods and frequencies for the top guide grid beam locations at 

Fermi 2. Based on this response, the staff finds that the flaw evaluation in the BWRVIP-26-A 

report does not need to be identified as a TLAA for the LRA because (a) the analysis is not 
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contained or incorporated by reference in the CLB and (b) the analysis, therefore, does not 

conform to Criterion 6 in 10 CFR 54.3(a). RAI 4.1-3 and Action Item 4 on BWRVIP-26-A are 

resolved with respect to this TLAA identification matter, as discussed in SER Section 4.1. 

The staff also noted that, in its response to RAI 4.1-3, the applicant indicated that BWRVIP-183 

establishes the EPRI BWRVIP’s I&E guidelines for the top guide and its components. The 

applicant stated that it will implement the inspections of the top guide and its components in 

accordance with the plant procedure for implementing LRA AMP B.1.10, “BWR Vessel 

Internals,” which will be used to implement the inspection guidelines in BWRVIP-183, as applied 

to the top guide and its components. 

The staff noted that GALL Report AMP XI.M9 recommends using BWRVIP-26-A and 

BWRVIP-183 for the inspection of the top guide and its components. However, the staff noted 

that, in the NRC’s draft final safety evaluation report for BWRVIP-183, dated 

December 13, 2011, the staff established three conditions/limitations on the use of 

BWRVIP-183 I&E methodology. However, the EPRI BWRVIP has yet to accept the staff’s draft 

final safety evaluation report for the BWRVIP-183 report. Therefore, as of February 18, 2015, 

the staff noted that BWRVIP-183 had not been formally endorsed by the NRC. Therefore, if 

BWRVIP-183 was to be used as the basis for performing augmented inspection and potential 

flaw evaluations of the top guide, the staff determined that it would need the technical 

information in the BWRVIP-183 report to be docketed with the Fermi 2 LRA for staff review and 

approval, as submitted on a plant-specific basis. The staff’s full evaluation of the applicant’s 

response to RAI 4.1-3 is evaluated in SER Section 4.1. 

By letter dated May 15, 2015, the staff issued RAI B.1.10-3 (followup to RAI 4.1-3), Parts 1, 2, 

and 3, requesting that the applicant address this issue. Specifically, in RAI B.1.10-3, Part 1, the 

staff asked the applicant to clarify (with a justification) which BWR Vessel Internals Program 

element criteria in the BWRVIP-183 report will be used when applying the report to specific I&E 

activities of the top guide assembly and its components. In RAI B.1.10-3, Part 2, the staff 

addressed how BWRVIP-183 would be used for the evaluation of flaws if the report was being 

applied to the evaluation of flaws detected in the top guide assembly. Specifically, the staff 

asked the applicant to clarify how the flaw evaluation methodology will account for the following 

factors that may impact the flaw evaluation basis: (a) stress loads for potential flaws detected 

near component discontinuities, (b) conservative flaw growth assumptions in the methodology, 

and (c) potential for, and impact of, severed beam locations if flaw growth assumptions in the 

flaw evaluation methodology are determined to be nonconservative for the top guide beam 

locations. In RAI B.1.10-3, Part 3, the staff asked the applicant to update the LRA, including 

LRA Appendix C and any additional enhancements to AMP B.1.10, as appropriate. The staff’s 

evaluation of the response to RAI B.1.10-3 and completion of its review of the applicant’s 

response to Action Item 4 in BWRVIP-26-A will be documented in this SER section. 

By letter dated June 9, 2015, the applicant responded to RAI B.1.10-3. The applicant stated 

that BWRVIP-183 will be used for the inspection and flaw evaluation of the top guide grid beams 

as part of its BWR Vessel Internals Program. The applicant’s response addresses the three 

conditions/limitations associated with the report to justify its use of the flaw evaluation 

methodology. For condition (a), as specified in the RAI, the applicant stated that it will 

demonstrate that the detected flaws will be sufficiently far from geometric discontinuities such 

that the stress condition in the vicinity of the flaw is consistent with that for a single edge-crack 

plate and that it will use and justify its application of appropriate K values, which account for 

effects of geometric discontinuities. For condition (b), the applicant stated that the flaw 

evaluation in BWRVIP-183 will be used to justify continued operation on a cycle-by-cycle basis. 
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The applicant stated that it will require NRC approval to justify operation for more than a cycle 

and that the evaluation will be based on plant-specific operating experience, including crack 

length measurements of detected top guide grid beam flaws, to benchmark the accuracy of the 

flaw evaluation methodology. For condition (c), the applicant stated that its severed beam 

analysis will demonstrate that a completely severed beam will not be expected to interfere with 

the ability of the CRD system to insert control rods. 

The staff finds the response acceptable because, if flaw evaluations are needed for the top 

guide components, the “monitoring and trending” and “corrective actions” elements of the 

program will ensure that the flaw evaluations will (1) be based on conservative flaw growth 

assumptions, (2) consider the impacts of severed top guide beam locations on the assumptions 

for the analyses, and (3) consider the impacts that geometric discontinuities will have on the 

stress loads assumed in the analyses if the flaws are located near geometric discontinuities. 

The staff’s concerns in RAI B.1.10-3 are resolved. Therefore, the staff finds the applicant’s 

response to Action Item 4 in BWRVIP-26-A acceptable. 

For Action Item 4 in BWRVIP-27-A, the applicant is requested to identify and evaluate the 

projected fatigue cumulative usage factors (CUFs) as a potential TLAA issue. The applicant’s 

response states that the standby liquid control system/core ∆P (SLC/core ∆P) lines internal to 

the Fermi 2 RPV are not within the scope of license renewal. The staff’s evaluation of the 

applicant’s determination that there are no subject fatigue TLAAs for the internal portions of the 

SLC/core ∆P lines is documented in SER Section 4.1. As part of the staff’s review of LRA 

Section 4.1 and the applicant’s response to Action Item 4, the staff determined that the applicant 

had sufficiently demonstrated that the internal portions of the SLC/core ∆P lines would not need 

to be within the scope of license renewal in accordance with 10 CFR 54.4(a)(1), (a)(2), or (a)(3) 

and would not need to be the subject of an AMR in accordance with 10 CFR 54.21(a)(1). 

Based on its review of the UFSAR and BWRVIP-27-A, the staff determined that the internal 

portions of the core line would not need to be within the scope of license renewal because they 

only serve a diagnostic differential pressure reading function and do not serve a license renewal 

intended function, as defined in 10 CFR 54.4(b). However, the staff noted that the UFSAR 

indicates that the SLC lines are needed for mitigate the consequences of an anticipated 

transient without scram event and that the internal portions of the SLC system are needed to 

promote good mixing of the system’s pentaborate solution into the reactor during an SLC 

system activation. The staff also noted that the UFSAR indicates that the internal portions of 

the SLC/core ∆P lines reduce thermal shock to the SLC/core ∆P nozzles during an SLC 

actuation. Therefore, based on this UFSAR information, the staff concluded that the internal 

portions of the SLC system may need to be within the scope of license renewal. SER 

Section 4.1 documents the staff’s evaluation of the applicant’s response to RAI 4.1-4. 

By letter dated May 20, 2015, the staff issued RAI 4.1-4a (followup), Parts a, b, and c, to the 

applicant. SER Section 2.3.3.2 documents the staff’s evaluation of the applicant’s responses to 

RAI 4.1-4a, Parts a and b, which are associated with the license renewal scoping and screening 

determination of internal portions of the SLC/core ∆P line. In RAI 4.1-4a (followup), Part c, the 

staff asked the applicant to identify the applicable aging effects requiring management that 

apply to the components and to identify (with justification) how these aging effects will be 

managed during the period of extended operation. Otherwise, the staff asked the applicant to 

justify why the applicable aging effects do not need to be age-managed if condition-monitoring 

activities (i.e., inspections) will not be performed on the internal portions of the SLC during the 

period of extended operation. The staff’s evaluation of the response to RAI 4.1-4a, Part c, and 
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the completion of its review of the applicant’s response to Action Item 4 in BWRVIP-26-A report 

will be documented in this SER section. 

By letter dated July 6, 2015, the applicant responded to RAI 4.1-4a. The applicant also 

provided a supplemental response to RAI 4.1-4a by letter dated August 20, 2015. In response 

to Parts a and b, the applicant stated that Fermi 2 will conservatively assume that the SLC/core 

∆P line internal to the reactor vessel does perform a license renewal intended function per 

10 CFR 54.4(a)(3) such that this line will facilitate adequate boron mixing to shut down the core 

during an anticipated transient without scram event. SER Section 2.3.3.2 documents the staff’s 

full evaluation of RAI 4.1-4a, Parts a and b. In its response to RAI 4.1-4a, Part c, the applicant 

stated that the SLC/core ∆P line internal to the vessel is stainless steel and exposed to an 

environment of treated water greater than 140 °F. The applicant stated that this 

material/environment combination is subject to loss of material and cracking. The applicant will 

manage loss of material and cracking using the Water Chemistry Control – BWR Program as 

verified by the One-Time Inspection Program. The applicant also stated that it will manage 

cracking using the BWR Vessel Internals Program and perform opportunistic inspections of the 

SLC/core ∆P line internal to the reactor vessel during the period of extended operation. These 

opportunistic inspections will be included as an enhancement to the BWR Vessel Internals 

Program. The applicant stated that the inspections will be opportunistic based on plant-specific 

operating experience that showed no history of degradation, the use of the Water Chemistry 

Control – BWR Program, the use of the One-Time Inspection Program, and consistency with the 

recommendations of BWRVIP-27-A. The staff finds the use of the Water Chemistry Control – 

BWR Program as verified by the One-Time Inspection Program acceptable because (1) the 

applicant’s use of the Water Chemistry Control – BWR Program will ensure that the 

environment will not be conducive for loss of material and cracking to occur and is consistent 

with the recommendations in the GALL Report and (2) the One-Time Inspection Program will 

provide visual and/or equivalent volumetric examination to verify that unacceptable loss of 

material or cracking is not occurring and may trigger additional actions that ensure that the 

intended functions of the affected components are maintained throughout the period of 

extended operation. The staff finds the applicant’s use of the opportunistic inspections as part 

of the BWR Vessel Internals Program acceptable because these inspections will be performed 

in addition to the aging management activities of the Water Chemistry Control – BWR Program 

and One-Time Inspection Program to provide additional assurance that cracking will be 

detected and that appropriate corrective actions will be performed before loss of intended 

function. The staff’s concerns in RAI 4.1-4a are resolved. Therefore, the staff finds the 

applicant’s response to Action Item 4 in BWRVIP-27-A acceptable. 

For Action Item 4 in BWRVIP-47-A, the applicant is requested to identify and evaluate the 

projected CUF as a potential TLAA issue. The applicant’s response states that TLAA issues 

were identified and evaluated for select lower plenum pressure boundary components, which is 

discussed in LRA Section 4.3.1.4. The staff confirmed that the applicant includes its fatigue 

analyses for those lower plenum areas that were analyzed in accordance with ASME Code 

Section III fatigue analysis requirements in LRA Section 4.3.1.4. The staff finds the applicant’s 

response to the action item to be acceptable because it has confirmed that the applicant has 

included the applicable metal fatigue TLAAs in LRA Section 4.3.1.4. SER Section 4.3.1.4 

documents the staff’s evaluation of LRA Section 4.3.1.4. 

For Action Item 4 in BWRVIP-74-A, the applicant is requested to identify an AMP for the vessel 

flange leak detection line. The applicant’s response states that aging of the vessel flange leak 

detection line is managed by the Water Chemistry Control – BWR Program, as verified by the 

One-Time Inspection Program. The acceptance criteria in SRP-LR Section 3.1.2.2.4.1 state 
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that cracking due to SCC and IGSCC could occur in the stainless steel and nickel alloy BWR 

top head enclosure vessel flange leak detection lines and recommend that a plant-specific AMP 

be evaluated because existing programs may not be capable of mitigating or detecting cracking 

due to SCC and IGSCC. The staff’s evaluation in SER Section 3.1.2.2.4, item 1, provides the 

staff’s basis for accepting that the Water Chemistry Control – BWR Program and One-Time 

Inspection Program are acceptable to manage cracking due to SSC or IGSSC in the vessel 

flange leakage detection line. Therefore, based on this review, the staff finds this response 

acceptable because (1) the Water Chemistry Control – BWR Program will control water 

chemistry and enable the applicant to effectively manage the occurrence of any cracking or loss 

of material in the vessel flange leak detection line and (2) the One-Time Inspection Program will 

adequately determine whether aging degradation is found. 

For Action Item 5 in BWRVIP-74-A, the applicant is requested to describe how each 

plant-specific AMP addresses the 10 elements. The applicant’s response states that LRA 

Appendix B addresses the required 10 elements. The staff verified that all of the AMPs in LRA 

Appendix B have been defined in accordance with the 10 program elements that are defined in 

the GALL Report and in SRP-LR Appendix A.1. Therefore, the staff finds the applicant’s 

response to be acceptable because the AMPs in LRA Appendix B adequately address the 

10 elements for AMPs recommended in the GALL Report AMP. 

For Action Item 6 in BWRVIP-74-A, the applicant is requested to contain water chemistry 

programs based on monitoring and control guidelines for reactor water chemistry. The 

applicant’s response states that the Water Chemistry Control – BWR Program monitors and 

controls reactor water chemistry in accordance with BWRVIP-190, which supersedes 

BWRVIP-29. The staff noted that the BWR water chemistry guidelines in BWRVIP-190 

represent the updated version of the EPRI BWRVIP water chemistry guidelines in BWRVIP-29 

and implement similar water chemistry control practices as those given in the previous 

BWRVIP-29 report. The staff verified that the corresponding criteria in BWRVIP-190 

implements acceptable water chemistry control practices, including establishment of 

conservative action levels (i.e., acceptance criteria) for the water chemistry parameters that are 

defined in the report and guidelines to implement appropriate corrective actions if those action 

levels are exceeded. Therefore, staff finds the applicant’s basis to be acceptable because the 

staff has verified that the applicant’s conformance with the water chemistry guidelines in 

BWRVIP-190 will provide adequate management of water chemistry at the plant and will be 

capable of mitigating those aging effects that may be induced by postulated abnormal water 

chemistry conditions (e.g., loss of material due to general, pitting, or crevice corrosion; SSC; or 

IGSCC). 

For Action Item 7 in BWRVIP-74-A, the applicant is requested to identify its Reactor Vessel 

Material Surveillance Program. The applicant’s response states that Fermi 2 received NRC 

approval to use the BWRVIP integrated surveillance program (ISP) and applied it to the Reactor 

Vessel Surveillance Program. The staff verified that the applicant’s reactor vessel material 

surveillance program is given in LRA Section B.1.38, “Reactor Vessel Surveillance.” The staff 

also verified that the applicant’s program is an ISP that complies with the requirements for ISPs 

in Appendix H, “Reactor Vessel Material Surveillance Program Requirements,” to 

10 CFR Part 50. The staff finds this response acceptable because the applicant has included 

its Reactor Vessel Surveillance Program in the LRA. SER Section 3.0.3.2.19 provides the 

staff’s evaluation of the Reactor Vessel Surveillance Program and the program’s basis for 

generating relevant reactor vessel data to the reactor vessel neutron irradiation embrittlement 

TLAAs. 
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For Action Item 8 in BWRVIP-74-A, the applicant is requested to verify that its original fatigue 

design cycles have been updated to 60 years of operation and to address the effects of 

environmental fatigue. The applicant’s response states that fatigue during the period of 

extended operation and environmentally assisted fatigue (EAF) have been addressed. The staff 

verified that the applicant has included the metal fatigue evaluations and EAF evaluation LRA 

Section 4.3. Therefore, the staff finds the applicant’s response to the action item acceptable. 

SER Section 4.3 documents the staff’s evaluations of the metal fatigue analyses and EAF 

analyses for ASME Code Class 1 and the metal fatigue analyses for non-ASME Code Class 1 

components. 

For Action Item 9 in BWRVIP-74-A, the applicant is requested to develop a set of 

pressure-temperature (P-T) curves for the heatup and cooldown operating conditions during the 

period of extended operation. The applicant’s response states that P-T curves were developed, 

as discussed in LRA Section 4.2.3, and will be updated as required by Appendix G, “Fracture 

Toughness Requirements,” to 10 CFR Part 50. The staff evaluated the applicant’s TLAA for 

managing the aging effects associated with P-T limits, as discussed in LRA Section 4.2.3, and 

finds the applicant’s response to the action item acceptable. SER Section 4.2.3 documents the 

staff’s evaluation of LRA Section 4.2.3. 

For Action Item 10 in BWRVIP-74-A, the applicant is requested to demonstrate that the beltline 

materials meet the Charpy upper-shelf energy (USE) criteria specified in BWRVIP-74-A, 

Appendix B. The applicant’s response states that the USE was evaluated for reactor vessel 

beltline materials to the end of the period of extended operation (i.e., to 52 effective full-power 

years (EFPY)) to demonstrate continued compliance with the requirements for USE analyses in 

Appendix G to 10 CFR Part 50. The applicant also stated that it calculated the applicable USE 

values for these components in accordance with applicable criteria for USE analyses in 

RG 1.99, “Radiation Embrittlement of Reactor Vessel Materials,” Revision 2, dated May 1988, 

and that the USE analysis is given and discussed in LRA Section 4.2.4. The staff verified that 

the applicant included its TLAA for USE in LRA Section 4.2.4. Therefore, the staff finds the 

applicant’s response to the action item acceptable. SER Section 4.2.4 documents the staff’s 

evaluation of the TLAA for USE. 

For Action Item 11 in BWRVIP-74-A, the applicant can obtain relief from the ISI of the 

circumferential welds during the license renewal period. The applicant’s response states that 

Fermi 2 has received this relief for the remaining term of the original operating term. An 

extension of this relief for the period of extended operation will be submitted to the NRC in 

accordance with 10 CFR 50.55(a), as discussed in LRA Section 4.2.5. The staff verified that the 

applicant included reactor vessel probability of failure analyses (i.e., TLAAs) for the reactor 

vessel circumferential welds in LRA Sections 4.2.5 and will use these TLAAs as the basis for 

submitting a future ISI relief request for the reactor vessel circumferential welds during the 

period of extended operation. Therefore, the staff finds the applicant’s response to the action 

item acceptable. SER Section 4.2.5 documents the staff’s evaluation of this TLAA. 

For Action Item 12 in BWRVIP-74-A, the applicant is requested to monitor axial beltline weld 

embrittlement. The applicant’s response indicates that the previous probability of failure 

analyses for the reactor vessel axial welds is a TLAA for the LRA. The applicant stated that the 

limiting mean adjusted reference temperature (ART) for these welds has been projected to the 

expiration of the period of extended operation (i.e., to 52 EFPY) and has been demonstrated to 

be less than the bounding criteria specified in the BWRVIP report, as discussed in LRA 

Section 4.2.6. The staff verified that the applicant included the applicable TLAA for the reactor 

vessel axial welds in LRA Section 4.2.6. Therefore, the staff finds the applicant’s response to 
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the action item acceptable. SER Section 4.2.6 documents the staff’s evaluation of the 

probability of failure analysis TLAA for the reactor vessel axial welds. 

For Action Item 13 in BWRVIP-74-A, the applicant is requested to either perform neutron 

fluence calculations using staff-approved methodology or submit plant-specific methodology for 

staff review. The applicant’s response states that its neutron fluence calculations were 

performed in accordance with RG 1.190, “Calculational and Dosimetry Methods for Determining 

Pressure Vessel Neutron Fluence,” dated March 2001, as discussed in LRA Section 4.2.1. The 

staff verified that the applicant has included its neutron fluence calculations for the reactor 

vessel beltline components (including those in the extended portion of the beltline) in LRA 

Section 4.2.1 and that the neutron fluence values for these components have been 

appropriately extended to the end of the period of extended operation (i.e., to 52 EFPY). 

Therefore, the staff finds the response acceptable. SER Section 4.2.1 documents the staff’s 

evaluation of the neutron fluence analysis in LRA Section 4.2.1. 

For Action Item 14 in BWRVIP-74-A, indications evaluated in accordance with ASME Code 

Section XI to the end of the original operating term are requested to be re-evaluated for the 

period of extended operation. The applicant’s response states that it analyzed two reactor 

vessel flaw indications to the end of the period of extended operation, as discussed in LRA 

Section 4.7.5. The staff verified that the applicant has included the fracture mechanics 

evaluation TLAA for these flaws in LRA Section 4.7.5. Therefore, the staff finds the applicant’s 

response to the action item acceptable. SER Section 4.7.5 documents the staff’s evaluation of 

fracture mechanics evaluations for these flaws. 

For Action Item 4 in BWRVIP-76, Revision 1, the applicant is requested to reference 

BWRVIP-14-A, BWRVIP-99-A, and BWRVIP-100-A in its evaluation procedures for cracked 

core shroud welds in the reactor vessel internals AMP and to confirm that it will incorporate any 

emerging inspection guidelines. The applicant’s response states that the BWR Vessel Internals 

Program references these BWRVIP reports, specifies that the crack growth rate evaluations and 

fracture toughness values in the reports will be used, and confirms that emerging inspection 

guidelines will be incorporated into the program. The staff verified that the applicant has 

included these BWRVIP reports as part of the methodologies that will be applied in accordance 

with the BWR Vessel Internals Program. Therefore, the staff finds the response acceptable 

because it evaluated the BWR Vessel Internals Program and confirmed that these items were 

referenced in the program. 

For Action Item 5 in BWRVIP-76, Revision 1, the applicant is requested to incorporate the tie 

rod cracking operating experience at Hatch 1 into its AMPs. The applicant’s response states 

that Fermi 2 does not have core shroud with tie rod repairs. The staff reviewed the UFSAR and 

verified that the applicant has yet to implement core shroud modifications, which install tie rod 

repair assemblies. Therefore, the staff finds the applicant’s response acceptable because the 

staff reviewed the UFSAR and confirmed that the Fermi 2 core shroud design does not include 

tie rod repair assemblies. 

For Action Item 6 in BWRVIP-76, Revision 1, the applicant is requested to identify the aging 

effects for the core shrouds and core shroud assembly components if a repair design 

modification has been implemented and to identify the specific AMPs or TLAAs that will be used 

to manage the effects for the period of extended operation. The LRA states that loss of 

material; cumulative fatigue damage; and cracking due to SCC, IGSCC, and IASCC have been 

identified as applicable aging effects for the core shroud. The BWR Vessel Internals Program 

and the Water Chemistry Control – BWR Program will be used to manage the effects of loss of 
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material due to pitting and crevice corrosion and cracking due to SCC, IGSCC, and IASCC. 

The Fatigue Monitoring Program will be used to manage cumulative fatigue damage, as 

discussed in LRA Section 4.3.1.4. 

For Action Item 7 in BWRVIP-76, Revision 1, the applicant is requested to identify and manage 

applicable aging effects for core shroud components or core shroud repair assembly 

components that are made from materials other than stainless steel or nickel alloy. The 

applicant’s response states that this is not applicable because the Fermi 2 core shroud is 

fabricated from Type 304L stainless steel and because no repair hardware has been installed. 

The staff finds this acceptable because the staff reviewed the UFSAR and confirmed the 

applicant’s response. 

For Action Item 8 in BWRVIP-76, Revision 1, the applicant is requested to reference 

BWRVIP-99A and BWRVIP-100-A in its reactor vessel internals AMP. The applicant’s response 

states that these two BWRVIP reports are referenced in the BWR Vessel Internals Program. 

The staff confirmed the reference in the applicant’s program and finds the applicant’s response 

acceptable. 

In the applicant’s annual update of May 9, 2016, the applicant updated the version of the 

BWRVIP-76 being used for the core shroud to BWRVIP-76, Revision 1-A, and indicated that the 

responses to Action Items 4 – 8 are applicable to this version of the BWRVIP report. The staff 

noted that BWRVIP-76, Revision 1, was approved in an NRC safety evaluation dated 

December 28, 2015 (ADAMS Accession No. ML15307A468), and that the change in the title to 

Revision 1-A of the report was strictly an administrative change that is part of EPRI’s BWRVIP 

report review process. The staff noted that BWRVIP-76, Revision 1-A, remains within the scope 

of the referenced safety evaluation, and that use of Revision 1-A of the report would not alter 

any of the applicant’s response bases for resolving Action Items 4 – 8. Therefore, based on this 

review, the staff finds the use of BWRVIP-76, Revision 1-A, to be acceptable because: 

(a) Revision 1-A of the report remains within the scope of the referenced safety evaluation of 

December 28, 2015, and (b) the applicant’s bases for resolving Action Items 4 – 8 in the 

BWRVIP-76, Revision 1, methodology remain within the scope of Revision 1-A of the report. 

Operating Experience. LRA Section B.1.10 summarizes operating experience related to the 

BWR Vessel Internals Program. The staff reviewed operating experience information in the 

application and during the audit to determine whether the applicable aging effects and industry 

and plant-specific operating experience were reviewed by the applicant. The staff noted that the 

applicant has identified relevant plant-specific operating experience. Flaw indications have 

been found on the steam dryer support ring and the thermal sleeve to elbow weld on jet pump 

risers. The other indications were determined not to have operability or safety impacts as 

confirmed by followup inspections. The applicant identified cracked retainer screw tack welds 

and restrainer bracket wear on jet pumps. This was repaired by the installation of auxiliary 

spring wedges and a slip joint clamp. As discussed in the Audit Report, the staff conducted an 

independent search of the plant operating experience information to determine whether the 

applicant had adequately evaluated and incorporated operating experience related to this 

program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 
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addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M9 was evaluated. 

UFSAR Supplement. LRA Section A.1.10 provides the UFSAR supplement for the BWR Vessel 

Internals Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. 

The staff also noted that the applicant committed to (1) evaluate CASS and X-750 alloy reactor 

vessel internals components for susceptibility to neutron or thermal embrittlement before the 

period of extended operation, (2) inspect reactor vessel internals components susceptible to 

thermal aging, neutron fluence, and cracking before or within 5 years after entering the period of 

extended operation, and (3) install core plate wedges or complete a plant-specific analysis 

associated with inspections of the core plate hold-down bolts. Enhancement 3 was amended by 

letter dated April 27, 2015, as documented in the staff’s evaluation of the applicant’s response 

to Action Item 4 in BWRVIP-25 in the section entitled, “Review of License Renewal Applicant 

Action Items – Appendix C,” of this evaluation. 

In addition, as a result of its responses to RAIs B.1.10-3 and 4.1-4a, the applicant amended 

LRA Section A.1.10 to state that the BWR Vessel Internals Program will also be enhanced to 

state how the three conditions/limitations associated with BWRVIP-183 are addressed to justify 

its use of the flaw evaluation methodology and that the BWR Vessel Internals Program 

procedures will be revised to perform opportunistic inspections of the differential pressure and 

standby liquid control line inside the reactor vessel when the line becomes accessible. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s BWR Vessel Internals 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation before the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Compressed Air Monitoring 

Summary of Technical Information in the Application. LRA Section B.1.11 describes the 

existing Compressed Air Monitoring Program as consistent, with an exception and 

enhancements, with GALL Report AMP XI.M24, “Compressed Air Monitoring.” The LRA states 

that the AMP addresses loss of material in piping, compressors, dryers, aftercoolers, and filters 

in compressed air systems by periodically monitoring air samples for moisture and contaminants 

and by opportunistically inspecting internal surfaces within compressed air systems. The LRA 

also states that the inspection frequency, acceptance criteria, and design and operating reviews 

are conducted in accordance with Fermi 2’s response to NRC GL 88-14, “Instrument Air Supply 

Problems Affecting Safety-Related Equipment,” dated August 8, 1988. 
3-86 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M24. The staff also reviewed the 

portions of the “scope of program,” “preventive actions,” “parameters monitored or inspected,” 

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria” program 

elements associated with an exception and enhancements to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

the exception and enhancements follows. 

Exception. LRA Section B.1.11 includes an exception to the “monitoring and trending” program 

element. In this exception, the applicant stated that the dew point testing and trending is 

performed quarterly rather than daily as recommended in the GALL Report. The staff reviewed 

this exception against the corresponding program element in GALL Report AMP XI.M24 and 

finds it acceptable because taking quarterly air samples for dew point and contaminants is 

consistent with the guidance in ASME Code OM-S/G-1998, Part 17, “Performance Testing of 

Instrument Air System in Light-Water Reactor Power Plant,” dated 1998. Additionally, the 

applicant reviewed operating experience and recent system health reports and did not find any 

indication that components’ intended functions have been compromised. The staff’s 

independent review of operating experience confirmed the applicant’s claim. 

Enhancement 1. LRA Section B.1.11 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that the procedures will be revised 

to periodically sample, test, and monitor moisture and corrosive contaminants to verify that 

parameters are within acceptable limits in the EDG starting air system to mitigate aging effects, 

such as loss of material due to corrosion. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M24 and finds it acceptable because, 

when it is implemented, it will ensure that moisture and contaminants in the EDG starting air 

system are maintained below acceptable limits. 

Enhancement 2. LRA Section B.1.11 includes an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements. In this enhancement, the applicant stated that procedures will be revised to 

include periodic and opportunistic inspections of accessible internal surfaces of piping, 

compressors, dryers, aftercoolers, and filters. Procedures will also be revised to include 

recommendations from EPRI NP-7079, “Instrument Air System – A Guide for Power Plant 

Maintenance,” dated December 1990; EPRI TR-108147, “Compressed Air System Maintenance 

Guide,” dated March 1998; and ASME Code OM-S/G-1998, Part 17, for air system 

contaminants, inspection frequency, inspection methods, and acceptance criteria for 

components subject to an AMR that are exposed to compressed air in the EDG starting air 

system and control air system. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M24 and finds it acceptable because, when it is 

implemented, it will ensure that visual inspections will be conducted and that applicable 

recommendations for air quality and inspection will be incorporated consistent with the guidance 

in the GALL Report AMP. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M24. The staff also reviewed the exception associated with 

the “monitoring and trending” program element and its justification and finds that the AMP, with 

the exception, is adequate to manage the applicable aging effects. In addition, the staff 

reviewed the enhancements associated with the “scope of program,” “preventive actions,” 
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“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements and finds that, when implemented, they will make the AMP adequate to 

manage the applicable aging effects. 

Operating Experience. LRA Section B.1.11 summarizes operating experience related to the 

Compressed Air Monitoring Program. 

In 2007, a walkdown of EDG tubing looked for damaged tubing, tubing routinely taken apart that 

should be replaced, tubing rubbing against something that could lead to wear, tubing not 

properly restrained in clamps (at an angle), and operation of a valve that could flex tubing. The 

walkdown identified bent tubing in the EDG starting air system. A work order was placed, and 

the tube was repaired. 

In August 2011, the applicant issued a corrective action report due to unsatisfactory dew point 

readings on the west interruptible air supply dryer. The long-term solution is to replace the 

obsolete air dryer controllers with an equivalent controller. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M24 was evaluated. 

UFSAR Supplement. LRA Section A.1.11 provides the UFSAR supplement for the Compressed 

Air Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed to implement the enhancements to the program 

before the period of extended operation. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program. 

Conclusion. Based on its audit and review of the applicant’s Compressed Air Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. In addition, the staff reviewed the enhancements and confirmed that 

their implementation before the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 
3-88 

 Containment Inservice Inspection – IWE 

Summary of Technical Information in the Application. LRA Section B.1.12 describes the 

existing Containment Inservice Inspection – IWE (CII IWE) Program, with enhancements, as 

consistent with GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE.” Fermi 2 has a 

General Electric Mark I pressure suppression steel containment, which consists of a drywell, a 

torus, and a vent system connecting the drywell and torus. The current interval code of record 

for examination of the containment is “in accordance with ASME Code Section XI, 

Subsection IWE, 2001 Edition with the 2003 Addenda, as mandated and modified by 

10 CFR 50.55a.” The LRA states that the AMP is a condition-monitoring program and manages 

the effects of aging on the free-standing steel containment vessel and its integral attachments, 

containment hatches, airlocks, moisture barriers, and pressure-retaining bolting. The LRA also 

states that the AMP proposes to manage these aging effects through periodic visual 

examinations (general visual, VT-1, and VT-3) to assess the general condition of the 

containment and to detect evidence of degradation that may affect structural integrity or leak 

tightness. The LRA further states that visual inspections monitor loss of material of the steel 

containment vessel surface areas, including welds and base metal and containment vessel 

integral attachments, metal shell, personnel and equipment access hatches, and 

pressure-retaining bolting. The program addresses the aging management activities of 

LR-ISG-2006-01, “Plant-Specific Aging Management Program for Inaccessible Areas of Boiling 

Water Reactor (BWR) Mark I Steel Containments Drywell Shell,” dated November 16, 2006, for 

inaccessible areas of BWR Mark I drywell shell. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 7 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S1. 

For the “preventive action,” “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” and “corrective actions” program elements, the staff determined the 

need for additional information, which resulted in the issuance of RAIs, as discussed below. 

The “preventive action” program element of GALL Report AMP XI.S1 recommend preventive 

actions in accordance with the Research Council for Structural Connections (RCSC) report 

entitled, “Specification for Structural Joints Using ASTM A325 or A490 Bolts,” dated 

June 30, 2004 (hereinafter referred to as the RCSC report), for structural bolting consisting of 

ASTM A325, ASTM F1852, and ASTM A490 bolts. The staff noted during its audit that the 

corresponding element, with enhancements, of the LRA AMP basis document addresses 

ASTM A325 and ASTM A490 bolting but made no mention of ASTM F1852 bolting. The staff 

was not clear if the above mentioned program element of the LRA AMP is consistent with the 

recommendations in the GALL Report AMP because there was no mention of ASTM F1852 

bolting. Therefore, by letter dated November 25, 2014, the staff issued a common RAI B.1.42-1 

across LRA AMPs B.1.42, B.1.22, and B.1.12 requesting that the applicant clarify whether 

ASTM F1852 structural bolting was used in Fermi 2 structures and, if so, explain how the effects 

of aging will be adequately managed for this bolting type. 

In its response to RAI B.1.42-1 dated December 26, 2014, the applicant confirmed that the 

Fermi 2 plant does not use ASTM F1852 structural bolting based on a review of applicable site 

documents, material management and inventory systems, and consulting cognizant plant 

personnel. 
3-89 

The staff finds the applicant’s response acceptable because the applicant confirmed that 

ASTM F1852 structural bolting was not used at Fermi 2. The staff’s concern described in 

RAI B.1.42-1 is resolved. 

The “detection of aging effects” program element in GALL Report AMP XI.S1 recommends that 

the program be augmented to require surface examination, in addition to visual examination, to 

detect cracking in (a) stainless steel and dissimilar metal welds of penetration sleeves, 

penetration bellows, and vent line bellows and (b) steel components that are subject to cyclic 

loading but have no CLB fatigue analysis. This program element also states that, where 

feasible, appropriate Appendix J to 10 CFR Part 50 tests may be performed in lieu of surface 

examination. However, during its audit, the staff found that the “detection of aging effects” 

program element of the applicant’s Containment Inservice Inspection – IWE Program states that 

stainless steel penetration sleeves, dissimilar metal welds, bellows, and steel components that 

are subject to cyclic loading but have no CLB fatigue analysis are monitored for cracking. It also 

states that the Containment Leak Rate Program (Appendix J to 10 CFR Part 50) tests may be 

performed in lieu of surface examination. It was not clear that the method for detecting cracking 

in these components is consistent with that described in GALL Report AMP XI.S1. Additionally, 

for components that may be subject to Appendix J tests in lieu of surface examination, the 

program did not mention the type of Appendix J test that would be performed for the specific 

components to allow the staff to evaluate the appropriateness of the test to detect cracking. By 

letter dated December 16, 2014, the staff issued RAI B.1.12-1 requesting that the applicant 

state whether supplemental surface examinations will be performed as recommended in the 

GALL Report on the following specified components: (a) stainless steel and dissimilar metal 

welds of penetration sleeves, penetration bellows, and vent line bellows and (b) steel 

components that are subject to cyclic loading but have no CLB fatigue analysis. If such 

examinations will be performed, the applicant should indicate what standard will be used to 

perform surface examination of the stainless steel and dissimilar metal welds. The staff also 

requested that, if Appendix J tests are used in lieu of surface examinations for certain 

components, the applicant indicate the type of Appendix J test that will be used and justify its 

appropriateness. 

In its response to RAI B.1.12-1 dated January 15, 2015, the applicant stated that the penetration 

sleeves at Fermi 2 are of carbon steel material but some include dissimilar metal welds. The 

penetration bellows and the dissimilar metal welds of the penetration sleeves are inaccessible, 

and it is not possible to perform a surface examination. The applicant also explained that due to 

the industrial safety hazards (i.e., steep angle pipe configuration, high radiation area, 

contamination area, and confined space), it is not feasible to perform a supplemental surface 

examination on the torus vent line bellows. Therefore, the supplemental surface examination 

discussed in GALL Report AMP XI.S1 will not be performed for the components with stainless 

steel or dissimilar metal welds. The applicant further stated that, as allowed by 

recommendations in the “detection of aging effects” program element of GALL Report 

AMP XI.S1, it plans to credit the conduct of test under Appendix J to 10 CFR Part 50 (GALL 

Report AMP XI.S4) in lieu of surface examination to supplement Subsection IWE general visual 

examinations for detecting cracking in stainless steel or dissimilar metal welds of containment 

pressure-retaining penetration sleeves and bellows (penetration and vent line) components. 

The applicant further explained that the Appendix J tests that are performed on the penetration 

sleeves, penetration bellows, and torus vent line bellows are Type B tests (for bellows) and 

Type A integrated leak rate tests (for bellows and sleeves) in accordance with the Fermi 2 

Containment Leak Rate Program (LRA Section B.1.13) and are consistent with GALL Report 

AMP XI.S4. The applicant also stated that with the low leak rate acceptance criterion for the 

bellows at Fermi 2 of less than or equal to 1 scfh, the Type B testing is able to detect extremely 
3-90 

small leaks due to cracking in the bellows before loss of intended function. The applicant also 

clarified that the evaluation of its applicable bellows (i.e., torus vent line bellows) against the 

operating experience described in NRC IN 92-20, “Inadequate Local Leak Rate Testing,” dated 

March 3, 1992, concluded that the bellows construction is that which allows a Type B test to be 

performed. The applicant also stated that it did not identify any containment steel components 

at Fermi 2, including the sleeve and bellows components with stainless steel or dissimilar metal 

welds described above, that are subject to cyclic loading but have no CLB fatigue analysis. The 

applicant concluded that its use of Appendix J tests for stainless steel or dissimilar metal welds 

of penetration sleeves and bellows, in lieu of supplemental surface examination, is consistent 

with the “detection of aging effects” program element of GALL Report AMP XI.S1. The 

applicant revised LRA Sections A.1.12 and B.1.12 to clarify that the alternative of Appendix J 

tests is being used for the stainless steel and dissimilar metal welds of the penetration sleeves, 

penetration bellows, and torus vent line bellows, as allowed by GALL Report AMP XI.S1. The 

applicant also included wording that the program specifies (Subsection IWE) augmented 

inspections as required. 

The response to RAI B.1.12-1 clarified that supplemental surface examination will not be 

performed because the penetration sleeves (carbon steel) with dissimilar metal welds and the 

penetration bellows (stainless steel) are inaccessible at Fermi 2, and because of the industrial 

safety hazards, it is also not feasible to perform a supplemental surface examination on the 

torus vent line bellows (stainless steel). Alternatively, the applicant will perform applicable and 

feasible Appendix J tests (Type A and Type B tests for penetration and vent line bellows and 

Type A tests for dissimilar metal welds of penetration sleeves) in lieu of surface examination, 

which is consistent with the recommendation of GALL Report AMP XI.S1. The Type B tests will 

have a low administrative leak rate acceptance criteria able to detect small leaks through 

cracks, and for the case in which the Type B test is not feasible (dissimilar metal welds of 

penetration sleeves), the Type A test would reflect leakage from cracking; therefore, the use of 

Type A and Type B leak tests is an appropriate supplemental means of detecting cracking. The 

applicant also clarified that there are no containment pressure-retaining steel components at 

Fermi 2 that are subject to cyclic loading but have no CLB fatigue analysis. 

The staff finds the applicant’s response acceptable because the response confirms that the 

applicant will use appropriate and feasible Type A and Type B leak rate tests under Appendix J 

to 10 CFR Part 50 in lieu of supplemental surface examination to detect cracking in dissimilar 

metal welds of penetration sleeves and in stainless steel penetration bellows and torus vent line 

bellows, which is consistent with the recommendations of GALL Report AMP XI.S1. The staff’s 

concern described in RAI B.1.12-1 is resolved. 

The “preventive action” program element in GALL Report AMP XI.S1 recommends that the 

program be augmented to include preventive actions that ensure that moisture levels associated 

with an accelerated corrosion rate do not exist in the exterior portion of the BWR Mark I steel 

containment drywell shell. The actions consist of ensuring that the sand pocket area drains 

and/or the refueling seal drains are clear. The “parameters monitored or inspected” program 

element of GALL Report AMP XI.S1 recommends that applicants with BWR Mark I steel 

containments should monitor sand pocket area drains and/or the refueling seal drains for water 

leakage and should ensure that the drain lines are clear to prevent moisture levels associated 

with accelerated corrosion rates in the exterior portion of the drywell shell. However, during its 

audit, the staff found that the applicant’s enhancements to the “preventive action,” “parameters 

monitored or inspected,” and “detection of aging effects” program elements (associated with 

Commitment Nos. 9a, 9d, and 9e) do not clearly demonstrate consistency with the GALL 

Report, as claimed in LRA Section B.1.12. The staff identified the need for additional 
3-91 

information to determine that the proposed enhancements are consistent with the 

recommendation for BWR Mark I steel containments in the “preventive actions” and “parameters 

monitored or inspected” program elements. By letter dated December 16, 2014, the staff issued 

RAI B.1.12-2 requesting that the applicant clarify whether the intent of Commitment Nos. 9a, 9d, 

and 9e is to revise plant procedures before the period of extended operation or to revise plant 

procedures and perform inspection of drain lines before the period of extended operation. The 

staff also requested that the applicant describe the objective(s) for the program enhancements 

as listed in Commitment Nos. 9a and 9d and to provide the frequency of inspection associated 

with Commitment Nos. 9a, 9d, and 9e. Further, the staff requested that the applicant clarify 

whether the LRA AMP B.1.12 includes actions to ensure that the refueling seal drains are clear 

to prevent moisture levels associated with accelerated corrosion rates in the exterior portion of 

the drywell shell. 

In its response dated January 15, 2015, the applicant stated that the objective for the sand 

cushion drain lines inspections in Commitment Nos. 9a and 9d is to determine the internal 

condition (e.g., moisture, sand, and blockage) and to confirm that the drains are not blocked. 

The applicant also stated that the inspections will be performed one time before the period of 

extended operation and once every 10 years during the period of extended operation. The 

applicant explained that the sand cushion drain lines have been inspected for blockage twice so 

far, with the most recent inspection being in 2014, after approximately 29 years of plant 

operation. The inspections revealed that the drain lines were not blocked or obstructed; 

therefore, based on the Fermi 2 operating experience, an additional inspection before the period 

of extended operation and once every 10 years during the period of extended operation are 

considered appropriate to ensure that the sand cushion drain lines are clear. 

The applicant further clarified in its response that its Containment Inservice Inspection – IWE 

Program does include actions to visually check the refueling seal drain line and the sand 

cushion area drain lines for water leakage every RFO to prevent accumulation of moisture on 

the exterior portion of the drywell shell. The applicant explained in detail that it is not practical to 

inspect the refueling seal drain line to ensure it remains clear because the opening to the drain 

line itself is inaccessible because it is sealed off by the drywell seals bellows assembly and 

associated plates, which constitute a welded seal boundary. The applicant further explained 

that, based on the stainless steel material, fatigue design, and water chemistry management, 

leakage through the drywell seal bellows is unlikely. However, the sand cushion area drain 

lines have been inspected and will be inspected again before and during the period of extended 

operation to ensure they are not blocked. The applicant further stated that, because GALL 

Report AMP XI.S1 recommends that the sand cushion area drains and/or (emphasis added) 

refueling sealing drains are monitored for water leakage, ensuring that the drains are clear, its 

commitment to monitor only the sand cushion drain lines for blockage is consistent with the 

GALL Report recommendations. The applicant also revised and consolidated license renewal 

Commitment Nos. 9a, 9d, and 9e into one commitment designated Commitment No. 9a to 

clarify the timing and frequency of the sand cushion drain line internal inspections. This revised 

Commitment No. 9a to be implemented before the period of extended operation and that is 

applicable to “preventive action,” “parameters monitored or inspection,” and “detection of aging 

effects” program elements states, “Revise plant procedures to require inspection of the sand 

cushion drain lines (e.g., for moisture, sand, [and] blockage) and [to] ensure there is no 

evidence of blockage at least once prior to the period of extended operation and once every 

10 years during the period of extended operation.” The applicant revised LRA Sections A.1.12, 

A.4, and B.1.12 to delete Commitment Nos. 9d and 9e and to reflect the revised 

Commitment No. 9a. 
3-92 

The applicant’s response clarified that the objective of Commitment Nos. 9a, 9d, and 9e 

(revised and consolidated in the response as Commitment No. 9a) is to inspect the sand 

cushion drain lines to determine its internal condition to confirm that they are clear (i.e., not 

blocked). The revised Commitment No. 9a clearly states that the sand cushion drain lines will 

be inspected to determine the internal condition and to ensure they are not blocked once before 

the period of extended operation and once every 10 years during the period of extended 

operation. The staff finds the timing and frequency of the inspections reasonable to ensure that 

the sand cushion drain lines are clear during the period of extended operation. The response 

further clarified and justified that, even though the refueling seal drains cannot be inspected for 

blockage, the commitment to inspect only the sand cushion drain lines for internal condition 

(e.g., moisture, sand, and blockage) and blockage is consistent with the GALL Report 

recommendations to prevent moisture levels associated with accelerated corrosion rates in the 

exterior portion of the drywell shell. 

The staff finds the applicant’s response acceptable because the revised and consolidated 

enhancement (Commitment No. 9a) in the response clearly states the objective, timing, and 

frequency of the applicant’s commitment to inspect the sand cushion drain lines to ensure they 

are clear, which demonstrates consistency with the GALL Report recommendations to prevent 

moisture levels associated with accelerated corrosion rates in the exterior portion of the drywell 

shell. The staff’s concern described in RAI B.1.12-2 is resolved. 

The “preventive action” program element in GALL Report AMP XI.S1 recommends that the 

program be augmented to include preventive actions that ensure that moisture levels associated 

with an accelerated corrosion rate do not exist in the exterior portion of the BWR Mark I steel 

containment drywell shell. The “parameters monitored or inspected” program element of GALL 

Report AMP XI.S1 recommends that applicants with BWR Mark I steel containments should 

monitor sand pocket area drains and/or the refueling seal drains for water leakage and should 

ensure that the drain lines are clear to prevent moisture levels associated with accelerated 

corrosion rates in the exterior portion of the drywell shell. However, during its audit, the staff 

found contradictory statements between the “preventive actions” and “parameters monitored or 

inspected” program elements of the LRA AMP. The “preventive actions” program element 

states the following: 

During refueling the refueling bellows drain empties into a manifold which is 

equipped with a sight glass. This sight glass is monitored when the refueling 

pool is flooded to detect potential leakage of water into the space around the 

drywell shell. The sand pocket drains are also being monitored for signs of 

moisture. Fermi 2 plans to re-inspect the drain lines to verify their condition prior 

to the period of extended operation to confirm that these preventative actions are 

not warranted (emphasis added). The program will be enhanced to require 

inspection of the sand pocket drain lines prior to the period of extended 

operation. 

The “parameters monitored or inspected” program element states that “Fermi 2 performs routine 

surveillances of the drains to record the observed condition of the drain lines for any leakage. 

Fermi 2 will inspect the sand pocket drain lines to verify their condition prior to the period of 

extended operation to confirm that the sand pocket drains are clear.” As documented in the 

Audit Report, the staff noted that Fermi 2 Surveillance Procedure 24.000.03 required inspection 

of the reactor-drywell seal bellows and the four sand cushion drain lines for leakage every RFO, 

as part of regulatory commitments made in response to NRC GL 87-05, “Request for Additional 

Information Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation 
3-93 

of Mark I Drywells.” However, it was not clear if the periodic monitoring of the sand cushion 

drain lines and refueling seal bellows for water leakage every RFO will continue consistent with 

the recommendations in the “parameters monitored or inspected” program element of GALL 

Report AMP XI.S1. By letter dated December 16, 2014, the staff issued RAI B.1.12-3 

requesting that the applicant confirm if the refueling seal bellows and the sand cushion drain 

lines of the Fermi 2 Mark I steel containment will continue to be monitored periodically every 

RFO for water leakage or signs of moisture during the period of extended operation. The staff 

also requested that the applicant clarify the apparently contradictory statement that “Fermi 2 

plans to re-inspect the drain lines to verify their condition prior to the period of extended 

operation to confirm that these preventive actions are not warranted.” 

In its response to RAI B.1.12-3 dated January 15, 2015, the applicant stated that it plans to 

continue monitoring of the drywell seal bellows and sand cushion drain lines every RFO for 

water leakage or signs of moisture through the period of extended operation. The applicant 

clarified that the statement “to confirm that these preventative actions are not warranted” was 

intended to indicate that periodic confirmation that the sand cushion drain lines were clear is not 

necessary during the period of extended operation. The applicant further explained that, as 

discussed in the response to RAI B.1.12-2, it revised Commitment No. 9a to specify inspection 

of the drain lines to verify their condition before the period of extended operation and once every 

10 years during the period of extended operation. 

The staff finds the applicant’s response acceptable because the applicant (a) confirmed that the 

reactor drywell seal bellows and the four sand cushion drain lines will continue to be monitored 

for water leakage every RFO during the period of extended operation, and (b) clarified that, 

based on its revised Commitment No. 9a in response to RAI B.1.12-2, the sand cushion drain 

lines will be inspected to ensure that they are clear once before the period of extended 

operation and once every 10 years during the period of extended operation. These actions are 

consistent with the recommendations of the “parameters monitored or inspected” program 

element of GALL Report AMP XI.S1 with regard to BWR Mark I steel containment. The staff’s 

concern described in RAI B.1.12-3 is resolved. 

The “monitoring and trending” program element in GALL Report AMP XI.S1 recommends that, 

for plants with a BWR Mark I containment, license renewal applicants develop a corrosion rate 

that can be inferred from past ultrasonic thickness measurements or establish a corrosion rate 

using representative alternate means to provide a technical basis based on the developed or 

established corrosion rate that the drywell will have sufficient thickness to perform its intended 

function through the period of extended operation. However, during its audit, the staff found that 

the applicant’s enhancement (Commitment No. 9f) to the “monitoring and trending” program 

element of the Containment Inservice Inspection – IWE Program states, “Revise plant 

procedures to determine drywell shell thickness in the sand pocket areas before the period of 

extended operation. From the results, develop a corrosion rate to demonstrate that the drywell 

shell will have sufficient thickness to perform its intended function through the period of 

extended operation.” The staff also noted that, for justified reasons summarized in LRA 

Section B.1.12, ultrasonic thickness measurements of the drywell shell sand pocket areas were 

not performed at Fermi 2 in response to NRC GL 87-05. It was not clear to the staff that this 

enhancement would make the program consistent with the GALL Report because the proposed 

enhancement (Commitment No. 9f) does not indicate the minimum number of sets and interval 

at which UT measurements will be performed and because it does not provide the technical 

basis of how an appropriate corrosion rate will be developed if only one set of UT 

measurements is intended. By letter dated December 16, 2014, the staff issued RAI B.1.12-4 

requesting that the applicant state the minimum number of sets of UT measurements and the 
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interval at which they will be performed to determine the corrosion rate of the drywell shell sand 

pocket area and provide the technical basis that the drywell shell will have sufficient thickness to 

perform its intended function through the period of extended operation. If only one set of UT 

measurements will be performed, the staff requested that the applicant provide the technical 

basis of how an appropriate or conservatively biased corrosion rate will be developed based on 

one set of UT measurements. 

In its response to RAI B.1.12-4 dated January 15, 2015, the applicant stated the following: 

One set of UT measurements was taken in spring of 2014 (RF16) on the drywell 

shell sand cushion area. The measurements were taken from [azimuth] 

300 degrees progressing clockwise every 12 inches and ending at [azimuth] 

120 degrees. One reading was taken at the moisture barrier and another reading 

was taken approximately 6 inches above the moisture barrier. Out of the 

150 readings taken, the lowest reading was 1.557 inches and the highest reading 

was 1.690 inches. All measurements were above the nominal design value of 

1.5 inches, with no apparent material loss after almost 30 years of operation, so 

there is reasonable assurance that the drywell shell will have sufficient thickness 

to perform its intended function throughout the period of extended operation 

(PEO). A second set of UT measurements will be taken prior to the PEO [period 

of extended operation] to determine a corrosion rate from the two sets. UT 

measurements will be re-performed once each interval (i.e. ten [10] years) during 

PEO [period of extended operation]. 

The applicant also revised the program enhancement (Commitment No. 9f) in LRA 

Sections A.1.12, A.4, and B.1.12 to reflect the schedule and interval, indicated in the response 

above, at which drywell shell thickness will be determined to develop the corrosion rate. 

The staff notes that the set of 150 UT measurements made of the drywell shell sand pocket 

area in spring 2014 demonstrate that all the measured thickness values are above the nominal 

design thickness of 1.5 inches, indicating no apparent significant corrosion degradation after 

30 years of operation. The applicant clarified that two sets of UT measurements of the sand 

cushion area taken before the period of extended operation, approximately 10 years apart, will 

be used to determine the corrosion rate of the drywell shell. The corrosion rate will be further 

confirmed by performing UT measurements at a 10-year interval during the period of extended 

operation. The staff finds the applicant’s response acceptable because (a) the applicant’s 

commitment to determine the corrosion rate of the drywell shell based on two sets of UT 

measurements of the sand cushion before the period of extended operation, followed by 

confirmatory UT measurements on a10-year interval during the period of extended operation, 

will provide an adequate technical basis to demonstrate that the drywell shell will have sufficient 

thickness to perform its intended function through the period of extended operation, (b) the 

applicant revised the commitment to reflect the schedule and interval of UT measurements 

before and during the period of extended operation, and (c) the response clarified consistency 

of the program element with the GALL Report. The staff’s concern described in RAI B.1.12-4 is 

resolved. 

The “corrective actions” program element in GALL Report AMP XI.S1 recommends that, if 

moisture has been detected or suspected in the inaccessible area on the exterior of the Mark I 

containment drywell shell or if the source of moisture cannot be determined subsequent to a 

root cause analysis, then the following applies: 
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 Include in the scope of license renewal any components that are identified as a source 

of moisture, if applicable, such as the refueling seal or cracks in the stainless liners of 

the refueling cavity pools walls, and perform an AMR. 

 Identify surfaces requiring examination by implementing augmented inspections for the 

period of extended operation in accordance with Subsection IWE-1240, as identified in 

Table IWE-2500-1, “Examination Category E-C.” 

 Use examination methods that are in accordance with Subsection IWE-2500. 

 Demonstrate, through use of augmented inspections performed in accordance with 

Subsection IWE, that corrosion is not occurring or that corrosion is progressing so slowly 

that the age-related degradation will not jeopardize the intended function of the drywell 

shell through the period of extended operation. 

However, during its audit, the staff found that the applicant’s Containment Inservice Inspection – 

IWE Program did not address the above action of GALL Report AMP XI.S1, which recommends 

including any components that are identified as a source of moisture, if applicable, within the 

scope of license renewal and performing an AMR. It was not clear that the “corrective actions” 

program element of the Containment Inservice Inspection – IWE Program is consistent with the 

recommendations in GALL Report AMP XI.S1, as claimed in the LRA. By letter dated 

December 16, 2014, the staff issued RAI B.1.12-5 requesting that the applicant clarify whether 

applicable components that are sources of moisture to inaccessible areas of the Mark I 

containment drywell shell exterior have been identified and subjected to an AMR and, if so, that 

it list the components that have been identified as potential sources of moisture to inaccessible 

areas of the drywell exterior. 

In its response dated January 15, 2015, the applicant stated that the components that are 

potential sources of moisture to the inaccessible area of the drywell exterior are the reactor 

cavity liner and the refueling bellows assembly. The applicant stated that these components are 

subject to an AMR as indicated in LRA Table 2.4-1 and that the AMR results are provided in 

LRA Table 3.5.2-1. The applicant further stated that, as noted in LRA Table 3.5.2-1, loss of 

material for the stainless steel reactor cavity liner is managed by the Water Chemistry Control – 

BWR AMP, and loss of material for the refueling bellows assembly is managed by the Water 

Chemistry Control-BWR and Structures Monitoring AMPs. 

The staff reviewed LRA Table 2.4-1 and verified that the reactor cavity liner and the refueling 

bellows assembly were included as components subject to an AMR. The staff also reviewed 

LRA Table 3.5.2-1 and verified that applicable aging effects (i.e., loss of material and cracking) 

that could result in leakage from these components were being managed using appropriate 

AMPs and/or TLAAs. The staff finds the applicant’s response acceptable because the applicant 

confirmed that it addressed recommended Item (a) in the “corrective actions” program element 

of GALL Report AMP XI.S1 by identifying the components that are potential sources of moisture 

to inaccessible areas of the drywell exterior, provided references to the LRA tables that 

document these components that were subjected to AMR and the AMR results, and provided a 

response that clarified consistency of the program element with the GALL Report. The staff’s 

concern described in RAI B.1.12-5 is resolved. 

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “corrective actions” 

program elements associated with enhancements to determine whether the program will be 
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adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows. 

Enhancement 1. LRA Section B.1.12 includes an enhancement to the “preventive actions” 

program element. In this enhancement (Commitment 9b), the applicant stated that, before the 

period of extended operation, plant procedures will be revised to specify the preventive actions 

delineated in NUREG-1339 and in EPRI NP-5769, EPRI NP-5067, “Good Bolting Practices – A 

Reference Manual for Nuclear Power Plant Maintenance Personnel, Volume 1: Large Bolt 

Manual, 1987; Volume 2: Small Bolts and Threaded Fasteners, 1990,” and EPRI TR-104213 

that emphasize proper selection of bolting material, installation torque or tension, and use of 

lubricants and sealants for high strength bolting. The staff reviewed this enhancement against 

the corresponding program element in GALL Report AMP XI.S1 and finds it acceptable 

because, when it is implemented, it will provide guidance for “preventive actions” to ensure 

integrity of structural bolting, which is consistent with the recommendations of GALL Report 

AMP XI.S1. 

Enhancement 2. LRA Section B.1.12, as clarified by letter dated December 26, 2014, in 

response to RAI B.1.42-1, includes an enhancement to the “preventive actions” program 

element. In this enhancement (Commitment No. 9c), the applicant stated that, before the period 

of extended operation, plant procedures will be revised to include the preventive actions for 

ASTM A325 and ASTM A490 bolting from Section 2 of the Research Council for Structural 

Connection publication entitled, “Specification for Structural Joints Using ASTM A325 or A490 

Bolts.” The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S1 and finds it acceptable because, when it is implemented, it will provide 

guidance for “preventive actions” to ensure integrity of ASTM A325 and/or ASTM A490 

structural bolting, which is consistent with the recommendations of GALL Report AMP XI.S1. 

Enhancement 3. LRA Section B.1.12, as amended by letter dated January 15, 2015 in 

response to RAI B.1.12-2, includes an enhancement applicable to the “preventive actions,” 

“parameters monitored or inspected,” and “detection of aging effects” program elements. In this 

enhancement (Commitment No. 9a), the applicant committed to revise plant procedures, before 

the period of extended operation, to require inspection of the sand cushion drain lines (e.g., for 

moisture, sand, and blockage) and to ensure there is no evidence of blockage at least once 

before the period of extended operation and once every 10 years during the period of extended 

operation. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S1 and finds it acceptable because, when it is implemented, it will ensure 

that moisture levels associated with accelerated corrosion rates do not exist in the exterior 

portion of the Fermi 2 Mark I steel containment drywell shell by taking preventive actions that 

are consistent with the recommendations of GALL Report AMP XI.S1. 

Enhancement 4. LRA Section B.1.12, as amended by letter dated January 15, 2015 in 

response to RAI B.1.12-4, includes an enhancement to the “monitoring and trending” program 

element. In this enhancement (Commitment No. 9f), the applicant committed to revise plant 

procedures to determine the drywell shell thickness in the sand cushion areas before the period 

of extended operation and once in each 10-year interval during the period of extended 

operation. From the results (including prior results), the applicant committed to develop a 

corrosion rate to demonstrate that the drywell shell will have sufficient wall thickness to perform 

its intended function through the period of extended operation. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.S1 and finds 

it acceptable because, when it is implemented, it will provide a technical basis, consistent with 

the GALL Report recommendations for Mark I steel containment, to develop a corrosion rate 
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and to demonstrate that the drywell shell will have sufficient wall thickness to perform its 

intended function through the period of extended operation. 

Enhancement 5. LRA Section B.1.12, as clarified by letter dated January 15, 2015 in response 

to RAI B.1.12-5, includes an enhancement to the “corrective actions” program element. In this 

enhancement (Commitment No. 9g), the applicant committed to revise plant procedures, before 

the period of extended operation, to require corrective actions if moisture is detected or 

suspected in the inaccessible area on the exterior of the drywell shell. The three corrective 

actions include the following: 

(1) identifying surfaces that require augmented inspections in accordance with 

Subsection IWE-1240, as identified in Table IWE-2500-1, “Examination Category E-C” 

(2) using examination methods that are in accordance with Subsection IWE-2500 

(3) demonstrating through augmented inspections, performed in accordance with 

Subsection IWE, that corrosion is not occurring or that corrosion is progressing so slowly 

that the degradation will not jeopardize the intended function of the drywell shell through 

the period of extended operation 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.S1 and finds it acceptable because, when it is implemented, it will ensure 

appropriate corrective actions, consistent with the GALL Report recommendations, if moisture is 

detected or suspected in the inaccessible area on the exterior of the Fermi 2 Mark I containment 

drywell shell or if the source of moisture cannot be determined. 

Based on its audit and review of the applicant’s responses to RAIs B.1.42-1 and B.1.12-1 

through B.1.12-5, the staff finds that program elements 1 through 7 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.S1. In addition, the staff reviewed the enhancements 

associated with the “preventive actions,” “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” and “corrective action” program elements and finds 

that, when implemented, they will make the AMP adequate to manage the applicable aging 

effects. 

Operating Experience. LRA Section B.1.12 summarizes operating experience related to the 

Containment Inservice Inspection – IWE Program. The applicant described examples of 

plant-specific operating experience and evaluation of applicable industry operating experience 

to provide objective evidence that the Containment Inservice Inspection – IWE Program will be 

effective in ensuring that intended functions will be maintained during the period of extended 

operation. Some of these examples are described below. 

Drywell. Only one corrosion pit has been detected in the drywell shell. This pit, which 

measured 0.02 inch by 0.04 inch by 0.093 inch deep, was detected during ISI examinations 

in 2000. The corrosion was attributed to a screw and uncoated washer that were in contact with 

an uncoated portion of the drywell shell in a beam seat area. The screw and washer were 

removed. The drywell shell in the area of the pit was coated in 2003. 

Sand Pocket Region. Fermi 2 first noted drainage from the sand pocket drain lines in 1989. 

This leakage was a minimal one-to-two drops per minute. Analysis of leakage for tritium and 

gamma emitters indicated that the source was not reactor cavity water. During startup from the 

RFO in September 1992, leakage was still minimal at approximately one drop per minute, and 
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during a short period after startup, the leakage was recorded as zero. Leakage has been 

periodically monitored and has remained at zero since 1993. 

During a RFO in 1994, Fermi 2 planned to remove the sand from around the sand pocket drains 

and expose a small portion of the liner to perform a visual inspection at the four locations. The 

sand was removed from the sand pocket drain lines, but personnel were unable to inspect the 

drywell shell due to access limitations of the video probe. The sand in the sand pocket zone 

was found highly compacted. The LRA states that Fermi 2 evaluated NRC IN-2011-15, “Steel 

Containment Degradation and Associated Aging Management Issues,” dated August 11, 2011. 

Although the evaluation determined that no accelerated actions were warranted, the applicant 

initiated planning for a borescope inspection of the sand pocket drains and UT examinations of 

the shell in the vicinity of the sand cushion. 

In 2013, all four sand cushion drain lines were internally inspected with a boroscope. There 

were indications of sand in the bottom of three of the pipes and soft sand at the ends of the 

pipe. No water was present, and the sand would have allowed a drain path through the pipe. In 

three cases, the boroscope reached the 90-degree elbow at the sand cushion; in the other case, 

the boroscope could not reach the final foot of the pipe before the elbow because of the 

presence of sand. There were signs of corrosion in three of the pipes, showing that moisture 

had been present in the past. UT measurements taken in 2014 of the drywell shell in the sand 

cushion area showed thicknesses above the design value, indicating no or minimal apparent 

loss of material after almost 30 years of operation. 

The LRA also summarized the technical basis provided to the NRC for not performing UT 

examination of the drywell shell plates adjacent to the sand pocket region in its response to 

NRC GL 87-05, which addressed the potential for corrosion of BWR Mark I steel drywells in the 

sand pocket region. 

Torus. The LRA states that the torus is inspected in alternate RFOs. An inspection was 

performed in 2012 when 100 percent of the torus wetted and vapor space was inspected by 

qualified NDE inspectors. No pitting of the torus primary containment boundary was identified. 

One 0.25 inch-diameter pit has been identified in the torus wetted area during the history of the 

plant. This 0.0285-inch-deep corrosion pit was identified under a coating blister in 2001. The 

depth of the pit left the remaining shell thickness well within design tolerances. The coating was 

repaired. 

Coating condition continues to be monitored during inspections. During 2012, broken blisters, 

mechanical damage, and pinpoint rust areas were identified and repaired in the wetted areas of 

the torus. In the vapor region, all flaking paint was removed from the torus ring header, torus 

vacuum breaker valves, nitrogen supply lines, monorail rail, and torus walkway and handrail. 

Flaking or cracked coating was removed and protective coating was reapplied to the torus shell. 

The applicant evaluated NRC IN-2006-01, “Torus Cracking in a BWR Mark I Containment,” 

dated January 12, 2006, which described a through-wall crack and its probable cause in the 

torus of a BWR Mark I containment. The applicant determined that the Fermi 2 HPCI design 

has a turbine exhaust pipe sparger that precludes this condition. The LRA states that the 

Containment Inservice Inspection – IWE Program considers the industry operating experience 

provided in NRC IN 86-99, “Degradation of Steel Containments,” dated December 8, 1986; 

IN 88-82, “Torus Shells with Corrosion and Degraded Coatings in BWR Containments,” dated 

October 14, 1988; IN 89-79, “Degraded Coatings and Corrosion of Steel Containment Vessels,” 

dated December 1, 1989; IN 2004-09, “Corrosion of Steel Containment and Containment Liner,” 
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dated April 27, 2004; and NUREG-1522, “Assessment of Inservice Conditions of Safety-Related 

Nuclear Plant Structures,” dated June 1995, as discussed in the “operating experience” element 

of the GALL Report AMP. In addition, the program evaluates plant-specific and industry 

operating experience, and relevant information and lessons learned are incorporated into the 

program. 

As documented in the Audit Report, the staff noted during the audit that Fermi 2 has a proactive 

inspection program of the interior wetted surfaces of submerged areas of the torus and the vent 

header. The interior of the torus is inspected and repaired on an every other RFO basis. 

During these examinations, the submerged areas of the torus shell are cleaned from water line 

to water line to remove sludge and other foreign material following which coating inspectors 

inspect the entire area by VT-3 visual. All areas of broken blisters and mechanical damage 

exhibiting corrosion on the pressure boundary immersion area are repaired. Additionally, 

Fermi 2 monitors the blister condition on specific immersed areas of the torus, which are chosen 

based on their relatively high number of indications. During each inspection, the size, 

population density and condition of the blisters are monitored and trended to identify and 

evaluate adverse trends. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S1 was evaluated. 

UFSAR Supplement. LRA Section A.1.12 provides the UFSAR supplement for the Containment 

Inservice Inspection – IWE Program. The staff reviewed this UFSAR supplement description of 

the program, as amended by letter dated January 15, 2015, and noted that it is consistent with 

the recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed (Commitment No. 9) to implement the enhancements to the program before the 

period of extended operation (i.e., before September 20, 2024, or the end of the last outage 

before March 20, 2025, whichever is later). The staff finds that the information in the UFSAR 

supplement, as amended by letter dated January 15, 2015, is an adequate summary description 

of the program. 

Conclusion. On the basis of its audit; review of the applicant’s responses to RAIs by letters 

dated December 26, 2014, and January 15, 2015; and review of the applicant’s Containment 

Inservice Inspection – IWE Program, the staff determines that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. In addition, the 

staff reviewed the enhancements and confirmed that their implementation before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 
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UFSAR supplement for this AMP, as amended by letter dated January 15, 2015, and concludes 

that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Diesel Fuel Monitoring 

Summary of Technical Information in the Application. As amended by letter dated 

May 19, 2015, LRA Section B.1.14 describes the existing Diesel Fuel Monitoring Program as 

consistent, with enhancements, with GALL Report AMP XI.M30, “Fuel Oil Chemistry.” The LRA 

states that the Diesel Fuel Monitoring Program manages loss of material in piping, tanks, and 

other components exposed to an environment of diesel fuel by periodically testing the quality of 

the fuel oil. The program monitors water, sediments, total particulate, biodiesel concentration, 

and levels of microbiological activity. Additionally, the program periodically samples, drains, 

cleans, and internally inspects tanks for signs of moisture, contaminants and corrosion. 

A one-time inspection activity will be performed to verify the effectiveness of the Diesel Fuel 

Monitoring Program. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M30. The staff also reviewed the 

portions of the “preventive actions,” “parameters monitored or inspected,” “detection of aging 

effects,” “monitoring and trending,” “acceptance criteria,” and “corrective actions” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of these enhancements 

follows. 

Enhancement 1. LRA Section B.1.14 includes an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” 

“acceptance criteria,” and “corrective actions” program elements. In this enhancement, the 

applicant stated that it will revise procedures to monitor and trend water and sediment, 

particulates, and levels of microbiological organisms in the EDG fuel oil storage tanks, EDG fuel 

oil day tanks, diesel fire pump fuel oil tank, and CTG fuel oil tank quarterly. In addition, the 

applicant will revise the procedures to state that biocides or corrosion inhibitors may be added 

as a preventive measure or are added if periodic testing indicates biological activity or evidence 

of corrosion, respectively. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M30 and finds it acceptable because, when it is 

implemented, it will be consistent with the guidance in the GALL Report AMP. 

Enhancement 2. LRA Section B.1.14 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that it will revise 

procedures to include a 10-year periodic cleaning and internal visual inspection of the EDG fuel 

oil storage tanks, EDG fuel oil day tanks, diesel fire pump fuel oil tank, and CTG fuel oil tank 

with the following instructions: “If visual inspection is not possible, a volumetric inspection will 

be performed.” If any evidence of degradation is observed during visual inspection, a volumetric 

examination of the affected area will be performed. Additionally, the applicant stated that, for 

the diesel fire pump fuel oil tank inspection, it will continue to drain and flush the tank, as well as 

inspect the tank at its defined frequency at the time of the enhancement implementation, until a 

preventative maintenance evaluation of results from fuel oil samples and tank inspections 

indicates that the system will be capable of continuing to perform its function during the period 

of extended operation with a lower frequency, not less than once per a 10-year interval for 
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cleaning and internal visual inspection consistent with GALL Report. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M30 and 

finds it acceptable because, when it is implemented, it will be consistent with the guidance in the 

GALL Report AMP. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M30. In addition, the staff reviewed the enhancements 

associated with the “preventive actions,” “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” “acceptance criteria,” and “corrective action” program 

elements and finds that, when implemented, they will make the AMP adequate to manage the 

applicable aging effects. 

Operating Experience. LRA Section B.1.14 summarizes operating experience related to the 

Diesel Fuel Monitoring Program. 

In April 2000, it was suspected that the fuel in the CTG fuel oil storage tank was contaminated, 

therefore, it was drained, cleaned, and inspected. Minor pitting was repaired, and an epoxy 

liner was installed on the tank floor to protect against further pitting. The applicant instituted 

measures to periodically drain and inspect the tank internals. 

In 2009, the applicant amended the program to require multi-level samples of the CTG and EDG 

main fuel oil storage tanks rather than a single sample from the bottom of the tank. The 

multi-level stratification sampling is performed annually. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M30 was evaluated. 

UFSAR Supplement. As amended by letter dated May 19, 2015, LRA Section A.1.14 provides 

the UFSAR supplement for the Diesel Fuel Monitoring Program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed to 

implement the enhancements to the program before September 20, 2024, or at the end of the 

last RFO before March 20, 2025, whichever is later. The staff finds that the information in the 

UFSAR supplement is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Diesel Fuel Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation before the period of extended operation 
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will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 External Surfaces Monitoring 

Summary of Technical Information in the Application. As amended by letters dated 

July 30, 2014; January 28, 2015; and June 18, 2015, LRA Section B.1.16 describes the existing 

External Surfaces Monitoring Program as consistent, with enhancements, with GALL Report 

AMP XI.M36 “External Surfaces Monitoring of Mechanical Components,” as modified by 

LR-ISG-2011-03, “Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, 

‘Buried and Underground Piping and Tanks,’” and LR-ISG-2012-02, “Aging Management of 

Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under 

Insulation.” The LRA states that the AMP addresses metallic, elastomeric, and polymeric 

components to manage the aging effects of loss of material, cracking, fouling, changes in 

material properties, and degradation of thermal insulation due to moisture intrusion. The LRA 

also states that the AMP proposes to manage these aging effects through periodic visual 

inspections and physical manipulation (for flexible polymers). The LRA further states that, to 

address corrosion under insulation, periodic visual inspections will be conducted on a 

representative sample of external surfaces under insulation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M36. 

For the “parameters monitored or inspected” and “detection of aging effects” program elements, 

the staff determined the need for additional information, which resulted in the issuance of RAIs, 

as discussed below. 

The “parameters monitored or inspected” program element in GALL Report AMP XI.M36 

recommends inspections for leakage to identify cracking of stainless steel external surfaces 

exposed to air environments containing halides. The applicant’s External Surfaces Monitoring 

Program also includes this activity. LRA Tables 3.3.2-3, 3.3.2-10, and 3.3.2-11 contain AMR 

items for gas-filled outdoor stainless steel and aluminum components that are managed for 

cracking. For components that have a gaseous internal environment, it was not clear to the 

staff how walkdowns of external surfaces will effectively use leakage as an indicator of cracking. 

By letter dated December 19, 2014, the staff issued RAI B.1.16-1 requesting that the applicant 

state the parameters inspected and the inspection methods that will be used to determine 

whether cracking is present on these components. 

In its response dated January 28, 2015, the applicant stated that alternate detection methods 

will be used to detect cracks in gas-filled aluminum and stainless steel components when visual 

inspections are ineffective. The response addressed each LRA table in question as follows: 

 Table 3.3.2-3. The aluminum and stainless steel components in the service water 

system that are managed for cracking are pressurized using bottled nitrogen. System 

pressure readings and bottle replacement frequencies are recorded daily and trended to 

identify the development of adverse trends. Trending of the daily pressure readings and 
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bottle replacement frequencies will be used to detect leakage and as an indication of 

cracking. 

 Table 3.3.2-10. The EDG system contains a stainless steel expansion joint for which 

cracking is managed. The expansion joint is internally exposed to exhaust gas and 

externally exposed to outdoor air. The applicant stated that leaking exhaust gas will 

stain the stainless steel surface. The expansion joint will be visually inspected for 

staining, in accordance with GALL Report AMP XI.M36. 

 Table 3.3.2-11. The aluminum and stainless steel components in the heating, 

ventilation, and air conditioning (HVAC) system that are managed for cracking will be 

visually inspected. The periodic visual inspections will be conducted using a soap 

solution with the system pressurized. LRA Sections A.1.16 and B.1.16 were revised to 

state that alternate detection methods will be used to detect cracks in gas-filled 

aluminum and stainless steel components when visual inspections are ineffective. 

Commitment No. 11g and Enhancement 7 were added to revise the plant-specific procedures to 

include instructions for detection of cracks in gas-filled aluminum and stainless steel 

components. 

The staff finds the applicant’s response acceptable because visual inspections augmented with 

the use of a soap solution and trending performance data are methods capable of detecting 

cracking before loss of intended function. In addition, conducting visual inspections of the EDG 

system is consistent with GALL Report AMP XI.M36 because leakage will be evident by 

discoloration of the surface of the stainless steel material. The staff’s concern described in 

RAI B.1.16-1 is resolved. 

The “detection of aging effects” program element in GALL Report AMP XI.M36, as revised by 

LR-ISG-2012-02, recommends managing reduced thermal insulation resistance due to moisture 

intrusion by visual inspections of insulation jacketing to ensure that there is no damage that 

would allow moisture inleakage. The applicant’s External Surfaces Monitoring Program does 

not include this activity; instead, the LRA credits the Structures Monitoring Program to manage 

this aging effect. It was unclear to the staff what activities in the Structures Monitoring Program 

would be used to manage reduced thermal insulation resistance. By letter dated 

December 19, 2014, the staff issued RAI B.1.16-2 requesting that the applicant describe the 

insulation configuration and the activities in the Structures Monitoring Program that will be used 

to manage reduced thermal insulation resistance due to moisture intrusion. 

In its response dated January 28, 2015, the applicant stated that the insulation installation 

specifications contain configuration controls for insulation jacketing that include minimum 

overlap and seam locations. In addition, the AMR items that cited the Structures Monitoring 

Program to manage the aging effect of reduced thermal insulation resistance due to moisture 

intrusion have been revised to reference the External Surfaces Monitoring Program. Revisions 

to LRA Sections A.1.16 and B.1.16 state that the inspections of insulated components will be 

conducted to ensure that moisture intrusion has not degraded the insulation when it is required 

to reduce heat transfer. Commitment No. 11h and Enhancement 8 were added to revise the 

plant-specific procedures to include instructions for the inspection of both jacketed and 

nonjacketed insulation. 

The staff finds the applicant’s response acceptable, in part, because the applicant revised LRA 

Table 3.5.2-2 to manage degradation of insulation due to moisture intrusion with the External 

Surfaces Monitoring Program. However, the response did not state an inspection methodology 
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and frequency for the nonjacketed insulation. By letter dated March 20, 2015, the staff issued 

RAI B.1.16-2a requesting that the applicant provide the inspection methodology and frequency 

used to inspect nonjacketed insulation. 

In its response dated June 18, 2015, the applicant stated that both jacketed and nonjacketed 

insulation will be periodically visually inspected in accordance with the External Surfaces 

Monitoring Program and at a frequency consistent with GALL Report AMP XI.M36, as modified 

by LR-ISG-2012-02. LRA Section A.1.16, B.1.16, Enhancement 5, Enhancement 8, 

Commitment No. 11e, and Commitment No. 11h have been revised to reflect these changes. 

The applicant also stated that thermography will be performed on at least 20 percent of the 

population for nonjacketed insulation where plant conditions permit (i.e., the insulated pipe is 

carrying a heat load and is not located in a high-radiation area) to assess insulating ability. 

These inspections will begin 5 years before entering the period of extended operation and every 

5 years after using the Periodic Surveillance and Preventive Maintenance Program. LRA 

Sections A.1.35 and B.1.35 have been revised to reflect these changes to the program. SER 

Section 3.0.3.3.1 documents the staff’s evaluation of the Periodic Surveillance and Preventive 

Maintenance Program. 

The staff noted that the “detection of aging effects” program element in LR-ISG-2012-02 states 

that inspections are conducted at a frequency not to exceed one refueling cycle to 

accommodate components located in areas accessible only during outages, such as high dose 

areas. The program element further states that components that are not accessible during 

either plant operation or RFOs are inspected at a frequency that ensures that the intended 

functions are maintained and whenever such components are made accessible. The staff finds 

the applicant’s response acceptable because periodic visual examinations will be conducted to 

detect degradation of insulation due to moisture intrusion for both jacketed and nonjacketed 

insulation. The frequency of the periodic visual inspections is consistent with GALL Report 

AMP XI.M36, as modified by LR-ISG-2012-02. In addition, nonjacketed insulation will also be 

inspected using thermography, which is capable of evaluating the effectiveness of the 

insulation. The applicant has also revised the applicable sections of the LRA to reflect these 

changes. The staff’s concern described in RAI B.1.16-2a is resolved. 

In reviewing the program for consistency with the GALL Report, the staff notes that the program 

includes fouling as an aging effect requiring management; however, management of fouling is 

not consistent with GALL Report AMP XI.M36. The program proposes to manage reduction of 

heat transfer due to air-side fouling of heat exchanger fins and tubes by using periodic visual 

inspections of external surfaces during system inspections and walkdowns. The staff notes that 

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” includes 

periodic air-side visual inspections to ensure cleanliness of air-to-water heat exchangers as an 

acceptable approach for verifying heat transfer capability. The staff considers cleanliness of 

heat exchanger tubes and fins to be readily identifiable using periodic visual inspections during 

system inspections and walkdowns. Based on this assertion, and as documented in SER 

Section 3.2.2.3.4, the staff finds that the visual inspections in this program are capable of 

detecting fouling of air-side heat exchanger surfaces before loss of the intended function. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “acceptance criteria,” and “administrative controls” 

program elements associated with enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows. 
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Enhancement 1. LRA Section B.1.16 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that the plant-specific procedures 

will be revised to clarify that periodic inspections will be performed for in-scope components in 

accordance with the requirements of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff reviewed 

this enhancement against the corresponding program element in GALL Report AMP XI.M36 and 

finds it acceptable because, when it is implemented, it will provide clarifying guidance in 

plant-specific procedures to ensure that the scope of inspections in the program will be in 

accordance with 10 CFR 54.4, “Scope,” and consistent with the GALL Report 

recommendations. 

Enhancement 2. LRA Section B.1.16 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that plant-specific procedures will be revised to inspect 100 percent of 

accessible components at least once per refueling cycle. The Program Description of the AMP 

states that “[s]urfaces that are not readily visible during plant operations and refueling outages 

are inspected when they are made accessible and at such intervals that would ensure the 

components’ intended functions are maintained.” The applicant also stated that plant-specific 

procedures will be revised to include instructions on the parameters to be inspected for metallic 

components. The staff noted that the proposed parameters monitored are consistent with those 

in GALL Report AMP XI.M36. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M36 and finds it acceptable because, when it is 

implemented, it will ensure that the extent of inspections, frequency of inspections, and 

parameters monitored will be consistent with the GALL Report recommendations. 

Enhancement 3. LRA Section B.1.16 includes an enhancement to the “parameters monitored 

or inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that plant-specific procedures will be revised to include instructions for 

inspecting flexible polymeric components, including a 10-percent minimum sample size for 

physical manipulation and parameters to be monitored. The staff noted that the proposed 

parameters monitored are consistent with those in GALL Report AMP XI.M36 for all polymers. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M36 and finds it acceptable because, when it is implemented, it will ensure that 

the extent of inspections and parameters monitored for polymers will be consistent with the 

GALL Report recommendations. 

Enhancement 4. LRA Section B.1.16, as amended by letter dated July 30, 2014, includes an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that plant-specific procedures will be revised to include the inspection of 

insulated components. Specifically, the enhancement includes periodic inspections during each 

10-year period of a representative sample of components that are insulated and that may be 

exposed to moisture (i.e., outdoors or indoors where condensation may occur). The 

enhancement also includes provisions for conducting followup inspections of either outer 

insulation surfaces or bare-metal surfaces, depending on whether prior inspections detect 

degradation or moisture intrusion. The enhancement further includes guidance for the 

inspection of components with tightly adhering insulation. The staff noted that the details of the 

enhancement are consistent with the inspections of insulated components recommended by 

GALL Report AMP XI.M36, as revised by LR-ISG-2012-02. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M36 and 

finds it acceptable because, when it is implemented, it will ensure that the inspections of 

insulated components will be consistent with the GALL Report recommendations. 
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Enhancement 5. LRA Section B.1.16, as amended by letter dated June 18, 2015, includes an 

enhancement to the “acceptance criteria” program element. In this enhancement, the applicant 

stated that plant-specific procedures will be revised to include acceptance criteria for metals and 

polymers. Acceptance criteria for insulation include verification that no discoloration, staining, or 

surface irregularities from moisture intrusion are observed. The staff noted that the applicant’s 

proposed acceptance criteria are consistent with those in GALL Report AMP XI.M36. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M36 and finds it acceptable because, when it is implemented, it will ensure that 

acceptance criteria will be consistent with the GALL Report recommendations. 

Enhancement 6. LRA Section B.1.16 includes an enhancement to the “administrative controls” 

program element. In this enhancement, the applicant stated that plant-specific procedures will 

be revised to state that administrative controls will be in accordance with the plant’s QA program 

under Appendix B to 10 CFR Part 50. The staff noted that the “administrative controls” program 

element of GALL Report AMP XI.M36 states that the requirements of Appendix B to 

10 CFR Part 50 are acceptable to address the administrative controls. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M36 and 

finds it acceptable because, when it is implemented, the administrative controls for the External 

Surfaces Monitoring Program will be consistent with the GALL Report recommendations. 

Enhancement 7. As amended by letter dated January 28, 2015, LRA Section B.1.16 includes 

an enhancement to the “parameters monitored or inspected” and “detection of aging effects” 

program elements. In this enhancement, the applicant stated that plant-specific procedures will 

be revised to include instructions for the detection of cracking of gas-filled aluminum and 

stainless steel components exposed to outdoor air. RAI B.1.16-1 documents the staff’s 

evaluation of this enhancement. 

Enhancement 8. LRA Section B.1.16, as amended by letters dated January 28, 2015, and 

June 18, 2015, includes an enhancement to the “detection of aging effects” and “parameters 

monitored and inspected” program elements. In this enhancement, the applicant stated that 

jacketed and nonjacketed insulation will be visually inspected for evidence of moisture intrusion 

at a frequency consistent with GALL Report AMP XI.M36, as modified by LR-ISG-2012-02. The 

enhancement also states that the plant-specific procedures will be revised to include 

instructions to inspect for signs of water intrusion. RAI B.1.16-2a documents the staff’s 

evaluation of this enhancement. 

Operating Experience. LRA Section B.1.16 summarizes operating experience related to the 

External Surfaces Monitoring Program. The LRA describes instances in which piping 

component leaks, a bulging air seal gasket, and missing piping insulation were discovered 

during system walkdowns from 2009 to 2012. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 
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Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M36 was evaluated. 

UFSAR Supplement. As amended by letter dated June 18, 2015, LRA Section A.1.16 provides 

the UFSAR supplement for the External Surfaces Monitoring Program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1, as revised by LR-ISG-2012-02. The staff 

also noted that the applicant committed to implement the enhancements to the program before 

the period of extended operation. The staff finds that the information in the UFSAR supplement 

is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s External Surfaces Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation before the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Fatigue Monitoring 

Summary of Technical Information in the Application. LRA Section B.1.17, as amended by 

letters dated June 26, 2015, and March 10, 2016, describes the existing Fatigue Monitoring 

Program as consistent, with an exception and enhancements, with GALL Report AMP X.M1, 

“Fatigue Monitoring.” The LRA states that the AMP ensures that the fatigue usage remains 

within allowable limits for components identified to have fatigue-related TLAAs. The LRA also 

states that the AMP (a) tracks plant transients that cause significant fatigue usage, (b) verifies 

that the severity of the transients being monitored are bounded by the design transients for 

which they are classified, and (c) assesses the impact of the reactor coolant environment on a 

sample of critical and limiting components. The LRA further states that fatigue usage factors 

will be updated if transient definitions change, new thermal events are discovered, or 

component geometries are modified. Additionally, as an alternative to monitoring the 

occurrences of transients, the LRA states that the program will include stress-based fatigue 

(SBF) monitoring. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP X.M1. 

For the “parameters monitored or inspected” program element, the staff determined the need for 

additional information, which resulted in the issuance of an RAI, as discussed below. 

The “parameters monitored or inspected” program element in GALL Report AMP X.M1 

recommends tracking the number of each plant transient; however, it does not provide guidance 

on the use of a specific fatigue monitoring method. During its audit, the staff found that the 
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applicant’s Fatigue Monitoring Program states that the “cycle counting” method of fatigue 

monitoring will be used to track the number of occurrences for plant transients. The staff also 

noted that the LRA states that fatigue usage calculations will be updated using refined fatigue 

analysis to determine valid CUFs of less than 1.0 for locations in LRA Table 4.3-8 that are 

projected to exceed the limit of 1.0. However, it was not clear if fatigue monitoring methods 

other than “cycle counting” are being used to prevent the fatigue design limit of components 

from being exceeded. By letter dated January 14, 2015, the staff issued RAI 4.3.3-1, requesting 

that the applicant clarify the methodology used to refine the fatigue analysis to ensure that the 

CUF values projected to exceed 1.0 will remain within the ASME Code limit. 

In its response dated February 12, 2015, the applicant stated that several options may be used 

to ensure that the CUF values do not exceed the limit of 1.0. The options include implementing 

cycle-based fatigue (CBF) and SBF monitoring methods when accounting for environmental 

effects. The applicant also stated that the recommendations provided in Regulatory Issue 

Summary 2008-30, “Fatigue Analysis of Nuclear Power Plant Components,” dated 

December 16, 2008, will be applied when using the SBF monitoring method. The applicant has 

revised LRA Sections A.1.17 and B.1.17 to state that SBF monitoring will compute the stress 

history for a given component using transient pressure and temperature data collected from 

plant instrumentation. The LRA also states that the computed stress history will then be used to 

compute a CUF. Additionally, the applicant revised Enhancement 4 and Commitment No. 12 to 

include CBF and SBF for EAF calculations. 

The staff finds the applicant’s response acceptable because the CBF and SBF monitoring 

methods are consistent with the guidance provided in GALL Report AMP X.M1. GALL Report 

AMP X.M1 states that the number of occurrences of plant transients or detailed local pressure 

and thermal conditions should be monitored to allow for calculation of the fatigue usage. The 

CBF method uses accumulated cycles to determine whether the CUF. The SBF method uses 

transient pressure and temperature data collected from plant instrumentation to determine a 

local stress history. The applicant has revised the Fatigue Monitoring Program to include the 

CBF and SBF monitoring methods. The staff’s full evaluation of RAI 4.3.3-1 is in SER 

Section 4.3.3. The staff’s concern described in RAI 4.3.3-1 is resolved. 

During its review of LRA Sections 4.1 and 4.7, the staff noted that the Fatigue Monitoring 

Program was being used to track cumulative operating time to ensure that a “cumulative usage 

time limit” associated with a flaw evaluation TLAA is not exceeded. It was unclear if flaw 

evaluation analyses and tracking events, other than plant design transients, were within the 

scope of the Fatigue Monitoring Program. By letter dated December 17, 2014, the staff issued 

RAI B.1.17-2, requesting that the applicant identify TLAAs that will use the Fatigue Monitoring 

Program to ensure that any analysis or design limit, other than a fatigue usage factor for crack 

initiation, is not exceeded during the period of extended operation. The RAI also requested that 

the applicant identify events and cycles that will be tracked by the Fatigue Monitoring Program 

that are not plant design transients. The applicant’s response to RAI B.17-2 resulted in 

revisions to the Fatigue Monitoring Program. The aspects of the response that relate to the 

Fatigue Monitoring Program are discussed below. 

In its response dated January 20, 2015, the applicant stated that there are two TLAAs that will 

use the Fatigue Monitoring Program to ensure that an analysis or design limit, other than a 

fatigue usage factor for crack initiation, is not exceeded during the period of extended operation. 

The two TLAAs identified are (1) the “Determination of High-Energy Line Break Locations” (LRA 

Section 4.7.2) and (2) the “Main Steam Bypass Lines Cumulative Operating Time” (LRA 

Section 4.7.6). The response also states that the only event that is not a design transient being 
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tracked by the Fatigue Monitoring Program is the number of days of operation at 30 percent to 

45 percent open for the main steam bypass line. 

The Determination of HELB Locations TLAA calculates a CUF in accordance with ASME Code 

Section III. The Fatigue Monitoring Program is used to track design transients to ensure that a 

CUF limit of 0.1 is not exceeded for this TLAA. Exception 1 of the Fatigue Monitoring Program 

states that corrective action will be taken for the HELB locations before a limit of 0.1 is reached 

instead of the ASME Code fatigue crack initiation design limit of 1.0. SER Section 4.7.2 

discusses the staff’s evaluation of the applicant’s HELB TLAA. 

The staff finds the applicant’s response for the Determination of HELB Locations TLAA 

acceptable because (1) the CUF is determined using design transients and in accordance with 

ASME Code Section III and (2) Exception 1 modifies the Fatigue Monitoring Program to ensure 

that corrective actions will be taken before the limit of 0.1 is reached. 

The Main Steam Bypass Lines Cumulative Operating Time TLAA is not a fatigue usage 

analysis. This TLAA is a flaw evaluation analysis. The TLAA analysis entails the determination 

of an operating time limit. The operating time limit is used to establish a cumulative operating 

time factor with a limit of 1.0. The Fatigue Monitoring Program is being used to track the 

number of days of operation at 30 percent to 45 percent open for the main steam bypass line. 

Days of operation at the 30 percent to 45 percent open is not a design transient. In its RAI 

response, the applicant also added Enhancement 5 to prevent the cumulative operating time 

limit from being exceeded during the period of extended operation, and it committed 

(Commitment Nos. 12e and 12f) to implementing the enhancement before entering the period of 

extended operation. Enhancement 5 was subsequently separated into Enhancement 5 and 

Enhancement 6, by letter dated June 26, 2015, for administrative purposes without any 

technical changes. SER Section 4.7.6 discusses the staff’s evaluation of the applicant’s Main 

Steam Bypass Lines Cumulative Operating Time TLAA. 

The staff finds the applicant’s response for the Main Steam Bypass Lines Cumulative Operating 

Time TLAA acceptable because the Fatigue Monitoring Program has been enhanced to track 

the applicable plant events and to prevent the cumulative operating time limit from being 

exceeded. Enhancement 5 and Enhancement 6 expand the “scope of program,” “preventive 

actions,” “parameters monitored or inspected,” “detection of aging effects,” “monitoring and 

trending,” “acceptance criteria,” and “corrective actions” program elements. The staff’s concern 

described in RAI B.1.17-2 is resolved. 

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” “monitoring and trending,” “acceptance 

criteria,” and “corrective actions” program elements associated with the exception and 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of the exception and enhancements follows. 

Exception. LRA Section B.1.17 includes an exception to the “corrective actions” program 

element. The exception is the use of a CUF limit of 0.1 instead of 1.0 to initiate a corrective 

action for the HELB locations. In this exception, the applicant stated that an additional 

corrective action will be applied to the HELB locations. The LRA also states that this corrective 

action is based on a fatigue usage limit value of 0.1. The staff reviewed this exception against 

the corresponding program element in GALL Report AMP X.M1 and finds it acceptable because 

the fatigue usage limit value being applied to the HELB is more conservative than the value 
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recommended by GALL Report AMP X.M1. The staff also noted that the fatigue usage limit 

value of 0.1 being applied to the HELB is consistent with the UFSAR. 

Enhancement 1. LRA Section B.1.17 includes an enhancement to the “scope of program,” 

“preventive actions,” “parameters monitored or inspected,” and “monitoring and trending” 

program elements. In this enhancement, the applicant stated that the procedures of the AMP 

will be revised to monitor transients for components that have been identified as TLAAs. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMP X.M1 and finds it acceptable because, when it is implemented, it will ensure that the 

thermal and pressure transients being tracked are consistent with the GALL Report 

recommendations. 

Enhancement 2. LRA Section B.1.17 includes an enhancement to the “scope of program,” 

“preventive actions,” and “acceptance criteria” program elements. In this enhancement, the 

applicant stated that EAF usage calculations that consider the effects of the reactor coolant 

environment will be developed for select locations. The enhancement states that the select 

locations will consist of those identified in NUREG/CR-6260, “Application of NUREG/CR-5999 

Interim Fatigue Curves to Selected Nuclear Power Plant Components,” dated February 1995, 

and a sample of more limiting plant-specific locations in the reactor coolant pressure boundary. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP X.M1 and finds it acceptable because, when it is implemented, it will ensure that 

EAF usage factors are calculated in a manner consistent with the GALL Report guidance. 

Enhancement 3. LRA Section B.1.17 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that the procedures of the 

AMP will be revised to provide updates to the fatigue usage calculation on an as needed basis. 

The enhancement states that events that will prompt the updates to the fatigue usage 

calculation include (a) the approach of an allowable cycle limit, (b) a change in transient 

definitions, (c) the discovery of new thermal events, or (d) the modification of component 

geometries. The staff reviewed this enhancement against the corresponding program elements 

in GALL Report AMP X.M1 and finds it acceptable because, when it is implemented, it will 

ensure that fatigue usage factors remain valid and below the design limit in accordance with the 

GALL Report guidance. 

Enhancement 4. LRA Section B.1.17, as amended by letter dated February 12, 2015, includes 

an enhancement to the “acceptance criteria” program element. In this enhancement, the 

applicant stated that the procedures of the AMP will be revised to maintain the EAF usage factor 

below the design limit. The applicant also stated that the procedures of the AMP will be revised 

to allow for the use of the CBF and SBF monitoring methods if EAF usage factors are predicted 

to exceed the limit of 1.0. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP X.M1 and finds it acceptable because, when it is 

implemented, it will prevent the EAF usage factor from exceeding 1.0 in accordance with the 

GALL Report guidance. 

Enhancement 5. LRA Section B.1.17, as amended by letter dated June 26, 2015, includes an 

enhancement to the “scope of program,” “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements. In this enhancement, the applicant stated that the procedures of the AMP 

will be revised to include monitoring of the main steam bypass valve operation at the 30-percent 

to 45-percent open position and trending to ensure that the cumulative operating time remains 

below the established limit. The staff reviewed this enhancement against the corresponding 
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program elements in GALL Report AMP X.M1 and finds it acceptable because, when it is 

implemented, it will prevent the cumulative operating time limit from being exceeded during the 

period of extended operation. 

Enhancement 6. LRA Section B.1.17, as amended by letter dated June 26, 2015, includes an 

enhancement to the “corrective actions” program elements. In this enhancement, the applicant 

stated that the procedures of the AMP will be revised to provide corrective actions to prevent the 

operating time limit of the main steam bypass valve in the 30-percent to 45-percent open 

position from being exceeded during the period of extended operation. The enhancement 

states that acceptable corrective actions include component repair, component replacement, or 

more rigorous analysis to demonstrate that the service life will not be exceeded. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP X.M1 and finds it acceptable because, when it is implemented, it will ensure that corrective 

actions are taken before the operating time limit is reached ensuring that the service life of the 

main steam bypass valve is not exceeded during the period of extended operation. The content 

of this enhancement was originally added to the AMP in response to RAI B.1.17-2 and 

encompassed within Enhancement 5. Enhancement 6 was subsequently created by the 

applicant because these activities are only associated with the “corrective actions” program 

element of the AMP and do not affect the other program elements in Enhancement 5. 

Based on its audit and review of the applicant’s response to RAI 4.3.3-1 and RAI B.1.17-2, the 

staff finds that program elements 1 through 6 for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP X.M1. The staff also reviewed the exception associated with the “acceptance criteria” 

program element and its justification and finds that the AMP, with the exception, is adequate to 

manage the applicable aging effects. In addition, the staff reviewed the enhancements 

associated with the “scope of program,” “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements and finds that, when implemented, they will make the AMP adequate to 

manage the applicable aging effects. 

Operating Experience. LRA Section B.1.17 summarizes operating experience related to the 

Fatigue Monitoring Program. The LRA describes an instance in which the transient cycle count 

was approaching the cycle limits for a component, and corrective measures were successfully 

taken. The LRA also states that a component at the facility has never experienced the loss of 

intended function due to thermally induced fatigue. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

Based on its audit and review of the LRA, the staff finds that the applicant has appropriately 

evaluated plant-specific and industry operating experience and that implementation of the 

program has resulted in the applicant taking corrective actions. In addition, the staff finds that 

the conditions and operating experience at the plant are bounded by those for which GALL 

Report AMP X.M1 was evaluated. 
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UFSAR Supplement. LRA Section A.1.17, as amended by letter dated February 12, 2015, 

provides the UFSAR supplement for the Fatigue Monitoring Program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed (Commitment No. 12) to implement Enhancements 1, 3, 4, 5, and 6 before 

September 20, 2024, and Enhancement 2 at least 2 years before March 20, 2025. 

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

February 12, 2015, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Fatigue Monitoring Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exception and its 

justification and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. In addition, the staff reviewed the enhancements and confirmed that 

their implementation before the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Fire Protection 

Summary of Technical Information in the Application. As amended by letter dated 

January 15, 2015, LRA Section B.1.18 describes the existing Fire Protection Program as 

consistent, with enhancements, with GALL Report AMP XI.M26, “Fire Protection.” The LRA 

states that the program manages the following aging effects for the SCs with a fire barrier 

intended function: cracking and loss of material for concrete components and masonry walls; 

loss of material for carbon steel components; loss of material, change in material properties, 

cracking, delamination, and separation for fire resistant materials; and increased hardness, 

shrinkage, and loss of strength for elastomer components. The program includes visual 

inspections of not less than 10 percent of each type of penetration seal; visual inspections of fire 

barrier walls, ceilings, and floors in structures within the scope of license renewal; periodic 

visual and functional testing of fire doors; and visual and functional tests of the carbon dioxide 

(CO2) and Halon systems. The frequencies of the inspections and testing are in accordance 

with the applicant’s Technical Requirements Manual (TRM). 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M26. 

For the “detection of aging effects” program element, the staff determined the need for 

additional information, which resulted in the issuance of an RAI, as discussed below. 

The “detection of aging effects” program element in GALL Report AMP XI.M26 recommends 

that visual inspections of fire barrier materials be conducted at a frequency in accordance with 

an NRC-approved fire protection program. However, during its audit, the staff noted that the 

applicant’s existing Fire Protection Program includes visual inspection of all fire-rated 

assemblies (e.g., fire damper housings), separating safety-related fire areas or separating 
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portions of redundant systems important to safe shutdown within a fire area, every 18 months in 

accordance with the TRM. The applicant proposes to manage aging of fire damper housings 

using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program and the External Surfaces Monitoring Program. The inspection frequency for the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is 

based on a sampling of at least 20 percent or maximum of 25 components every 10 years. The 

frequency and scope of this inspection is less than what is currently required by the TRM. 

Therefore, by letter dated December 17, 2014, the staff issued RAI B.1.18-1 requesting that the 

applicant explain why the frequency and number of inspections for fire damper housings using 

the “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” program 

is adequate given the requirements in the TRM. 

In its response dated January 15, 2015, the applicant indicated that it will continue to comply 

with TRM Section TRSR 3.12.8.6 and to perform visual inspections of each fire damper housing 

and that such inspections will also be credited to meet the inspection recommendations in both 

the Internal Surfaces in Miscellaneous Piping and Ducting Components Program and the 

External Surfaces Monitoring Program. 

The staff finds the applicant’s response acceptable because the applicant will continue to 

comply with the requirements in its TRM for frequency of inspection of the fire damper housings. 

The inspections required by the TRM are the same type as those recommended in the two 

AMPs. Because the frequency and number of inspections required by the TRM is greater than 

or equal to those recommended by the two credited AMPs, the staff’s concern described in 

RAI B.1.18-1 is resolved. 

The staff also reviewed the portions of the “scope of program” and “detection of aging effects” 

program elements associated with the enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows. 

Enhancement 1. LRA Section B.1.18 includes an enhancement to the “scope of program” and 

“detection of aging effects” program elements. In this enhancement, the applicant stated that it 

will revise procedures to perform visual inspections of the Halon and CO2 fire suppression 

systems. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M26 and finds it acceptable because, when it is implemented, it will make 

the program consistent with the recommendations in the GALL Report to perform visual 

inspections of these systems to detect any sign of corrosion. 

Enhancement 2. LRA Section B.1.18, as amended by letter dated January 15, 2015, includes 

an enhancement to the “detection of aging effects” program elements. In this enhancement, the 

applicant stated that it will revise procedures to perform visual inspections of fire wrap and fire 

stop materials, carbon steel penetration sleeves, steel framing, roof decking, floor decking, 

concrete fire barriers, and railroad bay airlock doors at a frequency consistent with the 

NRC-approved fire protection program or at least once every refueling cycle. The staff reviewed 

this enhancement against the corresponding program element in GALL Report AMP XI.M26 and 

finds it acceptable because, when it is implemented, it will make the program consistent with the 

recommendations in the GALL Report to perform visual inspections of these components to 

detect any signs of degradation. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 
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elements of GALL Report AMP XI.M26. The staff reviewed the enhancements associated with 

the “scope of program” and “detection of aging effects” program elements and finds that, when 

implemented, they will make the AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.18 summarizes operating experience related to the 

Fire Protection Program. 

Nuclear Electric Insurance Limited reports from October 2011, September 2012, and 

October 2013 did not identify any issues related to aging of fire barriers or fire protection 

features or any issues related to the CO2 system. 

Fermi 2 personnel identified small holes in fire doors, damaged fire door seals, damaged fire 

walls, or damaged penetrations seals. According to the LRA, when deficiencies are noted, a fire 

impairment is declared, and maintenance personnel repair the deficiency. 

In 2009, the applicant found that eight fire penetration seals in the reactor building steam tunnel 

floor were cracked due to heat stress. The applicant prepared a fire protection engineering 

evaluation (FPEE) that documented the historical record of the failure of these seals and the 

acceptability of the fire barrier penetration seals between the turbine building and the torus 

room. The FPEE concluded that the seals deviated from their rated design because they were 

used in conditions beyond their design capabilities due to their exposure to pipe movement and 

extreme temperatures during normal plant operations. However, the FPEE further concluded 

that the seals were acceptable due to the extremely low fire loading in the area and the 

presence of an automatic sprinkler system below the steam tunnel in the reactor building 

basement. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M26 was evaluated. 

UFSAR Supplement. LRA Section A.1.18 provides the UFSAR supplement for the Fire 

Protection Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed to implement the enhancements to the program before 

September 20, 2024. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Fire Protection Program, the 

staff determines that those program elements for which the applicant claimed consistency with 
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the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Fire Water System 

Summary of Technical Information in the Application. As amended by letters dated 

July 30, 2014; January 15, 2015; and April 10, 2015, LRA Section B.1.19 describes the existing 

Fire Water System Program as consistent, with exceptions and enhancements, with GALL 

Report AMP XI.M27, “Fire Water System,” as modified by LR-ISG-2012-02, “Aging 

Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation.” The LRA states that the AMP addresses water-based fire 

suppression system components to manage loss of material, fouling, and flow blockage. The 

LRA also states that when using visual inspections to detect loss of material, the inspection 

techniques will also be capable of detecting corrosion product deposition and flow blockage due 

to fouling. The LRA further states that the AMP proposes to manage these aging effects 

through periodic flow tests, visual inspections, sprinkler testing, and volumetric wall thickness 

evaluations. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M27, “Fire Water System,” as 

modified by LR-ISG-2012-02. 

For the “acceptance criteria” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below. 

The “acceptance criteria” program element in LR-ISG-2012-02 AMP XI.M27 recommends that, 

as stated in NFPA 25 Section 5.2.1.1.2, sprinklers that exhibit corrosion should be replaced. 

However, during its audit, the staff found that the applicant’s Fire Water System Program and 

plant-specific procedures for inspecting sprinklers do not include an acceptance criteria 

associated with corrosion of sprinklers. By letter dated December 17, 2014, the staff issued 

RAI B.1.19-7 requesting that the applicant state the basis for why a corroded sprinkler will be 

capable of performing its CLB intended function during the period of extended operation. 

In its response dated January 15, 2015, the applicant revised LRA Section B.1.19 to include an 

enhancement, Enhancement 16, which states that corroded fire sprinklers will be replaced. 

The staff finds the applicant’s response acceptable because the enhancement is consistent with 

LR-ISG-2012-02 AMP XI.M27, which ensures that corrosion on sprinklers will be corrected by 

replacement. The staff’s concern described in RAI B.1.19-7 is resolved. 

The staff also reviewed the portions of the “parameters monitored or inspected,” and “detection 

of aging effects,” “acceptance criteria,” and “corrective actions” program elements associated 

with exceptions and enhancements to determine whether the program will be adequate to 
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manage the aging effects for which it is credited. The staff’s evaluation of these exceptions and 

enhancements follows. 

Exception 1. As amended by letter dated July 30, 2014, LRA Section B.1.19 includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that it will perform sprinkler inspections on a refueling cycle interval (i.e., 18 months) in 

lieu of annual testing specified by Section 5.2.1 of NFPA 25, “Standard for the Inspection, 

Testing, and Maintenance of Water-Based Fire Protection Systems,” (hereinafter, unless noted 

otherwise, the 2011 Edition). The applicant also stated that the refueling cycle inspection 

interval has been effective at maintaining component intended function. 

NFPA 25 was written for a broad range of facilities, including those with a few sprinklers (e.g., a 

small manufacturing facility with only a dozen sprinklers) and those with numerous sprinklers 

(as is typical for power plants). The staff reviewed this exception against the corresponding 

program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because the applicant 

stated that the refueling cycle inspection interval has not resulted in a loss of intended functions 

in the past. In addition, the staff’s independent search of plant-specific operating experience 

during the audit did not reveal any evidence that sprinkler degradation was occurring, and there 

are a sufficient number of sprinklers installed in commercial nuclear power plants to establish an 

adverse performance trend, even with plant-specific inspections being completed on a refueling 

cycle basis rather than annually. 

Exception 2. As amended by letter dated July 30, 2014, LRA Section B.1.19 includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that sprinklers will not be inspected for orientation, foreign material, physical damage, 

and loading due to dust or debris as specified by NFPA 25 Section 5.2.1.1. The staff reviewed 

this exception against the corresponding program element in LR-ISG-2012-02 AMP XI.M27 and 

finds it acceptable because the excluded inspection results are not associated with aging 

effects. 

Exception 3. As amended by letter dated July 30, 2014, LRA Section B.1.19 includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that it will not perform flow testing at the hydraulically most remote hose connections of 

each zone of an automatic standpipe system to verify that the water supply provides the design 

pressure as specified by NFPA 25 Section 6.3.1. The applicant also stated that it conducts 

(a) flow testing in the main headers that supply the standpipe system to verify that design 

pressure and required flow are met; (b) testing on the fire water hoses listed in the Technical 

Requirements Manual every 3 years by flowing several gallons of water to ensure there are no 

indications of obstruction or undue restriction; (c) flow tests at hose stations, including 

approximately 15 in the Auxiliary Building, 33 in the Reactor Building, and 8 in the RHR 

Complex; and (d) a “version” of a main drain test in each building every 18 months on a portion 

of the deluge and sprinkler systems. The applicant further stated the following: 

Fermi 2 also flow tests the wet pipe sprinkler systems through 14 inspector test 

valves and 7 main drain valves in the Reactor Building, Auxiliary Building and 

RHR Complex. For 6 of those locations that are flowed through the inspector 

test valve and main drain valve, the difference between static and flowing 

pressure is recorded and two of those locations are flowed through a sample 

collection sock. Any debris found in the sample collection sock is representative 

of what is in the rest of the system. Similar tests are also performed for the 

balance of the plant. 
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The applicant further stated that NFPA 25 (2014 Edition) Section 6.3.1 has been revised to state 

that the testing is only applicable to Class I and Class III standpipe systems and that its 

automatic standpipe system is Class II. 

NFPA 25 Section 6.3.1 requires that flow testing be conducted every 5 years. The purpose of 

the flow tests is to detect potential flow blockage. As stated in NFPA 25, a Class II standpipe 

system is differentiated from Class I and Class III systems based on the size of the hose 

stations supplied by the standpipe and its use (e.g., a Class III system supplies a larger volume 

of water for use by fire departments). 

During the audit, the staff confirmed that the applicant conducts fire water system main header 

flow testing and flow confirmation at each hose station every 3 years. In relation to Item (c) 

above, during the audit, the staff determined that flow is verified but not measured at hose 

stations. 

The staff reviewed this exception against the corresponding program element in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because the proposed alternative testing 

is sufficient to establish reasonable assurance that flow blockage will be detected before a CLB 

intended function not being met. The staff based this conclusion on the following: (a) the 

alternative flow verifications (in number, breadth of locations, and frequency), which provide 

insights concerning potential accumulation of corrosion products that are comparable to insights 

gained from the test recommended in LR-ISG-2012-02 AMP XI.M27, (b) the number of tests 

conducted (i.e., main header flow testing is conducted every 3 years, 64 hose stations are 

tested every 3 years to verify no flow blockage, and multiple main drain tests are conducted 

every 18 months), (c) the breadth of testing, which will encompass piping located in three 

different buildings, (d) the frequency of testing, with alternative tests conducted more frequently 

than every 5 years, and (e) removal by NFPA 25 (2014 Edition) (an industry consensus 

document) of the requirement to conduct the test for the class of standpipe used at the station. 

Exception 4. As amended by letter dated July 30, 2014, LRA Section B.1.19 includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that it does not perform main drain tests on all standpipes and risers as specified by 

NFPA 25 Sections 6.3.1.5 and 13.2.5. The applicant stated that it performs seven main drain 

tests throughout the plant. The tests are conducted to verify that there has not been a change 

in supply piping internal conditions and control valves. 

Several GALL Report AMPs (e.g., XI.M32, XI.M33) base the inspection population size on either 

20 percent or a maximum of 25 components of each material, environment, and aging effect 

combination. NFPA 25 Sections 13.2.5 and 13.2.5.1 (2014 Edition) allows the conduct of a 

reduced number of main drain tests. Specifically, where the lead-in to a building supplies a 

header or manifold serving multiple systems, a single main drain test is allowed. 

During the audit, the staff confirmed that there are 28 main drain test locations within the 

in-scope buildings protected by the fire protection water system. The staff also confirmed that 

the applicant conducts main drain tests in accordance with NFPA 25 at locations in the reactor 

building, auxiliary building, and general service water pump house building. 

The staff reviewed this exception against the corresponding program element in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, although the applicant has not 

proposed to conduct main drain tests in each water-based fire protection system riser, the 

proposed alternative testing is sufficient to establish reasonable assurance that flow blockage 
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will be detected before a CLB intended function not being met. The staff based this conclusion 

on the following: (a) the main drain tests, both in number and scope of locations, provide 

insights concerning potential accumulation of corrosion products that are sufficient from a 

sampling basis, (b) the applicant proposed to periodically perform seven main drain tests, which 

exceeds the 20-percent sampling size criterion cited in random sampling programs 

recommended in GALL Report AMPs XI.M32, XI.M33, and XI.M38, and (c) the testing locations 

encompass piping located in three different buildings. 

Exception 5. As amended by letter dated July 30, 2014, LRA Section B.1.19 includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that the calibration of gauges (NFPA 25 Section 6.3.1.5.2) is not addressed in the Fire 

Water System Program because they are active components. The staff reviewed this exception 

against the corresponding program element in LR-ISG-2012-02 AMP XI.M27 and finds it 

acceptable because calibration of test equipment is not addressed in LR-ISG-2012-02 

AMP XI.M27 and the staff recognizes that calibration of gauges is controlled by plant-specific 

procedures. 

Exception 6. As amended by letter dated July 30, 2014, LRA Section B.1.19 includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that it does not conduct inspections and cleaning of the suction screens for the fire water 

pumps after the annual flow test or fire protection activation as specified by NFPA 25 

Sections 8.3.3.7 and 14.3.1 (1). The applicant also stated that it conducts routine inspections of 

the intake structure screens (water source for the fire water system), annual inspections of the 

fire water pump suction screens, inspections of the diesel driven fire water pump discharge 

strainer on 18-month intervals, and inspections of the electric-driven fire water pump discharge 

strainer on 3-year intervals. 

NFPA 25 Section 14.3.1 (1) specifies that an obstruction inspection should be conducted if a 

“defective intake for fire pumps taking suction from open bodies of water” is detected. The staff 

determined that the purpose of inspecting the pump suction screens from a license renewal 

perspective is to provide insights into the condition of the internal surfaces of the fire water 

piping (see footnote 1 to LR-ISG-2012-02 AMP XI.M27, Table 4a). Periodic inspection of the 

intake structure screens ensures that external foreign material is not entering the system; 

however, foreign debris from the lake would not be associated with age-related degradation of 

the internal surfaces of the fire water piping. Therefore, the staff finds it acceptable that the 

applicant took exception to NFPA 25 Section 14.3.1 (1). The staff reviewed the exception to 

NFPA 25 Section 8.3.3.7 against the corresponding program element in LR-ISG-2012-02 

AMP XI.M27 and finds it acceptable because the applicant will periodically inspect both the 

suction screens and discharge strainers; therefore, the number and periodicity of inspections is 

sufficient to provide insights into the internal surface conditions of the fire water piping. 

Exception 7. As amended by letters dated July 30, 2014; January 15, 2015; and April 10, 2015, 

LRA Section B.1.19 includes an exception to the “detection of aging effects” program element. 

In this exception, the applicant stated that it performs full flow testing of the piping downstream 

of the deluge valves associated with transformers at least once each RFO, but it does not 

perform an internal inspection on the dry piping downstream of the deluge valves. The 

applicant also stated that it does not inspect the dry lines downstream of the manual isolation 

valves for the control center HVAC makeup filter charcoal filter absorber unit, control center 

HVAC recirculation filter charcoal absorber unit, and the manual wet pipe cable spreading room 

fire water supply, as specified by NFPA 25 Section 14.2 (5-year inspection of wet and dry fire 

water piping). The applicant further stated that, in lieu of performing these inspections, the 
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“piping and the nozzles associated with the charcoal absorber unit will be internally inspected 

when the charcoal is replaced.” 

LR-ISG-2012-02 AMP XI.M27, Table 4a, and NFPA 25 Section 13.4.3.2.2.4 state the frequency 

of testing deluge valves should not exceed every 3 years. It was not clear to the staff that the 

proposed exception is consistent with LR-ISG-2012-02 AMP XI.M27 because, during the audit, 

the staff reviewed charcoal filter media replacement work orders and determined that media is 

replaced approximately every 7 to 10 years. By letter dated December 17, 2014, the staff 

issued RAI B.1.19-2 requesting that the applicant state the basis for why there is reasonable 

assurance that the CLB intended function(s) of the deluge systems for the control center HVAC 

makeup filter charcoal filter absorber unit and the Control Center HVAC recirculation filter 

charcoal absorber unit will be met during the period of extended operation when inspections do 

not occur every 3 years. 

In its response dated January 15, 2015, the applicant stated that (a) the deluge valves for the 

control center HVAC makeup filter charcoal filter absorber unit and control center HVAC 

recirculation filter charcoal absorber unit are manually operated and, therefore, are not subject 

to NFPA 25 Section 13.4.3.2.2.4 testing, (b) the piping is normally isolated from the wet portion 

of the fire protection system, (c) the piping is constructed of stainless steel, (d) the suppression 

system does not have nozzles (e) the water is distributed by a series of holes in the piping, 

(f) the piping upstream of the manual isolation valve is constructed of carbon steel and “is 

routinely flushed to ensure no blockage,” and (g) “[s]hould obstructive material be found during 

flow testing, an obstruction investigation would be performed in accordance with NFPA 25 

Section 14.3.1 (2).” The applicant revised LRA Sections A.1.19 and B.1.19 to clarify that the 

charcoal units are adsorbers, not absorbers, and the deluge water is distributed by water 

distribution piping, not sprinklers. 

The staff noted that NFPA 25 Section 13.4.3.2.2.4 states that deluge valves shall be trip tested. 

The staff finds the applicant’s response, in part, acceptable because (a) the isolation valves are 

manual (i.e., not capable of being trip tested); therefore, they are not within the scope of 

NFPA 25 Section 13.4.3.2.2.4 and (b) flow blockage due to buildup of corrosion products would 

not be expected to occur in the stainless steel normally dry portions of the charcoal filter water 

distribution piping. However, corrosion products could accumulate in the upstream carbon steel 

piping, and although the applicant stated that this piping is routinely flushed, it did not state the 

periodicity of these flushes or how they are documented in the CLB. By letter dated 

March 11, 2015, the staff issued RAI B.1.19-2a requesting that the applicant state and justify the 

periodicity of the flushing of the carbon steel piping upstream of the control center HVAC 

makeup filter charcoal filter absorber unit and control center HVAC recirculation filter charcoal 

absorber unit and state how the periodicity of the flushing is documented in the CLB. 

In its response dated April 10, 2015, the applicant stated the steel piping supplying the control 

center HVAC units is normally isolated and drained. In accordance with the TRM, the isolation 

valve is opened and closed once every 12 months. The piping is drained after the valve is 

closed. The applicant also stated that personnel inspect for “particles and other indications of 

flow blockage” during draining. The applicant further stated that the plant-specific procedure 

does not require documentation of the inspection of the drain down water; however, an 

enhancement, Enhancement 12 was added to the program to include formal documentation of 

the inspection for indications of flow blockage during draining of the steel piping upstream of the 

control center HVAC units. The applicant revised LRA Sections A.1.19 and B.1.19 and 

Commitment No. 14 to reflect the new enhancement. 
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The staff finds the applicant’s response acceptable because the annual (more frequent than the 

3-year interval for deluge valve testing) drain down of the steel portions of the supply to the 

control center HVAC units and observation for indications of flow blockage provide reasonable 

assurance that the distribution holes will not be blocked. The staff’s concern described in 

RAIs B.1.19-2 and B.1.19-2a is resolved. 

The applicant also stated that it will perform a one-time inspection of the dry piping downstream 

of the manual isolation valve for the wet pipe system for the cable spreading room. The 

applicant further stated that this piping is a backup system for the Halon system that provides 

fire suppression for the cable spreading room. 

LR-ISG-2012-02 AMP XI.M27 recommends the conduct of periodic inspections of fire water 

system piping that is exposed to indoor air. It was not clear to the staff that the proposed 

exception is consistent with LR-ISG-2012-02 AMP XI.M27 because the applicant did not provide 

a basis for why there is reasonable assurance that the CLB intended function(s) of the piping 

would be met when only a one-time inspection is conducted. By letter dated 

December 17, 2014, the staff issued RAI B.1.19-1 requesting that the applicant state the basis 

for why there is reasonable assurance that the CLB intended function(s) of the piping 

downstream of the manual isolation valve for the wet pipe system for the cable spreading room 

will be met during the period of extended operation when only a one-time inspection is 

conducted. 

In its response dated January 15, 2015, the applicant revised its Periodic Surveillance and 

Preventive Maintenance Program to require periodic visual inspections of a representative 

sample of the dry piping downstream of the manual isolation valve for the cable spreading room 

wet pipe system to detect potential flow blockage. The inspections will commence within the 

5-year period before the period of extended operation and will be conducted every 5 years. The 

applicant also revised the “acceptance criteria” program element of the Periodic Surveillance 

and Preventive Maintenance Program to state the following: “[n]o flow blockage due to fouling.” 

In addition, the applicant revised LRA Table 3.3.2-7 to include an AMR item for carbon steel 

piping exposed to air-indoor being managed for flow blockage due to fouling by the Periodic 

Surveillance and Preventive Maintenance Program. 

The staff finds the applicant’s response acceptable because the periodic visual inspections are 

capable of detecting flow blockage; the periodicity is consistent with NFPA 25 Section 14.2.1, 

which cites a frequency of 5 years for internal piping inspections; and the “acceptance criteria” 

program element for the Periodic Surveillance and Preventive Maintenance Program states that 

flow blockage due to fouling is not acceptable. The staff’s concern described in RAI B.1.19-1 is 

resolved. 

The staff reviewed this exception and Enhancements 10 and 18 below against the 

corresponding program element in GALL Report AMP XI.M27, as modified by LR-ISG-2012-02 

and finds it acceptable because the proposed alternative inspections occur on a frequency 

sufficient to detect potential flow blockage and because the inspection methods are capable of 

detecting precursors to flow blockage. 

Enhancement 1. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “parameters monitored or inspected” program element. In this 

enhancement, the applicant stated that the Fire Water System Program procedures will be 

revised to require sprinkler heads to be tested or replaced in accordance with NFPA 25. The 

staff reviewed this enhancement against the corresponding program elements in 
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LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when it is implemented, it will be 

consistent with LR-ISG-2012-02 AMP XI.M27, which recommends testing of sprinkler heads 

that have been in service for 50 years. 

Enhancement 2. As amended by letters dated July 30, 2014, and January 15, 2015, LRA 

Section B.1.19 states an enhancement to the “parameters monitored or inspected” program 

element. In this enhancement, the applicant stated that the Fire Water System Program 

procedures will be revised to: 

[P]erform an inspection of wet fire water system piping condition at least once 

every five years by opening a flushing connection at the end of one main and by 

removing a sprinkler toward the end of one branch line for the purpose of 

inspecting the interior for evidence of loss of material and the presence of foreign 

organic or inorganic material that could result in flow obstructions or blockage of 

a sprinkler head. (Refer to NFPA 25 (2011 Edition) Section 14.2.1). 

The applicant also stated that the inspection technique will be capable of detecting surface 

irregularities that are indicative of loss of material, corrosion product deposition, and flow 

blockage due to fouling. The applicant further stated that it will conduct followup volumetric wall 

thickness evaluations where irregularities are detected. 

NFPA 25 Section 14.2.2 specifies that, in buildings with multiple wet pipe systems, every other 

system is inspected every 5 years. During the audit, the applicant confirmed that it has multiple 

wet pipe systems in buildings with in-scope components protected by the fire water system. 

The applicant did not provide a basis for why testing only one system every 5 years is sufficient. 

By letter dated December 17, 2014, the staff issued RAI B.1.19-3 requesting that the applicant 

state the basis for why inspecting only one of the wet pipe systems in each building every 

5 years will provide reasonable assurance that the wet fire water system piping will be capable 

of performing its CLB intended function(s) during the period of extended operation. 

In its response dated January 15, 2015, the applicant revised the enhancement to state that 

“[w]here multiple wet-pipe systems are in a building every other system shall be inspected in a 

five year period. Then in the next five year period, the remaining systems in that building shall 

be inspected.” 

The staff finds the applicant’s response and Enhancements 2 and 7 (below) acceptable 

because it is consistent with LR-ISG-2012-02 AMP XI.M27 and NFPA 25 Section 14.2.2, which 

recommend that every other piping system be inspected to ensure that an adequate number of 

inspections are conducted to ensure that potential flow blockage is detected. The staff’s 

concern described in RAI B.1.19-3 is resolved. 

Enhancement 3. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the Fire Water System Program procedures will be revised to require that 

sprinkler heads are tested or replaced in accordance with NFPA 25 and that the fire protection 

engineer will approve the test laboratory. The staff reviewed this enhancement against the 

corresponding program elements in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because, when it is implemented, it will be consistent with LR-ISG-2012-02 AMP XI.M27, which 

recommends testing of sprinkler heads that have been in service for 50 years. 
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Enhancement 4. As amended by letters dated July 30, 2014, and January 15, 2015, LRA 

Section B.1.19 states an enhancement to the “detection of aging effects” program element. In 

this enhancement, the applicant stated that the Fire Water System Program procedures will be 

revised to: 

a) address a 10 percent decrease in pressure from one main drain test to the 

previous main drain test results, b) note the time to return to static pressure after 

performing a main drain test, and c) develop a basis for the acceptance criteria of 

≤ 25 psig and ≤ 10 psig that currently exists in the main drain test procedures. 

LR-ISG-2012-02 AMP XI.M27 recommends that, as stated in NFPA Section 13.2.5.2, a 

10 percent reduction on full flow pressure during main drain tests should be corrected. During 

the audit, the staff confirmed that the fire water system header pressure is 150 psig, plus or 

minus 10 psig. Although the enhancement states that the basis for the less than or equal to 

25 psig and less than or equal to 10 psig criteria will be developed before the period of extended 

operation, the staff could not complete its review of the Fire Water System Program until it was 

provided the basis for the acceptance criteria. By letter dated December 17, 2014, the staff 

issued RAI B.1.19-4 requesting that the applicant provide the basis for the acceptance criteria of 

less than or equal to 25 psig and less than or equal to 10 psig that currently exists in the main 

drain test procedures. 

In its response dated January 15, 2015, the applicant revised this enhancement to state the 

following: “[I]n accordance with NFPA Section 13.2.5.2 when there is a 10 percent reduction in 

full flow pressure when compared to the original acceptance test or previously performed tests, 

the cause of the reduction shall be identified and corrected as necessary.” The applicant 

deleted part (c) of this enhancement. 

The staff finds the applicant’s response and this enhancement acceptable because, as 

amended, it is consistent with NFPA Section 13.2.5.2 and the acceptance criteria of a 

10 percent reduction in full flow is sufficient to detect potential flow blockage. The staff finds the 

deletion of part (c) of the enhancement acceptable because with adoption of the 10 percent 

criterion, a basis for the less than or equal to 25 psig and less than or equal to 10 psig that 

currently exists in the main drain test procedures is not necessary for the staff to evaluate this 

enhancement. The staff’s concern described in RAI B.1.19-4 is resolved. 

Enhancement 5. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the Fire Water System Program procedures will be revised to notify the fire 

protection engineer of test results and deficiencies identified or detected during testing. The 

staff reviewed this enhancement against the corresponding program elements in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, although personnel 

qualifications are not addressed in LR-ISG-2012-02 AMP XI.M27, when it is implemented, it will 

ensure that the appropriate personnel evaluate test results and inspection deficiencies. 

Enhancement 6. As amended by letters dated July 30, 2014, and January 15, 2015, LRA 

Section B.1.19 states an enhancement to the “detection of aging effects” program element. In 

this enhancement, the applicant stated that the Fire Water System Program procedures will be 

revised to “ensure piping and sprinklers are cleaned if obstructions are identified during internal 

inspections.” 
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LR-ISG-2012-02 AMP XI.M27 recommends that, as stated in NFPA Section 5.2.1.1.2, sprinklers 

that are corroded or that exhibit loading should be replaced. By letter dated 

December 17, 2014, the staff issued RAI B.1.19-5 requesting that the applicant state the basis 

for why cleaning debris from a sprinkler will not impact its ability to perform its CLB intended 

function(s) during the period of extended operation. 

In its response dated January 15, 2015, the applicant revised the enhancement to state that 

(a) piping is cleaned if obstructions are identified during inspections, (b) sprinklers are replaced 

if obstructions are identified during inspections, and (c) “[s]prinklers loaded with dust may be 

cleaned using air rather than replaced.” 

The staff finds the applicant’s response and this enhancement acceptable because replacing 

sprinklers rather than cleaning them if obstructions are detected is consistent with 

LR-ISG-2012-02 AMP XI.M27 and NFPA 25 Section 5.2.1.1.2, which ensures that, rather than 

potentially damaging a sprinkler during cleaning, it is replaced. Use of compressed air to clean 

dust from a sprinkler is consistent with NFPA 25 Section A.5.2.1.1.2 (5), which recommends this 

practice for sprinklers loaded with a coating of dust. The staff’s concern described in 

RAI B.1.19-5 is resolved. 

Enhancement 7. As amended by letters dated July 30, 2014, and January 15, 2015, LRA 

Section B.1.19 states an enhancement to the “detection of aging effects” program element. 

This enhancement reflects the changes to the “detection of aging effects” program element 

reflected in Enhancement 2 associated with the “parameters monitored or inspected” program 

element. The staff’s evaluation of this enhancement is documented in the above discussion of 

Enhancement 2. 

Enhancement 8. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the Fire Water System Program procedures will be revised to require that a 

“one-time internal inspection of the dry portion of the manual wet pipe system associated with 

the cable spreading room will be performed by removing a sprinkler toward the end of one 

branch line.” As a result of the response to RAI B.1.19-1, this enhancement was deleted. The 

staff’s evaluation of the RAI response is documented in Exception 7 above. Given the 

enhancement to the Periodic Surveillance and Preventive Maintenance Program described in 

Exception 7, the staff finds it acceptable to delete the one-time inspection of this piping because 

periodic inspections will be conducted. 

Enhancement 9. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the Fire Water System Program procedures will be revised to: 

[P]erform at least once every five years either an internal inspection of the dry 

components downstream of the deluge valves for the hydrogen seal oil unit by 

removing a sprinkler toward the end of one branch line and inspecting for 

evidence of loss of material and the presence of foreign organic and inorganic 

material that could result in flow obstructions or blockage of sprinklers, or Revise 

Fire Water System Program procedures to perform at least once every five years 

an air or smoke test to verify there is no flow obstruction or blockage of 

sprinklers. 
3-124 

NFPA 25 Section 13.4.3.2.2.4 specifies that the interval between deluge valve full flow testing 

should not exceed 3 years. During the audit the staff confirmed that the applicant tests the 

hydrogen seal oil unit deluge system every 364 days. 

The staff reviewed this enhancement against the corresponding program elements in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when implemented, it will 

supplement the recommended deluge valve testing for the hydrogen seal oil unit, which is 

conducted more frequently than what is cited in NFPA 25. 

Enhancement 10. As amended by letters dated July 30, 2014, and January 15, 2015, LRA 

Section B.1.19 states an enhancement to the “detection of aging effects” program element. In 

this enhancement, the applicant stated that the Fire Water System Program procedures will be 

revised to perform an internal inspection of the water distribution piping associated with charcoal 

filters, when the charcoal beds are replaced, for loss of material and debris that could result in 

flow blockage. 

This enhancement is associated with Exception 7 above. The discussion of Exception 7 above 

documents the staff’s evaluation of this enhancement. 

Enhancement 11. As amended by letters dated July 30, 2014, and January 15, 2015, LRA 

Section B.1.19 states an enhancement to the “detection of aging effects” program element. In 

this enhancement, the applicant stated that the Fire Water System Program procedures will be 

revised to “perform an obstruction investigation after an extended shutdown of more than one 

year.” 

NFPA 25 Section 14.2.1.3 specifies that an obstruction investigation should be performed if 

sufficient inorganic material is found to obstruct pipe or sprinklers. In addition, NFPA 25 

Section 14.3.1 includes criteria for conducting an obstruction inspection related to aging 

management (e.g., discharge of obstructive material during routine water tests, plugging of 

inspector’s test connection, and pinhole leaks). During the audit, the staff did not find any 

procedures that included the additional criteria for conducting an obstruction investigation. In 

addition, the applicant did not provide a basis for why its enhancement is sufficient to ensure 

that it would conduct obstruction investigations when appropriate. By letter dated 

December 17, 2014, the staff issued RAI B.1.19-6 requesting that the applicant state the criteria 

that will be used to determine when an obstruction investigation should be conducted. 

In its response dated January 15, 2015, the applicant revised the enhancement to state that 

obstruction investigations will be conducted whenever any of the criteria in NFPA 25 

Sections 14.2.1.3 or 14.3.1 are met. 

The staff finds the applicant’s response and this enhancement acceptable because obstruction 

investigations will be conducted consistent with LR-ISG-2012-02 AMP XI.M27 and NFPA 25 

Sections 14.2.1.3 or 14.3.1, which ensures that when conditions occur that could be indicative 

of potential flow blockage, the extent of the issue is investigated and corrected. The staff’s 

concern described in RAI B.1.19-6 is resolved. 

Enhancement 12. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that a walk down of normally dry piping that is periodically wetted will be 

conducted to determine whether there are any segments that collect water. The applicant also 

stated that it will conduct periodic inspections or tests of normally dry but periodically wetted 
3-125 

firewater system piping that are collecting water, including flow test, flushes, or internal 

inspections of 100 percent of the piping that cannot be drained or allows water to collect, and 

will conduct volumetric wall thickness measurements of 20 percent of the piping. The flow tests, 

flushes, or internal inspections will commence 5 years before the period of extended operation 

and will be conducted every 5 years during the period of extended operation. The wall 

thickness measurements will be conducted every 5 years during the period of extended 

operation. The staff reviewed this enhancement against the corresponding program elements in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when it is implemented, it will be 

consistent with LR-ISG-2012-02 AMP XI.M27, which recommends the described augmented 

tests and inspections for normally dry piping that is periodically wetted and allows water to 

collect. 

Enhancement 13. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “acceptance criteria” program element. In this enhancement, the applicant 

stated that the Fire Water System Program procedures will be revised to “include acceptance 

criteria that any indication of fouling is evaluated.” 

The staff reviewed this enhancement against the corresponding program elements in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when it is implemented, it will be 

consistent with LR-ISG-2012-02 AMP XI.M27, which recommends that indications of 

degradation detected during flow testing and visual inspections should be evaluated. 

Enhancement 14. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “acceptance criteria” program element. In this enhancement, the applicant 

stated that the Fire Water System Program procedures will be revised to “specify that if the 

presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is 

detected during pipe inspections, the material is removed and the source and extent of condition 

determined, corrected, and the condition entered into the Corrective Action Program.” The staff 

reviewed this enhancement against the corresponding program elements in LR-ISG-2012-02 

AMP XI.M27 and finds it acceptable because, when it is implemented, it will be consistent with 

LR-ISG-2012-02 AMP XI.M27, which recommends removal of debris, evaluation of the debris 

source, and actions taken to correct the cause of the source of the debris. 

Enhancement 15. As amended by letter dated July 30, 2014, LRA Section B.1.19 states an 

enhancement to the “corrective actions” program element. In this enhancement, the applicant 

stated that the Fire Water System Program procedures will be revised to “replace sprinklers 

associated with representative tested sprinkler, if the representative test sprinkler fails to meet 

the test requirements.” The staff reviewed this enhancement against the corresponding 

program elements in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when it is 

implemented, it will be consistent with LR-ISG-2012-02 AMP XI.M27, which recommends 

testing of sprinklers that have been in service for 50 years to determine whether they need to be 

replaced. 

Enhancement 16. As amended by letter dated January 15, 2015, LRA Section B.1.19 states an 

enhancement to the “acceptance criteria” program element. In this enhancement, the applicant 

stated that the Fire Water System Program procedures will be revised to state that any sprinkler 

that shows signs of corrosion will be replaced. RAI B.1.19-7 documents the staff’s evaluation of 

this enhancement. 
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Enhancement 17. As amended by letters dated January 15, 2015, and April 10, 2015, LRA 

Section B.1.19 states an enhancement to the “corrective action” program element. In this 

enhancement, the applicant stated the following: 

If the decreasing trend in fire water system flow tests is not resolved through the 

Corrective Action Program prior to the period of extended operation, revise Fire 

Water System Program procedures to continue performing annual fire water 

system flow tests during the period of extended operation until such a time as 

trend data from fire water system flow tests indicates that the system will be 

capable of performing its intended function throughout the period of extended 

operation and therefore TRM frequency may be resumed. 

RAI B.1.19-8 below documents the staff’s evaluation of this enhancement. 

Enhancement 18. As amended by letter dated April 10, 2015, LRA Section B.1.19 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the Fire Water System Program procedures will be revised to document 

the inspection of the drain down water from the steel piping upstream of the control center 

HVAC units. The response to RAI B.1.19-2a documents the staff’s evaluation of this 

enhancement. 

Based on its audit and review of the applicant’s responses to RAIs B.1.19-1 through B.1.19-7 

and RAI B.1.19-2a, the staff finds that program elements 1 through 6 and the “corrective 

actions” program element for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of LR-ISG-2012-02 AMP XI.M27. The staff 

also reviewed the exceptions associated with the “detection of aging effects” program element 

and their justifications and finds that the AMP, with the exceptions, is adequate to manage the 

applicable aging effects. In addition, the staff reviewed the enhancements associated with the 

“parameters monitored or inspected,” “detection of aging effects,” “acceptance criteria,” and 

“corrective action” program elements and finds that, when implemented, they will make the AMP 

adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.19 summarizes operating experience related to the 

Fire Water System Program. The LRA describes instances in which planned inspections were 

not conducted and describes inspections that identified internal tubercles. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, which resulted in the issuance of an RAI, as discussed below. 

One of the plant-specific operating experience examples cited in the LRA describes fire 

suppression flow testing that demonstrated degrading conditions in the underground piping 

system. The applicant stated that it increased the frequency of testing and evaluation of this 

piping from 3 years, as required in the CLB, to annual testing. Based on its review of corrective 

action reports that describe the trend of degradation, it is not clear to the staff why the increased 
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frequency of testing should not be continued during the period of extended operation. By letter 

dated December 17, 2014, the staff issued RAI B.1.19-8 requesting that the applicant state the 

basis for why performing the fire suppression flow test of the underground piping system every 

3 years during the period of extended operation will be adequate to detect a decreasing trend 

before the system not being able to perform its CLB intended function. 

In its response dated January 15, 2015, the applicant revised the Fire Water System Program to 

include a new enhancement, Enhancement 17, as described above. 

The staff did not find the applicant’s response and Enhancement 17 acceptable because the 

enhancement states that the applicant will “consider in accordance with the Corrective Action 

Program increasing test frequency.” The term “consider” leaves it indeterminate whether the 

frequency of fire water system flow tests will be increased during the period of extended 

operation if the current decreasing trend in system performance reveals that the system may not 

be capable of performing its intended function throughout the period of extended operation. 

With the current trend in performance, the staff lacked sufficient information to conclude that 

existing corrective actions will be sufficient to correct the adverse trend; therefore, the staff 

could not conclude that the applicant has appropriately evaluated plant-specific operating 

experience. By letter dated March 11, 2015, the staff issued RAI B.1.19-8a requesting that the 

applicant state the basis for why the current trend in system performance will be corrected 

before the period of extended operation or state a commitment to continue the increased 

frequency of fire water system flow tests until such time as trend data demonstrate that the 

system will be capable of performing its intended function throughout the period of extended 

operation. 

In it response dated April 10, 2015, the applicant stated annual flow tests will continue to be 

conducted until the data demonstrate that the fire water system will be capable of performing its 

intended function throughout the period of extended operation. The applicant revised LRA 

Sections A.1.19 and B.1.19 and Commitment No. 14 to reflect the revision to Enhancement 17. 

The staff finds the applicant’s response and enhancement acceptable because annual flow 

testing provides sufficient input data to the plant staff to determine the extent of degraded 

conditions in the underground portions of the fire water system. The staff’s concern described 

in RAIs B.1.19-8 and B.1.19-8a is resolved. 

Based on its audit and review of the application and review of the applicant’s response to 

RAIs B.1.19-8 and B.1.19-8a, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience and that implementation of the program has 

resulted in the applicant taking corrective actions. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which LR-ISG-2012-02 

AMP XI.M27 was evaluated. 

UFSAR Supplement. LRA Section A.1.19, as amended by letters dated July 30, 2014; 

January 15, 2015; and April 10, 2015, provides the UFSAR supplement for the Fire Water 

System Program. 

The staff reviewed this UFSAR supplement description of the program against the 

recommended description for this type of program as described in SRP-LR Table 3.0-1, as 

modified by LR-ISG-2012-02, and noted that as amended by letter dated July 30, 2014, LRA 

Section A.1.19 references fouling and flow blockage. However, these statements only refer to 

conducting visual inspections, not all of the inspections and testing in the program. 
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LR-ISG-2012-02 Table 3.0-1 recommends that the UFSAR supplement summary description for 

the Fire Water System Program should state that it manages fouling and flow blockage. The 

CLB for this program for the period of extended operation may not be adequate if the applicant 

does not incorporate this information in its UFSAR supplement. By letter dated 

December 17, 2014, the staff issued RAI B.1.19-9 requesting that the applicant state the basis 

for not including fouling and flow blockage in the UFSAR supplement description for the Fire 

Water System Program. 

In its response dated January 15, 2015, the applicant revised LRA Section A.1.19 to state the 

program “manages loss of material due to general pitting, and crevice corrosion, 

microbiologically-influenced corrosion, or fouling, and flow blockage due to fouling.” Therefore, 

the UFSAR supplement for the Fire Water System Program is consistent with the corresponding 

program description in LR-ISG-2012-02 SRP-LR Table 3.0-1. The staff’s concern described in 

RAI B.1.19-9 is resolved. 

The staff also noted that the applicant committed to enhance the program as described in the 

above Enhancements 1 through 18. The staff further noted that the applicant committed to 

implement the enhancement(s) “[p]rior to September 20, 2024, or the end of the last refueling 

outage prior to March 20, 2025, whichever is later, with the exception that the activities 

described in this commitment for piping segments designed to be dry but determined to be 

collecting water shall be conducted within five years prior to March 20, 2025.” 

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

April 10, 2015, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Fire Water System Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determined that the AMP, with the exception(s), is adequate to manage the 

applicable aging effects. In addition, the staff reviewed the enhancements and confirmed that 

their implementation before the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Flow-Accelerated Corrosion 

Summary of Technical Information in the Application. LRA Section B.1.20 describes the 

existing Flow-Accelerated Corrosion Program as consistent, with enhancements, with GALL 

Report AMP XI.M17, “Flow-Accelerated Corrosion.” The LRA states that the program manages 

wall thinning caused by flow-accelerated corrosion in carbon steel piping and components by 

performing an analysis to identify susceptible systems, conducting analyses to predict wall 

thinning, performing wall thickness measurements based on predictions and operating 

experience, and evaluating measurement results to determine the remaining service life and the 

need for replacement or repair. The LRA also states that the program relies on implementing 

the guidelines of EPRI NSAC-202L-R3, “Recommendations for an Effective Flow-Accelerated 

Corrosion Program,” Revision 3, dated August 10, 2007, and internal and external operating 

experience. In addition, the LRA states that the program also manages wall thinning due to 
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various erosion mechanisms in treated water or steam systems for all materials that may be 

identified through industry or plant-specific operating experience. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 7 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M17. For the “scope of program” 

program element, the staff identified the need for additional information, which resulted in the 

issuance of RAIs, as discussed below. 

The “scope of program” program element in GALL Report AMP XI.M17 recommends that the 

program, as described by EPRI NSAC-202L, includes procedures or administrative controls to 

ensure that the structural integrity is maintained. The applicant’s program uses the 

CHECWORKSTM predictive software and categorizes this software as Class B. The staff noted 

that the applicant’s administrative controls only allow software categorized as Class A to be 

used for safety-related design work; however, the implementing procedures allow the wear 

calculated using CHECWORKSTM to demonstrate that the design wall thickness will be met at 

the next RFO. The staff also noted that the program includes both safety-related and 

nonsafety-related components, but does not limit the use of the wear rates calculated by 

CHECWORKSTM to nonsafety-related components. By letter dated December 19, 2014, the 

staff issued RAI B.1.20-1 requesting that the applicant demonstrate how wear rates calculated 

by CHECWORKSTM for safety-related components are independently checked and verified or 

justify the use of Class B software for safety-related design work. 

In its response dated January 28, 2015, the applicant stated that it had revised the 

implementing procedure (MES26, “Flow-Accelerated Corrosion, Prediction, Detection, and 

Correction”) in December 2014 to modify the process for component evaluation. The applicant 

stated that MES26 now draws a distinction between ANSI B31.1, “Power Piping,” 

(nonsafety-related) and ASME Code Section III (safety-related) components requiring ASME 

Code components to be evaluated using methods that do not use CHECWORKSTM calculation 

results and that allow for independent verification by a qualified checker. The applicant also 

stated that MES26 includes a new enclosure listing all lines containing ASME Code components 

to ensure the appropriate methodology is used for analysis. The staff finds the applicant’s 

response acceptable because the applicant revised its implementing procedure to distinguish 

between safety-related and nonsafety-related components to ensure that calculation results 

from CHECWORKSTM, which is currently categorized as Class B software, are not used for 

safety-related design work. The staff’s concerns described in RAI B.1.20-1 are resolved. 

According to SRP-LR Section A.1.2.3.1, the “scope of program” program element should 

include the specific SCs that are being managed by the program. The staff noted that the onsite 

information identified Program Notebook PEP19, “Flow-Accelerated Corrosion,” as one of the 

sources of information for this program. Although PEP19 specifies the “Feedwater Heater 

Susceptibility Review” as one of the items to be considered for the outage scope, the staff noted 

that LRA Table 3.4.2-2 only showed the feedwater shells as being managed for loss of material 

by the Water Chemistry Control – BWR Program. By letter dated December 19, 2014, the staff 

issued RAI B.1.20-2 requesting that the applicant clarify whether the feedwater shells are being 

managed for loss of material by the Flow-Accelerated Corrosion Program. 

In its response dated January 28, 2015, the applicant stated that the Flow-Accelerated 

Corrosion Program manages loss of material in the feedwater heater shells through periodic 

inspections. The applicant also revised LRA Table 3.4.2-2 by adding a new item that includes 

the Flow-Accelerated Corrosion Program for managing loss of material in the feedwater heat 
3-130 

exchanger shells. The staff finds the applicant’s response acceptable because the applicant 

revised LRA Table 3.4.2-2 to include the specific components being managed by the program 

as recommended in the SRP-LR. The staff’s concern described in RAI B.1.20-2 is resolved. 

The staff also reviewed the portions of the “scope of program,” “detection of aging effects,” 

“monitoring and trending,” and “corrective action” program elements associated with the 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.1.20 includes an enhancement to the “scope of program,” 

“detection of aging effects,” “monitoring and trending,” and “corrective action” program 

elements. In this enhancement, the applicant stated that the program procedures would be 

revised to indicate that the Flow-Accelerated Corrosion Program also manages loss of material 

due to erosion mechanisms and to include a susceptibility review based on internal and external 

operating experience and various industry guidance documents. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M17, as 

modified by LR-ISG-2012-01, “Wall Thinning Due to Erosion Mechanisms,” dated May 1, 2013, 

and notes that the LRA currently contains several of the new AMR items included in 

LR-ISG-2012-01. The staff finds the enhancement acceptable because, when it is 

implemented, the Flow-Accelerated Corrosion Program will manage loss of material due to 

erosion mechanisms consistent with the guidance provided in LR-ISG-2012-01. 

Enhancement 2. LRA Section B.1.20 includes an additional enhancement to the “corrective 

action” program element. In this enhancement, the applicant stated that the program 

procedures would be revised to specify that downstream components are monitored for wall 

thinning whenever susceptible upstream components are replaced with materials that are 

resistant to flow-accelerated corrosion. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M17 and finds it acceptable because 

monitoring the wear rates on components downstream of components that are replaced with 

resistant materials is appropriate based on industry guidance and because it is consistent with 

the guidance in the GALL Report. 

Based on its audit and review of the applicant’s responses to RAIs B.1.20-1 and B.1.20-2, the 

staff finds that program elements 1 through 7 for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M17. In addition, the staff reviewed the enhancements associated with the “scope of 

program,” “detection of aging effects,” “monitoring and trending,” and “corrective actions” 

program elements and finds that, when implemented, they will make the AMP adequate to 

manage the applicable aging effects. 

Operating Experience. LRA Section B.1.20 summarizes operating experience related to the 

Flow-Accelerated Corrosion Program. The LRA discusses self-assessments and gap studies 

performed in 2008, 2010, and 2011 that resulted in recommendations, gaps, and deficiencies 

being entered into the applicant’s corrective action program. The LRA also includes examples 

of specific inspections that resulted in replacements or increased inspection frequencies. The 

LRA concludes that the history of identification of degradation and program deficiencies with 

subsequent corrective actions before loss of intended function provide assurance that the 

program will remain effective. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 
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experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M17 was evaluated. 

UFSAR Supplement. LRA Section A.1.20 provides the UFSAR supplement for the 

Flow-Accelerated Corrosion Program. The staff reviewed this UFSAR supplement description 

of the program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the UFSAR supplement included a description of the 

program enhancements discussed above that are also contained in Commitment No. 15. The 

staff finds that the information in the UFSAR supplement is an adequate summary description of 

the program. 

Conclusion. On the basis of its audit and review of the applicant’s Flow-Accelerated Corrosion 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation before the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Inservice Inspection – IWF 

Summary of Technical Information in the Application. LRA Section B.1.22 describes the 

existing Inservice Inspection – IWF Program as consistent, with enhancements, with GALL 

Report AMP XI.S3, “ASME Section XI, Subsection IWF.” 

The LRA states that the AMP addresses ASME Code Class 1, 2, 3 and metal containment (MC) 

piping supports and component supports exposed to uncontrolled indoor air, outdoor air, and 

fluid to manage the effects of loss of material, loss of mechanical function, and loss of preload. 

The LRA also states that the AMP proposes to manage these aging effects through periodic 

visual inspections. The LRA further states that the AMP is implemented through plant 

procedures and that the necessary activities are conducted to comply with the requirements of 

ASME Code Section XI in accordance with 10 CFR 50.55a. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S3. 
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For the “preventive actions,” “parameters monitored or inspected,” and “detection of aging 

effects” program elements, the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below. 

The “detection of aging effects” program element in GALL Report AMP XI.S3 recommends that, 

for high strength structural bolting (actual measured yield strength greater than or equal to 

150 ksi) in sizes greater than 1 inch in nominal diameter, volumetric examinations should be 

performed in addition to VT-3 (i.e., visual examinations) to detect cracking. GALL Report 

AMP XI.S3 also has the following recommendations for aging management of high strength 

structural bolting: 

 The “scope of program” program element states that the scope of the program includes 

high strength structural bolting. 

 The “preventive actions” program element recommends using bolting material that has 

an actual measured yield strength that is less than 150 ksi. 

 The “parameters monitored or inspected” program element recommends that high 

strength structural bolting susceptible to SCC should be monitored for cracking. 

 The “detection of aging effects” program element states that the volumetric examination 

may be waived with adequate plant-specific justification. 

The staff noted that the AMP includes enhancements to revise plant procedures to identify 

unacceptable conditions, such as “cracked or sheared bolts, including high strength bolts.” 

However, it is not clear whether there are high strength structural bolts (actual measured yield 

strength greater than or equal to 150 ksi) in sizes greater than 1 inch in nominal diameter within 

the scope of the AMP. In addition, it is not clear how the applicant plans to manage aging for 

these components consistent with GALL Report AMP XI.S3 recommendations in the “preventive 

actions” and “parameters monitored or inspected” program elements described above. The 

LRA also states that “[p]lant procedures prohibit the use of lubricants containing molybdenum 

disulfide [(MoS2)]. Since the use of this type of lubricant is prohibited in plant procedures and 

plant procedures provide the technical guidance for installation requirements [...], the potential 

for [SCC] for high-strength structural bolting material, i.e., ASTM A325 and A490, is not 

plausible.” Because the use of MoS2 is not the only contributor to SCC of high strength bolts, 

the staff has not determined that there is sufficient basis to conclude that SCC is not a credible 

aging effect for high strength structural bolting (actual measured yield strength greater than or 

equal to 150 ksi) in sizes greater than 1 inch in diameter. If there are high strength structural 

bolts (actual measured yield strength greater than or equal to 150 ksi) in sizes greater than 

1 inch in diameter within the scope of license renewal, the staff needs additional information 

regarding the environments to which these bolts are exposed to evaluate the applicant's claim 

that there is no potential for SCC. Therefore, by letter dated December 19, 2014, the staff 

issued RAI B.1.22-1 requesting the applicant to: 

(1) State whether or not there are high-strength structural bolts (actual measured yield 

strength greater than or equal to 150 ksi) in sizes greater than 1 inch diameter within the 

scope of the Inservice Inspection – IWF Program, and 

(2) If high strength structural bolts (actual measured yield strength greater than or equal to 

150 ksi) in sizes greater than 1 inch diameter are within the scope of the AMP, 

(a) provide additional information regarding the environments to which bolts are 

exposed, and (b) state whether the recommendations for managing degradation of 

high-strength bolts described in the “preventive actions” and “parameters monitored or 
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inspected” of GALL Report AMP XI.S3 will be implemented for the Inservice Inspection – 

IWF Program. 

By letter dated February 19, 2015, the applicant provided its response to RAI B.1.22-1. In its 

response to RAI B.1.22-1, Part (1), the applicant stated that it reviewed the Fermi 2 pipe 

erection specification, concrete anchor specification, and 100 percent of the hanger sketch bill 

of materials for the ASME Code Section XI Class 1, 2, 3 component supports that are part of the 

ISI sample. Based on its review of these documents, the applicant determined that there are 

60 ASTM A490 high strength structural bolts (actual measured yield strength greater than or 

equal to 150 ksi) in sizes greater than 1 inch in diameter within the scope of the Inservice 

Inspection – IWF Program. The bolts are located in the RPV skirt to ring girder bolted joint and 

are subject to visual inspections under the Inservice Inspection – IWF Program. The applicant 

also stated that there are no additional high strength structural bolts (actual measured yield 

strength greater than or equal to 150 ksi) in sizes greater than 1 inch in diameter within the 

scope of the Inservice Inspection – IWF Program. In its response to RAI B.1.22-1, Part (2)(a), 

the applicant stated that the bolts are “installed in the lower area of the bioshield annulus, which 

is a dry and relatively cool area of the drywell” and that the bolt thread lubricant does not contain 

MoS2. The applicant also stated that, during Fermi 2 plant operation, the drywell is inerted with 

nitrogen. Based on these conditions the applicant concluded that the bolts are in a 

noncorrosive low-temperature environment; therefore, the initiation of SCC is not a credible 

aging effect. In its response to RAI B.1.22 1, Part (2)(b), the applicant stated that the 

recommendations for high strength bolts stated in the “preventive actions” program element of 

GALL Report AMP XI.S3 will be implemented through an enhancement in LRA Section B.1.22. 

The applicant also stated that the recommendations in GALL Report AMP XI.S3 “parameters 

monitored or inspected” program element regarding monitoring for cracking of high strength 

bolts susceptible to SCC through volumetric inspection do not apply to Fermi 2 because the 

high strength bolts at Fermi 2 are not in a corrosive environment and, therefore, are not 

susceptible to SCC. 

The staff finds the applicant response to RAI B.1.22-1, Part (1), acceptable because the 

applicant completed a review of applicable drawings and specifications regarding ASME Code 

Section XI Class 1, 2, 3 component supports and clarified that there are high strength structural 

bolts (actual measured yield strength greater than or equal to 150 ksi) in sizes greater than 

1 inch in diameter within the scope of the Inservice Inspection – IWF Program. The staff finds 

the applicant response to RAI B.1.22-1, Part (2)(a), acceptable because the applicant clarified 

that the high strength bolts are exposed to a dry, noncorrosive, and inert environment. The staff 

needed additional clarification of the response to RAI Part (2)(b). Although the applicant states 

that it will implement the recommendations in the “preventive actions” program element to use 

bolting material with an actual yield strength less than 150 ksi, the applicant did not include this 

information in the LRA. In addition, the staff needed clarification regarding whether the 

applicant inspects the drywell bioshield annulus area so that it can verify that the environment is 

kept dry. Therefore, during a telephone conference call held on March 6, 2015, the staff asked 

the applicant for clarification on these concerns. During the call, the applicant stated that it 

would provide information on bolting selection in the LRA. The applicant also stated that the 

drywell bioshield annulus area is inspected every RFO. 

By letter dated April 17, 2015, the applicant submitted a supplemental response to 

RAI B.1.22-1, Part (2)(b). In its supplemental response, the applicant revised LRA 

Sections A.1.22 and B.1.22 and Table A.4 (Commitment No. 16) to include an enhancement to 

the Inservice Inspection – IWF Program to “revise plant procedures to include the preventive 

action of using bolting material that has an actual measured yield strength less than 150 ksi, 
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except in the case of like-for-like replacement of existing bolting material in the reactor pressure 

vessel skirt to ring girder bolted joint.” 

The staff reviewed the applicant’s response to RAI B.1.22-1, Part (2)(b), and noted that GALL 

Report AMP XI.S3 recommends that the industry recommendations delineated in 

EPRI NP-5769 be implemented in the Inservice Inspection – IWF Program for high strength 

structural bolting. The GALL Report and EPRI NP-5769 state that SCC is caused by an 

undesirable combination of susceptible material, significant stress, and an aggressive 

environment. The staff notes that an aggressive environment that can contribute to SCC is 

described as one consisting of a wet environment with high levels of dissolved oxygen and/or 

aggressive contaminants, such as chlorides and sulfates (e.g., MoS2). The GALL Report; 

EPRI NP-5769; and GL 91-17, “Generic Safety Issue 29, ‘Bolting Degradation or Failure in 

Nuclear Power Plants,’” dated October 17, 1991, also states that MoS2 is a potential contributor 

to SCC, especially when applied to high strength bolting steels and, therefore, should not be 

used. The staff notes that inert nitrogen is used to displace and maintain low levels of oxygen 

concentrations in the drywell atmosphere. The staff also notes that the applicant inspects the 

drywell bioshield annulus area every RFO. The staff confirmed, based on its review of Fermi 2’s 

2009 ISI Summary Report (ADAMS Accession No. ML092100486), that 100 percent of the 

support bolts are visually inspected (VT-3) every 10 years as required in accordance with 

Table IWF 2500-1 for Class 1 supports (supports other than piping supports). Therefore, the 

staff finds the applicant’s response to RAI B.1.22-1, Part (2)(b), acceptable for the following 

reasons: 

 The high strength structural bolts in the RPV skirt to ring girder bolted joint are not 

exposed to an aggressive environment (i.e., wet environment with high levels of oxygen 

concentration and/or use of MoS2 as a lubricant) conducive of SCC; therefore, this is an 

adequate justification to waive the GALL Report-recommended volumetric examinations 

to detect cracking due to SCC in high strength structural bolts. 

 The applicant revised the LRA to include an enhancement to follow GALL Report 

AMP XI.S3 recommendations in the “preventive actions” program element to only 

procure high strength structural bolts that have an actual measured yield strength that is 

less than 150 ksi when bolts are to be installed elsewhere than the RPV skirt to ring 

girder bolted joint. 

 The inspection of the drywell bioshield annulus area performed every RFO and the 

required ASME Code IWF visual (VT-3) inspection of 100 percent of the support bolts 

performed every 10 years provide reasonable assurance that the applicant will identify 

conditions that may be conducive of SCC and will take corrective actions before there is 

a loss of intended function. 

The staff’s concerns described in RAI B.1.22-1 are resolved. 

The staff also reviewed the portions of the “preventive actions,” “detection of aging effects,” 

“monitoring and trending,” and “acceptance criteria” program elements associated with 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.1.22 includes an enhancement to the “preventive actions” 

program element. In this enhancement, the applicant stated that plant procedures will be 

revised to include preventive actions, such as proper selection of bolting material, installation 

torque or tension, and the use of lubricants and sealants for high strength bolts, as 
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recommended in NUREG-1339, EPRI NP-5769, EPRI NP-5067, and EPRI TR-104213. The 

staff reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.S3 and finds it acceptable because, when it is implemented, it will make the program 

consistent with the recommendations in the GALL Report to use the guidelines in EPRI 

documents and NUREG-1339 for selection of material, installation of bolts, and use of lubricants 

to prevent or mitigate degradation or failure of bolting. 

Enhancement 2. LRA Section B.1.22 includes an enhancement to the “preventive actions,” 

program element. In this enhancement, the applicant stated that plant procedures will be 

revised to require that maintenance activities and replacement of structural bolting include 

appropriate preload and torque consistent with the recommendations in EPRI documents, 

ASTM standards, and American Institute of Steel Construction (AISC) specifications. Plant 

procedures will also be revised to include the preventive actions in Section 2 of the RCSC report 

“Specification for Structural Joints Using ASTM A325 or A490 Bolts” for the storage of 

ASTM A325 and A490 bolting. By letter dated April 17, 2015, the applicant revised this 

enhancement “to include the preventive action of using bolting material that has an actual 

measured yield strength less than 150 ksi, except in the case of like-for-like replacement of 

existing bolting material in the [RPV] skirt to ring girder bolted joint.” The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.S3 and finds 

it acceptable (1) because, when it is implemented it, will make the program consistent with the 

recommendations in the GALL Report to use the guidelines in referenced EPRI documents; 

ASTM standards; AISC specifications; and Section 2 of the RCSC report, as applicable, for the 

proper preload, tightening, and storage of structural bolting, and (2) because, as discussed 

above in the staff’s evaluation of RAI B.1.22-1, once every 10 years visual examinations of 

100 percent of the high strength bolts located in the RPV skirt to ring girder bolted joint are 

adequate to manage the applicable aging effects because these bolts are not exposed to an 

aggressive environment that may be conducive of SCC. 

Enhancement 3. LRA Section B.1.22 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that plant procedures will 

be revised to include detection of aging effects, such as loss of material of anchor bolts, loose or 

missing nuts and bolts, and cracking of concrete around anchor bolts. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S3 and 

finds it acceptable because, when it is implemented, it will make the program consistent with the 

recommendations in the GALL Report to monitor structural bolts for loss of material and loose or 

missing nuts and to monitor concrete around anchor bolts for cracking. 

Enhancement 4. LRA Section B.1.22 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that plant procedures will be 

revised to identify unacceptable conditions such as debris, dirt, or excessive wear that could 

prevent or restrict sliding of the sliding surfaces, as intended in the design basis of the support, 

and cracked or sheared bolts, including high strength bolts and anchors. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S3 and 

finds it acceptable because, when it is implemented, it will make the program consistent with the 

recommendations in the GALL Report to include in the acceptance criteria unacceptable 

conditions of supports that may result in a component not meeting its design basis. 

Enhancement 5. LRA Section B.1.22 as revised by letter dated April 27, 2014, includes an 

enhancement to the “monitoring and trending” program element. In this enhancement, the 

applicant stated that plant procedures will be revised to “include assessment of the impact on 

the inspection sample, in terms of sample size and representativeness, if components that are 
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part of the sample population are reworked.” The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.S3 and finds it acceptable because, 

when it is implemented, it will ensure that the IWF sample population is representative of the 

age-related degradation of the total population of supports and component supports within the 

scope of the Inservice Inspection – IWF Program. 

Based on its audit and review of the applicant’s response to RAI B.1.22-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.S3. In 

addition, the staff reviewed the enhancements associated with the “preventive actions,” 

“detection of aging effects,” “monitoring and trending,” and “acceptance criteria” program 

elements and finds that, when implemented, they will make the AMP adequate to manage the 

applicable aging effects. 

Operating Experience. LRA Section B.1.22 summarizes operating experience related to the 

Inservice Inspection – IWF Program. 

In 2010, the applicant inspected 34 supports consistent with its NDE program. The inspection 

identified a discrepancy in the gap between the pipe and the pipe support box of one pipe 

support. The applicant entered the issue into the corrective action program, and the issue was 

resolved. 

In 2012, the applicant inspected 40 supports. As a result of the inspection, only one corrective 

action report was written regarding rust and water at one of four torus earthquake ties. The 

applicant also inspected 19 main steam constant support hangers in the steam tunnel. The 

applicant stated that “although wear was observed, all supports were found acceptable based 

on evaluation.” The applicant performed a minor repair on one support. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. The staff also determined that the operating experience provided by the 

applicant is not sufficient to allow the staff to verify that the LRA AMP, as implemented by the 

applicant, is adequate to detect and manage the effects of aging. During its review, the staff 

identified operating experience for which it determined the need for additional clarification, which 

resulted in the issuance of RAIs, as discussed below. 

GALL Report AMP XI.S3 states that MoS2 should not be used as a lubricant due to its potential 

contribution to SCC, especially for high strength bolts (actual yield strength greater than or 

equal to 150 ksi). During its onsite audit, the staff reviewed the AMP basis documents and 

confirmed that the bolting procedures had been revised to prohibit the use of MoS2 as a 

lubricant for bolting; however, it was not clear whether MoS2 lubricants have been used at 

Fermi 2 before plant procedures were revised to prohibit their use. By letter dated 

December 19, 2014, the staff issued RAI B.1.2-3, requesting that the applicant clarify whether 

MoS2 lubricants have been used on any high strength closure bolts or any high strength 

structural bolts in sizes greater than 1 inch in nominal diameter within the scope of license 

renewal. The staff evaluation of the applicant response is documented in SER 

Section 3.0.3.2.1. Based on the applicant’s response to RAI B.1.2-3, the staff concluded that 

the applicant did not prescribe the use of MoS2 lubricants at Fermi 2; therefore, there is 
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reasonable assurance that the adverse degradation effects (e.g., SCC) in high strength bolts 

that can be caused by the use of MoS2 lubricants will not be present at Fermi 2. The staff’s 

concern in RAI B.1.2-3 is resolved. 

The GALL Report AMP XI.S3 “monitoring and trending” program element states that 

examinations of Class 1, 2, 3 and MC component supports and related hardware that reveal 

unacceptable conditions that exceed the acceptance criteria and that require corrective 

measures are extended to include additional examinations in accordance with ASME Code 

Section XI, Subsection IWF-2430. The ASME Code Section XI, Subsection IWF-2430, states 

that to the extent practical, the same supports selected for examination during the first 

inspection interval shall be examined during each successive inspection interval. The staff 

noted that there is recent industry operating experience in which degraded conditions were 

found during ASME Code Section XI, Subsection IWF-2430, examinations of Class 1, 2, 3 and 

MC component supports and related hardware and an engineering evaluation determined that 

the as-found component/hardware was acceptable as is, but the component/hardware was still 

reworked to the as-new condition. Because it was determined that the as-found condition did 

not affect the support’s capability to perform its design function or exceed the threshold of 

ASME Code Subsection IWF-3400 acceptance criteria, the licensee did not apply ASME Code 

Subsections IWF-2420 and IWF-2430 for successive or additional examinations. The staff is 

concern that if ASME Code Section XI, Subsection IWF, supports that are part of the inspection 

sample are reworked to as-new condition, they may no longer be representative of the other 

supports in the population; therefore, subsequent inspections of the same sample would not 

represent the age-related degradation of the rest of the population. The staff noted that the LRA 

and associated AMP basis documents provide no discussion of how this issue would be 

addressed or any indication on whether the IWF sample would be changed or expanded if a 

support within the original sample was reworked. By letter dated December 19, 2014, the staff 

issued RAI B.1.22-2 requesting that the applicant describe, when corrective actions are not 

required per the ASME Code Subsection IWF acceptance criteria but when a component in the 

IWF sample is reworked and no longer represents age-related degradation of the entire 

population, how the AMP will be effective in managing aging of similar/adjacent components 

that are not included in the IWF inspection sample. 

In its response dated January 20, 2015, the applicant stated that its IWF component support 

inspection is consistent with the sample percentages specified in the ASME Code Section XI 

and includes more than 250 supports being examined each 10-year interval. Procedures 

require that discrepancies be reported in the corrective action program and that a CARD should 

be made to initiate a work order for maintenance. The applicant stated that correction of some 

conditions over the life of the plant will not impair the ability of the Inservice Inspection – IWF 

Program to manage the effects of aging and that modifying the program to add new component 

locations when a condition has been addressed is not necessary because (1) the degradation 

will likely be caused by local environmental or operational conditions (e.g., vibration or 

humidity), (2) the program requirements for sample expansion or extent of condition will address 

the degradation, and (3) the IWF inspection sample size is “large enough that correction of 

some conditions will not prevent the program from adequately managing the effects of aging.” 

The staff reviewed the applicant response and notes that the basis for not considering 

modification of the program to add new components to the population sample is acceptable if, 

after rework of the component, the sample continues to represent all combinations of material, 

environments, operational conditions, and leading indicators of degradation of the population. 

The staff determined that consideration needs to be taken as to whether reworking of a sample 

component that meets the IWF acceptance may result in that component no longer representing 
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the degradation of the population. The staff noted that, after a component is reworked, the 

material, environment, and degradation conditions could result in the component no longer 

representing the degradation of the population independently of the sample size. The staff 

needed additional information because it was not clear whether, in the absence of the 

requirements of sample expansion or extent of condition when a reworked sample component 

meets the IWF acceptance criteria, the AMP will be effective in managing the aging effects of 

components that are similar/adjacent to the reworked component but that are not included in the 

IWF inspection sample. Therefore, by letter dated March 26, 2015, the staff issued followup 

RAI B.1.22-2a requesting that the applicant state how the Inservice Inspection – IWF Program 

will ensure that the inspection sample will adequately represent the age-related degradation of 

the IWF component population when components that are part of the sample are reworked and 

no longer represent the age-related degradation of the remaining population. 

In its response dated April 27, 2015, the applicant stated that “[t]he Inservice Inspection [–] IWF 

Program will be enhanced to include assessment of the impact on the inspection sample, in 

terms of sample size and representativeness, if components that are part of the sample 

population are re-worked.” The staff noted that, as part of its response, the applicant revised 

LRA Sections A.1.22 and B.1.22 and Table A.4 Commitment No. 16 to include this 

enhancement to the Inservice Inspection – IWF Program. 

The staff finds this response acceptable because the applicant’s enhancement to the Inservice 

Inspection – IWF to include an assessment on the representativeness of the inspection sample 

when a sample component is reworked provides reasonable assurance that the inspection 

sample will represent the age-related degradation of the total population of IWF supports and 

component supports. The staff’s concern described in RAIs B.1.22-2 and B.1.22-2a is resolved. 

Based on its audit and review of the application and review of the applicant’s responses to 

RAIs B.1.22-2 and B.1.22-2a, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience and that implementation of the program has 

resulted in the applicant taking corrective actions. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which GALL Report AMP XI.S3 

was evaluated. 

UFSAR Supplement. LRA Section A.1.22 provides the UFSAR supplement for the Inservice 

Inspection – IWF Program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to implement the enhancements 

to the program before September 20, 2024. The staff finds that the information in the UFSAR 

supplement, as amended by letter dated April 27, 2015, is an adequate summary description of 

the program. 

Conclusion. On the basis of its audit and review of the applicant’s Inservice Inspection – IWF 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation before the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 
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 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems 

Summary of Technical Information in the Application. LRA Section B.1.23 describes the 

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program as consistent, with enhancements, with GALL Report AMP XI.M23, 

“Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.” 

The LRA states that the existing program performs periodic inspections through plant 

procedures and PM and manages loss of material due to corrosion, loose bolting or rivets, and 

crane rail wear of cranes and hoists within the scope of 10 CFR 54.4. The LRA also states that 

visual examinations and functional testing on active crane components, not credited for 

managing relevant passive components, ensure that cranes and hoists are capable of 

maintaining their intended function through the period of extended operation. The LRA further 

states that the program evaluates the effectiveness of the maintenance monitoring program and 

the effects of usage on the reliability of the cranes and hoists. 

The LRA states that the scope of program includes structural bolting for the bridge, trolley, lifting 

devices, and rails in the rail system and includes cranes and hoists that meet the provisions of 

10 CFR 54.4 (a)(1) and (a)(2), as well as that of NUREG-0612, “Control of Heavy Loads at 

Nuclear Power Plants: Resolution of Technical Activity A-36.” The LRA also states that the 

program will be enhanced to implement the guidance provided in ASME Code Safety Standard 

B30.2, “Overhead and Gantry Cranes (Top Running Bridge, Single or Multiple Girder, Top 

Running Trolley Hoist),” dated 2005. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M23. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.1.23 includes an enhancement to the “scope of program” and 

“parameters monitored or inspected” program elements. In this enhancement, the applicant 

stated that it plans to revise plant procedures to specify the monitoring of (1) rails in the rail 

system for loss of material due to wear, (2) structural components of the bridge, trolley, and 

hoists for deformation, cracking, and loss of material due to corrosion, and (3) structural 

connections/bolting for loose or missing bolts, nuts, pins or rivets and any other conditions 

indicative of loss of bolting integrity. The “scope of program” program element of GALL Report 

AMP XI.M23 recommends that the program manages loss of material due to general corrosion 

of bridge rails, bridge, and trolley structural components; wear on the rails; and loss of preload 

of bolted connections for all relevant components for cranes within the scope of 10 CFR 54.4. 

The “parameters monitored or inspected” program element of GALL Report AMP XI.M23 

recommends the use of visual inspections to monitor surface conditions to ensure that loss of 

material is not occurring due to corrosion or wear and to monitor bolted connections for loose 

bolts, missing or loose nuts, and other conditions indicative of loss of preload. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M23 and finds it acceptable because, when it is implemented, it will align the 

“scope of program” program element with that of the GALL Report AMP to manage the effects 
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of aging for crane rails, bridge trolley, and hoists for loss of material due to general corrosion 

and wear, and bolts for loss of bolting integrity and preload. The enhancement will also make 

the “parameters monitored or inspected” program element consistent with the GALL Report 

AMP recommendation to monitor loss of material due to corrosion; wear; loose bolts and nuts; 

missing nuts, pins, and rivets; and other conditions indicative of loss of preload. In addition to 

the recommendations of the GALL Report, the program is further enhanced to monitor 

deformation and cracking of rail system structural components. The staff finds this acceptable 

because deformation is an aging mechanism that could lead to age-related degradation. The 

inclusion of these additional parameters monitored to the Inspection of Overhead Heavy Load 

and Light Load (Related to Refueling) Handling Systems Program provides additional 

assurance that age-related degradation would be identified before the loss of intended function 

of the included components. 

Enhancement 2. LRA Section B.1.23 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that it plans to “revise plant 

procedures to specify inspection frequency requirements in accordance with ASME B30.2 or 

other appropriate standard in the ASME B30 series.” GALL Report AMP XI.M23 recommends 

that visual inspections be conducted at a frequency consistent with ASME Code Safety 

Standard B30.2 or another appropriate ASME Code Safety Standard B30 series. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.M23 and finds it acceptable because, when it is implemented, the program will follow 

the inspection frequency recommendations in accordance with ASME Code Safety 

Standard B30.2, which provides guidance regarding timely periodic inspections of infrequently 

used cranes and their systems and components (e.g., rails, structural components, bolts, and 

nuts), or will use another applicable ASME Code Safety Standard B30, which is consistent with 

the recommendations in the GALL Report AMP. 

Enhancement 3. LRA Section B.1.23 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that it plans to revise plant 

procedures to require evaluations for significant loss of material due to wear of rails in the rail 

system and for any signs of loss of bolting integrity in accordance with ASME Code Safety 

Standard B30.2 or other appropriate safety standard in the ASME Code Safety Standard B30 

series. The staff noted that the GALL Report considers an aging mechanism to be significant 

when it could potentially result in aging effects that produce a loss of intended function of a 

component or structure if allowed to continue without mitigation. The staff also noted that GALL 

Report AMP XI.M23 recommends that any visual indication of loss of material due to corrosion 

or wear and loss of bolting preload should be evaluated in accordance with ASME Code Safety 

Standard B30.2 or other applicable ASME Code Safety Standard B30 series. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.M23 and finds it acceptable because, when it is implemented, it will ensure loss of 

material due to wear in crane rails and loss of preload in bolted connections are inspected and 

evaluated in accordance with applicable ASME Code Safety Standard B30 series and as 

recommended by Chapter 2-4, “Maintenance Training and Maintenance,” of the ASME Code 

Safety Standard B30.2, which states that any condition disclosed by the inspections performed 

in accordance with the standard that is determined to be a hazard to continued operation shall 

be corrected by adjustment, repair, or replacement before continuing the use of the crane. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M23. In addition, the staff reviewed the enhancements 

associated with the “scope of program,” “parameters monitored or inspected,” “detection of 
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aging effects,” and “acceptance criteria” program elements and finds that, when implemented; 

they will make the AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.23 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program. Objective evidence that the Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems Program will be effective in ensuring that intended 

functions are maintained consistent with the CLB during the period of extended operation is 

demonstrated by the two examples addressed in the LRA described below. 

In 2005, following the April 24, 2004, DTE Electric Monroe Power Plant hoist failure, a review of 

site cranes and hoists and maintenance procedures resulted in the enhancement of the 

procedures to address inspection provisions of codes and standards and vendor manuals and 

the inclusion of additional inspections. The LRA also states that a 2009 NRC inspection of 

cranes and heavy lifting, performed in accordance with the supplemental guidance to the NRC 

Inspection Procedure 71111.20, “Refueling and Other Outage Activities,” and as part of an 

operating experience smart sample program, did not yield any issues that needed to be 

addressed. In addition to the above two examples, the staff also noted, during its onsite audit 

operating experience review, a 2009 condition assessment of a bolted connection failure. The 

assessment indicated that a bolt failure occurred due to possible misalignment of turbine crane 

structural support members. Following an evaluation and identification of the root cause of the 

bolt failure to be fatigue, the bolt was replaced and repairs were performed eliminating any 

potential future crane loading fatigue issues. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M23 was evaluated. 

UFSAR Supplement. LRA Section A.1.23 provides the UFSAR supplement for the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems AMP. The staff 

reviewed this UFSAR supplement description of the program and noted that it is consistent with 

the recommended description in SRP-LR Table 3.0-1. The staff also noted that the applicant 

committed to implement the enhancements to the program before September 20, 2024. The 

staff finds that the information in the UFSAR supplement is an adequate summary description of 

the program. 

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the enhancements and confirmed 

that their implementation before the period of extended operation will make the AMP adequate 
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to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Masonry Wall 

Summary of Technical Information in the Application. LRA Section B.1.25 describes the 

existing Masonry Wall Program as consistent, with enhancements, with GALL Report 

AMP XI.S5, “Masonry Walls.” The LRA states that the program manages the aging effects for 

loss of material and cracking of masonry walls such that applicable components will continue to 

perform their intended functions in accordance with 10 CFR 54.4, and consistent with the CLB 

through the period of extended operation. Included components are masonry walls required by 

10 CFR 50.48, “Fire Protection”; radiation-shielding masonry walls; and masonry walls with the 

potential to affect safety-related components. The LRA also states that the program is based on 

the guidance provided in IE Bulletin 80-11, “Masonry Wall Design,” dated May 8, 1980, and 

NRC IN 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response 

to IE Bulletin 80-11,” dated December 31, 1987. 

The LRA states the Masonry Walls Program is implemented as part of the Structures Monitoring 

Program (LRA Section B.1.42), which proposes to manage these aging effects through periodic 

visual inspections of masonry walls at a frequency of at least once every 5 years, with 

provisions for more frequent inspections to ensure there is no loss of intended function between 

inspections. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S5. 

For the “acceptance criteria” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below. 

The “acceptance criteria” program element in GALL Report AMP XI.S5 recommends that further 

evaluation is conducted if the extent of cracking and loss of material is sufficient to impact the 

intended function of the wall or to invalidate its evaluation basis. However, during its audit, the 

staff found that the applicant’s Masonry Wall Program appears not to address the “invalidate its 

evaluation basis” aspect of the acceptance criteria because Section 4 of the applicant’s 

referenced MMR14 procedure, “Fermi 2 Maintenance Rule Conduct Manual – Structures 

Monitoring,” describes the qualitative criteria for evaluation of inspections results in terms of 

structural functionality only. By letter dated November, 25 2014, the staff issued RAI B.1.25-1 

requesting that the applicant clarify how the acceptance criteria for the inspection of masonry 

walls is consistent with that described in GALL Report AMP XI.S5 and provide either a 

supporting program enhancement if it is needed for consistency with the GALL Report or a 

description of the exception that includes the acceptance criteria and technical basis if different 

criteria from the GALL Report are being used. 

In its response dated December 26, 2014, the applicant stated that an enhancement to the 

Masonry Wall Program (LRA Sections A.1.25 and B.1.25) is added to the Structures Monitoring 

Program (LRA Sections A.1.42 and B.1.42) to address the “invalidate evaluation basis” aspect 
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and to clarify the “acceptance criteria” for the program described in LRA Section B.1.25, 

“Masonry Wall Program.” 

The staff finds the applicant’s response acceptable because the enhancement provided by the 

applicant to address the “invalidate evaluation basis” aspect ensures that observed conditions 

do not invalidate the evaluation basis or impact the intended function of the applicant’s masonry 

walls as recommended in the “acceptance criteria” program element of GALL Report 

AMP XI.S5. The staff’s evaluation of this enhancement is documented in SER 

Section 3.0.3.2.22, “Structures Monitoring.” The staff’s concern described in RAI B.1.25-1 is 

resolved. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff notes that the LRA Masonry Wall Program is 

implemented as part of the Structures Monitoring Program and that the LRA has integrated the 

enhancements for the Masonry Wall Program with the enhancements to the Structures 

Monitoring Program. Therefore, SER Section 3.0.3.2.22 documents the staff’s evaluation of 

LRA Section B.1.42 enhancements associated with masonry walls. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.S5. In addition, the staff reviewed the enhancements 

associated with the “scope of the program,” “parameters monitored or inspected,” “detection of 

aging effects,” and “acceptance criteria” program elements relevant to the Masonry Wall 

Program, as integrated with the enhancements of the Structures Monitoring Program, and finds 

that, when they are implemented, they will make the AMP adequate to manage the applicable 

aging effects. 

Operating Experience. LRA Section B.1.25 summarizes operating experience related to the 

Masonry Wall Program. A summary of the operating experience is given below: 

In 2007, Fermi 2 personnel identify loose grout in a block wall in the turbine building basement 

during maintenance rule structural walkdowns. According to the LRA, the condition identified 

was entered into Fermi 2’s corrective action program and the identified condition was repaired. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S5 was evaluated. 
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UFSAR Supplement. LRA Section A.1.25 provides the UFSAR supplement for the Masonry 

Wall Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also notes that the applicant committed to implement the enhancements to the program as part 

of the Structures Monitoring Program (LRA Section A.1.42) before September 20, 2024. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Masonry Wall Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Neutron-Absorbing Material Monitoring 

Summary of Technical Information in the Application. LRA Section B.1.27 describes the 

existing Neutron-Absorbing Material Monitoring Program as consistent, with enhancements, 

with GALL Report AMP XI.M40, “Monitoring of Neutron Absorbing Materials Other Than 

Boraflex.” The LRA states that the AMP detects degradation of the neutron-absorbing material 

(i.e., Boral) used in spent fuel pools. The AMP relies on periodic inspection, testing, and other 

monitoring activities to ensure that the required 5-percent subcriticality margin is maintained 

during the period of extended operation. The LRA states that the AMP monitors loss of material 

and changes in dimension, such as blisters, pits, and bulges that could result in a loss of 

neutron-absorbing capability. The LRA further states that the frequency of testing will be based 

on the condition of the neutron-absorbing material at a minimum of once every 10 years in the 

period of extended operation. 

In a letter dated September 24, 2015, the applicant provided supplemental information revising 

LRA Sections A.1.27 and B.1.27 to cover all neutron-absorbing material other than Boraflex 

(i.e., including, but not limited to, Boral) for the period of extended operation. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M40. 

The staff also reviewed the portions of the “detection of aging effects” and “monitoring and 

trending” program elements associated with enhancements to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

these enhancements follows. 

Enhancement 1. LRA Section B.1.27 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that, before the period of 

extended operation, it will revise the AMP procedures to establish an inspection frequency, 

justified with plant-specific operating experience, of at least once every 10 years based on the 
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condition of the neutron-absorbing material. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M40 and finds it acceptable because 

the GALL Report recommends establishing a frequency of inspection and testing, based on the 

condition of the neutron-absorbing material and determined and justified with plant-specific 

operating experience, not to exceed 10 years. The staff finds that when this enhancement is 

implemented it will make the AMP consistent with the recommendations of GALL Report 

AMP XI.M40. 

Enhancement 2. LRA Section B.1.27 includes an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that it will revise the AMP 

procedures to perform trending of coupon testing results to determine the rate of degradation. 

The LRA notes that this enhancement will ensure that the predicted boron-10 areal density will 

be sufficient to maintain the subcritical conditions required by TS until the next coupon test. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M40 and finds it acceptable because the GALL Report recommends comparing periodic 

inspections to baseline information or prior measurements and analysis for trend analysis. The 

staff finds that when this enhancement is implemented it will make the AMP consistent with the 

recommendations of GALL Report AMP XI.M40. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M40. In addition, the staff reviewed the enhancements 

associated with the “detection of aging effects” and “monitoring and trending” program elements 

and finds that, when implemented, they will make the AMP adequate to manage the applicable 

aging effects. 

Operating Experience. LRA Section B.1.27 summarizes operating experience related to the 

Neutron-Absorbing Material Monitoring Program. The applicant provided the following operating 

experience: 

In 2010, the LRA states that a Boral test coupon was found with numerous blisters (18 on the 

front side and 16 on the back side). The LRA states that one of the blisters on the front was 

2.1 inches in diameter. The applicant evaluated the blisters and determined that they did not 

affect the neutron-absorbing properties of the Boral. The applicant revised the inspection 

procedure to require a blister characterization if blisters are observed on a Boral coupon and to 

require an inspection of the associated Boral capsule for any deformation that would be caused 

by blisters. 

In 2010, the applicant made enhancements to its procedure regarding Boral coupon 

surveillance. The enhancements were based on operating experience presented at an EPRI 

Neutron Absorber User Group meeting. 

In 2013, the applicant performed a Boral coupon test at Pennsylvania State University. The 

applicant performed an NDE on coupon YD610122-1-7. The coupon was determined to be in 

good overall condition with several very small blisters. The applicant noted that all acceptance 

criteria were met. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 
3-146 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M40 was evaluated. 

UFSAR Supplement. LRA Section A.1.27 provides the UFSAR supplement for the 

Neutron-Absorbing Material Monitoring Program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. 

In a letter dated September 24, 2015, the applicant provided supplemental information revising 

LRA Section A.1.27 to cover all neutron-absorbing material other than Boraflex (i.e., including, 

but not limited to, Boral) for the period of extended operation. 

The staff also noted that the applicant committed to ongoing implementation of the existing 

Neutron-Absorbing Material Monitoring Program for managing the effects of aging for applicable 

components during the period of extended operation. 

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

September 24, 2015, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Neutron-Absorbing Material 

Monitoring Program, as amended by letter dated September 24, 2015, the staff determines that 

those program elements for which the applicant claimed consistency with the GALL Report are 

consistent. In addition, the staff reviewed the enhancements and confirmed that their 

implementation before the period of extended operation will make the AMP adequate to manage 

the applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Oil Analysis 

Summary of Technical Information in the Application. LRA Section B.1.32 describes the 

existing Oil Analysis Program as consistent, with enhancements, with GALL Report 

AMP XI.M39, “Lubricating Oil Analysis.” The LRA states that the AMP addresses loss of 

material for aluminum, carbon steel, copper-alloy, and stainless steel components exposed to 

lubricating oil by periodically sampling for water and particulates. The LRA also states that the 

AMP addresses fouling on heat exchanger tubes and fins exposed to lubricating oil. 

A one-time inspection activity will be performed to verify the effectiveness of the Oil Analysis 

Program. 
3-147 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M39. The staff also reviewed the 

portions of the “scope of program,” “parameters monitored or inspected,” “detection of aging 

effects,” and “acceptance criteria” program elements associated with enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.1.32 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that procedures will be revised to 

identify components within the scope of the program. The staff reviewed this enhancement 

against the corresponding program element in GALL Report AMP XI.M39 and finds it 

acceptable because, when it is implemented, it will be consistent with the guidance in the GALL 

Report AMP. 

Enhancement 2. LRA Section B.1.32 includes an enhancement to the “parameters monitored 

or inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the applicant stated that procedures will be revised to provide a formalized 

analysis technique for particulate counting. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M39 and finds it acceptable because, 

when it is implemented, it will be consistent with the guidance in the GALL Report AMP. 

Enhancement 3. LRA Section B.1.32 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that procedures will be 

revised to include the sampling and testing recommendations of equipment manufacturers or 

industry standards. The staff reviewed this enhancement against the corresponding program 

element in GALL Report AMP XI.M39 and finds it acceptable because, when it is implemented, 

it will be consistent with the guidance in the GALL Report AMP. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M39. In addition, the staff reviewed the enhancements 

associated with the “scope of program,” “parameters monitored or inspected,” “detection of 

aging effects,” and “acceptance criteria” program elements and finds that, when implemented, 

they will make the AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.32 summarizes operating experience related to the Oil 

Analysis Program. 

In 2004, an oil sample taken from the SLC pump gearbox for analysis, and the results indicated 

high severe wear index. Followup vibration readings were high. The pump was removed from 

service, and an investigation determined that there was a low oil level. The gearbox was 

inspected with no abnormalities noted. The gear box was cleaned out, new oil was added, and 

the pump was restored back to service. 

In 2007, the reactor core isolation cooling turbine was declared inoperable due to excessive 

water in the oil sample. The excessive water content was caused by leaking valve internals and 

inadequate draining during PM. Although the condition was not attributed to oil degradation due 

to aging, the program was enhanced to entail selection of a better sampling location. 
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The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M39 was evaluated. 

UFSAR Supplement. LRA Section A.1.32 provides the UFSAR supplement for the Oil Analysis 

Program. The staff reviewed this UFSAR supplement description of the program and noted that 

it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted 

that the applicant committed to implement the enhancements before the period of extended 

operation. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Oil Analysis Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. In addition, the staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Protective Coating Monitoring and Maintenance 

Summary of Technical Information in the Application. LRA Section B.1.36 describes the 

existing Protective Coating Monitoring and Maintenance Program as consistent, with 

enhancements, with GALL Report AMP XI.S8, “Protective Coating Monitoring and Maintenance 

Program.” The LRA states that the AMP monitors and maintains Service Level I coatings 

applied to carbon steel and concrete surfaces inside containment (e.g., steel containment 

vessel shell, structural steel, supports, penetrations, and concrete walls and floors). The LRA 

states that the AMP proposes to assess coating conditions through visual inspections by 

identifying degraded or damaged coatings and by providing a means for repair of identified 

problem areas. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S8. 

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements associated with enhancements to determine whether the program will be 
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adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows. 

Enhancement 1. LRA Section B.1.36 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that it will revise plant procedures 

to include Service Level I coating applied to steel and concrete surfaces of the steel 

containment vessel. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S8 and finds it acceptable because the GALL Report 

recommends including all accessible Service Level I coating applied to steel and concrete 

surfaces inside containment as part of the scope for this AMP. The staff finds that when this 

enhancement is implemented it, will make the AMP consistent with the recommendations of 

GALL Report AMP XI.S8. 

Enhancement 2. LRA Section B.1.36 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement, the applicant stated that it will revise plant 

procedures to include information and instructions for monitoring Service Level I coating 

systems to be used for the inspection of coatings in accordance with guidelines identified in 

ASTM Standard D5163-08 (ASTM D5163-08), “Standard Guide for Establishing a Program for 

Condition Assessment of Coating Service Level I Coating Systems in Nuclear Power Plants,” 

dated November 1, 2008. In addition, the applicant stated that it will revise plant procedures to 

specify the parameters monitored or inspected in accordance with subparagraph 10.2 of 

ASTM D5163-08. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S8 and finds it acceptable because the GALL Report 

recommends using ASTM D5163-08 for guidance on identifying parameters that should be 

monitored and inspected. The staff finds that, when this enhancement is implemented, it will 

make the AMP consistent with the recommendations of GALL Report AMP XI.S8. 

Enhancement 3. LRA Section B.1.36 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that it will revise plant 

procedures to establish the inspection frequency in accordance with paragraph 6 of 

ASTM D5163-08. The applicant also stated that it will revise plant procedures to develop an 

inspection plan and to specify inspection methods to be used in accordance with 

subparagraph 10.1 of ASTM D5163-08. The applicant stated that it will revise plant procedures 

to specify that the nuclear coating specialist qualification recommendations and duties should 

be as defined in ASTM Standard D7108 (ASTM D7108), “Standard Guide for Establishing 

Qualifications for a Nuclear Coatings Specialist,” Revisions September 1, 20015, and 

November 15, 2012. The applicant further stated that qualification of inspection personnel who 

perform these inspections shall be as specified in ASTM Standard D4537 (ASTM D4537), 

“Standard Guide for Establishing Procedures to Qualify and Certify Personnel Performing 

Coating and Lining Work Inspection in Nuclear Facilities,” Revision March 1, 2012 The 

applicant stated that it will revise plant procedures to specify a protective-coatings program 

owner or an equivalent to a nuclear-coating specialist, as defined in ASTM D5163-08, and that 

will have general duties and responsibilities similar to those defined in Section 5 of 

ASTM D7108, Revision 2005. In addition, the applicant stated that it will revise plant 

procedures to specify that detection of aging effects will include visual inspections of coatings 

near sumps or screens associated with the emergency core cooling system. The applicant also 

stated that it will revise plant procedures to specify instruments and equipment needed for 

inspection as identified in subparagraph 10.5 of ASTM D5163-08. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S8 and 

finds it acceptable because the GALL Report recommends using ASTM D5163-08 for guidance 

on performing inspections. The staff reviewed ASTM D7108, Revisions 2005 and 2012, and 
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finds them acceptable because the standards provide guidance on developing a qualification 

program for a nuclear-coating specialist. The staff also reviewed ASTM D4537, Revision 2012, 

and finds it acceptable because the standard provides guidance on qualification and certification 

of personnel who perform inspection of coating and lining work. The staff finds that, when this 

enhancement is implemented, it will make the AMP consistent with the recommendations of 

GALL Report AMP XI.S8. 

Enhancement 4. LRA Section B.1.36 includes an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that it will revise plant procedures 

to specify that, upon the completion of a planned RFO, a coatings outage summary report will 

be prepared for the coating work performed in Service Level I areas during the outage. The 

applicant further stated that the summary report will prioritize repair areas as areas that must be 

repaired during the same outage or postponed to future outages, keeping the coatings under 

surveillance during the interim period. The applicant also stated that it will revise plant 

procedures to specify that the last two performance monitoring reports pertaining to the coating 

systems will be reviewed before the inspection or monitoring process. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S8 and 

finds it acceptable because the GALL Report recommends developing and maintaining 

inspection reports that prioritize repair areas and that identify other areas that should be under 

surveillance in interim periods. GALL Report AMP XI.S8 also recommends performing a 

pre-inspection review of the previous two monitoring reports. The staff finds that, when this 

enhancement is implemented, it will make the AMP consistent with the recommendations of 

GALL Report AMP XI.S8. 

Enhancement 5. LRA Section B.1.36 includes an enhancement to the “acceptance criteria” 

program element. In this enhancement, the applicant stated that it will revise plant procedures 

to describe the characterization, documentation, and testing of defective or deficient coating 

surface in accordance with subparagraphs 10.2.1 through 10.2.6, 10.3, and 10.4 of 

ASTM D5163-08. The applicant also stated that it will revise plant procedures to specify that 

the coatings outage summary report will be evaluated and approved by the protective coatings 

program owner. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S8 and finds it acceptable because the GALL Report 

recommends using ASTM D5163-08 for guidance on performing inspections. The staff finds 

that, when this enhancement is implemented, it will make the AMP consistent with the 

recommendations of GALL Report AMP XI.S8. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.S8. In addition, the staff reviewed the enhancements 

associated with the “scope of program,” “parameters monitored or inspected,” “detection of 

aging effects,” “monitoring and trending,” and “acceptance criteria” program elements and finds 

that, when implemented, they will make the AMP adequate to manage the applicable aging 

effects. 

Operating Experience. LRA Section B.1.36 summarizes operating experience related to the 

Protective Coating Monitoring and Maintenance AMP. The LRA states that the operating 

experience on monitoring of primary containment pressure boundary coatings has been 

obtained under ASME Code Section XI-IWE. 

The applicant provided the following operating experience. 
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In 2003, degraded coatings were identified during ASME Code CII IWE primary containment 

inspections. The LRA notes that several areas required simple recoating and other areas 

required cleaning of rust and recoating. Furthermore, the LRA states that in none of the cases 

had the primary containment boundary been degraded. 

In 2005, degraded coatings were identified during ASME Code CII IWE inspections of the torus 

shell coating. The areas identified involved the loss of torus protective coating; however, the 

torus shell material was not degraded. The applicant attributed the failure of the torus coating to 

inadequate curing of the initial coating. As a result, the applicant modified the ASME Code 

CII IWE program to require divers to inspect the torus coatings every other outage. 

In 2012, the applicant identified and repaired broken blisters, mechanical damage, and pinpoint 

rust in wetted areas of the torus. The applicant stated that all flaking paint was removed from 

the torus ring header, torus vacuum breaker valves, nitrogen supply lines, monorail rail, and 

torus walkway and handrail of the torus vapor region. In addition, the applicant removed flaking 

or cracked coating and reapplied protective coating to the torus shell. The total collective 

surface area of underwater coating repairs performed is estimated at 607 square inches. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S8 was evaluated. 

UFSAR Supplement. LRA Section A.1.36 provides the UFSAR supplement for the Protective 

Coating Monitoring and Maintenance AMP. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. 

The staff also noted that the applicant committed to ongoing implementation of the existing 

Protective Coating Monitoring and Maintenance AMP for managing the effects of aging for 

applicable components during the period of extended operation. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Protective Coating Monitoring 

and Maintenance AMP, the staff determines that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. In addition, the staff 

reviewed the enhancements and confirmed that their implementation before the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. The 
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staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

 Reactor Head Closure Studs 

Summary of Technical Information in the Application. LRA Section B.1.37 describes the 

existing Reactor Head Closure Studs Program as consistent, with exceptions and 

enhancements, with GALL Report AMP XI.M3, “Reactor Head Closure Stud Bolting.” The LRA 

states that the Reactor Head Closure Studs Program provides for ASME Code Section XI 

inspections of reactor head closure studs, associated nuts, bushings, flange threads, and 

washers for cracking and loss of material. The LRA also states that the program is based on 

the examination and inspection requirements specified in ASME Code Section XI and that it 

uses preventive measures described in NRC RG 1.65, “Materials and Inspections for Reactor 

Vessel Closure Studs,” dated April 2010. 

The LRA also includes exceptions to the program. Because the GALL Report recommends use 

of bolting material for closure studs that has actual measured yield strength less than 150 ksi, 

the applicant stated that it cannot verify actual measured yield strength of bolting material for 

closure studs and, therefore, assumed that it is higher than 150 ksi. 

In addition, the program includes enhancements to ensure that replacement studs are 

fabricated from material with actual measured yield strength less than 150 ksi. The program 

also includes an enhancement to specifically exclude the use of MoS2. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program 

with the corresponding program elements of GALL Report AMP XI.M3. 

The staff also reviewed the portions of the “preventive actions” and “corrective actions” program 

elements associated with an exception and two enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these exception and enhancements follows. 

Exception. LRA Section B.1.37 includes an exception to the “preventive actions” and “corrective 

actions” program elements. In this exception, the applicant stated that it cannot verify the actual 

measured yield strength of bolting material for closure studs and, therefore, assumed that the 

yield strength for the closure studs is higher than 150 ksi. The staff reviewed the applicant’s 

exception and justification for the adequacy of the AMP to manage SCC in the high strength 

material and finds it acceptable. The staff compared this exception against the corresponding 

program elements of GALL Report AMP XI.M3 and finds it acceptable because (a) the program 

includes ultrasonic examination of each closure stud during each inspection interval, which 

provides reasonable assurance that SCC in closure studs can be detected and adequately 

managed before loss of intended function and (b) the volumetric examinations of the closure 

studs have not detected any evidence of SCC. 

Enhancements 1 and 2. LRA Section B.1.37 includes two enhancements to the “preventive 

actions” and “corrective actions” program elements. In these enhancements, the applicant 

stated that it will revise the “preventive actions” and “corrective actions” program elements to 
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ensure that replacement studs are fabricated from bolting materials with actual measured yield 

strength less than 150 ksi. In addition, the applicant will revise the “preventive actions” program 

element to specifically include a statement in its program procedures, which excludes the use of 

MoS2 on reactor vessel closure studs. The staff reviewed these enhancements against the 

corresponding program elements in the GALL Report AMP and determined that these 

enhancements, when implemented, will make the AMP adequate to manage the applicable 

aging effects. 

Based on its audit and review of the applicant’s Reactor Head Closure Studs Program, the staff 

finds that the program elements 1 through 6, for which the applicant claimed consistency with 

the GALL Report, are consistent with the corresponding program elements of GALL Report 

AMP XI.M3. The staff also reviewed the exception associated with the “preventive actions” and 

“corrective actions” program elements and their justifications and finds the AMP, with the 

exception, is adequate to manage the applicable aging effects. In addition, the staff reviewed 

the enhancements associated with the “preventive actions” and “corrective actions” program 

elements and finds that, when implemented, they will make the AMP adequate to manage the 

applicable aging effects. 

Operating Experience. LRA Section B.1.37 summarizes operating experience related to the 

Reactor Head Closure Studs Program. The applicant stated that ultrasonic examinations 

performed on the closure studs and flange threads from 2006 to 2010 confirmed that there were 

no recordable indications. The applicant also stated that there has been no history of 

degradation and that there have been no deficiencies noted from past inspection activity for this 

program. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M3 was evaluated. 

UFSAR Supplement. LRA Section A.1.37 provides the UFSAR supplement for the Reactor 

Head Closure Studs Program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed to implement the enhancements 

to the program before the period of extended operation. 

Conclusion. On the basis of its audit and review of the applicant’s Reactor Head Closure Studs 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions 

and their justification and determines that the AMP, with the exceptions, is adequate to manage 

the applicable aging effects. In addition, the staff reviewed the enhancements and confirmed 

that their implementation before the period of extended operation will make the AMP adequate 
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to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Reactor Vessel Surveillance 

Summary of Technical Information in the Application. LRA Section B.1.38 describes the 

existing Reactor Vessel Surveillance Program as consistent, with an enhancement and an 

exception, with GALL Report AMP XI.M31, “Reactor Vessel Surveillance.” This program 

manages reduction of fracture toughness of reactor vessel beltline materials due to neutron 

irradiation embrittlement and monitors reactor vessel long-term operating conditions that could 

affect neutron irradiation embrittlement of the reactor vessel. The objective of the program is to 

provide sufficient material and dosimetry data to (a) monitor irradiation embrittlement at the end 

of the period of extended operation and (b) determine the need for operating restrictions on the 

inlet temperature, neutron spectrum, and neutron flux. The program includes all reactor vessel 

beltline materials and complies with the requirements of Appendix H to 10 CFR Part 50 for 

reactor vessel material surveillance. Fermi 2 participates in the BWRVIP ISP in accordance 

with BWRVIP-86, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan,” 

Revision 1-A, dated October 2012, as approved by the NRC. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M31. The staff also reviewed the 

portions of the “detection of aging effects” program element associated with an exception and 

the “monitoring and trending” program element associated with an enhancement in order to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of the program exception and enhancement follows below. 

In addition, the staff noted that this program provides material and neutron dosimetry data to be 

used in the reactor vessel neutron embrittlement TLAAs. The staff’s review of the applicant’s 

TLAAs for reactor vessel neutron fluence, ARTs, P-T limits, and USE are documented in SER 

Sections 4.2.1, 4.2.2, 4.2.3, and 4.2.4, respectively. 

Exception. LRA Section B.1.38 includes an exception to the “detection of aging effects” 

program element. In this exception, the applicant stated that the GALL Report recommends 

that the reactor vessel surveillance program shall have at least one capsule with projected 

neutron fluence equal to, or exceeding, the 60-year peak reactor vessel wall neutron fluence 

before the end of the period of extended operation. The exception also states that a capsule 

meeting this qualification is not expected to be obtained before the end of the period of 

extended operation. 

In its review of the exception, the staff noted that LRA Section B.1.38 indicates that the 

applicant participates in the BWRVIP ISP, which is described in BWRVIP-86, Revision 1-A. 

The staff also noted the following reference addresses technical information related to ISP 

surveillance materials for the applicant’s reactor vessel: 
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 Tables 4-5 and 4-6 of GE Report NEDO-33133, “Pressure-Temperature Curves for DTE 

Energy Fermi Unit 2,” Revision 0, dated February 2005 (ADAMS Accession 

No. ML050870587) 

In addition, the staff noted that the BWRVIP ISP includes a surveillance weld material that 

represents the applicant’s reactor vessel target welds (i.e., lower shell axial welds). In the 

BWRVIP ISP, a target weld or plate material is the specific vessel material to which the ISP test 

matrix assigns a representative surveillance material. The staff also noted that the ISP includes 

a surveillance plate material that represents the applicant’s vessel target plates (i.e., lower and 

lower intermediate shell plates). The staff further noted that each of these surveillance 

materials was irradiated or is being irradiated in one of the host reactor vessels, which are 

different from the applicant’s reactor vessel, as planned in the ISP. 

The staff noted that the BWRVIP ISP tested the surveillance weld material at neutron fluence 

levels greater than 1.43x1018 n/cm2 (E > 1 MeV), as described in the following references: 

 Table 5-1 of EPRI BWRVIP-111NP, “BWR Vessel and Internals Project: Testing and 

Evaluation of BWR Supplemental Surveillance Program Capsules E, F, and I,” 

Revision 1, dated August 2010 (ADAMS Accession No. ML080780267) 

 Table 5-2 of EPRI BWRVIP-87NP, “BWR Vessel and Internals Project: Testing and 

Evaluation of BWR Supplemental Surveillance Program Capsules D, G, and H,” 

Revision 1, dated September 2007 (ADAMS Accession No. ML080770344) 

In comparison, LRA Section 4.2.1 states that the applicant’s peak reactor vessel wall fluence for 

60 years of operation is 1.43x1018 n/cm2 (E > 1 MeV), which indicates that the neutron fluence 

levels of the tested surveillance weld material exceed the peak reactor vessel wall fluence for 

60 years of operation (52 EFPY). 

In its review, the staff also noted that the BWRVIP ISP has a plan to test the representative 

surveillance plate material for the applicant’s reactor vessel before the end of the period of 

extended operation at an estimated neutron fluence between one and two times the applicant’s 

peak reactor vessel wall fluence for 52 EFPY, consistent with GALL Report AMP XI.M31. 

As discussed above, the staff noted that the neutron fluences (E > 1 MeV) of the ISP 

surveillance weld and plate materials, which represent the applicant’s reactor vessel materials, 

range between one and two times the peak reactor vessel wall fluence for 60 years of operation. 

However, the program exception identified in the LRA indicates that the applicant’s program 

does not include a surveillance capsule that meets the fluence range specified in the GALL 

Report for the period of extended operation. Therefore, additional clarification was necessary to 

resolve this apparent inconsistency between the program exception and the ISP surveillance 

capsule withdrawal schedule for the applicant’s reactor vessel. 

By letter dated December 4, 2014, the staff issued RAI B.1.38-1 requesting that the applicant 

clarify whether its program includes a surveillance capsule that meets the neutron fluence range 

specified in the GALL Report for the period of extended operation. The staff also requested 

that, as part of the response, the applicant clarify whether the capsule withdrawal schedule and 

associated fluences of the ISP for its reactor vessel have been changed or updated in such a 

manner that a program exception needs to be identified. 

In its response dated January 5, 2015, the applicant stated that the intent of the exception was 

not to circumvent participation in a reactor vessel surveillance program as recommended by the 
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GALL Report. The applicant also stated that it identified the exception because a capsule with 

the representative surveillance materials is not physically located within the Fermi 2 reactor 

vessel. The applicant further stated that Fermi 2 License Amendment No. 152 approved the 

participation of the plant in the BWRVIP ISP. In addition, the applicant stated that, through the 

ISP, Fermi 2 representative surveillance materials with the appropriate peak fluences are tested 

in accordance with Appendix H to 10 CFR Part 50. The applicant also indicated that, because it 

maintains participation in the BWRVIP ISP consistent with the provisions of GALL Report 

AMP XI.M31, the LRA is revised to remove this exception. 

The staff finds the applicant’s response acceptable because (a) the applicant clarified that the 

representative surveillance materials with the appropriate peak neutron fluences are tested 

through the BWRVIP ISP in accordance with Appendix H to 10 CFR Part 50 and GALL Report 

AMP XI.M31, (b) the guidance of GALL Report AMP XI.M31 permits use of ISP capsules 

irradiated in other reactors, and (c) the applicant provided adequate revisions to the LRA to 

delete the program exception based on consistency with GALL Report AMP XI.M31. The staff’s 

concern described in RAI B.1.38-1 is resolved. 

Enhancement. LRA Section B.1.38 includes an enhancement to the “monitoring and trending” 

program element. In this enhancement, the applicant stated that it will revise Reactor Vessel 

Surveillance Program procedures to ensure that new fluence projections through the period of 

extended operation and the latest vessel beltline ART tables are provided to the BWRVIP 

before the period of extended operation. 

The staff noted that the applicant’s Reactor Vessel Surveillance Program is an existing program 

and that, upon receipt of a renewed license, the applicant’s program should continue to provide 

adequate fracture toughness and dosimetry data throughout the license renewal term. 

However, the staff noted that the LRA states that the applicant’s enhancement regarding data 

sharing of new fluence projections and associated ART tables will be implemented before the 

period of extended operation but not within a specific time period upon receipt of the renewed 

license. 

By letter dated December 4, 2014, the staff issued RAI B.1.38-2 requesting that the applicant 

provide adequate justification for why the program enhancement regarding data sharing of new 

fluence projections and associated ART tables will not be implemented within a specific time 

period upon receipt of renewed license. 

In its response dated January 5, 2015, the applicant stated that the Fermi 2 Reactor Vessel 

Surveillance Program has been integrated into the BWRVIP ISP, which follows the provisions of 

BWRVIP-86, Revision 1-A, and the latest revision to BWRVIP-135, “BWRVIP ISP Data Source 

Book and Plant Evaluations.” The applicant also stated that Item 10, “Licensee Responsibilities 

Regarding Information Exchange,” of Section 3 of Revision 2 to BWRVIP-135 states that all 

plants are responsible to notify the BWRVIP of any changes in fluence projections for RPV 

(inner diameter and 1/4T), fluence values for any previously withdrawn capsules (due to 

recalculated fluence), latest vessel beltline ART tables, and placement and location of all 

capsules. The applicant further stated that this guidance is already in place to ensure that the 

transmittal of new fluence projections and associated ART tables in support of license renewal 

are shared with the BWRVIP. 

In addition, the applicant stated that the requirements in BWRVIP-86 or BWRVIP-135 do not 

indicate a specific time period in which new fluence projections and ART tables must be 

provided to the BWRVIP. The applicant stated that the intent of the enhancement to ensure that 
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the identified information would be provided before the period extended operation is to formalize 

the need for information exchange, specifically for license renewal. The applicant also 

confirmed that Fermi 2 has had no previous issues in promptly submitting changes affecting the 

requested information to the BWRVIP. The applicant further stated that, for example, revised 

ART tables due to the Measurement Uncertainty Recapture/Thermal Power Optimization project 

implemented in early 2014 were submitted to the BWRVIP in March 2013 and January 2014. 

The applicant stated that no additional enhancement is necessary. 

During its review of the RAI response, the staff noted that Section 5.7, “Planning for ISP 

Changes,” of Revision 1 to BWRVIP-86 states the following: 

As time progresses, actual plant operating experience will provide more accurate 

data about each plant for predicting end-of-life vessel fluences and target 

capsule fluence values. This information will be factored into the ISP planning 

and, if necessary, adjustments will be made to the remaining capsule test matrix 

and withdrawal schedule in order to maintain an optimized program. Minor 

reassessments in the ISP test matrix will take into account plant-specific 

variations in scheduled withdrawal dates due to modifications in fuel cycles, or 

changes in target fluences caused by power uprates or variation in capacity 

factor. For example, target fluences in the original plan assume a nominal 

capacity factor of 80 percent for all BWR plants, and actual plant operation may 

vary from this assumed value. 

The staff noted that Revision 1 to BWRVIP-86 indicates that the BWRVIP ISP continues to 

consider updated reactor vessel fluence values in the ISP planning in order to maintain an 

optimized program. The staff also noted that, upon receipt of a renewed license, the new 

fluence projections and ARTs are incorporated into the applicant’s CLB. The staff further noted 

that this CLB information should be communicated with the BWRVIP in a timely manner to 

ensure the effectiveness of the ISP. By contrast, the staff noted that the applicant’s response 

did not provide sufficient justification for why its enhancement regarding the data sharing will be 

implemented before the period of extended operation but not within a specific time period upon 

receipt of a renewed license. In addition, it was not clear to the staff what the timeframe is for 

sharing fluence projections and associated ARTs with the BWRVIP when these values are 

revised. 

By letter dated February 11, 2015, the staff issued RAI B.1.38-2a requesting that the applicant 

provide sufficient justification for why its program enhancement regarding the data sharing of 

new fluence projections and associated ARTs will not be implemented within a specific time 

period upon receipt of a renewed license. The staff also requested that the applicant clarify the 

timeframe for sharing fluence projections and associated ARTs with the BWRVIP when these 

values are revised. 

In its response dated March 6, 2015, the applicant stated that, as discussed in the response to 

RAI B.1.38-2, BWRVIP guidelines do not define a specific time period for data sharing of new 

fluence projections and associated ARTs upon their acquisition by the utility. The applicant also 

stated that it will continue to follow the provisions of BWRVIP-135 and BWRVIP-86 for 

“Licensee Responsibilities Regarding Information Exchange.” The applicant further clarified that 

data relevant to license renewal will be provided to the BWRVIP in a manner consistent with 

previous Fermi 2 data submittals. In addition, the applicant stated that the program 

enhancement for this activity is deleted because Fermi 2 has had no issues in submitting the 

requested information to the BWRVIP as previously indicated in its response to RAI B.1.38-2. 
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In its review, the staff finds the applicant’s response acceptable because it clarified that the 

fluence and ART data relevant to license renewal will be provided to the BWRVIP in a manner 

consistent with the previous data submittals, which had no issues in promptly submitting 

changes affecting the requested information to the BWRVIP. The staff also finds that the 

deletion of the enhancement is acceptable because the applicant confirmed that it will continue 

to share relevant data with the BWRVIP in a manner consistent with the CLB and previous data 

submittals (such as prompt data sharing related to the 2014 implementation of the 

Measurement Uncertainty Recapture/Thermal Power Optimization project). The staff’s concern 

described in RAIs B.1.38-2 and B.1.38-2a is resolved. 

Based on its audit, and review of the applicant’s responses to RAIs B.1.38-1, B.1.38-2 and 

B.1.38-2a, the staff finds that program elements 1 through 6 for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M31. The staff also reviewed the exception associated with the “detection 

of aging effects” program element, and its justification, and finds that the AMP, with the 

exception, is adequate to manage the applicable aging effects. In addition, the staff reviewed 

the enhancement associated with the “monitoring and trending” program element and finds that, 

when implemented, it will make the AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.38 summarizes operating experience related to the 

applicant’s Reactor Vessel Surveillance Program. The applicant cited its participation in the 

BWRVIP ISP. The applicant also indicated that the best representative surveillance capsules 

available were chosen to represent its reactor vessel materials in the BWRVIP ISP and that 

results of the surveillance material test and analysis were used in the preparation of the P-T limit 

curves for Fermi 2. The applicant further indicated that this example of operating experience 

provides confidence that continued implementation of the Reactor Vessel Surveillance Program 

will effectively manage reduction of fracture toughness of reactor vessel beltline materials due to 

neutron irradiation embrittlement. The applicant stated that continued participation in the 

BWRVIP ISP provides reasonable assurance that the effects of aging will be managed such that 

components will continue to perform their intended functions consistent with the CLB through 

the period of extended operation. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M31 was evaluated. 

UFSAR Supplement. LRA Section A.1.38, as amended by letter dated February 11, 2015, 

provides the UFSAR supplement for the applicant’s Reactor Vessel Surveillance Program. The 

staff reviewed the UFSAR supplement description of the program against the recommended 

description for this type of program as described in SRP-LR Table 3.0-1. In its review of the 

applicant’s UFSAR supplement against SRP-LR Table 3.0-1, the staff finds that the UFSAR 
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supplement is an adequate summary description of the applicant’s Reactor Vessel Surveillance 

Program. 

Conclusion. On the basis of its audit and review of the applicant’s Reactor Vessel Surveillance 

Program and responses to RAIs B.1.38-1, B.1.38-2, and B.1.38-2a, the staff determines that the 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M31. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP, as amended by letter dated February 11, 2015, and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants 

Summary of Technical Information in the Application. LRA Section B.1.39, as revised by letter 

dated December 26, 2014, describes the existing RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program as consistent, with enhancements, 

with GALL Report AMP XI.S7, “RG 1.127, Inspection of Water-Control Structures Associated 

with Nuclear Power Plants.” The LRA states that Fermi 2 is not committed to the requirements 

of NRC RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power 

Plants,” dated March 1978; however, the program at Fermi 2 was developed based on guidance 

in Revision 1 to RG 1.127 and provides ISIs and surveillance for the Fermi 2 slopes, channels, 

and raw water-control structures associated with emergency cooling water systems or flood 

protection. The LRA also states that the scope of the Fermi 2 program includes water-control 

structures within the scope of license renewal, as delineated in 10 CFR 54.4, as well as 

structural steel, structural bolting, and miscellaneous steel associated with these water-control 

structures. The LRA further states that the program is implemented as part of the Structures 

Monitoring Program (LRA Section B.1.42) and proposes to manage age-related deterioration 

and degradation due to extreme environment conditions and the effects of natural phenomena 

through periodic visual inspections and maintenance so that aging effects can be prevented or 

mitigated in a timely manner. 

The LRA states inspections are conducted by, or under, the direction of qualified engineers. 

The LRA also states that the program provides guidance on engineering data compilation, 

inspection activities, technical evaluation, inspection frequency, and the content of inspection 

reports as required to minimize the possibility of overlooking significant features and that 

technical evaluations are performed if observed degradations have the potential to impact the 

intended function of water-control structures. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S7. For the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below. 

The “scope of program” program element in GALL Report AMP XI.S7 recommends including in 

the scope of the program structural steel and structural bolting associated with water-control 
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structures, steel or wood piles, and sheeting required for the stability of embankments and 

channel slopes, as well as miscellaneous steel, such as sluice gates and trash racks. The 

applicant’s RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power 

Plants Program states that the program “performs periodic visual examinations to monitor the 

condition of water control structures and structural components, including...steel piles required 

for the stability of the shore barrier.” However, during its audit, the staff found that the applicant 

does not plan to perform visual inspections of the submerged steel piles at the shore barrier. By 

letter dated November 25, 2014, the staff issued RAI B.1.39-2 requesting that the applicant 

clarify whether the steel piles at the shore barrier will be managed for age-related degradation 

through visual inspections as described in the LRA and, if not, describe how the proposed AMP 

will adequately manage the effects of aging during the period of extended operation. 

In its response dated December 26, 2014, the applicant stated that the steel pile component of 

the shore barrier was conservatively included in the LRA as in scope and subject to an AMR. 

The applicant also stated that, based on further evaluation and on information presented in the 

applicant’s response dated December 26, 2014, the steel sheet pile component of the Fermi 2 

shore barrier does not perform the intended functions of “Flood Barrier” and “Support for 

Criterion (a)(1) Equipment” previously specified in the LRA. To support this conclusion, the 

applicant also stated that the shore barrier construction specification, as referenced in 

Figure 2.4-22, “Shore Barrier Design,” of the UFSAR indicates that the steel sheet piling was 

installed solely to facilitate shore barrier construction activities and is procured as a QA Level III 

component. The applicant revised the LRA to indicate that the steel sheet pile component of 

the shore barrier is not within the scope of license renewal. 

The staff finds the applicant’s response acceptable because the staff’s review of the referenced 

Figure 2.4-22 and Subsection 2.4.5, “Probable Maximum Surge and Seiche Flooding,” and 

Subsection 3.4.4, “Flood Protection,” of the UFSAR verify that the steel sheet piling is not 

credited as part of the shore barrier function (i.e., required for stability) and confirm that the steel 

sheet piling was installed as a QA Level III component. The information provided in the 

applicant’s response demonstrates that the steel sheet pile component of the shore barrier does 

not perform an intended function within the scope of license renewal as described in 

10 CFR 54.4 and, therefore, is not subject to an AMR. The staff’s concern described in 

RAI B.1.39-2 is resolved. 

The “detection of aging effects” program element in GALL Report AMP XI.S7 recommends 

periodic inspections to be performed at least once every 5 years with provision for increased 

inspection frequency if the extent of the degradation is such that the structure or component 

may not meet its design basis if allowed to continue uncorrected until the next normally 

scheduled inspection. However, during its audit, the staff found that the applicant’s RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program appears 

to lack a provision for increased inspection frequency of water-control structures as 

recommended in GALL Report AMP XI.S7. By letter dated November 25, 2014, the staff issued 

RAI B.1.39-1 requesting that the applicant state how the program is consistent with the GALL 

Report provision for identifying and addressing the need to increase inspection frequency or 

provide the technical justification for the exception to the GALL Report recommendation. 

In its response dated December 26, 2014, the applicant stated that the Structures Monitoring 

Program in LRA Section B.1.42, which implements the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program, already contains a provision for 

increased inspection frequency and trending of SCs in accordance with 10 CFR 50.65(a)(1). 

The applicant also stated that this existing provision is consistent with the GALL Report 
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recommendation for identifying and addressing the need to increase inspection frequency to 

adequately manage the effects of aging during the period of extended operation. The applicant 

further stated no additional enhancement was provided to the “detection of aging effects” 

program element in either LRA Section B.1.42 or LRA Section B.1.39 because this provision is 

in the existing Structures Monitoring Program. 

The staff finds the applicant’s response acceptable because the RG 1.127, Inspection of Water 

Control Structures Associated with Nuclear Power Plants Program is implemented as part of the 

planned enhancement of the existing Structures Monitoring Program, which has provisions for 

increased inspection frequency for those SCs in scope of the RG 1.127, “Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program,” when the extent of 

the degradation is such that the structure or component may not meet its design basis if allowed 

to continue uncorrected until the next normally scheduled inspection. This existing provision in 

the Structures Monitoring Program is consistent with the one described in the “detection of 

aging effects” program element of GALL Report AMP XI.S7. The staff’s concern described in 

RAI B.1.39-1 is resolved. 

The “detection of aging effects” program element in GALL Report XI.S7 provides several 

recommendations, depending on the plant’s specific groundwater/soil condition and/or raw 

water conditions in water-control structures, to address the detection of aging effects for 

inaccessible below-grade concrete structural elements. However, during its audit, the staff 

found that the applicant’s Structures Monitoring Program, which implements the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, 

proposes to manage the aging effects for inaccessible, below-grade concrete structural 

elements by following similar GALL Report recommendations applicable to plants with 

nonaggressive groundwater/soil and/or raw water for water-control structures, where the LRA 

AMP basis document indicates that the Fermi 2 concrete structures are subjected to an 

aggressive groundwater/soil environment. The staff also noted that in UFSAR Table 2.5-16, 

“Chemical Analysis of Ground Water,” the groundwater tested in Fermi 2 had sulfate content 

above the 1,500-ppm limit stated in the GALL Report for aggressive groundwater. By letter 

dated November 25, 2014, the staff issued RAI B.1.42-2, and the subsequent followup 

RAI B.1.42-2a, by letter dated February 20, 2015, requesting that the applicant clarify how the 

enhancement of this program element is consistent with that described in the GALL Report AMP 

for inaccessible areas exposed to aggressive groundwater/soil or provide the basis to justify the 

adequacy of the proposed exception to manage the aging effects in inaccessible areas if a 

different criteria other than that described in the GALL Report is being used. The staff notes 

that this RAI is common to the Structures Monitoring Program and the RG 1.127, Inspection of 

Water Control Structures Associated with Nuclear Power Plants Program. Therefore, SER 

Section 3.0.3.2.22 documents the staff’s review and evaluation of the applicant’s response to 

RAI B.1.42-2 and followup RAI B.1.42-2a. 

The “parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements in GALL Report AMP XI.S7 recommends that high strength (actual measured 

yield strength more than or equal to 150 ksi) structural bolts greater than 1 inch in diameter 

should be monitored for SCC and that high strength bolts degradations should be accepted by 

engineering evaluation or should be subject to corrective actions. However, during its audit, the 

staff noted that the applicant’s program and basis document does not provide sufficient 

information to determine whether high strength structural bolts (other than ASTM A325, F1852, 

and A490) are used in the structures and to explain how the AMP will manage SCC. By letter 

dated November 25, 2014, the staff issued RAI B.1.42-4 requesting that the applicant state 

whether high strength structural bolts greater than 1 inch in diameter are used in Fermi 2 
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structures and, if so, explain how the program elements are consistent with the GALL Report 

recommendations to monitor for SCC through supplemental volumetric or surface examinations. 

The staff noted that this RAI is common to the Structures Monitoring Program and the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program. Therefore, SER Section 3.0.3.2.22 documents the staff’s review and evaluation of the 

applicant’s response to RAI B.1.42-4. 

The staff also reviewed the portions of the “scope of program,” “preventive action,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff notes that the LRA RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program is 

implemented as part of the Structures Monitoring Program and that the LRA has integrated the 

enhancements for the RG-1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program with the enhancements to the Structures Monitoring Program. 

Therefore, SER Section 3.0.3.2.22 document the staff’s evaluation of LRA Section B.1.42 

enhancements associated with water-control structures. 

Based on its audit and review of the applicant’s responses to RAIs B.1.39-1, B.1.39-2, B.1.42-2, 

B.1.42-4, and followup RAI B.1.42-2a, the staff finds that program elements 1 through 6 for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S7. In addition, the staff reviewed 

the enhancements associated with the “scope of program,” “preventive action,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements, which are included with the enhancements to the Structures Monitoring Program, as 

documented in SER Section 3.0.3.2.22, and finds that, when implemented, they will make the 

AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.39 summarizes operating experience related to the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program. A summary of the operating experience is given below. 

Between December 2007 and January 2008, the Fermi 2 Structures Monitoring Program 

identified no significant findings during the inspection of the general service water pump house 

and RHR complex, but some low significant findings were identified. In response to the items 

identified as low significance, some panel bolts were tightened, and a nut and clamps were 

replaced. 

Between 2003 and 2012, Fermi 2 shore barrier surveillances identified no discrepancies with 

the structure, and, in some years, the inspections resulted in an action to remove the debris 

from the beach. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 
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Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.S7 was evaluated. 

UFSAR Supplement. LRA Section A.1.39 provides the UFSAR supplement for the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program. The 

staff reviewed this UFSAR supplement description of the program and noted that it is consistent 

with the recommended description in SRP-LR Table 3.0-1. The staff also noted that the 

applicant committed to implement the enhancements to the program before 

September 20, 2024, as part of the Structures Monitoring Program (LRA Section A.1.42). 

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

December 26, 2014, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program, the staff determines 

that those program elements for which the applicant claimed consistency with the GALL Report 

are consistent. In addition, the staff reviewed the enhancements and confirmed that their 

implementation before the period of extended operation will make the AMP adequate to manage 

the applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Service Water Integrity 

Summary of Technical Information in the Application. LRA Section B.1.41 describes the 

existing Service Water Integrity Program as consistent, with enhancements, with GALL Report 

AMP XI.M20, “Open-Cycle Cooling Water System.” The LRA states that the program manages 

loss of material and fouling as described in the applicant’s response to GL 89-13 for 

safety-related systems exposed to service water systems. The program includes surveillance 

and control techniques to manage the effects of biofouling, corrosion, erosion, and silting; tests 

of heat exchangers to verify heat transfer capability; and routine inspection and maintenance 

activities. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M20. For the “scope of program” 

program element, the staff identified the need for additional information, which resulted in the 

issuance of an RAI, as discussed below. 

The “scope of program” program element in GALL Report XI.M20 recommends that the 

program should address fouling due to microorganisms or macroorganisms. During its audit, 

the staff noted that previous PM activities identified plugging in the MDCT spray nozzles. 

However, LRA Table 3.3.2-3 indicates that loss of material is the only aging effect being 

managed for the flow control nozzles exposed to raw water in the service water system. By 

letter dated December 19, 2014, the staff issued RAI B.1.41-1 requesting that the applicant 
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justify how the intended function of the nozzles will be maintained without managing fouling for 

these components. The staff also asked the applicant to determine whether there were other 

activities associated with its response to GL 89-13 for managing aging effects that were similarly 

not included in the LRA. 

In its response dated January 28, 2015, the applicant stated that fouling is an aging effect 

requiring management for the MDCT spray nozzles and, therefore, revised LRA Table 3.3.2-3 to 

add an appropriate AMR item. The applicant stated that LRA Sections A.1.41 and B.1.41 

currently include fouling; therefore, neither section required changes. The applicant also 

provided a listing of other components with aging management activities that are performed in 

accordance with its GL 89-13 response and confirmed these components are currently included 

in either LRA Table 3.3.2-3 or LRA Table 3.5.2-2. The staff finds the applicant’s response 

acceptable because the revision to LRA Table 3.3.2-3 now includes the degradation 

mechanisms, as prescribed by SRP-LR Section A.1.2.1, that have occurred for the flow control 

nozzles. In addition, the applicant confirmed that all other aging management activities 

associated with its GL 89-13 response were included in other items within the LRA. The staff’s 

concerns described in RAI B.1.41-1 are resolved. 

The staff also reviewed the portions of the “detection of aging effects” and “administrative 

controls” program elements associated with the enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.1.41 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant stated that it will revise the 

Service Water Integrity Program procedures to include inspections to determine whether loss of 

material due to erosion is occurring in the system. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMP XI.M20 and finds it acceptable 

because, when it is implemented, the program will include erosion as an aging mechanism, 

which is consistent with GL 89-13 and GALL Report AMP XI.M20. 

Enhancement 2. LRA Section B.1.41 includes an enhancement to the “administrative controls” 

program element. In this enhancement, the applicant stated that it will revise the Service Water 

Integrity Program procedures to stipulate that administrative controls are in accordance with 

Fermi 2’s QA program under Appendix B to 10 CFR Part 50. The staff reviewed this 

enhancement and finds it acceptable because, when it is implemented, the administrative 

controls will be consistent with the approach described in Appendix A to the GALL Report. 

Based on its audit and review of the applicant’s response to RAI B.1.41-1, the staff finds that 

program elements 1 through 6 for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.M20. 

In addition, the staff reviewed the enhancements associated with the “detection of aging effects” 

and “administrative controls” program elements and finds that, when implemented, they will 

make the AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.41 summarizes operating experience related to the 

Service Water Integrity Program. The LRA discusses inspections of the EDG service water 

piping in 2007 that identified heavy nodules, which prompted an ultrasonic thickness survey. 

Additional ultrasonic measurements over several years led to the replacement of the EDG 

service water piping in the EDG rooms in 2012. The LRA also discusses a fitness for service 

and life-cycle management plan for the Service Water Integrity Program that included the 
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development of a leak evolution and prediction model as a result of operating experience in 

2012. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience that would 

indicate that the applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and that 

implementation of the program has resulted in the applicant taking corrective actions. In 

addition, the staff finds that the conditions and operating experience at the plant are bounded by 

those for which GALL Report AMP XI.M20 was evaluated. 

UFSAR Supplement. LRA Section A.1.41 provides the UFSAR supplement for the Service 

Water Integrity Program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant included a summary of Commitment No. 33 for the 

enhancements to the program as part of the UFSAR supplement. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program 

Conclusion. On the basis of its audit and review of the applicant’s Service Water Integrity 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation before the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

 Structures Monitoring 

Summary of Technical Information in the Application. LRA Section B.1.42 describes the 

existing Structures Monitoring Program as consistent, with enhancements, with GALL Report 

AMP XI.S6, “Structures Monitoring.” The LRA states that the Structures Monitoring Program 

was developed based on guidance in RG 1.160, “Monitoring the Effectiveness of Maintenance 

at Nuclear Power Plants,” Revision 2, dated March 1997, and NUMARC 93-01, “Industry 

Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” Revision 2, 

to implement the requirements of 10 CFR 50.65, “Requirements for Monitoring the Effectiveness 

of Maintenance at Nuclear Power Plants.” The LRA states that the AMP includes the condition 

monitoring of masonry walls and water-control structures as described in the LRA Masonry Wall 

Program (LRA Section B.1.25) and in the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program (LRA Section B.1.39). SER Sections 3.0.3.2.14 

and 3.0.3.2.20, respectively, document the staff’s evaluations of these AMPs. 
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The LRA states that inspections are performed at least once every 5 years with provisions for 

more frequent inspections, when necessary, to ensure that there is no loss of intended functions 

between inspections. The LRA also states that the program will be enhanced to include 

provisions for periodic sampling and chemical analysis of groundwater chemistry on a frequency 

of at least once every 5 years. In addition, for surfaces within the scope of the program that are 

provided with protective coatings, the program will observe the condition of the paint or coating 

to identify the absence of degradation of the underlying material. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.S6. For the “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below. 

The “preventive actions,” “parameters monitored or inspected,” and “detection of aging effects” 

program elements in GALL Report AMP XI.S6 recommend the use of preventive actions as 

discussed in Section 2 of the RCSC report for storage, lubricants, and the potential for SCC 

when structural bolting consisting of ASTM A325, ASTM F1852, and/or ASTM A490 bolts is 

used. GALL Report AMP XI.S6 also recommends monitoring for loss of material, loose or 

missing nuts, and cracking of concrete around the bolts for structural bolting. During its audit, 

the staff found that the applicant’s Structures Monitoring Program basis document addresses 

ASTM A325 and ASTM A490 bolting. However, the document does not state whether 

ASTM F1852 twist-off-type bolting is used for structural components and whether this bolting 

would be inspected within the scope of the Structures Monitoring Program. Therefore, by letter 

dated November 25, 2014, the staff issued RAI B.1.42 1 requesting that the applicant state 

whether ASTM F1852 structural bolting is used in Fermi 2 structures, whether the bolt type is 

within the scope of license renewal, and whether it is subject to aging management to explain 

how the effects of aging will be adequately managed for the period of extended operation. 

In its response dated December 26, 2014, the applicant stated that Fermi 2 does not use 

ASTM F1852 structural bolting as verified through the review of site structural steel 

specifications, site bolting and torqueing procedures, and consultations with plant personnel and 

through the review of site-specific systems related to documents search, materials 

management, and nuclear inventory. Therefore, the Structures Monitoring Program does not 

include ASTM F1852 structural bolting. The staff finds the applicant’s response acceptable 

because the applicant confirmed that ASTM F1852 structural bolting is not used at the site and, 

therefore, is not included in the program. The staff’s concern described in RAI B.1.42-1 is 

resolved. 

The “detection of aging effects” program element in GALL Report AMPs XI.S6 and XI.S7 

provides several recommendations, depending on the plant’s specific groundwater/soil condition 

(and/or raw water conditions in water-control structures), to address the detection of aging 

effects for inaccessible below-grade concrete structural elements. The staff noted that the 

applicant’s Structures Monitoring Program proposes an enhancement to (a) inspect normally 

inaccessible areas as they become accessible due to plant activities and (b) inspect 

inaccessible areas in environments where observed conditions in accessible areas exposed to 

the same environment indicate that significant degradation is occurring. This enhancement is 

consistent with the GALL Report recommendations for plants with nonaggressive 

groundwater/soil and raw water; however, the LRA AMP basis document indicates that the 

Fermi 2 concrete structures are subjected to an aggressive groundwater/soil environment. 
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Further, the staff noted that, in UFSAR Table 2.5-16, “Chemical Analysis of Groundwater,” the 

Fermi 2 groundwater was tested and found to have sulfate content above the 1,500-ppm limit 

stated in the GALL Report for aggressive groundwater. For plants with aggressive 

groundwater/soil (with a pH of less than 5.5, chlorides of more than 500 ppm, or sulfates of 

more than 1,500 ppm) and/or with areas in which the concrete structural elements have 

experienced degradation, the GALL Report recommends implementing a plant-specific AMP 

that accounts for the extent of the degradation. From review of the AMP basis documents and 

proposed enhancement, it was not clear to the staff whether the applicant had considered the 

need for a plant-specific AMP to manage inaccessible concrete for sites with aggressive 

groundwater as recommended by the GALL Report. 

Therefore, by letter dated November 25, 2014, the staff issued RAI B.1.42 2 requesting that the 

applicant either (a) clarify how the enhancement of this program element is consistent with that 

described in the GALL Report AMP for inaccessible areas exposed to aggressive 

groundwater/soil or (b) provide the basis to justify the adequacy of the proposed exception to 

manage the aging effects in inaccessible areas. 

In its response dated December 26, 2014, the applicant stated that inaccessible areas will be 

managed as described in the LRA Section B.1.42 enhancement for the “detection of aging 

effects” program element as modified in its response to RAI 3.5.2.2.2.1-1, dated 

October 24, 2014. The applicant’s response to RAI 3.5.2.2.2.1-1 states that “[i]f normally 

inaccessible areas become accessible due to plant activities, an inspection of these areas shall 

be conducted. Additionally, inspections will be performed of areas in environments where 

observed conditions in accessible areas indicate that significant degradation may be occurring 

in the inaccessible areas.” 

The applicant also stated in its response that performing inspections of accessible concrete 

exposed to different environments, but is experiencing the same aging effect requiring 

management as the inaccessible concrete, provides an indication of the condition of 

inaccessible structures. A review of site operating experience and observations from recent site 

modifications where inaccessible below-grade concrete structural elements became accessible 

showed no instances of structural degradation indicative of significant degradation of the 

below-grade inaccessible concrete structures exposed to groundwater/soil. The applicant 

further stated that the Structures Monitoring Program, as modified in its response to 

RAI 3.5.2.2.2.1-1 serves as the plant-specific AMP and accounts for the extent of degradation 

experienced at the site. 

The staff reviewed the applicant’s response to RAI B.1.42-2 and found it unacceptable because 

the applicant did not provide the technical bases to support the claim that consistency with the 

GALL Report recommendations for plants that have nonaggressive groundwater is acceptable 

for structures at Fermi 2, which are exposed to aggressive groundwater. 

Further, it was not clear whether the applicant has evaluated or has plans to evaluate the effects 

of its aggressive groundwater on inaccessible concrete. Therefore, by letter dated 

February 20, 2015, the staff issued followup RAI B.1.42-2a requesting that the applicant provide 

the technical bases to justify the adequacy of the Structures Monitoring Program to ensure 

adequate management of degradation due to an aggressive groundwater environment in 

inaccessible areas of Fermi 2 below-grade concrete structures during the period of extended 

operation. 
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In its response dated March 19, 2015, the applicant stated that, as described in UFSAR 

Sections 2.5.1.2.7 and 2.5.4.11.2, the concrete mix design used for the construction of Fermi 2 

below-grade concrete already took into consideration the sulfate levels in the natural 

groundwater by using sulfate-resistant cement, Type II and Type V Portland cement, for all 

cement grout and below-grade concrete that will be in contact with groundwater. The applicant 

also stated that due to the sulfate-resistant cement used for below-grade concrete, the potential 

degradation due to aggressive groundwater environment would be minimal and the 

above-grade portion of the same structure subject to year-round weathering would experience 

higher levels of degradation than below-grade portion of the structures that are protected by the 

sulfate-resistant cement. The applicant further stated that the Fermi 2 reactor/auxiliary building 

contains a waterproof membrane for the below-grade concrete, which prevents direct contact 

with soil, subgrade, or backfill materials. In accordance with Table 4.2 in American Concrete 

Institute (ACI) 515.1R, “Guide to the Use of Waterproofing, Dampproofing, Protective, and 

Decorative Barrier Systems for Concrete,” dated 1985, providing a positive-side waterproofing 

barrier system will prevent water from entering the concrete. The applicant stated that, due to 

this protective barrier and the sulfate-resistant cement used, an aggressive groundwater 

environment is expected to play a negligible role in degradation of the below-grade concrete. In 

addition, the applicant stated that past inspections of the Fermi 2 structures under the 

Structures Monitoring Program and recent site projects that exposed below-grade exterior walls 

of the structures did not identify degradation attributed to aggressive chemical attack. 

The staff finds the applicant’s response acceptable because the technical justification provided 

clarifies that below-grade concrete structures were constructed using sulfate-resistant cement to 

prevent concrete chemical degradation from occurring and states that no degradation attributed 

to chemical attacks has been identified thus far in below-grade exterior walls from inspection of 

exposed concrete surfaces during recent site projects. The staff determined that the applicant 

has provided sufficient technical basis that the program enhancement to manage the aging 

effects for inaccessible areas of below-grade concrete structures accounts for the plant-specific 

design and construction and the extent of degradation experienced at the site as recommended 

by the GALL Report. The staff’s concern described in followup RAI B.1.42-2a is resolved. 

The “parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements in GALL Report AMP XI.S6 recommend the use of ACI 349.3R, “Evaluation 

of Existing Nuclear Safety-Related Concrete Structures,” dated 2002, as an acceptable basis for 

selecting parameters to be monitored or inspected, prescribing quantitative acceptance criteria 

for concrete, and establishing qualification requirements for I&E personnel. However, during its 

audit, the staff found that the applicant’s Structures Monitoring Program basis document 

references the 1996 edition of ACI 349.3R, whereas GALL Report AMP XI.S6 is based on, and 

references, the 2002 edition of ACI 349.3R. By letter dated November 25, 2014, the staff 

issued RAI B.1.42-3 requesting that the applicant describe how differences between the 

ACI 349.3R editions referenced in the program basis document and the GALL Report are being 

addressed to demonstrate consistency with the GALL Report recommendations or provide a 

technical justification for the exception to the GALL Report recommendations. 

In its response dated December 26, 2014, the applicant stated that the provisions of the 

2002 edition of ACI 349.3R was considered when assessing the consistency between GALL 

Report AMP XI.S6 and the Fermi 2 Structural Monitoring Program and that no exception was 

taken to the GALL Report recommendation. The applicant stated that it did not include 

reference to a specific edition of the ACI 349.3R so that the program would allow the use of 

latest version of ACI 349.3R during the development of implementing procedures. For 
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clarification, the applicant revised LRA Sections A.1.42, A.4, and B.1.42 to state the use of a 

“2002 or later” version of ACI 349.3R. 

Based on its review, the staff found that the applicant’s response to RAI B.1.42 3 clarifies that 

there were no inconsistencies between the ACI 349.3R editions referenced in the application 

because the applicant considered the provisions from the 2002 edition of ACI 349.3R during the 

LRA review process. However, based on the applicant’s revision to the LRA to indicate the use 

of a “2002 or later” edition/version, the staff was unclear as to whether the applicant plans to 

use, without adequate justification, a later edition/revision from that referenced in the GALL 

Report for ACI 349.3R. The staff could not determine whether the applicant would opt to use a 

different version that has a plant-specific NRC endorsement as allowed by the GALL Report 

guidance on page XI-3 for adopting a later edition/revision. Therefore, by letter dated 

February 20, 2015, the staff issued followup RAI B.1.42-3a requesting that the applicant identify 

the later version of ACI 349.3R that has been endorsed/approved by the NRC and that will be 

used by the Structures Monitoring Program and identify the plant-specific licensing action that 

contained the endorsement/approval if a plant-specific NRC endorsement/approval has been 

provided. 

In its response dated March 19, 2015, the applicant stated that the provision of the 2002 version 

of ACI 349.3R was considered during the review of the Fermi 2 Structures Monitoring Program. 

The applicant also stated that DTE does not rely on plant-specific NRC endorsement/approval 

of a later version of ACI 349.3R and that, to be consistent with the code version used to assess 

the consistency with the GALL Report, the applicant revised the enhancements noted in its 

responses to RAIs B.1.42-3 and 3.5.2.2.2.1-3 to reflect that only the 2002 version of ACI 349.3R 

was used to assess the AMP consistency with the GALL Report. 

The staff finds the applicant’s response acceptable because the applicant revised the program 

enhancements and the affected responses to reflect the use of the 2002 version of ACI 349.3R 

in the LRA AMP, which is consistent with that used in the GALL Report AMP. The staff’s 

concern described in followup RAI B.1.42-3a is resolved. 

The “preventive actions,” “parameters monitored or inspected,” and “detection of aging effects” 

program elements in GALL Report AMP XI.S6 recommend that high strength (actual measured 

yield strength greater than or equal to150 ksi) structural bolts in sizes greater than 1 inch in 

nominal diameter be monitored for SCC, that preventive actions be included in the program to 

prevent such cracking, and that visual inspections be supplemented with volumetric or surface 

examinations to detect cracking due to SCC. The staff noted that the SRP-LR states that high 

strength ASTM A325, F1852, and A490 bolts have not been shown to be prone to SCC and that 

potential for SCC need not be evaluated for these bolts. During its review of the applicant’s 

program and implementing documents, the staff did not have sufficient information to determine 

whether there are other high strength structural bolting types (other than ASTM A325, F1852, 

and A490) used in plant structures and whether these would be managed by the AMP for SCC. 

By letter dated November 25, 2014, the staff issued RAI B.1.42-4 requesting that the applicant 

state whether high strength structural bolts greater than 1 inch in diameter are used in Fermi 2 

structures and, if so, state how these program elements are consistent with the GALL Report 

recommendations to monitor SCC-prone bolt types through supplemental volumetric or surface 

examinations. 

In its response dated December 26, 2014, the applicant stated that high strength structural bolts 

greater than 1 inch in diameter that are within the scope of the Structures Monitoring Program 

and the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 
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Plants Program are not used in Fermi 2 structures, with the exception of the high strength bolts 

used in the drywell stabilizer assembly. The applicant also stated that the 1-3/8-inch high 

strength structural bolts used in the drywell stabilizer are type ASTM A325 bolting, which, 

according to the GALL Report, are not prone to SCC and, therefore, are excluded from the SCC 

supplemental monitoring. 

Through the review of Figure 3.8-25 of the UFSAR, the staff noted that the 1-3/8-inch high 

strength structural bolts used in the earthquake stabilizer truss system for the drywell provide a 

civil-structural function, not a pressure-retaining function; therefore, these bolts are not prone to 

SCC, consistent with guidance in the SRP-LR. The staff finds the applicant’s response 

acceptable because the applicant confirmed that there are no high strength structural bolts 

greater than 1 inch in diameter within the scope of the Structures Monitoring Program that 

require age management for SCC. The staff’s concern described in RAI B.1.42-4 is resolved. 

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff noted that the Masonry Wall 

Program and the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear 

Power Plants Program are implemented as part of the Structures Monitoring Program and that 

the LRA has included the enhancements for these programs within the enhancements to the 

Structures Monitoring Program. The staff’s evaluation of these enhancements follows. 

Enhancement 1. LRA Section B.1.42 includes an enhancement to the “scope of program” 

program element. In this enhancement (Commitment No. 34a), the applicant stated that plant 

procedures will be revised to include the following structures to the scope of the Structures 

Monitoring Program: 

 CST and condensate return tank foundations and retaining barrier 

 CTG-11 fuel oil storage tank foundation 

 independent spent fuel storage installation rail transfer pad 

 manholes, handholes, and ductbanks 

 shore barrier 

 transformers and switchyard support structures and foundations 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.S6 and finds it acceptable because, when it is implemented, it will address 

additional site structures within the scope of license renewal that are not covered by other 

structural AMPs. This enhancement makes the applicant’s “scope of program” program 

element consistent with the recommendations provided in GALL Report AMP XI.S6, will help 

monitor and assess the impact of age-related degradation on these structures, and will provide 

assurance that the aging degradation can be detected and quantified before there is a loss of 

intended functions. 

Enhancement 2. LRA Section B.1.42 includes an enhancement to the “scope of program” 

program element. In this enhancement (Commitment No. 34b), the applicant stated that plant 

procedures will be revised to include the following structures and structural components to the 

scope of the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Program: 
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 general service water pump house 

 RHR complex 

 shore barrier 

The staff noted that these structures will be inspected as part of the Structures Monitoring 

Program. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.S7 and finds it acceptable because, when it is implemented, it will include 

additional structures, structural components, component supports, and structural commodities 

related to water-control structures associated with emergency cooling water systems or flood 

protection of nuclear power plants that are within the scope of license renewal, which is 

consistent with the GALL Report provision for inspection of water-control structures. This 

enhancement makes the applicant’s “scope of program” program element consistent with the 

recommendations provided in GALL Report AMP XI.S7 in that it will help monitor and assess 

the impact of age-related degradation on these water-control structures and structural 

components and will provide assurance that the aging degradation can be detected and 

quantified before there is a loss of intended functions. 

Enhancement 3. LRA Section B.1.42 includes an enhancement to the “scope of program” 

program element. In this enhancement (Commitment No. 34c), the applicant stated that plant 

procedures will be revised to include masonry walls located in in-scope structures of the 

Masonry Wall Program (LRA Section B.1.25). The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S5 and finds it acceptable because, 

when it is implemented, it will include masonry walls identified as performing intended functions 

in accordance with 10 CFR 54.4. This enhancement is consistent with the GALL Report 

provision for including inspection of masonry walls and makes the applicant’s “scope of 

program” program element consistent with the recommendations provided in GALL Report 

AMP XI.S5, “Masonry Wall Program.” This enhancement will help monitor and assess the 

impact of age-related degradation on in-scope masonry walls and will provide assurance that 

the aging degradation can be detected and quantified before there is a loss of intended 

functions. 

Enhancement 4. LRA Section B.1.42 includes an enhancement to the “scope of program” 

program element. In this enhancement (Commitment No. 34d), the applicant stated that plant 

procedures will be revised to include a list of structural components and commodities within the 

scope of license renewal to the scope of the Structures Monitoring Program. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.S6 and 

finds it acceptable because, when it is implemented, it will include the structural components, 

component supports, and structural commodities that are in the scope of license renewal and 

that are not covered by other structural AMPs. This enhancement makes the applicant’s “scope 

of program” program element consistent with the recommendations provided in GALL Report 

AMP XI.S6. This enhancement will help monitor and assess the impact of age-related 

degradation on these structural components and commodities and will provide assurance that 

the aging degradation can be detected and addressed before there is a loss of intended 

functions. 

Enhancement 5. LRA Section B.1.42 includes an enhancement to the “scope of program” 

program element. In this enhancement (Commitment No. 34e), the applicant stated that plant 

procedures will be revised to include a periodic sampling and chemical analysis of groundwater 

to the scope of the Structures Monitoring Program. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.S6 and finds it acceptable 

because, when it is implemented, it will be consistent with the recommendations provided in 
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GALL Report AMP XI.S6 for including periodic sampling and testing of groundwater. This 

enhancement will help monitor and assess the impact of age-related degradation on 

below-grade structures due to exposure to aggressive groundwater and will provide assurance 

that the aging degradation can be detected and quantified before there is a loss of intended 

functions. 

Enhancement 6. LRA Section B.1.42 includes an enhancement to the “preventive actions” 

program element. In this enhancement (Commitment No. 34f), the applicant stated that plant 

procedures will be revised to specify the preventive actions delineated in NUREG-1339 and in 

EPRI NP-5769, EPRI NP-5067, and EPRI TR-104213 for proper selection of bolting material, 

installation torque or tension, and use of lubricant and sealant for high strength bolting. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report 

AMPs XI.S6 and XI.S7 and finds it acceptable because, when it is implemented, it will provide 

preventive actions as delineated in NUREG-1339 and the other industry standards, as 

recommended by the GALL Report, to ensure bolting integrity. 

Enhancement 7. LRA Section B.1.42 includes an enhancement to the “preventive actions” 

program element. In this enhancement (Commitment No. 34f), the applicant stated that plant 

procedures will be revised to include preventive actions from Section 2 of the RCSC report for 

storage of ASTM A325 and A490 bolting. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMPs XI.S6 and XI.S7 and finds it acceptable 

because, when it is implemented, it will include preventive actions from industry guidelines for 

storage of ASTM A325 and ASTM A490 structural bolts, as recommended by the GALL Report, 

to ensure bolting integrity. 

Enhancement 8. LRA Section B.1.42 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement (Commitment No. 34g), the applicant 

stated that plant procedures will be revised to base the inspection of concrete structures on 

quantitative criteria from industry codes, standards and guidelines, and considerations from 

industry and plant-specific operating experience. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMPs XI.S6 and XI.S7 and finds it 

acceptable because, when it is implemented, it will provide an acceptable basis for selection of 

parameters to be monitored or inspected for concrete as recommended by the GALL Report 

and will provide assurance that the aging degradation can be detected and quantified before 

there is a loss of intended function. 

Enhancement 9. LRA Section B.1.42 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement (Commitment No. 34g), the applicant 

stated that plant procedures will be revised to include the following parameters to be monitored 

for concrete SCs: loss of material, loss of bond, increase in porosity and permeability, loss of 

strength, and reduction in concrete anchor capacity due to local concrete degradation. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report AMPs 

XI.S6 and XI.S7 and finds it acceptable because, when it is implemented, it will expand the list 

of parameters monitored in the existing program to make it consistent with the GALL Report 

recommendations and will ensure that aging degradation leading to loss of intended functions 

will be detected and that the extent of degradation will be determined before there is a loss of 

intended function. 

Enhancement 10. LRA Section B.1.42 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement (Commitment No. 34g), the applicant 

stated that plant procedures will be revised to include chemical analysis to monitor pH, 
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chlorides, and sulfates. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMPs XI.S6 and XI.S7 and finds it acceptable because, 

when it is implemented, it will allow the applicant to assess the impact of the groundwater on 

below-grade concrete structures by monitoring the groundwater chemistry. This enhancement 

makes the applicant’s “parameters monitored or inspected” program element consistent with the 

recommendations provided in GALL Report AMPs XI.S6 and XI.S7. 

Enhancement 11. LRA Section B.1.42 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement (Commitment No. 34g), the applicant 

stated that plant procedures will be revised to monitor the gaps between the structural steel and 

masonry walls. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S5 and finds it acceptable because, when it is implemented, it 

will allow detection of deteriorations that could impact the intended function of the masonry walls 

or potentially could invalidate its evaluation basis. This enhancement makes the applicant’s 

“parameters monitored or inspected” program element consistent with the recommendations 

provided in GALL Report AMP XI.S5. 

Enhancement 12. LRA Section B.1.42 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement (Commitment No. 34h), the applicant 

stated that plant procedures will be revised to include the following parameters to be monitored 

for the associated components: 

 structural bolting and anchors/fastener for loss of material, loose or missing nuts and 

bolts, and cracking of concrete around the anchor bolts 

 elastomeric vibration isolators and structural sealant for cracking, loss of material, loss of 

sealing, and change in material properties (e.g., hardening) 

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMPs XI.S6 and XI.S7 and finds it acceptable because, when it is implemented, it will 

allow detection of deterioration that could impact the intended function of these structural 

components. This enhancement makes the applicant’s “parameters monitored or inspected” 

program element consistent with the recommendations provided in GALL Report AMPs XI.S6 

and XI.S7. 

Enhancement 13. LRA Section B.1.42 includes an enhancement to the “parameters monitored 

or inspected” program element. In this enhancement (Commitment No. 34i), the applicant 

stated that plant procedures will be revised to provide technical guidance for torque value 

requirements for specified bolting material subject to plant operating environments. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMPs XI.S6 and XI.S7 and finds it acceptable because, when it is implemented, it will allow 

detection of other conditions indicative of loss of preload that could impact the intended function 

of the component, consistent with the recommendations of the GALL Report AMPs. 

Enhancement 14. LRA Section B.1.42, as amended by the applicant’s response dated 

March 19, 2015 to followup RAI B.1.42-3a, includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

plant procedures will be revised to state that personnel involved in the I&E of structures and 

structural components, including masonry walls and water-control structures, meet the 

qualification guidance in ACI 349.3R, “Evaluation of Existing Nuclear Safety-Related Concrete 

Structures,” dated 2002. The staff reviewed this enhancement against the corresponding 
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program elements in GALL Report AMPs XI.S5, XI.S6, and XI.S7 and finds it acceptable 

because, when it is implemented, it will ensure that inspections and evaluations are performed 

by personnel that meet the qualification requirements of ACI 349.3R, as recommended by the 

GALL Report. 

Enhancement 15. LRA Section B.1.42 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

plant procedures will be revised to supplement visual inspection of elastomeric material with feel 

or touch to detect hardening if performance of the intended function is suspect. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.S6 and finds it acceptable because, when it is implemented, it will provide supplemental 

feel or touch inspection techniques, as recommended by the GALL Report, to allow the 

detection of additional aging effects (i.e., hardening) that could potentially impact the intended 

function of elastomeric materials and will provide assurance that the aging degradation can be 

detected before there is a loss of intended function. 

Enhancement 16. LRA Section B.1.42 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

plant procedures will be revised to state that structures and submerged structures will be 

inspected at least once every 5 years. In its response to RAI B.1.39-1 dated 

December 26, 2014, the applicant also stated that the Structures Monitoring Program (LRA 

Section B.1.42) contains provision for increased inspection frequency and trending of SCs in 

accordance with 10 CFR 50.65(a)(1). The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMPs XI.S6 and XI.S7 and finds it acceptable 

because, when it is implemented, it will ensure that structures and submerged structures will be 

monitored on a frequency not to exceed 5 years, with the provision for more frequent 

inspections to ensure no loss of intended function between inspections. This enhancement 

makes the applicant’s “detection of aging effects” program element consistent with the 

recommendations provided in GALL Report AMPs XI.S6 and XI.S7, considering the safety 

significance and condition of the structures. 

Enhancement 17. LRA Section B.1.42, as amended by the applicant’s response to 

RAI 3.5.2.2.2.1-1 dated October 24, 2014, includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

normally inaccessible areas will be inspected as they become accessible due to plant activities 

and where observed conditions in accessible areas indicate that significant degradation may be 

occurring in the inaccessible areas. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMPs XI.S6 and XI.S7 and finds the 

enhancement acceptable because, when it is implemented, it will be able to provide detection of 

aging effects for inaccessible concrete structural elements in a manner consistent with the 

GALL Report recommendations for plants with aggressive groundwater/soil. This enhancement 

takes into consideration the fact that Fermi 2 below-grade concrete structures were designed 

and constructed to resist elevated sulfate levels from natural groundwater and the fact that no 

degradation has been experienced at the site from past inspections under the Structures 

Monitoring Program for Fermi 2 structures and from recent site projects that have exposed 

below-grade exterior walls of structures. 

Enhancement 18. LRA Section B.1.42 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

plant procedures will be revised to state that sampling and chemical analysis of groundwater will 

be performed at least once every 5 years. The staff reviewed this enhancement against the 
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corresponding program elements in GALL Report AMPs XI.S6 and XI.S7 and finds it acceptable 

because, when it is implemented, it will include the sampling and testing of groundwater on a 

frequency not to exceed 5 years, which is consistent with the inspection frequency 

recommended by the GALL Report and which accounts for the extent of the degradation 

experienced at the site. 

Enhancement 19. LRA Section B.1.42 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

plant procedures will be revised to state that masonry walls will be inspected at least once every 

5 years, with provisions for more frequent inspections to ensure that there is no loss of intended 

function between inspections. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.S5 and finds it acceptable because when, it is 

implemented, it will be consistent with the recommendation of the GALL Report for performing 

visual examinations of masonry wall every 5 years, with provisions for more frequent 

inspections in areas where significant loss of material or cracking is observed to ensure that 

there is no loss of intended function between inspections. 

Enhancement 20. LRA Section B.1.42 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

plant procedures will be revised to state that inspections of water-control structures should be 

conducted under the direction of qualified personnel experienced in the investigation, design, 

construction, and operation of these types of facilities. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.S7, and finds it 

acceptable because, when it is implemented, it will be consistent with the qualification 

requirements in NRC RG 1.127 for the inspections of water-control structures associated with 

nuclear power plants, as recommended by the GALL Report. 

Enhancement 21. LRA Section B.1.42 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34j), the applicant stated that 

plant procedures will be revised to perform inspection of water-control structures on an interval 

not to exceed 5 years. The applicant also stated, in its response to RAI B.1.39-1 dated 

December 26, 2014, that the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program is implemented as part of the Structures Monitoring Program, 

which already contains provision for increased inspection frequency and trending of SCs in 

accordance with 10 CFR 50.65(a)(1). The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S7 and finds it acceptable because, 

when it is implemented, it will be consistent with the GALL Report recommendation for 

performing periodic inspections of water-control structures at least once every 5 years as 

described in NRC RG 1.127, with the provision for more frequent inspections to ensure no loss 

of intended function between inspections. 

Enhancement 22. LRA Section B.1.42 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement (Commitment No. 34, Item j), the applicant 

stated that plant procedures will be revised to perform special inspections of water-control 

structures immediately (within 30 days) after the occurrence of significant natural phenomena. 

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.S7 and finds it acceptable because, when it is implemented, it will be consistent 

with the special inspections requirements in NRC RG 1.127 for inspections of water-control 

structures associated with nuclear power plants, as recommended by the GALL Report. 
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Enhancement 23. LRA Section B.1.42, as amended by the applicant’s response dated 

March 19, 2015, to followup RAI B.1.42-3a, includes an enhancement to the “acceptance 

criteria” program element. In this enhancement (Commitment No. 34k), the applicant stated that 

plant procedures will be revised to prescribe quantitative acceptance criteria based on 

ACI 349.3R, 2002 version (ACI 349.3R-02); information provided in industry codes, standards, 

and guidelines, including ACI 318, “Building Code Requirements for Reinforced Concrete and 

Commentary,” dated 2002; ANSI/ASCE 11, “Guideline for Structural Condition Assessment of 

Existing Buildings,” dated 1999; and relevant AISC specifications; and industry and 

plant-specific operating experience. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMPs XI.S5, XI.S6, and XI.S7 and finds it 

acceptable because, when it is implemented, it will provide quantitative acceptance criteria from 

industry standards that allow for determining the adequacy of observed aging effects and will 

specify further evaluation criteria to determine the need of corrective actions based on industry 

codes, specifications, guidelines, standards, and/or operating experience, as recommended by 

the GALL Report. 

Enhancement 24. LRA Section B.1.42, as amended by the applicant’s response to 

RAI B.1.25-1 dated December 26, 2014, includes an enhancement to the “acceptance criteria” 

program element. In this enhancement (Commitment No. 34l), the applicant stated that plant 

procedures will be revised to include acceptance criteria for masonry wall inspections, which 

ensure that observed aging effects do not invalidate the evaluation basis of masonry walls or 

affect their intended function. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.S5 and finds it acceptable because, when it is 

implemented, it will ensure that observed aging effects on masonry walls do not invalidate the 

evaluation basis or impact the intended function of the walls, as recommended by the GALL 

Report. 

Enhancement 25. LRA Section B.1.42, as amended by the applicant’s response to 

RAI 3.5.2.2.2.1-3 dated January 26, 2015, includes an enhancement to the “parameters 

monitored or inspected” and “detection of aging effects” program elements. In this 

enhancement (Commitment No. 34m), the applicant stated that plant procedures will be revised 

to include testing and evaluation of water/mineral deposits where in-leakage is observed in 

concrete elements and to determine whether leaching of calcium hydroxide and carbonation is 

occurring, which could impact the intended function(s) of the concrete structures. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.S6 and finds it acceptable because, when it is implemented, it will ensure that observed 

water/mineral deposits from observed in-leakage on accessible concrete areas will be tested 

and evaluated to identify concrete degradation associated with leaching of calcium hydroxide 

and carbonation and will provide assurance that this aging degradation can be detected and 

managed before there is a loss of intended function(s) of the affected concrete structures. 

Enhancement 26. LRA Section B.1.42, as amended by the applicant’s responses to 

RAI 3.5.2.2.2.1-3 dated January 26, 2015, and RAI B.1.4-3a dated March 19, 2015, includes an 

enhancement to the “detection of aging effects” and “corrective actions” program elements. In 

this enhancement (Commitment No. 34n), the applicant stated that testing and evaluation will be 

performed before the period of extended operation, to confirm that previously identified 

conditions are not the result of leaching of calcium hydroxide and carbonation that could impact 

the intended function(s) of the concrete structures. The water/mineral deposit samples will be 

tested for mineral and iron content to assess the effect of the water in-leakage on the concrete 

elements involved, and the results will be used to determine corrective actions in accordance 

with the corrective action program. The staff reviewed this enhancement against the 
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corresponding program elements in GALL Report AMP XI.S6 and finds it acceptable because, 

when it is implemented, it will provide for testing and evaluation of previously identified 

conditions before the period of extended operation and will take corrective actions, as 

necessary, based on the results. 

Based on its audit and review of the applicant’s responses to RAIs B.1.42-1, B.1.42-2, B.1.42-3, 

B.1.42-4, followup RAI B.1.42-2a, followup RAI B.1.42-3a, RAI B.1.25-1, RAI B.1.39-1, 

RAI 3.5.2.2.2.1-1, and RAI 3.5.2.2.2.1-3, the staff finds that program elements 1 through 6 for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMPs XI.S5, XI.S6, and XI.S7. In addition, 

the staff also reviewed the enhancements associated with the “scope of program,” “preventive 

actions,” “parameters monitored or inspected,” “detection of aging effects,” “acceptance criteria,” 

and “corrective actions” program elements and finds that, when implemented, they will make the 

AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.42 summarizes operating experience related to the 

Structures Monitoring Program. The staff reviewed operating experience information in the 

application and during the audit to determine whether the applicable aging effects and industry 

and plant-specific operating experience were reviewed by the applicant. As discussed in the 

Audit Report, the staff conducted an independent search of the plant operating experience 

information to determine whether the applicant had adequately evaluated and incorporated 

operating experience related to this program. 

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, which resulted in the issuance of an RAI, as discussed below. 

The “operating experience” program element in GALL Report AMP XI.S6 recommends 

considering program enhancements based on observed and reported degradation from 

operating experience to ensure that the aging effects of SCs are adequately managed during 

the period of extended operation. However, during its audit, the staff noted that there was 

plant-specific operating experience involving concrete degradation in accessible areas that was 

characterized as leaching; however, the applicant’s Structures Monitoring Program did not 

discuss this operating experience or provide any evaluation of the impact of observed leaching 

of calcium hydroxide and carbonation in accessible areas on the intended function of the 

concrete structure. Therefore, by letter dated December 23, 2014, the staff issued 

RAI 3.5.2.2.2.1-3 requesting that the applicant provide a summary of operating experience 

regarding leaching of calcium hydroxide and carbonation in accessible areas of Groups 1–5 and 

7–9 structures. The staff also requested that the applicant state whether an evaluation has 

been performed to determine the impact on the intended function of the concrete structure and 

the results. If no evaluation of this condition has been performed for accessible areas of the 

affected area, the staff issued an RAI to determine whether the program would be adequate to 

manage this aging effect for inaccessible areas. Item 4, “Aging Management of Inaccessible 

Areas,” of SER Section 3.5.2.2.2 documents the staff’s review and evaluation of the applicant’s 

response to RAI 3.5.2.2.2.1-3. 

Based on its audit and review of the application and review of the applicant’s response to 

RAI 3.5.2.2.2.1-3, the staff finds that the applicant has appropriately evaluated plant-specific 

and industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which GALL Report AMP XI.S6 was 

evaluated. 
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UFSAR Supplement. LRA Section A.1.42, as amended by the applicant’s response dated 

March 19, 2015 to followup RAI B.1.42-3a, provides the UFSAR supplement for the Structures 

Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed to implement the enhancements to the Structures 

Monitoring Program before September 20, 2024. The staff finds that the information in the 

UFSAR supplement, as amended by letters dated October 24, 2014; December 26, 2014; 

January 26, 2015; and March 19, 2015, is an adequate summary description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Structures Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. The staff reviewed the enhancements and 

confirmed that their implementation before the period of extended operation will make the AMP 

adequate to manage the applicable aging effects. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

 Water Chemistry Control – Closed Treated Water Systems 

Summary of Technical Information in the Application. LRA Section B.1.44, as revised by letter 

dated March 19, 2015, describes the existing Water Chemistry Control – Closed Treated Water 

Systems Program as consistent, with an exception and enhancements, with GALL Report 

AMP XI.M21A, “Closed Treated Water Systems.” The LRA states that the AMP manages loss 

of material, cracking, and fouling in components exposed to a closed treated water environment. 

The LRA also states that the AMP manages these aging effects through monitoring and control 

of water chemistry, which includes the use of corrosion inhibitors, chemical testing, and visual 

inspections of internal surfaces. 

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements 1 through 6 of the applicant’s program to 

the corresponding program elements of GALL Report AMP XI.M21A. 

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements associated with the exception and enhancements to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

the exception and enhancements follows. 

Exception. LRA Section B.1.44, as revised by letter dated March 19, 2015, includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that the process sampling system sample cooler loops will be sampled and tested 

annually. The applicant also stated that the process sampling system sample cooler loops are 

both small closed-loop cooling systems (approximately 10 to 20 gal). The applicant further 

stated that the frequent water testing would remove a relatively large percentage of the loop 

water and would result in refilling and retreatment. The applicant also stated that the small 

volume of the system limits the amount of water that may leak, making it unlikely that leakage 

would affect nearby safety-related equipment. The staff noted that GALL Report AMP XI.M21A 

recommends that closed treated water systems be tested quarterly. The staff reviewed this 
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exception against the corresponding program element in GALL Report AMP XI.M21A. The staff 

finds the exception acceptable because it noted that, in a small closed treated water system, 

quarterly samples taken for testing purposes would remove a relatively large percentage of the 

treated water and result in unnecessary retreatment. In addition, the frequency of the needed 

makeup water would inadvertently result in difficulties establishing consistent chemical control 

and would offset the intended function of the periodic testing to maintain adequate chemistry 

control of the system. Furthermore, the staff noted that the relatively small volume available in 

the system also makes any possible leakage from this nonsafety-related system unlikely to 

adversely affect the nearby safety-related systems. 

Enhancement 1. LRA Section B.1.44, as revised by letter dated March 19, 2015, includes an 

enhancement to the “scope of program” program element. In this enhancement, the applicant 

stated that the program will be revised to include the process sampling system sample cooler 

loops and the CCHVAC chill water systems. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.M21A and finds it acceptable because 

the addition of these systems is consistent with the “scope of program” element of GALL Report 

AMP XI.M21A, which includes closed portions of HVAC systems. 

Enhancement 2. LRA Section B.1.44, as revised by letter dated March 19, 2015, includes an 

enhancement to the “preventive actions” program element. In this enhancement, the applicant 

stated that the program will be revised to provide chemical treatment, including a corrosion 

inhibitor for the process sampling system sample cooler loops and the CCHVAC chill water 

systems in accordance with industry guidelines and vendor recommendations. The staff 

reviewed this enhancement against the corresponding program element in GALL Report 

AMP XI.M21A and finds it acceptable because the GALL Report AMP XI.M21A “preventive 

actions” program element includes the use of corrosion inhibitors as a means of minimizing 

corrosion. 

Enhancement 3. LRA Section B.1.44 includes an enhancement to the “parameters monitored 

or inspected” and “acceptance criteria” program elements. In this enhancement, the applicant 

stated that the program will be revised to specify the water chemistry parameters to be 

monitored and their acceptable range of values in accordance with the closed cooling water 

chemistry guidance in EPRI TR-1007820, “Closed Cooling Water Chemistry Guidelines,” dated 

April 2004, industry guidance, or vendor recommendations. The staff reviewed these 

enhancements against the corresponding program elements in GALL Report AMP XI.M21A and 

finds it acceptable because the GALL Report AMP XI.M21A “parameters monitored and 

inspected” and “acceptance criteria” program elements specifically recommend that water 

chemistry concentrations be maintained within limits specified in selected industry documents 

and guidelines. 

Enhancement 4. LRA Section B.1.44 includes an enhancement to the “detection of aging 

effects” program element. In this enhancement, the applicant will revise the program to include 

inspections of accessible components whenever the boundary of a closed treated water system 

is opened and an inspection at least every 10 years of a representative sample of piping and 

components. The applicant stated that the sample will focus on components most likely to 

degrade and will comprise 20 percent of each material/environment/aging effect combination 

with a maximum of 25 components. The applicant also stated that the enhancement would 

require quarterly water sampling and analysis in accordance with industry guidelines. 

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M21A and finds it acceptable because, when it is implemented, the inclusion of 
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opportunistic and periodic representative sample inspections, along with water sampling and 

analysis, will make this program element consistent with the “detection of aging effects” program 

element of the GALL Report AMP. As identified in the Audit Report, although the program basis 

documentation did not address the inconsistency between the applicant’s current yearly water 

chemistry test frequency for the CCHVAC chill water system and the quarterly frequency 

specified in GALL Report AMP XI.M21, the staff concluded that the testing frequency difference 

would be resolved during implementation of the enhancement. 

Based on its audit, the staff finds that program elements 1 through 6 for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M21A. The staff also reviewed the exception associated with 

the “detection of aging effects” program element and its justification and finds that the AMP, with 

the exception, is adequate to manage the applicable aging effects. In addition, the staff 

reviewed the enhancements associated with “scope of program,” “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements and finds that, when implemented, they will make the AMP adequate to 

manage the applicable aging effects.

Operating Experience. LRA Section B.1.44 summarizes operating experience related to the 

Water Chemistry Control – Closed Treated Water Systems Program. The applicant described 

the identification in 2005 of an increase in the bacterial count for the jacket coolant of an EDG. 

The applicant entered the issue in the corrective action program and replaced the coolant to 

correct the problem. The applicant also described the identification in 2005, 2008, and 2009 of 

high dissolved oxygen content in the turbine building closed cooling water system due to a high 

makeup rate. The applicant identified and repaired the leakage sources through the corrective 

action program, and the dissolved oxygen levels returned to within specifications. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which GALL 

Report AMP XI.M21A was evaluated. 

UFSAR Supplement. LRA Section A.1.44, as revised by letter dated March 19, 2015, provides 

the UFSAR supplement for the Water Chemistry Control – Closed Treated Water Systems 

Program. The staff reviewed this UFSAR supplement description of the program and noted that 

it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted 

that the applicant committed to implement the enhancements to the program before 

September 20, 2024. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program. 
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Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry Control – 

Closed Treated Water Systems Program, the staff determines that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. In addition, the 

staff reviewed the exception and its justification and determined that the AMP, with the 

exception, is adequate to manage the applicable aging effects. In addition, the staff reviewed 

the enhancements and confirmed that their implementation before the period of extended 

operation will make the AMP adequate to manage the applicable aging effects. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

 Coating Integrity 

Summary of Technical Information in the Application. As amended by letters dated 

February 5, 2015, and June 9, 2015, LRA Section B.1.45 describes the new Coating Integrity 

Program as consistent, with exceptions, with GALL Report AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” The 

LRA states that the AMP addresses loss of coating integrity for coatings or linings installed on 

the internal surfaces of in-scope piping, piping components, heat exchangers, and tanks. The 

LRA also states that loss of coating integrity will be managed by periodic visual inspections by 

qualified individuals. 

Staff Evaluation. The staff issued LR-ISG-2013-01, “Aging Management of Loss of Coating or 

Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat 

Exchangers, and Tanks,” on November 14, 2014. By letter dated February 5, 2015, the 

applicant (1) provided the technical basis for why loss of coating integrity is not identified as an 

applicable AERM for certain internally coated in-scope components and (2) proposed revisions 

to its LRA to address LR-ISG-2013-01. 

In its response, the applicant provided a list of in-scope nonsafety-related components that are 

located remotely from safety-related components and components that perform an intended 

function, as described in 10 CFR 54.4(a)(3). The applicant stated that for these 

nonsafety-related components, there are no downstream detrimental effects due to loss of 

coating integrity on safety-related components and components that perform an intended 

function, as described in 10 CFR 54.4(a)(3). The applicant proposed that based on the above 

criteria, loss of coating integrity would not be cited as an AERM for the following components: 

condensate backwash tank, hydrogen seal oil vacuum tank, main generator hydrogen gas 

coolers, reactor recirculation pump seal test fixture, condensate filter demineralizer, and reactor 

water cleanup filter demineralizers. 

The staff finds the applicant’s proposal that loss of coating integrity is not an applicable AERM 

for the above components acceptable because the only components that are within the scope of 

GALL Report AMP XI.M42 are those for which loss of coating or lining integrity could prevent 

satisfactory accomplishment of any of the component’s or downstream component’s CLB 

intended functions identified under 10 CFR 54.4(a)(1), (a)(2), or (a)(3). In support of this 

statement, (a) the components are nonsafety related, (b) the applicant justified why leakage 

through the pressure boundary of the components would not impact a nearby safety-related 

component, and (c) the applicant’s description of the component and its location in the plant 
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provides reasonable assurance that flow blockage will not impact another component’s CLB 

intended functions identified under 10 CFR 54.4(a)(1) and (a)(3). 

As amended by letter dated June 9, 2015, the applicant removed the internally galvanized 

piping associated with its MDCT spray header assemblies from the scope of the Coating 

Integrity Program. The internally galvanized piping is located outside of the RHR complex pump 

rooms and is within the MDCT spray areas. The applicant stated that the spray header 

distributes service water in the cooling tower by a series of spray nozzles. The MDCTs consist 

of two cells in each of two divisions of cooling towers. Flow blockage for the spray nozzles is 

addressed in the Service Water Integrity Program, which includes periodic PM visual 

inspections of the spray pattern for each nozzle. At least one flow cell is tested during every 

RFO. SER Section 3.0.3.2.21 documents the staff’s evaluation of the use of the Service Water 

Integrity Program to monitor for flow blockage. The applicant also stated that a one-time 

inspection of the galvanized piping would be conducted in accordance with the One-Time 

Inspection Program. The inspection will consist of 25 1-ft piping segments. Inspection locations 

will be based on the risk of material loss. The acceptance criteria are (a) a less than 50-percent 

wall loss and (b) that, if more than 10 percent of the locations exceed the 50-percent wall loss, 

periodic inspections consisting of a representative sample of five locations will be conducted 

every 5 years in accordance with the Periodic Surveillance and Preventive Maintenance 

Program. The applicant revised LRA Sections A.1.33 and B.1.33 to include the requirement to 

conduct a one-time inspection of the piping wall thickness. 

UFSAR Table 9.2-7, “Ultimate Heat Sink Component Design Parameters,” states that the total 

head of (a) the RHR service water pump is 185 ft, (b) the emergency equipment service water 

pump is 145 ft, and (c) the diesel generator service water pump is 115 ft. The staff noted it is 

expected that a 50-percent wall loss will provide sufficient wall thickness to ensure structural 

integrity because the header pressure is low, resulting in lower pressure stresses. The staff 

finds the applicant’s change to remove the internally galvanized piping associated with the 

MDCT spray header assemblies from the scope of the Coating Integrity Program acceptable 

because (a) observing the spray pattern during flow tests conducted during every RFO interval 

can detect flow blockage due to galvanized coating debris and associated loss of material 

debris, (b) the resulting spray from a potential through-wall leak will not impact a safety-related 

function because the galvanized piping is only used in the MDCT spray areas, (c) the location 

selection criterion and quantity of inspections for the one-time inspection is consistent with the 

GALL Report recommendations in AMP XI.M32, (d) the criterion to convert to a periodic 

sampling program from a one-time program, 10 percent of the 25 inspections, is sufficiently low 

such that a trend will be clearly established, and (e) conducting five inspections every 5 years if 

the wall thickness acceptance criterion is not met can be sufficient to detect recurring loss of 

material. 

The staff also reviewed the portions of the “detection of aging effects” and “corrective actions” 

program elements associated with exceptions to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

exceptions follows. 

Exception 1. As amended by letter dated February 5, 2015, LRA Section B.1.45 includes an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that internally coated fire water system components will be inspected on an opportunistic 

versus periodic basis. The applicant stated that the only internally coated components in the 

fire water system are buried and consist of cement-lined piping and internally lined replacement 

isolation valves. The applicant also stated that it conducts routine surveillance tests that are 
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capable of demonstrating that flow blockage is not occurring. In addition, the fire water system 

is maintained pressurized, and a low-pressure alarm annunciates in the control room. 

The staff noted that as stated in the staff’s evaluation of Exception 3 associated with the Fire 

Water System Program, SER Section 3.0.3.2.10, the applicant conducts main header flow 

testing every 3 years, 64 hose stations are tested every 3 years to verify no flow blockage, and 

multiple main drain tests are conducted every 18 months. The fire water system testing is 

conducted in three different buildings. The staff reviewed this exception against the 

corresponding program element in GALL Report AMP XI.M42 and finds it acceptable because 

(a) there is reasonable assurance that, with the frequency, number, and multiple locations of 

flow tests that are conducted, flow blockage would be detected just as effectively as if internal 

visual inspections were being periodically conducted on a portion of the piping in accordance 

with Table 4a, “Inspection Intervals for Internal Coatings/Linings for Tanks, Piping, Piping 

Components, and Heat Exchangers,” of AMP XI.M42, and (b) the continuous monitoring and 

low-pressure alarm associated with the fire water system are effective means to detect potential 

through-wall flaws in the piping and piping components. 

Exception 2. As amended by letter dated February 5, 2015, LRA Section B.1.45 includes an 

exception to the “corrective actions” program element. In this exception, the applicant stated 

that the HPCI system lube oil reservoir internal coating will not be repaired or replaced. The 

applicant stated the Nuclear Maintenance Applications Center Terry Turbine Users Group 

recommends that paint defects should be removed and not recoated. 

The staff noted that Section 20.2.5, “Inspection and Maintenance,” of EPRI TR-1007459, “Terry 

Turbine Maintenance Guide, HPCI Application,” dated November 2002, states the following: 

“Remove any damaged preservative paint coating. Do not attempt to repaint the surfaces of the 

oil reservoir.” The staff also noted that the EPRI document was developed to provide 

maintenance practices that lead to improved turbine reliability. The staff reviewed this exception 

against the corresponding program element in GALL Report AMP XI.M42 and finds it 

acceptable, in part, because the staff’s review of EPRI TR-1007459 confirmed that it does not 

recommend recoating the HPCI turbine oil reservoir when degraded coatings are detected. 

However, the applicant’s exception states that coatings will not be replaced or repaired, 

whereas TR-1007459 states that damaged preservative coatings should be removed. By letter 

dated March 26, 2015, the staff issued RAI B.1.45-1 requesting that the applicant state what 

actions would be taken to mitigate potential further degradation of degraded coatings on the 

internal surfaces of the HPCI system lube oil reservoir. 

In its response dated April 27, 2015, the applicant revised LRA Section B.1.45, Exception 2, to 

state that “defective, damaged, or degraded preservative paint coating will be removed.” 

The staff finds the applicant’s response acceptable because it will remove degraded coatings 

and, therefore, ensure that flow blockage will not occur due to further degradation of degraded 

coatings. The staff’s concern described in RAI B.1.45-1 is resolved. The staff reviewed the 

revised exception against the corresponding program element in GALL Report AMP XI.M42 and 

finds it acceptable because of the reasons stated above. 

Exception 3. As amended by letters dated February 5, 2015, and June 9, 2015, LRA 

Section B.1.45 includes an exception to the “corrective actions” program element. In this 

exception the applicant stated that when delamination or peeling is detected during coating 

inspections and the coatings will be returned to service, physical testing will consist of lightly 

tapping the coating, light hand scraping, light power tool cleaning, or adhesion testing. The 
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applicant also stated that destructive adhesion testing will not be conducted. The applicant 

further stated that longer followup and re-inspection inspection intervals than that recommended 

in GALL Report AMP XI.M42 would be allowed as long as they were technically justified. 

The staff reviewed this exception against the corresponding program element in GALL Report 

AMP XI.M42 and does not find it acceptable. The “corrective actions” program element of 

AMP XI.M42 recommends that in areas in which adhesion testing is not possible due to physical 

constraints, alternative means of physical testing, such as those described by the applicant, 

would be acceptable. However, the applicant has not limited these alternative methods to 

instances in which adhesion testing is not possible. There are nondestructive adhesion testing 

techniques that can be conducted. Therefore, the applicant’s justification is not sufficient 

because it is based on the conclusion that coatings would be removed down to the base metal if 

adhesion testing is conducted. In addition, the applicant stated that it might extend inspection 

intervals beyond those recommended in AMP XI.M42, Table 4a, but did not provide a basis for 

this portion of the exception beyond stating that a future evaluation would be conducted. By 

letter dated March 26, 2015, the staff issued RAI B.1.45-2 requesting that the applicant 

(a) explain why nondestructive adhesion testing cannot be performed when coatings are 

returned to service with delamination, peeling, or blisters (see Exception 4), (b) explain how 

lightly tapping the coating, light hand scraping, and light power tool cleaning will be controlled 

(e.g., procedures and method qualification) to obtain consistent results if nondestructive 

adhesion testing will not be performed, and (c) state the basis and justification for any inspection 

intervals beyond those in the “corrective actions” program element of AMP XI.M42. 

In its response dated June 9, 2015, the applicant stated that it “will not perform adhesion testing 

for peeling and delamination where not possible due to physical constraints,” that “[a]dhesion 

testing [where physically possible] will be applied in the case of peeling and delamination that 

has progressed to the base metal,” and that: 

Adhesion testing will be applied in the case of peeling and delamination that has 

not progressed to the base metal unless both of the following conditions apply: 

(1) the peeling and delamination is occurring in a tank, pipe, or piping component 

with laminar or no flow conditions and (2) the scope of interrogation is expanded 

beyond the damaged area with large margins to ensure that all loose coatings 

have been removed. If the two conditions apply, then other methods of physical 

testing may be performed such as those discussed in the response to part b 

below. This exception will also apply to blisters not repaired. 

In Part b of its response, the applicant stated that, if nondestructive adhesion testing is not 

conducted, it will use light tapping, light hand scraping, or light power tool cleaning to determine 

the suitability of the coating. The light hand scraping or light power tool cleaning will conform to 

the provisions of applicable Society of Protective Coatings (SSPC) standards. The applicant 

provided examples of these standards including SSPC-SP 2, “Hand Tool Cleaning”; 

SSPC-SP 3, “Power Tool Cleaning”; SSPC-SP 11, “Power Tool Cleaning to Bare Metal”; and 

SSPC-SP WJ-1, 2, 3, and 4, “Water Jet Cleaning.” The applicant also stated that “these 

cleaning methods ‘remove all loose mill scale, loose rust, loose paint, and other loose 

detrimental foreign matter. It is not intended that adherent mill scale, rust, and paint be 

removed by this process. Mill scale, rust, and paint are considered adherent if they cannot be 

removed by lifting with a dull putty knife.’” The applicant further stated that given that there is no 

consensus standard document for tap testing, the training provided on this method in the EPRI 

Comprehensive Coatings Training Course will be credited to ensure that the technique is 

appropriately used. The applicant stated that the EPRI Comprehensive Coatings Training 
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Course will be incorporated into site training and qualification requirements for a coating 

specialist, as well as the tap testing guidance contained in the training course. The applicant 

revised Exception 4 to include these above alternative provisions to adhesion testing when 

coatings exhibiting blistering are returned to service without repair. The applicant revised LRA 

Sections A.1.45 and B.1.45 to incorporate the use of the SSPC standards and the EPRI 

Comprehensive Coatings Training Course into its CLB. 

The applicant further stated that subsequent inspection intervals will be in accordance with the 

“corrective actions” program element of AMP XI.M42. Repeat visual inspections of degraded 

coatings that do not meet acceptance criteria but that are returned to service will be performed 

every 2 years from the date that the degraded condition was detected until the degraded coating 

is repaired or replaced. The applicant revised Exception 3 to remove the option to conduct 

inspections at longer inspection intervals than those recommended in AMP XI.M42. 

The staff noted that the SSPC standards are industry-wide recognized standards for the surface 

preparation of noncoated and coated surfaces that provide sufficient direction to ensure that 

surfaces are properly prepared. The staff confirmed by attendance at the EPRI Comprehensive 

Coatings Training Course that tap testing is covered during the course contents. The staff finds 

the applicant’s response to RAI B.1.45-2 and the alternatives to adhesion testing described in 

Exceptions 3 and 4 acceptable because (a) a combination of the use of industry consensus 

documents and training will be used to ensure that consistent results can be obtained when 

testing in the vicinity of degraded coatings, (b) the cited example SSPC standards can be used 

to demonstrate that loose degraded coatings do not remain in the vicinity of coatings adhering 

to a surface, (c) performing alternatives to adhesion testing when it is not physically possible to 

conduct adhesion testing is consistent with AMP XI.M42, (d) in areas in which system flow rates 

are low (i.e., tanks and piping that experience laminar flow conditions), the applicant provides 

reasonable assurance that the use of light tapping, light hand scraping, or light power tool 

cleaning as an alternative to adhesion testing will be sufficient to detect coatings that are not 

adhering to the substrate, (e) the applicant included the use of the SSPC standards and the 

EPRI Comprehensive Coatings Training Course into its CLB, and (f) followup inspection 

intervals for coatings exhibiting peeling, delamination, and blistering are consistent with 

AMP XI.M42. The staff’s concern described in RAI B.1.45-2 is resolved. The staff reviewed the 

revised exception against the corresponding program element in GALL Report AMP XI.M42 and 

finds it acceptable for the reasons stated above. 

Exception 4. As amended by letters dated February 5, 2015, and June 9, 2015, LRA 

Section B.1.45 includes an exception to the “corrective actions” program element. In this 

exception, the applicant described alternatives to adhesion testing when coatings exhibiting 

blistering will be returned to service without repair. The alternatives are as described in 

Exception 3. The staff’s review of this exception is documented in the response to RAI B.1.45-2 

above. 

Based on its review of the applicant’s Coating Integrity Program and responses to 

RAIs B.1.45-1 and B.1.45-2, the staff finds that program elements 1 through 7 for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M42. The staff also reviewed the exceptions 

associated with the “detection of aging effects” and “corrective actions” program elements and 

their justifications and finds that the AMP, with the exceptions, is adequate to manage the 

applicable aging effects. 
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Operating Experience. LRA Section B.1.45 summarizes operating experience related to the 

Coatings Integrity Program. The applicant stated that the Coatings Integrity Program is a new 

program; however, routine inspections had identified coating deficiencies in the main condenser 

water box coatings, reactor water cleanup resin feed tank, seal oil vacuum tank, and upper main 

turbine lube oil cooler that the corrective action program addressed. 

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. The staff conducted an independent search of the 

plant operating experience information, using the following keywords: “blister,” “block,” “clog,” 

“coat,” “degrade,” “delam,” “foul,” “holiday,” “leak,” “lined,” “lining,” “peel,” and “spall” to 

determine whether the applicant had adequately evaluated and incorporated operating 

experience related to this program. During its review, the staff did not identify any operating 

experience that would indicate that the applicant should consider modifying its proposed 

program. 

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

GALL Report AMP XI.M42 was evaluated. 

UFSAR Supplement. As amended through letter dated June 9, 2015, LRA Section A.1.45 

provides the UFSAR supplement for the Coating Integrity Program. The staff reviewed this 

UFSAR supplement description of the program against the recommended description for this 

type of program as described in SRP-LR Table 3.0-1, as modified by LR-ISG-2013-01 and 

noted that the applicant stated the following: “Baseline coating/lining inspections will occur in 

the 10-year period before the period of extended operation. Subsequent inspections are based 

on an evaluation of the effect of a coating/lining failure on in-scope component intended 

functions, potential problems identified during prior inspections, and service life history.” The 

staff also noted that the AMP XI.M42 “detection of aging effects” program element makes 

virtually the same statement; however, it expands on the statement by stating the following: 

“[I]nspection intervals should not exceed those in Table 4a, ‘Inspection Intervals for Internal 

Coatings/Linings for Tanks, Piping, Piping Components, and Heat Exchangers.’” The staff 

further noted that based on the proposed wording in the UFSAR supplement, subsequent 

inspections may not occur on recommended intervals or may not occur at all. By letter dated 

March 26, 2015, the staff issued RAI B.1.45-3 requesting that the applicant state the criteria that 

will be used to determine the maximum duration between coating inspections. 

In its response dated April 27, 2015, the applicant revised LRA Section A.1.45 to state that 

subsequent inspection intervals should not exceed the inspection intervals in Table 4a. 

The staff finds the applicant’s response acceptable because the inspection intervals will be 

consistent with Table 4a in AMP XI.M42, which establishes a maximum inspection interval 

regardless of the results of prior inspections. Therefore, the UFSAR supplement for the Coating 

Integrity Program is consistent with the corresponding program description in SRP-LR 

Table 3.0-1, as modified by LR-ISG-2013-01. The staff’s concern described in RAI B.1.45-3 is 

resolved. 

The staff also noted that the applicant committed to implement the new Coating Integrity 

Program before September 20, 2024 or at the end of the last RFO before March 20, 2025; 
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however, initial inspections will be performed in the 10 years before March 30, 2025, for 

managing the effects of aging for applicable components. 

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program. 

Conclusion. On the basis of its audit and review of the applicant’s Coating Integrity Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determines that the AMP, with the exceptions, is adequate to manage the 

applicable aging effects. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d). 

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report 

In LRA Appendix B, the applicant identified the following AMPs as plant specific: 

 Periodic Surveillance and Preventive Maintenance 

For AMPs not consistent with or not addressed in the GALL Report, the staff performed a 

complete review to determine their adequacy to monitor or manage aging. The following 

sections document the staff’s review of these plant-specific AMPs. 

 Periodic Surveillance and Preventive Maintenance 

Summary of Technical Information in the Application. LRA Section B.1.35, as revised by letters 

dated July 30, 2014; January 15, 2015; and April 27, 2015, describes the existing Periodic 

Surveillance and Preventive Maintenance (PSPM) Program as a plant-specific program with 

enhancements that will be used to manage the aging of components that do not fall within the 

scope of other AMPs. The LRA states that the AMP addresses metallic, elastomeric, and glass 

components exposed to various environments to manage the effects of loss of material due to 

corrosion and wear, fouling, and loss of sealing. The LRA also states that the AMP proposes to 

manage these aging effects through periodic visual inspections, physical manipulation 

(for rubber gaskets and seals), or other NDE methods. The LRA further states that the AMP 

manages loss of material of carbon steel components exposed to raw water for which 

plant-specific operating experience includes recurring internal corrosion. 

Staff Evaluation. The staff reviewed program elements 1 through 6 of the applicant’s program 

against the acceptance criteria for the corresponding elements as stated in SRP-LR 

Section A.1.2.3. The staff’s review focused on how the applicant’s program manages aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 

each of these program elements follows. SER Section 3.0.4 documents the staff’s review of the 

“corrective actions,” “confirmation process,” and “administrative controls” program elements. 

Scope of Program. LRA Section B.1.35 states that the scope of the PSPM Program includes 

those specific SCs that are tabulated in the LRA program description. 
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The staff reviewed the applicant’s “scope of program” program element against the criteria in 

SRP-LR Section A.1.2.3.1, which states that the scope of the program should include the 

specific SCs, the aging of which the program manages. 

The staff noted that the program description of LRA Section B.1.35, as revised by letters dated 

July 30, 2014; January 15, 2015; and April 27, 2015, lists the system or structure and describes 

the components associated with each program activity. The staff also noted that the revisions 

to the PSPM Program procedures to include these activities were included as an enhancement 

to the program. The staff finds the applicant’s “scope of program” program element to be 

adequate because it includes the specific SCs that the program manages. 

Based on its review of the application, the staff confirmed that the “scope of program” program 

element satisfies the criteria defined in SRP-LR Section A.1.2.3.1; therefore, the staff finds it 

acceptable. 

Preventive Actions. LRA Section B.1.35 states that the PSPM Program is a condition 

monitoring program and does not include preventive actions. 

The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that, for condition or performance monitoring programs 

that do not rely on preventive actions, this information need not be provided. The staff finds the 

applicant’s “preventive actions” program element to be adequate because the PSPM Program is 

described as a condition monitoring program; therefore, preventive actions do not need to be 

described. 

Based on its review of the application, the staff confirmed that the “preventive actions” program 

element satisfies the criteria defined in SRP-LR Section A.1.2.3.2; therefore, the staff finds it 

acceptable. 

Parameters Monitored or Inspected. LRA Section B.1.35, as revised by letter dated 

July 30, 2014, states that the PSPM Program identifies degradation by inspecting surface 

condition, flexibility (for elastomeric components), and wall thickness (for components subject to 

recurring internal corrosion). 

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which states that, for a condition monitoring 

program, the parameters monitored or inspected should be capable of detecting the presence 

and extent of aging effects. 

The staff noted that the use of the parameter “surface condition” is consistent with the guidance 

for identifying loss of material in GALL Report AMP XI.M32, “One-Time Inspection,” and is 

similarly capable of identifying component fouling. The staff also noted that monitoring surface 

condition and flexibility of components is capable of identifying elastomer degradation that may 

affect the ability of a seal to perform its function. The staff further noted that measurements of 

wall thickness are capable of identifying the presence and degree of loss of material due to 

recurring internal corrosion. The staff finds the applicant’s “parameters monitored or inspected” 

program element to be adequate because, as described above, the use of the stated 

parameters is sufficient to identify loss of material, fouling, and loss of sealing before loss of 

intended functions of the component. 
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Based on its review of the application, the staff confirmed that the “parameters monitored or 

inspected” program element satisfies the criteria defined in SRP-LR Section A.1.2.3.3; 

therefore, the staff finds it acceptable. 

Detection of Aging Effects. LRA Section B.1.35, as revised by letter dated July 30, 2014, states 

that the PSPM Program periodically inspects components at least once every 5 years to detect 

aging. The LRA also states that inspections are conducted by qualified personnel and focus on 

locations most susceptible to aging, where practical. The LRA further states that visual 

inspections are used to detect loss of material and fouling for metallic and glass-like 

components and that visual inspections and manual flexing are used to detect loss of sealing for 

elastomers. For activities involving sampling, a representative sample consists of 20 percent of 

the population (i.e., components having the same material, environment, and aging effect) up to 

a maximum of 25 components. 

To address the recurring internal corrosion of carbon steel components exposed to raw water, 

the LRA states that periodic wall thickness measurements will be performed using ultrasonic 

thickness testing or other suitable techniques. The LRA also states that location selection will 

be based on pipe configuration, flow conditions, and operating history and that the locations will 

be periodically reviewed to validate their usefulness. In addition, as stated in the “monitoring 

and trending” program element, a minimum of five inspections will be performed each year until 

the occurrences of corrosion no longer meet the criteria for recurring internal corrosion (as 

defined in LR-ISG-2012-02 for the revised SRP-LR Section 3.3.2.2.8). To address the internal 

surfaces of buried piping subject to recurring corrosion, the LRA states that an inspection 

method will be selected from available technologies to provide a suitable indication of wall 

thickness for a representative sample of buried locations. 

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that the program element should address 

how age-related degradation will be detected before a loss of component function and should 

describe all aspects of activities for data collection (e.g., inspection technique and frequency). 

The SRP-LR Section A.1.2.3.4 also states that inspection samples should be biased toward 

locations most susceptible to the specific aging effect of concern. 

The staff noted that portions of the program element described above are consistent with the 

guidance in the GALL Report for managing the aging of internal surfaces. For example, GALL 

Report AMP XI.M38 “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” includes visual inspections and physical manipulation (of elastomers), which are 

conducted at least once every 10 years on a representative sample of components. 

The staff also noted that the portion of the program element associated with recurring internal 

corrosion is consistent with the guidance in the revision to SPR-LR Section 3.3.2.2.8 of 

LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric 

Storage Tanks, and Corrosion under Insulation. LR-ISG-2012-02 states that, when a review of 

operating experience reveals recurring corrosion, augmented inspections should be considered 

that focus on sites based on aging susceptibility and consequences of failure. The staff also 

noted that the applicant’s proposal to inspect at least five locations every year would result in at 

least 50 inspections over a 10-year period for as long as the issue persists, which doubles the 

minimum number of inspections that are recommended in GALL Report AMP XI.M38, which 

manages internal surfaces. 
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The staff finds the applicant’s “detection of aging effects” program element to be adequate 

because (1) the inspection techniques specified in the LRA for each activity in the program are 

capable of detecting the aging effect being managed, (2) the inspection sample size and 

frequency are comparable to other condition monitoring GALL Report AMPs that use sampling 

(and that are augmented as appropriate for recurring corrosion), (3) the component selection 

will focus on locations most susceptible to the aging effect, and (4) the inspections are 

performed by qualified personnel. 

Based on its review of the application, the staff confirmed that the “detection of aging effects” 

program element satisfies the criteria defined in SRP-LR Section A.1.2.3.4; therefore, the staff 

finds it acceptable. 

Monitoring and Trending. LRA Section B.1.35, as revised by letter dated July 30, 2012, states 

that the PSPM Program monitors and trends aging degradation and that inspection intervals are 

established to provide for timely detection of degradation. To address the recurring internal 

corrosion of carbon steel components exposed to raw water, the LRA states that wall thickness 

measurements will be compared to nominal wall thickness or previous measurements to 

determine rates of corrosion. Subsequent measurements will be performed as needed for each 

selected location based on rate of corrosion and expected time to reach the code minimum wall 

thickness plus margin for corrosion during the refueling cycle. In addition, as stated above, a 

minimum of five inspections will be performed each year until the occurrences of corrosion no 

longer meet the criteria for recurring internal corrosion. 

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities should 

be described and the results should be evaluated against the acceptance criteria to effect timely 

corrective or mitigative actions. 

The staff finds the applicant’s “monitoring and trending” program element to be adequate 

because inspection intervals are adjusted, as necessary, based on trending of wall thickness 

measurements to allow the detection of aging degradation before loss of intended function. 

Based on its review of the application, the staff confirmed that the “monitoring and trending” 

program element satisfies the criteria defined in SRP-LR Section A.1.2.3.5; therefore, the staff 

finds it acceptable. 

Acceptance Criteria. LRA Section B.1.35, as revised by letters dated July 30, 2014, and 

January 15, 2015, states that the PSPM Program acceptance criteria are defined in specific 

inspection procedures and that the criterion is no indication of relevant degradation 

(e.g., absence of excessive corrosion). 

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states that acceptance criteria should be qualitative or 

quantitative and should ensure that the SC intended functions are maintained consistent with all 

CLB design conditions. The staff finds the applicant’s “acceptance criteria” program element to 

be adequate because the use of no indication of relevant degradation ensures that any degree 

of aging beyond that normally observed in the subject components will be evaluated to allow the 

component intended functions to be maintained consistent with the CLB. Based on its review of 

the application, the staff confirmed that the “acceptance criteria” program element satisfies the 

criteria defined in SRP-LR Section A.1.2.3.6; therefore, the staff finds it acceptable. 
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The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements associated with enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows. 

Enhancement 1. LRA Section B.1.35 includes an enhancement to the “scope of program” 

program element. In this enhancement, the applicant stated that the program will be enhanced 

to revise program procedures as necessary to include all activities identified in the program 

description. The staff finds the enhancement acceptable because it will establish appropriate 

inspection activities to ensure that the LRA program is implemented. 

Enhancement 2. LRA Section B.1.35, as revised by letter dated July 30, 2014, includes an 

enhancement to the “parameters monitored or inspected” program element. In this 

enhancement, the applicant stated that procedures will be revised to require periodic 

determination of wall thickness of selected components. The review of the “parameters 

monitored or inspected” program element documents the staff’s review of this enhancement. 

Enhancement 3. LRA Section B.1.35, as revised by letter dated July 30, 2014, includes an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that procedures will be revised to require periodic wall thickness measurements 

using UT or other suitable techniques to identify loss of material due to recurring internal 

corrosion. The review of the “detection of aging effects” program element documents the staff’s 

review of this enhancement. 

Enhancement 4. LRA Section B.1.35, as revised by letter dated July 30, 2014, includes an 

enhancement to the “monitoring and trending” program element. In this enhancement, the 

applicant stated that procedures will be revised to require trending of wall thickness and use of 

that information to inform the extent of further inspections. The “monitoring and trending” 

program element documents the staff’s review of this enhancement. 

Enhancement 5. LRA Section B.1.35, as revised by letters dated July 30, 2014, and 

January 15, 2015, includes an enhancement to the “acceptance criteria” program element. In 

this enhancement, the applicant stated that program procedures will be revised to state that the 

acceptance criterion is no indication of relevant degradation. The applicant also stated the 

revisions will include specific acceptance criteria for metallic and elastomeric components. The 

review of the “acceptance criteria” program element documents the staff’s review of this 

enhancement. 

In summary, the staff reviewed the enhancements associated with the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” “monitoring and trending,” and 

“acceptance criteria” program elements and finds that, when implemented, they will make the 

AMP adequate to manage the applicable aging effects. 

Operating Experience. LRA Section B.1.35 summarizes operating experience related to the 

PSPM Program. The LRA states that an Institute of Nuclear Power Operations (INPO) 

assessment in 2011 led to improvements to the PM program, including using plant-specific 

templates for some PM activities and adopting a living PM program philosophy. The LRA also 

provided examples of activities that, according to the applicant, demonstrated the effectiveness 

of the PSPM Program. These examples include the use of visual inspections, eddy current 
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testing, ultrasonic thickness testing to prompt plugging of heat exchanger tubes in the EDG 

system, and the use of periodic PMs to rate the condition of the combustion turbine generator. 

The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, which states that operating experience should be discussed. SRP-LR 

Section A.1.2.3.10 also states that this information should provide objective evidence to support 

the conclusion that the effects of aging will be adequately managed to maintain the SC intended 

function(s) during the period of extended operation. 

During its review, the staff did not identify any operating experience that would indicate that the 

applicant should consider modifying its proposed program. Based on its review of the 

application, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the “operating experience” program 

element satisfies the criteria in SRP-LR Section A.1.2.3.10; therefore, the staff finds it 

acceptable. 

UFSAR Supplement. LRA Section A.1.35, as revised by letters dated July 30, 2014; 

January 15, 2015; and April 27, 2015, provides the UFSAR supplement for the PSPM Program. 

The staff reviewed this UFSAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1. The UFSAR supplement 

contains a complete description of the in-scope components, their aging management activities, 

and the enhancements to the program. The staff also noted that the applicant committed to 

implement the enhancements before the period of extended operation. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program. 

Conclusion. On the basis of its technical review of the applicant’s PSPM Program, the staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

3.0.4 QA Program Attributes Integral to Aging Management Programs 

Pursuant to 10 CFR 54.21(a)(3), the applicant is required to demonstrate that the effects of 

aging on SCs subject to an AMR will be adequately managed so that their intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. SRP-LR 

Branch Technical Position (BTP) RLSB-1, “Aging Management Review – Generic,” describes 

10 elements of an acceptable AMP. Elements (7), (8), and (9) are associated with the QA 

activities of “corrective actions,” “confirmation process,” and “administrative controls.” 

BTP RLSB-1 Table A.1-1, “Elements of an Aging Management Program for License Renewal,” 

provides the following description of these three program elements: 

(1) “corrective actions” – These actions, including root cause determination and prevention 

of recurrence, should be timely. 

(2) “confirmation process” – This process should ensure that preventive actions are 

adequate and that appropriate corrective actions are completed and effective. 

(3) “administrative controls” – These controls should provide for a formal review and 

approval process. 
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SRP-LR BTP IQMB-1, “Quality Assurance for Aging Management Programs,” notes that AMP 

aspects that affect the quality of safety-related SSCs are subject to the QA requirements of 

Appendix B to 10 CFR Part 50. Additionally, for nonsafety-related SCs subject to an AMR, the 

applicant may use the existing QA program under Appendix B to 10 CFR Part 50 to address the 

elements of “corrective actions,” “confirmation process,” and “administrative controls.” SRP-LR 

BTP IQMB-1 provides the following guidance on the QA attributes of AMPs: 

 Safety-related SCs are subject to the requirements in Appendix B to 10 CFR Part 50, 

which are adequate to address all quality-related aspects of an AMP consistent with the 

CLB of the facility for the period of extended operation. 

 For nonsafety-related SCs that are subject to an AMR, an applicant has an option to 

expand the scope of its QA program under Appendix B to 10 CFR Part 50 to include 

these SCs to address “corrective action,” “confirmation process,” and “administrative 

control” for aging management during the period of extended operation. In this case, the 

applicant should document such commitment in the UFSAR supplement in accordance 

with 10 CFR 54.21(d). 

3.0.4.1 Summary of Technical Information in the Application 

In LRA Appendix A, “Updated Final Safety Analysis Report Supplement,” Section A.1, “Aging 

Management Programs,” and LRA Appendix B, Section B.0.3, “Corrective Action, Confirmation 

Process and Administrative Controls,” the applicant described the elements of corrective action, 

confirmation process, and administrative controls that are applied to the AMPs for both 

safety-related and nonsafety-related components. 

LRA Appendix A, Section A.1, states, in part: 

 Corrective actions for systems, structures and components are accomplished per the 

existing Fermi 2 Corrective Action Program and Fermi 2 procedures. The site Corrective 

Action Program and procedure control program apply to license renewal aging 

management activities for both safety-related and nonsafety-related structures and 

components. 

 The confirmation process is part of the Corrective Action Program. 

 Fermi 2 QA Program aspects related to procedure controls and administrative controls 

(document control requirements for procedures and manuals) and retention of records 

apply to Fermi 2 aging management activities associated with license renewal for both 

safety-related and nonsafety-related structures, systems, and components. 

LRA Appendix B, Section B.0.3, states, in part: 

 Corrective actions for systems, structures, and components are accomplished per the 

existing Fermi 2 Corrective Action Program and Fermi 2 procedures. The site Corrective 

Action Program and procedure control program apply to license renewal aging 

management activities for both safety-related and nonsafety-related structures and 

components. 

 The confirmation process is part of the Corrective Action Program. 

 The Fermi 2 QA Program aspects related to procedure controls and administrative 

controls (document control requirements for procedures and manuals) and retention of 
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records apply to Fermi aging management activities associated with license renewal for 

both safety-related and nonsafety-related structures, systems, and components. The 

Fermi 2 administrative controls are consistent with NUREG-1801. 

3.0.4.2 Staff Evaluation 

Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of 

aging on SCs subject to an AMR will be adequately managed so that their intended functions 

will be maintained consistent with the CLB for the period of extended operation. The SRP-LR 

BTP RLSB-1 describes 10 attributes of an acceptable AMP. Three of these 10 attributes are 

associated with the QA activities of corrective action, confirmation process, and administrative 

controls. BTP RLSB-1 Table A.1-1 provides the following description of these quality attributes: 

 Attribute No. 7 - Corrective Actions, including root cause determination and prevention of 

recurrence, should be timely; 

 Attribute No. 8 - Confirmation Process, which should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective; 

and, 

 Attribute No. 9 - Administrative Controls, which should provide a formal review and 

approval process. 

SRP-LR BTP IQMB-1 states that those aspects of the AMP that affect the quality of SSCs are 

subject to the QA requirements of Appendix B to 10 CFR Part 50. Additionally, for 

nonsafety-related SCs subject to an AMR, the applicant's existing QA program under 

Appendix B to 10 CFR Part 50 may be used to address the elements of corrective action, 

confirmation process, and administrative control. SRP-LR BTP IQMB-1 provides the following 

guidance with regard to the QA attributes of AMPs: 

Safety-related SCs are subject to Appendix B to 10 CFR Part 50 requirements, 

which are adequate to address all quality related aspects of an AMP consistent 

with the CLB of the facility for the period of extended operation. For 

nonsafety-related SCs that are subject to an AMR for license renewal, an 

applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50 

program to include these SCs to address corrective action, confirmation process, 

and administrative control for aging management during the period of extended 

operation. In this case, the applicant should document such a commitment in the 

Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d). 

The staff reviewed LRA Sections Appendix A, Section A.1, and Appendix B, Section B.0.3, 

which describe how the applicant’s existing QA program includes the QA-related elements 

(corrective action, confirmation process, and administrative controls) for AMPs consistent with 

the staff’s guidance described in SRP-LR BTP IQMB-1. The staff also reviewed a sample of 

AMP program basis documents and verified that the AMPs implement the corrective action 

program, confirmation processes, and administrative controls as described in the LRA. Based 

on its review, the staff determined that the quality attributes presented in the AMP program 

basis documents and the associated AMPs are consistent with the staff’s position regarding QA 

for aging management. 
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3.0.4.3 Conclusion 

Based on the staff’s evaluation of LRA Appendix A, Section A.1 LRA Appendix B, Section B.0.3; 

and the AMP program basis documents, the staff concludes that the QA attributes (corrective 

action, confirmation process, and administrative control) of the applicant’s AMPs are consistent 

with SRP-LR BTP RLSB-1. 

3.0.5 Operating Experience for Aging Management Programs 

3.0.5.1 Summary of Technical Information in the Application 

LRA Section B.0.4 describes the consideration of operating experience for AMPs. The LRA 

states that operating experience for the programs credited with managing the effects of aging 

are reviewed and include a review of corrective actions that resulted in program enhancements. 

The applicant states that it does a systematic review of plant-specific and industry operating 

experience concerning aging management and age-related degradation to ensure that the 

license renewal AMPs will be effective in managing the aging effects for which they are credited. 

3.0.5.2 Staff Evaluation 

 Overview 

In accordance with 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects 

of aging on SCs subject to an AMR will be adequately managed so that their intended functions 

will be maintained in a way consistent with the CLB for the period of extended operation. 

SRP-LR Appendix A describes 10 elements of an acceptable AMP. SRP-LR Section A.1.2.3.10 

describes program element 10, “operating experience.” On March 16, 2012, the staff issued 

Final LR-ISG-2011-05, “Ongoing Review of Operating Experience,” which includes interim 

revisions to the SRP-LR to clarify criteria for the “operating experience” program element. SER 

Section 3.0.3 discusses the staff’s review of the second and third criteria, which concern 

currently available operating experience associated with existing and new programs, 

respectively. The following evaluation covers the staff’s review of the first criterion, which 

concerns the consideration of future operating experience. 

 Consideration of Future Operating Experience 

The staff reviewed LRA Sections B.0.4 and B.1 to determine how the applicant will use future 

operating experience to ensure that the AMPs are effective. Each of the program descriptions 

in LRA Section B.1 indicate that LRA Section B.0.4 describes the process for review of future 

plant-specific and industry operating experience. The staff evaluated the applicant’s operating 

experience review activities, as described in the LRA. The staff’s evaluations with respect to 

these SRP-LR sections follow in SER Sections 3.0.5.2.3 and 3.0.5.2.4, respectively. 

 Acceptability of Existing Programs 

SRP-LR Section A.4.2 describes existing programs generally acceptable to the staff for the 

capture, processing, and evaluation of operating experience concerning age-related 

degradation and aging management during the term of a renewed operating license. The 

acceptable programs are those relied on to meet the requirements of Appendix B to 

10 CFR Part 50 and Item I.C.5, “Procedures for Feedback of Operating Experience to Plant 
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Staff,” in NUREG-0737, “Clarification of TMI Action Plan Requirements,” dated November 1980. 

SRP-LR Section A.4.2 also states that, as part of meeting the requirements of NUREG-0737, 

Item I.C.5, the applicant’s operating experience program should rely on active participation in 

the INPO operating experience program (formerly the INPO Significant Event Evaluation and 

Information Network (SEE IN) program endorsed in NRC GL 82-04, “Use of INPO SEE IN 

Program,” dated March 9, 1982). 

LRA Section B.0.4 states that the applicant uses its operating experience program to 

systematically capture and review operating experience from plant-specific and industry 

sources. The applicant stated that the operating experience program meets the requirements of 

NUREG-0737. The applicant further states that the operating experience program interfaces 

and relies on active participation in the INPO operating experience program. Based on this 

information, the staff determined that the applicant’s operating experience program is consistent 

with the programs described in SRP-LR Section A.4.2. 

 Areas of Further Review 

Application of Existing Programs and Procedures to the Processing of Operating Experience 

Related to Aging. SRP-LR Section A.4.2 states that the programs and procedures relied on to 

meet the requirements of Appendix B to 10 CFR Part 50 and NUREG-0737, Item I.C.5, should 

not preclude the consideration of operating experience on age-related degradation and aging 

management. 

The applicant stated that operating experience from plant-specific and industry sources are 

systematically captured and reviewed on an ongoing basis in accordance with the QA program, 

which is consistent with Appendix B to 10 CFR Part 50, and the operating experience program, 

which is consistent with NUREG-0737, Item I.C.5. LRA Section B.0.4 states that the ongoing 

evaluation of operating experience included a review of corrective actions resulting in program 

enhancements. The LRA states that, for inspection programs, reports of recent inspections, 

examinations, and tests were reviewed to determine whether aging effects have been identified 

on applicable components. For monitoring programs, reports of sample results were reviewed 

to determine whether parameters are being maintained as required by the program. In addition, 

the LRA states that program owners contributed evidence of program success or weakness and 

identified applicable self-assessments, QA audits, peer evaluations, and NRC reviews. 

Based on this information, the staff determined that the processes implemented under the QA 

program, the corrective action program, and the enhanced operating experience program would 

not preclude consideration of age-related operating experience, which is consistent with the 

guidance in SRP-LR Section A.4.2. In addition, SRP-LR Section A.4.2 states that the applicant 

should use the option described in SRP-LR Appendix A.2 to expand the scope of the QA 

program under Appendix B to 10 CFR Part 50 to include nonsafety-related SCs. 

LRA Section B.0.3 states that the applicant’s QA program includes nonsafety-related SCs, 

which the staff finds consistent with the guidance in SRP-LR Section A.2 and, therefore, 

consistent with SRP-LR Section A.4.2 as well. SER Section 3.0.4 documents the staff’s 

evaluation of LRA Section B.0.3. 

Consideration of Guidance Documents as Industry Operating Experience. RP-LR Section A.4.2 

states that NRC and industry guidance documents and standards applicable to aging 

management, including revisions to the GALL Report, should be considered as sources of 

industry operating experience and evaluated accordingly. 
3-197 

LRA Section B.0.4 states that the sources of external operating experience include an active 

participation in the INPO operating experience program, GALL Report revisions, and other NRC 

guidance documents on aging management. The applicant also lists additional external 

sources, which include GALL Report revisions and other NRC guidance documents. 

The staff finds the sources of industry operating experience acceptable because the applicant 

will consider an appropriate breadth of industry operating experience for impacts to its aging 

management activities, which includes sources that the staff considers to be the primary 

sources of external operating experience information. The applicant’s consideration of industry 

guidance documents as operating experience is therefore consistent with the guidance in 

SRP-LR Section A.4.2. 

Screening of Incoming Operating Experience. SRP-LR Section A.4.2 states that all incoming 

plant-specific and industry operating experience should be screened to determine whether it 

involves age-related degradation or impacts to aging management activities. LRA Section B.0.4 

states that internal and external operating experience is captured and systematically reviewed 

on an ongoing basis. 

LRA Section B.04 states that the operating experience program will be enhanced to provide for 

periodic evaluation of the effectiveness of their self-assessment process for each AMP 

described in the UFSAR supplement. The staff finds the applicant’s operating experience 

review processes acceptable because, after enhancement, these processes will include 

screening of all new operating experience to identify and evaluate items that have the potential 

to impact the aging management activities. The applicant’s screening of plant-specific and 

industry operating experience is therefore consistent with the guidance in SRP-LR 

Section A.4.2. 

Identification of Operating Experience Related to Aging. SRP-LR Section A.4.2 states that 

coding should be used within the plant corrective action program to identify operating 

experience involving age-related degradation applicable to the plant. The SRP-LR also states 

that the associated entries should be periodically reviewed and any adverse trends should 

receive further evaluation. 

LRA Section B.0.4 states that the operating experience program will be revised to add aging 

type codes to the corrective action program to describe either plant conditions related to aging 

or industry operating experience related to aging. 

The staff finds the applicant’s identification of operating experience related to aging acceptable 

because the applicant has a means at a programmatic level to identify, trend, and evaluate 

operating experience that involves age-related degradation. The applicant’s identification of 

age-related operating experience applicable to the plants is therefore consistent with the 

guidance in SRP-LR Section A.4.2. 

Information Considered in Operating Experience Evaluations. SRP-LR Section A.4.2 states that 

operating experience identified as involving aging should receive further evaluation based on 

consideration of information, such as the affected SSCs, materials, environments, aging effects, 

aging mechanisms, and AMPs. The SRP-LR also states that actions should be initiated within 

the corrective action program to either enhance the AMPs or develop and implement new AMPs 

if an operating experience evaluation finds that the effects of aging may not be adequately 

managed. 
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LRA Section B.0.4 states that procedures will be revised to specify that the evaluations of 

operating experience concerning age-related degradation will include consideration of affected 

SSCs, environment, materials, aging effects, aging mechanisms, and AMPs. The staff 

determined that the applicant’s evaluations of age-related operating experience will include the 

assessment of appropriate information to determine potential impacts to the aging management 

activities. The staff also determined that the applicant’s operating experience program, in 

conjunction with the corrective action program, will implement any changes necessary to 

manage the effects of aging, as determined through its operating experience evaluations. 

Therefore, the staff finds that the information considered in the applicant’s operating experience 

evaluations and use of the operating experience program and corrective action program to 

ensure that the effects of aging are adequately managed is consistent with the guidance in 

SRP-LR Section A.4.2. 

Evaluation of AMP Implementation Results. SRP-LR Section A.4.2 states that the results of 

implementing the AMPs, such as data from inspections, tests, and analyses, should be 

evaluated regardless of whether the acceptance criteria of the particular AMP have been met. 

SRP-LR Section A.4.2 states that this information should be used to determine whether it is 

necessary to adjust the inspection activities for aging management. In addition, SRP-LR 

Section A.4.2 states that actions should be initiated within the plant corrective action program to 

either enhance the AMPs or develop and implement new AMPs if these evaluations indicate 

that the effects of aging may not be adequately managed. 

For inspection programs, the staff reviewed reports of recent inspections, examinations, or tests 

to determine whether aging effects have been identified on applicable components. For 

monitoring programs, the staff reviewed reports of sample results to determine whether 

parameters are being maintained as required by the program. In addition, program owners 

contributed evidence of program success or weakness and identified applicable 

self-assessments, QA audits, peer evaluations, and NRC reviews. 

The staff reviewed the LRA and finds the applicant’s treatment of AMP implementation results 

as operating experience acceptable because the applicant will evaluate these results and use 

the information to determine whether to adjust the aging management activities. The applicant’s 

activities for the evaluation of AMP implementation results are therefore consistent with the 

guidance in SRP-LR Section A.4.2. 

Training. SRP-LR Section A.4.2 states that training on age-related degradation and aging 

management should be provided to those personnel responsible for implementing the AMPs 

and those personnel that may submit, screen, assign, evaluate, or otherwise process 

plant-specific and industry operating experience. SRP-LR Section A.4.2 also states that the 

training should be periodic and include provisions to accommodate the turnover of plant 

personnel. 

LRA Section B.0.4 states that the operating experience program procedures will be revised to 

provide for training for personnel responsible for submitting, screening, assigning, evaluating, or 

otherwise processing plant-specific and industry operating experience concerning age-related 

degradation and aging management and for personnel responsible for implementing AMPs 

based on the complexity of the job performance requirements and assigned responsibilities. 

The staff reviewed the LRA and determined that the scope of personnel included in the 

applicant’s training program are consistent with the guidelines in SRP-LR Section A.4.2. The 

staff also determined that the applicant has demonstrated that its training program, when 
3-199 

enhanced, will cover age-related degradation and aging management topics. The applicant’s 

enhanced training activities are therefore consistent with the guidance in SRP-LR Section A.4.2. 

Reporting Operating Experience to the Industry. SRP-LR Section A.4.2 states that guidelines 

should be established for reporting plant-specific operating experience on age-related 

degradation and aging management to the industry. The staff finds this acceptable because the 

applicant will have established appropriate expectations and guidelines for identifying 

plant-specific operating experience concerning aging management and age-related degradation 

to the industry. The applicant’s establishment of these guidelines is therefore consistent with 

the guidance in SRP-LR Section A.4.2. 

Schedule for Implementing the Operating Experience Review Activities. Fermi 2’s UFSAR 

Section A.1 states that DTE will enhance the Fermi 2 self-assessment process to provide for 

periodic evaluation of the effectiveness of this operating experience program described in the 

UFSAR supplement. 

SRP-LR Section A.4.2 states that the operating experience review activities should be 

implemented on an ongoing basis throughout the term of a renewed license. 

LRA Section B.0.4 states that the enhanced operating experience program will be implemented 

on an ongoing basis throughout the terms of the renewed licenses. In addition, LRA 

Section A.1 provides the UFSAR supplement summary description of the applicant’s enhanced 

programmatic activities for ongoing review of the operating experience. On issuance of the 

renewed licenses in accordance with 10 CFR 54.3(c), this summary description will be 

incorporated into each plant’s CLB, and, at that time, the applicant will be obligated to conduct 

its operating experience review activities accordingly. 

The staff finds the implementation schedule acceptable because the applicant will implement 

the enhanced operating experience review activities on an ongoing basis throughout the term of 

the renewed operating licenses. 

 Summary 

Based on its review of the LRA the staff determined that the applicant’s programmatic activities 

for the ongoing review of operating experience are acceptable for (a) the systematic review of 

plant-specific and industry operating experience to ensure that the license renewal AMPs are, 

and will continue to be, effective in managing the aging effects for which they are credited and 

(b) the enhancement of AMPs or development of new AMPs when it is determined through the 

evaluation of operating experience that the effects of aging may not be adequately managed. 

Based on the completion of the staff’s review and the consistency of the applicant’s operating 

experience review activities with the guidance in LR-ISG-2011-05, the staff finds the applicant’s 

programmatic activities for the ongoing review of operating experience acceptable. 

3.0.5.3 UFSAR Supplement 

In accordance with 10 CFR 54.21(d), the UFSAR supplement must contain a summary 

description of the programs and activities for managing the effects of aging. LRA Section A.1 

provides the UFSAR supplement summary description of the applicant’s programmatic activities 

for the ongoing review of operating experience. It also identifies enhancements that will be 

implemented to ensure that plant-specific and industry operating experience related to aging 

management will be used effectively. 
3-200 

The staff reviewed LRA Section A.1 and found that the summary description of the ongoing 

evaluation of operating experience related to aging management will consider (a) SSCs, 

(b) materials, (c) environments, (d) aging effects, (e) aging mechanisms, and (f) AMPs and that 

procedures will be revised to specify these evaluations. 

Based on its review, the staff determined that the content of the applicant’s summary description 

is consistent with the example and also sufficiently comprehensive to describe the applicant’s 

programmatic activities for evaluating operating experience to maintain the effectiveness of the 

AMPs. Therefore, the staff finds the applicant’s UFSAR supplement summary description 

acceptable. 

3.0.5.4 Conclusion 

Based on its review of the applicant’s programmatic activities for the ongoing review of 

operating experience, the staff concludes that the applicant has demonstrated that operating 

experience will be reviewed to ensure that the effects of aging will be adequately managed so 

that the intended functions will remain consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for these activities and concludes that it provides an adequate summary description, as required 

by 10 CFR 54.21(d). 

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

System 

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

reactor vessel, reactor vessel internals, and reactor coolant system (RCS) components and 

component groups of the following: 

 reactor vessel 

 reactor vessel internals 

 reactor coolant pressure boundary 

 miscellaneous RCS systems in scope for 10 CFR 54.4(a)(2) 

3.1.1 Summary of Technical Information in the Application 

LRA Section 3.1 provides AMR results for the reactor vessel, reactor vessel internals, and 

reactor coolant system components and component groups. LRA Table 3.1.1, “Summary of 

Aging Management Programs for the Reactor Coolant System Evaluated in Chapter IV of 

NUREG-1801,” is a summary comparison of the applicant’s AMRs with those evaluated in the 

GALL Report for the reactor vessel, reactor vessel internals, and RCS components and 

component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 
3-201 

3.1.2 Staff Evaluation 

The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the reactor vessel, reactor vessel 

internals, and RCS components within the scope of license renewal and subject to an AMR will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff conducted a review of the applicant’s AMRs to confirm the applicant’s claim that 

certain AMRs are consistent with the GALL Report, not applicable, or not used. The staff did 

not repeat its review of the matters described in the GALL Report; however, the staff did verify 

that the material presented in the LRA is applicable and that the applicant identified the 

appropriate GALL Report AMRs. The AMRs that the staff confirmed are consistent with the 

GALL Report are noted as such in SER Table 3.1-1 and no further discussion is required. The 

AMRs that the staff confirmed are not applicable to Fermi 2 or not used, because the 

component, material, and environment combination described in the SRP-LR does not exist for 

in-scope SCs at Fermi 2 or because the component, material, and environment combination is 

addressed by another SER Table 3.1-1 item, or that require no aging management are noted in 

SER Table 3.1-1 and are discussed in SER Section 3.1.2.1.1, “AMR Results Identified as Not 

Applicable or Not Used.” Details of the staff’s evaluation of AMRs that the applicant claimed are 

consistent with the GALL Report, but for which a different AMP from the program recommended 

in the GALL Report is used to manage aging, and AMRs for which the staff requested additional 

information are documented in SER Sections 3.1.2.1.2 through 3.1.2.1.4. 

During its review, the staff also reviewed AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff’s evaluations of 

AMRs for which the GALL Report recommends further evaluation are documented in SER 

Section 3.1.2.2. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs not consistent 

with, or not addressed in, the GALL Report are documented in SER Section 3.1.2.3. 

SER Table 3.1-1 summarizes the staff’s evaluation of components, aging effects, or 

mechanisms, and AMPs listed in LRA Section 3.1 and addressed in the GALL Report. 
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Table 3.1-1 Staff Evaluation for Reactor Vessel, Internals, and Reactor Coolant System 

Components in the GALL Report 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

High strength, 

low-alloy steel top 

head closure stud 

assembly exposed 

to air with potential 

for reactor coolant 

leakage (3.1.1-1) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1)) 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1) 

Nickel alloy tubes 

and sleeves 

exposed to reactor 

coolant and 

secondary 

feedwater/steam 

(3.1.1-2) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1)) 

Yes, TLAA Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1) 

Stainless steel or 

nickel alloy reactor 

vessel internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-3) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1)) 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1) 

Steel pressure 

vessel support skirt 

and attachment 

welds (3.1.1-4) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1)) 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1) 

Steel, stainless 

steel, or steel (with 

stainless steel or 

nickel alloy cladding) 

steam generator 

components, 

pressurizer relief 

tank components or 

piping components 

or bolting (3.1.1-5) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1)) 

Yes, TLAA Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1) 
3-203 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

coolant pressure 

boundary 

components: piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-6) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section 

4.3 “Metal Fatigue,” 

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1)) 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1) 

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

vessel components: 

flanges; nozzles; 

penetrations; safe 

ends; thermal 

sleeves; vessel 

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-7) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section 

4.3 “Metal Fatigue,” 

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1)) 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1) 

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy steam 

generator 

components 

exposed to reactor 

coolant (3.1.1-8) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section 

4.3 “Metal Fatigue,” 

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1)) 

Yes, TLAA Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1) 
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Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

RCPB piping; 

flanges; nozzles & 

safe ends; 

pressurizer shell 

heads & welds; 

heater sheaths & 

sleeves; 

penetrations; 

thermal sleeves 

exposed to reactor 

coolant (3.1.1-9) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section 

4.3 “Metal Fatigue,” 

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1)) 

Yes, TLAA Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1) 

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

reactor vessel 

flanges; nozzles; 

penetrations; 

pressure housings; 

safe ends; thermal 

sleeves; vessel 

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-10) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, Section 

4.3 “Metal Fatigue,” 

for acceptable 

methods to comply 

with 

10 CFR 54.21(c)(1)) 

Yes, TLAA Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1) 

Steel or stainless 

steel pump and 

valve closure bolting 

exposed to high 

temperatures and 

thermal cycles 

(3.1.1-11) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation; check 

ASME Code limits 

for allowable cycles 

(less than 7,000 

cycles) of thermal 

stress range (see 

SRP Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1)) 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.2.1) 
3-205 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel steam 

generator 

components: upper 

and lower shells, 

transition cone; new 

transition cone 

closure weld 

exposed to 

secondary feedwater 

or steam (3.1.1-12) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,” 

and, for 

Westinghouse Model 

44 and 51 S/G, if 

corrosion of the shell 

is found, additional 

inspection 

procedures are 

developed 

Yes, 

detection of 

aging 

effects is to 

be 

evaluated 

Not applicable Not applicable to 

BWRs (see SER 

Sections 

3.1.2.2.2(1) and 

3.1.2.2.2(2)) 

Steel (with or without 

stainless steel 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds 

exposed to reactor 

coolant and neutron 

flux (3.1.1-13) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

TLAA is to be 

evaluated in 

accordance with 

Appendix G of 

10 CFR Part 50 and 

RG 1.99. The 

applicant may 

choose to 

demonstrate that the 

materials of the 

nozzles are not 

controlling for the 

TLAA evaluations 

Yes, TLAA TLAA Consistent with the 

GALL Report (see 

SER Section 

3.1.2.2.3(1)) 

Steel (with or without 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds; 

safety injection 

nozzles (3.1.1-14) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

Chapter XI.M31, 

“Reactor Vessel 

Surveillance” 

Yes, plantspecific or 

integrated 

surveillance 

program 

Reactor Vessel 

Surveillance 

Program 

Consistent with the 

GALL Report 

(see SER Section 

3.1.2.2.3(2)) 

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 (3.1.1-15) 

Reduction of 

ductility and 

fracture 

toughness due 

to neutron 

irradiation 

embrittlement, 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement 

Ductility - Reduction 

in fracture toughness 

is a TLAA to be 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.7, “Other 

Plant-Specific 

TLAAs,” for 

acceptable methods 

of meeting the 

requirements of 

10 CFR 54.21(c)). 

Yes, TLAA Not applicable Not applicable to 

BWRs (see 

SER Section 

3.1.2.2.3(3)) 
3-206 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel and 

nickel alloy top head 

enclosure vessel 

flange leak detection 

line (3.1.1-16) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking 

A plant-specific 

aging management 

program is to be 

evaluated because 

existing programs 

may not be capable 

of mitigating or 

detecting crack 

initiation and growth 

due to SCC in the 

vessel flange leak 

detection line 

Yes, plantspecific One-Time 

Inspection and 

Water Chemistry 

Control – BWR 

programs 

Consistent with the 

GALL Report (see 

SER Section 

3.1.2.2.4(1)) 

Stainless steel 

isolation condenser 

components 

exposed to reactor 

coolant (3.1.1-17) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

for BWR water, and 

a plant-specific 

verification program 

Yes, 

detection of 

aging 

effects is to 

be 

evaluated 

Not used. Fermi 2 

does not have an 

isolation 

condenser. 

Not applicable to 

Fermi 2 (see 

SER Section 

3.1.2.2.4(2)) 

Reactor vessel shell 

fabricated of 

SA508-Cl 2 forgings 

clad with stainless 

steel using a 

high-heat-input 

welding process 

exposed to reactor 

coolant (3.1.1-18) 

Crack growth 

due to cyclic 

loading 

Growth of 

intergranular 

separations is a 

TLAA evaluated for 

the period of 

extended operation. 

Standard Review 

Plan, Section 4.7, 

“Other Plant-Specific 

Time-Limited Aging 

Analysis,” provides 

guidance for meeting 

the requirements of 

10 CFR 54.21(c) 

Yes, TLAA Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.5) 

Stainless steel 

reactor vessel 

closure head flange 

leak-detection line 

and bottom-mounted 

instrument guide 

tubes (external to 

reactor vessel) 

(3.1.1-19) 

Cracking due to 

stress corrosion 

cracking 

A plant-specific 

aging management 

program is to be 

evaluated 

Yes, plantspecific Not applicable Not applicable to 

BWRs (see SER 

Section 

3.1.2.2.6(1)) 

Cast austenitic 

stainless steel 

Class 1 piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-20) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry” 

and, for CASS 

components that do 

not meet the 

NUREG-0313 

guidelines, a 

plant-specific aging 

management 

program 

Yes, plantspecific Not applicable Not applicable to 

BWRs (see SER 

Section 

3.1.2.2.6(2)) 
3-207 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-21) 

Cracking due to 

cyclic loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components. 

The ISI program is to 

be augmented by a 

plant-specific 

verification program. 

Yes, 

detection of 

aging 

effects is to 

be 

evaluated 

Not used. Fermi 2 

does not have an 

isolation 

condenser. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.2.7) 

Steel steam 

generator feedwater 

impingement plate 

and support exposed 

to secondary 

feedwater (3.1.1-22) 

Loss of material 

due to erosion 

A plant-specific 

aging management 

program is to be 

evaluated 

Yes, plantspecific Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.8) 

SRP-LR Item No. 

(3.1.1-23) Deleted 

by LR-ISG-2011-04 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

(see SER 

Section 3.1.2.2.9) 

SRP-LR Item No. 

(3.1.1-24) Deleted 

by LR-ISG-2011-04 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

(see SER 

Section 3.1.2.2.10)

Steel (with nickelalloy cladding) or 

nickel alloy steam 

generator primary 

side components: 

divider plate and 

tube-to-tube sheet 

welds exposed to 

reactor coolant 

(3.1.1-25) 

Cracking due to 

primary water 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry” 

Yes, plantspecific Not applicable Not applicable to 

BWRs (see SER 

Sections 

3.1.2.2.11(1) and 

3.1.2.2.11(2)) 

SRP-LR Item No. 

(3.1.1-26) Deleted 

by LR-ISG-2011-04 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

(see SER 

Section 3.1.2.2.12)

SRP-LR Item No. 

(3.1.1-27) Deleted 

by LR-ISG-2011-04 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

(see SER 

Section 3.1.2.2.13)

Stainless steel 

Combustion 

Engineering 

“Existing Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-28) 

Loss of material 

due to wear; 

cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-208 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Nickel alloy core 

shroud and core 

plate access hole 

cover (welded 

covers) exposed to 

reactor coolant 

(3.1.1-29) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,” 

and for BWRs with a 

crevice in the access 

hole covers, 

augmented 

inspection using UT 

or other acceptable 

techniques 

No Inservice 

Inspection and 

Water Chemistry 

Control – BWR 

programs 

Consistent with the 

GALL Report 

Stainless steel or 

nickel alloy 

penetration: drain 

line exposed to 

reactor coolant 

(3.1.1-30) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry” 

No Not used. The 

Fermi 2 vessel 

does not have a 

stainless steel or 

nickel alloy drain 

penetration. 

Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-31) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry” 

No Not used. Fermi 2 

does not have an 

isolation 

condenser. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.1.1) 

Stainless steel, 

nickel alloy, or CASS 

reactor vessel 

internals, core 

support structure 

(not already 

referenced in ASME 

Section XI 

Examination 

Category B-N-3 core 

support structure 

components in MRP227-A), exposed to 

reactor coolant and 

neutron flux 

(3.1.1-32) 

Cracking, or 

loss of material 

due to wear 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” or 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” invoking 

applicable 10 CFR 

50.55a and ASME 

Section XI inservice 

inspection 

requirements for 

these components 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel, steel 

with stainless steel 

cladding Class 1 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-33) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-209 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

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) (3.1.1-34) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

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 (3.1.1-35) 

Cracking due to 

cyclic loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel, stainless steel 

pressurizer integral 

support exposed to 

air with metal 

temperature up to 

288°C (550°F) 

(3.1.1-36) 

Cracking due to 

cyclic loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel reactor vessel 

flange (3.1.1-37) 

Loss of material 

due to wear 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Cast austenitic 

stainless steel 

Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant >250 °C 

(>482 °F) (3.1.1-38) 

Loss of fracture 

toughness due 

to thermal aging 

embrittlement 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components. 

For pump casings 

and valve bodies, 

screening for 

susceptibility to 

thermal aging is not 

necessary. 

No Inservice 

Inspection 

Program 

Consistent with the 

GALL Report 

Steel, stainless 

steel, or steel with 

stainless steel 

cladding Class 1 

piping, fittings and 

branch connections 

< NPS 4 exposed to 

reactor coolant 

(3.1.1-39) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking (for 

stainless steel 

only), and 

thermal, 

mechanical, and 

vibratory loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

Chapter XI.M2, 

“Water Chemistry,” 

and XI.M35, “OneTime Inspection of 

ASME Code Class 1 

Small-bore Piping” 

No Inservice 

Inspection, Water 

Chemistry Control 

– BWR, and OneTime Inspection – 

Small-Bore Piping 

programs 

Consistent with the 

GALL Report 
3-210 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel with stainless 

steel or nickel alloy 

cladding; or stainless 

steel pressurizer 

components 

exposed to reactor 

coolant (3.1.1-40) 

Cracking due to 

cyclic loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Nickel alloy core 

support pads; core 

guide lugs exposed 

to reactor coolant 

(3.1.1-40.5) 

Cracking due to 

primary water 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Nickel alloy core 

shroud and core 

plate access hole 

cover (mechanical 

covers) exposed to 

reactor coolant 

(3.1.1-41) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not used. The 

shroud support 

access hole 

covers are 

welded. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.1.1) 

Steel with stainless 

steel or nickel alloy 

cladding or stainless 

steel primary side 

components; steam 

generator upper and 

lower heads, and 

tube sheet weld; or 

pressurizer 

components 

exposed to reactor 

coolant (3.1.1-42) 

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel and 

nickel-alloy reactor 

vessel internals 

exposed to reactor 

coolant (3.1.1-43) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry” 

No Water Chemistry 

Control – BWR, 

One-Time 

Inspection, and 

Inservice 

Inspection 

programs. 

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.1.2) 

Steel steam 

generator secondary 

manways and 

handholds (cover 

only) exposed to air 

with leaking 

secondary-side 

water and/or steam 

(3.1.1-44) 

Loss of material 

due to erosion 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 2 components 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-211 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Nickel alloy and 

steel with nickelalloy cladding 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-45) 

Cracking due to 

primary water 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking 

of Nickel-Alloy 

Components and 

Loss of Material Due 

to Boric Acidinduced Corrosion in 

RCPB Components 

(PWRs Only)” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel, 

nickel-alloy, nickelalloy welds and/or 

buttering control rod 

drive head 

penetration pressure 

housing or nozzles 

safe ends and welds 

(inlet, outlet, safety 

injection) exposed to 

reactor coolant 

(3.1.1-46) 

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking 

of Nickel-Alloy 

Components and 

Loss of Material Due 

to Boric Acidinduced corrosion in 

RCPB Components 

(PWRs Only)” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel, 

nickel-alloy control 

rod drive head 

penetration pressure 

housing exposed to 

reactor coolant 

(3.1.1-47) 

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking 

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

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 (3.1.1-48) 

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, 

“Boric Acid 

Corrosion,” and 

Chapter XI.M11B, 

“Cracking of NickelAlloy Components 

and Loss of Material 

Due to Boric AcidInduced Corrosion in 

RCPB Components 

(PWRs Only)” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel reactor coolant 

pressure boundary 

external surfaces or 

closure bolting 

exposed to air with 

borated water 

leakage (3.1.1-49) 

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, 

“Boric Acid 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-212 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Cast austenitic 

stainless steel 

Class 1 piping, 

piping component, 

and piping elements 

and control rod drive 

pressure housings 

exposed to reactor 

coolant >250 °C 

(>482 °F) (3.1.1-50) 

Loss of fracture 

toughness due 

to thermal aging 

embrittlement 

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)” 

No Not used. The 

Inservice 

Inspection 

Program manages 

the reduction of 

fracture toughness 

in cast austenitic 

stainless steel 

pump casings and 

valve bodies in the 

reactor coolant 

pressure 

boundary (see 

item 3.1.1-38). 

There are no other 

Class 1 CASS 

components in the 

reactor coolant 

system pressure 

boundary. The 

main steam line 

flow elements 

(flow restrictors) 

and recirculation 

loop flow elements 

are not Class 1 

components 

(elements are 

completely 

internal to the 

carbon steel pipe). 

The CASS 

subcomponents of 

the flow elements 

are not 

susceptible to 

thermal aging 

embrittlement 

because they are 

composed of lowmolybdenum 

CASS (DF8) and 

were centrifugally 

cast. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal “Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-51a) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-213 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal “Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-51b) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, 

fatigue, or 

overload 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52a) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52b) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “Existing 

Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52c) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal 

“Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-53a) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel 

Westinghouse 

reactor internal 

“Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-53b) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-214 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal 

“Existing Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-53c) 

Cracking due to 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking, or 

fatigue 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

(for SCC 

mechanisms only) 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel 

bottom mounted 

instrument system 

flux thimble tubes 

(with or without 

chrome plating) 

exposed to reactor 

coolant and neutron 

flux (Westinghouse 

“Existing Programs” 

components) 

(3.1.1-54) 

Loss of material 

due to wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals,” or 

Chapter XI.M37, 

“Flux Thimble Tube 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel alloy Babcock 

& Wilcox reactor 

internal “No 

Additional 

Measures” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55a) 

No additional 

aging 

management for 

reactor internal 

“No Additional 

Measures” 

components 

unless required 

by ASME 

Section XI, 

Examination 

Category B-N-3 

or relevant 

operating 

experience 

invalidates 

MRP-227-A. 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel alloy 

Combustion 

Engineering reactor 

internal “No 

Additional 

Measures” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55b) 

No additional 

aging 

management for 

reactor internal 

“No Additional 

Measures” 

components 

unless required 

by ASME 

Section XI, 

Examination 

Category B-N-3 

or relevant 

operating 

experience 

invalidates 

MRP-227-A. 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-215 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel or 

nickel alloy 

Westinghouse 

reactor internal “No 

Additional 

Measures” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55c) 

No additional 

aging 

management for 

reactor internal 

“No Additional 

Measures” 

components 

unless required 

by ASME 

Section XI, 

Examination 

Category B-N-3 

or relevant 

operating 

experience 

invalidates 

MRP-227-A. 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Combustion 

Engineering reactor 

internal “Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56a) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-216 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) Combustion 

Engineering 

“Expansion” reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56b) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Combustion 

Engineering reactor 

internal “Existing 

Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56c) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.1.1-57) 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 
3-217 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Babcock & Wilcox 

reactor internal 

“Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-58a) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to wear; or 

loss of material 

due to wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Babcock & Wilcox 

reactor internal 

“Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-58b) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-218 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Westinghouse 

reactor internal 

“Primary” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59a) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) Westinghouse 

reactor internal 

“Expansion” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59b) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-219 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel (SS, 

including CASS, PH 

SS or martensitic 

SS) or nickel alloy 

Westinghouse 

reactor internal 

“Existing Programs” 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59c) 

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement 

and for CASS, 

martensitic SS, 

and PH SS due 

to thermal aging 

embrittlement; 

or changes in 

dimensions due 

to void swelling 

or distortion; or 

loss of preload 

due to thermal 

and irradiation 

enhanced stress 

relaxation or 

creep; or loss of 

material due to 

wear 

Chapter XI.M16A, 

“PWR Vessel 

Internals” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant (3.1.1-60) 

Wall thinning 

due to flowaccelerated 

corrosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Flow-Accelerated 

Corrosion 

Program 

Consistent with the 

GALL Report 

Steel steam 

generator steam 

nozzle and safe end, 

feedwater nozzle 

and safe end, AFW 

nozzles and safe 

ends exposed to 

secondary 

feedwater/steam 

(3.1.1-61) 

Wall thinning 

due to flowaccelerated 

corrosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

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 (3.1.1-62) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M18, 

“Bolting Integrity” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel or stainless 

steel closure bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-63) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion or 

wear 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 
3-220 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel closure bolting 

exposed to air – 

indoor uncontrolled 

(3.1.1-64) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M18, 

“Bolting Integrity” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-65) 

Loss of material 

due to wear 

Chapter XI.M18, 

“Bolting Integrity” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

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 (3.1.1-66) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening 

Chapter XI.M18, 

“Bolting Integrity” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel or stainless 

steel closure bolting 

exposed to air – 

indoor with potential 

for reactor coolant 

leakage (3.1.1-67) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 

Nickel alloy steam 

generator tubes 

exposed to 

secondary feedwater 

or steam (3.1.1-68) 

Changes in 

dimension 

(“denting”) due 

to corrosion of 

carbon steel 

tube support 

plate 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

or steam (3.1.1-69) 

Cracking due to 

outer diameter 

stress corrosion 

cracking and 

intergranular 

attack 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Nickel alloy steam 

generator tubes, 

repair sleeves, and 

tube plugs exposed 

to reactor coolant 

(3.1.1-70) 

Cracking due to 

primary water 

stress corrosion 

cracking 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-221 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including 

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-71) 

Cracking due to 

stress corrosion 

cracking or 

other 

mechanism(s); 

loss of material 

due general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel steam 

generator tube 

support plate, tube 

bundle wrapper, 

supports, and 

mounting hardware 

exposed to 

secondary feedwater 

or steam (3.1.1-72) 

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion, 

ligament 

cracking due to 

corrosion 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

phosphate chemistry 

in secondary 

feedwater or steam 

(3.1.1-73) 

Loss of material 

due to wastage 

and pitting 

corrosion 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel steam 

generator upper 

assembly and 

separators including 

feedwater inlet ring 

and support exposed 

to secondary 

feedwater or steam 

(3.1.1-74) 

Wall thinning 

due to flowaccelerated 

corrosion 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel steam 

generator tube 

support lattice bars 

exposed to 

secondary feedwater 

or steam (3.1.1-75) 

Wall thinning 

due to flowaccelerated 

corrosion and 

general 

corrosion 

Chapter XI.M19, 

“Steam Generators,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including 

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-76) 

Loss of material 

due to fretting 

Chapter XI.M19, 

“Steam Generators” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

or steam (3.1.1-77) 

Loss of material 

due to wear and 

fretting 

Chapter XI.M19, 

“Steam Generators” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 
3-222 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Nickel alloy steam 

generator 

components such as 

secondary side 

nozzles (vent, drain, 

and instrumentation) 

exposed to 

secondary feedwater 

or steam (3.1.1-78) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection,” or 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD.” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and nickelalloy reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-79) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel or 

steel with stainless 

steel cladding 

pressurizer relief 

tank: tank shell and 

heads, flanges, 

nozzles (noneASME Section XI 

components) 

exposed to treated 

borated water >60°C 

(>140°F) (3.1.1-80) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-81) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Nickel alloy 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-82) 

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel steam 

generator shell 

assembly exposed 

to secondary 

feedwater or steam 

(3.1.1-83) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel top head 

enclosure (without 

cladding) top head 

nozzles (vent, top 

head spray or RCIC, 

and spare) exposed 

to reactor coolant 

(3.1.1-84) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 
3-223 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel, 

nickel-alloy, and 

steel with nickelalloy or stainless 

steel cladding 

reactor vessel 

flanges, nozzles, 

penetrations, safe 

ends, vessel shells, 

heads and welds 

exposed to reactor 

coolant (3.1.1-85) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel 

steam generator 

primary side divider 

plate exposed to 

reactor coolant 

(3.1.1-86) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel or 

nickel-alloy PWR 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-87) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry” 

No Not used Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and nickelalloy reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-88) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-89) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-90) 

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1 

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-91) 

Cracking due to 

stress corrosion 

cracking; loss of 

material due to 

general, pitting, 

and crevice 

corrosion, or 

wear (BWR) 

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting” 

No Reactor Head 

Closure Studs 

Program 

Consistent with the 

GALL Report 
3-224 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-92) 

Cracking due to 

stress corrosion 

cracking; loss of 

material due to 

general, pitting, 

and crevice 

corrosion, or 

wear (PWR) 

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Copper alloy >15% 

Zn or > 8% Al piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-93) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching “

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1) 

Stainless steel and 

nickel alloy vessel 

shell attachment 

welds exposed to 

reactor coolant 

(3.1.1-94) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking 

Chapter XI.M4, 

“BWR Vessel ID 

Attachment Welds,” 

and Chapter XI.M2, 

“Water Chemistry” 

No BWR Vessel ID 

Attachment Welds 

and Water 

Chemistry Control 

– BWR programs 

Consistent with the 

GALL Report 

Steel (with or without 

stainless steel 

cladding) feedwater 

nozzles exposed to 

reactor coolant 

(3.1.1-95) 

Cracking due to 

cyclic loading 

Chapter XI.M5, 

“BWR Feedwater 

Nozzle” 

No BWR Feedwater 

Nozzle Program 

Consistent with the 

GALL Report 

Steel (with or without 

stainless steel 

cladding) control rod 

drive return line 

nozzles exposed to 

reactor coolant 

(3.1.1-96) 

Cracking due to 

cyclic loading 

Chapter XI.M6, 

“BWR Control Rod 

Drive Return Line 

Nozzle” 

No Not used. The 

Fermi 2 control 

rod drive return 

line was cut and 

capped before 

initial plant 

operation. The 

nozzles have not 

been exposed to 

thermal cyclic 

loading form 

operation of the 

return line. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.1.1) 

Stainless steel and 

nickel alloy piping, 

piping components, 

and piping elements 

greater than or equal 

to 4 NPS; nozzle 

safe ends and 

associated welds 

(3.1.1-97) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking 

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Either BWR 

Stress Corrosion 

Cracking 

Program, 

Inservice 

Inspection 

Program, or BWR 

CRD Return Line 

Nozzle Program; 

and Water 

Chemistry Control 

– BWR Program. 

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.1.3) 
3-225 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel or 

nickel alloy 

penetrations: 

instrumentation and 

standby liquid 

control exposed to 

reactor coolant 

(3.1.1-98) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading 

Chapter XI.M8, 

“BWR Penetrations,” 

and Chapter XI.M2, 

“Water Chemistry” 

No BWR Penetrations 

and Water 

Chemistry Control 

– BWR programs 

Consistent with the 

GALL Report 

Cast austenitic 

stainless steel; PH 

martensitic stainless 

steel; martensitic 

stainless steel; 

X-750 alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-99) 

Loss of fracture 

toughness due 

to thermal aging 

and neutron 

irradiation 

embrittlement 

Chapter XI.M9, 

“BWR Vessel 

Internals” 

No BWR Vessel 

Internals Program 

Consistent with the 

GALL Report 

Stainless steel 

reactor vessel 

internals 

components (jet 

pump wedge 

surface) exposed to 

reactor coolant 

(3.1.1-100) 

Loss of material 

due to wear 

Chapter XI.M9, 

“BWR Vessel 

Internals” 

No BWR Vessel 

Internals Program 

Consistent with the 

GALL Report 

Stainless steel 

steam dryers 

exposed to reactor 

coolant (3.1.1-101) 

Cracking due to 

flow-induced 

vibration 

Chapter XI.M9, 

“BWR Vessel 

Internals” for steam 

dryer 

No BWR Vessel 

Internals Program 

Consistent with the 

GALL Report 

Stainless steel fuel 

supports and control 

rod drive assemblies 

control rod drive 

housing exposed to 

reactor coolant 

(3.1.1-102) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking 

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

No BWR Vessel 

Internals and 

Water Chemistry 

Control – BWR 

programs 

Consistent with the 

GALL Report 

Stainless steel and 

nickel alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-103) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking 

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry” 

No BWR Vessel 

Internals, Water 

Chemistry Control 

– BWR, and 

Inservice 

Inspection 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.1.2.1.4) 

X-750 alloy reactor 

vessel internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-104) 

Cracking due to 

intergranular 

stress corrosion 

cracking 

Chapter XI.M9, 

“BWR Vessel 

Internals” for core 

plate, and Chapter 

XI.M2, “Water 

Chemistry” 

No Not used. The 

Fermi 2 vessel 

internals do not 

have X-750 alloy 

core plate 

components. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.1.1) 
3-226 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel piping, piping 

components, and 

piping element 

exposed to concrete 

(3.1.1-105) 

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 2) plant OE 

indicates no 

degradation of the 

concrete 

No, if 

conditions 

are met. 

Not used. No 

steel reactor 

coolant pressure 

boundary piping 

components are 

embedded in 

concrete. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.1.1) 

Nickel alloy piping, 

piping components, 

and piping element 

exposed to air – 

indoor, uncontrolled, 

or air with borated 

water leakage 

(3.1.1-106) 

None None NA – No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report” 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping element 

exposed to gas, 

concrete, air with 

borated water 

leakage, air – 

indoors, uncontrolled 

(3.1.1-107) 

None None NA – No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report” 

Consistent with the 

GALL Report 

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.1.1-108) 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.1.1-109) 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

Any material, piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-110) 

Wall thinning 

due to erosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Not used. Based 

on plant operating 

experience, 

components of the 

RCS are not 

susceptible to 

erosion. 

Not applicable to 

Fermi 2 (see SER 

Section 3.1.2.1.1) 

3.1.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the reactor vessel, reactor internals, and reactor coolant system 

components: 
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 Bolting Integrity 

 BWR CRD Return Line Nozzle 

 BWR Feedwater Nozzle 

 BWR Penetrations 

 BWR Stress Corrosion Cracking 

 BWR Vessel ID Attachment Welds 

 BWR Vessel Internals 

 Compressed Air Monitoring 

 External Surfaces Monitoring 

 Flow-Accelerated Corrosion 

 Inservice Inspection 

 Internal Surfaces in Miscellaneous Piping and Ducting Components 

 Oil Analysis 

 One-Time Inspection 

 One-Time Inspection – Small-Bore Piping 

 Periodic Surveillance and Preventive Maintenance 

 Reactor Head Closure Studs 

 Reactor Vessel Surveillance 

 Selective Leaching 

 Water Chemistry Control – BWR 

 Water Chemistry Control – Closed Treated Water Systems 

LRA Tables 3.1.2-1 through 3.1.2-4-3 summarize AMRs for the reactor vessel, reactor vessel 

internals, and RCS components and indicate AMRs claimed to be consistent with the GALL 

Report. 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components of these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR item. The notes describe how the information in 

the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions. 

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 

Note C indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 
3-228 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as the component under review. The staff audited 

these AMR items to confirm consistency with the GALL Report. The staff also determined 

whether the AMR item of the different component applied to the component under review and 

whether the AMR was valid for the site-specific conditions. 

Note D indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions. 

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, it did confirm that the material presented in the LRA 

was applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluation follows. 

 AMR Results Identified as Not Applicable or Not Used 

For LRA Table 3.1.1, items 3.1.1-28, 3.1.1-30, 3.1.1-32, 3.1.1-33, 3.1.1-34, 3.1.1-35, 3.1.1-36, 

3.1.1-37, 3.1.1-40, 3.1.1-40.5, 3.1.1-42, 3.1.1-44, 3.1.1-45, 3.1.1-46, 3.1.1-47, 3.1.1-48, 

3.1.1-49, 3.1.1-51a, 3.1.1-51b, 3.1.1-52a, 3.1.1-52b, 3.1.1-52c, 3.1.1-53a, 3.1.1-53b, 3.1.1-53c, 

3.1.1-54, 3.1.1-55a, 3.1.1-55b, 3.1.1-55c, 3.1.1-56a, 3.1.1-56b, 3.1.1-56c, 3.1.1-58a, 3.1.1-58b, 

3.1.1-59a, 3.1.1-59b, 3.1.1-59c, 3.1.1-61, 3.1.1-62, 3.1.1-64, 3.1.1-65, 3.1.1-66, 3.1.1-68, 

3.1.1-69, 3.1.1-70, 3.1.1-71, 3.1.1-72, 3.1.1-73, 3.1.1-74, 3.1.1-75, 3.1.1-76, 3.1.1-77, 3.1.1-78, 

3.1.1-80, 3.1.1-81,3.1.1-82, 3.1.1-83, 3.1.1-86, 3.1.1-87, 3.1.1-88, 3.1.1-89, 3.1.1-90, 3.1.1-92, 

and 3.1.1-93, the applicant claimed that the corresponding AMR items in the GALL Report are 

not applicable because the associated items are only applicable to pressurized water reactors 

(PWRs). The staff reviewed the SRP-LR; confirmed these items only apply to PWRs; and finds 

that these items are not applicable to Fermi 2, which is a BWR. 

For LRA Table 3.1.1, items 3.1.1-31, and 3.1.1-50, the applicant claimed that the corresponding 

items in the GALL Report are not applicable or are not used because the component, material, 

and environment combination described in the SRP-LR does not exist for in-scope SCs at 

Fermi 2 or because the component, material, and environment combination is addressed by 

another Table 1 item. The staff reviewed the LRA and UFSAR and confirmed that the 

applicant’s LRA does not have any AMR results applicable for these items or that the aging 

effects addressed by other Table 1 AMR line items are appropriate. 
3-229 

LRA Table 3.1.1, item 3.1.1-41, addresses nickel alloy core shroud and core plate access hole 

mechanical covers; the applicant’s design uses a welded cover that is represented by LRA 

Table 1 AMR item 3.1.1-29; therefore, item 3.1.1-41 is not applicable to Fermi 2. 

LRA Table 3.1.1, item 3.1.1-104, addresses X-750 alloy reactor vessel internal components 

exposed to reactor coolant and neutron flux. The GALL Report recommends GALL Report 

AMP XI.M9, “BWR Vessel Internals” for the core plate and GALL Report AMP XI.M2, “Water 

Chemistry” to manage cracking due to IGSCC for this component group. The applicant stated 

that this item is not used because Fermi 2 does not have X-750 alloy core plate components. 

The staff noted that LRA Table 3.1.2-2 contains reactor vessel internal components exposed to 

reactor coolant and neutron flux, such as certain jet pump assembly components. The staff 

noted that the applicant cited LRA Table 3.1.1, item 3.1.1-103, for these components. The staff 

evaluated the applicant’s claim and finds it acceptable because the applicant is using a more 

conservative LRA Table 3.1.1 line item to manage cracking of nickel alloy reactor vessel internal 

components, including those made from nickel alloy X-750 materials. LRA Table 3.1.1, 

item 3.1.1-103, is also being used to manage cracking in those reactor vessel internal 

components made from stainless steel materials. Therefore, it is acceptable to use LRA 

Table 3.1.1, item 3.1.1-103, in lieu of LRA Table 3.1.1, item 3.1.1-104. 

For LRA Table 3.1.1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable or are not used. However, the staff had to review 

sources beyond the LRA and UFSAR or to issue one or more RAIs, or both, in order to verify 

the applicant’s claim. 

LRA Table 3.1.1, item 3.1.1-96, addresses steel, with or without stainless steel cladding, CRD 

return line nozzles exposed to reactor coolant. The GALL Report recommends GALL Report 

AMP XI.M6, “BWR Control Rod Drive Return Line Nozzle,” to manage cracking due to cyclic 

loading for this component group. The applicant stated that this item is not applicable because 

the CRD return line was cut and capped before initial plant operation; therefore, the CRD return 

line nozzle has not been exposed to cyclic loading as a result of CRD return line operation. 

The staff evaluated the applicant’s claim that this item is not used. LRA Section B.1.5 states 

that the existing BWR CRD Return Line Nozzle Program is consistent with GALL Report 

AMP XI.M6; therefore, the scope of the BWR CRD Return Line Nozzle Program includes the 

CRD return line nozzle and its associated nozzle-to-vessel weld. However, given that the 

applicant did not use LRA Table 3.1.1, item 3.1.1-96, and the absence of other line items for 

these components in the LRA, the staff determined that the applicant had not sufficiently 

demonstrated that the effects of aging for these components will be adequately managed so 

that the intended function(s) will be maintained consistent with the CLB for the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

By letter dated December 23, 2014, the staff issued RAI 3.1.2.1-1 requesting that the applicant 

provide the AMR results for the CRD return line nozzle and its nozzle-to-vessel weld if these 

components are within the scope of the BWR CRD Return Line Nozzle Program. The staff also 

requested that the applicant describe how these AMR results compare with SRP-LR 

Table 3.1-1, item 96. If the CRD return line nozzle and its nozzle-to-vessel weld are not within 

the scope of the BWR CRD Return Line Nozzle Program, the staff requested that the applicant 

explain why LRA Section B.1.5 does not identify an exception to the “scope of program” 

program element of GALL Report AMP XI.M6. 
3-230 

In its response dated January 26, 2015, the applicant stated that all the components included in 

LRA Section B.1.5 were not identified as line items in LRA Table 3.1.2-1 for the CRD return line 

nozzle (N9). The applicant also stated that the CRD Return Line Nozzle Program includes the 

CRD return line nozzle, its nozzle-to-reactor-vessel weld, CRD return line nozzle Inconel cap, 

and cap-to-nozzle Inconel weld. The applicant further stated that it will revise LRA Table 3.1.2-1 

to include line items for the nozzle with the aging effect of cracking and for the nozzle weld with 

the aging effect of cracking and loss of material. The applicant further stated that Table 3.1.1, 

item 96, will be revised to indicate that the CRD Return Line Nozzle Program manages cracking 

for the nozzle, cap, and the associated welds. The applicant cited generic note I, for the 

components associated with LRA Table 3.1.1, item 3.1.1-96, and the CRD return line nozzle. 

Plant-specific note I states that the aging effect identified in GALL Report for this component, 

material, and environment combination is not applicable. The applicant stated that because the 

CRD return line was cut and capped before initial operation, the nozzle has not been thermally 

cycled due to operation of the return line. The applicant also stated that cracking due to cyclic 

loading is not applicable to its CRD return line nozzle. 

The staff finds the applicant’s response related to item 3.1.1-96 acceptable because the staff 

verified that the applicant’s CRD return line was capped before initial operations; therefore, the 

applicant’s determination that the CRD return line nozzle is not subject to cyclic loading is 

justified. In addition, the applicant addressed the applicable aging effects for the components 

associated with the CRD return line by revising LRA Table 3.1.1, item 3.1.1-97, as discussed 

below. 

The applicant stated that, because the material for the weld and the cap are nickel alloy, it will 

use Table 3.1.1, item 3.1.1-97, for these components. The applicant cited generic note E for 

item 3.1.1-97 and the associated CRD return line nickel alloy components. Plant-specific note E 

states that the material, environment, and aging effect identified is consistent with the GALL 

Report for this material and environment combination; however, a different AMP is credited. 

The applicant also stated that the BWR CRD Return Line Nozzle and Water Chemistry Control 

– BWR programs are credited to manage cracking due to SCC for the nickel alloy welds for this 

component. As a result, the applicant revised LRA Tables 2.3.1-1, 3.1.1, and 3.1.2-1, 

consistent with its response. 

The staff’s evaluations of the applicant’s BWR CRD Return Line Nozzle and Water Chemistry 

Control – BWR programs are documented in SER Sections 3.0.3.1.3 and 3.0.3.1.20, 

respectively. The staff noted that the BWR CRD Return Line Nozzle Program uses volumetric 

examinations which can detect SCC, whereas the Water Chemistry Control – BWR Program 

limits the concentrations of contaminants (e.g., chlorides and sulfates) known to cause SCC. 

Therefore, the staff finds the applicant’s proposal acceptable. In addition, the applicant clarified 

that all the components associated with the applicant’s CRD return line, nozzle, cap, and 

associated welds will be age managed by the applicant’s CRD Return Line Nozzle Program, 

consistent with the guidance provided in the GALL Report. Based on its review of the 

components associated with item 3.1.1-97 for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the BWR CRD Return Line Nozzle 

Program and Water Chemistry Control – BWR programs acceptable. The staff’s concern 

described in RAI 3.1.2.1-1 is resolved. 

By letter dated May 9, 2016, the applicant provided an annual update to the LRA. The annual 

update states that a more detailed review of the CRD return line welds has indicated that the 

nozzle-to-cap weld is nickel alloy but the nozzle-to-vessel weld is carbon steel. In its update, 
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the applicant revised LRA Table 3.1.1, item 3.1.1-96 and Table 3.1.2-1 to indicate that the two 

welds are different materials. In its revision, the applicant also indicated that cracking due to 

cyclic loading of the carbon steel nozzle-to-vessel weld will be managed by using LRA 

Table 3.1.1, item 3.1.1-96 and BWR CRD Return Line Nozzle Program, consistent with the 

aging management for the CRD return line nozzle that is also fabricated of carbon steel. In its 

review, the staff finds the applicant’s update acceptable because it provides a correction to the 

material of fabrication for the nozzle-to-vessel weld and the BWR CRD Return Line Nozzle 

Program, which includes volumetric examination, is sufficient to detect and manage cracking for 

CRD return line components for the period of extended operation. 

The staff concludes that for LRA item 3.1.1-97 and the components associated with the CRD 

return line, the applicant has demonstrated that the effects of aging for these components will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

LRA Table 3.1.1, item 3.1.1-105, addresses steel piping, piping components, and piping 

elements exposed to concrete. The GALL Report recommends no AERM or AMP if certain 

concrete attributes and plant-specific operating experience are met for this component group. 

The applicant stated that this item is not used because there are no steel RCPB piping 

components exposed to concrete. However, in reference to small-bore field run RCPB piping, 

UFSAR Section 5.2.1.19 states that “[h]ydrostatic testing, prior to erection, is required for any 

pipe spool that is embedded in concrete or installed in an inaccessible location.” Although the 

UFSAR does not state that steel piping is embedded in concrete, it was not clear to the staff 

whether an oversight had occurred during the development of the LRA. By letter dated 

December 19, 2014, the staff issued RAI 3.1.2.1.1-1 requesting that the applicant reconcile the 

statement associated with LRA Table 3.1.1, item 3.1.1-105, with UFSAR Section 5.2.1.19 and, if 

the RCPB is embedded in concrete, state how it will manage the applicable aging effects or 

provide the basis for why there are no aging effects. 

In its response dated January 28, 2015, the applicant stated that there is no RCPB piping 

embedded in concrete. The applicant also stated that the UFSAR statement is a general 

specification. 

The staff finds the applicant’s response acceptable because the applicant confirmed that none 

of its RCPB piping is embedded in concrete; therefore, it is appropriate to cite LRA Table 3.1.1, 

item 3.1.1-105, as not used. The staff’s concern described in RAI 3.1.2.1.1-1 is resolved. 

LRA Table 3.1.1, item 3.1.1-110, addresses piping, piping components, and piping elements 

made from any material exposed to reactor coolant. The GALL Report recommends 

AMP XI.M17, “Flow-Accelerated Corrosion” to manage wall thinning due to erosion for this 

component group. The LRA states that this item was not used because, based on plant 

operating experience, components within the RCS are not susceptible to erosion. The staff 

notes that, as discussed in the Audit Report, the staff conducted an independent search of plant 

operating experience information using keywords associated with various erosion mechanisms. 

Based on its review, the staff finds the applicant’s claim acceptable because it also did not 

identify any issues due to erosion within the RCS during its independent search of the plant 

operating experience information. 
3-232 

 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.1.1, item 3.1.1-43, addresses stainless steel and nickel alloy reactor vessel 

internals exposed to reactor coolant, which will be managed for loss of material due to pitting 

and crevice corrosion. For the AMR items that cite generic note E, the LRA credits the Water 

Chemistry Control – BWR Program to manage the aging effect. The AMR items cite 

plant-specific note 101, which states that the effectiveness of the Water Chemistry Control – 

BWR Program will be verified using the One-Time Inspection Program. The GALL Report 

recommends GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, IWB, IWC, and 

IWD,” and GALL Report AMP XI.M2, “Water Chemistry,” to ensure that this aging effect is 

adequately managed. 

GALL Report AMP XI.M1 recommends using periodic visual, surface, and/or volumetric 

examination and leakage testing along with GALL Report AMP XI.M2, which recommends 

monitoring and controlling known detrimental contaminants in accordance with the 

recommendations of BWRVIP-190 to manage the aging of this line item. The One-Time 

Inspection Program, consistent with GALL Report AMP XI.M32, “One-Time Inspection,” is 

substituted for GALL Report AMP XI.M1. The One-Time Inspection Program is used to 

(a) verify the effectiveness of the Water Chemistry Control – BWR Program by confirming that 

unacceptable loss of material is not occurring with visual and/or equivalent volumetric 

examination and (b) provide additional actions to maintain the intended functions of applicable 

components throughout the period of extended operation. 

The staff’s evaluation of the applicant’s Water Chemistry Control – BWR Program and 

One-Time Inspection Program are documented in SER Sections 3.0.3.1.20 and 3.0.3.1.17, 

respectively. 

Based on its review of components associated with item 3.1.1-43, for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

Water Chemistry Control – BWR Program and One-Time Inspection Program acceptable 

because (a) the applicant’s use of the Water Chemistry Control – BWR Program will ensure that 

the environment will not be conducive for loss of material to occur and is consistent with the 

recommendations in the GALL Report and (b) the One-Time Inspection Program will provide 

visual and/or equivalent volumetric examination to verify that unacceptable loss of material is 

not occurring and may trigger additional actions that ensure that the intended functions of the 

affected components are maintained throughout the period of extended operation. 

The staff concludes that, for LRA item 3.1.1-43, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 

 Cracking Due to Stress Corrosion Cracking (SCC) and Intergranular Stress 

Corrosion Cracking (IGSCC) 

LRA Table 3.1.1, item 3.1.1-97 addresses stainless steel and nickel alloy piping, piping 

components, and piping elements greater than or equal to 4 NPS and reactor vessel nozzle 

safe ends and associated welds exposed to reactor coolant, which will be managed for cracking 

due to SCC (including IGSCC). The GALL Report recommends GALL Report AMP XI.M7, 

“BWR Stress Corrosion Cracking,” and GALL Report AMP XI.M2, “Water Chemistry” to ensure 

that the aging effect is adequately managed for these components. GALL Report AMP XI.M7 
3-233 

conducts volumetric examination on BWR piping and piping welds to detect and manage 

cracking due to IGSCC. GALL Report AMP XI.M2 performs water chemistry control to manage 

aging by limiting the concentrations of chemical species known to cause cracking due to SCC. 

The applicant cited generic note E for the nickel alloy CRD return line cap. The applicant also 

stated that the BWR CRD Return Line Nozzle Program and Water Chemistry Control – BWR 

Program are credited to manage cracking due to SCC for this component. 

The staff’s evaluations of the applicant’s BWR CRD Return Line Nozzle Program and Water 

Chemistry Control – BWR Program are documented in SER Sections 3.0.3.1.3 and 3.0.3.1.20, 

respectively. In addition, the staff’s evaluation of LRA Table 3.1.1, item 3.1.1-97 as it relates to 

CRD return line nickel alloy components is documented in SER Section 3.1.2.1.1. 

The applicant also cited generic note E for the following components, which are managed by the 

Inservice Inspection Program and Water Chemistry Control – BWR Program: (a) reactor vessel 

beltline shell rings and nonbeltline components (i.e., nonbeltline top head and closure flange, 

shell rings and closure flange, and bottom head) made of carbon steel clad with stainless steel, 

(b) thermowell, orifice, and reactor recirculating pump cooler assembly made of stainless steel, 

and (c) valve bodies less than 4 inch NPS made of stainless steel or cast austenitic stainless 

steel. 

The staff’s evaluations of the applicant’s Inservice Inspection Program and Water Chemistry 

Control – BWR Program are documented in SER Sections 3.0.3.1.10 and 3.0.3.1.20, 

respectively. The staff noted that the Inservice Inspection Program proposes to manage the 

effects of aging for these components through the use of volumetric, surface, and visual 

examinations. The staff also noted that the Water Chemistry Control – BWR Program proposes 

to manage the effects of aging for these components through the use of water chemistry control. 

Based on its review of these components associated with item 3.1.1-97, for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging using the Inservice 

Inspection Program and Water Chemistry Control – BWR Program acceptable because the 

Inservice Inspection Program uses NDEs in accordance with the ASME Code requirements and 

10 CFR 50.55a, which can detect and manage SCC, and the Water Chemistry Control – BWR 

Program limits the concentrations of chemical species known to cause SCC to minimize the 

environmental effect on SCC. 

By letter dated January 5, 2015, the applicant revised LRA Tables 3.4.2-2 and 3.4.2-3-2 to 

include AMR items that manage cracking due to SCC for feedwater heater nozzle-to-safe-end 

and safe-end-to-pipe welds made of stainless steel and nickel alloy, as documented in SER 

Section 3.0.3.1.6. The applicant indicated that these welds are GL 88-01 Category D welds in 

the feedwater and condensate systems. The applicant also stated that these AMR items are 

associated with LRA item 3.1.1-97, and generic note D is cited for these welds. In addition, the 

applicant stated that cracking due to SCC will be managed by using the BWR Stress Corrosion 

Cracking Program and Water Chemistry Control – BWR Program. The staff finds the 

applicant’s revisions to LRA Tables 3.4.2-2 and 3.4.2-3-2 acceptable, as documented in 

Section 3.0.3.1.6. 

The staff’s evaluations of the applicant’s BWR Stress Corrosion Cracking Program and Water 

Chemistry Control – BWR Program are documented in SER Sections 3.0.3.1.6 and 3.0.3.1.20, 

respectively. The staff noted that the BWR Stress Corrosion Cracking Program proposes to 

manage the effects of aging for these components through the use of volumetric examinations. 

As discussed above, the staff noted that the Water Chemistry Control – BWR Program 
3-234 

proposes to manage the effects of aging for these components through the use of water 

chemistry control. Based on its review of these components associated with item 3.1.1-97, for 

which the applicant cited generic note D, the staff finds the applicant’s proposal to manage 

aging using the BWR Stress Corrosion Cracking Program and Water Chemistry Control – BWR 

Program acceptable because the BWR Stress Corrosion Cracking Program performs periodic 

volumetric examinations, which can effectively detect and manage SCC, and the Water 

Chemistry Control – BWR Program limits the concentrations of chemical species known to 

cause SCC to minimize the environmental effect on SCC. 

The staff concludes that for LRA item 3.1.1-97 the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking 

LRA Table 3.1.1, item 3.1.1-103, addresses stainless steel and nickel alloy reactor internal 

components exposed to reactor coolant and neutron flux, which will be managed for cracking. 

The GALL Report recommends GALL Report AMP XI.M9, “BWR Vessel Internals,” and GALL 

Report AMP XI.M2, “Water Chemistry,” to ensure that this aging effect is adequately managed. 

During its review of components associated with item 3.1.1-103, for which the applicant cited 

generic note A, the staff noted that the LRA credits the BWR Vessel Internals Program and 

Water Chemistry Control – BWR Program to manage cracking that may occur in the jet pump 

assembly: slip joint clamp adjustable bolt and ratchet lock spring. However, the staff was 

unclear whether the jet pump assembly—slip joint clamp adjustable bolt and ratchet lock 

spring—is within the inspection strategy of the BWRVIP reports that are recommended by the 

GALL Report for inspection of the jet pump assembly. Specifically, the staff could not confirm 

which section or table in the BWRVIP-41, “BWR Jet Pump Assembly Inspection and Flaw 

Evaluation Guidelines,” dated September 2005, recommends inspections of these components. 

By letter dated December 23, 2014, the staff issued RAI 3.1.2.3.2-3, requesting that the 

applicant clarify which inspection methods are used for these components. By letter dated 

February 5, 2015, the applicant responded, stating that these components are inspected in 

accordance with BWRVIP-51-A, “Jet Pump Repair Design Criteria,” dated September 2005. 

The staff finds the applicant’s response acceptable because the applicant has identified that 

another BWRVIP report, BWRVIP-51-A, is implemented to inspect these components and 

because the BWRVIP-51-A report is endorsed by the NRC. The staff’s concern identified in 

RAI 3.1.2.3.2-3 is resolved. 

The staff concludes that, for LRA item 3.1.1-103, the applicant has demonstrated that the 

effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended 

In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the reactor vessel, reactor vessel internals, and RCS components and 

provides information concerning how it will manage the following aging effects: 
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 cumulative fatigue damage 

 loss of material due to general, pitting, and crevice corrosion 

 loss of fracture toughness due to neutron irradiation embrittlement 

 cracking due to stress corrosion cracking (SCC) and intergranular stress corrosion 

cracking (IGSCC) 

 crack growth due to cyclic loading – PWRs only 

 cracking due to SCC – PWRs only 

 cracking due to cyclic loading – for BWR with isolation condenser components 

 loss of material due to erosion – PWRs only 

 cracking due to primary water SCC (PWSCC) – PWRs only 

 QA for aging management of nonsafety-related components 

 ongoing review of operating experience 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

reviewed the applicant’s evaluation to determine whether it adequately addressed the issues 

further evaluated. In addition, the staff reviewed the applicant’s further evaluations against the 

criteria contained in SRP-LR Section 3.1.2.2. The staff’s review of the applicant’s further 

evaluation follows. 

 Cumulative Fatigue Damage 

LRA Section 3.1.2.2.1 is associated with LRA Table 3.1.1, item 3.1.1-1 through 3.1.1-11, and 

addresses the applicant’s AMR for managing cumulative fatigue damage in the reactor vessel, 

reactor vessel internals, and RCPB. The applicant addressed the further evaluation criteria of 

the SRP-LR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3, “Definitions,” and is 

evaluated in accordance with 10 CFR 54.21(c). The applicant stated that its evaluation of the 

TLAA is addressed in LRA Sections 4.3.1. 

The applicant stated that, items 3.1.1-2, 3.1.1-5, 3.1.1-8, 3.1.1-9, and 3.1.1-10 in LRA 

Table 3.1.1 are not applicable because they only apply to PWRs. SRP-LR Table 3.1-1 identifies 

these items as being applicable to PWRs only. The staff evaluated the applicant’s claim and 

finds it acceptable because the applicant’s facility is not a PWR. 

The staff reviewed LRA Section 3.1.2.2.1, items 3.1.1-1, 3.1.1-3, 3.1.1-4, 3.1.1-6, 3.1.1-7, 

and 3.1.1-11, against the criteria in SRP-LR Section 3.1.2.2.1, which state that cumulative 

fatigue damage is a TLAA and must be evaluated in accordance with the TLAA acceptance 

criteria requirements of 10 CFR 54.21(c). The staff reviewed these AMR line items and 

determined that the AMR results are consistent with the recommendations of the GALL Report 

and SRP-LR for managing cumulative fatigue damage. 

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.1.2.2.1 criteria. For those line items that apply to LRA Section 3.1.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 
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as required by 10 CFR 54.21(a)(3). SER Section 4.3.1 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components. 

 Loss of Material Due to General, Pitting, and Crevice Corrosion 

The staff reviewed LRA Section 3.1.2.2.2 against the following two criteria in SRP-LR 

Section 3.1.2.2.2: 

(1) LRA Section 3.1.2.2.2, item 1, associated with LRA Table 3.1.1, item 3.1.1-12, 

addresses loss of material caused by general, pitting, and crevice corrosion in steel 

PWR steam generator components exposed to secondary feedwater and steam. The 

applicant stated that this item is not applicable because the associated item in LRA 

Table 3.1.1 is applicable to PWRs only. The staff confirmed that the item is applicable 

only to PWRs and noted that the applicant’s unit is a BWR design and does not have 

steam generators; therefore, the staff finds it acceptable. 

(2) LRA Section 3.1.2.2.2, item 2, associated with LRA Table 3.1.1, item 3.1.1-12, 

addresses loss of material caused by general, pitting, and crevice corrosion in steel 

PWR steam generator components exposed to secondary feedwater and steam. The 

applicant stated that this item is not applicable because the associated item in LRA 

Table 3.1.1 is applicable to PWRs only. The staff confirmed that the item is applicable 

only to PWRs and noted that the applicant’s unit is a BWR design and does not have 

steam generators; therefore, the staff finds it acceptable. 

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.2 criteria do not apply. 

 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement 

The staff reviewed LRA Section 3.1.2.2.3 against the following two criteria in SRP-LR 

Section 3.1.2.2.3: 

(1) The staff reviewed LRA Section 3.1.2.2.3, item 1, which is associated with LRA 

Table 3.1.1, item 3.1.1-13. For components associated with item 3.1.1-13, the LRA 

states that neutron irradiation embrittlement is a TLAA evaluated in accordance with 

10 CFR 54.21(c). The LRA further states that the applicant’s evaluation of loss of 

fracture toughness for the reactor vessel beltline shell and welds is discussed in LRA 

Section 4.2. The staff’s evaluation of the TLAA associated with LRA Table 3.1.1, 

item 3.1.1-13, is documented in SER Section 4.2. 

(2) LRA Section 3.1.2.2.3, item 2, associated with LRA Table 3.1.1, item 3.1.1-14, 

addresses steel (with or without stainless steel cladding) reactor vessel beltline shell, 

nozzles, and welds exposed to a reactor coolant and neutron flux environment, which 

will be managed by the Reactor Vessel Surveillance Program. The applicant stated that 

the Reactor Vessel Surveillance Program (LRA AMP B.1.38) uses the BWRVIP ISP to 

manage reduction in fracture toughness due to neutron embrittlement that may occur in 

reactor vessel beltline components that are made from ferritic steel materials. The 

applicant stated that this AMP is consistent with the program described in GALL Report 

AMP XI.M31, “Reactor Vessel Surveillance.” 

The applicable “acceptance criteria” are given in SRP-LR Section 3.1.2.2.3, item 2, 

which states that the AMP is used to monitor for the amount of neutron irradiation 

embrittlement that is occurring in the reactor vessel. For BWRs like Fermi 2, the AMP is 

based on the requirements for ISPs in Appendix H to 10 CFR Part 50. The relevant 
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AMR items are given in SRP-LR Table 3.1-1, AMR item 14, and GALL 

Report, AMR item IV.A1.RP-227. 

The staff reviewed the applicant’s AMR basis for consistency with recommendations in 

SRP-LR Section 3.1.2.2.3, item 2; AMR item 14 in SRP-LR Table 3.1-1; and AMR 

item IV.A1.RP-227. The staff verified that the applicant included the applicable AMR 

items for the reactor vessel beltline components (including those for the N-16 

instrumentation nozzles) in LRA Table 3.1-1 and the applicable AMP in LRA 

Section B.1.38, “Reactor Vessel Surveillance.” The staff also noted that the applicant 

uses that AMP to manage loss of fracture toughness due to neutron irradiation 

embrittlement in these components consistent with the ISP that is documented in the 

BWRVIP-86, Revision 1-A, report. The staff verified that this ISP report was approved 

by the NRC in a safety evaluation dated October 20, 2011 (ADAMS Accession 

No. ML13176A097) and that the ISP complies with the requirements for ISPs in 

Appendix H to 10 CFR Part 50. Therefore, based on this review, the staff finds the 

applicant’s basis to be acceptable because it is consistent with the criteria in SRP-LR 

Section 3.1.2.2.3, item 2, and in GALL Report AMR item IV.A1.RP-227. 

The staff’s evaluation of the Reactor Vessel Surveillance Program is documented in 

SER Section 3.0.3.2.19. 

(3) LRA Section 3.1.2.2.3, item 3, associated with LRA Table 3.1.1, item 3.1.1-15, 

addresses a potential plant-specific TLAA for managing loss of ductility properties in 

stainless steel and nickel alloy reactor vessel internal components that are exposed to a 

reactor coolant and neutron flux environment. The applicant stated that the aging 

management topic in SRP-LR Section 3.1.2.2.3, item 3, is not applicable to the CLB for 

Fermi 2 because it only applies to PWR reactor vessel internal components designed by 

the Babcock and Wilcox Company. The applicant explained that GE designed the 

reactor vessel internal components at Fermi 2. 

The applicable “acceptance criteria” are given in SRP-LR Section 3.1.2.2.3, item 3, 

which states that the applicable ductility of reduction analysis is given Technical Report 

(TR) BAW-2248-A, “Demonstration of the Management of Aging Effects for the Reactor 

Vessel Internals.” This report was approved by the NRC in a safety evaluation dated 

December 9, 1999 (ADAMS Accession No. ML993490288). 

The staff noted that the UFSAR identifies that the nuclear steam supply system 

components (which include the reactor vessel internal components) for Fermi 2 were 

designed and furnished by GE. Therefore, the staff finds that TR-BAW-2248-A and the 

recommendations in SRP-LR Section 3.1.2.2.3, item 3, are not applicable to Fermi 2 

because the staff has confirmed that the reactor vessel internal components were not 

designed by Babcock and Wilcox Company. Instead, the staff has verified that the 

applicant will manage the aging effects that are applicable to the reactor vessel internal 

components through implementation of its BWR Vessel Internals Program 

(LRA AMP B.1.10). The staff’s evaluation of the BWR Vessel Internals Program is 

documented in SER Section 3.0.3.2.3. 

 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking 

The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR 

Section 3.1.2.2.4: 
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(1) LRA Section 3.1.2.2.4.1, associated with LRA item 3.1.1-16, addresses stainless steel 

reactor vessel closure head flange leak detection line piping exposed to treated water 

greater than 140 °F, which will be managed for cracking due to SCC and IGSCC by the 

Water Chemistry Control – BWR Program and One-Time Inspection Program. The 

acceptance criteria in SRP-LR Section 3.1.2.2.4.1 state that cracking due to SCC and 

IGSCC could occur in the stainless steel and nickel alloy BWR top head enclosure 

vessel flange leak detection lines. The GALL Report recommends that a plant-specific 

AMP be evaluated because existing programs may not be capable of mitigating or 

detecting cracking due to SCC and IGSCC. 

The LRA states that the Water Chemistry Control – BWR Program minimizes 

contaminants that promote SCC. The LRA also indicates that the One-Time Inspection 

Program will perform NDEs to verify the absence of significant cracking of the leak 

detection line. 

The staff’s evaluations of the applicant’s Water Chemistry Control – BWR Program and 

One-Time Inspection Program are documented in SER Sections 3.0.3.1.20 and 

3.0.3.1.17, respectively. In its review of components associated with LRA item 3.1.1-16, 

the staff finds that the applicant has met the further evaluation criteria and that its 

proposal to manage the effects of aging using these programs is acceptable because 

the Water Chemistry Control – BWR Program minimizes chemical species known to 

cause SCC (e.g., sulfur and chloride) and because the One-Time Inspection Program 

confirms the effectiveness of the water chemistry control to mitigate SCC. 

Based on the programs identified, the staff determines that the applicant’s programs and 

aging management evaluation meet the criteria in SRP-LR Section 3.1.2.2.4.1. For 

those items associated with LRA Section 3.1.2.2.4.1, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required 

by 10 CFR 54.21(a)(3). 

(2) LRA Section 3.1.2.2.4, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-17, 

addresses SCC and IGSCC for stainless steel BWR isolation condenser components 

exposed to reactor coolant. The applicant stated that this item is not used because 

Fermi 2 does not have an isolation condenser. The staff reviewed the applicant’s 

UFSAR and confirmed that the design of the applicant’s unit does not include an 

isolation condenser; therefore, the staff finds the applicant’s review result acceptable. 

 Crack Growth Due to Cyclic Loading 

LRA Section 3.1.2.2.5, associated with LRA Table 3.1.1, item 3.1.1-18, addresses crack 

initiation and growth in PWR reactor vessel forging components that are made from SA-508, 

Class 2, ferritic steel materials and are clad with stainless steel on their inside surfaces, where 

the cladding is exposed to a reactor coolant environment. SRP-SLR Section 3.1.2.2.5 identifies 

that a PWR may include a flaw growth analysis of intergranular separations (underclad 

cracking) occurring in the stainless steel cladding of reactor vessel forging components made 

from SA-508, Class 2, ferritic steel materials, where the cladding was welded to the forgings by 

use of a high heat input welding process. The SRP-SLR also identifies that this type of analysis 

qualifies as a TLAA for the LRA if the analysis conforms to all six of the criteria for defining 

TLAAs in 10 CFR 54.3(a). 
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The applicant stated that these AMR recommendations are not applicable to Fermi 2 because 

Fermi 2 is a BWR and the guidelines in SRP-LR Section 3.1.2.2.5 are only applicable to 

PWR-designed reactor vessels. The staff confirmed that this item is associated only with PWRs 

and, therefore, finds the applicant’s claim acceptable. 

 Cracking Due to Stress Corrosion Cracking 

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6: 

(1) LRA Section 3.1.2.2.6, item 1, associated with LRA Table 3.1.1, item 3.1.1-19, 

addresses cracking caused by SCC in PWR stainless steel reactor vessel flange leak 

detection lines and bottom-mounted instrument guide tubes exposed to reactor coolant. 

The applicant stated that this item is not applicable because the associated item in LRA 

Table 3.1.1 is applicable to PWRs only. The staff confirmed that this item is associated 

only with PWRs and, therefore, finds the applicant’s claim acceptable. 

(2) SRP-LR Section 3.1.2.2.6, item 2, associated with LRA Table 3.1.1, item 3.1.1-20, 

addresses cracking due to SCC that could occur in Class 1 PWR CASS RCS piping and 

piping components. In its review, the staff finds that this item is not applicable because 

the applicant’s plant is a BWR. 

 Cracking Due to Cyclic Loading 

LRA Section 3.1.2.2.7, which is associated with LRA Table 3.1.1, item 3.1.1-21, addresses 

cracking due to cyclic loading for steel and stainless steel BWR isolation condenser 

components exposed to reactor coolant. The applicant stated that this item is not used because 

Fermi 2 does not have an isolation condenser. The staff reviewed the applicant’s UFSAR and 

confirmed that the design of the applicant’s unit does not include an isolation condenser; 

therefore, the staff finds the applicant’s review result acceptable. 

 Loss of Material Due to Erosion 

LRA Section 3.1.2.2.8, associated with LRA Table 3.1.1 item 3.1.1-22, addresses steel steam 

generator feedwater impingement plates and supports exposed to secondary feedwater, which 

will be managed for loss of material due to erosion. The criteria in SRP-LR Section 3.1.2.2.8 

states that the GALL Report recommends further evaluation of a plant-specific AMP to manage 

loss of material due to erosion in these material/component combinations. 

The applicant addressed the further evaluation criteria of the SRP-LR by stating that LRA 

Section 3.1.2.2.8, associated with item 3.1.1-22, is applicable to PWRs only, and is therefore 

not applicable to Fermi 2. The staff confirmed that the item is applicable only to PWRs and 

noted that the applicant’s unit is a BWR design and does not have steam generators; therefore, 

the staff finds it acceptable. 
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 This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04, “Updated Aging Management Criteria for Reactor Vessel Internal 

Components for Pressurized Water Reactors,” dated June 3, 2013. 

 This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04. 

 Cracking Due to Primary Water Stress Corrosion Cracking 

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11. 

(1) LRA Section 3.1.2.2.11, item 1, associated with LRA Table 3.1.1, item 3.1.1-25, 

addresses foreign operating experience in steam generators with a similar design to that 

of the Westinghouse Electric Company Model 51, which has identified extensive 

cracking caused by PWSCC in steam generator divider plate assemblies fabricated of 

Alloy 600 and/or the associated Alloy 600 weld materials, even with proper primary 

water chemistry (EPRI TR-1014982, “Divider Plate Cracking in Steam Generators,” 

dated June 2007). The applicant stated that this item is not applicable because the 

associated item in LRA Table 3.1.1 is applicable to PWRs only. The staff confirmed that 

this item is associated only with PWRs and, therefore, finds the applicant’s claim 

acceptable. 

(2) LRA Section 3.1.2.2.11, item 2, associated with LRA Table 3.1.1, item 3.1.1-25, 

addresses cracking caused by PWSCC that could occur in steam generator nickel alloy 

tube-to-tube sheet welds exposed to reactor coolant. The applicant stated that this item 

is not applicable because the associated item in LRA Table 3.1.1 is applicable to PWRs 

only. The staff confirmed that this item is associated only with PWRs and, therefore, 

finds the applicant’s claim acceptable. 

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.11 criteria do not apply. 

 This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04. 

 This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04. 

 This paragraph for further evaluation from the SRP-LR was removed by 

LR-ISG-2011-04. 

 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

 Ongoing Review of Operating Experience 

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience for AMPs. 
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3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.1.2-1 through 3.1.2-4-3, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with, or not addressed 

in, the GALL Report. 

In LRA Tables 3.1.2-1 through 3.1.2-4-3, the applicant indicated, through notes F through J, that 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections. 

 Reactor Vessel – Summary of Aging Management Evaluation – LRA Table 3.1.2-1 

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the 

reactor vessel component groups. 

Carbon Steel Reactor Vessel Support Skirt Exposed to Indoor Air. In LRA Table 3.1.2-1, the 

applicant stated that the carbon steel reactor vessel support skirt exposed to indoor air will be 

managed for loss of material by the Inservice Inspection (ISI) Program. The AMR line item cites 

generic note H. 

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that steel pressure vessel support skirt and attachment welds exposed to indoor air 

(exterior) are susceptible to cracking due to fatigue and recommends treating this aging effect 

as a TLAA for the period of extended operation. However, the applicant has identified loss of 

material as an additional aging effect. The applicant addressed the GALL Report identified 

cracking due to fatigue for this component, material, and environment combination in another 

AMR item in LRA Table 3.1.2-1. 

The staff’s evaluations of the ISI Program and TLAAs are documented in SER 

Sections 3.0.3.1.10 and 4.2, respectively. The staff finds the applicant’s proposal to manage 

the effects of aging using the ISI Program acceptable because the ISI Program manages loss of 

material for the reactor vessel support skirt through a combination of visual and surface 

examinations in accordance with ASME Code Section XI, Subsection IWA. 

Steel Reactor Vessel Nozzles, Piping, and Piping Components Exposed to External Indoor Air. 

In LRA Tables 3.1.2-1 and 3.1.2-3, the applicant stated that, for steel reactor vessel nozzles, 

safe ends, piping, piping components, and portions of the reactor vessel and closure heads 
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exposed to external indoor air, aging effects are not applicable and that no AMP is proposed. 

The AMR items cite generic note G. The AMR items cite plant-specific note 102, which states 

that “[h]igh component surface temperature precludes moisture accumulation that could result in 

corrosion.” 

The components in LRA Table 3.1.2-1 are associated with reactor vessel nozzles, safe ends, 

and blind flanges in the direct vicinity of the reactor and the reactor vessel and closure heads 

and are, therefore, exposed to reactor coolant temperatures during operating and shutdown 

conditions. Each component in LRA Table 3.1.2-3 is also managed by the External Surfaces 

Monitoring of Mechanical Components Program for loss of material, citing LRA Table 3.2.1, 

“Summary of Aging Management Programs for Engineered Safety Features Evaluated in 

Chapter V of NUREG-1801,” item 3.2.1-40. The staff reviewed the associated items in the LRA 

to confirm that no credible aging effects are applicable for these component, material, and 

environment combinations. The staff finds the applicant’s proposal acceptable because 

(a) based on its review of GALL Report, items AP-4 and SP-1, there are no AERMs and no 

recommended AMP for dry surfaces of steel components exposed to indoor air and (b) with the 

exception of the components that will also be managed by the External Surfaces Monitoring of 

Mechanical Components Program, the surface of the cited components would be expected to 

be dry (i.e., above the dewpoint) during both operating and shutdown conditions. 

On the basis of its review, the staff concludes that for items in LRA Table 3.1.2-1 with no 

AERMs, the applicant has appropriately evaluated the material and environment combinations 

not addressed in the GALL Report, and their intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). The 

staff also concludes for items in this table with an AERM, that the applicant has demonstrated 

that the effects of aging for these items will be adequately managed so that their intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Reactor Vessel Internals – Summary of Aging Management Evaluation – LRA 

Table 3.1.2-2 

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the 

reactor vessel internals component groups. 

Nickel Alloy (Alloy X-750) Jet Pump Assembly: Restrainer Bracket and Auxiliary Spring Wedge 

Assembly Exposed to Treated Water. In LRA Table 3.1.2-2, the applicant stated that the nickel 

alloy (Alloy X-750) jet pump assembly – restrainer bracket and auxiliary spring wedge assembly 

components exposed to treated water (ext) – will be managed for loss of material due to wear 

by the BWR Vessel Internals Program. The AMR item cites generic note F. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The staff noted that the applicant addressed cracking, loss of 

material, and reduction of fracture toughness for this component, material, and environment 

combination. These are also included as other AMR items in LRA Table 3.1.2-2. Based on its 

review of the GALL Report, which states that reactor vessel internals components exposed to 

reactor coolant and neutron flux should be managed for cracking and loss of fracture toughness, 

the staff finds that the applicant has identified all credible aging effects for this component, 

material, and environment combination. 
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The staff noted that the BWR Vessel Internals Program calls for specific inspection techniques 

to be performed on these components in accordance with the inspection and evaluation 

methodology in BWRVIP-41. This report demonstrates that the specific types of inspection 

techniques performed on the components are also capable of detecting loss of material that 

may occur in the steam dryer assembly components. This is consistent with inspection criteria 

for the equivalent types of inspection techniques cited by ASME Code Section XI. Therefore, 

the staff finds that the BWR Vessel Internals Program is an acceptable program for managing 

loss of material that may occur in these components as well because the inspection techniques 

are consistent with the NRC-endorsed methodology in BWRVIP-41 and visual inspection criteria 

specified in the ASME Code Section XI. The staff’s evaluation of the applicant’s BWR Vessel 

Internals Program is documented in SER Section 3.0.3.2.3. 

Stainless Steel Core Support Plate Rim Hold-Down Bolts Exposed to Treated Water Greater 

Than 140 °F (ext). In LRA Table 3.1.2-2, the applicant stated that stainless steel core support 

plate rim hold-down bolts exposed to treated water greater than 140 °F will be managed for loss 

of preload by the BWR Vessel Internals Program. The AMR item cites generic note H. The 

staff noted that this material and environment combination is identified in the GALL Report, 

which states that stainless steel reactor vessel internals components exposed to reactor coolant 

are susceptible to loss of material and recommends GALL Report AMP XI.M1, “ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD,” and GALL Report 

AMP XI.M2, “Water Chemistry,” to manage the aging effect. However, the applicant has 

identified loss of preload as an additional aging effect. The applicant addressed the GALL 

Report-identified aging effects for this component, material, and environment combination in 

other AMR items in LRA Table 3.1.2-2. 

The staff’s evaluation of the applicant’s BWR Vessel Internals Program is documented in SER 

Section 3.0.3.2.3. The staff finds the applicant’s proposal to manage loss of preload using the 

BWR Vessel Internals Program acceptable because the program will inspect the core plate 

components in accordance with BWRVIP-25 and BWRVIP-50-A, which are endorsed by the 

NRC. 

Stainless Steel Steam Dryer Exposed to Treated Water Greater Than 140 °F (ext). In LRA 

Table 3.1.2-2, the applicant stated that stainless steel steam dryer exposed to treated water 

greater than 140 °F will be managed for cracking by a combination of the BWR Vessel Internals 

Program and the Water Chemistry Control – BWR Program. For the use of the BWR Vessel 

Internals Program, the AMR item cites generic note A. For the use of the Water Chemistry 

Control – BWR Program, the AMR item cites generic note H and plant-specific note 104, which 

states that SCC of the steam dryer is not identified as an aging mechanism in the GALL Report. 

The staff noted that SCC is not identified in the GALL Report for this MEAP combination and 

that GALL Report, AMR item IV.B1.RP-155, instead identifies that the steam dryer assembly 

components are only susceptible to cracking induced by a flow-induced vibration mechanism. 

However, the staff noted that this AMR item does recommend GALL Report AMP XI.M9, “BWR 

Vessel Internals,” to manage the aging effect of cracking in the steam dryer assembly 

components. The staff noted that the applicant has conservatively identified SCC as an 

additional aging effect mechanism that is applicable to these components and that the Water 

Chemistry Control – BWR Program will be used as an additional AMP, in addition to the BWR 

Vessel Internals Program, for managing cracking that is induced by a SCC mechanism. The 

staff finds this to be acceptable because it is consistent with other AMR items in GALL Report 

Section IV for managing cracking due to SCC in stainless steel or nickel alloy components. 
3-244 

The staff noted that the BWR Vessel Internals Program calls for specific inspection techniques 

to be performed on these components in accordance with inspection and evaluation 

methodology in BWRVIP-139-A. This report includes specific inspection techniques to be 

performed that are capable of detecting and resolving cracks that may be initiated by vibrational 

fatigue or SCC mechanism. The staff noted that BWRVIP-139-A also demonstrates that the 

specific types of inspection techniques performed on the components are also capable of 

detecting loss of material that may occur in the steam dryer assembly components. This is 

consistent with inspection criteria for the equivalent types of inspection techniques cited by 

ASME Code Section XI, Subsection IWA. Therefore, the staff finds that the BWR Vessels 

Internals Program is an acceptable program for managing not only cracking in the steam dryer 

assembly components but also loss of material that may occur in these components as well 

because the inspection techniques are consistent with the NRC-endorsed methodology in 

BWRVIP-139-A and visual inspection criteria specified in the ASME Code Section XI. 

The staff’s evaluation of the BWR Vessel Internals Program is documented in SER 

Section 3.0.3.2.3. The staff’s evaluation of the applicant’s Water Chemistry Control – BWR 

Program is documented in SER Section 3.0.3.1.20. 

Jet Pump Assembly Auxiliary Spring Wedge Assemblies and Slip Joint Clamp Adjustable Bolt 

and Ratchet Lock Spring Exposed to Treated Water (ext) and Neutron Fluence. LRA 

Section 4.7.3 discusses the applicant’s plant-specific TLAA to evaluate the relaxation of preload 

of the auxiliary spring wedges in the jet pump assembly due to irradiation-assisted stress 

relaxation or creep. The applicant dispositioned TLAA 4.7.3 in accordance with 

10 CFR 54.21(c)(1)(ii). However, the staff noted that LRA Table 3.1.2-2 does not include any 

applicable AMR items for managing loss of preload of the jet pump auxiliary spring wedge 

assembly. By letter dated December 23, 2014, the staff issued RAI 3.1.2.3.2-2, requesting that 

the applicant justify why the LRA did not include any applicable AMR line items. 

By letter dated February 5, 2015, the applicant responded to RAI 3.1.2.3.2-2. The applicant 

revised LRA Table 3.1.2-2 to include the applicable line item to show the applicant’s AMR 

results for managing loss of preload for the jet pump auxiliary spring wedge assembly. In LRA 

Table 3.1.2-2, as amended by letter dated February 5, 2015, the applicant stated that a TLAA 

will be used to manage loss of preload for the nickel alloy (Alloy X-750) jet pump assembly—

auxiliary spring wedge assemblies and slip joint clamp adjustable bolt and ratchet lock spring 

exposed to treated water (ext) and neutron fluence. The applicant cites generic note H for this 

line item. 

The staff finds the applicant’s response to RAI 3.1.2.3.2-2 acceptable. The staff’s concern 

addressed in RAI 3.1.2.3.2-2 is resolved. 

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that Alloy X-750 reactor vessel internals components exposed to reactor coolant 

and neutron flux are susceptible to loss of fracture toughness and cracking and recommends 

GALL Report AMP XI.M9, “BWR Vessel Internals,” and GALL Report AMP XI.M2, “Water 

Chemistry,” to manage the aging effects. However, the applicant has identified loss of preload 

as an additional aging effect. The applicant addressed the GALL Report identified aging effects 

for this component, material, and environment combination in other AMR items in LRA 

Table 3.1.2-2. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.7.3, for managing 

loss of preload for these components, which the applicant dispositioned in accordance with 
3-245 

10 CFR 54.21(c)(1)(ii). The staff’s evaluation of the applicant’s plant-specific TLAA 4.7.3 is 

documented in SER Section 4.7.3. The staff finds the applicant’s proposal to manage loss of 

preload using plant-specific TLAA 4.7.3 acceptable because the applicant provided the 

appropriate fluence and projected loss of preload values that demonstrate that the analysis has 

been appropriately projected to the end of the period of extended operation and will remain 

below the threshold value for inducing preload loss such that the components will maintain their 

intended function during the period of extended operation. 

Jet Pump Assembly Slip Join Clamp Body Exposed to Treated Water Greater Than 140 °F (ext) 

and Neutron Fluence. LRA Section 4.7.4 discusses the applicant’s plant-specific TLAA to 

evaluate the relaxation of preload of the slip joint repair clamp in the jet pump assembly due to 

irradiation-assisted stress relaxation or creep. The applicant dispositioned TLAA 4.7.4 in 

accordance with 10 CFR 54.21(c)(1)(ii). However, the staff noted that LRA Table 3.1.2-2 does 

not include any applicable AMR items for managing loss of preload of the jet pump slip joint 

repair clamp. By letter dated December 23, 2014, the staff issued RAI 3.1.2.3.2-2, requesting 

that the applicant justify why the LRA did not include any applicable AMR line items. 

By letter dated February 5, 2015, the applicant responded to RAI 3.1.2.3.2-2. The applicant 

revised LRA Table 3.1.2-2 to include the applicable line item to show the applicant’s AMR 

results for managing loss of preload for the jet pump slip joint repair clamp. In LRA 

Table 3.1.2-2, as amended by letter dated February 5, 2015, the applicant stated that a TLAA 

will be used to manage loss of preload for the stainless steel jet pump assembly—slip joint 

clamp body exposed to treated water greater than 140 °F (ext) and neutron fluence. The 

applicant cites generic note H for this line item. The staff finds the applicant’s response to 

RAI 3.1.2.3.2-2 acceptable. The staff’s concern addressed in RAI 3.1.2.3.2-2 is resolved. 

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that stainless steel reactor jet pump assembly components exposed to reactor 

coolant and neutron flux are susceptible to cracking and recommends GALL Report AMP XI.M9 

“BWR Vessel Internals,” and GALL Report AMP XI.M2, “Water Chemistry,” to manage the aging 

effects. However, the applicant has identified loss of preload as an additional aging effect. The 

applicant addressed the GALL Report identified aging effects for this component, material, and 

environment combination in other AMR items in LRA Table 3.1.2-2. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.7.4, for managing 

loss of preload in these components, which the applicant dispositioned in accordance with 

10 CFR 54.21(c)(1)(ii). The staff’s evaluation of the applicant’s plant-specific TLAA 4.7.4 is 

documented in SER Section 4.7.4. The staff finds the applicant’s proposal to manage loss of 

preload using plant-specific TLAA 4.7.4 acceptable because the neutron flux experienced by the 

jet pump slip joint repair clamps will remain below the threshold value for loss of preload 

induced irradiation-assisted stress relaxation such that the components will not experience a 

loss of preload and will maintain their intended function during the period of extended operation. 

On the basis of its review, the staff concludes that for items in LRA Table 3.1.2-2 with an AERM, 

the applicant has demonstrated that the effects of aging for these items will be adequately 

managed so that their intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 
3-246 

 Reactor Coolant Pressure Boundary – Summary of Aging Management 

Evaluation – LRA Table 3.1.2-3 

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the 

RCPB component groups. 

Steel Piping and Piping Components Exposed to External Indoor Air. The staff’s evaluation for 

steel piping and piping components exposed to external indoor air with no AERMs and no 

recommended AMP, which are associated with generic note G, is documented in SER 

Section 3.1.2.3.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.1.2-3 with no 

AERMs, the applicant has appropriately evaluated the material and environment combinations 

not addressed in the GALL Report, and their intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 Miscellaneous RCS Systems in Scope for 10 CFR 54.4(a)(2) – Summary of Aging 

Management Evaluation – LRA Tables 3.1.2-4-1 through 3.1.2-4-3. 

The staff reviewed LRA Tables 3.1.2-4-1 through 3.1.2-4-3, which summarizes the results of 

AMR evaluations for the miscellaneous RCS systems in scope for 10 CFR 54.4(a)(2) 

component groups. 

Nuclear Boiler System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.1.2-4-1. The staff reviewed LRA 

Table 3.1.2-4-1, which summarizes the results of AMR evaluations for the nuclear boiler system, 

nonsafety-related components affecting safety-related systems. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the nuclear boiler system, nonsafety-related 

components affecting safety-related systems are consistent with the GALL Report. 

Reactor Recirculation System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.1.2-4-2. 

Stainless Steel Flex Connections Exposed to Wastewater. In LRA Table 3.1.2-4-2 the applicant 

stated that there is a TLAA for stainless steel and nickel alloy flex connections exposed to 

wastewater, which cites generic note H. The staff confirmed that there is a TLAA, as 

documented in LRA Section 4.3.2, for this component and material. The staff’s evaluation of the 

fatigue TLAA for non-Class 1 components, other than piping, is documented in SER 

Section 4.3.2.2. 

Neutron Monitoring System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.1.2-4-3. The staff 

reviewed LRA Table 3.1.2-4-3, which summarizes the results of AMR evaluations for the 

neutron monitoring system, nonsafety-related components affecting safety-related systems. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the neutron monitoring 

system, nonsafety-related components affecting safety-related systems are consistent with the 

GALL Report. 
3-247 

3.1.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effect of aging for the reactor vessel, internal and reactor coolant system components within 

the scope of license renewal and subject to an AMR will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.2 Aging Management of Engineered Safety Features Systems 

This section of the SER documents the staff’s review of the applicant’s AMR results for the ESF 

systems components and component groups of the following items: 

 nuclear pressure relief 

 residual heat removal 

 core spray 

 high pressure coolant injection 

 reactor core isolation cooling 

 containment penetrations 

 standby gas treatment 

 miscellaneous ESF systems in scope for 10 CFR 54.4(a)(2) 

3.2.1 Summary of Technical Information in the Application 

LRA Section 3.2 provides AMR results for the ESF systems components and component 

groups. LRA Table 3.2.1, “Summary of Aging Management Programs for Engineered Safety 

Features Evaluated in Chapter V of NUREG–1801,” is a summary comparison of the applicant’s 

AMRs with those evaluated in the GALL Report for the ESF systems components and 

component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.2.2 Staff Evaluation 

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the ESF systems components within the 

scope of license renewal and subject to an AMR will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

The staff conducted a review of the applicant’s AMRs to confirm the applicant’s claim that 

certain AMRs are consistent with the GALL Report, not applicable, or not used. The staff did 

not repeat its review of the matters described in the GALL Report; however, the staff did verify 

that the material presented in the LRA was applicable and that the applicant identified the 

appropriate GALL Report AMRs. The AMRs that the staff confirmed are consistent with the 

GALL Report are noted as such in Table 3.2-1, and no further discussion is required. The 

AMRs that the staff confirmed are not applicable to Fermi 2 or not used, because the 
3-248 

component, material, and environment combination described in the SRP-LR does not exist for 

in-scope SCs at Fermi 2 or because the component, material, and environment combination is 

addressed by another SER Table 3.1-1 item, or that require no aging management are noted in 

SER Table 3.2-1 and discussed in SER Section 3.2.2.1.1. Details of the staff’s evaluation of 

AMRs that the applicant claimed are consistent with the GALL Report, but for which a different 

AMP from the program recommended in the GALL Report is used to manage aging, and AMRs 

for which the staff requested additional information, are documented in SER Section 3.2.2.1.2. 

During its review, the staff also reviewed AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staff’s evaluations of 

AMRs for which the GALL Report recommends further evaluation are documented in SER 

Section 3.2.2.2. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs not consistent 

with, or not addressed in, the GALL Report are documented in SER Section 3.2.2.3. 

Table 3.2-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.2 and addressed in the GALL Report. 

Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems Components in the 

GALL Report 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel, steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated) 

(3.2.1-1) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a timelimited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation. See 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1). 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.2.1) 

Steel (with stainless 

steel cladding) pump 

casings exposed to 

treated water 

(borated) (3.2.1-2) 

Loss of material 

due to cladding 

breach 

A plant-specific 

aging management 

program is to be 

evaluated. 

Reference NRC 

Information 

Notice 94-63, “Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.” 

Yes, verify 

that plantspecific 

program 

addresses 

clad breach

Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.2.2) 
3-249 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel 

partially-encased 

tanks with breached 

moisture barrier 

exposed to raw 

water (3.2.1-3) 

Loss of material 

due to pitting 

and crevice 

corrosion 

A plant-specific 

aging management 

program is to be 

evaluated for pitting 

and crevice 

corrosion of tank 

bottom because 

moisture and water 

can egress under 

the tank due to 

cracking of the 

perimeter seal from 

weathering. 

Yes, plant 

specific 

Not applicable Not applicable to 

BWRs (see SER 

Section 

3.2.2.2.3(1)) 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.2.1-4) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

Yes, 

evironmental 

conditions 

need to be 

evaluated 

Not used. There 

are no stainless 

steel ESF system 

components 

exposed to 

outdoor air 

included in the 

scope of license 

renewal 

Not applicable to 

Fermi 2 (see SER 

Section 

3.2.2.2.3(2)) 

Stainless steel 

orifice (miniflow 

recirculation) 

exposed to treated 

water (borated) 

(3.2.1-5) 

Loss of material 

due to erosion 

A plant-specific 

aging management 

program is to be 

evaluated for erosion 

of the orifice due to 

extended use of the 

centrifugal HPSI 

pump for normal 

charging. See 

LER 50-275/94-023 

for evidence of 

erosion. 

Yes, plant 

specific 

Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.2.4) 

Steel drywell and 

suppression 

chamber spray 

system (internal 

surfaces): flow 

orifice; spray nozzles 

exposed to air – 

indoor, uncontrolled 

(internal) (3.2.1-6) 

Loss of material 

due to general 

corrosion; 

fouling that 

leads to 

corrosion 

A plant-specific 

aging management 

program is to be 

evaluated 

Yes, plant 

specific 

Not used. There 

are no steel 

orifices or spray 

nozzles exposed 

to indoor air in the 

containment spray 

subsystem of the 

residual heat 

removal system. 

Not used (see SER 

Section 3.2.2.2.5) 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.2.1-7) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

Yes, 

environmental 

conditions 

need to be 

evaluated 

Not used. There 

are no stainless 

steel ESF system 

components 

exposed to 

outdoor air 

included in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.2.6) 
3-250 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Aluminum, copper 

alloy (>15% Zn or 

>8% Al) piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage (3.2.1-8) 

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, 

“Boric Acid 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.2.1-9) 

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, 

“Boric Acid 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Cast austenitic 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated) 

>250°C (>482°F), 

treated water 

>250°C (>482°F) 

(3.2.1-10) 

Loss of fracture 

toughness due 

to thermal aging 

embrittlement 

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)” 

No Not used. There 

are no cast 

austenitic 

stainless steel 

components 

exposed to treated 

water >250 °C 

(>482 °F) within 

the scope of 

license renewal 

that are outside 

the reactor coolant 

system pressure 

boundary. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to steam, 

treated water 

(3.2.1-11) 

Wall thinning 

due to flowaccelerated 

corrosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Flow-Accelerated 

Corrosion 

Program 

Consistent with the 

GALL Report 

Steel, high-strength 

closure bolting 

exposed to air with 

steam or water 

leakage (3.2.1-12) 

Cracking due to 

cyclic loading, 

stress corrosion 

cracking 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 
3-251 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel; stainless steel 

bolting, closure 

bolting exposed to 

air – outdoor 

(external), air – 

indoor, uncontrolled 

(external) (3.2.1-13) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Loss of material 

for steel closure 

bolting exposed to 

indoor air is 

managed by the 

Bolting Integrity 

Program. Loss of 

material is not an 

aging effect for 

stainless steel 

closure bolting in 

indoor air unless it 

is exposed to 

prolonged leakage 

(an event-driven 

condition). 

Nevertheless, the 

Bolting 

Integrity Program 

also applies to 

stainless steel 

bolting exposed to 

indoor air. There 

is no ESF system 

bolting exposed to 

outdoor air in the 

scope of license 

renewal. 

Consistent with the 

GALL Report 

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.2.1-14) 

Loss of material 

due to general 

corrosion 

Chapter XI.M18, 

“Bolting Integrity” 

No Not used. As 

stated in item 

3.2.1-13, loss of 

material of steel 

bolting exposed to 

air in the ESF 

systems is 

managed by the 

Bolting 

Integrity Program. 

However, steam 

or water leakage 

is not considered 

as a separate 

aspect of the 

indoor air 

environment. 

Not used (see SER 

Section 3.2.2.1.1) 
3-252 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Copper alloy, nickel 

alloy, steel; stainless 

steel, stainless steel, 

steel; stainless steel 

bolting, closure 

bolting exposed to 

any environment, air 

– outdoor (external), 

raw water, treated 

borated water, fuel 

oil, treated water, air 

– indoor, 

uncontrolled 

(external) (3.2.1-15) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 

Steel containment 

isolation piping and 

components (internal 

surfaces), piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.2.1-16) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Aluminum, stainless 

steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.2.1-17) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

treated water 

(3.2.1-18) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel heat 

exchanger tubes 

exposed to treated 

water, treated water 

(borated) (3.2.1-19) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M2, 

“Water Chemistry,” 

and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

treated water 

(borated) >60°C 

(>140°F) (3.2.1-20) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry” 

and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 
3-253 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel (with stainless 

steel or nickel-alloy 

cladding) safety 

injection tank 

(accumulator) 

exposed to treated 

water (borated) 

>60°C (>140°F) 

(3.2.1-21) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry” 

and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

treated water 

(borated) (3.2.1-22) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry” 

and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Steel heat 

exchanger 

components, 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-23) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

- influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.2.1-24) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Stainless steel heat 

exchanger 

components, 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-25) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 

Stainless steel heat 

exchanger tubes 

exposed to raw 

water (3.2.1-26) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 

Stainless steel, steel 

heat exchanger 

tubes exposed to 

raw water (3.2.1-27) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no steel ESF 

system heat 

exchanger tubes 

exposed to raw 

water in the scope 

of license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 
3-254 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.2.1-28) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems and 

Inservice 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel Piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

(3.2.1-29) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no steel ESF 

system piping 

components 

exposed to 

closed-cycle 

cooling water in 

the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Steel heat 

exchanger 

components 

exposed to closedcycle cooling water 

(3.2.1-30) 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Stainless steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.2.1-31) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Copper alloy heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.2.1-32) 

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to closedcycle cooling water 

(3.2.1-33) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to closedcycle cooling water 

(3.2.1-34) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching” 

No Selective 

Leaching Program 

Consistent with the 

GALL Report 
3-255 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Gray cast iron motor 

cooler exposed to 

treated water 

(3.2.1-35) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

(3.2.1-36) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil 

(3.2.1-37) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching” 

No Not used. There 

are no ESF 

system 

components 

exposed to soil in 

the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Elastomers, 

elastomer seals and 

components 

exposed to air – 

indoor, uncontrolled 

(external) (3.2.1-38) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no elastomer 

ESF system 

components in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Steel containment 

isolation piping and 

components 

(external surfaces) 

exposed to 

condensation 

(external) (3.2.1-39) 

Loss of material 

due to general 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

Steel ducting, piping, 

and components 

(external surfaces), 

ducting, closure 

bolting, containment 

isolation piping and 

components 

(external surfaces) 

exposed to air – 

indoor, uncontrolled 

(external) (3.2.1-40) 

Loss of material 

due to general 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

Steel external 

surfaces exposed to 

air – outdoor 

(external) (3.2.1-41) 

Loss of material 

due to general 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

Aluminum piping, 

piping components, 

and piping elements 

exposed to air – 

outdoor (3.2.1-42) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no aluminum 

ESF system 

components 

exposed to 

outdoor air in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 
3-256 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Elastomers, 

elastomer seals and 

components 

exposed to air – 

indoor, uncontrolled 

(internal) (3.2.1-43) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Not used. There 

are no elastomer 

ESF system 

components in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Steel piping and 

components (internal 

surfaces), ducting 

and components 

(internal surfaces) 

exposed to air – 

indoor, uncontrolled 

(internal) (3.2.1-44) 

Loss of material 

due to general 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components, 

Periodic 

Surveillance and 

Preventive 

Maintenance, and 

External Surfaces 

Monitoring 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.1.2) 

Steel encapsulation 

components 

exposed to air – 

indoor, uncontrolled 

(internal) (3.2.1-45) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Steel piping and 

components (internal 

surfaces) exposed to 

condensation 

(internal) (3.2.1-46) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

Steel encapsulation 

components 

exposed to air with 

borated water 

leakage (internal) 

(3.2.1-47) 

Loss of material 

due to general, 

pitting, crevice, 

and boric acid 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

(internal surfaces); 

tanks exposed to 

condensation 

(internal) (3.2.1-48) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.2.1-49) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 
3-257 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Copper alloy, 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.2.1-50) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel, copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to 

lubricating oil 

(3.2.1-51) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.2.1-52) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no buried or 

underground ESF 

system 

components 

exposed to soil or 

concrete in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.2.1-53) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no buried or 

underground ESF 

system 

components 

exposed to soil or 

concrete in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Steel, stainless 

steel, nickel alloy 

underground piping, 

piping components, 

and piping elements 

exposed to airindoor uncontrolled 

or condensation 

(external) (3.2.1-

53.5) 

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no buried or 

underground ESF 

system 

components 

exposed to 

condensation in 

the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60°C 

(>140°F) (3.2.1-54) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking 

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not used. 

Stainless steel 

components of the 

ESF systems 

subject to 

evaluation under 

the BWR Stress 

Corrosion 

Cracking Program 

were reviewed as 

part of the Class 1 

reactor coolant 

pressure 

boundary. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 
3-258 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.2.1-55) 

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 

2) plant OE indicates 

no degradation of 

the concrete 

No, if 

conditions 

are met. 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report” 

Consistent with the 

GALL Report 

Aluminum piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

(internal/external) 

(3.2.1-56) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report” 

Consistent with the 

GALL Report 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

(external), gas 

(3.2.1-57) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report” 

Consistent with the 

GALL Report 

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.2.1-58) 

None None NA - No 

AEM or 

AMP 

Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1) 

Galvanized steel 

ducting, piping, and 

components 

exposed to air – 

indoor, controlled 

(external) (3.2.1-59) 

None None NA - No 

AEM or 

AMP 

Not used. 

Galvanized 

steel is evaluated 

as steel. 

Not used (see SER 

Section 3.2.2.1.1) 
3-259 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Glass piping 

elements exposed to 

air – indoor, 

uncontrolled 

(external), lubricating 

oil, raw water, 

treated water, 

treated water 

(borated), air with 

borated water 

leakage, 

condensation 

(internal/external), 

gas, closed-cycle 

cooling water, air – 

outdoor (3.2.1-60) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report” 

Consistent with the 

GALL Report 

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

(external) (3.2.1-61) 

None None NA - No 

AEM or 

AMP 

Not used. There 

are no nickel alloy 

ESF system 

components 

exposed to indoor 

air in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage (3.2.1-62) 

None None NA - No 

AEM or 

AMP 

Not used. There 

are no nickel alloy 

ESF system 

components 

exposed to indoor 

air in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air – 

indoor, uncontrolled 

(external), air with 

borated water 

leakage, concrete, 

gas, air – indoor, 

uncontrolled 

(internal) (3.2.1-63) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

for stainless steel 

components 

exposed to indoor 

air and gas. 

Consistent with the 

GALL Report 

Steel Piping, piping 

components, and 

piping elements 

exposed to air – 

indoor, controlled 

(external), gas 

(3.2.1-64) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

for components 

exposed to gas. 

Consistent with the 

GALL Report 

Any material, piping, 

piping components, 

and piping elements 

exposed to treated 

water, treated water 

(borated) (3.2.1-65) 

Wall thinning 

due to erosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Flow-Accelerated 

Corrosion 

Program 

Consistent with the 

GALL Report 
3-260 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

wastewater (3.2.1-

66) 

Loss of material 

due to recurring 

internal 

corrosion 

A plant-specific 

aging management 

program is to be 

evaluated to address 

recurring internal 

corrosion 

Yes, plantspecific Periodic 

Surveillance and 

Preventive 

Maintenance 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.2.9) 

Stainless steel or 

aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.2.1-67) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Not used. There 

are no stainless 

steel or aluminum 

tanks (consistent 

with the scope of 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) in 

the ESF systems 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Steel, stainless 

steel, or aluminum 

tanks (within the 

scope of Chapter 

XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.2.1-68) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Not used. There 

are no steel, 

stainless steel or 

aluminum tanks 

(consistent with 

the scope of 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) in 

the ESF systems 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Insulated steel, 

stainless steel, 

copper alloy, or 

aluminum, piping, 

piping components, 

and tanks exposed 

to condensation, airoutdoor (3.2.1-69) 

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

and crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks,” (for 

tanks only) 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 
3-261 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water, treated 

borated water (3.2.1-

70) 

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Not used. There 

are no steel, 

stainless steel, or 

aluminum tanks 

(consistent with 

the scope of 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) in 

the ESF systems. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Insulated stainless 

steel, aluminum, or 

copper alloy (> 15% 

Zn) piping, piping 

components, and 

tanks exposed to 

condensation, airoutdoor (3.2.1-71) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components,” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” (for 

tanks only) 

No Not used. There 

are no stainless 

steel, aluminum, 

or copper alloy 

insulated piping 

components or 

tanks exposed to 

condensation or 

outdoor air in the 

ESF systems. 

Not applicable to 

Fermi 2 (see SER 

Section 3.2.2.1.1) 

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closed 

cycle cooling water, 

raw water, treated 

water, treated 

borated water, or 

lubricating oil 

(3.2.1-72) 

Loss of coating 

or lining integrity 

due to blistering, 

cracking, 

flaking, peeling, 

delamination, 

rusting, or 

physical 

damage, and 

spalling for 

cementitious 

coatings/linings 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Coating Integrity 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.2.2.3.2) 

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closed 

cycle cooling water, 

raw water, treated 

water, treated 

borated water, or 

lubricating oil 

(3.2.1-73) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Not used Not used (see SER 

Section 3.2.2.1.1) 

Gray cast iron piping 

components with 

internal 

coatings/linings 

exposed to closed 

cycle cooling water, 

raw water, or treated 

water (3.2.1-74) 

Loss of material 

due to selective 

leaching 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Not used Not used (see SER 

Section 3.2.2.1.1) 
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3.2.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the ESF systems components: 

 Bolting Integrity 

 External Surfaces Monitoring 

 Flow-Accelerated Corrosion 

 Internal Surfaces in Miscellaneous Piping and Ducting Components 

 Oil Analysis 

 One-Time Inspection 

 Service Water Integrity 

 Water Chemistry Control – BWR 

 Water Chemistry Control – Closed Treated Water Systems 

 Buried and Underground Piping 

 Coating Integrity 

 Periodic Surveillance and Preventive Maintenance 

LRA Tables 3.2.2-1 through 3.2.2-8-6 summarize AMRs for the ESF systems components and 

indicate AMRs claimed to be consistent with the GALL Report. 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine if the plant-specific components of these GALL 

Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR item. The notes describe how the information in 

the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions. 

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 

Note C indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as the component under review. The staff audited 

these AMR items to confirm consistency with the GALL Report. The staff also determined 
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whether the AMR item of the different component applied to the component under review and 

whether the AMR was valid for the site-specific conditions. 

Note D indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions. 

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff audited these AMR 

items to confirm consistency with the GALL Report and determined whether the identified AMP 

would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, the staff did confirm that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows. 

 AMR Results Identified as Not Applicable or Not Used 

For LRA Table 3.2.1, items 3.2.1-8, 3.2.1-9, 3.2.1-20, 3.2.1-21, 3.2.1-22, 3.2.1-24, 3.2.1-35, 

3.2.1-36, 3.2.1-45, 3.2.1-47, and 3.2.1-58, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable because the associated items are only applicable 

to PWRs. The staff reviewed the SRP-LR; confirmed that these items only apply to PWRs; and 

finds that these items are not applicable to Fermi 2, which is a BWR. 

For LRA Table 3.2.1, items 3.2.1-10, 3.2.1-14, 3.2.1-29, 3.2.1-37, 3.2.1-38, 3.2.1-42, 3.2.1-43, 

3.2.1-52, 3.2.1-53, 3.2.1-53.5, 3.2.1-54, 3.2.1-59, 3.2.1-61, 3.2.1-62, 3.2.1-67, 3.2.1-68, 

3.2.1-70, and 3.2.1-71, the applicant claimed that the corresponding items in the GALL Report 

are not applicable or are not used because the component, material, and environment 

combination described in the SRP-LR does not exist for in-scope SCs at Fermi 2 or because the 

component, material, and environment combination is addressed by another Table 1 line item. 

The staff reviewed the LRA and UFSAR and confirmed that the applicant’s LRA does not have 

any AMR results applicable for these items or that the aging effects addressed by other Table 1 

AMR line items are appropriate. 

LRA Table 3.2.1, item 3.2.1-27 addresses both stainless steel and steel heat exchanger tubes 

exposed to raw water. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle 

Cooling Water System,” to manage reduction of heat transfer for this component group. The 

applicant stated that this item is not used because there are no steel heat exchanger tubes 

exposed to raw water in ESF systems. The staff notes that, although there are stainless steel 

heat exchanger tubes exposed to raw water in ESF systems, the applicant will manage 

reduction of heat transfer for these components by using item 3.2.1-26. The staff evaluated the 

applicant’s claim and finds it acceptable because the item cited by the applicant uses the 

Service Water Integrity Program, which corresponds to the Open-Cycle Cooling Water System 
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Program in the GALL Report, and it is appropriate for managing the associated stainless steel 

heat exchanger tubes. 

SER Table 3.2-1, items 3.2.1-73 and 3.2.1-74, reflect changes to the SRP-LR incorporated by 

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal 

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

ISG added these line items to allow applicants to credit the new GALL Report AMP XI.M42, 

“Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and 

Tanks,” to manage loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion; fouling that leads to corrosion; or selective leaching in 

certain components. The applicant did not credit the related plant-specific AMP, “Coating 

Integrity,” for the aging effect and components that reference SRP-LR items 3.2.1-73 and 

3.2.1-74 but instead credited alternate items and programs to manage the effects of these aging 

mechanisms for these components. For example, in regard to item 3.2.1-73, loss of material for 

the internally coated residual heat exchanger end channels is managed by the Service Water 

Integrity Program. In regard to item 3.2.1-74, there are no gray cast iron components in the 

engineered safety feature systems. The staff finds this approach acceptable because the 

alternate items and programs used are adequate to manage the effects of aging for these 

components and because this approach is consistent with GALL Report AMP XI.M42. 

 Loss of Material Due to General Corrosion 

LRA Table 3.2.1, item 3.2.1-44, addresses carbon steel piping, ducting, and components 

internally exposed to uncontrolled indoor air, which will be managed for loss of material due to 

general corrosion. For the AMR items that cite generic note E, the LRA credits either the 

External Surfaces Monitoring or Periodic Surveillance and Preventive Maintenance (PSPM) 

programs to manage the aging effect for steel piping and piping components. The GALL Report 

recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” to ensure that this aging effect is adequately managed. 

GALL Report AMP XI.M38 recommends using opportunistic visual inspections, with a 

representative sample of components inspected at least once every 10 years, to manage the 

effects of aging. GALL Report AMP XI.M38 also states that, when the material and environment 

combinations are similar for the internal and external surfaces, external inspections of 

components may be credited for managing loss of material on the internal surfaces of metallic 

components. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The External Surfaces Monitoring Program proposes to manage the 

effects of aging for carbon steel piping and piping components through the use of periodic visual 

inspections at least once per RFO. LRA Table 3.2-1, item 3.2.1-44, states that the program is 

used to manage loss of material on the internal surfaces of carbon steel components when the 

internal and external surfaces are exposed to the same environment, which is consistent with 

the GALL Report guidance. Based on its review of components associated with item 3.2.1-44, 

for which the applicant cited generic note E and the use of the External Surfaces Monitoring 

Program, the staff finds the applicant’s proposal to manage the effects of aging using this 

program acceptable because periodic visual inspections of component external surfaces at least 

once per RFO are sufficient to identify the potential for corrosion of component internal surfaces 

when the internal and external environments are the same. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The program proposes to manage the effects of aging for the recombiner 
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system component internal surfaces in the containment atmosphere control system through the 

use of periodic visual inspections or other established NDE techniques with a frequency of at 

least once every 5 years. Based on its review of components associated with item 3.2.1-44 for 

which the applicant cited generic note E, the staff finds the applicant’s proposal to manage the 

effects of aging using the PSPM Program acceptable because visual or other NDE testing at a 

frequency of at least once every 5 years is similar to the inspection approach recommended by 

the GALL Report and is capable of identifying loss of material before loss of component 

intended functions. 

The staff concludes that for LRA item 3.2.1-44, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended 

In LRA Section 3.2.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the ESF systems components and provided information concerning how it 

will manage the following aging effects: 

 cumulative fatigue damage 

 loss of material due to cladding breach 

 loss of material due to pitting and crevice corrosion 

 loss of material due to erosion 

 loss of material due to general corrosion and fouling that leads to corrosion 

 cracking due to SCC 

 QA for aging management of nonsafety-related components 

 ongoing review of operating experience 

 loss of material due to recurring internal corrosion 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.2.2.2. The staff’s review of the applicant’s 

further evaluation follows. 

 Cumulative Fatigue Damage 

LRA Section 3.2.2.2.1 is associated with LRA Table 3.2.1, item 3.2.1-1, addresses steel and 

stainless steel piping, piping components, and piping elements exposed to treated water 

(borated), which will be managed for cumulative fatigue damage. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that fatigue is a TLAA, as defined in 

10 CFR 54.3, and is evaluated in accordance with 10 CFR 54.21(c). The applicant stated that 

its evaluation of the TLAA is addressed in LRA Section 4.3. 

The staff reviewed LRA Section 3.2.2.2.1 against the criteria in SRP-LR Section 3.2.2.2.1, which 

state that cumulative fatigue damage of steel and stainless steel piping, piping components, and 

piping elements is a TLAA and is to be evaluated in accordance with the TLAA acceptance 

criteria requirements of 10 CFR 54.21(c). The staff reviewed the applicant’s AMR line items and 
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determined that the AMR results are consistent with the recommendations of the GALL Report 

and SRP-LR for managing cumulative fatigue damage in steel and stainless steel piping, piping 

components, and piping elements. 

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.2.2.2.1 criteria. For those line items that apply to LRA Section 3.2.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components. 

 Loss of Material Due to Cladding Breach 

LRA Section 3.2.2.2.2, associated with LRA Table 3.2.1, item 3.2.1-2, addresses loss of 

material due to cladding breach in PWR steel charging pump casings with stainless steel 

cladding exposed to treated borated water. The applicant stated that this item is not applicable 

because it only applies to PWRs. The staff confirmed that this item is associated only with PWR 

plants; therefore, the staff finds the applicant’s determination acceptable. 

 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP-LR 

Section 3.2.2.2.3: 

(1) LRA Section 3.2.2.2.3, associated with LRA Table 3.2.1, item 3.2.1-3, addresses 

partially encased stainless steel tanks exposed to raw water. The criterion in SRP-LR 

Section 3.2.2.2.3, item 1, states that moisture and water can enter under the tank if the 

perimeter seal is degraded. The applicant stated that this item is not applicable because 

the engineered safety features systems do not have any partially encased stainless steel 

tanks. The staff evaluated the applicant’s claim and finds it acceptable because, based 

on walkdowns performed during the audit and a review of the UFSAR, the staff verified 

that the applicant does not have partially encased stainless steel tanks. 

(2) LRA Section 3.2.2.2.3, item 2, associated with LRA Table 3.2.1, item 3.2.1-4, addresses 

loss of material due to pitting and crevice corrosion in stainless steel piping, piping 

components, piping elements, and tanks exposed to outdoor air. The criteria in SRP-LR 

Section 3.2.2.2.3, item 2, states that loss of material could occur for stainless steel 

components exposed to outdoor air environments containing sufficient halides and in 

which condensation or deliquescence is possible. The applicant stated that this item is 

not used because there are no stainless steel components exposed to outdoor air in the 

engineered safety features systems within the scope of license renewal. The staff 

evaluated the applicant’s claim and finds it acceptable because the staff reviewed the 

LRA and UFSAR and verified that there are no in-scope stainless steel components 

exposed to outdoor air in the engineered safety features systems. 

 Loss of Material Due to Erosion 

LRA Section 3.2.2.2.4 is associated with LRA Table 3.2.1, item 3.2.1-5, and addresses loss of 

material due to erosion of stainless steel minimum flow orifices for PWR high-pressure safety 

injection pumps exposed to treated borated water. The applicant stated that item 3.2.1-5 is not 

applicable because it only applies to PWRs. The staff evaluated the applicant’s claim and finds 
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it acceptable because item 3.2.1-5 addresses the use of the high-pressure safety injection 

pumps for normal charging in PWRs and does not apply to Fermi 2. 

 Loss of Material Due to General Corrosion and Fouling That Leads to Corrosion 

LRA Section 3.2.2.2.5, associated with LRA Table 3.2.1, item 3.2.1-6, addresses loss of 

material due to general corrosion and fouling that leads to corrosion in steel drywell and 

suppression chamber spray system nozzle and flow orifice internal surfaces exposed to 

uncontrolled indoor air. The applicant stated that for item 3.2.1-6 the applicability is limited to 

steel orifices or spray nozzles exposed to indoor air and is, therefore, not used. The staff 

confirmed that the applicant’s containment spray nozzles are copper alloy and that no steel 

orifices are present in the containment spray subsystem. The staff also noted that GALL 

Report, item V.F.EP-10, identifies copper alloy components exposed to indoor air as having no 

aging effect and mechanism and does not recommend an AMP. 

However, the staff noted that this further evaluation subsection includes plugging of the spray 

nozzles and discusses internal surface corrosion of the steel spray systems in the drywell and 

suppression chamber. The staff also noted that nozzle plugging can be caused by the buildup 

of corrosion products from upstream components, not just corrosion of the nozzles themselves. 

The staff further noted that even though this system is in standby the majority of the time, the 

wetting and drying of these components can accelerate corrosion and lead to flow blockage due 

to fouling. Based on this, by letter dated December 24, 2014, the staff issued RAI 3.2.2.2-1, 

requesting that the applicant provide information on the potential for internal corrosion in the 

spray systems for the drywell and suppression chamber as it relates to plugging of the 

associated spray nozzles. 

In its response dated February 5, 2015, the applicant confirmed that the drywell sprays are not 

credited and are not within the scope of license renewal. The applicant stated that the 

suppression chamber atmosphere is inerted to less than 4 percent oxygen during power 

operation, which reduces the potential for corrosion. The applicant also stated that flow rates 

greater than 500 gpm were achieved during the last 16 quarterly surveillances of the 

suppression pool spray system and that, if significant blockage were to develop, the flow rates 

through the spray header would indicate a decreasing trend. The applicant further stated that 

the spray header material and environment combination is included in the Water Chemistry 

Control – BWR Program and the One-Time Inspection Program. 

In its review of the applicant’s response, the staff noted that, although the inerted atmosphere 

may reduce the amount of corrosion, there appears to be sufficient oxygen in the water within 

the system to support general corrosion based on the ongoing operating experience for the 

corrosion of components in BWR suppression pools. In addition, the staff noted the operating 

experience included in the James A. Fitzpatrick Nuclear Power Plant license renewal SER that 

discussed blockage in some suppression pool spray nozzles found during surveillance tests, 

and it was unclear to the staff whether the applicant’s quarterly surveillance required flow-rate 

trending and whether flow-rate trending alone could detect the development of similar flow 

blockage. Additionally, it was not clear to the staff that the internal environment of the 

suppression pool spray header would be considered as a uniquely classified environment within 

the One-Time Inspection Program because of the periodic wetting and drying. By letter dated 

March 26, 2015, the staff issued RAI 3.2.2.2-1a requesting that the applicant address the above 

issues. 
3-268 

In its response dated April 27, 2015, the applicant stated that based on the spray nozzle design 

capacity, a total flow rate of approximately 700 gpm or greater is expected when flow testing 

through the suppression pool nozzles. However, because the current surveillance testing 

acceptance criteria is 500 gpm, there is a potential for the acceptance criteria to be met with 

several spray nozzles blocked. Consequently, the applicant will perform air flow testing, similar 

to the testing currently being performed for the drywell spray nozzles, as part of the PSPM 

Program at least once every 5 years. In addition, the applicant added an AMR item with a 

generic note H to LRA Table 3.2.2-2 indicating that the PSPM Program will manage “flow 

blockage due to fouling” for the spray nozzles. In addition, the applicant added plant-specific 

note 206 to LRA Table 3.2.2-2, stating that portions of the spray piping are normally dry, but 

wetted during periodic system testing and that a one-time inspection activity will confirm that 

loss of material is not occurring or is occurring slowly. The applicant also modified LRA 

Sections A.1.33 and B.1.33 to reflect the above changes to the One-Time Inspection Program 

and Sections A.1.35 and B.1.35 to reflect the above changes to the PSPM Program. 

The staff finds the applicant’s response acceptable because implementing new periodic 

inspections using an air test through the PSPM Program will be adequate to manage flow 

blockage due to fouling in the suppression pool spray nozzles. In addition, performing 

inspections on a representative sample of the periodically wetted suppression pool spray piping 

through the One-Time Inspection Program will ensure that any loss of material in the associated 

portion of the RHR system will not affect component intended function during the period of 

extended operation. Based on the programs identified, the staff determines that the applicant’s 

programs meet SRP-LR Section 3.2.2.2.5 criteria. For those items associated with LRA 

Section 3.2.2.2.5, the staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3). The 

staff’s concerns described in RAIs 3.2.2.2-1 and 3.2.2.2-1a are resolved. 

 Cracking Due to Stress Corrosion Cracking 

LRA Section 3.2.2.2.6, associated with LRA Table 3.2.1, item 3.2.1-7, addresses cracking due 

to SCC in stainless steel piping, piping components, piping elements, and tanks exposed to 

outdoor air. The criteria in SRP-LR Section 3.2.2.2.6 state that cracking could occur for 

stainless steel components exposed to outdoor air environments containing sufficient halides 

and in which condensation or deliquescence is possible. The applicant stated that this item is 

not used because there are no stainless steel components exposed to outdoor air, including air 

that has recently been introduced into buildings, in the ESFs systems within the scope of license 

renewal. The staff evaluated the applicant’s claim and finds it acceptable because the staff 

reviewed the LRA and UFSAR and verified that there are no in-scope stainless steel 

components exposed to outdoor air, or air which has recently been introduced into buildings, in 

the ESFs systems. 

 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

 Ongoing Review of Operating Experience 

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience for AMPs. 
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 Loss of Material Due to Recurring Internal Corrosion 

LRA Section 3.2.2.2.9, associated with LRA Table 3.2.1, item 3.2.1-66, addresses metallic 

piping, piping components, and tanks exposed to raw water or wastewater, which will be 

managed for loss of material due to recurring internal corrosion by the PSPM Program. The 

criteria in SRP-LR Section 3.2.2.2.9 state that recurring internal corrosion can result in the need 

to augment AMPs beyond the recommendations in the GALL Report. The SRP-LR also states 

that recurring internal corrosion can be identified by an operating experience search for 

repeated instances in which an aging effect resulted in a component either not meeting 

plant-specific acceptance criteria or experiencing a reduction in wall thickness greater than 

50 percent. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that recurring internal corrosion was identified in carbon steel piping components exposed to 

raw water in the ESF systems. The applicant also stated that this aging effect will be managed 

with the PSPM Program by monitoring wall thickness at selected locations and by replacing pipe 

where necessary. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The program includes periodic wall thickness measurements at selected 

locations based on pipe configuration, flow conditions, and operating history. A minimum of five 

inspections of carbon steel piping exposed to raw water will be performed each year until the 

rate of recurring internal corrosion occurrences no longer meets the operating experience 

criteria in the further evaluation that prompted the augmented inspections. 

In its review of components associated with item 3.2.1-66, the staff finds that the applicant has 

met the further evaluation criteria and that its proposal to manage the effects of aging using the 

PSPM Program is acceptable because the applicant’s proposal increases the minimum number 

and frequency of inspections beyond that recommended by the GALL Report such that 

recurring corrosion can be effectively monitored before a loss of intended function. The GALL 

Report program to manage the internal surfaces of piping in raw water (outside of the fire 

protection and safety-related service water systems), GALL Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” recommends the 

inspection of a maximum of 25 locations in each 10-year period, with no provision to perform 

inspections every year. In contrast, the applicant proposes to examine a minimum of 

50 locations in each 10-year period, with inspections occurring each year. 

Based on the program identified, the staff determines that the applicant’s program meets the 

criteria in SRP-LR Section 3.2.2.2.9. For those items associated with LRA Section 3.2.2.2.9, 

the staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.2.2-1 through 3.2.2-8-6, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with, or not addressed 

in, the GALL Report. 

In LRA Tables 3.2.2-1 through 3.2.2-8-6, the applicant indicated, through notes F through J, that 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 
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manage the aging effects. Specifically, note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations that are not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections. 

 Nuclear Pressure Relief System – Summary of Aging Management Evaluation – 

LRA Table 3.2.2-1 

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the 

nuclear pressure relief component groups. 

Steel Piping Exposed to Treated Water. In LRA Tables 3.2.2-1, 3.2.2-2, 3.2.2-3, 3.2.2-4, 

and 3.2.2-5, the applicant stated that carbon steel piping exposed to treated water will be 

managed for loss of material by the One-Time Inspection Program. The AMR items cite generic 

note G and plant-specific note 203, which states that the environment may alternate between 

wet and dry for the piping that passes through the waterline region of the suppression pool and 

that the One-Time Inspection Program will use visual or other NDE techniques to inspect this 

piping to manage the potential accelerated loss of material. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The staff noted that the applicant is also using the Water 

Chemistry Control – BWR Program to manage loss of material for this piping. Based on its 

review of the GALL Report, which states that steel piping, piping components, and piping 

elements exposed to treated water should be managed for loss of material due to general, 

pitting, and crevice corrosion, the staff finds that the applicant has identified all credible aging 

effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s One-Time Inspection Program is documented in SER 

Section 3.0.3.1.17. During the staff’s review of these items and the One-Time Inspection 

Program, it noted that plant-specific note 203 states that the One-Time Inspection Program will 

inspect the piping “to manage the potential accelerated loss of material,” whereas a table in LRA 

Section B.1.33, “One-Time Inspection,” states that the one-time inspection “will confirm that loss 

of material is not occurring or is occurring so slowly that the aging effect will not affect the 

component intended function.” To clarify this apparent disparity, by letter dated 

December 23, 2014, the staff issued RAI 3.2.2.3.1-1 to request that the applicant clarify the 

intent of the use of the One-Time Inspection Program. 

By letter dated February 5, 2015, the applicant stated that significant loss of material is not 

expected nor has it been observed at Fermi 2. Water quality in the torus is controlled in 

accordance with the Water Chemistry Control – BWR Program, and the torus is normally inerted 
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in the piping splash zone. Additionally, the applicant stated that, in accordance with its 

One-Time Inspection Program, if there is any indication or relevant condition of degradation, it 

will be evaluated, as well as any need for followup examinations. The applicant revised 

plant-specific note 203 to be consistent with the wording in LRA Sections A.1.33 and B.1.33 and 

added “gas” as an environment for the relevant AMR items. 

The staff finds the applicant’s response and proposal to manage the effects of aging using the 

One-Time Inspection Program acceptable because it clarified that an accelerated loss of 

material is not expected and revised the LRA accordingly. Additionally, the applicant stated 

that, in accordance with its One-Time Inspection Program, any indication or relevant condition of 

degradation will be evaluated. The staff’s concern described in RAI 3.2.2.3.1-1 is resolved. 

Stainless Steel Flex Connections Exposed to Steam. In LRA Table 3.2.2-1, the applicant stated 

that there is a TLAA for stainless steel flex connections exposed to steam that cites generic 

note H. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for this 

component and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 

components, other than piping, is documented in SER Section 4.3.2.2. 

On the basis of its review, the staff concludes that for items in LRA Table 3.2.2-1 with an AERM, 

the applicant has demonstrated that the effects of aging for these items will be adequately 

managed so that their intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

 Residual Heat Removal System – Summary of Aging Management Evaluation – 

LRA Table 3.2.2-2 

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the 

RHR component groups. 

Carbon Steel Heat Exchanger Components and Tanks Exposed to Treated Water, Raw Water, 

and Lubricating Oil. As amended by letter dated February 15, 2015, LRA Tables 3.2.2-2 

and 3.2.2-4 state that carbon steel heat exchanger components and tanks exposed to treated 

water, raw water, and lubricating oil will be managed for loss of coating integrity by the Coating 

Integrity Program. The AMR items cite generic note H. 

The staff noted that, although the applicant cited generic note H, LR-ISG-2013-01, “Aging 

Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope 

Piping, Piping Components, Heat Exchangers, and Tanks,” provides AMR line items to address 

this MEAP combination. SRP-LR Table 3.2-1, item 3.2.1-72 states that metallic heat 

exchangers and tanks with internal coatings/linings exposed to raw water, treated water, or 

lubricating oil are managed for loss of coating integrity by GALL Report AMP XI.M42, “Internal 

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

The staff’s evaluation of the applicant’s Coating Integrity Program is documented in SER 

Section 3.0.3.2.24. The staff finds the applicant’s proposal to manage the effects of aging using 

the Coating Integrity Program acceptable because periodic visual inspections of internal 

coatings by qualified personnel are capable of detecting loss of coating integrity. 

Copper Alloy Nozzles Exposed to Treated Water. In LRA Table 3.2.2-2, as modified in its 

response dated April 27, 2015, to RAI 3.2.2.2-1a, the applicant stated that copper alloy nozzles 
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exposed to treated water will be managed for flow blockage due to fouling by the PSPM 

Program. The AMR item cites generic note H. 

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper-alloy piping components are susceptible to loss of material and 

recommends GALL Report AMP XI.M2, “Water Chemistry” and GALL Report AMP XI.M32, 

“One-Time Inspection” programs to manage the aging effect. However, the applicant has 

identified flow blockage due to fouling as an additional aging effect for the suppression pool 

spray nozzles. The applicant addressed the GALL Report-identified aging effect for this 

component, material, and environment combination in other AMR items in LRA Table 3.2.2-2. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The staff finds the applicant’s proposal to manage flow blockage due to 

fouling using the PSPM Program acceptable because the new periodic surveillance will use air 

testing similar to the periodic testing that has been shown to be effective for the detection of flow 

blockage in the drywell spray nozzles. 

Steel Piping Exposed to Treated Water. The staff’s evaluation for steel piping exposed to 

treated water, which will be managed for loss of material by the One-Time Inspection Program 

and is associated with generic note G, is documented in SER Section 3.2.2.3.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.2.2-2 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Core Spray – Summary of Aging Management Review – LRA Table 3.2.2-3 

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the 

core spray component groups. 

Steel Piping Exposed to Treated Water. The staff’s evaluation for steel piping exposed to 

treated water, which will be managed for loss of material by the One-Time Inspection Program 

and is associated with generic note G, is documented in SER Section 3.2.2.3.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.2.2-3 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 High-Pressure Coolant Injection – Summary of Aging Management Evaluation – 

LRA Table 3.2.2-4 

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the 

system name component groups. 

Carbon Steel Heat Exchanger Components and Tanks Exposed to Treated Water, Raw Water, 

and Lubricating Oil. The staff’s evaluation for carbon steel heat exchanger components and 

tanks exposed to treated water, raw water, and lubricating oil, which will be managed for loss of 

coating integrity by the Coating Integrity Program and are associated with generic note H, is 

documented in SER Section 3.2.2.3.2. 
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Carbon Steel, Aluminum, and Copper Alloy Heat Exchanger Components Exposed to Indoor 

and Outdoor Air. In LRA Tables 3.2.2-4 and 3.3.2-9, the applicant stated that carbon steel heat 

exchanger fins exposed to indoor air and aluminum and copper alloy heat exchanger fins and 

tubes exposed to outdoor air will be managed for fouling by the External Surfaces Monitoring 

Program. The AMR items cite generic notes H (carbon steel) and G (aluminum and copper 

alloy). 

The staff noted that these material and environment combinations are identified in the GALL 

Report; however, the GALL Report does not provide any guidance for the management of 

fouling of heat exchanger surfaces in air environments. The applicant has identified fouling as 

an applicable aging effect. The applicant addressed the GALL Report-identified aging effect of 

loss of material for the copper alloy heat exchanger tubes in another AMR item in LRA 

Table 3.3.2-9. The applicant did not address loss of material for the carbon steel and aluminum 

heat exchanger fins, which were cited as having only a heat transfer intended function. 

Nevertheless, the visual inspections for fouling conducted by the External Surfaces Monitoring 

Program discussed below also are capable of identifying loss of material before the heat 

transfer function of the fins being challenged. Therefore, the staff finds that the applicant has 

identified all credible aging effects for these component, material, and environment 

combinations. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The staff finds the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable because the periodic visual inspections in the 

program, which are conducted at least once per refueling cycle, are capable of detecting fouling 

of the heat exchanger surfaces before loss of the intended function. 

Stainless Steel Piping, Tubing, and Valve Bodies Exposed to Steam. In LRA Table 3.2.2-4, the 

applicant stated that there are TLAAs for stainless steel piping, tubing, and valve bodies 

exposed to steam; these TLAAs cite generic note H. The staff confirmed that there are TLAAs, 

as documented in LRA Section 4.3.1, for these components and material. The staff’s evaluation 

of the fatigue TLAAs for Class 1 piping components and valves is documented in SER 

Section 4.3.1.6. 

Steel Piping Exposed to Treated Water. The staff’s evaluation for steel piping exposed to 

treated water, which will be managed for loss of material by the One-Time Inspection Program 

and is associated with generic note G, is documented in SER Section 3.2.2.3.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.2.2-4 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Reactor Core Isolation Cooling – Summary of Aging Management Evaluation – 

LRA Table 3.2.2-5 

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the 

reactor core isolation cooling component groups. 

Stainless Steel Piping, Tubing, Orifices, and Valve Bodies Exposed to Steam. In LRA 

Table 3.2.2-5, the applicant stated that there are TLAAs for stainless steel piping, tubing, 

orifices, and valve bodies exposed to steam; the TLAAs cite generic note H. The staff 
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confirmed that there are TLAAs, as documented in LRA Section 4.3.1, for these components 

and material. The staff’s evaluation of the fatigue TLAAs for Class 1 piping components and 

valves is documented in SER Section 4.3.1.6. 

Steel Piping Exposed to Treated Water. The staff’s evaluation for steel piping exposed to 

treated water, which will be managed for loss of material by the One-Time Inspection Program 

and is associated with generic note G, is documented in SER Section 3.2.2.3.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.2.2-5 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Containment Penetrations – Summary of Aging Management Evaluation – LRA 

Table 3.2.2-6 

The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the 

containment penetrations component groups. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the containment penetrations component groups are consistent 

with the GALL Report. 

 Standby Gas Treatment – Summary of Aging Management Evaluation – LRA 

Table 3.2.2-7 

The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the 

standby gas treatment component groups. 

Fiberglass Moisture Separators Exposed to Wastewater. In LRA Table 3.2.2-7, the applicant 

stated that fiberglass moisture separators exposed to wastewater will be managed for cracking 

and changes in material properties by the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. Based on its review of the GALL Report, which states that 

fiberglass piping exposed to raw water is susceptible to cracking, blistering, and change in color 

due to water absorption, the staff finds that the applicant has identified all credible aging effects 

for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.11. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the opportunistic visual inspections conducted by 

the program, with a representative sample of components inspected at least once every 

10 years, are capable of detecting cracking and changes in material properties in the fiberglass 

separators by observing for cracking, other surface discontinuities, and discoloration. 

On the basis of its review, the staff concludes that for items in LRA Table 3.2.2-7 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 
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their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Miscellaneous ESF Systems in Scope for 10 CFR 54.4(a)(2) – Summary of Aging 

Management Evaluation – LRA Tables 3.2.2-8-1 through 3.2.2-8-6 

The staff reviewed LRA Tables 3.2.2-8-1 through 3.2.2-8-6, which summarize the results of 

AMR evaluations for the miscellaneous ESF systems in scope for 10 CFR 54.4(a)(2) component 

groups. 

Residual Het Removal System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.2.2-8-1 

Carbon Steel Closure Bolting Exposed to Condensation (External). The staff’s evaluation for 

carbon steel closure bolting exposed to condensation (external), which will be managed for loss 

of preload by the Bolting Integrity Program and is associated with generic note H, is 

documented in SER Section 3.3.2.3.3. 

Stainless Steel and Nickel Alloy Piping, Piping Components, Heat Exchanger Components, and 

Tanks Exposed to Condensation. In LRA Tables 3.2.2-8-1, 3.3.2-3, 3.3.2-5, 3.3.2-10, 

3.3.2-11, 3.3.2-12, 3.3.2-17-3, 3.3.2-17-16, and 3.3.2-17-17, the applicant stated that stainless 

steel piping, piping components, heat exchanger components, and tanks and nickel alloy flex 

connections exposed to condensation will be managed for loss of material by the External 

Surfaces Monitoring Program. The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The GALL Report states that stainless steel and nickel alloys are 

susceptible only to loss of material in a condensation environment. Therefore, the staff finds 

that the applicant has identified all credible aging effects for this component, material, and 

environment combination. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The GALL Report contains guidance for managing loss of material of 

stainless steel and nickel alloy components in a condensation environment for internal surfaces 

only and recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to manage this aging effect. That program 

uses opportunistic and periodic visual inspections to identify loss of material. The applicant has 

identified these material and environment combinations for external surfaces and has, therefore, 

proposed the External Surfaces Monitoring Program to manage loss of material. The staff finds 

the applicant’s proposal to manage aging using the External Surfaces Monitoring Program 

acceptable because the periodic visual inspections in the program, which are conducted at least 

once per refueling cycle, are capable of detecting loss of material before loss of the intended 

function. 

On the basis of its review, the staff concludes that for items in LRA Table 3.2.2-8-1 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 
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Core Spray System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.2.2-8-2 

The staff reviewed LRA Table 3.2.2-8-2, which summarizes the results of AMR evaluations for 

the core spray system, nonsafety-related components affecting safety-related systems. The 

staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the core spray systems, 

nonsafety-related components affecting safety-related systems are consistent with the GALL 

Report. 

High-Pressure Coolant Injection System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA Table 3.2.2-8-3 

The staff reviewed LRA Table 3.2.2-8-3, which summarizes the results of AMR evaluations for 

the high-pressure coolant injection system, nonsafety-related components affecting 

safety-related systems. The staff’s review did not identify any AMR items with notes F through 

J, indicating that the combinations of component type, material, environment, and AERM for the 

high-pressure coolant injection system, nonsafety-related components affecting safety-related 

systems are consistent with the GALL Report. 

Reactor Core Isolation Cooling System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA Table 3.2.2-8-4 

Stainless Steel Piping Exposed to Steam. In LRA Table 3.2.2-8-4, the applicant stated that 

there is a TLAA for stainless steel piping exposed to steam; the TLAA cites generic note H. The 

staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for this component 

and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 piping is documented in 

SER Section 4.3.2.1. 

Containment Penetrations, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.2.2-8-5 

The staff reviewed LRA Table 3.2.2-8-5, which summarizes the results of AMR evaluations for 

the containment penetrations, nonsafety-related component affecting safety-related systems. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the containment 

penetrations, nonsafety-related component affecting safety-related systems are consistent with 

the GALL Report. 

Standby Gas Treatment System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.2.2-8-6 

The staff reviewed LRA Table 3.2.2-8-6, which summarizes the results of AMR evaluations for 

the standby gas treatment system, nonsafety-related components affecting safety-related 

systems. The staff’s review did not identify any AMR items with notes F through J, indicating 

that the combinations of component type, material, environment, and AERM for the standby gas 

treatment system, nonsafety-related components affecting safety-related systems are consistent 

with the GALL Report. 
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3.2.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effect of aging for the engineered safety features system components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

3.3 Aging Management of Auxiliary Systems 

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

auxiliary systems components and component groups of the following items: 

 control rod drive system 

 standby liquid control system 

 service water system 

 fuel pool cooling and cleanup system 

 emergency equipment cooling water system 

 compressed air system 

 fire protection – water system 

 fire protection – CO2 and halon system 

 combustion turbine generator system 

 emergency diesel generator system 

 heating, ventilation and air conditioning system 

 control center heating, ventilation and air conditioning system 

 containment atmospheric control system 

 plant drains system 

 fuel oil system 

 primary containment monitoring and leakage detection system 

 miscellaneous auxiliary systems in scope for 10 CFR 54.4(a)(2) 

3.3.1 Summary of Technical Information in the Application 

LRA Section 3.3 provides AMR results for the auxiliary systems components and component 

groups. LRA Table 3.3.1, “Summary of Aging Management Programs for Auxiliary Systems 

Evaluated in Chapter VII of NUREG-1801,” is a summary comparison of the applicant’s AMRs 

with those evaluated in the GALL Report for the auxiliary systems components and component 

groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.3.2 Staff Evaluation 

The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the auxiliary systems components within 

the scope of license renewal and subject to an AMR will be adequately managed so that the 
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intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

The staff conducted a review of the applicant’s AMRs to confirm the applicant’s claim that 

certain AMRs are consistent with the GALL Report, not applicable, or not used. The staff did 

not repeat its review of the matters described in the GALL Report; however, the staff did verify 

that the material presented in the LRA is applicable and that the applicant identified the 

appropriate GALL Report AMRs. The AMRs that the staff confirmed are consistent with the 

GALL Report are noted as such in SER Table 3.3-1, and no further discussion is required. The 

AMRs that the staff confirmed are not applicable to Fermi 2 or not used, because the 

component, material, and environment combination described in the SRP-LR does not exist for 

in-scope SCs at Fermi 2 or because the component, material, and environment combination is 

addressed by another SER Table 3.1-1 item, or that require no aging management are noted in 

SER Table 3.3-1 and are discussed in SER Section 3.3.2.1.1. Details of the staff’s evaluation of 

AMRs that the applicant claimed are consistent with the GALL Report, but for which a different 

AMP from the program recommended in the GALL Report is used to manage aging, and AMRs 

for which the staff requested additional information, are documented in SER Sections 3.3.2.1.2 

through 3.3.2.1.14. 

During its review, the staff also reviewed AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staff’s evaluations of 

AMRs for which the GALL Report recommends further evaluation are documented in SER 

Section 3.3.2.2. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs not consistent 

with, or not addressed in, the GALL Report are documented in SER Section 3.3.2.3. 

SER Table 3.3-1 summarizes the staff’s evaluation of components, aging effects or 

mechanisms, and AMPs that are listed in LRA Section 3.3 and are addressed in the GALL 

Report. 
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Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel Cranes: 

structural girders 

exposed to Air – 

indoor, uncontrolled 

(external) (3.3.1-1) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a timelimited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation for 

structural girders of 

cranes that fall within 

the scope of 

10 CFR 54 (see 

Standard Review 

Plan (SRP), 

Section 4.7, “Other 

Plant-Specific TimeLimited Aging 

Analyses,” for 

generic guidance for 

meeting the 

requirements of 

10 CFR 54.21(c)(1)) 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.1) 

Stainless steel, steel 

heat exchanger 

components and 

tubes, piping, piping 

components, and 

piping elements 

exposed to treated 

borated water, air - 

indoor, uncontrolled, 

treated water 

(3.3.1-2) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a timelimited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation (see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1). 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.1) 

Stainless steel heat 

exchanger 

components, nonregenerative 

exposed to treated 

borated water >60°C 

(>140°F) (3.3.1-3) 

Cracking due to 

stress corrosion 

cracking; cyclic 

loading 

Chapter XI.M2, 

“Water Chemistry.” 

The AMP is to be 

augmented by 

verifying the 

absence of cracking 

due to stress 

corrosion cracking 

and cyclic loading. 

An acceptable 

verification program 

is to include 

temperature and 

radioactivity 

monitoring of the 

shell side water, and 

eddy current testing 

of tubes. 

Yes, plantspecific Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.2.2) 
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Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.3.1-4) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

Yes, 

environmental 

conditions 

need to be 

evaluated 

External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.3) 

Steel (with stainless 

steel or nickel-alloy 

cladding) pump 

casings exposed to 

treated borated 

water (3.3.1-5) 

Loss of material 

due to cladding 

breach 

A plant-specific 

aging management 

program is to be 

evaluated. 

Reference NRC 

Information Notice 

94-63, “Boric Acid 

Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.” 

Yes, verify 

that plantspecific 

program 

addresses 

clad 

cracking 

Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.2.4) 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air–outdoor (3.3.1-6) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

Yes, 

environmental 

conditions 

need to be 

evaluated 

External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.5) 

Stainless steel highpressure pump, 

casing exposed to 

treated borated 

water (3.3.1-7) 

Cracking due to 

cyclic loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1) 

Stainless steel heat 

exchanger 

components and 

tubes exposed to 

treated borated 

water >60°C 

(>140°F) (3.3.1-8) 

Cracking due to 

cyclic loading 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1) 

Steel, aluminum, 

copper alloy (>15% 

Zn or >8% Al) 

external surfaces, 

piping, piping 

components, and 

piping elements, 

bolting exposed to 

air with borated 

water leakage 

(3.3.1-9) 

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, 

“Boric Acid 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1) 

Steel, high-strength 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-10) 

Cracking due to 

stress corrosion 

cracking; cyclic 

loading 

Chapter XI.M18, 

“Bolting Integrity” 

No Not used. There 

is no high-strength 

steel closure 

bolting used in 

auxiliary systems 

within the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-281 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel, high-strength 

high-pressure pump, 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-11) 

Cracking due to 

stress corrosion 

cracking; cyclic 

loading 

Chapter XI.M18, 

“Bolting Integrity” 

No Not used. There 

is no high-strength 

steel closure 

bolting used in 

auxiliary systems 

within the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Steel; stainless steel 

closure bolting, 

bolting exposed to 

condensation, air – 

indoor, uncontrolled 

(external), air – 

outdoor (external) 

(3.3.1-12) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program. Loss of 

material for steel 

and stainless steel 

bolting is 

managed by the 

Bolting Integrity 

Program. 

Consistent with the 

GALL Report 

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-13) 

Loss of material 

due to general 

corrosion 

Chapter XI.M18, 

“Bolting Integrity” 

No Not used. As 

stated in 

item 3.3.1-12, loss 

of material 

of steel bolting 

exposed to air in 

the auxiliary 

systems is 

managed by the 

Bolting Integrity 

Program. 

However, 

steam or water 

leakage is not 

considered as a 

separate aspect of 

the indoor air 

environment. 

Not used (see SER 

Section 3.3.2.1.1) 

Steel, stainless steel 

bolting exposed to 

soil (3.3.1-14) 

Loss of preload Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 

Steel; stainless 

steel, copper alloy, 

nickel alloy, stainless 

steel closure bolting, 

bolting exposed to 

air – indoor, 

uncontrolled 

(external), any 

environment, air – 

outdoor (external), 

raw water, treated 

borated water, fuel 

oil, treated water 

(3.3.1-15) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 
3-282 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60°C 

(>140°F) (3.3.1-16) 

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M25, 

“BWR Reactor 

Water Cleanup 

System” 

No Not used. 

Reactor water 

cleanup system 

piping 

downstream of 

the second 

containment 

isolation valve, 

4 inch NPS or 

greater that is 

above 200 °F 

during power 

operation, is 

carbon steel 

and is not subject 

to NRC Generic 

Letter 88-01 

requirements. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Stainless steel heat 

exchanger tubes 

exposed to treated 

water, treated 

borated water 

(3.3.1-17) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. There 

are no stainless 

steel heat 

exchanger tubes 

exposed to treated 

water with an 

intended function 

of heat transfer in 

the auxiliary 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Stainless steel highpressure pump, 

casing, piping, piping 

components, and 

piping elements 

exposed to treated 

borated water >60°C 

(>140°F), sodium 

pentaborate solution 

>60°C (>140°F) 

(3.3.1-18) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. The 

operating 

temperature of the 

standby liquid 

control system is 

below the 140 °F 

threshold for 

cracking in 

stainless steel. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Stainless steel 

regenerative heat 

exchanger 

components 

exposed to treated 

water >60°C 

(>140°F) (3.3.1-19) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. 

Regenerative 

heat exchanger 

components with 

an intended 

function for 

license renewal 

are made of 

carbon steel. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-283 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel, 

stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to treated 

borated water >60°C 

(>140°F), treated 

water >60°C 

(>140°F) (3.3.1-20) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.3.1-21) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-22) 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-23) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. Loss of 

material for 

aluminum 

components 

exposed to treated 

water is 

addressed 

in item 3.3.1-25 

Not used (see SER 

Section 3.3.2.1.1) 

Aluminum Piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-24) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. Loss of 

material for 

aluminum 

components 

exposed to treated 

water is 

addressed 

in item 3.3.1-25. 

Not used (see SER 

Section 3.3.2.1.1) 

Stainless steel, 

stainless steel; steel 

with stainless steel 

cladding, aluminum 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to treated 

water, sodium 

pentaborate solution 

(3.3.1-25) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 
3-284 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel (with stainless 

steel cladding) 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.3.1-26) 

Loss of material 

due to pitting 

and crevice 

corrosion (only 

after cladding 

degradation) 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. 

Elastomer 

linings are not 

credited for 

protection of 

piping in the 

scope of license 

renewal. 

Not used (see SER 

Section 3.3.2.1.1) 

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.3.1-27) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. There 

are no stainless 

steel heat 

exchanger tubes 

exposed to treated 

water with an 

intended function 

of heat transfer in 

the auxiliary 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements, 

piping; tanks 

exposed treated 

borated water 

(primary, oxygen 

levels controlled) 

>60°C (>140°F) 

(3.3.1-28) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1) 

Steel (with stainless 

steel cladding); 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

(primary, oxygen 

levels controlled) 

(3.3.1-29) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1) 

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-30) 

Changes in 

material 

properties due 

to aggressive 

chemical attack 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no concrete 

components 

exposed to raw 

water in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-285 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Fiberglass, HDPE 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (internal) 

3.3.1-30.5) 

Cracking, 

blistering, 

change in color 

due to water 

absorption 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no fiberglass 

or HDPE 

components 

exposed to raw 

water in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Concrete; 

cementitious 

material Piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-31) 

Cracking due to 

settling 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no concrete 

components 

exposed to raw 

water in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-32) 

Cracking due to 

aggressive 

chemical attack 

and leaching; 

changes in 

material 

properties due 

to aggressive 

chemical attack 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no reinforced 

concrete or 

asbestos cement 

components 

exposed to raw 

water in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Elastomer seals and 

components 

exposed to raw 

water (3.3.1-32.5) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation; 

loss of material 

due to erosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no elastomer 

components 

exposed to raw 

water in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-33) 

Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no concrete 

components 

exposed to raw 

water in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-286 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Nickel alloy, 

copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-34) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no nickel alloy 

components 

exposed to raw 

water in the 

auxiliary systems 

in the scope of 

license renewal. 

Copper alloy 

piping 

components 

exposed to raw 

water are 

addressed in item 

3.3.1-36. 

Not used (see SER 

Section 3.3.2.1.1) 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-35) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. Copper 

alloy piping 

components 

exposed to raw 

water are 

addressed in item 

3.3.1-36. 

Not used (see SER 

Section 3.3.2.1.1) 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-36) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-37) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 

Copper alloy, steel 

heat exchanger 

components 

exposed to raw 

water (3.3.1-38) 

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 
3-287 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-39) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. 

Stainless steel 

piping 

components 

exposed to raw 

water are 

addressed in 

items 3.3.1-40 and 

3.3.1-41. 

Not used (see SER 

Section 3.3.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-40) 

Loss of material 

due to pitting 

and crevice 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-41) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity Program 

Consistent with the 

GALL Report 

Copper alloy, 

titanium, stainless 

steel heat exchanger 

tubes exposed to 

raw water (3.3.1-42) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Service Water 

Integrity and 

Periodic 

Surveillance and 

Preventive 

Maintenance 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.2) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.3.1-43) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.3.1-44) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no stainless 

steel heat 

exchanger 

components 

exposed to 

closed-cycle 

cooling water 

>60 °C (>140 °F) 

in the auxiliary 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Steel Piping, piping 

components, and 

piping elements; 

tanks exposed to 

closed-cycle cooling 

water (3.3.1-45) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 
3-288 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel, copper alloy 

heat exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.3.1-46) 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to closedcycle cooling water 

(3.3.1-47) 

Loss of material 

due to 

microbiologically

-influenced 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Aluminum piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.3.1-48) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no aluminum 

components 

exposed to 

closed-cycle 

cooling water in 

the auxiliary 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

(3.3.1-49) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

Stainless steel, 

copper alloy, steel 

heat exchanger 

tubes exposed to 

closed-cycle cooling 

water (3.3.1-50) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Water Chemistry 

Control – Closed 

Treated Water 

Systems Program 

Consistent with the 

GALL Report 

BoraflexTM spent fuel 

storage racks: 

neutron-absorbing 

sheets (PWR), spent 

fuel storage racks: 

neutron-absorbing 

sheets (BWR) 

exposed to treated 

borated water, 

treated water 

(3.3.1-51) 

Reduction of 

neutronabsorbing 

capacity due to 

BoraflexTM 

degradation 

Chapter XI.M22, 

“Boraflex Monitoring”

No Boraflex 

Monitoring 

Program 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.3) 
3-289 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel cranes: rails 

and structural 

girders exposed to 

air – indoor, 

uncontrolled 

(external) (3.3.1-52) 

Loss of material 

due to general 

corrosion 

Chapter XI.M23, 

“Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to 

Refueling) Handling 

Systems” 

No Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling Systems 

Program 

Consistent with the 

GALL Report 

Steel cranes - rails 

exposed to air – 

indoor, uncontrolled 

(external) (3.3.1-53) 

Loss of material 

due to wear 

Chapter XI.M23, 

“Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to 

Refueling) Handling 

Systems” 

No Not used. Loss of 

material due to 

wear is the result 

of relative 

movement 

between two 

surfaces in 

contact with each 

other. General 

wear of crane rails 

may occur during 

the performance 

of the active 

function; as a 

result of improper 

design, 

application, or 

operation; or, to a 

very small degree, 

with insignificant 

consequences. 

Additionally, wear 

of crane rails due 

to rolling or sliding 

wheels is not 

expected in any 

measurable 

amount owing to 

infrequent crane 

use. Therefore, 

loss of material 

due to wear is not 

an aging effect 

requiring 

management for 

crane rails 

exposed to airindoor, 

uncontrolled. 

However, the 

condition of steel 

crane rails is 

monitored by the 

Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling Systems 

Program under 

item 3.3.1-52. 

Not used (see SER 

Section 3.3.2.1.4) 
3-290 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(3.3.1-54) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M24, 

“Compressed Air 

Monitoring” 

No Compressed Air 

Monitoring 

Program 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements: 

compressed air 

system exposed to 

condensation 

(internal) (3.3.1-55) 

Loss of material 

due to general 

and pitting 

corrosion 

Chapter XI.M24, 

“Compressed Air 

Monitoring” 

No Compressed Air 

Monitoring 

Program 

Consistent with the 

GALL Report 

Stainless steel 

Piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.3.1-56) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M24, 

“Compressed Air 

Monitoring” 

No Compressed Air 

Monitoring 

Program 

Consistent with the 

GALL Report 

Elastomers fire 

barrier penetration 

seals exposed to air 

- indoor, 

uncontrolled, air – 

outdoor (3.3.1-57) 

Increased 

hardness; 

shrinkage; loss 

of strength due 

to weathering 

Chapter XI.M26, 

“Fire Protection” 

No Fire Protection 

Program 

Consistent with the 

GALL Report 

Steel halon/carbon 

dioxide fire 

suppression system 

piping, piping 

components, and 

piping elements 

exposed to air – 

indoor, uncontrolled 

(external) (3.3.1-58) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M26, 

“Fire Protection” 

No Fire Protection 

Program 

Consistent with the 

GALL Report 

Steel fire rated doors 

exposed to air - 

indoor, uncontrolled, 

air – outdoor 

(3.3.1-59) 

Loss of material 

due to wear 

Chapter XI.M26, 

“Fire Protection” 

No Fire Protection 

and Structures 

Monitoring 

programs 

Consistent with the 

GALL Report 

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings and floors 

exposed to air - 

indoor, uncontrolled 

(3.3.1-60) 

Concrete 

cracking and 

spalling due to 

aggressive 

chemical attack, 

and reaction 

with aggregates 

Chapter XI.M26, 

“Fire Protection,” 

and Chapter XI.S6, 

“Structures 

Monitoring” 

No Fire Protection 

and Structures 

Monitoring 

programs 

Consistent with the 

GALL Report 

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings and floors 

exposed to air – 

outdoor (3.3.1-61) 

Cracking, loss 

of material due 

to freeze-thaw, 

aggressive 

chemical attack, 

and reaction 

with aggregates 

Chapter XI.M26, 

“Fire Protection,” 

and Chapter XI.S6, 

“Structures 

Monitoring” 

No Fire Protection 

and Structures 

Monitoring 

programs 

Consistent with the 

GALL Report 
3-291 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings and floors 

exposed to air - 

indoor, uncontrolled, 

air – outdoor 

(3.3.1-62) 

Loss of material 

due to corrosion 

of embedded 

steel 

Chapter XI.M26, 

“Fire Protection,” 

and Chapter XI.S6, 

“Structures 

Monitoring” 

No Fire Protection 

and Structures 

Monitoring 

programs 

Consistent with the 

GALL Report 

Steel fire hydrants 

exposed to air – 

outdoor (3.3.1-63) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M27, 

“Fire Water System” 

No Fire Water System 

Program 

Consistent with the 

GALL Report 

Steel, copper-alloy 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-64) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling 

Chapter XI.M27, 

“Fire Water System” 

No Fire Water System 

Program 

Consistent with the 

GALL Report 

Aluminum piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-65) 

Loss of material 

due to pitting 

and crevice 

corrosion; flow 

blockage due to 

fouling 

Chapter XI.M27, 

“Fire Water System” 

No Not used. There 

are no aluminum 

auxiliary system 

components 

exposed to raw 

water in the scope 

of license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-66) 

Loss of material 

due to pitting 

and crevice 

corrosion; 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling 

Chapter XI.M27, 

“Fire Water System” 

No Fire Water System 

Program 

Consistent with the 

GALL Report 

Steel tanks exposed 

to air – outdoor 

(external) (3.3.1-67) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Aboveground 

Metallic Tanks 

Program 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to fuel oil 

(3.3.1-68) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M30, 

“Fuel Oil Chemistry”, 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. Loss of 

material for steel 

components 

exposed to fuel oil 

is addressed in 

item 3.3.1-70. 

Not used (see SER 

Section 3.3.2.1.1) 
3-292 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to fuel oil 

(3.3.1-69) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.M30, 

“Fuel Oil Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Diesel Fuel 

Monitoring and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

fuel oil (3.3.1-70) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M30, 

“Fuel Oil Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Diesel Fuel 

Monitoring 

Program and OneTime Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel, 

aluminum piping, 

piping components, 

and piping elements 

exposed to fuel oil 

(3.3.1-71) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion 

Chapter XI.M30, 

“Fuel Oil Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Diesel Fuel 

Monitoring and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Gray cast iron, 

copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to treated 

water, closed-cycle 

cooling water, soil, 

raw water, 

wastewater 

(3.3.1-72) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching” 

No Selective 

Leaching Program 

Consistent with the 

GALL Report 

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air – 

outdoor (3.3.1-73) 

Changes in 

material 

properties due 

to aggressive 

chemical attack 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no concrete 

piping 

components in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air – 

outdoor (3.3.1-74) 

Cracking due to 

settling 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no concrete 

piping 

components in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-293 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to air – 

outdoor (3.3.1-75) 

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no concrete 

piping 

components in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Elastomers 

elastomer: seals and 

components 

exposed to air – 

indoor, uncontrolled 

(internal/external) 

(3.3.1-76) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.5) 

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air – 

outdoor (3.3.1-77) 

Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no concrete 

piping 

components in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Steel piping and 

components 

(external surfaces), 

ducting and 

components 

(external surfaces), 

ducting; closure 

bolting exposed to 

air – indoor, 

uncontrolled 

(external), air – 

indoor, uncontrolled 

(external), air – 

outdoor (external), 

condensation 

(external) (3.3.1-78) 

Loss of material 

due to general 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring, Fire 

Protection, and 

Service Water 

Integrity programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.6) 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(external) (3.3.1-79) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

Steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

(external), air – 

outdoor (external) 

(3.3.1-80) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 
3-294 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Copper alloy, 

aluminum piping, 

piping components, 

and piping elements 

exposed to air – 

outdoor (external), 

air – outdoor 

(3.3.1-81) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring and 

Service Water 

Integrity programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.7) 

Elastomers 

elastomer: seals and 

components 

exposed to air – 

indoor, uncontrolled 

(external) (3.3.1-82) 

Loss of material 

due to wear 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.8) 

Stainless steel diesel 

engine exhaust 

piping, piping 

components, and 

piping elements 

exposed to diesel 

exhaust (3.3.1-83) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.9) 

The SRP-LR, as 

amended by ISGs, 

does not list and 

Item No. (3.3.1-84) 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

Elastomers 

elastomer seals and 

components 

exposed to closedcycle cooling water 

(3.3.1-85) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

Elastomers 

elastomers, linings, 

elastomer: seals and 

components 

exposed to treated 

borated water, 

treated water, raw 

water (3.3.1-86) 

Hardening and 

loss of strength 

due to 

elastomer 

degradation 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

The SRP-LR, as 

amended by ISGs, 

does not list an Item 

No. (3.3.1-87) 

Not applicable Not applicable Not 

applicable 

Not applicable Not applicable 

Steel; stainless steel 

piping, piping 

components, and 

piping elements, 

piping, piping 

components, and 

piping elements, 

diesel engine 

exhaust exposed to 

raw water (potable), 

diesel exhaust 

(3.3.1-88) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 
3-295 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel, copper-alloy 

piping, piping 

components, and 

piping elements 

exposed to moist air 

or condensation 

(internal) (3.3.1-89) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

For fire water system 

components: 

Chapter XI.M27, 

“Fire Water System,” 

or for other 

components: 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

Steel ducting and 

components (internal 

surfaces) exposed to 

condensation 

(internal) (3.3.1-90) 

Loss of material 

due to general, 

pitting, crevice, 

and (for drip 

pans and drain 

lines) 

microbiologically

-influenced 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

wastewater 

(3.3.1-91) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components and 

Periodic 

Surveillance and 

Preventive 

Maintenance 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.10)

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(internal) (3.3.1-92) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Compressed Air 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.11)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (potable) 

(3.3.1-93) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

Stainless steel 

ducting and 

components 

exposed to 

condensation 

(3.3.1-94) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 
3-296 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Copper alloy, 

stainless steel, 

nickel alloy, steel 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components, piping, 

piping components, 

and piping elements; 

tanks exposed to 

wastewater, 

condensation 

(internal) (3.3.1-95) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components and 

Periodic 

Surveillance and 

Preventive 

Maintenance 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.12)

Elastomers 

elastomer: seals and 

components 

exposed to air – 

indoor, uncontrolled 

(internal) (3.3.1-96) 

Loss of material 

due to wear 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.8) 

Steel piping, piping 

components, and 

piping elements, 

reactor coolant 

pump oil collection 

system: tanks, 

reactor coolant 

pump oil collection 

system: piping, 

tubing, valve bodies 

exposed to 

lubricating oil 

(3.3.1-97) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel heat 

exchanger 

components 

exposed to 

lubricating oil 

(3.3.1-98) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Copper alloy, 

aluminum piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.3.1-99) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.3.1-100) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 
3-297 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Aluminum heat 

exchanger tubes 

exposed to 

lubricating oil 

(3.3.1-101) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not used. There 

are no aluminum 

heat exchanger 

tubes exposed to 

lube oil with an 

intended function 

of heat transfer in 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Boral®; boron steel, 

and other materials 

(excluding 

BoraflexTM) spent 

fuel storage racks: 

neutron-absorbing 

sheets (PWR), spent 

fuel storage racks: 

neutron-absorbing 

sheets (BWR) 

exposed to treated 

borated water, 

treated water 

(3.3.1-102) 

Reduction of 

neutronabsorbing 

capacity; 

change in 

dimensions and 

loss of material 

due to effects of 

SFP 

environment 

Chapter XI.M40, 

“Monitoring of 

Neutron-Absorbing 

Materials other than 

Boraflex” 

No NeutronAbsorbing 

Material 

Monitoring 

Program 

Consistent with the 

GALL Report 

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-103) 

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no buried 

concrete 

components in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

HDPE, fiberglass 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-104) 

Cracking, 

blistering, 

change in color 

due to water 

absorption 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no fiberglass 

or HDPE 

components 

exposed to soil or 

concrete in the 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Concrete cylinder 

piping, asbestos 

cement pipe piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-105) 

Cracking, 

spalling, 

corrosion of 

rebar due to 

exposure of 

rebar 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no concrete or 

asbestos cement 

components 

exposed to soil or 

concrete in the 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-298 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-106) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Buried and 

Underground 

Piping Program 

Consistent with the 

GALL Report 

Stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-107) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no buried or 

underground 

stainless steel or 

nickel alloy 

components 

exposed to soil 

or concrete in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Titanium, super 

austenitic, 

aluminum, copper 

alloy, stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements, 

bolting exposed to 

soil or concrete 

(3.3.1-108) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. None 

of the component 

type, material, and 

environment 

combinations 

represented by 

this item apply to 

components in 

auxiliary systems 

included in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Steel bolting 

exposed to soil or 

concrete (3.3.1-109) 

Loss of material 

due to general, 

pitting and 

crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Buried and 

Underground 

Piping Program 

Consistent with the 

GALL Report 

Underground 

aluminum, copper 

alloy, stainless steel, 

nickel alloy and steel 

piping, piping 

components, and 

piping elements 

(3.3.1-109.5) 

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Buried and 

Underground 

Piping Program 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60°C 

(>140°F) (3.3.1-110) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not used. 

Stainless steel 

components of the 

auxiliary systems 

subject to 

evaluation under 

the BWR Stress 

Corrosion 

Cracking Program 

were reviewed as 

part of the Class 1 

reactor coolant 

pressure 

boundary. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-299 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel structural steel 

exposed to air – 

indoor, uncontrolled 

(external) 

(3.3.1-111) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not used. Aging 

management 

review results for 

structural steel 

components are 

presented in, and 

compared to, 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

items in LRA 

Section 3.5. 

Not used (see SER 

Section 3.3.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.3.1-112) 

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 

2) plant OE indicates 

no degradation of 

the concrete 

No, if 

conditions 

are met. 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

Aluminum piping, 

piping components, 

and piping elements 

exposed to air – dry 

(internal/external), 

air – indoor, 

uncontrolled 

(internal/external), 

air – indoor, 

controlled (external), 

gas (3.3.1-113) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

(internal/external), 

air – dry, gas 

(3.3.1-114) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.3.1-115) 

None None NA - No 

AEM or 

AMP 

Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1) 
3-300 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Galvanized steel 

piping, piping 

components, and 

piping elements 

exposed to air - 

indoor, uncontrolled 

(3.3.1-116) 

None None NA - No 

AEM or 

AMP 

Not used. 

Galvanized (zinc) 

coating applied to 

some steel 

components is not 

credited for 

corrosion 

protection for 

license renewal. 

Not used (see SER 

Section 3.3.2.1.1) 

Glass Piping 

elements exposed to 

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 (3.3.1-117) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

(external) 

(3.3.1-118) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

Nickel alloy, PVC, 

glass piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage, air – indoor, 

uncontrolled, 

condensation 

(internal), 

wastewater 

(3.3.1-119) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

for glass 

components 

exposed to waste 

water. 

Consistent with the 

GALL Report 
3-301 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air – 

indoor, uncontrolled 

(internal/external), 

air – indoor, 

uncontrolled 

(external), air with 

borated water 

leakage, concrete, 

air – dry, gas 

(3.3.1-120) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to air – 

indoor, controlled 

(external), air – dry, 

gas (3.3.1-121) 

None None NA - No 

AEM or 

AMP 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

for steel 

components 

exposed to gas. 

Consistent with the 

GALL Report 

Titanium heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

or air – outdoor 

(3.3.1-122) 

None None NA - No 

AEM or 

AMP 

Not used. There 

are no titanium 

components 

included in 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Titanium (ASTM 

Grades 1,2, 7, 11, or 

12 that contains > 

5% aluminum or 

more than 0.20% 

oxygen or any 

amount of tin) heat 

exchanger 

components other 

than tubes, piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-123) 

None None NA - No 

AEM or 

AMP 

Not used. There 

are no titanium 

components 

included in 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-302 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Stainless steel, steel 

(with stainless steel 

or nickel-alloy 

cladding) spent fuel 

storage racks 

(BWR), spent fuel 

storage racks 

(PWR), piping, 

piping components, 

and piping elements; 

exposed to treated 

water >60°C 

(>140°F), treated 

borated water >60°C 

(>140°F) (3.3.1-124) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel (with stainless 

steel cladding); 

stainless steel spent 

fuel storage racks 

(BWR), spent fuel 

storage racks 

(PWR), piping, 

piping components, 

and piping elements 

exposed to treated 

water, treated 

borated water (3.3.1-

125) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Any material, piping, 

piping components, 

and piping elements 

exposed to treated 

water, treated water 

(borated), raw water 

(3.3.1-126) 

Wall thinning 

due to erosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Flow-Accelerated 

Corrosion and 

Service Water 

Integrity programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.13)

Metallic piping, 

piping components, 

and tanks exposed 

to raw water or 

wastewater (3.3.1-

127) 

Loss of material 

due to recurring 

internal 

corrosion 

A plant-specific 

aging management 

program is to be 

evaluated to address 

recurring internal 

corrosion 

Yes, plantspecific Periodic 

Surveillance and 

Preventive 

Maintenance 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.2.8) 

Steel, stainless 

steel, or aluminum 

tanks (within the 

scope of Chapter 

XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.3.1-128) 

Loss of material 

due to general 

(steel only), 

pitting, or 

crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only) 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Not used. There 

are no stainless 

steel or aluminum 

tanks (consistent 

with the scope of 

NUREG-1801, 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) in 

the auxiliary 

systems. Loss of 

material for steel 

tanks in outdoor 

air is addressed in 

item 3.3.1-67. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-303 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel tanks exposed 

to soil or concrete; 

air-indoor 

uncontrolled, raw 

water, treated water, 

wastewater, 

condensation (3.3.1-

129) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Aboveground 

Metallic Tanks 

Program 

Consistent with the 

GALL Report 

Metallic sprinklers 

exposed to airindoor controlled, 

air-indoor 

uncontrolled, airoutdoor, moist air, 

condensation, raw 

water, treated water 

(3.3.1-130) 

Loss of material 

due to general 

(where 

applicable), 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling 

Chapter XI.M27, 

“Fire Water System” 

No Fire Water System 

Program 

Consistent with the 

GALL Report 

Steel, stainless 

steel, copper alloy, 

or aluminum fire 

water system piping, 

piping components 

and piping elements 

exposed to airindoor uncontrolled 

(internal), airoutdoor(internal), or 

condensation 

(internal) (3.3.1-131) 

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

crevice, and 

microbiologically

-influenced 

corrosion, 

fouling that 

leads to 

corrosion; flow 

blockage due to 

fouling 

Chapter XI.M27, 

“Fire Water System” 

No Fire Water 

Systems and 

Periodic 

Surveillance and 

Preventive 

Maintenance 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.14)

Insulated steel, 

stainless steel, 

copper alloy, 

aluminum, or copper 

alloy (> 15% Zn) 

piping, piping 

components, and 

tanks exposed to 

condensation, airoutdoor (3.3.1-132) 

Loss of material 

due to general 

(steel, and 

copper alloy 

only), pitting, 

and crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(aluminum, 

stainless steel 

and copper alloy 

(>15% Zn) only) 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” (for 

tanks only) 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 
3-304 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Underground HDPE 

piping, piping 

components, and 

piping elements in 

an air-indoor 

uncontrolled or 

condensation 

(external) 

environment (3.3.1-

133) 

Cracking, 

blistering, 

change in color 

due to water 

absorption 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There 

are no 

underground 

HDPE piping 

components in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Steel, stainless 

steel, or copper-alloy 

piping, piping 

components, and 

piping elements, and 

heat exchanger 

components 

exposed to a raw 

water environment 

(for nonsafetyrelated components 

not covered by NRC 

GL 89-13) (3.3.1-

134) 

Loss of material 

due to general 

(steel and 

copper alloy 

only), pitting, 

crevice, and 

microbiologically

-influenced 

corrosion, 

fouling that 

leads to 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components” 

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Program 

Consistent with the 

GALL Report 

Steel or stainless 

steel pump casings 

submerged in a 

wastewater (internal 

and external) 

environment (3.3.1-

135) 

Loss of material 

due to general 

(steel only), 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.MI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no steel or 

stainless steel 

pump casings 

exposed internally 

and externally to 

waste water in the 

auxiliary systems 

in the scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Steel, stainless steel 

or aluminum fire 

water storage tanks 

exposed to airindoor uncontrolled, 

air-outdoor, 

condensation, moist 

air, raw water, 

treated water (3.3.1-

136) 

Loss of material 

due to general 

(steel only), 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion, 

fouling that 

leads to 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only) 

Chapter XI.M27, 

“Fire Water System” 

No Not used. There 

are no fire water 

storage tanks in 

the auxiliary 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 
3-305 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water, treated 

borated water 

(3.3.1-137) 

Loss of material 

due to general 

(steel only) 

pitting and 

crevice 

corrosion 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Not used Not applicable to 

Fermi 2 (see SER 

Section 3.3.2.1.1) 

Metallic 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, 

or fuel oil (3.3.1-138) 

Loss of coating 

or lining integrity 

due to blistering, 

cracking, 

flaking, peeling, 

delamination, 

rusting, or 

physical 

damage and 

spalling for 

cementitious 

coatings/linings 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Coating Integrity 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.3.3) 

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closed 

cycle cooling water, 

raw water, treated 

water, treated 

borated water, or 

lubricating oil (3.3.1-

139) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Not used Not used (see SER 

Section 3.3.2.1.1) 
3-306 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation 

Gray cast iron piping 

components with 

internal 

coatings/linings 

exposed to closed 

cycle cooling water, 

raw water, or treated 

water (3.3.1-140) 

Loss of material 

due to selective 

leaching 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Not used 

 

Not used (see SER 

Section 3.3.2.1.1) 

3.3.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the auxiliary systems components: 

 Aboveground Metallic Tanks 

 Bolting Integrity 

 Boraflex Monitoring 

 Buried and Underground Piping 

 Compressed Air Monitoring 

 Diesel Fuel Monitoring 

 External Surfaces Monitoring 

 Fire Protection 

 Fire Water System 

 Flow-Accelerated Corrosion 

 Internal Surfaces in Miscellaneous Piping and Ducting Components 

 Neutron-Absorbing Material Monitoring 

 Oil Analysis 

 One-Time Inspection 

 Periodic Surveillance and Preventive Maintenance 

 Selective Leaching 

 Service Water Integrity 

 Water Chemistry Control – BWR 

 Water Chemistry Control – Closed Treated Water Systems 

LRA Tables 3.3.2-1 through 3.3.2-17-36 summarize AMRs for the auxiliary system components 

and indicate AMRs that claimed to be consistent with the GALL Report. 

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components of these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR item. The notes describe how the information in 

the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

notes A through E, which indicate how the AMR was consistent with the GALL Report. 
3-307 

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions. 

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 

Note C indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as the component under review. The staff audited 

these AMR items to confirm consistency with the GALL Report. The staff also determined 

whether the AMR item of the different component applied to the component under review and 

whether the AMR was valid for the site-specific conditions. 

Note D indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions. 

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, the staff did confirm that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows. 

 AMR Results Identified as Not Applicable or Not Used 

For LRA Table 3.3.1, items 3.3.1-7, 3.3.1-8, 3.3.1-9, 3.3.1-28, 3.3.1-29, and 3.3.1-115, the 

applicant claimed that the corresponding AMR items in the GALL Report are not applicable 

because the associated items are only applicable to PWRs. The staff reviewed the SRP-LR; 

confirmed that these items only apply to PWRs; and finds that these items are not applicable to 

Fermi 2, which is a BWR. 
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For LRA Table 3.3.1, items 3.3.1-10, 3.3.1-11, 3.3.1-13, 3.3.1-16, 3.3.1-17, 3.3.1-18, 3.3.1-19, 

3.3.1-27, 3.3.1-30, 3.3.1-30.5, 3.3.1-31, 3.3.1-32, 3.3.1-32.5, 3.3.1-33, 3.3.1-44, 3.3.1-48, 

3.3.1-65, 3.3.1-73, 3.3.1-74, 3.3.1-75, 3.3.1-77, 3.3.1-101, 3.3.1-103, 3.3.1-104, 3.3.1-105, 

3.3.1-107, 3.3.1-108, 3.3.1-110, 3.3.1-111, 3.3.1-116, 3.3.1-122, 3.3.1-123, 3.3.1-128, 

3.3.1-133, 3.3.1-135, 3.3.1-136, and 3.3.1-137, the applicant claimed that the corresponding 

items in the GALL Report are not applicable or are not used because the component, material, 

and environment combination described in the SRP-LR does not exist for in-scope SCs at 

Fermi 2 or because the component, material, and environment combination is addressed by 

another Table 1 line item. The staff reviewed the LRA and UFSAR and confirmed that the 

applicant’s LRA does not have any AMR results applicable for these items or that the aging 

effects addressed by other Table 1 AMR line items are appropriate. 

LRA Table 3.3.1, items 3.3.1-23 and 3.3.1-24, address aluminum piping, piping components, 

and piping elements exposed to treated water. The GALL Report recommends GALL Report 

AMPs XI.M2, “Water Chemistry,” and XI.M32, “One-Time Inspection,” to manage loss of 

material due to pitting and crevice corrosion for this component group. The applicant stated that 

these AMR items are not used because loss of material for these aluminum components 

exposed to treated water are addressed by AMR item 3.3.1-25. The staff evaluated the 

applicant’s claim and found it acceptable because item 3.3.1-25 manages the loss of material 

for aluminum piping, piping components, and piping elements exposed to treated water in a 

manner consistent with items 3.3.1-23, 3.3.1-24 and the GALL Report recommendations. The 

staff also verified that aluminum piping components exposed to treated water in the auxiliary 

systems reference item 3.3.1-25. 

The staff concludes that, for AMR items 3.3.1-23 and 3.3.1-24, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

LRA Table 3.3.1, item 3.3.1-26, addresses loss of material for steel (with elastomer lining), steel 

(with elastomer lining or stainless steel cladding) piping, piping components, and piping 

elements exposed to treated water. The applicant stated that this item is not used because 

elastomer linings are not credited for protection of in-scope piping. Subsequent to the issuance 

of the LRA, the staff issued LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining 

Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat 

Exchangers, and Tanks.” LR-ISG-2013–01, which recommends GALL Report AMP XI.M42, 

“Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and 

Tanks,” to manage loss of coating or liner integrity. In addition, LR-ISG-2013-01 revised 

Table 3.3.1, item 3.3.1-26 to remove the reference to elastomer linings. By letter dated 

February 15, 2015, the applicant revised its LRA to address LR-ISG-2013-01. The staff noted 

that the applicant revised LRA Tables 3.2.2-3, 3.3.2-7, 3.3.2-10, 3.3.2-15, 3.3.2-17-5, 

3.3.2-17-15, and 3.3.2-17-28 to address steel piping and tanks exposed to various 

environments being managed for loss of coating integrity and cited generic note H for these 

AMR items. The staff’s evaluation of the addition of these new line items is documented in SER 

Section 3.3.2.3.3. 

LRA Table 3.3.1, items 3.3.1-34 and 3.3.1-35 address nickel alloy and copper-alloy piping, 

piping components, and piping elements exposed to raw water. The GALL Report recommends 

GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to manage loss of material 

due to various corrosion mechanisms for this component group. The applicant stated that these 

items are not used because copper-alloy piping components exposed to raw water are 
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addressed in item 3.3.1-36. The staff evaluated the applicant’s claim and finds it acceptable 

because the item cited by the applicant uses the Service Water Integrity Program, which 

corresponds to the Open-Cycle Cooling Water System Program in the GALL Report, and 

because it is appropriate for managing the associated copper-alloy piping components. 

LRA Table 3.3.1, item 3.3.1-39 addresses stainless steel piping, piping components, and piping 

elements exposed to raw water. The GALL Report recommends GALL Report AMP XI.M20, 

“Open-Cycle Cooling Water System,” to manage loss of material due to various corrosion 

mechanisms for this component group. The applicant stated that this item is not used because 

stainless steel piping components exposed to raw water are addressed in items 3.3.1-40 

and 3.3.1-41. The staff evaluated the applicant’s claim and finds it acceptable because the 

items cited by the applicant use the Service Water Integrity Program, which corresponds to the 

Open-Cycle Cooling Water System Program in the GALL Report, and because they are 

appropriate for managing the associated stainless steel piping components. 

LRA Table 3.3.1, item 3.3.1-68, addresses steel piping, piping components, and piping 

elements exposed to fuel oil. The GALL Report recommends GALL Report AMPs XI.M30, “Fuel 

Oil Chemistry,” and XI.M32, “One-Time Inspection,” to manage loss of material due to general, 

pitting, and crevice corrosion for this component group. The applicant stated that this item is not 

used because it is addressed by item 3.3.1-70. The staff evaluated the applicant’s claim and 

finds it acceptable because item 3.3.1-70 addresses steel piping, piping components, and piping 

elements; tanks exposed to fuel oil. The GALL Report also recommends GALL Report 

AMPs XI.M30 and XI.M32 to manage loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion. 

SER Table 3.3-1, items 3.3.1-139 and 3.3.1-140, reflect changes to the SRP-LR incorporated by 

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal 

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

ISG added these line items to allow applicants to credit the new GALL Report AMP XI.M42, 

“Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and 

Tanks,” to manage loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion; fouling that leads to corrosion; or selective leaching in 

certain components. The applicant did not credit the related plant-specific AMP, “Coating 

Integrity,” for the aging effect and components that reference SRP-LR items 3.3.1-139 and 

3.3.1-140 but instead credited alternate items and programs to manage the effects of these 

aging mechanisms for these components. For example, in regard to item 3.3.1-139, loss of 

material for the internally coated service water piping is managed by the Service Water Integrity 

Program. In regard to item 3.3.1-140, the no gray cast iron valve bodies exposed to raw water 

in the auxiliary systems are managed for loss of material due to selective leaching by the 

Selective Leaching Program. The staff finds this approach acceptable because the alternate 

items and programs used are adequate to manage the effects of aging for these components 

and this approach is consistent with GALL Report AMP XI.M42. 

 Reduction of Heat Transfer Due to Fouling 

LRA Table 3.3.1, item 3.3.1-42 addresses copper alloy, stainless steel, and titanium heat 

exchanger tubes exposed to raw water, which will be managed for fouling. For the AMR item 

that cites generic note E, the LRA credits the PSPM Program to manage the aging effect for 

copper alloy heat exchanger tubes. The GALL Report recommends GALL Report AMP XI.M20, 

“Open-Cycle Cooling Water System,” to ensure that this aging effect is adequately managed. 
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GALL Report AMP XI.M20 recommends using periodic performance monitoring or visual 

inspections to manage fouling of heat exchanger tubes. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The staff notes that this program proposes to manage the effects of aging for 

copper alloy heat exchanger tubes by visually inspecting the internal surfaces of the heat 

exchanger tubes at least once every 5 years. Based on its review of components associated 

with item 3.3.1-42 for which the applicant cited generic note E, the staff finds the applicant’s 

proposal to manage the effects of aging using the PSPM Program acceptable because it will 

perform comparable inspections at a comparable frequency as that of the Open-Cycle Cooling 

Water System Program, which are capable of detecting fouling before a loss of intended 

function. 

The staff concludes that LRA item 3.3.1-42, the applicant has demonstrated that the effects of 

aging for these components will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Reduction of Neutron-Absorbing Capacity Due to Boraflex Degradation 

LRA Table 3.3.1, item 3.3.1-51, addresses Boraflex spent fuel storage racks: 

neutron-absorbing sheets (PWR); spent fuel storage racks: neutron-absorbing sheets (BWR) 

exposed to treated borated water, treated water. The GALL Report recommends GALL Report 

AMP XI.M22, “Boraflex Monitoring,” to manage reduction of neutron-absorbing capacity due to 

Boraflex degradation. In a letter dated September 24, 2015, the applicant provided 

supplemental information on the continued use of the Boraflex material in the Fermi 2 spent fuel 

pool. The applicant stated that the Boraflex currently used in the spent fuel racks will not be 

credited for neutron absorption during the period of extended operation. Accordingly, the 

Boraflex Monitoring Program will not be relied upon during the period of extended operation. 

The applicant revised LRA Table 3.3.1, item 3.3.1-51, to no longer credit the Boraflex material 

or the Boraflex Monitoring Program during the period of extended operation. The staff’s 

evaluation of the discontinued reliance on the Boraflex material and the Boraflex Monitoring 

Program is documented in SER Section 3.0.3.2.2. 

 Loss of Material Due to Wear 

LRA Table 3.3.1, item 3.3.1-53 addresses steel cranes – rails exposed to air – indoor, 

uncontrolled (external). The GALL Report recommends GALL Report AMP XI.M23 “Inspection 

of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems” to manage 

loss of material due to wear for this component group. The applicant stated that this item is not 

used because of the following: 

[W]ear of crane rails due to rolling or sliding wheels is not expected in any 

measurable amount owing to infrequent crane use...[and that] the condition of 

steel crane rails is monitored by the Inspection of Overhead Heavy Load and 

Light Load (Related to Refueling) Handling Systems Program under 

Item 3.3.1-52. 

The staff reviewed the applicant’s claim and noted that item 3.3.1-52 of the SRP-LR manages 

loss of material due to general corrosion. The staff also noted that item 3.3.1-52 is used by the 

applicant in LRA Table 3.5.2-1, “Reactor/Auxiliary Building and Primary Containment,” and 
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Table 3.5.2-3, “Turbine Building, Process Facilities and Yard Structures,” for loss of material and 

for the same material (steel) and similar components as those managed by item 3.3.1-53. The 

staff further noted the LRA states that cranes and hoists meet the provisions of NUREG-0612, 

“Control of Heavy Loads at Nuclear Power Plants,” (ADAMS Accession No. ML070250180). 

NUREG-0612 specifies conformance of cranes and hoists to the American National Standard, 

(ASME B30.2, “Overhead and Gantry Cranes” safety standard, which is implemented in the 

proposed enhanced Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program; reviewed and documented in SER Section 3.0.3.2.13; and, for crane usage, 

to the Crane Manufacturers Association of America Specification No. 70 (CMAA-70). 

LRA Section 4.7.7, “Crane (Heavy Load) Cycles,” states that the reactor building crane meets 

the CMAA-70 Class A service (very infrequent usage) crane criteria with 7,170 anticipated 

number of lifts, which are well below the historical record of 500 annual lifts discussed in 

NUREG-0612. The turbine building crane is a limited access crane in accordance with UFSAR 

Section 12.1.2.2.3, “Turbine Building,” and is not subject to lift cycles consistent with the Electric 

Overhead Crane Institute Specification No. 61 (EOCI-61), “Specifications for Electric Traveling 

Cranes,” as verified by the staff during the audit. 

The staff finds the proposed approach acceptable because the proposed enhanced Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program and another line 

item monitor loss of material for corrosion or limited wear of the reactor and turbine building 

crane rails, because of the very infrequent crane usage, and because of the applicant’s 

implementation of ASME B30.2 safety standard for corrosion/wear inspection guidance by the 

proposed enhanced Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems Program. 

 Hardening and Loss of Strength Due to Elastomer Degradation 

LRA Table 3.3.1, item 3.3.1-76 addresses elastomeric flex connections exposed to indoor 

uncontrolled air (internal and external), which will be managed for hardening and loss of 

strength due to elastomer degradation. The GALL Report recommends GALL Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to ensure that this 

aging effect is adequately managed. 

LRA Tables 3.3.2-9 and 3.3.2-11 state that flex connections exposed to internal indoor air will 

be managed for cracking by the External Surfaces Monitoring Program. These components are 

also being managed for loss of material due to wear by the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program. The staff’s evaluation of the applicant’s External 

Surfaces Monitoring and Internal Surfaces in Miscellaneous Piping and Ducting Components 

programs is documented in SER Sections 3.0.3.2.7 and 3.0.3.1.11, respectively. The staff 

recognizes that internal cracking will not be detected by the External Surfaces Monitoring 

Program unless the cracking extends to the external surface of the component. However, the 

staff finds the applicant’s proposal to manage cracking on the internal surfaces of these 

components acceptable because the periodic visual and physical manipulation inspections for 

loss of material due to wear on internal surfaces can detect internal cracking in these 

components. 

The staff concludes that, for LRA item 3.3.1-76, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
3-312 

 Loss of Material Due to General Corrosion 

LRA Table 3.3.1, item 3.3.1-78, addresses carbon steel piping, ducting, and components that 

are exposed to indoor air, outdoor air, and condensation and that will be managed for loss of 

material due to general corrosion. For the AMR items that cite generic note E, the LRA credits 

the Service Water Integrity Program to manage the aging effect for carbon steel piping in the 

service water system and the Fire Protection Program to manage the aging effect for carbon 

steel piping and valve bodies in the CO2 and halon system. The GALL Report recommends 

GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to 

ensure that this aging effect is adequately managed. GALL Report AMP XI.M36 recommends 

using periodic visual inspections to manage the effects of aging. 

The staff’s evaluation of the applicant’s Service Water Integrity Program is documented in SER 

Section 3.0.3.2.21. The staff noted that LRA Section B.1.41 states that the program includes 

system walkdowns. In addition, as stated in LRA Table 3.3.1, item 3.3.1-78, the Service Water 

Integrity Program manages loss of material of the external surfaces of outdoor components in 

the service water system that are not routinely accessible for inspection under the External 

Surfaces Monitoring Program. Specifically, these components are associated with the RHR 

MDCTs. As referenced in the staff’s Audit Report of this program, the Service Water Integrity 

Program includes activities for inspecting the cooling tower component external surfaces when 

they become accessible (Station Procedures E1156 B001A and B; B002A and B). Based on its 

review of the subject service water components associated with item 3.3.1-78 for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage the effects of 

aging using the Service Water Integrity Program acceptable because inspections of external 

surfaces whenever the components become accessible are capable of identifying loss of 

material before loss of intended functions. 

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.9. The staff noted that the Fire Protection Program proposes to manage the 

effects of aging of carbon steel piping and valve bodies in the CO2 and halon system through 

the use of periodic visual inspections and functional tests. The staff noted that this approach is 

consistent with that recommended in GALL Report AMP XI.M26, “Fire Protection,” which states 

that periodic visual inspections and functional tests are performed to examine for signs of 

corrosion that may lead to loss of material. Based on its review of components in the CO2 and 

halon system associated with item 3.3.1-78 for which the applicant cited generic note E, the 

staff finds the applicant’s proposal to manage the effects of aging using the Fire Protection 

Program acceptable because periodic visual inspections are capable of detecting loss of 

material due to general corrosion. 

The staff concludes that, for LRA item 3.3.1-78, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.3.1, item 3.3.1-81, addresses copper alloy and aluminum piping, piping 

components, and piping elements exposed to outdoor air, which will be managed for loss of 

material due to pitting and crevice corrosion. For the AMR item that cites generic note E, the 

LRA credits the Service Water Integrity Program to manage the aging effect for copper alloy 

nozzles in the service water system. The GALL Report recommends GALL Report 
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AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to ensure that this 

aging effect is adequately managed. GALL Report AMP XI.M36 recommends using periodic 

visual inspections to manage the effects of aging. 

The staff’s evaluation of the applicant’s Service Water Integrity Program is documented in SER 

Section 3.0.3.2.21. The staff noted that LRA Section B.1.41 states that the program includes 

system walkdowns. In addition, as stated in LRA Table 3.3.1, item 3.3.1-78, the Service Water 

Integrity Program manages loss of material of the external surfaces of outdoor components in 

the service water system that are not routinely accessible for inspection under the External 

Surfaces Monitoring Program. Specifically, these components are associated with the RHR 

MDCTs. As referenced in the staff’s Audit Report of this program, the Service Water Integrity 

Program includes activities for inspecting the cooling tower component external surfaces when 

they become accessible (Station Procedures E1156 B001A and B; B002A and B). Based on its 

review of components associated with item 3.3.1-78 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage the effects of aging using the Service 

Water Integrity Program acceptable because inspections of external surfaces whenever the 

components become accessible are capable of identifying loss of material before loss of 

intended functions. 

The staff concludes that, for LRA item 3.3.1-81, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Loss of Material Due to Wear 

LRA Table 3.3.1, items 3.3.1-82 and 3.3.1-96, address elastomeric components exposed to 

indoor uncontrolled air (external and internal), which will be managed for loss of material due to 

wear. The GALL Report recommends GALL Report AMP XI.M36, “External Surfaces 

Monitoring of Mechanical Components,” and AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” respectively, to ensure that this aging effect is 

adequately managed. 

LRA Table 3.3.2-6 states that elastomeric flex connections exposed to indoor air (external and 

internal) will be managed for change in material properties and cracking by the External 

Surfaces Monitoring and Internal Surfaces in Miscellaneous Piping and Ducting Components 

programs. The table does not cite loss of material due to wear for these components. During 

the audit, the staff confirmed that these flex connections consist of flexible elastomeric hoses. 

GALL Report Section IX.F, “Selected Definitions & Use of Terms for Describing and 

Standardizing Aging Mechanisms,” states that wear can be due to intermittent relative motion, 

frequent manipulation, loosening of clamping force, or abrasive particles. The staff finds it 

acceptable that the applicant is not managing these components for loss of material due to wear 

because (a) flexible hoses are designed to accommodate relative motion and frequent 

manipulation with no degradation, (b) flexible hoses and their end fittings are not susceptible to 

loosening of clamping force, and (c) plant indoor air does not contain adequate abrasive 

particles to cause wear. 

The staff concludes that, for LRA items 3.3.1-82 and 3.3.1-96, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 
3-314 

 Cracking Due to Stress Corrosion Cracking 

LRA Table 3.3.1, item 3.3.1-83, addresses stainless steel diesel exhaust piping, piping 

components, and piping elements exposed to diesel exhaust. The GALL Report recommends 

GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” in order to manage loss of material due to pitting and crevice corrosion and 

cracking due to SCC for this component group. The applicant originally stated that they did not 

use this item and provided a discussion stating that “[t]he configuration of stainless steel diesel 

engine exhaust components precludes moisture collection necessary to concentrate 

contaminates, so these components are not susceptible to cracking.” 

The staff evaluated the applicant’s claim and found it unclear how the configuration of the 

stainless steel exhaust components prevent the accumulation of moisture and how the effects of 

other contaminants that may accumulate even without the collection of moisture are mitigated. 

By letter dated December 17, 2014, the staff issued RAI 3.3.2.3-1, requesting that the applicant 

state the basis as to why this material, environment, and aging effect combination does not 

apply or explain how loss of material due to pitting and crevice corrosion and cracking due to 

SCC will be managed for these components. 

In its response dated January 15, 2015, the applicant cited Appendix D Table 4-1 of Appendix D 

to EPRI TR-1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical 

Tools, Revision 4,” dated January 2006, and stated that “[s]usceptibility to pitting and crevice 

corrosion for stainless steel in an air/gas environment requires the presence of three conditions, 

including a wetted surface and potential for concentrating contaminants.” The applicant also 

stated that the vertical orientation of the EDG exhaust expansion joints preclude the 

accumulation of moisture needed to concentrate contaminants; therefore, pitting and crevice 

corrosion is not an applicable aging affect for this component. 

The staff evaluated the applicant’s response and found that, for most components, a vertical 

orientation would prevent the wetted condition for this aging effect. However, the staff found it 

unclear how the vertical orientation of the EDG exhaust expansion joints precludes the 

accumulation of moisture because stainless steel expansion joints generally include many 

vertical and horizontal segments and crevices, which can prevent proper drainage and allow for 

moisture accumulation in any orientation. By letter dated February 20, 2015, the staff issued 

followup RAI 3.3.2.3-1a, requesting that the applicant state the basis for why the EDG exhaust 

expansion joint’s vertical orientation precludes the collection of moisture or explain how it would 

manage loss of material due to pitting and crevice corrosion and stress corrosion cracking in 

these components during the period of extended operation. 

In its response dated March 19, 2015, the applicant revised LRA Table 3.3.2-10 to include AMR 

line items, which cite stainless steel expansion joints exposed to exhaust gas that will be 

managed for cracking and loss of material using the Internal Surfaces and Miscellaneous Piping 

and Ducting Components Program. 

The staff noted that the Internal Surfaces and Miscellaneous Piping and Ducting Components 

Program conducts visual inspections to detect cracking and loss of material. The staff finds this 

response acceptable because the applicant revised the LRA to ensure that it has identified the 

appropriate aging effects for the material and environment combination of the EDG exhaust 

expansion joints and that visual inspections are capable of detecting loss of material and 

cracking in stainless steel components. The staff’s concern described in RAI 3.3.2.3-1a is 

resolved. 
3-315 

The staff concludes that, for LRA item 3.3.1-83, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

LRA Table 3.3.1, item 3.3.1-91, addresses carbon steel piping, piping components, piping 

elements, and tanks exposed to wastewater, which will be managed for loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion. For the AMR items that cite 

generic note E, the LRA credits the PSPM Program to manage the aging effect for carbon steel 

piping, piping components, and tanks. The GALL Report recommends GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” to ensure that this aging effect is adequately managed. GALL Report 

AMP XI.M38 recommends using opportunistic visual inspections, with a representative sample 

of components inspected at least once every 10 years, to manage the effects of aging. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The program proposes to manage the effects of aging of the internal 

surfaces of a representative sample of carbon steel piping, piping components, and tanks 

through the use of periodic visual inspections (or ultrasonic inspections of components in the 

fuel pool cooling and cleanup system) with a frequency of at least once every 5 years. The LRA 

states that a representative sample is 20 percent of each population with the same material, 

environment, and aging effect combination, with a maximum of 25 components. Based on its 

review of components associated with item 3.3.1-91 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage the effects of aging using the PSPM 

Program acceptable because periodic visual or ultrasonic inspection of a representative sample 

of components is similar to the inspection approach recommended by the GALL Report and is 

capable of identifying loss of material before loss of component intended functions. 

The staff concludes that, for LRA item 3.3.1-91, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.3.1, item 3.3.1-92, addresses aluminum piping, piping components, and piping 

elements exposed internally to condensation, which will be managed for loss of material due to 

pitting and crevice corrosion. For the AMR item that cites generic note E, the LRA credits the 

Compressed Air Monitoring Program to manage this aging effect for aluminum valve bodies. 

The GALL Report recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to ensure that the noted aging effect is 

adequately managed. GALL Report AMP XI.M38 recommends using visual inspections of all 

accessible surfaces whenever the piping or ducting is opened for any reason and minimally 

during each 10-year period during the period of extended operation on a sampling basis. 

The staff’s evaluation of the applicant’s Compressed Air Monitoring Program is documented in 

SER Section 3.0.3.2.4. The staff noted that Compressed Air Monitoring Program proposes to 

manage the effects of aging for aluminum valve bodies through the use of periodic and 
3-316 

opportunistic inspections of accessible internal surfaces of piping and other components. 

Based on its review of components associated with item 3.3.1-92 for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage aging using the Compressed 

Air Monitoring Program acceptable because the opportunistic and periodic visual inspections of 

accessible internal surfaces of the valve bodies for any signs of loss of material will ensure that, 

if such degradation is occurring, it will be detected before a loss of intended function. 

The staff concludes that, for LRA item 3.3.1-92, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

LRA Table 3.3.1, item 3.3.1-95 addresses stainless steel and copper-alloy piping, piping 

components, piping elements, and tanks exposed to wastewater, which will be managed for loss 

of material due to pitting, crevice, and microbiologically-influenced corrosion. For the AMR 

items that cite generic note E, the LRA credits the PSPM Program to manage the aging effect 

for stainless steel, copper alloy, and copper alloy with greater than 15 percent zinc or 8 percent 

aluminum piping, piping components, and tanks. The GALL Report recommends GALL Report 

AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” to ensure that this aging effect is adequately managed. GALL Report 

AMP XI.M38 recommends using opportunistic visual inspections, with a representative sample 

of components inspected at least once every 10 years, to manage the effects of aging. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The program proposes to manage the effects of aging of the internal 

surfaces of a representative sample of piping, piping components, and tanks through the use of 

periodic visual inspections with a frequency of at least once every 5 years. The LRA states that 

a representative sample is 20 percent of each population with the same material, environment, 

and aging effect combination, with a maximum of 25 components. Based on its review of 

components associated with item 3.3.1-95 for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage the effects of aging using the PSPM Program 

acceptable because periodic visual inspection of a representative sample of components is 

similar to the inspection approach recommended by the GALL Report and is capable of 

identifying loss of material before loss of component intended functions. 

The staff concludes that, for LRA item 3.3.1-95, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Wall Thinning Due to Erosion 

LRA Table 3.3.1, item 3.3.1-126, addresses piping, piping components and piping elements 

exposed to treated water, treated borated water, and raw water, which will be managed for wall 

thinning due to erosion. For the AMR items that cite generic note E, the LRA credits the Service 

Water Integrity Program to manage the aging effect for carbon steel, stainless steel, and 

copper-alloy piping, tubing, pump casings, valves, flow elements, nozzles, thermowells, and 

orifices. The GALL Report recommends GALL Report AMP XI.M17, “Flow-Accelerated 
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Corrosion” to ensure that this aging effect is adequately managed through the use of periodic 

thickness measurements. 

The staff’s evaluation of the applicant’s Service Water Integrity Program is documented in SER 

Section 3.0.3.2.21. The staff notes that the Service Water Integrity Program proposes to 

manage the effects of aging for various components through routine inspections and 

maintenance activities. The staff also notes that the LRA includes an enhancement to the 

“detection of aging effects” program element to revise the Service Water Integrity Program 

procedures by including inspections to identify loss of material due to erosion in the system. 

Based on its review of components associated with item 3.3.1-126 for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage the effects of aging using the 

Service Water Integrity Program acceptable because the program is being specifically 

enhanced to include loss of material due to erosion. 

The staff concludes that, for LRA item 3.3.1-126, the applicant has demonstrated that the 

effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Flow Blockage Due to Fouling 

As amended by letter dated January 15, 2015, LRA Table 3.3.1, item 3.3.1-131, addresses 

carbon steel piping exposed to an air-indoor (internal) environment, which will be managed for 

flow blockage due to fouling. For the AMR item that cites generic note E, the LRA credits the 

PSPM Program to manage this aging effect. The GALL Report recommends GALL Report 

AMP XI.M27, “Fire Water System,” as modified by LR-ISG-2012-02, “Aging Management of 

Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under 

Insulation,” to ensure that this aging effect is adequately managed. GALL Report AMP XI.M27 

recommends using periodic visual inspections to manage the effects of aging. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The staff’s evaluation of the use of the PSPM Program to manage flow 

blockage due to fouling for the carbon steel piping exposed to an air-indoor (internal) 

environment in the fire protection water system is documented in SER Section 3.0.3.2.10 in the 

staff’s evaluation of the response to RAI B.1.19-1. 

The staff concludes that, for LRA item 3.3.1-131, the applicant has demonstrated that the 

effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended 

In LRA Section 3.3.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the auxiliary system components and provides information concerning how 

it will manage the following aging effects: 

 cumulative fatigue damage 

 cracking due to SCC and cyclic loading 

 cracking due to SCC 
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 loss of material due to cladding breach 

 loss of material due to pitting and crevice corrosion 

 QA for aging management of nonsafety-related components 

 ongoing review of operating experience 

 loss of material due to recurring internal corrosion 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.3.2.2. The staff’s review of the applicant’s 

further evaluation follows. 

 Cumulative Fatigue Damage 

LRA Section 3.3.2.2.1 states that where fatigue is identified as an AERM for piping, and piping 

for components designed to ASME Code requirements, or for plant cranes and girders designed 

to CMAA-70 requirements, the analysis of fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs 

are evaluated in accordance with 10 CFR 54.21(c)(1). Evaluations of these TLAAs are 

addressed in LRA Sections 4.3 and 4.7. 

LRA Section 3.3.2.2.1, associated with LRA Table 3.3.1, item 3.3.1-1, addresses steel cranes 

and girders exposed to an air-indoor uncontrolled environment, which will be managed for 

cumulative fatigue damage or cracking induced by fatigue. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the assessment of cumulative fatigue damage 

or cracking by fatigue in the associated reactor building crane is a TLAA, as defined in 

10 CFR 54.3. The applicant stated that the applicable TLAA is evaluated in accordance with 

10 CFR 54.21(c)(1) and is addressed in LRA Section 4.7.7. 

LRA Section 3.3.2.2.1, associated with LRA Table 3.3.1, item 3.3.1-2, addresses steel and 

stainless steel piping, piping components, piping elements, heat exchanger components, and 

heat exchanger tubes exposed to treated borated water, treated water, or an air-indoor 

uncontrolled environment, which will be managed for cumulative fatigue damage or cracking 

induced by fatigue (i.e., aging effects induced by cyclical loading). The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that assessment of fatigue in these 

components is a TLAA, as defined in 10 CFR 54.3. The applicant stated that the applicable 

TLAA is evaluated in accordance with 10 CFR 54.21(c)(1) and is addressed in LRA Section 4.3. 

By letter dated May 9, 2016, the applicant amended the LRA to include two new AMR items for 

steel piping, piping components, and valve bodies in the BDBEE mitigation (Fukushima) 

system. The new AMR items, associated with LRA Table 3.2.1-1, item 3.2.1-1, address steel 

piping, piping components, and valve bodies exposed to an internal treated water environment, 

which will be managed for cumulative fatigue damage or cracking due to fatigue. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that the assessment of fatigue 

in these components is a TLAA, as defined in 10 CFR 54.3. The applicant stated that the 

applicable TLAA is evaluated in accordance with 10 CFR 54.21(c)(1) and is addressed in LRA 

Section 4.3. 

The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR Section 3.3.2.2.1, which 

state that cumulative fatigue damage or cracking due to fatigue of these components is a TLAA 

and must be evaluated in accordance with the TLAA acceptance criteria requirements of 
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10 CFR 54.21(c). The staff reviewed the applicant’s AMR line items and determined that the 

AMR results are consistent with the recommendations of the GALL Report and SRP-LR for 

managing cumulative fatigue damage in these components. The staff verified that the 

applicable metal fatigue TLAA for the Non-Class 1 auxiliary system components is given in LRA 

Section 4.3.2, “Non-Class 1 Fatigue Analyses,” and that the applicable cyclical loading TLAA for 

the reactor building crane is given in LRA Section 4.7.7, “Crane (Heavy Load) Cycles.” 

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.3.2.2.1 criteria. For those line items that apply to LRA Section 3.3.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). The staff’s evaluation of the metal fatigue analyses for 

these auxiliary system components is documented in SER Section 4.3.2, “Non-Class 1 Fatigue 

Analyses.” The staff’s evaluation of the cyclical loading analysis for the reactor building crane is 

documented in SER Section 4.7.7, “Crane (Heavy Load) Cycles.” 

 Cracking Due to Stress Corrosion Cracking and Cyclic Loading 

LRA Section 3.3.2.2.2 is associated with LRA Table 3.3.1, item 3.3.1-3, and addresses cracking 

due to SCC and cyclic loading in stainless steel nonregenerative heat exchanger components 

exposed to treated borated water in PWR chemical and volume control systems. The applicant 

stated that this item is not applicable because it pertains to PWR nonregenerative heat 

exchanger components. The staff evaluated the applicant’s claim and finds it acceptable 

because this item only applies to PWRs. 

 Cracking Due to Stress Corrosion Cracking 

LRA Section 3.3.2.2.3, associated with LRA Table 3.3.1, item 3.3.1-4, addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air, which will be 

managed for cracking due to SCC by the External Surfaces Monitoring Program. The criteria in 

SRP-LR Section 3.3.2.2.3 state that cracking could occur for stainless steel components 

exposed to outdoor air environments containing sufficient halides and in which condensation or 

deliquescence is possible. The SRP-LR also states that the possibility for cracking extends to 

components exposed to air that has recently been introduced to buildings. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that cracking of stainless steel 

components directly exposed to outdoor air will be managed by the External Surfaces 

Monitoring Program. The applicant also stated that there are no indoor stainless steel auxiliary 

system components located near outdoor air intakes that could also be subject to this aging 

effect. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The program includes an enhancement to revise procedures to ensure 

that walkdowns inspect for leakage to detect cracking in stainless steel components exposed to 

air containing halides. However, several AMR items associated with item 3.3.1-4 have a 

gaseous internal environment. As a result, it was unclear to the staff how walkdowns of external 

surfaces will effectively use leakage as an indicator of cracking. By letter dated 

December 19, 2014, the staff issued RAI B.1.16-1, requesting that the applicant state the 

parameters inspected and the inspection method(s) that it will use to determine whether 

cracking is present on the gas-filled outdoor components. The staff’s evaluation of the response 

to RAI B.1.16-1 is documented in SER Section 3.0.3.2.7. 
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In its review of components associated with item 3.3.1-4, the staff finds that the applicant has 

met the further evaluation criteria and that its proposal to manage the effects of aging using the 

External Surfaces Monitoring Program is acceptable because visual inspections and 

augmenting visual inspections by using techniques, such as soap bubbles and trending 

performance data, are methods capable of detecting cracking before loss of intended function, 

as documented in SER Section 3.0.3.2.7. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.3.2.2.3 criteria. For those items associated with LRA Section 3.3.2.2.3, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Loss of Material Due to Cladding Breach 

LRA Section 3.3.2.2.4, associated with LRA Table 3.3.1, item 3.3.1-5, addresses loss of 

material due to cladding breach in PWR steel charging pump casings with stainless steel 

cladding exposed to treated borated water. The applicant stated that this item is not applicable 

because it only applies to PWRs. The staff confirmed that this item is associated only with PWR 

plants; therefore, the staff finds the applicant’s determination acceptable. 

 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Section 3.3.2.2.5, associated with LRA Table 3.3.1, item 3.3.1-6, addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air, which will be 

managed for loss of material due to pitting and crevice corrosion by the External Surfaces 

Monitoring Program. The criteria in SRP-LR Section 3.3.2.2.5 state that loss of material could 

occur for stainless steel components exposed to outdoor air environments containing sufficient 

halides and in which condensation or deliquescence is possible. The SRP-LR also states that 

the possibility for loss of material extends to components exposed to air that has recently been 

introduced to buildings. The applicant addressed the further evaluation criteria of the SRP-LR 

by stating that loss of material of stainless steel components directly exposed to outdoor air will 

be managed by the External Surfaces Monitoring Program. The applicant also stated that there 

are no indoor stainless steel auxiliary system components located near outdoor air intakes that 

could also be subject to this aging effect. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The staff noted that the applicant’s program includes periodic visual 

inspections of external surfaces, which are conducted at least once per refueling cycle, to 

identify corrosion and any other conditions that preclude the stainless steel from having a clean, 

shiny surface. In its review of components associated with item 3.3.1-6, the staff finds that the 

applicant has met the further evaluation criteria and that its proposal to manage the effects of 

aging using the External Surfaces Monitoring Program is acceptable because the periodic visual 

inspections described above are capable of identifying loss of material before loss of intended 

functions. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.3.2.2.5 criteria. For those items associated with LRA Section 3.3.2.2.5, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
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function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

 Ongoing Review of Operating Experience 

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience for AMPs. 

 Loss of Material Due to Recurring Internal Corrosion 

LRA Section 3.3.2.2.8, associated with LRA Table 3.3.1, item 3.3.1-127, addresses metallic 

piping, piping components, and tanks exposed to raw water or wastewater, which will be 

managed for loss of material due to recurring internal corrosion by the PSPM Program. The 

criteria in SRP-LR Section 3.3.2.2.8 state that recurring internal corrosion can result in the need 

to augment AMPs beyond the recommendations in the GALL Report. The SRP-LR also states 

that recurring internal corrosion can be identified by an operating experience search for 

repeated instances where an aging effect resulted in a component either not meeting 

plant-specific acceptance criteria or experiencing a reduction in wall thickness greater than 

50 percent. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that recurring internal corrosion was identified in carbon steel piping components exposed to 

raw water in the auxiliary systems. The applicant also stated that this aging effect will be 

managed with the PSPM Program by monitoring wall thickness at selected locations and by 

replacing pipe where necessary. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The program includes periodic wall thickness measurement at selected 

locations based on pipe configuration, flow conditions, and operating history. A minimum of five 

inspections of carbon steel piping exposed to raw water will be performed each year until the 

rate of recurring internal corrosion occurrences no longer meets the operating experience 

criteria in the further evaluation that prompted the augmented inspections. 

In its review of components associated with item 3.3.1-127, the staff finds that the applicant has 

met the further evaluation criteria and that its proposal to manage the effects of aging using the 

PSPM Program is acceptable because the applicant’s proposal increases the minimum number 

and frequency of inspections beyond those recommended by the GALL Report such that 

recurring corrosion can be effectively monitored before a loss of intended function. The GALL 

Report program to manage the internal surfaces of piping in raw water (outside of the fire 

protection and safety-related service water systems), GALL Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,” recommends the 

inspection of a maximum of 25 locations in each 10-year period, with no provision to perform 

inspections every year. In contrast, the applicant proposes to examine a minimum of 

50 locations in each 10-year period, with inspections occurring each year. 

Based on the program identified, the staff determines that the applicant’s program meets the 

criteria in SRP-LR Section 3.3.2.2.8. For those items associated with LRA Section 3.3.2.2.8, 

the staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
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function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

For LRA Tables 3.3.2-1 through 3.3.2-17-36, the staff reviewed additional details of the AMR 

results for material, environment, AERM, and AMP combinations not consistent with, or not 

addressed in, the GALL Report. 

In LRA Tables 3.3.2-1 through 3.3.2-17-36, the applicant indicated, through notes F through J, 

that the combination of component type, material, environment, and AERM does not correspond 

to a line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations that are not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections. 

 Control Rod Drive System – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-1 

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the 

CRD system component groups. The staff’s review did not identify any AMR items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for the CRD system component groups are consistent with the GALL Report. 

 Standby Liquid Control System – Summary of Aging Management Review – LRA 

Table 3.3.2-2 

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the 

standby liquid control system component groups. The staff’s review did not identify any AMR 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the standby liquid control system component groups are consistent 

with the GALL Report. 

 Service Water Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-3 

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the 

service water systems component groups. 
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Carbon Steel and Stainless Steel Piping, Piping Components Heat Exchanger Components and 

Tanks Exposed to Treated Water, Raw Water, Lubricating Oil, and Fuel Oil. As amended by 

letter dated February 15, 2015, LRA Tables 3.3.2-3, 3.3.2-7, 3.3.2-10, 3.3.2-15, 3.3.2-17-5, 

3.3.2-17-15, and 3.3.2-17-28 state that carbon steel and stainless steel piping, piping 

components, heat exchanger components, and tanks exposed to treated water, raw water, 

lubricating oil, and fuel oil will be managed for loss of coating integrity by the Coating Integrity 

Program. The AMR items cite generic note H. 

The staff noted that, although the applicant cited generic note H, LR-ISG-2013-01, “Aging 

Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope 

Piping, Piping Components, Heat Exchangers, and Tanks,” provides AMR line items to address 

this MEAP combination. SRP-LR Table 3.3 1, item 3.3.1-138, states that metallic piping, piping 

components, heat exchangers, and tanks with internal coatings/linings exposed to raw water, 

treated water, lubricating oil, or fuel oil are managed for loss of coating integrity by GALL Report 

AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat 

Exchangers, and Tanks. 

The staff’s evaluation of the applicant’s Coating Integrity Program is documented in SER 

Section 3.0.3.2.24. The staff finds the applicant’s proposal to manage the effects of aging using 

the Coating Integrity Program acceptable because periodic visual inspections of internal 

coatings by qualified personnel are capable of detecting loss of coating integrity. 

Carbon Steel and Stainless Steel Closure Bolting Exposed to Condensation (External). In LRA 

Tables 3.2.2-8-1, 3.3.2-3, 3.3.2-5, 3.3.2-10, 3.3.2-11, 3.3.2-12, 3.3.2-17-16, 3.3.2-17-17, 

and 3.3.2-17-28, the applicant stated that carbon steel and stainless steel closure bolting 

exposed to condensation (external) will be managed for loss of preload by the Bolting Integrity 

Program. The AMR items cite plant-specific note H, which states that the aging effect is not in 

the GALL Report for this component, material, and environment combination. 

However, the staff noted that this material and environment combination is identified in the 

GALL Report, which states that steel and stainless steel closure bolts exposed to uncontrolled 

indoor air (uncontrolled indoor air is an environment associated with systems with temperatures 

higher than the dew point, (i.e., condensation can occur, but only rarely)) are susceptible to loss 

of preload and loss of material. The GALL Report recommends GALL Report AMP XI.M18, 

“Bolting Integrity,” to manage the aging effects for closure bolting. The applicant addressed the 

GALL Report identified aging effect of loss of material for this component, material, and 

environment combination in other AMR items in LRA Tables 3.3.2-3, 3.3.2-5, 3.3.2-10, 3.3.2-11, 

3.3.2-12, 3.3.2-17-17, and 3.3.2-17-28. 

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.1. The staff noted that the Bolting Integrity Program proposes to manage the 

aging effect of loss of preload of closure bolting by performing periodic visual inspections of 

closure bolts and taking preventive actions, such as applying the appropriate preload and 

checking for uniformity of gasket compression to prevent loss of preload. The staff finds the 

applicant’s proposal to manage loss of preload using the Bolting Integrity Program acceptable 

because, consistent with the GALL Report recommendations, the program includes periodic 

visual inspections capable of detecting loss of preload and preventive actions to minimize the 

potential for loss of preload before loss of intended function. 

Carbon Steel and Stainless Steel Closure Bolting Exposed to Raw Water (External). In LRA 

Tables 3.3.2-3, 3.3.2-7, and 3.3.2-10, the applicant stated that carbon steel and stainless steel 
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closure bolting exposed to raw water will be managed for loss of material by the Bolting Integrity 

Program. The AMR items cite plant-specific note H, which states that the aging effect is not in 

the GALL Report for this component, material, and environment combination. However, the 

staff noted that this material and environment combination is identified in the GALL Report, 

which states that steel and stainless steel bolts exposed to raw water are susceptible to loss of 

material and loss of preload and recommends GALL Report AMP XI.M18, “Bolting Integrity,” to 

manage the aging effects. The applicant addressed the GALL Report identified aging effect of 

loss of material for this component, material, and environment combination in other AMR items 

in LRA Tables 3.3.2-7 and 3.3.2-10. 

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.1. The staff notes that GALL Report AMP XI.M18 recommends periodic 

inspections (at least once per refueling cycle) of closure bolting for signs of leakage to ensure 

the detection of age-related degradation due to loss of material. The staff also noted that a 

submerged (raw water) environment limits the ability to detect leakage of submerged bolted 

connections; therefore, the applicant’s explanation on how the program will detect loss of 

material before a loss of intended function was not clear. By letters dated December 19, 2014, 

and April 4, 2015, the staff issued RAIs B.1.2-2 and B.1.2-2a to address this issue. The issue is 

resolved and documented in SER Section 3.0.3.2.1. Based on its review of information 

provided in the applicant’s responses to RAIs B.1.2-2 and B.1.2-2a and revisions to LRA 

Sections A.1.2, A.4, and B.1.2, the staff noted that the Bolting Integrity Program proposes to 

manage the aging effect of loss of material for closure bolting submerged in raw water by 

performing the following activities: 

 Taking preventive actions consistent with the GALL Report to minimize the potential of 

lubricant-related degradation. 

 Performing visual inspections, at least once every RFO, of bolt head and exposed bolt 

threads to detect loss of material. 

 Quarterly monitoring of pump performance, which can result in the detection of 

age-related degradation of the submerged bolting. 

 Performing opportunistic inspections of the bolts, including the nonexposed area of the 

bolt threads, during pump maintenance activities. 

The staff finds the applicant’s proposal to manage loss of material for closure bolts submerged 

in raw water using the Bolting Integrity Program acceptable because the combination of the 

activities described above are able to detect and adequately manage these aging effects before 

a loss of intended function. 

Stainless Steel Piping and Piping Components Exposed to Condensation. The staff’s 

evaluation for stainless steel piping and piping components exposed to condensation, which will 

be managed for loss of material by the External Surfaces Monitoring Program and are 

associated with generic note G, is documented in SER Section 3.2.2.3.8. 

Elastomer Flex Connections Exposed to Outdoor Air. In LRA Table 3.3.2-3, the applicant stated 

that elastomer flex connections exposed to outdoor air will be managed for changes in material 

properties, cracking, and loss of material due to wear by the External Surfaces Monitoring 

Program. The AMR items cite generic note G. 
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The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The GALL Report states that elastomeric components exposed to 

air environments are susceptible to increased hardness, shrinkage, loss of strength, and loss of 

material due to wear. Because the aging effects proposed by the applicant effectively describe 

those identified in the GALL Report, the staff finds that the applicant has identified all credible 

aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The staff finds the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable because the program’s periodic visual 

inspections and physical manipulation of elastomer external surfaces, which are conducted at 

least once per refueling cycle, are capable of detecting degradation of elastomer components 

by observations of cracking, scuffing, discoloration, and hardening. 

Elastomer Flex Connections Exposed to Gas, Condensation, Fuel Oil, Lubricating Oil, and 

Steam. In LRA Tables 3.3.2-3, 3.3.2-6, 3.3.2-9, and 3.4.2-3-5, the applicant stated that 

elastomer flex connections exposed to gas, condensation, fuel oil, lubricating oil, and steam will 

be managed for cracking and changes in material properties by the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program. The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. GALL Report Table IX.E, as revised by LR-ISG-2012-02, states 

that elastomers can experience increased hardness, shrinkage, loss of sealing, cracking, and 

loss of strength. GALL Report AMR items also cite the aging effects of hardening and loss of 

strength for elastomer components in air and water environments. Because the aging effects 

proposed by the applicant effectively describe those identified in the GALL Report, the staff 

finds that the applicant has identified all credible aging effects for this component, material, and 

environment combination. 

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.11. The program includes both 

visual inspections and physical manipulation or pressurization to characterize elastomer 

degradation. The staff finds the applicant’s proposal to manage aging using the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program acceptable because the 

opportunistic visual inspections and physical manipulation conducted by the program, with a 

representative sample of components inspected at least once every 10 years, are capable of 

detecting cracking and changes in material properties of elastomer components by observations 

of cracking, other surface discontinuities, discoloration, and hardening. 

Carbon Steel Piping Exposed to Raw Water. As amended by letter dated June 9, 2015, LRA 

Table 3.3.2-3 states that carbon steel piping exposed to raw water will be managed for loss of 

coating integrity by the Service Water Integrity Program. The AMR item cites generic note H 

and plant-specific note 312. Plant-specific note 312 states that “[t]he One-Time Inspection 

Program will supplement the Service Water Integrity Program for the galvanized piping in the 

mechanical draft cooling tower spray assemblies.” 

The staff noted that, although the applicant cited generic note H, LR-ISG-2013-01, “Aging 

Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope 

Piping, Piping Components, Heat Exchangers, and Tanks,” provides an AMR line item to 
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address this MEAP combination. SRP-LR Table 3.3-1, item 3.3.1-138, states that metallic 

piping with internal coatings exposed to raw water are managed for loss of coating integrity by 

GALL Report AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, 

Heat Exchangers, and Tanks.” 

The applicant removed the MDCT spray assemblies from the scope of the Coating Integrity 

Program and proposed to use the Service Water Integrity and One-Time Inspection programs to 

manage loss of coating integrity for these components. The staff’s evaluation of the applicant’s 

proposal to use the Service Water Integrity and One-Time Inspection programs to manage loss 

of coating integrity for these components is documented in SER Section 3.0.3.2.24. The staff 

finds the applicant’s proposal to manage the effects of aging using the Service Water Integrity 

and One-Time Inspection programs acceptable because periodic flow tests and one-time wall 

thickness measurements, with a criterion to conduct periodic wall thickness measurements if 

necessary, are capable of detecting loss of coating integrity. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-3 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Fuel Pool Cooling and Cleanup System – Summary of Aging Management 

Review – LRA Table 3.3.2-4 

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the 

fuel pool cooling and cleanup system component groups. The staff’s review did not identify any 

AMR items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the fuel pool cooling and cleanup system component groups are 

consistent with the GALL Report. 

 Emergency Equipment Cooling Water System – Summary of Aging Management 

Review – LRA Table 3.3.2-5 

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the 

emergency equipment cooling water system component groups. 

Carbon Steel and Stainless Steel Closure Bolting Exposed to Condensation (External). The 

staff’s evaluation for carbon steel and stainless steel closure bolting exposed to condensation 

(external), which will be managed for loss of preload by the Bolting Integrity Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.3. 

Nickel Alloy Flexible Connections Exposed to Treated Water. In LRA Table 3.3.2-5, the 

applicant stated that nickel alloy flex connections exposed to treated water (internal) will be 

managed for loss of material by the Water Chemistry Control – Closed Treated Water Systems 

Program. The AMR item cites generic note G. LRA Table 3.3.2-5 also states that cracking due 

to fatigue is a TLAA. The AMR item cites generic note H. The staff’s review of TLAAs is 

discussed in SER Section 4.2. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The staff notes that the applicant addressed cracking due to 

fatigue for this component, material, and environment combination in other AMR items in LRA 
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Table 3.3.2-5. Based on its review of GALL Report Table VIII.B1, which states that stainless 

steel components exposed to treated water can experience loss of material due to pitting and 

crevice corrosion, the staff believes that corrosion of nickel alloy would be very similar (i.e., both 

alloy systems could be susceptible to loss of materials due to crevice and pitting corrosion). 

Therefore, the staff finds that the aging effects proposed by the applicant conservatively 

describe those essentially identified in the GALL Report and that the applicant has identified all 

credible aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program is documented in SER Section 3.0.3.2.23. The program includes both 

inspections and control of water chemistry to mitigate the effects of corrosion. The staff finds 

the applicant’s proposal to manage aging using the Water Chemistry Control – Closed Treated 

Water Systems Program acceptable because the inspections are capable of detecting loss of 

material if it is occurring, whereas the control of water chemistry will mitigate the effects of 

corrosion. 

Stainless Steel Piping and Piping Components and Nickel Alloy Flex Connections Exposed to 

Condensation. The staff’s evaluation for stainless steel piping and piping components and 

nickel alloy flex connections exposed to condensation, which will be managed for loss of 

material by the External Surfaces Monitoring Program and are associated with generic note G, 

is documented in SER Section 3.2.2.3.8. 

Nickel, Steel, and Stainless Steel Flex Connections Exposed to Treated Water. In LRA 

Table 3.3.2-5, the applicant stated that there are TLAAs for nickel, steel, and stainless steel flex 

connections exposed to treated water that cite generic note H. The staff confirmed that there 

are TLAAs, as documented in LRA Section 4.3.2, for these components and materials. The 

staff’s evaluation of the fatigue TLAAs for non-Class 1 components, other than piping, is 

documented in SER Section 4.3.3.2. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-5 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Compressed Air Systems – Summary of Aging Management Review – LRA 

Table 3.3.2-6 

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the 

compressed air systems component groups. 

Nickel Alloy Flex Connector Exposed to Internal Condensation. In LRA Table 3.3.2-6, the 

applicant stated that nickel alloy flex connectors exposed to internal condensation will be 

managed for loss of material by the Compressed Air Monitoring Program. The AMR item cites 

generic note F. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. For nickel alloy, cracking is a potential aging effect in 

high-temperature, highly caustic solutions (ASM International’s Metals Handbook). Because the 

nickel alloy flex connectors are not exposed to such an environment, cracking is not a credible 
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aging effect. Based on the above, the staff finds that the applicant has identified all credible 

aging effects for these component, material, and environment combinations. 

The staff’s evaluation of the applicant’s Compressed Air Monitoring Program is documented in 

SER Section 3.0.3.2.4. The staff finds the applicant’s proposal to manage the loss of material 

using the Compressed Air Monitoring Program acceptable because the Compressed Air 

Monitoring Program prevents moisture and contaminants from occurring within the system by 

monitoring the air quality. In addition, periodic internal visual inspections of critical components 

are performed to detect signs of corrosion. 

Elastomer Flex Connections Exposed to Condensation. The staff’s evaluation for elastomer flex 

connections exposed to condensation, which will be managed for cracking and changes in 

material properties by the Internal Surfaces in Miscellaneous Piping and Ducting Component 

Program and are associated with generic note G, is documented in Section 3.3.2.3.3. 

Aluminum, Copper Alloy, Copper Alloy with Greater Than 15 percent Zinc (inhibited), and 

Stainless Steel Heat Exchanger Fins and Tubes Exposed to Indoor Air, Outdoor Air, and 

Condensation. In LRA Tables 3.3.2-6, 3.3.2-10, 3.3.2-11, and 3.3.2-12, the applicant stated that 

aluminum, copper alloy, copper alloy with greater than 15 percent zinc (inhibited), and stainless 

steel heat exchanger fins and tubes exposed to indoor air, outdoor air, and condensation will be 

managed for fouling by the Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program. The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. For the subject heat exchanger fins and tubes that were cited as 

having a pressure boundary intended function (in addition to heat transfer), the applicant 

addressed loss of material in other AMR items in LRA Tables 3.3.2-6, 3.3.2-11, and 3.3.2-12. 

The LRA did not address loss of material for the subject heat exchanger fins and tubes that 

were cited as having only a heat transfer intended function. Nevertheless, for the one subject 

component in which loss of material may occur (copper alloy tubes exposed to condensation in 

LRA Table 3.3.2-11), the visual inspections for fouling conducted by the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program are capable of identifying loss of 

material before the heat transfer function of the fins and tubes are challenged. Therefore, the 

staff finds that the applicant has identified all credible aging effects for this component, material, 

and environment combination. 

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.11. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the opportunistic visual inspections conducted by 

the program, with a representative sample of components inspected at least once every 

10 years, are capable of detecting fouling of the heat exchanger surfaces before loss of the 

intended function. 

Steel and Stainless Steel Piping, Valve Bodies, and Flex Connections Exposed to 

Condensation. In LRA Table 3.3.2-6 the applicant stated that there are TLAAs for steel and 

stainless steel piping, valve bodies, and flex connections exposed to condensation that cite 

generic note H. The staff confirmed that there are TLAAs, as documented in LRA Section 4.3, 

for these components and materials. The staff’s evaluation of the fatigue TLAAs for piping, 

valve bodies, and flex connections is documented in SER Sections 4.3.1 and 4.3.2. 
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On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-6 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Fire Protection – Water System – Summary of Aging Management Review – 

LRA Table 3.3.2-7 

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the 

fire protection – water system component groups. 

Carbon Steel and Stainless Steel Piping, Piping Components, Heat Exchanger Components, 

and Tanks Exposed to Treated Water, Raw Water, Lubricating Oil, and Fuel Oil. The staff’s 

evaluation for carbon steel and stainless steel piping, piping components, heat exchanger 

components, and tanks exposed to treated water, raw water, lubricating oil, and fuel oil, which 

will be managed for loss of coating integrity by the Coating Integrity Program and are associated 

with generic note H, is documented in SER Section 3.3.2.3.3. 

Stainless Steel Closure Bolting Exposed to Raw Water (External). The staff’s evaluation for 

stainless steel closure bolting exposed to raw water (external), which will be managed for loss of 

material by the Bolting Integrity Program and is associated with generic note H, is documented 

in SER Section 3.3.2.3.3. 

Steel Piping Exposed to Exhaust Gas. In LRA Table 3.3.2-7 the applicant stated that there is a 

TLAA for steel piping exposed to exhaust gas that cites generic note H. The staff confirmed that 

there is a TLAA, as documented in LRA Section 4.3.1, for this component and material. The 

staff’s evaluation of the fatigue TLAA for Class 1 piping is documented in SER Section 4.3.1.6. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-7 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Fire Protection – CO2 and Halon System – Summary of Aging Management 

Review – LRA Table 3.3.2-8 

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the 

fire protection – CO2 and halon system component groups. 

Teflon® Flex Connections Exposed to Indoor Air and Gas. In LRA Table 3.3.2-8, the applicant 

stated that, for Teflon® flex connections exposed externally to indoor air and internally to gas, 

there is no aging effect and no proposed AMP. The AMR items cite generic note F. 

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environmental combination. Based on its review, 

the staff identified the following potential environmental factors that could result in age-related 

degradation: 

 Table 1 of National Aeronautics and Space Administration Technical 

Memorandum 105753, “High Temperature Dielectric Properties of Apical, Kapton, Peek, 

Teflon® AF, and Upilex Polymers,” A.N. Hammoud, dated 1992, states that Teflon® can 
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handle long-term temperatures up to 285 degrees Celsius (°C); however, there are 

studies that demonstrate that certain grades of Teflon® degrade when exposed to 

radiation. 

 PTFE [Teflon®] Expansion Joint Engineering Guide, 2200, Ethylene LLC, Kentwood, MI, 

www.ethylene.com, accessed on October 20, 2014, states that the service life of 

Teflon® flexible connections will be reduced if it is subject to scratching, abrasion, and 

weld splatter. 

 DuPont Teflon® PTFE Fluoropolymer Resin Properties Handbook, 

http://www.rjchase.com/ptfe_handbook.pdf, accessed on October 20, 2014, states that 

Teflon®-based products are susceptible to creep. 

The staff lacked sufficient information to conclude that the radiation levels are low enough in the 

vicinity of the flex connections. In addition, although external scratching, abrasion, and weld 

splatter could be considered as event driven, these mechanisms can occur in the power plant 

environment as a matter of course. Further, the staff lacks sufficient information to conclude 

that, with creep, the material will retain sufficient material properties throughout the period of 

extended operation. By letter dated December 17, 2014, the staff issued RAI 3.3.2.3.8-1, 

requesting that the applicant (a) state the specific Teflon® material type for these flexible 

connections, (b) state the basis for why there is no AERM and no proposed AMP, and 

(c) explain how the aging effects will be managed if the specific Teflon® material type does age. 

In its response dated January 15, 2015, the applicant stated that (a) the expected cumulative 

radiation exposure for these components is less than 104 rads, (b) the Teflon® material is 

contained within a stainless steel wire braid cover and, therefore, is not susceptible to 

scratching, abrasion, and weld splatter, and (c) the flex connections are not normally 

pressurized and, therefore, are not susceptible to creep. 

The staff noted that NRC IN 2014-04, “Potential for Teflon® Material Degradation in 

Containment Penetrations, Mechanical Seals and Other Components,” dated March 26, 2014, 

cites the Westinghouse Electric Company report entitled, “AP1000® Design Control Document,” 

Revision 19, Tier 2 Chapter 3, Appendix 3D, “Methodology for Qualifying AP1000 

Safety-Related Electrical and Mechanical Equipment.” The Westinghouse Electric Company 

document states that, “for a gamma dose of less than 104 rads, there are no observable 

radiation effects that impact material mechanical properties.” 

The staff reviewed several commercial websites on January 29, 2015, http://navyaviation. 

tpub.com/14018/css/14018_228.htm, http://www.titeflex.com/industrial/products/PTFE/ 

index.html, http://www.herberaircraft.com/pdf/Hoses%20tech%20broch(new)/Teflon%20Hoses/ 

666%20Crimp%20Fittings%20eng%20bulletin.PDF. These websites state that Teflon® (PTFE) 

hose assemblies do not have shelf-life limitations, PTFE is chemically inert, it will not break 

down or deteriorate in service, and the service- and shelf-life of a Teflon® hose is unlimited for 

all practical purposes. The staff noted that Licensee Event Report (LER) 285/2012-002-01, 

“Inadequate Qualifications for Containment Penetrations Renders Containment Inoperable,” 

dated July 2, 2013 (ADAMS Accession No. ML13184A270), documents physical testing of 

electrical penetration assemblies with Teflon® seals and Teflon®-insulated conductors 

conducted between November 2012 and February 2013. The penetration assemblies had been 

in service for 39 years. The testing consisted of exposing the assembly to additional irradiation 

and then exposing the assemblies to a design basis accident test profile. The Teflon® seals 

passed helium leak test criteria. Based on its review of these references, the staff concluded 

that Teflon® flex connections exposed externally to indoor air and internally to gas are not 
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subject to an AERM as long as the components environmental conditions (e.g., temperature 

and exposure) are not beyond threshold values for Teflon®. 

The staff finds the applicant’s response and proposal that there are no AERMs acceptable 

because (a) Teflon® has a radiation exposure threshold higher than the cumulative dose to 

which the components will be exposed, (b) Teflon® has a temperature exposure threshold much 

higher than what the components would be exposed to in the CO2 and halon system, (c) the 

Teflon® material is protected from scratching, abrasion, and weld splatter by the stainless steel 

braided covering, and (d) the material is not pressurized and it is designed as a flexible 

connections and is, therefore, not subject to creep. In addition, based on a review of GALL 

Report, item AP-23, there are no AERMs for stainless steel piping components exposed to 

indoor air. The staff’s concern described in RAI 3.3.2.3.8-1 is resolved. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-8 with no 

AERMs, the applicant has appropriately evaluated the material and environment combinations 

not addressed in the GALL Report, and their intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 Combustion Turbine Generator – Summary of Aging Management 

Evaluation – LRA Table 3.3.2-9 

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the 

combustion turbine generator system component groups. 

Glass and Stainless Steel Filters Exposed to Indoor Air. In LRA Table 3.3.2-9, the applicant 

stated that glass and stainless steel filters exposed to indoor air will be managed for fouling by 

the PSPM Program. The AMR items cite generic note H. 

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that glass and stainless steel exposed to indoor air are not susceptible to any 

aging effects. However, the applicant has identified fouling as an aging effect for filters that 

have an intended function of filtration. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The applicant’s program includes periodic visual inspections and cleaning of 

the atomizing air booster compressor suction filter and the compressor extraction air filter in the 

combustion turbine generator system. These activities are performed at least once every 

5 years to manage fouling. The staff finds the applicant’s proposal to manage the effects of 

aging using the PSPM Program acceptable because periodic visual inspections and cleaning 

can ensure that the filtration function of the subject components are maintained. 

Copper Alloy Heat Exchanger Tubes Exposed to Indoor Air. In LRA Table 3.3.2-9, the applicant 

stated that copper alloy heat exchanger tubes exposed to indoor air will be managed for fouling 

and loss of material due to wear by the PSPM Program. The AMR items cite generic notes G 

(fouling) and H (loss of material). 

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper alloy exposed to uncontrolled indoor air is not susceptible to any aging 

effects. However, the applicant has identified fouling and loss of material due to wear as aging 

effects on the external surfaces of heat exchanger tubes. 
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The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The applicant’s program includes periodic visual inspections of a 

representative sample of atomizing air precooler heat exchanger tubes to manage fouling and 

loss of material due to wear. The representative sample is inspected at least once every 

5 years. The staff finds the applicant’s proposal to manage the effects of aging using the PSPM 

Program acceptable because periodic visual inspections of a sample of the heat exchanger tube 

external surfaces is capable of identifying fouling and wear before loss of intended function. 

Copper Alloy with Greater than 15 percent Zinc Heat Exchanger Tubes Exposed to Lubricating 

Oil and Treated Water. In LRA Tables 3.3.2-9 and 3.3.2-10, the applicant stated that copper 

alloy with greater than 15 percent zinc heat exchanger tubes exposed to lubricating oil and 

closed treated water will be managed for loss of material due to wear by the PSPM Program. 

The AMR items cite generic note H. 

The staff noted that these material and environment combinations are identified in the GALL 

Report, which states that copper alloy heat exchanger tubes exposed to lubricating oil and 

closed treated water are susceptible to fouling and loss of material due to corrosion and which 

recommends GALL Report AMPs XI.M39, “Lubricating Oil Analysis,” and XI.M32, “One-Time 

Inspection” to manage the aging effects in the lubricating oil environment and GALL Report 

AMP XI.M21A, “Closed Treated Water Systems,” to manage the aging effects in the closed 

treated water environment. However, the applicant has identified loss of material due to wear 

as an additional aging effect. The applicant addressed the GALL Report identified aging effects 

for this component, material, and environment combination in other AMR items in LRA 

Tables 3.3.2-9 and 3.3.2-10. 

The staff’s evaluation of the applicant’s PSPM Program is documented in SER 

Section 3.0.3.3.1. The applicant’s program includes periodic visual inspections of a 

representative sample of lubricating oil and jacket water (closed treated water) heat exchanger 

tubes to manage loss of material due to wear. The representative sample is inspected at least 

once every 5 years. The staff finds the applicant’s proposal to manage the effects of aging 

using the PSPM Program acceptable because periodic visual inspections of a sample of the 

heat exchanger tube external surfaces is capable of identifying wear before loss of intended 

function. 

Carbon Steel Closure Bolting Exposed to Lube Oil (External). In LRA Tables 3.3.2-9 and 

3.3.2-12 the applicant stated that carbon steel closure bolting exposed to lube oil (external) will 

be managed for loss of material and loss of preload by the Bolting Integrity Program. The AMR 

items cite generic note G, which states that the environment is not in the GALL Report for this 

component and material combination. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. Based on its review of the GALL Report, which recommends that 

steel components (other than heat exchangers) exposed to lubricating oil be managed for loss 

of material and that closure steel bolts (that are not made of high strength steel) be managed for 

loss of material and loss of preload, the staff finds that the applicant has identified all credible 

aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.2.1. The staff notes that, consistent with the GALL Report AMP XI.M18 

recommendations, the Bolting Integrity Program includes preventive measures, such as proper 
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torqueing of bolts and checking for uniformity of gasket compression to minimize loss of 

preload. 

GALL Report AMP XI.M18 also recommends periodic inspections (at least once per refueling 

cycle) of closure bolting for signs of leakage to ensure the detection of age-related degradation 

due to loss of material and loss of preload. The LRA states that the bolts were exposed to a 

lube oil (exterior) environment. Based on the LRA description of the lube oil (exterior) 

environment, it was not clear whether the bolts in a lube oil (exterior) environment were always 

submerged in lube oil. The staff was concerned that, if the bolts are always submerged in lube 

oil, the ability to detect leakage in the submerged bolted connections would be limited. If 

leakage cannot be readily detected, the program would not be able to use leakage as an 

indicator of loss of material and loss of preload for submerged bolted connections before loss of 

intended function. By letter dated January 14, 2015, the staff issued RAI 3.3.2.9-1 requesting 

that the applicant state whether the closure bolts are submerged in lube oil and describe how 

the program will be capable of detecting loss of material and loss of preload for these bolts, 

including how the proposed bolting inspections will be capable of detecting loss of material in 

the threaded regions, below the bolt head, that are not readily visible. 

In its response dated February 12, 2015, the applicant stated that the bolting is submerged in 

lubricating oil and located in lube oil pumps that are internal to a machine in a lube oil sump in 

the nonsafety-related combustion turbine generator system and safety-related control center 

HVAC system. The applicant clarified that these pumps are inaccessible during normal 

operation. The applicant noted that, due to the inaccessibility of the pumps, it is impractical to 

inspect the submerged bolting every RFO as recommended by GALL Report AMP XI.M18. 

Therefore, the applicant stated that an exception to the GALL Report recommended frequency 

of inspections will be taken for the inspection of these submerged bolts. The applicant also 

noted that Appendix C to EPRI TR-1010639, “Non-Class 1 Mechanical Implementation 

Guideline and Mechanical Tools, Revision 4,” dated January 2006, states that lubricating oil 

systems generally do not suffer appreciable degradation by cracking or loss of material because 

the environment is not conducive to corrosion mechanisms. In its response, the applicant also 

described the following activities to manage the aging effects of loss of material and loss of 

preload in the submerged closure bolting: 

 To minimize the potential for loss of material and loss of preload, preventive measures 

that are consistent with the GALL Report AMP XI.M18 recommendations will be taken 

under the Bolting Integrity Program. The preventive actions consist of the selection of 

materials and lubricants, application of the appropriate preload, and checking for 

uniformity of gasket compression of closure bolting. 

 The lube oil pump and associated submerged bolting in the control center HVAC system 

will be inspected during scheduled disassembly and inspection preventive maintenance 

events, which occur at an 8- to 10-year frequency. Bolting issues could result in indirect 

degradation of lube oil performance. During system operation, lube oil pressure is 

monitored, and degradation of lube oil performance will be identified, entered into the 

corrective action program, and may result in pump repair or refurbishment. The 

associated bolting, including the bolting threads, will be inspected during these 

maintenance activities to ensure that loss of material in the thread area of the bolt will be 

detected. 

 The lube oil pump in the combustion turbine generator system has a good performance 

record and no performance maintenance events are scheduled. This lube oil pump and 

associated submerged closure bolting will be subject to opportunistic inspections 
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(e.g., whenever the lube oil sump is drained). During system operation, lube oil pressure 

is monitored, and degradation of lube oil performance will be identified, entered into the 

Corrective Action Program, and may result in pump repair or refurbishment. 

The staff notes that, as part of its response to RAI 3.3.2.9-1, the applicant also revised LRA 

Sections A.1.2, and B.1.2 to incorporate new exceptions, enhancements, and commitments to 

the Bolting Integrity Program. The staff’s review of the exceptions, enhancements, and 

commitments related to the Bolting Integrity Program is documented in SER Section 3.0.3.2.1. 

The staff noted that the information cited by the applicant from Appendix C of EPRI TR-1010639 

is consistent with the GALL Report guidance, which states that steel, when exposed to 

lubricating oil with some water, will have limited susceptibility to aging degradation due to 

general or localized corrosion. The staff needed clarification on whether the environment to 

which the closure bolts were exposed was always lube oil or whether the bolts were exposed 

during prolonged periods to a water environment that could cause them to be susceptible to 

accelerated corrosion. In addition, based on the applicant’s statement that lube oil pressure is 

monitored and that degradation of lube oil performance could be identified and could lead to 

corrective actions, the frequency at which the pressure is monitored such that corrective actions 

would be taken before the loss of intended function of the bolts was unclear. The staff needed 

this information in consideration of the fact that the program does not include periodic visual 

inspections to detect the loss of material and loss of preload for submerged bolted connections. 

Therefore, in a telephone conference call held in March 6, 2015, the staff requested clarification 

on the RAI response regarding whether the closure bolts were always exposed to a lube oil 

submerged environment or whether there were periods in which they were exposed to a water 

environment. The staff also requested clarification on how often the applicant monitors the lube 

oil pressure of the pumps. The applicant stated that, other than during maintenance activities, 

the bolts were always exposed to a lube oil environment. The applicant stated that 

maintenance activities are performed once every 8 years. The applicant also stated that, for the 

pump in the control center HVAC system, the lube oil pressure is monitored during startup of the 

pump and approximately once every 12 hours every day. For the pump in the combustion 

turbine generator system, the lube oil pressure is monitored once a month when the pump is 

running. 

The staff finds the applicant’s response to RAI 3.3.2.9-1 and its proposal to manage the aging 

effects using the Bolting Integrity Program acceptable because of the following: 

 The applicant provided additional information describing the environment and clarifying 

that the closure bolts are submerged in lubricating oil and that, as stated in the GALL 

Report, steel components exposed to lubricating oil with some water have limited 

susceptibility to aging degradation. 

 The Bolting Integrity Program has preventive measures in place that are consistent with 

GALL Report AMP XI.M18 to prevent loss of material and loss of preload. 

 The submerged closure bolts will be subject to opportunistic visual inspections under the 

Bolting Integrity Program. 

 The preventive actions taken and opportunistic inspections to be performed under the 

Bolting Integrity Program in combination with the periodic monitoring of the lube oil 

pressure (every 12 hours for the control center HVAC system pump and once a month 

for the combustion turbine generator system pump) provide reasonable assurance that 

degradation associated with the submerged bolts will be identified, and corrective 

actions will be taken, before there is a loss of the intended function. 
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The staff’s concerns described in RAI 3.3.2.9-1 are resolved. 

Aluminum and Copper Alloy Heat Exchanger Components Exposed to Outdoor Air. The staff’s 

evaluation for aluminum heat exchanger fins and copper alloy heat exchanger tubes exposed to 

outdoor air, which will be managed for fouling by the External Surfaces Monitoring Program and 

are associated with generic note G, is documented in SER Section 3.2.2.3.4. 

Carbon Steel Housings and Screens Exposed to Outdoor Air. In LRA Table 3.3.2-9, the 

applicant stated that the internal surfaces of carbon steel housing and screens exposed to 

outdoor air will be managed for loss of material by the External Surfaces Monitoring Program. 

The AMR items cite generic note G and plant-specific note 304, which states that “because the 

internal and external surfaces are exposed to the same environments, aging effects of the 

internal surfaces can be inferred from external surface conditions.” 

The staff reviewed the associated items in the LRA and considered whether the aging effect 

proposed by the applicant constitutes all the credible aging effects for this component, material, 

and environment description. The GALL Report states that steel is only susceptible to loss of 

material in outdoor air. Therefore, the staff finds that the applicant has identified all credible 

aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The GALL Report states that GALL Report AMP XI.M36, “External 

Surfaces Monitoring of Mechanical Components,” may be credited with managing the aging of 

internal surfaces when the material and environment combinations of the internal and external 

surfaces are the same. The staff finds the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable because the periodic visual inspections in the 

program, which are conducted at least once per refueling cycle, are capable of detecting loss of 

material on the component external surfaces such that any degradation of the internal surfaces 

will be identified before loss of the intended function. 

Elastomer Flex Connections Exposed to Fuel Oil and Lubricating Oil. The staff’s evaluation for 

elastomer flex connections exposed to fuel oil and lubricating oil, which will be managed for 

cracking and changes in material properties by the Internal Surfaces in Miscellaneous Piping 

and Ducting Component Program and are associated with generic note G, is documented in 

Section 3.3.2.3.3. 

Carbon Steel, Copper Alloy, and Stainless Steel Piping Components, Heat Exchanger 

Components, and Condenser Housings Exposed to Outdoor Air. In LRA Tables 3.3.2-9, 

3.3.2-11, and 3.3.2-15, the applicant stated that carbon steel, copper alloy, and stainless steel 

piping components, heat exchanger components, and condenser housings exposed to outdoor 

air will be managed for loss of material by the Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program. The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effect 

proposed by the applicant constitutes all the credible aging effects for this component, material, 

and environment description. The applicant addressed fouling of copper alloy heat exchanger 

tubes in another AMR item in LRA Table 3.3.2-11. The applicant did not cite any additional 

aging effects for the other subject components. The GALL Report states that steel and copper 

alloys are only susceptible to loss of material in outdoor air. The GALL Report also states that 

stainless steel is susceptible to cracking when exposed to outdoor air with chloride 

contamination. LRA Table 3.3.2-15 contains AMR items for stainless steel sight glasses 
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exposed to outdoor air in the fuel oil systems, and cracking was not cited as an aging effect for 

these components. However, as described in UFSAR Sections 7.5.2.5.2, 9.5.1, and 9.5.2, 

because the fuel oil systems are sheltered from direct exposure to the outdoor air environment, 

chloride contamination of the site glasses is not expected to occur. Therefore, the staff finds 

that the applicant has identified all credible aging effects for this component, material, and 

environment combination. 

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.11. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the opportunistic visual inspections conducted by 

the program, with a representative sample of components inspected at least once every 

10 years, are capable of detecting loss of material before loss of the intended function. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-9 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Emergency Diesel Generator System – Summary of Aging Management 

Review – LRA Table 3.3.2-10 

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for 

the EDG system component groups. 

Carbon Steel and Stainless Steel Piping, Piping Components, Heat Exchanger Components, 

and Tanks Exposed to Treated Water, Raw Water, Lubricating Oil, and Fuel Oil. The staff’s 

evaluation for carbon steel and stainless steel piping, piping components, heat exchanger 

components, and tanks exposed to treated water, raw water, lubricating oil, and fuel oil, which 

will be managed for loss of coating integrity by the Coating Integrity Program and are associated 

with generic note H, is documented in SER Section 3.3.2.3.3. 

Copper Alloy with Greater Than 15 Percent Zinc Heat Exchanger Tubes Exposed to Lubricating 

Oil and Treated Water. The staff’s evaluation for copper alloy with greater than 15 percent zinc 

heat exchanger tubes exposed to lubricating oil and closed treated water, which will be 

managed for loss of material due to wear by the PSPM Program and are associated with 

generic note H, is documented in SER Section 3.3.2.3.9. 

Carbon Steel Closure Bolting Exposed to Condensation (External). The staff’s evaluation for 

carbon steel closure bolting exposed to condensation (external), which will be managed for loss 

of preload by the Bolting Integrity Program and is associated with generic note H, is 

documented in SER Section 3.3.2.3.3. 

Carbon Steel Closure Bolting Exposed to Raw Water (External). The staff’s evaluation for 

carbon steel closure bolting exposed to raw water (external), which will be managed for loss of 

material by the Bolting Integrity Program and which is associated with generic note H, is 

documented in SER Section 3.3.2.3.3. 

Stainless Steel Piping Components Exposed to Condensation. The staff’s evaluation for 

stainless steel piping components exposed to condensation, which will be managed for loss of 
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material by the External Surfaces Monitoring Program and are associated with generic note G, 

is documented in SER Section 3.2.2.3.8. 

Aluminum and Copper Alloy with Greater Than 15 percent Zinc (inhibited) Heat Exchanger Fins 

and Tubes Exposed to Indoor Air. The staff’s evaluation for aluminum and copper alloy with 

greater than 15 percent zinc (inhibited) heat exchanger fins and tube exposed to indoor air, 

which will be managed for fouling by the Internal Surfaces in Miscellaneous Piping and Ducting 

Component Program and are associated with generic note G, is documented in SER 

Section 3.3.2.3.6. 

Steel and Stainless Steel Piping and Expansion Joints Exposed to Exhaust Gas. In LRA 

Table 3.3.2-10, the applicant stated that there are TLAAs for steel and stainless steel piping and 

expansion joints exposed to exhaust gas that cite generic note H. The staff confirmed that there 

are TLAAs, as documented in LRA Section 4.3.2, for these components and materials. The 

staff’s evaluation of the fatigue TLAAs for non-Class 1 components is documented in SER 

Sections 4.3.2.1 and 4.3.2.2. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-10 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Heating, Ventilation, and Air Conditioning Systems – Summary of Aging 

Management Review – LRA Table 3.3.2-11 

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for 

the HVAC systems component groups. 

Carbon Steel and Stainless Steel Closure Bolting Exposed to Condensation (External). The 

staff’s evaluation for carbon steel and stainless steel closure bolting exposed to condensation 

(external), which will be managed for loss of preload by the Bolting Integrity Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.3. 

Aluminum Filter Housings Exposed to Outdoor Air. In LRA Table 3.3.2-11, the applicant stated 

that aluminum filter housings exposed to outdoor air will be managed for cracking by the 

External Surfaces Monitoring Program. The AMR item cites generic note H. 

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that aluminum piping, piping components, and piping elements exposed to outdoor 

air are susceptible to loss of material and recommends GALL Report AMP XI.M36, “External 

Surfaces Monitoring of Mechanical Components,” to manage the aging effect. However, the 

applicant has identified cracking as an additional aging effect for aluminum filter housings. The 

applicant addressed the GALL Report identified aging effect for this component, material, and 

environment combination in another AMR item in LRA Table 3.3.2-11. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. GALL Report AMP XI.M36, “External Surfaces Monitoring of 

Mechanical Components,” manages for cracking on external surfaces by identifying leakage of 

internal liquids. However, the aluminum filter housings have a gaseous internal environment. 

As a result, it was unclear to the staff how walkdowns of external surfaces will effectively use 

leakage as an indicator of cracking. By letter dated December 19, 2014, the staff issued 
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RAI B.1.16-1 requesting that the applicant state the parameters inspected and describe the 

inspection method(s) that will be used to determine whether cracking is present on gas-filled 

outdoor components. The staff’s evaluation of the response to RAI B.1.16-1 is documented in 

SER Section 3.0.3.2.7. 

In its review of components associated with LRA Table 3.3.2-11, the staff finds that the 

applicant has met the further evaluation criteria and that its proposal to manage the effects of 

aging using the External Surfaces Monitoring Program is acceptable because visual inspections 

and augmenting visual inspections by using techniques, such as soap bubbles and trending 

performance data, are methods capable of detecting cracking before loss of intended function, 

as documented in SER Section 3.0.3.2.7. 

Aluminum, Copper Alloy, and Stainless Steel Heat Exchanger Fins and Tubes Exposed to 

Indoor Air, Outdoor Air, and Condensation. The staff’s evaluation for aluminum, copper alloy, 

and stainless steel heat exchanger fins and tube exposed to indoor air, outdoor air, and 

condensation, which will be managed for fouling by the Internal Surfaces in Miscellaneous 

Piping and Ducting Component Program and are associated with generic note G, is 

documented in Section 3.3.2.3.6. 

Carbon Steel Housings and Copper Alloy Heat Exchanger Tubes Exposed to Outdoor Air. The 

staff’s evaluation for carbon steel condenser and heat exchanger housings and copper alloy 

heat exchanger tubes exposed to outdoor air, which will be managed for loss of material by the 

Internal Surfaces in Miscellaneous Piping and Ducting Component Program and are associated 

with generic note G, is documented in Section 3.3.2.3.9. 

Stainless Steel Heat Exchanger Components Exposed to Condensation. The staff’s evaluation 

for stainless steel heat exchanger components exposed to condensation, which will be 

managed for loss of material by the External Surfaces Monitoring Program and are associated 

with generic note G, is documented in SER Section 3.2.2.3.8. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-11 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Control Center Heating, Ventilation, and Air Conditioning System – Summary of 

Aging Management Review – LRA Table 3.3.2-12 

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for 

the control center HVAC system component groups. 

Carbon Steel and Stainless Steel Closure Bolting Exposed to Condensation (External). The 

staff’s evaluation for carbon steel and stainless steel closure bolting exposed to condensation 

(external), which will be managed for loss of preload by the Bolting Integrity Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.3. 

Carbon Steel Closure Bolting Exposed to Lube Oil (External). The staff’s evaluation for carbon 

steel closure bolting exposed to lube oil (external), which will be managed for loss of preload by 

the Bolting Integrity Program and is associated with generic note G, is documented in SER 

Section 3.3.2.3.9. 
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Stainless Steel Piping Components Exposed to Condensation. The staff’s evaluation for 

stainless steel piping components exposed to condensation, which will be managed for loss of 

material by the External Surfaces Monitoring Program and are associated with generic note G, 

is documented in SER Section 3.2.2.3.8. 

Aluminum and Copper Alloy Heat Exchanger Fins and Tubes Exposed to Indoor Air and 

Condensation. The staff’s evaluation for aluminum and copper alloy heat exchanger fins and 

tubes exposed to indoor air and condensation, which will be managed for fouling by the Internal 

Surfaces in Miscellaneous Piping and Ducting Component Program and are associated with 

generic note G, is documented in SER Section 3.3.2.3.6. 

Fiberglass Moisture Separators Exposed to Indoor Air. In LRA Table 3.3.2-12, the applicant 

stated that, for fiberglass moisture separators exposed to indoor air, there is no aging effect and 

no AMP is proposed. The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environment combination. NRC Regulatory Issue 

Summary 2012-02, “Insights into Recent License Renewal Application Consistency with the 

Generic Aging Lessons Learned Report,” dated January 24, 2012, discusses several 

environmental factors that can degrade polymeric materials, including ultraviolet light, ozone, 

high temperatures, chemicals, and radiation. The staff finds the applicant’s statement that there 

is no aging effect acceptable because the filters associated with the moisture separators in the 

control room HVAC system are not expected to be exposed to the above environmental 

stressors. 

Graphite Rupture Discs Exposed to Indoor Air and Gas. In LRA Table 3.3.2-12, the applicant 

stated that, for graphite rupture discs exposed externally to indoor air and internally to gas, there 

is no aging effect and no proposed AMP. The AMR items cite generic note F. 

During the audit, the staff reviewed plant-specific drawings and identified that the graphite 

rupture discs exposed externally to indoor air and internally to gas are Mersen Bursting Discs 

constructed of GRAPHILOR® material. The staff reviewed the supplier’s website, 

https://www.mersen.com/en/products/anticorrosion-and-process-equipment/graphilor-bursting-di

scs.html, on October 20, 2014. The website states, “GRAPHILOR®, a resin impregnated 

graphite developed and patented by Mersen, is virtually impervious to most corrosive liquids 

and vapors within its temperature/pressure rating. GRAPHILOR® is a unique material 

insensitive to thermal shock.” By letter dated December 17, 2014, the staff issued 

RAI 3.3.2.3.12-1, requesting that the applicant state the basis for not conducting inspections of 

the rupture disc material during the period of extended operation. 

In its response dated January 15, 2015, the applicant stated that the rupture discs are routinely 

replaced every 8 years and, as a result, are not subject to an AMR. The applicant revised LRA 

Tables 2.3.3-12 and 3.3.2-12 and LRA Section 3.3.2.1.12 to remove the AMR line items. 

The staff finds the applicant’s response acceptable because items that are replaced on a 

periodic basis independent of condition monitoring are not subject to an AMR. In addition, 

based on the material being virtually impervious to most corrosive liquids and being insensitive 

to thermal shock, an 8-year replacement schedule provides reasonable assurance that the 

intended function(s) of the discs will be met during the period of extended operation. The staff’s 

concern described in RAI 3.3.2.3.12-1 is resolved. 
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On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-12 with no 

AERMs, the applicant has appropriately evaluated the material and environment combinations 

not addressed in the GALL Report, and their intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). The 

staff also concludes that, for items in this table with an AERM, the applicant has demonstrated 

that the effects of aging will be adequately managed so that their intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Containment Atmospheric Control Systems – Summary of Aging Management 

Review – LRA Table 3.3.2-13 

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for 

the containment atmospheric control systems component groups. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the containment atmospheric control systems 

component groups are consistent with the GALL Report. 

 Plant Drains – Summary of Aging Management Review – LRA Table 3.3.2-14 

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for 

the plant drains component groups. 

Copper Alloy Drain Exposed to Concrete. In LRA Table 3.3.2-14, the applicant stated that for 

copper alloy plant drains exposed to concrete (external surface), there is no aging effect and no 

AMP is proposed. The AMR item cites generic note G, which states that the environment is not 

addressed in the GALL Report for this material and component combination. 

The staff reviewed the associated items in the LRA to confirm that there are no applicable aging 

effects for this component, material, and environmental combination. The staff finds the 

applicant’s proposal acceptable based on its review of ASM Handbook, Volume 13B, 

“Corrosion: Materials,” dated 2005, which states that copper alloys are corrosion resistant or 

corrode at negligible rates except when exposed to oxidizing acids, oxidizing heavy-metal salts, 

sulfur, ammonia, and some sulfur and ammonia compounds. Concrete, which is primarily 

composed of calcium, silicon, and oxide compounds, is not a corrosive environment for copper 

alloys. Additionally, the staff noted that the applicant will separately manage loss of material for 

these components, which are exposed to wastewater (internal surface), by performing visual 

inspections in accordance with the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program as described in SER Section 3.0.3.1.11. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-14 with no 

AERMs, the applicant has appropriately evaluated the material and environment combinations 

not addressed in the GALL Report, and their intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

 Fuel Oil Systems – Summary of Aging Management Review – LRA Table 3.3.2-15 

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for 

the fuel oil systems component groups. 
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Carbon Steel and Stainless Steel Piping, Piping Components, Heat Exchanger Components, 

and Tanks Exposed to Treated Water, Raw Water, Lubricating Oil, and Fuel Oil. The staff’s 

evaluation for carbon steel and stainless steel piping, piping components, heat exchanger 

components, and tanks exposed to treated water, raw water, lubricating oil, and fuel oil, which 

will be managed for loss of coating integrity by the Coating Integrity Program and are associated 

with generic note H, is documented in SER Section 3.3.2.3.3. 

Stainless Steel Site Glasses Exposed to Outdoor Air. The staff’s evaluation for stainless steel 

site glasses exposed to outdoor air, which will be managed for loss of material by the Internal 

Surfaces in Miscellaneous Piping and Ducting Component Program and are associated with 

generic note G, is documented in SER Section 3.3.2.3.9. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-15 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Primary Containment Monitoring and Leakage Detection Systems – Summary of 

Aging Management Review – LRA Table 3.3.2-16 

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for 

the primary containment monitoring and leakage systems component groups. 

Stainless Steel Tubing, Valve Bodies, and Thermowells Exposed to Steam. In LRA 

Table 3.3.2-16, the applicant stated that there are TLAAs for stainless steel tubing, valve 

bodies, and thermowells exposed to steam which cite generic note H. The staff confirmed that 

there are TLAAs, as documented in LRA Section 4.3, for these components and material. The 

staff’s evaluation of the fatigue TLAAs for tubing, valve bodies, and thermowells is documented 

in SER Sections 4.3.1 and 4.3.2. 

 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2) – Summary of 

Aging Management Evaluation – LRA Tables 3.3.2-17-1 through 3.3.2-17-37 

The staff reviewed LRA Tables 3.3.2-17-1 through 3.3.2-17-37, which summarize the results of 

AMR evaluations for the miscellaneous auxiliary systems in scope for 10 CFR 54.4(a)(2) 

component groups. 

CRD Hydraulic System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-1. The staff reviewed LRA 

Table 3.3.2-17-1, which summarizes the results of AMR evaluations for the CRD hydraulic 

system, nonsafety-related components affecting safety-related systems. The staff’s review did 

not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the CRD hydraulic system, 

nonsafety-related components affecting safety-related systems are consistent with the GALL 

Report. 

Standby Liquid Control System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-2. The staff 

reviewed LRA Table 3.3.2-17-2, which summarizes the results of AMR evaluations for the 

standby liquid control system, nonsafety-related components affecting safety-related systems. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 
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combinations of component type, material, environment, and AERM for the standby liquid 

control system, nonsafety-related components affecting safety-related systems are consistent 

with the GALL Report. 

Process Radiation Monitoring System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-3. 

Copper Alloy Sight Glasses Exposed to Wastewater. LRA Table 3.3.2-17-3 states that copper 

alloy (with greater than 15 percent zinc or 8 percent aluminum) sight glasses exposed internally 

to wastewater will be managed for loss of material by the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program. The AMR item references GALL Report, 

item AP-272. However, several GALL Report items, such as item AP-31, also state that 

components constructed of these copper alloys exposed to environments, including wastewater, 

may be susceptible to selective leaching. These items recommend GALL Report AMP XI.M33, 

“Selective Leaching” to ensure that this aging effect is adequately managed. 

By letter dated December 4, 2014, the staff issued RAI 3.3.2.17.3-1 requesting that the 

applicant show that these copper alloy sight glasses are not susceptible to selective leaching or 

state how selective leaching will be managed for these components. In its response dated 

January 5, 2015, the applicant stated that the subject components are susceptible to loss of 

material due to selective leaching and added a new item to LRA Table 3.3.2-17-3 for copper 

alloy sight glasses exposed internally to wastewater. This new item also credits the Selective 

Leaching Program to manage loss of material and cites SRP-LR, item 3.3.1-72. 

The staff finds the applicant’s response acceptable because selective leaching will be managed 

in these components in a manner consistent with the GALL Report. The staff’s concern 

described in RAI 3.3.2.17.3-1 is resolved. 

Stainless Steel Piping, Piping Components, and Tanks Exposed to Condensation. The staff’s 

evaluation for stainless steel piping, piping components, and tanks exposed to condensation, 

which will be managed for loss of material by the External Surfaces Monitoring Program and are 

associated with generic note G, is documented in SER Section 3.2.2.3.8. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-3 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Radioactive Waste System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-4. The staff 

reviewed LRA Table 3.3.2-17-4, which summarizes the results of AMR evaluations for the 

radioactive waste system, nonsafety-related components affecting safety-related systems. The 

staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the radioactive waste 

system, nonsafety-related components affecting safety-related systems are consistent with the 

GALL Report. 

Reactor Water Cleanup System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-5. The staff 

reviewed LRA Table 3.3.2-17-5, which summarizes the results of AMR evaluations for the 

reactor water cleanup system, nonsafety-related components affecting safety-related systems. 
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The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the reactor water 

cleanup system, nonsafety-related components affecting safety-related systems are consistent 

with the GALL Report. 

Fuel Pool Cooling and Cleanup System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-6. 

The staff reviewed LRA Table 3.3.2-17-6, which summarizes the results of AMR evaluations for 

the fuel pool cooling and cleanup system, nonsafety-related components affecting safety-related 

systems. The staff’s review did not identify any AMR items with notes F through J, indicating 

that the combinations of component type, material, environment, and AERM for the fuel pool 

cooling and cleanup system, nonsafety-related components affecting safety-related systems are 

consistent with the GALL Report. 

Torus Water Management System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-7. The staff 

reviewed LRA Table 3.3.2-17-7, which summarizes the results of AMR evaluations for the torus 

water management system, nonsafety-related components affecting safety-related systems. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the torus water 

management system, nonsafety-related components affecting safety-related systems are 

consistent with the GALL Report. 

Local Panels and Racks System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-8. The staff 

reviewed LRA Table 3.3.2-17-8, which summarizes the results of AMR evaluations for the local 

panels and racks system, nonsafety-related components affecting safety-related systems. The 

staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the local panels and 

racks system, nonsafety-related components affecting safety-related systems are consistent 

with the GALL Report. 

Off-Gas Process and Vacuum System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-9. 

Stainless Steel Piping, Recombiner Components, and Valve Bodies Exposed to Steam. In LRA 

Tables 3.3.2-17-9, 3.3.2-17-28, and 3.3.2-17-33, the applicant stated that stainless steel piping, 

recombiner components, and valve bodies exposed to steam (internal) will be managed for 

cracking and loss of material by the Water Chemistry Control – Closed Treated Water Systems 

Program. The associated AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The staff noted that the applicant also addressed loss of material 

and cracking due to fatigue for some of the components with the same material and 

environment combination in other AMR items in LRA Tables 3.3.2-17-9, 3.3.2-17-28, and 

3.3.2-17-33. Based on its review of the GALL Report Table VIII, which states that stainless 

steel components exposed to steam can experience loss of material due to pitting and crevice 

corrosion and cracking due to SCC, the staff finds that the aging effects proposed by the 

applicant conservatively describe those identified in the GALL Report; therefore, the staff finds 
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that the applicant has identified all the credible aging effects for this component, material, and 

environment combination. 

The staff’s evaluation of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program is documented in SER Section 3.0.3.2.23. The program includes both 

inspections and control of water chemistry to mitigate the effects of corrosion. The staff finds 

the applicant’s proposal to manage aging using the Water Chemistry Control – Closed Treated 

Water Systems Program acceptable because the inspections are capable of detecting loss of 

material due to corrosion and cracking due to stress corrosion before loss of intended function, 

whereas control of water chemistry will mitigate the effects of corrosion and SCC. 

Stainless Steel Piping Exposed to Steam. In LRA Table 3.3.2-17-9, the applicant stated that 

there is a TLAA for stainless steel piping exposed to steam that cites generic note H. The staff 

confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for this component and 

material. The staff’s evaluation of the fatigue TLAAs for non-Class 1 piping is documented in 

SER Section 4.3.2.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-9 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Potable Water System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-10. 

Plastic Piping and Valve Bodies Exposed to Indoor Air. In LRA Tables 3.3.2-17-10 and 

3.4.2-3-7, the applicant stated that plastic piping and valve bodies exposed to indoor air will be 

managed for change in material properties by the External Surfaces Monitoring Program. The 

AMR items cite generic note F. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The GALL Report states that polyvinyl chloride (PVC) piping, 

piping components, and piping elements exposed to indoor air have no aging effect, whereas 

high-density polyethylene (HDPE) and fiberglass piping exposed to raw water, soil, and 

concrete environments are susceptible to cracking, blistering, and changes in color due to water 

absorption. Because the applicant identified an aging effect that the GALL Report recognizes 

only for environments considered more severe than indoor air, the staff finds that the applicant 

has identified all credible aging effects for this component, material, and environment 

combination. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The staff finds the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable because the periodic visual inspections in the 

program, which are conducted at least once per refueling cycle, are capable of the timely 

detection of parameters indicative of changes in material properties, such as discoloration, 

surface cracking, crazing, and dimensional changes. 

Plastic Piping and Valve Bodies Exposed to Indoor Air. In LRA Table 3.3.2-17-10, the applicant 

stated that plastic piping and valve bodies exposed to indoor air have no aging effect and 

proposed no AMP. The AMR items cite generic note F. 
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The staff reviewed the associated items in the LRA and considered whether the applicant 

identified all credible aging effects for this component, material, and environment description. 

The GALL Report states that HDPE and fiberglass piping exposed to raw water, soil, and 

concrete environments are susceptible to cracking, blistering, and changes in color due to water 

absorption, whereas PVC piping exposed to condensation environments is not cited as having 

an aging effect. Because the applicant did not provide details on the type of plastic used in the 

potable water system, it was unclear to the staff whether the applicant identified all the credible 

aging effects. By letter dated January 14, 2015, the staff issued RAI 3.3.2.3.17.10-1, requesting 

that the applicant describe the type of plastic used in the potable water system and justify why 

that plastic is not susceptible to aging. 

In its response dated February 12, 2015, the applicant states that the plastic piping and valve 

bodies in LRA Table 3.3.2-17-10, which cite generic note F, do not perform a safety or license 

renewal function and are not in the scope of license renewal. The plastic piping and valve 

bodies, which cite generic note F, have been removed from LRA Table 3.3.2-17-10. 

The staff finds the applicant’s response to RAI 3.3.2.3.17.10-1 acceptable because the 

components do not perform a license renewal function and are not in the scope of license 

renewal. Therefore, the components do not need to be included in LRA Table 3.3.2-17-10 for 

aging management. The staff’s concerns described in RAI 3.3.2.3.17-10-1 are resolved. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-10 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Process Sampling System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-11. The staff reviewed LRA 

Table 3.3.2-17-11, which summarizes the results of AMR evaluations for the process sampling 

system, nonsafety-related components affecting safety-related systems. The staff’s review did 

not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the process sampling system, 

nonsafety-related components affecting safety-related systems are consistent with the GALL 

Report. 

Post-Accident Sampling System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-12. The staff 

reviewed LRA Table 3.3.2-17-12, which summarizes the results of AMR evaluations for the 

post-accident sampling system, nonsafety-related components affecting safety-related systems. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the post-accident 

sampling system, nonsafety-related components affecting safety-related systems are consistent 

with the GALL Report. 

General Service Water System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-13. The staff 

reviewed LRA Table 3.3.2-17-13, which summarizes the results of AMR evaluations for the 

general service water system, nonsafety-related components affecting safety-related systems. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the general service 
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water system, nonsafety-related components affecting safety-related systems are consistent 

with the GALL Report. 

Reactor Building Closed Cooling Water System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-14. The staff reviewed LRA Table 3.3.2-17-14, which summarizes the results of 

AMR evaluations for the reactor building closed cooling water system, nonsafety-related 

components affecting safety-related systems. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the reactor building closed cooling water system, nonsafety-related 

components affecting safety-related systems are consistent with the GALL Report. 

Turbine Building Closed Cooling Water System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-15. 

Carbon Steel and Stainless Steel Piping, Piping Components, Heat Exchanger Components, 

and Tanks Exposed to Treated Water, Raw Water, Lubricating Oil, and Fuel Oil. The staff’s 

evaluation for carbon steel and stainless steel piping, piping components, heat exchanger 

components, and tanks exposed to treated water, raw water, lubricating oil, and fuel oil, which 

will be managed for loss of coating integrity by the Coating Integrity Program and are associated 

with generic note H, is documented in SER Section 3.3.2.3.3. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-15 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Emergency Equipment Cooling Water System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-16. 

Carbon Steel Closure Bolting Exposed to Condensation (External). The staff’s evaluation for 

carbon steel closure bolting exposed to condensation (external), which will be managed for loss 

of preload by the Bolting Integrity Program and is associated with generic note H, is 

documented in SER Section 3.3.2.3.3. 

Stainless Steel Piping Components Exposed to Condensation. The staff’s evaluation for 

stainless steel piping components exposed to condensation, which will be managed for loss of 

material by the External Surfaces Monitoring Program and are associated with generic note G, 

is documented in SER Section 3.2.2.3.8. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-16 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Emergency Equipment Service Water System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-17. 
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Carbon Steel Closure Bolting Exposed to Condensation (External). The staff’s evaluation for 

carbon steel closure bolting exposed to condensation (external), which will be managed for loss 

of preload by the Bolting Integrity Program and is associated with generic note H, is 

documented in SER Section 3.3.2.3.3. 

Stainless Steel Piping Components Exposed to Condensation. The staff’s evaluation for 

stainless steel piping components exposed to condensation, which will be managed for loss of 

material by the External Surfaces Monitoring Program and are associated with generic note G, 

is documented in SER Section 3.2.2.3.8. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-17 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Supplemental Cooling Chilled Water System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-18. The staff reviewed LRA Table 3.3.2-17-18, which summarizes the results of 

AMR evaluations for the supplemental cooling chilled water system, nonsafety-related 

components affecting safety-related systems. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the supplemental cooling chilled water system, nonsafety-related 

components affecting safety-related systems are consistent with the GALL Report. 

Station Air, Control Air, Emergency Breathing Air System, Nonsafety-Related Components 

Affecting Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-19. The staff reviewed LRA Table 3.3.2-17-19, which summarizes the results of 

AMR evaluations for the station air, control air, emergency breathing air system, 

nonsafety-related components affecting safety-related systems. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the station air, control air, emergency breathing air 

system, nonsafety-related components affecting safety-related systems are consistent with the 

GALL Report. 

Auxiliary Boiler System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-20. 

Steel Components Exposed to Steam. In LRA Tables 3.3.2-17-20, 3.3.2-17-28, and 

3.3.2-17-33, the applicant stated that steel piping, condenser shells, expansion joints, heater 

housings, humidifiers, strainer housings, traps, and valve bodies exposed to steam (internal) will 

be managed for loss of material by the Water Chemistry Control – Closed Treated Water 

Systems Program. The associated AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. Based on its review of the GALL Report Table VIII, which states 

that steel components exposed to steam can experience loss of material, the staff finds that the 

aging effects proposed by the applicant effectively describe those essentially identified in the 

GALL Report; therefore, the staff finds that the applicant has identified all the credible aging 

effects for this component, material, and environment combination. 
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The staff’s evaluation of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program is documented in SER Section 3.0.3.2.23. The program includes both 

inspections and control of water chemistry to mitigate the effects of corrosion. The staff finds 

the applicant’s proposal to manage aging using the Water Chemistry Control – Closed Treated 

Water System Program acceptable because the inspections are capable of detecting loss of 

material before loss of intended function, whereas control of water chemistry will mitigate loss of 

material. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-20 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Waste Oil System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-21. The staff reviewed LRA 

Table 3.3.2-17-21, which summarizes the results of AMR evaluations for the waste oil system, 

nonsafety-related components affecting safety-related systems. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the waste oil system, nonsafety-related components 

affecting safety-related systems are consistent with the GALL Report. 

On-Line Noble Chemistry Injection System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-22. The staff reviewed LRA Table 3.3.2-17-22, which summarizes the results of 

AMR evaluations for the online noble chemistry injection system, nonsafety-related components 

affecting safety-related systems. The staff’s review did not identify any AMR items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for the online noble chemistry injection system, nonsafety-related components affecting 

safety-related systems are consistent with the GALL Report. 

Fire Protection System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-23. The staff reviewed LRA 

Table 3.3.2-17-23, which summarizes the results of AMR evaluations for the fire protection 

system, nonsafety-related components affecting safety-related systems. The staff’s review did 

not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the fire protection system, 

nonsafety-related components affecting safety-related systems are consistent with the GALL 

Report. 

Zinc Injection System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-24. The staff reviewed LRA 

Table 3.3.2-17-24, which summarizes the results of AMR evaluations for the zinc injection 

system, nonsafety-related components affecting safety-related systems. The staff’s review did 

not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the zinc injection system, 

nonsafety-related components affecting safety-related systems are consistent with the GALL 

Report. 

Emergency Diesel Generator System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-25. The staff 

reviewed LRA Table 3.3.2-17-25, which summarizes the results of AMR evaluations for the 
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emergency diesel generator system, nonsafety-related components affecting safety-related 

systems. The staff’s review did not identify any AMR items with notes F through J, indicating 

that the combinations of component type, material, environment, and AERM for the emergency 

diesel generator system, nonsafety-related components affecting safety-related systems are 

consistent with the GALL Report. 

Reactor/Auxiliary Building Systems, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-26. The staff 

reviewed LRA Table 3.3.2-17-26, which summarizes the results of AMR evaluations for the 

reactor/auxiliary building systems, nonsafety-related components affecting safety-related 

systems. The staff’s review did not identify any AMR items with notes F through J, indicating 

that the combinations of component type, material, environment, and AERM for the 

reactor/auxiliary building systems, nonsafety-related components affecting safety-related 

systems are consistent with the GALL Report. 

Storage Pools System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.3.2-17-27. The staff reviewed LRA 

Table 3.3.2-17-27, which summarizes the results of AMR evaluations for the storage pools 

system, nonsafety-related components affecting safety-related systems. The staff’s review did 

not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the storage pools system, 

nonsafety-related components affecting safety-related systems are consistent with the GALL 

Report. 

Reactor/Auxiliary Building HVAC System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-28. 

Carbon Steel and Stainless Steel Piping, Piping Components, Heat Exchanger Components, 

and Tanks Exposed to Treated Water, Raw Water, Lubricating Oil, and Fuel Oil. The staff’s 

evaluation for carbon steel and stainless steel piping, piping components, heat exchanger 

components, and tanks exposed to treated water, raw water, lubricating oil, and fuel oil, which 

will be managed for loss of coating integrity by the Coating Integrity Program and are associated 

with generic note H, is documented in SER Section 3.3.2.3.3. 

Carbon Steel Closure Bolting Exposed to Condensation (External). The staff’s evaluation for 

carbon steel closure bolting exposed to condensation (external), which will be managed for loss 

of preload by the Bolting Integrity Program and is associated with generic note H, is 

documented in SER Section 3.3.2.3.3. 

Stainless Steel Valve Bodies Exposed to Steam. The staff’s evaluation for stainless steel valve 

bodies exposed to steam, which will be managed for cracking and loss of material by the Water 

Chemistry Control – Closed Treated Water Systems Program and are associated with generic 

note G, is documented in SER Section 3.3.2.3.17-9. 

Steel Components Exposed to Steam. The staff’s evaluation for steel piping, condenser shells, 

expansion joints, heater housings, humidifiers, strainer housings, traps, and valve body 

components exposed to steam, which will be managed for loss of material by the Water 

Chemistry Control – Closed Treated Water System Program and are associated with generic 

note G, is documented in SER Section 3.3.2.3.17-20. 
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Copper Alloy Coil Components Exposed to Steam. In LRA Tables 3.3.2-17-28 and 3.3.2-17-33, 

the applicant stated that copper alloy coil components exposed to steam (internal) will be 

managed for loss of material by the Water Chemistry Control – Closed Treated Water Systems 

Program. The associated AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. Based on its review of GALL Report Tables VII and VIII, which 

state that copper alloy components exposed to treated water (internal) can experience loss of 

material, the staff finds that, under these environmental conditions, the aging effects would be 

similar to those proposed by the applicant; therefore, the staff finds that the applicant has 

identified all the credible aging effects for this component, material, and environment 

combination. 

The staff’s evaluation of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program is documented in SER Section 3.0.3.2.23. The program includes both 

inspections and control of water chemistry to mitigate the effects of corrosion. The staff finds 

the applicant’s proposal to manage aging using the Water Chemistry Control – Closed Treated 

Water Systems Program acceptable because the inspections are capable of detecting loss of 

material before loss of intended function, whereas the control of water chemistry will mitigate 

loss of material. 

Stainless Steel Valve Body Exposed to Steam. In LRA Table 3.3.2-17-28, the applicant stated 

that there is a TLAA for stainless steel valve bodies exposed to steam that cites generic note H. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for this 

component and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 valve 

bodies is documented in SER Section 4.3.2.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-28 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Floor and Equipment Drains System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-29. The staff 

reviewed LRA Table 3.3.2-17-29, which summarizes the results of AMR evaluations for the floor 

and equipment drains system, nonsafety-related components affecting safety-related systems. 

The staff’s review did not identify any AMR items with notes F through J, indicating that the 

combinations of component type, material, environment, and AERM for the floor and equipment 

drains system, nonsafety-related components affecting safety-related systems are consistent 

with the GALL Report. 

Containment Atmospheric Control System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-30. The staff reviewed LRA Table 3.3.2-17-30, which summarizes the results of 

AMR evaluations for the containment atmospheric control system, nonsafety-related 

components affecting safety-related systems. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the containment atmospheric control system, nonsafety-related 

components affecting safety-related systems are consistent with the GALL Report. 
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Primary Containment Pneumatics System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-31. The staff reviewed LRA Table 3.3.2-17-31, which summarizes the results of 

AMR evaluations for the primary containment pneumatics system, nonsafety-related 

components affecting safety-related systems. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the primary containment pneumatics system, nonsafety-related 

components affecting safety-related systems are consistent with the GALL Report. 

Primary Containment Monitoring System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-32. The staff reviewed LRA Table 3.3.2-17-32, which summarizes the results of 

AMR evaluations for the primary containment monitoring system, nonsafety-related components 

affecting safety-related systems. The staff’s review did not identify any AMR items with notes F 

through J, indicating that the combinations of component type, material, environment, and 

AERM for the primary containment monitoring system, nonsafety-related components affecting 

safety-related systems are consistent with the GALL Report. 

Turbine Building HVAC System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.3.2-17-33. 

Stainless Steel Valve Bodies Exposed to Steam. The staff’s evaluation for stainless steel valve 

bodies exposed to steam, which will be managed for cracking and loss of material by the Water 

Chemistry Control – Closed Treated Water Systems Program and are associated with generic 

note G, is documented in SER Section 3.3.2.3.17-9. 

Steel Components Exposed to Steam. The staff’s evaluation for steel piping, condenser shells, 

expansion joints, heater housings, humidifiers, strainer housings, traps, and valve body 

components exposed to steam, which will be managed for loss of material by the Water 

Chemistry Control – Closed Treated Water System Program and are associated with generic 

note G, is documented in SER Section 3.3.2.3.17-20. 

Copper Alloy Coils Exposed to Steam. The staff’s evaluation for copper alloy coils exposed to 

steam, which will be managed for loss of material by the Water Chemistry Control – Closed 

Treated Water Systems Program and are associated with generic note G, is documented in 

SER Section 3.3.2.3.17-28. 

Steel and Stainless Steel Valve Bodies, Piping, Flow Elements, and Thermowells Exposed to 

Steam and Treated Water. In LRA Table 3.3.2-17-33, the applicant stated that there are TLAAs 

for steel and stainless steel valve bodies, piping, flow elements, and thermowells exposed to 

steam and treated water that cite generic note H or G. The staff confirmed that there are 

TLAAs, as documented in LRA Section 4.3.2, for these components, environments, and 

materials. The staff’s evaluation of the fatigue TLAAs for non-Class 1 components is 

documented in SER Sections 4.3.2.1 and 4.3.2.2. 

On the basis of its review, the staff concludes that for items in LRA Table 3.3.2-17-33 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 
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Turbine Building Potable Water and Plumbing System, Nonsafety-Related Components 

Affecting Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-34. The staff reviewed LRA Table 3.3.2-17-34, which summarizes the results of 

AMR evaluations for the turbine building potable water and plumbing system, nonsafety-related 

components affecting safety-related systems. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the turbine building potable water and plumbing system, 

nonsafety-related components affecting safety-related systems are consistent with the GALL 

Report. 

RHR Complex and Office Service Building HVAC Systems, Nonsafety-Related Components 

Affecting Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-35. The staff reviewed LRA Table 3.3.2-17-35, which summarizes the results of 

AMR evaluations for the RHR complex and office service building HVAC systems, 

nonsafety-related components affecting safety-related systems. The staff’s review did not 

identify any AMR items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for the RHR complex and office service building HVAC 

systems, nonsafety-related components affecting safety-related systems are consistent with the 

GALL Report. 

RHR Complex Drains and OSB Potable Water System, Nonsafety-Related Components 

Affecting Safety-Related Systems – Summary of Aging Management Evaluation – LRA 

Table 3.3.2-17-36. The staff reviewed LRA Table 3.3.2-17-36, which summarizes the results of 

AMR evaluations for the RHR complex drains and the office service building (OSB) potable 

water system, nonsafety-related components affecting safety-related systems. The staff’s 

review did not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for the RHR complex drains and OSB 

potable water system, nonsafety-related components affecting safety-related systems are 

consistent with the GALL Report. 

Beyond Design Basis External Event Mitigation (Fukushima) System, Nonsafety-Related 

Components Affecting Safety-Related Systems – Summary of Aging Management Evaluation – 

LRA Table 3.3.2-17-37. The staff reviewed LRA Table 3.3.2-17-37, which summarizes the 

results of AMR evaluations for the BDBEE mitigation (Fukushima) system, nonsafety-related 

components affecting safety-related systems. The staff’s review did not identify any AMR items 

with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for the BDBEE mitigation (Fukushima) system, nonsafety-related 

components affecting safety-related systems, are consistent with the GALL Report. 

3.3.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the auxiliary systems components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.4 Aging Management of Steam and Power Conversion Systems 

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

steam and power conversion systems components and component groups of the following: 
3-353 

 condensate storage and transfer system 

 feedwater and standby feedwater system 

 miscellaneous steam and power conversion systems in scope for 10 CFR 54.4(a)(2) 

3.4.1 Summary of Technical Information in the Application 

LRA Section 3.4 provides AMR results for the steam and power conversion systems 

components and component groups. LRA Table 3.4.1, “Summary of Aging Management 

Programs for Steam and Power Conversion System Evaluated in Chapter VIII of NUREG-1801,” 

is a summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for 

the steam and power conversion systems components and component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.4.2 Staff Evaluation 

The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the steam and power conversion 

systems components, within the scope of license renewal and subject to an AMR, will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff conducted a review of the applicant’s AMRs to ensure the applicant’s claim that certain 

AMRs were consistent with the GALL Report, not applicable, or not used. The staff did not 

repeat its review of the matters described in the GALL Report; however, the staff did verify that 

the material presented in the LRA was applicable and that the applicant identified the 

appropriate GALL Report AMRs. The AMRs that the staff confirmed are consistent with the 

GALL Report are noted as such in SER Table 3.4-1, and no further discussion is required. The 

AMRs that the staff confirmed are not applicable to Fermi 2 or not used, because the 

component, material, and environment combination described in the SRP-LR does not exist for 

in-scope SCs at Fermi 2 or because the component, material, and environment combination is 

addressed by another SER Table 3.1-1 item, or that require no aging management are noted in 

SER Table 3.4-1 and discussed in SER Section 3.4.2.1.1. Details of the staff’s evaluation of 

AMRs that the applicant claimed are consistent with the GALL Report, but for which a different 

AMP from the program recommended in the GALL Report is used to manage aging, and of 

AMRs for which the staff requested additional information are documented in SER 

Section 3.4.2.1.2. 

During its review, the staff also reviewed AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff’s evaluations of 

AMRs for which the GALL Report recommends further evaluation are documented in SER 

Section 3.4.2.2. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed are appropriate for the 
3-354 

material-environment combinations specified. The staff’s evaluations of AMRs not consistent 

with, or not addressed in, the GALL Report are documented in SER Section 3.4.2.3. 

SER Table 3.4-1 summarizes the staff’s evaluation of components, aging effects or 

mechanisms, and AMPs listed in LRA Section 3.4 and addressed in the GALL Report. 

Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems Components in 

the GALL Report 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water 

(3.4.1-1) 

Cumulative 

fatigue damage 

due to fatigue 

Fatigue is a timelimited aging analysis 

(TLAA) to be 

evaluated for the 

period of extended 

operation. See SRP 

Section 4.3, “Metal 

Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1). 

Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.2.1) 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.4.1-2) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

Yes, 

environmental 

conditions 

need to be 

evaluated 

External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.2.2) 

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to air 

– outdoor (3.4.1-3) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

Yes, 

environmental 

conditions 

need to be 

evaluated 

External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.2.3) 

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.4.1-4) 

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, 

“Boric Acid 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to steam, 

treated water 

(3.4.1-5) 

Wall thinning 

due to flowaccelerated 

corrosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Flow-Accelerated 

Corrosion Program 

Consistent with the 

GALL Report 

Steel, stainless steel 

bolting exposed to 

soil (3.4.1-6) 

Loss of preload Chapter XI.M18, 

“Bolting Integrity “ 

No Not used. There is 

no steel or 

stainless steel 

bolting 

exposed to soil in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 
3-355 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage (3.4.1-7) 

Cracking due to 

cyclic loading, 

stress corrosion 

cracking 

Chapter XI.M18, 

“Bolting Integrity” 

No Not used. There is 

no high strength 

steel bolting in the 

steam and power 

conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Steel; stainless steel 

bolting, closure 

bolting exposed to air 

– outdoor (external), 

air – indoor, 

uncontrolled 

(external) (3.4.1-8) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.4.1-9) 

Loss of material 

due to general 

corrosion 

Chapter XI.M18, 

“Bolting Integrity” 

No Not used. As 

stated in item 

3.4.1-8, loss of 

material of steel 

bolting exposed to 

air in the steam 

and power 

conversion 

systems is 

managed by the 

Bolting Integrity 

Program. 

However, steam or 

water leakage is 

not considered as 

a separate aspect 

of the indoor air 

environment. 

Not used (see SER 

Section 3.4.2.1.1) 

Copper alloy, nickel 

alloy, steel; stainless 

steel, steel; stainless 

steel bolting, closure 

bolting exposed to 

any environment, air 

– outdoor (external), 

air – indoor, 

uncontrolled 

(external) (3.4.1-10) 

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening 

Chapter XI.M18, 

“Bolting Integrity” 

No Bolting Integrity 

Program 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements, 

tanks, heat 

exchanger 

components exposed 

to steam, treated 

water >60°C 

(>140°F) (3.4.1-11) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 
3-356 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel; stainless steel 

tanks exposed to 

treated water 

(3.4.1-12) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.4.1-13) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Steel piping, piping 

components, and 

piping elements, 

PWR heat exchanger 

components exposed 

to steam, treated 

water (3.4.1-14) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel heat exchanger 

components exposed 

to treated water 

(3.4.1-15) 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Copper alloy, 

stainless steel, nickel 

alloy, aluminum 

piping, piping 

components, and 

piping elements, heat 

exchanger 

components and 

tubes, PWR heat 

exchanger 

components exposed 

to treated water, 

steam (3.4.1-16) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Copper alloy heat 

exchanger tubes 

exposed to treated 

water (3.4.1-17) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.4.1-18) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.M32, 

“One-Time 

Inspection” 

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel, steel 

heat exchanger 

components exposed 

to raw water 

(3.4.1-19) 

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no heat 

exchanger 

components 

exposed to raw 

water in the steam 

and power 

conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 
3-357 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Copper alloy, 

stainless steel piping, 

piping components, 

and piping elements 

exposed to raw water 

(3.4.1-20) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no piping 

components 

exposed to raw 

water (open cycle 

cooling water) in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Stainless steel heat 

exchanger 

components exposed 

to raw water 

(3.4.1-21) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Stainless steel, 

copper alloy, steel 

heat exchanger 

tubes, heat 

exchanger 

components exposed 

to raw water 

(3.4.1-22) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System” 

No Not used. There 

are no heat 

exchanger tubes 

exposed to raw 

water with an 

intended function 

of heat transfer in 

the steam and 

power conversion 

systems in the 

scope of 

license renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to closedcycle cooling water 

>60°C (>140°F) 

(3.4.1-23) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no stainless 

steel components 

exposed to closedcycle cooling water 

> 60 °C (> 140 °F) 

in the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Steel heat exchanger 

components exposed 

to closed-cycle 

cooling water 

(3.4.1-24) 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no steel heat 

exchanger 

components 

exposed to closedcycle cooling 

water in the steam 

and power 

conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 
3-358 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel heat exchanger 

components exposed 

to closed-cycle 

cooling water 

(3.4.1-25) 

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no steel heat 

exchanger 

components 

exposed to closedcycle cooling 

water in the steam 

and power 

conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Stainless steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.4.1-26) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no stainless 

steel components 

exposed to closedcycle cooling water 

in the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

(3.4.1-27) 

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no copper 

alloy components 

exposed to 

closed-cycle 

cooling water in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Steel, stainless steel, 

copper alloy heat 

exchanger 

components and 

tubes, heat 

exchanger tubes 

exposed to closedcycle cooling water 

(3.4.1-28) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M21A, 

“Closed Treated 

Water Systems” 

No Not used. There 

are no heat 

exchanger tubes 

exposed to 

closed-cycle 

cooling water with 

an intended 

function of heat 

transfer in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Steel tanks exposed 

to air – outdoor 

(external) (3.4.1-29) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Not used. There 

are no steel tanks 

exposed to 

outdoor air in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 
3-359 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel, stainless steel, 

aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.4.1-30) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

(stainless steel 

and aluminum 

only) 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Not used. There 

are no steel or 

stainless steel 

tanks (consistent 

with the scope of 

NUREG-1801, 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) in 

the steam and 

power conversion 

systems. 

Aluminum tanks 

are addressed in 

item 3.4.1-31. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Stainless steel, 

aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to soil or 

concrete, or the 

following external 

environments airoutdoor, air-indoor 

uncontrolled, moist 

air, condensation 

(3.4.1-31) 

Loss of material 

due to pitting, 

and crevice 

corrosion; 

cracking due to 

stress corrosion 

cracking 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Aboveground 

Metallic Tanks 

Program 

Consistent with the 

GALL Report 

Gray cast iron piping, 

piping components, 

and piping elements 

exposed to soil 

(3.4.1-32) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching” 

No Not used. There 

are no gray cast 

iron components 

exposed to soil in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Gray cast iron, 

copper alloy (>15% 

Zn or >8% Al) piping, 

piping components, 

and piping elements 

exposed to treated 

water, raw water, 

closed-cycle cooling 

water (3.4.1-33) 

Loss of material 

due to selective 

leaching 

Chapter XI.M33, 

“Selective Leaching” 

No Selective Leaching 

Program 

Consistent with the 

GALL Report 

Steel external 

surfaces exposed to 

air – indoor, 

uncontrolled 

(external), air – 

outdoor (external), 

condensation 

(external) (3.4.1-34) 

Loss of material 

due to general 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No External Surfaces 

Monitoring 

Program 

Consistent with the 

GALL Report 
3-360 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Aluminum piping, 

piping components, 

and piping elements 

exposed to air – 

outdoor (3.4.1-35) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Buried and 

Underground 

Piping Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.1.2) 

Steel piping, piping 

components, and 

piping elements 

exposed to air – 

outdoor (internal) 

(3.4.1-36) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.4.1-37) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to raw water 

(3.4.1-38) 

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.4.1-39) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components” 

No Not used. There 

are no stainless 

steel components 

exposed to 

condensation in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.4.1-40) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Steel heat exchanger 

components exposed 

to lubricating oil 

(3.4.1-41) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.4.1-42) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 
3-361 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.4.1-43) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements, heat 

exchanger 

components exposed 

to lubricating oil 

(3.4.1-44) 

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Oil Analysis and 

One-Time 

Inspection 

programs 

Consistent with the 

GALL Report 

Aluminum heat 

exchanger 

components and 

tubes exposed to 

lubricating oil 

(3.4.1-45) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Stainless steel, steel, 

copper alloy heat 

exchanger tubes 

exposed to 

lubricating oil 

(3.4.1-46) 

Reduction of 

heat transfer 

due to fouling 

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Steel (with coating or 

wrapping) stainless 

steel, nickel alloy 

piping, piping 

components, and 

piping elements; 

tanks exposed to soil 

or concrete 

(3.4.1-47) 

Loss of material 

due to general 

(steel only), 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Buried and 

Underground 

Piping Program 

Consistent with the 

GALL Report 

Stainless steel, 

nickel alloy bolting 

exposed to soil 

(3.4.1-48) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There is 

no stainless steel 

or nickel alloy 

bolting exposed to 

soil in the steam 

and power 

conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Stainless steel, 

nickel alloy piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.4.1-49) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Buried and 

Underground 

Piping Program 

Consistent with the 

GALL Report 
3-362 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel bolting 

exposed to soil 

(3.4.1-50) 

Loss of material 

due to general, 

pitting and 

crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There is 

no steel bolting 

exposed to soil in 

the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Underground 

stainless steel, nickel 

alloy, and steel 

piping, piping 

components, and 

piping elements 

(3.4.1-50.5) 

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion 

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks” 

No Not used. There is 

no underground 

piping in areas of 

restricted access 

in the steam and 

power conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.4.1-51) 

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, and 

2) plant OE indicates 

no degradation of the 

concrete 

No, if 

conditions 

are met. 

Not used. There 

are no steel 

components 

embedded in 

concrete in the 

steam and power 

conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Aluminum piping, 

piping components, 

and piping elements 

exposed to gas, air – 

indoor, uncontrolled 

(internal/external) 

(3.4.1-52) 

None None NA - No 

AEM or 

AMP 

None 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.4.1-53) 

None None NA - No 

AEM or 

AMP 

Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1) 

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to gas, air – 

indoor, uncontrolled 

(external) (3.4.1-54) 

None None NA - No 

AEM or 

AMP 

None Consistent with the 

GALL Report 
3-363 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Glass piping 

elements exposed to 

lubricating oil, air – 

outdoor, 

condensation 

(internal/external), 

raw water, treated 

water, air with 

borated water 

leakage, gas, closedcycle cooling water, 

air – indoor, 

uncontrolled 

(external) (3.4.1-55) 

None None NA - No 

AEM or 

AMP 

None Consistent with the 

GALL Report 

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air – 

indoor, uncontrolled 

(external) (3.4.1-56) 

None None NA - No 

AEM or 

AMP 

None Consistent with the 

GALL Report 

Nickel alloy, PVC 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage, air – indoor, 

uncontrolled, 

condensation 

(internal) (3.4.1-57) 

None None NA - No 

AEM or 

AMP 

Not used. There 

are no nickel alloy 

or PVC 

components 

exposed to the 

environments 

represented by 

this item in the 

steam and power 

conversion 

systems in the 

scope of license 

renewal. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air – 

indoor, uncontrolled 

(external), concrete, 

gas, air – indoor, 

uncontrolled 

(internal) (3.4.1-58) 

None None NA - No 

AEM or 

AMP 

None Consistent with the 

GALL Report 

Steel piping, piping 

components, and 

piping elements 

exposed to air – 

indoor controlled 

(external), gas 

(3.4.1-59) 

None None NA - No 

AEM or 

AMP 

Not used. There 

are no steel steam 

and power 

conversion system 

components 

exposed to the 

environments 

represented by 

this item in the 

scope of license 

renewal. 

Not used (see SER 

Section 3.4.2.1.1) 
3-364 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Any material, piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.4.1-60) 

Wall thinning 

due to erosion 

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion” 

No Flow-Accelerated 

Corrosion Program 

Consistent with the 

GALL Report 

Metallic piping, 

piping components, 

and tanks exposed to 

raw water or 

wastewater (3.4.1-

61) 

Loss of material 

due to recurring 

internal 

corrosion 

A plant-specific aging 

management 

program is to be 

evaluated to address 

recurring internal 

corrosion 

Yes, plantspecific Not used. No 

conditions of 

recurring internal 

corrosion 

(RIC) as defined in 

LR-ISG-2012-02, 

Section A, were 

identified in piping 

components of the 

steam and power 

conversion 

systems. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.2.6) 

Steel, stainless steel 

or aluminum tanks 

(within the scope of 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”) 

exposed to treated 

water (3.4.1-62) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” 

No Aboveground 

Metallic Tanks 

Program 

Consistent with the 

GALL Report 

Insulated steel, 

stainless steel, 

copper alloy, 

aluminum, or copper 

alloy (> 15% Zn) 

piping, piping 

components, and 

tanks exposed to 

condensation, airoutdoor (3.4.1-63) 

Loss of material 

due to general 

(steel, and 

copper alloy), 

pitting, or 

crevice 

corrosion, and 

cracking due to 

stress corrosion 

cracking 

(aluminum, 

stainless steel 

and copper alloy 

(>15% Zn) only) 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” or 

Chapter XI.M29, 

“Aboveground 

Metallic Tanks” (for 

tanks only) 

No External Surfaces 

Monitoring and 

Aboveground 

Metallic Tanks 

programs 

Consistent with the 

GALL Report 

Jacketed calcium 

silicate or fiberglass 

insulation in an airindoor uncontrolled 

or air-outdoor 

environment (3.4.1-

64) 

Reduced 

thermal 

insulation 

resistance due 

to moisture 

intrusion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

 No Not used. There 

are no insulation 

components with 

an intended 

function of thermal 

insulation in the 

steam and power 

conversion 

systems. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 

Jacketed 

FOAMGLAS® (glass 

dust) insulation in an 

air-indoor 

uncontrolled or airoutdoor environment 

(3.4.1-65) 

Reduced 

thermal 

insulation 

resistance due 

to moisture 

intrusion 

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components” 

No Not used. There 

are no insulation 

components with 

an intended 

function of thermal 

insulation in the 

steam and power 

conversion 

systems. 

Not applicable to 

Fermi 2 (see SER 

Section 3.4.2.1.1) 
3-365 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Metallic 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, or lubricating 

oil (3.4.1-66) 

Loss of coating 

or lining integrity 

due to blistering, 

cracking, flaking, 

peeling, 

delamination, 

rusting, or 

physical damage 

and to spalling 

for cementitious 

coatings/linings 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Coating Integrity 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.4.2.3.3) 

Metallic piping, 

piping components, 

heat exchangers, 

tanks with internal 

coatings/linings 

exposed to closed 

cycle cooling water, 

raw water, treated 

water, treated 

borated water, or 

lubricating oil 

(3.4.1-67) 

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Not used Not used (see SER 

Section 3.4.2.1.1) 

Gray cast iron piping 

components with 

internal 

coatings/linings 

exposed to closed 

cycle cooling water, 

raw water, or treated 

water (3.4.1-68) 

Loss of material 

due to selective 

leaching 

Chapter XI.M42, 

“Internal 

Coatings/Linings for 

In-Scope Piping, 

Piping Components, 

Heat Exchangers, 

and Tanks” 

No Not used Not used (see SER 

Section 3.4.2.1.1) 

3.4.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the steam and power conversion systems components: 

 Aboveground Metallic Tanks 

 Bolting Integrity 

 Buried and Underground Piping 

 External Surfaces Monitoring 

 Flow-Accelerated Corrosion 

 Internal Surfaces in Miscellaneous Piping and Ducting Components 

 Oil Analysis 

 One-Time Inspection 

 Periodic Surveillance and Preventive Maintenance 

 Selective Leaching 

 Water Chemistry Control – BWR 

LRA Tables 3.4.2-1 through 3.4.2-3-9 summarize AMRs for the steam and power conversion 

systems components and indicate AMRs claimed to be consistent with the GALL Report. 
3-366 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components of these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR item. The notes describe how the information in 

the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions. 

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 

Note C indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as the component under review. The staff audited 

these AMR items to confirm consistency with the GALL Report. The staff also determined 

whether the AMR item of the different component applied to the component under review and 

whether the AMR was valid for the site-specific conditions. 

Note D indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions. 

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, the staff did confirm that the material presented in the 
3-367 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows. 

 AMR Results Identified as Not Applicable or Not Used 

For LRA Table 3.4.1, items 3.4.1-4, 3.4.1-13, 3.4.1-17, 3.4.1-21, 3.4.1-36, 3.4.1-37, 3.4.1-38, 

3.4.1-41, 3.4.1-42, 3.4.1-45, 3.4.1-46, and 3.4.1-53, the applicant claimed that the 

corresponding AMR items in the GALL Report are not applicable because the associated items 

are only applicable to PWRs. The staff reviewed the SRP-LR; confirmed these items only apply 

to PWRs; and finds that these items are not applicable to Fermi 2, which is a BWR. 

For LRA Table 3.4.1, items 3.4.1-6, 3.4.1-7, 3.4.1-9, 3.4.1-19, 3.4.1-20, 3.4.1-22, 3.4.1-23, 

3.4.1-24, 3.4.1-25, 3.4.1-26, 3.4.1-27, 3.4.1-28, 3.4.1-29, 3.4.1-30, 3.4.1-32, 3.4.1-39, 3.4.1-51, 

3.4.1-57, 3.4.1-59, 3.4.1-64, and 3.4.1-65, the applicant claimed that the corresponding items in 

the GALL Report are not applicable or are not used because the component, material and 

environment combination described in the SRP-LR does not exist for in-scope SCs at Fermi 2 or 

because the component, material, and environment combination is addressed by another 

Table 1 line item. The staff reviewed the LRA and UFSAR and confirmed that the applicant’s 

LRA does not have any AMR results applicable for these items or that the aging effects 

addressed by other Table 1 AMR line items are appropriate. 

For LRA Table 3.4.1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable or are not used. However, the staff had to review 

sources beyond the LRA and UFSAR or to issue one or more RAIs, or both, in order to verify 

the applicant’s claim of nonapplicability or not used. 

LRA Table 3.4.1, item 3.4.1-48, addresses stainless steel and nickel alloy bolting exposed to 

soil. The GALL Report recommends GALL Report AMP XI.M41, “Buried and Underground 

Piping and Tanks,” to manage loss of material due to pitting and crevice corrosion for this 

component group. The applicant stated that this line item was not used because there is no 

stainless steel or nickel alloy bolting exposed to soil in the steam and power conversion 

systems. The staff evaluated the applicant’s claim and finds it acceptable based on its review of 

plant-specific drawings during the AMP audit. 

LRA Table 3.4.1, item 3.4.1-50, addresses steel bolting exposed to soil. The GALL Report 

recommends GALL Report AMP XI.M41, “Buried and Underground Piping and Tanks,” to 

manage loss of material due to general, pitting, and crevice corrosion for this component group. 

The applicant stated that this line item was not used because there is no steel bolting exposed 

to soil in the steam and power conversion systems. The staff evaluated the applicant’s claim 

and finds it acceptable based on its review of plant-specific drawings during the AMP audit. 

LRA Table 3.4.1, item 3.4.1-50.5, addresses underground stainless steel; nickel alloy; and steel 

piping, piping components, and piping elements. The GALL Report recommends GALL Report 

AMP XI.M41, “Buried and Underground Piping and Tanks,” to manage loss of material for this 

component group. The applicant stated that this item is not used because there is no 

underground piping in areas of restricted access in the steam and power conversion systems. 

GALL Report AMP XI.M41 states that underground piping is below grade but contained within a 

tunnel or vault such that it is in contact with air and is located where access for inspection is 

restricted. The staff evaluated the applicant’s claim and finds it acceptable because, during the 

AMP audit, the staff observed the CST dog house pit and confirmed that access to the 
3-368 

below-grade piping in the steam and conversion system is available through an entranceway 

that can be opened unassisted (i.e., not restricted) by plant staff. 

SER Table 3.4-1, items 3.4.1-67 and 3.41-68, reflect changes to the SRP-LR incorporated by 

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal 

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

ISG added these line items to allow applicants to credit the new GALL Report AMP XI.M42, 

“Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and 

Tanks,” to manage loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion; fouling that leads to corrosion; or selective leaching in 

certain components. The applicant did not credit the related plant-specific AMP, “Coating 

Integrity,” for the aging effect and components that reference SRP-LR items 3.4.1-67 and 

3.4.1-68 but instead credited alternate items and programs to manage the effects of these aging 

mechanisms for these components. For example, in regard to item 3.4.1-67, loss of material for 

an internally coated tank in the condensate system exposed to treated water is managed by the 

Water Chemistry – BWR Program. In regard to item 3.3.1-68, there are no gray cast iron 

components in the steam and power conversion systems. The staff finds this approach 

acceptable because the alternate items and programs used are adequate to manage the effects 

of aging for these components and because this approach is consistent with GALL Report 

AMP XI.M42. 

 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.4.1, item 3.4.1-35, addresses aluminum piping exposed to outdoor air, which will 

be managed for loss of material due to pitting and crevice corrosion. For the AMR item that 

cites generic note E, the LRA credits the Buried and Underground Piping Program to manage 

the aging effect for aluminum piping in the condensate storage and transfer system. The GALL 

Report recommends GALL Report AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components,” to ensure that this aging effect is adequately managed. GALL Report 

AMP XI.M36 recommends using periodic visual inspections to manage the effects of aging. 

The staff’s evaluation of the applicant’s Buried and Underground Piping Program is documented 

in SER Section 3.0.3.1.2. The staff noted that GALL Report AMP XI.M36 recommends the use 

of GALL Report AMP XI.M41, “Buried and Underground Piping and Tanks,” for piping that is 

located in a tunnel or vault such that access for inspections is restricted. The applicant’s Buried 

and Underground Piping Program includes inspections that are consistent with those 

recommended in GALL Report AMP XI.M41. Specifically, at least 1 percent of the length of 

underground aluminum piping (not to exceed one inspection of a 10-foot length) is visually 

inspected in each 10-year period to detect external corrosion. Based on its review of 

components associated with item 3.4.1-35 for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage the effects of aging using the Buried and Underground 

Piping Program acceptable because the applicant is managing underground aluminum 

components in a manner consistent with GALL Report guidance. 

The staff concludes that, for LRA item 3.4.1-35, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
3-369 

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended 

In LRA Section 3.4.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the steam and power conversion systems components and provides 

information concerning how it will manage the following aging effects: 

 cumulative fatigue damage 

 cracking due to SCC 

 loss of material due to pitting and crevice corrosion 

 QA for aging management of nonsafety-related components 

 ongoing review of operating experience 

 loss of material due to recurring internal corrosion 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.4.2.2. The staff’s review of the applicant’s 

further evaluation follows. 

 Cumulative Fatigue Damage 

LRA Section 3.4.2.2.1 is associated with LRA Table 3.4.1, item 3.4.1-1, that addresses steel 

piping, piping components, and piping elements exposed to steam or treated water, which will 

be managed for cumulative fatigue damage. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3, and is 

evaluated in accordance with 10 CFR 54.21(c). The applicant stated that its evaluation of the 

TLAA is addressed in LRA Section 4.3. 

The staff reviewed LRA Section 3.4.2.2.1 against the criteria in SRP-LR Section 3.4.2.2.1, which 

state that cumulative fatigue damage of steel piping, piping components, and piping elements is 

a TLAA and must be evaluated in accordance with the TLAA acceptance criteria requirements 

of 10 CFR 54.21(c). The staff reviewed the applicant’s AMR line items and determined that the 

AMR results are consistent with the recommendations of the GALL Report and SRP-LR for 

managing cumulative fatigue damage in steel and stainless steel piping, piping components, 

and piping elements. 

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.4.2.2.1 criteria. For those line items that apply to LRA Section 3.4.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components. 

 Cracking Due to Stress Corrosion Cracking 

LRA Section 3.4.2.2.2, associated with LRA Table 3.4.1, item 3.4.1-2, addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air that will be 

managed for cracking due to SCC by the External Surfaces Monitoring Program. The criteria in 
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SRP-LR Section 3.4.2.2.2 state that cracking could occur for stainless steel components 

exposed to outdoor air environments containing sufficient halides and in which condensation or 

deliquescence is possible. The SRP-LR also states that the possibility for cracking extends to 

components exposed to air that has recently been introduced to buildings. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that cracking of stainless steel 

components directly exposed to outdoor air will be managed by the External Surfaces 

Monitoring Program. The applicant also stated that there are no indoor stainless steel steam 

and power conversion system components located near outdoor air intakes that could also be 

subject to this aging effect. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The staff noted that the subject components at the applicant’s site carry 

water and are associated with the condensate storage and transfer system. The staff also 

noted that the applicant’s program includes periodic visual inspections of external surfaces, 

which are conducted at least once per refueling cycle, to identify leakage that would be 

indicative of cracking. In its review of components associated with item 3.4.1-2, the staff finds 

that the applicant has met the further evaluation criteria and that its proposal to manage the 

effects of aging using the External Surfaces Monitoring Program is acceptable because the 

periodic visual inspections for leakage described above are capable of identifying cracking 

before loss of intended functions. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.4.2.2.2 criteria. For those items associated with LRA Section 3.4.2.2.2, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Section 3.4.2.2.3, associated with LRA Table 3.4.1, item 3.4.1-3, addresses stainless steel 

piping, piping components, piping elements, and tanks exposed to outdoor air that will be 

managed for loss of material due to pitting and crevice corrosion by the External Surfaces 

Monitoring Program. The criteria in SRP-LR Section 3.4.2.2.3 state that loss of material could 

occur for stainless steel components exposed to outdoor air environments containing sufficient 

halides and in which condensation or deliquescence is possible. The SRP-LR also states that 

the possibility for loss of material extends to components exposed to air that has recently been 

introduced to buildings. The applicant addressed the further evaluation criteria of the SRP-LR 

by stating that loss of material of stainless steel components directly exposed to outdoor air will 

be managed by the External Surfaces Monitoring Program. The applicant also stated that there 

are no indoor stainless steel steam and power conversion system components located near 

outdoor air intakes that could also be subject to this aging effect. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.2.7. The staff noted that the applicant’s program includes periodic visual 

inspections of external surfaces, which are conducted at least once per refueling cycle, to 

identify corrosion and any other conditions that preclude the stainless steel from having a clean, 

shiny surface. In its review of components associated with item 3.4.1-3, the staff finds that the 

applicant has met the further evaluation criteria and that its proposal to manage the effects of 

aging using the External Surfaces Monitoring Program is acceptable because the periodic visual 
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inspections described above are capable of identifying loss of material before loss of intended 

functions. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.4.2.2.3 criteria. For those items associated with LRA Section 3.4.2.2.3, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

 Ongoing Review of Operating Experience 

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience for AMPs. 

 Loss of Material Due to Recurring Internal Corrosion 

LRA Section 3.4.2.2.6, associated with LRA Table 3.4.1, item 3.4.1-61, addresses metallic 

piping, piping components, and tanks exposed to raw water or wastewater. The criteria in 

SRP-LR Section 3.4.2.2.6 state that recurring internal corrosion can result in the need to 

augment AMPs beyond the recommendations in the GALL Report. The SRP-LR also states 

that recurring internal corrosion can be identified by an operating experience search for 

repeated instances in which an aging effect resulted in a component either not meeting 

plant-specific acceptance criteria or experiencing a reduction in wall thickness greater than 

50 percent. The applicant stated that this item is not applicable because a review of plant 

operating experience identified no conditions of recurring internal corrosion in the steam and 

power conversion systems. The staff evaluated the applicant’s claim and finds it acceptable 

because the staff’s independent review of plant operating experience during its onsite audit of 

the applicant’s AMPs did not identify conditions in the steam and power conversion systems that 

meet the further evaluation criteria in the SRP-LR that could result in the need to augment the 

AMPs. 

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.4.2-1 through 3.4.2-3-9, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with, or not addressed 

in, the GALL Report. 

In LRA Tables 3.4.2-1 through 3.4.2-3-9, the applicant indicated, through notes F through J, that 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 
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Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations that were not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections. 

 Condensate Storage and Transfer System – Summary of Aging Management 

Review – LRA Table 3.4.2-1 

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the 

condensate storage and transfer system component groups. 

Piping and Piping Components Exposed to Outdoor Air and Soil. In LRA Tables 3.4.2-1 

and 3.4.2-2, the applicant stated that aluminum, carbon steel, and stainless steel flex 

connections, piping, and valve bodies exposed to outdoor air and soil will be managed for loss 

of material and cracking (aluminum and stainless steel only) by the Buried and Underground 

Piping Program. The AMR items cite generic notes G and H. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The GALL Report provides the following aging effects for the 

material and environment combinations cited in these tables: 

 Item SP-147 states that aluminum components exposed to outdoor air are susceptible to 

loss of material. 

 Item S-41 states that carbon steel components exposed to outdoor air are susceptible to 

loss of material. 

 Item SP-94 states that stainless steel components exposed to soil are susceptible to 

loss of material. 

 Item SP-118 states that stainless steel components exposed to outdoor air are 

susceptible to cracking. 

In addition, Table 8.2, “Environment – Alloy Combinations Known to Produce Stress-Corrosion 

Cracking,” in the report entitled, “Principles and Prevention of Corrosion,” D.A. Jones, second 

edition, states that aluminum alloys are susceptible to SCC in the presence of air with water 

vapor. 

Based on its review of the above reference, the staff finds that the applicant has identified all 

credible aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Buried and Underground Piping Program is documented 

in SER Section 3.0.3.1.2. The staff finds the applicant’s proposal to manage the effects of aging 

using the Buried and Underground Piping Program acceptable because it includes periodic 

visual inspections that are capable of detecting loss of material and cracking. 

On the basis of its review, the staff concludes that for items in LRA Tables 3.4.2-1 and 3.4.2-2 

with an AERM, the applicant has demonstrated that the effects of aging for these items will be 
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adequately managed so that their intended function(s) will be maintained consistent with the 

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Stainless Steel Flex Connections Exposed to Outdoor Air. In LRA Table 3.4.2-1, the applicant 

stated that there is a TLAA for stainless steel flex connections exposed to outdoor air that cites 

generic note G. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, 

for this component, environment, and material. The staff’s evaluation of the fatigue TLAA for 

non-Class 1 components, other than piping, is documented in SER Section 4.3.2.2. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-1 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Feedwater and Standby Feedwater System – Summary of Aging Management 

Review – LRA Table 3.4.2-2 

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the 

feedwater and standby feedwater system component groups. 

Piping and Piping Components Exposed to Outdoor Air. The staff’s evaluation for carbon steel 

and stainless steel piping and piping components exposed to outdoor air, which will be 

managed for loss of material and cracking by the Buried and Underground Piping Program and 

are associated with generic note G, is documented in SER Section 3.4.2.3.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-2 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) – Summary of Aging Management Evaluation – LRA 

Tables 3.4.2-3-1 through 3.4.2-3-9 

The staff reviewed LRA Tables 3.4.2-3-1 through 3.4.2-3-9, which summarize the results of 

AMR evaluations for the system name component groups. 

Main Steam System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.4.2-3-1. 

Stainless Steel Thermowell Exposed to Steam. In LRA Table 3.4.2-3-1, the applicant stated 

that there is a TLAA for stainless steel thermowells exposed to steam that cites generic note H. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for this 

component and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 

components, other than piping, is documented in SER Section 4.3.2.2. 

Condensate System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.4.2-3-2. 

Carbon Steel Heat Exchanger Components and Tanks Exposed to Treated Water and Raw 

Water. As amended by letter dated February 15, 2015, LRA Tables 3.4.2-3-2, 3.4.2-3-5, and 
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3.4.2-3-6 state that carbon steel heat exchanger components and tanks exposed to treated 

water and raw water will be managed for loss of coating integrity by the Coating Integrity 

Program. The AMR items cite generic note H. 

The staff noted that although the applicant cited generic note H, LR-ISG-2013-01, “Aging 

Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope 

Piping, Piping Components, Heat Exchangers, and Tanks,” provides AMR line items to address 

this MEAP combination. SRP-LR Table 3.4-1, item 3.4.1-66, states that metallic heat 

exchangers and tanks with internal coatings/linings exposed to raw water and treated water are 

managed for loss of coating integrity by GALL Report AMP XI.M42, “Internal Coatings/Linings 

for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.” 

The staff’s evaluation of the applicant’s Coating Integrity Program is documented in SER 

Section 3.0.3.2.24. The staff finds the applicant’s proposal to manage the effects of aging using 

the Coating Integrity Program acceptable because periodic visual inspections of internal 

coatings by qualified personnel are capable of detecting loss of coating integrity. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-3-2 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Feedwater and Standby Feedwater System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA Table 3.4.2-3-3. 

Stainless Steel Flow Element Exposed to Steam. In LRA Table 3.4.2-3-3, the applicant stated 

that there is a TLAA for stainless steel flow elements exposed to steam that cites generic 

note H. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for this 

component and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 piping 

elements is documented in SER Section 4.3.2.1. 

Heater Drains System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.4.2-3-4. 

Carbon Steel with Nickel Alloy Clad Valve Body Exposed to Treated Water (Internal). As 

amended by letter dated June 26, 2015, in LRA Table 3.4.2-3-4, the applicant stated that carbon 

steel with nickel alloy clad valve body exposed internally to treated water will be managed for 

loss of material by the Water Chemistry Control – BWR Program. The AMR item cites generic 

note F. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The staff noted that the applicant addressed cracking due to 

fatigue for these component, material, and environment combinations in other AMR items in 

LRA Tables 3.4.2-3-4, 3.4.2-3-5, and 3.4.2-3-9 and loss of material due to flow-accelerated 

corrosion in piping in an AMR item in LRA Table 3.4.2-3-9. The staff noted that EPRI 

TR-1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, 

Revision 4,” dated January 2006, states that cracking due to SCC or intergranular attack is an 

aging effect of concern for nickel alloys in the power production loop (i.e., condensate, 

feedwater, and main steam systems), or if temperature is greater than 500 °F and the oxygen 

concentration is greater than 100 ppb or chlorides are greater than 150 ppb. Loss of material is 
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also an aging effect of concern if the oxygen concentration and chlorides are above these limits. 

The staff noted that that the GALL Report identifies cracking and loss of material as applicable 

aging effects for nickel alloy components exposed to treated water. Based on its review of the 

EPRI TR-1010639 and the GALL Report, which state that nickel alloys can be subject to the 

aging effects of cracking and loss of material, the staff finds that the applicant has identified all 

credible aging effects for this component, material, and environment combination. 

The staff’s evaluations of the applicant’s One-Time Inspection and Water Chemistry Control – 

BWR programs are documented in SER Sections 3.0.3.1.17 and 3.0.3.1.20, respectively. The 

staff finds the applicant’s proposal to manage aging using the Water Chemistry Control - BWR 

Program and One-Time Inspection Program acceptable because the water chemistry controls 

limit oxygen concentration and contaminants, such as chlorides, to minimize cracking and loss 

of material and because a one-time inspection of a representative sample of components will 

verify the effectiveness of the water chemistry controls. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-3-4 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Main Turbine Generator and Auxiliaries System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA Table 3.4.2-3-5. 

Carbon Steel Heat Exchanger Components and Tanks Exposed to Treated Water and Raw 

Water. The staff’s evaluation for carbon steel heat exchanger components and tanks exposed 

to treated water and raw water, which will be managed for loss of coating integrity by the 

Coating Integrity Program and are associated with generic note H, is documented in SER 

Section 3.4.2.3.3-2. 

Elastomer Flex Connections Exposed to Steam. The staff’s evaluation for elastomer flex 

connections exposed to steam, which will be managed for cracking and changes in material 

properties by the Internal Surfaces in Miscellaneous Piping and Ducting Component Program 

and are associated with generic note G, is documented in SER Section 3.3.2.3.3. 

Aluminum Traps Exposed to Wastewater. In LRA Table 3.4.2-3-5, the applicant stated that 

aluminum traps exposed internally to wastewater will be managed for loss of material by the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The AMR item 

cites generic note G. 

The staff reviewed the associated item in the LRA and considered whether the aging effect 

proposed by the applicant constitutes all the credible aging effects for this component, material, 

and environment description. The GALL Report states that aluminum components exposed to 

raw water (i.e., untreated surface water or groundwater) and potential contaminants, such as 

lubricating oil and fuel oil, are susceptible only to loss of material. The ASM International’s 

Metals Handbook, Desk Edition, states that SCC is most likely in the highest strength grades of 

structural aluminum, such as those used in armor plate and automotive structural components. 

Therefore, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination. 

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.11. The staff finds the applicant’s 
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proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the opportunistic visual inspections conducted by 

the program, with a representative sample of components inspected at least once every 

10 years, are capable of detecting loss of material before loss of the intended function. 

Stainless Steel and Nickel Piping, Valve Bodies, Expansion Joints, Flow Element, Orifices, and 

Thermowells Exposed to Steam. In LRA Table 3.4.2-3-5, the applicant stated that there are 

TLAAs for stainless steel and nickel piping, valve bodies, expansion joints, flow element, 

orifices, and thermowells exposed to steam that cite generic note H or G. The staff confirmed 

that there are TLAAs, as documented in LRA Section 4.3.2, for these components, environment, 

and materials. The staff’s evaluation of the fatigue TLAAs for non-Class 1 components is 

documented in SER Sections 4.3.2.1 and 4.3.2.2. 

Nickel Alloy Expansion Joints and Piping Exposed to Steam. In LRA Tables 3.4.2-3-5 and 

3.4.2-3-9, the applicant stated that nickel alloy expansion joints and piping exposed internally to 

steam will be managed for cracking and loss of material by the Water Chemistry Control – BWR 

Program. The AMR items cite generic note G. As stated in LRA Table 3.0-1, steam is subject 

to a water chemistry program, and for determining aging effects, steam is considered as treated 

water. As documented in LRA Sections B.1.33 and B.1.43, the One-Time Inspection Program 

will be used to verify the effectiveness of the Water Chemistry Control – BWR Program. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed cracking 

due to fatigue for these components, material, and environment combinations in other AMR 

items in LRA Tables 3.4.2-3-5 and 3.4.2-3-9 and loss of material due to flow-accelerated 

corrosion in piping in an AMR item in LRA Table 3.4.2-3-9. The staff notes that EPRI 

TR-1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, 

Revision 4,” dated January 2006, states that cracking due to stress corrosion cracking or 

intergranular attack is an aging effect of concern for nickel alloys in the power production loop 

(i.e., condensate, feedwater, and main steam systems), or if the temperature is greater than 

500 °F and if the oxygen concentration is greater than 100 ppb or if chlorides are greater than 

150 ppb. Loss of material is also an aging effect of concern if the oxygen concentration and 

chlorides are above these limits. Therefore, the staff finds that the applicant has identified all 

credible aging effects for this component, material, and environment combination. 

The staff’s evaluations of the applicant’s One-Time Inspection and Water Chemistry Control – 

BWR programs are documented in SER Sections 3.0.3.1.17 and 3.0.3.1.20, respectively. The 

staff finds the applicant’s proposal to manage aging using the Water Chemistry Control – BWR 

Program and One-Time Inspection Program acceptable because the water chemistry controls 

limit oxygen concentration and contaminants, such as chlorides, to minimize cracking and loss 

of material and because a one-time inspection of a representative sample of components will 

verify the effectiveness of the water chemistry controls. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-3-5 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Condenser and Auxiliaries System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.4.2-3-6. 
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Carbon Steel Heat Exchanger Components and Tanks Exposed to Treated Water and Raw 

Water. The staff’s evaluation for carbon steel heat exchanger components and tanks exposed 

to treated water and raw water, which will be managed for loss of coating integrity by the 

Coating Integrity Program and are associated with generic note H, is documented in SER 

Section 3.4.2.3.3-2. 

Stainless Steel Expansion Joints Exposed to Steam. In LRA Table 3.4.2-3-6, the applicant 

stated that there is a TLAA for stainless steel expansion joints exposed to steam that cites 

generic note H. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, 

for this component and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 

components, other than piping, is documented in SER Section 4.3.2.2. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-3-6 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

Circulating Water System, Nonsafety-Related Components Affecting Safety-Related Systems – 

Summary of Aging Management Evaluation – LRA Table 3.4.2-3-7. 

Plastic Piping Exposed to Indoor Air. The staff’s evaluation for plastic piping exposed to indoor 

air, which will be managed for change in material properties by the External Surfaces Monitoring 

Program and is associated with generic note F, is documented in SER Section 3.3.2.3.17. 

Plastic Piping Exposed to Raw Water. In LRA Table 3.4.2-3-7, the applicant stated that for 

plastic piping internally exposed to raw water, there is no aging effect and no proposed AMP. 

The AMR item cites generic note F. 

During the audit, the staff reviewed plant-specific drawings and identified that the plastic piping 

exposed to raw water in LRA Table 3.4.2.3-7 is constructed of PVC. The staff reviewed the 

associated items in the LRA to confirm that no credible aging effects are applicable for this 

component, material, and environment combination. The staff noted that the American Water 

Works Association manual, PVC Pipe – Design and Installation – Manual of Water Supply 

Practices, M23, Second Edition, dated 2002, states, “PVC and PVCO pipes are resistant to 

almost all types of corrosion – both chemical and electrochemical – that are experienced in 

underground piping systems. Because PVC is a nonconductor, galvanic and electrochemical 

effects are nonexistent in PVC piping systems. PVC pipe cannot be damaged by aggressive 

waters or corrosive soils.” It also states, “PVC pipe is nearly totally resistant to biological attack. 

Biological attack can be described as degradation or deterioration caused by the action of living 

microorganisms or macroorganisms.” It further states, “PVC pipe is well suited to applications 

where abrasive conditions are anticipated.” Appendix A, “Chemical Resistance Tables,” to this 

manual lists PVC as generally resistant to chemicals up to 140 °F, such as bleach (12.5 percent 

active chlorine), potassium hydroxide, sodium hydroxide, kerosene, hydrochloric acid, hydrogen 

peroxide (90 percent), sea water, soaps, and sulfuric acid (70 percent). The staff also noted 

that PVC Formulary, G. Wypych, ChemTec Publishing, dated September 28, 2009, states that 

“[a]s a general rule, PVC is not resistant to polar solvents but very resistant to acids, bases, 

salts, alcohols, esters, and hydrocarbons.” Given that the PVC piping is located in the 

circulating water system, it is not clear to the staff whether chlorine is injected into the system 

and at what levels. By letter dated December 17, 2014, the staff issued RAI 3.4.2.3.3-7-1, 

requesting that the applicant state whether chlorine is injected into the circulating water system. 

If chlorine is injected, the applicant should state the percent of active chlorine that would be 
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present in the PVC piping. If the free chlorine exceeds 12.5 percent, the applicant should 

explain how aging of the PVC pipe will be managed. 

In its response dated January 15, 2015, the applicant stated that the in-scope portions of the 

system constructed of PVC and exposed to raw water are in the normally isolated circulating 

water drain down system. The chlorine levels in this portion of the system are significantly less 

than 12.5 percent. 

The staff noted that the circulating water drain down system would not be expected to be 

exposed to temperatures as high as 140 °F. The staff finds the applicant’s response and 

proposal that there are no AERMs acceptable based on its review of the above references, 

which state that PVC piping exposed to low-temperature water (less than 140 °F) and low 

chlorine levels is not subject to degradation. The staff’s concern described in RAI 3.4.2.3.3-7-1 

is resolved. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-3-7 with no 

AERMs, the applicant has appropriately evaluated the material and environment combinations 

not addressed in the GALL Report, and their intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). The 

staff also concludes that for items in this table with an AERM, the applicant has demonstrated 

that the effects of aging will be adequately managed so that their intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

Condenser Storage and Transfer System, Nonsafety-Related Components Affecting 

Safety-Related Systems – Summary of Aging Management Evaluation – LRA Table 3.4.2-3-8. 

The staff reviewed LRA Table 3.4.2-3-8, which summarizes the results of AMR evaluations for 

the condenser storage and transfer system, nonsafety-related components affecting 

safety-related systems. The staff’s review did not identify any AMR items with notes F through 

J, indicating that the combinations of component type, material, environment, and AERM for the 

condenser storage and transfer system, nonsafety-related components affecting safety-related 

systems are consistent with the GALL Report. 

Drips, Drains and Vents System, Nonsafety-Related Components Affecting Safety-Related 

Systems – Summary of Aging Management Evaluation – LRA Table 3.4.2-3-9. 

Nickel and Stainless Steel Expansion Joints, Piping, Tubing, Valve Bodies, and Orifices 

Exposed to Steam. In LRA Table 3.4.2-3-9, the applicant stated that there are TLAAs for nickel 

and stainless steel expansion joints, piping, tubing, valve bodies, and orifices exposed to steam 

that cite generic note H or G. The staff confirmed that there are TLAAs, as documented in LRA 

Section 4.3.2, for these components and materials. The staff’s evaluation of the fatigue TLAAs 

for non-Class 1 components is documented in SER Sections 4.3.2.1 and 4.3.2.2. 

Nickel Alloy Expansion Joints and Piping Exposed to Steam. In LRA Tables 3.4.2-3-5 and 

3.4.2-3-9, the applicant stated that nickel alloy expansion joints and piping exposed internally to 

steam will be managed for cracking and loss of material by the Water Chemistry Control – BWR 

Program. The AMR items cite generic note G. As stated in LRA Table 3.0-1, steam is subject 

to a water chemistry program, and for determining aging effects, steam is considered as treated 

water. As documented in LRA Sections B.1.33 and B.1.43, the One-Time Inspection Program 

will be used to verify the effectiveness of the Water Chemistry Control – BWR Program. 
3-379 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed cracking 

due to fatigue for these components, material, and environment combinations in other AMR 

items in LRA Tables 3.4.2-3-5 and 3.4.2-3-9 and loss of material due to flow-accelerated 

corrosion in piping in an AMR item in LRA Table 3.4.2-3-9. The staff notes that EPRI 

TR-1010639 “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, 

Revision 4,” dated January 2006, states that cracking due to stress corrosion cracking or 

intergranular attack is an aging effect of concern for nickel alloys in the power production loop 

(i.e., condensate, feedwater, and main steam systems), or if temperature is greater than 500 °F 

and if the oxygen concentration is greater than 100 ppb or if chlorides are greater than 150 ppb. 

Loss of material is also an aging effect of concern if the oxygen concentration and chlorides are 

above these limits. Therefore, the staff finds that the applicant has identified all credible aging 

effects for this component, material, and environment combination. 

The staff’s evaluations of the applicant’s One-Time Inspection and Water Chemistry Control – 

BWR programs are documented in SER Sections 3.0.3.1.17 and 3.0.3.1.20, respectively. The 

staff finds the applicant’s proposal to manage aging using the Water Chemistry Control – BWR 

Program and One-Time Inspection Program acceptable because the water chemistry controls 

limit oxygen concentration and contaminants, such as chlorides, to minimize cracking and loss 

of material and because a one-time inspection of a representative sample of components will 

verify the effectiveness of the water chemistry controls. 

On the basis of its review, the staff concludes that for items in LRA Table 3.4.2-3-9 with an 

AERM, the applicant has demonstrated that the effects of aging will be adequately managed so 

that their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

3.4.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effect of aging for the steam and power conversion systems components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

3.5 Aging Management of Structures and Component Supports 

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

structures and component supports components and component groups of the following: 

 reactor/auxiliary building and primary containment 

 water-control structures 

 turbine building, process facilities, and yard structures 

 bulk commodities 

The GALL Report organizes safety-related and other structures (other than containments), such 

as those listed above, into nine groups. These nine groups, which are referenced in the LRA 

and staff’s evaluation as Groups 1–9 Structures, are generically defined in GALL Report 

Chapter III.A, “Safety Related and Other Structures.” 
3-380 

3.5.1 Summary of Technical Information in the Application 

LRA Section 3.5 provides AMR results for the structures and component supports components 

and component groups. LRA Table 3.5.1, “Summary of Aging Management Programs for 

Structures and Component Supports Evaluated in Chapters II and III of NUREG-1801,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for the 

structures and component supports components and component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.5.2 Staff Evaluation 

The staff reviewed LRA Section 3.5, as amended by letter dated May 9, 2016, to determine 

whether the applicant provided sufficient information to demonstrate that the effects of aging for 

the structures and component supports components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

The staff conducted a review of the applicant’s AMRs to ensure the applicant’s claim that certain 

AMRs are consistent with the GALL Report, not applicable, or not used. The staff did not repeat 

its review of the matters described in the GALL Report; however, the staff did verify that the 

material presented in the LRA is applicable and that the applicant identified the appropriate 

GALL Report AMRs. The AMRs that the staff confirmed are consistent with the GALL Report 

are noted as such in SER Table 3.5-1 and no further discussion is required. The AMRs that the 

staff confirmed are not applicable to Fermi 2 or not used, because the component, material, and 

environment combination described in the SRP-LR does not exist for in-scope SCs at Fermi 2 or 

because the component, material, and environment combination is addressed by another SER 

Table 3.1-1 item, or that require no aging management are noted in SER Table 3.5-1 and are 

discussed in SER Section 3.5.2.1.1. Details of the staff’s evaluation of the AMRs that the 

applicant claimed are consistent with the GALL Report, but for which a different AMP from the 

program recommended in the GALL Report is used to manage aging, and AMRs for which the 

staff requested additional information are documented in SER Sections 3.5.2.1.2 through 

3.5.2.1.9. 

During its review, the staff also reviewed AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.5.2.2 acceptance criteria. The staff’s evaluations of 

AMRs for which the GALL Report recommends further evaluation are documented in SER 

Section 3.5.2.2. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs not consistent 

with, or not addressed in, the GALL Report are documented in SER Section 3.5.2.3. 
3-381 

SER Table 3.5-1 summarizes the staff’s evaluation of components, aging effects or 

mechanisms, and AMPs listed in LRA Section 3.5 and addressed in the GALL Report. 

Table 3.5-1 Staff Evaluation for Structures and Component Supports Components in the 

GALL Report 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

BWR Concrete and Steel (Mark I, II, and III) Containments

Concrete: dome; 

wall; basemat; ring 

girders; buttresses, 

concrete elements, 

all (3.5.1-1) 

Cracking and 

distortion due to 

increased stress 

levels from 

settlement 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” or 

Chapter XI.S6, 

“Structure 

Monitoring” 

If a de-watering 

system is relied upon 

for control of 

settlement, then the 

licensee is to ensure 

proper functioning of 

the de-watering 

system through the 

period of extended 

operation. 

Yes, if a 

de-watering 

system is 

relied upon 

to control 

settlement 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Concrete: 

foundation; 

subfoundation 

(3.5.1-2) 

Reduction of 

foundation 

strength and 

cracking due to 

differential 

settlement and 

erosion of 

porous concrete 

subfoundation 

Chapter XI.S6, 

“Structures 

Monitoring” 

If a de-watering 

system is relied upon 

for control of erosion, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation. 

Yes, if a 

de-watering 

system is 

relied upon 

to control 

settlement 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Concrete: dome; 

wall; basemat; ring 

girders; buttresses; 

Concrete: 

containment; wall; 

basemat; Concrete: 

basemat, concrete 

fill-in annulus 

(3.5.1-3) 

Reduction of 

strength and 

modulus due to 

elevated 

temperature 

(>150°F general; 

>200°F local) 

A plant-specific aging 

management 

program is to be 

evaluated. 

Yes, if 

temperature 

limits are 

exceeded 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Steel elements 

(inaccessible areas): 

drywell shell; drywell 

head; and drywell 

shell (3.5.1-4) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

Yes, if 

corrosion is 

indicated 

from the 

IWE 

examinations 

Containment 

Inservice 

Inspection – IWE 

and Containment 

Leak Rate 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1) 
3-382 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel elements 

(inaccessible areas): 

liner; liner anchors; 

integral attachments; 

Steel elements 

(inaccessible areas): 

suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable) (3.5.1-5) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” and 

Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

Yes, if 

corrosion is 

indicated 

from the 

IWE 

examinations 

Not used. The 

torus shell steel 

elements are 

accessible and are 

addressed in item 

3.5.1-6. The loss 

of material for 

inaccessible areas 

of steel drywell 

shell; drywell 

head; and drywell 

shell in sand 

pocket regions is 

addressed in item 

3.5.1-4 (as 

applicable). Steel 

elements 

(inaccessible 

areas): liner, liner 

anchors, and 

integral 

attachments, are 

applicable to PWR 

containments. 

Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Steel elements: torus 

shell (3.5.1-6) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” and 

Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

Yes, if 

corrosion is 

significant, 

recoating 

of the torus 

is recommended. 

Containment 

Inservice 

Inspection and 

Containment Leak 

Rate programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1) 

Steel elements: torus 

ring girders; 

downcomers; Steel 

elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-7) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” 

Yes, if 

corrosion is 

significant 

Containment 

Inservice 

Inspection – IWE 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1) 

Pre-stressing 

system: tendons 

(3.5.1-8) 

Loss of 

prestress due to 

relaxation; 

shrinkage; 

creep; elevated 

temperature 

Yes, TLAA Yes, TLAA Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

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 

(3.5.1-9) 

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists) 

Yes, TLAA Yes, TLAA TLAA Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1) 
3-383 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Penetration sleeves; 

penetration bellows 

(3.5.1-10) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

Yes, 

detection of 

aging 

effects is to 

be 

evaluated 

Containment 

Inservice 

Inspection – IWE 

and Containment 

Leak Rate 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.1) 

Concrete 

(inaccessible areas): 

dome; wall; basemat; 

ring girders; 

buttresses, Concrete 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

dome; wall; basemat 

(3.5.1-11) 

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw 

Further evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557). 

Yes, for 

plants 

located in 

moderate to 

severe 

weathering 

conditions 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Concrete 

(inaccessible areas): 

dome; wall; basemat; 

ring girders; 

buttresses, Concrete 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

containment; wall; 

basemat, Concrete 

(inaccessible areas): 

basemat, concrete 

fill-in annulus 

(3.5.1-12) 

Cracking due to 

expansion from 

reaction with 

aggregates 

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes, if 

concrete is 

not 

constructed 

as stated 

function 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Concrete 

(inaccessible areas): 

basemat, Concrete 

(inaccessible areas): 

dome; wall; basemat 

(3.5.1-13) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes, if 

leaching is 

observed in 

accessible 

areas that 

impact 

intended 

function 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Concrete 

(inaccessible areas): 

dome; wall; basemat; 

ring girders; 

buttresses, Concrete 

(inaccessible areas): 

containment; wall; 

basemat (3.5.1-14) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes, if 

leaching is 

observed in 

accessible 

areas that 

impact 

intended 

function 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.1) 

Concrete (accessible 

areas): basemat 

(3.5.1-15) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 
3-384 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Concrete (accessible 

areas): basemat, 

Concrete: 

containment; wall; 

basemat (3.5.1-16) 

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses 

(3.5.1-17) 

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete (accessible 

areas): basemat 

(3.5.1-18) 

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete (accessible 

areas): basemat, 

Concrete (accessible 

areas): containment; 

wall; basemat, 

Concrete (accessible 

areas): basemat, 

concrete fill-in 

annulus (3.5.1-19) 

Cracking due to 

expansion from 

reaction with 

aggregates 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

Concrete (accessible 

areas): containment; 

wall; basemat 

(3.5.1-20) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete (accessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses; 

reinforcing steel, 

Concrete (accessible 

areas): basemat; 

reinforcing steel, 

Concrete (accessible 

areas): dome; wall; 

basemat; reinforcing 

steel (3.5.1-21) 

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 
3-385 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Concrete 

(inaccessible areas): 

basemat; reinforcing 

steel (3.5.1-22) 

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete 

(inaccessible areas): 

basemat; reinforcing 

steel, Concrete 

(inaccessible areas): 

dome; wall; basemat; 

reinforcing steel 

(3.5.1-23) 

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete 

(inaccessible areas): 

dome; wall; basemat; 

ring girders; 

buttresses, Concrete 

(inaccessible areas): 

basemat, Concrete 

(accessible areas): 

dome; wall; basemat 

(3.5.1-24) 

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Concrete 

(inaccessible areas): 

dome; wall; basemat; 

ring girders; 

buttresses; 

reinforcing steel 

(3.5.1-25) 

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.5.2.1.1) 

Moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-26) 

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” 

No Containment 

Inservice 

Inspection – IWE 

and Periodic 

Surveillance and 

Preventive 

Maintenance 

programs 

Consistent with 

GALL Report 

(see SER 

Section 3.5.2.1.2) 

Penetration sleeves; 

penetration bellows, 

Steel elements: 

torus; vent line; vent 

header; vent line 

bellows; 

downcomers, 

suppression pool 

shell (3.5.1-27) 

Cracking due to 

cyclic loading 

(CLB fatigue 

analysis does 

not exist) 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Personnel airlock, 

equipment hatch, 

CRD hatch (3.5.1-28) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Containment 

Inservice 

Inspection – IWE 

and Containment 

Leak Rate 

programs 

Consistent with the 

GALL Report 
3-386 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Personnel airlock, 

equipment hatch, 

CRD hatch: locks, 

hinges, and closure 

mechanisms 

(3.5.1-29) 

Loss of leak 

tightness due to 

mechanical wear 

of locks, hinges 

and closure 

mechanisms 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Containment 

Inservice 

Inspection – IWE 

and Containment 

Leak Rate 

programs 

Consistent with the 

GALL Report 

Pressure-retaining 

bolting (3.5.1-30) 

Loss of preload 

due to selfloosening 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Containment 

Inservice 

Inspection – IWE 

and Containment 

Leak programs 

Consistent with the 

GALL Report 

Pressure-retaining 

bolting, Steel 

elements: 

downcomer pipes 

(3.5.1-31) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” 

No Containment 

Inservice 

Inspection – IWE 

Program 

Consistent with the 

GALL Report 

Prestressing system: 

tendons; anchorage 

components 

(3.5.1-32) 

Loss of material 

due to corrosion 

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Seals and gaskets 

(3.5.1-33) 

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other defects 

Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J “ 

No Containment Leak 

Rate Program 

Consistent with the 

GALL Report 

Service Level I 

coatings (3.5.1-34) 

Loss of coating 

integrity due to 

blistering, 

cracking, flaking, 

peeling, 

delamination, 

rusting, or 

physical damage 

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance” 

No Protective Coating 

Monitoring and 

Maintenance 

Program 

Consistent with the 

GALL Report 

Steel elements 

(accessible areas): 

liner; liner anchors; 

integral attachments, 

Penetration sleeves, 

Steel elements 

(accessible areas): 

drywell shell; drywell 

head; drywell shell in 

sand pocket regions; 

Steel elements 

(accessible areas): 

suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable), Steel 

elements (accessible 

areas): drywell shell; 

drywell head 

(3.5.1-35) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Containment 

Inservice 

Inspection – IWE 

and Containment 

Leak programs 

Consistent with the 

GALL Report 
3-387 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel elements: 

drywell head; 

downcomers 

(3.5.1-36) 

Fretting or 

lockup due to 

mechanical wear 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Steel elements: 

suppression 

chamber (torus) liner 

(interior surface) 

(3.5.1-37) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Steel elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-38) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Steel elements: vent 

line bellows 

(3.5.1-39) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,” 

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J” 

No Containment 

Inservice 

Inspection 

Program and 

Containment Leak 

Rate programs 

Consistent with the 

GALL Report 

Unbraced 

downcomers, Steel 

elements: vent 

header; downcomers 

(3.5.1-40) 

Cracking due to 

cyclic loading 

(CLB fatigue 

analysis does 

not exist) 

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Steel elements: 

drywell support skirt, 

Steel elements 

(inaccessible areas): 

support skirt 

(3.5.1-41) 

None None NA - No 

AEM or 

AMP 

None Consistent with the 

GALL Report 

Safety-Related and Other Structures; and Component Supports

Groups 1-3, 5, 7-9: 

concrete 

(inaccessible areas): 

foundation (3.5.1-42) 

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw 

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557) 

Yes, for 

plants 

located in 

moderate to 

severe 

weathering 

conditions 

Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

All Groups except 

Group 6: concrete 

(inaccessible areas): 

all (3.5.1-43) 

Cracking due to 

expansion from 

reaction with 

aggregates 

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes, if 

concrete is 

not 

constructed 

as stated 

Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 
3-388 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

All Groups: concrete: 

all (3.5.1-44) 

Cracking and 

distortion due to 

increased stress 

levels from 

settlement 

Chapter XI.S6, 

“Structures 

Monitoring” 

If a de-watering 

system is relied upon 

for control of 

settlement, then the 

licensee is to ensure 

proper functioning of 

the de-watering 

system through the 

period of extended 

operation. 

Yes, if a dewatering 

system is 

relied upon 

to control 

settlement 

Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Groups 1-3, 5-9: 

concrete: foundation; 

subfoundation 

(3.5.1-45) 

Reduction in 

foundation 

strength, 

cracking due to 

differential 

settlement, 

erosion of 

porous concrete 

subfoundation 

Chapter XI.S6, 

“Structures 

Monitoring” 

If a de-watering 

system is relied upon 

for control of 

settlement, then the 

licensee is to ensure 

proper functioning of 

the de-watering 

system through the 

period of extended 

operation. 

Yes, if a dewatering 

system is 

relied upon 

to control 

settlement 

Not applicable Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Groups 1-3, 5-9: 

concrete: foundation; 

subfoundation 

(3.5.1-46) 

Reduction of 

foundation 

strength and 

cracking due to 

differential 

settlement and 

erosion of 

porous concrete 

subfoundation 

Chapter XI.S6, 

“Structures 

Monitoring” 

If a de-watering 

system is relied upon 

for control of 

settlement, then the 

licensee is to ensure 

proper functioning of 

the de-watering 

system through the 

period of extended 

operation. 

Yes, if a dewatering 

system is 

relied upon 

to control 

settlement 

Not applicable Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Groups 1-5, 7-9: 

concrete 

(inaccessible areas): 

exterior above- and 

below-grade; 

foundation (3.5.1-47) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes, if 

leaching is 

observed in 

accessible 

areas that 

impact 

intended 

function 

Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Groups 1-5: 

concrete: all 

(3.5.1-48) 

Reduction of 

strength and 

modulus due to 

elevated 

temperature 

(>150°F general; 

>200°F local) 

A plant-specific aging 

management 

program is to be 

evaluated. 

Yes, if 

temperature 

limits are 

exceeded 

Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.2.) 
3-389 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Groups 6 - concrete 

(inaccessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-49) 

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw 

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557) 

Yes, for 

plants 

located in 

moderate to 

severe 

weathering 

conditions 

RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Groups 6: concrete 

(inaccessible areas): 

all (3.5.1-50) 

Cracking due to 

expansion from 

reaction with 

aggregates 

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes, if 

concrete is 

not 

constructed 

as stated 

RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Groups 6: concrete 

(inaccessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-51) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Further evaluation is 

required to determine 

if a plant-specific 

aging management 

program is needed. 

Yes, if 

leaching is 

observed in 

accessible 

areas that 

impact 

intended 

function 

RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Groups 7, 8 - steel 

components: tank 

liner (3.5.1-52) 

Cracking due to 

stress corrosion 

cracking; Loss of 

material due to 

pitting and 

crevice 

corrosion 

A plant-specific aging 

management 

program is to be 

evaluated. 

Yes, plant 

specific 

Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.2.2) 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-53) 

Cumulative 

fatigue damage 

due to fatigue 

(Only if CLB 

fatigue analysis 

exists) 

Yes, TLAA Yes, TLAA Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.2.2) 

All groups except 6: 

concrete (accessible 

areas): all (3.5.1-54) 

Cracking due to 

expansion from 

reaction with 

aggregates 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

Building concrete at 

locations of 

expansion and 

grouted anchors; 

grout pads for 

support base plates 

(3.5.1-55) 

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation/ 

service-induced 

cracking or other 

concrete aging 

mechanisms 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 
3-390 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Concrete: exterior 

above- and belowgrade; foundation; 

interior slab 

(3.5.1-56) 

Loss of material 

due to abrasion; 

cavitation 

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army Corp 

of Engineers dam 

inspections and 

maintenance 

programs. 

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

Constant and 

variable load spring 

hangers; guides; 

stops (3.5.1-57) 

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, fatigue 

due to vibratory 

and cyclic 

thermal loads 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Inservice 

Inspection – IWF 

(ISI-IWF) Program 

Consistent with the 

GALL Report 

Earthen watercontrol structures: 

dams; 

embankments; 

reservoirs; channels; 

canals and ponds 

(3.5.1-58) 

Loss of material; 

loss of form due 

to erosion, 

settlement, 

sedimentation, 

frost action, 

waves, currents, 

surface runoff, 

seepage 

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army Corp 

of Engineers dam 

inspections and 

maintenance 

programs. 

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

Group 6: concrete 

(accessible areas): 

all (3.5.1-59) 

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel 

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army Corp 

of Engineers dam 

inspections and 

maintenance 

programs. 

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 
3-391 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation (3.5.1-60) 

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw 

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army Corp 

of Engineers dam 

inspections and 

maintenance 

programs. 

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-61) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army Corp 

of Engineers dam 

inspections and 

maintenance 

programs. 

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

Group 6: wooden 

piles; sheeting 

(3.5.1-62) 

Loss of material; 

change in 

material 

properties due to 

weathering, 

chemical 

degradation, and 

insect infestation 

repeated wetting 

and drying, 

fungal decay 

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army Corp 

of Engineers dam 

inspections and 

maintenance 

programs. 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Groups 1-3, 5, 7-9: 

concrete (accessible 

areas): exterior 

above- and belowgrade; foundation 

(3.5.1-63) 

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.3) 

Groups 1-3, 5, 7-9: 

concrete (accessible 

areas): exterior 

above- and belowgrade; foundation 

(3.5.1-64) 

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 
3-392 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

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 (3.5.1-65) 

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

Groups 1-5, 7, 9: 

concrete (accessible 

areas): interior and 

above-grade exterior 

(3.5.1-66) 

Cracking; loss of 

bond; and loss 

of material 

(spalling, 

scaling) due to 

corrosion of 

embedded steel 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

Groups 1-5, 7, 9: 

concrete: interior; 

above-grade exterior, 

Groups 1-3, 5, 7-9 - 

concrete 

(inaccessible areas): 

below-grade exterior; 

foundation, Group 6: 

concrete 

(inaccessible areas): 

all (3.5.1-67) 

Increase in 

porosity and 

permeability; 

cracking; loss of 

material 

(spalling, 

scaling) due to 

aggressive 

chemical attack 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

High-strength 

structural bolting 

(3.5.1-68) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

High-strength 

structural bolting 

(3.5.1-69) 

Cracking due to 

stress corrosion 

cracking 

Chapter XI.S6, 

“Structures 

Monitoring” 

Note: ASTM A 325, F 

1852, and ASTM A 

490 bolts used in civil 

structures have not 

shown to be prone to 

SCC. SCC potential 

need not be 

evaluated for these 

bolts. 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Masonry walls: all 

(3.5.1-70) 

Cracking due to 

restraint 

shrinkage, 

creep, and 

aggressive 

environment 

Chapter XI.S5, 

“Masonry Walls” 

No Masonry Wall 

Program 

Consistent with the 

GALL Report 

Masonry walls: all 

(3.5.1-71) 

Loss of material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw 

Chapter XI.S5, 

“Masonry Walls” 

No Masonry Wall 

Program 

Consistent with the 

GALL Report 
3-393 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Seals; gasket; 

moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-72) 

Loss of sealing 

due to 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants) 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring and 

Periodic 

Surveillance and 

Preventive 

Maintenance 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.2) 

Service Level I 

coatings (3.5.1-73) 

Loss of coating 

integrity due to 

blistering, 

cracking, flaking, 

peeling, 

delamination, 

rusting, or 

physical damage 

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance” 

No Protective Coating 

Monitoring and 

Maintenance 

Program 

Consistent with the 

GALL Report 

Sliding support 

bearings; sliding 

support surfaces 

(3.5.1-74) 

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

debris, overload, 

wear 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Sliding surfaces 

(3.5.1-75) 

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

debris, overload, 

wear 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Sliding surfaces: 

radial beam seats in 

BWR drywell 

(3.5.1-76) 

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, wear 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Steel components: 

all structural steel 

(3.5.1-77) 

Loss of material 

due to corrosion 

Chapter XI.S6, 

“Structures 

Monitoring” 

If protective coatings 

are relied upon to 

manage the effects 

of aging, the 

structures monitoring 

program is to include 

provisions to address 

protective coating 

monitoring and 

maintenance. 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 
3-394 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Steel components: 

fuel pool liner 

(3.5.1-78) 

Cracking due to 

stress corrosion 

cracking; Loss of 

material due to 

pitting and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Monitoring of the 

spent fuel pool water 

level in accordance 

with technical 

specifications and 

leakage from the 

leak chase channels.

No, unless 

leakages 

have been 

detected 

through the 

SFP liner 

that cannot 

be 

accounted 

for from the 

leak chase 

channels 

Water Chemistry 

Control – BWR 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.4) 

Steel components: 

piles (3.5.1-79) 

Loss of material 

due to corrosion 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Structural bolting 

(3.5.1-80) 

Loss of material 

due to general, 

pitting and 

crevice 

corrosion 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

Structural bolting 

(3.5.1-81) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Inservice 

Inspection – IWF 

Program 

Consistent with the 

GALL Report 

Structural bolting 

(3.5.1-82) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

Structural bolting 

(3.5.1-83) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army Corp 

of Engineers dam 

inspections and 

maintenance 

programs 

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.5) 

Structural bolting 

(3.5.1-84) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

and Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Structural bolting 

(3.5.1-85) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Not applicable Not applicable to 

Fermi 2 (see SER 

Section 3.5.2.1.1) 

Structural bolting 

(3.5.1-86) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Inservice 

Inspection – IWF 

Program 

Consistent with the 

GALL Report 
3-395 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Structural bolting 

(3.5.1-87) 

Loss of preload 

due to selfloosening 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Inservice 

Inspection – IWF 

Program 

Consistent with the 

GALL Report 

Structural bolting 

(3.5.1-88) 

Loss of preload 

due to selfloosening 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-89) 

Loss of material 

due to boric acid 

corrosion 

Chapter XI.M10, 

“Boric Acid 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.5.2.1.1) 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-90) 

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion 

Chapter XI.M2, 

“Water Chemistry,” 

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Water Chemistry 

Control – BWR 

and Inservice 

Inspection - IWF 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.6) 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-91) 

Loss of material 

due to general 

and pitting 

corrosion 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Inservice 

Inspection – IWF 

Program 

Consistent with the 

GALL Report 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-92) 

Loss of material 

due to general 

and pitting 

corrosion 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring and 

Fire Water System 

programs 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.7) 

Support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

(3.5.1-93) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.S6, 

“Structures 

Monitoring” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.8) 

Vibration isolation 

elements (3.5.1-94) 

Reduction or 

loss of isolation 

function due to 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory loading 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF” 

No Structures 

Monitoring 

Program 

Consistent with the 

GALL Report 

(see SER 

Section 3.5.2.1.9) 

Aluminum, 

galvanized steel and 

stainless steel 

support members; 

welds; bolted 

connections; support 

anchorage to 

building structure 

exposed to air – 

indoor, uncontrolled 

(3.5.1-95) 

None None NA - No 

AEM or 

AMP 

None Consistent with the 

GALL Report 
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3.5.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.5.2.1, as amended by letter dated May 9, 2016, identifies the materials, 

environments, AERMs, and the following programs that manage aging effects for the structures 

and component supports components: 

 Containment Inservice Inspection – IWE 

 Containment Leak Rate 

 External Surface Monitoring 

 Fire Protection 

 Fire Water System 

 Inservice Inspection – IWF 

 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

 Masonry Wall 

 Periodic Surveillance and Preventive Maintenance 

 Protective Coating Monitoring and Maintenance 

 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

 Structures Monitoring 

 Water Chemistry Control – BWR 

LRA Tables 3.5.2-1 through 3.5.2-4 summarize AMRs for the structures and component 

supports components and indicate AMRs claimed to be consistent with the GALL Report. 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components of these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR item. The notes describe how the information in 

the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions. 

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 
3-397 

Note C indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as the component under review. The staff audited 

these AMR items to confirm consistency with the GALL Report. The staff also determined 

whether the AMR item of the different component applied to the component under review and 

whether the AMR was valid for the site-specific conditions. 

Note D indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions. 

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect; however, a different AMP is credited. The staff audited these 

AMR items to confirm consistency with the GALL Report and determined whether the identified 

AMP would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, the staff did confirm that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows. 

 AMR Results Identified as Not Applicable or Not Used 

For LRA Table 3.5.1, items 3.5.1-25, and 3.5.1-89, the applicant claimed that the corresponding 

AMR items in the GALL Report are not applicable because the associated items are only 

applicable to PWRs. The staff reviewed the SRP-LR; confirmed these items only apply to 

PWRs; and finds that these items are not applicable to Fermi 2, which is a BWR. 

For LRA Table 3.5.1, items 3.5.1-15, 3.5.1-16, 3.5.1-17, 3.5.1-18, 3.5.1-19, 3.5.1-20, 3.5.1-21, 

3.5.1-22, 3.5.1-23, 3.5.1-24, 3.5.1-27, 3.5.1-32, 3.5.1-37, 3.5.1-38, 3.5.1-40, 3.5.1-62, 3.5.1-74, 

3.5.1-84, and 3.5.1-85, the applicant claimed that the corresponding items in the GALL Report 

are not applicable or not used because the component, material, and environment combination 

described in the SRP-LR does not exist for in-scope SCs at Fermi 2 or because the component, 

material, and environment combination is addressed by another Table 1 line item. The staff 

reviewed the LRA and UFSAR and confirmed that the applicant’s LRA does not have any AMR 

results applicable for these items or that the aging effects addressed by other Table 1 AMR line 

items are appropriate. 

For LRA Table 3.5.1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable or not used. However, the staff had to review 
3-398 

sources beyond the LRA and UFSAR or to issue one or more RAIs, or both, to verify the 

applicant’s claim. 

LRA Table 3.5.1, item 3.5.1-36, addresses the steel drywell head and downcomers exposed to 

an air-indoor uncontrolled environment. The GALL Report recommends GALL Report 

AMP XI.S1, “ASME Section XI, Subsection IWE,” to manage fretting or lockup due to 

mechanical wear for this component group. The applicant stated that this item is not applicable 

because “the drywell head is a stationary or fixed component and the downcomers are 

stationary, well-braced components and the spatial distance between connecting components 

makes it unlikely for fretting and lock up to occur.” However, the staff noted that UFSAR 

Section 3.8.2.1.3.6, “Access for Refueling Operations,” states that the drywell head is removed 

during refueling operations and is held in place by bolts and sealed with a double seal, which 

makes the drywell head a nonstationary or nonfixed component. Therefore, by letter dated 

December 23, 2014, the staff issued RAI 3.5.1.36-1, requesting that the applicant clarify 

whether the drywell head is fixed or removable and, if it is removable, state how fretting of 

lockup due to mechanical wear will be adequately managed during the period of extended 

operation. 

In its response dated January 26, 2015, the applicant stated that the drywell head is a fixed 

component during plant operation and is removed during refueling operation cycles, as 

described in the Fermi 2 UFSAR Section 3.8.2.1.3.6. The applicant also stated that the 

movement is limited to the drywell head and the mating surfaces on the drywell shell during the 

drywell head removal and reinstallation cycle. However, this cycle does not involve oscillatory 

movements that could cause fretting and lockup, and although wear can occur in parts that 

experience intermittent relative motion or frequent manipulation, the removal and reinstallation 

cycle is infrequent. The applicant further stated that drywell head bolts are torqued during 

installation and verified with plant procedure using specific torque values that preclude 

movement between the drywell head and the drywell shell. Thus, fretting and lockup is not an 

AERM for the drywell head surfaces. 

The staff finds the applicant’s response acceptable because the drywell head is in a fixed 

condition during plant operation with the head bolts torqued to preclude movement between 

surfaces and because the infrequent (typically once per refueling cycle) manipulation of the 

drywell head only during the removal and reinstallation cycle for refueling does not provide the 

aging mechanisms necessary for the aging effects of fretting and lockup to occur. The staff also 

noted that the applicant’s LRA credits the Containment Inservice Inspection - IWE and the 

Containment Leak Rate programs to detect the aging effects of loss of material in steel 

elements of the drywell shell and drywell head. The staff’s concern described in RAI 3.5.1.36-1 

is resolved. Therefore, the staff finds the applicant’s claim for LRA Table 3.5.1, item 3.5.1-36, 

acceptable. 

LRA Table 3.5.1, item 3.5.1-68, addresses low-alloy steel (actual measured yield strength equal 

or greater than 150 ksi), high-strength structural bolting exposed to an air-indoor uncontrolled 

environment. The GALL Report recommends GALL Report AMP XI.S3, “ASME Section XI, 

Subsection IWF,” to manage cracking due to SCC for this component group. The applicant 

stated that this item is not applicable because there are no high-strength bolts subject to a 

sustained high tensile stress in a corrosive environment and “high strength structural bolts in 

civil structures have not shown to be prone to SCC.” In its review of the applicant’s Inservice 

Inspection – IWF Program, the staff issued RAI B.1.22-1, by letter dated December 19, 2014, 

requesting, in part, that the applicant provide additional information regarding the environment 

to which high-strength bolts are exposed to evaluate the applicant’s claim that SCC in 
3-399 

high-strength bolts is not an AERM at Fermi 2. The staff’s review of the applicant’s response to 

RAI B.1.22-1 is documented in SER Section 3.0.3.2.12. In its response to RAI B.1.22-1, dated 

February 19, 2015, the applicant stated that high-strength bolts are located in the lower area of 

drywell bioshield annulus. The applicant clarified that in this location the high-strength bolts are 

exposed to a dry and relatively cool (low-temperature) environment. The applicant also stated 

that the lubricant used for the bolts does not contain MoS2. 

The staff needed additional clarification on the applicant’s response regarding whether the 

applicant inspects the drywell bioshield annulus area such that it can verify that the environment 

is kept dry. Therefore, during a telephone conference call held on March 6, 2015, the staff 

asked the applicant if it inspects the drywell bioshield annulus area. The applicant stated that 

the drywell bioshield annulus area is inspected every RFO. The staff notes that SCC cracking 

has been commonly found in high-strength bolts that are subject to an undesirable combination 

of high tensile stress, wet environment, and the presence of a corrosive agent (e.g., MoS2). The 

staff noted that the drywell bioshield annulus area is a dry environment that is inspected by the 

applicant every RFO and that 100 percent of the support bolts are visually inspected (VT-3) 

every 10 years as required per Table IWF-2500-1 for Class 1 supports (supports other than 

piping supports). The staff evaluated the applicant’s RAI response and finds it acceptable 

because high-strength bolts at Fermi 2 are not subject to conditions (e.g., wet environment and 

corrosive agents) conducive to SCC. 

LRA Table 3.5.1, item 3.5.1-69, addresses high-strength structural bolting exposed to air-indoor 

uncontrolled or air-outdoor environment. The GALL Report recommends GALL Report 

AMP XI.S6 to manage cracking due to SCC for this component group. The applicant stated that 

this item is not applicable because “Fermi 2 does not have high strength bolts that are subject to 

sustained high tensile stress in a corrosive environment.” The applicant also stated that “high 

strength bolts used in civil structures have not shown to be prone to SCC.” The applicant’s 

response to RAI B.1.42-4, dated December 26, 2014, further stated that high-strength structural 

bolts greater than 1 inch in diameter (other than ASTM A325, F1852, and A490 bolts) are not 

used in Fermi 2 structures with the exception of high-strength bolts used in the drywell stabilizer 

assembly. These high-strength bolts are type ASTM A325 bolting, which is not shown to be 

prone to SCC according to the recommendation in the GALL Report. The staff evaluated the 

applicant’s claim and finds it acceptable because the applicant does not have high-strength 

structural bolting with the necessary material and environment combination for this aging effect 

to occur. The staff’s review and evaluation of the applicant’s response to RAI B.1.42-4 is 

documented in SER Section 3.0.3.2.22, “Structures Monitoring Program.” 

LRA Table 3.5.1, items 3.5.1-75 and 3.5.1-76, address sliding surfaces of Lubrite® exposed to 

an air-indoor uncontrolled or air-outdoor environment. For item 3.5.1-75, the GALL Report 

recommends GALL Report AMP XI.S3 to manage loss of mechanical function due to corrosion, 

distortion, dirt, debris, overload, and wear for this component group. For item 3.5.1-76, the 

GALL Report recommends GALL Report AMP XI.S6 to manage loss of mechanical function due 

to corrosion, distortion, dirt, overload, and wear for this component group. The applicant stated 

that these items are not applicable because “[l]ubrite plates are not subject to aging 

management because the listed aging mechanisms are event driven and typically can be 

avoided through proper design. Loss of material which could cause loss of mechanical function 

is addressed under Item 3.5.1-77 related to component support members.” 

The staff notes that the applicant plans to manage aging effects on Lubrite® sliding surfaces 

with item 3.5.1-77 (GALL Report, item III.A2.TP-302) through the Structures Monitoring Program 

for loss of material due to corrosion, which the applicant states could cause loss of mechanical 
3-400 

function. The staff also notes that the applicant’s program, with enhancements, will be 

consistent with GALL Report AMP XI.S6. The staff’s review of the applicant’s Structures 

Monitoring Program is documented in SER Section 3.0.3.2.22. 

The staff evaluated the applicant’s claim and finds it acceptable because the GALL Report 

states that Lubrite® is “characterized as maintenance-free” but emphasizes its proper installation 

to reduce the likelihood of functional problems during challenging loading conditions, and that it 

may require examinations. The GALL Report also states that the Structures Monitoring 

Program manages sliding surfaces for loss of material due to wear or corrosion and aging 

effects due to debris or dirt. According to Lubrite® Technologies, Lubrite® sliding surfaces, by 

design, prevent foreign matter contamination of the surfaces, and the U.S. Army Corps of 

Engineers (USACE) confirms that “Lubrite products have been used with uniform success” in 

challenging environments. The staff’s search of the applicant’s operating experience database 

during the audit yielded no results for Lubrite®, indicating that operating experience involving 

Lubrite® that warranted corrective action has not been identified. Thus, the staff determines that 

loss of mechanical function due to distortion, dirt, debris, overload, or wear would be an 

event-driven phenomenon and that visual inspections required by the Structures Monitoring 

Program would detect the aging effect of loss of material, which would serve as a leading 

indicator for identifying loss of mechanical function of Lubrite® sliding surfaces. 

LRA Table 3.5.1, item 3.5.1-79, addresses steel components from piles exposed to groundwater 

or soil environments. The GALL Report recommends GALL Report AMP XI.S6, “Structures 

Monitoring,” to manage loss of material due to corrosion for this component group. In its 

response to RAI B.1.39-2, dated December 26, 2014, the applicant stated that this item is not 

applicable because steel piles at Fermi 2 do not perform a license renewal intended function. 

The staff evaluated the applicant’s response and finds it acceptable because a staff review of 

the referenced Figure 2.4-22, “Shore Barrier Design,” and UFSAR Subsections 2.4.5, “Probable 

Maximum Surge and Seiche Flooding,” and 3.4.4, “Flood Protection,” verified that the steel 

sheet piles are not credited as part of the shore barrier function (i.e., required for stability) and 

confirms that the steel sheet piles were installed as a QA Level III component. The staff’s 

evaluation of the applicant’s response to RAI B.1.39-2 is provided in SER Section 3.0.3.2.20. 

 Loss of Sealing Due to Deterioration of Seals, Gaskets, and Moisture Barriers 

(Caulking, Flashing, and Other Sealants) 

LRA Table 3.5.1, items 3.5.1-26 and 3.5.1-72, address the spent fuel storage pool gate rubber 

(elastomer) gasket/seal exposed to an air-indoor uncontrolled environment and a fluid 

environment, respectively, which will be managed for loss of sealing due to deterioration, wear, 

damage, erosion, tear, surface cracks, or other defects. For the AMR items that cite generic 

note E, the LRA credits the existing plant-specific PSPM Program to manage the loss of sealing 

aging effect for the spent fuel storage pool gate rubber gasket/seal. The GALL Report 

recommends GALL Report AMP XI.S1 “ASME Section XI, Subsection IWE” and/or AMP XI.S6 

“Structures Monitoring” to ensure that this aging effect is adequately managed. GALL Report 

AMP XI.S1 recommends using general visual inspections by qualified personnel every 3 to 

4 years to examine moisture barriers for wear, damage, erosion, tear, or other defects to 

manage the loss of sealing aging effect. GALL Report AMP XI.S6 recommends monitoring 

elastomeric structural sealants for cracking, loss of material, and hardening using visual 

inspections supplemented by feel to detect hardening on a frequency not to exceed 5 years to 

manage the loss of sealing aging effect. 
3-401 

The staff’s evaluation of the applicant’s existing plant-specific PSPM Program, as described in 

LRA Section B.1.35, is documented in SER Section 3.0.3.3.1. The staff noted that the 

PSPM Program proposes to manage the effects of aging (i.e., loss of sealing) for the rubber 

gasket/seal for spent fuel storage pool gates in the reactor building through the use of visual 

inspections and manual flexing performed at least once every 5 years. Based on its review of 

components associated with LRA Table 3.5.2-1, items 3.5.1-26 and 3.5.1-72, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage the effects of 

aging using the PSPM Program acceptable because the program will effectively manage loss of 

sealing for the rubber gasket/seal of the spent fuel storage pool gates located in the reactor 

building by visually inspecting the surface condition and by having qualified personnel manually 

flex (to assess hardening) these elastomeric components at intervals not exceeding 5 years, 

which is consistent with the recommendations in the GALL Report. 

The staff concludes that for LRA items 3.5.1-26 and 3.5.1-72, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Increase in Porosity and Permeability and Loss of Strength Due to Leaching of 

Calcium Hydroxide and Carbonation 

LRA Table 3.5.1, item 3.5.1-63, addresses above- and below-grade accessible areas of 

concrete and foundation for Groups 1–3, 5, and 7–9 structures exposed to flowing water. The 

GALL Report recommends GALL Report AMP XI.S6 to manage an increase in porosity and 

permeability and loss of strength due to leaching of calcium hydroxide and carbonation for this 

component group. The applicant originally stated that this item is not applicable because 

Fermi 2 Category 1 structures are founded on bedrock; structures do not use porous concrete 

subfoundations, do not rely on a dewatering system to control settlement, and do not have 

water flowing underneath the foundation. However, by letter dated January 26, 2015, in 

response to RAI 3.5.2.2.2.1-3, the applicant revised LRA Sections A.1.42 and B.1.42 (LRA 

Commitment Nos. 34m and 34n) to manage the potential aging effects of increase in porosity 

and permeability and loss of strength due to leaching of calcium hydroxide and carbonation for 

inaccessible areas based on testing and evaluation of observed conditions of in-leakage (water 

and mineral deposits) in accessible areas, which suggests that LRA Table 3.5.1, item 3.5.1-63, 

might be applicable. Therefore, by letter dated April 22, 2015, the staff issued followup 

RAI 3.5.2.2.2.1-3a, requesting that the applicant clarify and/or reconcile the inconsistencies 

between LRA Commitments No. 34, items m and n, and the nonapplicability of LRA Table 3.5.1, 

items 3.5.1-47 and 3.5.1-63, and provide the Table 2 line items for the structures and 

components associated with this aging effect. Alternatively, the staff requested that the 

applicant provide the technical basis to justify why LRA Table 3.5.1, items 3.5.1-63 and 

3.5.1-47, continue to remain not applicable. The staff’s evaluation of the applicant’s response to 

followup RAI 3.5.2.2.2.1-3a and applicability of LRA Table 3.5.1, items 3.5.1-47 and 3.5.1-63, is 

provided in SER Section 3.5.2.2.2. 

 Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and 

Crevice Corrosion 

LRA Table 3.5.1, item 3.5.1-78, addresses steel components – spent fuel pool liner exposed to 

a fluid environment, which will be managed for cracking due to SCC and loss of material due to 

pitting and crevice corrosion. For the AMR items that cite generic note E, the LRA credits the 

Water Chemistry Control – BWR Program and “monitoring of the spent fuel pool water level in 
3-402 

accordance with technical specifications and leakage from the leak chase channels” to manage 

the aging effects for these components. The GALL Report recommends AMP XI.M2, “Water 

Chemistry,” and monitoring of the spent fuel pool water level in accordance with technical 

specifications and leakage from the leak chase channels. 

During its review of components associated with item 3.5.1-78, which cites generic note E, the 

staff noted that the applicant applied this item to components other than the spent fuel pool 

liner. These fuel pool components (e.g., reactor cavity liner, refueling bellows, and skimmer 

surge tank) are only flooded during refueling, and leakage may not reveal cracking or corrosion. 

Therefore, monitoring of the spent fuel pool water level and leak chase channel, although 

recommended by the GALL Report, may not be appropriate to verify the effectiveness of the 

water chemistry program in these components. Additionally, it was unclear to the staff why the 

applicant does not manage the aging effect of cracking for these items. By letter dated 

December 17, 2014, the staff issued RAI 3.5.2.78-1 requesting that the applicant clarify how the 

effectiveness of the Water Chemistry Control – BWR Program will be verified for these 

Table 3.5.2-1 components that reference LRA Table 3.5.1, item 3.5.1-78, generic note E, and 

state the basis for why cracking was not being managed for these components. 

In its response dated January 15, 2015, the applicant stated that the Water Chemistry Control – 

BWR Program references the One-Time Inspection Program to verify the effectiveness of water 

chemistry control for managing the applicable aging affects. The letter also states that the 

stainless steel components, which reference item 3.5.1-78, are exposed to treated water that is 

less than 140 F, which is not an environment conducive to SCC; therefore, cracking does not 

need to be managed in this case. 

The staff reviewed the applicant’s statement that the stainless steel components, which 

reference item 3.5.1-78, are exposed to water that is less than 140 °F and, therefore, are not 

susceptible to cracking. However, a review of the UFSAR found that, under normal operating 

conditions, the spent fuel pool is maintained at a temperature less than or equal to 125 °F and 

150 °F during RFOs. For stainless steel components exposed to treated water greater than 

140 °F, the GALL Report recommends GALL Report AMPs XI.M2 and XI.M32, “One-Time 

Inspection.” 

The staff finds the applicant’s response acceptable because the LRA states that the Water 

Chemistry Control – BWR Program uses the One-Time Inspection Program as verification of 

effectiveness of the water chemistry controls to mitigate cracking, which is consistent with the 

GALL Report for stainless steel components exposed to treated water greater than 140 °F 

(e.g., item 3.4.1-11). The staff’s concern described in RAI 3.5.2.78-1 is resolved. 

The staff concludes that, for LRA Table 3.5.1, item 3.5.1-78, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Loss of Material Due to General, Pitting, and Crevice Corrosion 

LRA Table 3.5.1, item 3.5.1-83, addresses structural bolting exposed to a fluid environment and 

air-indoor uncontrolled or air-outdoor environments, which will be managed for loss of material 

due to general, pitting, and crevice corrosion. The GALL Report recommends GALL Report 

AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with 
3-403 

Nuclear Power Plants” or the Federal Energy Regulatory Commission (FERC)/USACE dam 

inspections and maintenance programs to ensure that this aging effect is adequately managed. 

During its review of components associated with item 3.5.1-83 for which the applicant cited 

generic note A, the staff noted that the LRA credits the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program to manage the aging effect for 

stainless steel anchor bolts exposed to fluid environment. However, sufficient information had 

not been provided to adequately determine whether stainless steel anchor bolts are exposed to 

an environment conducive to SCC because the LRA environment description for “Exposed to 

Fluid Environment” corresponds to a broad list of environment types that includes environments 

with treated water and/or treated water with temperature above 140 °F, which makes a stainless 

steel material susceptible to SCC. Therefore, by letter dated November 25, 2014, the staff 

issued RAI 3.5.1.83-1, requesting that the applicant clarify the fluid environment to which these 

anchor bolts are exposed, including temperature and water chemistry, and state how the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program will adequately manage this aging effect if the anchor bolts are exposed to an 

environment conducive to SCC. 

In its response dated December 26, 2014, the applicant stated that the fluid environment in 

which the stainless steel anchor bolts are exposed is raw water from Lake Erie with 

temperatures less than 140 °F and water chemistry similar to groundwater. The applicant 

provided some key water chemistry parameters of Lake Erie water obtained from a recent water 

quality study performed at Fermi 2 between 2008 and 2009, as described in Table 2, “Summary 

of Surface Water Quality Data Collected at Sampling Location LE1-W” (ADAMS Accession 

No. ML093380411) and further stated that these anchor bolts are not exposed to an 

environment with a significant presence of contaminants, specifically chlorides, and that normal 

temperature limits of the fluid environment to which these anchor bolts are exposed is less than 

the SCC threshold of 140 °F. The applicant also stated that, based on these considerations, the 

stainless steel anchor bolts listed in LRA Table 3.5.2-4, exposed to a fluid environment, are not 

in an environment conductive to SCC and that cracking due to SCC is not an AERM for these 

stainless steel anchor bolts. 

The staff finds the applicant’s response acceptable because it clarified that the fluid environment 

in which the anchor bolts are exposed is not a harsh environment. Rather, normal temperature 

limits are less than the threshold of 140 °F for SCC, and no stagnant, oxygenated, or borated 

water is present that would allow SCC to occur. Because the anchor bolts are not exposed to 

environment conductive to SCC, aging effects from anchor bolts exposed to an environment 

conductive to SCC is not considered a credible aging effect required to be manage, as 

recommended by the GALL Report. The staff's concern described in RAI 3.5.1.83-1 is resolved. 

The staff concludes that for LRA Table 3.5.1, item 3.5.1-83, the applicant has demonstrated that 

the effects of aging for these components will be adequately managed and that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Loss of Material Due to General (Steel Only), Pitting, and Crevice Corrosion 

LRA Table 3.5.1, item 3.5.1-90 addresses steel and stainless steel support members, welds, 

bolted connections, and support anchorage to building structure components exposed to a 

treated water environment less than 60 °C (140 °F), which will be managed for loss of material 

due to general (steel only), pitting, and crevice corrosion. The LRA states that item 3.5.1-90 is 
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consistent with the GALL Report. The SRP-LR states that item 3.5.1-90 corresponds to GALL 

Report, item III.B1.1.TP-10. The GALL Report recommends GALL Report AMPs XI.M2, “Water 

Chemistry,” and XI.S3, “ASME Section XI, Subsection IWF,” to ensure that this aging effect is 

adequately managed. 

LRA Tables 3.5.2-1, “Reactor/Auxiliary Building and Primary Containment Summary of Aging 

Management Evaluation,” and 3.5.2-4, “Bulk Commodities Summary of Aging Management 

Evaluation,” assign item 3.5.1-90 for the AMRs of carbon vent header support and stainless 

steel anchorage/embedments components exposed to a fluid environment, which will be 

managed for loss of material by the Water Chemistry Control – BWR and Inservice Inspection – 

IWF programs. For the carbon vent header support, the LRA cites note A, indicating that the 

AMR item combination of component, material, environment, aging effect, and assigned AMPs 

are consistent with those recommended in the GALL Report. For the stainless steel 

anchorage/embedments components, the LRA cites note C, indicating that the AMR item 

component is different but consistent with the material, environment, aging effect, and AMP 

recommended in the GALL Report. 

During its review of the AMR items, the staff confirmed the applicant’s claims of consistency 

with the GALL Report with respect to material, environment, aging effect, and recommended 

AMPs; however, additional information was needed to confirm that the environment description 

is consistent with the GALL Report. The staff noted that LRA Table 3.0-2, “Service 

Environments for Structural Aging Management Reviews,” states, in part, that the “exposed to 

fluid environment” corresponds to the GALL Report environment of treated water greater than 

140 °F. However, GALL Report, AMR item III.B1.1.TP-10, addresses steel and stainless steel 

components exposed to an environment of treated water less than 140 °F. It was not clear how 

the LRA description of an “exposed to fluid environment” was consistent with an environment of 

treated water less than 140 °F. In addition, for stainless steel components exposed to treated 

water greater than 140 °F, the GALL Report states that cracking is an aging effect that should 

be subject to age management. It was not clear whether stainless steel anchorage/embedment 

components, if exposed to treated water greater than 140 °F, will be managed for cracking. 

Therefore, by letter dated January 14, 2015, the staff issued RAI 3.5.1.90-1, requesting that the 

applicant (1) clarify how its characterization of “exposed to fluid environment,” defined in the 

LRA, is consistent with an environment of treated water less than 140 °F in GALL 

Report, AMR item III.B1.1.TP-10, and (2) state how the aging effects of cracking for 

anchorage/embedments stainless steel components exposed to treated water greater than 

140 °F will be adequately managed during the period of extended operation. 

In its response dated February 12, 2015, the applicant stated that the “exposed to fluid 

environment” in LRA Table 3.0-2 encompass several raw and treated water environments, 

including both treated water greater than 140 °F and treated water less than 140 °F. The 

applicant clarified that the components in LRA Tables 3.5.2-1 and 3.5.2-4 that are listed as 

“exposed to fluid environment” and consistent with GALL Report, AMR item III.B1.1.TP-10, are 

in an environment of treated water less than 140 °F. The applicant also stated that the 

anchorage/embedments stainless steel components do not need to be age managed for SCC 

because the treated water in a less than 140 °F environment is not conducive to this aging 

effect. The staff finds the applicant’s response acceptable because it clarified that the 

components are in an environment of treated water less than 140 °F, which makes the AMR of 

these components consistent with GALL Report, AMR item III.B1.1.TP-10 and, therefore, not 

subject to the aging effect of cracking due to the environment. The staff’s concerns described in 

RAI 3.5.1.90-1 are resolved. 
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The staff concludes that, for LRA Table 3.5.1, item 3.5.1-90, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

 Loss of Material Due to General and Pitting Corrosion 

LRA Table 3.5.1, item 3.5.1-92 addresses steel support members; welds; bolted connections; 

support anchorage to building structure exposed to an air-indoor uncontrolled or air-outdoor 

environment, which will be managed for loss of material due to general and pitting corrosion. 

For the AMR item that cites generic note E, the LRA credits the Fire Water System Program to 

manage the aging effect for carbon steel fire hose reels. The GALL Report recommends GALL 

Report AMP XI.S6, “Structures Monitoring,” to ensure that this aging effect is adequately 

managed. GALL Report AMP XI.S6 recommends using periodic visual inspections by qualified 

personnel, at a frequency not to exceed 5 years, to monitor steel components for loss of 

material to manage the effects of aging. 

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.2.10. The staff noted that the Fire Water System Program, as revised by letter 

dated July 30, 2014, proposes to manage the effects of aging for fire suppression system 

components through the use of periodic visual inspections. The LRA states that the Fire Water 

System Program includes visual inspection techniques capable of detecting loss of material due 

to corrosion and that the acceptance criteria include no unacceptable signs of degradation 

observed during visual inspections. Based on its review of components associated with LRA 

Table 3.5.1, item 3.5.1-92, for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage the effects of aging using the Fire Water System Program 

acceptable because the carbon steel fire hose reels will be subject to periodic visual inspections 

to detect loss of material at a frequency not to exceed 5 years, which is consistent with the 

recommendations in GALL Report AMP XI.S6. 

The staff concludes that, for LRA Table 3.5.1, item 3.5.1-92, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.5.1, item 3.5.1-93, addresses support members, welds, bolted connections, and 

support anchorage for building structures exposed to an air-outdoor environment, which will be 

managed for loss of material due to pitting and crevice corrosion. For the AMR item that cites 

generic note E, the LRA credits the Inservice Inspection – IWF Program to manage the aging 

effect for stainless steel structural bolting. The GALL Report recommends GALL Report 

AMP XI.S6 “Structures Monitoring” to ensure that this aging effect is adequately managed. 

GALL Report AMP XI.S6 recommends using periodic visual inspections to manage the effects 

of aging. 

The staff’s evaluation of the applicant’s Inservice Inspection – IWF Program is documented in 

SER Section 3.0.3.2.12. The staff noted that the Inservice Inspection – IWF Program proposes 

to manage the effects of aging for component supports associated with ASME Code Class 1, 2, 

3 and MC piping through the use of periodic visual examination. Because the Inservice 

Inspection – IWF Program is associated with ASME Code Class 1, 2, 3 and MC piping and 
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other components as opposed to the components described in the GALL Report for this line 

item, it was not clear whether the AMR line item in LRA Table 3.5.2-4 was intended to address 

stainless steel structural bolting under ASME Code Section XI, Subsection IWF component 

supports or non-ASME Code component supports. Therefore, by letter dated 

December 23, 2014, the staff issued RAI 3.5.1.93-1 requesting that the applicant clarify whether 

the stainless steel structural bolting is associated with ASME Code Section XI, Subsection IWF 

components or non-ASME Code component supports and, if it is associated with non-ASME 

Code component supports, clarify whether the stainless steel structural bolting is within the 

scope of the Inservice Inspection – IWF Program. 

In its response dated January 26, 2015, the applicant stated that the stainless steel structural 

bolting was intended for ASME Code Section XI, Subsection IWF components because SRP-LR 

Table 3.5-1, item 91, is associated with steel components rather than stainless steel 

components. The applicant also stated that, after further review of drawings following this RAI, 

no stainless steel bolting in scope of the Inservice Inspection – IWF Program was identified to 

be exposed to an air-outdoor environment. Therefore, the applicant revised LRA Table 3.5.2-4 

to delete the line item associated with stainless steel structural bolting exposed to an air-outdoor 

environment. 

The staff evaluated the applicant’s response and finds it acceptable because the applicant 

clarified that there is no stainless steel bolting in the scope of the Inservice Inspection – IWF 

Program that is exposed to an air-outdoor environment. The applicant revised LRA 

Table 3.5.2-4 accordingly and deleted the line item with generic note E that corresponds to LRA 

Table 3.5.1, item 3.5.1-93. The staff’s concern described in RAI 3.5.1.93-1 is resolved. 

 Reduction or Loss of Isolation Function Due to Radiation Hardening, Temperature, 

Humidity, and Sustained Vibratory Loading 

LRA Table 3.5.1, item 3.5.1-94 addresses nonmetallic (e.g., rubber) vibration isolation elements 

exposed to an air-indoor uncontrolled environment, which will be managed for reduction or loss 

of isolation function due to radiation hardening, temperature, humidity, and sustained vibratory 

loading. For the AMR item that cites generic note E, the LRA credits the Structures Monitoring 

Program to manage the aging effect for elastomeric vibration isolation components. The GALL 

Report recommends GALL Report AMP XI.S3, “ASME Section XI, Subsection IWF,” to ensure 

that this aging effect is adequately managed. To manage the effects of aging, GALL Report 

AMP XI.S3 recommends that elastomeric vibration isolation components (1) be monitored for 

cracking, loss of material, and hardening and (2) be subject to visual examinations 

supplemented by feel to detect hardening if the vibration isolation function is suspect. The 

GALL Report AMP XI.S3 also states that the condition of elastomeric vibration isolation 

components is unacceptable if there is loss of material, cracking, and hardening that could 

reduce their vibration isolation function. 

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.22. The LRA states that the Structures Monitoring Program is consistent, with 

enhancement, with GALL Report AMP XI.S6, “Structures Monitoring.” The staff noted that the 

Structures Monitoring Program proposes, through its enhancements to the “parameters 

monitored or inspected” and “detection of aging effects” program elements, to manage the 

effects of aging for elastomeric vibration isolators by (1) monitoring parameters, such as 

cracking, loss of material, and hardening, and (2) supplementing visual inspections by feel to 

detect hardening when the intended function of the elastomeric material is suspect. Based on 

its review of components associated with LRA Table 3.5.1, item 3.5.1-94, for which the applicant 
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cited generic note E, the staff finds the applicant’s proposal to manage the effects of aging using 

the Structures Monitoring Program acceptable because, consistent with the recommendation in 

the GALL Report, elastomeric vibration isolation components will be inspected for cracking, loss 

of material, and hardening and will be subject to visual examinations supplemented by feel to 

detect hardening. 

The staff concludes that, for LRA Table 3.5.1, item 3.5.1-94, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

function will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended 

In LRA Section 3.5.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the structures and component supports components and provides 

information concerning how it will manage aging effects in the following three areas: 

(1) PWR and BWR containments 

 cracks and distortion due to increased stress levels from settlement, reduction of 

foundation strength, and cracking due to differential settlement and erosion of 

porous concrete subfoundations 

 reduction of strength and modulus due to elevated temperature 

 loss of material due to general, pitting, and crevice corrosion 

 loss of prestress due to relaxation, shrinkage, creep, and elevated temperature 

 cumulative fatigue damage 

 cracking due to SCC 

 loss of material (scaling, spalling) and cracking due to freeze-thaw 

 cracking due to expansion and reaction with aggregates 

 increase in porosity and permeability due to leaching of calcium hydroxide and 

carbonation 

(2) safety-related and other structures and component supports 

 aging management of inaccessible areas 

 reduction of strength and modulus of concrete structures due to elevated 

temperature 

 aging management of inaccessible areas for Group 6 structures 

 cracking due to SCC and loss of material due to pitting and crevice corrosion 

 cumulative fatigue damage due to fatigue 

(3) QA for aging management of nonsafety-related components 

(4) ongoing review of operating experience 
3-408 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.5.2.2. The staff’s review of the applicant’s 

further evaluation follows. 

 PWR and BWR Containments 

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1, which 

address several areas listed below. 

Cracking and Distortion Due to Increased Stress Levels from Settlement, Reduction of 

Foundation Strength, and Cracking Due to Differential Settlement and Erosion of Porous 

Concrete Subfoundations. LRA Section 3.5.2.2.1.1, associated with LRA Table 3.5.1, 

item 3.5.1-1, addresses cracking and distortion due to increased stress levels from settlement in 

concrete dome, wall, basemat, ring girders, and buttresses exposed to soil. LRA 

Section 3.5.2.2.1.1 is also associated with LRA Table 3.5.1, item 3.5.1-2, which addresses 

reduction of foundation strength and cracking due to differential settlement and erosion of 

porous concrete subfoundation in concrete foundation and subfoundation exposed to flowing 

water. The criteria in SRP-LR Section 3.5.2.2.1.1 state that, for PWR and BWR containments, 

the GALL Report recommends further evaluation for aging management of (1) cracking and 

distortion due to settlement and (2) reduction of foundation strength and cracking if a dewatering 

system is used to control settlement. The SRP-LR also states that, when a dewatering system 

to control settlement is in place, its functionality should be monitored through ASME Code 

Section XI, Subsection IWL, or the Structures Monitoring Program. 

The applicant stated that these items are not applicable because the Fermi 2 containment base 

foundation consists of a concrete bed founded on bedrock with no porous concrete 

subfoundation and because the site “does not rely on a de-watering system for control of 

settlement.” The staff reviewed the Fermi 2 UFSAR and confirmed that there is no dewatering 

system credited for settlement control at the site. The staff evaluated the applicant’s claim and 

finds it acceptable because (1) Fermi 2 containment concrete base foundation is founded on 

bedrock, which does not allow for settlement, (2) the subfoundation is not made of porous 

concrete, and (3) there is no dewatering system for control of settlement at the site. 

Reduction of Strength and Modulus due to Elevated Temperature. LRA Section 3.5.2.2.1.2, 

associated with LRA Table 3.5.1, item 3.5.1-3, addresses reduction of strength and modulus 

due to elevated temperature in concrete, including the dome, wall, basemat, ring girders, 

buttresses, containment, and/or fill-in annulus exposed to elevated temperature. The criteria in 

SRP-LR Section 3.5.2.2.1.2 state that further evaluation of a plant-specific AMP is 

recommended if any portion of the concrete containment components exceeds the specified 

temperature limits of more than 150 °F in a general area and more than 200 °F in local areas. 

The SRP-LR also states that implementation of 10 CFR 50.55a and ASME Code Section XI, 

Subsection IWL, would not be able to identify this aging effect; however, higher temperatures 

may be allowed if tests and/or calculations are provided to evaluate the reduction in strength 

and modulus of elasticity and if these reductions are applied to the design calculations. The 

applicant stated that these aging effects and mechanisms are not applicable to the Fermi 2 

primary containment because the concrete base foundation elements are integral with the 

reactor building foundation and are not exposed to general temperatures that exceed the 

specified threshold. 
3-409 

Further, the applicant stated that the GALL Report item is not associated with the Fermi 2 BWR 

Mark I steel containment structure type. The staff reviewed UFSAR Sections 3.8.2.1.3.1 

and 9.4 and confirmed that normal operating temperatures in containment are maintained below 

the specified threshold in the GALL Report for general and local areas of concrete. Therefore, 

the steel containment base foundation concrete elements are not exposed to the environment 

required for this aging effect to occur. The staff evaluated the applicant’s claim and finds it 

acceptable because this aging effect is applicable to concrete containment structures and 

because Fermi 2 has a Mark I carbon steel containment structure type. 

Loss of Material Due to General, Pitting, and Crevice Corrosion. LRA Section 3.5.2.2.1.3, 

associated with LRA Table 3.5.1, items 3.5.1-4 through 3.5.1-7, addresses the following: 

(1) LRA Section 3.5.2.2.1.3, item 1, associated with LRA Table 3.5.1, items 3.5.1-4 

and 3.5.1-5, addresses steel elements (inaccessible areas), including drywell shell, 

drywell head, and drywell shell in sand pocket region, and steel elements (inaccessible 

areas), including the suppression chamber, respectively, exposed to an air-indoor, 

uncontrolled environment or concrete, which will be managed for loss of material due to 

general, pitting, and crevice corrosion by the Containment Inservice Inspection – IWE 

Program and the Containment Leak Rate Program. The criteria in SRP-LR 

Section 3.5.2.2.1.3, item 1, state that loss of material due to general, pitting, and crevice 

corrosion could occur in steel elements of inaccessible areas for all types of PWR and 

BWR containments. The existing program relies on ASME Code, Section XI, 

Subsection IWE, and Appendix J to 10 CFR Part 50 to manage this aging effect. The 

SRP-LR also states that the GALL Report recommends further evaluation of 

plant-specific programs to manage this aging effect if corrosion is indicated from the IWE 

examinations. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that the moisture barrier provided at the concrete-to-steel interface where the 

drywell shell becomes embedded in the concrete floor within the drywell is inspected in 

accordance with ASME Code, Section XI, Subsection IWE. The applicant also stated 

that, to prevent corrosion, the interior and exterior surfaces of the lower drywell shell are 

protected from contact with the atmosphere by complete concrete encasement, and 

because the concrete is over 8 feet thick and is placed in multiple horizontal layers, it is 

not credible for water to reach the drywell shell even if a crack is assumed. The interior 

concrete is monitored for cracks using the Structures Monitoring Program. The 

applicant further stated that the drywell sand cushion area contains drains to protect the 

exterior surface of the drywell shell at the sand cushion interface from water that might 

enter the air gap. Additionally, the applicant explained that significant corrosion of the 

drywell is not expected because the drywell shell exterior has galvanic corrosion 

protection and because inspection activities ensure that excessive moisture levels on 

the exterior of the drywell shell are identified. The applicant concluded that the 

continued monitoring of the Fermi 2 steel containment using the Containment Inservice 

Inspection – IWE Program and the Containment Leak Rate Program provides 

reasonable assurance that loss of material due to corrosion in inaccessible areas will be 

detected before loss of intended function and that a plant-specific program is not 

necessary. 

In its review of components (i.e., steel elements (inaccessible areas), including the 

drywell shell, drywell head, and drywell shell in the sand pocket region) in LRA 

Table 3.5.2-1, associated with item 3.5.1-4 and generic note C, the staff noted that the 

AMR results item listed item II.B.1.1.CP-63 as the corresponding GALL Report line item. 

However, this line item did not correspond to the GALL Report line item 
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(i.e., item II.B3.1.CP-113) referenced in SRP-LR Table 3.5.1, item 3.5.1-4. Further, the 

staff could not find an item designated item II.B.1.1.CP-63 in the GALL Report. By letter 

dated December 22, 2014, the staff issued RAI 3.5.2.2.1.3.1-1 requesting that the 

applicant identify the appropriate AMR item in the GALL Report that would apply to the 

material, environment, and aging effect being managed by the AMR item in LRA 

Table 3.5.2-1 mentioned above for inaccessible areas of the Fermi 2 steel drywell, 

including the portion of the shell embedded in concrete. 

In its response dated January 30, 2015, the applicant stated that LRA Table 3.5.1, 

item 3.5.1-4, remains the appropriate Table 1 item and identified the corresponding 

GALL Report item as item II.B3.1.CP-113, which is listed under Mark III steel 

containments. The applicant explained that GALL Report, item II.B3.1.CP-113, is 

appropriate for the drywell inaccessible areas of the Fermi 2 Mark I containment 

because, in addition to an air-indoor uncontrolled environment, it includes concrete as an 

environment, which addresses the inaccessible portion of the Fermi 2 drywell shell that 

is embedded in concrete. The applicant revised the corresponding line item in LRA 

Table 3.5.2-1 to include concrete as an environment and to reference the GALL Report, 

item II.B3.1.CP-113. 

The staff find’s the applicant’s response to RAI 3.5.2.2.1.3.1-1 appropriate because the 

GALL Report, item II.B3.1.CP-113, identified by the applicant, corresponds to the line 

item referenced in SRP-LR Table 3.5.1, item 3.5.1-4, and applies to the two 

environments (i.e., an air-indoor uncontrolled environment or concrete) in which the 

aging effect is required to be managed for inaccessible areas of the Fermi 2 steel drywell 

shell, including the portion embedded within the concrete floor. The staff’s concern 

described in RAI 3.5.2.2.1.3.1-1 is resolved. 

In its review of the applicant’s evaluation in LRA Section 3.5.2.2.1.3, item 1, related to 

LRA Table 3.5.1, items 3.5.1-4 and 3.5.1-5, intended to address steel inaccessible areas 

of the drywell and the torus, respectively, the staff noted that the applicant had not 

addressed the plant-specific operating experience related to the loss of material due to 

corrosion of the inaccessible areas of the Fermi 2 primary containment (i.e., the drywell 

and the torus). The staff requested this information to determine whether a 

plant-specific AMP is necessary to manage the aging effect. By letter dated 

December 22, 2014, the staff issued RAI 3.5.2.2.1.3.1-2, requesting that the applicant 

describe the plant-specific operating experience related to loss of material due to 

general, pitting, and crevice corrosion of the drywell shell and torus of the Fermi 2 

primary containment and address its significance to justify whether a plant-specific 

program is necessary to manage the aging effect. 

In its response to RAI 3.5.2.2.1.3.1-2 dated January 30, 2015, with regard to the torus, 

the applicant clarified that there are no inaccessible areas of the torus; therefore, LRA 

Table 3.5.1, item 3.5.1-5, is not used for the aging effect. The applicant revised LRA 

Section 3.5.2.2.1.3, item 1, and LRA Table 3.5.1, item 3.5.1-5, to reflect this information 

about the torus and that accessible areas of the torus shell are addressed in LRA 

Table 3.5.1, item 3.5.1-6. The applicant also deleted the AMR line item for steel 

elements (inaccessible): torus shell in LRA Table 3.5.2-1 that referenced LRA 

Table 3.5.1, item 3.5.1-5. With regard to the drywell, the applicant clarified that the 

interior of the drywell shell is accessible for inspections except for beneath the concrete 

floor. The applicant also stated that the operating experience to date indicates that only 

one corrosion pit (0.02 inch by 0.04 inch by 0.093 inch deep) has been detected in the 

drywell shell that was attributed to a screw and uncoated washer in contact with an 

uncoated portion of the shell. The screw and washer were removed, and the drywell 
3-411 

shell area in the pit was coated. The applicant further stated that the exterior drywell 

shell is inaccessible, except for the drywell dome, and that, to date, there is no operating 

experience related to loss of material due to corrosion of the exterior of the drywell shell. 

Additionally, the applicant stated that no loss of material was indicated by ultrasonic 

thickness measurements taken in 2014 of the drywell shell in the sand cushion area. 

The applicant explained that an inspection on the normally inaccessible areas at the 

interface of the drywell shell and the concrete floor performed in 2010 during repair of 

the degraded moisture seal at the interface also did not identify loss of material due to 

corrosion of the drywell shell at the interface. The applicant concluded that a 

plant-specific AMP is not needed because the operating experience did not identify any 

significant loss of material due to corrosion of the drywell shell from the Containment 

Inservice Inspection Program – IWE inspections. 

The staff reviewed UFSAR Section 3.8.2 and did not find any information indicating that 

any portion of the exterior or interior of the torus shell was inaccessible. The staff finds 

the applicant’s response and “not used” (i.e., not applicable) disposition of LRA 

Table 3.5.1, item 3.5.1-5, acceptable because (a) there are no inaccessible areas in the 

Fermi 2 torus shell and (b) SRP-LR Table 3.5.1, item 5, does not make reference to a 

GALL Report item that applies directly to Mark I steel containments. With regard to the 

drywell shell, the staff notes that applicant’s operating experience and ASME Code, 

Section XI, Subsection IWE inspections, including UT measurements, suggests that 

there is no significant loss of material of the Fermi 2 drywell shell due to general, pitting, 

or crevice corrosion in accessible and inaccessible areas to necessitate a plant-specific 

program to manage the aging effect. The staff finds the applicant’s response with regard 

to the drywell shell (LRA Table 3.5.1, item 3.5.1-4) acceptable because the applicant’s 

description of the plant-specific operating experience from ASME Code, Section XI, 

Subsection IWE examinations of accessible and inaccessible areas of the drywell shell, 

which indicate no significant loss of material due to corrosion, justified that a 

plant-specific program is not necessary to manage the aging effect. The staff’s concerns 

described in RAI 3.5.2.2.1.3.1-2 are resolved. 

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWE 

Program, with enhancements, and the Containment Leak Rate Program is documented 

in SER Sections 3.0.3.2.5 and 3.0.3.1.8, respectively. The staff noted that the programs 

ensure that corrosion of the drywell shell is detected and that corrective actions are 

taken before there is a loss of material that affects its ability to perform intended 

functions by using visual examinations of all accessible drywell areas, including moisture 

barriers at the interface of the steel shell and the concrete floor inside the drywell, at 

frequencies required by ASME Code, Section XI, Subsection IWE, and applicable 

regulations and by periodic leak rate testing in accordance with Appendix J to 

10 CFR Part 50. Augmented examinations of the drywell shell, including inaccessible 

areas, are required if there are indications in accessible areas that degradation of 

inaccessible areas could also be occurring. The staff notes that the applicant’s 

Containment Inservice Inspection – IWE Program includes enhancements (Commitment 

Nos. 9a, 9f, and 9g) related to aging management of potential loss of material due to 

corrosion in inaccessible areas on the exterior of its Mark I containment drywell shell. 

Additionally, as discussed in the staff evaluation of RAI 3.5.2.2.1.3.1-2, the staff notes 

that the Fermi 2 operating experience of the drywell shell indicates no significant loss of 

material due to corrosion; therefore, a plant-specific program is not necessary to 

manage the aging effect. 
3-412 

The staff finds that the applicant has met the further evaluation criteria and that the 

applicant’s proposal to manage the effects of aging using the enhanced Containment 

Inservice Inspection – IWE Program and the Containment Leak Rate Program is 

acceptable because the plant-specific operating experience from ASME Code, 

Section XI, Subsection IWE examinations indicates no significant loss of material due to 

corrosion in inaccessible areas of the Fermi 2 drywell shell and because the applicant’s 

approach to managing the aging effect is consistent with the recommendations in GALL 

Report, item II.B3.1.CP-113, which corresponds to LRA Table 3.5.1, item 3.5.1-4. 

Based on the programs identified, the staff determines that the applicant’s programs 

meet SRP-LR Section 3.5.2.2.1.3, item 1, criteria. For those items associated with LRA 

Section 3.5.2.2.1.3, item 1, as amended by letter dated January 30, 2015, the staff 

concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

(2) LRA Section 3.5.2.2.1.3, item 2, associated with LRA Table 3.5.1 item 3.5.1–6, 

addresses steel elements: torus shell, exposed to air-indoor, uncontrolled or exposed to 

fluid environment, which will be managed for loss of material due to general, pitting, and 

crevice corrosion by the Containment Inservice Inspection – IWE Program and the 

Containment Leak Rate Program. The criteria in SRP-LR Section 3.5.2.2.1.3, item 2, 

state that loss of material due to general, pitting, and crevice corrosion could occur in the 

steel torus shell of Mark I containments. The existing program relies on ASME Code, 

Section XI, Subsection IWE, and Appendix J to 10 CFR Part 50 to manage this aging 

effect. The SRP-LR also states that the GALL Report recommends further evaluation of 

plant-specific programs to manage this aging effect if corrosion is significant. The GALL 

Report, item II.B1.1.CP-48, corresponding to SRP-LR Table 3.5 1, item 6, states, in part, 

“License renewal applicants are advised to address their plant-specific operating 

experience related to the torus shell corrosion. If the identified corrosion is significant, a 

plant-specific aging management is required.” The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that the continued monitoring of its Mark I 

containment steel torus shell for loss of material due to general, pitting, and crevice 

corrosion through the Containment Inservice Inspection – IWE Program by visual 

examination of accessible interior and exterior surfaces and through the Containment 

Leak Rate Program provides reasonable assurance that loss of material due to 

corrosion will be detected before a loss of intended function. The applicant also stated 

in LRA Section 3.5.2.2.1.3, item 1, as amended by its response to RAI 3.5.2.2.1.3.1-2, 

dated January 30, 2015, that the interior and exterior shell of the torus is accessible. 

In its review of the applicant’s evaluation in LRA Section 3.5.2.2.1.3, item 2, related to 

LRA Table 3.5.1, item 3.5.1-6, and the corresponding AMR results line in LRA 

Table 3.5.2-1 associated with loss of material due to corrosion of steel elements of the 

torus shell, the staff noted that the applicant had not addressed the plant-specific 

operating experience related to the loss of material due to corrosion of the torus shell, as 

recommended in the GALL Report. The staff needed this information to determine 

whether a plant-specific AMP is necessary to manage the aging effect. By letter dated 

December 22, 2014, the staff issued RAI 3.5.2.2.1.3.2-1, requesting that the applicant 

describe the plant-specific operating experience related to loss of material due to 

general, pitting, and crevice corrosion of the Fermi 2 steel torus shell and address its 

significance to justify whether a plant-specific program is necessary to manage the aging 

effect. 
3-413 

In its response to RAI 3.5.2.2.1.3.2-1, dated January 30, 2015, the applicant stated that 

only one 0.25-inch-diameter by 0.0285-inch-deep corrosion pit under a coating blister 

has been identified in the torus wetted area during the history of the plant; the coating 

was repaired. The applicant also stated that during the recent inspection performed in 

2012, when 100 percent of the torus wetted and vapor space was inspected, no pitting of 

the torus primary containment boundary was identified. However, broken coating 

blisters, mechanical damage, and pin point rust areas were identified and repaired in the 

wetted areas of the torus. With regard to the vapor region, the applicant stated that all 

flaking paint was removed from the torus ring header, torus vacuum breaker valves, 

nitrogen supply lines, monorail rail, and torus walkway and handrail. The applicant 

explained that flaking or cracked coating was removed and protective coating reapplied 

to the torus shell. The applicant also stated that no loss of material due to corrosion of 

the exterior surface of the Fermi 2 torus shell has been identified to date. The applicant 

concluded that, because no significant loss of material due to corrosion has occurred in 

the torus shell, a plant-specific program is not needed to manage the aging effect. The 

applicant revised LRA Section 3.5.2.2.1.3, item 2, to reflect the above operating 

experience of the Fermi 2 torus shell. 

The staff noted that LRA Section B.1.12 states that the torus is inspected in alternate 

RFOs, which is more frequent than that required by ASME Code, Section XI, 

Subsection IWE. LRA Section B.1.12 also states that the coating condition continues to 

be monitored and repaired, as necessary. Based on the torus shell thickness in the 

wetted region of 0.658 inch indicated in UFSAR Section 3.8.2, the single 0.0285-inch 

corrosion pit identified in the torus wetted area is less than the 5 percent of the torus 

shell thickness and is an insignificant loss of material. The staff notes that the 

applicant’s operating experience description of the torus shell indicates no significant 

loss of material due to corrosion to necessitate a plant-specific program to manage the 

aging effect. The staff finds the applicant’s response acceptable because the applicant 

provided a summary description of the operating experience of the Fermi 2 torus shell, 

which indicates no significant loss of material due to corrosion, and justified that a 

plant-specific program is not necessary to manage the aging effect on the torus shell. 

The staff’s concern described in RAI 3.5.2.2.1.3.2-1 is resolved. 

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWE 

Program, with enhancements, and the Containment Leak Rate Program is documented 

in SER Sections 3.0.3.2.5 and 3.0.3.1.8, respectively. The staff noted that the programs 

ensure that corrosion of the torus shell is detected and that corrective actions are taken 

before there is a loss of material that affects its ability to perform intended functions by 

using visual examinations of accessible and wetted torus areas at frequencies required 

by ASME Code, Section XI, Subsection IWE, and applicable regulations and by periodic 

leak rate testing in accordance with Appendix J to 10 CFR Part 50. Augmented 

examinations are specified as required. Additionally, as discussed in the staff evaluation 

of RAI 3.5.2.2.1.3.2-1, the staff notes that the Fermi 2 operating experience of the torus 

shell indicates no significant loss of material due to corrosion; therefore, a plant-specific 

program is not necessary to manage the aging effect. The staff finds that the applicant 

has met the further evaluation criteria and that its proposal to manage the effects of 

aging using the enhanced Containment Inservice Inspection – IWE Program and the 

Containment Leak Rate Program is acceptable because the plant-specific operating 

experience indicates no significant loss of material due to corrosion of the Fermi 2 torus 

shell and because the applicant’s approach to managing the aging effect is consistent 

with the recommendations in GALL Report, item II.B1.1.CP 48, which corresponds to 

LRA Table 3.5.1, item 3.5.1-6. 
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Based on the programs identified, the staff determines that the applicant’s programs 

meet SRP-LR Section 3.5.2.2.1.3, item 2, criteria. For those items associated with LRA 

Section 3.5.2.2.1.3, item 2, as amended by letter dated January 30, 2015, the staff 

concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

(3) LRA Section 3.5.2.2.1.3, item 3, associated with LRA Table 3.5.1, item 3.5.1-7, and 

GALL Report, item II.B1.1.CP-109, addresses steel elements: torus ring girders; 

downcomers, exposed to air-indoor, uncontrolled or exposed to fluid environment, which 

will be managed for loss of material due to general, pitting, and crevice corrosion by the 

Containment Inservice Inspection – IWE Program. The criteria in SRP-LR 

Section 3.5.2.2.1.3, item 3, state that loss of material due to general, pitting, and crevice 

corrosion could occur in steel torus ring girders and downcomers of Mark I 

containments. The existing program relies on ASME Code, Section XI, Subsection IWE, 

to manage this aging effect. The SRP-LR also states that the GALL Report 

recommends further evaluation of plant-specific programs to manage this aging effect if 

plant operating experience identified significant corrosion. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that the continued monitoring of its 

Mark I steel containment, including the steel torus ring girders and downcomers, for loss 

of material due to general, pitting, and crevice corrosion through the Containment 

Inservice Inspection – IWE Program by visual examination of accessible surfaces 

provides reasonable assurance that loss of material due to corrosion will be detected 

before a loss of intended function. 

In its review of the applicant’s evaluation in LRA Section 3.5.2.2.1.3, item 3, related to 

LRA Table 3.5.1, item 3.5.1-7, and the corresponding AMR results in LRA Table 3.5.2-1 

associated with loss of material due to corrosion of steel torus ring girders and 

downcomers, the staff noted that the applicant had not addressed the plant-specific 

operating experience related to the loss of material due to corrosion of the torus shell, as 

recommended in the GALL Report. The staff needed this information to determine 

whether a plant-specific AMP is necessary to manage the aging effect. By letter dated 

December 22, 2014, the staff issued RAI 3.5.2.2.1.3.3-1, requesting that the applicant 

describe the plant-specific operating experience related to loss of material due to 

general, pitting, and crevice corrosion of the Fermi 2 steel torus ring girders and 

downcomers and address its significance to justify whether a plant-specific program is 

necessary to manage the aging effect. 

In its response to RAI 3.5.2.2.1.3.3-1, dated January 30, 2015, the applicant stated that, 

to date, operating experience has identified no loss of material due to general, pitting, 

and crevice corrosion of the Fermi 2 steel torus ring girders and downcomers. The 

applicant concluded that a plant-specific program is not needed because corrosion has 

not been identified. The applicant revised LRA Section 3.5.2.2.1.3, item 3, to indicate 

that operating experience has identified no loss of material due to corrosion of the 

Fermi 2 torus ring girders and downcomers. 

The staff finds the applicant’s response acceptable because the applicant’s operating 

experience description indicated no loss of material due to corrosion of the torus ring 

girders and downcomers, which justifies that a plant-specific program is not necessary to 

manage the aging effect. The staff’s concern described in RAI 3.5.2.2.1.3.3-1 is 

resolved. 
3-415 

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWE 

Program, with enhancements, is documented in SER Sections 3.0.3.2.5. The staff noted 

that the program ensures that corrosion of the torus ring girders and downcomers is 

detected and that corrective actions are taken before there is a loss of material that 

affects its ability to perform intended functions by using visual examinations of 

accessible and wetted torus areas at frequencies required by ASME Code, Section XI, 

Subsection IWE, and applicable regulations. Augmented examinations are specified as 

required. Additionally, as discussed in the staff evaluation of RAI 3.5.2.2.1.3.3-1, the 

staff notes that the Fermi 2 operating experience of the torus ring girders and 

downcomers identified no loss of material due to corrosion; therefore, a plant-specific 

program is not necessary to manage the aging effect. The staff finds that the applicant 

has met the further evaluation criteria and that its proposal to manage the effects of 

aging using the enhanced Containment Inservice Inspection – IWE Program is 

acceptable because the plant-specific operating experience indicates no loss of material 

due to corrosion of the Fermi 2 torus ring girders and downcomers and because the 

applicant’s approach to managing the aging effect is consistent with the 

recommendations in GALL Report item II.B1.1.CP-109, which corresponds to LRA 

Table 3.5.1, item 3.5.1-7. 

Based on the programs identified, the staff determines that the applicant’s programs 

meet SRP-LR Section 3.5.2.2.1.3, item 3, criteria. For those items associated with LRA 

Section 3.5.2.2.1.3, item 3, as amended by letter dated January 30, 2015, the staff 

concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA 

Section 3.5.2.2.1.4, associated with LRA Table 3.5.1, item 3.5.1-8, addresses loss of prestress 

due to relaxation, shrinkage, creep, and elevated temperature in steel prestressing tendons 

exposed to air-indoor uncontrolled or air-outdoor environments. The criteria in SRP-LR 

Section 3.5.2.2.1.4 state that the evaluation of this TLAA is addressed separately in SRP-LR 

Section 4.5. The applicant stated that this item is not applicable because the Fermi 2 

containment is a Mark I steel containment and because its design does not contain prestressing 

tendons. The staff evaluated the applicant’s claim and finds it acceptable because the Fermi 2 

containment structure is a Mark I steel containment and because prestressing tendons are used 

only in prestressed concrete containment structures. 

Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.5 (as amended by letter dated 

February 12, 2015, in response to RAI 4.6.1-1 discussed in SER Section 4.6.1), associated with 

LRA Table 3.5.1, item 3.5.1-9, states that TLAAs are evaluated in accordance with 

10 CFR 54.21(c)(1) and that the evaluation of this TLAA for Fermi 2 containment components, 

including the torus, vent line bellows, and downcomers, is addressed in LRA Section 4.6, 

“Containment Liner Plates, Metal Containments, and Penetrations Fatigue Analysis.” This is 

consistent with SRP-LR Section 3.5.2.2.1, item 5, and is, therefore, acceptable. The staff’s 

evaluation of the TLAAs for the Fermi 2 primary containment suppression chamber (torus) and 

vent system, vent line bellows, refueling and drywell seal bellows, traversing incore probe 

penetration bellows, containment flued head penetrations, and penetration sleeve bellows is 

documented in SER Section 4.6. 
3-416 

Cracking Due to Stress Corrosion Cracking. LRA Section 3.5.2.2.1.6, associated with LRA 

Table 3.5.1, item 3.5.1-10, addresses stainless steel containment penetration sleeves, 

penetration bellows and dissimilar metal welds exposed to plant indoor air, which will be 

managed for cracking due to SCC by the Containment Inservice Inspection – IWE Program and 

Containment Leak Rate Program. The acceptance criteria in SRP-LR Section 3.5.2.2.1.6 state 

that cracking due to SCC of stainless steel penetration bellows and dissimilar metal welds could 

occur in all types of PWR and BWR containments. The SRP-LR also states that the existing 

program relies on GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE” and 

AMP XI.S4, “10 CFR Part 50, Appendix J” to manage this aging effect. The GALL Report 

recommends further evaluation of additional appropriate examinations implemented to detect 

cracking due to SCC for these stainless steel containment penetration components. 

The applicant credited the existing Containment Inservice Inspection – IWE Program and 

Containment Leak Rate Program to manage cracking due to SCC, as recommended in the 

GALL Report. The LRA states that the applicant’s Containment Inservice Inspection – IWE 

Program and Containment Leak Rate Program are consistent with GALL Report AMP XI.S1 and 

AMP XI.S4, respectively. The applicant also stated that initiation and propagation of SCC 

require the following three factors: (1) a material susceptible to SCC, (2) a high tensile stress, 

and (3) a corrosive environment. The applicant further stated that elimination of any of these 

factors prevents SCC. In addition, the applicant stated that SCC is not expected to occur in the 

stainless steel penetration components at Fermi 2 because these components are not exposed 

to a corrosive environment (e.g., environments contaminated with chlorides, fluorides, or 

sulfates). The applicant stated that its review of plant-specific operating experience did not 

identify cracking of these components. The applicant also stated that containment pressure 

boundary functions have not been identified as a concern at Fermi 2. 

In its review, the staff finds the applicant’s aging management for the stainless steel 

containment penetration components acceptable because the applicant clarified that (1) the 

environment without chemical contamination is not conducive to SCC of the component, (2) the 

plant-specific operating experience indicates the absence of SCC in these components, and 

(3) the existing Containment Inservice Inspection – IWE Program and Containment Leak Rate 

Program are used to ensure the integrity of these components. 

The staff’s evaluations of the applicant’s Containment Inservice Inspection – IWE Program and 

Containment Leak Rate Program are documented in SER Sections 3.0.3.2.5 and 3.0.3.1.8, 

respectively. In its review of components associated with LRA Table 3.5.1, item 3.5.1-10, the 

staff finds that the applicant has met the further evaluation criteria and that its proposal to 

manage the effects of aging using these programs is acceptable because the applicant’s 

evaluation confirms that (1) the environment without chemical contamination is not conducive to 

SCC, (2) the plant-specific operating experience does not identify cracking of the components, 

and (3) the existing Containment Inservice Inspection – IWE Program and Containment Leak 

Rate Program will continue to ensure that cracking due to SCC does not affect the integrity of 

the components. 

Based on the programs identified, the staff determines that the applicant’s programs and aging 

management evaluation meet the criteria in SRP-LR Section 3.5.2.2.1.6. For those items 

associated with LRA Section 3.5.2.2.1.6, the staff concludes that the LRA is consistent with the 

GALL Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 
3-417 

Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw. LRA 

Section 3.5.2.2.1.7, associated with LRA Table 3.5.1, item 3.5.1-11, addresses loss of material 

(spalling, scaling) and cracking due to freeze-thaw in inaccessible areas of concrete: dome, 

wall, basemat, ring girders, and/or buttresses exposed to an air-outdoor environment or a 

groundwater/soil environment. The criteria in SRP-LR Section 3.5.2.2.1.7 state that further 

evaluation of this aging effect is recommended for plants located in moderate to severe 

weathering conditions. The SRP-LR also states that a plant-specific program is not required if 

documented evidence confirms that the existing concrete has an air content of 3 percent to 

8 percent and if subsequent inspection of accessible areas did not exhibit degradation related to 

freeze-thaw. The applicant stated that this item is not applicable to the Fermi 2 primary 

containment structure because the concrete base foundation is founded below grade integral 

with the reactor building base foundation and is not exposed to an air-outdoor environment that 

is subject to freeze-thaw action and because the GALL Report item is not associated with the 

Fermi 2 BWR Mark I steel containment structure type. The staff reviewed UFSAR Section 3.8 

and confirmed that the Fermi 2 steel containment vessel, concrete floor slab, and reactor vessel 

pedestal are surrounded by the reactor building and are integral with the reinforced concrete 

basemat of the reactor building; therefore, these concrete elements are not exposed to the 

environment required for this aging effect to occur. The staff evaluated the applicant’s claim 

and finds it acceptable because this aging effect is applicable to concrete containment 

structures and because Fermi 2 has a Mark I carbon steel containment structure type. 

Cracking Due to Expansion and Reaction with Aggregates. LRA Section 3.5.2.2.1.8, associated 

with LRA Table 3.5.1, item 3.5.1-12, addresses cracking due to expansion from a reaction with 

aggregates in inaccessible areas of concrete elements exposed to any environment. The 

criteria in SRP-LR Section 3.5.2.2.1.8 state that a plant-specific AMP is not necessary if 

investigations, tests, and petrographic examinations of aggregates performed in accordance 

with ASTM C295, “Standard Guide for Petrographic Examination of Aggregates for Concrete,” 

and other ASTM reactivity tests, as required, can demonstrate that those aggregates do not 

adversely react within concrete, or for potentially reactive aggregates, aggregate concrete 

reaction is not significant if the structure was constructed in accordance with ACI 318, “Building 

Code Requirements for Reinforced Concrete.” The applicant stated that this item is not 

applicable because the GALL Report item is not associated with the Fermi 2 Mark I steel 

containment structure. The LRA also states that materials for the containment vessel concrete 

base foundation were investigated, tested, and examined in accordance with Michigan 

Department of State Highways and ASTM standards and that, if potentially reactive aggregates 

were encountered, low-alkali Portland cement was used to prevent reaction with aggregates. 

The applicant further stated that based on ongoing industry operating experience, the Structures 

Monitoring Program will manage this aging effect in accessible concrete areas for the Fermi 2 

steel containment vessel concrete base foundation. The staff reviewed UFSAR Section 3.8 and 

confirmed that the Fermi 2 steel containment vessel concrete base slab and reactor vessel 

pedestal are surrounded by the reactor building and that they are integral with the reinforced 

concrete basemat of the reactor building. The staff evaluated the applicant’s claim and finds it 

acceptable because (1) this aging effect is applicable to concrete containment structures, 

whereas Fermi 2 has a Mark I carbon steel containment structure type, and (2) the use of the 

Structures Monitoring Program to manage the aging effect of cracking due to expansion from 

reaction with aggregates for the basemat foundation of a steel containment is consistent with 

the GALL Report recommendation. 

Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide and Carbonation. 

LRA Section 3.5.2.2.1.9, associated with LRA Table 3.5.1, items 3.5.1-13 and 3.5.1-14, 

addresses increase in porosity and permeability and loss of strength due to leaching of calcium 
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hydroxide and carbonation in inaccessible areas of concrete elements exposed to a flowing 

water environment. The criteria in SRP-LR Section 3.5.2.2.1.9 recommend further evaluation if 

leaching is observed in accessible areas that impact intended functions. The SRP-LR also 

states that a plant-specific AMP is not required, even if reinforced concrete is exposed to flowing 

water if (1) there is evidence in the accessible areas that the flowing water has not caused 

leaching and carbonation or (2) an evaluation has determined that the observed leaching of 

calcium hydroxide and carbonation in accessible areas has no impact on the intended function 

of the concrete structure. The applicant stated that this item is not applicable because the 

GALL Report item is not associated with the Fermi 2 Mark I steel containment structure. The 

applicant also stated that the steel containment vessel structure’s concrete base foundation is 

below grade, is protected by the reactor building’s concrete base foundation, and is not exposed 

to the flowing water environment necessary for this aging effect to occur. The staff reviewed 

UFSAR Section 3.8 and confirmed that the Fermi 2 Mark I steel containment vessel concrete 

components are surrounded by the reactor building and that they are integral with the reinforced 

concrete basemat of the reactor building; therefore, these concrete elements are not exposed to 

the environment required for this aging effect to occur. The staff evaluated the applicant’s claim 

and finds it acceptable because this aging effect is applicable to concrete containment 

structures and because Fermi 2 is a Mark I carbon steel containment structure type. 

 Safety-Related and Other Structures and Component Supports 

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2, which 

address several areas listed below. 

Aging Management of Inaccessible Areas. 

(1) LRA Section 3.5.2.2.2.1, item 1, associated with LRA Table 3.5.1, item 3.5.1-42, 

addresses loss of material (spalling, scaling) and cracking due to freeze-thaw in 

below-grade inaccessible concrete areas of Groups 1–3, 5, and 7–9 structures exposed 

to an air-outdoor environment. The criteria in SRP-LR Section 3.5.2.2.2.1, item 1, state 

that loss of material (spalling, scaling) and cracking due to freeze-thaw could occur for 

below-grade inaccessible concrete areas of Groups 1–3, 5, and 7–9 exposed to outdoor 

air and that the GALL Report recommends further evaluation of the need for a 

plant-specific AMP for plants located in moderate to severe weathering conditions. As 

stated in the GALL Report, a plant-specific program is not required if documented 

evidence confirms that the existing concrete had air content of three percent to eight 

percent, and if subsequent inspections have not identified degradation related to 

freeze-thaw. The applicant originally stated that this item is not applicable because 

(a) the Fermi 2 concrete structures are designed and constructed in accordance with the 

recommendations in ACI 318-63 and/or ACI 318-71, (b) Fermi 2 specifications provide a 

durable concrete that is not subject to freeze-thaw aging effects, and (c) Fermi 2 

specifications require the use of an air-entraining agent for concrete subject to 

weathering. 

In its review of components associated with LRA Table 3.5.1, item 3.5.1-42, the staff 

noted that Fermi 2 is located in a severe weathering condition; however, sufficient 

information had not been provided to adequately address the further evaluation criteria. 

In its review of LRA Section 3.5.2.2.2.1, item 1, the staff noted that the applicant did not 

provide documented evidence that confirms that the existing concrete has air content of 

3 to 8 percent and did not discuss results of past inspections that demonstrate that 

freeze-thaw degradation is not an issue. Therefore, by letter dated September 26, 2014, 

the staff issued RAI 3.5.2.2.2.1-1, requesting that the applicant (a) confirm whether the 
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existing concrete for Groups 1–3, 5, and 7–9 structures had air content between 

3 percent and 8 percent, (b) describe whether the results of past inspections have 

identified degradation attributed to freeze-thaw, and (c) if evidence is unavailable, 

demonstrate air content between 3 percent and 8 percent, to provide either a description 

of a plant-specific AMP to manage the aging effects or a technical basis for not 

proposing a plant-specific program. 

In its response dated October 24, 2014, the applicant stated that the air content values 

for below-grade inaccessible concrete of Groups 1–3, 5, and 7–9 structures are less 

than 3 percent based on the review of test results and are consistent with the original 

site-specific design and are between 3 percent and 8 percent for the above-grade 

concrete. The applicant also stated that past inspections of the Fermi 2 structures under 

the Structures Monitoring Program and from projects where below-grade exterior 

concrete walls were exposed did not identify degradation attributed to freeze-thaw. The 

applicant revised LRA Section 3.5.2.2.2.1, item 1, and LRA Table 3.5.1, item 3.5.1-42, to 

clarify that the Structures Monitoring Program will manage the loss of material and 

cracking due to freeze-thaw in below-grade inaccessible concrete of Groups 1–3, 5, and 

7–9 structures through visual inspections when they become accessible as a result of an 

excavation activity and when observed conditions in accessible areas indicate that 

significant degradation may be occurring in the inaccessible area. 

The staff finds the applicant’s response acceptable because the applicant stated that the 

Structures Monitoring Program will manage the aging effects loss of material and 

cracking due to freeze-thaw in inaccessible areas of Groups 1–3, 5, and 7–9 structures 

after clarifying that air content for concrete in inaccessible areas of these groups of 

structures is less than 3 percent and that no degradation has been attributed to 

freeze-thaw from past inspections. The staff’s concern described in RAI 3.5.2.2.2.1-1 is 

resolved. 

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in 

SER Section 3.0.3.2.22. The staff noted that the Structures Monitoring Program 

proposes to manage the effects of aging for below-grade inaccessible concrete areas of 

these groups of structures through the use of visual inspections when they become 

accessible as a result of an excavation activity and when observed conditions in 

accessible areas indicate that significant degradation may be occurring in the 

inaccessible area. The staff also noted that, consistent with the GALL Report 

recommendation, LRA Table 3.5.1, item 3.5.1-64, manages loss of material and cracking 

due to freeze-thaw in exterior and below-grade accessible areas and foundations of 

Groups 1–5 and 7–9 concrete structures using the Structures Monitoring Program. The 

staff finds that the applicant has met the further evaluation criteria and that its proposal 

to manage the effects of aging using the Structures Monitoring Program is acceptable 

because (1) the program is consistent with the AMP recommended by the GALL Report 

for managing these aging effects in accessible areas for these groups of structures, 

(2) management of these aging effects through visual inspection of inaccessible 

concrete areas when they become accessible for any reason and through use of the 

observed condition from accessible areas as an indicator is consistent with the GALL 

Report recommendation to adequately manage concrete degradations due to 

freeze-thaw before there is a loss of intended function, and (3) past inspections from 

exposed inaccessible areas have not revealed concrete structural degradations 

attributed to freeze-thaw. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.2.1, item 1, criteria. For those items associated with LRA 
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Section 3.5.2.2.2.1, item 1, the staff concludes that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

(2) LRA Section 3.5.2.2.2.1, item 2, associated with LRA Table 3.5.1, item 3.5.1-43, 

addresses concrete in below-grade inaccessible concrete areas of Groups 1–5 and 7–9 

structures exposed to soil, which will be managed for cracking due to expansion from 

reaction with aggregates by the Structures Monitoring Program. The criteria in SRP-LR 

Section 3.5.2.2.2.1, item 2, state that cracking due to expansion from reaction with 

aggregates could occur for inaccessible concrete areas of Groups 1–5 and 7–9 

structures exposed to any environment. The SRP-LR also states that, if concrete was 

not constructed in accordance with the recommendations in the GALL Report, further 

evaluation is recommended to determine whether a plant-specific AMP is necessary to 

manage this aging effect. As stated in the GALL Report, a plant-specific AMP is not 

necessary if (1) investigations, tests, and petrographic examination of aggregates 

performed in accordance with ASTM C295 and other ASTM reactivity tests can 

demonstrate that those aggregates do not adversely react within concrete or (2) the 

applicant can demonstrate that, for potentially reactive aggregates, the in-place concrete 

can perform its intended function. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that (1) Fermi 2 Groups 1–5 and 7–9 concrete 

structures are designed and constructed in accordance with the recommendations in 

ACI 318-63 and/or ACI 318-71, (2) the aggregate used did not come from a region 

known to yield aggregates suspected of, or known to cause, aggregate reactions, and 

(3) materials were specifically investigated, tested, and examined in accordance with 

pertinent Michigan Department of State Highways and ASTM standards. However, the 

applicant also stated that the Structures Monitoring Program manages this aging effect 

by considering ongoing industry operating experience. 

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in 

SER Section 3.0.3.2.22. The staff noted that the Structures Monitoring Program 

proposes to manage the effects of aging for below-grade inaccessible concrete areas of 

these groups of structures through the use of visual inspections when they become 

accessible as a result of an excavation activity and when observed conditions in 

accessible areas indicate that significant degradation may be occurring in the 

inaccessible area. The staff also noted that, consistent with the GALL Report 

recommendation, LRA Table 3.5.1, item 3.5.1-54, manages cracking due to expansion 

from reaction with aggregates in all accessible concrete areas of Groups 1–5 and 7–9 

structures using the Structures Monitoring Program. The staff reviewed UFSAR 

Section 3.8.4.6.1 and confirmed that Fermi 2 concrete structures are designed and 

constructed in accordance with the recommendations in ACI 318 and ACI 349. Based 

on its review of components associated with LRA Table 3.5.1, item 3.5.1-43, for which 

the applicant cited generic note E, the staff finds that the applicant has met the further 

evaluation criteria and that its proposal to manage the effects of aging using the 

Structures Monitoring Program is acceptable because (1) the program is consistent with 

the AMP recommended by the GALL Report for managing this aging effect in accessible 

areas for these groups of structures, (2) management of this aging effect through visual 

inspection of inaccessible concrete areas when they become accessible for any reason 

and through use of the observed condition from accessible areas as an indicator is 

consistent with the GALL Report recommendations to adequately identify concrete 

degradation due to expansion and reaction with aggregates before there is a loss of 
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intended function, and (3) Fermi 2 concrete structures are designed and constructed in 

accordance with the recommendations in ACI 318 and ACI 349, and (4) past inspections 

from exposed inaccessible areas have not revealed concrete structural degradations 

attributed to expansion due to reaction with aggregates. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.2.1, item 2, criteria. For those items associated with LRA 

Section 3.5.2.2.2.1, item 2, the staff concludes that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

(3) LRA Section 3.5.2.2.2.1, item 3, associated with LRA Table 3.5.1, item 3.5.1-44, 

addresses inaccessible concrete areas of structures for all groups exposed to soil, which 

will be managed for cracks and distortion due to increased stress levels from settlement 

by the Structures Monitoring Program. The criteria in SRP-LR Section 3.5.2.2.2.1, 

item 3, state that cracking and distortion due to increased stress levels from settlement 

could occur in below-grade inaccessible concrete areas for all groups of structures. The 

SRP-LR further states that the existing program relies on structure monitoring programs 

to manage these aging effects but that some plants may rely on a dewatering system to 

control settlement or erosion. The SRP-LR also states that the GALL Report 

recommends the verification of the continued functionality of the dewatering system 

through the period of extended operation for plants that credit a dewatering system in 

their CLB. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that Fermi 2 structures do not rely on a dewatering system to control settlement. 

The applicant stated that for LRA Table 3.5.1, item 3.5.1-44, the applicability is limited to 

the process facilities and yard structures exposed to compacted structural backfill or soil 

environment because other structures are founded on bedrock and because the aging 

effects of cracking and distortion due to increased stress levels from settlement are not 

applicable. The staff reviewed UFSAR Section 3.8.5 and confirmed that Fermi 2 

Category 1 structures are founded on bedrock; however, sufficient information was not 

provided to confirm whether the turbine building foundation is susceptible to cracking 

and distortion due to increased stress levels from settlement. Therefore, by letter dated 

December 23, 2014, the staff issued RAI 3.5.2.2.2.1-2, requesting that the applicant 

describe the foundation type for Fermi 2 turbine building and, if the structure is not 

founded on bedrock and is susceptible to these aging effects, state how these aging 

effects will be adequately managed for the period of extended operation or provide 

additional information to justify why these aging effects do not require aging 

management. 

In its response dated January 26, 2015, the applicant stated that the Fermi 2 turbine 

building has a mat founded on bedrock, as confirmed by site drawings and calculations, 

and that the aging effects of cracking and distortion due to increased stress levels from 

settlement are not applicable to the turbine building. The applicant also stated that the 

turbine pedestal is founded on bedrock. 

The staff noted that the applicant’s response and general search of the applicant’s 

UFSAR confirmed that there are no in-scope concrete structures exposed to soil 

environment and susceptible to increased stress levels from settlement, except those 

listed in LRA Section 3.5.2.2.2.1, item 3, and LRA Table 3.5.1, item 3.5.1-44. The staff 

finds the applicant’s response acceptable because the applicant clarified that the turbine 

building is founded on bedrock, as confirmed by site drawings and calculations; 
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therefore, the aging effects of cracking and distortion due to increased stress levels from 

settlement are not credible aging effects for the turbine building. The staff’s concern 

described in RAI 3.5.2.2.2.1-2 is resolved. 

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in 

SER Section 3.0.3.2.22. The staff noted that the Structures Monitoring Program will be 

used to manage cracking and distortion of concrete in accessible and inaccessible 

concrete areas for structures founded on soil through visual inspections of structures at 

a frequency of 5 years, with provisions for more frequent inspection to ensure that there 

is no loss of intended function between inspections. The staff also noted that a review of 

the applicant’s CLB documents concluded that no dewatering system was credited to 

lower the groundwater level or to control settlement at the site. The staff finds that the 

applicant has met the further evaluation criteria and that its proposal to manage the 

effects of aging using the Structures Monitoring Program is acceptable because (1) the 

program is consistent with the AMP recommended by the GALL Report for managing 

this aging effect in accessible areas for these groups of structures, (2) the in-scope 

Fermi 2 Category I concrete structures and turbine building are founded on bedrock, and 

(3) Fermi 2 does not rely on a dewatering system to lower the groundwater level or to 

control settlement at the site. 

LRA Section 3.5.2.2.2.1, item 3, associated with LRA Table 3.5.1, items 3.5.1-45 

and 3.5.1-46, addresses reduction in foundation strength, cracking due to differential 

settlement, and erosion of porous concrete subfoundations in inaccessible concrete 

areas of Groups 1–3 and 5–9 structures exposed to a fluid environment. The criteria in 

SRP-LR Section 3.5.2.2.2.1, item 3, state that reduction in foundation strength and 

cracking due to differential settlement and erosion of porous concrete subfoundations 

could occur in below-grade inaccessible concrete areas of Groups 1–3 and 5–9 

structures. The SRP-LR further states that the existing program relies on structure 

monitoring programs to manage these aging effects but that some plants may rely on a 

dewatering system to control settlement or erosion. The SRP-LR also states that the 

GALL Report recommends the verification of the continued functionality of the 

dewatering system through the period of extended operation for plants that credit a 

dewatering system in their CLB. The applicant stated that this item is not applicable 

because Fermi 2 Groups 1–3 and 5–9 concrete structures do not use porous concrete 

subfoundations, do not have water flowing underneath the foundation, and do not rely on 

a dewatering system for control of settlement. The staff’s review of applicant’s CLB 

documents concluded that no dewatering system was credited to lower the groundwater 

level or control settlement at the site. The staff evaluated the applicant’s claim and finds 

it acceptable based on its review of UFSAR Section 2.5, which confirmed that the 

Fermi 2 concrete structures are not founded on porous concrete subfoundations but are 

generally founded on grouted bedrock or on compacted crushed rock fill or soil and that 

Fermi 2 does not rely on a dewatering system to lower the groundwater level or control 

settlement at the site. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.2.1, item 3, criteria. For those items associated with LRA 

Section 3.5.2.2.2.1, item 3, the staff concludes that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 
3-423 

(4) LRA Section 3.5.2.2.2.1, item 4, associated with LRA Table 3.5.1, item 3.5.1-47, 

addresses increase in porosity and permeability and loss of strength due to leaching of 

calcium hydroxide and carbonation in below-grade inaccessible concrete areas of 

Groups 1–5 and 7–9 structures exposed to flowing water. The criteria in SRP-LR 

Section 3.5.2.2.2.1, item 4, state that increase in porosity and permeability and loss of 

strength due to leaching of calcium hydroxide and carbonation could occur in 

below-grade inaccessible concrete areas of these structures. The SRP-LR also states 

that the GALL Report recommends further evaluation if leaching is observed in 

accessible areas that impact the intended functions of the concrete structure. As stated 

in the GALL Report, a plant-specific AMP is not required for the reinforced concrete 

exposed to flowing water if (1) there is evidence in the accessible areas that the flowing 

water has not caused leaching of calcium hydroxide and carbonation or (2) an 

evaluation determined that the observed leaching of calcium hydroxide and carbonation 

in accessible areas has no impact on the intended function of the concrete structure. 

During its review of components associated with LRA Table 3.5.1, item number 3.5.1-47, 

the staff noted that the applicant stated that these groups of structures are not subject to 

the flowing water environment necessary for these aging effects to occur and that no 

leaching has been observed in accessible areas of Fermi 2 concrete structures; 

however, during the AMP audit, the staff observed indications of concrete leaching in the 

floor and walls of the turbine building basement and identified operating experience 

associated with groundwater in leakage and leaching issues in the reactor building, RHR 

complex, and manholes. Therefore, by letter dated December 23, 2014, the staff issued 

RAI 3.5.2.2.2.1-3, requesting that the applicant (1) provide a summary of operating 

experience regarding leaching of calcium hydroxide and carbonation in accessible areas 

of these group of structures, (2) state whether it has performed an evaluation to 

determine the impact on the intended function of the concrete structure, (3) describe the 

results, and (4) if it has not performed an evaluation, state and describe how this aging 

effect will be adequately managed for inaccessible areas. 

In its response dated January 26, 2015, the applicant provided plant operating 

experience of seven water in-leakage events that may appear to be potential leaching of 

calcium hydroxide and carbonation in accessible areas. The applicant stated that these 

events have generally been characterized as efflorescence. In addition, to confirm that 

these deposits are not the results of leaching of calcium hydroxide and carbonation that 

could impact the intended functions of the concrete structures, the applicant revised the 

LRA to include Commitment No. 34n, to perform testing (for mineral and iron content) 

and evaluation of previously identified conditions before the period of extended operation 

to confirm that the observed conditions are not the result of leaching of calcium 

hydroxide and carbonation. The applicant also stated that it will perform similar testing 

on samples for future observations of the same nature to determine whether the 

observed condition in accessible areas is experiencing leaching of calcium hydroxide 

and carbonation and, based on the test results, will perform further evaluations to 

determine whether the observed condition has any impact on the intended functions of 

the concrete element (Commitment No. 34m). The applicant further stated that it will 

develop a similar corrective action plan for testing and evaluation of concrete elements 

in inaccessible concrete areas if observed conditions in accessible areas are found to 

impact the intended functions of the concrete elements in question. An enhancement 

(Commitment Nos. 34m and 34n) to the LRA Structures Monitoring Program and a 

revision to LRA Section B.1.42 were provided to manage the potential for these aging 

effects. 
3-424 

Based on its review, the staff finds the applicant’s general characterization as 

efflorescence for the conditions identified in the plant’s operating experience to be 

inconsistent with the staff’s observations from the operating experience reviewed during 

the AMP audit. As noted in the “Aging Management Programs Audit Report Regarding 

the Fermi 2 Nuclear Power Plant (TAC No. MF4222)” (ADAMS Accession 

No. ML15030A229), CARD 10-22385, CARD 12-27792, and CARD 09-26756 identified 

the presence of leaching in the RHR complex, auxiliary building basement, and reactor 

building subbasement. The applicant described the condition as leaching due to 

groundwater in-leakage and concluded that the identified conditions do not affect the 

structural integrity of the structures. To clarify the inconsistency between the staff’s 

observation and the applicant’s response, the staff reviewed the CARDs referenced in 

the applicant’s response during its onsite inspection of the applicant’s license renewal 

activities. The staff confirmed that several of the identified conditions by the applicant 

are associated with leaching, consistent with the staff’s observations made during the 

AMP audit. The staff notes that the applicant will perform further testing and evaluation 

for these identified conditions before the period of extended operation to confirm that 

existing conditions are not the result of leaching of calcium and carbonation that could 

impact the intended function(s) of the concrete structures (Commitment No. 34n). 

The staff also notes that the applicant’s response includes an enhancement to the 

Structures Monitoring Program (Commitment No. 34m) to manage the potential aging 

effect of increase in porosity and permeability and loss of strength due to leaching of 

calcium hydroxide and carbonation for accessible areas based on testing and evaluation 

of observed conditions of in-leakage (water and mineral deposits). The staff finds that 

the use of this same enhancement to detect degradation for concrete elements in 

inaccessible areas based on observed conditions in accessible areas allows the 

applicant to manage the potential for these aging effects before a loss of intended 

function. However, during the staff’s review of components associated with LRA 

Table 3.5.1, items 3.5.1-47 and 3.5.1-63, the staff noted that this enhancement appears 

to be inconsistent or in conflict with LRA Table 3.5.1 AMR items because they continue 

to be identified as “not applicable.” Therefore, by letter dated April 22, 2015, the staff 

issued followup RAI 3.5.2.2.2.1-3a, requesting that the applicant clarify and/or reconcile 

the inconsistencies between LRA Commitment Nos. 34m and 34n, and the 

nonapplicability of LRA Table 3.5.1, items 3.5.1-47 and 3.5.1-63, and provide the 

Table 2 AMR items for the structures and components associated with this aging effect. 

Otherwise, the staff requested that the applicant provide its technical basis to justify why 

LRA Table 3.5.1, items 3.5.1-47 and 3.5.1-63, continue to remain “not applicable.” 

In its response dated May 19, 2015, the applicant stated that the aging effects of 

increase in porosity and permeability and loss of strength due to leaching of calcium 

hydroxide and carbonation are applicable to Groups 1–5 and 7–9 concrete structures. 

The applicant revised LRA Table 3.5.1, items 3.5.1-47 and 3.5.1-63, to indicate that the 

aging effects are applicable and will be managed by the Structures Monitoring Program. 

The applicant also revised LRA Section 3.5.2.2.2.1, item 4, and LRA Tables 3.5.2-1 and 

3.5.2-3 for consistency. 

The staff finds the applicant’s response acceptable because the applicant clarified that 

these aging effects associated with LRA Table 3.5.1, items 3.5.1-47 and 3.5.1-63, are 

applicable and will be managed by the Structures Monitoring Program for Groups 1–5 

and 7–9 concrete structures and provided revisions to the LRA to indicate its applicability 

consistent with the GALL Report recommendation. The staff’s concern described in 

followup RAI 3.5.2.2.2.1-3a is resolved. 
3-425 

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in 

SER Section 3.0.3.2.22. The staff noted that the Structures Monitoring Program is 

enhanced to include testing and evaluation of water/mineral deposits where in-leakage is 

observed in concrete elements and to determine whether leaching of calcium hydroxide 

and carbonation are occurring that could impact the intended function of the concrete 

structures. The staff also notes that the Structures Monitoring Program proposes to 

manage these aging effects in inaccessible concrete areas when observed conditions in 

accessible areas indicate that significant degradation may be occurring in the 

inaccessible area. The staff finds that the applicant has met the further evaluation 

criteria and that its proposal to manage the effects of aging using the Structures 

Monitoring Program is acceptable because (1) it will ensure that these aging effects are 

adequately managed before loss of intended function and (2) the proposed program for 

the inaccessible area is consistent with the AMP recommended by the GALL Report for 

the same aging effects and mechanisms for accessible areas. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.2.1, item 4, criteria. For those items associated with LRA 

Section 3.5.2.2.2.1.4, the staff concludes that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Reduction of Strength and Modulus Due to Elevated Temperature. LRA Section 3.5.2.2.2.2, 

associated with LRA Table 3.5.1, item 3.5.1-48, addresses Groups 1–5 concrete structures 

exposed to an air-indoor uncontrolled environment which will be managed for reduction of 

strength and modulus due to elevated temperature by the Structures Monitoring Program. The 

criteria in SRP-LR Section 3.5.2.2.2.2 recommend further evaluations for any concrete elements 

that exceed specified temperature limits. The SRP-LR also states that the GALL Report 

recommends further evaluation of a plant-specific program if any portion of the safety-related 

and other concrete structures exceeds specified temperature limits (i.e., a general area 

temperature greater than 150 °F and a local area temperature greater than 200 °F). However, 

higher temperatures may be allowed if tests and/or calculations are provided to evaluate the 

reduction in strength and modulus of elasticity and if these reductions are applied to the design 

calculations. The applicant addressed the further evaluation criteria of the SRP-LR by stating 

that Fermi 2 Groups 1–5 concrete structures are not exposed to temperatures exceeding the 

limits described in the GALL Report, except for the main steam tunnel (pipe tunnel) in the 

turbine building. 

The applicant stated that for LRA Table 3.5.1, item 3.5.1-48, the applicability is limited to the 

concrete of the main steam tunnel (pipe tunnel) in the turbine building exposed to an air-indoor 

uncontrolled environment. The staff reviewed UFSAR Section 9.4 and confirmed that Fermi 2 

ventilation systems are designed to maintain the general area temperature of structures below 

150 °F during normal operation with an exception for the turbine building steam tunnel area. 

The staff also noted that UFSAR Section 3.8.2.1.3.1 provides design consideration to limit the 

concrete local area temperatures to less than 150 °F for a pipe sleeve penetration adjacent to 

concrete and to limit the fluid temperatures in pipelines to less than 150 °F when an unsleeved 

penetration is use. The staff’s review confirmed that no in-scope concrete exposed to an 

air-indoor uncontrolled environment is present in the structures except for the main steam tunnel 

(pipe tunnel) in the turbine building, as specified in LRA Section 3.5.2.2.2.2. 
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In its review of components associated with LRA Table 3.5.1, item 3.5.1-48, the staff noted that 

sufficient information had not been provided to adequately address the further evaluation criteria 

and to determine whether the Structures Monitoring Program would adequately manage the 

aging effect of “changes in material properties” due to elevated temperatures at the turbine 

building main steam tunnel. Therefore, by letter dated November 25, 2014, the staff issued 

RAI 3.5.2.2.2.2-1, requesting that the applicant clarify whether a reduction in strength and 

modulus of elasticity was applied in the design calculations of Fermi 2 Group 1–5 concrete 

structures exposed to local and/or general area temperatures above the limits specified in the 

GALL Report and, if it was not applied in the design calculations, explain how the Structures 

Monitoring Program will adequately manage this aging effect. 

In its response dated December 26, 2014, the applicant stated that a reduction in strength and 

modulus of elasticity was not applied in the design calculations of Fermi 2 Group 1–5 concrete 

structures exposed to general area temperatures above 150 °F or local area temperatures 

above 200 °F. The applicant further stated that that the Structures Monitoring Program will 

adequately manage the aging effects of reduction of strength and modulus of elasticity due to 

elevated temperature by addressing the aging effects of loss of material, cracking, and change 

in material properties and by monitoring parameters to manage this aging effects on exposed 

concrete surfaces. The acceptance criteria include the absence of spalling, cracking, and other 

physical damages consistent with the parameters identified in ACI 349.3R-02, “Evaluation of 

Existing Nuclear Safety-Related Concrete Structures,” dated January 1, 2002, for concrete 

degradations due to external exposure. The applicant revised LRA Table 3.5.1, item 3.5.1-48, 

to reflect these changes. 

In its review of the applicant’s response, the staff determined that additional information was 

needed to evaluate the adequacy of the applicant’s plant-specific activities to manage the aging 

effects of “reduction of concrete strength and modulus due to elevated temperature” for the 

main steam pipe tunnel concrete in the turbine building because of the following concerns: 

 It was not clear how the applicant's Structures Monitoring Program will be capable of 

detecting the presence and extent of the aging effects of reduction in concrete strength 

and modulus of elasticity (change in material properties) due to long-term exposure to 

elevated temperatures by visual inspection of the condition of the exposed concrete 

surface (parameters monitored) because there may be no visible physical manifestation 

(e.g., spalling, scaling, and cracking) indicative of reduction of concrete strength and 

modulus of elasticity under prolonged exposure to elevated temperatures below 300 °F 

(EPRI TR-103842 and SRP-LR Section 3.5.2.2.2.2). 

 The Structures Monitoring Program described in LRA Sections A.1.42 and B.1.42 and 

audited by the staff did not appear to address the plant-specific program aspect related 

to the “reduction in concrete strength and modulus due to elevated temperature” aging 

effect for which visible symptoms are not likely to manifest at temperatures below 

300 °F. 

 The LRA component intended functions for the concrete main steam pipe tunnel 

appeared to indicate that the structure supports equipment loads. The applicant claimed 

consistency with the GALL Report, but the response to RAI 3.5.2.2.2.2-1 did not address 

the GALL Report, item III.A3.TP-114, recommendation that if significant equipment loads 

are supported by the concrete at temperatures exceeding 150 °F, an evaluation of its 

ability to withstand the postulated design loads must be made. 
3-427 

Therefore, by letter dated April 22, 2015, the staff issued followup RAI 3.5.2.2.2.2-1a, requesting 

that the applicant provide information with a technical basis to address the following activities: 

 Demonstrate the adequacy of the parameters proposed to be monitored or inspected by 

the plant-specific aspect of the Structures Monitoring Program to detect, quantify extent, 

and manage the aging effects of “reduction of concrete strength and modulus due to 

elevated temperature” of the main steam pipe tunnel concrete. 

 Clearly establish the link between the parameters proposed to be monitored and explain 

how monitoring these parameters will ensure adequate aging management of the 

“reduction of concrete strength and modulus due to elevated temperature” before loss of 

intended functions of the main steam pipe tunnel concrete such that CLB design 

conditions will be maintained during the period of extended operation. 

 Address the GALL Report, item III.A3.TP-114, recommendation that if significant 

equipment loads are supported by the concrete at temperatures exceeding 150 °F, an 

evaluation of its ability to withstand the postulated design loads must be made. 

 Ensure consistency of applicable LRA program elements, UFSAR supplement, and/or 

AMR tables, as appropriate, with the response to the requests above. 

In its response dated May 19, 2015, the applicant stated that Fermi 2 had conservatively 

assumed the turbine building steam tunnel concrete temperature to be above the temperature 

criteria of the GALL Report. The applicant also stated that a review of temperature data from a 

recent cycle during normal operation confirmed that sustained bulk air temperatures in the 

turbine building steam tunnel are below the GALL Report threshold. The applicant further 

stated that local area temperature of the concrete is not above the 200 °F threshold from the 

ACI 349 recommended provision. Therefore, the applicant stated that reduction in strength and 

modulus for accessible and inaccessible concrete is not an AERM. As a result, the applicant 

revised LRA Sections 3.5.2.1.3 and 3.5.2.2.2.2 and LRA Table 3.5.1, item 48, and LRA 

Table 3.5.2-3 to indicate that the aging effect is not applicable to the turbine building steam 

tunnel concrete. 

Considering the applicant’s responses to followup RAI 3.5.2.2.2.2-1a, the staff notes that the 

concrete elements are not exposed to the environment necessary for this aging effect to occur 

and that further evaluation is not required to be addressed, as recommended by the GALL 

Report. The staff finds the applicant’s response acceptable because the technical justification 

provided clarifies that sustained air temperatures for local and general areas in the turbine 

building steam tunnel are below the GALL Report threshold. The staff’s concern described in 

followup RAI 3.5.2.2.2.2-1a is resolved. 

Aging Management of Inaccessible Areas for Group 6 Structures. 

(1) LRA Section 3.5.2.2.2.3, item 1, associated with LRA Table 3.5.1, item 3.5.1-49, 

addresses below-grade inaccessible concrete areas of Group 6 structures exposed to an 

air-outdoor environment, which will be managed for loss of material (spalling, scaling) 

and cracking due to freeze-thaw by the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program. The criteria in SRP-LR 

Section 3.5.2.2.2.3, item 1, state that further evaluation of this aging effect is 

recommended for inaccessible areas of this group of structures for plants located in 

moderate to severe weathering conditions. The SRP-LR also states that a plant-specific 

program is not required if documented evidence confirms that the existing concrete had 
3-428 

air content of 3 percent to 8 percent and if subsequent inspection did not exhibit 

degradation related to freeze-thaw. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program manages loss of material 

(spalling, scaling) and cracking due to freeze-thaw in below-grade (above the frost line) 

concrete for Fermi 2 Group 6 concrete structures. As stated in the applicant’s response 

to RAI 3.5.2.2.2.1-1, dated October 24, 2014, documented in SER Section 3.5.2.2.2, the 

applicant will perform visual inspections of inaccessible areas when they become 

accessible as a result of an excavation activity and when observed conditions in 

accessible areas indicate that significant degradation may be occurring in the 

inaccessible area. 

The staff’s evaluation of the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program is documented in SER 

Section 3.0.3.2.20. The staff noted that the applicant implemented the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program 

as part of the Structures Monitoring Program. The staff also noted that, consistent with 

the GALL Report recommendation, LRA Table 3.5.1, item 3.5.1-60, manages loss of 

material (spalling, scaling) and cracking due to freeze-thaw in accessible concrete areas 

of Group 6 structures using the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program. In its review of components associated 

with LRA Table 3.5.1, item 3.5.1-49, the staff finds that the applicant has met the further 

evaluation criteria and that its proposal to manage the effects of aging using the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program is acceptable because (1) the program is consistent with the AMP 

recommended by the GALL Report for managing this aging effect in accessible areas for 

this group of structures, (2) management of this aging effect through visual inspection of 

inaccessible areas, when they become accessible for any reason, and through use of 

the observed condition from accessible areas as an indicator is consistent with the GALL 

Report recommendation to adequately manage concrete degradation due to freeze-thaw 

before there is a loss of intended function, and (3) past inspections from exposed 

inaccessible areas have not revealed concrete structural degradation attributed to 

freeze-thaw. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.2.3, item 1, criteria. For those items associated with LRA 

Section 3.5.2.2.2.3.1, the staff concludes that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

(2) LRA Section 3.5.2.2.2.3, item 2, associated with LRA Table 3.5.1, item 3.5.1-50, 

addresses inaccessible concrete of Group 6 structures exposed to air-outdoor, air-indoor 

uncontrolled, soil, and fluid environments, which will be managed for cracking due to 

expansion from reaction with aggregates by the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program. The criteria in SRP-LR 

Section 3.5.2.2.2.3, item 2, state that cracking due to expansion from reaction with 

aggregates could occur in below-grade inaccessible concrete areas of Group 6 

structures exposed to any environment. The GALL Report recommends further 

evaluation to determine whether a plant-specific program is required to manage the 

aging effect. The SRP-LR also states that a plant-specific program is not required if 

(1) investigations, tests, and petrographic examinations of aggregates performed in 
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accordance with ASTM C295 and other ASTM reactivity tests, as required, can 

demonstrate that those aggregates do not adversely react within reinforced concrete or 

(2) for potentially reactive aggregates, aggregate reinforced concrete reaction is not 

significant if the structure was constructed in accordance with ACI 318. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that Fermi 2 Group 6 

concrete structures are designed and constructed in accordance with the 

recommendations of ACI 318-63 and/or ACI 318-71; however, based on ongoing 

industry operating experience, the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program manages this aging effect for 

below-grade inaccessible concrete areas. 

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program is documented in SER 

Section 3.0.3.2.20. The staff noted that the applicant implemented the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program 

as part of the Structures Monitoring Program. The staff also noted that the use of the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program through the Structures Monitoring Program to manage this aging effect is 

consistent with the recommendations of the GALL Report to manage the same 

structures/aging effect combinations in accessible areas. The staff reviewed UFSAR 

Section 3.8.4.6.1 and confirmed that Fermi 2 concrete structures are designed and 

constructed in accordance with the recommendations in ACI 318. Based on its review of 

components associated with item 3.5.1-50 for which the applicant cited generic note E, 

the staff finds that the applicant has met the further evaluation criteria and that its 

proposal to manage the effects of aging using the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program is acceptable because (1) the 

program is consistent with the AMP recommended by the GALL Report for managing 

this aging effect in accessible areas for similar groups of structures, (2) these structures 

are designed and constructed in accordance with the recommendations in ACI 318, and 

(3) past inspections from exposed inaccessible areas have not revealed concrete 

structural degradation attributed to expansion and reaction with aggregates. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.2.1, item 2, criteria. For those items associated with LRA 

Section 3.5.2.2.2.1.2, the staff concludes that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

(3) LRA Section 3.5.2.2.2.3, item 3, associated with LRA Table 3.5.1, item 3.5.1-51, 

addresses inaccessible concrete areas of Group 6 structures exposed to a fluid 

environment, which will be managed for increase in porosity and permeability and loss of 

strength by the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program. The criteria in SRP-LR Section 3.5.2.2.2.3, item 3, state 

that increase in porosity and permeability due to leaching of calcium hydroxide and 

carbonation could occur in below-grade inaccessible concrete areas of Group 6 

structures exposed to a water flowing environment. The GALL Report recommends 

further evaluation to determine whether a plant-specific program is required to manage 

the aging effect. The GALL Report also states that a plant-specific AMP is not required 

if (1) there is evidence in the accessible areas that the flowing water has not caused 

leaching and carbonation or (2) evaluation determined that the observed leaching of 

calcium hydroxide and carbonation in accessible areas has no impact on the intended 
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function of the concrete structure. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program manages this aging effect for 

below-grade inaccessible concrete areas. 

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program is documented in SER 

Section 3.0.3.2.20. The staff noted that the applicant implements the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program 

as part of the Structures Monitoring Program. The staff also noted that, consistent with 

the GALL Report recommendation, LRA Table 3.5.1, item 3.5.1-61, manages increase in 

porosity and permeability and loss of strength due to leaching of calcium hydroxide and 

carbonation in accessible concrete areas of Groups 6 structures using the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program. 

In its review of components associated with item 3.5.1-51, the staff finds that the 

applicant has met the further evaluation criteria and that its proposal to manage the 

effects of aging using the RG 1.127, Inspection of Water-Control Structures Associated 

with Nuclear Power Plants Program is acceptable because (1) this program is consistent 

with the AMP recommended by the GALL Report for managing this aging effect in 

accessible areas for this group of structures and (2) management of this aging effect 

through (1) visual inspection of inaccessible areas when they become accessible for any 

reason, (2) use of the observed condition, and (3) employment of further testing and 

evaluation of water/mineral deposits from accessible areas as an indicator is consistent 

with the GALL Report recommendation to adequately manage concrete degradation due 

to leaching and carbonation before there is a loss of intended function. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.2.3, item 3, criteria. For those items associated with LRA 

Section 3.5.2.2.2.3.3, the staff concludes that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and Crevice 

Corrosion. LRA Section 3.5.2.2.2.4, associated with LRA Table 3.5.1, item 3.5.1-52, addresses 

cracking due to SCC and loss of material due to pitting and crevice corrosion in stainless steel 

liners of other components, such as drywell sump, reactor building sump, and turbine building 

sump, exposed to a fluid environment. The criteria in SRP-LR Section 3.5.2.2.2.4 state that 

“cracking due to SCC and loss of material due to pitting and crevice corrosion could occur for 

Group 7 and Group 8 stainless steel tank liners exposed to standing water.” The SRP-LR also 

states that the GALL Report recommends further evaluation of plant-specific programs to 

manage these aging effects for stainless steel tank liners exposed to standing water. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that a plant-specific 

program is not necessary because, for Fermi 2, there are no (Group 7 or Group 8) concrete or 

steel tanks with stainless steel liners included as structures within the scope of license renewal; 

however, the corresponding GALL Report item(s) (e.g., item III.A7.T-23) for concrete tanks can 

be compared to the stainless steel liners of other components, such as sumps in the 

containment drywell, reactor building, and turbine building. These liners can be exposed to a 

fluid environment and may be subjected to loss of material (due to corrosion). The applicant 

also stated that fluid temperatures are below the threshold value of 140 °F (60 °C) for SCC. 

The applicant further stated that the Structures Monitoring Program manages the loss of 

material aging effect for these liners by periodic inspections. 
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The staff notes that fluid temperatures, to which the sump liners are exposed, are below the 

threshold value of 140 °F (60 °C), as indicated in GALL Report Section IX.D for SCC; therefore, 

cracking due to SCC is not an applicable aging effect for these sump liners. For the AMR 

results items in LRA Tables 3.5.2-1 and 3.5.2-3 that cite generic note E, the LRA credits the 

Structures Monitoring Program to manage loss of material for the stainless steel liners of drywell 

sump, reactor building sump, and turbine building sump. The GALL Report recommends the 

evaluation of a plant-specific program to ensure that these aging effects are adequately 

managed; however, the staff notes that the applicant does not have any tanks with stainless 

steel liners included as structures within the scope of license renewal. However, the applicant 

compared the stainless steel liners of other components (drywell sump, reactor building sump 

and turbine building sump) to LRA Table 3.5.1, item 3.5.1-52, and proposed to manage loss of 

material due to corrosion using the Structures Monitoring Program. 

The staff’s evaluation of the applicant’s Structures Monitoring Program, which, with 

enhancements, is consistent with GALL Report AMP XI.S6, is documented in SER 

Section 3.0.3.2.22. The staff noted that the program includes monitoring for loss of material due 

to corrosion for steel structures and components through the use of visual inspections by 

qualified personnel at a frequency not to exceed 5 years. The staff also noted that the program 

contains provisions for increased inspection frequency and trending to ensure that there is no 

loss of intended function between inspections. The staff also noted that the applicant cited 

generic note E in the Table 2’s for components associated with LRA Table 3.5.1, item 3.5.1-52, 

because the GALL Report recommends further evaluation to determine whether a plant-specific 

program is needed to manage the aging effects. In its review of components associated with 

LRA Table 3.5.1, item 3.5.1-52, that cite general note E, the staff finds that the applicant has 

met the further evaluation criteria and that its proposal to manage the effects of aging using the 

Structures Monitoring Program is acceptable because (a) the enhanced program will effectively 

manage loss of material due to corrosion by performing periodic visual inspections of the 

stainless steel sump liners by qualified personnel at intervals not to exceed 5 years and (b) a 

plant-specific program is unnecessary. 

Based on the program identified, the staff determines that the applicant’s program meets 

SRP-LR Section 3.5.2.2.4 criteria. For those items associated with LRA Section 3.5.2.2.4, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

Cumulative Fatigue Damage Due to Fatigue. LRA Section 3.5.2.2.2.5 states that TLAAs are 

evaluated in accordance with 10 CFR54.21(c), as documented in LRA Section 4. For LRA 

Table 3.5.1, item 3.5.1-53, the applicant stated that the AMR item is not applicable because 

there are no fatigue analyses identified for component support members, welds, or support 

anchorage to building structures for Groups B1.1, B1.2, and B1.3. The staff reviewed the LRA 

and UFSAR and confirmed that the applicant’s LRA does not have any AMR results that are 

applicable for this item. 

 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 
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 Ongoing Review of Operating Experience 

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience for AMPs. 

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.5.2-1 through 3.5.2-4, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with, or not addressed 

in, the GALL Report. 

In LRA Tables 3.5.2-1 through 3.5.2-4, the applicant indicated, through notes F through J, that 

the combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections. 

 Reactor/Auxiliary Building and Primary Containment – Summary of Aging 

Management Evaluation – LRA Table 3.5.2-1 

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the 

reactor/auxiliary building and primary containment component groups. 

Coating Exposed to Fluid Environment. In LRA Table 3.5.2-1, the applicant stated that Service 

Level I coatings exposed to a fluid environment will be managed for loss of coating integrity by 

the Protective Coating Monitoring and Maintenance Program. The AMR item cites generic 

note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. Based on its review of GALL Report AMP XI.S8 and 

ASTM D5163-08, “Standard Guide for Establishing a Program for Condition Assessment of 

Coating Service Level I Coating Systems in Nuclear Power Plants,” dated December 2008, 

which indicate that immersion coatings may be susceptible to failure or loss of coating integrity 

due to formation of blisters or nodules, the staff finds that the applicant has identified all credible 

aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Protective Coating Monitoring and Maintenance 

Program is documented in SER Section 3.0.3.2.17. The staff finds the applicant’s proposal to 
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manage loss of coating integrity using the Protective Coating Monitoring and Maintenance 

Program acceptable because the AMP provides an effective method to asses coating condition 

through visual inspections by identifying degraded or damaged coatings and by providing a 

means for repair of identified problem areas. 

On the basis of its review, the staff concludes that for items in LRA Table 3.5.2-1 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

 Water-Control Structures – Summary of Aging Management Evaluation – LRA 

Table 3.5.2-2 

The staff reviewed LRA Table 3.5.2-2, as amended by letter dated December 26, 2014, which 

summarizes the results of AMR evaluations for the water-control structures component groups. 

Asbestos Cement Board from RHR Cooling Tower Fill/Mist Eliminators Exposed to a Fluid 

Environment. In LRA Table 3.5.2-2, as amended by letter dated December 26, 2014, the 

applicant stated that asbestos cement board, which is used as the RHR cooling tower fill/mist 

eliminators, is exposed to a fluid environment and will be managed for loss of material by the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program. The AMR item cites generic note J. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. However, sufficient information had not been provided to 

adequately determine which type of fluid environment the asbestos cement board is exposed to 

in order to consider whether the applicant identified all the credible aging effects for this 

component. The LRA environment description for “exposed to fluid environment” corresponds 

to a broad list of environment types that includes environments with raw water, treated water, 

and/or chemically treated water, which could make cementitious material susceptible to different 

aging effects. Therefore, by letter dated November 25, 2014, the staff issued RAI 3.5.2.3.2-1, 

requesting that the applicant clarify the fluid environment to which the asbestos cement board is 

exposed to, including the water chemistry, and explain why other aging effects relevant to 

cementitious materials are not considered as credible aging effects. 

In its response dated December 26, 2014, the applicant stated that the fluid environment in 

which the asbestos cement boards are exposed is raw water from Lake Erie. The raw water is 

chemically treated for control of microbes, corrosion, and deposits, and its chemistry is 

monitored and maintained within the specified chemical control parameters. The applicant also 

stated that, although in some cases the water chemistry values are above the ranges of the 

original Lake Erie water, values described in the water quality study performed at Fermi 2 

between 2008 and 2009, as described in Table 2, “Summary of Surface Water Quality Data 

Collected at Sampling Location LE1-W,” in the report entitled, “Water Quality Survey, Detroit 

Edison Company, Fermi 3 Project, Final Report,” dated October 2009 (ADAMS Accession 

No. ML093380411), the chlorides and sulfate values are well below the threshold for an 

aggressive chemical attack discussed in the GALL Report. The applicant further stated that 

credible aging effects for the asbestos cement boards do include loss of material due to 

abrasion and cracking due to freeze-thaw. The applicant clarified that other aging effects, like 

cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded 

steel or due to expansion from reaction with aggregates, are not applicable because the 
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asbestos cement board does not have embedded steel and does not have aggregates that 

could potentially expand. The applicant revised the LRA to include the additional aging effects 

of cracking, increase in porosity and permeability, and loss of strength for the asbestos cement 

board in the RHR cooling tower fill/mist eliminator. The applicant made this revision to be 

consistent with the application of aging effects to concrete components and to consider that loss 

of material is already included in LRA Table 3.5.2-2, as amended by letter dated 

December 26, 2014, as an applicable aging effect. 

The staff finds the applicant's response acceptable because it clarifies the fluid environment to 

which the asbestos cement board is exposed and enhances the AMP to manage additional 

aging effects for cracking, increase in porosity and permeability, and loss of strength for the 

asbestos cement board to ensure that there is no loss of intended function between inspections. 

Based on a review of the GALL Report recommendations, the staff finds that the applicant 

identified all credible aging effects for a cementitious material exposed to a chemically treated 

raw water environment. The staff noted that the applicant’s consideration of the asbestos 

cement boards as a concrete component is consistent with the description of asbestos cement 

in GALL Report Table IX.C as a cementitious material having cementing properties similar to 

concrete. The staff's concern described in RAI 3.5.2.3.2-1 is resolved. 

The staff's evaluation of the applicant's RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program is documented in SER Section 3.0.3.2.20. The 

staff noted that the applicant implements the planned to be enhanced RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program as part of the 

Structures Monitoring Program and includes monitoring for loss of material, loss of bond, 

increase in porosity and permeability, and loss of strength on concrete structures and 

components associated with water-control structures with inspection frequencies not to exceed 

5 years. The staff’s review and evaluation of the Structures Monitoring Program is documented 

in SER Sections 3.03.2.22. The staff finds the applicant's proposal to manage the effects of 

aging using the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear 

Power Plants Program acceptable because the program provides for periodic visual inspections 

at specified frequencies to identify loss of material, cracking, increase in porosity and 

permeability, and loss of strength in the asbestos cement board consistent with GALL Report 

AMP XI.S7 and before there is a loss of component’s intended function. 

On the basis of its review, the staff concludes that for items in LRA Table 3.5.2-2 with an AERM, 

as amended by letter dated December 26, 2014, the applicant has demonstrated that the effects 

of aging will be adequately managed so that their intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

 Turbine Building, Process Facilities, and Yard Structures – Summary of Aging 

Management Evaluation – LRA Table 3.5.2-3 

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the 

turbine building, process facilities, and yard structures component groups. The staff’s review 

did not identify any AMR items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERMs for the turbine building, process facilities, 

and yard structures component groups are consistent with the GALL Report. 
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 Bulk Commodities – Summary of Aging Management Evaluation – LRA 

Table 3.5.2-4 

The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the 

bulk commodities component groups. 

Carborundum Durablanket, Carborundum Fibersil Cloth, Fiberboard, Thermo-lag®, Silicon 

Elastomer, and Elastomer Fire Stops and Fire Wraps Exposed to Uncontrolled Indoor Air. In 

LRA Table 3.5.2-4, the applicant stated that carborundum durablanket, carborundum fibersil 

cloth, fiberboard, Thermo-lag®, silicone elastomer, and elastomer fire stops and fire wraps 

exposed to uncontrolled indoor air will be managed for loss of material, change in material 

properties, cracking, delamination, and separation by the Fire Protection Program. The AMR 

item cites generic note J. 

The staff noted that in Enhancement 2 to the Fire Protection Program, the applicant stated that 

it will revise procedures to require visual inspections of in-scope fire wrap and fire stop materials 

constructed of fibersil cloth, cerafoam, kaowool, Thermo-lag®, Flamemastic®, and Pyrocrete®; 

however, LRA Table 3.5.2-4 does not appear to include AMR items for these materials. 

Therefore, by letter dated December 17, 2014, the staff issued RAI 3.5.2-1, requesting that the 

applicant state whether cerafoam, kaowool, Flamemastic®, and Pyrocrete® are used as fire 

stops or fire wraps at Fermi 2 and, if so, explain how the effects of aging of these components 

and materials will be managed. 

By letter dated January 15, 2015, the applicant stated that it inadvertently included cerafoam, 

kaowool, Flamemastic®, and Pyrocrete® as fire wrap and fire stop materials in the 

enhancements. The applicant revised the enhancement to remove the specific materials that 

are not installed in the plant. 

The staff finds the applicant’s response acceptable because the applicant revised the 

enhancement to remove materials that are not installed in the plant. Because the enhancement 

now generically refers to in-scope fire wrap and fire stop materials, the staff has reasonable 

assurance that all in-scope fire wrap and fire stop materials will be inspected. Therefore, the 

staff’s concern in RAI 3.5.2-1 is resolved. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for the component, material, 

and environment description. Although the GALL Report does not have any AMR items for 

nonmetallic fire barriers (e.g., fire stops), the staff noted that GALL Report AMP XI.M26, “Fire 

Protection,” does include aging management of fire resistant materials within the scope of the 

AMP. GALL Report AMP XI.M26 recommends that these materials be managed for loss of 

material and cracking, increased hardness, shrinkage, and loss of strength. Based on its review 

of the GALL Report, the staff finds that the applicant has identified all credible aging effects for 

these component, material, and environment combinations. 

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.2.9. The staff finds the applicant’s proposal to manage the effects of aging using 

the Fire Protection Program acceptable because the program includes visual inspections of fire 

barriers (e.g., fire stops and fire wraps) of various material types that are capable of detecting 

degradation of the fire barrier before loss of intended function. 
3-436 

Fiberglass, Calcium Silicate, Fiberfrax, Fiberfrax Ceramic Fiber Durablanket, and Insulfrax 

Insulation Exposed to an Air-Indoor Uncontrolled Environment. In LRA Table 3.5.2-4, the 

applicant stated that insulations of fiberglass, calcium silicate, Fiberfrax®, Fiberfrax® ceramic 

fiber durablanket, and Insulfrax® exposed to an air-indoor uncontrolled environment will be 

managed for loss of material and changes in material properties by the Structures Monitoring 

Program. The AMR item cites generic note J. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. However, sufficient information had not been provided to 

understand how the Structures Monitoring Program adequately manages the aging effects for 

this component group to maintain the intended function of “providing insulating characteristics to 

reduce heat transfer.” Therefore, by letter dated December 19, 2014, the staff issued 

RAI B.1.16-2, requesting that the applicant describe the insulation configuration and the 

activities in the Structures Monitoring Program that will be used to manage reduced thermal 

insulation resistance due to moisture intrusion, state whether the jacketing had been installed 

with procedures that include insulation configuration controls if the insulation is jacketed, and 

describe the parameters that will be monitored or inspected to ensure that the thermal function 

of the insulation is maintained. 

In its response dated January 28, 2015, the applicant stated that the AMR item in LRA 

Table 3.5.2-4 will be revised to include insulation degradation due to moisture intrusion as an 

AERM and will reference the External Surfaces Monitoring Program as the AMP. By letter 

dated April 17, 2015, the applicant further revised this AMR item to reference both the External 

Surfaces Monitoring Program and the PSPM Program. The staff finds the applicant’s proposal 

to manage the effects of aging using the combination of these two programs acceptable. The 

staff’s evaluation of the applicant’s PSPM Program is documented in SER Section 3.0.3.3.1. 

The staff’s evaluation of the response to RAI B.1.16-2 is documented in SER Section 3.0.3.2.7. 

On the basis of its review, the staff concludes that for items in LRA Table 3.5.2-4 with an AERM, 

the applicant has demonstrated that the effects of aging will be adequately managed so that 

their intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3). 

3.5.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effect of aging for the containments, structures, and component supports components within 

the scope of license renewal and subject to an AMR will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.6 Aging Management of Electrical and Instrumentation and Controls System 

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

electrical and instrumentation and control (I&C) system components and commodity groups of 

the following items: 

 high-voltage insulators 

 non-EQ insulted cable and connections 
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 cable connections (metallic parts) 

 electrical cables and connections not subject to 10 CFR 50.49 EQ requirements 

 electrical cables not subject to 10 CFR 50.49 EQ requirements used in 

instrumentation circuits 

 electrical and I&C penetration cables and connections not subject to 10 CFR 50.49 

EQ requirements 

 fuse holders (insulation material) 

 non-EQ fuse holders (metallic portion) 

 inaccessible power (400 V to 13.8 kV) cables (e.g., installed underground in 

conduit, duct bank or direct buried) not subject to 10 CFR 50.49 EQ requirements 

 metal enclosed bus 

 switchyard bus and connections 

 transmission conductors and connections 

3.6.1 Summary of Technical Information in the Application 

LRA Section 3.6 provides AMR results for the electrical and I&C system components and 

component groups. LRA Table 3.6.1, “Summary of Aging Management Programs for the 

Electrical and I&C Components Evaluated in Chapter VI of NUREG-1801,” is a summary 

comparison of the applicant’s AMRs with those evaluated in the GALL Report for the electrical 

and I&C system components and component groups. 

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report. 

3.6.2 Staff Evaluation 

The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the electrical and I&C system 

components, within the scope of license renewal and subject to an AMR, will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

The staff conducted a review of the applicant’s AMRs to confirm its claim that certain AMRs are 

consistent with the GALL Report, not applicable, or not used. The staff did not repeat its review 

of the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA is applicable and that the applicant identified the appropriate GALL Report 

AMRs. The AMRs that the staff confirmed are consistent with the GALL Report are noted as 

such in SER Table 3.6-1, and no further discussion is required. The AMRs that the staff 

confirmed are not applicable to Fermi 2 or not used, because the component, material, and 

environment combination described in the SRP-LR does not exist for in-scope SCs at Fermi 2 or 

because the component, material, and environment combination is addressed by another SER 

Table 3.5-1 item, or require no aging management are noted in SER Table 3.6-1 and are 

discussed in SER Section 3.6.2.1.1. 
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During its review, the staff also reviewed AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

are consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff’s evaluations of 

AMRs for which the GALL Report recommends further evaluation are documented in SER 

Section 3.6.2.2. 

The staff also conducted a technical review of the remaining AMRs not consistent with, or not 

addressed in, the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed are appropriate for the 

material-environment combinations specified. The staff’s evaluations of AMRs not consistent 

with, or not addressed in, the GALL Report are documented in SER Section 3.6.2.3. 

SER Table 3.6-1 summarized the staff’s evaluation of components, aging effects or 

mechanisms, and AMPs listed in LRA Section 3.6 and addressed in the GALL Report. 

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls in the 

GALL Report 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Electrical equipment 

subject to 

10 CFR 50.49 EQ 

requirements 

composed of various 

polymeric and 

metallic materials 

exposed to adverse 

localized 

environment caused 

by heat, radiation, 

oxygen, moisture, or 

voltage (3.6.1-1) 

Various aging 

effects due to 

various 

mechanisms in 

accordance with 

10 CFR 50.49 

EQ is a time-limited 

aging analysis 

(TLAA) to be 

evaluated for the 

period of extended 

operation. See the 

Standard Review 

Plan, Section 4.4, 

“Environmental 

Qualification (EQ) of 

Electrical 

Equipment,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1)(i) 

and (ii). 

See Chapter X.E1, 

“Environmental 

Qualification (EQ) of 

Electric 

Components,” of this 

report for meeting 

the requirements of 

10 CFR 54.21(c)(1) 

(iii). 

Yes, TLAA EQ equipment is 

not subject to 

aging 

management 

review because 

the equipment is 

subject to 

replacement 

based on a 

qualified life. 

Consistent with the 

GALL Report 

(see SER 

Sections 3.6.2.2.1 

and 4.4) 

High-voltage 

insulators composed 

of porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

air – outdoor 

(3.6.1-2) 

Loss of material 

due to 

mechanical wear 

caused by wind 

blowing on 

transmission 

conductors 

A plant-specific aging 

management 

program is to be 

evaluated 

Yes, plant 

specific 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.2.2) 
3-439 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

High-voltage 

insulators composed 

of porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

air – outdoor 

(3.6.1-3) 

Reduced 

insulation 

resistance due 

to presence of 

salt deposits or 

surface 

contamination 

A plant-specific aging 

management 

program is to be 

evaluated for plants 

located such that the 

potential exists for 

salt deposits or 

surface 

contamination 

(e.g., in the vicinity of 

salt water bodies or 

industrial pollution) 

Yes, plant 

specific 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.2.2) 

Transmission 

conductors 

composed of 

aluminum; steel 

exposed to air – 

outdoor (3.6.1-4) 

Loss of 

conductor 

strength due to 

corrosion 

A plant-specific aging 

management 

program is to be 

evaluated for ACSR 

Yes, plant 

specific 

Consistent with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

(see SER 

Section 3.6.2.2.3) 

Transmission 

connectors 

composed of 

aluminum; steel 

exposed to air – 

outdoor (3.6.1-5) 

Increased 

resistance of 

connection due 

to oxidation or 

loss of pre-load 

A plant-specific aging 

management 

program is to be 

evaluated 

Yes, plant 

specific 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.2.3) 

Switchyard bus and 

connections 

composed of 

aluminum; copper; 

bronze; stainless 

steel; galvanized 

steel exposed to air – 

outdoor (3.6.1-6) 

Loss of material 

due to windinduced 

abrasion; 

Increased 

resistance of 

connection due 

to oxidation or 

loss of pre-load 

A plant-specific aging 

management 

program is to be 

evaluated 

Yes, plant 

specific 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.2.3) 

Transmission 

conductors 

composed of 

aluminum; steel 

exposed to air – 

outdoor (3.6.1-7) 

Loss of material 

due to windinduced 

abrasion 

A plant-specific aging 

management 

program is to be 

evaluated for ACAR 

and ACSR 

Yes, plant 

specific 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.2.3) 

Insulation material 

for electrical cables 

and connections 

(including terminal 

blocks, fuse holders, 

etc.) composed of 

various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-8) 

Reduced 

insulation 

resistance due 

to thermal/ 

thermoxidative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiationinduced 

oxidation; 

moisture 

intrusion 

Chapter XI.E1, 

“Insulation Material 

for Electrical Cables 

and Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements” 

No Non-EQ Insulated 

Cables and 

Connections and 

Environmental 

Qualification (EQ) 

of Electric 

Components 

programs 

Consistent with the 

GALL Report 
3-440 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Insulation material 

for electrical cables 

and connections 

used in 

instrumentation 

circuits that are 

sensitive to reduction 

in conductor 

insulation resistance 

(IR) composed of 

various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-9) 

Reduced 

insulation 

resistance due 

to thermal/ 

thermoxidative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiationinduced 

oxidation; 

moisture 

intrusion 

Chapter XI.E2, 

“Insulation Material 

for Electrical Cables 

and Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used 

in Instrumentation 

Circuits” 

No Non-EQ 

Instrumentation 

Circuits Test 

Review Program 

Consistent with the 

GALL Report 

Conductor insulation 

for inaccessible 

power cables greater 

than or equal to 400 

volts (e.g., installed 

in conduit or direct 

buried) composed of 

various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by significant 

moisture (3.6.1-10) 

Reduced 

insulation 

resistance due 

to moisture 

Chapter XI.E3, 

“Inaccessible Power 

Cables Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements” 

No Non-EQ 

Inaccessible 

Power Cables 

(400 V to 13.8 kV) 

Program 

Consistent with the 

GALL Report 

Metal enclosed bus: 

enclosure 

assemblies 

composed of 

elastomers exposed 

to air – indoor, 

controlled or 

uncontrolled or air – 

outdoor (3.6.1-11) 

Surface 

cracking, 

crazing, scuffing, 

dimensional 

change (e.g., 

“ballooning” and 

“necking”), 

shrinkage, 

discoloration, 

hardening and 

loss of strength 

due to elastomer 

degradation 

Chapter XI.E4, 

“Metal Enclosed 

Bus,” or Chapter 

XI.M38, “Inspection 

of Internal Surfaces 

in Miscellaneous 

Piping and Ducting 

Components” 

No Metal Enclosed 

Bus Inspection 

Program 

Consistent with the 

GALL Report 

Metal enclosed bus: 

bus/connections 

composed of various 

metals used for 

electrical bus and 

connections exposed 

to air – indoor, 

controlled or 

uncontrolled or air – 

outdoor (3.6.1-12) 

Increased 

resistance of 

connection due 

to the loosening 

of bolts caused 

by thermal 

cycling and 

ohmic heating 

Chapter XI.E4, 

“Metal Enclosed Bus”

No Metal Enclosed 

Bus Inspection 

Program 

Consistent with the 

GALL Report 
3-441 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Metal enclosed bus: 

insulation; insulators 

composed of 

porcelain; xenoy; 

thermo-plastic 

organic polymers 

exposed to air – 

indoor, controlled or 

uncontrolled or air – 

outdoor (3.6.1-13) 

Reduced 

insulation 

resistance due 

to thermal/ 

thermoxidative 

degradation of 

organics/thermo

plastics, 

radiationinduced 

oxidation, 

moisture/debris 

intrusion, and 

ohmic heating 

Chapter XI.E4, 

“Metal Enclosed Bus”

No Metal Enclosed 

Bus Inspection 

Program 

Consistent with the 

GALL Report 

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of steel 

exposed to air – 

indoor, uncontrolled 

or air – outdoor 

(3.6.1-14) 

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion 

Chapter XI.E4, 

“Metal Enclosed 

Bus,” or Chapter 

XI.S6, “Structures 

Monitoring” 

No Metal Enclosed 

Bus Inspection 

Program 

Consistent with the 

GALL Report 

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

galvanized steel; 

aluminum exposed to 

air – outdoor 

(3.6.1-15) 

Loss of material 

due to pitting 

and crevice 

corrosion 

Chapter XI.E4, 

“Metal Enclosed 

Bus,” or Chapter 

XI.S6, “Structures 

Monitoring” 

No Metal Enclosed 

Bus Inspection 

Program 

Consistent with the 

GALL Report 

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

various metals used 

for electrical 

connections exposed 

to air – indoor, 

uncontrolled 

(3.6.1-16) 

Increased 

resistance of 

connection due 

to chemical 

contamination, 

corrosion, and 

oxidation (in an 

air, indoor 

controlled 

environment, 

increased 

resistance of 

connection due 

to chemical 

contamination, 

corrosion and 

oxidation do not 

apply); fatigue 

due to ohmic 

heating, thermal 

cycling, 

electrical 

transients 

Chapter XI.E5, “Fuse 

Holders” 

No NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.1.1) 
3-442 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

various metals used 

for electrical 

connections exposed 

to air – indoor, 

controlled or 

uncontrolled 

(3.6.1-17) 

Increased 

resistance of 

connection due 

to fatigue 

caused by 

frequent 

manipulation or 

vibration 

Chapter XI.E5, “Fuse 

Holders” 

No aging 

management 

program is required 

for those applicants 

who can 

demonstrate these 

fuse holders are 

located in an 

environment that 

does not subject 

them to 

environmental aging 

mechanisms or 

fatigue caused by 

frequent 

manipulation or 

vibration 

No NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.1.1) 

Cable connections 

(metallic parts) 

composed of various 

metals used for 

electrical contacts 

exposed to air – 

indoor, controlled or 

uncontrolled or air – 

outdoor (3.6.1-18) 

Increased 

resistance of 

connection due 

to thermal 

cycling, ohmic 

heating, 

electrical 

transients, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation 

Chapter XI.E6, 

“Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements” 

No Non-EQ Cable 

Connections 

Program 

Consistent with the 

GALL Report 

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage composed of 

various metals used 

for electrical contacts 

exposed to air with 

borated water 

leakage (3.6.1-19) 

Increased 

resistance of 

connection due 

to corrosion of 

connector 

contact surfaces 

caused by 

intrusion of 

borated water 

Chapter XI.M10, 

“Boric Acid 

Corrosion” 

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.6.2.1.1) 

Transmission 

conductors 

composed of 

aluminum exposed to 

air – outdoor (3.6.1-

20) 

Loss of 

conductor 

strength due to 

corrosion 

None - for Aluminum 

Conductor Aluminum 

Alloy Reinforced 

(ACAR) 

None NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report,” 

aging effects are 

not applicable to 

Fermi 2. 

Not applicable to 

Fermi 2 (see SER 

Section 3.6.2.2.3) 
3-443 

Component Group 

(SRP-LR Item No.) 

Aging Effect/ 

Mechanism 

Recommended 

AMP in SRP-LR 

Further 

Evaluation 

in SRP-LR 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Fuse holders (not 

part of active 

equipment): 

insulation material, 

metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

insulation material: 

bakelite; phenolic 

melamine or 

ceramic; molded 

polycarbonate; other, 

galvanized steel; 

aluminum, steel 

exposed to air – 

indoor, controlled or 

uncontrolled 

(3.6.1-21) 

None None NA - No 

AEM or 

AMP 

None. Consistent 

with 

NUREG-1801, 

“Generic Aging 

Lessons Learned 

(GALL) Report.” 

Consistent with the 

GALL Report 

3.6.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.6.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the electrical and I&C system components: 

 Metal Enclosed Bus Inspection 

 Non-EQ Cable Connections 

 Non-EQ Inaccessible Power Cables (400 V to 13.8 kV) 

 Non-EQ Instrumentation Circuits Test Review 

 Non-EQ Insulated Cables and Connections 

LRA Table 3.6.2 summarizes AMRs for the electrical and I&C system components and indicates 

AMRs claimed to be consistent with the GALL Report. 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components of these 

GALL Report component groups were bounded by the GALL Report evaluation. 

The applicant provided a note for each AMR item. The notes describe how the information in 

the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

notes A through E, which indicate how the AMR was consistent with the GALL Report. 

Note A indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these AMR items to confirm consistency with the GALL Report and the validity 

of the AMR for the site-specific conditions. 

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the AMP 
3-444 

identified in the GALL Report. The staff audited these AMR items to confirm consistency with 

the GALL Report and confirmed that it had reviewed and accepted the identified exceptions to 

the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant 

was consistent with the AMP identified in the GALL Report and whether the AMR was valid for 

the site-specific conditions. 

Note C indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP is consistent with the AMP identified by the GALL Report. Note C indicates 

that the applicant was unable to find a listing of some system components in the GALL Report; 

however, the applicant identified a different component in the GALL Report that had the same 

material, environment, aging effect, and AMP as the component under review. The staff audited 

these AMR items to confirm consistency with the GALL Report. The staff also determined 

whether the AMR item of the different component applied to the component under review and 

whether the AMR was valid for the site-specific conditions. 

Note D indicates that the component for the AMR item, although different from that in the GALL 

Report, is consistent with the GALL Report for material, environment, and aging effect. In 

addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff 

audited these AMR items to confirm consistency with the GALL Report and confirmed whether 

the AMR item of the different component was applicable to the component under review. The 

staff confirmed whether it had reviewed and accepted the exceptions to the GALL Report AMPs. 

The staff also determined whether the AMP identified by the applicant was consistent with the 

AMP identified in the GALL Report and whether the AMR was valid for the site-specific 

conditions. 

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but a different AMP is credited. The staff audited these AMR 

items to confirm consistency with the GALL Report and determined whether the identified AMP 

would manage the aging effect consistent with the AMP identified in the GALL Report and 

whether the AMR was valid for the site-specific conditions. 

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, the staff did confirm that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows. 

 AMR Results Identified as Not Applicable or Not Used 

For LRA Table 3.6.1, item 3.6.1-19, the applicant claimed that the corresponding AMR item in 

the GALL Report is not applicable because the associated item is only applicable to PWRs. 

The staff reviewed the SRP-LR; confirmed that this item only applies to PWRs; and finds that 

this item is not applicable to Fermi 2, which is a BWR. 

For LRA Table 3.6.1 items discussed below, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable or not used. However, the staff had to review 

sources beyond the LRA and UFSAR or to issue one or more RAIs, or both, to verify the 

applicant’s claim. 

LRA Table 3.6.1, items 3.6.1-16 and 3.6.1-17, address the aging mechanisms and effects for 

fuse holders (metallic portion), including increased resistance of connection due to chemical 
3-445 

contamination, corrosion, and oxidation or fatigue caused by ohmic heating, thermal cycling, 

electrical transients, frequent manipulation, or vibration. The GALL Report recommends GALL 

Report AMP XI.E5, “Fuse Holders,” to manage the following fuse holder (metallic portion) aging 

effects: (a) increased resistance of connection due to chemical contamination, (b) corrosion, 

and (c) oxidation or fatigue caused by ohmic heating, thermal cycling, electrical transients, 

frequent manipulation, or vibration for this component group. 

The applicant stated that these items are not applicable because the non-EQ fuse holders, 

located in the Class IE 260/130 VDC battery system, that support a license renewal function 

and are subject to an AMR are not subjected to an environment that requires aging 

management. 

The staff evaluated the applicant’s claim and finds it acceptable because operating experience, 

license renewal basis documents, and condition reports reviewed and walkdowns performed 

during the audit support the applicant’s claim that the in-scope non-EQ fuse holders installed as 

part of the Class IE 260/130 VDC battery system are not subject to increased resistance of 

connection caused by frequent manipulation; vibration; or thermal fatigue caused by ohmic 

heating, thermal cycling, or electrical transients. Further, the staff finds that fuse holders are not 

located in an environment that would subject them to an environment causing an increased 

resistance of connection caused by chemical contamination, corrosion and oxidation. 

3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended 

In LRA Section 3.6.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the electrical and I&C system components and provides information 

concerning how it will manage the following aging effects: 

 electrical equipment subject to EQ 

 reduced insulation resistance due to presence of any salt deposits and surface 

contamination and loss of material due to mechanical wear caused by wind blowing on 

transmission conductors 

 loss of material due to wind-induced abrasion and fatigue, loss of conductor strength due 

to corrosion, and increased resistance of connection due to oxidation or loss of preload 

 QA for aging management of nonsafety-related components 

 ongoing review of operating experience 

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.6.2.2. The staff’s review of the applicant’s 

further evaluation follows. 

 Electrical Equipment Subject to Environmental Qualification 

LRA Section 3.6.2.2.1 states that EQ is a TLAA, as defined in 10 CFR 54.3. Applicants must 

evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.4 documents the staff’s 

review of the applicant’s evaluation of this TLAA. 
3-446 

 Degradation of Insulator Quality Due to Presence of Any Salt Deposits and Surface 

Contamination and Loss of Material Due to Mechanical Wear 

High-Voltage Insulators Composed of Porcelain, Malleable Iron, Aluminum, Galvanized Steel, 

and Cement Exposed to Outdoor Air. LRA Section 3.6.2.2.2, “Degradation of Insulator Quality 

due to Presence of Any Salt Deposits and Surface Contamination and Loss of Material due to 

Mechanical Wear,” associated with LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3, addresses 

reduced insulation resistance and loss of material in high-voltage insulators exposed to salt 

deposits, surface contamination, and insulator mechanical wear due to wind-induced movement 

of the associated high-voltage insulator transmission conductor. 

The applicant stated in the LRA that this item is not applicable because airborne materials can 

contaminate insulator surfaces, but the buildup of contamination is gradual and is usually 

removed by rain. The applicant also pointed out that the glazed surface of the insulator helps in 

the removal of dust, salt, and industrial effluent contamination. Fermi 2 is not located near the 

seacoast or near other sources of airborne particulates. The applicant therefore concluded that 

reduced insulation resistance due to surface contamination is not an applicable aging effect for 

high-voltage insulators at Fermi 2 and that a plant-specific AMP is not required. 

For LRA Table 3.6.2 items corresponding to LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3, the 

applicant stated that, for high-voltage insulators, mechanical wear and reduced insulation 

resistance and loss of material due to wind and movement of the associated transmission 

conductor are not credible aging effects at Fermi 2 and that a plant-specific AMP is not required 

for these aging effects. The applicant noted in its evaluation that high-voltage insulator wear 

has not been apparent during routine inspections. The applicant also stated that industry 

experience has shown transmission conductors do not normally swing and that movement due 

to substantial wind will subside after a short period. The applicant’s LRA Table 3.6.2 indicates 

that the aging effect in the GALL Report for this component, material, and environmental 

combination is not applicable. The applicant cites generic note I for this item. The staff 

reviewed the associated items in the LRA to confirm that these aging effects are not applicable 

for this component, material, and environmental combination. 

In its review of components associated with LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3, the staff 

noted a discrepancy between LRA Table 3.6.1 and the corresponding items of LRA Table 3.6.2 

in describing high-voltage insulator materials. Table 3.6.2 contradicts Table 3.6.1 in that 

Table 3.6.2 omits malleable iron and aluminum from the list of high-voltage insulator materials. 

LRA Table 3.6.1 is consistent with the SRP-LR Table 3.6.1 with both Table 3.6.1 and SRP-LR 

Table 3.6.1 material descriptions, including malleable iron and aluminum. In a letter dated 

January 14, 2015, the staff issued RAI 3.6.2.2.2-1 requesting that the applicant clarify the 

discrepancy between Tables 3.6.1 and 3.6.2 regarding high-voltage insulator material. 

In its response dated February 12, 2015, the applicant stated that LRA Table 3.6.2, “Electrical 

Components,” will be revised to include the material “aluminum” for high-voltage insulators. The 

applicant noted that malleable iron is implicitly included in LRA Table 3.6.2 because it lists 

galvanized metal, which according to EPRI TR-1013475, “Plant Support Engineering: License 

Renewal Handbook, Revision 1 to EPRI Report 1003057,” dated February 2007, includes 

malleable iron, ductile iron, and drop-forged steel. With the applicant revising Table 3.6.2 to 

include the material component “aluminum” and the clarification provided by EPRI TR-1013475 

to include malleable iron, the staff concludes that the applicant’s evaluation is consistent with 

SRP-LR Section 3.6.2.2.2 criteria for components associated with Table 3.6.1, items 3.6.1-2 

and 3.6.1-3. The staff’s concern described in RAI 3.6.2.2.2-1 is resolved. 
3-447 

In LRA Table 3.6.2 items corresponding to LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3, the 

applicant stated that, for high-voltage insulators, mechanical wear and reduced insulation 

resistance and loss of material due to wind and movement of the associated transmission 

conductors are not applicable and that no AMP is proposed. The applicant’s evaluation 

concluded that a plant-specific AMP is not required because mechanical wear due to wind for 

high-voltage insulators is not an applicable aging effect for Fermi 2 (LRA Table 3.6.2, note I). 

The staff noted that EPRI TR-1003057, “License Renewal Handbook,” dated December 2001, 

states that mechanical wear in insulators is an aging effect for strain and suspension insulators 

in that they are subject to movement. Movement of insulators can be caused by wind blowing 

on the supported transmission conductor, causing it to swing. If this swing is frequent enough, it 

could cause wear in the metal contact point of the insulator string and between an insulator and 

supporting hardware. EPRI TR-1003057 indicates this mechanism is possible but that industry 

operating experience has shown that the transmission conductors are not designed to normally 

swing, and when they do swing (e.g., due to a substantial wind), transmission conductors do not 

continue to swing for a long period of time once the wind has subsided. The staff evaluated the 

applicant’s claim and finds it acceptable because the applicant’s further evaluation was 

performed consistent with SRP-LR Section 3.6.2.2.2 criterion, demonstrating that mechanical 

wear due to wind is not an applicable aging effect for Fermi 2. 

In LRA Table 3.6.2 items corresponding to LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3, the 

applicant’s evaluation concluded that, for high-voltage insulators exposed to salt, dust, or other 

industrial particulates, surface contamination is not an applicable aging effect for Fermi 2. The 

applicant concluded in the LRA that a plant-specific AMP is not required because Fermi 2 is not 

located near the seacoast or other sources of airborne particulate surface contamination. 

The staff also notes that Fermi 2 is not located in the vicinity of neither salt water bodies nor 

industrial pollution; therefore, surface contamination of high-voltage insulators is minimized. In 

addition, rainfall and snow periodically wash away minor contamination, and the glazed insulator 

surface also aids contamination removal. The staff evaluated the applicant’s claim and finds it 

acceptable because the applicant’s evaluation was performed consistent with SRP-LR 

Section 3.6.2.2.2 criterion demonstrating that a reduced insulation resistance aging effect due to 

salt deposits or surface contamination of high-voltage insulators is not an applicable aging 

mechanism requiring management for Fermi 2. 

 Loss of Material Due to Wind Induced Abrasion and Fatigue, Loss of Conductor 

Strength Due to Corrosion, and Increased Resistance of Connection Due to 

Oxidation or Loss of Preload 

Transmission Conductors Composed of Aluminum, Steel Exposed to Air-Outdoor. In LRA 

Table 3.6.2, the applicant stated that, for LRA Table 3.6.1, item 3.6.1-4, transmission 

conductors composed of aluminum exposed to air-outdoor and aging effect/mechanism of loss 

of strength due to corrosion, there is no aging effect and that no AMP is proposed. LRA 

Table 3.6.2 cites generic note C that states, “Component is different, but consistent with 

material, environment, aging effect and AMP listed for NUREG-1801 line item.” 

The applicant stated that at Fermi 2, in-scope transmission conductors are all aluminum 

conductors (AAC), which are not subject to aging management because AAC conductors are 

similar in construction to aluminum conductor aluminum alloy-reinforced (ACAR) transmission 

conductors evaluated in the GALL Report. An AAC transmission conductor consists of 

aluminum alloy wires in a multilayer construction similar to ACAR transmission conductors 
3-448 

except that the AAC conductors do not have an aluminum alloy core. Therefore, the applicant 

concluded that the GALL Report aging effects associated with aluminum conductor steel 

reinforced (ACSR) conductors are not applicable for Fermi 2 AAC transmission conductors. 

The applicant referenced an Ontario Hydro study that included the results of ACSR laboratory 

and field tests, including the evaluation of conductor aging effects due to locations near pollution 

sources and major urban areas. The study reported that the aluminum layers retained their 

original properties to a large degree. This is consistent with GALL Report, item VI.A.LP-46, 

which states that a program is not needed for loss of conductor strength due to corrosion for 

ACAR transmission conductors. The AAC transmission conductors have the same corrosion 

resistant properties as the ACAR transmission conductors. Therefore, the applicant concluded 

that the loss of conductor strength is not an AERM for Fermi 2 AAC transmission conductors for 

the period of extended operation. 

GALL Report Table VIA, item VI.A.LP-46, does not recommend an AMP nor further evaluation 

for transmission conductors of ACAR construction. The applicant stated that AAC conductors 

are similar in construction to ACAR conductors with both types of conductors less susceptible to 

the aging effects for ACSR transmission conductors. Although the applicant’s transmission 

conductor is of a different construction than that described in the GALL Report, the material, 

environment, and aging effect combination is representative of the aging degradation of AAC 

transmission conductor material. The staff finds that the applicant’s evaluation is consistent with 

the GALL Report aging mechanisms/effects with respect to aluminum transmission conductors. 

The staff concludes that the Fermi 2 AAC transmission conductors of the in-scope switchyard 

components have a high degree of corrosion resistance because steel reinforcement is not 

used in this type of conductors. The applicant’s evaluation of AAC transmission conductor 

aging is consistent with GALL Report, item VI.A LP-46, which states that loss of conductor 

strength is not an applicable aging effect for similar transmission conductors. Therefore, the 

staff finds that loss of conductor strength due to corrosion of AAC transmission conductors is 

not an applicable aging effect at Fermi 2. 

LRA Table 3.6.1, item 3.6.1-20, addresses loss of conductor strength due to corrosion in 

transmission conductors composed of aluminum exposed to air-outdoor. The applicant states 

that Table 3.6.1, item 3.6.1-20, is not applicable to Fermi 2 because, as shown in the GALL 

Report, an AMP and further evaluation are not recommended for ACAR-type all-aluminum 

transmission conductors. In addition, SRP-LR Table 3.6-1, “Summary of Aging Management 

Programs for the Electrical Components Evaluated in Chapter V1 of the GALL Report,” ID 20, 

Component, “Transmission Conductors Composed of Aluminum Exposed to Air – Outdoor,” 

also recommends no AMP or further evaluation for this component, material, and environment 

combination. 

Transmission Connectors Composed of Aluminum and Steel Exposed to an Air-Outdoor 

Environment. In LRA Table 3.6.2, the applicant stated that, for LRA Table 3.6.1, item 3.6.1-5, 

transmission connectors composed of aluminum, steel, steel alloy exposed to an air-outdoor 

environment, and aging effect/mechanism of increased resistance of connection due to 

oxidation or loss of preload are not applicable and that no AMP is proposed. The AMR item 

cites generic note I that states, “Aging effect in NUREG-1801 for this component, material, and 

environment combination is not applicable.” 

The applicant stated that switchyard connections can be susceptible to increased resistance 

due to corrosion. Fermi 2 air quality, due to the fact that its location is away from any industrial 
3-449 

facilities and is free from salty moisture, is not a contributing factor to aging degradation due to 

corrosion. At Fermi 2, switchyard connection surfaces are coated with an antioxidant compound 

that provides a corrosion-resistant low electrical resistance connection. Fermi 2 also performs 

quarterly infrared inspections of the switchyard connections. These inspections and absence of 

operating experience problems at Fermi 2 indicate that increased connection resistance due to 

general corrosion and oxidation is not an AERM. 

The applicant stated that due to the design of the transmission switchyard conductors and bus 

bolted connections, torque relaxation (loss of preload) is precluded. The design calls for use of 

Belleville washers and antioxidant compounds to preclude connection degradation due to loss 

of preload. The operating experience at Fermi 2, as indicated by quarterly infrared inspections 

of connections, has confirmed the absence of loss of preload. Therefore, increased connection 

resistance due to loss of preload of transmission conductor connections and switchyard bus 

connections is not an AERM at Fermi 2. 

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s evaluation acceptable in accordance with the review described below. 

The staff’s evaluation concludes that the Fermi 2 switchyard buses are located in an area away 

from industrial air pollution; therefore, the aluminum bus material is not expected to exhibit 

significant aging effects. In addition, switchyard connections employ corrosion inhibitors and 

bolting practices using washers that prevent loss of preload and limit vibration. Therefore, the 

staff concludes that corrosion, oxidation, and loss of preload are not considered an applicable 

aging mechanism for Fermi 2. 

Switchyard Bus Connections Composed of Aluminum, Copper, Bronze, Stainless Steel, 

Galvanized Steel Exposed to Air-Outdoor. In LRA Table 3.6.2, the applicant stated that, for 

LRA Table 3.6.1, item 3.6.1-6, switchyard bus connections composed of aluminum, copper, 

bronze, stainless steel, and galvanized steel exposed to an air-outdoor environment; aging 

effect/mechanism of loss of material due to wind-induced abrasion; and increased resistance of 

connection due to oxidation or loss of preload are not applicable and that no AMP is proposed. 

The AMR item cites generic note I that states, “Aging effect in NUREG-1801 for this component, 

material, and environment combination is not applicable.” 

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s evaluation acceptable in accordance with the review described below. 

The applicant reviewed loss of material (wear) due to wind particulates and vibration caused by 

operation of active switchyard components and concluded that they are not applicable AERMs. 

The staff noted that wind-born particulates have not been shown to be a contributor to loss of 

material. The staff also noted that the switchyard bus is connected to active components by 

short sections of flexible conductors, which dampen the vibration effects caused by operation of 

switchyard components. Therefore, the staff finds that the loss of material (wear) due to wind 

induced abrasion and vibration is not a significant AERM for transmission conductors and 

connections at Fermi 2. 

The applicant stated that switchyard connections can be susceptible to increased resistance 

due to corrosion. Fermi air quality, due to the fact that its location is away from any industrial 

facilities and is free from salty moisture, is not a contributing factor to aging degradation due to 
3-450 

corrosion. At Fermi, switchyard connection surfaces are coated with an antioxidant compound 

that provides a corrosion-resistant low electrical resistance connection. Fermi also performs 

quarterly infrared inspections of the switchyard connections. These inspections and absence of 

operating experience problems at Fermi indicates that increased connection resistance due to 

general corrosion and oxidation is not an AERM. 

The applicant stated that due to the design of the transmission switchyard conductors and bus 

bolted connections, torque relaxation (loss of preload) is precluded. The design calls for use of 

Belleville washers and antioxidant compounds to preclude connection degradation due to loss 

of preload. The operating experience at Fermi, as indicated by quarterly infrared inspections of 

connections, has confirmed the absence of loss of preload. Therefore, increased connection 

resistance due to loss of preload of transmission conductor connections and switchyard bus 

connections is not an AERM at Fermi 2. 

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s evaluation acceptable per the review described below. 

The staff’s evaluation concludes that the Fermi 2 switchyard buses are located in an area away 

from industrial air pollution; therefore, the bus material is not expected to exhibit significant 

aging effects. The staff also noted that wind-born particulates have not been shown to be a 

contributor to loss of material through abrasion. In addition, switchyard connections employ 

corrosion inhibitors and bolting practices using washers that prevent loss of preload and limit 

vibration. Therefore, the staff concludes that abrasion, corrosion, oxidation, and loss of preload 

are not considered an applicable aging mechanism for switchyard bus and connections at 

Fermi 2. 

Transmission Conductors Composed of Aluminum, Steel Exposed to Air-Outdoor. In LRA 

Table 3.6.2, the applicant stated that, for LRA Table 3.6.1, item 3.6.1-7, transmission 

conductors composed of aluminum and steel exposed to an air-outdoor environment and aging 

effect/mechanism of loss of material due to wind-induced abrasion are not applicable and that 

no AMP is proposed. The AMR item cites generic note I that states, “Aging effect in 

NUREG-1801 for this component, material, and environment combination is not applicable.” 

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s evaluation acceptable in accordance with the review described below. 

The applicant reviewed loss of material (wear) due to wind particulates and concluded that they 

are not applicable AERMs. The staff noted that wind-born particulates have not been shown to 

be a contributor to loss of material. Therefore, the staff finds that the loss of material (wear) due 

to wind-induced abrasion is not a significant AERM for transmission conductors and 

connections at Fermi 2. 

On the basis of its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.6.2.2.3 criteria. For those line items that apply to LRA Section 3.6.2.2.3, the staff 

finds that the LRA is consistent with the GALL Report and that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 
3-451 

 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program. 

 Ongoing Review of Operating Experience 

SER Section 3.0.5, “Operating Experience for Aging Management Programs,” documents the 

staff’s evaluation of the applicant’s consideration of operating experience for AMPs. 

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Table 3.6.2, the staff reviewed additional details of the AMR results for material, 

environment, AERM, and AMP combinations not consistent with, or not addressed in, the GALL 

Report. 

In LRA Table 3.6.2, the applicant indicated, through notes F through J, that the combination of 

component type, material, environment, and AERM does not correspond to a line item in the 

GALL Report. The applicant provided further information about how it will manage the aging 

effects. Specifically, note F indicates that the material for the AMR line item component is not 

evaluated in the GALL Report. Note G indicates that the environment for the AMR line item 

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR line item component, material, and environment combination is not evaluated 

in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

line item component, material, and environment combination is not applicable. Note J indicates 

that neither the component nor the material and environment combination for the line item is 

evaluated in the GALL Report. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections. 

 Electrical and I&C Components – Summary of Aging Management Evaluation – 

LRA Table 3.6.2 

The staff reviewed LRA Table 3.6.2, which summarizes the results of AMR evaluations for the 

electrical and I&C components component groups. 

Porcelain, Galvanized Metal, Cement High Voltage Insulators (High Voltage Insulators for SBO 

Recovery) Exposed to Air-Outdoor. In LRA Table 3.6.2, the applicant stated that high-voltage 

insulators, composed of porcelain, malleable iron, aluminum, galvanized steel, and cement 

exposed to an air-outdoor environment, are not applicable and that no AMP is proposed. The 

AMR item cites generic note I, which states that the aging effect in the GALL Report for this 

component, material, and environment combination is not applicable. 

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination. The staff finds the 

applicant’s proposal acceptable based on its further evaluation performed consistent with the 

SRP-LR Section 3.6.2.2.2 criterion. The staff’s evaluation of the applicant’s claim is 

documented in SER Section 3.6.2.2.2. 
3-452 

Transmission Connectors Composed of Aluminum, Steel and Steel Alloy, Switchyard Bus and 

Connections Composed of Aluminum, Steel and Steel Alloy, and Transmission Conductors 

Composed of Aluminum, for SBO Recovery Exposed to Air-Outdoor. In LRA Table 3.6.2, the 

applicant stated that transmission connectors composed of aluminum, steel exposed to an 

air-outdoor environment; switchyard bus and connectors composed of copper, bronze, stainless 

steel, and galvanized steel exposed to an air-outdoor environment; and transmission conductors 

composed of aluminum and steel exposed to an air-outdoor environment are not applicable and 

that no AMP is proposed. The AMR item cites generic note I, which states the aging effect in 

the GALL Report for this component, material, and environment combination is not applicable. 

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for these component, material, and environmental combinations. The staff finds the 

applicant’s proposal acceptable based on the applicant’s further evaluation performed 

consistent with the SRP-LR Section 3.6.2.2.2 criterion. The staff’s evaluation of the applicant’s 

claim is documented in SER Section 3.6.2.2.3. 

Fuse Holders (Not Part of Active Equipment) Metallic Clamps Composed of Various Metals 

Used for Electrical Connections Exposed to Air-Outdoor Controlled or Uncontrolled. In LRA 

Table 3.6.2, the applicant stated that fuse holders (that are not part of active equipment) metallic 

clamps composed of various metals used for electrical connections exposed to an air-indoor 

controlled or uncontrolled environment are not applicable and that no AMP is proposed. The 

AMR item cites generic note I, which states the aging effect in the GALL Report for this 

component, material, and environment combination is not applicable. 

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for these components, material, and environmental combinations. The staff finds the 

applicant’s proposal acceptable based on operating experience, license renewal basis 

documents, condition reports, and walkdowns performed during the audit, which support the 

applicant’s claim that in-scope non-EQ fuse holders installed as part of the Class IE 

260/130 VDC battery system are not subject to the aging mechanisms and effects, as 

referenced by the GALL Report. The staff’s evaluation of the applicant’s claim is documented in 

SER Section 3.6.2.1.1. 

On the basis of its review, the staff concludes that for items in LRA Table 3.6.2 with no AERMs, 

the applicant has appropriately evaluated the material and environment combinations not 

addressed in the GALL Report, and their intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.6.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effect of aging for the electrical and instrumentation and controls components within the 

scope of license renewal and subject to an AMR will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

3.7 Conclusion for Aging Management Review Results 

The staff reviewed the information in LRA Section 3, “Aging Management Review Results,” and 

LRA Appendix B, “Aging Management Programs and Activities.” On the basis of its review of 

the AMR results and AMPs, the staff concludes that the applicant has demonstrated that the 
3-453 

aging effects will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the applicable UFSAR supplement program 

summaries and concludes that the supplement adequately describes the AMPs credited for 

managing aging, as required by 10 CFR 54.21(d). 

The staff concludes that there is reasonable assurance that the applicant will continue to 

conduct the activities authorized by the renewed licenses in accordance with the CLB and any 

changes to the CLB made in order to comply with 10 CFR 54.21(a)(1), in accordance with the 

Atomic Energy Act of 1954, as amended, and in accordance with NRC regulations. 

4-1 

 

TIME-LIMITED AGING ANALYSES 

4.1 Identification of Time-Limited Aging Analyses 

This section of the safety evaluation report (SER) provides the U.S. Nuclear Regulatory 

Commission (NRC) staff (the staff) evaluation of the applicant’s basis for identifying those 

plant-specific or generic analyses that need to be identified as time-limited aging analyses 

(TLAAs) for the applicant’s license renewal application (LRA) and the list of TLAAs for the LRA. 

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined 

by the current operating term. This SER section also provides the staff’s evaluation of the 

applicant’s basis for identifying those exemptions that need to be identified in the LRA. 

Pursuant to the requirements in Title 10 of the Code of Federal Regulations 54.21(c)(1) 

(10 CFR 54.21(c)(1)), an applicant for license renewal must list all evaluations, analyses, and 

calculations in the current licensing basis (CLB) that conform to the definition of a TLAA, as 

defined in 10 CFR 54.3, “Definitions.” 

The NRC regulations in 10 CFR 54.3 state that a plant-specific or generic evaluation, analysis, 

or calculation is a TLAA if it meets all six of the following TLAA identification criteria: 

(1) involves a system, structure, or component (SCC) that is within the scope of license 

renewal, as delineated in 10 CFR 54.4(a) 

(2) considers the effect or effects of aging 

(3) involves time-limited assumptions that are defined by the current operating term 

(e.g., 40 years) 

(4) was determined to be relevant by the applicant in making a safety determination 

(5) involves conclusions, or provides the basis for conclusions, related to the capability of 

the SSC to perform its intended function(s), as described in 10 CFR 54.4(b) 

(6) is contained or incorporated by reference in the CLB 

For each evaluation, analysis, or calculation that is a TLAA, the applicant must demonstrate that 

the TLAA will be acceptable for the period of extended operation in accordance with one of the 

following three acceptance criteria for TLAAs in 10 CFR 54.21(c)(1): 

(i) demonstration that the TLAA will remain valid for the period of extended operation 

(ii) demonstration that the TLAA has been projected to the end of the period of extended 

operation 

(iii) demonstration that the effects of aging on the intended function(s) will be adequately 

managed during the period of extended operation 

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list all plant-specific exemptions in 

the CLB that were granted in accordance with the exemption approval criteria in 10 CFR 50.12, 

“Specific Exemptions,” and that are based on a TLAA. For any such exemptions, the applicant 

must evaluate and justify the continuation of the exemptions for the period of extended 

operation. 
4-2 

The staff’s guidance for reviewing LRA Section 4.1 is given in NUREG-1800, Revision 2, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants” 

(SRP-LR), Section 4.1, “Identification of Time-Limiting Aging Analyses,” dated December 2010. 

SRP-LR Section 4.1.1 summarizes the areas of review. SRP-LR Section 4.1.2 provides the 

staff’s “acceptance criteria” for performing TLAA and LRA exemption identification reviews. 

SRP-LR Section 4.1.3 provides the staff’s “review procedures” for performing the TLAA and 

LRA exemption identification reviews. SRP-LR Table 4.1-1 provides some case-by-case 

examples on whether a given analysis category would be required to be identified as a TLAA for 

an LRA. SRP-LR Table 4.1-2 provides a list of those analyses or calculations that normally are 

part of an applicant’s CLB and that are normally identified as TLAAs (i.e., generic TLAAs). 

SRP-LR Table 4.1-3 provides a list of those analyses or calculations that may be identified as 

plant-specific TLAAs. 

4.1.1 Summary of Technical Information in the Application 

4.1.1.1 Identification of Time-Limited Aging Analyses 

LRA Section 4.1 states that the applicant reviewed and evaluated the analyses and calculations 

in the CLB for Fermi 2, against the six criteria for TLAAs in 10 CFR 54.3. The LRA also states 

that the applicant reviewed the list of TLAAs in the SRP-LR to see if they are applicable to and 

included as part of the applicant’s CLB. The applicant stated that it used the following guidance 

documents as of part of its bases for TLAA identification methodology: (1) SRP-LR, (2) Nuclear 

Energy Institute (NEI) 95-10, “Industry Guideline for Implementing the Requirements of 

10 CFR Part 54 – the License Renewal Rule,” (3) 10 CFR Part 54, “Requirements for Renewal 

of Operating Licenses for Nuclear Power Plants,” (4) NRC SERs, (5) docketed licensing 

correspondence, (6) Fermi 2 updated final safety analysis report (UFSAR), (7) Fermi 2 

Technical Specifications (TS), and (8) industry topical reports (relevant documents referenced in 

the UFSAR or in docketed licensing correspondence). 

The applicant provided its list of TLAAs in LRA Table 4.1-1, “List of TLAAs.” In this table, the 

applicant indicates that the following evaluations, analyses, or calculations in the CLB meet the 

six criteria for TLAAs in 10 CFR 54.3 and are TLAAs for the LRA: 

 reactor vessel neutron embrittlement analyses (LRA Section 4.2) 

 metal fatigue analyses (LRA Section 4.3) 

 environmental qualification (EQ) analyses of electric equipment (LRA Section 4.4) 

 containment liner plate, metal containment, and penetrations fatigue analyses (LRA 

Section 4.6) 

 other plant-specific TLAAs (LRA Section 4.7) 

The applicant provided its bases for accepting these TLAAs in accordance with either 

10 CFR 54.21(c)(1)(i), (ii), or (iii) in the applicable subsections of LRA Sections 4.2 – 4.7. 

The applicant indicates that the following generic evaluations, analyses, or calculations listed in 

SRP-LR Table 4.1-2 are not part of the Fermi 2 CLB and therefore do not need to be identified 

as applicable TLAAs for the LRA: 

 concrete containment tendon prestress analyses 

 inservice local metal containment corrosion analyses 
4-3 

The applicant indicates that the following potentially applicable plant-specific evaluations, 

analyses, or calculations listed in SRP-LR Table 4.1-3 are not part of the Fermi 2 CLB and 

therefore do not need to be identified as applicable TLAAs for the LRA: 

 reactor pressure vessel (RPV) underclad intergranular separation (underclad cracking) 

 low-temperature overpressure protection (LTOP) analyses 

 fatigue analysis for main steam supply lines to the turbine-driven auxiliary feedwater 

(AFW) pumps 

 fatigue analysis of the reactor coolant pump (RCP) flywheels 

 flow-induced vibration endurance limit for the reactor vessel internals (RVIs) 

 ductility reduction of fracture toughness for the RVIs 

 leak-before-break (LBB) 

 metal corrosion allowance 

4.1.1.2 Identification of Exemptions 

The applicant stated that it performed a search in accordance with the exemption approval 

criteria in 10 CFR 50.12 to find any exemptions that were granted for the Fermi 2 CLB and were 

based on a TLAA. The applicant stated it performed its search based on a review of relevant 

licensing basis or design basis information in the UFSAR, American Society of Mechanical 

Engineers (ASME) Code Section XI Program documentation, fire protection documents, 

operating license, TS and docketed correspondence. The applicant stated that it did not find 

any exemptions that were based on a TLAA and will remain in effect for the period of extended 

operation. 

4.1.2 Staff Evaluation 

4.1.2.1 Identification of TLAAs 

The staff reviewed the applicant’s methodology for identifying the TLAAs and the TLAA results 

for the LRA against the six criteria for TLAA identification in 10 CFR 54.3 and the list of TLAAs 

in SRP-LR Section 4.1, including the analyses in SRP-LR Table 4.1-2 that are normally generic 

TLAAs for the U.S. nuclear power industry and the list of analyses in SRP-LR Table 4.1-3 that 

may be plant-specific TLAAs for the industry. The staff used the “acceptance criteria” in 

SRP-LR Section 4.1.2 and the review procedures in SRP-LR Section 4.1.3 as the basis for its 

review. 

To verify the completeness of the applicant’s list of TLAAs, the staff reviewed LRA Appendix C, 

“Response to BWRVIP Applicant Action Items,” which provides the applicant’s responses to 

those applicant action items (AAIs) that were issued by the NRC on the applicant’s bases for 

implementing specific Electric Power Research Institute (EPRI) BWRVIP technical report 

methodologies during the period of extended operation. This review is provided in SER 

Section 4.1.2.1.2. SER Section 3.0.3.2.3 provides the staff’s evaluations of the AAI responses 

that were provided in the LRA for non-TLAA-related topics. 
4-4 

 Evaluations, Analyses, and Calculations in the CLB Conforming to 10 CFR 54.3 

TLAA Criteria 

LRA Table 4.1-1 identifies those generic analyses and plant-specific analyses in the CLB that 

have been identified as TLAAs for the LRA. The staff concluded that these analyses are in 

conformance with the six criteria for defining TLAAs in 10 CFR 54.3. Based on its review, the 

staff finds that the identification of these TLAAs is acceptable because it is in accordance with 

the requirement in 10 CFR 54.21(c)(1). The staff’s evaluation of the applicant’s demonstration 

for each TLAA in accordance with 10 CFR 54.21(c)(1) is documented in SER Sections 4.2, 4.3, 

4.4, 4.6, and 4.7. 

 Evaluation of Applicant’s List of Evaluations, Analyses, and Calculations in the CLB 

That Do Not Conform to Six Criteria for TLAAs in 10 CFR 54.3 or Absence of a 

TLAA due to Absence of a Particular Analysis in the CLB 

As discussed in Section 4.1.1.1, the applicant identified a number of evaluations, analyses, and 

calculations in the SRP-LR that either do not apply to the Fermi 2 CLB or do not meet the 

definition of a TLAA in 10 CFR 54.3(a). The staff’s evaluation of the applicant’s statements and 

bases for these matters are provided below. 

Absence of a Containment Tendon Prestress TLAA. SRP-LR Table 4.1-2 and SRP-LR 

Section 4.5 both identify that a containment tendon prestress analysis is a generic TLAA that 

may be applicable to plant containment designs. SRP-LR Section 4.5 states that containment 

prestress analyses are only applicable to concrete containment structures that use prestressed 

tendons as the reinforcement basis for the structures. 

The applicant stated that the CLB does not include a containment tendon prestress analysis 

because Fermi 2 uses a General Electric (GE) Mark I containment design that does not include 

prestressed tendons. 

The staff reviewed the Fermi 2 UFSAR and confirmed that the CLB for Fermi 2’s Mark I 

containment structure does not rely on prestressed tendons to reinforce the structure. 

Therefore, the staff concludes that the LRA does not need to include a concrete containment 

prestress TLAA because the staff confirmed that this type of analysis is not included in the CLB. 

Absence of an Inservice Localized Metal Containment Corrosion TLAA. SRP-LR Table 4.1-2 

identifies that a local metal containment corrosion analysis is a generic TLAA that may be 

applicable to plants. The applicant stated that the CLB does not include any inservice local 

metal containment corrosion analyses because the containment is a GE Mark I containment 

design and the CLB does not include any corrosion analysis associated with this type of 

containment design. 

The staff reviewed the UFSAR and noted that the CLB for Fermi 2’s Mark I containment 

structure does not rely on localized metal corrosion analyses to justify the structural integrity of 

metallic containment components against the consequences of corrosion-induced aging effects. 

The staff confirmed that the applicant relies on the application of coatings and pH control to 

achieve this objective. Therefore, the staff concludes that the LRA does not need to include a 

localized metal containment corrosion TLAA because the staff has confirmed that this type of 

analysis is not included in the CLB. 
4-5 

Absence of a TLAA on RPV Underclad Intergranular Separation (Underclad Cracking). SRP-LR 

Table 4.1-3 identifies that a plant-specific RPV underclad cracking analysis may qualify as a 

TLAA for plants. The applicant stated that the CLB does not include any analysis of 

intergranular separations (i.e., underclad cracks or underclad cracking) in the RPV because this 

analysis is not applicable to boiling water reactor (BWR) designs. 

The staff noted that the relevant TLAA recommendations in the SRP-LR for RPV underclad 

cracking analyses are only applicable to SA-508, Class 2 forgings in pressurized water reactor 

(PWR)-designed RPVs and do not apply to BWR designs. The staff reviewed the UFSAR and 

verified that the UFSAR defines that the Fermi 2 reactor is a GE Model 4 BWR design. 

Therefore, the staff concludes that the LRA does not need to include a plant-specific RPV 

underclad cracking TLAA because this type of analysis is not applicable to BWRs. 

Absence of a Low-Temperature Overpressure Protection (LTOP) TLAA. SRP-LR Table 4.1-3 

identifies a plant-specific LTOP analysis that may qualify as a TLAA for plants. The applicant 

stated that the CLB does not include an LTOP analysis for the RPV and reactor coolant 

pressure boundary (RCPB) because this analysis is not applicable to BWR designs. 

The staff noted that the relevant TLAA recommendations for plant-specific LTOP analyses in the 

SRP-LR are only applicable to the reactor coolant systems in PWR-designed reactors and do 

not apply to BWR designs. The staff reviewed the UFSAR and confirmed that the Fermi 2 

reactor is a GE Model 4 BWR design. Therefore, the staff concludes that the LRA does not 

need to include a plant-specific LTOP TLAA because this type of analysis is not applicable to 

BWRs. 

Absence of a Fatigue Analysis for Main Steam Supply Lines to Steam-Driven Auxiliary 

Feedwater (AFW) Pumps TLAA. SRP-LR Table 4.1-3 identifies a plant-specific metal fatigue 

analysis for the steam line that supplies steam to a steam-driven AFW pump as a possible 

TLAA for plants. The applicant stated that the CLB does not include this type of fatigue analysis 

because the analysis does not apply to BWR designs. 

The staff noted that the relevant TLAA recommendations in the SRP-LR for these types of 

plant-specific fatigue analyses are only applicable to PWR designs that include steam-driven 

AFW pumps and do not apply to BWR designs. The staff reviewed the UFSAR and confirmed 

that the Fermi 2 reactor is a GE Model 4 BWR design. Therefore, the staff concludes that the 

LRA does not need to include a plant-specific fatigue TLAA for steam-driven AFW pump steam 

supply lines because this type of analysis is not applicable to BWRs. 

Absence of a Fatigue Flaw Growth Analysis for Reactor Coolant Pump (RCP) Flywheels TLAA. 

SRP-LR Table 4.1-3 identifies a plant-specific cycle-dependent fatigue growth or flaw tolerance 

analysis for RCP flywheels that may qualify as a TLAA for plants. The applicant stated that the 

CLB does not include any cycle-dependent flaw growth or flaw tolerance analysis for RCP 

flywheels because this analysis does not apply to BWR designs. 

The staff noted that the relevant TLAA recommendations in the SRP-LR for RCP flywheel 

fatigue flaw growth analyses are only applicable to the designs of the RCPs in PWR plant 

designs and do not apply to BWR plant designs. The staff reviewed the UFSAR and confirmed 

that the Fermi 2 reactor is a GE Model 4 BWR design. Therefore, the staff concludes that the 

LRA does not need to include a plant-specific RCP flywheel TLAA because this type of analysis 

is not applicable to BWRs. 
4-6 

Absence of a Flow-Induced Vibration Analysis for Reactor Vessel Internal (RVI) Components 

TLAA. SRP-LR Table 4.1-3 identifies a plant-specific flow-induced vibration analysis for the RVI 

components that may qualify as a TLAA for plants. The applicant stated that the flow-induced 

vibration analysis for the RVI components in the CLB is not a TLAA because it is not based on 

the current operating term such as 40 years and thus does not conform to the definition of a 

TLAA in 10 CFR 54.3(a). 

The staff noted that UFSAR Section 1.5.2.3 states that flow-induced vibrations of the RVI 

components were qualified by prototypical testing performed in accordance with GE Report 

No. NEDO-24057-P, “Assessment of Reactor Internals Vibration in BWR/4 and BWR/5 Plants,” 

dated November 1977, and that this report provides the design basis for demonstrating 

conformance with NRC Regulatory Guide (RG) 1.20, Revision 2, “Comprehensive Vibration 

Assessment Program for Reactor Internals during Preoperational and Initial Startup Testing,” 

dated May 1976. However, the staff noted that the UFSAR did not indicate whether the 

methodology in GE Report No. NEDO-24057-P included a time-dependent analysis for 

qualifying the structural integrity of the RVI components against the consequences of 

flow-induced vibrations. 

By letter dated December 23, 2014, the staff issued Request for Additional Information 

(RAI) 4.1-1, requesting that the applicant clarify whether the methodology in GE Report 

No. NEDO-24057-P included a time-dependent analysis, and if so, whether the analysis is relied 

upon to qualify the structural integrity of the RVI components against the consequences of 

flow-induced vibrations. If the analysis is time-dependent, the staff asked the applicant to 

provide justification as to why it would not need to be identified as a TLAA, when compared to 

the six criteria for TLAAs in 10 CFR 54.3(a). 

By letter dated February 5, 2014, as amended by letter dated April 10, 2014, the applicant 

responded to RAI 4.1-1. In its response, the applicant stated that the methodology in 

TR No. NEDO-24057-P does not include a time-dependent analysis as long as the flow-induced 

vibration stress is less than 10,000 psi. The applicant stated that, based on startup vibration 

measurements at the prototype plant, the maximum peak stress amplitude due to flow induced 

vibrations is less than 10,000 psi. The applicant also stated that, since the value is less than 

10,000 psi, no fatigue usage is accumulated by the component as a result of flow-induced 

vibrations and operating time has no effect on the RVI component evaluation. 

The staff compared the applicant’s basis in the response to RAI 4.1-1 to the information in 

ASME Code Section III, Subsection NB-3600, and stress-number (S-N) criteria in 

Figure I-9.2.2-1 of ASME Code Section III. The staff confirmed that, at vibrational stress levels 

less than 10,000 psi, the magnitude of the stresses is below those in Figure 1-9.2.2-1 that would 

identify fatigue as a potential issue for the RVI components. Therefore, based on this review, 

the staff confirmed that the criteria in ASME Code Section III, Subsection NB-3600, would not 

have required the applicant to perform a fatigue usage factor analysis for vibrational loads in the 

components. Therefore, based on its review of this analysis, the staff has confirmed that the 

assessment of vibrational loads for RVI components in NEDO-24057-P does not include any 

analysis that would need to be identified as a TLAA. The staff’s concern described in RAI 4.1-1 

is resolved. 

Therefore, based on this review, the staff concludes that the assessment of vibrational loads in 

Report NEDO-24057-P does not need to be identified as a TLAA because the assessment does 

not: (a) involve an assessment of an applicable aging effect, and (b) conform to Criterion 2 in 

10 CFR 54.3(a). 
4-7 

Absence of a Reduction of Ductility Analysis for Reactor Vessel Internal (RVI) Components 

TLAA. SRP-LR Section 3.1.2.2.3 (item 3) and SRP-LR Table 4.1-3 state that the CLB for PWRs 

designed by the Babcock & Wilcox Company may include a reduction of ductility TLAA for the 

RVI components in these types of plant designs; the applicable analysis is given in Technical 

Report (TR) No. BAW-2248A, “Demonstration of the Management of Aging Effects for the 

Reactor Vessel Internals” (Agencywide Documents Access and Management System (ADAMS) 

Accession No. ML003708443), dated April 2000. 

LRA Table 4.1-2 states that the CLB does not include any time-dependent reduction of ductility 

analysis for the RVI components. LRA Section 3.1.2.2.3, item 3, states that this analysis 

pertains to a plant-specific TLAA for Babcock & Wilcox reactor internals and is therefore not 

applicable to Fermi 2. 

The staff reviewed the UFSAR and confirmed that the Fermi 2 reactor is a GE designed BWR 

Model 4 reactor. Therefore, consistent with the analysis that has been provided in LRA 

Section 3.1.2.2.3, item 3, the staff concludes that the LRA does not need to include a reduction 

of ductility TLAA because this type of analysis is not applicable to BWRs. 

Absence of a Leak-Before-Break (LBB) TLAA. SRP-LR Table 4.1-3 identifies a plant-specific 

LBB analysis that may qualify as a TLAA for plants. 

LRA Table 4.1-2 states that the CLB does not include any time-dependent LBB analysis for 

plant design. LRA Table 4.1-2 also states that Fermi 2 does not credit the use of LBB 

technology. The staff reviewed the UFSAR and confirmed that the Fermi 2 reactor is a GE 

designed BWR Model 4 reactor. Therefore, the staff concludes that the LRA does not need to 

include an LBB TLAA because this type of analysis is not applicable to BWRs. 

Absence of a Component Metal Corrosion Allowance Analyses TLAA. SRP-LR Table 4.1-3 

identifies a plant-specific metal component corrosion allowance analysis that may qualify as a 

TLAA for plants. In LRA Table 4.1-2, the applicant stated that the CLB does not include any 

time-dependent metal corrosion allowance evaluations for metallic components that would need 

to be identified as TLAAs. 

The staff reviewed the UFSAR and noted that it did not identify any specific cases of metallic 

components with corrosion allowances where the additional amount of metal material in the 

component designs were established by a time-dependent analysis. Therefore, based on its 

review, the staff concludes that the LRA does not need to include any corrosion allowance 

TLAAs because the staff has confirmed that the CLB does not include these types of TLAAs. 

Potentially Applicable TLAAs in Response to BWRVIP Report Applicant Action Items. The staff 

noted that inclusion of LRA Aging Management Program (AMP) B.1.11, “BWR Vessel Internals,” 

confirms that the applicant applies the BWRVIP inspection and flaw evaluation (I&FE) guideline 

reports as part of its basis for managing aging effects applicable to the RVI components at 

Fermi 2. Therefore, the staff reviewed the NRC-issued safety evaluations (SEs) on the 

BWRVIP reports that are referenced in the Generic Aging Lessons Learned (GALL) Report 

AMPs XI.M4, “BWR Vessel ID Attachment Welds,” XI.M8, “BWR Vessel Penetrations,” and 

XI.M9, “BWR Vessel Internals,” to determine whether the SEs included applicable TLAA-related 

AAIs for the specific RVI components that are within the scope of the BWRVIP reports. The 

staff’s review included a review of the following BWRVIP report SEs: 
4-8 

 SE on Report No. BWRVIP-18, Revision 1-A (I&FE guidelines for BWR core spray 

internals) 

 SE on Report No. BWRVIP-25 (I&FE guidelines for BWR core plates) 

 SE on Report No. BWRVIP-26-A (I&FE guidelines for BWR top guides) 

 SE on Report No. BWRVIP-27-A (I&FE guidelines for BWR standby liquid 

control/core ∆P (SLC/core ∆P) nozzles and lines) 

 SE on Report No. BWRVIP-38 (I&FE guidelines for core shroud supports) 

 SE on Report No. BWRVIP-41, Revision 3 (I&FE guidelines for jet pump assembly 

components) 

 SE on Report No. BWRVIP-42-A (I&FE guidelines for BWR low-pressure coolant 

injection (LPCI) couplings) 

 SE on Report No. BWRVIP-47-A (I&FE guidelines for BWR RVI lower plenum 

components 

 SE on Report No. BWRVIP-74-A (I&FE guidelines for BWR reactor pressure vessel 

(RPV) components) 

 SE on Report No. BWRVIP-76, Revision 1-A (I&FE guidelines for BWR core shrouds) 

The staff noted that, of these reports, only BWRVIP-18, Revision 1-A, BWRVIP-25, 

BWRVIP-26-A, BWRVIP-27-A, BWRVIP-42-A, BWRVIP-47-A, BWRVIP-74-A, and BWRVIP-76, 

Revision 1-A, included AAIs that relate to the identification of TLAAs. 

AAI No. 4 on BWRVIP-18-A (BWRVIP I&FE Guidelines for Internal BWR Core Spray Lines). In 

the staff’s SE on BWRVIP-18-A, dated December 7, 2000 (ADAMS Accession 

No. ML003775973), and approval letter for BWRVIP-18, Revision 1-A, dated May 2, 2013 

(ADAMS Accession No. ML13067A072), the staff issued AAI No. 4, requesting that BWR 

applicants identify any plant-specific TLAAs that may be applicable to the evaluation of BWR 

core spray line (internal portions) and sparger components. Specifically, in this AAI, the staff 

stated that BWR applicants for renewal should identify all TLAAs that are applicable to the 

design of its core spray internal components. 

In its response to this AAI, the applicant stated that the metal fatigue TLAAs have been 

identified for the core spray lines and the core spray spargers and the TLAAs are discussed in 

LRA Section 4.3.1.4. 

The staff confirmed that the applicant discusses its metal fatigue TLAA (i.e., cumulative usage 

factor (CUF) analysis) for the internal portion of the core spray line and core spray sparger in 

LRA Section 4.3.1.4. The staff also confirmed that the fatigue analysis for the internal portions 

of the core spray line and sparger was the only analysis that conformed to the definition of a 

TLAA in 10 CFR 54.3(a). 

Based on this review, the staff finds the applicant’s response to this AAI acceptable because the 

staff has confirmed that the applicant has included the applicable fatigue TLAA for the core 

spray line and sparger components in the LRA and because the design basis does not include 

any other analysis that needs to be identified as a TLAA for these components. The staff 

evaluation of the CUF analysis for the internal portions of the core spray line and the core spray 

sparger is documented in SER Section 4.3.1.4.2. 
4-9 

AAI No. 4 on BWRVIP-25 (BWRVIP I&FE Guidelines for BWR Core Plates). In the staff’s SE on 

BWRVIP-25, dated December 7, 2000 (ADAMS Accession No. ML003775989), the staff issued 

AAI No. 4, requesting BWR applicants to identify any plant-specific TLAAs that may be 

applicable to the evaluation of BWR core plate assemblies or the components in these 

assemblies. Specifically, in this AAI, the staff stated that BWR applicants for license renewal 

should identify and evaluate whether the evaluation of stress relaxation in core plate rim 

hold-down bolts should be identified as a TLAA for the components. 

In its response to this AAI, documented in LRA Appendix C, the applicant stated that, at 

Fermi 2, the structural integrity of the core plate is not ensured by the inclusion of wedges that 

hold the core plate in place; instead, the Fermi 2 design relies on rim hold-down bolts that are 

tensioned (preloaded) in place. To address AAI No. 4 on BWRVIP-25, the applicant stated that 

the BWR Vessel Internals Program (LRA AMP B.1.10) will be enhanced (Commitment No. 7, 

Part c), in part, to perform one of the following activities: 

 Option (a) - Install wedges in the core plate design prior to entering the period of 

extended operation. 

 Option (b) - Complete a plant-specific analysis to determine acceptance criteria for 

continued inspection of core plate hold-down bolts in accordance with BWRVIP-25 and 

submit the inspection plan, along with the acceptance criteria and justification for the 

inspection plan, to the NRC 2 years prior to the period of extended operation. 

The staff noted that the applicant identified these activities as applicable program 

enhancements to the BWRVIP Vessel Internals Program in LRA UFSAR supplement 

Section A.1.10 and committed to these activities in Commitment No. 7 of UFSAR Supplement 

Table A.4, “License Renewal Commitment List.” However, the staff noted that some aspects of 

Commitment No. 7, Part c, would need to be clarified, particularly if Option (b) of the 

commitment is selected as the basis for managing aging in the plant’s core plate rim hold-down 

bolts. 

Specifically, the staff noted that Option (b) of Commitment No. 7, Part c, does not address 

whether the analysis will evaluate loss of preload due to stress relaxation in the core plate rim 

hold-down bolts and whether the analysis will quantify the loss of preload/stress relaxation that 

will occur in these bolts during the period of extended operation. Presuming that the analysis in 

Option (b) will be a loss of preload/stress relaxation analysis, the staff noted that the option does 

not identify whether the analysis will be based on the generic loss of preload/stress relaxation 

analysis in BWRVIP-25, as approved in the staff’s SE of December 7, 2000, or a plant-specific 

loss of preload/stress relaxation analysis that is applicable to the plant-specific design of the 

core plate rim hold-down bolts at Fermi 2. The staff also noted that Option (b) of LRA 

Commitment No. 7, Part c, does not require the applicant to submit the applicable analysis to 

the NRC for staff approval (i.e., if not already approved by the NRC). 

By letter dated December 23, 2014, the staff issued RAI 4.1-2, Parts (a) – (c), requesting that 

the applicant provide further clarifications and justifications relative to Option (b) of LRA 

Commitment No. 7, Part c, as provided in LRA UFSAR Supplement Table A.4. 

In RAI 4.1-2, Part (a), the staff requested the applicant to clarify whether the specific analysis in 

Option (b) of LRA Commitment No. 7, Part c, will address loss of preload due to stress 

relaxation in the core plate rim hold-down bolts, and if so whether the analysis will quantify the 

loss of preload/stress relaxation that will occur in these bolts during the period of extended 
4-10 

operation. If not, the staff asked the applicant to justify why the analysis would not quantify the 

amount of preload loss/stress relaxation that would occur in the core plate rim hold-down bolts 

at the end of the period of extended operation. 

In RAI 4.1-2, Part (b), the staff requested the applicant to clarify whether the analysis referred to 

in Option (b) of LRA Commitment No. 7, Part c, will be a plant-specific loss of preload/stress 

relaxation analysis for the core plate rim hold-down bolts or the generic analysis loss of 

preload/stress relaxation analysis that was evaluated in BWRVIP-25 and approved in the staff’s 

SE of December 7, 2000. If the analysis will be the generic analysis in BWRVIP-25, the staff 

asked the applicant to provide its basis for why the analysis has not been identified as a TLAA 

for the LRA and evaluated (with justification) in accordance with 10 CFR 54.21(c), and why the 

generic core plate rim hold-down analysis in BWRVIP-25 is considered to be bounding and 

acceptable for the design and loadings of the core plate assembly at Fermi 2. 

In RAI 4.1-2, Part (c), the staff requested the applicant to explain why Option (b) of LRA 

Commitment No. 7, Part c, does not state that the loss of preload/stress relaxation analysis will 

be submitted for NRC approval (i.e., if the analysis has not already been demonstrated to be 

applicable to the bolt design at Fermi 2 and approved by the staff). 

By letter dated February 5, 2015, the applicant responded to RAI 4.1-2, Parts (a), (b), and (c). 

In its response to RAI 4.1-2, Part (a), the applicant stated that the specific analysis referred to in 

Commitment No. 7 will address loss of preload due to stress relaxation in the core plate rim 

hold-down bolts and quantify the loss of preload/stress relaxation that will occur in these bolts 

during the period of extended operation. The applicant also provided the following responses to 

RAI 4.1-2, Parts (b) and (c): 

(b) The BWRVIP is developing justification for the elimination of core plate bolt inspections 

for plants without installed core plate wedges. This new evaluation is different than the 

generic analysis evaluated in BWRVIP-25 and approved in the NRC SE of 

December 7, 2000. While this new evaluation will also be generic (applicable to multiple 

plants), each site will have to meet criteria dependent on plant-specific load 

combinations and peak fluence at the core plate bolt locations. Like the analysis 

evaluated in BWRVIP-25, the new core plate bolt evaluation will address loss of 

preload/stress relaxation through the period of extended operation. 

(c) The new evaluation described above will be performed when instructed by the BWRVIP 

through incorporation into an existing BWRVIP Inspection & Evaluation Guideline. The 

evaluation will be performed under the provisions of BWRVIP implementation guidelines 

in BWRVIP-94, Revision 2, which also provides for NRC notification and submittal as 

appropriate. Therefore, notification and submittal to the NRC will be performed in 

accordance with BWRVIP-94, Revision 2. 

If Option 2 of Commitment No. 7 is performed and the analysis results in acceptance 

criteria for continued inspection, then the inspection plan, along with the acceptance 

criteria and justification for the inspection plan, will be submitted to the NRC two years 

prior to the period of extended operation. 

The applicant amended LRA AMP B.1.10, “BWR Vessel Internals”; LRA UFSAR Supplement 

Section A.1.10, “BWR Vessel Internals”; Commitment No. 7 in LRA UFSAR Supplement 

Table A.4; and the response to AAI No. 4 on BWRVIP-25, as given in LRA Appendix C, to be 
4-11 

consistent with the amended basis provided in the responses to RAI 4.1-2, Parts (a), (b), 

and (c). 

The staff noted that, based on the responses to RAI, 4.1-2, Parts (a), (b), and (c), there is no 

analysis contained or incorporated by reference in the CLB related to the stress relaxation of the 

core plate rim hold-down bolts at Fermi 2, and therefore this is not a TLAA. 

The adequacy of the applicant’s plans for aging management of the core plate rim hold-down 

bolts is evaluated in SER Section 3.0.3.2.3. 

AAI No. 4 on BWRVIP-26-A (BWRVIP I&FE Guidelines for BWR Top Guide Assemblies). In the 

staff’s SE on BWRVIP-26-A, dated December 7, 2000 (ADAMS Accession No. ML003776110), 

the staff issued AAI No. 4, requesting BWR applicants to identify any plant-specific TLAAs that 

may be applicable to the evaluation of BWR top guide components. Specifically, in this AAI, the 

staff stated that BWR applicants for license renewal should identify and evaluate the impact of 

accumulated neutron fluence on the potential to initiate irradiation assisted stress corrosion 

cracking (IASCC) in BWR top guide components and should evaluate the basis for identifying 

this evaluation as a TLAA for the top guide components. 

In its response to this AAI, the applicant stated that the 60-year projected fluence for the Fermi 2 

top guide exceeds the threshold for the initiation of the IASCC-induced cracking in the top guide 

and its subcomponents. However, the applicant stated that the methodology in BWRVIP-26-A 

does not include any analysis that would constitute a TLAA for Fermi 2 since the report was not 

used to make any safety determination or as justification for reducing the number of inspections 

that would be applied to these components. The applicant stated that, since Fermi 2 has 

implemented the inspection requirements of BWRVIP-26-A and BWRVIP-183, the BWR Vessel 

Internals Program will be adequate to manage the effects of aging of the top guide assembly for 

the period of extended operation. 

The staff noted that, in BWRVIP-26-A report, Appendix B, the EPRI BWRVIP included a generic 

flaw analysis for postulated cracks in BWR top guide grid beam components. The staff noted 

that this flaw analysis uses a proprietary upper bound fluence value as the basis for establishing 

the critical stress intensity value for BWR top guide components in the industry. Therefore, it 

was not evident to the staff why the time-dependent flaw evaluation in BWRVIP-26-A had not 

been identified as a TLAA, particularly if the applicant was relying on the analysis to justify the 

augmented inspection methods and frequencies that will be applied to the top guide assembly 

during the period of extended operation. 

By letter dated December 23, 2014, the staff issued RAI 4.1-3, requesting that the applicant 

clarify whether the flaw evaluation for BWR top guide grid beam locations in BWRVIP-26-A, 

Appendix B, is relied upon to justify the augmented inspection methods and frequencies for the 

top guide grid beam locations at Fermi 2. If so, the staff asked the applicant to provide 

justification for: (a) why the flaw evaluation in BWRVIP-26-A was not considered to be part of 

the safety basis decision for implementing the BWRVIP-26-A guidelines as part of the BWR 

Vessel Internals Program and (b) why the generic flaw evaluation in BWRVIP-26-A, Appendix B, 

had not been identified as a TLAA for the LRA, when compared to the six criteria for TLAAs in 

10 CFR 54.3(a). 

By letter dated February 5, 2015, the applicant provided its response to RAI 4.1-3. In its 

response, the applicant stated that BWRVIP-26-A, Appendix B, only provides a sample flaw 

evaluation for selected BWR top guide grid beam locations. The applicant also clarified that, 
4-12 

since the evaluation is not a component-specific evaluation, the sample flaw evaluation in 

BWRVIP-26-A is not relied upon to justify the validity of augmented inspections that will be 

applied to the top guide assembly during the period of extended operation. The staff noted that 

the applicant’s response to RAI 4.1-3 provides a valid basis for concluding that the flaw 

evaluation in BWRVIP-26-A is not part of the CLB for Fermi 2. Based on this response, the staff 

finds that the flaw evaluation in the BWRVIP-26-A report does not need to be identified as a 

TLAA for the LRA because (a) the analysis is not contained or incorporated by reference in the 

CLB and (b) therefore, the analysis does not conform to Criterion 6 in 10 CFR 54.3(a). The 

staff’s concerns associated with RAI 4.1-3 and AAI No. 4 on BWRVIP-26-A are resolved with 

respect to this TLAA identification matter. 

Based on this review, the staff concludes that AAI No. 4 on BWRVIP-26-A does not include a 

TLAA applicable to the applicant. 

AAI No. 4 on BWRVIP-27-A (BWRVIP I&FE Guidelines for Standby Liquid Control Nozzles). In 

the staff’s SE on BWRVIP-27-A, dated December 20, 1999 (ADAMS Accession 

Nos. ML993630179 and ML993630186), the staff issued AAI No. 4, requesting BWR applicants 

to address those plant-specific TLAAs that may be applicable to the evaluation of BWR 

SLC/core ∆P nozzle components. Specifically, in this AAI (AAI No. 4 on BWRVIP-27-A), the 

staff stated that, due to the susceptibility of the subject components to fatigue, applicants 

referencing the BWRVIP-27-A report for license renewal should identify and evaluate the 

projected fatigue CUFs as a potential TLAA issue. 

In its response to this AAI, the applicant stated that the BWRVIP-27-A fatigue analysis of the 

SLC/core ∆P line for 60 years of operation is a TLAA. The applicant stated that the NRC SE on 

BWRVIP-27-A calls for each BWR applicant to address the projected CUF but recognizes that 

this fatigue analysis is not required for all SLC/core ∆P configurations. The applicant stated that 

at Fermi 2, the SLC/core ∆P lines inside the reactor RPV are not subject to an aging 

management review (AMR). 

The staff noted that the applicant’s response to AAI No. 4 on BWRVIP-27-A identifies that the 

CLB includes a metal fatigue TLAA (i.e., CUF analysis) for the SLC/core ∆P nozzle to the RPV. 

The staff confirmed that the LRA includes a CUF assessment for the SLC/core ∆P nozzle in 

LRA Section 4.3.1.1. The staff evaluation of the CUF analysis for SLC/core ∆P nozzle is 

documented in SER Section 4.3.1.1. 

The staff noted that UFSAR Section 4.5.2.4.3 states that the SLC system is needed to remain 

operational to comply with the requirements in 10 CFR 50.62, “Requirements for Reduction of 

Risk from Anticipated Transients without Scram (ATWS) Events for Light-Water-Cooled Nuclear 

Power Plants,” as referenced in 10 CFR 54.4(a)(3). The staff also noted that UFSAR 

Section 4.5.1.2.11 states that portions of the SLC/core ∆P line internal to the RPV are needed 

to facilitate good mixing and dispersion of the system boron contents into the RPV when SLC is 

activated and to reduce thermal shock to the RPV’s SLC/core ∆P nozzle should SLC be 

activated. Thus, it is not clear to the staff why the portions of the SLC lines internal to the RPV 

would not need to be included in the scope of license renewal in accordance with either one of 

the following requirements in 10 CFR 54.4, “Scope”: 

 10 CFR 54.4(a)(2) – in that the failure of the SLC line inside the RPV would no longer be 

capable of mitigating a thermal shock impact to the RPV’s SLC/core ∆P nozzle 

(an RCPB component) during a postulated design basis loss of coolant accident (LOCA) 
4-13 

 10 CFR 54.4(a)(3) – in that the failure of the SLC line inside the RPV could impact the 

ability of SLC to properly mix and disperse boron-10 inside of the reactor if SLC is called 

upon to actuate during a postulated design basis accident 

The staff also noted that the applicant’s response to AAI No. 4 on BWRVIP-27-A did not provide 

sufficient demonstration that the CLB did not include a metal fatigue analysis (i.e., CUF 

analysis) or other type of cycle loading analysis for the portions of the SLC/core ∆P line internal 

to the RPV (i.e., not inclusive of the SLC/core ∆P nozzle adjoined to the RPV). 

By letter dated December 23, 2014, the staff issued RAI 4.1-4, requesting that the applicant 

provide further clarification on these matters. Specifically, in Part (a) of RAI 4.1-4, the staff 

requested the applicant to justify why the portions of the SLC and core ∆P line internal to the 

RPV have not been identified as within the scope of license renewal. Specifically, the staff 

requested the applicant to indicate whether these components are required to be within the 

scope of license renewal in accordance with 10 CFR 54.4(a). If these components are within 

the scope of license renewal, the staff asked the applicant to provide the basis as to why the 

portions of the SLC and core ∆P line internal to the RPV had not been subject to an AMR, as 

required by 10 CFR 54.21(a)(1). The staff also asked the applicant to amend the LRA 

accordingly if it is determined that these components are subject to an AMR. 

In RAI 4.1-4, Part (b), the staff requested the applicant to identify the design code or design 

analyses of record that was used for the portions of the SLC and core ∆P line that are located 

internal to the RPV (i.e., not inclusive of the SLC and core ∆P nozzle adjoined to the RPV). The 

staff also asked the applicant to clarify whether the design code or design analyses of record 

included a metal fatigue analysis or other type of cyclical loading analysis (e.g., cycle-based 

expansion stress or maximum allowable stress range reduction analysis or a fatigue waiver 

analysis) for the portions of the SLC and core ∆P line internal to the RPV. If so, the staff asked 

the applicant to explain why the analysis would not need to be identified and evaluated as a 

TLAA for the LRA, when compared to the six criteria for TLAAs in 10 CFR 54.3(a). 

By letter dated February 5, 2015, the applicant responded to RAI 4.1-4, Parts (a) and (b). In its 

response to RAI 4.1-4, Part (a), the applicant stated that the internal portions of the core ∆P line 

only serve a diagnostic function for measuring differential pressure across the reactor internal 

core plate and does not serve a license renewal intended function. The applicant stated that, 

although the UFSAR indicates that the internal portions of the SLC line are needed to facilitate 

good mixing, the BWRVIP-27-A report concludes that the boron need only reach the bottom 

head and there is sufficient natural circulation to distribute boron uniformly through the core. 

Therefore, the applicant stated that distribution of liquid by the SLC and core ∆P line is not 

essential and the portions of the SLC/core ∆P line internal to the RPV do not perform a license 

renewal intended function. 

The staff noted that the applicant’s response to RAI 4.1-4, Part (a), did not provide the staff with 

sufficient demonstration that the internal portions of the SLC/core ∆P line are not within the 

scope of license renewal in accordance with 10 CFR 54.4(a). Based on the staff’s review of 

UFSAR Sections 4.5.1.2.11 and 4.5.2.4.1, the staff concluded that the internal portions of the 

SLC/core ∆P line should be included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2), where its failure could potentially impact the ability to achieve its RCPB 

function or 10 CFR 54.4(a)(3) for mitigating the consequences of anticipated transients without 

scram events. 
4-14 

By letter dated May 20, 2015, the staff issued followup RAI 4.1-4a, Parts a and b, to address the 

applicant’s scoping and screening bases for the internal portions of the SLC/core ∆P line. The 

staff also issued followup RAI 4.1-4a, Part c, to address whether the applicant would need to 

perform an AMR of the internal portions of the SLC/core ∆P line in accordance with 

10 CFR 54.21(a)(1), and whether there are any aging effects that would need to be managed in 

these lines. 

The applicant responded to RAI 4.1-4a, by letter dated July 6, 2015, and provided a 

supplemental response to RAI 4.1-4a, by letter dated August 20, 2015. The latter stated that 

Fermi 2 will conservatively assume that the SLC/core ∆P line internal to the reactor vessel 

performs a license renewal intended function per 10 CFR 54.4(a)(3), such that this line will 

facilitate adequate boron mixing to shut down the core during an anticipated transient without 

scram event. In its responses, the applicant further provided the aging management activities to 

ensure that loss of material and cracking of the internal portions of the SLC/core ∆P line will be 

adequately managed for the period of extended operation. Therefore, the staff finds the 

applicant’s response to RAI 4.1-4, Part (a) and RAI 4.1-4a acceptable. The staff’s full 

evaluation and resolution of concerns of the applicant’s response to followup RAI 4.1-4a, 

Parts a and b, is documented in SER Section 2.3.3.2. The staff’s evaluation and resolution of 

concerns of the applicant’s response to followup RAI 4.1-4a, Part c, is documented in SER 

Section 3.0.3.2.3. 

In its response letter to RAI 4.1-4, Part (b), dated February 5, 2015, the applicant provided a 

proprietary response that (a) summarized the vibrational loading analysis for the internal 

portions of the SLC/core ∆P line and (b) provided the applicant’s basis for concluding that the 

vibrational loading analysis would not need to be identified as a TLAA for the LRA. The 

applicant stated that both an ASME Code Section III stress analysis and a vibrational loading 

analysis were applied to the internal portions of the SLC line. The applicant also stated that the 

ASME stress analysis only involved a stress analysis for these lines. The applicant also stated 

that the vibrational loading analysis for the internal portions of the SLC/core ∆P line did not 

involve stresses sufficient to initiate fatigue in the components. 

The staff confirmed that, consistent with information in the Fermi 2 UFSAR, the ASME analysis 

only involved a stress analysis for the SLC lines and that the SLC lines were not procured and 

analyzed to a design code (e.g., ASME Code Section III or American National Standards 

Institute (ANSI) B31.1) that would have required a CUF or implicit fatigue analysis of the lines. 

The staff also confirmed that the vibrational stress loads for the SLC/core ∆P line (as cited in the 

applicant’s proprietary response to RAI 4.1-4) were lower than those assessed for fatigue in the 

ASME Code Section III. Therefore, based on its review, the staff concludes that the applicant 

has provided sufficient demonstration that there are no cyclical loading-related TLAAs for the 

internal portions of the SLC/core ∆P line because the staff has confirmed that: (a) the design 

basis does not include a metal fatigue analysis for internal portions of these lines, and (b) the 

magnitude of the stresses in the vibrational loading analysis are below the threshold for time 

dependence. The staff’s concerns described in RAI 4.1-4, Part (b), and applicant/licensee 

action item (A/LAI) No. 4 on BWRVIP-27-A are resolved. 

AAI No. 4 on BWRVIP-42 (I&FE Guidelines for Low-Pressure Coolant Injection Couplings). In 

the staff’s SE on BWRVIP-42-A, dated January 9, 2001 (ADAMS Accession 

No. ML010100157), the staff issued AAI No. 4, requesting BWR applicants to address those 

plant-specific TLAAs that may be applicable to the evaluation of BWR LPCI coupling 

components. 
4-15 

The staff reviewed BWRVIP-42-A and confirmed that the scope of the report is not applicable to 

the design of the LPCI lines at Fermi 2. Therefore, based on its review, the staff concludes that 

the LRA does not need to include a response to AAI No. 4 on BWRVIP-42-A because the staff 

has confirmed that the I&FE guidelines in the report do not apply to the design of the LPCI lines 

at Fermi 2. 

AAI No. 4 on BWRVIP-47-A (I&E Guidelines for BWR Lower Plenum Components). In the 

staff’s SE on BWRVIP-47-A, dated December 7, 2000 (ADAMS Accession No. ML003775765), 

the staff issued AAI No. 4, requesting BWR applicants to address those plant-specific TLAAs 

that may be applicable to the evaluation of BWR lower plenum components. Specifically, in this 

AAI (AAI No. 4 on BWRVIP-47-A), the staff stated that, due to fatigue of the subject 

safety-related components, applicants referencing the BWRVIP-47 report for license renewal 

should identify and evaluate the projected CUF as a potential TLAA issue. 

In its response to this AAI, the applicant stated that the BWRVIP-47-A identified fatigue 

analyses of lower plenum pressure boundary components as potential TLAAs. The applicant 

stated that the CLB includes metal fatigue evaluations (calculated CUF) for selected RPV lower 

plenum components. The applicant stated that the metal fatigue evaluations qualify as TLAAs 

for the LRA. The applicant stated that the metal fatigue TLAAs for the lower plenum 

components are identified and evaluated in LRA Section 4.3.1.4. 

The staff reviewed LRA Chapter 4 and verified that Section 4.3.1.4 identifies the CUF analyses 

for the following RPV lower plenum component locations: (a) access hole cover – ring-to-cover 

location, (b) access hole cover – ring-to-adapter ring location, and (c) access hole cover – 

adapter ring-to-shroud support location. 

Based on its review, the staff finds the applicant’s response to this AAI acceptable because the 

staff has confirmed that the applicant has included applicable fatigue TLAAs for the three 

access hole cover locations in the LRA and that the design basis does not include any other 

analysis that needs to be identified as a TLAA for RPV lower plenum area components. The 

staff’s evaluation of the metal fatigue TLAAs for the RPV lower plenum component locations is 

documented in SER Section 4.3.1.4.2. 

AAI Nos. 8 – 13 on BWRVIP-74-A (I&E Guidelines for BWR Reactor Pressure Vessel 

Components). In the staff’s SE on BWRVIP-74-A, dated June 30, 2003 (ADAMS Accession 

No. ML031710349), the staff issued AAI Nos. 8 – 13, which relate to the need for identification 

of the following TLAAs or assessments related to the RCPB function of BWR RPVs: 

 AAI No. 8 on the need to identify metal fatigue TLAAs (CUF analyses) for RPV 

components that are part of the RCPB 

 AAI No. 9 on the need to identify applicable pressure-temperature (P-T) limit TLAAs for 

the RPV 

 AAI No. 10 on the need to identify applicable upper-shelf energy (USE) TLAAs for the 

RPV 

 AAI Nos. 11 and 12 on the need to identify applicable mean reference nil-ductility 

transition temperature (RTNDT) and probability of failure TLAAs for RPV circumferential 

and axial weld components if the methodology in TR No. BWRVIP-05 was used to 

request relief from augmented inspection requirements for RPV circumferential welds in 
4-16 

10 CFR 50.55a(g) and relief was granted in accordance with 10 CFR 50.55a(a)(3) 

requirements for the current operating period 

 AAI No. 13 on the need to perform 60-year neutron fluence values assessments for the 

RPV components, as inputs to the TLAAs identified in AAI Nos. 8 – 12 

The staff noted that the applicant included its response to these AAIs in LRA Appendix C. The 

staff also confirmed that the applicant has included all of these assessments as appropriate 

TLAAs for the LRA, as given in the following LRA sections: 

 LRA Section 4.2.1, which provides the 60-year neutron fluence evaluation and TLAA for 

components in the beltline and extended beltline of the RPV 

 LRA Sections 4.2.2 and 4.2.3 for the adjusted reference temperature (ART) and P-T 

TLAAs that are needed to ensure that appropriate P-T limits are developed for the period 

of extended operation 

 LRA Section 4.2.4 for the TLAA on USE 

 LRA Sections 4.2.5 and 4.2.6 for the mean RTNDT and conditional probability of failure 

analyses of the RPV circumferential and axial weld components 

 LRA Section 4.3.1.1 for the metal fatigue TLAAs for RPV components, LRA 

Section 4.3.1.2 for the metal fatigue TLAA for the RPV feedwater nozzles, and LRA 

Section 4.3.3 for the effects of reactor water environment on metal fatigue life 

Based on its review, the staff finds the applicant has addressed and resolved the requests in 

AAI Nos. 8 – 13 on the BWRVIP-74-A report because the applicant has included the applicable 

TLAAs in the LRA. The staff’s evaluation of the neutron fluence TLAA for the RPV is given in 

SER Section 4.2.1. The staff’s evaluation of the TLAA on the ART calculations for the RPV 

components is documented in SER Section 4.2.2. The staff’s evaluation of the TLAA for the 

RPV P-T limits is documented in SER Section 4.2.3. The staff’s evaluation of the TLAA on RPV 

USE is documented in SER Section 4.2.4. The staff’s evaluations of the TLAAs on the mean 

ART (mean RTNDT) and conditional probability of failure analyses for the RPV circumferential 

and axial welds components are documented in SER Sections 4.2.5 and 4.2.6. AAI Nos. 8 – 13 

on the BWRVIP-74-A report are resolved. 

AAI No. 6 on BWRVIP-76 Revision 1-A (I&FE Guidelines for BWR Core Shrouds). In the staff’s 

SE on BWRVIP-76-A, dated December 31, 2009 (ADAMS Accession No. ML101530467), which 

also applies to BWRVIP-76 Revision 1-A (ADAMS Accession No. ML15266A192), the staff 

issued AAI No. 6, requesting BWR applicants to address those AMPs and plant-specific TLAAs 

that may be applicable to the evaluation of BWR core shroud components. Specifically, in this 

AAI (AAI No. 6 on BWRVIP-76-A), the staff noted that the guidance in Table IV.B1 of the GALL 

Report lists two potentially applicable aging effects (i.e., in addition to cracking) for generic BWR 

RVI components (including BWR core shroud and core shroud repair assembly components) 

that are made from either stainless steel (including cast austenitic stainless steel) or nickel alloy: 

(1) loss of material due to pitting and crevice corrosion (GALL Report AMR IV.B1-15) and 

(2) cumulative fatigue damage (GALL Report AMR IV.B1-14). In AAI No. 6 on BWRVIP-76-A, 

the staff requested that BWR license renewal applicants address the bases for managing 

cumulative fatigue damage and loss of materials due to pitting and crevice corrosion of their 

core shroud components: 
4-17 

BWR [license renewal] applicants will need to assess their designs to see if the 

generic guidelines for managing cumulative fatigue damage in GALL AMR item 

IV.B1-14 and for managing loss of material due to pitting and crevice corrosion in 

GALL AMR IV.B1-15 are applicable to the design of their core shroud 

components (including welds) and any core shroud repair assembly components 

that have been installed through a design modification of the plant. If these aging 

effects are applicable to the design of these components as a result of exposing 

them to a reactor coolant with integrated neutron flux environment, applicants for 

license renewal will need to: (1) identify the aging effects as aging effects 

requiring management (AERM) for the core shrouds and for their core shroud 

repair assembly components if a repair design modification has been 

implemented, and (2) identify the specific aging management programs or 

time-limited aging analyses that will be used to manage these aging effects 

during the period of extended operation. 

In its response to this AAI, the applicant stated that the core shroud is fabricated from stainless 

steel Type 304L and that the aging effects of loss of material and cumulative fatigue damage 

have been identified for the core shroud. The applicant stated that the BWR Vessel Internals 

Program and the Water Chemistry Control – BWR Program have been credited to manage loss 

of material due to pitting and crevice corrosion in the core shroud during the period of extended 

operation. The applicant also stated that it has not detected any cracking of vertical (axial) or 

horizontal (circumferential) weld seams in the core shroud and therefore has not implemented a 

repair design modification for the shroud. The applicant stated that the metal fatigue TLAAs for 

the RVI components are evaluated in LRA Section 4.3.1.4. 

The staff confirmed that aging management of the core shroud in accordance with 

BWRVIP-76-A is within the scope of the applicant’s BWR Vessel Internals Program. The staff’s 

evaluation of the BWR Vessel Internals Program is documented in SER Section 3.0.3.2.3. The 

staff noted that the applicant stated that the evaluation of the metal fatigue TLAAs for the RVI 

components are in LRA Section 4.3.1.4; however, the staff also noted that LRA Section 4.3.1.4 

did not indicate which design code or specification was used for the design and fabrication of 

the core shroud or whether the design code or specification required a metal fatigue analysis or 

other type of cyclical loading analysis for the core shroud. 

By letter dated December 23, 2014, the staff issued RAI 4.1-5, requesting that the applicant 

identify the design code or design specification of record that was used for the design and 

fabrication of the core shroud. The staff also requested the applicant to clarify whether the 

design code or design specification of record required the applicant to perform a metal fatigue 

analysis or other type of cyclical loading analysis (e.g., cycle-based expansion stress or 

maximum allowable stress range reduction analysis or a fatigue waiver analysis) for the core 

shroud. If so, the staff requested the applicant to provide justification as to why the analysis 

would not need to be identified as a TLAA for the LRA, when compared to the six criteria for 

TLAAs in 10 CFR 54.3(a). 

By letter dated February 5, 2015, the applicant responded to RAI 4.1-5. The applicant’s 

response stated that, for BWR-4 plants such as Fermi 2, the core shroud was not designed to 

either ASME Code III or other design specification requirements. The applicant stated that the 

design and construction of the shroud only used the ASME design code as a general guideline 

for fabricating the core shroud, using welders and techniques qualified in accordance with 

ASME Code Section IX. The applicant stated that, as discussed in LRA Sections 3.1.2.2.1 and 

4.3.1.4, the RVIs and core support structure (including the shroud) are not part of the RCPB. 
4-18 

Based on these factors, the applicant stated that the design bases for the design and fabrication 

of the core shroud did not require a fatigue analysis of the shroud as part of the CLB for the 

facility. 

The staff reviewed the applicant’s response and basis against the relevant design information 

provided in the UFSAR. The staff noted that the UFSAR does not identify that either ASME 

Code Section III or any another design code or specification was used for the design or 

fabrication of the core shroud. Therefore, the staff determined that the applicant has provided 

an acceptable basis for concluding that the design of the core shroud did not require the 

applicant to perform a fatigue analysis for the shroud because: (a) the staff confirmed that the 

core shroud was not designed in accordance with any design code or specification that 

otherwise, if used for the CLB, might have required the performance of a fatigue analysis as part 

of the CLB, and (b) this provides sufficient demonstration that the CLB does not include any 

fatigue analyses for the core shroud that would need to be identified as TLAAs for the LRA. The 

staff’s concerns described in RAI 4.1-5 are resolved. 

4.1.2.2 Identification of Exemptions 

As required by 10 CFR 54.21(c)(2), the applicant must identify all exemptions that were granted 

in accordance with the exemption approval criteria in 10 CFR 50.12 and are based on a TLAA. 

For those exemptions that meet these criteria, the rule requires the applicant to evaluate the 

exemptions and justify their use during the period of extended operation. 

In LRA Section 4.1.2, the applicant stated that it performed a search in accordance with the 

exemption approval criteria in 10 CFR 50.12 to find any exemptions that were granted for the 

Fermi 2 CLB and were based on a TLAA. The applicant stated it performed its search based on 

a review of relevant licensing basis or design basis information in the UFSAR, ASME Code 

Section XI Program documentation, fire protection documents, operating license, TS and 

docketed correspondence. The applicant stated that it did not find any exemptions that were 

based on a TLAA and will remain in effect for the period of extended operation. 

The staff also reviewed the applicant’s CLB to see if it included any exemptions based on a 

TLAA that were granted in accordance with 10 CFR 50.12. The staff’s review included a review 

of the current operating license and TS for the facility and the applicant’s UFSAR. The staff’s 

review also included a search of the NRC’s main and legacy libraries in the NRC’s ADAMS 

Document Control Library using the keyword “exemption.” 

The staff noted that 10 CFR 54.21(c)(2) requires the applicant to identify a particular exemption 

as part of the LRA if the exemption was granted in accordance with the requirements of 

10 CFR 50.12 and based on a TLAA. For exemptions that meet these criteria, the requirements 

in 10 CFR 54.21(c)(2) apply regardless of whether the exemptions will remain in effect for the 

period of extended operation. Therefore, the staff noted that LRA Section 4.1.2 may have 

omitted exemptions that were granted in accordance with 10 CFR 50.12 and are based on a 

TLAA, but will not remain in effect for the period of extended operation. The staff noted that any 

such omissions would not be in compliance with the requirements of 10 CFR 54.21(c)(2). 

By letter dated December 23, 2014, the staff issued RAI 4.1-6 requesting that the applicant 

identify all exemptions that were granted in accordance with 10 CFR 50.12 and are based on a 

TLAA, but will not remain in effect for the period of extended operation. 
4-19 

By letter dated February 5, 2015, the applicant responded to RAI 4.1-6. In its response, the 

applicant stated that the CLB does not include any exemptions that were granted in accordance 

with 10 CFR 50.12 and that are based on a TLAA that are currently in effect, but will not remain 

in effect for the period of extended operation. The staff's review of this RAI response is 

discussed in conjunction with that for RAI 4.1-7. 

The staff noted that UFSAR Section 6.2 states that the NRC granted a number of exemptions 

from meeting the requirements of 10 CFR Part 50, Appendix J, “Primary Reactor Containment 

Leakage Testing for Water-Cooled Power Reactors,” Option B, for the containment leak rate 

testing program. However, the UFSAR does not describe what these exemptions involved or 

whether the alternative testing requirements or exceptions authorized by the exemptions were 

based on or supported by a time-dependent analysis. Therefore, the staff determined that 

additional information would be needed to determine whether these exemptions were previously 

granted in accordance with 10 CFR 50.12 and are based on a TLAA. 

By letter dated December 23, 2014, the staff issued RAI 4.1-7, requesting that the applicant 

describe each exemption that was granted in accordance with 10 CFR 50.12 from meeting the 

10 CFR Part 50, Appendix J, leak rate testing requirements. The staff requested the applicant 

to explain whether the exemptions were based on or supported by a time-dependent analysis, 

calculation, or evaluation that conforms to the six criteria for TLAAs in 10 CFR 54.3(a). If it is 

determined that a specific 10 CFR Part 50, Appendix J, leak rate testing exemption was granted 

under 10 CFR 50.12 and is based on a TLAA, the staff asked the applicant to amend the LRA to 

identify and evaluate the exemption in accordance with the requirement in 10 CFR 54.21(c)(2). 

By letter dated February 5, 2015, the applicant responded to RAI 4.1-7. In its response, the 

applicant identified that the following exemptions from the requirements of 10 CFR Part 50, 

Appendix J, were granted for the CLB in accordance with the requirements of 10 CFR 50.12: 

 An alternative leak rate testing basis for the main steam isolation valves (MSIVs) in lieu 

of the typical Type C local leak rate testing requirements for these valves in 

10 CFR Part 50, Appendix J. For this exemption, the applicant explained that the MSIVs 

have separate leakage limits, and the dose consequence of this leakage path is 

evaluated separately and added to those calculated from Primary containment “La” 

leakage requirements specified in the 10 CFR Part 50, Appendix J, rule. The applicant 

explained that, as such, this leakage is not combined with the Type B and C leakage 

rate totals. The applicant stated that this exemption is not based on a TLAA. 

 An alternate testing of the air lock, which consisted of testing the seals of the inner and 

outer doors at the “Pa” pressure rather than testing the entire air lock, after the opening 

of the doors. The applicant stated this exemption was not based on a time-limited 

analysis and it is no longer in effect because it was deleted from the CLB in License 

Amendment No. 108. 

 An exemption that reclassified the inboard containment LPCI valve configuration as an 

alternate definition for a containment isolation valve, such that Type C testing is no 

longer required for the LPCI valve. This reclassification was approved in License 

Amendment 98 and Exemption to the Facility Operation License No. NPF-43 Fermi 2. 

The applicant stated that the exemption permits the applicant to use an alternate testing 

method for the LPCI valves and explained that the LPCI penetrations X-13A & B were 

designed and built to General Design Criteria 55, which required both an inboard and 

outboard isolation capability. The applicant stated that the exemption took exception to 

the Type C testing requirements based on identification of two alternative barriers, which 
4-20 

included the residual heat removal system being a closed loop outside of primary 

containment and that penetrations (X-13A & B) will remain water sealed during a 

loss-of-coolant accident. The applicant stated that this exemption is not based on a 

TLAA. 

 An exemption that proposed an alternate technique to the mass plot method for 

analyzing Type A test data had been approved. The applicant stated that the “need for 

this exemption was eliminated when the Primary Containment Leakage Testing Program 

was implemented per 10 CFR Part 50, Appendix J, Option B, based on NEI 94-01 and 

RG 1.163, as approved in License Amendment 108.” The applicant stated this 

exemption was not based on a time-limited analysis and it is no longer in effect because 

it was deleted from the CLB in License Amendment No. 108. 

 Two one-time schedule exemptions from 10 CFR Part 50, Appendix J, leak rate testing 

requirements had been issued and expired. The applicant stated that these scheduler 

exemptions were not based on a TLAA. 

The staff noted that the six exemptions granted from the requirements in 10 CFR Part 50, 

Appendix J, involved either alternative testing bases, alternative test data analysis bases, or 

alternative test implementation schedule bases. The staff also noted that the exemption 

requests for these alternatives were not predicated on any analysis qualifying as a TLAA. 

Therefore, based on its review, the staff finds that these exemptions do not meet the criteria for 

exemption identification in 10 CFR 54.21(c)(2) because the staff has confirmed that the 

exemptions are not based on a TLAA. 

Based on its review of the applicant’s responses to RAI 4.1-6 and 4.1-7, the staff confirms that 

the applicant has provided ample demonstration that the CLB does not include any exemptions 

granted under 10 CFR 50.12 that are based on a TLAA, regardless of whether the exemptions 

will be relied upon for the period of extended operation. The staff’s concerns described in 

RAI 4.1-6 and 4.1-7 are resolved. The staff finds that there are not any other exemptions that 

were granted from 10 CFR Part 50 requirements in accordance with 10 CFR 50.12 and that are 

based on a TLAA. 

4.1.3 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable list 

of TLAAs, as required by 10 CFR 54.21(c)(1). The staff concludes, as required by 

10 CFR 54.21(c)(2), that no exemption, pursuant to 10 CFR 50.12, based on a TLAA had been 

granted. 

4.2 Reactor Vessel Neutron Embrittlement 

4.2.1 Reactor Vessel Fluence 

4.2.1.1 Summary of Technical Information in the Application 

LRA Section 4.2.1 describes the applicant’s TLAA for reactor vessel neutron fluence. The 

applicant stated that the reactor vessel neutron fluence was calculated using a higher power 

level, beginning with cycle 17 when the reactor power increased due to the measurement 

uncertainty recapture/thermal power optimization (MUR/TPO) update. 
4-21 

The LRA also states that the peak neutron fluence projected for 52 effective full-power years 

(EFPY) is 1.43x1018 n/cm2 at the vessel inner surface. In addition, the one-quarter thickness 

(1/4T) peak fluence values (E > 1 MeV) for 52 EFPY are as follows: 9.90x1017 n/cm2 for 

lower-intermediate shell plates and axial welds; 2.47x1017 n/cm2 for water level instrumentation 

nozzle; and 6.51x1017 n/cm2 for lower shell plates and axial welds, and lower to 

lower-intermediate girth weld. The reactor vessel neutron fluence was determined using the 

General Electric-Hitachi (GEH) method for neutron fluence calculation found in the 

staff-approved topical NEDO-32983-A, “General Electric Methodology for RPV Fast Neutron 

Flux Evaluations,” Revision 2, dated January 31, 2006 (ADAMS Accession No. ML072480121). 

The LRA states that this method adheres to the guidance prescribed in RG 1.190, “Calculational 

and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,” dated March 2001 

(ADAMS Accession No. ML010890301). The neutron fluence calculation results are inputs into 

the other reactor vessel neutron embrittlement TLAAs, such as analyses for ARTs and P-T 

limits. 

The applicant dispositioned the TLAA for reactor vessel neutron fluence in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation. 

4.2.1.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the reactor vessel and the corresponding disposition 

of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in SRP-LR Section 4.2.3.1 

(e.g., SRP-LR Sections 4.2.3.1.1.1, 4.2.3.1.2.1, and 4.2.3.1.3.1), which state that the applicant 

should identify (a) the neutron fluence for the reactor vessel at the end of the license renewal 

period, (b) the staff-approved methodology used to determine the neutron fluence (or should 

submit the methodology for staff review), and (c) whether the methodology follows the guidance 

in RG 1.190. 

The staff noted that the applicant provided 52-EFPY fluence values, which cover the period of 

extended operation. The staff also noted that the applicant used the staff-approved GEH 

methodology. The staff further noted that the fluence calculation uncertainty analysis and 

qualification of the applicant’s methodology adhere to the guidance contained in RG 1.190. In 

addition, the staff’s acceptance of the GEH methodology is described in the SE, dated 

November 17, 2005, for NEDO-32982P-A. 

The staff noted that LRA Section 4.2.1 states that the peak reactor vessel wall neutron fluence 

projected for 52 EFPY is 1.43x1018 n/cm2 (E > 1 MeV), considering the implemented MUR/TPO. 

In comparison, the staff noted that UFSAR Section 4.3.2.8.2, “Extended Power Uprate 

Analysis,” indicates that a reactor vessel fluence evaluation was performed in support of an 

extended power uprate (EPU) to 120 percent of the original licensed power. The staff also 

noted that UFSAR Table 4.3-2 describes both pre-EPU and EPU fluence values for 32 EFPY 

(i.e., original license term of 40 years). 

The LRA does not clearly address whether the fluence calculations are based on the operating 

conditions of the potential EPU described in UFSAR Section 4.3.2.8.2. By letter dated 

December 4, 2014, the staff issued RAI 4.2.1-1 requesting that the applicant clarify whether the 

neutron fluence described in the LRA are based on the operating conditions of the potential 

EPU described in UFSAR Section 4.3.2.8.2. The staff also requested that the applicant clarify 

the operating power levels on which the neutron fluence calculations are based. 
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By letter dated January 5, 2015, the applicant provided its response to RAI 4.2.1-1. In its 

response, the applicant clarified that the neutron fluence projections in the LRA are not based 

on the use of EPU power projections, because the EPU was never pursued. The applicant also 

clarified that the staff approved an MUR/TPO power increase of Fermi 2 from 3,430 megawatts 

thermal (MWt) to 3,486 MWt beginning in cycle 17 by letter dated February 10, 2014 (ADAMS 

Accession No. ML13364A131). The applicant further clarified that the operating power levels 

used to determine the 52-EFPY fluence are based on either 3,292 MWt or 3,430 MWt for 

operating cycles through cycle 16 and 3,486 MWt for operating cycles beginning with cycle 17 

and continuing through the period of extended operation, which is consistent with the staff 

approval for the MUR/TPO. 

The staff finds the applicant’s response acceptable because the applicant provided clarification 

of the operating power levels used to determine the neutron fluence projections, and these 

power levels are consistent with the plant’s CLB. The staff’s concern described in RAI 4.2.1-1 is 

resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii) that the 

analysis for the reactor vessel fluence has been projected to the end of the period of extended 

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.2 because (1) the 

fluence evaluation was performed in accordance with NRC-approved RG 1.190-adherent 

methodology and (2) the applicant provided 52-EFPY fluence values, which cover the period of 

extended operation. 

4.2.1.3 UFSAR Supplement 

LRA Section A.2.1.1 provides the UFSAR supplement summarizing the TLAA on the reactor 

vessel neutron fluence. The staff reviewed LRA Section A.2.1.1 consistent with the review 

procedures in SRP-LR Section 4.2, which state that the applicant should provide a summary 

description of the evaluation of the reactor vessel neutron embrittlement. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.2.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of the actions to address the neutron 

fluence analysis, as required by 10 CFR 54.21(d). 

4.2.1.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the neutron fluence analysis for the 

reactor vessel have been projected to the end of the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required per 10 CFR 54.21(d). 

4.2.2 Adjusted Reference Temperatures (ARTs) 

4.2.2.1 Summary of Technical Information in the Application 

LRA Section 4.2.2 describes the applicant’s TLAA on the ARTs for reactor vessel components. 

The LRA states that a key parameter that characterizes the fracture toughness of a reactor 

vessel material is the material reference temperature, which for the unirradiated condition is the 

RTNDT value. As neutron irradiation of the material increases, the material reference 
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temperature RTNDT increases and the embrittlement effects of neutron irradiation are reflected in 

the change (increase) in the reference temperature (RTNDT). The adjusted reference 

temperature or ART is calculated by adding RTNDT to the initial unirradiated RTNDT along with a 

margin term to account for uncertainties (M), in accordance with RG 1.99, “Radiation 

Embrittlement of Reactor Vessel Materials,” Revision 2, dated May 1988 (ADAMS Accession 

No. ML003740284). The LRA also states that the reactor vessel plate and weld materials 

included in the BWRVIP Integrated Surveillance Program (ISP) were evaluated to determine 

52-EFPY ARTs in accordance with RG 1.99, Position 2.1 (surveillance data available). The 

ART values of all other reactor vessel beltline materials were determined in accordance with 

RG 1.99 Position 1.1 (surveillance data not available). In addition, the method used to evaluate 

the 52-EFPY ARTs for 60 years of operation is the same as the method used by GEH in the 

Fermi 2 license amendment request for MUR/TPO uprate, as approved by letter dated 

February 10, 2014 (ADAMS Accession No. ML13364A131). The LRA states that the GEH 

method used to evaluate the neutron fluence values used in this TLAA adheres to the guidance 

provided in RG 1.190. The ARTs are used in the evaluation of the P-T limits as required by 

10 CFR Part 50, Appendix G, “Fracture Toughness Requirements.” 

The applicant dispositioned the TLAA for the reactor vessel in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation. 

4.2.2.2 Staff Evaluation 

The staff reviewed the applicant’s ART TLAA for the reactor vessel components and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.7.3.1.2, which state that the documented results of the revised analyses are 

reviewed to verify that their period of evaluation is extended such that they are valid for the 

period of extended operation. SRP-LR Section 4.7.3.1.2 also states that the applicable analysis 

technique can be the one in effect in the plant’s CLB at the time of filing of the renewal 

application. 

In its review, the staff noted that LRA Table 4.2-2 describes the 52-EFPY ART values of the 

reactor vessel beltline materials and other related data (e.g., material chemistry, chemistry 

factor, 52-EFPY fluence, initial RTNDT, and RTNDT). The staff also noted that the ART values in 

LRA Table 4.2-2 are calculated by using the chemistry factor tables and fluence factor 

described in RG 1.99, Revision 2, in accordance with Position 1.1. The staff reviewed the initial 

RTNDT values reported in LRA Table 4.2-2 and determined that, with the exception of the initial 

RTNDT value for the RPV N16 nozzle, the reported initial RTNDT values were acceptable because 

they were consistent with those reported for the RPV shell plates in the applicant’s response to 

Generic Letter (GL) No. 92-01, Revision 1, “Reactor Vessel Structural Integrity” dated June 30, 

1992, or for the RPV welds fabricated by the Combustion Engineering Company, as 

documented in the NRC’s letter of December 23, 1993, to the Fort Calhoun Station (i.e., to the 

Omaha Public Power District), which also has a Combustion Engineering-fabricated vessel. In 

addition, the staff noted that LRA Table 4.2-3 describes the 52-EFPY ART values of the 

surveillance plate and weld materials based on the available data from the BWRVIP ISP. The 

staff further noted that LRA Section 4.2.2 states that the representative surveillance plate and 

weld materials were evaluated for 52 EFPY in accordance with RG 1.99, Revision 2, 

Position 2.1 (surveillance data available) to generate the ART values in LRA Table 4.2-3. In 

addition, the staff noted that the LRA and onsite documentation indicate that the reactor vessel 

surveillance data are described in BWRVIP-135, Revision 2, “Integrated Surveillance Program 

(ISP) Data Source Book and Plant Evaluations.” 
4-24 

As described above, the staff noted that LRA Table 4.2-3 describes the 52-EFPY ART values of 

the surveillance plate and weld materials. However, the staff noted that LRA Table 4.2-3 is 

inconsistent with LRA Table 4.2-2 because it does not provide other related data (e.g., material 

chemistry, chemistry factor, initial RTNDT, and RTNDT) for these materials. Therefore, the staff 

could not determine the adequacy of these ART values due to the insufficient data. In addition, 

the staff noted that the LRA does not clearly address whether the ART values based on the 

surveillance data are used in the other neutron embrittlement TLAAs (e.g., LRA Section 4.2.3 

for P-T limits, Section 4.2.5 for circumferential weld inspection relief, and Section 4.2.6 for axial 

weld failure probability). 

By letter dated December 19, 2014, the staff issued RAI 4.2.2-1 requesting that the applicant 

provide the material chemistry, chemistry factor, initial RTNDT, RTNDT, and other related data for 

the surveillance materials listed in LRA Table 4.2-3, or justify why LRA Table 4.2-3 does not 

contain the data. The staff also requested that, as part of the response, the applicant identify 

the specific heat of each surveillance material that was used to generate credible surveillance 

data, and the applicant’s reactor vessel material that is represented by the surveillance material. 

In addition, the staff requested that the applicant clarify whether ART values based on credible 

surveillance data are used as the data of limiting materials in the other neutron embrittlement 

TLAAs (e.g., LRA Sections 4.2.3, 4.2.5, and 4.2.6). If credible surveillance data are not used, 

the staff further requested that the applicant state whether the conclusions of these TLAAs are 

affected by the use of credible ART values. 

In its response dated January 30, 2015, the applicant provided the requested data for the 

surveillance materials in a consistent format with LRA Table 4.2.2-1. The applicant also 

provided the information regarding the heat of the surveillance materials in companion with the 

Fermi 2 reactor vessel materials. The applicant further clarified that the heat of the surveillance 

weld material is identical to the heat used to fabricate the reactor vessel lower shell axial welds 

(i.e., Tandem Heat No. 13253/12008). In addition, the applicant clarified that the heat of the 

surveillance plate material is not identical to any heat of the reactor vessel plates so that the 

surveillance data for the plates are not used in the neutron embrittlement TLAAs. 

The applicant stated that the credible ISP data for the lower shell axial welds generated a 

52-EFPY ART of 102 °F in accordance with RG 1.99, Revision 2, Position 2.1, which is greater 

than the ART value (i.e., 87 °F) that would be calculated using Position 1.1 and the chemistry 

factor tables in RG 1.99, Revision 2. The applicant also clarified that the surveillance data for 

the limiting plate (heat number C4568-2) generated a 52-EFPY ART of 57 °F per RG 1.99, 

Revision 2, Position 2.1, and this ART value is the same as that based on RG 1.99, Revision 2, 

Position 1.1. 

The applicant clarified that ART values based on the credible surveillance data per RG 1.99, 

Revision 2, Position 2.1, were used in the TLAA evaluated in LRA Section 4.2.3, 

“Pressure-Temperature Limits.” The applicant also clarified that the surveillance materials do 

not include a representative material for the lower shell-to-lower-intermediate shell 

circumferential weld as documented in LRA Section 4.2.5, “Reactor Vessel Circumferential 

Weld Inspection Relief.” 

In its response, the applicant clarified that credible surveillance data, which were available for 

Welds 2-307A, B, and C (lower shell axial welds), were not used in support of LRA 

Section 4.2.6, “Reactor Vessel Axial Weld Failure Probability.” The applicant revised LRA 

Section 4.2.6 and Table 4.2-7 to use the credible reactor vessel surveillance data in the analysis 

of the reactor vessel axial weld failure probability. The applicant stated that in the axial weld 
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failure probability failure analysis, the ART of 102 °F, based on the credible surveillance data, is 

less than the acceptable bounding value (i.e., 114 °F) described in the staff’s SE, dated 

October 18, 2001, for BWRVIP-74 (ADAMS Accession No. ML012920549). The staff’s 

evaluation of the applicant’s revisions to LRA Section 4.2.6 and Table 4.2-7 are documented in 

SER Section 4.2.6. 

Based on its review, the staff finds the applicant’s response acceptable because: (1) the 

applicant adequately provided the reactor vessel surveillance data from the ISP and associated 

ART values, (2) the applicant clarified that its TLAA on P-T limits uses ART values based on 

credible surveillance data in accordance with RG 1.99, Revision 2, (3) the applicant clarified that 

the reactor vessel surveillance materials do not include a material that represents the 

circumferential weld evaluated in the TLAA on the reactor vessel circumferential weld inspection 

relief, and (4) the applicant adequately revised its TLAA on reactor vessel axial weld failure 

probability in accordance with Position 2.1 of RG 1.99, Revision 2, as documented in SER 

Section 4.2.6. The staff’s concern described in RAI 4.2.2-1 is resolved. 

As discussed above, LRA Table 4.2-2 describes the 52-EFPY ART values of the reactor vessel 

beltline components and other data related to the ARTs. In its review, the staff noted that LRA 

Section 4.2.1 indicates that N16 water level instrumentation nozzles are reactor vessel beltline 

components because: (1) the peak fluence for these nozzles is projected to be 3.57x1017 n/cm2 

(E > 1 MeV) at 52 EFPY, and (2) this exceeds the threshold fluence of 1x1017 n/cm2 for defining 

a reactor vessel component as a beltline component. However, the staff noted that LRA 

Table 4.2-2 does not describe ART and other related data (e.g., chemistry data, initial RTNDT, 

and RTNDT) for the N16 nozzles. The staff could not determine the adequacy of the ART 

calculations due to the omission of ART and associated data on the N16 nozzles. 

By letter dated December 19, 2014, the staff issued RAI 4.2.2-2 requesting that the applicant 

provide the ART and other related data of N16 nozzles in a format consistent with the other 

beltline components described in LRA Table 4.2-2. In its response letter dated 

January 30, 2015, the applicant provided the 52-EFPY ART (i.e., 83 °F) and associated data for 

the N16 nozzles in a format consistent with the other beltline materials. The staff finds the 

applicant’s response acceptable because the applicant provided the requested information 

regarding the ART of the N16 nozzles and the ART was calculated for 52 EFPY in accordance 

with the guidance in RG 1.99, Revision 2. The staff’s concern described in RAI 4.2.2-2 is 

resolved. 

In addition, the staff noted that the following reference indicates that, due to insufficient material 

information, the applicant determined the initial RTNDT value (i.e., unirradiated reference 

temperature) of the N16 water level instrumentation nozzles using Paragraph B.1.1(4) of NRC 

Branch Technical Position (BTP) MTEB 5-3, as given in NUREG-0800, Revision 2, “Standard 

Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants.” 

The staff noted that this initial RTNDT value was established in Section 3.2 of GEH Nuclear 

Energy Report, NEDO-33785, Revision 0, “DTE Energy/Enrico Fermi Plant 2 Pressure and 

Temperature Limits Report Up To 24 and 32 Effective Full-Power Years,” October 2012 

(ADAMS Accession No. ML13004A135). 

The NEDO-33785 indicates that testing for the N16 nozzle material, performed at a single 

temperature (10 °F), generated a minimum Charpy V-notch energy of 30 ft-lb. The 

NEDO-33785 further indicates that the initial RTNDT of the N16 nozzles was determined to be 

30 °F, which is 20 °F above the test temperature, based on NRC BTP MTEB 5-2, 
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Paragraph B.1.1(4). The NRC position, which the applicant used, is currently referred to as 

NRC BTP 5-3, Paragraph 1.1(4), as described in NUREG-0800, Revision 2, “Standard Review 

Plan for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition,” 

Chapter 5, “Reactor Coolant System and Connected Systems,” dated March 2007. 

The staff noted that a recent letter from AREVA Inc. to the NRC (ADAMS Accession 

No. ML14038A265), dated January 30, 2014, addresses a potential nonconservatism in NRC 

BTP 5-3, Paragraph 1.1(4). The letter indicates that unirradiated RTNDT values as estimated in 

accordance with BTP 5-3, Paragraph 1.1(4), may not result in a conservative bounding estimate 

of the unirradiated RTNDT. The staff noted that the LRA and onsite documentation do not clearly 

address how the applicant will resolve this concern about the potential nonconservatism in the 

initial RTNDT of N16 water level instrumentation nozzles. By letter dated December 19, 2014, 

the staff issued RAI 4.2.2-3 requesting that the applicant explain why the initial RTNDT of N16 

nozzles in LRA Section 4.2.2 is adequate given the potential nonconservatism in NRC BTP 5-3, 

Paragraph 1.1(4). 

In its response letter dated January 28, 2015, the applicant stated that it is aware of the 

potential nonconservatism inherent to NRC BTP 5-3, Paragraph 1.1(4), when used to determine 

initial RTNDT for reactor vessel beltline materials. The applicant also stated that BTP 5-3, 

Paragraph 1.1(4), was used to determine initial RTNDT for the N16 nozzles because only limited 

Charpy V-Notch tests were performed at a single temperature for the nozzle material. The 

applicant further stated that at this time there is no information that suggests that the plant is not 

operating within its approved licensing basis. In addition, the applicant stated that an 

industry-wide effort is being organized by the BWRVIP in collaboration with the EPRI PWR 

Material Reliability Program to evaluate this potential issue and determine if any actions are 

necessary. 

Based on its review of the applicant’s response, the staff noted that the ART calculations for 

reactor vessel beltline materials are based on the methodology that is part of the applicant’s 

CLB. The staff also noted that the BWRVIP is coordinating an effort to evaluate potential 

nonconservatism associated with NRC BTP 5-3 in calculating initial RTNDT for reactor vessel 

materials. The staff further noted that the potential nonconservatism associated with BTP 5-3 is 

an operating reactor 10 CFR Part 50 issue and is not within the scope of license renewal, in 

accordance with 10 CFR 54.30. Therefore, the staff finds the applicant’s response acceptable 

because the applicant is participating in the industry-coordinated effort to resolve this potential 

issue that is within the scope of the CLB. The staff’s concern described in RAI 4.2.2-3 is 

resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the ART 

analysis for the reactor vessel has been projected to the end of the period of extended 

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the 

applicant’s analysis adequately evaluates the effects of neutron irradiation embrittlement 

including the surveillance data in accordance with RG 1.99, Revision 2, and 10 CFR Part 50, 

Appendix H, “Reactor Vessel Material Surveillance Program Requirements.” 

4.2.2.3 UFSAR Supplement 

LRA Section A.2.1.2 provides the UFSAR supplement summarizing the TLAA on the ARTs of 

reactor vessel beltline components. The staff reviewed LRA Section A.2.1.2 consistent with the 

review procedures in SRP-LR Section 4.7.3.2, which state that the reviewer verifies that the 
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applicant has provided information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of each TLAA. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA on the 

ARTs of reactor vessel beltline components, as required by 10 CFR 54.21(d). 

4.2.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the ART analysis for the reactor vessel 

beltline components have been projected to the end of the period of extended operation. The 

staff also concludes that the UFSAR supplement contains an appropriate summary description 

of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.2.3 Pressure-Temperature Limits 

4.2.3.1 Summary of Technical Information in the Application 

LRA Section 4.2.3 describes the applicant’s TLAA on P-T limits. The NRC regulations in 

10 CFR Part 50, Appendix G, require that the reactor vessel remain within established P-T limits 

during boltup, hydro-test, pressure tests, normal operation, and anticipated operational 

occurrences. The LRA states that these limits are calculated using materials and fluence data, 

including data obtained through the Reactor Vessel Surveillance Program (LRA Section B.1.38). 

The provisions of 10 CFR Part 50, Appendix G, require plants to operate within the licensed P-T 

limit curves. The P-T limit curves are maintained and updated as necessary to maintain plant 

operation, in accordance with 10 CFR Part 50, Appendix G. The LRA also states that these P-T 

limit curves will be updated as necessary through the period of extended operation in 

conjunction with the Reactor Vessel Surveillance Program. The water level instrumentation 

nozzles (N16) are also evaluated using the neutron fluence at the nozzles and the material 

properties of the irradiated nozzles. 

The applicant dispositioned the TLAA for the reactor vessel components in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of loss of fracture toughness due to 

neutron irradiation embrittlement on the intended functions will be adequately managed in 

accordance with the requirements of 10 CFR Part 50, Appendix G for the period of extended 

operation. 

4.2.3.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the reactor vessel components and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in 

SRP-LR Section 4.2.3.1.3.3. The review procedures indicate that (1) updated P-T limits for the 

period of extended operation must be available prior to the period of extended operation and 

(2) an adequate process to maintain and update the P-T limits through the period of extended 

operation is the 10 CFR 50.90, “Application for Amendment of License, Construction Permit, or 

Early Site Permit,” process for P-T limits located in the limiting conditions of operation (LCOs) of 

plant TS or an administrative process for updating P-T limits located in a P-T limits report 

(PTLR), as controlled by the administrative controls section of the plant TS. SRP-LR 

Section 4.2.3.1.3.3 also states that for BWRs, the staff confirms that the applicant addresses 
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AAI No. 9 that is specified in the staff’s SE for BWRVIP-74 dated October 18, 2001 (ADAMS 

Accession No. ML012920549). The action item is that the applicant, who has not provided 

updated P-T limits for the period of extended operation, shall have a process for updating P-T 

limits prior to the period of extended operation in accordance with 10 CFR Part 50, Appendix G, 

that will cover 60 years of operation. 

The staff reviewed the applicant’s CLB to determine whether the applicant controls updates of 

its P-T limits through updates of the LCOs in the plant TS in accordance with the 10 CFR 50.90 

license amendment process, or through a PTLR process that is governed and controlled by the 

administrative controls section of the plant TS. Specifically, the staff noted that, by letter dated 

February 4, 2014, the staff approved a license amendment for Fermi 2 that granted the 

relocation of P-T limit curves from the TS LCOs into a PTLR. In this license amendment, the 

staff approved the provisions in TS 5.6.8 that will be used to implement the PTLR process for 

Fermi 2. 

The staff further noted that the applicant uses a staff-approved methodology to determine P-T 

limits for the reactor coolant system as described in GEH Corporation TR NEDC-33178P-A, “GE 

Hitachi Nuclear Energy Methodology for Development of Reactor Pressure Vessel 

Pressure-Temperature Curves,” Revision 1, dated June 2009. The staff also noted that the 

methodology for P-T limits is also referenced in TS 5.6.8 of Fermi 2. In addition, the staff noted 

that the methodology was also used to support a license amendment for measurement 

uncertainty recapture (MUR) power uprate as approved in the staff’s letter to J. Plona dated 

February 10, 2014. The staff noted that TS 5.6.8 requires that the applicant (a) implement the 

methodology in GEH Report NEDC-33178P-A, Revision 1, for updates of P-T limits and 

(b) provide the PTLR to the staff upon issuance for each reactor vessel fluence period and for 

any revision or supplement thereto. The staff also noted that LRA Appendix C addresses AAI 

No 9 for BWRVIP-74 by stating that development of P-T limits for the period of extended 

operation has been evaluated as a TLAA in LRA Section 4.2.3 and that P-T limit curves will 

continue to be updated in accordance with 10 CFR Part 50, Appendix G. 

As discussed above, the staff confirmed that the applicant implemented an administrative 

controls process (i.e., PTLR process) to update P-T limits through the period of extended 

operation in accordance with 10 CFR Part 50, Appendix G, and GL 96-03, “Relocation of the 

Pressure Temperature Limit Curves and Low Temperature Overpressure Protections System 

Limits,” dated January 31, 1996. The staff also confirmed that the applicant uses a 

staff-approved methodology to determine P-T limits as referenced in TS 5.6.8. The staff further 

noted that the applicant’s disposition of this TLAA on P-T limits in accordance with 

10 CFR 54.21(c)(1)(iii) is consistent with the incorporation of the PTLR process and the 

TS 5.6.8 requirements into the CLB. In addition, the staff noted that the applicant adequately 

addressed AAI No. 9 for BWRVIP-74 to ensure that P-T limits will be updated for the period of 

extended operation before entering the extended operation. 

The staff noted that the applicant uses material test data, which are obtained from the Reactor 

Vessel Surveillance Program, to determine the ARTs for reactor vessel materials as a measure 

of neutron irradiation embrittlement. The staff noted that the ARTs used in the P-T limits 

analysis are determined in accordance with RG 1.99, Revision 2, as documented in SER 

Section 4.2.2.2. In addition, the staff noted that the neutron fluence for reactor vessel 

components is calculated in accordance with the guidance in RG 1.190. Therefore, the staff 

finds that the applicant’s TLAA on P-T limits adequately evaluates neutron irradiation effects on 

reactor vessel components in accordance with the guidance in RG 1.99, Revision 2, and 

RG 1.190. 
4-29 

The staff finds that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of loss of fracture toughness due to neutron irradiation embrittlement on the intended 

functions of the reactor vessel components will be adequately managed in accordance with the 

PTLR process and TS 5.6.8 requirements during the period of extended operation. Additionally, 

it meets the acceptance criteria in SRP-LR Section 4.2.2.1.3.3 because the PTLR process and 

TS 5.6.8 requirements provide an adequate basis for accepting this TLAA in accordance with 

10 CFR 54.21(c)(1)(iii). 

4.2.3.3 UFSAR Supplement 

LRA Section A.2.1.3 provides the UFSAR supplement summarizing the TLAA on the P-T limits 

of reactor vessel beltline components. The staff reviewed LRA Section A.2.1.3 consistent with 

the review procedures in SRP-LR Section 4.2.3.2, which state that the reviewer verifies that the 

applicant has provided information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of the reactor vessel neutron embrittlement TLAA. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.2.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA on the 

P-T limits of reactor vessel beltline materials, as required by 10 CFR 54.21(d). 

4.2.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of loss of fracture toughness 

due to neutron irradiation embrittlement on the intended function of the reactor vessel 

components will be adequately managed for the period of extended operation by the applicant’s 

implementation of the PTLR process and TS 5.6.6 requirements. The staff also concludes that 

the UFSAR supplement contains an appropriate summary description of the TLAA evaluation, 

as required by 10 CFR 54.21(d). 

4.2.4 Upper-Shelf Energy 

The NRC’s requirements for performing USE analyses of ferritic base-metal components 

(i.e., plate or forging components) and ferritic weld components in the beltline region of the RPV 

are specified in 10 CFR Part 50, Appendix G. The rule requires the USE values for these RPV 

components to be greater than or equal to 50 ft-lb at the end of the licensed operating period. 

These analyses are TLAAs because the analyses meet all six of the criteria in 10 CFR 54.3(a) 

that define an analysis as a TLAA. 

4.2.4.1 Summary of Technical Information in the Application 

LRA Section 4.2.4 describes the applicant’s TLAA evaluation for calculating the USE values for 

base metal and weld components that are made from ferritic steel materials and are located in 

the beltline region of the RPV. The LRA states that the applicant calculated the USE values 

using methods that are consistent with NRC’s methods of analysis in RG 1.99, Revision 2. The 

LRA states that these calculations are based on the peak neutron fluence values for the 1/4T 

locations of the components in the RPV through 52 EFPY, which bounds the maximum possible 

EFPY at the end of the period of extended operation. The LRA also states that the applicant 

adjusted the fluence values for the RPV axial weld locations, where appropriate. Concerning 
4-30 

the results, the LRA states that the USE values for all of the ferritic steel components in the RPV 

will remain above 50 ft-lb throughout the period of extended operation. 

The applicant dispositioned the TLAA for USE of the RPV beltline materials in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation. 

4.2.4.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA on USE for the RPV beltline region metal and weld 

components, and the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the 

review procedures in SRP-LR Section 4.2.3.1.1.2. Specifically, the SRP-LR states that the staff 

is to review the documented results of the applicant’s updated USE analysis based on the 

projected neutron fluence at the end of the period of extended operation and compare the 

analytical results against the USE analysis requirements in 10 CFR Part 50, Appendix G. The 

regulation requires the USE values for the ferritic base-metal components (i.e., plates or forged 

components) and ferritic weld components in the beltline region of the RPV to be greater than or 

equal to 50 ft-lb at the end of the licensed operating period. 

Concerning the neutron fluence projections, SRP-LR Section 4.2.3.1.1.2 states that the 

applicant should identify the neutron fluence at the 1/4T location for each RPV beltline 

component at the expiration of the license renewal period. The staff reviewed LRA Table 4.2-4 

and determined that it contains this information. SRP-LR Section 4.2.3.1.1.2 also states that the 

applicant should identify the methodology that it used to determine the neutron fluence 

projections and indicate whether this methodology follows the guidance in RG 1.190. The staff 

noted that LRA Section 4.2.1 indicates that the applicant determined the neutron fluence values 

using the methodology in GE Report NEDO-32983-A, Revision 2, “General Electric 

Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations,” dated January 2006 

(ADAMS Accession No. ML072480121), and that this methodology adheres to the guidance in 

RG 1.190. Based on a review of the staff’s SEs on this methodology, which were transmitted by 

letters dated September 14, 2001 (ADAMS Accession No. ML012400381), and 

November 17, 2005 (ADAMS Accession No. ML053210469), the staff confirmed that 

NEDO-32983-A, Revision 2, is a staff-approved methodology that follows the guidance in 

RG 1.190. Therefore, the staff determined that the applicant’s 1/4T fluence projections for the 

updated USE analysis are acceptable. 

To confirm that the revised USE analysis meets the requirements of 10 CFR Part 50, 

Appendix G, at the end of the period of extended operation, SRP-LR Section 4.2.3.1.1.2 states 

that the staff should determine whether the applicant followed the guidance in RG 1.99, 

Revision 2, to perform the update of the USE analysis or whether the applicant used an 

equivalent margins analysis as the basis for complying with USE requirements 

in10 CFR Part 50, Appendix G. The staff noted that the LRA indicates that the applicant used 

the guidance in RG 1.99, Revision 2, to perform its update of the USE analysis; therefore, the 

staff reviewed this analysis to confirm that it adheres to the guidance in RG 1.99, Revision 2. 

SRP-LR Section 4.2.3.1.1.2 states that, for reviews of RPV beltline component USE analyses, 

the reviewer should confirm that the applicant has provided both the UUSE values and the 

projected USE values for the components at the end of the license renewal period. The 

SRP-LR also states that the reviewer should determine whether the percent decreases in the 

USE values were established using the limit lines in Figure 2 of RG 1.99, Revision 2, or from 

applicable RPV surveillance data obtained from implementation of 10 CFR Part 50, Appendix H, 
4-31 

“Reactor Vessel Material Surveillance Program Requirements.” The staff’s review of LRA 

Section B.1.38, “Reactor Vessel Surveillance,” is documented in SER Section 3.0.3.2.19. LRA 

Table 4.2-4 provides these values for the lower shell plate, lower-intermediate shell plate, axial 

weld, and circumferential weld components in the RPV, along with the values for the percent 

copper content. 

The staff reviewed the UUSE values reported in LRA Table 4.2-4 and determined that, with the 

exception of the UUSE value for the RPV N16 nozzle, the reported UUSE values were 

acceptable because they were consistent with those reported for the RPV shell plates in the 

applicant’s response to GL No. 92-01, Revision 1, “Reactor Vessel Structural Integrity,” dated 

June 30, 1992, or for RPV weld materials, as provided in NRC documentation for CE-fabricated 

vessel welds, in BWRVIP-74-A for non-Linde 80 submerged arc welds, or in other applicable 

BWRVIP reports. However, the staff noted that LRA Table 4.2-4 appeared to be incomplete 

because it did not provide the UUSE value or the percent decrease in USE value for the RPV’s 

N16 instrumentation nozzle. In addition, it was not evident which methodology was used to 

establish the UUSE value and percent decrease in USE value for the N16 instrumentation 

nozzle. By letter dated January 26, 2015, the staff issued RAI 4.2.4-1, requesting that the 

applicant provide these values and identify and justify the methodology that was used to 

establish or calculate them. Alternatively, the staff requested that the applicant provide an 

explanation as to why LRA Table 4.2-4 omits the UUSE and percent decrease in USE values for 

the N16 instrumentation nozzle. 

By letter dated March 5, 2015, the applicant provided its response to RAI 4.2.4-1. In its 

response, the applicant provided a proprietary UUSE value for the RPV N16 instrumentation 

nozzle plate materials that was lower than and more conservative than the nonproprietary 

UUSE values that were reported for the shell plates in the lower shell and lower-intermediate 

shells of the RPV. The applicant stated that the UUSE value was determined from 

Charpy-impact data in a set of fleetwide certified material test reports. The applicant stated that 

the UUSE value was calculated using a statistical 95/95 lower tolerance limit as defined in 

Section 9.12, “Statistical Tolerance Limits for a Normal Population,” to NUREG-1475, “Applying 

Statistics,” Revision 1, dated March 2011 (ADAMS Accession No. ML11102A076). The 

applicant stated that, using the 52-EFPY 1/4T fluence of 2.47 x 1017 n/cm2 (E > 1 MeV) for the 

N16 instrumentation nozzle, it identified a 16 percent decrease in USE value for the N16 

instrumentation nozzle. Based on its assessment, the applicant identified a 52 ft-lb USE value 

for the N16 instrumentation nozzle at the end of the period of extended operation (i.e., at 

52 EFPY). 

Based on the UUSE and copper content values reported in the response to RAI 4.2.4-1, the 

staff independently calculated that the percent decrease in USE value for the N16 nozzle was 

16 percent of the UUSE value reported for the component. Based on its review, the staff finds 

the applicant’s response acceptable because (1) the applicant has provided the UUSE and 

percent decrease in USE values for the N16 instrumentation nozzle plate materials and (2) the 

staff has confirmed that these values are based on conservatively established bases in 

staff-accepted reports and the USE analysis guidelines in RG 1.99, Revision 2, and are 

acceptable when compared to those independently calculated by the staff. The staff’s concern 

described in RAI 4.2.4-1 is resolved. 

SRP-LR Section 4.2.3.1.1.2 also states that the applicant should indicate whether it calculated 

the percent decrease in USE values using the USE calculation extrapolation lines in Figure 2 of 

RG 1.99, Revision 2, or whether it used available surveillance data. RG 1.99, Revision 2, 

Regulatory Position 1.2, describes the former approach, whereas Regulatory Position 2.2 
4-32 

describes the latter approach. Based on its review of LRA Table 4.2-4, the staff determined that 

the applicant used Regulatory Position 1.2 to determine the percent decrease in USE values for 

all of the plate and axial weld components in the lower shell and lower-intermediate shell of the 

RPV, and for the lower shell-to-lower intermediate shell girth weld and plate material used in the 

fabrication of the RPV N16 instrumentation nozzle. The staff reviewed these values and, given 

the percent copper content and fluence projection values for each RPV component material, 

confirmed that the applicant correctly calculated them using Figure 2 in RG 1.99, Revision 2. 

LRA Table 4.2-4 indicates that the applicant also used Regulatory Position 2.2 to determine the 

percent decrease in USE values for the vertical and girth weld materials based on data from the 

BWR ISP. In addition, LRA Table 4.2-5 provides fluence and USE values from the ISP for 

plates and welds. However, the staff could not determine how the ISP data were applied to 

RPV USE calculations for 52 EFPY because the LRA did not include all of the relevant ISP data 

that are representative of the plate and weld components in the RPV. By letter dated 

January 26, 2015, the staff issued RAI 4.2.4-2 requesting that the applicant provide all host 

reactor capsule testing data from the ISP that were used in USE calculations of RPV axial welds 

and circumferential weld components in the RPV at 52 EFPY. The staff also requested the 

applicant to explain how the ISP data were applied to the USE calculations for these 

components at 52 EFPY. 

By letter dated March 5, 2015, the applicant provided its response to RAI 4.2.4-2. The staff 

noted that the applicant’s response to RAI 4.2.4-2 provided the applicable appropriate ISP data 

for ISP host reactor welds that are evaluated and have a direct match to heat of materials used 

in the fabrication of the beltline weld components in the Fermi 2 RPV. The staff confirmed that, 

for the Fermi 2 RPV, this is the heat of material used (Tandem Heat No. 13253/12008) in the 

fabrication of RPV lower shell axial welds 2-307, A, B, and C. The staff finds this to be 

acceptable because the staff has determined that the data are consistent with those reported for 

Fermi 2 in applicable BWRVIP reports, as submitted for implementation of the ISP. The staff 

did not apply the ISP data to the USE calculations for the materials used to fabricate lower 

intermediate shell axial welds 15-308, A, B, and C (i.e., weld heat No. 33A277) and the lower 

shell-to-lower intermediate shell circumferential weld 1-313 (i.e., weld heat No. 10137) because 

the supplemental surveillance program capsules E and G in the ISP (as pulled on behalf of the 

Fermi 2 RPV welds) do not include these heats of material. This is consistent with the basis in 

BWRVIP-86, Revision 1-A. The staff’s concern described in RAI 4.2.4-2 is resolved. 

SRP-LR Section 4.2.3.1.1.2 states that the applicant should also provide the results of revised 

USE analysis (i.e., the USE values), as projected at the end of the period of extended operation. 

LRA Table 4.2-4 provides the USE values for all RPV beltline components at the end of the 

period of extended operation (i.e., through 52 EFPY). The staff noted that this includes the USE 

values that were performed at 52 EFPY for the N16 instrumentation nozzle plates, the RPV 

shell plates and axial welds in the lower shell and lower-intermediate shells of the RVP, and the 

RPV’s lower shell-to-lower intermediate shell circumferential weld. The staff confirmed that all 

of these values were calculated correctly in accordance with methods of analysis in Regulatory 

Position 1.2 of RG 1.99, Revision 2. The staff also confirmed that the applicant provided the 

52-EFPY USE calculation for the RPV lower shell axial welds 2-307, A, B, and C using the 

applicable RPV surveillance data from the ISP. From these results, the staff confirmed that the 

applicant’s assessment is limited by the USE calculation for the RPV N16 instrumentation 

nozzle, with a projected USE value of 52 ft-lb at the end of the period of extended operation 

(i.e., at 52 EFPY). 
4-33 

The staff performed independent calculations of the USE values for the RPV welds, nozzles, 

and plates at the end of the period of extended operation based on the data provided in the 

LRA, as amended in the applicant’s responses to RAIs 4.2.4-1 and 4.2.4-2. The staff’s 

calculations included calculations of the USE value for the RPV lower shell axial welds 

(Nos. 2-307, A, B, and C) using both the method of analysis in Regulatory Position 1.2 and 

Regulatory Position 2.2 of RG 1.99, Revision 2, which is the method that is used if there are 

applicable surveillance data that apply to the USE analysis. Based on its independent 

assessment, the staff confirmed that the USE analysis is limited by the 52-EFPY projection for 

the RPV’s N16 instrumentation nozzle. The staff independently calculated a USE value greater 

than 50 ft-lb for the N16 instrumentation nozzles at the end of the period of extended operation 

(i.e., at 52 EFPY). The applicant’s limiting USE value (52 ft-lb) and staff’s independent 

calculation of the limiting USE value (greater than 50 ft-lb) demonstrate that the USE values for 

the ferritic base-metal (i.e., plates) and weld components in the RPV will meet the lower-bound 

10 CFR Part 50, Appendix G, requirement of 50 ft-lb at the end of the period of extended 

operation. 

The staff finds that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

USE analysis for the RPV has been adequately projected to the end of the period of extended 

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.2.2.1.1.2 because 

the RPV beltline components were re-evaluated to consider the period of extended operation in 

accordance with 10 CFR Part 50, Appendix G. 

4.2.4.3 UFSAR Supplement 

LRA Section A.2.1.4 provides the UFSAR supplement summarizing the TLAA for USE of the 

RPV beltline materials. The staff reviewed LRA Section A.2.1.4 consistent with the review 

procedures in SRP-LR Section 4.2.3.2, which state that the reviewer is to verify that the 

applicant has provided a supplement with information that is equivalent to the examples in 

SRP-LR Table 4.2-1. 

The staff compared the summary description in LRA Section A.2.1.4 against the example for 

USE analyses in SRP-LR Table 4.2-1. Whereas the example summary description includes a 

comparison of the results of the revised USE analysis against the requirements of 

10 CFR Part 50, Appendix G, the staff found that no such information is included in the 

summary description proposed by the applicant. The staff determined that the applicant’s 

summary description does not contain adequate information regarding the basis for its 

demonstration made pursuant to 10 CFR 54.21(c)(1)(ii). Therefore, by letter dated 

January 26, 2015, the staff issued RAI 4.2.4-3 requesting that the applicant provide justification 

as to why the results of the TLAA are not included in the UFSAR supplement. Otherwise, the 

staff requested that the applicant revise LRA Section A.2.1.4 to include a comparison of the 

results of the revised USE analysis against the requirements of 10 CFR Part 50, Appendix G. 

By letter dated March 5, 2015, the applicant provided its response to RAI 4.2.4-3. In its 

response, the applicant amended UFSAR supplement Section A.2.1.4 to state: 

[USE] is evaluated for beltline materials. Fracture toughness criteria in 

10 CFR 50 Appendix G require that beltline materials maintain USE no less than 

50 ft-lb during operation of the reactor. The 52 EFPY USE values for the beltline 

materials were determined using methods consistent with RG 1.99. The 

determination used the peak 1/4T fluence. The results of the evaluation 

demonstrate that all beltline material remains above 50 ft-lb throughout the 
4-34 

period of extended operation. The [TLAA] for [USE] has been projected to the 

end of the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(ii). 

The staff reviewed the applicant’s response to RAI 4.2.4-3 and amended version of UFSAR 

Supplement Section A.2.1.4 and finds it acceptable because the UFSAR supplement provides 

sufficient information to describe how the TLAA on USE has been projected to the end of the 

period of extended operation and why the projected analysis meets the USE analysis 

requirements in 10 CFR Part 50, Appendix G. The staff’s concern described in RAI 4.2.4-3 is 

resolved. 

Based on its review of the UFSAR supplement, as amended in the letter of March 5, 2015, the 

staff finds it meets the acceptance criteria in SRP-LR Section 4.2.2.2, and is therefore 

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address the USE of the RPV beltline materials, as required by 

10 CFR 54.21(d). 

4.2.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for the USE of the RPV 

beltline materials has been projected to the end of the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.2.5 Reactor Vessel Circumferential Weld Inspection Relief 

4.2.5.1 Summary of Technical Information in the Application 

LRA Section 4.2.5 describes the applicant’s TLAA for the probabilistic fracture mechanics 

analysis based on 52-EFPY mean RTNDT for the RPV circumferential welds. The LRA states 

that relief from the inservice inspection (ISI) requirements of the RPV circumferential welds was 

requested in a relief request (No. RR-A25) dated August 19, 1999. This relief request was 

supplemented in a letter dated March 15, 2000. 

The applicant stated that a re-evaluation of the circumferential weld inspection relief basis for 

power operations up to 32 EFPY was included in the MUR power uprate submittal to evaluate 

the effects of the increased power as approved by the NRC. The applicant stated that the 

method used in the MUR power uprate re-evaluation was also used to evaluate the acceptability 

of the relief through the period of extended operation (up to 52 EFPY). 

The LRA states that the staff’s final safety evaluation report (FSER) for the BWRVIP-05 report 

identifies that a licensee may request relief from the ASME-defined volumetric ISI requirements 

for RPV circumferential welds by demonstrating that they meet the following acceptance criteria: 

(a) at the expiration of the license, the circumferential welds will satisfy the limiting conditional 

failure probability for the circumferential welds, and (b) operator training and procedures that 

limit the frequency of cold over-pressure events to the amounts specified in the FSER will be 

implemented. The applicant stated that the CLB includes procedures and TS requirements for 

monitoring and controlling reactor pressure, temperature, and water inventory during all aspects 

of cold shutdown operations in order to minimize the likelihood of a LTOP event. The applicant 

stated that it also provides operator training for implementation of these procedures. 
4-35 

The LRA indicates that the RPV was fabricated by CE. LRA Table 4.2-6 provides a comparison 

of the limiting mean RTNDT value of the circumferential welds in the Fermi 2 RPV to that listed in 

the BWRVIP-05 report for circumferential welds in CE-designed RPVs. The applicant stated 

that LRA Table 4.2-6 demonstrates that the mean RTNDT value for the limiting circumferential 

weld in the Fermi 2 RPV is less than the limiting mean RTNDT value listed in the BWRVIP-05 

report for CE-designed RPV circumferential weld components. The LRA also states that ISI 

examinations of the RPV axial welds are performed in accordance with 10 CFR 50.55a and the 

applicable ASME Code Section XI ISI requirements for performing volumetric examinations of 

these types of welds. The applicant stated that previous ISI examinations of the axial welds in 

the RPV have not revealed any active mechanistic mode of degradation in the axial welds. The 

applicant also stated that examination of the circumferential welds will be performed if axial 

welds examinations reveal an active mechanistic mode of degradation. The applicant further 

stated that a request for relief for the period of extended operation will be submitted to the NRC 

in accordance with 10 CFR 50.55(a), and that this serves as an acceptable basis for 

demonstrating that the effects of aging associated with the reactor vessel circumferential weld 

inspection relief TLAA will be managed in accordance with the requirements in 

10 CFR 54.21(c)(1)(iii). 

4.2.5.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA associated with the RPV circumferential weld 

inspection and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the 

review procedures in SRP-LR Section 4.2.3.1.4, which state the following: 

The staff verifies that the applicant has identified that, should the inspection relief 

be desired for the period of extended operation, an application will be made 

under 10 CFR 50.55a(a)(3) prior to entering the period of extended operation. If 

the applicant indicates that relief from circumferential weld examination will be 

made under 10 CFR 50.55a(a)(3), the applicant will manage this TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii). 

In addition, the acceptance criteria in SRP-LR Section 4.2.2.1.4 states that some BWRs have 

an approved technical alternative, which eliminates the reactor vessel circumferential shell weld 

inspections for the current license term because they satisfy the limiting conditional failure 

probability for the circumferential welds at the expiration of the current license, based on 

BWRVIP-05 and the extent of neutron embrittlement. The acceptance criteria in SRP-LR 

Section 4.2.2.1.4 is based on the alternative probabilistic fracture mechanics methodology in 

BWRVIP-05. The staff confirmed that the applicant had requested the applicable code relief of 

the RPV circumferential welds for the current operating period in Relief Request No. RR-A25, 

dated March 15, 2000. The staff approved Relief Request No. RR-A25 in an SE dated 

March 30, 2000 (ADAMS Accession No. ML003697623). 

The staff reviewed the mean RTNDT calculation and data that were provided in LRA Table 4.2-6 

for the RPV circumferential welds to determine whether the TLAA can be accepted in 

accordance with the criterion in 10 CFR 54.21(c)(1)(iii), such that a relief request could be 

submitted for the RPV circumferential welds for the period of extended operation. The staff 

reviewed the applicant’s mean RTNDT in comparison to a limiting mean RTNDT acceptance 

criterion value of 113 °F, as discussed in the staff’s SE report for the BWRVIP-05 report. 

The staff confirmed that all of the input parameters (i.e., copper (Cu) and nickel (Ni) alloying 

contents and unirradiated RTNDT value) used for the mean RTNDT calculation in LRA Table 4.2-6 
4-36 

were consistent with those incorporated in the CLB for Fermi 2 and provided in previous 

correspondence letters to the NRC, including the applicant’s responses to GL 92-01, 

Supplement 1, and GL 92-01, Supplement 1, Revision 1. 

The staff also noted the applicant’s mean RTNDT calculation uses the cumulative RPV inside 

surface neutron fluence for the limiting RPV circumferential weld (i.e., RPV weld 1-313, as made 

from Heat No. 10137) as reported for 52 EFPY in LRA Table 4.2-2. The staff found this neutron 

fluence value to be acceptable for the calculation because the staff has confirmed that the 

52-EFPY neutron fluence value was calculated in accordance with the applicable GEH neutron 

fluence methodology that was approved for the CLB by the staff’s SE of September 14, 2001 

(ADAMS Accession No. ML012400381), as supplemented by the SE of November 17, 2005 

(ADAMS Accession No. ML053210469). 

In addition, the staff noted that the applicant’s mean RTNDT calculation applies the appropriate 

chemistry factor for the weld heat of material, as determined from the Cu and Ni alloying 

contents for the material and Table 1 of RG 1.99, Revision 2. The staff also confirmed that the 

mean RTNDT value of 48.3 °F, as projected for the RPV circumferential weld 1-313 at 52 EFPY, 

is lower than the limiting mean RTNDT value of 113 °F that was discussed in the staff’s SE for the 

BWRVIP-05 report. Therefore, based on these confirmations, the staff confirmed that the mean 

RTNDT value calculated for RPV lower shell-to-lower intermediate shell weld 1-313 was 

acceptable because it was both consistent with the method for calculating mean RTNDT values in 

the BWRVIP-05 report and less than the mean RTNDT value discussed in the staff’s SE for the 

BWRVIP-05 report. 

The staff noted that LRA Section B.1.38 provides the applicant’s Reactor Vessel Surveillance 

Program and indicates that the AMP is based on implementation of the BWRVIP ISP that has 

been approved by the staff in BWRVIP-86, Revision 1-A. The staff noted that this AMP relies 

on specific RPV surveillance data that are obtained from specific RPV surveillance materials in 

host reactors that are representative of the base metal and weld materials used in the 

fabrication of the Fermi 2 RPV. However, the staff noted that LRA Table 4.2-6 did not include 

an analogous mean RTNDT analysis for RPV circumferential weld 1-313 that was based on the 

use of ISP surveillance data for the facility’s RPV welds. The staff noted that additional 

information was needed for the applicant to demonstrate acceptance of this TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii). 

By letter dated December 17, 2014, the staff issued RAI 4.2.5-1, requesting that the applicant 

clarify whether the surveillance weld materials from the host reactors representing Fermi 2 in 

the BWRVIP ISP (i.e., the BWRVIP-86, Revision 1-A program) are a match to the weld heat for 

RPV circumferential weld 1-313 (i.e., Heat No. 10137). If so, the staff requested the applicant to 

provide the basis as to why LRA Table 4.2-6 did not include an additional mean RTNDT

calculation for this circumferential weld using (a) the applicable ISP surveillance weld data from 

the host reactors and (b) the methodology in Section 5.2 of BWRVIP-86, Revision 1-A, for 

calculating the chemistry factor and ∆RTNDT values using the applicable ISP surveillance weld 

data. The staff also requested that, if the heat of material for surveillance weld materials in the 

host reactors is not a match to the heat of material for RPV circumferential weld 1-313, the 

applicant should clarify how the ISP surveillance weld data from the host reactors supports the 

adequacy of the predicted ∆RTNDT value used in the mean RTNDT calculation for RPV 

circumferential weld 1-313, as provided in LRA Table 4.2-6. 

By letter dated January 15, 2015, the applicant provided its response to RAI 4.2.5-1. In its 

response, the applicant clarified that the surveillance weld materials from the host reactors 
4-37 

representing Fermi 2 in the BWRVIP ISP are not a match to weld heat for RPV lower 

shell-to-lower intermediate shell circumferential weld 1-313 (i.e., Heat No. 10137). The staff 

noted that the applicant would only apply the RPV surveillance data as the basis for performing 

the RTNDT calculation for this weld if the welds in the ISP host reactors were made from the 

same heat of material used in the fabrication of weld 1-313. Based on this information, the staff 

finds that the chemistry factor tables in RG 1.99, Revision 2, are the appropriate basis for 

performing the calculation of the mean RTNDT calculation for lower shell-to-lower intermediate 

shell circumferential weld 1-313 because the host reactor surveillance data do not apply to the 

heat of material used to fabricate weld 1-313. The staff’s concern described in RAI 4.2.5-1 is 

resolved. 

In the BWRVIP-05 report and in Section 4 of the SE for the BWRVIP-05 report, the staff 

approved the EPRI BWRVIP basis that the relief from the ASME Code inspections will not be 

valid, and that the ASME-defined volumetric inspections of the RPV circumferential welds will 

need to be performed if the corresponding ISI examinations of the RPV axial welds reveal the 

presence of an active age-related degradation mechanism in the welds. The staff noted that 

LRA Section 4.2.5 states that examinations of the RPV circumferential welds will be performed if 

the ISI examinations of the RPV axial welds “reveal an active mechanistic mode of 

degradation.” The staff found this statement to be acceptable because it is consistent with the 

basis in the BWRVIP-05 report and the corresponding staff’s FSER. 

The staff also noted that LRA Section 4.7.5 provides the applicant’s plant-specific TLAA for 

flaws that were detected in the applicant’s RPV and the basis for dispositioning this TLAA in 

accordance with 10 CFR 54.21(c)(1)(ii). However, the staff noted that LRA Section 4.7.5 did not 

indicate whether these flaws were located in the RPV welds or had initiated or are growing as 

the result of an active mechanistic mode of degradation (i.e., as a result of an age-related 

initiation or growth mechanism). 

By letter dated December 17, 2014, the staff issued RAI 4.2.5-2, requesting that the applicant 

clarify whether the RPV flaws discussed in LRA Section 4.7.5 were detected in any of the welds 

used in the fabrication of the RPV. The staff also asked the applicant to identify whether the 

flaws had initiated or are currently growing as a result of an active degradation mechanism, and 

if so, to justify whether volumetric inspections of the RPV circumferential welds would need to 

be performed during the period of extended operation in accordance with the applicable ASME 

Code Section XI ISI requirements. 

By letter dated January 15, 2015, the applicant provided its response to RAI 4.2.5-2. In its 

response, the applicant stated that the applicable RPV flaws were detected in an RPV 

fabrication weld and were associated with slag deposits resulting from the welding process. 

The applicant stated that the flaws are subsurface flaws, which were evaluated by a detailed 

fracture mechanics analysis that demonstrated that the flaws are not susceptible to flaw growth. 

The applicant also stated that repeated examination has confirmed that there has been no 

growth of these flaws. 

The staff finds the applicant’s response acceptable because it demonstrated that the RPV flaws 

are not associated with an active degradation issue that, if otherwise present, would require the 

applicant to perform the ASME-defined volumetric inspections of the RPV circumferential welds 

during the period of extended operation and would invalidate any basis for requesting approval 

of an ISI relief request for the welds during the period of extended operation in accordance with 

10 CFR 50.55a(z). The staff’s concern described in RAI 4.2.5-2 is resolved. 
4-38 

For the second criterion for RPV circumferential weld relief request acceptance, the applicant 

stated that it has implemented operator training and established procedures that limit the 

frequency of cold over-pressure events to the levels specified in the staff’s FSER for the 

BWRVIP-05 report. The applicant also stated that the CLB includes procedures and TS 

requirements for monitoring and controlling reactor pressure, temperature, and water inventory 

during all aspects of cold shutdown operations to minimize the likelihood of an LTOP event at 

Fermi 2. Although this is not specifically related to any time-limited parameter subject to a TLAA 

review, the staff finds that the continued implementation of operator training and procedures to 

limit the frequency of cold over-pressure events meets the second criterion in the staff’s FSER 

for the BWRVIP-05 report. 

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cracking on the intended functions of the RPV circumferential welds will be adequately 

managed for the period of extended operation. Additionally, the applicant’s analysis meets the 

acceptance criteria in SRP-LR Section 4.2.2.1.4 because: 

(a) The applicant has demonstrated that the conclusions of the BWRVIP-05 report are 

applicable to and valid for the design of the RPV circumferential welds at Fermi 2 during 

the period of extended operation. 

(b) The applicant plans to reapply for code relief from the ISI requirements that will apply to 

BWR RPV circumferential welds during the period of extended operation in accordance 

with the alternative ISI program requirements in 10 CFR 50.55a(z). 

(c) This provides an adequate basis for accepting this TLAA in accordance the 

requirements in 10 CFR 54.21(c)(1)(iii). 

4.2.5.3 UFSAR Supplement 

LRA Section A.2.1.5 provides the UFSAR supplement summarizing the TLAA evaluation of the 

RPV circumferential welds inspection relief. The staff reviewed LRA Section A.2.1.5 consistent 

with the review procedures in SRP-LR Section 4.2.3.2, which state that the reviewer should 

verify that the applicant has provided information to be included in the UFSAR supplement that 

includes a summary description of the evaluation of the TLAA. 

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.2.2.2. Additionally, the staff determines that the applicant provided 

an adequate summary description of its actions to address the TLAA on the RPV circumferential 

welds inspection, as required by 10 CFR 54.21(d). 

4.2.5.4 Conclusion 

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cracking on the intended 

functions of the RPV circumferential welds will be adequately managed by the ISI relief request 

process for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d). 
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4.2.6 Reactor Vessel Axial Weld Failure Probability 

4.2.6.1 Summary of Technical Information in the Application 

LRA Section 4.2.6 describes the applicant’s TLAA for probabilistic fracture mechanics and mean 

RTNDT analysis for the RPV axial welds. The applicant stated that the staff’s FSER for the 

BWRVIP-74-A report evaluated the failure frequency of axially-oriented welds in BWR reactor 

vessels. The applicant stated that applicants for license renewal must evaluate axially-oriented 

RPV welds to show that their failure frequency remains below the value calculated in the 

BWRVIP-74-A report. The SER states that an acceptable way to do this is to show that the 

mean RTNDT of the limiting axial beltline weld at the end of the period of extended operation is 

less than the values specified in the report. 

The applicant stated that LRA Table 4.2-7 compares the Fermi 2 reactor vessel limiting axial 

weld parameters to those summarized in the FSER for the BWRVIP-74-A report. The applicant 

clarified that the calculations summarized in LRA Table 4.2-7 are based on the neutron fluence 

at the inside surface for the limiting RPV axial shell weld, but do not include a margin term value 

(i.e., an additional RTNDT value added into the calculation as a safety basis decision). The 

applicant stated that LRA Table 4.2-7 demonstrates that the projected mean RTNDT value of 

66 °F for limiting RPV axial welds at 52 EFPY is less than the bounding mean RTNDT value of 

114 °F listed in BWRVIP-74-A report for BWR-4 designed RPVs. The applicant also stated that 

this demonstrates that the RPV failure frequency listed in the BWRVIP-74-A report (i.e., a 

probability of failure value of 5x10-6 per reactor-year) for BWR-4 RPV axial shell welds is 

acceptable and applicable to the design of the RPV axial shell welds at Fermi 2. 

The applicant dispositioned the probability of failure TLAA for the RPV axial shell welds in 

accordance with 10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to 

the end of the period of extended operation. 

4.2.6.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the RPV axial shell weld probability of failure 

analysis, and the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review 

procedures in SRP-LR Section 4.2.3.1.5, which state the following: 

To demonstrate that the vessel has not been embrittled beyond the basis for the 

staff and BWRVIP analyses, the applicant should provide (a) a comparison of the 

neutron fluence, initial RTNDT, chemistry factor amounts of copper and nickel, 

delta RTNDT, and mean RTNDT of the limiting axial weld at the end of the license 

renewal period to the reference case in the BWRVIP and staff analyses and 

(b) an estimate of conditional failure probability of the RPV at the end of the 

license renewal term based on the comparison of the mean RTNDT for the limiting 

axial welds and the reference case. If this comparison does not indicate that the 

RPV failure frequency for axial welds is less than 5 x 10-6 per reactor year, the 

applicant should provide a probabilistic analysis to determine the RPV failure 

frequency for axial welds. Consistent with the staff’s supplemental [SER] of 

BWR Vessel and Internals Project BWRVIP-05 Report, dated May 7, 2000 . . ., 

the staff should ensure that the applicant’s plant is bounded by the BWRVIP-05 

analysis or that the applicant has committed to a program to monitor axial weld 

embrittlement relative to the values specified by the staff in its May 7, 2000, SER. 
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The SRP-LR also states that the staff confirms that the applicant has addressed action item 12 

in the staff’s SER for BWRVIP-74. 

The staff noted that the applicant performed applicable mean RTNDT calculations of the limiting 

axial shell welds for the current operating term as part of supporting technical information and 

calculations needed for the processing of relief request RR-A25, which was approved in the 

staff’s SE, “Fermi 2 Relief Requests for the Second 10-Year Interval Inservice Inspection (ISI) 

Nondestructive Examination (NDE) Program,” dated March 30, 2000 (ADAMS Accession 

No. ML003697623). The staff reviewed the updated mean RTNDT calculation in LRA Table 4.2-7 

for 52 EFPY against the mean RTNDT calculation performed in the BWRVIP-05 report for the 

Pilgrim Mod-2 case study. This case study is applicable to RPV axial shell welds and 

establishes a limiting mean RTNDT value of 114 °F and a probability of failure value of 5x10-6 per 

reactor year for RPV axial shell welds. 

The staff confirmed that the Cu and Ni alloying contents and unirradiated RTNDT value used for 

the mean RTNDT calculation in LRA Table 4.2-7 were consistent with those provided in previous 

correspondence letters to the NRC, including the applicant’s response to GL 92-01, Revision 1, 

and GL 92-01, Revision 1, Supplement 1, and thus, are consistent with the CLB for Fermi 2. 

The staff also noted that LRA Section 4.2.6 identified a mean RTNDT of 66 °F for the limiting axial 

welds in the RPV (i.e., RPV lower shell axial welds 2-307 A, B, and C, which are tandem welds 

made from Heat No. 13253/12008). 

The staff noted that LRA Section B.1.38 describes the applicant’s Reactor Vessel Surveillance 

Program for the LRA and indicates that the AMP is based on implementation of the BWRVIP 

ISP that has been approved by the staff in BWRVIP-86, Revision 1-A. The staff noted that this 

AMP relies on specific RPV surveillance data that are obtained from specific RPV surveillance 

materials in host reactors that are representative of the base and weld materials used in the 

fabrication of the Fermi 2 RPV. However, the staff noted that LRA Table 4.2-7 did not include a 

mean RTNDT analysis for RPV lower shell axial welds 2-307 A, B, and C that is based on the ISP 

surveillance data for these weld components and is calculated (in part) using Section 5.2 of 

BWRVIP-86, Revision 1-A, for the chemistry factor and ∆RTNDT values used in the mean RTNDT

analysis. 

By letter dated December 17, 2014, the staff issued RAI 4.2.6-1, requesting that the applicant 

clarify whether the heat of material for surveillance weld materials from the host reactors in the 

ISP were a direct match to the weld heat for RPV lower shell axial welds 2-307 A, B, and C, 

which are the limiting RPV axial welds in the mean RTNDT analysis. If so, the staff asked the 

applicant to provide the basis for why LRA Table 4.2-7 did not include an additional mean RTNDT

calculation for these axial welds using (a) the applicable ISP surveillance data and (b) the 

methodology for calculating chemistry factor and ∆RTNDT values in Section 5 of BWRVIP-86, 

Revision 1-A. Otherwise, the staff asked the applicant to clarify how the ISP surveillance weld 

data from the host reactors support the adequacy of the predicted ∆RTNDT value used in the 

mean RTNDT calculation for RPV axial welds 2-307A, B, and C. 

By letter dated January 30, 2015, the applicant provided its response to RAI 4.2.6-1. In its 

response, the applicant stated that the heat of material for the RPV axial weld materials in the 

host reactors for the ISP was a direct match to the heat of material that was used to fabricate 

RPV lower shell axial welds 2-307 A, B, and C. The applicant amended the 52-EFPY neutron 

fluence value reported in LRA Table 4.2-7 from a value of 0.143x1019 n/cm2 (as reported in LRA 

Section 4.2.1 for inside surface of RPV circumferential shell weld 1-313) to a value of 

0.100x1019 n/cm2 (as reported in LRA Section 4.2.1 for inside surface of RPV lower shell axial 
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welds 2-307, A, B, and C). The staff found the amended neutron fluence value acceptable for 

the calculations of the mean RTNDT of the axial welds because (a) the change is consistent with 

the neutron fluence provided in LRA Table 4.2-1 for these axial weld components and (b) the 

staff has confirmed that the neutron fluence values reported in LRA Section 4.2.1 for 52 EFPY 

were calculated in accordance with the applicable GEH neutron fluence methodology approved 

for the CLB (this information is in the SE of September 14, 2001 (ADAMS Accession 

No. ML012400381), as supplemented by the SE of November 17, 2005 (ADAMS Accession 

No. ML053210469)). 

Based on this neutron fluence value change, the applicant amended the mean RTNDT value that 

was reported for these welds using the methods in RG 1.99, Revision 2, from a value of 66 °F to 

an amended value of 49 °F. The applicant also amended LRA Table 4.2-7 to include an 

additional mean RTNDT calculation for RPV lower shell axial welds 2-307 A, B, and C that was 

based on (a) the amended inside surface neutron fluence value of 0.100x1019 n/cm2 reported for 

RPV lower axial welds 2-307 A, B, and C, (b) the host reactor surveillance data obtained from 

the implementation of the ISP, and (c) the staff-approved methodology for performing RTNDT

calculations in the BWRVIP-86, Revision 1-A, report, as modified for mean RTNDT calculation 

margin term bases in the staff-approved version of the BWRVIP-05 report. Therefore, the staff 

noted that the applicant conservatively calculated an ISP-based mean RTNDT value of 102 °F for 

these axial welds using the applicable RPV surveillance data obtained from the applicant’s 

implementation of its ISP. Based on this assessment, the staff confirmed the applicant 

performed two acceptable mean RTNDT calculations for RPV lower axial welds 2-307, A, B, and 

C that demonstrate that the mean RTNDT values reported for the welds at 52 EPFY (i.e., mean 

RTNDT values of 49 °F and 102 °F, respectively) are bounded by the limiting mean RTNDT value 

of 114 °F, as reported in the BWRVIP-05 report for BWR-4 RPV axial weld components. 

The staff noted that, in the FSER for the BWRVIP-74-A report, dated October 18, 2001 (ADAMS 

Accession No. ML012920549), the staff included AAI No. 12, which requested that BWR license 

renewal applicant take the following actions with respect to information provided in their LRAs: 

As indicated in the staff’s March 7, 2000, letter to Carl Terry [i.e., letter enclosing 

the FSER on TR No. BWRVIP-05 to Mr. Carl Terry, Chairman of the BWRVIP], 

[an] LR applicant shall monitor axial beltline weld embrittlement. One acceptable 

method is to determine that the mean RTNDT of the limiting axial beltline weld at 

the end of the period of extended operation is less than the values specified in 

Table 1 of this FSER. 

The staff noted that, in the applicant’s response to RAI 4.2.6-1, the applicant provided an 

amended response to AAI No. 12 indicating that it had performed the applicable mean RTNDT

calculations for the limiting axial welds in the beltline region of the RPV (i.e., axial welds 2-307, 

A, B, and C), as based on the methodologies for performing ART calculations in RG 1.99, 

Revision 2, and BWRVIP-86, Revision 1-A, as modified by the mean RTNDT calculation bases in 

the staff-approved version of the BWRVIP-05 report. The staff noted that the response to AAI 

No. 12 adequately summarized that the mean RTNDT calculations demonstrated conformance 

with the mean RTNDT value of 114 °F, as listed for BWR-4 RPV axial welds in the BWRVIP-05 

report. Therefore, the staff finds that the applicant has adequately addressed the request in AAI 

No. 12 because the response adequately explains how the applicant has used the TLAA for 

RPV axial weld components to monitor neutron irradiation embrittlement in the RPV axial shell 

welds. The staff’s concerns described in RAI 4.6.2-1 are resolved. 
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The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the mean 

RTNDT analysis for the RPV axial shell welds has been projected to the end of the period of 

extended operation. The staff also finds that the mean RTNDT analysis meets the acceptance 

criteria in SRP-LR Section 4.2.2.1.5 because: 

(a) The mean RTNDT values reported for these welds at 52 EFPY were conservatively 

calculated with both the NRC’s approved methodologies for performing ART (RTNDT) 

calculations in RG 1.99, Revision 2, and BWRVIP-86, Revision 1-A (i.e., the 

methodology for performing RTNDT calculations using applicable ISP data), as modified 

for mean RTNDT calculation mean RTNDT calculation bases in the NRC-approved version 

of the BWRVIP-05 report. 

(b) The mean RTNDT calculations demonstrate that mean RTNDT values for the limiting axial 

shell welds in the RPV (welds 2-307 A, B, and C) are bounded by those values 

calculated in the limiting case study in the BWRVIP-05 report for RPV axial weld 

components. 

(c) This demonstrates that the probability of failure value of 5x10-6 per reactor year (as 

reported in the BWRVIP-05 report) will remain bounding for the design of the RPV axial 

shell welds during the period of extended operation. 

(d) The applicant has adequately addressed AAI No. 12 of the FSER for the BWRVIP-74-A 

report. 

4.2.6.3 UFSAR Supplement 

LRA Section A.2.1.6 provides the UFSAR supplement summarizing the TLAA evaluation of the 

mean RTNDT calculations for the RPV axial weld components. The staff reviewed LRA 

Section A.2.1.6 consistent with the review procedures in SRP-LR Section 4.2.3.2, which state 

that the reviewer should verify that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the evaluation of the TLAA. 

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.2.2.2, and is therefore acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the TLAA evaluation of the RPV axial welds, as required by 10 CFR 54.21(d). 

4.2.6.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided, an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the mean RTNDT analysis for the RPV 

axial welds has been adequately projected to the end of the period of extended operation. The 

staff also concludes that the UFSAR supplement contains an appropriate summary description 

of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.2.7 Reactor Pressure Vessel Core Reflood Thermal Shock Analysis 

4.2.7.1 Summary of Technical Information in the Application 

LRA Section 4.2.7 describes the applicant’s TLAA evaluation for the RPV core reflood thermal 

shock analysis. The LRA states that the UFSAR references GE Report NEDO-10029, “An 

Analytical Study on Brittle Fracture of GE-BWR Vessels Subject to the Design Basis Accident,” 

dated June 1969, which addresses brittle fracture of the RPV due to reflood following a 
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postulated LOCA. The LRA states that the thermal shock analysis in NEDO-10029 assumes a 

LOCA from a recirculation line break that is followed by LPCI. The LRA states that this thermal 

shock analysis accounts for the effects of neutron irradiation embrittlement at the end of 

40 years of operation. The LRA also states that a later thermal shock analysis, “Fracture 

Mechanics Evaluation of a Boiling Water Reactor Vessel Following a Postulated Loss of Coolant 

Accident,” was developed by Ranganath in August 1979 (ADAMS Legacy Library Accession 

No. 9110110105). The LRA states that the Ranganath analysis is bounding and that the 

maximum ART for the Fermi 2 RPV beltline materials is below the 400 °F temperature predicted 

at the time of peak stress intensity in the Ranganath analysis. 

The applicant dispositioned the TLAA for RPV core reflood thermal shock in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation. 

4.2.7.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the RPV core reflood thermal shock analysis and 

the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.7.3.1.2, which state that the staff is to review the results of the revised 

analysis to verify that the evaluation period has been extended, such that the analysis is valid 

for the period of extended operation. SRP-LR Section 4.7.3.1.2 also states that the applicable 

analysis technique can be the one that is in effect in the plant’s CLB at the time that the LRA is 

filed. The staff reviewed the UFSAR and determined that NEDO-10029 represents the RPV 

core reflood thermal shock analysis that is currently in effect for Fermi 2. However, LRA 

Section 4.2.7 states that the applicant used the 1979 Ranganath analysis to project this TLAA to 

the end of the period of extended operation. 

The staff noted that the 1979 Ranganath analysis was performed for a GE BWR-6 reactor 

design; however, the RPV at Fermi 2 is for a GE BWR-4 designed reactor. Therefore, the staff 

determined that the applicant had not demonstrated that the TLAA in LRA Section 4.2.7 is 

acceptable in accordance with 10 CFR 54.21(c)(1)(ii). 

By letter dated March 26, 2015, the staff issued RAI 4.2.7-1, Parts 1 and 2, requesting that the 

applicant address these issues. In RAI 4.2.7-1, Part 1, the staff asked the applicant to clarify 

which of the two RPV core reflood analyses (i.e., the NED0-10029 report or the 

1979 Ranganath analysis) will be used for the period of extended operation. The staff also 

asked the applicant to identify the limit that is placed on the end-of-life neutron fluence value or 

end-of-life RTNDT values in the report that will be relied upon for the period of extended operation 

and to identify whether the specific limit is based on the inside surface location, RPV base 

metal-to-clad interface location, or 1/4T location of the RPV. In RAI 4.2.7-1, Part 2, the staff 

requested the applicant to justify the basis for applying the 1979 Ranganath report to the 

licensing basis for Fermi 2 during the period of extended operation, if in response to Part 1 of 

the RAI, the 1979 Ranganath report will be the report that is relied upon for the period of 

extended option. As part of this response, the staff asked the applicant to demonstrate that the 

stress and neutron fluence levels assumed in the 1979 Ranganath analysis for the RPV in a 

BWR-6 reactor design are bounding for those that will apply to the BWR-4 RPV at Fermi 2 at 

the end of the period of extended operation (i.e., through 52 EFPY). 

By letter dated April 27, 2015, the applicant provided its response to RAI 4.2.7-1, Parts 1 and 2. 

In its response to RAI 4.2.7-1, Part 1, the applicant clarified that the 1979 Ranganath analysis 

will be the RPV core reflood analysis of record for the period of extended operation. The 
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applicant stated that the 1979 Ranganath analysis does not specifically calculate a limit for 

reference nil ductility transition temperature value (i.e., RTNDT value) for the reflood analysis. 

Instead, the applicant explained that the analysis calculates the temperature distribution and 

thermal stress for the RPV and then establishes that the RPV wall temperature is high enough 

to ensure margin in the available fracture toughness at the time of maximum stress intensity 

after initiation of a postulated LOCA. The applicant discussed that the TLAA aspect of the 

evaluation uses the projected limiting RTNDT value for the RPV, as adjusted for neutron fluence, 

to calculate the temperature at which the upper-shelf energy transition would occur. This 

temperature is compared to the RPV wall temperature at the time of maximum stress intensity 

established in the 1979 Ranganath analysis. 

In its response to RAI 4.2.7-1, Part 2, the applicant stated that the 1979 Ranganath analysis 

was based on a 6-inch-thick BWR-6 vessel. The applicant stated that, in comparison, the 

thickness of the lower shell and lower-intermediate shell in the RPV are 7.125 inches and 

6.125 inches, respectively. The applicant stated that the 1979 Ranganath analysis is applicable 

to the RPV at Fermi 2 because (a) the difference in temperature and thermal stresses at the 

1/4T location between a 6-inch-thick BWR/6 vessel and vessel shells ranging from 6.125 inches 

to 7.125 inches in thickness is small, with wall thickness temperatures being slightly higher and 

wall thermal stresses being slightly lower for slightly thicker locations, and (b) the pressure 

stresses being higher for a thinner vessel, but near zero in a thermal shock event, which can 

then be neglected. The applicant also stated that the fluence levels and RTNDT values used in 

the analysis have been projected to the end of the period of extended operation (i.e., to 

52 EFPY) and are documented in the LRA Section 4.2.2. The applicant further stated that the 

results of the projected analysis demonstrate that there is significant margin in the RPV core 

reflood analysis during the period of extended operation. 

The staff noted that the applicant amended LRA Section 4.2.7 to be consistent with clarifications 

made in its response to RAI 4.2.7-1, Parts 1 and 2. To assess the validity of the applicant’s 

basis, the staff performed independent calculations of the 1/4T RTNDT values for the plate 

components and weld components used in the fabrication of the RPV. The staff calculated a 

limiting RTNDT value of 87.2 °F for the limiting components in the RPV, which are the lower shell 

axial welds (welds 2-307, A, B, and C) that were made from weld heat 13253/12008 using a 

Linde 1092 weld flux. The staff noted that this is the same value as that calculated by the 

applicant for these limiting welds. The staff also noted that the RPV core reflood analysis uses 

the more conservative temperature at which upper-shelf transition occurs based on the ART 

value (i.e., 206 °F) that bounds the most limiting 1/4T ART (1/4 RTNDT) value calculated for the 

components at 52 EFPY. The staff noted that this provides sufficient demonstration that the 

projected RTNDT value used in the analysis is bounded by the RPV wall temperature value 

(400 °F) used in the RPV core reflood analysis (i.e., in the 1979 Ranganath analysis). 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii) that the RPV 

core reflood analysis has been projected to the end of the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the applicant 

has projected the limiting RTNDT value for the RPV to the end of the period of extended 

operation (i.e., to 52 EPFY) and has demonstrated that the analysis remains acceptable when 

compared to limiting temperature acceptance criterion in the RPV core reflood analysis that will 

be applied to the period of extended operation (i.e., for the 1979 Ranganath analysis). The 

staff’s concerns described in RAI 4.2.7-1, Parts 1 and 2 are resolved. 
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4.2.7.3 UFSAR Supplement 

LRA Section A.2.1.7 provides the UFSAR supplement summarizing the applicant’s TLAA 

evaluation for the RPV core reflood thermal shock analysis. The staff reviewed LRA 

Section A.2.1.7 consistent with the review procedures in SRP-LR Section 4.7.3.2, which state 

that the applicant is to provide a summary description for its evaluation of each TLAA. The 

SRP-LR also states that the summary description should contain information on the disposition 

of the TLAA for the period of extended operation and be appropriate such that later changes 

can be controlled by 10 CFR 50.59, “Changes, Tests, and Experiments.” 

Based on its review of the UFSAR supplement, as amended by the letter dated April 27, 2015, 

the staff finds that it meets the acceptance criteria in SRP-LR Section 4.7.2.2, and is therefore 

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address RPV core reflood thermal shock, as required by 

10 CFR 54.21(d). 

4.2.7.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for RPV core reflood 

thermal shock has been projected to the end of the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3 Metal Fatigue 

LRA Section 4.3 contains the fatigue analyses for Class 1 and non-Class 1 mechanical 

components. LRA Section 4.3 provides the applicant’s analyses of the following areas: 

 Class 1 fatigue analyses 

 non-Class 1 fatigue analyses 

 effects of reactor water environment on fatigue life 

4.3.1 Class 1 Fatigue Analyses 

LRA Section 4.3.1, as revised by the LRA annual update dated June 26, 2015, introduces the 

applicant’s metal fatigue TLAAs for Class 1 components. The LRA states that the fatigue 

analyses performed during the design phase of the Class 1 components were based on the 

assumed number of plant transients for a 40-year operating life. Extending the period of 

operation for these components from 40 to 60 years results in the fatigue evaluations being 

TLAAs. The applicant stated that it reviewed the transient cycles that are required to be tracked 

for fatigue evaluations and confirmed the current cycle counts. The cycle counts were linearly 

extrapolated to determine a projected count at 60 years of operation. The current, projected, 

and analyzed cycle counts are provided in LRA Table 4.3-1, “Analyzed Transients with 

Projections,” as modified by letter dated May 9, 2016. The LRA states that the Fatigue 

Monitoring Program is being used to ensure that the number of cycles experienced by a 

component does not exceed its design limit. 

During the staff’s review of LRA Section 4.3.1, it was noted that Table 4.3-1 lists some events 

being tracked that are not design transients. It was also unclear to the staff which events were 

being used to calculate the CUFs for the TLAAs described in the LRA Section 4.3.1 
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subsections. By letter dated January 14, 2015, the staff issued RAI 4.3.1-1 requesting that the 

applicant clearly distinguish between events that are design transients and those that are not 

design transients in Table 4.3-1. The staff also requested that the applicant clarify which 

transients are being used to calculate the CUFs for each LRA Section 4.3.1 subsection. 

In its response dated February 12, 2015, the applicant stated that the only event listed in LRA 

Table 4.3-1 that is not a design transient is the “Main steam bypass line time of operation at 

30% - 45% open (days),” which is used in a vibration-based service life evaluation. The Fatigue 

Monitoring Program was enhanced (Enhancement 5 in SER Section 3.0.3.2.8) to track this 

event. The applicant’s response also included a description of which transients are being used 

to calculate the CUFs for components in each LRA Section 4.3.1 subsection. The staff finds the 

applicant’s response acceptable because it clearly identified a transient event listed in LRA 

Table 4.3-1 that is not a design transient and clarified that the Fatigue Monitoring Program will 

be enhanced to track this transient. The response also provided traceability between events in 

LRA Table 4.3-1 and TLAAs that use these events as cycle inputs. The staff’s concern 

described in RAI 4.3.1-1 is resolved. 

The staff notes that the projected 60-year number of cycles for each event is less than the 

corresponding analysis input value, and the applicant's Fatigue Monitoring Program is used to 

track transient cycles and requires corrective actions if the numbers of cycles approach 

analyzed values. The staff’s evaluation of the Fatigue Monitoring Program is documented in 

SER Section 3.0.3.2.8. 

LRA Section 4.3.1 provides the applicant’s analyses of the following areas: 

 RPV 

 RPV feedwater nozzles 

 reactor vessel underclad cracking 

 RPV internals 

 reactor recirculation pumps 

 Class 1 piping 

4.3.1.1 Reactor Pressure Vessel 

 Summary of Technical Information in the Application 

LRA Section 4.3.1.1, as revised by the LRA annual updates dated June 26, 2015, and 

May 9, 2016, describes the applicant’s TLAA for the RPV cumulative fatigue damage. The RPV 

is a cylindrical pressure vessel with hemispherical heads. Design data for the RPV are provided 

in UFSAR Table 5.4-1, “Reactor Pressure Vessel Design Data.” LRA Table 4.3-1 provides the 

transients that contribute to cumulative fatigue damage that are tracked by the Fatigue 

Monitoring Program. LRA Table 4.3-2, “Reactor Pressure Vessel Cumulative Usage Factors,” 

as revised by letter dated May 9, 2016, provides the CUFs for the RPV locations. 

The applicant dispositioned the TLAAs for the RPV closure region, RPV closure studs, RPV 

shell, bottom head support skirt, steam outlet nozzles, feedwater nozzles, core spray nozzles, 

control rod drive (CRD) return nozzle, recirculation outlet nozzles, recirculation inlet nozzles, 

core ∆P nozzle, CRD nozzles, basin seal skirt, shroud support, 4-inch vent nozzle bolts, 6-inch 

instrument/head spray nozzle bolts, and CRD assembly in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of cumulative fatigue damage on the 
4-47 

intended functions will be adequately managed by the Fatigue Monitoring Program for the 

period of extended operation. 

 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the RPV components listed in LRA Table 4.3-2 and 

the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures 

in SRP-LR Section 4.3.3.1.1.3, which state that the applicant may use GALL Report AMP X.M1, 

“Fatigue Monitoring,” to accept the TLAA in accordance with 10 CFR 54.21(c)(1)(iii). The 

SRP-LR also states that the reviewer verifies that the applicant has stated that GALL Report 

AMP X.M1 is applicable to its program that monitors and tracks the number of transients for the 

relevant components. The staff noted that the applicant’s response to RAI 4.3.1-1, by letter 

dated February 12, 2015, included a description of which transients in LRA Table 4.3-1 are 

being used to calculate the CUFs in LRA Table 4.3-2. The staff’s evaluation of RAI 4.3.1-1 is 

documented in SER Section 4.3.1 above. The staff finds that the current and projected cycle 

counts associated with the RPV in LRA Table 4.3-1 are bounded by the number of analyzed 

cycles. 

The staff noted that the applicant is managing the effects of cumulative fatigue damage on the 

intended functions of the applicable components using the Fatigue Monitoring Program. The 

staff’s review of the Fatigue Monitoring Program is in SER Section 3.0.3.2.8. The staff review of 

the program concludes that the elements of the Fatigue Monitoring Program are consistent with 

the corresponding program elements of GALL Report AMP X.M1. 

The staff finds that the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cumulative fatigue damage on the intended functions of the RPV components listed in 

LRA Table 4.3-2 will be adequately managed for the period of extended operation. Additionally, 

the analysis meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the 

applicant’s Fatigue Monitoring Program is consistent with GALL Report AMP X.M1, which can 

be used to accept a TLAA in accordance with 10 CFR 54.21(c)(1)(iii). 

 UFSAR Supplement 

LRA Section A.2.2.1, as revised by the LRA annual update dated June 26, 2015, provides the 

UFSAR supplement summarizing the RPV TLAA that evaluates cumulative fatigue damage. 

The staff reviewed LRA Section A.2.2.1 consistent with the review procedures in SRP-LR 

Section 4.3.3.2, which state that the review verifies that the applicant has provided a summary 

description of the evaluation for the RPV TLAA to be included in the UFSAR supplement. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address cumulative 

fatigue damage of the RPV, as required by 10 CFR 54.21(d). 

 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue 

damage on the intended functions of the RPV components listed in LRA Table 4.3-2 will be 

adequately managed by the Fatigue Monitoring Program for the period of extended operation. 
4-48 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.1.2 Reactor Pressure Vessel Feedwater Nozzles 

 Summary of Technical Information in the Application 

LRA Section 4.3.1.2 describes the applicant’s TLAA evaluations for the feedwater nozzle 

fracture mechanics analysis and feedwater nozzle fatigue due to rapid cycling. The LRA states 

that a plant-specific fracture mechanics analysis was completed for the feedwater nozzles as 

part of the applicant’s review of NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive 

Return Line Nozzle Cracking,” dated November 1980. From this analysis, it was determined 

that a total of 620 startup and shutdown transients plus scram transients would cause a 

postulated crack to grow from 0.25 inch to the limit of 1 inch. The LRA states that the projected 

number of these transients through the period of extended operation is less than the total 

number of transients that were analyzed. 

The applicant dispositioned the TLAA for the feedwater nozzle fracture mechanics analysis in 

accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the 

period of extended operation. 

The LRA states that the fatigue analysis for the feedwater nozzles accounts for potential rapid 

cycling behind the thermal sleeves. The LRA states that this rapid cycling contributes to the 

fatigue usage at this location, and it is calculated based on time and feedwater temperature. 

The applicant dispositioned the TLAA for feedwater nozzle fatigue due to rapid cycling behind 

the thermal sleeves in accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of 

cracking on the intended functions of the feedwater nozzles will be adequately managed for the 

period of extended operation. 

 Staff Evaluation 

Fracture Mechanics Analysis. The staff reviewed the applicant’s TLAA for the feedwater nozzle 

fracture mechanics analysis and the corresponding disposition of 10 CFR 54.21(c)(1)(i), 

consistent with the review procedures in SRP-LR Section 4.3.3.1.5.1. The SRP-LR states that 

the staff is to review the operating cyclic experience and a list of the assumed cycles used in the 

existing analysis to ensure that the number of assumed cycles would not be exceeded during 

the period of extended operation. 

LRA Section 4.3.1.2 states that the fracture mechanics analysis for the feedwater nozzles was 

completed as part of the NUREG-0619 review. The staff published NUREG-0619 to address 

cracking that had occurred in the feedwater nozzles of several BWRs in the late 1970s. The 

report discusses various solutions to the cracking problem, which include system modifications 

and changes to operating procedures to decrease the magnitude and frequency of temperature 

fluctuations that had led to the cracking. One potential system modification was the 

implementation of a low-flow feedwater controller that met certain characteristics. As a followup 

to NUREG-0619, on February 29, 1981, the staff issued GL 81-11, “BWR Feedwater Nozzle 

and Control Rod Drive Return Line Nozzle Cracking (NUREG-0619),” dated February 29, 1981. 

GL 81-11 notes that there was some difficulty in implementing low-flow feedwater controllers 

that met all of the recommended characteristics. As an alternative, GL 81-11 states that the 

staff would accept the use of feedwater controllers that did not meet all of the recommended 
4-49 

characteristics, provided that a plant-specific fracture mechanics analysis was submitted to 

demonstrate that the stresses from conservative controller temperature and flow profiles, when 

added to those resulting from the other crack growth phenomena, such as startup and shutdown 

cycles, did not result in the growth of a crack to greater than 1 inch for the 40-year life of the 

plant. 

The staff’s review noted that the applicant had submitted an initial plant-specific fracture 

mechanics analysis for the Fermi 2 feedwater nozzles by letter dated November 22, 1989 

(ADAMS Legacy Library Accession No. 8912040089). An updated analysis, documented in GE 

Report GE-NE-523-22-0292, “Updated NUREG-0619 Feedwater Nozzle Fatigue Crack Growth 

Analysis, Enrico Fermi Nuclear Power Plant, Unit 2,” was later submitted by letter dated 

July 29, 1992 (ADAMS Legacy Library Accession No. 9208030210). Because this updated 

analysis only demonstrated that a postulated 0.25-inch crack would grow to 1 inch in 38.3 years 

– a result that did not meet the acceptance standard in GL 81-11 – the staff requested the 

applicant to submit additional information to confirm the results of the updated analysis. By 

letter dated June 24, 1998 (ADAMS Legacy Library Accession No. 9806300462), the applicant 

provided this confirmatory information in Design Calculation 5922, “NUREG-0619 RPV 

Feedwater Nozzle Crack Growth Reevaluation.” The analysis in Design Calculation 5922 is 

based on additional plant thermal cycle data, which was used to update the 40-year transient 

projections for the fracture mechanics analysis. At that time, 180 startup and shutdown 

transients and 316 scram transients were projected, for a total of 496 transients. Using the 

crack depth curve in Figure 6-1 of GE-NE-523-22-0292, the applicant determined that 

496 transients would grow the postulated crack from 0.25 inch to 0.8 inch in 40 years. In an SE 

dated August 5, 1998 (ADAMS Legacy Library Accession No. 9808199327), the staff found this 

analysis to be acceptable because the calculated crack depth was less than 1 inch in 40 years, 

and therefore it met the acceptance standard in GL 81-11. Accordingly, the applicant’s fracture 

mechanics analysis is relied upon to justify continued use of its feedwater controller. 

Consistent with the guidance in SRP-LR Section 4.3.3.1.5.1, the staff reviewed the list of 

assumed transients used in the fracture mechanics analysis. The staff determined that there 

are two types of assumed transients: (1) startup and shutdown and (2) scram. The staff 

confirmed that both of these transient types are identified in the applicant’s TLAA evaluation 

along with projections for the period of extended operation. LRA Section 4.3.1.2 states that 

transient numbers 3 and 15-17 in LRA Table 4.3-1 reflect the startup and shutdown transients, 

and transient numbers 10 and 11 reflect the scram transients. Based on its reviews of 

GE-NE-523-22-0292 and Design Calculation 5922, the staff determined that power reductions 

were also counted as scram transients. In particular, Design Calculation 5922 states that power 

reductions to below 50 percent power were counted as scrams. LRA Table 4.3-1 states that 

transient number 10 is for “SCRAM – turbine generator trip” and transient number 11 is for 

“SCRAM – all others.” However, based on this information, the staff could not determine 

whether the projections for transient numbers 10 and 11 also include power reductions to below 

50 percent power. 

By letter dated January 26, 2015, the staff issued RAI 4.3.1.2-1, requesting that the applicant 

indicate whether such power reductions are included in transient numbers 10 and 11 in LRA 

Table 4.3-1. The staff also requested that the applicant provide justification if these power 

reductions were not included in the transient projections. 

In its response dated March 5, 2015, the applicant stated that the power reductions to below 

50 percent of power are counted as either Event No. 8 (loss of feedwater heater – turbine trip 

with 100 percent bypass), 9 (loss of feedwater heaters – partial feedwater heater bypass), or 11 
4-50 

(LRA Table 4.3-1, SCRAM – all others), depending on the lowest reactor power and feedwater 

temperature achieved during the event. The applicant stated that a significant contributor to 

feedwater nozzle crack growth is low-flow feedwater control. At 20 percent power, feedwater 

flow in the reactor water cleanup (RWCU) return loop is an order of magnitude larger than 

RWCU flow. Therefore, feedwater flow changes at or above 20 percent power have much less 

effect on “RWCU + Feedwater” temperature and the nozzle transient for this event is limited to a 

single cycle of slow temperature and flow change associated with the power change. The 

applicant also stated that it was conservative to count these power reduction events as scram 

events. 

The staff reviewed the applicant’s response and finds it acceptable because it provided a 

technical basis for how the transient is counted and that, at or above 20 percent power, 

feedwater flow changes have much less effect on the transient. In addition, the applicant 

counted the power reduction events conservatively as scram events or loss of feedwater heater 

events. The staff’s concern described in RAI 4.3.1.2-1 is resolved. 

Following the guidance in SRP-LR Section 4.3.3.1.5.1, the staff also reviewed the applicant’s 

transient projections against the total number of transients that were assumed in the existing 

analysis. LRA Section 4.3.1.2 states that a total of 620 transients were assumed in the existing 

analysis. However, the staff reviewed GE Report GE-NE-523-22-0292 and determined that its 

calculations are based on a total of 648 transients. Also, as previously stated, the results of 

these calculations did not meet the acceptance standard in GL 81-11. In addition, the staff 

reviewed Design Calculation 5922 and determined that its calculations, which did meet the 

acceptance standard in GL 81-11, are based on a projected total of 496 transients. Since 

neither of these existing calculations were based on a total of 620 transients, it was not clear to 

the staff why the applicant compared its transient projections for this TLAA against this value to 

demonstrate that the analysis remains valid for the period of extended operation. 

By letter dated January 26, 2015, the staff issued RAI 4.3.1.2-2 requesting that the applicant 

show how the existing fracture mechanics analysis is based on a total of 620 transients. 

Alternatively, the staff requested the applicant to demonstrate that the projections for startup 

and shutdown transients plus scram transients, inclusive of power reductions to below 

50 percent power, are less than the 496 transients that were used in Design Calculation 5922. 

Otherwise, the staff requested that the applicant provide and justify a different demonstration for 

this TLAA pursuant to 10 CFR 54.21(c)(1). 

In its response dated March 5, 2015, the applicant stated that GE Report GE-NE-523-22-0292 

is based on a total of 648 startup, shutdown, and scram transient event occurrences, at a rate of 

16.2 events per year for 40 years. Because this number of occurrences results in the 

postulated 0.25-inch flaw growing to a size greater than the acceptance limit of 1 inch, GE 

Report GE-NE-523-22-0292 determined that the postulated 0.25-inch flaw would grow to 1 inch 

in 38.3 years (or 620 transient event occurrences). The applicant also stated that it performed a 

design calculation, DC-5922, which evaluated Fermi 2’s history of startup, shutdown, and scram 

transient events subsequent to GE Report GE-NE-523-22-0292 to show that the projection of 

648 events per 40 years in GE-NE-523-22-0292 was conservative; DC-5922 projected 496 

transient event occurrences for a 40-year operating period. For license renewal, projections of 

transient event occurrences for 60 years of operation are based on the information from LRA 

Table 4.3-1, in which the sum of the occurrences for Events Nos. 3, 10, 11, and 15-17 is a total 

of 566 transients, which is still less than the 620 transient events necessary to grow a 

postulated crack from 0.25 inch to 1 inch. 
4-51 

The staff reviewed the applicant’s response and finds it acceptable because the applicant 

performed an analysis of the postulated flaw for the period of extended operation (for the 

60 years of operation), and the analysis shows that all the applicable events conservatively add 

up to a total of 566 events, which is less than the 620 transient events necessary to grow a 

postulated crack from 0.25 inch to 1 inch. The staff’s concern described in RAI 4.3.1.2-2 is 

resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

feedwater nozzle fracture mechanics analysis remains valid for the period of extended 

operation. Additionally, the analysis meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.5.1 because the applicant demonstrated that the number of transient cycles 

assumed for the 40-year life would not be exceeded during the period of extended operation. 

Fatigue due to Rapid Cycling. The staff reviewed the applicant’s TLAA for the feedwater nozzle 

cumulative fatigue damage due to rapid cycling and the corresponding disposition of 

10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR Section 4.3.3.1.1.3, 

which state that the applicant may use GALL Report AMP X.M1, “Fatigue Monitoring,” to accept 

the TLAA in accordance with 10 CFR 54.21(c)(1)(iii). The SRP-LR also states that the reviewer 

verifies that the applicant has stated that GALL Report AMP X.M1 is applicable to its program 

that monitors and tracks the number of transients for the relevant components. The applicant’s 

response to RAI 4.3.1-1, by letter dated February 12, 2015, includes a description of which 

transients in LRA Table 4.3-1 are being used to calculate the CUFs in LRA Table 4.3-2 for the 

feedwater nozzles. The staff’s evaluation of RAI 4.3.1-1 is documented in SER Section 4.3.1. 

The staff noted that the current and projected cycle counts associated with the feedwater nozzle 

in LRA Table 4.3-1 are bounded by the number of analyzed cycles. 

The staff noted that the applicant is managing the effects of cumulative fatigue damage on the 

intended functions of the feedwater nozzles using the Fatigue Monitoring Program. The staff’s 

review of the Fatigue Monitoring Program is documented in SER Section 3.0.3.2.8. The staff’s 

review of the program concludes that the elements of the Fatigue Monitoring Program are 

consistent with the corresponding program elements of GALL Report AMP X.M1. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cracking due to rapid cycling on the intended functions of the feedwater nozzles will 

be adequately managed for the period of extended operation. Additionally, the analysis meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant’s Fatigue 

Monitoring Program is consistent with GALL Report AMP X.M1. 

 UFSAR Supplement 

LRA Section A.2.2.1, as revised by the LRA annual update dated June 26, 2015, provides the 

UFSAR supplement summarizing the applicant’s TLAA evaluations for the feedwater nozzle 

fracture mechanics and fatigue due to rapid cycling analyses. The staff reviewed LRA 

Section A.2.2.1 consistent with the review procedures in SRP-LR Section 4.3.3.2, which state 

that the reviewer verifies that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the evaluation of the TLAAs. 

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 
4-52 

address the feedwater nozzle fracture mechanics and fatigue due to rapid cycling analyses, as 

required by 10 CFR 54.21(d). 

 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the feedwater nozzle fracture mechanics 

analysis remains valid for the period of extended operation. The staff concludes that the 

applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cracking due 

to rapid cycling on the intended functions of the feedwater nozzles will be adequately managed 

by the Fatigue Monitoring Program for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluations, as required by 10 CFR 54.21(d). 

4.3.1.3 Reactor Vessel Underclad Cracking 

 Summary of Technical Information in the Application 

LRA Section 4.3.1.3 states that there is no TLAA associated with reactor vessel underclad 

cracking at Fermi 2. 

 Staff Evaluation 

The staff noted that SRP-LR Table 3.1-1, item 3.1.1-18, identifies this plant-specific TLAA as 

applicable to PWRs only. The staff evaluated the applicant’s claim and finds it acceptable 

because an evaluation of a TLAA for the reactor vessel underclad cracking is only applicable to 

PWRs and Fermi 2 is a BWR. 

 UFSAR Supplement 

The staff concludes that an UFSAR supplement is not required because this TLAA is not 

applicable to BWRs. 

 Conclusion 

On the basis of its review, the staff concludes that this TLAA is not applicable to Fermi 2 and a 

UFSAR supplement is not required. 

4.3.1.4 Reactor Pressure Vessel Internals 

 Summary of Technical Information in the Application 

LRA Section 4.3.1.4, as revised by the LRA annual update dated June 26, 2015, describes the 

applicant’s TLAA for RPV internals that evaluates cumulative fatigue damage. The RPV 

internals consist primarily of the core, core support structure, steam dryer assembly, and jet 

pumps. LRA Table 4.3-1 provides the transients that contribute to cumulative fatigue damage 

that are tracked by the Fatigue Monitoring Program. LRA Table 4.3-3, “RPV Internals 

Cumulative Usage Factors,” provides the CUFs for the locations that are subject to an AMR. 

The applicant dispositioned the TLAAs for the RPV internals (core spray lines, jet pump riser 

braces, access hole covers, jet pump auxiliary spring wedges, and feedwater sparger) in 
4-53 

accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of cumulative fatigue 

damage on the intended functions will be adequately managed by the Fatigue Monitoring 

Program for the period of extended operation. 

 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the RPV internals and the corresponding disposition 

of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR Section 4.3.3.1.1.3, 

which state that the applicant may use GALL Report AMP X.M1, “Fatigue Monitoring,” to accept 

the TLAA in accordance with 10 CFR 54.21(c)(1)(iii). The SRP-LR also states that the reviewer 

verifies that the applicant has stated that GALL Report AMP X.M1 is applicable to its program 

that monitors and tracks the number of transients for the relevant components. The staff noted 

that the applicant’s response to RAI 4.3.1-1, by letter dated February 12, 2015, includes a 

description of which transients in LRA Table 4.3-1 are being used to calculate the CUFs in LRA 

Table 4.3-3. The staff’s evaluation of RAI 4.3.1-1 is documented in SER Section 4.3.1. The 

staff noted that the current and projected cycle counts associated with the RPV internals in LRA 

Table 4.3-1 are bounded by the number of analyzed cycles. 

The staff noted that the applicant is managing the effects of cumulative fatigue damage on the 

intended functions of the applicable components using the Fatigue Monitoring Program. The 

staff’s review of the Fatigue Monitoring Program is documented in SER Section 3.0.3.2.8. The 

staff review of the program concludes that the elements of the Fatigue Monitoring Program are 

consistent with the corresponding program elements of GALL Report AMP X.M1. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cumulative fatigue damage on the intended functions of the RPV internals will be 

adequately managed for the period of extended operation. Additionally, the analysis meets the 

acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant’s Fatigue Monitoring 

Program is consistent with GALL Report AMP X.M1. 

 UFSAR Supplement 

LRA Section A.2.2.1, as revised by the LRA annual update dated June 26, 2015, provides the 

UFSAR supplement summarizing the RPV internals cumulative fatigue damage TLAAs. The 

staff reviewed LRA Section A.2.2.1 consistent with the review procedures in SRP-LR 

Section 4.3.3.2, which state that the review verifies that the applicant has provided a summary 

description of the evaluation for the TLAA to be included in the UFSAR supplement. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address cumulative 

fatigue damage of the RPV internals, as required by 10 CFR 54.21(d). 

 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue 

damage on the intended functions of the RPV internals (core spring lines, jet pump riser braces, 

access hole covers, jet pump auxiliary spring wedges, and feedwater sparger) will be 

adequately managed by the Fatigue Monitoring Program for the period of extended operation. 
4-54 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.1.5 Reactor Recirculation Pumps 

 Summary of Technical Information in the Application 

LRA Section 4.3.1.5, as revised by the LRA annual update dated June 26, 2015, and 

May 9, 2016, describes the applicant’s TLAA for the cumulative fatigue damage of the reactor 

recirculation pumps. The details of the construction and design of the reactor recirculation 

pumps are provided in UFSAR Table 3.2-1, “Structures, Systems, and Components 

Classification,” and Table 3.2-4, “Code Status of Class I (A) Primary Pressure Boundary 

Components.” UFSAR Table 3.9-20, “Recirculation Pumps,” provides representative analyses 

of the recirculation pumps. LRA Table 4.3-1, as modified by letter dated May 9, 2016, provides 

the events that contribute to cumulative fatigue damage that are tracked by the Fatigue 

Monitoring Program. LRA Table 4.3-4, “Reactor Recirculation Pumps Cumulative Usage 

Factors,” as modified by letter dated May 9, 2016, provides the CUFs for the locations that are 

subject to an AMR. 

The applicant dispositioned the TLAA for the reactor recirculation pumps in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of cumulative fatigue damage on the 

intended functions will be adequately managed by the Fatigue Monitoring Program for the 

period of extended operation. 

 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the reactor recirculation pumps and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in 

SRP-LR Section 4.3.3.1.1.3, which state that the applicant may use GALL Report AMP X.M1, 

“Fatigue Monitoring,” to accept the TLAA in accordance with 10 CFR 54.21(c)(1)(iii). The 

SRP-LR also states that the review verifies that the applicant has stated that GALL Report 

AMP X.M1 is applicable to its program that monitors and tracks the number of transients for the 

relevant components. The staff noted that the applicant’s response to RAI 4.3.1-1, by letter 

dated February 12, 2015, includes a description of which transients in LRA Table 4.3-1 are 

being used to calculate the CUFs in LRA Table 4.3-4. The staff’s evaluation of RAI 4.3.1-1 is 

documented in SER Section 4.3.1. The current and projected cycle counts associated with the 

reactor recirculation pumps in LRA Table 4.3-1, as modified by letter dated May 9, 2016, are 

bounded by the number of analyzed cycles provided in the LRA. 

The staff noted that the applicant is managing the effects of cumulative fatigue damage on the 

intended functions of the reactor recirculation pumps using the Fatigue Monitoring Program. 

The staff’s review of the Fatigue Monitoring Program is documented in SER Section 3.0.3.2.8. 

The staff’s review of the program concludes that the elements of the Fatigue Monitoring 

Program are consistent with the corresponding program elements of GALL Report AMP X.M1. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cumulative fatigue damage on the intended functions of the reactor recirculation 

pumps will be adequately managed for the period of extended operation. Additionally, the 

analysis meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant’s 

Fatigue Monitoring Program is consistent with GALL Report AMP X.M1. 
4-55 

 UFSAR Supplement 

LRA Section A.2.2.1, as revised by the LRA annual update dated June 26, 2015, provides the 

UFSAR supplement summarizing the TLAA for the cumulative fatigue damage of the reactor 

recirculation pumps. The staff reviewed LRA Section A.2.2.1 consistent with the review 

procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that the applicant 

has provided a summary description of the evaluation for the TLAA to be included in the UFSAR 

supplement. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address cumulative 

fatigue damage of the reactor recirculation pumps, as required by 10 CFR 54.21(d). 

 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue 

damage on the intended functions of the reactor recirculation pumps will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.1.6 Class 1 Piping 

 Summary of Technical Information in the Application 

LRA Section 4.3.1.6, as revised by the LRA annual update dated June 26, 2015, describes the 

applicant’s TLAA for the cumulative fatigue damage of Class 1 piping. The LRA states that 

fatigue analyses were performed on multiple locations for each system within the Class 1 

boundary. The Class 1 piping is denoted in the drawing listed in LRA Table 4.3-5, “LRA 

Drawings for Class 1 Piping.” LRA Table 4.3-1 provides the transient events that contribute to 

cumulative fatigue damage and are tracked by the Fatigue Monitoring Program. The CUFs for 

the most limiting piping location and associated valves are provided in LRA Tables 4.3-6, 

“Piping Cumulative Usage Factors,” and 4.3-7, “Valve Cumulative Usage Factors.” 

The applicant dispositioned the TLAAs for the Class 1 piping and associated valves in 

accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of cumulative fatigue 

damage on the intended functions will be adequately managed by the Fatigue Monitoring 

Program for the period of extended operation. 

 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the Class 1 piping and associated valves and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in 

SRP-LR Section 4.3.3.1.1.3, which state that the applicant may use GALL Report AMP X.M1, 

“Fatigue Monitoring,” to accept the TLAA in accordance with 10 CFR 54.21(c)(1)(iii). The 

SRP-LR also states that the review verifies that the applicant has stated that GALL Report 

AMP X.M1 is applicable to the program that monitors and tracks the number of transients for the 

relevant components at the site. The staff noted that the applicant’s response to RAI 4.3.1-1, by 

letter dated February 12, 2015, includes a description of which transients in LRA Table 4.3-1 are 
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being used to calculate the CUFs in LRA Tables 4.3-6 and 4.3-7. The staff’s review of 

RAI 4.3.1-1 is documented in SER Section 4.3.1. The current and projected cycle counts 

associated with the Class 1 piping in LRA Table 4.3-1 are bounded by the number of analyzed 

cycles. 

The staff noted that the applicant is managing the effects of cumulative fatigue damage on the 

intended functions of the applicable components using the Fatigue Monitoring Program. The 

staff’s review of the Fatigue Monitoring Program is documented in SER Section 3.0.3.2.8. The 

staff’s review of the program concludes that the elements of the Fatigue Monitoring Program are 

consistent with the corresponding program elements of GALL Report AMP X.M1. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cumulative fatigue damage on the intended functions of the Class 1 piping and 

associated values will be adequately managed for the period of extended operation. 

Additionally, the analysis meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because 

the applicant’s Fatigue Monitoring Program is consistent with GALL Report AMP X.M1. 

 UFSAR Supplement 

LRA Section A.2.2.1, as revised by the LRA annual update dated June 26, 2015, provides the 

UFSAR supplement summarizing the TLAAs for the cumulative fatigue damage of Class 1 

piping. The staff reviewed LRA Section A.2.2.1 consistent with the review procedures in 

SRP-LR Section 4.3.3.2, which state that the reviewer verifies that the applicant has provided a 

summary description of the evaluation for the TLAA to be included in the UFSAR supplement. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address cumulative 

fatigue damage of the Class 1 piping, as required by 10 CFR 54.21(d). 

 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cumulative fatigue 

damage on the intended functions of the Class 1 piping and associated valves will be 

adequately managed by the Fatigue Monitoring Program for the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.2 Non-Class 1 Fatigue Analyses 

4.3.2.1 Piping and In-Line Components 

 Summary of Technical Information in the Application 

LRA Section 4.3.2.1 describes the applicant’s TLAA for fatigue of the non-Class 1 piping and 

in-line components. The LRA states that the in-scope non-Class 1 piping is built to ASME Code 

Section III Class 2, ASME Code Section III Class 3, or ANSI B31.1. Implicit fatigue-based 

maximum allowable stress calculations were performed on these components. The individual 

system evaluations indicate that 7,000 thermal cycles will not be exceeded during the period of 

extended operation and a stress range reduction factor of 1.0 is used in the stress analysis. 
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The LRA also states that plant heatups and cooldowns limit many of the system’s thermal 

cycles and that the number of plant heatups and cooldowns are significantly below 7,000, as 

shown in LRA Table 4.3-1. 

The applicant dispositioned the TLAAs for the non-Class 1 piping and in-line components in 

accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the fatigue analyses remain valid for 

the period of extended operation. 

 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the non-Class 1 piping and in-line components and 

the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in 

SRP-LR Section 4.3.3.1.2.1, which state that the relevant information in the TLAA is reviewed to 

verify that the maximum allowable stress range values remain valid. The SRP-LR also states 

that the reviewer verifies that the allowable limit for full thermal range transients will not be 

exceeded during the period of extended operation. 

LRA Section 4.3.2.1 states that none of the TLAAs associated with non-Class 1 piping within the 

scope of license renewal will exceed the thermal cycle limit of 7,000 cycles during the period of 

extended operation. The LRA further states that for many plant systems the number of thermal 

cycles coincides with the number of plant heatups and cooldowns; however, the number of 

thermal cycles is independent of plant heatups and cooldowns for other systems. The staff 

noted that the LRA does not provide the transients, current cycle count, and projected cycle 

count being used to determine that the thermal cycle limit of 7,000 will not be exceeded during 

the period of extended operation. By letter dated January 14, 2015, the staff issued RAI 4.3.2-1 

requesting that the applicant provide the transients (or cycles) being counted that are used to 

determine that the stress calculations are valid for the period of extended operation and the 

projected number of full thermal cycles for the non-Class 1 piping TLAAs being evaluated. 

In its response dated February 12, 2015, the applicant provided a summary of the cycles being 

counted for each system and the estimated number of cycles projected out to 60 years for each 

system. The applicant stated that the number of cycles for many of the components is limited 

by those in LRA Table 4.3-1. The number of cycles for the remaining locations is related to 

system-specific operations. The applicant stated that the estimated total number of cycles 

provided for each in-scope system are all considerably below the limit of 7,000 cycles. 

The staff finds the applicant’s response acceptable because (a) the applicant clarified what 

cycles are being counted as part of the analyses, (b) the applicant provided the estimated 

number of cycles at 60 years of operation, and (c) the estimated number of cycles are all within 

an allowable limit. The staff’s concern described in RAI 4.3.2-1 is resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analyses for the non-Class 1 piping and in-line components remain valid for the period of 

extended operation. Additionally, the analysis meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.2.1 since the maximum allowable stress range values for the existing fatigue 

analysis remain valid because the allowable limit for the number of full thermal cycles does not 

exceed the 7,000 limit during the period of extended operation. 
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 UFSAR Supplement 

LRA Section A.2.2.2 provides the UFSAR supplement summarizing the TLAA for the cumulative 

fatigue damage of the non-Class 1 piping and in-line components. The staff reviewed LRA 

Section A.2.2.2 consistent with the review procedures in SRP-LR Section 4.3.3.2, which state 

that the reviewer verifies that the applicant has provided a summary description of the 

evaluation for the TLAA to be included in the UFSAR supplement. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address cumulative 

fatigue damage of the non-Class 1 piping and in-line components, as required by 

10 CFR 54.21(d). 

 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the cumulative fatigue analyses for the 

non-Class 1 piping and in-line components remain valid for the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.3.2.2 Components Other Than Piping 

 Summary of Technical Information in the Application 

LRA Section 4.3.2.2 describes the applicant’s TLAAs for fatigue of non-Class 1 components 

other than piping. The LRA states that a review of the in-scope non-Class 1 components, other 

than piping, identified TLAAs associated with the fatigue analyses of expansion joints and 

flexible connections. The analyses assumed a bounding number of fatigue cycles. The LRA 

also states that the assumed number of fatigue cycles remains bounding for 60 years of 

operation. 

The applicant dispositioned the TLAAs for the non-Class 1 components other than piping in 

accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the fatigue analyses remain valid for 

the period of extended operation. 

 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the non-Class 1 components, other than piping, and 

the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the applicable review 

procedures in SRP-LR Section 4.3.3.1.2.1, which state that the reviewer verifies that the 

maximum allowable stress range values for the existing fatigue analysis remain valid for the 

period of extended operation and that the allowable limit for full thermal range transients will not 

be exceeded during the period of extended operation. 

LRA Section 4.3.2.2 states that the non-Class 1 components, other than piping, were analyzed 

and determined to remain valid for the period of extended operation. However, the staff lacked 

sufficient details regarding how this determination was made. By letter dated January 14, 2015, 

the staff issued RAI 4.3.2-2 requesting that the applicant provide a summary of the analysis 

used to evaluate these components. The staff requested that the summary include the code 
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that the components were designed to, transients being counted for the fatigue analyses, 

projected number of cycles, and number of bounding cycles. 

In its response dated February 12, 2015, the applicant stated that the expansion joints and 

flexible connections are designed in accordance with Expansion Joint Manufacturers 

Association, Inc., standards for fatigue or tested in accordance with ASME Section III 

NC-3649.4(e)(2)(b) to establish the allowable number of fatigue cycles. The response also 

included Table 4.3.2-2a, “Expansion Joints with TLAAs.” This table identifies the expansion 

joints with TLAAs and the applicable system in which they reside. Table 4.3.2-2a also includes 

the cycles counted for the fatigue analyses, projected number of cycles for 60 years of 

operation, and the bounding number of cycles for each component. The projected number of 

cycles for 60 years of operation are all considerably below the bounding number of cycles. 

The staff finds the applicant’s response acceptable because the applicant (1) provided the 

pertinent details of the fatigue analyses, (2) demonstrated that the number of allowable thermal 

cycles, which bounds the fatigue analyses, is determined by either testing or design analyses in 

accordance with applicable industrial standards, and (3) provided the bounding number of 

cycles and projected number of cycles that illustrate that the analyses remain valid for 60 years 

of operation. The staff’s concern described in RAI 4.3.2-2 is resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analyses for the non-Class 1 components, other than piping, remain valid for the period 

of extended operation. Additionally, the analysis meets the applicable acceptance criteria in 

SRP-LR Section 4.3.2.1.2.1 and the projected numbers of cycles do not exceed the bounding 

limit during the period of extended operation. 

 UFSAR Supplement 

LRA Section A.2.2.2 provides the UFSAR supplement summarizing the TLAAs for fatigue of the 

non-Class 1 components, other than piping. The staff reviewed LRA Section A.2.2.2 consistent 

with the review procedures in SRP-LR Section 4.3.3.2, which state that the reviewer verifies that 

the applicant has provided a summary description of the evaluation for the TLAA to be included 

in the UFSAR supplement. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address fatigue of the 

non-Class 1 components, other than piping, as required by 10 CFR 54.21(d). 

 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analyses on the intended 

functions of the non-Class 1 components, other than piping, remain valid for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 
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4.3.3 Effects of Reactor Water Environment on Fatigue Life 

4.3.3.1 Summary of Technical Information in the Application 

LRA Section 4.3.3, as revised by the LRA annual updates dated June 26, 2015, and 

May 9, 2016, describes the applicant’s evaluation for the effects of environmentally assisted 

fatigue (EAF) due to the reactor water environment on the fatigue life of pressure boundary 

components for the period of extended operation. The LRA states that all ASME Class 1 RPV 

boundary locations that are wetted, including the six locations identified in NUREG/CR-6260, 

“Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant 

Components,” were reviewed as part of the screening process for evaluating environmental 

effects on fatigue. The EAF correction factors (Fen) and EAF CUF values (CUFen) for these 

locations were calculated using the formulas and fatigue curves in NUREG/CR-6909, “Effect of 

LWR Coolant Environments on the Fatigue Life of Reactor Materials.” The LRA also states that 

an evaluation of the water chemistry history, based on normal water chemistry, hydrogen water 

chemistry, and on-line noble metal chemistry information, was used to determine the dissolved 

oxygen (DO) levels. The LRA further states that guidance in NUREG/CR-6909 was used for 

location screening and the methodology to determine the bounding locations is based on 

industry guidance. LRA Table 4.3-8, “EAF Screening of Fermi 2 Locations,” as revised by 

letters dated January 22, 2016, and May 9, 2016, provides the Fen factors and associated CUFen

values for the screening locations and identifies the bounding locations, referred to as sentinel 

locations. 

The applicant dispositioned the evaluation for the ASME Class 1 wetted RPV boundary 

locations in accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of EAF on 

the intended functions will be adequately managed by the Fatigue Monitoring Program for the 

period of extended operation. 

4.3.3.2 Staff Evaluation 

The staff reviewed the applicant’s evaluation for the effects of the reactor water environment on 

fatigue life and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the 

review procedures in SRP-LR Section 4.3.3.1.3, which state that the reviewer verifies that the 

applicant has addressed the staff recommendation for the closure of GSI-190, “Fatigue 

Evaluation of Metal Components for 60-Year Plant Life,” dated December 26, 1999. The 

SRP-LR also states that the review verifies that the applicant has identified high fatigue usage 

locations for evaluation, including those in NUREG/CR-6260, and evaluated these locations by 

applying environmental correction factors to the existing CUFs using the appropriate formulae in 

NUREG/CR-6909, NUREG/CR-5704, and/or NUREG/CR-6583. The review procedures in 

SRP-LR Section 4.3.3.1.1.3 for analysis based on CUF calculations states that the applicant 

may use GALL Report AMP X.M1, “Fatigue Monitoring,” to accept a TLAA in accordance with 

10 CFR 54.21(c)(1)(iii), as applicable. GALL Report AMP X.M1 is applicable to EAF 

evaluations. The staff noted that Commission Order No. CLI-10-17, dated July 8, 2010 

(ADAMS Accession No. ML131890775), indicates that evaluations associated with the effects of 

the reactor coolant environment on component fatigue life are not TLAAs in accordance with the 

definition in 10 CFR 54.3(a) because these evaluations are not in the applicant’s CLB. 

However, the staff will review the EAF evaluation in a similar manner as a TLAA evaluation. 

LRA Section 4.3.3 states that an EAF screening has been conducted on all wetted ASME 

Class 1 RPV boundary locations and that the results of the screening calculations were used to 

determine the bounding locations. The LRA states that when the screening produced a CUFen
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value exceeding the limit of 1.0, the locations were re-evaluated using average load pair 

temperatures or average transient temperatures when available. The results of the screening 

evaluation are provided in LRA Table 4.3-8 with four locations having projected CUFen values 

exceeding the limit of 1.0. The LRA also states that the fatigue usage calculations will be 

updated using refined fatigue analysis to determine valid CUFen values of less than 1.0 for the 

locations in Table 4.3-8. The LRA originally stated that “DTE will review design basis ASME 

Class 1 component fatigue evaluations to ensure the Fermi 2 locations evaluated for the effects 

of the reactor coolant environment on fatigue include the most limiting components within the 

[RCPB].” It was unclear to the staff what methodologies are being used to identify the 

plant-specific limiting locations. It was also unclear what corrective actions and/or refined 

fatigue analysis will be used to ensure that the CUFen values projected to exceed 1.0 will remain 

within the Code limit. By letter dated January 14, 2015, the staff issued RAI 4.3.3-1 requesting 

that the applicant provide the methodology being used to identify plant-specific component 

locations in the RCPB that are more limiting than the components identified in 

NUREG/CR-6260. The staff also requested that the applicant provide the corrective actions 

being used and/or the methodology to refine the fatigue analysis to ensure that the CUFen

values projected to exceed 1.0 will remain within the Code limit. 

In its response dated February 12, 2015, and supplemented by letter dated March 10, 2016, the 

applicant stated that the methodology being used to identify plant-specific component locations 

in the RCPB that are more limiting than the components identified in NUREG/CR-6260 is EPRI 

TR 1024995, “Environmentally Assisted Fatigue Screening, Process and Technical Basis for 

Identifying EAF Limited Locations,” dated August 2012. The response also stated that 

Section 3.0 of EPRI TR 1024995 provides the technical basis for the screening process and 

Section 4.0 provides the details of the screening process. The response further stated that the 

corrective actions being used to ensure that the CUFen values projected to exceed 1.0 will 

remain within the Code limit are repair, replacement, performing refined ASME Code 

calculations, implementing cycle-based fatigue monitoring, and implementing stress-based 

fatigue monitoring. 

The staff finds the applicant’s response acceptable in part because the response provided the 

corrective actions to ensure that the CUFen values projected to exceed 1.0 will remain within the 

Code limit. The response also revised Commitment No. 12 and Enhancement 4 of the Fatigue 

Monitoring Program to include cycle-based fatigue and stress-based fatigue monitoring 

methods. The staff’s review of the Fatigue Monitoring Program is documented in SER 

Section 3.0.3.2.8. However, EPRI TR 1024995 has not been submitted to the staff for approval 

and has not been endorsed by the NRC. Additionally, the application of EPRI TR 1024995 

requires plant-specific review. By letter dated May 21, 2015, the staff issued RAI 4.3.3-1a 

requesting further information regarding the methodology being used to identify plant-specific 

component locations in the RCPB that are more limiting than the components identified in 

NUREG/CR-6260. The information requested includes (i) a description of the site-specific 

review that was conducted to determine that the application of the EAF screening processes 

being utilized is appropriate for identifying the EAF limiting locations, (ii) the evaluation of 

representative systems to demonstrate the adequacy of the methodology to identify the limiting 

plant-specific component locations, and (iii) a description of the engineering judgement, plantspecific assumptions, and plant-specific criteria used in the EAF analysis or screening process. 

In its response to part (i) of RAI 4.3.3-1a, dated June 18, 2015, the applicant stated that Fermi 2 

has an ASME Section III design basis for Class I vessels and piping. The response also stated 

that the design stress analysis and CUF values in LRA Tables 4.3-2, 4.3-4, 4.3-6, and 4.3-7 had 

previously been updated for 60 years of operation during a reanalysis for a power uprate. The 
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response further stated that these activities were performed under the 10 CFR Part 50 

Appendix B Quality Assurance Program, therefore making the screening process robust and 

comprehensive. 

In its response to part (ii) of RAI 4.3.3-1a, the applicant provided the EAF evaluations of the 

feedwater (FW) and SLC systems as representative systems to demonstrate that the 

methodology conservatively identifies bounding locations. The response also states that the 

same degree of analytical rigor was not always applied during the screening process and that 

the approach being utilized takes this into account. The EAF evaluation of the FW system, 

provided in the response, illustrates that the same degree of analytical rigor was not always 

applied during the screening process. The EAF evaluation of the SLC system, provided in the 

response, identifies a bounding location with a CUFen value that exceeds the limit of 1.0. The 

response states that if this location is re-evaluated to produce a CUFen value below the limit of 

1.0, then an additional bounding location may also be identified. 

In its response to part (iii) of RAI 4.3.3-1a, the applicant provided an outline of the screening 

process used to identify EAF limiting locations and site-specific application of the process. The 

applicant stated that the Fen factors and associated CUFen values were initially determined using 

strain rate, metal sulfur content, and transient temperature values that produced the most 

conservative results. The response also stated that when a refined analysis was performed to 

reduce a CUFen value below 1.0, the Fen factor was re-evaluated to reduce its value. The 

response further stated that if transient pairs were subjected to only rapid cycling or solely 

dynamic loading that a Fen factor of 1.0 was used based on the guidance in Section 4.2 of 

NUREG/CR-6909. 

The staff finds the applicant’s response to part (i) of RAI 4.3.3-1a acceptable. The staff finds 

that the site-specific review conducted by the applicant, to determine the appropriateness of the 

screening processes being utilized for identifying the EAF limiting locations, is adequate for 

Fermi 2. The site-specific review confirmed that the applicable components have an ASME 

Section III Class 1 design basis. The review also confirmed that the applicable components all 

have CUF values that were reanalyzed for current plant conditions. The screening process was 

conducted under the 10 CFR Part 50 Appendix B Quality Assurance Program. The staff’s 

concerns associated with part (i) of RAI 4.3.3-1a are resolved. 

The staff finds the applicant’s response to part (iii) of RAI 4.3.3-1a acceptable. In the applicant’s 

response to part (iii), it stated that engineering judgment was used to address dynamic/rapid 

cycling loads. The applicant also stated that plant-specific criteria was applied to re-evaluate 

Fen factors after the initial screening. The staff confirmed that the engineering judgment and 

plant-specific criteria that were applied are consistent with the guidance in NUREG/CR-6909. 

Additional information related to engineering judgment and/or plant-specific criteria is provided 

in the applicant’s responses to RAI 4.3.3-1b, RAI 4.3.3-2, and RAI 4.3.3-3 below. The staff’s 

evaluation and disposition of the information in these RAIs resolves the staff’s concerns 

associated with part (iii) of RAI 4.3.3-1a. 

The staff finds the applicant’s response to part (ii) of RAI 4.3.3-1a partially acceptable. The EAF 

evaluations provided by the applicant, to demonstrate the adequacy of the methodology to 

identify the limiting plant-specific component locations, included an example of an approach 

being utilized to conservatively identify bounding locations when the same degree of analytical 

rigor is not used in the evaluation. However, the overall approach being used to account for 

differences in analytical rigor and how it would be applied to other systems was not described. 

The relative ranking of analyzed locations based on CUFen values may be influenced by 
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applying different degrees of analytical rigor. Therefore, the subsequent identification of 

bounding locations may also be affected. The staff could not determine the adequacy of the 

bounding locations because it lacked sufficient information regarding the approach used to 

account for differences in analytical rigor. By letter dated September 1, 2015, the staff issued 

RAI 4.3.3-1b requesting that the applicant describe the approach used to account for 

differences in analytical rigor when determining bounding locations and justify that it retains an 

appropriate level of conservatism in the methodology being used to identify plant-specific 

bounding locations. 

In its response dated September 24, 2015, the applicant stated that there are three 

circumstances in its evaluation where differences in the degree of analytical rigor may be 

applied and described the accompanying justification for each. These circumstances are use of 

design-severity instead of actual-severity plant transients, design by analysis rather than design 

by rule, and bundling of multiple transients using the enveloping or most severe transient. 

The first instance is when actual-severity plant transients are used rather than design-severity 

plant transients. The applicant stated that actual-severity plant transients produce a lower CUF 

value compared to design-severity plant transients. The applicant stated that design-severity 

plant transients were used for all transients except the RWCU out of service transient. The 

applicant stated that the RWCU out of service transient is not part of the Fermi 2 design basis 

but is known to contribute to fatigue usage in the RWCU system and connected systems. 

Fermi 2 concluded that including this actual-severity plant transient is conservative given that it 

is not part of the design basis for Fermi 2. 

The second instance is when the more rigorous design by analysis (ASME Section III, NB-3200) 

method is used to calculate fatigue usage compared to the design by rule (ASME Section III, 

NB-3600) method. The applicant stated that the CUF values determined using the design by 

analysis method were often larger than those determined using the design by rule method for a 

given system or subsystem. The applicant also stated that when a CUF value was calculated 

using the design by analysis method, the design by rule calculations were also performed so 

that CUF values determined using different methods could be compared on a common basis. 

The third instance is where multiple transients were bundled rather than using each load set 

transient pair. The applicant stated that bundling transients reduces the computational time 

required to perform a fatigue analysis; is used when the fatigue margin is sufficiently large; and 

results in an inflated CUF value. The applicant also stated that engineering judgment was 

applied to ensure that locations with higher CUFen values due to the bundling of transients are 

not inappropriately identified as bounding locations for a system or subsystem. The applicant 

further stated that this was done by identifying locations where bundled transients were applied 

and assessing the severity of the individual transients relative to locations with lower CUF 

values that did not bundle transients. Additionally, the applicant states that this process was 

used consistently through the evaluation. 

The staff finds the applicant’s response acceptable because the differences in analytical rigor 

used by the applicant when determining bounding locations were either more representative of 

actual plant operations or conservative. The applicant used design-severity plant transients, 

versus actual-severity plant transients, for all but one transient. An actual-severity plant 

transient was used for the RWCU out of service transient. The RWCU out of service transient is 

not part of the Fermi 2 design basis. The staff agrees with the applicant’s conclusion that the 

addition of this transient is conservative because it was applied consistently to the applicable 

systems and appropriately increases fatigue usage for those systems. The applicant also used 
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the more rigorous design by analysis method to calculate fatigue usage for some locations. 

When the largest CUF value within a system is not a value determined using the design by 

analysis method, calculations are performed using both methods so that CUF values can be 

compared on a common basis. Determining the CUF values using both design methods 

ensures that the most limiting location is identified. The bundling of transients increases fatigue 

usage and the applicant used engineering judgment to ensure that the most limiting location 

within a system was properly identified. This application of engineering judgment is only 

necessary when a location using bundled transients is found to be limiting for a system or 

subsystem. When this occurs the applicant compares the severity of the bundled transients to 

those of the other locations within the system to verify that the most limiting location is selected 

as bounding. The evaluation of the feedwater system, provided in the applicant’s response to 

part (ii) of RAI 4.3.3-1a, demonstrates how the applicant applied engineering judgment when 

bundling transients. The staff’s concerns described in RAIs 4.3.3-1, 4.3.3-1a, and 4.3.3-1b are 

resolved. 

By letter dated June 26, 2015, the applicant submitted the annual update for LRA Section 4.3.3 

which includes a summary of the steps involved in the EAF screening process. The process 

used to screen locations, identify bounding locations, and reduce bounding locations has also 

been partially summarized in the response to RAI 4.3.3-1 and follow-up RAIs 4.3.3-1a and 

4.3.3-1b. However, none of these documents fully describe the process. Additionally, when 

reviewed as a group, the documents still leave areas of uncertainty and potentially inconsistent 

steps/activities. The process is not defined clearly enough to be evaluated by the staff. By 

letter dated September 1, 2015, the staff issued RAI 4.3.3-2 requesting that the applicant 

describe the steps of the screening process in sufficient detail to be performed independently on 

a random system. The staff also requested that the applicant describe and justify any 

engineering judgment, all plant-specific assumptions, and all plant-specific criteria for each step 

in the process. 

In its response dated September 24, 2015, the applicant stated that the only engineering 

judgment applied in the process was related to differences in degree of analytical rigor and the 

only plant-specific assumptions/criteria were related to the DO content associated with each 

water chemistry zone. The response also provided additional information on the steps involved 

in the EAF screening process. The following steps are derived from the information provided by 

the applicant in its LRA annual update (dated June 26, 2015) and from the applicant’s 

responses to RAI 4.3.3-1a (dated June 18, 2015) and RAI 4.3.3-1b (dated 

September 24, 2015): 

(1) Prescreening: All ASME Class 1 RPV and piping locations with CUF values were 

reviewed to determine if an EAF evaluation was necessary. Locations that are not 

exposed to reactor water or part of the RCPB were eliminated. All the remaining RCPB 

locations with CUF calculations comprise the population to be evaluated for the effects 

of EAF. 

(2) Determination of Candidate Locations: Each location in the population was examined 

and the locations with the largest CUF values were identified for each system or 

subsystem. Each material type within a system or subsystem was retained for additional 

evaluation because the application of the Fen factor to a CUF value may affect the 

relative ranking of CUFen values for these locations. All remaining locations were 

eliminated. The candidate population consists of the locations with the largest CUF 

values and a location representing each material type for a given system or subsystem. 
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(3) Determination of Bounding Locations: The CUF value for each candidate location was 

revised using the applicable fatigue curve provided in NUREG/CR-6909. Time-weighted 

Fen factors were determined using the plant-specific water chemistry history to establish 

DO content and the least favorable values for sulfur content of the material, strain rate, 

and temperature as inputs to the applicable formulas in NUREG/CR-6909. CUFen

values were determined for each candidate location by multiplying the revised CUF 

value by the accompanying Fen factor. The CUFen values for each location are tabulated 

by system or subsystem. 

(4) Finalize Bounding Locations: All NUREG-6260 locations are established as bounding 

locations. The location with the largest CUFen value in each system or subsystem for 

each material type is selected. All locations with CUFen values of less than 0.8 are 

subsequently eliminated unless the location is part of a component with other material 

types that exceed 0.8 for other locations. The locations with the second highest CUFen

value for each material type is retained if it is within 50 percent of the largest location for 

a given system or subsystem. Any locations that do not meet these criteria are 

eliminated. The remaining locations are the final bounding locations for EAF (sentinel 

locations). 

The staff finds the applicant’s response acceptable because, when combined with the LRA 

annual update and the response to RAI 4.3.3-1a, the process used to identify leading locations 

that bound the effects of EAF has been described and is appropriately conservative. The 

prescreening process (Step 1) ensures that all locations potentially effected by EAF are 

identified for evaluation. Establishing a candidate population (Step 2) ensures that each 

material type and the locations with the highest fatigue usage are evaluated for each system or 

subsystem. The preliminary bounding locations (Step 3) were determined by establishing Fen

factors and CUFen values for the candidate locations in accordance with staff approved 

guidance. Finalizing the bounding locations (Step 4) reduces the population of bounding 

locations to a subset of limiting locations to be managed by the Fatigue Monitoring Program. 

This subset of locations is appropriate for bounding the effects of EAF because the CUFen

threshold value 0.8 is more conservative than the Code limit of 1.0. The inclusion of a second 

bounding location, if it is within 50 percent of the leading location for a given system or 

subsystem, provides additional assurance that the most limiting locations are monitored. 

Including any location of a different material type if it is part of a component that contains a 

location that is greater than or equal to 0.8 is conservative because it ensures that locations with 

different material types are tracked regardless of their CUFen value. Additionally, all 

NUREG-6260 locations are also established as bounding locations. The staff also noted that 

the bounding locations for carbon steel, low alloy steel, stainless steel, and nickel based alloy 

have CUFen values as low as 0.045, 0.095, 0.071, and 0.273, respectively. These CUFen values 

are significantly lower than the Code limit of 1.0. The staff reviewed the application of 

engineering judgment in the process in its disposition of RAIs 4.3.3-1a and 4.3.3-1b. The staff’s 

concern described in RAI 4.3.3-2 is resolved. 

LRA Table 4.3-8, as revised by the LRA annual updates dated June 26, 2015, contains 

bounding locations with CUFen values projected to exceed 1.0. This update reduced by four the 

number of locations that were identified in the LRA as having CUFen values projected to exceed 

1.0. Of these four locations, two were re-evaluated and the CUFen values were reduced to less 

than 1.0, one was eliminated because it is not a pressure boundary location, and one was 

eliminated because it is bounded by adjacent piping. This update also identified two new 

locations with CUFen values greater than 1.0, the stainless steel condensing chamber and the 

nickel-based alloy core ∆P nozzle location. The remaining four locations with CUFen values 
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greater than 1.0 (e.g., the two cited above and nickel-based alloy CRD nozzle and the stainless 

steel portion of the FW nozzle safe end identified in the LRA) will be managed by the Fatigue 

Monitoring Program and further actions will be taken in accordance with the AMP. Further 

actions may include refining the fatigue analyses to produce CUFen values below 1.0. It was 

unclear to the staff how bounding locations with CUFen values projected to exceed 1.0 will be 

affected if the fatigue analyses are refined to reduce the CUFen value. By letter dated 

September 1, 2015, the staff issued RAI 4.3.3-3 requesting that the applicant describe the 

process used to rank locations that have been (or will be) re-evaluated because the CUFen

value exceeds the limit of 1.0. The staff also requested that the applicant justify that the 

process retains an appropriate level of conservatism to identify plant-specific bounding 

locations. 

In its response dated September 24, 2015, the applicant stated that the Fen factors were 

recalculated for locations where the CUFen value was projected to exceed 1.0. The applicant 

stated that the recalculations reduced the Fen factors by applying average transient 

temperatures or maximum operating temperatures rather than the design temperature. The 

applicant also stated that recalculating the Fen factors reduced the CUFen values for two 

locations (SLC piping inside containment and core spray penetration X-16A/B body) to below 

the screening threshold 0.8, although four locations still exceeded the limit of 1.0. The four 

locations are the CRD nozzles, feedwater nozzles, condensing chambers, and core ∆P nozzle. 

These four locations projected to exceed 1.0 will be reanalyzed in accordance with the Fatigue 

Monitoring Program. The applicant further stated that three locations, which are the CRD 

nozzles, feedwater nozzles, and core ∆P nozzle, will be retained as bounding locations after 

reanalysis unless the current values are determined to be a result of significant overconservatisms in the current analysis that would have resulted in these values not being 

selected initially if they had been analyzed in a manner consistent with the other component 

locations. Additionally, the applicant provided the intended re-evaluation approach for each of 

the locations. 

The staff finds the applicant’s response partially acceptable because re-evaluated locations will 

be ranked in a manner consistent with the criteria described in Step 4 of the EAF screening 

process. Additionally, using the average transient temperatures to calculate the Fen factors is 

also consistent with NUREG/CR-6909, provided that the specific guidance for determining the 

average temperature is followed. The staff noted that the method used to calculate the average 

temperature, per NUREG/CR-6909, depends on whether the minimum transient temperature 

exceeds the threshold temperature for the material, which is the temperature below which 

environmental effects are considered insignificant. When the minimum transient temperature 

exceeds the threshold temperature, the maximum and minimum temperature values of the 

stress cycle or load set pair are used to calculate the average transient temperature. When the 

minimum transient temperature is below the threshold temperature, the transient maximum 

temperature and the threshold temperature are used to calculate the average temperature. The 

staff also noted that NUREG/CR-6909 states that the average temperature may be used to 

calculate the Fen factor only when the transient has a constant strain rate and a linear 

temperature response. 

Therefore, on December 15, 2015, the staff held a conference call with the applicant to obtain 

clarification on the applicant’s response to RAI 4.3.3-3 and the manner in which the average 

temperatures were calculated by the applicant to confirm that the method is consistent with 

NUREG/CR-6909. During the conference call, the applicant described the methods used to 

calculate the average temperatures. The applicant stated that in one of the methods, the 

minimum transient temperature was used instead of the threshold temperature to calculate the 
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average temperature. If the resulting temperature was less than the threshold temperature, the 

threshold temperature was used to calculate the Fen factor. Based on these descriptions, the 

staff determined that the applicant had calculated average temperatures using minimum 

temperature values that, in some cases, were below the threshold value, which is not consistent 

with the guidance in NUREG/CR-6909. The staff had concerns that this may result in the 

underestimation of both the Fen factors and the resulting CUFen values for some locations. By 

letter dated January 14, 2016, the staff issued followup RAI 4.3.3-3a requesting that the 

applicant assess the impact of revising the evaluations to use the correct determination of 

average temperature in a manner consistent with NUREG/CR-6909 and submit a description of 

the impact of this revision to the previous screening and Fen evaluation results for staff review. 

The followup RAI also requested that the applicant’s assessment include a description of 

whether the revised average temperature calculations impacts the selection of sentinel 

locations. In its response dated January 22, 2016, the applicant identified six locations where 

average transient temperatures were used to calculate Fen factors. The Fen factors for five of the 

six locations were recalculated to become consistent with the guidance in NUREG/CR-6909. 

The remaining location (core ∆P nozzle) was consistent with the guidance in NUREG/CR-6909. 

The core ∆P nozzle was re-evaluated for the purpose of refining the analysis. The following 

information describes the applicant’s re-evaluation of these six locations: 

 The Fen factor for the core ∆P nozzle location was originally determined using bundled 

transients and the average temperature of the dominant transient was calculated in a 

manner consistent with the guidance in NUREG/CR-6909. The re-evaluation of this 

location unbundled the transients and used the maximum design temperature for the 

location. The CUFen value for this location was reduced from 1.48 to 0.929. This 

location remains a bounding location in accordance with the screening criteria. 

 The Fen factor for the SLC piping inside containment was originally determined using an 

average temperature for the startup and shutdown load set values that used a minimum 

transient temperature that was below the stainless steel threshold temperature. This 

method of calculating average temperature is not consistent with the guidance in 

NUREG/CR-6909. The re-evaluation of this location uses a minimum transient 

temperature equal to the stainless steel threshold temperature to calculate the average 

temperature in accordance with NUREG/CR-6909. All transients associated with the 

fatigue usage of this location have a constant strain rate and linear temperature 

response that, therefore, make them simple transients, consistent with 

NUREG/CR-6909. The CUFen value for this location increased from 0.503 to 0.658. 

Although DTE previously stated that this was not a sentinel location, as noted in the 

annual update dated May 9, 2016, DTE decided to conservatively identify the SLC piping 

inside containment as a sentinel location and revised LRA Table 4.3-8 to reflect this. 

 The Fen factor for the CRD nozzle location was originally determined using bundled 

transients and average temperatures that used minimum transient temperatures that 

were below the nickel-based alloy threshold temperature. This method of calculating 

average temperature is not consistent with the guidance in NUREG/CR-6909. The 

re-evaluation of this location unbundled the transients and used the maximum design 

temperature for the location. The CUFen value for this location was reduced from 1.28 to 

0.191. This location remains a bounding location in accordance with the screening 

criteria. 

 The Fen factor for the CRD assembly main flange location was originally determined 

using average temperatures that used minimum transient temperatures below the 

stainless steel threshold temperature. This method of calculating average temperature 
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is not consistent with the guidance in NUREG/CR-6909. The re-evaluation of this 

location uses a maximum service temperature for all of the transients except the startup 

transient that uses an average temperature determined using a minimum transient 

temperature equal to the stainless steel threshold temperature in accordance with 

NUREG/CR-6909. The startup transient is a simple transient because it has a constant 

strain rate and linear temperature response. The CUFen value for this location increased 

from 0.329 to 0.725. This location is still not a bounding location in accordance with the 

screening criteria. 

 The Fen factor for the reactor recirculation pump cooler location was originally 

determined using an average temperature for the on-off-on transient that used the 

stainless steel threshold temperature as the minimum temperature. The on-off-on 

transient is not a simple transient; therefore, calculating an average temperature for this 

transient is not consistent with the guidance in NUREG/CR-6909. The re-evaluation of 

this location uses the design temperature of 575 °F and appropriately accounted for the 

cooler being replaced in 1998. The CUFen value for this location was reduced from 

0.581 to 0.578. This location remains a bounding location in accordance with the 

screening criteria. 

 The feedwater nozzles have carbon steel, low alloy steel, and stainless steel locations 

subjected to EAF evaluation. The Fen factors for carbon steel and low alloy steel 

locations were determined using the maximum design temperature. The Fen factor for 

the stainless steel location was originally determined using average transient 

temperatures. However, not all of the transients associated with the stainless steel 

location are simple transients; therefore, calculating an average temperature for this 

location is not consistent with the guidance in NUREG/CR-6909. The re-evaluation of 

the stainless steel location uses the maximum design temperature of 575 °F. 

Additionally, all three locations (carbon steel, low alloy steel, and stainless steel 

locations) of the feedwater nozzles were re-evaluated to treat the hot standby transient 

and reactor core isolation cooling system injection as unique transients. The CUFen

values for the carbon steel, low alloy steel, and stainless steel locations were reduced 

from 0.165, 0.115, and 6.37 to 0.083, 0.113, and 5.55, respectively. These three 

locations remain bounding locations in accordance with the screening criteria. 

The applicant’s response revised LRA Table 4.3-8 to reflect the results of the re-evaluation for 

the six locations described above and to make unrelated editorial changes. The applicant’s 

response also provided the material of construction and a description of the temperature used to 

calculate the Fen factors for all the locations in LRA Table 4.3-8 that did not use average 

transient temperature. Additionally, the applicant clarified that the core spray penetration 

X-16A/B carbon steel body used the maximum operating temperature in its EAF calculations. 

The staff finds the applicant’s response acceptable because the applicant identified all of the 

locations that used an average temperature to calculate the Fen factors and re-evaluated them 

to either (a) use the design temperature or maximum operating temperature instead of an 

average temperate or (b) use an average temperature determined in a manner consistent with 

NUREG/CR-6909. The SLC piping inside containment and CRD assembly main flange are the 

only locations that use average transient temperatures to calculate Fen factors. The staff verified 

that a minimum transient temperature equal to the stainless steel threshold temperature was 

used to calculate the average temperature value; the transients associated with the average 

temperature value have a constant strain rate and linear temperature response; and the 

calculations for these locations are consistent with the guidance in NUREG/CR-6909. The staff 
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also verified that the screening criteria were consistently applied after these six locations were 

re-evaluated and that the sentinel locations did not change. 

In its annual update dated May 9, 2016, the applicant stated that it performed a revised CUFen

calculation for the condensing chamber using a new stress and fatigue analysis. The applicant 

stated that the new CUFen value is 0.025. The applicant stated that this location now has a 

lower CUFen value than a NUREG/CR-6260 feedwater nozzle-vessel intersection of the RPV 

upper region. However, the staff noted that the feedwater nozzle-vessel intersection is a low 

alloy steel component, and the condensing chamber is a stainless steel component. The staff 

further noted that the applicant is monitoring a stainless steel component in the RPV upper 

region, the feedwater nozzle safe end. Since the condensing chamber has a lower CUFen value 

than the feedwater nozzle safe end, the condensing chamber is bounded by a 

NUREG/CR-6260 location and is no longer a more limiting plant-specific location. Based on its 

response to RAI 4.3.3-3 and its annual update by letter dated May 9, 2016, the applicant further 

stated that three locations, which are the CRD nozzles, feedwater nozzles, and core ∆P nozzle, 

will be retained as bounding locations after reanalysis unless the current values are determined 

to be a result of significant over-conservatisms in the current analysis that would have resulted 

in these values not being selected initially if they had been analyzed in a manner consistent with 

the other component locations. In addition, the 2016 update revised LRA Table 4.3-8 to reflect 

the results of the re-evaluation for the locations described above. 

The staff noted that the CUFen value for one location is still projected to exceed 1.0, as 

described in a letter dated May 9, 2016. The location is the stainless steel portion of the reactor 

vessel feedwater nozzle safe end. The applicant will manage this location using the Fatigue 

Monitoring Program to ensure that the CUFen limit is not exceeded. The applicant stated that it 

intends to reanalyze and/or use stress-based fatigue monitoring for this location in accordance 

with the Fatigue Monitoring Program. The staff’s concerns described in RAI 4.3.3-3 and 

RAI 4.3.3-3a are resolved. 

The May 9, 2016, update letter also modified the list of sentinel locations. The final list of 

locations is based on a combination of the January 22, 2016, update letter and the May 9, 2016, 

update letter. 

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of environmentally assisted fatigue due to the reactor water environment on the intended 

functions of the ASME Class 1 reactor pressure vessel boundary will be adequately managed 

for the period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.3 because the applicant has addressed the staff recommendation for the closure 

of GSI-190. The applicant has identified high fatigue usage locations, including those in 

NUREG/CR-6260, and has evaluated these locations using the formulas, fatigue curves, and 

guidance in NUREG/CR-6909. The applicant is managing the effects of cumulative fatigue 

damage on the intended functions of the applicable components using the Fatigue Monitoring 

Program. The staff’s review of the Fatigue Monitoring Program appears in SER 

Section 3.0.3.2.8. 

4.3.3.3 UFSAR Supplement 

LRA Section A.2.2.3, as revised by the LRA annual update dated June 26, 2015, provides the 

UFSAR supplement summarizing the evaluation for the effects of reactor water environment on 

fatigue life. The staff reviewed LRA Section A.2.2.3 consistent with the review procedures in 

SRP-LR Section 4.3.3.2, which state that the review verifies that the applicant has provided a 
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summary description of the TLAA to be included in the UFSAR supplement. The SRP-LR also 

states that the review verifies that the information provided in the UFSAR supplement is 

equivalent to that in SRP-LR Table 4.3-2. 

The staff also noted that the applicant committed to developing EAF usage calculations that 

consider the effects of the reactor water environment (Commitment No. 12b) and to revising the 

Fatigue Monitoring Program procedures to maintain the cumulative fatigue usage below the 

design limit through the period of extended operation, with consideration of the reactor water 

environmental fatigue effects (Commitment No. 12d). This commitment is to be implemented 

before entering the period of extended operation. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.3.2.2 and, therefore, is acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the effects of 

reactor water environment on fatigue life, as required by 10 CFR 54.21(d). 

4.3.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of environmentally assisted 

fatigue due to the reactor water environment on the intended functions of pressure boundary 

components will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the evaluation, as required by 10 CFR 54.21. 

4.4 Environmental Qualification (EQ) Analyses of Electric Equipment 

The EQ program in 10 CFR 50.49, “Environmental Qualification (EQ) of Electric Equipment 

Important to Safety for Nuclear Power Plants,” is a TLAA for the purposes of license renewal. 

The TLAA of the EQ electrical components includes all long-lived, passive, and active electrical 

and instrumentation and control (I&C) components that are important to safety and located in a 

harsh environment. The harsh environments of the plant are those areas subject to 

environmental effects by LOCAs or high-energy line breaks (HELBs). EQ equipment comprises 

safety-related, Q-list, and nonsafety-related equipment, the failure of which could prevent 

satisfactory accomplishment of any safety-related function, and necessary post-accident 

monitoring equipment. 

4.4.1 Summary of Technical Information in the Application 

LRA Section 4.4 describes the applicant’s TLAAs for the EQ analyses of electric equipment. 

The applicant stated that qualification is established for the environmental and service 

conditions expected for normal plant operation and those conditions postulated for plant 

accidents. The applicant also stated that equipment qualification evaluations for EQ 

components that result in a qualification of at least 40 years, but less than 60 years, are 

considered TLAAs for license renewal. The LRA states that the “Environmental Qualification 

(EQ) of Electric Components” Program (EQ Program) is an existing program established to 

meet Fermi 2 commitments for 10 CFR 50.49. The LRA also states that through the applicant’s 

EQ Program, as required by 10 CFR 50.49, EQ components are refurbished, replaced, or their 

qualification is extended before reaching the aging limits established in the evaluation. The LRA 

further states that the reanalysis of an aging evaluation addresses attributes of the analytical 
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methods, data reduction and collection methods, underlying assumptions, acceptance criteria, 

and corrective actions. 

The applicant dispositioned the TLAAs for the EQ analyses of electric equipment in accordance 

with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of aging on the intended functions 

will be adequately managed by the EQ Program for the period of extended operation. 

4.4.2 Staff Evaluation 

The staff reviewed the applicant’s TLAAs for the EQ analyses of electric equipment and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in 

SRP-LR Section 4.4.3.1.3, which state that the reviewer verifies that the applicant has identified 

the appropriate program as described in the GALL Report. The acceptance criteria in SRP-LR 

Section 4.4.2.1 states that pursuant to 10 CFR 54.21(c)(1)(iii), an applicant must demonstrate 

that the effects of aging on the intended function(s) will be adequately managed for the period of 

extended operation. 

The EQ requirements established by 10 CFR Part 50, Appendix A, “General Design Criteria for 

Nuclear Power Plants,” Criterion 4, and 10 CFR 50.49 specifically require each applicant to 

establish a program to qualify electrical equipment so that such equipment, in its end-of-life 

condition, will meet its performance specifications during and following design-basis accidents. 

An EQ Program per the requirements of 10 CFR 50.49 is considered an AMP for the purposes 

of license renewal. Electric components in the applicant’s EQ Program identified as having a 

qualified life equal to or greater than the current operating term are considered a TLAA for 

licensee renewal. The EQ of electric components includes long-lived passive and active 

electrical and I&C components that are important to safety and are located in a harsh 

environment. Harsh environments are those areas of the plant subject to the environmental 

effects of a LOCA, a HELB, or post-LOCA environment. EQ equipment comprises 

safety-related and nonsafety-related equipment, the failure of which could prevent satisfactory 

accomplishment of any safety-related function, and necessary operation of post-accident 

monitoring equipment. 

The staff reviewed LRA Sections 4.4 and B.1.15 (EQ Program), plant basis documents, 

additional information provided to the staff, and interviewed plant personnel to verify whether the 

applicant provided adequate information to meet the requirement of 10 CFR 54.21(c)(1). For 

electrical equipment, the applicant uses 10 CFR 54.21(c)(1)(iii) in its EQ analyses of electric 

equipment TLAA evaluation to demonstrate that EQ equipment aging mechanisms and effects 

will be adequately managed during the period of extended operation. The GALL Report states 

that plant EQ programs that implement the requirements of 10 CFR 50.49 are considered 

acceptable AMPs to meet the requirements of 10 CFR 54.21(c)(1)(iii). GALL Report AMP X.E1, 

“Environmental Qualification (EQ) of Electric Components,” meets the requirements of 

10 CFR 54.21(c)(1)(iii). The staff reviewed the applicant’s EQ Program to determine whether 

the electrical and I&C components covered under this program will continue to perform their 

intended functions, consistent with the CLB, for the period of extended operation. 

The staff’s evaluation of the components qualification focused on how the EQ Program 

manages the aging effects of components associated with the EQ analyses of electric 

equipment TLAA in order to meet the requirements pursuant to 10 CFR 50.49. The staff 

conducted an audit of the information provided in LRA Sections 4.4, A.2.3, B.1.15, and A.1.15 

and program-basis documents, including the AMR of electrical systems, AMP evaluation results, 

and operating experience reviews – AMP effectiveness. LRA Section B.1.15 discusses the 
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component reanalysis attributes, including analytical models, data collection and reduction 

methods, underlying assumptions, acceptance criteria, and corrective actions. On the basis of 

its audit and review of LRA Section B.1.15, the staff concludes that the EQ Program the 

applicant claimed to be consistent with GALL Report AMP X.E1 is consistent; therefore, the staff 

also concludes that the applicant’s EQ analyses of electric equipment TLAAs are implemented 

in accordance with the requirements of 10 CFR 54.21(c)(1)(iii). The staff’s review of the 

applicant’s EQ Program is documented in SER Section 3.0.3.1.9. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii) that the 

effects of aging on the intended functions of components within the scope of the EQ Program 

will be adequately managed by the EQ Program for the period of extended operation. 

Additionally, the EQ analyses of electric equipment meets the acceptance criteria in SRP-LR 

Section 4.4.2.1.3 because the applicant’s EQ Program is consistent with GALL Report 

AMP X.E1, and therefore is capable of programmatically managing the qualified life of 

components within the scope of the program for license renewal. The staff finds that the 

continued implementation of the EQ Program provides reasonable assurance that the aging 

effects will be managed and that components within the scope of the EQ program will continue 

to perform their intended functions for the period of extended operation, per the requirements of 

10 CFR 50.49 and 10 CFR 54.21(c)(1)(iii). 

4.4.3 UFSAR Supplement 

LRA Section A.2.3 provides the UFSAR supplement summarizing the EQ analyses of electric 

equipment TLAAs. The staff reviewed LRA Section A.2.3 consistent with the review procedures 

in SRP-LR Section 4.4.3.2, which state that the applicant has provided information to be 

included in the UFSAR supplement that includes a summary description of the TLAA evaluation 

of the EQ of electric equipment and the applicant has provided a UFSAR supplement with 

information equivalent to that in Table 4.4-2. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.4.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the EQ analyses 

of electric equipment TLAAs for the period of extended operation, as required by 

10 CFR 54.21(d). 

4.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the aging mechanisms and effects of 

thermal, radiation, and cyclical aging on the intended functions of the electric equipment will be 

adequately managed by the EQ Program for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAAs evaluation, as required by 10 CFR 54.21(d). 

4.5 Concrete Containment Tendon Prestress Analyses 

4.5.1 Summary of Technical Information in the Application 

LRA Section 4.5 describes the applicant’s TLAA for containment tendon prestress analyses. 

LRA Section 4.5 and Table 4.1-1 state that this TLAA is not applicable because the Fermi 2 

containment design does not include tendons. 
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4.5.2 Staff Evaluation 

The staff reviewed UFSAR Section 3.8.2 and confirmed that the Fermi 2 containment structure 

is a Mark I steel containment and, therefore, its design does not include prestress tendons. The 

staff evaluated the applicant’s claim that concrete containment tendon prestress analysis is not 

a TLAA for the Fermi 2 steel containment, and finds it acceptable because such prestressing 

tendons are used only in prestressed concrete containment structures. 

4.5.3 UFSAR Supplement 

The staff concludes that an UFSAR supplement is not required because this TLAA is not 

applicable to containments without prestress tendons. 

4.5.4 Conclusion 

On the basis of its review, the staff concludes that this TLAA is not applicable to Fermi 2 and an 

UFSAR supplement is not required. 

4.6 Containment Liner Plate, Metal Containment, and Penetrations Fatigue 

Analyses 

LRA Section 4.6 provides the applicant’s TLAAs for fatigue analyses of the following 

containment structural components. 

 primary containment 

 vent line bellows 

 refueling and drywell seal bellows 

 traversing incore probe (TIP) penetration bellows 

 containment penetrations 

4.6.1 Primary Containment 

4.6.1.1 Summary of Technical Information in the Application 

LRA Section 4.6.1, as revised by the LRA annual update dated June 26, 2015, describes the 

applicant’s TLAA for the Fermi 2 Mark I steel containment suppression chamber (torus) and 

vent system whose design comply with the requirements for Class B vessel in ASME Code 

Section III. The applicant stated that the suppression chamber shell, supports, internals, and 

attachments have also been re-evaluated to include the hydrodynamic loading events and 

analysis methods defined by GE Topical Report NEDO-21888, “Mark I Containment Program 

Load Definition Report,” dated December 1978, and NUREG-0661, “Safety Evaluation Report: 

Mark I Containment Long-Term Program,” dated July 1980 (ADAMS Accession 

No. ML11203A031). The applicant also stated that appropriate service limits and the edition of 

the ASME Code Section III, specified in NUREG-0661, were applied to the reanalysis, which is 

documented in the plant unique analysis report for Fermi 2. LRA Table 4.6-1 summarizes the 

calculated bounding CUFs of the suppression chamber as 0.486 for the torus shell and 0.238 

for welds. LRA Table 4.6-1 also summarizes the CUFs of the containment vent system 

as 0.550 for the vent header and 0.194 for welds. The applicant further stated that transient 

cycles from safety relief valve (SRV) actuations and seismic cycles are tracked by the Fatigue 

Monitoring Program described in LRA Section B.1.17 and will be maintained below the cycle 
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value used in the fatigue evaluation, or a reanalysis will be completed prior to exceeding the 

design limits considered in the fatigue evaluations. 

The applicant dispositioned the TLAAs for the containment suppression chamber (torus shell, 

welds) and the containment vent system (vent header, welds) in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of aging due to fatigue on the intended 

functions will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation. 

4.6.1.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the fatigue design of the Fermi 2 Mark I steel 

containment suppression chamber (torus) and vent system and the corresponding disposition of 

10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR Section 4.6.3.1.1.3, 

which state that the applicant’s proposed AMP is reviewed to ensure that the effects of aging on 

the component’s intended functions are adequately managed for the period of extended 

operation. 

The staff noted that LRA Table 4.6-1 documented CUF values from SRV actuation, seismic or 

other applicable transient events, for the containment suppression chamber and the vent 

system, which are less than the code allowable limit of 1.0. During its review of components 

associated with LRA Table 3.5.1, item 3.5.1-9, the staff noted that LRA Table 3.5.2-1 includes, 

on LRA page 3.5-64, an AMR item for component type “steel elements (accessible areas): 

drywell shell; drywell head; drywell shell in sand pocket region” which credits TLAA - metal 

fatigue as the AMP. The staff noted that LRA Table 3.5.2-1 also includes, on LRA page 3.5-65, 

an AMR item for component type “steel elements: torus; vent line; vent header; vent line 

bellows; downcomers.” These AMR items in LRA Table 3.5.2-1 correspond to item 3.5.1-9 in 

LRA Table 3.5.1, which refers to the further evaluation in LRA Section 3.5.2.2.1.5. LRA 

Section 3.5.2.2.1.5, “Cumulative Fatigue Damage,” states, in part, that “the evaluation of fatigue 

as a TLAA for the Fermi 2 containment, including its drywell shell, torus, vent line bellows, 

downcomers, etc., is addressed in [LRA] Section 4.6.” However, from its review of LRA 

Section 4.6.1 “Primary Containment,” the staff could not find fatigue analyses or fatigue waiver 

analyses of the Fermi 2 primary containment drywell and the downcomers, specified by the 

ASME Code Section III (code of record), as a TLAA that was credited to manage fatigue 

cracking in the above mentioned items in LRA Table 3.5.2-1 and LRA Table 3.5.1. By letter 

dated January 14, 2015, the staff issued RAI 4.6.1-1 requesting the applicant to state whether 

or not the fatigue analysis or fatigue waiver analysis of the drywell and the downcomers 

required by ASME Code Section III is a TLAA under the CLB and, if so, to provide an evaluation 

of the fatigue analysis for these components in accordance with10 CFR 54.21(c)(1) to justify 

crediting it in the AMR results items mentioned above. The staff also requested the applicant to 

update the LRA, as appropriate, to be consistent with the responses to the above requests. 

In its response dated February 12, 2015, the applicant stated that stress analyses for the 

drywell shell and drywell head are not TLAAs since no cyclic loads were identified for these 

components in the applicable design specification in the CLB. The applicant also clarified that 

the downcomers are included as part of the vent system fatigue analysis identified as a TLAA in 

LRA Section 4.6.1, for which the bounding CUF results are documented in LRA Table 4.6-1. 

The applicant revised LRA Table 3.5.2-1 to delete the AMR item, corresponding to item 3.5.1-9 

on LRA page 3.5-64, for component type “steel elements (accessible areas): drywell shell; 

drywell head; drywell shell in sand pocket region” that credits AMP “TLAA - metal fatigue” to 
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manage the “cracking” aging effect. The applicant also revised LRA Section 3.5.2.2.1.5, 

“Cumulative Fatigue Damage,” to delete the reference to the TLAA for the drywell shell. 

The staff finds the response to RAI 4.6.1-1 acceptable because the applicant clarified that 

(a) the fatigue evaluation of the drywell shell and head is not a TLAA in the CLB and (b) the 

fatigue evaluation of the downcomers are included and bounded as part of the vent system 

fatigue analysis results in LRA Section 4.6.1. The staff also finds the revision to LRA 

Table 3.5.2-1 and LRA Section 3.5.2.2.1.5 to delete the AMR item and reference to the drywell 

shell components acceptable because no CLB fatigue analysis exists for the component type. 

The staff’s concern described in RAI 4.6.1-1 is resolved. 

The staff noted that the TLAA evaluations for primary containment components in LRA 

Section 4.6.1 and containment penetrations in LRA Section 4.6.5 appear to include load cycles 

from seismic operating-basis earthquake (OBE) and possibly safe-shutdown earthquake (SSE) 

events that the applicant claimed to track using the Fatigue Monitoring Program described in 

LRA Section B.1.17. However, the program descriptions in LRA Section B.1.17, “Fatigue 

Monitoring,” LRA Section A.1.17 “Fatigue Monitoring,” and GALL Report AMP X.M1, “Fatigue 

Monitoring,” appear focused on monitoring and tracking critical thermal and pressure transients 

for selected components. It was not clear to the staff whether the Fatigue Monitoring Program, 

credited in the disposition of the TLAAs in LRA Sections 4.6.1 and 4.6.5 in accordance with 

10 CFR 54.21(c)(1)(iii), included under its scope load cycles from OBE and SSE events as 

parameters monitored and tracked. Further, it was not clear as to the number of specific load 

cycles considered in the fatigue evaluation for each OBE event and/or SSE event that defines 

the total bounding limit of seismic load cycles monitored against by the credited Fatigue 

Monitoring Program. By letter dated January 14, 2015, the staff issued RAI 4.6.1-2 requesting 

the applicant to (1) clarify whether the Fatigue Monitoring Program includes under its scope load 

cycles from OBE or SSE (as applicable) events as parameters monitored and tracked, and 

(2) state the number of specific load cycles considered in the fatigue evaluations in LRA 

Sections 4.6.1 and 4.6.5 for each OBE or SSE event, as applicable, and clarify why seismic 

SSE is not listed as an analyzed transient in LRA Table 4.3-1. 

In its response dated February 12, 2015, to Part 1 of RAI 4.6.1-2, the applicant stated that the 

“Fatigue Monitoring Program includes all normal, upset, and testing condition events that are 

included in the TLAAs discussed in LRA Sections 4.6.1 and 4.6.5.” The applicant explained that 

OBE is an upset condition event that is included in the fatigue analysis, as required by ASME 

Code Section III, and counted in the Fatigue Monitoring Program. The applicant also stated that 

the “number of cycles experienced by each component per OBE event (two OBE events are 

considered as indicated in LRA Table 4.3-1) varies from 5 to 250 cycles, as described in 

UFSAR Section 3.7.3.1,” and that the total number of cycles considered in the analysis of some 

components may be greater. 

In its response to Part 2 of RAI 4.6.1-2, the applicant stated that the fatigue analyses in LRA 

Section 4.6.1 considered 600 seismic OBE cycles for the suppression chamber (torus shell) and 

1,000 cycles for the containment vent system. The applicant also stated that for the fatigue 

analysis of flued head penetrations addressed in LRA Section 4.6.5, 530 OBE cycles were 

considered for penetrations X-9A/B, 90 OBE cycles for penetration X-10, and 508 OBE cycles 

for the remaining penetrations. The applicant further explained that, as stated in UFSAR 

Section 3.7.3.1, “SSE is an emergency condition event that requires plant shutdown in 

accordance with the [TS],” and emergency or faulted condition events are not required to be 

considered in fatigue evaluations by ASME Code Section III. With regard to emergency events, 
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fatigue considerations would need to be addressed as part of the activities required for plant 

restart. 

The staff reviewed UFSAR Section 3.7.3.1 and confirmed that OBE is an upset condition 

required to be included in the fatigue evaluation and that SSE is an emergency condition not 

required to be included in the fatigue evaluation in the CLB in accordance with ASME Code 

Section III. The staff also noted the number of OBE seismic cycles considered by the applicant 

is conservative because there are more than the 20 cycles per seismic event indicated in 

UFSAR Section 3.7.3.1 for conservative design. The staff finds the response to RAI 4.6.1-2 

acceptable because the applicant (a) clarified that seismic OBE cycles are included and 

counted by the Fatigue Monitoring Program, (b) clarified that SSE, being an extreme or faulted 

event, is not required to be included in the fatigue evaluation by ASME Code Section III, and 

therefore not included as a plant transient in LRA Table 4.3-1, and (c) provided the actual 

number of seismic OBE cycles considered in the fatigue analysis of the different components 

addressed in LRA Sections 4.6.1 and 4.6.5, which are conservative. The staff’s concerns 

described in RAI 4.6.1-2 are resolved. 

Additionally, the staff noted that LRA Section 4.6.1 states that “SRV actuations and seismic 

cycles are tracked [by the Fatigue Monitoring Program] and will be maintained below the cycle 

value used in the fatigue evaluation, or re-analysis will be completed.” However, it was not clear 

which specific transient events (other than seismic) and corresponding analysis (cycle) input 

values were used in calculating the CUFs documented in LRA Table 4.6-1 for the containment 

suppression chamber and containment vent system, and will be monitored by the Fatigue 

Monitoring Program. By letter dated January 14, 2015, the staff issued RAI 4.6.1-3 requesting 

the applicant to state the specific applicable transients and corresponding cycle input limits that 

were used in the fatigue analyses for calculating the CUF values documented in LRA 

Table 4.6-1 for the containment suppression chamber (torus) and the containment vent system 

and will be monitored by the Fatigue Monitoring Program, and to clarify if the applicable 

transients were listed in LRA Table 4.3-1. 

In its response dated February 12, 2015, to RAI 4.6.1-3, the applicant stated that the CUFs 

shown in LRA Table 4.6-1 for the torus shell and vent are for the controlling case, which is 

normal operating conditions plus the (one) small break accident (SBA) event. The applicant 

stated that the governing transient, under normal operating conditions, are the SRV discharge 

loads from individual and/or multiple SRV actuations. For the containment vent system, the 

applicant explained that the largest CUF value was in the vent header at the intersection of 

downcomer and the header, with the magnitudes and numbers of cycles of downcomer lateral 

loads being the primary contributors to fatigue at this location. The applicant further explained 

that for the vent system weld, the largest CUF value was at the nozzle to gusset weld at the 

SRV penetration to the vent line, with the SRV temperature and thrust loads and the number of 

SRV actuations being the major contributors to fatigue at this location. The applicant stated that 

“[c]ycles from LRA Table 4.3-1 considered in these analyses for containment vent include 

individual SRV actuation [1435 cycles from LRA Table 4.3-1] and 1000 seismic [OBE] cycles.” 

The applicant further stated that the “governing load combination also includes SBA 

condensation oscillation and chugging load cycles.” For the suppression chamber (torus shell), 

the applicant stated that cycles from LRA Table 4.3-1 considered in the fatigue analyses include 

SRV discharge loads from individual (largest contributor) and multiple SRV actuations, and 600 

seismic (OBE) cycles. The applicant explained that the governing load combination also include 

SBA chugging load cycles. The applicant further stated that SRV actuations (single and 

multiple) and OBE events are included in LRA Table 4.3-1, and clarified that drywell pipe break 

events (e.g., SBA), which are faulted events, are not included in LRA Table 4.3-1 because 
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“ASME Code Section III does not require fatigue evaluation of emergency and faulted condition 

events.” The applicant explained that if an emergency or faulted condition event occurs during 

plant operation, it must be evaluated as part of plant restart activities. 

The staff noted from the response that the controlling transient contributors in the fatigue 

analyses of the Fermi 2 suppression chamber (torus) and the containment vent system are the 

SRV actuations during normal operating conditions, and seismic OBE events (upset condition). 

The staff also noted that cycles from both these transient events are included in LRA 

Table 4.3-1, and are tracked by the Fatigue Monitoring Program. The staff reviewed UFSAR 

Section 3.6.1.5.1 and confirmed that pipe break events are considered faulted events, which are 

not required to be included in fatigue evaluations by ASME Code Section III. Therefore, 

although load cycles from a single SBA event are conservatively accounted for in the fatigue 

usage evaluations, it is not necessary to monitor these cycles through the Fatigue Monitoring 

Program, and if a faulted event occurs during plant operation, its effects including fatigue 

considerations are evaluated prior to return to service. The staff finds the response to 

RAI 4.6.1-3 acceptable because the applicant (1) identified the applicable transients (i.e., SRV 

actuations, seismic OBE, and one SBA) and the corresponding cycle input values that were 

considered in the fatigue analyses for calculating the CUF values documented in LRA 

Table 4.6-1 for the suppression chamber and vent system, and that will be monitored using the 

Fatigue Monitoring Program, and (2) clarified that the transient cycles from required controlling 

events (i.e., SRV actuations and seismic OBE) are included in LRA Table 4.3-1 and will be 

monitored using the Fatigue Monitoring Program. The staff’s concern described in RAI 4.6.1-3 

is resolved. 

The staff also reviewed the applicant’s descriptions of the Fatigue Monitoring Program, in LRA 

Sections B.1.17 and A.1.17, credited as the AMP in the disposition of the TLAA. The staff noted 

that the applicant will use its Fatigue Monitoring Program, which with enhancements and an 

exception, is consistent with the 10 elements of GALL Report AMP X.M1 “Fatigue Monitoring,” 

to manage aging effects due to fatigue of the containment suppression chamber and vent 

system by monitoring applicable transients (i.e., SRV actuations and seismic OBE) against 

analysis input values tabulated in LRA Table 4.3-1 through the period of extended operation. 

The Fatigue Monitoring Program accomplishes this by monitoring applicable transients against 

analysis input values tabulated in LRA Table 4.3-1 through the period of extended operation and 

requires corrective action if the number of cycles approach analyzed values prior to exceeding 

the number of transient cycles assumed in the fatigue evaluation. LRA Sections A.1.17 and 

B.1.17 state that the Fatigue Monitoring Program monitors and tracks plant transients that 

cause significant fatigue usage for components identified to have a fatigue TLAA and, therefore, 

the program includes the containment suppression chamber (torus) and vent system in its 

scope. The staff thus determined that the Fatigue Monitoring Program, with enhancements and 

an exception, ensures that the number of transients assumed in the fatigue analysis of the 

Fermi 2 Mark I containment suppression chamber (torus) and vent system will not be exceeded 

during the period of extended operation or that corrective actions are taken to ensure that the 

code allowable limit for CUF of 1.0 is not exceeded. The staff’s evaluation of the Fatigue 

Monitoring Program is documented in SER Section 3.0.3.2.8. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging due to fatigue from applicable plant transients on the intended functions of the 

Fermi 2 Mark I containment suppression chamber (torus) and vent system will be adequately 

managed for the period of extended operation. Additionally, the TLAA meets the acceptance 

criteria in SRP-LR Section 4.6.2.1.1.3 because the applicant’s Fatigue Monitoring Program, with 

enhancements and exception, monitors applicable transient cycles on the Fermi 2 Mark I 
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containment suppression chamber (torus) and vent system, and requires corrective action prior 

to exceeding the allowable transient limits used in the fatigue evaluation to ensure that the 

design CUF limit of 1.0 is not exceeded during the period of extended operation. 

4.6.1.3 UFSAR Supplement 

LRA Section A.2.4 provides the UFSAR supplement summarizing the TLAAs for the Mark I 

containment suppression chamber (torus) and vent system. The staff reviewed LRA 

Section A.2.4 consistent with the review procedures in SRP-LR Section 4.6.3.2, which state that 

the staff verifies that the applicant has provided an UFSAR supplement that includes a summary 

description of the evaluation of the metal fatigue TLAA with information equivalent to that in 

SRP-LR Table 4.6-1. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAAs of the 

Mark I containment suppression chamber (torus) and vent system, as required by 

10 CFR 54.21(d). 

4.6.1.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue on the 

intended functions of the primary containment suppression chamber (torus shell, welds) and the 

containment vent system (vent header, welds) will be adequately managed by the Fatigue 

Monitoring Program for the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d). 

4.6.2 Vent Line Bellows 

4.6.2.1 Summary of Technical Information in the Application 

LRA Section 4.6.2 describes the applicant’s TLAA related to fatigue evaluation of the vent line 

bellows of the Fermi 2 Mark I containment. The applicant stated that the “vent line bellows were 

specified to be qualified for at least 500 cycles of bellows expansion from the drywell and torus 

temperature increase following an accident, 600 cycles from [OBE], and 300 cycles from [SSE].” 

The applicant also stated that through its calculation it determined that the bellows were 

qualified for over 6,000 cycles. Since accident or earthquake cycles have not occurred at the 

plant, the applicant concluded that the vent line bellows fatigue analysis remains valid for the 

period of extended operation. 

The applicant dispositioned the TLAA for the fatigue analysis of vent line bellows in accordance 

with 10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the period of 

extended operation. 

4.6.2.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the fatigue design of Fermi 2 containment vent line 

bellows and the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the review 

procedures in SRP-LR Section 4.6.3.1.1.1. The SRP-LR states that the reviewer compares the 
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number of assumed transients used in the existing calculations for the current operating term to 

the extrapolation to 60 years of operation of the number of operating transients experienced to 

date. The SRP-LR also states that comparison confirms that the number of transients in the 

existing analyses will not be exceeded during the period of extended operation. 

The staff noted that the design specifications of the vent line bellows required it to be qualified 

for at least 500 cycles of expansion from accident temperatures, 600 OBE cycles (from two 

OBE events stated in LRA Table 4.3-1) and 300 SSE cycles (from one SSE event), and the 

actual bellows design is qualified for a total of at least 6,000 cycles from accident temperature 

and seismic events. The staff also noted that no accident or seismic events have occurred to 

date at Fermi 2 and the number of transient cycles from accident temperature and seismic 

events specified and considered in the fatigue evaluation is conservative and there is 

reasonable assurance that it will not be exceeded during the period of extended operation. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analysis of the Fermi 2 containment vent line bellows remains valid for the period of 

extended operation. Additionally, the TLAA meets the acceptance criteria in SRP-LR 

Section 4.6.2.1.1.1 because there is reasonable assurance that the number of assumed 

accident temperature and seismic cyclic loads in the existing fatigue analysis of vent line 

bellows will not be exceeded during the period of extended operation. 

4.6.2.3 UFSAR Supplement 

LRA Section A.2.4 provides the UFSAR supplement summarizing the TLAA for fatigue analysis 

of the vent line bellows. The staff reviewed LRA Section A.2.4 consistent with the review 

procedures in SRP-LR Section 4.6.3.2, which state that the staff verifies that the applicant has 

provided an UFSAR supplement that includes a summary description of the evaluation of the 

metal fatigue TLAA with information equivalent to that in SRP-LR Table 4.6-1. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address TLAA involving 

fatigue analysis of the vent line bellows, as required by 10 CFR 54.21(d). 

4.6.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analysis for the vent line 

bellows remains valid for the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d). 

4.6.3 Refueling and Drywell Seal Bellows 

4.6.3.1 Summary of Technical Information in the Application 

LRA Section 4.6.3 describes the applicant’s TLAA for fatigue design of refueling bellows 

attached to the reactor vessel near the flange, and drywell seal bellows outside of the drywell 

shell. The applicant stated that its calculations determined that the refueling bellows were 

qualified for 45,000 thermal cycles and 9,000 refueling cycles, and that the drywell seal bellows 

were qualified for 2,800 thermal cycles and 180,000 refueling cycles. The applicant further 
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stated that the number of analyzed cycles are “many more than the expected number of 

startups and shutdowns and refueling outages through the period of extended operation.” 

Therefore, the applicant concluded that the bellows analyses remains valid for the period of 

extended. 

The applicant dispositioned the TLAAs for the refueling and drywell seal bellows in accordance 

with 10 CFR 54.21(c)(1)(i) to demonstrate that the analyses remain valid for the period of 

extended operation. 

4.6.3.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA related to the fatigue design of Fermi 2 containment 

refueling and drywell seal bellows and the corresponding disposition of 10 CFR 54.21(c)(1)(i), 

consistent with the review procedures in SRP-LR Section 4.6.3.1.1.1. The SRP-LR states that 

the reviewer compares the number of assumed transients used in the existing calculations for 

the current operating term to the extrapolation to 60 years of operation of the number of 

operating transients experienced to date. The SRP-LR also states that comparison confirms 

that the number of transients in the existing analyses will not be exceeded during the period of 

extended operation. 

The staff noted that Fermi 2 is on an 18-month operating cycle. The staff also noted from LRA 

Table 4.3-1 that the projected number of transient cycles from startup and shutdown (and 

refueling outage) events to the end of the period of extended operation is 234, which is 

significantly smaller than the number of thermal and refueling cycles for which the refueling 

bellows and drywell seal bellows have been qualified. Therefore, the staff finds that the number 

of qualified transient cycles (from startup and shutdown) and refueling events considered in the 

fatigue evaluation is so conservative that it will not be exceeded during the period of extended 

operation. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analysis of the refueling and drywell seal bellows remains valid for the period of 

extended operation. Additionally, the TLAA meets the acceptance criteria in SRP-LR 

Section 4.6.2.1.1.1 because the number of qualified thermal and refueling cycles in the existing 

fatigue analyses of the refueling and drywell seal bellows will not be exceeded during the period 

of extended operation. 

4.6.3.3 UFSAR Supplement 

LRA Section A.2.4 provides the UFSAR supplement summarizing the TLAA for the fatigue 

analyses of the refueling and drywell seal bellows. The staff reviewed LRA Section A.2.4 

consistent with the review procedures in SRP-LR Section 4.6.3.2, which state that the staff 

verifies that the applicant has provided an UFSAR supplement that includes a summary 

description of the evaluation of the metal fatigue TLAA with information equivalent to that in 

SRP-LR Table 4.6-1. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address TLAA evaluations 

involving fatigue analyses of the refueling and drywell seal bellows, as required by 

10 CFR 54.21(d). 
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4.6.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analyses for the refueling and 

drywell seal bellows remain valid for the period of extended operation. The staff also concludes 

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d). 

4.6.4 Traversing Incore Probe Penetration Bellows 

4.6.4.1 Summary of Technical Information in the Application 

LRA Section 4.6.4 describes the applicant’s TLAA for fatigue of the penetration bellows at the 

TIP penetrations. The applicant stated that the fatigue analysis determined that the bellows 

were qualified for more than 6,900 earthquake or thermal cycles, which are “many more cycles 

than they are expected to experience through the period of extended operation.” Therefore, the 

applicant concluded that the bellows fatigue analysis remains valid for the period of extended 

operation. 

The applicant dispositioned the TLAA for the TIP penetration bellows in accordance with 

10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the period of extended 

operation. 

4.6.4.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for fatigue of the penetration bellows at the TIP 

penetrations and the corresponding disposition of 10 CFR 54.21(c)(1)(i), consistent with the 

review procedures in SRP-LR Section 4.6.3.1.1.1. The SRP-LR states that the reviewer 

compares the number of assumed transients used in the existing calculations for the current 

operating term to the extrapolation to 60 years of operation of the number of operating 

transients experienced to date. The SRP-LR also states that comparison confirms that the 

number of transients in the existing analyses will not be exceeded during the period of extended 

operation. 

The staff noted from LRA Table 4.3-1 that the projected number of thermal transient cycles, to 

the end of the period of extended operation, from startup and shutdown, weekly reduction to 

50 percent power, and reduction to 0 percent power events is 500. Based on its review of LRA 

Table 4.3-1 and Section 4.6.2, the staff noted that the number of cycles considered from two 

OBE seismic events is 600 cycles and no seismic events have occurred to date. Thus, the 

number of thermal and seismic transient cycles expected through the period of extended 

operation is significantly smaller than the 6,900 thermal or seismic cycles for which the TIP 

penetration bellows are designed. Therefore, there is reasonable assurance that the number of 

thermal and seismic transient cycles considered in the fatigue analysis of the TIP penetration 

bellows is not expected to be exceeded during the period of extended operation. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analysis of the Fermi 2 TIP penetration bellows remains valid for the period of extended 

operation. Additionally, the TLAA meets the acceptance criteria in SRP-LR Section 4.6.2.1.1.1 

because the number of qualified thermal and seismic transient cycles in the existing fatigue 

analysis of the TIP penetration bellows will not be exceeded during the period of extended 

operation. 
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4.6.4.3 UFSAR Supplement 

LRA Section A.2.4 provides the UFSAR supplement summarizing the TLAA for fatigue analysis 

of the TIP penetration bellows. The staff reviewed LRA Section A.2.4 consistent with the review 

procedures in SRP-LR Section 4.6.3.2, which state that the staff verifies that the applicant has 

provided an UFSAR supplement that includes a summary description of the evaluation of the 

metal fatigue TLAA with information equivalent to that in SRP-LR Table 4.6-1. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address TLAA evaluations 

of the TIP penetration bellows, as required by 10 CFR 54.21(d). 

4.6.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analysis for the TIP 

penetration bellows remains valid for the period of extended operation. The staff also concludes 

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d). 

4.6.5 Containment Penetrations 

4.6.5.1 Summary of Technical Information in the Application 

LRA Section 4.6.5, as revised by the LRA annual update dated June 26, 2015, describes the 

applicant’s TLAA for the fatigue design of the containment sleeved flued head penetrations and 

the associated penetration sleeve bellows. 

The applicant stated that the sleeved penetration assemblies with bellows, described in UFSAR 

Section 3.8.2.1.3.1 and illustrated and listed (designated as Type 1 design) in UFSAR 

Figure 3.8-9, consist of the process pipe, guard pipe, penetration sleeve bellows, and flued 

head. The applicant also stated that for Class 1 piping (the Fermi 2 Group A), the design of the 

flued head meets the requirements for Class 1 components of ASME Code Section III, which 

specify a fatigue analysis that determines the CUF for the flued head. The applicant further 

stated that “UFSAR Figure 3.8-9 provides a cross-sectional drawing of the penetration 

assemblies and a listing of the penetrations that use this design (designated as Type I).” The 

applicant listed the CUF values (maximum value being 0.471 for feedwater A/B penetrations 

X-9A/B) for these flued head penetrations in LRA Table 4.6-2, calculated based on the number 

of transient cycles shown in the analysis input value column in LRA Table 4.3-1. The applicant 

concluded that Fermi 2 will manage the aging effects due to fatigue of these flued head 

penetrations using the Fatigue Monitoring Program (LRA Section B.1.17), which monitors the 

plant transients that contribute to fatigue usage. 

Regarding the specification for the penetration sleeve bellows the applicant stated that the 

specification: 

[R]equired the bellows to be analyzed for at least 200 cycles of normal operation 

thermal movement and 10 faulted (accident pressure and temperature) cycles. 

The analysis for these bellows determined they were capable of handling the 

movement from many more normal operation or faulted cycles than were 
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specified. The bellows are qualified for more than the projected number of 

startups and shutdowns; therefore, the bellows analysis remains valid for the 

period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). 

The applicant dispositioned the TLAAs for the containment flued head penetrations in 

accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of aging due to fatigue 

on the intended functions will be adequately managed by the Fatigue Monitoring Program for 

the period of extended operation. The applicant also dispositioned the TLAA for the sleeved 

penetration assembly bellows in accordance with 10 CFR 54.21(c)(1)(i) to demonstrate that the 

analysis remains valid for the period of extended operation. 

4.6.5.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for fatigue design of the containment sleeved flued 

head penetrations and the corresponding disposition of 10 CFR 54.21(c)(1)(iii), consistent with 

the review procedures in SRP-LR Section 4.6.3.1.1.3. The SRP-LR states that the applicant’s 

proposed AMP is reviewed to ensure that the effects of aging on the component’s intended 

functions are adequately managed for the period of extended operation. 

The staff noted that the CUF values listed in LRA Table 4.6-2 for different flued head 

penetrations are less than the code allowable limit of 1.0, and were calculated based on the 

number of cycles of applicable transients shown in the “Analysis Input Value” column in LRA 

Table 4.3-1, “Analyzed Transients with Projections,” which included two OBE events. Further, 

the staff noted that Fermi 2 will manage the aging effects due to fatigue of these penetrations 

using the Fatigue Monitoring Program described in LRA Section B.1.17. However, it was not 

clear which specific transient events in LRA Table 4.3-1 and corresponding analysis input 

values were used in calculating the CUFs documented in LRA Table 4.6-2 for flued head 

penetrations and will be monitored by the Fatigue Monitoring Program. By letter dated 

January 14, 2015, the staff issued RAI 4.6.5-1 requesting the applicant to state the specific 

applicable transients in LRA Table 4.3-1, and the corresponding analysis input values that were 

used in the design fatigue analysis for calculating the CUF values documented in LRA 

Table 4.6-2 for flued head penetrations and that will be monitored using the Fatigue Monitoring 

Program. 

In its response letter dated February 12, 2015, the applicant stated that the “containment 

penetrations were originally analyzed (ndesign) for 250 cycles (300 cycles for [penetration] 

X-9A/B) of bounding transient events and attached piping loads.” For purposes of projecting the 

number of cycles (n60) to 60 years of operation (i.e., analysis input values column in LRA 

Table 4.3-1), the applicant categorized the Fermi 2 containment flued head penetrations into 

three groups and provided a table listing the bounding transient events and the projected 

analysis cycle input values for each group. The transient events and transient cycle analysis 

input values provided in the applicant’s response for the feedwater penetrations X-9A/B, with 

the highest CUF values, are listed in Table 4.6.5-1 below. 

Table 4.6.5-1 Transients Considered for Feedwater A/B Penetrations X-9A/B 

Events for Penetrations 

X-9A/B 

LRA Table 4.3-1 

Event Number Plant Condition 

ndesign, Cycles 

(original 

design) 

n60, Cycles (60-year 

projected analysis 

input value in LRA 

Table 4.3-1) 

Startup 3 normal/upset 120 246 

Shutdown 15-17 normal/upset 111 246 
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Events for Penetrations 

X-9A/B 

LRA Table 4.3-1 

Event Number Plant Condition 

ndesign, Cycles 

(original 

design) 

n60, Cycles (60-year 

projected analysis 

input value in LRA 

Table 4.3-1) 

Pre-Op Blowdown 21 normal/upset 10 3 

Loss of FW Pumps 22 normal/upset 5 13 

Scram-Turbine Generator Trip 10 normal/upset 40 12 

Loss of FW Heaters-Turbine 

Trip with 100% Bypass 

8 normal/upset 10 10 

OBE (assumed to act 

concurrently with other 

transients) 

no event number 

assigned 

normal/upset 300 530 

(from response to 

RAI 4.6.1-2 in SER 

Section 4.6.1) 

The staff finds the response to RAI 4.6.5-1 acceptable because the applicant identified the 

specific applicable transient events in LRA Table 4.3-1 and the corresponding projected 

analysis (cycle) input values that were used in the design fatigue analysis for calculating the 

CUF values documented in LRA Table 4.6-2 for flued head penetrations, and which will be 

monitored using the Fatigue Monitoring Program. The staff’s concern described in RAI 4.6.5-1 

is resolved. 

The staff also reviewed the applicant’s descriptions of the Fatigue Monitoring Program, in LRA 

Section B.1.17 and LRA Section A.1.17, credited as the AMP in the disposition of the TLAA. 

The staff noted that the applicant will use its Fatigue Monitoring Program, which with 

enhancements and an exception described in LRA Section B.1.17 is consistent with the 10 

elements of GALL Report AMP X.M1, “Fatigue Monitoring,” to manage aging effects due to 

fatigue of the containment flued head penetrations. The Fatigue Monitoring Program 

accomplishes this by monitoring applicable transients against analysis input values listed in LRA 

Table 4.3-1 through the period of extended operation and by also requiring corrective action if 

the number of cycles approach analyzed values prior to exceeding the limit number of transient 

cycles in the fatigue evaluation. LRA Sections A.1.17 and B.1.17 state that the Fatigue 

Monitoring Program monitors and tracks plant transients that cause significant fatigue usage for 

components identified to have a fatigue TLAA; therefore, the program includes the containment 

flued head penetrations in its scope. The staff thus determined that the Fatigue Monitoring 

Program, with enhancements and an exception, ensures that the number of transients assumed 

in the fatigue analysis of the flued head penetrations will not be exceeded during the period of 

extended operation and that corrective actions are taken to ensure that the code allowable limit 

for CUF of 1.0 is not exceeded. The staff’s evaluation of the Fatigue Monitoring Program is 

documented in SER Section 3.0.3.2.8. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging due to fatigue on the intended functions of the containment flued head 

penetrations will be adequately managed for the period of extended operation. Additionally, the 

TLAA meets the acceptance criteria in SRP-LR Section 4.6.2.1.1.3 because the applicant’s 

Fatigue Monitoring Program, with enhancements and an exception, monitors applicable 

transient cycles on the flued head penetrations and requires corrective action prior to exceeding 

the allowable transient limits used in the fatigue evaluation to ensure that the design CUF limit 

of 1.0 is not exceeded during the period of extended operation. 

The staff also reviewed the applicant’s TLAA in LRA Section 4.6.5 for fatigue evaluation of the 

containment penetration sleeve bellows and the corresponding disposition of 
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10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR Section 4.6.3.1.1.1. 

The SRP-LR states that the reviewer compares the number of assumed transients used in the 

existing calculations for the current operating term to the extrapolation to 60 years of operation 

of the number of operating transients experienced to date. The SRP-LR also states that 

comparison confirms that the number of transients in the existing analyses will not be exceeded 

during the period of extended operation. 

The staff noted the applicant’s statement that the design specification for the penetration sleeve 

bellows required it to be analyzed for at least 200 cycles of normal operation thermal movement 

and 10 faulted (accident pressure and temperature) cycles. However, without providing the 

actual number of transient cycles, the applicant claimed that the analysis for these bellows 

determined they were capable of handling the movement from many more normal operation or 

faulted cycles than were specified. The staff needed this information to verify that the bellows 

analysis remains valid for the period of extended operation. Therefore, by letter dated 

January 14, 2015, the staff issued RAI 4.6.5-2 requesting the applicant to state the number of 

normal operation and/or faulted transient cycles that the penetration sleeve bellows were 

determined to be capable of handling by the bellows’ design fatigue analysis. 

In its response letter dated February 12, 2015, the applicant stated that the “containment 

penetration bellows are installed to accommodate the differential movement between the 

drywell nozzle pipe and the flued head anchor.” The applicant also stated that these bellows 

were originally designed for 200 cycles of cold to normal operating thermal movement, 

10 cycles of cold to faulted thermal movement, and that most penetration bellows were 

analyzed for 4 cycles of compression/extension during installation. The applicant further stated 

that for the most limiting penetration bellows, more than 3,000 cycles of cold to normal operating 

thermal movement would be required to reach the allowable CUF value of 1.0. Therefore, the 

applicant concluded that the “permissible number of cycles is an order of magnitude greater 

than the number of startup and shutdown cycles expected through the period of extended 

operation.” 

The staff noted that, although faulted thermal movements are not required to be considered in a 

fatigue analysis by ASME Code Section III, the penetration bellows analysis included 10 cycles 

of cold to faulted thermal movement. Further, the applicant’s response indicated that, for the 

predominant cold to normal operating thermal transient applicable to the fatigue analysis, the 

allowable number of transient cycles is over 3,000, which is an order of magnitude larger than 

the expected number of thermal cycles from startup and shutdown events (i.e., 234 from LRA 

Table 4.3-1) during the period of extended operation. The staff finds the applicant’s response to 

RAI 4.6.5-2 acceptable because the applicant provided the allowable number of thermal 

transient cycles (i.e., 3,000) for the limiting penetration bellows, which is significantly larger than 

the expected number of thermal cycles through the period of extended operation; therefore, the 

fatigue analysis of the penetration sleeve bellows remains valid for the period of extended 

operation. The staff’s concern described in RAI 4.6.5-2 is resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analysis of the containment penetration sleeve bellows remains valid for the period of 

extended operation. Additionally, the TLAA meets the acceptance criteria in SRP-LR 

Section 4.6.2.1.1.1 because the number of assumed thermal cycles, in the existing fatigue 

analyses of the penetration sleeve bellows will not be exceeded during the period of extended 

operation. 
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4.6.5.3 UFSAR Supplement 

LRA Section A.2.4 provides the UFSAR supplement summarizing the TLAA for the fatigue 

analyses of the containment flued head penetrations and sleeved penetration assembly bellows. 

The staff reviewed LRA Section A.2.4 consistent with the review procedures in SRP-LR 

Section 4.6.3.2, which state that the staff verifies that the applicant has provided an UFSAR 

supplement that includes a summary description of the evaluation of the metal fatigue TLAA 

with information equivalent to that in SRP-LR Table 4.6-1. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address TLAA evaluations 

of flued head penetrations and sleeved penetration assembly bellows, as required by 

10 CFR 54.21(d). 

4.6.5.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analysis for the containment 

sleeved penetration assembly bellows remains valid for the period of extended operation. The 

staff also concludes that the applicant has provided an acceptable demonstration, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue on the intended functions of the 

containment flued head penetrations will be adequately managed by the Fatigue Monitoring 

Program for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an appropriate summary description of the TLAA evaluations, as required 

by 10 CFR 54.21(d). 

4.7 Other Plant-Specific TLAAs 

4.7.1 Erosion of the Main Steam Line Flow Restrictors 

4.7.1.1 Summary of Technical Information in the Application 

LRA Section 4.7.1 describes the applicant’s TLAA for erosion of the main steam line flow 

restrictors. The LRA states that “the main steam line flow restrictors are fabricated from 

stainless steel and that only very slow erosion is expected to occur over time.” The LRA also 

states that UFSAR Section 5.5.4.4 summarizes the existing analysis of the effect of this erosion 

on flow restriction. The LRA further states that UFSAR Section 5.5.4.4 “postulates that even 

with an erosion rate of 0.004 inches per year, the increase in choked flow through the restrictors 

after 40 years of operation would be no more than 5 percent.” The erosion rate was 

re-evaluated and a new erosion rate was established for the period of extended operation. The 

LRA new erosion rate is based on the specific material of the flow restrictors and operation of 

the main steam lines with flow velocities that would be present following an EPU. Based on 

recalculating the analysis with the new erosion rate and a time frame of 60 years, the LRA 

states that the choked flow will remain within the 5 percent limit specified in UFSAR 

Section 5.5.4.4. 

The applicant dispositioned the TLAA for erosion of the main steam line flow restrictors in 

accordance with 10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to 

the end of the period of extended operation. 
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4.7.1.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA evaluation for erosion of the main steam line flow 

restrictors and the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the 

review procedures in SRP-LR Section 4.7.3.1.2, which state that the staff is to review the results 

of the applicant’s revised analysis to verify that the evaluation period has been extended, such 

that the analysis is valid for the period of extended operation. The SRP-LR also states that the 

applicant may recalculate the analysis using a 60-year period to show that the acceptance 

criteria continue to be satisfied for the period of extended operation. In addition, the SRP-LR 

states that the applicant may revise the analysis by recognizing and re-evaluating any overly 

conservative conditions and assumptions. 

Based on its review of UFSAR Section 5.5.4.4, the staff determined that the particular 

acceptance criteria for the analysis is to have no more than a 5 percent increase in the choked 

flow rate as a result of erosion of the main steam line flow restrictors. The staff determined that 

the erosion rate of 0.004 inch per year, provided in UFSAR Section 5.5.4.4, results in a total of 

0.160 inch of erosion after 40 years of operation. The staff noted that the applicant revised the 

existing analysis to show that the acceptance criteria will continue to be met through the period 

of extended operation. The applicant’s revised analysis is based on a 60-year period and a 

re-evaluation of the overly conservative assumption concerning the erosion rate. The staff 

found this approach to be acceptable because it is consistent with the guidelines in SRP-LR 

Section 4.7.3.1.2. 

Because the LRA did not provide certain details concerning the results and methodology for the 

revised analysis, the staff determined that the applicant had not satisfactorily demonstrated that 

the analysis has been projected to the end of the period of extended operation pursuant to 

10 CFR 54.21(c)(1)(ii). Specifically, the staff found that the LRA did not provide the new erosion 

rate or describe how this rate was calculated. The staff also found that the LRA did not describe 

how the choked flow rate was calculated or quantify by how much it will increase as a result of 

recalculating the analysis. As such, the staff determined that the LRA did not provide sufficient 

information to demonstrate that the increase in the choked flow rate will remain less than the 

acceptance criteria of 5 percent. By letter dated January 20, 2015, the staff issued RAI 4.7.1-1 

requesting that the applicant quantify the new erosion rate and describe and justify the 

methodology that was used to calculate it. The staff also requested that the applicant indicate 

whether wall thickness measurements of the Fermi 2 main steam line flow restrictors were 

considered in the determination of the new erosion rate. In addition, the staff requested that the 

applicant quantify the increase in the choked flow rate that was determined as a result of 

recalculating the analysis using the new erosion rate and a time frame of 60 years. The staff 

also requested that the applicant indicate whether the methodology used for this particular 

calculation was the same as the methodology used in the existing analysis. If the methodology 

was different, then the staff requested the applicant to provide justification. 

In its response letter dated March 5, 2015, as supplemented by letter dated May 19, 2015, the 

applicant stated that thickness measurements were not taken on the main steam line flow 

restrictor stainless steel castings and were not used to determine the new erosion rate. The 

new erosion-corrosion rate, provided in the applicant’s response, for the flow restrictor castings 

is less than the original rate of 0.004 inch per year. The applicant cited a combination of design 

features and erosion-corrosion data to support its determination that the original 

erosion-corrosion rate was overly conservative. The key input used to calculate the choked flow 

after 60 years of operation is the new erosion-corrosion rate. The increase in flow area after 

60 years of operation is determined using the new erosion-corrosion rate and used by the 
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applicant to conclude that the increase in choked flow rate is below 5 percent, with the choked 

flow rate calculated using the enhanced GEH homogenous equilibrium method. The proprietary 

portion of the RAI response stated specific numerical values for new erosion-corrosion rate and 

increase in choked flow that are below 0.004 inch per year and 5 percent, respectively. 

The staff reviewed the applicant’s response and the impact of 60 years of operation on the 

increase in restrictor flow area. Based on the review of the response, the staff verified that the 

expected erosion-corrosion rate of the stainless steel, high chromium Grade CF8, main steam 

line restrictors is less than the rate stated in UFSAR Section 5.5.4.4, and the total erosion after 

60 years of operation is projected to be less than 0.160 inch. The staff also verified that the 

projected increase in the choked flow is within the acceptance criteria of 5 percent stated in 

UFSAR Section 5.5.4.4. The staff’s concerns described in RAI 4.7.1-1 are resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis for erosion of the main steam line flow restrictors has been projected to the end of the 

period of extended operation. Additionally, the analysis meets the acceptance criteria in 

SRP-LR Section 4.7.2.1 because the analysis re-evaluated the overly conservative assumptions 

in the original analysis to show that the TLAA acceptance criteria continue to be satisfied for the 

period of extended operation. 

4.7.1.3 UFSAR Supplement 

LRA Section A.2.5.1 provides the UFSAR supplement summarizing the applicant’s TLAA for 

erosion of the main steam line flow restrictors. The staff reviewed LRA Section A.2.5.1 

consistent with the review procedures in SRP-LR Section 4.7.3.2, which state that the applicant 

is to provide a summary description for its evaluation of each TLAA. The acceptance criteria of 

SRP-LR Section 4.7.2.2 state that the summary description should contain information on the 

disposition of the TLAA for the period of extended operation and be appropriate such that later 

changes can be controlled by 10 CFR 50.59. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address erosion of the 

main steam line flow restrictors, as required by 10 CFR 54.21(d). 

4.7.1.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for erosion of the main 

steam line flow restrictors has been projected to the end of the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7.2 Determination of High-Energy Line Break Locations 

4.7.2.1 Summary of Technical Information in the Application 

LRA Section 4.7.2, as revised by the LRA annual update dated June 26, 2015, describes the 

applicant’s TLAA for the fatigue of HELB locations. The LRA states that “the method used to 

determine intermediate locations of pipe breaks in high-energy lines includes an evaluation 

based on CUF [values] being less than 0.1 if other stress criteria are also met,” as also stated in 
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UFSAR Sections 3.6.1 and 3.6.2. The LRA states that the CUF analyses used in the 

determination of postulated HELB locations were based on design transients assumed for the 

original 40-year life of the plant and are, therefore, considered TLAAs. The LRA also states that 

the CUF calculations were modified to account for the projected cycles for 60 years of operation 

and that limiting locations were reanalyzed, which resulted in these locations meeting the 0.1 

CUF criteria. The LRA states that the Fatigue Monitoring Program will identify when the 

transients affecting high-energy piping systems are approaching their analyzed number of 

cycles. 

The applicant dispositioned the TLAA in accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate 

that the effects of aging associated with fatigue on the intended functions of HELB locations will 

be adequately managed by the Fatigue Monitoring Program for the period of extended 

operation. 

4.7.2.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the fatigue of HELB locations and the corresponding 

disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR 

Section 4.7.3.1.3, which state that the applicant proposes to manage the aging effects 

associated with the TLAA by an AMP in the same manner as described in the integrated plant 

assessment (IPA) in 10 CFR 54.21(a)(3). The SRP-LR also states that the reviewer reviews the 

applicant’s AMP to verify that the effects of aging on the intended function(s) are adequately 

managed consistent with the CLB for the period of extended operation. In addition, the SRP-LR 

states that a license renewal applicant should identify the structures and components (SCs) 

associated with the TLAA. 

The staff also reviewed the applicant’s TLAA against the acceptance criteria in SRP-SLR 

Section 4.3.2.1.1.3, which state that an AMP corresponding to GALL Report AMP X.M1, 

“Fatigue Monitoring,” may be used by the applicant to demonstrate acceptance of a CUF-based 

analysis in accordance with the requirement in 10 CFR 54.21(c)(1)(iii). 

UFSAR Section 3.6.2 states that high-energy fluid systems include systems in which, under 

normal or upset plant conditions, the maximum operating temperature exceeds 200 °F or the 

maximum operating pressure exceeds 275 psig. UFSAR Section 3.6.2.1.2.2 establishes the 

criteria for identifying a given location as a HELB location. One such criterion is that any 

intermediate piping location between terminal ends with a CUF that exceeds an acceptance 

criterion value of 0.1 is identified as a HELB location. UFSAR Section 3.6.2.1.2.2 and LRA 

Section 4.7.2 state that postulated pipe breaks in the high-energy piping between the 

containment penetrations and outboard isolation valves were not postulated because the piping 

was conservatively designed and restrained. The staff noted that UFSAR Section 3.6.2.1.2.2 

states that the piping was conservatively designed and restrained such that the transmitted pipe 

load during a postulated pipe break would not impair the operability of the outboard isolation 

valve nor affect the integrity of the piping of the containment penetration. 

The applicant credits the Fatigue Monitoring Program to manage the effects of aging associated 

with the fatigue analyses of these postulated HELB locations through the period of extended 

operation. The staff’s review of the Fatigue Monitoring Program is documented in SER 

Section 3.0.3.2.8. The staff noted that as long as the number of transients that occur at the site 

remains bounded by the cycle limits assumed in the HELB analyses, the HELB evaluations will 

remain valid. The staff also noted that the applicant provided an exception to its Fatigue 

Monitoring Program to apply the lower CUF limit of 0.1 at HELB locations. The staff found the 
4-90 

exception to apply a value of 0.1 as the acceptance criteria for the HELB CUF analysis was 

acceptable because it is in conformance with recommended acceptance criteria defined for 

these types of analyses in NUREG-0800 Section 3.6.2, “Determination of Rupture Locations 

and Dynamic Effects Associated with the Postulated Rupture of Piping.” Therefore, the staff 

determined that the enhanced Fatigue Monitoring Program, with an exception, ensures that 

(1) the number of transients will not be exceeded during the period of extended operation and 

(2) corrective actions are taken such that the impact of cracking by fatigue or cumulative fatigue 

damage on the intended functions of the ASME Code Class 1 components analyzed in the 

HELB analyses will be adequately managed during the period of extended operation. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cracking due to fatigue on the intended functions of the HELB locations will be 

adequately managed for the period of extended operation. Additionally, it meets the acceptance 

criteria in SRP-LR Sections 4.7.2.1 and 4.3.2.1.1.3 because: (a) the applicant has adequately 

demonstrated that the Fatigue Monitoring Program provides an acceptable basis for managing 

the impact of cracking by fatigue or cumulative fatigue damage on the intended functions of the 

ASME Code Class 1 components analyzed in the HELB locations, and (b) this is consistent with 

bases for accepting these types of TLAAs in accordance with 10 CFR 54.21(c)(1)(iii). 

4.7.2.3 UFSAR Supplement 

LRA Section A.2.5.2 provides the UFSAR supplement summarizing the TLAA for HELB 

postulated locations based on CUF. The staff reviewed LRA Section A.2.5.2 consistent with the 

review procedures in SRP-LR Section 4.7.3.2, which state that the information to be included in 

the UFSAR supplement should include a summary description of the evaluation of the TLAA. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2. Additionally, the staff determines that the applicant provided an 

adequate summary description of its actions to address the TLAA for HELB postulated locations 

based on CUF, as required by 10 CFR 54.21(d). 

4.7.2.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended 

functions of the HELB postulated locations will be adequately managed by the Fatigue 

Monitoring Program for the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d). 

4.7.3 Jet Pump Auxiliary Spring Wedge Assembly 

4.7.3.1 Summary of Technical Information in the Application 

LRA Section 4.7.3 describes the applicant’s TLAA for the loss of preload of the jet pump 

auxiliary spring wedge assemblies installed on jet pumps 1, 2 and 15. The LRA states that the 

auxiliary spring wedge assemblies will experience a loss of spring preload due to exposure to 

neutron fluence. The applicant also stated that the original evaluation of this loss of preload 

considered a fluence of 1.2x1020 n/cm2 for a 40-year design life. The LRA states that the 

applicant re-evaluated the fluence to the end of the period of extended operation and 

determined that the projected neutron fluence for one of the spring wedge assemblies would 
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exceed the original design fluence by 4 percent, and determined that this increase in fluence 

would result in an increase in preload loss. Based on recalculating the analysis with the new 

fluence and a period of 60 years, the LRA states that higher fluence will have no adverse impact 

on the structural integrity and functional performance of the spring wedge assembly. 

The applicant dispositioned the TLAA for the loss of preload of the jet pump auxiliary spring 

wedge assembly in accordance with 10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has 

been projected to the end of the period of extended operation. 

4.7.3.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the jet pump auxiliary spring wedge assembly and 

the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.7.3.1.2, which state that the applicant may recalculate the analysis using a 

60-year period to show that the acceptance criteria continue to be satisfied for the period of 

extended operation. The SRP-LR also states that the applicant may revise the analysis by 

recognizing and re-evaluating any overly conservative conditions and assumptions. However, 

the staff’s review of this TLAA found that the applicant did not provide sufficient basis for the 

conclusion of the capability of the component to perform its intended function; therefore, the 

staff determined that the LRA did not properly describe this TLAA. By letter dated 

January 14, 2015, the staff issued RAI 4.7.3-1 requesting the applicant provide additional 

information on the following items to support the conclusion that an increased loss of preload 

due to an increase in projected fluence will have no adverse impact on the intended function of 

the spring wedge assembly. The RAI requested information on (1) how preload ensures 

functional performance and the amount of preload that ensures functionality of the spring wedge 

assemblies, (2) justification for and methodology used to calculate spring wedge assembly 

neutron fluence through the end of the period of extended operation, (3) the methodology used 

to calculate loss of preload and how it is different from the original methodology, and (4) the 

amount of preload loss calculated to the end of the period of extended operation and how that 

value compares to the amount needed to ensure functional performance of the spring wedge 

assembly. 

In its response letter dated February 12, 2015, the applicant stated the following: 

(1) In response to how preload ensures functional performance of the spring wedge 

assembly, the applicant stated that the component is designed to function with any 

magnitude of preload. 

(2) Regarding the methodology used to calculate spring wedge assembly fluence, the 

applicant stated it used NRC approved methodology in Licensing Topical Report (LTR) 

NEDC-32983P-A that the NRC staff determined was acceptable as a best-estimate 

prediction of the fast neutron flux for BWR pressure vessel and internal components. 

Additionally, the applicant stated that the neutron fluence is calculated using 

conservative assumptions, including (a) calculated end-of-life fluence using the peak flux 

for each wedge, (b) “the operating history that included the historical and projected 

reactor power level and the associated time,” and (c) a capacity factor of 100 percent to 

ensure a conservative end-of-life fluence of 52 effective full power years. 

(3) Regarding the description of the methodology used to calculate loss of preload, the 

applicant stated that the reanalysis methodology is the same as the original 

methodology and attributes loss of preload to wedge material stress relaxation due to 
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neutron fluence at reactor operating temperature and potential plastic deformation 

during installation. 

(4) When quantifying the amount of preload loss calculated to the end of the 60-year period 

and comparing that value to the amount needed to ensure functional performance of the 

spring wedge assembly, the applicant stated that the new calculated amount of 

expected preload loss is only slightly higher than originally projected for the end of the 

current operating period. Additionally, the applicant showed that the total amount of 

spring preload projected to the end of the period of extended operation is more than the 

amount needed in the most limiting case, where the friction forces between the wedge 

and associated restrainer bracket must be greater than the maximum combined loads 

applicable to the auxiliary spring wedge assembly. 

The staff finds the applicant’s response to RAI 4.7.3-1 Parts 1-4 acceptable because it provided 

proprietary values regarding the design preload, expected loss of preload, and loss of preload 

projected to the end of the period of extended operation, using staff-approved fluence 

methodology for 52 EFPY, for the jet pump auxiliary spring wedge assembly. The response 

showed that these projected values are within the minimum preload limits used as acceptance 

criteria for the spring wedges. Therefore, the staff finds the applicant has appropriately 

projected the analysis to the end of the period of extended operation. The information provided 

regarding how functionality of the spring wedge is ensured, how flux was calculated, how stress 

relaxation was analyzed, and how the final amount of preload compares to the amount needed 

to ensure functionality, consists of a sufficient description of the analysis and conclusions for 

this TLAA. The staff’s concerns described in RAI 4.7.3-1 are resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis for the auxiliary spring wedge assemblies has been projected to the end of the period 

of extended operation. The staff finds that the applicant provided the appropriate fluence and 

loss of preload projections to demonstrate that it projected the analysis to the end of the period 

of extended operation and that the reanalysis still meets the applicant’s limit on preload loss. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.3.1.2 because the applicant 

has provided a sufficient description of the analysis and conclusions to show that they are 

satisfactory for the period of extended operation. 

4.7.3.3 UFSAR Supplement 

LRA Section A.2.5.3 provides the UFSAR supplement summarizing the TLAA for loss of preload 

in jet pump auxiliary spring wedge assemblies. The staff reviewed LRA Section A.2.5.3 

consistent with the review procedures in SRP-LR Section 4.7.3.2, which state that the UFSAR 

supplement provides a summary description of the evaluation of the TLAA. 

The staff’s review of this UFSAR supplement found that the applicant did not provide a sufficient 

summary description of this TLAA. By letter dated January 14, 2015, the staff issued 

RAI 4.7.3-2 requesting the applicant to provide additional information regarding (1) which 

auxiliary spring wedge assemblies are addressed in the analysis and which assemblies 

represent the most limiting case, (2) the acceptance criteria used to determine how functionality 

of the spring wedge is ensured, and (3) the results of the analysis in terms of the amount of 

preload loss and how those results compare to the acceptance criteria. 

In its response dated February 12, 2015, the applicant revised LRA Section A.2.5.3 to include 

the following information: 
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(1) Auxiliary spring wedges are installed on jet pumps 1, 2, and 15, and are designed to 

“maintain continuous three-point contact for the inlet mixer to the restrainer bracket.” 

(2) The wedge installed on jet pump 1 was determined to be the most limiting, with its 

projected neutron fluence slightly exceeding the design fluence when projected to the 

end of the period of extended operation. 

(3) “The results of the analysis demonstrated that the available preload at the end of the 

period of extended operation is considerably greater than the required preload. 

Additionally, the auxiliary spring wedge assembly is designed to function independent of 

the spring preload i.e. the spring wedge function works at any preload. There will be 

contact between the belly band, auxiliary spring wedge assembly, and the restrainer 

bracket.” 

The staff finds this response acceptable because the amendments to the UFSAR supplement 

section provided additional specific details on (a) how the jet pump assemblies are designed, 

(b) which of the jet pump auxiliary spring wedge assemblies in the plant design was the limiting 

assembly for the loss of preload TLAA, and (c) how preload is used to ensure that the jet pump 

auxiliary spring wedge assemblies will maintain their integrity during the period of extended 

operation. The staff’s concerns described in RAI 4.7.3-2 are resolved. 

Based on its review of the UFSAR supplement, as amended by letter dated January 14, 2015, 

the staff finds it meets the acceptance criteria in SRP-LR Section 4.7.2.2, and is therefore 

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address the loss of preload in jet pump auxiliary spring wedge 

assemblies TLAA, as required by 10 CFR 54.21(d). 

4.7.3.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for loss of preload in jet 

pump auxiliary spring wedge assemblies has been projected to the end of the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7.4 Jet Pump Slip Joint Repair Clamps 

4.7.4.1 Summary of Technical Information in the Application 

LRA Section 4.7.4 describes the applicant’s TLAA for loss of preload of the jet pump slip joint 

repair clamps. The LRA states that the slip joint repair clamps are connected to the diffuser and 

the mixer (throat) in the jet pump assembly. The LRA states that the original analysis of the 

clamps used a stress relaxation of 5 percent, due to neutron fluence. A fluence analysis was 

performed at the clamp location for 52 EFPY of plant operation, including MUR/TPO. The LRA 

also states that the fluence analysis produced a value of 3.07x1018 n/cm2 (E > 1 MeV), which is 

below the threshold of 1x1019 n/cm2 to cause stress relaxation in stainless steel from neutron 

irradiation. Based on the neutron irradiation level, the applicant concludes that the original 

relaxation value remains valid and the stress report results remain applicable for the period of 

extended operation. 
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The applicant dispositioned the TLAA for the jet pump slip joint repair clamps in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation. 

4.7.4.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the jet pump slip joint repair clamps and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.7.3.1.2, which state that the staff is to review and verify that the revised 

analyses are valid for the period of extended operation. The SRP-LR also states that the 

applicant may recalculate the TLAA using a 60-year period to show that the TLAA acceptance 

criteria continue to be satisfied during the period of extended operation. 

The LRA states that the clamps were installed with a preload that may decrease due to neutron 

fluence and thermal exposure. The LRA also states that the analysis that evaluated the 

decrease of the installation preload for the slip joint repair clamp is a TLAA that has been 

projected to the end of the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(ii). However, the staff lacked sufficient information to evaluate the jet pump 

slip joint repair clamp TLAA for the period of extended operation and determine if the UFSAR 

supplement, LRA Section A.2.5.4, adequately summarizes the TLAA in accordance with 

10 CFR 54.21(d). By letter dated December 23, 2014, the staff issued RAI 4.7.4-1 requesting 

that the applicant provide (1) a functional description of the clamps, (2) a physical description of 

the clamps, and (3) summaries of the analysis used to evaluate the jet pump slip joint repair 

clamps during the period of extended operation. 

In its response dated February 5, 2015, the applicant stated that the intended function of the slip 

joint clamp is to provide a lateral preload that restrains the motion of the jet pump inlet mixer 

relative to the diffuser collar to suppress abnormal jet pump vibration. The loss of preload, 

below a minimum design value, would preclude the clamp from performing this function. The 

applicant also provided drawings referenced from site procedures to show the physical 

characteristics of the clamp. The applicant stated that a relaxation evaluation was performed for 

the slip joint clamp to determine if the original structural evaluation would remain valid for the 

period of extended operation (52 EFPY). The analysis used to determine the level of neutron 

irradiation exposure (fluence) that the clamps will experience is described in Section 2.1 of 

NEDC-32983P-A, “Licensing Topical Report General Electric Methodology for Reactor Pressure 

Vessel Fast Neutron Flux Evaluations,” Revision 2, dated January 2006, which is approved by 

the staff and consistent with RG 1.190. The neutron fluence analysis was performed, using the 

conservative assumption that the clamps have been installed since the beginning of plant life, 

and produced a value of 3.07x1018 n/cm2 for 52 EFPY. The threshold value of 1x1019 n/cm2, to 

cause stress relaxation in stainless steel from neutron irradiation, was taken from design curves 

in the GE BWR Materials Handbook. The design curves are the result of the statistical 

treatment of empirically established stress relaxation curves that have been developed and 

verified by the GEH Materials Engineering Group. The applicant concluded that the original 

analysis and results of the stress report remain applicable during the period of extended 

operation because the flux experienced by the jet pump slip joint repair clamps will remain 

below the threshold value to cause stress relaxation. 

The staff reviewed the applicant’s response and finds it acceptable because (1) the neutron 

fluence experienced by the jet pump slip joint repair clamps (3.07x1018 n/cm2) will remain below 

the threshold value (1x1019 n/cm2) necessary to cause stress relaxation, (2) the neutron flux 

analysis used to determine the neutron fluence in the relaxation evaluation is a staff-approved 
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methodology, (3) the applicant provided physical and functional descriptions of the jet pump slip 

joint repair clamps, and (4) the jet pump slip joint repair clamps will not experience a loss of 

preload during the period of extended operation and will maintain their intended function. The 

staff’s concerns described in RAI 4.7.4-1 are resolved. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis for the jet pump slip joint repair clamps has been projected to the end of the period of 

extended operation and remains valid. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.7.2.1 because the fluence analysis has been projected to the end of the period of 

extended operation and has been shown to have no impact on the original stress relaxation 

evaluation for the jet pump slip joint repair clamps. 

4.7.4.3 UFSAR Supplement 

LRA Section A.2.5.4 provides the UFSAR supplement summarizing the evaluation of the loss of 

preload due to neutron irradiation for the jet pump slip joint repair clamps. The staff reviewed 

LRA Section A.2.5.4 consistent with the review procedures in SRP-LR Section 4.7.3.2, which 

state that the staff verifies that the applicant has provided information in the UFSAR supplement 

that includes a summary description of the TLAA. The SRP-LR also states that the TLAA 

should contain information on how it has been dispositioned for the period of extended 

operation. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address loss of preload for 

the jet pump slip joint repair clamps, as required by 10 CFR 54.21(d). 

4.7.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the stress relaxation analysis for the jet 

pump slip joint repair clamps has been projected to the end of the period of extended operation. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7.5 Flaw Evaluations for the Reactor Pressure Vessel 

4.7.5.1 Summary of Technical Information in the Application 

LRA Section 4.7.5 describes the applicant’s TLAA for a fracture mechanics evaluation 

performed to determine the acceptability of the RPV flaw indications. The LRA states that 

“during refueling outage 9 (RF9) in 2003, new ASME Code Section XI, Appendix VIII, qualified 

ultrasonic examination procedures were used for the first time on [RPV] welds.” These new 

techniques greatly improved flaw detection and sizing capabilities and detected several flaws 

that had not been detectable previously. The LRA also states that a re-examination in refueling 

outage 12 in 2009 using phased-array technique identified flaws at two additional RPV 

locations. A fracture mechanics analysis evaluated the bounding flaw location to determine the 

acceptability of the RPV flaw indications for consideration of the P-T analysis. The LRA further 

states that “the analysis determined the indications are acceptable for 52 EFPY with 

consideration of the effects of MUR/TPO.” 
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The applicant dispositioned the TLAA for the RPV flaws in accordance with 

10 CFR 54.21(c)(1)(ii) to demonstrate that the analysis has been projected to the end of the 

period of extended operation. 

4.7.5.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the RPV flaw indications and the corresponding 

disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in SRP-LR 

Section 4.7.3.1.2, which state that the results of the analysis should be reviewed to verify that 

they are valid for the period of extended operation. The SRP-LR also states that the applicant 

may calculate the analysis using the 60-year period to demonstrate that the acceptance criteria 

continue to be satisfied for the period of extended operation. In addition, the SRP-LR states 

that the applicant should provide a sufficient description of the analysis and document the 

results of the reanalysis to demonstrate that it is satisfactory for the 60-year period. 

In its review, the staff noted the following related to the applicant’s flaw analysis for the CLB. 

The applicant’s evaluation of the reactor vessel flaws for the current license period (32 EFPY) is 

described in GE Report NEDO-33133, Revision 0, “Pressure-Temperature Curves for DTE 

Energy Fermi Unit 2,” dated February 2005 (ADAMS Accession No. ML050870587); and in GE 

Report NEDO-33785, Revision 0, “DTE Energy/Enrico Fermi Power Plant 2 Pressure and 

Temperature Limits Report Up to 24 and 32 Effective Full-Power Years,” dated October 2012 

(ADAMS Accession No. ML13004A135). The evaluation used the bounding flaw (flaw No. 124) 

which is 2 inches in length and 4.24 inches in depth and is at a 374.6-inch elevation above the 

vessel 0 foot elevation. Based on the evaluation of the bounding flaw (flaw No. 124), the 

applicant’s evaluation concludes that the projected fatigue growth of the flaws for the current 

license period is minimal (0.04 inch) and the detected flaws are acceptable for the current 

license period. 

The staff also noted that the applicant performed an analysis of the flaws for the period of 

extended operation. During its audit, the staff reviewed the applicant’s analysis and confirmed 

that the bounding flaw (flaw No. 124) for the current license period still remains the bounding 

flaw for the period of extended operation. The staff further noted that the applicant’s analysis 

concludes that the projected flaw growth during the period of extended operation is very minimal 

(0.02 inch) and the detected flaws are also acceptable through the period of extended 

operation. In addition, the staff confirmed that the applicant’s TLAA adequately accounts for the 

design requirements for the RPV. Specifically, the staff noted that the applicant’s analysis of the 

bounding flaw ensures that the bounding flaw meets the requirements of the design 

specification and the ASME Code for the RPV through the period of extended operation. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis for the RPV has been projected to the end of the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the applicant 

projected the fracture mechanics analysis of the RPV flaws to the end of the period of extended 

operation. 

4.7.5.3 UFSAR Supplement 

LRA Section A.2.5.5 provides the UFSAR supplement summarizing the TLAA for the fracture 

mechanics evaluation of the RPV flaws. The staff reviewed LRA Section A.2.5.5 consistent with 

the review procedures in SRP-LR Section 4.7.3.2, which state that the following is to be 

confirmed: (a) the applicant has provided information to be included in the UFSAR supplement 
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that includes a summary description of the evaluation of each TLAA, and (b) each such 

summary description is appropriate such that later changes can be controlled by 10 CFR 50.59. 

The SRP-LR also states that the description should contain information that the TLAA has been 

dispositioned for the period of extended operation. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the fracture 

mechanics evaluation of the RPV flaws, as required by 10 CFR 54.21(d). 

4.7.5.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the fracture mechanics analysis for the 

RPV flaws has been projected to the end of the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7.6 Main Steam Bypass Lines Cumulative Operating Time 

4.7.6.1 Summary of Technical Information in the Application 

LRA Section 4.7.6 describes the applicant’s TLAA for the main steam bypass lines cumulative 

operating time. The LRA states that in accordance with Detroit Edison’s letter to NRC, dated 

November 7, 1986 (ADAMS Legacy Library Accession No. 8611170335), the cumulative time 

that the main steam bypass lines are operated with the bypass valves configured in the 

30-percent to 45-percent open position will be reported to the NRC annually. The LRA also 

states that the cumulative value of 100 days of operation shall not be exceeded without prior 

notification to the NRC. 

The LRA states that an evaluation of a postulated flaw was performed that concluded that the 

main steam bypass lines are acceptable for continued service provided that the lines are 

operated within the constraints (100 days of total operation with bypass valves in the 30-percent 

to 45-percent open position). The LRA states that based on this evaluation, the main steam 

bypass lines have a service life that will allow them to operate for the life of the plant, including 

the period of extended operation. The LRA further states that tracking of the cumulative 

operating time of the main steam bypass lines will be as shown in LRA Table 4.3-1, and it will 

be continued for the period of extended operation. LRA Table 4.3-1 provides a projection of the 

number of days (i.e., 98 days) the main bypass lines will be operated with the bypass valves in 

the 30-percent to 45-percent open position through 60 years of operation. The applicant stated 

that it will monitor this usage to “ensure this limit is maintained or that it is reanalyzed or that 

inspections are performed as required.” 

The applicant dispositioned the TLAA for the main steam bypass line in accordance with 

10 CFR 54.21(c)(1)(iii), to demonstrate that the effects of the cumulative operating time on the 

intended functions will be adequately managed by the Fatigue Monitoring Program for the 

period of extended operation. 
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4.7.6.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the main steam bypass lines and the corresponding 

disposition of 10 CFR 54.21(c)(1)(iii), consistent with the review procedures in SRP-LR 

Section 4.7.3.1.3, which state that the applicant can propose to manage the aging effects 

associated with the TLAA by an AMP as described in the IPA in 10 CFR 54.21(a)(3). The 

SRP-LR also states that the reviewer verifies that the effects of aging on the intended 

function(s) are adequately managed consistent with the applicant’s CLB for the period of 

extended operation. 

The staff also reviewed the applicant’s evaluation dated October 16, 1986, “Service Life of Main 

Steam Bypass Line” (ADAMS Legacy Library Accession No. 8610220177). The staff verified 

that the limiting input value from the applicant’s original evaluation is 100 days, as identified in 

LRA Table 4.3-1. The staff noted that the projected operating time through the end of the period 

of extended operation, 98 days, is bounded by the analyzed limit of 100 days. The staff noted 

that the applicant has credited its enhanced Fatigue Monitoring Program to track the cumulative 

operating time of the main steam bypass line during the period of extended operation. The 

staff’s evaluation of the applicant’s Fatigue Monitoring Program is documented in SER 

Section 3.0.3.2.8. 

The staff finds that the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of cumulative operating time on the intended functions of the main steam bypass lines 

will be adequately managed for the period of extended operation. Additionally, the applicant's 

demonstration meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the Fatigue 

Monitoring Program will monitor the cumulative operating time of the main steam bypass lines to 

ensure that, if the established limit is approached, corrective action is taken prior to exceeding 

the limit. 

4.7.6.3 UFSAR Supplement 

LRA Section A.2.5.6 provides the UFSAR supplement summarizing the main steam bypass line 

cumulative operating time TLAA. The staff reviewed LRA Section A.2.5.2 consistent with the 

review procedures in SRP-LR Section 4.7.3.2, which state that the reviewer verifies that the 

applicant has provided an adequate summary description in its UFSAR supplement of the 

evaluation of its TLAAs for the period of extended operation. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant has provided an adequate summary description of its actions to address the main 

steam bypass lines TLAA, as required by 10 CFR 54.21(d). 

4.7.6.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of cumulative operating time 

on the main steam bypass lines will be adequately managed by the Fatigue Monitoring Program 

for the period of extended operation. The staff also concludes that the UFSAR supplement 

contains an appropriate summary description of the main steam bypass line TLAA evaluation, 

as required by 10 CFR 54.21(d). 
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4.7.7 Crane (Heavy Load) Cycles 

4.7.7.1 Summary of Technical Information in the Application 

LRA Section 4.7.7 describes the applicant’s TLAA related to the crane (heavy load) cycles for 

the reactor building crane. The LRA states that the reactor building crane meets the structural 

guidelines of Crane Manufacturers Association of America Specification No. 70 (CMAA-70), 

which provides allowable stress ranges based on joint category and service class. The LRA 

states that the lowest range of cycles for CMAA-70 Class A cranes is 20,000 to 100,000 cycles. 

Because of the cycles associated with such classification, the LRA states the analysis related to 

the CMAA-70 lift cycle limit is considered to be a TLAA. The LRA states that the reactor 

building crane has a capacity of 125 tons and it is used infrequently for refueling operations, 

service and maintenance of the reactor, equipment moved through the equipment access lock, 

and will be used during decommissioning. The LRA also states that the total number of crane 

lifts of over 20,000 lb (10 tons), are projected to be 2,868, which they have increased by 

applying a 25 percent margin to arrive at a projected number of 3,585 crane lifts. The LRA 

further states that lifts during construction and decommissioning are considered by doubling the 

3,585 lifts. Accordingly, the estimated total number of lifts for the reactor building overhead 

crane would be 7,170, which is below the 100,000 cycles established in CMAA-70 for Class A 

service cranes. 

The applicant dispositioned the TLAA for the reactor building crane in accordance with 

10 CFR 54.21(c)(1)(i) to demonstrate that the analysis remains valid for the period of extended 

operation. 

4.7.7.2 Staff Evaluation 

The staff reviewed the applicant’s TLAA for the reactor building crane and the corresponding 

disposition of 10 CFR 54.21(c)(1)(i), consistent with the review procedures in SRP-LR 

Section 4.7.3.1.1, which state that the existing analyses should be shown to be bounding even 

during the period of extended operation. The SRP-LR also states that the applicant should 

describe the TLAA with respect to the objectives of the analysis, assumptions used in the 

analysis, conditions, acceptance criteria, relevant aging effects, and intended functions. The 

applicant should show that conditions and assumptions used in the analysis already address the 

relevant aging effects for the period of extended operation, and that acceptance criteria are 

maintained to provide reasonable assurance that the intended functions are maintained for 

renewal, concluding that no reanalysis is necessary for renewal. 

The staff reviewed UFSAR Section 9.1, “Fuel Storage and Handling,” of the UFSAR and 

confirmed that the crane is used in a multifunctional role for refueling, and dry fuel cask loading 

and movements, as described in the LRA. In its review of the UFSAR, the staff confirmed that 

the lifting capacity of the crane in its current state and configuration is designed to accept loads 

of not more than 125 tons. The staff also confirmed the crane is designed in accordance with 

the requirements of the Electric Overhead Crane Institute No. 61 (EOCI-61), “Specifications for 

Electric Traveling Cranes,” Class A service and that it meets the structural guidelines of 

CMAA-70, which is recognized as the design code of record. The staff noted that the reactor 

building crane meets the provisions and guidelines of NUREG-0612, “Control of Heavy Loads at 

Nuclear Power Plants,” dated July 1980 (ADAMS Accession No. ML070250180). The staff also 

noted that NUREG-0612 Section 4.0, “Historical Records of Crane Operations,” indicates that 

the average number of lifts per crane is 500 or less per year. 
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The staff reviewed EOCI-61 and CMAA-70 Class A specifications and confirmed that the 

crane’s classification as stated in the LRA and the UFSAR is for standby service cranes used 

very infrequently, for loads in powerhouses, utilities, turbine rooms, and where precise handling 

at slow speeds is needed. In its review of the CMAA-70, Class A specifications, the staff also 

confirmed that in the definition of loading conditions and stress category classifications, fatigue 

becomes a concern when cranes have 20,000 to 100,000 lift cycles. 

The applicant identified in the LRA that this crane will have experienced a total of 7,170 lifts 

during construction, operation to the end of the period of operation, and decommissioning. 

Based on this projected number of cycles, the staff concludes that the analysis remains valid 

during the period of extended operation. 

The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(i), that the 

analysis for the reactor building crane remains valid for the period of extended operation. 

Additionally, it meets the acceptance criteria in SRP-LR Section 4.7.2.1 because the applicant 

has demonstrated that the projected load cycles over 60 years of operation will not exceed the 

CMAA-70 allowable load cycles for Class A service cranes. 

4.7.7.3 UFSAR Supplement 

LRA Section A.2.5.7 provides the UFSAR supplement summarizing the analysis associated with 

the reactor building crane (heavy load) cycle. The staff reviewed LRA Section A.2.5.7 

consistent with the review procedures in SRP-LR Section 4.7.3.2, which state that that the 

applicant has to provide information to be included in the UFSAR supplement that includes a 

summary description of the evaluation of each TLAA. The SRP-LR also states that each 

summary description is reviewed to verify that it is appropriate, such that later changes can be 

controlled by 10 CFR 50.59 and that the description should contain information that the TLAAs 

have been dispositioned for the period of extended operation. 

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.2.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the analysis of 

the reactor building crane (heavy load) cycles, as required by 10 CFR 54.21(d). 

4.7.7.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analysis for the reactor building crane 

(heavy load) cycles remains valid for the period of extended operation. The staff also concludes 

that the UFSAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d). 

4.8 Conclusion for TLAAs 

The staff reviewed the information in LRA Section 4, “Time-Limited Aging Analyses.” On the 

basis of its review, the staff concludes that the applicant has provided a sufficient list of TLAAs, 

as defined in 10 CFR 54.3, and that the applicant has demonstrated that each of the TLAAS will 

meet one of the following requirements in 10 CFR 54.21(c)(1): 

 The TLAAs will remain valid for the period of extended operation, as required by 

10 CFR 54.21(c)(1)(i). 
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 The TLAAs have been projected to the end of the period of extended operation, as 

required by 10 CFR 54.21(c)(1)(ii). 

 The effects of aging on intended functions will be adequately managed for the period of 

extended operation, as required by 10 CFR 54.21(c)(1)(iii). 

The staff also reviewed the UFSAR supplement for the TLAAs and finds that the supplement 

contains descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In 

addition, the staff concludes, as required by 10 CFR 54.21(c)(2), that no plant-specific, 

TLAA-based exemptions are in effect. 

The staff concludes that there is reasonable assurance that the applicant will continue to 

conduct the activities authorized by the renewed licenses in accordance with the CLB and any 

changes to the CLB made in order to comply with 10 CFR 54.21(a)(1), in accordance with the 

Atomic Energy Act of 1954, as amended, and in accordance with NRC regulations. 

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REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS 

In accordance with Title 10 of the Code of Federal Regulations Part 54, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants,” the Advisory Committee on Reactor 

Safeguards (ACRS) will review the license renewal application (LRA) for Fermi 2. The 

U.S. Nuclear Regulatory Commission (NRC) staff (the staff) presented its safety evaluation 

report (SER) with open items to the ACRS Subcommittee on Plant License Renewal in a public 

meeting on March 2, 2016. DTE Electric Company (DTE or the applicant) and the NRC staff will 

meet with the full committee on September 8, 2016, to discuss the closure of the open items 

and other issues associated with the review of the LRA. 

After the ACRS completes its review of the LRA and SER, the full committee will issue a report 

discussing the results of the review. An update to the SER will include the ACRS report and the 

staff’s response to any issues and concerns reported. 

 
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5-3 
5-4 
5-5 

6-1 

 

CONCLUSION 

The U.S. Nuclear Regulatory Commission (NRC) staff (the staff) reviewed the license renewal 

application (LRA) for Fermi 2 Nuclear Power Plant (Fermi 2) in accordance with NRC 

regulations and NUREG-1800, Revision 2, “Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants,” dated December 2010. Title 10 of the Code of 

Federal Regulations 54.29, “Standards for Issuance of a Renewal License” (10 CFR 54.29), 

sets the standards for issuance of a renewed license. 

On the basis of its review of the LRA, the staff determines that the requirements of 

10 CFR 54.29(a) have been met. 

The staff noted that any requirements of 10 CFR Part 51, “Environmental Protection 

Regulations for Domestic Licensing and Related Regulatory Functions,” Subpart A, “National 

Environmental Policy Act – Regulations Implementing Section 102(2),” will be documented in a 

final, plant-specific supplement to NUREG-1437, “Generic Environmental Impact Statement for 

License Renewal of Nuclear Plants (GEIS),” Supplement 56, “Generic Environmental Impact 

Statement for License Renewal of Nuclear Power Plants, Supplement 56, Regarding Fermi 2 

Nuclear Power Plant.” 

 

FERMI 2 LICENSE RENEWAL COMMITMENTS 

 

A-1 

A. Fermi 2 License Renewal Commitments 

During the review of the Fermi 2 Nuclear Power Plant (Fermi 2) license renewal application 

(LRA) by the staff of the U.S. Nuclear Regulatory Commission (NRC or the staff), DTE Electric 

Company (DTE or the applicant) made commitments related to aging management programs 

(AMPs) to manage aging effects for structures and components. The following table lists these 

commitments along with the implementation schedules and sources for each commitment. The 

period of extended operation starts on March 21, 2025, for Fermi 2. 
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Table A.1-1 Appendix A: Fermi 2 License Renewal Commitments 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

1 DTE will make the following changes to the process for operating 

experience review. 

a. Procedures will be revised to add an aging type code to 

corrective action program documents that describe either plant conditions related to aging or industry operating experience related to aging. 

b. Procedures will be revised to provide for training of personnel 

responsible for submitting, screening, assigning, evaluating, or 

otherwise processing plant-specific and industry operating experience concerning age-related degradation and aging management, as well as for personnel responsible for implementing AMPs, based on the complexity of the job 

performance requirements and assigned responsibilities. 

c. Procedures will be revised to specify that evaluations of 

operating experience concerning age-related degradation will include consideration of the affected systems, structures or components, the environments, materials, aging effects, aging mechanisms, and aging management programs. 

A.1 Completed LRA 

DTE letter NRC-15-0009 dated 1/15/15 DTE letter NRC-16-0045 dated 7/6/16 

2 DTE currently performs periodic self-assessments on many aging 

management programs. DTE will enhance the Fermi 2 self-assessment process to provide for periodic evaluation of the effectiveness of each aging management program described in the updated final safety analysis report (UFSAR) supplement. For new aging management programs, the first evaluation will be performed within 5 years of implementing the program. 

A.1 Within 5 years of 

implementing the program for new programs. 

LRA 

3 Implement the new Aboveground Metallic Tanks Program that will 

manage loss of material and cracking for outdoor tanks within the scope of license renewal that are sited on soil or concrete. Condensate storage tank (CST) internal inspections will be conducted in accordance with Table 4a of LR-ISG-2012-02; internal inspections of the combustion turbine generator (CTG) fuel oil tank will be conducted in accordance with NUREG-1801, XI.M30. This program will also manage the bottom surfaces of both in-scope aboveground metallic tanks. Within the 10 years prior to the period of extended operation 

and every 10 years thereafter, a volumetric examination of a minimum 

25 percent of the CST tank bottom interface with the concrete ring foundation will be performed to manage loss of material. The 

A.1.1 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. Initial inspections will be performed within the 10 years prior to March 20, 2025. 

LRA DTE letter NRC-15-0005 dated 1/20/15 DTE letter NRC-15-0031 dated 4/10/15 
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Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

volumetric inspection will be on a 2 inch grid or less, depending on the technology utilized. 

4 Enhance the Bolting Integrity Program as follows: 

a. Revise Bolting Integrity Program procedures to ensure 

consideration of actual yield strength when procuring bolting material. If procured, closure bolting with actual yield strength greater than or equal to 150 ksi is monitored for cracking. 

b. Revise Bolting Integrity Program procedures to state that 

bolting for safety-related pressure-retaining components is inspected for leakage, loss of material, cracking, and loss of preload/loss of prestress. Closure bolting with actual yield strength greater than or equal to 150 ksi is monitored for cracking. 

c. Revise Bolting Integrity Program procedures to: 

(1) implement applicable recommendations for pressure 

boundary bolting in NUREG-1339, Electric Power Research Institute (EPRI) NP-5769, and EPRI TR-104213; 

(2) state both American Society of Mechanical Engineers 

(ASME) Code class bolted connections and non-ASME Code class bolted connections are inspected at least once per refueling cycle; and 

(3) include volumetric examination per ASME Code 

Section XI, Table IWB-2500-1, Examination Category B-G-1, for closure bolting with actual yield strength greater than or equal to 150 ksi regardless of code classification. 

d. Revise Bolting Integrity Program procedures to inspect 

residual heat removal service water (RHRSW), emergency equipment service water (EESW), and emergency diesel generator service water (EDGSW) systems’ pump and valve bolting submerged in the RHRSW reservoir at least once every refueling outage and to opportunistically inspect bolting threads during maintenance activities. 

e. Revise Bolting Integrity Program procedures to include the 

additional guidance and recommendations of EPRI NP-5769 for replacement of ASME pressure-retaining bolts and the guidance provided in EPRI TR-104213 for the replacement of other pressure-retaining bolts. 

A.1.2 Prior to 

September 20, 2024. 

LRA DTE letter NRC-15-0006 dated 1/20/15 DTE letter NRC-15-0011 dated 2/12/15 
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Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

f. Revise Bolting Integrity Program procedures to stipulate that 

administrative controls are in accordance with the Fermi 2 10 CFR Part 50 Appendix B Quality Assurance Program. 

g. Revise Bolting Integrity Program procedures to perform 

opportunistic inspections for Control Center HVAC system safety-related pressure-retaining bolting in a lube oil external environment, including the bolting threads to ensure that loss of material in crevice locations that are not readily visible can be detected. 

h. Revise Bolting Integrity Program procedures to perform 

opportunistic inspections for CTG system nonsafety-related pressure-retaining bolting in a lube oil external environment. 

5 Implement the Boraflex rack replacement approved in Amendment 

No. 141 so that the current Boraflex panels in the spent fuel pool will not be required to perform a neutron absorption function during the period of extended operation. 

A.1.3 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later.

LRA DTE letter NRC-15-0081 dated 9/24/15 

6 Implement new Buried and Underground Piping Program that will 

manage the effects of aging on the external surfaces of buried and underground piping within the scope of license renewal. Soil testing will be conducted once in each 10-year period starting 10 years prior to the period of extended operation, if a reduction in the number of inspections recommended in Table XI.M41-2of NUREG 1801 is taken based on a lack of soil corrosivity. 

A.1.4 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. Initial directed inspections and soil testing (if the reduction in inspections based on soil testing is taken) will be performed within the 10 years prior to March 20, 2025. 

LRA DTE letter NRC-15-0002 dated 1/15/15 DTE Letter NRC-16-0027 dated 4/12/16 

7 Enhance the BWR Vessel Internals Program as follows: 

a. The susceptibility to neutron or thermal embrittlement for 

reactor vessel internal components composed of cast austenitic stainless steel (CASS) and X-750 alloy will be evaluated. 

b. BWR Vessel Internals Program procedures will be revised as 

follows. Portions of the susceptible components determined to be limiting from the standpoint of thermal aging susceptibility, 

A.1.10 Perform initial inspection 

either prior to March 20, 2025, or before March 20, 2030. Submit analysis and inspection plan to the NRC prior to March 20, 2023. Remaining activities: 

LRA DTE letter NRC-15-0010 dated 2/5/15 DTE letter NRC-15-0044 dated 4/27/15 
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Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

neutron fluence, and cracking susceptibility (i.e., applied stress, operating temperature, and environmental conditions) will be inspected, using an inspection technique capable of detecting the critical flaw size with adequate margin. The critical flaw size will be determined based on the service loading condition and service-degraded material properties. The initial inspection will be performed either prior to or within 5 years after entering the period of extended operation. If cracking is detected after the initial inspection, the frequency of re-inspection will be justified based on fracture toughness properties appropriate for the condition of the component. The sample size for the initial inspection of susceptible components will be 100 percent of the accessible component population, excluding components that may be in compression during normal operations. 

c. BWR Vessel Internals Program procedures will be revised as 

follows. In accordance with an applicant action item for BWRVIP-25 safety evaluation: (a) install core plate wedges prior to the period of extended operation, or (b) complete a plant-specific analysis that justifies no inspections are required, or (c) complete a plant-specific analysis to determine acceptance criteria for continued inspection of core plate hold-down bolts in accordance with BWRVIP-25. For Option (b), the analysis will address loss of preload due to stress relaxation in the core plate rim hold-down bolts and quantify the loss of preload/stress relaxation that will occur in these bolts during the period of extended operation. The analysis will be submitted to the NRC 2 years prior to the period of extended operation. Additionally, the UFSAR will be revised to address the analysis if it is determined to meet the criteria for a time-limited aging analysis (TLAA) at least 2 years prior to the period of extended operation. For Option (c), the analysis will address loss of preload due to stress relaxation in the core plate rim hold-down bolts and quantify the loss of preload/stress relaxation that will occur in these bolts during the period of extended operation. The analysis, inspection plan with acceptance criteria, and justification for the inspection plan will be submitted to the NRC 2 years prior to the period of extended operation. Additionally, the UFSAR will be revised to address the 

Prior to September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

DTE letter NRC-15-0062 dated 6/9/15 DTE letter NRC-15-0083 dated 8/20/15 
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Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

analysis if it is determined to meet the criteria for a TLAA at least 2 years prior to the period of extended operation. 

d. Revise BWR Vessel Internals Program procedures such that 

the flaw evaluation methodology for the top guide grid beam will address the following three items if they have not been resolved generically during the NRC review and approval process of BWRVIP-183: (1) Detected flaws evaluated using the methodology in 

BWRVIP-183 Section 4 will be demonstrated to be sufficiently far from geometric discontinuities (i.e., notches or slots) such that the stress condition in the vicinity of the flaw is consistent with that for a single edgecrack plate. Appropriately applied K values which account for the effects of geometric discontinuities will be used and justified in the flaw evaluation. 

(2) The flaw evaluation methodology in BWRVIP-183 

Section 4 will be used to justify continued operation on a cycle-by-cycle basis. Use of the flaw evaluation methodology to justify operation for more than once cycle will require NRC approval and would be based on plant-specific operating experience including crack length measurements of detected top guide grid beam flaws to benchmark the accuracy of the flaw evaluation methodology. 

(3) When applying the flaw evaluation methodology in 

BWRVIP-183 Section 4, a severed beam evaluation consistent with BWRVIP-183 Section 5 will also be performed. The severed beam analysis will demonstrate that even if a beam was a completely severed beam, it would not be expected to interfere with the ability of the control rod drive system to insert control rods. 

e. Revise BWR Vessel Internals Program procedures to perform 

opportunistic inspections of the differential pressure and standby liquid control line inside the reactor vessel when the line becomes accessible. 

8 Enhance the Compressed Air Monitoring Program as follows: 

a. Revise Compressed Air Monitoring Program procedures to 

periodically sample, test, and monitor moisture and corrosive contaminants to verify parameters are within acceptable limits 

A.1.11 Prior to 

September 20, 2024. 

LRA 
A-7 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

in the emergency diesel generator (EDG) starting air system to mitigate aging effects such as loss of material due to corrosion. 

b. Revise Compressed Air Monitoring Program procedures to 

include periodic and opportunistic inspections of accessible internal surfaces of piping, compressors, dryers, aftercoolers, and filters. In addition, include in the Compressed Air Monitoring Program procedures the applicable provisions recommended in EPRI NP-7079, EPRI TR- 108147, and ASME OM-S/G-1998, Part 17 for air system contaminants, inspection frequency, inspection methods, and acceptance criteria for components subject to aging management review that are exposed to compressed air and components in the EDG starting air system and control air system. 

9 Enhance the Containment Inservice Inspection (CII)-IWE Program as 

follows: 

a. Revise plant procedures to require inspection of the sand 

cushion drain lines to monitor the internal conditions of the drain lines (e.g., for moisture, sand, blockage) and ensure there is no evidence of blockage at least once prior to the period of extended operation and once every 10 years during the period of extended operation. 

b. Revise plant procedures to specify the preventive actions 

delineated in NUREG-1339 and in EPRI NP-5769, NP-5067, and TR-104213 that emphasize proper selection of bolting material, installation torque or tension, and the use of lubricants and sealants for high strength bolting. 

c. Revise plant procedures to include the preventive actions for 

storage of American Society for Testing and Materials (ASTM) A325 and A490 bolting from Section 2 of Research Council for Structural Connections publication, "Specification for Structural 

Joints Using ASTM A325 or A490 Bolts." 

d. [Deleted] e. [Deleted] f. Revise plant procedures to determine drywell shell thickness 

in the sand cushion areas before the period of extended operation and once in each 10-year interval during the period of extended operation. From the results (including prior results), develop a corrosion rate to demonstrate that the 

A.1.12 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

LRA DTE letter NRC-15-0004 dated 1/15/15 
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Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

drywell shell will have sufficient wall thickness to perform its intended function through the period of extended operation. 

g. Revise plant procedures to require corrective actions should 

moisture be detected or suspected in the inaccessible area on the exterior of the drywell shell, including:  Identify surfaces requiring augmented inspections for the 

period of extended operation in accordance with Subsection IWE-1240, as identified in Table IWE- 2500-1, Examination Category E-C. 

 Use examination methods that are in accordance with 

Subsection IWE-2500. 

 Demonstrate through use of augmented inspections 

performed in accordance with Subsection IWE that corrosion is not occurring or that corrosion is progressing so slowly that the degradation will not jeopardize the intended function of the drywell shell through the period of extended operation. 

10 Enhance Diesel Fuel Monitoring Program as follows: 

a. Revise Diesel Fuel Monitoring Program procedures to monitor 

and trend water and sediment, particulates, and levels of microbiological organisms in the EDG fuel oil storage tanks, EDG fuel oil day tanks, diesel fire pump fuel oil tank, and CTG fuel oil tank quarterly. In addition, revise program procedures to state that biocides or corrosion inhibitors may be added as a preventive measure or are added if periodic testing indicates biological activity or evidence of corrosion, respectively. 

b. Revise the Diesel Fuel Monitoring Program procedures to 

include a 10-year periodic cleaning and internal visual inspection of the EDG fuel oil storage tanks, EDG fuel oil day tanks, diesel fire pump fuel oil tank, and CTG fuel oil tank with the following instructions. The cleanings and internal inspections will be performed at least once during the 10-year period prior to the period of extended operation and at succeeding 10- year intervals. If visual inspection is not possible, perform a volumetric inspection. If evidence of 

degradation is observed during visual inspection, perform a volumetric examination of the affected area. The schedule for the Preventive Maintenance (PM) event to perform diesel fire pump fuel oil tank draining, flushing, and inspection will continue at its frequency at the time of the 

A.1.14 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

LRA DTE letter NRC-15-0056 dated 5/19/15 
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Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

enhancement implementation, until a PM evaluation of results from fuel oil samples and tank inspections indicates that the system will be capable of continuing to perform its function during the period of extended operation with a lower frequency, not less than once per 10-year interval for cleaning and internal visual inspection consistent with NUREG-1801. 

11 Enhance External Surfaces Monitoring Program as follows: 

a. Revise External Surfaces Monitoring Program procedures to 

clarify that periodic inspections will be performed of systems in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4 (a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include structures, systems, and components (SSCs) that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2). 

b. Revise External Surfaces Monitoring Program procedures to 

inspect 100 percent of accessible components at least once per refueling cycle and to ensure required walk downs include instructions to inspect for the following related to metallic components:  Corrosion (loss of material).  Leakage from or onto external surfaces (loss of material).  Worn, flaking, or oxide-coated surfaces (loss of material).  Corrosion stains on thermal insulation (loss of material).  Protective coating degradation (cracking, flaking, and 

blistering). 

 Leakage for detection of cracks on the external surfaces 

of stainless steel components exposed to an air environment containing halides (cracking). 

c. Revise External Surfaces Monitoring Program procedures to 

include instructions for monitoring aging effects for flexible polymeric components through physical manipulations of the material, with a sample size for manipulation of at least 10 percent of the available surface area. Inspect accessible surfaces for the following:  Surface cracking, crazing, scuffing, dimensional changes 

(e.g., ballooning and necking). 

A.1.16 Prior to 

September 20, 2024. 

LRA DTE letter NRC-14-0051 dated 7/30/14 DTE letter NRC-15-0007 dated 1/28/15 DTE letter NRC-15-0032 dated 4/17/15 DTE letter NRC-15-0067 dated 6/18/15 
A-10 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

 Discoloration.  Exposure of internal reinforcement for reinforced 

elastomers. 

 Hardening as evidence by loss of suppleness during 

manipulation where the component and material are appropriate to manipulation. 

 Shrinkage, loss of strength. 

d. Revise External Surfaces Monitoring Program procedures to 

specify the following for insulated components:  Periodic representative inspections will be conducted 

during each 10-year period. 

 For a representative sample of insulated indoor 

components exposed to condensation (because the component is operated below the dew point) and insulated outdoor components, insulation will be removed for visual inspection of the component surface. Inspections include a minimum of 20 percent of the in-scope piping length for each material type (e.g., steel, stainless steel, copper alloy, aluminum), or for components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent of the surface area. Alternatively, insulation will be removed and a minimum of 25 inspections performed that can be a combination of 1-foot axial length sections and individual components for each material type. 

 Inspection locations are based on the likelihood of 

corrosion under insulation (CUI). For example, CUI is more likely for components experiencing alternate wetting and drying in environments where trace contaminants could be present and for components that operate for long periods of time below the dew point. Subsequent inspections will consist of an examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation, if the following conditions are verified in the initial inspection: 

o No loss of material due to general, pitting or crevice 

corrosion, beyond that which could have been present during initial construction, and 
A-11 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

o No evidence of cracking. If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g., water seepage through insulation seams/joints), periodic inspections under the insulation will continue as described above. 

 Removal of tightly adhering insulation that is impermeable 

to moisture is not required unless there is evidence of damage to the moisture barrier. If the moisture barrier is intact, the likelihood of CUI is low for tightly adhering insulation. Tightly adhering insulation is considered to be a separate population from the remainder of insulation installed on in-scope components. The entire population of in-scope accessible piping component surfaces that have tightly adhering insulation will be visually inspected for damage to the moisture barrier with the same frequency as for other types of insulation inspections. These inspections will not be credited towards the inspection quantities for other types of insulation. 

e. Revise External Surfaces Monitoring Program procedures to 

include acceptance criteria for the parameters observed.  Metals should not have any indications of relevant 

degradation. 

 Flexible polymers should have a uniform surface texture 

and color with no cracks and no dimension change, no abnormal surface conditions with respect to hardness, flexibility, physical dimensions, and color. 

 Rigid polymers should have no erosion, cracking, crazing 

or chalking. 

 For insulation, no discoloration, staining, or surface 

irregularities from moisture intrusion. 

f. Revise External Surfaces Monitoring Program procedures to 

stipulate that administrative controls are in accordance with the Fermi 2 10 CFR Part 50 Appendix B Quality Assurance Program. 

g. Revise External Surfaces Monitoring Program procedures to 

include instructions for detection of cracking of gas-filled stainless steel and aluminum components exposed to outdoor air. 
A-12 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

h. Revise External Surfaces Monitoring Program procedures to: 

(a) Visually inspect jacketed and nonjacketed insulation 

required to reduce heat transfer at a frequency consistent with NUREG-1801 Section XI.M36, as modified by LR-ISG-2012-02, to ensure that insulation degradation due to moisture intrusion has not occurred. 

(b) Ensure procedures include instructions to inspect for 

signs of water intrusion. Inspect accessible surfaces for the following signs of water intrusion: discoloration, staining, or surface irregularities. 

12 Enhance the Fatigue Monitoring Program as follows: 

a. Revise Fatigue Monitoring Program procedures to monitor and 

track critical thermal and pressure transients for components that have been identified to have a fatigue TLAA. 

b. Develop environmentally assisted fatigue (EAF) usage 

calculations that consider the effects of the reactor water environment for a set of sample reactor coolant system components. This sample set will include the locations identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they are found to be more limiting than those considered in NUREG/CR- 6260. Environmental correction factors will be determined using formulae consistent with those recommended in NUREG-1801, X.M1. 

c. Revise Fatigue Monitoring Program procedures to provide 

updates of the fatigue usage calculations on an as-needed 

basis if an allowable cycle limit is approached, or in a case where a transient definition has been changed, unanticipated new thermal events are discovered, or the geometry of 

components has been modified. For components with assumed minimal cycle counts, ensure that exemption assumptions are not exceeded. 

d. After the EAF calculations are completed, revise the Fatigue 

Monitoring Program procedures to state that the program 

counting of the cycle limits maintains the cumulative fatigue usage below the design limit through the period of extended operation, with consideration of the reactor water environmental fatigue effects. Revise Fatigue Monitoring Program procedures to allow for use of cycle-based fatigue 

A.1.17 Part (b): At least 2 years 

prior to March 20, 2025. Remainder: Prior to September 20, 2024. 

LRA DTE letter NRC-15-0005 dated 1/20/15 DTE letter NRC-15-0011 dated 2/12/15 
A-13 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

(CBF) or stress-based fatigue (SBF) monitoring methods (including environmental effects) if a component’s cumulative usage factor (CUF) value is projected to exceed 1.0 after EAF calculations are completed. 

e. Revise Fatigue Monitoring Program procedures so that the 

scope of the program includes monitoring the operating hours for the main steam bypass operation at the 30%-45% valve open position and perform trending to ensure that the operating time for the main steam bypass operation remains below the design limit during the period of extended operation.

f. Revise Fatigue Monitoring Program procedures to provide for 

corrective actions to prevent the operating time for the main steam bypass from exceeding the analysis during the period of extended operation. Acceptable corrective actions include repair of the component, replacement of the component, or a more rigorous analysis of the component to demonstrate that the service life will not be exceeded during the period of extended operation. 

13 Enhance the Fire Protection Program as follows: 

a. Revise Fire Protection Program procedures to perform visual 

inspections to manage loss of material of the Halon and CO2 fire suppression system. 

b. Revise Fire Protection Program procedures to require visual 

inspections of in-scope:  Fire wrap and fire stop materials for loss of material, 

change in material properties, cracking/delamination, separation, increased hardness, shrinkage, and loss of strength. 

 Carbon steel penetration sleeves for loss of material.  Steel framing, roof decking, and floor decking for loss of 

material. 

 Concrete fire barriers including manways, manhole 

covers, handholes, and roof slabs for loss of material and cracking. 

 Railroad bay airlock doors for loss of material. 

Inspections are performed at a frequency in accordance with the NRC-approved fire protection program or at least once every 

refueling cycle. 

A.1.18 Prior to 

September 20, 2024. 

LRA DTE letter NRC-15-0009 dated 1/15/15 
A-14 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

14 Enhance the Fire Water System Program as follows: 

a. Revise Fire Water System Program procedures to ensure 

sprinkler heads are tested or replaced in accordance with National Fire Protection Association (NFPA) 25 (2001 Edition), Section 5.3.1. 

b. Revise Fire Water System Program procedures to perform an 

inspection of wet fire water system piping condition at least once every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting the interior for evidence of loss of material and the presence of foreign organic or inorganic material that could result in flow obstructions or blockage of a sprinkler head. Where multiple wet-pipe systems are in a building, every other system shall be inspected in a 5-year period. Then, in the next 5-year period, the remaining systems in that building shall be inspected. (Refer to NFPA 25 (2011 Edition), Sections 14.2.1 and 14.2.2.) The inspection method used shall be capable of detecting surface irregularities that could indicate wall loss due to corrosion, corrosion product deposition, and flow blockage due to fouling. Ensure procedures require a followup volumetric wall thickness evaluation where irregularities are detected. 

c. Revise Fire Water System Program procedures to: 

(a) ensure sprinkler heads are tested or replaced in 

accordance with NFPA 25 (2011 Edition) Section 5.3.1 and 

(b) the fire protection engineer approves the sprinkler testing 

laboratory. 

d. Revise Fire Water System Program procedures to: 

(a) specify that in accordance with NFPA 13.2.5.2 when there 

is a 10 percent reduction in full flow pressure when compared to the original acceptance test or previously performed tests, the cause of the reduction shall be identified and corrected as necessary; and 

(b) note the time to return to static pressure after performing 

a main drain test. 

A.1.19 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later, with the exception that the activities described in this commitment for piping segments designed to be dry but determined to be collecting water shall be conducted within 5 years prior to March 20, 2025. 

LRA DTE letter NRC-14-0051 dated 7/30/14 DTE letter NRC-15-0002 dated 1/15/15 DTE letter NRC-15-0031 dated 4/10/15 
A-15 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

e. Revise Fire Water System Program procedures to notify the 

fire protection engineer of test results and deficiencies identified or detected during testing. 

f. Revise Fire Water System Program procedures to ensure 

piping is cleaned and sprinklers are replaced if obstructions are identified during internal inspections. Sprinklers loaded with dust may be cleaned using air rather than replaced. 

g. Revise Fire Water System Program procedures to perform an 

internal inspection of wet fire water system piping conditions at least once every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of the branch line for the purpose of inspecting the interior for evidence of loss of material and the presence of foreign organic and inorganic material that could result in flow obstructions or blockage of sprinkler heads. Where multiple wet-pipe systems are in a building, every other system shall be inspected in a 5-year period. Then, in the next 5-year period, the remaining systems in that building shall be inspected. 

h. [Deleted] i. Revise Fire Water System Program procedures to perform at 

least once every 5 years either an internal inspection of the dry components downstream of the deluge valves for the hydrogen seal oil unit by removing a sprinkler toward the end of one branch line and inspecting for evidence of loss of material and the presence of foreign organic and inorganic material that could result in flow obstructions or blockage of sprinklers, or Revise Fire Water System Program procedures to perform at least once every 5 years an air or smoke test to verify there is no flow obstruction or blockage of sprinklers. 

j. Revise Fire Water System Program procedures to perform an 

inspection of the water distribution piping associated with charcoal filters for loss of material and foreign organic or inorganic material when the charcoal beds are replaced. 

k. Revise Fire Water System Program procedures to perform an 

obstruction investigation whenever any of the criteria listed in NFPA Section 14.2.1.3 or 14.3.1 are met. 
A-16 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

l. Perform a fire water system walkdown of the piping and 

components that are designed to be dry (e.g., downstream of deluge valves or manual isolations of dry fire water piping), but are periodically wetted, to determine if any piping sections are collecting water and are subject to both of the following augmented inspections:  In each 5-year interval, beginning 5 years prior to the 

period of extended operation, either (a) conduct a flow test or flush sufficient to detect potential flow blockage, or (b) conduct a visual inspection of 100 percent of the internal surface of piping segments that cannot be drained or piping segments that allow water to collect. 

 In each 5-year interval of the period of extended 

operation, inspect 20 percent of the length of piping segments that cannot be drained or piping segments that 

allow water to collect using volumetric techniques to measure wall thickness. Measurement points will be obtained so that each potential degraded condition can be 

identified (e.g., general corrosion, microbiologically induced corrosion (MIC)). The 20 percent of piping that will be inspected in each 5-year interval will be in different locations than previously inspected piping. 

m. Revise Fire Water System Program procedures to include 

acceptance criteria that any indication of fouling is evaluated. 

n. Revise Fire Water System Program procedures to specify that 

if the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected during pipe inspections, the material is removed and the source and extent of condition determined, corrected, and the condition entered into the corrective action program. 

o. Revise Fire Water System Program procedures to replace 

sprinklers associated with representative tested sprinkler, if the representative test sprinkler fails to meet the test requirements. 

p. Revise Fire Water System Program procedures to replace any 

sprinkler that shows signs of corrosion. 

q. If the decreasing trend in fire water system flow tests is not 

resolved through the corrective action program prior to the period of extended operation, revise Fire Water System Program procedures to continue performing annual fire water 
A-17 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

system flow tests during the period of extended operation until such a time as trend data from fire water system flow tests indicates that the system will be capable of performing its intended function throughout the period of extended operation and, therefore, Technical Requirements Manual (TRM) frequency may be resumed. 

r. Revise Fire Water System Program procedures to include 

formal documentation of the Control Center Heating, Ventilation, and Air Conditioning (CCHVAC) makeup and recirculation fire water supply drain down inspection for indications of flow blockage. 

15 Enhance the Flow-Accelerated Corrosion Program as follows: 

a. Revise procedures to indicate that the Flow-Accelerated 

Corrosion Program also manages loss of material due to erosion mechanisms of cavitation, flashing, liquid droplet impingement, and solid particle erosion for any material in treated water or steam environments. Include in program procedures a susceptibility review based on internal operating experience, external operating experience, EPRI TR-1011231, and NUREG/CR-6031. Piping subject to erosive conditions is not excluded from inspections, even if it has been replaced with flow-accelerated corrosion-resistant material. Periodic wall thickness measurements of such piping should continue until the effectiveness of corrective actions is assured. 

b. Revise Flow-Accelerated Corrosion Program procedures to 

specify that downstream components are monitored closely for wall thinning when susceptible upstream components are replaced with resistant materials. 

A.1.20 Prior to 

September 20, 2024. 

LRA 

16 Enhance the Inservice Inspection (ISI)-IWF Program as follows: 

a. Revise plant procedures to specify the preventive actions 

delineated in NUREG-1339 and EPRI NP-5769, NP-5067, and TR-104213 that emphasize proper selection of bolting material, installation torque or tension, and the use of lubricants and sealants for high-strength bolting. 

b. Revise plant procedures to require structural bolting 

replacement and maintenance activities to include appropriate preload and proper tightening (torque or tension) as recommended in EPRI documents, ASTM standards, 

A.1.22 Prior to 

September 20, 2024. 

LRA DTE letter NRC-15-0032 dated 4/17/15 DTE letter NRC-15-0044 dated 4/27/15 
A-18 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

American Institute of Steel Construction (AISC) Specifications, as applicable. 

c. Revise plant procedures to include the preventive actions for 

storage of ASTM A325 and A490 bolting from Section 2 of Research Council for Structural Connections publication, "Specification for Structural Joints Using ASTM A325 or A490 Bolts." 

d. Revise plant procedures to specify that detection of aging 

effects will include monitoring anchor bolts for loss of material, loose or missing nuts or bolts, and cracking of concrete around the anchor bolts. 

e. Revise plant procedures to identify the following unacceptable 

conditions:  Debris, dirt, or excessive wear that could prevent or 

restrict sliding of the sliding surfaces as intended in the design basis of the support. 

 Cracked or sheared bolts, including high-strength bolts, 

and anchors. 

f. Revise plant procedures to include the preventive action of 

using bolting material that has an actual measured yield strength less than 150 ksi, except in the case of like-for-like replacement of existing bolting material in the reactor pressure vessel skirt to ring girder bolted joint. 

g. Revise plant procedures to include assessment of the impact 

on the inspection sample, in terms of sample size and representativeness, if components that are part of the sample population are re-worked. 

17 Enhance the Inspection of Overhead Heavy Load and Light Load 

(Related to Refueling) Handling Systems (OVHLL) Program as follows: 

a. Revise plant procedures to specify the monitoring of rails in 

the rail system for loss of material due to wear; monitor structural components of the bridge, trolley and hoists for deformation, cracking, and loss of material due to corrosion; and monitor structural connections/bolting for loose or missing bolts, nuts, pins, or rivets, and any other conditions indicative of loss of bolting integrity. 

A.1.23 Prior to 

September 20, 2024. 

LRA 
A-19 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

b. Revise plant procedures to specify inspection frequency 

requirements will be in accordance with ASME B30.2 or other appropriate standard in the ASME B30 series. 

c. Revise plant procedures to require that significant loss of 

material due to wear of rails in the rail system and any sign of loss of bolting integrity will be evaluated in accordance with ASME B30.2 or other appropriate standard in the ASME B30 series. 

d. Revise plant procedures to specify that maintenance and 

repair activities will use the guidance provided in ASME B30.2 or other appropriate standard in the ASME B30 series. 

18 Implement the new Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program to manage fouling, cracking, loss of material, and change in material properties using representative sampling and opportunistic visual inspections of the internal surfaces of piping and components in environments other than open-cycle cooling water, closed treated water, and fire water. Program periodic surveillances or maintenance activities will be conducted when the surfaces are accessible for visual inspection. 

A.1.24 Prior to 

September 20, 2024. 

LRA 

19 Implement the new Metal Enclosed Bus Inspection Program to provide 

for the inspection of the internal and external portions of metal enclosed bus to identify age-related degradation of the bus and bus connections, the bus enclosure assemblies, the bus insulation and the bus insulators. 

A.1.26 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

LRA 

20 Enhance Neutron-Absorbing Material Monitoring Program as follows: 

a. Prior to the period of extended operation, revise 

Neutron-Absorbing Material Monitoring Program procedures to establish an inspection frequency, justified with plant-specific operating experience, of at least once every 10 years, based on the condition of the neutron-absorbing material. 

b. Revise Neutron-Absorbing Material Monitoring Program 

procedures to perform trending of coupon testing results to determine the rate of degradation. Ensure the predicted boron-10 areal density will be sufficient to maintain the subcritical conditions required by technical specifications until the next coupon test. 

A.1.27 Prior to 

September 20, 2024. 

LRA 

21 Implement the new Non-EQ Cable Connections Program, a one-time 

inspection program that consists of a representative sample of electrical 

A.1.28 Prior to 

September 20, 2024, or the 

LRA 
A-20 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

connections within the scope of license renewal, which is inspected or tested at least once prior to the period of extended operation to confirm that there are no aging effects requiring management during that period. Cable connections included in this program are those connections susceptible to age-related degradation resulting in increased resistance of connection due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, or oxidation that are not subject to the environmental qualification requirements of 10 CFR 50.49. 

end of the last refueling outage prior to March 20, 2025, whichever is later. 

22 Implement the new Non-EQ Inaccessible Power Cables (400 V to 

13.8 kV) Program, a condition monitoring program that will manage the aging effect of reduced insulation resistance on inaccessible power (400 V to 13.8 kV) cables that have a license renewal intended function. The program calls for inaccessible or underground (e.g., in conduit, duct bank, or direct buried) power (greater than or equal to 400 V) cables exposed to significant moisture, to be tested at least once every 6 years to provide an indication of the condition of the conductor insulation, with the first tests occurring before the period of extended operation. The program will include periodic inspections for water accumulation in manholes within the scope of this program. 

A.1.29 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

LRA 

23 Implement the new Non-EQ Instrumentation Circuits Test Review 

Program, a performance monitoring program that will manage the aging effects of applicable cables in the following systems or sub-systems. 

 Neutron monitoring 

- Intermediate range channels (IRM) - Average power range monitors (includes local power 

range monitors [LPRM] detector strings) 

 Process radiation monitoring 

- Control center emergency air inlet radiation monitors - Fuel pool ventilation exhaust radiation monitors - Main steam line radiation monitors 

The Non-EQ Instrumentation Circuits Test Review Program calls for the review of calibration results or findings of surveillance tests on electrical cables and connections used in circuits with sensitive, high-voltage, low-level current signals, such as radiation monitoring and nuclear instrumentation, to provide an indication of the existence of aging 

effects based on acceptance criteria related to instrumentation circuit 

performance. The review of calibration results or findings of surveillance tests is performed at least once every 10 years. In cases where cables are not included as part of calibration or surveillance program testing circuit, a proven cable test (such as insulation 

A.1.30 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

LRA 
A-21 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

resistance tests, time domain reflectometry tests, or other testing judged to be effective in determining cable system insulation condition as justified in the application) is performed. The test frequency is based on engineering evaluation and is at least once every 10 years. 

24 Implement the new Non-EQ Insulated Cables and Connections 

Program, a condition monitoring program that provides reasonable assurance that the intended functions of insulated cables and connections exposed to adverse localized environments caused by heat, radiation, moisture, and chemical contamination (i.e., bird droppings) can be maintained consistent with the current licensing basis through the period of extended operation. The program consists of accessible insulated electrical cables and connections installed in adverse localized environments to be visually inspected at least once every 10 years. 

A.1.31 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

LRA DTE letter NRC-15-0056 dated 5/19/15 

25 Enhance the Oil Analysis Program as follows: 

a. Revise Oil Analysis Program procedures to identify 

components within the scope of the program. 

b. Revise Oil Analysis Program procedures to provide a 

formalized analysis technique for particulate counting. 

c. Revise Oil Analysis Program procedures to include the 

sampling and testing requirements of equipment manufacturers or industry standards. 

A.1.32 Prior to 

September 20, 2024. 

LRA 

26 Implement the new One-Time Inspection Program that will consist of a 

one-time inspection of selected components to accomplish the following: 

 Verify the effectiveness of an aging management program that 

is designed to prevent or minimize aging to the extent that it will not cause the loss of intended function during the period of extended operation. The aging effects evaluated are loss of material, cracking, and fouling. 

 Confirm the insignificance of an aging effect for situations in 

which additional confirmation is appropriate using inspections that verify degradation is not occurring. 

 Trigger additional actions that ensure the intended functions of 

affected components are maintained during the period of extended operation. 

A.1.33 Inspections will be 

performed within the 10 years prior to March 20, 2025. 

LRA 

27 Implement the new One-Time Inspection – Small-Bore Piping Program 

that will augment ASME Code, Section XI (2001 Edition with 2003 Addenda) requirements and be applicable to small-bore ASME 

A.1.34 The inspection will be 

performed within the 6-year 

LRA 
A-22 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

Code Class 1 piping and components with a nominal pipe size diameter less than 4 inches (NPS 4) and greater than or equal to 1 inch (NPS 1) in systems that have not experienced cracking of ASME Code Class 1 small-bore piping. 

period prior to March 20, 2025. 

28 Enhance the Periodic Surveillance and Preventive Maintenance 

Program as follows: 

a. Revise the Periodic Surveillance and Preventive Maintenance 

Program procedures as necessary to incorporate the identified activities in LRA Section A.1.35. 

b. Revise the Periodic Surveillance and Preventive Maintenance 

Program procedures to state that acceptance criterion is no indication of relevant degradation and to incorporate the 

following:  Examples of acceptance criteria for metallic components 

- No excessive corrosion (loss of material) - No leakage from or onto internal surfaces (loss of 

material) 

- No excessive wear (loss of material) - No flow blockage due to fouling - No loss of piping component structural integrity 

 Examples of acceptance criteria for elastomeric 

components - Flexible polymers should have a uniform surface 

texture and color with no cracks and no dimension change, no abnormal surface conditions with respect to hardness, flexibility, physical dimensions, and color. 

c. Revise Periodic Surveillance and Preventive Maintenance 

Program procedures to require periodic determination of wall thickness for selected piping components. 

d. Revise Periodic Surveillance and Preventive Maintenance 

Program procedures to require wall thickness measurements using ultrasonic testing (UT) or other suitable techniques at selected locations to be periodically performed to identify loss 

of material due to multiple corrosion mechanisms (MCM) in system piping components. The selected locations are based on pipe configuration, flow conditions, and operating history to 

represent a cross-section of potential MCM sites. The selected locations are periodically reviewed to validate their relevance and usefulness, and are modified accordingly. Prior 

A.1.35 Prior to 

September 20, 2024. Initial inspection of cable spreading room dry piping will be performed within the 5 years prior to March 20, 2025. 

LRA DTE letter NRC-14-0051 dated 7/30/14 DTE letter NRC-15-0002 dated 1/15/15 
A-23 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

to the period of extended operation, select a method (or methods) from available technologies for inspecting internal surfaces of buried piping that provide(s) suitable indication of piping wall thickness for a representative set of buried piping locations. 

e. Revise Periodic Surveillance and Preventive Maintenance 

Program procedures to compare wall thickness measurements to nominal wall thickness or previous measurements to determine rates of corrosion degradation. Compare wall thickness measurements to code minimum wall thickness plus margin for corrosion during the refueling cycle (Tmarg) to determine acceptability of the component for continued use. Perform subsequent wall thickness measurements as needed for each selected location based on the rate of corrosion and expected time to reach Tmarg. Perform a minimum of five MCM degradation inspections per year until the rate of MCM corrosion occurrences no longer meets the criteria for recurring internal corrosion. 

29 Enhance the Protective Coating Monitoring and Maintenance Program 

as follows: 

a. Revise plant procedures to include in the program Service 

Level I coating applied to steel and concrete surfaces of the steel containment vessel (e.g., steel containment vessel shell, structural steel, supports, penetrations, and concrete walls and floors). 

b. Revise plant procedures to include information and 

instructions for monitoring Service Level I coating systems to be used for the inspection of coatings in accordance with guidelines identified in ASTM D5163-08. 

c. Revise plant procedures to specify the parameters monitored 

or inspected in accordance with subparagraph 10.2 of ASTM D5163-08. 

d. Revise plant procedures to establish the inspection frequency 

in accordance with paragraph 6 of ASTM D5163-08. 

e. Revise plant procedures to develop an inspection plan and 

specify inspection methods to be used as identified in accordance with subparagraph 10.1 of ASTM D5163-08. 

f. Revise plant procedures to specify that the nuclear coating 

specialist qualification recommendations and duties be as 

 A.1.36 Prior to September 20, 2024 LRA 
A-24 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

defined in ASTM D7108. As a minimum, qualification of inspection personnel (protective coating surveillance personnel) who perform these inspections shall be as specified in ASTM D4537. 

g. Revise plant procedures to specify a protective coatings 

program owner (inspection coordinator and inspection results evaluator) or equivalent to nuclear coating specialist defined in ASTM D5163-08, is responsible for the overall plant coatings program and has general duties and responsibilities similar to those defined for a nuclear coating specialist in Section 5 of ASTM D7108-05. 

h. Revise plant procedures to specify that detection of aging 

effects will include visual inspections of coatings near sumps or screens associated with the ECCS. 

i. Revise plant procedures to specify instruments and equipment 

needed for inspection in accordance with subparagraph 10.5 of ASTM D5163- 08. 

j. Revise plant procedures to specify that upon the completion of 

a planned refuel outage, a coatings outage summary report will be prepared of the coating work performed in Service Level I areas during the outage. The summary report prioritizes repair areas as areas that must be repaired during the same outage or postponed to future outages, keeping the coatings under surveillance during the interim period. 

k. Revise plant procedures to specify that the last two 

performance monitoring reports pertaining to the coating systems will be reviewed prior to the inspection or monitoring process. 

l. Revise plant procedures to describe the characterization, 

documentation, and testing of defective or deficient coating surface in accordance with subparagraphs 10.2.1 through 10.2.6, 10.3, and10.4 of ASTM D5163-08. 

m. Revise plant procedures to specify that the coatings outage 

summary report will be evaluated and approved by the protective coatings program owner. 

30 Enhance the Reactor Head Closure Studs Program as follows: 

a. Revise Reactor Head Closure Studs Program procedures to 

ensure that replacement studs are fabricated from bolting 

A.1.37 Prior to 

September 20, 2024. 

LRA 
A-25 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

material with actual measured yield strength of less than 150 kilopounds per square inch (ksi). 

b. Revise Reactor Head Closure Studs Program procedures to 

include a statement that excludes the use of molybdenum disulfide (MoS2) on the reactor vessel closure studs and also 

refers to recommendations in Regulatory Guide 1.65, Rev. 1. 

31 [Deleted] LRA 

DTE letter NRC-15-0020 dated 3/5/15 

32 Implement the new Selective Leaching Program that will demonstrate 

the absence of selective leaching in a selected sample of components (i.e., 20 percent of the population with maximum of 25 components) 

fabricated from gray cast iron and copper alloys (except for inhibited 

brass) that contain greater than 15 percent zinc or greater than 8 percent aluminum exposed to raw water, treated water, waste water, or soil. 

A.1.40 Inspection will be performed 

within 5 years prior to March 20, 2025. 

LRA 

33 Enhance the Service Water Integrity Program as follows: 

a. Revise Service Water Integrity Program procedures to include 

inspection to determine if loss of material due to erosion is occurring in the system. 

b. Revise Service Water Integrity Program procedures to 

stipulate that administrative controls are in accordance with the Fermi 2 10 CFR Part 50 Appendix B Quality Assurance Program. 

A.1.41 Prior to 

September 20, 2024. 

LRA 

34 Enhance the Structures Monitoring Program as follows: 

a. Revise plant procedures to add the following structures to the 

program.  CST and condensate return tank foundations and 

retaining barrier 

 CTG-11-1 fuel oil storage tank foundation 

 Independent spent fuel storage installation (ISFSI) rail 

transfer pad 

 Manholes, handholes, and duct banks  Shore barrier  Transformer and switchyard support structures and 

foundations 

A.1.42 Prior to 

September 20, 2024. Testing and evaluation for possible leaching in previously identified conditions will commence in 2015. 

LRA DTE letter NRC-14-0070 dated 10/24/14 DTE letter NRC-14-0082 dated 12/26/14 DTE letter NRC-15-0008 dated 1/26/15 
A-26 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

b. Revise plant procedures to specify that the following in-scope 

structures are included in the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program (Section A.1.39):  General service water pump house  Residual heat removal complex  Shore barrier 

c. Revise plant procedures to ensure that masonry walls located 

in in-scope structures are in the scope of the Masonry Wall Program (Section A.1.25). 

d. Revise plant procedures to include a list of structural 

components and commodities within the scope of license renewal to be monitored in the program. 

e. Revise plant procedures to include periodic sampling and 

chemical analysis of groundwater. 

f. Revise plant procedures to include the following preventive 

actions:  Preventive actions delineated in NUREG-1339 and EPRI 

NP-5769, NP-5067, and TR-104213 that emphasize the 

proper selection of bolting material, installation torque or tension, and the use of lubricants and sealants for high-strength bolting. 

 Preventive actions for storage of ASTM A325 and A490 

bolting from Section 2 of Research Council for Structural Connections publication, “Specification for Structural 

Joints Using ASTM A325 or A490 Bolts.” 

g. Revise plant procedures to include the following parameters to 

be monitored or inspected:  For concrete structures, base inspections on quantitative 

requirements of industry codes (i.e., American Concrete Institute (ACI) 349.3R-02), standards and guidelines (i.e., American Society of Civil Engineers (ASCE) 11) and consideration of industry and plant-specific operating experience. 

 For concrete structures and components, include loss of 

material, loss of bond, increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation. 

DTE letter NRC-15-0030 dated 3/19/15 
A-27 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

 For chemical analysis of groundwater, monitor pH, 

chlorides, and sulfates. 

 Monitor gaps between the structural steel supports and 

masonry walls that could potentially affect wall qualification. 

h. Revise plant procedures to include the following components 

to be monitored for the associated parameters:  Structural bolting and anchors/fasteners (nuts and bolts) 

for loss of material, loose or missing nuts and/or bolts, and cracking of concrete around the anchor bolts. 

 Elastomeric vibration isolators and structural sealants for 

cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening). 

i. Revise plant procedures to provide technical guidance for 

torque value requirements for specified bolting material subject to plant operating environments. 

j. Revise plant procedures to include the following for detection 

of aging effects:  Personnel (Inspection Engineer and Program 

Administrator or Responsible Engineer) involved with the inspection and evaluation of structures and structural components, including masonry walls and water-control structures, meet the qualifications guidance identified in ACI 349.3R-02. 

 Visual inspection of elastomeric material should be 

supplemented by feel or touch to detect hardening if performance of the intended function of the elastomeric material is suspect. Include instructions to augment the visual examination of elastomeric material with physical manipulation of at least 10 percent of available surface area. 

 Structures will be inspected at least once every 5 years.  Submerged structures will be inspected at least once 

every 5 years. 

 If normally inaccessible areas become accessible due to 

plant activities, an inspection of these areas shall be conducted. Additionally, inspections will be performed of inaccessible areas in environments where observed conditions in accessible areas indicate that significant degradation may be occurring in the inaccessible areas. 
A-28 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

 Sampling and chemical analysis of groundwater at least 

once every 5 years. The Structures Monitoring Program owner will review the results and evaluate any anomalies and perform trending of the results. 

 Masonry walls will be inspected at least once every 

5 years, with provisions for more frequent inspections in areas where significant aging effects (e.g., missing blocks, cracking) is observed to ensure there is no loss of intended function between inspections. 

 Inspection of water-control structures should be 

conducted under the direction of qualified personnel experienced in the investigation, design, construction, and operation of these types of facilities. 

 Inspections of water-control structures on an interval not 

to exceed 5 years. 

 Perform special inspections of water-control structures 

immediately (within 30 days) following the occurrence of significant natural phenomena, such as large floods, earthquakes, hurricanes, tornadoes, and intense local rainfalls. 

k. Revise plant procedures to prescribe quantitative acceptance 

criteria based on the quantitative acceptance criteria of ACI 349.3R-02 and information provided in industry codes, standards, and guidelines including ACI 318, American National Standards Institute (ANSI)/ASCE 11, and relevant AISC specifications. Industry and plant-specific operating experience will also be considered in the development of the acceptance criteria. 

l. Revise plant procedures to include acceptance criteria for 

masonry wall inspections that ensure observed aging effects (cracking, loss of material or gaps between the structural steel supports and masonry walls) do not invalidate the wall’s evaluation basis or impact its intended function. 

m. Revise Structures Monitoring Program procedures to include 

testing and evaluation of water/mineral deposits where in-leakage is observed in concrete elements. Testing and evaluation will determine whether leaching of calcium hydroxide and carbonation are occurring that could impact the intended function(s) of the concrete structure. 
A-29 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

n. The following testing and evaluation will be performed prior to 

the period of extended operation to confirm that previously identified conditions are not the result of leaching of calcium hydroxide and carbonation that could impact the intended function(s) of the concrete structure.  Available water/mineral deposit samples will be tested for 

mineral and iron content to assess the effect of the water in-leakage on the reinforced concrete elements involved. 

 The results of the testing and Structures Monitoring 

Program inspections will be used to determine corrective actions per the corrective action program. Possible corrective actions include, but are not limited to, more frequent inspections, sampling and analysis of the in-leakage water for mineral and iron content, testing core bore samples, and evaluation of the affected area using evaluation and acceptance criteria of ACI 349.3R-02. 
A-30 

35 Enhance the Water Chemistry Control – Closed Treated Water 

Systems Program as follows: 

a. Revise the Water Chemistry Control – Closed Treated Water 

Systems Program procedures to include the following systems.  Process sampling system sample cooler loops  CCHVAC chill water system 

b. Revise the Water Chemistry Control – Closed Treated Water 

Systems Program procedures to provide chemical treatment, including a corrosion inhibitor for the following systems in accordance with industry guidelines and vendor recommendations.  Process sampling system sample cooler loops  CCHVAC chill water system 

c. Revise Water Chemistry Control – Closed Treated Water 

Systems Program procedures to specify water chemistry parameters monitored and the acceptable range of values for these parameters in accordance with EPRI 1007820, industry guidance, or vendor recommendations. 

d. Revise Water Chemistry Control – Closed Treated Water 

Systems Program procedures to inspect accessible components whenever a closed treated water system boundary is opened. Ensure that a representative sample of piping and components is inspected at a frequency of at least once every 10 years. These inspections will be conducted in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection guidance by qualified personnel using procedures that are capable of detecting corrosion, fouling, or cracking. If visual examination identifies adverse conditions, then additional examinations, including UT, are conducted. Components inspected will be those with the highest likelihood of corrosion, fouling, or cracking. A representative sample is 20 percent of the population (defined as components having the same material, environment, and aging effect combination) with a maximum of 25 components. Perform treated water sampling and analysis of the closed treated water systems per industry standards and in no case greater than quarterly unless justified with an additional analysis. 

A.1.44 Prior to 

September 20, 2024. 

LRA DTE letter NRC-15-0030 dated 3/19/15 
A-31 

Item 

Number Commitment FSAR Supplement Section/LRA Section Enhancement or Implementation Schedule Source 

36 Implement the Coating Integrity Program as described in LRA 

Section B.1.45. 

A.1.45 Prior to 

September 20, 2024, or the end of the last refueling outage prior to March 20, 2025, whichever is later. Initial inspections will be performed within the 10 years prior to March 20, 2025. 

DTE letter NRC-15-0021 dated 2/5/15 

37 Enhance the BWR CRD Return Line Nozzle Program as follows: 

a. Revise BWR CRD Return Line Nozzle Program procedures as 

necessary to ensure that UT examinations will be used to detect applicable aging effects. 

A.1.5 Prior to September 20, 2024 

or the end of the last refueling outage prior to March 20, 2025, whichever is later. 

DTE letter NRC-15-0056 dated 5/19/15 

CHRONOLOGY 

 

B-1 

B. Chronology 

This appendix lists chronologically the routine licensing correspondence between the staff of the 

U.S. Nuclear Regulatory Commission (NRC or the staff) and DTE Electric Company (DTE or the 

applicant). This appendix also lists other correspondence on the staff’s review of the Fermi 2 

Nuclear Power Plant (Fermi 2) license renewal application (LRA) (under Docket No. 50-341). 

Table B.1-1 Appendix B: Chronology 

Date Subject 

April 24, 2014 Fermi 2 License Renewal Application, NRC-14-0028 (ADAMS Accession 

No. ML14121A554) 

June 11, 2014 Determination of Acceptability and Sufficiency for Docketing, Proposed Review Schedule, 

and Opportunity for a Hearing Regarding the Application for DTE Electric Company, for 

Renewal of the Operating License for Fermi 2 (ADAMS Accession No. ML14150A416) 

July 24, 2014 Plan for the Scoping and Screening Regulatory Audit Regarding the Fermi 2 License 

Renewal Application Review (TAC No. MF4222) (ADAMS Accession No. ML14195A221) 

July 30, 2014 Fermi 2 License Renewal Application – Supplement for LR-ISG-2012-02 (TAC 

No. MF4222) (ADAMS Accession No. ML14213A061) 

September 5, 2014 Plan for the Aging Management Program Regulatory Audit Regarding the Fermi 2 

License Renewal Application Review (TAC No. MF4222) (ADAMS Accession 

No. ML14237A194) 

September 26, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 1 (TAC No. MF4222) (ADAMS Accession No. ML14258A094) 

October 20, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 2 (TAC No. MF4222) (ADAMS Accession No. ML14266A344) 

October 21, 2014 Scoping and Screening Methodology Audit Report Regarding the Fermi 2 License 

Renewal Application (TAC No. MF4222) (ADAMS Accession No. ML14267A267) 

October 24, 2014 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 1 (ADAMS Accession No. ML14301A466) 

October 29, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 3 (TAC No. MF4222) (ADAMS Accession No. ML14288A680) 

November 10, 2014 Summary of Telephone Conference Call Held on September 16, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Draft 

Request for Additional Information 2.1-1 Pertaining to the Fermi 2 Nuclear Power Plant, 

License Renewal Application (TAC No. MF4222) (ADAMS Accession No. ML14294A062)

November 10, 2014 Summary of Telephone Conference Call Held on September 9, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Draft 

Requests for Additional Information 2.4-1, 2.4-2, 2.4-3, and 3.5.2.2.2.1-1 Pertaining to the 

Fermi 2 Nuclear Power Plant, License Renewal Application (TAC No. MF4222) (ADAMS 

Accession No. ML14293A838) 

November 18, 2014 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 2 (ADAMS Accession No. ML14322A930) 

November 25, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 8 (TAC No. MF4222) (ADAMS Accession No. ML14322A526) 

November 26, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 6 (TAC No. MF4222) (ADAMS Accession No. ML14322A203) 

November 26, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 5 (TAC No. MF4222) (ADAMS Accession No. ML14322A178) 

November 26, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 4 (TAC No. MF4222) (ADAMS Accession No. ML14321A752) 
B-2 

Date Subject 

December 1, 2014 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 3 (ADAMS Accession No. ML14335A408) 

December 4, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 7 (TAC No. MF4222) (ADAMS Accession No. ML14323A880) 

December 9, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 9 (TAC No. MF4222) (ADAMS Accession No. ML14329B233) 

December 12, 2014 Summary of Telephone Conference Call Held on November 26, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Draft 

Requests for Additional Information B.1.12-1 and B.1.12-4 Pertaining to the Fermi 2 

Nuclear Power Plant, License Renewal Application (TAC No. MF4222) (ADAMS 

Accession No. ML14335A474) 

December 16, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 14 (TAC No. MF4222) (ADAMS Accession No. ML14335A188) 

December 17, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 15 (TAC No. MF4222) (ADAMS Accession No. ML14342A652) 

December 17, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 10 (TAC No. MF4222) (ADAMS Accession No. ML14342A868) 

December 19, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 12 (TAC No. MF4222) (ADAMS Accession No. ML14342A986) 

December 19, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 11 (TAC No. MF4222) (ADAMS Accession No. ML14342A938) 

December 22, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 18 (TAC No. MVF4222) (ADAMS Accession No. ML14350B358) 

December 23, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 16 (TAC No. MF4222) (ADAMS Accession No. ML14350B365) 

December 23, 2014 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 13 (TAC No. MF4222) (ADAMS Accession No. ML14351A458) 

December 26, 2014 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 8 (ADAMS Accession No. ML14363A092) 

December 30, 2014 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Sets 4, 5, and 6 (ADAMS Accession No. ML15013A276) 

January 5, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 7 (ADAMS Accession No. ML15005A508) 

January 14, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 17 (TAC No. MF4222) (ADAMS Accession No. ML14356A212) 

January 15, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 15, NRC- 15-0009 (ADAMS Accession 

No. ML15016A063) 

January 15, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 14 (ADAMS Accession No. ML15016A056) 

January 15, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 9 (ADAMS Accession No. ML15016A022) 

January 20, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 20 (TAC No. MF4222) (ADAMS Accession No. ML15002A046) 

January 20, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 11, NRC-15-0006 (ADAMS Accession 

No. ML15021A433) 
B-3 

Date Subject 

January 20, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 10 (ADAMS Accession No. ML15021A393) 

January 26, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 19 (TAC No. MF4222) (ADAMS Accession No. ML15015A194) 

January 26, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 13 (ADAMS Accession No. ML15026A624) 

January 28, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 12, NRC-15-0007 (ADAMS Accession 

No. ML15028A533) 

January 28, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 12 (ADAMS Accession No. ML15028A534) 

January 30, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 12 Questions 4.2.2-1 and 4.2.2-2 and Set 15 Question 

4.2.6-1 (ADAMS Accession No. ML15030A350) 

January 30, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 18 (ADAMS Accession No. ML15030A359) 

February 5, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 16, NRC-15-0010 (ADAMS Accession 

No. ML15037A531) 

February 5, 2015 Fermi 2 License Renewal Application - Response to LR-ISG-2013-01 (ADAMS Accession 

No. ML15037A495) 

February 11, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 21 (TAC No. MF4222) (ADAMS Accession No. ML15026A399) 

February 11, 2015 Aging Management Programs Audit Report Regarding the Fermi 2 Nuclear Power Plant 

(TAC No. MF4222) (ADAMS Accession No. ML15030A226) 

February 12, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 17 (ADAMS Accession No. ML15045A007) 

February 19, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 11 Question B.1.22-1, NRC-15-0029 (ADAMS 

Accession No. ML15050A602) 

February 20, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 22 (TAC No. MF4222) (ADAMS Accession No. ML15035A130) 

February 24, 2015 Schedule Revision and Project Manager Change for the Review of the Fermi 2 License 

Renewal Application (TAC No. MF4222) (ADAMS Accession No. ML15051A348) 

March 5, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Sets 19, 20, and 21, NRC-15-0020 (ADAMS Accession 

No. ML15064A105) 

March 11, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 24 (TAC No. MF4222) (ADAMS Accession No. ML15051A317) 

March 11, 2015 Summary of Telephone Conference Call Held on February 9, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15051A509) 

March 13, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 23 (TAC No. MF4222) (ADAMS Accession No. ML15051A420) 

March 13, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 26 (TAC No. MF4222) (ADAMS Accession No. ML15062A336) 

March 13, 2015 Request for Withholding Information from Public Disclosure (TAC No. MF4222) 

(ADAMS Accession No. ML15054A171) 
B-4 

Date Subject 

March 19, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 22 (ADAMS Accession No. ML15079A047) 

March 19, 2015 Request for Withholding Information from Public Disclosure (TAC No. MF4222) 

(ADAMS Accession No. ML15070A161) 

March 19, 2015 Summary of Telephone Conference Call Held on January 22, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 7 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15054A134) 

March 19, 2015 Request for Withholding Information from Public Disclosure (TAC No. MF4222) 

(ADAMS Accession No. ML15072A213) 

March 19, 2015 Summary of Telephone Conference Call Held on November 14, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Draft 

Requests for Additional Information in Sets 4, 5, and 6, Pertaining to the Fermi 2 License 

Renewal Application (TAC No. MF4222) (ADAMS Accession No. ML15051A507) 

March 19, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 25 (TAC No. MF4222) (ADAMS Accession No. ML15072A081) 

March 26, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 27 (TAC No. MF4222) (ADAMS Accession No. ML15077A108) 

March 26, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 28 (TAC No. MF4222) (ADAMS Accession No. ML15078A337) 

March 26, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 29 (TAC No. MF4222) (ADAMS Accession No. ML15082A046) 

April 2, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 31 (TAC No. MF4222) (ADAMS Accession No. ML15085A513) 

April 10, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Sets 23, 24, and 26 (ADAMS Accession 

No. ML15110A342) 

April 17, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 25, NRC-15-0032 (ADAMS Accession 

No. ML15107A408) 

April 22, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 32 (TAC No. MF4222) (ADAMS Accession No. ML15099A016) 

April 22, 2015 Summary of Telephone Conference Call Held on November 19, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 7 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15092A243) 

April 22, 2015 Summary of Telephone Conference Call Held on February 13, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15076A468) 

April 23, 2015 Request for Withholding Information from Public Disclosure (TAC No. MF4222) 

(ADAMS Accession No. ML15099A663) 

April 27, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Sets 27, 28, 29, 31, NRC-15-0044 (ADAMS Accession 

No. ML15118A557) 

April 27, 2015 Summary of Telephone Conference Call Held on March 16, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 27 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15082A188) 
B-5 

Date Subject 

April 27, 2015 Summary of Telephone Conference Calls Held on March 6, 2015 between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15072A203) 

May 13, 2015 Summary of Telephone Conference Call Held on April 7, 2015, between the U.S. Nuclear 

Regulatory Commission and DTE Electric Company, Concerning Requests for Additional 

Information Pertaining to the Fermi 2 License Renewal Application (TAC No. MF4222) 

(ADAMS Accession No. ML15098A302) 

May 13, 2015 Summary of Telephone Conference Call Held on December 15, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 17 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15113A282) 

May 13, 2015 Summary of Telephone Conference Call Held on December 8, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 12 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15113A198) 

May 13, 2015 Summary of Telephone Conference Call Held on March 17, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 29 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15098A175) 

May 13, 2015 Summary of Telephone Conference Call Held on April 10, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 33 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15117A564) 

May 13, 2015 Summary of Telephone Conference Call Held on March 25, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 31 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15104A388) 

May 13, 2015 Summary of Telephone Conference Call Held on March 24, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 30 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15104A504) 

May 15, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 34 (TAC No. MF4222) (ADAMS Accession No. ML15126A004) 

May 15, 2015 Summary of Telephone Conference Call Held on November 17, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15104A632) 

May 19, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 32 (ADAMS Accession No. ML15142A461) 

May 20, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 33 (TAC No. MF4222) (ADAMS Accession No. ML15139A461) 

May 21, 2015 Requests for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 35 (TAC No. MF4222) (ADAMS Accession No. ML15134A072) 

May 26, 2015 Summary of Telephone Conference Call Held on March 4, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 28 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15092A224) 

May 26, 2015 Summary of Telephone Conference Call Held on December 5, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15119A058) 
B-6 

Date Subject 

June 9, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 34 (ADAMS Accession No. ML15160A580) 

June 9, 2015 Summary of Telephone Conference Call Held on December 17, 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 17 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15134A122) 

June 11, 2015 Summary of Telephone Conference Call Held on May 13, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 35 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15139A519) 

June 11, 2015 Summary of Telephone Conference Call Held on December 16 2014, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15133A138) 

June 11, 2015 Summary of Telephone Conference Call Held on May 5, 2015, between the U.S. Nuclear 

Regulatory Commission and DTE Electric Company, Concerning Requests for Additional 

Information, Set 34 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15132A336) 

June 12, 2015 Summary of Telephone Conference Calls Held on May 14, 21, and 28, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15154B318) 

June 12, 2015 Request for Withholding Information from Public Disclosure (TAC No. MF4222) 

(ADAMS Accession No. ML15161A364) 

June 18, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 35 (ADAMS Accession No. ML15170A329) 

June 26, 2015 Fermi 2 License Renewal Application 2015 Annual Update (ADAMS Accession 

No. ML15180A327) 

July 6, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 33 (ADAMS Accession No. ML15187A457) 

July 6, 2015 Summary of Telephone Conference Calls Held on April 29 and May 4, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15175A039) 

July 6, 2015 Summary of Telephone Conference Call Held on May 18, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15175A062) 

July 6, 2015 Summary of Telephone Conference Call Held on January 14, 2015, between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company, Concerning Requests 

for Additional Information, Set 19 Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15175A020) 

August 3, 2015 Request for Withholding Information from Public Disclosure (TAC No. MF4222) 

(ADAMS Accession No. ML15209A424) 

August 20, 2015 Supplemental Response to NRC Request for Additional Information for the Review of the 

Fermi 2 License Renewal Application – Set 33 (ADAMS Accession No. ML15232A825) 

August 28, 2015 Schedule Revision for the Safety Review of the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15238B790) 

September 1, 2015 Request for Additional Information for the Review of the Fermi, Unit 2, License Renewal 

Application – Set 37 (TAC No. MF4222) (ADAMS Accession No. ML15237A044) 

September 24, 2015 Fermi 2 License Renewal Application Update for the Boraflex Monitoring Program 

(ADAMS Accession No. ML15268A454) 
B-7 

Date Subject 

September 24, 2015 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 37 (ADAMS Accession No. ML15268A490) 

December 11, 2015 Summary of Telephone Conference Calls Held on August 4, and 18, 2015, Between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company Concerning the 

Boraflex Monitoring Program Pertaining to the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML15341A261) 

January 8, 2016 Summary of Telephone Conference Call Held on December 15, 2015, Between the 

U.S. Nuclear Regulatory Commission and DTE Electric Company Concerning the 

Response to Request for Additional Information 4.3.3-3 Pertaining to the Fermi 2 License 

Renewal Application (TAC No. MF4222) (ADAMS Accession No. ML16005A399) 

January 14, 2016 Request for Additional Information for the Review of the Fermi 2 License Renewal 

Application – Set 38 (TAC No. MF4222) (ADAMS Accession No. ML16011A044) 

January 22, 2016 Response to NRC Request for Additional Information for the Review of the Fermi 2 

License Renewal Application – Set 38 (TAC No. MF4222) (ADAMS Accession 

No. ML16022A220) 

February 3, 2016 Schedule Revision for the Safety Review of the Fermi 2 License Renewal Application 

(TAC No. MF4222) (ADAMS Accession No. ML16021A257) 

February 25, 2016 DTE Comments on the NRC’s Safety Evaluation Report with Open Items Related to the 

License Renewal of Fermi 2 (TAC No. MF4222) (ADAMS Accession No. ML16057A760) 

March 10, 2016 Supplemental Response to NRC Request for Additional Information for the Review of the 

Fermi 2 License Renewal Application – Set 17 RAI 4.3.3-1 (TAC No. MF4222) (ADAMS 

Accession No. ML16074A215) 

April 12, 2016 Fermi 2 License Renewal Application Response to LR-ISG-2015-01 (TAC No. MF4222) 

(ADAMS Accession No. ML16104A188) 

May 9, 2016 Fermi 2 License Renewal Application 2016 Annual Update (TAC No. MF4222) (ADAMS 

Accession No. ML16131A461) 

May 10, 2016 Summary of Telephone Conference Call Held on February 10 and February 25, 2016, 

Between the U.S. Nuclear Regulatory Commission and DTE Electric Company 

Concerning the Response to Request for Additional Information 4.3.3-3 Pertaining to the 

Fermi 2 License Renewal Application (TAC No. MF4222) (ADAMS Accession 

No. ML16131A066) 

May 26, 2016 Fermi, Unit 2, Submittal of Revision 20 Updated Final Safety Analysis Report, 

10 CFR 50.59 and 10 CFR 72.48 Evaluation Summary Reports, Commitment 

Management Report & Revisions to Technical Requirements Manual & Technical 

Specifications Bases, and a Summary of the Excessive Detail Removed from the UFSAR 

(ADAMS Accession No. ML16165A442) 

July 6, 2016 Completion of Fermi 2 License Renewal Application Commitment Item 1 

September 16, 2016 Report on the Safety Aspects of the License Renewal Application of the Fermi 2 Nuclear 

Power Plant (ADAMS Accession No. ML16257A527) 

PRINCIPAL CONTRIBUTORS 

 

C-1 

C. Principal Contributors 

This appendix lists the principal contributors for the development of this safety evaluation report 

and their areas of responsibility. 

Table C.1-1 Appendix C: Principal Contributors 

Name Responsibility 

Meléndez-Colón, Daneira Project Manager 

Banerjee, Gautam Reviewer – Structural 

Brittner, Donald Reviewer – Operating Experience 

Buford, Angela Reviewer – Structural 

Casto, Greg Management Oversight 

Cuadrado de Jesús, Samuel Reviewer – Structural 

Daily, John Project Manager 

Dennig, Robert Management Oversight 

Doutt, Cliff Reviewer – Electrical 

Facco, Giovanni Reviewer – Mechanical and Materials 

Fu, Bart Reviewer – Mechanical and Materials 

Gardner, William Reviewer – Mechanical and Materials 

Gavula, James Reviewer – Mechanical and Materials 

Gettys, Evelyn Reviewer – Electrical 

Green, Kimberly Reviewer – Mechanical and Materials 

Hardgrove, Matthew Reviewer – Scoping and Screening 

Hiser, Allen Senior Technical Advisor 

Holston, William Reviewer – Mechanical and Materials 

Homiack, Matthew Reviewer – Mechanical and Materials 

Hovanec, Christopher Reviewer – Mechanical and Materials 

Iqbal, Naeem Reviewer – Scoping and Screening 

Jackson, Christopher Management Oversight 

James, Lois Project Management 

Kalikian, Varoujan (Roger) Reviewer – Mechanical and Materials 

Karipineni, Nageswara Reviewer – Scoping and Screening 

Klein, Alex Management Oversight 

Krepel, Scott Reviewer – Spent Fuel 

Kulesa, Gloria Management Oversight 

Lee, Samson Management Oversight 

López Ferrer, Juan Reviewer – Structural 

Lubinski, John Management Oversight 

Lupold, Timothy Management Oversight 

Marshall, Jane Management Oversight 

Marshall, Michael Management Oversight 

McGinty, Tim Management Oversight 

Miller, Christopher Management Oversight 

Medoff, James Reviewer – Mechanical 

Min, Seung Reviewer – Mechanical and Materials 

Morey, Dennis Management Oversight 

Obodoako, Aloysius Reviewer – Mechanical and Materials 
C-2 

Name Responsibility 

Otto, Ngola Reviewer – Scoping and Screening 

Pettis, Robert Reviewer – Scoping and Screening 

Plasse, Richard Project Management 

Prinaris, Andrew Reviewer – Structural 

Raval, Janak Reviewer – Scoping & Screening 

Richardson, Rebecca Project Manager 

Rogers, Bill Reviewer – Scoping & Screening Methodology 

Sadollah, Mohammad (Mo) Reviewer – Electrical 

Smith, Edward Reviewer – Scoping & Screening 

Thomas, George Reviewer – Structural 

Wise, John Reviewer – Mechanical and Materials 

Wittick, Brian Management Oversight 

Wood, Kent Reviewer – Spent Fuel 

Yoo, Mark Reviewer – Mechanical and Materials 

Zimmerman, Jacob Management Oversight 
REFERENCES 

 

D-1 

D. References 

This appendix lists the references used throughout this safety evaluation report (SER) for review 

of the license renewal application (LRA) for the Fermi 2 Nuclear Power Plant (Fermi 2). 

Table D.1-1 References 

U.S. Nuclear Regulatory Commission Documents

Bulletin 80-11, “Masonry Wall Design,” May 1980. 

Generic Letter (GL) 81-11, “BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking 

(NUREG-0619),” February 29, 1981. 

GL 87-05, “Request for Additional Information Assessment of License Measures to Mitigate and/or Identify 

Potential Degradation of Mark I Drywells.” 

GL 88-01, “NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel 

Piping,” January 1988. 

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 1989. 

GL 91-17, “Generic Safety Issue 29, ‘Bolting Degradation or Failure in Nuclear Power Plants,’” October 17, 1991. 

GL 92-01, Revision 1, “Reactor Vessel Structural Integrity,” June 30, 1992. 

GL 92-01, Supplement 1, Revision 1, “Reactor Vessel Structural Integrity (Generic Letter 92-01, Revision 1, 

Supplement,” May 19, 1995. 

Information Notice (IN) 86-99, “Degradation of Steel Containments,” December 8, 1986. 

IN 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11,” 

December 1987. 

IN 88-82, “Torus Shells with Corrosion and Degraded Coatings in BWR Containments,” October 14, 1988. 

IN 89-79, “Degraded Coatings and Corrosion of Steel Containment Vessels,” December 1, 1989. 

IN 92-20, “Inadequate Local Leak Rate Testing,” March 3, 1992. 

IN 2004-09, “Corrosion of Steel Containment and Containment Liner,” April 27, 2004. 

IN 2006-01, “Torus Cracking in a BWR Mark I Containment,” January 12, 2006. 

IN 2012-13, “Boraflex Degradation Surveillance Programs and Corrective Actions in the Spent Fuel Pool,” 

August 10, 2012. 

IN 2014-04, “Potential for Teflon® Material Degradation in Containment Penetrations, Mechanical Seals and Other 

Components,” March 26, 2014. 

Integrated Inspection Report 0500341/2009005, “Fermi Power Plant, Unit 2, Integrated Inspection Report 

05000341/2009005.” 

Integrated Inspection Report 0500341/2011005, “Fermi Power Plant, Unit 2, Integrated Inspection Report 

05000341/2011005.” 

Integrated Inspection Report 0500341/2012005, “Fermi Power Plant, Unit 2, NRC Integrated Inspection Report 

05000341/2012005.” 

Integrated Inspection Report 0500341/2013002, “Fermi Power Plant, Unit 2, NRC Integrated Inspection Report 

05000341/2013002.” 

Integrated Inspection Report 05000341/2013003, “Fermi Power Plant, Unit 2, NRC Integrated Inspection Report 

05000341/2013003.” 

Letter from the NRC to the Detroit Edison Company, dated December 18, 1992, Subject: Fermi 2 Removal of 

24 Condensate and Feedwater System Welds from the Inservice Inspection Nondestructive Examination 

(ISI NDE) Program (TAC No. M84177). 
D-2 

U.S. Nuclear Regulatory Commission Documents

Letter from the NRC to All Power Reactor Licensees and Holders of Construction Permits in Active or Deferred 

Status, dated March 12, 2012, Subject: Issuance of Order to Modify License with Regard to Requirements for 

Mitigation Strategies for Beyond-Design-Basis External Events 

License Renewal Interim Staff Guidance (LR-ISG)-2006-01, “Plant-Specific Aging Management Program for 

Inaccessible Areas of Boiling Water Reactor (BWR) Mark I Steel Containments Drywell Shell,” 

November 16, 2006. 

LR-ISG-2011-03, “Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, ‘Buried and 

Underground Piping and Tanks,’” August 2, 2012. 

LR-ISG-2011-04, “Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized 

Water Reactors,” June 3, 2013. 

LR-ISG-2011-05, “Ongoing Review of Operating Experience,” March 16, 2012. 

LR-ISG-2012-01, “Wall Thinning Due to Erosion Mechanisms,” May 1, 2013. 

LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation,” November 22, 2013. 

LR-ISG-2013-01, “Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on 

In-Scope Piping, Piping Components, Heat Exchangers, and Tanks,” November 14, 2014. 

LR-ISG-2015-01, “Changes to Buried and Underground Piping and Tank Recommendations,” February 4, 2016. 

NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants,” July 1980. 

NUREG-0619, “BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking,” November 1980. 

NUREG-0737, “Clarification of TMI Action Plan Requirements,” November 1980. 

NUREG-0798, Supplement 5, “Safety Evaluation Report Related to the Operation of Fermi 2,” March 1985. 

NUREG-0798, Supplement 6, “Safety Evaluation Report Related to the Operation of Fermi 2,” July 1985. 

NUREG-0800, Revision 2, “Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power 

Plants: LWR Edition,” Chapter 5, “Reactor Coolant System and Connected Systems,” March 2007. 

NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,” 

June 1990. 

NUREG-1475, “Applying Statistics,” Revision 1, March 2011. 

NUREG-1522, “Assessment of Inservice Conditions of Safety-Related Nuclear Plant Structures,” June 1995. 

NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,” 

Revision 2, December 2010. 

NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” Revision 2, December 2010. 

NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless 

Steels,” April 1999. 

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant 

Components,” February 1995. 

NUREG/CR-6583, “Effects of [Light-Water Reactor] LWR Coolant Environments on Fatigue Curves of Carbon and 

Low-Alloy Steels,” February 1998. 

NUREG/CR-6909, “Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials,” February 2007. 

Regulatory Guide (RG) 1.65, “Materials and Inspections for Reactor Vessel Closure Studs.” 

RG 1.99, “Radiation Embrittlement of Reactor Vessel Materials,” Revision 2, May 1988. 

RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants.” 

RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” March 1997. 
D-3 

U.S. Nuclear Regulatory Commission Documents

RG 1.163, “Performance-Based Containment Leak-Test Program,” September 1995. 

RG 1.188, “Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses.” 

RG 1.190, “Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,” March 2001. 

Regulatory Issue Summary (RIS) 2008-30, “Fatigue Analysis of Nuclear Power Plant Components,” 

December 16, 2008. 

RIS 2012-02, “Insights into Recent License Renewal Application Consistency with the Generic Aging Lessons 

Learned Report,” January 24, 2012. 

Safety Evaluation Report Related to the License Renewal of James A. FitzPatrick Nuclear Power Plant, 

February 2008. 

Final Safety Evaluation for Electric Power Research Institute Topical Report “BWRVIP-18, Revision 2: Boiling 

Water Reactor Vessel and Internals Project, Boiling Water Reactor Core Spray Internals Inspection and Flaw 

Evaluation Guidelines,” February 22, 2016 

Regulations

U.S. Code of Federal Regulations (CFR), “Domestic Licensing of Production and Utilization Facilities,” Part 50, 

Title 10, “Energy,” Office of the Federal Register, National Archives and Records Administration, 2012. 

CFR, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions,” Part 51, 

2012. 

CFR, “Reactor Site Criteria,” Part 100. 

CFR, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 2012. 

Industry Codes and Standards, By Source

American Concrete Institute (ACI): 

ACI 318, “Building Code Requirements for Reinforced Concrete and Commentary,” 2002. 

ACI 349, “Code Requirements for Nuclear Safety-Related Concrete Structures and Commentary.” 

ACI 349.3R-02, “Evaluation of Existing Nuclear Safety Related Concrete Structures,” June 2002. 

ACI 515.1R, “Guide to the Use of Waterproofing, Dampproofing Protective and Decorative Barrier Systems for 

Concrete,” 1985. 

American National Standards Institute, Inc./American Nuclear Society (ANSI/ANS): 

ANSI/ANS 56.8, “Containment System Leakage Testing Requirements,” 2002. 

American Society of Mechanical Engineers (ASME): 

ASME Code Section III, Subsection NB-3600. 

ASME Code OM-S/G-1998, Part 17, “Performance Testing of Instrument Air System in Light-Water Reactor Power 

Plant,” 1998. 

American Society for Metals (ASM): 

ASM Handbook, Volume 13B, “Corrosion: Materials,” 2005. 

J.R. Davis, “Corrosion of Aluminum and Aluminum Alloys,” ASM International, 1999. 

American Society for Testing and Materials (ASTM): 

ASTM B209, “Standard Specification for Aluminum and Aluminum-Alloy Sheet and Plate.” 

ASTM D4537, Revision, “Standard Guide for Establishing Procedures to Qualify and Certify Personnel Performing 

Coating and Lining Work Inspection in Nuclear Facilities,” 2012. 

ASTM D5163-08, “Standard Guide for Establishing a Program for Condition Assessment of Coating Service 

Level I Coating Systems in Nuclear Power Plants,” 2008. 
D-4 

Industry Codes and Standards, By Source

ASTM D7108, “Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist,” 2005. 

Electric Power Research Institute (EPRI): 

EPRI Boiling-Water Reactor Vessels Internal Program (BWRVIP)-05, “Reactor Pressure Vessel Shell Weld 

Inspection Guidelines,” September 1995. 

BWRVIP-14-A “BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Stainless Steel RPV 

Internals,” September 2008. Proprietary information. Not publicly available.

BWRVIP-18 A, “BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and Flaw Evaluation 

Guidelines,” Revision 2, January 2016. Proprietary information. Not publicly available.

BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines,” December 1996. Proprietary 

information. Not publicly available.

BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines,” November 2004. Proprietary 

information. Not publicly available.

BWRVIP-27-A, “BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core Plate ∆P Inspection 

and Flaw Evaluation Guidelines,” August 2003. Proprietary information. Not publicly available.

BWRVIP-38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines” (EPRI TR-108823), 

September 1997. Proprietary information. Not publicly available. 

BWRVIP-41, “BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines,” September 2005. 

Proprietary information. Not publicly available.

BWRVIP-42-A, “BWR Vessel and Internals Project Boiling Water Reactor Low Pressure Coolant Injection and 

Flaw Evaluation Guidelines,” February 2005. Proprietary information. Not publicly available.

BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines,” November 2004. Proprietary 

information. Not publicly available.

BWRVIP-50-A, “Top Guide/Core Plate Repair Design Criteria,” September 2005. Proprietary information. Not 

publicly available.

BWRVIP-51-A, “Jet Pump Repair Design Criteria,” September 2005. Proprietary information. Not publicly 

available.

BWRVIP-55-A, “Lower Plenum Repair Design Criteria,” September 2005. Proprietary information. Not publicly 

available.

BWRVIP-57-A, “Instrument Penetration Repair Design Criteria,” September 2005. Proprietary information. Not 

publicly available.

BWRVIP-58-A, “Control Rod Drive Internal Access Weld Repair,” October 2005. Proprietary information. Not 

publicly available.

BWRVIP-74-A, “Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines,” June 2003. Proprietary 

information. Not publicly available.

BWRVIP-75-A, “BWR Vessel and Internals Project, Technical Basis for Revisions to Generic Letter 88-01 

Inspection Schedules,” October 2005. Proprietary information. Not publicly available.

BWRVIP-76, Revision 1, “BWR Core Shroud Inspection and Flaw Evaluation Guidelines,” May 2011. Proprietary 

information. Not publicly available.

BWRVIP-76-A, “BWR Core Shroud Inspection and Flaw Evaluation Guidelines,” November 2009. Proprietary 

information. Not publicly available.

BWRVIP-86, Revision 1-A, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan,” 

October 2012. Proprietary information. Not publicly available.

BWRVIP-87NP, Revision 1, “BWR Vessel and Internals Project: Testing and Evaluation of BWR Supplemental 

Surveillance Program Capsules D, G, and H,” Revision 1, September 2007. 
D-5 

Industry Codes and Standards, By Source

BWRVIP-99-A, “Crack Growth Rates in Irradiated Stainless Steels in BWR Internal Components,” October 2008. 

Proprietary information. Not publicly available.

BWRVIP-100-A, “BWR Vessel and Internals Project, Updated Assessment of the Fracture Toughness of Irradiated 

Stainless Steel for BWR Core Shrouds,” August 2006. Proprietary information. Not publicly available.

BWRVIP-111NP, Revision 1, “BWR Vessel and Internals Project: Testing and Evaluation of BWR Supplemental 

Surveillance Program Capsules E, F, and I,” August 2010. 

BWRVIP-135, “BWRVIP ISP Data Source Book and Plant Evaluations.” 

BWRVIP-139-A, “Steam Dryer Inspection and Flaw Evaluation Guidelines,” July 2009. Proprietary information. 

Not publicly available

BWRVIP-183 “BWR Vessel and Internals Project, Top Guide Grid Beam Inspection and Flaw Evaluation 

Guidelines,” December 2007. 

EPRI Report 1016579, “BWRVIP-190: BWR Vessel and Internals Project: BWR Water Chemistry Guidelines – 

2008 Revision.” Proprietary Information. Not publicly available. 

EPRI Report 3002002623, “BWRVIP-190: BWR Vessel and Internals Project: BWR Water Chemistry Guidelines – 

20015 Revision.” Proprietary Information. Not publicly available. 

EPRI TR-1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR-107396, Closed 

Cooling Water Chemistry Guideline,” April 2004. 

EPRI NP-5067, “Good Bolting Practices – A Reference Manual for Nuclear Power Plant Maintenance Personnel, 

Volume 1: Large Bolt Manual, 1987; Volume 2: Small Bolts and Threaded Fasteners,” 1990.” 

EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” May 1988. 

EPRI NP-7079, “Instrument Air System – A Guide for Power Plant Maintenance,” December 1990. 

EPRI TR-1003057, “License Renewal Electrical Handbook,” December 2001. 

EPRI TR-1007459, “Terry Turbine Maintenance Guide, HPCI Application,” November 2002. 

EPRI TR-1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4,” 

January 2006. 

EPRI TR-1013475, “Plant Support Engineering: License Renewal Electrical Handbook,” Revision 1 to EPRI 

Report 1003057, February 2007 

EPRI TR-1014982, “Divider Plate Cracking in Steam Generators,” June 2007. 

EPRI TR-1024995, “Environmentally Assisted Fatigue Screening, Process and Technical Basis for Identifying EAF 

Limited Locations,” August 2012. 

EPRI TR-103834-P1-2, “Effects of Moisture on the Life of Power Plant Cables, Part 1: Medium Voltage Cables, 

Part 2: Low-Voltage Cables,” prepared by Ogden Environmental and Energy Services Company, Final Report, 

August 1994. 

EPRI TR-103842, “Class I Structures License Renewal Industry Report: Revision 1,” July 1994. 

EPRI TR-104213, “Bolted Joint Maintenance & Applications Guide,” December 1995.

EPRI TR-107514, “Age Related Degradation Inspection Method and Demonstration,” May 27, 1998. 

EPRI TR-108147, “Compressed Air System Maintenance Guide,” March 1998. 

General Electric (GE) Reports: 

GE-NE-523-A71-0594-A – Referenced in SER Section 3.0.3.1.4 BWR Feedwater Nozzle – dated May 2000, 

(ADAMS Accession No. ML003723265). 

GE-NE-523-22-0292, “Updated NUREG-0619 Feedwater Nozzle Fatigue Crack Growth Analysis, Enrico Fermi 

Nuclear Power Plant, Unit 2,” July 29, 1992. 

GE-NE-523-A71-0594-A, Revision 1, “Alternate BWR Feedwater Nozzle Inspection Requirements,” May 2000. 
D-6 

Industry Codes and Standards, By Source

GE NEDC-32983P-A, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations,” 

Revision 2, January 2006. Proprietary information. Not publicly available.

GE NEDO-10029, “An Analytical Study on Brittle Fracture of GE-BWR Vessels Subject to the Design Basis 

Accident,” June 1969. Proprietary information. Not publicly available.

GEH Nuclear Energy Report, NEDO-33785, Revision 0, “DTE Energy/Enrico Fermi Plant 2 Pressure and 

Temperature Limits Report Up to 24 and 32 Effective Full-Power Years,” October 2012. 

GE NEDO-32983-A, “General Electric Methodology for RPV Fast Neutron Flux Evaluations,” Revision 2, 

January 2006. 

GE NEDO-33133, “Pressure-Temperature Curves for DTE Energy Fermi Unit 2,” Revision 0, February 2005. 

National Association of Corrosion Engineering (NACE) International: 

NACE International Publication 05107, “Report on Corrosion Probes in Soil or Concrete.” 

NACE website at http://www.naceinstitute.org/Certification. 

National Fire Protection Association (NFPA): 

NFPA 25, “Standard for Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems,” 2008, 

2011, 2014. 

Nuclear Energy Institute (NEI): 

NEI 94-01 “Industry Guidance for Implementing Performance-Based Options of 10 CFR Part 50, Appendix J,” 

July 1995. 

NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54—The License Renewal 

Rule,” Revision 6, June 2005. 

Research Council on Structural Connections (RCSC): 

RCSC, “Specification for Structural Joints Using ASTM A325 or A490 Bolts,” June 30, 2004. 

Society of Protective Coatings (SSPC): 

SSPC-SP 2, “Hand Tool Cleaning.” 

SSPC-SP 3, “Power Tool Cleaning.” 

SSPC-SP 11, “Power Tool Cleaning to Bare Metal.” 

SSPC-SP WJ-1, 2, 3, and 4, “Water Jet Cleaning.” 

Other Sources

American Water Works Association manual, PCV Pipe – Design and Installation – Manual of Water Supply 

Practices, M23, Second Edition, 2002.

ANSI/American Society of Civil Engineers (ASCE) 11-99, “Guideline for Structural Condition Assessment of 

Existing Buildings,” 1999. 

B.F. Brown, “Stress-Corrosion Cracking in High Strength Steels and in Titanium and Aluminum Alloys,” Naval 

Research Laboratory, 1972. 

Letter from AREVA Inc. to the NRC (ADAMS Accession No. ML14038A265), January 30, 2014, Subject: Potential 

Non-Conservatism in NRC Branch Technical Positon 5-3. 

Letter from the Detroit Edison Company to the NRC (NRC 92 0090), July 29, 1992, Subject: Fermi 2 Response to 

GL 88-01, Supplement 1, NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic 

Stainless Steel Piping. 

Licensee Event Report (LER) 285/2012 002 01, “Inadequate Qualifications for Containment Penetrations Renders 

Containment Inoperable,” July 2, 2013 (ADAMS Accession No. ML13184A270). 

LER 285/2012 002 01, “Inadequate Qualifications for Containment Penetrations Renders Containment 

Inoperable,” July 2, 2013 (ADAMS Accession No. ML13184A270). 
D-7 

Other Sources

National Aeronautics and Space Administration Technical Memorandum 105753, “High Temperature Dielectric 

Properties of Apical, Kapton, Peek, Teflon® AF, and Upilex Polymers,” A.N. Hammoud, 1992. 

NUMARC 93-01, “Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,” 

Revision 2, April 1996. 

Ontario Hydro study that included the results of ACSR laboratory and field tests, including the evaluation of 

conductor aging effects due to locations near pollution sources and major urban areas. 

“Principles and Prevention of Corrosion,” D.A. Jones, second edition. 

PTFE [DuPont Teflon®] Expansion Joint Engineering Guide, 2200, Ethylene LLC, Kentwood, MI, 

www.ethylene.com. 

PTFE Fluoropolymer Resin Properties Handbook, http://www.rjchase.com/ptfe_handbook.pdf. 

PVC Formulary, G. Wypych, ChemTec Publishing, September 28, 2009. 

Technical Report (TR) BAW-2248-A, “Demonstration of the Management of Aging Effects for the Reactor Vessel 

Internals,” July 1997. 

The staff reviewed the supplier’s website: 

https://www.mersen.com/en/products/anticorrosion-and-process-equipment/graphilor-bursting-discs.html. 

The staff reviewed several commercial websites: http://navyaviation.tpub.com/14018/css/14018_228.htm, 

http://www.titeflex.com/industrial/products/PTFE/index.html, 

http://www.herberaircraft.com/pdf/Hoses%20tech%20broch(new)/Teflon%20Hoses/666%20Crimp%20Fittings%20

eng%20bulletin.PDF. 

Westinghouse Electric Company Report, “AP1000® Design Control Document,” Revision 19, Tier 2 Chapter 3, 

Appendix 3D, “Methodology for Qualifying AP1000 Safety-Related Electrical and Mechanical Equipment.” 





NUREG-2210 Safety Evaluation Report Related to the License Renewal of Fermi 2