Safety Evaluation Report

Related to the License

Renewal of Davis-Besse

Nuclear Power Station

Docket Number 50-346

FirstEnergy Nuclear Operating Company

Supplement 1

Office of Nuclear Reactor Regulation

NUREG-2193

Supplement 1

 

Safety Evaluation Report

Related to the License

Renewal of Davis-Besse

Nuclear Power Station

Docket Number 50-346

FirstEnergy Nuclear Operating Company

Supplement 1

Manuscript Completed: August 2015

Date Published: April 2016

Office of Nuclear Reactor Regulation

NUREG-2193

Supplement 1

iii

ABSTRACT

This document is a supplemental safety evaluation report (SSER) for the license renewal 

application (LRA) for Davis-Besse Nuclear Power Station (Davis-Besse) as submitted by

FirstEnergy Nuclear Operating Company (FENOC or the applicant). By letter dated 

August 27, 2010, FENOC submitted its LRA to the U.S. Nuclear Regulatory Commission (NRC) 

for renewal of the Davis-Besse operating licenses for an additional 20 years. The NRC staff 

(the staff) issued a safety evaluation report (SER) related to the license renewal of Davis-Besse 

Nuclear Power Station, dated September 3, 2013 (Agencywide Documents Access and 

Management System (ADAMS) Accession No. ML13248A267), which summarizes the results of 

its review of the LRA for compliance with the requirements of Title 10, Part 54, of the Code of 

Federal Regulations (10 CFR Part 54), “Requirements for Renewal of Operating Licenses for 

Nuclear Power Plants.”

This SSER documents the staff’s review of supplemental information provided by the applicant 

since the issuance of the SER. This information includes annual updates required by 

10 CFR 54.21(b) and updated information and commitments in response to the recent industry 

operating experience. This SSER supplements portions of SER Sections 1, 2, 3, 4, and 

Appendices.

v

TABLE OF CONTENTS

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

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

ABBREVIATIONS AND ACRONYMS ..................................................................................... xi

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

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

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

1.4.1 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’”............................................................................... 1-2

1.4.2 LR-ISG-2012-01, “Wall Thinning Due to Erosion 

Mechanisms” ............................................................................ 1-2

1.4.3 LR-ISG-2012-02, “Aging Management of Internal Surfaces, 

Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation” ...................................................... 1-2

1.4.3.1 Recurring Internal Corrosion.................................... 1-3

1.4.3.2 Representative Minimum Sample Sizes for 

Periodic Inspections ................................................ 1-3

1.4.3.3 Flow Blockage of Water-Based Fire Protection 

System Piping ......................................................... 1-3

1.4.3.4 Revisions to the Scope of Inspection 

Recommendations of GALL Report AMP XI.M29, 

“Aboveground Metallic Tanks” ................................. 1-3

1.4.3.5 Corrosion Under Insulation ...................................... 1-3

1.5 Summary of Open Items....................................................................... 1-3

1.7 Summary of Proposed License Conditions........................................... 1-4

SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING 

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

2.2 Plant-Level Scoping Results................................................................. 2-1

2.2.3 Staff Evaluation......................................................................... 2-1

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

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

2.4.12 Yard Structures......................................................................... 2-2

2.4.12.1 Summary of Technical Information in the 

Application............................................................... 2-2

2.4.12.2 Staff Evaluation ....................................................... 2-2

2.4.12.3 Conclusion............................................................... 2-3

2.5 Scoping and Screening Results: Electrical and Instrumentation and 

Controls................................................................................................ 2-3

2.5.1 Electrical and Instrumentation and Controls Commodity 

Groups...................................................................................... 2-3
Table of Contents

vi

2.5.1.1 Summary of Technical Information in the 

Application............................................................... 2-3

2.5.1.2 Staff Evaluation ....................................................... 2-4

2.5.1.3 Conclusion............................................................... 2-7

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

3.0 Applicant’s Use of the Generic Aging Lessons Learned (GALL) 

Report .................................................................................................. 3-1

3.0.3 Aging Management Programs (AMPs)...................................... 3-1

3.0.3.1 AMPs Consistent with the GALL Report .................. 3-1

3.0.3.2 AMPs Consistent with the GALL Report with 

Exceptions or Enhancements .................................. 3-4

3.0.3.3 AMPs Not Consistent with or Not Addressed in 

the GALL Report.................................................... 3-21

3.0.3.4 Aging Management Related to Recurring Internal 

Corrosion............................................................... 3-68

3.0.3.5 Staff Evaluation of LRA Changes To Incorporate 

LR-ISG-2012-01, “Wall Thinning Due to Erosion 

Mechanisms”......................................................... 3-69

3.1 Aging Management of Reactor Vessel, Internals, Reactor Coolant 

System and Reactor Coolant Pressure Boundary, and Steam 

Generators ......................................................................................... 3-70

3.1.1 Summary of Technical Information in the Application.............. 3-70

3.1.2 Staff Evaluation....................................................................... 3-70

3.1.2.1 AMR Results Consistent with the GALL Report ..... 3-70

3.1.2.2 AMR Results Consistent with the GALL Report 

for Which Further Evaluation Is Recommended..... 3-73

3.1.2.3 AMR Results Not Consistent with or Not 

Addressed in the GALL Report.............................. 3-74

3.2 Aging Management of Engineered Safety Features ........................... 3-74

3.2.1 Summary of Technical Information in the Application.............. 3-74

3.2.2 Staff Evaluation....................................................................... 3-74

3.2.2.1 AMR Results Consistent with the GALL Report ..... 3-75

3.2.2.2 AMR Results Consistent with the GALL Report 

for Which Further Evaluation Is Recommended..... 3-75

3.2.2.3 AMR Results Not Consistent with or Not 

Addressed in the GALL Report.............................. 3-76

3.2.3 Conclusion.............................................................................. 3-77

3.3 Aging Management of Auxiliary Systems............................................ 3-77

3.3.1 Summary of Technical Information in the Application.............. 3-77

3.3.2 Staff Evaluation....................................................................... 3-78

3.3.2.1 AMR Results Consistent with the GALL Report ..... 3-78

3.3.2.2 AMR Results Consistent with the GALL Report 

for Which Further Evaluation Is Recommended..... 3-78

3.3.2.3 AMR Results Not Consistent with or Not 

Addressed in the GALL Report.............................. 3-79

3.3.3 Conclusion.............................................................................. 3-82
Table of Contents

vii

3.4 Aging Management of Steam and Power Conversion Systems .......... 3-82

3.4.1 Summary of Technical Information in the Application.............. 3-82

3.4.2 Staff Evaluation....................................................................... 3-82

3.4.2.2 AMR Results Consistent with the GALL Report 

for Which Further Evaluation Is Recommended..... 3-82

3.4.2.3 AMR Results Not Consistent with or Not 

Addressed in the GALL Report.............................. 3-83

3.4.3 Conclusion.............................................................................. 3-83

3.5 Aging Management of Structures and Structural Components ........... 3-83

3.6 Aging Management of Electrical and Instrumentation and Controls.... 3-83

SECTION 4 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................ 4-1

4.1.2 Staff Evaluation......................................................................... 4-1

4.1.2.1 Evaluation of the Applicant’s Identification of 

Time-Limited Aging Analyses .................................. 4-1

4.1.2.2 Evaluation of the Applicant’s Identification of 

Those Exemptions in the CLB That Are Based 

on TLAAs ................................................................ 4-2

4.1.3 Conclusion................................................................................ 4-2

4.2 Reactor Vessel Neutron Embrittlement................................................. 4-2

4.2.7 Reduction in Fracture Toughness of Reactor Vessel 

Internals.................................................................................... 4-2

4.2.7.1 Summary of Technical Information in the 

Application............................................................... 4-2

4.2.7.2 Staff Evaluation ....................................................... 4-3

4.2.7.3 Conclusion............................................................... 4-6

4.3 Metal Fatigue ....................................................................................... 4-6

4.3.2 Class 1 Fatigue......................................................................... 4-6

4.3.2.2 Class 1 Vessels, Pumps, and Major Components ... 4-6

4.3.2.3 Class 1 Piping and Valves ..................................... 4-22

4.7 Other Plant-Specific Time-Limited Aging Analyses............................. 4-24

4.7.5 Inservice Inspection—Fracture Mechanics Analyses .............. 4-24

4.7.5.2 Once-Through Steam Generator 1-2 Flaw 

Evaluations............................................................ 4-24

SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS.... 5-1

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

Appendix A DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL 

COMMITMENTS...............................................................................................A-1

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

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

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

ix

LIST OF TABLES

Table 1.4-1 Current License Renewal Interim Staff Guidance ...................................... 1-2

Table 3.0.3.3.9-1 Crack Widths of Cracked Core Bores in Inspection Sample .................... 3-48

Table 3.0.3.3.9-2 Shield Building Laminar Cracking Planar Limits....................................... 3-52

Table 3.1-1 Revisions to SER Table 3.1-1.................................................................. 3-70

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report... 3-77

xi

ABBREVIATIONS AND ACRONYMS

ACI American Concrete Institute

ADAMS Agencywide Documents Access and Management System

AERM aging effect requiring management

AFW auxiliary feedwater

A/LAI applicant/licensee action items

ALARA as low as is reasonably achievable

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

ASCE American Society of Civil Engineers

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

B&W Babcock & Wilcox

BWST borated water storage tank

CASS cast austenitic stainless steel

CFR Code of Federal Regulations

CLB current licensing basis

CRGT control rod guide tube

CSE copper/copper sulfate reference electrode

CSS core support shield

CUF cumulative usage factor

CUI corrosion under insulation

EDG emergency diesel generator

EPRI Electric Power Research Institute

EQ Equipment Qualification
Abbreviations and Acronyms

xii

FACE Full Apparent Clause Evaluation (Report)

FD flow distributor

FENOC FirstEnergy Nuclear Operating Company

FIV flow-induced vibration

FMECA failure modes, effects and criticality analysis/analyses

GALL Generic Aging Lessons Learned

GL generic letter

HDPE high-density polyethylene

HPCI high-pressure coolant injection

HPI high-pressure injection

HTH high-temperature annealed and aged condition heat treatment

HVAC heating, ventilation, and air conditioning

I&C instrumentation and control

I&E inspection and evaluation

IASCC irradiation-assisted stress corrosion cracking

IGA intergranular attack

IMI incore monitoring instrumentation

IPA integrated plant assessment

ISI inservice inspection

LAI licensee action items

LCB lower core barrel

LOCA loss-of-coolant accident

LRA license renewal application

LR-ISG license renewal interim staff guidance

LTS lower thermal shield
Abbreviations and Acronyms

xiii

MFW main feedwater

MIC microbiologically-influenced corrosion

MRP Materials Reliability Program

MUR measurement uncertainty recapture

mV millivolt(s)

NACE National Association of Corrosion Engineers

NDE nondestructive examination

NEI Nuclear Energy Institute

NFPA National Fire Protection Association

NRC U.S. Nuclear Regulatory Commission

ohm-cm ohm-centimeter(s)

OTSG once-through steam generator

PIV post-indicating valves

PM preventive maintenance

ppm part(s) per million

psid pound(s) per square inch differential

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

RAI request for additional information

RCP reactor coolant pump

RCS reactor coolant system

RFO refueling outage

RG regulatory guide

RVI reactor vessel internals

RVIIP reactor vessel internals inspection plan
Abbreviations and Acronyms

xiv

SBO station blackout

SBODG station blackout diesel generator

SCC stress corrosion cracking

SCV steel containment vessel

SEI Structural Engineering Institute

SER safety evaluation report

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

Nuclear Power Plants, Revision 2”

SSC systems, structures, and components

SSER supplemental safety evaluation report

SSHT surveillance specimen holder tube

TR Topical Report

TLAA time-limited aging analysis

TS technical specification(s)

UCB upper core barrel

USAR updated safety analysis report

UT ultrasonic testing

UTS upper thermal shield

VT-3 visual examination
1-1

SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

This document is a supplemental safety evaluation report (SSER) for the license renewal 

application (LRA) for Davis-Besse Nuclear Power Station (Davis-Besse), as submitted by 

FirstEnergy Nuclear Operating Company (FENOC or the applicant). By letter dated 

August 27, 2010, FENOC submitted its LRA to the U.S. Nuclear Regulatory Commission (NRC) 

for renewal of the Davis-Besse operating licenses for an additional 20 years. The NRC staff 

(the staff) issued a safety evaluation report (SER) related to the license renewal of Davis-Besse

dated September 3, 2013 (Agencywide Documents Access and Management System (ADAMS)

Accession No. ML13248A267), which summarizes the results of its review of the LRA for 

compliance with the requirements of Title 10 of the Code of Federal Regulations

(10 CFR) Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants.”

This SSER documents the staff’s review of additional information provided by the applicant 

since the staff’s issuance of the SER in September 2013. This information includes annual 

updates required by 10 CFR 54.21(b) and updated information and commitments in response to 

the recent industry operating experience. This SSER supplements portions of SER 

Sections 1, 2, 3, 4, and Appendices.

The following sections, unless otherwise noted, have been updated and supersede the 

corresponding sections of the SER.

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. License renewal 

interim staff guidance (LR-ISG) is documented for use by the staff, industry, and other 

interested stakeholders until incorporated into such license renewal guidance documents as 

NUREG–1800, “Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants,” Revision 2, December 2010 (SRP-LR), and NUREG–1801, “Generic Aging 

Lessons Learned Report,” Revision 2, December 2010 (GALL Report).

The applicant revised several aging management programs (AMPs) and aging management

review (AMR) items in several Table 2s in order to address recently issued LR-ISGs. The staff’s 

evaluation of associated changes to AMPs and AMR items in the Table 2s are addressed in the 

corresponding sections of this SSER. For example, revised and new enhancements to the 

Buried Piping and Tanks Inspection Program are addressed in SSER Section 3.0.3.2.3. 

Changes to the AMR items in the Table 2s are addressed in SSER Sections (e.g., 3.2, 3.3, 3.4).
Introduction

1-2

Table 1.4-1 Current License Renewal Interim Staff Guidance

ISG Issue

(Approved ISG Number) Purpose SSER Section

“Changes to the Generic Aging 

Lessons Learned (GALL) Report 

Revision 2, Aging Management 

Program (AMP) XI.M41, Buried and 

Underground Piping and Tanks”

(LR-ISG-2011-03)

See Section 1.4.1 See SSER Section 3.0.3.2.3

“Wall Thinning Due to Erosion 

Mechanisms”

(LR-ISG-2012-01)

 See Section 1.4.2 See SSER Section 3.0.3.5

“Aging Management of Internal 

Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and 

Corrosion under Insulation”

(LR-ISG-2012-02)

 See Section 1.4.3 See SSER Sections 3.0.3.4.1, 

3.0.3.3.7, 3.0.3.2.8, 3.0.3.2.1, and 

3.0.3.2.5

1.4.1 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 issued LR-ISG-2011-03 on August 2, 2012, in order to address changes to 

GALL Report AMP XI.M41, “Buried and Underground Piping and Tanks,” associated with 

inspection recommendations for plants not utilizing a cathodic protection system, increases in 

inspection sample size when adverse conditions are detected, acceptance criteria for cathodic 

protection surveys, and other miscellaneous topics. The staff’s evaluation of the applicant’s 

changes to its Buried Piping and Tanks Inspection Program to address this ISG is documented 

in SSER Section 3.0.3.2.3.

1.4.2 LR-ISG-2012-01, “Wall Thinning Due to Erosion Mechanisms”

The staff issued LR-ISG-2012-01, “Wall Thinning Due to Erosion Mechanisms,” on May 1, 2013, 

in order to address loss of material due to various erosion mechanisms. This LR-ISG generated 

new AMR items and modified GALL Report AMP XI.M17, “Flow-Accelerated Corrosion.” By 

letter dated June 23, 2014, the applicant provided its evaluation of LR-ISG-2012-01 and 

concluded that an additional monitoring program was not needed to manage erosion, flashing, 

or cavitation, based on reviews of plant operating experience. The staff’s evaluation of the 

applicant’s review for this LR-ISG is documented in SSER Section 3.0.3.5.

1.4.3 LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and Corrosion Under Insulation”

The staff issued LR-ISG-2012-02, on November 22, 2013, in order to address aging effects 

associated with recurring internal corrosion, fire water systems, atmospheric storage tanks, 

corrosion under insulation, and other changes to the GALL Report and SRP-LR. The changes 

addressed in LR-ISG-2012-02 are discussed in the following sections.
Introduction

1-3

1.4.3.1 Recurring Internal Corrosion

Part A of LR-ISG-2012-02 addresses loss of material due to recurring internal corrosion. By 

letter dated February 19, 2014, the applicant provided its evaluation of LR-ISG-2012-02, Part A,

and provided a new LRA Section 3.3.2.2.16, “Loss of Material Due to Recurring Internal 

Corrosion.” The staff’s evaluation of the applicant’s review for loss of material due to recurring 

internal corrosion is documented in SSER Section 3.0.3.4.1.

1.4.3.2 Representative Minimum Sample Sizes for Periodic Inspections

Part B of LR-ISG-2012-02 addresses the representative minimum sample size for periodic 

inspections in GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components.” By letter dated February 19, 2014, the applicant provided its 

evaluation of LR-ISG-2012-02, Part B, and made changes to LRA Sections A.1.41 and B.2.41, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program.” The staff’s 

evaluation of changes to the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Program is documented in SSER Section 3.0.3.3.7.

1.4.3.3 Flow Blockage of Water-Based Fire Protection System Piping

Part C of LR-ISG-2012-02 addresses flow blockage of water-based fire protection system piping 

in GALL Report AMP XI.M27, “Fire Water System.” By letter dated February 19, 2014, the 

applicant provided its evaluation of LR-ISG-2012-02, Part C, and made changes to LRA

Sections A.1.18 and B.2.18, “Fire Water Program.” The applicant also revised LRA

Table 3.3.2-14 to address flow blockage and managing aging effects associated with the fire 

water storage tank. The staff’s evaluation of changes to the applicant’s Fire Water Program is 

documented in SSER Section 3.0.3.2.8.

1.4.3.4 Revisions to the Scope of Inspection Recommendations of GALL Report

AMP XI.M29, “Aboveground Metallic Tanks”

Part D of LR-ISG-2012-02 addresses revisions to the recommended inspection scope of 

GALL Report AMP XI.M29, “Aboveground Metallic Tanks.” By letter dated February 19, 2014, 

the applicant provided its evaluation of LR-ISG-2012-02, Part D, and replaced LRA

Sections A.1.2 and B.2.2, “Aboveground Steel Tanks Inspection Program,” in their entirety. The 

staff’s evaluation of the applicant’s changes to the Aboveground Steel Tanks Inspection 

Program is documented in SSER Section 3.0.3.2.1.

1.4.3.5 Corrosion Under Insulation

Part E of LR-ISG-2012-02 addresses corrosion under insulation. By letter dated 

February 19, 2014, the applicant provided its evaluation of LR-ISG-2012-02, Part E, and revised 

LRA Sections A.1.15 and B.2.15, “External Surfaces Monitoring Program.” The staff’s 

evaluation of changes to the applicant’s External Surfaces Monitoring Program is documented 

in SSER Section 3.0.3.2.5.

1.5 Summary of Open Items

The staff does not have any changes or updates to this section of the SER.
Introduction

1-4

1.7 Summary of Proposed License Conditions

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

provided by the applicant, the staff identified three proposed license conditions.

The first license condition requires the information in the updated safety analysis report (USAR)

supplement, submitted pursuant to 10 CFR 54.21(d), as revised during the LRA review process 

and supplemented by Appendix A of the “Safety Evaluation Report Related to the License 

Renewal of Davis-Besse Nuclear Power Station,” to be part of the USAR, which will be updated 

in accordance with 10 CFR 50.71(e), following the issuance of the renewed license. As such, 

the applicant may make changes to the programs and activities described in the USAR 

supplement, provided the applicant evaluates such changes pursuant to the criteria set forth in 

10 CFR 50.59 and otherwise complies with the requirements in that section.

The second license condition states that the applicant’s USAR supplement submitted pursuant 

to 10 CFR 54.21(d), as supplemented by Appendix A of the “Safety Evaluation Report Related 

to the License Renewal of Davis-Besse Nuclear Power Station,” describes certain future 

programs and activities to be completed before the period of extended operation.

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

programs no later than October 22, 2016 (i.e., no later than 6 months prior to the period 

of extended operation).

(b) The applicant shall complete those activities as noted in Commitment Nos. 22, 23, 24, 

38, 41, 54, and 55 no later than October 22, 2016.

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.

LRA Appendix A, “Updated Safety Analysis Report Supplement,” Table A-1, “Davis-Besse 

License Renewal Commitments,” contains commitments for license renewal and an associated 

schedule for when the applicant plans to implement or complete the commitments. The staff 

noted that, through the commitments in LRA Appendix A, Table A-1, the applicant will 

implement new programs, will implement enhancements to existing programs, and will also 

complete inspection or testing activities. The staff also noted that the Davis-Besse current 

license expires on April 22, 2017. Therefore, the applicant’s implementation schedule for some 

commitments, as provided originally in LRA Section Appendix A, Table A-1, may conflict with 

the implementation schedule intended by the generic second license condition described above.

By letter dated March 26, 2013, the staff issued RAI A.1-1, Part (1), requesting that the 

applicant identify those commitments to implement new programs and enhancements to 

existing programs and state when the implementation of these programs will be completed. In 

addition, RAI A.1-1, Part (2), requested that the applicant identify those commitments to 

complete inspection or testing activities and state when the completion of these inspection and 

testing activities will occur. The applicant responded to RAI A.1-1 in a letter dated March 26, 

2013.

In response to RAI A.1-1, Part (1), the applicant identified Commitment Nos. 1 through 14, 

16 through 21, 25, 27 through 32, 34, 40, 45 through 47, and 49, as those commitments 

associated with implementation of new programs and enhancements to existing programs. 
Introduction

1-5

The applicant stated that these commitments will be completed no later than October 22, 2016. 

As part of its response, the applicant also provided LRA Amendment 40, which revised the 

implementation schedule in LRA Appendix A, Table A-1, for these commitments, to state that 

they will be completed no later than October 22, 2016. In response to RAI A.1-1, Part (2), the 

applicant identified Commitment Nos. 22 through 24, 38, 41, 43, 44, and 48, as those 

commitments associated with inspection and testing activities. The applicant stated that these 

commitments will be completed no later than October 22, 2016. The applicant also revised the 

implementation schedule in LRA Appendix A, Table A-1, to state that these commitments will be 

completed no later than October 22, 2016.

The staff finds the applicant response to RAI A.1-1, Part (1), acceptable because the applicant 

identified those commitments that implement new programs and enhancements to existing 

programs and revised the implementation schedule on LRA Appendix A, Table A-1, to complete 

these commitments 6 months before the period of extended operation, which is consistent with 

the proposed second license condition. The staff finds the applicant response to RAI A.1-1, 

Part (2), acceptable because the applicant identified those commitments to complete inspection 

or testing activities and revised the implementation schedule on LRA Appendix A, Table A-1, 

consistent with the proposed second license condition, to state that these commitments will be 

implemented 6 months before the period of extended operation. Therefore, the staff’s concerns 

described in RAI A.1-1, Parts (1) and (2), are resolved.

The third license condition requires testing of surveillance capsules for the period of extended 

operation to meet the test procedures and reporting requirements of American Society of 

Testing and Materials (ASTM) E 185-82 to the extent practicable for the configuration of the 

specimens in the capsule. All pulled capsules shall be properly maintained for testing, and any 

changes to storage requirements must be approved by the NRC. All pulled and tested 

capsules, unless discarded before August 31, 2000, shall be placed in storage to be saved for 

possible future reconstitution and use.

2-1

SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW

2.2 Plant-Level Scoping Results

2.2.3 Staff Evaluation

Summary of Technical Information in the Application. By letter dated September 20, 2013, the 

applicant supplemented the LRA as required by 10 CFR 54.21(b). In this supplement, FENOC 

provided information related to a new steam generator storage facility that was not previously 

included as part of the August 27, 2010, LRA submittal. In the original LRA, the applicant 

provided the results of applying the license renewal scoping criteria for structures in Table 2.2-3. 

If a system or structure, in whole or in part, met one or more of the license renewal scoping 

criteria, the system or structure was evaluated as within the scope of license renewal for 

Davis-Besse. The applicant stated in the September 20, 2013 LRA supplement letter that the 

new steam generator storage facility is an 18,000-square-foot structure that will be used to 

house and protect the replacement steam generators until they are installed in the plant. This 

structure is located outside the protected area and, therefore, is not within the scope of license 

renewal.

The applicant also stated that LRA Table 2.2-3, “License Renewal Scoping Results for 

Structures,” had been revised to address the new structure.

In addition, FENOC included information related to new foundations added to the Davis-Besse 

switchyard to support new electrical breakers. Specifically, the applicant stated in the 

supplement letter that the Davis-Besse switchyard had been reconfigured in order to facilitate 

breaker maintenance, by extending the J (East) and K (West) buses and adding two new 

345 kilovolts (kV) breakers. The two 345 kV breakers are connected on either side of the new 

location of the Ohio Edison line, with one breaker between the Ohio Edison line and the J Bus 

and one breaker between the Ohio Edison line and the K Bus. The applicant also stated that the 

new switchyard configuration will enable the buses to be maintained under maintenance or 

outage conditions, resolving concerns regarding power interruption and short outage duration 

time limits imposed during line or breaker maintenance activities.

Staff Evaluation. The staff has completed the evaluation related to the new steam generator 

storage facility, as described in the supplemental information provided by the applicant on 

September 20, 2013. The staff compared the original review, as detailed in SER Section 2 from 

September 3, 2013, to the proposed changes detailed by the applicant in the supplement. The 

staff performed the review in accordance with the regulations and requirements of 

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

and the guidance contained in NUREG-1800, Revision 1, “Standard Review Plan for Review of 

License Renewal Applications for Nuclear Power Plants,” (SRP-LR), Section 2.1, “Scoping and 

Screening Methodology,” and SRP-LR Section 2.2, “Plant-Level Scoping Results.”
Structures and Components

2-2

The staff reviewed the information related to the new steam generator storage facility, since the 

applicant did not identify it as being within the scope of license renewal to verify whether the 

systems and structures have any intended functions requiring their inclusion within the scope of 

license renewal.

Based on its review, the staff determined that the new steam generator storage facility is not 

within the scope of license renewal because the structure does not meet any of the scoping 

criteria of 10 CFR 54.4 as described below:

(1) safety-related systems, structures, and components which are those relied upon 

to remain functional during and following design-basis events

(2) all nonsafety-related systems, structures, and components whose failure could 

prevent satisfactory accomplishment of any of the functions identified in 

paragraphs (a)(1)(i), (ii), or (iii) of 10 CFR 54.4

(3) all 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)

2.2.4 Conclusion

LRA Table 2.2-3, “License Renewal Scoping Results for Structures” has been revised to 

address the new structure. There are no changes or updates to this section of the SER.

2.4 Scoping and Screening Results: Structures

2.4.12 Yard Structures

2.4.12.1 Summary of Technical Information in the Application

The staff noted that, by letter dated June 23, 2014, the applicant provided additional information 

related to an additional yard structure after the issuance of the SER. The additional structure

below is added to the 2.4.12.1 list in the SER.

• SBO Components foundations and Structures in the Yard and Switchyard including 

Startup Transformers 01 and 02; Bus-Tie Transformers; 345-kV Switchyard circuit 

breakers ACB34560, ACB34561, ACB34562, ACB34563, ACB34564, 81-B-65, 81-B-66 

and 81-B-67; Relay House, Switchyard and Yard Towers for 345-kV distribution; “J” and 

“K” buses – Seismic Class II.

2.4.12.2 Staff Evaluation

There are no changes or updates to this section of the SER.
Structures and Components

2-3

2.4.12.3 Conclusion

There are no changes or updates to this section of the SER.

2.5 Scoping and Screening Results: Electrical and Instrumentation and 

Controls

This section documents the staff’s review of the applicant’s scoping and screening results for 

electrical and instrumentation and control (I&C) systems. Specifically, this section discusses 

electrical and I&C component commodity groups.

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived systems, structures, and components (SSCs) 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 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 and the request for 

additional information (RAI) responses, focusing on components that have not been identified 

as within the scope of license renewal. The staff reviewed the Davis-Besse updated safety 

analysis report (USAR) for each electrical and I&C system to determine whether the application 

has omitted, from the scope of license renewal, components with intended functions delineated 

under 10 CFR 54.4(a).

After its review of the scoping results, the staff evaluated the applicant’s screening results. 

For those SSCs with intended functions, the staff sought to determine whether (1) the functions 

are performed with moving parts or 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 SSCs 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).

2.5.1 Electrical and Instrumentation and Controls Commodity Groups

2.5.1.1 Summary of Technical Information in the Application

LRA Section 2.5 describes the electrical and I&C systems. The integrated plant assessment 

(IPA) approach for the review of the electrical and I&C components that are in scope of license 

renewal eliminates the need to uniquely identify each individual component and its specific 

location and precludes improper exclusion of components from an AMR.
Structures and Components

2-4

The applicant’s IPA scoping process includes all plant electrical and I&C systems within the 

scope of license renewal unless they are specifically scoped out. The IPA screening process 

groups all in-scope electrical and I&C components in commodity groups and identifies those 

electrical commodity groups that are subject to an AMR by applying 10 CFR 54.21(a)(1)(i) and 

10 CFR 54.21(a)(1)(ii). The applicant determined the in-scope electrical components required 

for compliance with the Station Blackout (SBO) Rule (10 CFR 50.63), as well as their 

corresponding intended functions, through a review of the Davis-Besse current licensing basis

(CLB), with consideration of the requirements of 10 CFR 54.4(a)(3) and the guidance provided 

in the SRP-LR.

LRA Table 2.5-1, “Electrical and I&C System Components Subject to Aging Management 

Review,” identifies the following electrical and I&C component and commodity groups subject to 

AMR along with their license renewal intended functions:

• non-environmentally qualified (EQ) insulated cables and connections includes non-EQ 

electrical penetration assemblies, non-EQ cable connections (metallic parts) – conduct 

electricity

• non-EQ sensitive, high-voltage, low-level signal instrument cables and connections –

conduct electricity

• non-EQ medium-voltage power cables – conduct electricity

• switchyard bus and connections – conduct electricity

• transmission conductors and connections – conduct electricity

• high-voltage insulators – insulation and support

Electrical and I&C components, such as thermocouples, radiation detectors, flow elements, and 

electrical heaters having pressure boundary intended functions, are assessed in LRA

Section 2.3, “Scoping and Screening Results: Mechanical.”

Components that support or interface with the electrical and I&C components are assessed in 

LRA Section 2.4, “Scoping and Screening Results: Structural.”

2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5, the annual updates to LRA Section 2.5 in LRA 

Amendments 46 and 50, and Davis-Besse USAR Chapters 7 and 8, using the evaluation 

methodology described in the guidance in SRP-LR Section 2.5, “Scoping and Screening 

Results: Electrical and Instrumentation and Controls Systems.”

During its review, the staff evaluated the system functions described in the LRA and USAR to 

verify that the applicant has not omitted, from the scope of license renewal, any components 

with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those 

components that the applicant identified as within the scope of license renewal to verify that the 

applicant has not omitted any passive and long-lived components subject to an AMR, in 

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

In LRA Section 2.5.3, “Elimination of Component Commodity Groups With No License Renewal 

Intended Functions,” the applicant provided the electrical and I&C component that do not 

perform a license renewal function and are excluded from AMR.
Structures and Components

2-5

The applicant excluded uninsulated ground conductors from AMR because uninsulated ground 

conductors do not perform a license renewal intended function at Davis-Besse. The applicant 

clarified that uninsulated ground conductors limit equipment damage and provide personnel 

protection; their failure cannot cause the loss of a safety function; and they are not relied upon 

in safety analyses or plant evaluations to perform any function consistent with the requirements 

of 10 CFR 54.4(a)(3). The staff reviewed the USAR and found that uninsulated ground 

conductors are not credited in the Davis-Besse design basis. Therefore, the staff concludes 

that the exclusion of uninsulated ground conductors from AMR is acceptable.

The applicant excluded fuse holders from AMR because Davis-Besse fuse holders are either 

part of active electrical panels or are located in circuits that perform no license renewal intended 

function. The applicant made this determination based on a review of Davis-Besse electrical 

drawings, the fuse documentation, and other engineering documents. Based on this 

information, the staff finds that the exclusion of fuse holders from AMR is consistent with 

NUREG-1801, Revision 1, “Generic Aging Lessons Learned Report” (GALL Report) and is, 

therefore, acceptable.

The applicant excluded cable tie-wraps from AMR because cable tie-wraps are not within the 

scope of license renewal at Davis-Besse. The applicant clarified that cables tie-wraps are used 

to bundle wires and cables together to keep the wire and cable runs neat and to restrain cables 

and wires within raceway to facilitate cable installation at Davis-Besse. The applicant stated 

that cable tie-wraps have no current license basis requirements at Davis-Besse; they are not 

required for maintaining cable ampacity, minimum bending radius, or cables within vertical 

raceways; and they are not required for seismic analysis. Based on this information and the 

review of the Davis-Besse USAR, the staff finds that the exclusion of cable-tie wraps from AMR 

is acceptable.

In LRA Section 2.5.6.2, “Station Blackout Recovery Path Evaluation Boundaries,” the applicant 

identified the SBO license renewal offsite power recovery path boundaries and the in-scope 

components for SBO. The Davis-Besse in-scope SBO recovery path boundary drawing is 

provided in LRA Figure 2.5-1.

Regulations in 10 CFR 54.4(a)(3) require that all systems, structures, and components (SSCs) 

relied on in safety analyses or plant evaluations to perform a function that demonstrates 

compliance with NRC regulations for SBO (10 CFR 50.63) be included within the scope of 

license renewal. SRP-LR Section 2.5.2.1.1 provides the guidance to identify electrical and I&C 

systems components that are relied upon to meet the requirements of the SBO Rule for license 

renewal. This includes equipment that is required to cope with an SBO (e.g., alternate ac power 

sources) meeting the requirements in 10 CFR 54.4(a)(3) and the plant system portion of the 

offsite power system, including 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, that is used to 

connect the plant to the offsite power source. In addition, General Design Criteria 17 of 

10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities,” Appendix A, 

“General Design Criteria for Nuclear Power Plants,” 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. SSCs that are 

relied upon to meet the requirements of the SBO Rule in both circuits are to be included within 

the scope of license renewal.
Structures and Components

2-6

By letters dated September 20, 2013 (LRA Amendment 46), and June 23, 2014 (LRA 

Amendment 50), the applicant provided annual updates of the LRA that include revisions to 

Section 2.5. The revisions summarized changes to the Davis Besse switchyard that affect the 

in-scope components in the SBO power recovery path.

In LRA Amendment 46, the applicant stated that the Davis-Besse switchyard was reconfigured 

to facilitate breaker maintenance by extending the J (East) and K (West) buses, adding two new 

345 kV breakers, and removing existing disconnect ABS34625. Specifically, the two new 

345 kV breakers are connected on either side of the new location of the Ohio Edison line, with 

one breaker between the Ohio Edison line and the J Bus and one breaker between the Ohio 

Edison line and the K Bus. The applicant also stated that the new switchyard configuration will 

enable the buses to be maintained under maintenance or outage conditions, resolving concerns 

regarding power interruption and short outage duration time limits imposed during line or 

breaker maintenance activities. This configuration change provides greater operational 

flexibility, power transfer capability, and less operational risk. As a result of the switchyard 

reconfiguration, the applicant revised the last two paragraphs of LRA Section 2.5.6.2, LRA 

Figure 2.5-1, and LRA Table A-1, “Davis-Besse License Renewal Commitments.”

In LRA Amendment 50, the applicant stated that the Davis-Besse switchyard was reconfigured 

to install a fourth 345-kV transmission line, the “Hayes Line,” to relocate the Ohio Edison line 

and rename it as the “Beaver Tower C” line, and to add a new 345 kV circuit breaker (81-B-65). 

The Beaver Tower C line is now connected between the new circuit breaker 81-B-65 and 

existing circuit breaker ACB34564. The applicant also stated that new foundation was added to 

the Davis-Besse switchyard to support the new breaker and associated structures. As a result, 

the applicant provided a second revision to the second to last paragraph of LRA Section 2.5.6.2 

and LRA Figure 2.5-1.

During the review of LRA Amendment 50, the staff noted that Davis-Besse relies on an SBO 

diesel generator (SBODG) system to satisfy the 10 CFR 54.4(a)(3) scoping criteria for the SBO 

regulated event. The applicant evaluated the in-scope mechanical components of the SBODG 

system in LRA Section 2.3 and the in-scope structural items (SBODG building) in LRA

Section 2.4. However, the applicant neither evaluated the in-scope electrical components of the 

SBODG in LRA Section 2.5 nor included the SBODG in LRA Figure 2.5-1. By letter dated 

August 19, 2014, the staff issued RAI 2.5.6.2a, requesting the applicant to provide the scoping 

and screening results of SBODG system electrical components and revise LRA Figure 2.5-1.

In its response letter dated September 16, 2014, the applicant provided LRA Amendment 53 

including an update to LRA Figure 2.5-1 and the first two paragraphs of LRA Section 2.5.6.2. 

The applicant stated that the emergency diesel generators (EDGs) systems are safety-related 

systems that perform license renewal intended functions meeting the requirements under 

10 CFR 54.4(a)(1); therefore, LRA Section 2.5.6.2 is revised to state that the cable and 

connectors from the EDGs and SBODG systems provide connection to the onsite power system 

meeting the requirements of 10 CFR 54.4. The applicant included the cable and connectors 

from the SBODG and EDGs systems in the commodity groups subject to an AMR and added 

the SBODG and the EDGs to the SBO offsite power recovery path in LRA Figure 2.5-1.

No change was required for LRA Table 2.5-1 since no new components types were added.

The revised paragraphs in LRA Section 2.5.6.2 and the revised LRA Figure 2.5-1 supersede 

those in the original LRA. In the revised LRA Section 2.5.6.2, the applicant included within the 

scope of license renewal all components starting from transmission line circuit breakers 

ACB34560, ACB34561, ACB34562, ACB34563, ACB34564, 81-B-65, 81-B-66, 81-B-67 
Structures and Components

2-7

supplying the startup transformers 01 and 02 down to the 4.16 kV essential buses “C1” and “D1” 

and all components from and including the SBODG to the 4.16 kV essential buses “C1” and 

“D1.” The startup transformers 01 and 02 provide the in-scope power pathways into the plant 

and to the safety buses. As shown in revised LRA Figure 2.5-1, the startup transformers 01 and 

02 step down the voltage from 345 kV to 13.8 kV to supply the 13.8 kV switchgear buses “A” 

and “B”, then the bus-tie transformers “AC” and “BD” step down the voltage from 13.8 kV to 

4.16 kV to supply the 4.16 kV essential buses “C1” and “D1” through the 4.16 kV switchgear 

buses “C2” and “D2.” The circuit from the SBODG to the 4.16 kV essential buses “C1” and “D1” 

is through the 4.16 kV switchgear buses “D3” and “D2.”

The switchyard 345 kV “J” and “K” buses and connections, the transmission conductors and 

connections, high-voltage insulators, and the control circuits and protective relays for the 

switchyard circuit breakers (and the equipment associated with the “J” and “K” buses) are within 

the scope of license renewal. The applicant stated that the in-scope structural items (towers 

and foundations) and the switchyard relay house (where the switchyard control circuits and 

relays located) are evaluated in LRA Section 2.4. Components that are subject to AMR are 

included in LRA Table 2.5-1.

Based on the review of this information and the Davis-Besse USAR, the staff concludes that the 

scoping is consistent with the guidance in SRP-LR Section 2.5.2.1.1. The staff’s concern 

described in RAI 2.5.6.2a is resolved.

In LRA Section 2.5.5, “Electrical and I&C Component Commodity Groups Requiring an Aging 

Management Review,” the applicant evaluated the electrical and I&C component commodity 

groups that require AMR. These commodity groups are listed in LRA Table 2.5-1 along with 

their intended functions. The staff reviewed the commodity groups and did not identify any 

omissions of components from those that are subject to an AMR.

2.5.1.3 Conclusion

The staff reviewed the LRA Section 2.5, LRA Amendments 46, 50, and 53, and Davis-Besse 

USAR to determine whether the applicant identified all SSCs within the scope of license renewal 

and to determine whether the applicant had identified all components subject to an AMR. On 

the basis of its review, the staff concludes that the applicant adequately identified the electrical 

and I&C systems 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).

3-1

SECTION 3

AGING MANAGEMENT REVIEW RESULTS

3.0 Applicant’s Use of the Generic Aging Lessons Learned (GALL) Report

3.0.3 Aging Management Programs (AMPs)

3.0.3.1 AMPs Consistent with the GALL Report

3.0.3.1.8 Flow-Accelerated Corrosion Program

Summary of Technical Information in the Application. In response to a steam line failure event 

in May 2015, the applicant provided supplemental operating experience information in LRA 

Amendment 58, by letter dated June 12, 2015. Based on issues identified during its 

investigation into the steam line failure event, the applicant revised LRA Table A-1 to include 

new license renewal Commitment No. 55 to improve and maintain the fidelity of the data in the 

Flow-Accelerated Corrosion Program.

Staff Evaluation. There are no changes or updates to this section of the SER.

Operating Experience. By letter dated June 12, 2015, the applicant revised LRA

Section B.2.19, as a result of its investigation and corrective actions related to a steam line 

failure in May 2015. The applicant clarified that the corrective actions associated with an earlier 

steam leak in 2006 had enhanced the program by providing second level verification of 

CHECWORKSTM data to improve the software model quality, had focused on single-phase and 

two-phase flow aspects and did not include flow orifice input parameter verification. The steam 

line failure in 2015 was attributed to a data entry error in the CHECWORKSTM model for the 

restricting orifice, immediately upstream of the failed elbow. The applicant determined that the 

input error occurred during the original computer model development in the late 1980s and 

resulted in a nonconservative wear rate prediction from the inception of the Flow-Accelerated 

Corrosion Program. Corrective actions from this event included verifying all critical design 

inputs to the current CHECWORKSTM models, enhancing documentation requirements for 

changes to CHECWORKSTM models, and updating procedures for evaluating known 

accelerated wear rate configurations.

Based on its audit and review of the application, as modified on June 12, 2015, the staff finds 

that operating experience related to the applicant’s program demonstrates that implementation 

of the program has resulted in the applicant taking appropriate corrective actions and that it can 

adequately manage the detrimental effects of aging within the scope of the program. 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.

USAR Supplement. Although the applicant did not revise the USAR supplement in LRA 

Amendment 58, the staff notes that in commitment 55 the applicant committed to performing

several actions to improve and maintain the fidelity of the data in the Flow-Accelerated 

Corrosion Program, in response to the steam failure event in May 2015 and the resulting Root 

Cause Evaluation Corrective Actions. The applicant will review and validate the data inputs and 
Aging Management Review Results

3-2

will create and maintain a document of the validation results as a quality record. The applicant 

committed to implementing these actions prior to October 22, 2016. The staff determined that 

the previous information in the USAR supplement continues to be an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. There are no changes or updates to this section of the SER.

3.0.3.1.10 Inservice Inspection (ISI) Program—IWE

Summary of Technical Information in the Application. The applicant provided additional 

information related to the Inservice Inspection (ISI) Program—IWE after the issuance of the 

SER. By letter dated June 23, 2014, the applicant stated that, during the Cycle 18 

(Spring 2014) refueling outage, FENOC performed core bores to access the inside surface of 

the embedded steel containment vessel (SCV) described in Phase 1 of Commitment No. 39 

related to addressing the potential for borated water degradation of the steel containment. The 

applicant also stated that there was no evidence of the presence of borated water in the 

concrete or in contact with the SCV, and the ultrasonic testing (UT) thickness measurement of 

the SCV performed at that location indicated that the thickness was above the nominal value of 

1.5 inches. The applicant further stated that the compressive strength of the core samples 

tested was above design values and no aging effects were identified that required entry into the 

Corrective Action Program. The applicant also stated that it completed Phase 1 of Commitment 

No. 35, with acceptable results.

Staff Evaluation. The staff evaluated the core bore results of Phase 1 of Commitment No. 39 

and noted that there was no evidence of the presence of borated water in the concrete or 

degradation of the inaccessible portion of the SCV due to borated water at the locations of the 

core bores. Therefore, the staff determines that its plan to impose a license condition 

associated with Commitment No. 39, as described in SER Section 3.0.3.1.10 (pages 3-47),

dated September 2013, is not necessary and is deleted from this section of the SER.

Operating Experience. There are no changes or updates to this section of the SER.

USAR Supplement. LRA Section A.1.22 provides the USAR supplement for the ISI Program—

IWE. The staff reviewed this USAR supplement description of the program and noted that it 

conforms to the recommended description for this type of program, as described in SRP-LR,

Table 3.5-2. The staff also noted that, by letter dated June 23, 2014, the applicant amended the 

LRA to state that it completed Phase 1 of Commitment Nos. 35 and 39. The staff determined 

that the information in the USAR supplement, as amended, is an adequate summary description 

of the program, as required by 10 CFR 54.21(d).

Conclusion. There are no changes or updates to this section of the SER.

3.0.3.1.18 Steam Generator Tube Integrity Program

Summary of Technical Information in the Application. LRA Section B.2.38 describes the 

existing Steam Generator Tube Integrity Program as consistent with GALL Report AMP XI.M19, 

“Steam Generators.” The applicant stated that the Steam Generator Tube Integrity Program is 

credited for aging management of cracking, denting, loss of material, and reduction in heat 

transfer of the steam generator (SG) tubes, as well as cracking of tube plugs and tube support 

plates. The applicant further stated that the Steam Generator Tube Integrity Program is 

performed as part of the overall Steam Generator Management Program; the program is based 

on technical specifications (TS) requirements, and the program is implemented in accordance 
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3-3

with Nuclear Energy Institute (NEI) 97-06, “Steam Generator Program Guidelines.” The 

applicant further stated that the Steam Generator Tube Integrity Program includes 

secondary-side examinations to assist in the verification of tube integrity and the condition of the 

tube support plates. Additionally, the applicant stated that the Steam Generator Tube Integrity 

Program is a combination condition monitoring and mitigation program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine if they are bounded by 

the conditions for which the GALL Report was evaluated. The staff compared elements one 

through six of the applicant’s program to the corresponding elements of GALL Report

AMP XI.M19. As discussed in the Audit Report, the staff confirmed that these elements are 

consistent with the corresponding elements of GALL Report AMP XI.M19. Based on its audit, 

the staff finds that elements one through six of the applicant’s Steam Generator Tube Integrity 

Program are consistent with the corresponding program elements of GALL AMP XI.M19 and

are, therefore, acceptable.

Operating Experience. LRA Section B.2.38 summarizes operating experience related to the 

Steam Generator Tube Integrity Program. The staff reviewed this information and interviewed 

the applicant’s technical personnel to confirm that the applicable aging effects and industry and 

plant-specific operating experience have been reviewed by the applicant and are evaluated in 

the GALL Report. During the audit, the staff independently confirmed that the applicant 

adequately incorporated and evaluated operating experience related to this program.

The applicant stated that, during each refueling outage (RFO), SG degradation assessments

are performed in accordance with the provisions of NEI 97-06, “Steam Generator Program 

Guidelines,” dated August 2005 and the Electric Power Research Institute (EPRI) pressurized 

water reactor (PWR) SG examination guidelines. These industry guidelines are based, in part,

on operating experience and inspection results from other operating PWRs. Degradation 

assessment topics include SG tube degradation mechanisms, inspection and expansion 

requirements, tube repair criteria, structural limits, guidelines for testing, and chemical cleaning 

provisions.

The Davis-Besse original SGs were replaced during the Cycle 18 refueling outage 

(Spring 2014). The applicant stated that the nuclear station is currently in the first cycle of 

operation following SG replacement and has no identified tube degradation mechanisms.

The staff reviewed operating experience information, in the application and during the audit, to 

determine if the applicable aging effects and industry and plant-specific operating experience 

were reviewed by the applicant and are evaluated in the GALL Report. As discussed in the 

audit report, the staff conducted an independent search of the plant operating experience 

information to determine if the applicant adequately incorporated and evaluated operating 

experience related to this program. The applicant’s operating experience demonstrates that 

plant-specific and industry acceptable practices are implemented and that the program is able to 

manage the aging effects of cracking, denting, loss of material, and reduction in heat transfer of 

the SG tubes, as well as cracking of tube plugs and tube support plates. During its review, the 

staff found no operating experience to indicate that the applicant’s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that operating experience related 

to the applicant’s program demonstrates that it can adequately manage the detrimental effects 

of aging within the scope of the program and that implementation of the program has resulted in 
Aging Management Review Results

3-4

the applicant taking appropriate corrective actions. The staff confirmed that the “operating 

experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10; therefore, the 

staff finds it acceptable.

USAR Supplement. LRA Section A.1.38 provides the USAR supplement for the Steam 

Generator Tube Integrity Program. The staff reviewed this USAR supplement description of the 

program and noted that it conforms to the recommended description for this type of program, as 

described in SRP-LR Table 3.1-2. The staff determined that the information in the USAR 

supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant’s Steam Generator Tube Integrity 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will remain consistent with the current licensing basis (CLB) for 

the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed 

the USAR 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

3.0.3.2.1 Aboveground Steel Tanks Inspection Program

Summary of Technical Information in the Application. LRA Section B.2.2 describes the existing 

Aboveground Steel Tanks Inspection Program as consistent, with enhancements, with 

GALL Report AMP XI.M29, “Aboveground Steel Tanks.” Subsequent to the submittal of the 

LRA, the staff issued LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water 

Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation,” which revised several 

AMPs, including the guidance for AMP XI.M29. By letter dated February 19, 2014, the applicant 

revised LRA Section B.2.2 in its entirety, based on its review of LR-ISG-2012-02 AMP XI.M29. 

The description of the applicant’s revised program and the staff’s evaluation of the applicant’s 

revised AMP are discussed below.

In a letter dated February 19, 2014, the applicant described its amended Aboveground Steel 

Tanks Inspection Program as an existing program that, with enhancements, will be consistent 

with the GALL Report AMP XI.M29, as revised by LR-ISG-2012-02. The applicant stated that 

the Aboveground Steel Tanks Inspection Program manages the effects of loss of material and 

cracking on the outside and inside surfaces of aboveground tanks constructed on concrete or 

soil. The applicant also stated that the tanks included in the program are the steel diesel fuel oil 

outdoor storage tank, stainless steel borated water outdoor storage tank, and steel condensate 

indoor storage tanks. The applicant further stated that the program is a condition monitoring 

program that consists of periodic visual inspections of tank external surfaces and volumetric 

examinations of tank bottoms. The applicant stated that additional opportunistic tank bottom 

inspections would be performed whenever the tanks are drained. The applicant also stated that 

the program credits coatings or protective paint on external surfaces of steel tanks as a 

preventive measure to mitigate corrosion. In addition, the program relies on periodic 

inspections to monitor degradation of the coatings or protective paint.

Staff Evaluation. The staff noted that the applicant’s amendment placed the fire water storage 

tank in the scope of its Fire Water Program, which is consistent with the staff’s revised 

guidance. The staff’s review of the applicant’s Fire Water Program is discussed in 
Aging Management Review Results

3-5

Section 3.0.3.2.8 of this SSER. The staff also noted that the applicant amended its program to 

include the two indoor condensate steel storage tanks in the scope of its amended 

Aboveground Steel Tanks Inspection Program, which is also consistent with the revised 

guidance in LR-ISG-2012-02.

The staff noted that LRA Section 2.3.3.21 states that the miscellaneous liquid radwaste system 

satisfies the scoping criteria for 10 CFR 54.4(a)(2). The staff also noted that license renewal 

drawing M-037C, “Clean Liquid Radioactive Waste System,” states that the clean waste 

receiver tanks are in scope and have a nominal capacity of 103,000 gallons. During its review 

of the changes to the Aboveground Steel Tanks Program described by the applicant’s letter 

dated February 19, 2014, the staff noted that the clean waste receiver tanks may meet the 

revised guidance but were not included in the scope of the program. By letter dated, 

July 7, 2014, the staff issued RAI 3.0.3.4.3-1, requesting that the applicant state whether the 

clean waste receiver tanks should be in the scope of LR-ISG-2012-02, AMP XI.M29. The staff 

requested that the applicant: (a) revise the program to include the clean water receiver tanks or 

(b) state the basis for why it is not necessary to include these tanks in the scope of the 

Aboveground Steel Tanks Inspection Program, and (c) state whether there are other indoor 

tanks that should be within the scope of the Aboveground Steel Tanks Inspection Program.

In its response dated July 29, 2014, the applicant stated that the top of the clean waste receiver 

tanks have a design pressure of 15 psig. The applicant further stated that because these indoor 

tanks have a design pressure above atmospheric, they are not within the scope of its 

Aboveground Steel Tanks Inspection Program. The staff finds the applicant’s response to 

RAI 3.0.3.4.3-1 acceptable because the clean waste receiver tanks do not meet the scoping 

criteria to be included within the applicant’s Aboveground Steel Tanks Inspection Program. 

The staff noted that the scoping criteria of GALL Report AMP XI.M29, as revised by 

LR-ISG-2012-02, requires that indoor tanks that have a storage capacity greater than 

100,000 gallons, and a design pressure near atmospheric, be included within the scope of the 

program. The staff also noted that LRA Table 3.3.1, item 3.3.1-91, addresses stainless steel 

and steel with stainless steel cladding, piping, piping components, and piping elements exposed 

to treated borated water, which are being managed for loss of material due to pitting and crevice 

corrosion. The staff further noted that the applicant also applies this item to the clean waste 

receiver tanks; therefore, these components, although not within the scope of the Aboveground 

Steel Tanks Inspection Program, will be managed for aging. The staff’s evaluation of 

components associated with item 3.3.1-91 is discussed in SER Section 3.3.2.1.24. The staff’s 

concerns described in RAI 3.0.3.4.3-1 are resolved.

During the audit, the staff noted that the borated water storage tank (BWST) is insulated and is 

located in an environment that could result in stress corrosion cracking (SCC) of the stainless 

steel tank (e.g., located within 1/2 mile of a salt-treated highway, or other sources of chlorides). 

The staff also noted that the applicant’s response to RAI B.2.2-2, dated May 24, 2011, states 

that: “(a) the outdoor air environment could result in an AERM for the BWST; (b) the 

polyurethane foam insulation installed on the BWST is limited to leach less than 1000 ppm 

chlorides; and (c) the Aboveground Steel Tanks Inspection Program was revised to manage 

SCC for the BWST.”

Based on its review of Licensee Event Report No. 346-1982-001, Rev. 2, dated 

October 11, 1984, the staff noted that the insulation for the BWST was added a number of years 

after the plant was placed in service. The staff also noted that Regulatory Guide (RG) 1.36, 

“Nonmetallic Thermal Insulation for Austenitic Stainless Steel,” Figure 1, recommends an upper 

limit of chlorides and fluorides dependent on the sodium and silicate content of the insulation. 
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Based on the applicant’s response to RAI B.2.2-2 in relation to the chloride content of the 

insulation, the staff does not have adequate information to conclude that the leachable chlorides 

and fluorides from the BWST insulation, coupled with possible chloride contaminants present 

prior to the application of the insulation, would not result in SCC.

In addition, the insulation appears to be that which could be described as tightly adhering 

insulation. LR-ISG-2012-02 AMP XI.M29 does not require removal of tightly adhering insulation 

unless there is evidence of damage to the moisture barrier. The revised Aboveground Steel 

Tanks Inspection Program does not include inspections related to corrosion under insulation. It 

is not clear to the staff whether the inspections related to corrosion under insulation in the 

External Surfaces Monitoring Program include inspections of the BWST insulation. The number 

and periodicity of inspections in LR-ISG-2012-02 AMP XI.M29 are generally in alignment with 

those for LR-ISG-2012-02 AMP XI.M36, “External Surfaces Monitoring of Mechanical 

Components”; however, the recommended inspection locations are different. The staff needed

clarification on the specific inspections and periodicity of inspections, which the applicant will 

use to manage loss of material due to pitting and crevice corrosion, as well as cracking due to 

SCC on the exterior surfaces of the BWST.

By letter dated July 7, 2014, the staff issued RAI 3.0.3.4.3-2, requesting that the applicant do 

the following:

(1) Confirm whether the insulation installed on the BWST is considered as tightly adhering 

insulation and impermeable to moisture.

(2) State whether inspections of the BWST insulation will be conducted under the External 

Surfaces Monitoring Program. If this is the case, state the extent and periodicity of 

inspections, the inspection methods, and how inspection locations will be selected. If no 

inspections will be conducted, state the basis for why there is reasonable assurance that 

the BWST will perform its current licensing-basis intended functions during the period of 

extended operation.

(3) State whether visual and surface examinations sufficient to detect loss of material due to 

pitting and crevice corrosion, and cracking were conducted on the external surfaces of 

the BWST prior to installing the insulation. If they were not conducted, state the basis 

for why bare metal inspections would not have to be conducted prior to the period of 

extended operation.

(4) Provide a summary of plant-specific operating experience related to the integrity of the 

BWST insulation. If there have been instances of damage to the insulation such that 

moisture could have penetrated to the surface of the BWST, state what inspections have 

been conducted on the bare metal surfaces of the tank. If none were conducted, state 

the basis for why bare metal inspections would not have to be conducted prior to the 

period of extended operation.

By letter dated July 29, 2014, the applicant provided its response to RAI 3.0.3.4.3-2. In its 

response to Part 1 of RAI 3.0.3.4.3-2, the applicant stated that the exterior accessible surfaces 

of the tank are painted and, with the exception of the roof, some nozzles, and the bottom, also 

insulated. The applicant also stated that the insulation for the BWST consists of multiple layers 

of coating and insulation; therefore, it is considered tightly adhering and impermeable to 

moisture. 
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The staff finds the applicant’s response to RAI 3.0.3.4.3-2, Part 1, acceptable because the 

applicant clarified that the insulation for the BWST is considered tightly adhering and 

impermeable to moisture penetration. The staff’s concerns described in RAI 3.0.3.4.3-2, Part 1,

are resolved.

In its response to Part 2 of RAI 3.0.3.4.3-2, the applicant stated that the Aboveground Steel 

Tanks Inspection Program would be used to inspect the insulation for the BWST. The applicant 

also stated that the inspection periodicity, methods, and locations would be consistent with the 

GALL Report AMP XI.M29, as revised by LR-ISG-2012-02. As part of its response, the 

applicant revised LRA Sections A.1.2, B.2.2, and LRA Table A-1 accordingly. The staff finds the 

applicant’s response to RAI 3.0.3.4.3-2, Part 2, acceptable because the applicant revised the 

Aboveground Steel Tanks Inspection Program to specifically include inspections for the exterior 

surfaces of the insulation for the BWST, consistent with the staff’s revised guidance for 

GALL Report AMP XI.M29. The staff’s concerns described in RAI 3.0.3.4.3-2, Part 2, are 

resolved.

In its response to Part 3 of RAI 3.0.3.4.3-2, the applicant stated that it could not locate any 

documentation that confirmed whether any surface inspections were conducted on the BWST 

prior to the application of the insulation, which could detect loss of material due to pitting, 

cracking, and crevice corrosion. The applicant also stated that the Aboveground Steel Tanks 

Inspection Program will be enhanced to specifically include bare metal inspection of the BWST 

exterior surfaces prior to the period of extended operation. As part of its response, the applicant 

revised LRA Sections A.1.2, B.2.2, and LRA Table A-1 accordingly. The staff finds the 

applicant’s response to RAI 3.0.3.4.3-2, Part 3, acceptable because (a) the applicant revised the 

Aboveground Steel Tanks Inspection Program to specifically include inspections of the exterior 

bare metal surfaces of the BWST for loss of material and cracking and (b) these inspections

would be completed prior to the start of extended operation. The staff’s concerns described in 

RAI 3.0.3.4.3-2, Part 3, are resolved.

In its response to Part 4 of RAI 3.0.3.4.3-2, the applicant stated that a 2011 condition report 

described coating damage to the insulation of the BWST. The applicant also stated that 

120 square feet of the butyl rubber coating was detached (delaminated) from the polyurethane 

foam insulation. The applicant further stated that the insulation was not damaged, and there 

was no evidence of any moisture penetration to the BWST. The applicant stated that there 

were no records to indicate any instances of insulation damage or delamination, or bare metal 

inspections of the BWST. The applicant also restated that, as discussed in its response for 

Part 3 of this RAI, the enhanced Aboveground Steel Tanks Program includes a bare metal 

inspection of the exterior surfaces of the BWST prior to the period of extended operation.

The staff finds the applicant’s response to RAI 3.0.3.4.3-2, Part 4, acceptable because (a) the 

applicant provided the available operating experience related to the insulation for the BWST,

which indicated that there have been no known instances of damage or evidence of moisture 

intrusion or penetration to the foam insulation, (b) the exterior coating applied to the BWST and 

the multilayered nature of the insulation should provide protection against moisture intrusion, 

(c) the exterior surfaces of the insulation will be inspected, and (d) bare metal surface 

examinations performed prior to the period of extended operation will provide confirmation of the 

adequacy of the AMP. The staff’s concerns described in RAI 3.0.3.4.3-2, Part 4, are resolved.

Based on its review of the applicant’s Aboveground Steel Tanks Inspection Program as 

amended by LRA Amendment 48, dated February 19, 2014, and revised by letter dated 

July 29, 2014, response to RAI 3.0.3.4.3-1, and response to RAI 3.0.3.4.3-2, the staff finds that 
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elements one through six of the applicant’s program, with the enhancements, are consistent 

with the corresponding program elements of LR-ISG-2012-02 AMP XI.M29. Therefore, the staff 

finds the applicant’s Aboveground Steel Tanks Inspection Program acceptable.

Operating Experience. The staff does not have any changes or updates to this section of the 

SER.

USAR Supplement. The staff reviewed LRA Section A.1.2, which provides the applicant’s 

USAR supplement for the Aboveground Steel Tanks Inspection Program, as amended by letters 

dated February 19, 2014, and July 29, 2014. The staff reviewed this USAR supplement 

description of the program and noted that it conforms to the recommended description for this 

type of program, as described in LR-ISG-2012-02, Table 3.0-1. The staff also noted that the 

applicant committed (Commitment No. 1) to enhancing the existing Aboveground Steel Tanks 

Inspection Program prior to entering the period of extended operation, in accordance with the 

enhancements described above.

The staff determined that the information in the USAR supplement, as amended, is an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant’s Aboveground Steel Tanks Inspection 

Program, the staff determined 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, through Commitment No. 1, prior to the 

period of extended operation, would make the existing AMP consistent with the GALL Report

AMP, as revised by LR-ISG-2012-02, to which it was compared. The staff concludes that the 

applicant demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) 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 USAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.2.3 Buried Piping and Tanks Inspection Program

Summary of Technical Information in the Application. Subsequent to the submittal of the LRA, 

the staff issued 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.’” By letter dated September 20, 2013, the applicant submitted changes to its Buried 

Piping and Tanks Inspection Program to incorporate the changes recommended in 

LR-ISG-2011-03.

Staff Evaluation. The staff’s evaluation of the changes to the applicant’s Buried Piping and 

Tanks Inspection Program follows.

Extent of Fuel Oil Piping Inspections. By letter dated September 20, 2013, the applicant 

amended the extent of piping inspections (i.e., 2 percent of the buried in-scope piping containing 

hazardous materials) for buried fuel oil piping to address the changes in recommendations 

issued in LR-ISG-2011-03. The applicant stated that the extent of piping inspections will be 

consistent with LR-ISG-2011-03, Table 4a, “Inspections of Buried Pipe.” The staff noted that 

Table 4a recommends the extent of inspections based on the material type and availability and 

effectiveness of preventive actions (i.e., cathodic protection availability and effectiveness, 

coatings, and backfill) and not on the contents of the piping. 
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The staff finds this change acceptable because it is consistent with LR-ISG-2011-03 in regard to 

the extent of piping inspections.

Cathodic Protection Acceptance Criteria. By letter dated September 20, 2013, the applicant 

amended the acceptance criteria for cathodic protection ground surveys to address the changes 

in recommendations issued in LR-ISG-2011-03. As amended, the cathodic protection 

acceptance criteria are negative 850 mV relative to a copper/copper sulfate reference electrode 

(CSE) instant off or negative 100 mV minimum polarization, and limiting the potential to be not 

more negative than 1,200 mV.

The staff noted that LR-ISG-2011-03, Table 6a, “Cathodic Protection Acceptance Criteria,” 

recommends that:

The 100 mV polarization criterion is limited to electrically isolated piping sections

or areas of grounded piping where the effects of mixed potentials are shown to 

be minimal. When the 100 mV criterion is utilized in lieu of the - 850 mV CSE 

criterion for steel piping, or where copper or aluminum components are 

protected, 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.

In addition, Table 6a recommends that polarized potentials not be greater than 

negative 1,200 mV to avoid potentially detrimental effects (e.g., coating disbondment) 

associated with excessive overprotection. By letter dated February 11, 2014, the staff issued 

RAI 2011-03-1, requesting that the applicant state the basis for use of the negative 100 mV 

minimum polarization criterion.

In its response dated March 11, 2014, the applicant stated that the negative 100 mV minimum 

polarization criterion is applied to the manways and vents located at the top of the two EDG fuel 

oil storage tanks. The tanks are installed above grade elevation with tornado missile protection 

provided by a truncated pyramid of structural backfill built around the tanks (mound-buried). 

The negative 850 mV polarized potential criterion is being met at all locations except the top of 

the mound, which is approximately 13 feet above grade. At all other locations that are 

cathodically protected, the negative 850 mV polarized potential instant off acceptance criterion 

will be applied. To ensure that the man ways and vents at the top of the mound over the EDG 

fuel oil storage tanks are not degrading due to the lower polarization criterion, UT thickness 

measurements will be performed prior to entering the period of extended operation and every 

10 years during the period of extended operation to ensure that the metal thickness in those 

areas remains satisfactory.

The staff noted that the applicant revised LRA Section B.2.7 and Commitment No. 3 to reflect 

the above changes.

The staff finds the applicant’s response acceptable because, in the locations where the 

negative 100 mV polarization will be used, the applicant will periodically confirm that the 

cathodic protection is providing effective protection by volumetric wall thickness measurements. 

These inspections will provide a direct indication that the effects of mixed potentials have been 

minimal and that, therefore, the program will be consistent with LR-ISG-2011-03. The staff’s 

concern described in RAI 2011-03-1 is resolved. The staff also finds the applicant’s cathodic 

protection acceptance criteria acceptable because they are consistent with LR-ISG-2011-03, 

ensuring that the effectiveness of the cathodic protection system can be determined.
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Sample Size Expansion Criteria. By letter dated September 20, 2013, the applicant amended 

the sample size expansion criteria to address the changes in recommendations issued in 

LR-ISG-2011-03. The applicant added a requirement that, if adverse indications are detected, 

the inspection sample sizes, within the affected piping categories, are initially doubled, and if 

adverse conditions are discovered in the expanded sample, the size of the follow-on inspections 

is determined by establishing the extent of condition and extent of cause. The applicant stated 

that scheduling of additional examinations will be based on the severity of the degradation 

identified and commensurate with the consequences of a leak or loss of function, but in all 

cases, the expanded sample inspection will be completed within the 10-year interval in which 

the original adverse indication was identified. The staff finds this change acceptable because it 

is consistent with LR-ISG-2011-03 in regard to the extent of piping inspections, ensuring that an 

appropriate number of additional inspections will be conducted when adverse conditions are 

detected.

Changes in Classification of Piping. Prior to issuance of LR-ISG-2011-03, GALL Report

AMP XI.M41 recommended that the number of inspections to be conducted for a specific 

material of buried in-scope piping was, in part, based on its contents and function (i.e., code 

class, safety-related, contains hazardous materials) under the “detection of aging effects” 

program element description. In its response to RAI B.2.7-1(12) dated May 24, 2011, the 

applicant stated that the components cited in LRA Table 3.3.2-12, row 102, have an internal 

environment of fuel oil. However, LR-ISG-2011-03, as stated in Table 4a, bases the extent of 

the inspection recommendations on the material type and availability and effectiveness of 

preventive actions (i.e., cathodic protection availability and effectiveness, coatings, and backfill) 

and not on the contents of the piping. Therefore, the response to RAI B.2.7-1(12) is no longer 

technically relevant. As stated above, in subsection Extent of Fuel Oil Piping Inspections, the 

applicant’s extent of inspections related to buried fuel oil piping is appropriately based on 

Table 4a of LR-ISG-2011-03.

Underground Piping Volumetric Inspections. By letter dated September 20, 2013, the applicant 

amended the underground inspection requirements of its program to address the changes in 

recommendations issued in LR-ISG-2011-03. The applicant stated that volumetric inspections 

of underground piping will not be conducted. The staff noted that the recommendation to 

perform volumetric examinations of underground piping was removed from the scope of 

GALL Report AMP XI.M41 by LR-ISG-2011-03 because the purpose of volumetric examinations 

is to detect aging effects occurring on the internal surfaces of the piping, whereas the purpose 

of AMP XI.M41 is to manage aging effects associated with the external surfaces of the 

components. In a prior response dated May 24, 2011, the applicant had amended its program 

to include visual inspections of the external surfaces of in-scope underground piping. The staff 

finds this change acceptable because conducting visual examinations of the external surfaces 

of in-scope underground piping is consistent with LR-ISG-2011-03.

The applicant amended Enhancement No. 2 and added 12 new enhancements, Enhancement

Nos. 3 through 14.

Enhancement 2. By letter dated September 20, 2013, the applicant amended Enhancement

No. 2. The applicant stated that the extent of piping inspections will be consistent with 

LR-ISG-2011-03, Table 4a, “Inspections of Buried Pipe.” Table 4a recommends the extent of 

inspections be based on the material type and condition of preventive actions (i.e., cathodic 

protection availability and effectiveness, coatings, and backfill). On the basis of its review, the 

staff finds the applicant’s change to Enhancement No. 2 acceptable because, when it is 
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implemented prior to the period of extended operation, it will make the program’s extent of 

inspections consistent with the recommendations in LR-ISG-2011-03.

Enhancement 3. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “parameters monitored or inspected” program element. The applicant 

stated that it will conduct annual potential surveys of the cathodic protection system. The 

applicant also stated that the cathodic protection voltage and current will be monitored monthly. 

The applicant further stated that voltage, current, and ground potential readings will be trended 

and evaluated for adverse trends. On the basis of its review, the staff finds the applicant’s 

enhancement acceptable because, when it is implemented prior to the period of extended 

operation, it will make the program consistent with the recommendations in LR-ISG-2011-03, 

and because the proposed parameters and frequency of testing will be sufficient to demonstrate 

the availability and effectiveness of the cathodic protection system.

Enhancement 4. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “detection of aging effects” program element. The applicant stated that it 

will monitor the activity of the jockey pump or equivalent parameter on at least a monthly 

interval. The applicant also stated that, when unresolved changes in jockey pump activity are 

observed, a flow test will be conducted by the end of the next refueling outage. On the basis of 

its review, the staff finds the applicant’s enhancement acceptable because, when it is 

implemented prior to the period of extended operation, it will make the program consistent with 

the recommendations in LR-ISG-2011-03, and the proposed monitoring and followup testing will 

be effective at detecting leakage in buried fire protection piping.

Enhancement 5. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “detection of aging effects” program element. The applicant stated that it 

will select buried pipe inspection locations based on risk. On the basis of its review, the staff 

finds the applicant’s enhancement acceptable because, when it is implemented prior to the 

period of extended operation, it will make the program consistent with the recommendations in 

LR-ISG-2011-03, and inspections of the highest risk locations will ensure that the most critical 

piping locations are inspected.

Enhancement 6. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “detection of aging effects” program element. The applicant added a 

requirement to inspect the EDG fuel oil storage tanks prior to the period of extended operation. 

The applicant stated that the inspection will be either (a) a visual inspection of at least 

25 percent of each tank and include at least some portion of the tank top and bottom, or (b) an 

internal inspection consisting of UT measurements with at least one measurement per square 

foot of the surface of the tanks. The applicant also stated that these inspections are not 

required if it is demonstrated that the tanks are cathodically protected in accordance with 

National Association of Corrosion Engineers (NACE) SP0169-2007, “Control of External 

Corrosion on Underground or Submerged Metallic Piping Systems,” or NACE RP0285-2002, 

“Corrosion Control of Underground Storage Tank Systems by Cathodic Protection.” In addition, 

as described above in the response to RAI 2011-03-1, the applicant amended this enhancement 

to include the UT measurements of the man ways and vents for the EDG fuel oil storage tanks.

The staff noted that the applicant has committed (Commitment No. 44) to cathodically protecting

the EDG fuel oil storage tanks prior to entering the period of extended operation. The staff also 

noted that LR-ISG-2011-03, Table 4c, “Inspections of Buried Tanks for all Inspection Periods,” 

recommends that tank inspections not be required if the tank is cathodically protected in 

accordance with certain provisions of footnote 3 of the Table. However, in the event that the 
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tanks are not cathodically protected (due to a future commitment change), the staff considers 

the incorporation of the Table 4c inspections into the commitment necessary to ensure that 

aging will be managed throughout the period of extended operation. By letter dated 

February 11, 2014, the staff issued RAI 2011-03-2, requesting that the applicant revise 

Enhancement No. 6 to require that, if cathodic protection is not provided, tank inspections meet 

the recommendations of Table 4c, or state the basis for why tank inspections would not be 

required during the period of extended operation.

In its response dated March 11, 2014, the applicant stated that cathodic protection was installed 

and has been operational for the in-scope buried EDG fuel oil storage tanks and associated fuel 

oil supply piping from the storage tanks to the EDGs in the auxiliary building since April 2012. In 

addition, the buried service water system piping and diesel fuel oil piping from the aboveground 

diesel oil storage tank to the auxiliary building have been cathodically protected. As such, the 

applicant stated that it completed Commitment No. 44.

The staff noted that the applicant revised LRA Section B.2.7 and Commitment No. 3 to state 

that, if the cathodic protection system for the EDG fuel oil storage tanks meets the availability 

criteria in Table 4c., inspections would not need to be conducted. Otherwise, inspections will be 

performed in accordance with Table 4c.

The staff finds the applicant’s response, closure of Commitment No. 44, and enhancement 

acceptable because cathodic protection has been installed as committed and the tank 

inspections will be conducted if the cathodic protection system does not meet the availability 

and effectiveness goals described in the footnotes to Table 4c. The staff’s concern described in 

RAI 2011-03-2 is resolved.

Enhancement 7. As amended by letters dated May 24, 2011, and September 20, 2013, LRA

Section B.2.7 states an enhancement to the “detection of aging effects” program element. The 

applicant stated that it will conduct a visual inspection of the underground piping within the 

borated water piping trench during each 10-year period, beginning no sooner than 10 years 

prior to entry into the period of extended operation. On the basis of its review, the staff finds the 

applicant’s enhancement acceptable because, when it is implemented prior to the period of 

extended operation, it will make the program consistent with the recommendations in 

LR-ISG-2011-03, Table 4b, “Inspections of Underground Piping for all Inspection Periods,” and 

visual inspections of underground pipe can detect the loss of material and cracking on the 

external piping surfaces.

Enhancement 8. As amended by letters dated May 24, 2011, and September 20, 2013, LRA

Section B.2.7 states an enhancement to the “detection of aging effects” program element. The 

applicant stated that, if adverse conditions are detected, it will conduct inspection sample-size 

expansions as quoted above in the response to RAI B.2.7-1(10). On the basis of its review, the 

staff finds the applicant’s enhancement acceptable because, when it is implemented prior to the 

period of extended operation, the inspection sample-size expansion criteria will be consistent 

with LR-ISG-2011-03 and will ensure that an appropriate number of additional inspections will 

be conducted when adverse conditions are detected.

Enhancement 9. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “detection of aging effects” program element. The applicant stated that it 

will conduct inspections of buried fire protection system bolting when the bolting becomes 

accessible during opportunistic or focused inspections. On the basis of its review, the staff finds 

the applicant’s enhancement acceptable because, when it is implemented prior to the period of 
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extended operation, it will be consistent with the “scope of program” element of 

LR-ISG-2011-03, which states that the program manages loss of material due to corrosion of 

buried piping system bolting.

Enhancement 10. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “detection of aging effects” program element. The applicant stated that it 

will conduct inspections of buried piping using visual (VT-3 or equivalent) inspection methods,

and the inspections will encompass a minimum of 10 linear feet of piping, with all surfaces of the 

pipe exposed. On the basis of its review, the staff finds the applicant’s enhancement 

acceptable because, when it is implemented prior to the period of extended operation, it will be 

consistent with LR-ISG-2011-03 and will ensure that visual examinations are conducted on a 

sufficiently lengthy segment of piping in order to detect degradation such as damage to coatings 

or loss of material.

Enhancement 11. As amended by letters dated May 24, 2011, September 20, 2013, and 

March 11, 2014, LRA Section B.2.7 states an enhancement to the “acceptance criteria” program 

element. The applicant stated that the acceptance criteria for the cathodic protection system 

performance will be as stated above in the response to RAIs B.2.7-1(3) and 2011-03-1. On the 

basis of its review, the staff finds the applicant’s enhancement acceptable because, when it is 

implemented prior to the period of extended operation, the cathodic protection acceptance 

criteria will be consistent with LR-ISG-2011-03 and will ensure that the effectiveness of the 

cathodic protection system can be determined.

Enhancement 12. As amended by letters dated May 24, 2011, and September 20, 2013, LRA

Section B.2.7 states an enhancement to the “acceptance criteria” program element. The 

applicant stated that:

For coated piping or tanks, there should be either no evidence of coating

degradation or the type and extent of coating degradation should be insignificant 

as evaluated by an individual possessing a NACE Coating Inspector Program 

Level 2 or 3 inspector qualification or an individual has attended the Electric 

Power Research Institute (EPRI) Comprehensive Coatings Course and 

completed the EPRI Buried Pipe Condition Assessment and Repair Training 

Computer Based Training Course. Where damage to the coating has been 

evaluated as significant and the damage was caused by non-conforming backfill, 

an extent of condition evaluation should be conducted to ensure that the as-left 

condition of backfill in the vicinity of observed damage will not lead to further 

degradation.

On the basis of its review, the staff finds the applicant’s enhancement acceptable because, 

when it is implemented prior to the period of extended operation, it will be consistent with 

LR-ISG-2011-03 and will ensure that adverse conditions are evaluated by individuals qualified 

to make effective decisions and that an extent-of-condition evaluation is conducted to determine 

the extent of nonconforming backfill.

Enhancement 13. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “acceptance criteria” program element. The applicant stated that, if metallic 

piping or tanks show evidence of corrosion, the remaining wall thickness in the affected area is 

determined to ensure that the minimum wall thickness is maintained. On the basis of its review, 

the staff finds the applicant’s enhancement acceptable because, when it is implemented prior to 
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the period of extended operation, it will be consistent with LR-ISG-2011-03 and will ensure that 

there is reasonable assurance that loss of material is adequately managed.

Enhancement 14. As amended by letter dated May 24, 2011, LRA Section B.2.7 states an 

enhancement to the “acceptance criteria” program element. The applicant stated that an 

acceptance criterion will be established to state that changes in jockey pump activity 

(e.g., longer run periods, more frequent starts) or equivalent parameters that are attributed to 

leakage from buried piping will not be acceptable. On the basis of its review, the staff finds the 

applicant’s enhancement acceptable because, when it is implemented prior to the period of 

extended operation, it will be consistent with LR-ISG-2011-03, which allows jockey pump 

monitoring, or an equivalent parameter, to be used to demonstrate that buried fire water system 

piping will meet its current licensing-basis intended function(s).

Based on its review of the above changes the staff finds that elements one through six of the 

applicant’s Buried Piping and Tanks Inspection Program, with acceptable enhancements, are 

consistent with the corresponding program elements of LR-ISG-2011-03 and, therefore, are 

acceptable.

Operating Experience. The staff noted that LR-ISG-2011-03 states that a 10-year search of 

plant-specific operating experience should be conducted if cathodic protection is not provided. 

The staff also noted that the applicant has committed (Commitment No. 41) to cathodically 

protecting the EDG fuel oil storage tanks and in-scope fuel oil and service water piping prior to 

entering the period of extended operation. The staff concludes that the applicant’s original 

search of 5 years of plant-specific operating experience is sufficient because cathodic protection 

will be provided for buried in-scope components prior to the period of extended operation.

As addressed in the original SER, by letter dated April 20, 2011, the staff issued RAI B.2.7-1(6),

requesting that the applicant state the basis for having reasonable assurance that the planned 

inspections represent an adequate quantity to identify coating damage and holidays before 

leaks occur. In its response to RAI B.2.7-1(6) dated May 24, 2011, the applicant cited the 

increase in inspections in the time frame from 10 years prior to the period of extended operation 

to the end of extended operation from two to six inspections and that the inspection locations 

will be selected based on previous examination results, trending, risk ranking, and areas of 

cathodic protection failures or gaps as the basis for establishing reasonable assurance that the 

buried in-scope components will meet their current licensing-basis intended functions. As 

amended by letter dated September 20, 2013, the extent of the applicant’s buried pipe 

inspections will instead be consistent with LR-ISG-2011-03, Table 4a., which recommends that 

the extent of inspections be based on the material type and condition of preventive actions 

(i.e., cathodic protection availability and effectiveness, coatings, and backfill). The staff 

continues to find the applicant’s response to RAI B.2.7-1(6) acceptable because the number of 

inspections will be consistent with LR-ISG-2011-03 Table 4a, which states that the number of 

inspections is increased based on the condition of preventive actions (i.e., cathodic protection 

availability and effectiveness, coatings, and backfill).

USAR Supplement. As amended by letter dated September 20, 2013, LRA Section A.1.7 

provides the USAR supplement for the Buried Piping and Tanks Inspection Program. The staff 

reviewed this USAR supplement description of the program and noted that it conforms to the 

recommended description for this type of program, as described in LR-ISG-2011-03, 

Table 3.0-1. The staff determines that the information in the USAR supplement, as amended, is 

an adequate summary description of the program, as required by 10 CFR 54.21(d).
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Conclusion. On the basis of its review of the changes to the applicant’s Buried Piping and 

Tanks Inspection Program, the staff determined that those program elements for which the 

applicant claimed consistency with the GALL Report, as revised by LR-ISG-2011-03, are 

consistent. Also, the staff reviewed the enhancements and confirmed that their implementation, 

through Commitments No. 3 and No. 44, prior to the period of extended operation, would make 

the existing AMP consistent with the GALL Report AMP to which it was compared. The staff 

concludes that the applicant demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) 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 USAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21.

3.0.3.2.5 External Surfaces Monitoring Program

Summary of Technical Information in the Application. Subsequent to the submittal of the LRA, 

the staff issued LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and Corrosion Under Insulation,” which revised GALL Report

AMPs associated with managing loss of material due to corrosion under insulation. By letter 

dated February 19, 2014, the applicant provided the results of its review and changes to the 

LRA associated with the staff’s recommendations in LR-ISG-2012-02 Section E, “Corrosion 

Under Insulation,” and associated appendices. The staff’s evaluation of these changes follows. 

The staff’s evaluation of the applicant’s revisions to its Aboveground Steel Tanks Inspection 

Program to address corrosion under insulation for outdoor tanks is documented in SSER

Section 3.0.3.2.1.

Staff Evaluation. The staff’s evaluation of the changes to the applicant’s External Surfaces 

Monitoring Program follows.

By letter dated February 19, 2014, the applicant revised the program description, and “scope of 

program” element of its External Surfaces Monitoring Program to also state that outdoor 

insulated components, and indoor insulated components exposed to condensation (because the 

in-scope component is operated below the dew point), have portions of the insulation inspected 

or removed to determine whether the exterior surface of the component is degrading or has the 

potential to degrade. The applicant also revised the “detection of aging effects” program 

element to address the selection of sample locations, sample size, method of inspection, and 

frequency of inspections for inspections associated with corrosion under insulation.

The staff finds the applicant’s changes to the External Surfaces Monitoring Program acceptable 

because the details associated with inspection locations, sample size, methodology, and 

frequency are consistent with the staff’s inspection and sampling recommendations of 

AMP XI.M36, as revised by LR-ISG-2012-02.

The staff also reviewed the portions of the “scope of program,” and “detection of aging effects” 

program elements associated with the additional enhancements of the applicant’s program, to 

determine if the program will be adequate to manage the aging effects for which it is credited. 

The staff’s evaluation of these enhancements follows.

Enhancement 7. As amended by letter dated February 19, 2014, LRA Section B.2.15 states an 

enhancement to the “scope of program” program element. 
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The applicant stated that the program will be enhanced to include inspection of outdoor 

insulated components, and indoor insulated components exposed to condensation (because the 

in-scope component is operated below the dew point).

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M36, as modified by LR-ISG-2012-02. On the basis of its review, the staff 

finds this enhancement acceptable because the revised scope is consistent with AMP XI.M36,

as modified by LR-ISG-2012-02.

Enhancement 8. As amended by letter dated February 19, 2014, LRA Section B.2.15 states an 

enhancement to the “detection of aging effects” program element. The applicant stated that the 

program will be enhanced to include details associated with the selection of sample locations, 

sample size, method of inspection, and frequency of inspections to address corrosion under 

insulation.

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M36, as modified by LR-ISG-2012-02. On the basis of its review, the staff 

finds this enhancement acceptable because the revised scope is consistent with AMP XI.M36,

as modified by LR-ISG-2012-02.

Based on its review of the applicant’s letter dated February 19, 2014, the staff finds that 

elements one through six of the applicant’s External Surfaces Monitoring Program are 

consistent with the corresponding program elements of GALL Report AMP XI.M36, as modified 

by LR-ISG-2012-02 and, therefore, are acceptable.

USAR Supplement. As amended by letter dated February 19, 2014, LRA Section A.1.15 

provides the USAR supplement for the External Surfaces Monitoring Program. The staff 

reviewed this USAR supplement description of the program and noted that it conforms to the 

recommended description for this type of program, as described in SRP-LR Table 3.0-1, as 

modified by LR-ISG-2012-02.

The staff determined that the information in the USAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the proposed changes to the External Surfaces 

Monitoring Program, as amended by letter dated February 19, 2014, the staff determined that 

those program elements for which the applicant claimed consistency with AMP XI.M36, as 

revised by LR-ISG-2012-02, are consistent. The staff concludes that the applicant 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) 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 USAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.2.8 Fire Water Program

Summary of Technical Information in the Application. Subsequent to the submittal of the LRA, 

the staff issued LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and Corrosion Under Insulation,” which revised several AMPs,

including the guidance for AMP XI.M27. By letter dated February 19, 2014, (LRA Amendment 

48) the applicant revised LRA Section B.2.18, based on its review of LR-ISG-2012-02 

AMP XI.M27.
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Staff Evaluation. The staff’s evaluation of LRA Amendment 48 is as follows.

Flow Blockage as an Aging Effect. The staff noted that the applicant amended LRA

Table 3.3.2-14 to include flow blockage (in addition to loss of material) as an AERM for multiple 

component types and materials exposed to raw water. The staff finds this acceptable because

the addition of flow blockage as an aging effect is consistent with LR-ISG-2012-02 AMP XI.M27.

Fire Water Storage Tank. The staff noted that the applicant deleted the AMR item for the fire 

water storage tank exposed to outdoor air being managed for loss of material by the 

Aboveground Steel Tanks Inspection Program in LRA Table 3.3.2-14 because aging effects 

associated with this tank will be managed by the Fire Water Program. The staff also noted that, 

as stated in Enhancement No. 5, the applicant will conduct inspections and tests in accordance 

with LR-ISG-2012-02 Table 4a, “Fire Water System Inspection and Testing Recommendations.” 

This table includes inspections of the external surfaces of the fire water storage tank; therefore, 

the staff finds the deletion of the AMR item acceptable.

Followup Wall Thickness Examinations Due to Detection of Surface Irregularities. The staff 

noted that the applicant’s changes to the Fire Water Program did not state whether the internal 

visual inspections used to detect loss of material would be capable of detecting surface 

irregularities that could be indicative of wall loss below nominal pipe wall thickness due to 

corrosion and corrosion product deposition. In addition, the program did not address the actions 

that would be taken if such irregularities are detected. The staff also noted that the Fire Water 

Program did not state what actions would be taken if the presence of sufficient foreign organic 

or inorganic material to obstruct pipe or sprinklers is detected during pipe inspections. By letter 

dated July 7, 2014, the staff issued RAI B.2.18-2 requesting that the applicant state the basis for 

not including the above information in the Fire Water Program,

In its response dated July 29, 2014, the applicant revised the Fire Water Program to include two 

new enhancements (Enhancement Nos. 7 and 8) to address the staff’s concern described in 

RAI B.2.18-2. The staff’s evaluation of these enhancements is described below.

In LRA Amendment 48, the applicant deleted Enhancement Nos. 1, 2, and 4, amended 

Enhancement No. 3, and added Enhancement Nos. 5 through 8. The staff’s evaluation of these 

changes is documented as follows.

Enhancement 1. LRA Section B.2.18 states an enhancement to the “parameters monitored or 

inspected” and “detection of aging effects” program elements to add a program requirement to 

perform periodic UT for wall thickness of representative above-ground water suppression piping 

that is not periodically flow tested but contains, or has contained, stagnant water. As amended 

by letter dated February 19, 2014, the applicant deleted this enhancement. The staff finds the 

deletion of this enhancement acceptable because the inspections and tests recommended in 

LR-ISG-2012-02 AMP XI.M27 Table 4a, described in Enhancement No. 5, augmented 

inspections and tests described in Enhancement No. 6, and followup ultrasonic examinations 

when internal visual inspections reveal surface irregularities that could be indicative of wall loss 

below nominal pipe wall thickness are sufficient to establish reasonable assurance that the fire 

water system will be able to perform its CLB intended function(s) during the period of extended 

operation.

Enhancement 2. LRA Section B.2.18 states an enhancement to the “detection of aging effects” 

program element to add a program requirement to perform at least one opportunistic or focused 

visual inspection of the internal surface of buried fire water piping and of similar above-ground 
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fire water piping within the 5-year period prior to the period of extended operation. As amended 

by letter dated February 19, 2014, the applicant deleted this enhancement. The staff finds the 

deletion of this enhancement acceptable because the inspections and tests recommended in 

LR-ISG-2012-02 AMP XI.M27 Table 4a described in Enhancement No. 5, augmented 

inspections and tests described in Enhancement No. 6, and followup ultrasonic examinations 

when internal visual inspections reveal surface irregularities that could be indicative of wall loss 

below nominal pipe wall thickness, are sufficient to establish reasonable assurance that the fire 

water system will be able to perform its CLB intended function(s) during the period of extended 

operation.

Enhancement 3. As amended by letter dated February 19, 2014, LRA Section B.2.18 states an 

enhancement to the “detection of aging effects” program element to add a program requirement 

to perform representative sprinkler head sampling or replacement prior to 50 years of service 

and at 10-year intervals thereafter, in accordance with the 2011 Edition of National Fire 

Protection Association (NFPA) 25, “Standard for the Inspection, Testing, and Maintenance of 

Water-Based Fire Protection Systems,” or until there are no untested sprinkler heads that will 

see 50 years of service through the end of the period of extended operation. The staff reviewed 

this enhancement against the corresponding program element in GALL Report AMP XI.M27. 

GALL Report AMP XI.M27 states that sprinkler heads are tested before the end of the 50-year 

sprinkler head service life and at 10-year intervals thereafter during the period of extended 

operation to ensure that signs of degradation, such as corrosion, are detected in a timely 

manner. The staff finds the applicant’s enhancement acceptable because the applicant will 

inspect the sprinkler heads or replace them prior to 50 years of service, which is consistent with 

the recommendations in GALL Report AMP XI.M27.

Enhancement 4. LRA Section B.2.18 states an enhancement to the “detection of aging effects” 

program element to add a program requirement to perform opportunistic fire water supply and 

water-based suppression system internal inspections each time one of these systems is opened 

for repair or maintenance. As amended by letter dated February 19, 2014, the applicant deleted 

this enhancement. The staff finds the deletion of this enhancement acceptable because the 

inspections and tests recommended in LR-ISG-2012-02 AMP XI.M27 Table 4a, described in 

Enhancement No. 5, augmented inspections and tests described in Enhancement No. 6, and 

followup ultrasonic examinations when internal visual inspections reveal surface irregularities 

that could be indicative of wall loss below nominal pipe wall thickness, are sufficient to establish 

reasonable assurance that the fire water system will be able to perform its CLB intended 

function(s) during the period of extended operation.

Enhancement 5. As amended by letter dated February 19, 2014, LRA Section B.2.18 states an 

enhancement to the “detection of aging effects” program element to include the inspections and 

tests recommended in LR-ISG-2012-02 Table 4a. The staff reviewed this enhancement against 

the corresponding program element in LR-ISG-2012-02 AMP XI.M27. The AMP recommends 

the inspections and tests in Table 4a in order to detect potential loss of material and flow 

blockage. The staff finds the applicant’s enhancement acceptable because it is consistent with 

LR-ISG-2012-02 AMP XI.M27.

Enhancement 6. As amended by letter dated February 19, 2014, LRA Section B.2.18 states an 

enhancement to the “detection of aging effects” program element to include augmented 

inspections and tests of water-based fire protection system piping segments that are normally 

dry but periodically subject to flow that either cannot be drained or will allow water to collect. 

The inspections and tests of these piping segments will consist of the following:
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• A flow test or flush sufficient to detect potential flow blockage will be conducted in each 

5-year interval beginning 5 years prior to the period of extended operation. Alternatively, 

a visual inspection of 100 percent of the internal surface of piping segments will be 

conducted.

• Volumetric wall thickness inspections will be conducted on 20 percent of the length of 

the piping segments in each 5-year interval of the period of extended operation. 

Measurement points are obtained sufficient to ensure that each potential aging effect 

can be identified (e.g., general corrosion, microbiologically-influenced corrosion (MIC)). 

The 20 percent of piping that is inspected in each 5-year interval will be in different 

locations than previously inspected piping.

• Further tests or inspections will not be conducted if the 100-percent internal visual 

inspections are acceptable and the piping segment is not subsequently wetted.

The staff reviewed this enhancement against the corresponding program element in 

LR-ISG-2012-02 AMP XI.M27. The AMP recommends these inspections and tests to ensure 

that potential corrosion product buildup due to accelerated corrosion as a result of the water and 

air mixture in the piping will not result in flow blockage. The staff finds the applicant’s 

enhancement acceptable because it is consistent with LR-ISG-2012-02 AMP XI.M27.

Enhancement 7. As amended by letter dated July 29, 2014, LRA Section B.2.18 states an 

enhancement to the “parameters monitored or inspected” program element to require that,

“when visual inspections are used to detect loss of material, the inspection technique is capable 

of detecting surface irregularities that could indicate wall loss to below nominal pipe wall 

thickness due to corrosion and corrosion product deposition. Where such irregularities are 

detected, followup volumetric wall thickness examinations are performed. The staff reviewed 

this enhancement against the corresponding program element in LR-ISG-2012-02 AMP XI.M27. 

The AMP recommends that the visual inspections be capable of detecting surface irregularities 

and followup volumetric wall thickness examinations be performed to ensure that, where loss of 

material is detected, the remaining wall thickness will be adequate to ensure that the fire water 

system will be capable of performing its current licensing-basis intended function(s) during the 

period of extended operation. The staff finds the applicant’s enhancement acceptable because

it is consistent with LR-ISG-2012-02 AMP XI.M27.

Enhancement 8. As amended by letter dated July 29, 2014, LRA Section B.2.18 states an 

enhancement to the “acceptance criteria” program element to require 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 its source is determined and corrected.”

The staff reviewed this enhancement against the corresponding program element in 

LR-ISG-2012-02 AMP XI.M27. The AMP recommends that evidence of foreign material 

capable of obstructing pipe or sprinklers be removed and the source determined and corrected 

in order to ensure that there is reasonable assurance that flow blockage will not occur in the fire 

water system. The staff finds the applicant’s enhancement acceptable because it is consistent 

with LR-ISG-2012-02 AMP XI.M27.

Based on the inclusion of Enhancement Nos. 7 and 8, the staff’s concern described in 

RAI B.2.18-2 is resolved. In addition, based on its review of the applicant’s response to 

RAI B.2.18-2 by letter dated February 19, 2014, the staff finds that elements one through six of 

the applicant’s Fire Water Program, with acceptable enhancements, are consistent with the 

corresponding program elements of LR-ISG-2012-02 AMP XI.M27, and, therefore, are 

acceptable.
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Operating Experience. The staff does not have any changes or updates to this section of the 

SER.

USAR Supplement. As amended by letter dated February 19, 2014, LRA Section A.1.18 

provides the USAR supplement for the Fire Water Program. The staff reviewed this USAR 

supplement description of the program and noted that it conforms to the recommended 

description for this type of program, as described in LR-ISG-2012-02, Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 10), as amended by letter dated 

July 29, 2014, to enhancing the existing Fire Water Program prior to entering the period of 

extended operation in accordance with the enhancements described above.

The staff determines that the information in the USAR supplement, as amended, is an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. The staff does not have any changes or updates to this section of the SER.

3.0.3.2.11 One-Time Inspection

Summary of Technical Information in the Application. The applicant amended the One-Time 

Inspection Program subsequent to the issuance of the SER. The revisions are discussed below 

in the “Staff Evaluation” section.

Staff Evaluation. The staff’s evaluation of the applicant’s proposed One-Time Inspection 

Program is documented in SER Section 3.0.3.2.11. By letter dated June 23, 2014, the applicant 

revised the One-Time Inspection Program to delete the enhancement associated with 

inspections to detect cracking due to cyclic loading in the stainless steel makeup pump casings 

in the makeup and purification system. The staff’s evaluation of this item is documented in 

SSER Section 3.3.2.2.4, item 3.

Operating Experience. The staff does not have any changes or updates to this section of the 

SER.

USAR Supplement. The staff does not have any changes or updates to this section of the SER.

Conclusion. The staff does not have any changes or updates to this section of the SER.

3.0.3.2.15 Structures Monitoring Program

Summary of Technical Information in the Application. The applicant amended the Structures 

Monitoring Program subsequent to the issuance of the SER. The revisions are discussed below 

in the “USAR Supplement” section.

Staff Evaluation. The staff does not have any changes or updates to this section of the SER.

Operating Experience. The staff does not have any changes or updates to this section of the 

SER.

USAR Supplement. LRA Section A.1.39 provides the USAR supplement for the Structures 

Monitoring Program.

In LRA Appendix A, “Updated Safety Analysis Report Supplement,” the applicant provided the 

USAR supplement for the Structures Monitoring Program. The staff reviewed the USAR 
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supplement sections and noted that they conform to the recommended description for these 

types of programs, as described in SRP-LR Table 3.5-2. The staff also noted that the applicant 

committed (Commitment No. 20) to enhancing the Structures Monitoring Program prior to 

April 22, 2017. The staff also noted that, by letter dated June 23, 2014, the applicant amended 

the LRA to state that it completed Commitment No. 33, Phase 1, Actions 1 and 2; and Phase 2, 

Action 1.

The staff determined that the information in the USAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. The staff does not have any changes or updates to this section of the SER.

3.0.3.2.16 Water Control Structures Inspection

Summary of Technical Information in the Application. The applicant amended the Water Control 

Structures Inspection Program subsequent to the issuance of the SER. The revisions are 

discussed below in the “USAR Supplement” section.

Staff Evaluation. The staff does not have any changes or updates to this section of the SER.

Operating Experience. The staff does not have any changes or updates to this section of the 

SER.

USAR Supplement. LRA Section A.1.40 provides the USAR supplement for the Water Control 

Structures Inspection Program. In LRA Appendix A, “Updated Safety Analysis Report 

Supplement,” the applicant provided the USAR supplement for the Water Control Structures 

Inspection Program. The staff reviewed the USAR supplement sections and noted that they 

conform to the recommended description for these types of programs, as described in SRP-LR 

Table 3.5-2. The staff also noted that the applicant committed (Commitment No. 21) to 

enhancing the Water Control Structures Inspection Program prior to entering the period of 

extended operation. The staff also noted that, by letter dated June 29, 2015, the applicant 

amended the LRA to state that it completed Commitment No. 48.

The staff determined that the information in the USAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. The staff does not have any changes or updates to this section of the SER.

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report

3.0.3.3.6 PWR Reactor Vessel Internals Program

Summary of Technical Information in the Application. LRA Section B.2.32 includes the PWR 

Reactor Vessel Internals Program, which is defined as a new, plant-specific AMP for the LRA. 

The applicant stated that the PWR Reactor Vessel Internals Program will manage the following 

aging effects for the reactor vessel internals (RVI) components at Davis-Besse.

• changes in component dimensions due to void swelling or distortion

• cracking due to flaw initiation, flaw growth, SCC/intergranular attack (SCC/IGA), and 

irradiation-assisted SCC (IASCC)

• loss of preload due to stress relaxation
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• reduction in fracture toughness due to radiation and thermal embrittlement

• loss of material due to wear

A full description of the AMP for managing aging in the RVI components is given in the 

Summary of Technical Information in the Application subsection of Section 3.0.3.3.6 in the SER. 

The RVI components at Davis-Besse were designed and fabricated by the Babcock and Wilcox 

Company (B&W, now owned by AREVA).

By letter dated April 21, 2015, the applicant amended the LRA and submitted the inspection 

plan for the RVI components in order to fulfill the conditions and criteria specified in LRA 

Commitment No. 15, which was included as a commitment in USAR Supplement Table A-1. In 

this commitment, the applicant committed to submitting the RVI inspection plan (RVIIP) to the 

NRC for review and approval by April 22, 2015. The RVIIP is documented in nonproprietary 

AREVA Report No. ANP-3920, Revision 1, “Reactor Vessel Internals Inspection Plan for 

Davis-Besse Nuclear Plant Unit No. 1 – Licensing Report,” which was included as an enclosure 

in the letter of April 21, 2015.

The letter of April 21, 2015, also included the following AREVA reports that contain the 

background criteria for the RVIIP:

• Nonproprietary AREVA NP Licensing Report No. ANP-3285, Revision 0, “Confirmation 

of Stress Relief for the DB-1 [Davis-Besse] Core Support Structure Upper Flange Weld” 

(ADAMS Accession No. ML15113B134).

• Proprietary AREVA NP Licensing Report No. ANP-3359P, Revision 0, “Davis-Besse 

License Renewal Scope and MRP-189, Revision 1 Comparison,” which is a controlled 

document that the staff has determined meets the NRC’s withholding requirements in 

10 CFR 2.390 and is being withheld from disclosure to members of the general public in 

accordance with those requirements.

• Nonproprietary AREVA NP Licensing Report No. ANP-3359NP, Revision 0, 

“Davis-Besse License Renewal Scope and MRP-189, Revision 1 Comparison” (ADAMS 

Accession No. ML15113B134), which is the nonproprietary version of Proprietary Report 

ANP-3359P, Revision 0, and which may be accessed by the general public.

The applicant stated that the RVI components at Davis-Besse were assessed according to their 

intended functions and the probability of inducing specific aging effects in the components.

The applicant stated that the components were then assessed for aging effect impacts on the 

intended functions of the components and then grouped into the categories for “primary,” 

“expansion,” “existing program,” and “no additional measures” categories for the components, 

as defined in MRP-227-A. The applicant stated that the MRP-227-A protocols do not credit any 

“existing program” requirements for management of RVI components in B&W-designed plants. 

Therefore, the applicant clarified that the program does not implement any “existing program” 

inspections of the RVI components at Davis-Besse, other than the TS-defined surveillance 

requirements that apply to the vent valve assemblies and are implemented at Davis-Besse.

Evaluation. The NRC’s evaluation of the PWR Reactor Vessel Internals Program (LRA 

AMP B.2.32) is documented in SER Section 3.0.3.3.6. The program is based on inspection and 

evaluation (I&E) guidelines that are provided in EPRI MRP Technical Report (TR) No. 1022863, 

“Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation 

Guidelines (MRP-227-A),” dated January 2012 (ADAMS Accession Nos. ML12017A193 for the 
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transmittal letter to the NRC and ML12017A194, ML12017A196, ML12017A197, ML12017A191, 

ML12017A192, ML12017A195, and ML12017A199 for the final report), and EPRI MRP 

No. 1018292, “Materials Reliability Program: Screening, Categorization, and Ranking of 

B&W-Designed PWR Internals Component Items (MRP-189-Revision 1),” which was issued in 

2009.

This supplemental evaluation provides the staff’s assessment of any changes to the previous 

program element’s criteria for the PWR Reactor Vessel Internals Program that were proposed 

and included in the applicant’s letter of April 21, 2015, including any impacts on the program 

elements induced by the I&E protocols defined in the RVIIP. This supplemental evaluation also 

includes a review of the applicant’s bases for resolving those applicant/licensee action items 

(A/LAIs) that were issued in the NRC’s supplemental evaluation for the MRP-227-A report and 

apply to the design of RVI components in B&W-designed reactors, which apply to the specific 

design of the RVI components at Davis-Besse.

Evaluation of AMP Program Element Nos. 1 – 4 and 7 – 9

The staff noted that, in the RVIIP, the applicant’s definitions for “primary,” “expansion,” “existing 

programs,” and “no additional measures” category components were consistent with those 

defined in MRP-227-A.1

 The staff confirmed that, consistent with this AMP and the RVIIP, the 

applicant will implement specific visual or UT inspections of the RVI components (as defined in 

MRP-227-A) in order to monitor and manage the following aging effects that are applicable to 

the RVI components: (a) loss of material, (b) cracking, (c) loss of fracture toughness, (d) loss of 

preload, and (e) changes in component dimensions/distortion.

The staff verified that the criteria for the “scope of program,” “preventive actions,” “parameters 

monitored,” “detection of aging effects,” “corrective actions,” “confirmation process,” and 

“administrative controls” program elements had not changed from the previous version of these 

elements in the FENOC letter of Sept. 16, 2011 (ADAMS Accession No. ML11264A059). 

Therefore, the staff concludes that the previous evaluations of “the scope of program,” 

“preventative actions,” “parameters monitored,” “detection of aging effects,” “corrective actions,” 

“confirmation process,” and “administrative controls” program elements remain valid, as 

previously documented in SER Section 3.0.3.3.6.

Evaluation of AMP Program Element No. 5, “Monitoring and Trending”

The staff determined that the applicant’s “monitoring and trending” element remained 

unchanged in the letter of April 21, 2015, and that the RVIIP will implement all I&E criteria for 

“primary” category components defined in Table 4-1 of the MRP-227-A report and for 

“expansion” category components defined in Table 4-4 of the MRP-227-A report, with the 

exceptions of the deviations that the applicant had identified in the RVIIP for the vent valve 

assemblies and for nickel alloy weld locations in the lower grid and upper grid assemblies. 

Other than these changes, the staff reconfirmed that the previous “monitoring and trending” 

element had not changed from the previous version of this element in the FENOC letter of

 1 In MRP-227-A, the EPRI MRP did not apply any “existing program” criteria for aging management of 

B&W-designed RVI components. The applicant states that it will need to perform ASME Section XI-defined 

inspections of any RVI components that are defined as removable core support structure components (i.e., ASME 

Examination Category B-N-3 components), as required by 10 CFR 50.55a and the Table IWB-2500-1 

requirements in the ASME Code Section XI. The applicant acknowledges that these requirements apply even if 

the components were placed into the “no additional measures” category in accordance with MRP-227-A 

methodology.
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September 16, 2011. Therefore, the staff concludes that the previous evaluation of the 

“monitoring and trending” element, as previously documented in SER Section 3.0.3.3.6, remains 

valid, with the exception of the deviations identified for the vent valve assemblies and nickel 

alloy locations in the lower grid and upper grid assemblies. The staff evaluates these deviations 

in the staff’s evaluation of A/LAI #2 in this section, subsection Evaluation of the Applicant’s 

Bases for Resolving Those A/LAIs That Apply to the RVI Components at Davis-Besse as a 

B&W-Designed Light Water Reactor Facility.

Evaluation of AMP Program Element No. 6, “Acceptance Criteria”

The applicant’s “acceptance criteria” for the AMP and RVIIP are provided in Table 5-1 of the 

MRP-227-A report, with the exception of the changes to acceptance criteria for evaluating those 

nickel alloy component locations in the lower grid and upper grid assemblies and for evaluating 

components in the vent valve assemblies. Other than these changes, the staff reconfirmed that 

the previous “acceptance criteria” element had not changed from the previous version of this 

element in the FENOC letter of September 16, 2011. Therefore, the staff concludes that the 

previous evaluation of the “acceptance criteria” element, as previously documented in SER 

Section 3.0.3.3.6, remains valid, with the exception of the acceptance criteria that relate to the 

identified deviations from MRP-227-A. The staff evaluates the changes to the acceptance 

criteria for nickel alloy locations in the lower grid and upper grid assemblies in the staff’s 

evaluation of A/LAI #2 in this section, subsection Evaluation of the Applicant’s Bases for 

Resolving Those A/LAIs That Apply to the RVI Components at Davis-Besse as a B&WDesigned Light Water Reactor Facility. The staff evaluates the basis for using TS 5.5.4 to 

establish appropriate acceptance criteria for the vent valve assemblies in Section 3.1.2.1.5 of 

this SSER and in the staff’s evaluation of A/LAI #2 in this section, subsection Evaluation of the 

Applicant’s Bases for Resolving Those A/LAIs That Apply to the RVI Components at DavisBesse as a B&W-Designed Light Water Reactor Facility.

Evaluation of AMP Program Element No. 10, “Operating Experience”—Past RVI Inspection 

Summary and Updated “Operating Experience” Evaluation.

The staff noted that the applicant stated that the following inspections were performed during 

the current operating period:

• Vent valve tests and inspections are performed every 24 months (i.e., once every 

refueling outage [RFO]) in accordance with applicable requirements in TS Section 5.5.4. 

The applicant stated that past operating experience did not identify any relevant 

conditions other than the following: (a) raised/backed out jackscrew bushing observed 

during RFO 14 in 2006, (b) vent valve seating discoloration observed during RFO 16 in 

2010, and (c) during RFO 17 in 2012, one vent valve exceeded the stay-open force 

acceptance criterion.

The staff reviewed this operating experience against the stated intended function of the 

vent valve assemblies, as identified and discussed in nonproprietary 

TR No. ANP-3359NP, Revision 0. The staff noted that the intended function of 

B&W-designed vent valve assemblies is to open and achieve a fully open position during 

a postulated loss of coolant accident (LOCA) such that an adequate emergency core 

cooling system coolant flow through the reactor core is ensured during the design basis

accident conditions. AREVA states that the opening of the valve prevents any 

back-pressure across the reactor core that could otherwise impede reactor flow into the 

core. Regarding the operating experience associated with the jackscrew bushing, the 

staff noted that the applicant’s re-inspection of the jackscrew bushings during RFO 16 
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did not reveal any indications of raised/backed out bushings during the visual 

inspections that were performed in 2010. Thus, the staff noted that the applicant has not 

had any issues with jackscrew positions since 2010.

With regard to the discoloration that was observed in the vent valve seat in 2010, the 

staff noted that the discoloration observed in the vent valve seat did not affect the ability 

of the vent valve assembly to meet its intended function, as tested and confirmed during 

the TS-required surveillance test performed during RFO 16. Therefore, the staff 

concludes that this operating experience would not affect any of the elements in the 

PWR Reactor Vessel Internals Program or the ability of the AMP to manage aging 

during the period of extended operation.

Regarding the operating experience on the force needed to open the vent valves during 

the surveillance test, the applicant stated it performed several subsequent surveillance 

test cycles of the impacted vent valve assembly to confirm valve operability. The 

applicant stated that the subsequent surveillance tests did not result in any conditions 

where an excessive holding force would be needed to place the vent valve in a fully 

open valve disc position.

The staff noted that the vent valve surveillance test requirement in TS 5.5.4, Section c., 

limits the vertical force needed to place the valve configuration in a fully open position to 

a maximum value of 400 lbs of force. Thus, the staff noted that the subsequent 

surveillance tests of the impacted vent valve assembly confirmed that the valve would 

fully open when a vertical force of 400 lbs or less was applied to the impacted vent valve 

assembly.

Thus, based on this review, the staff noted that the applicant had appropriately 

reassessed the applicable operating experience for its impact on the intended function of 

the vent valve assemblies and that there was not any unresolved operating experience

that could affect the intended function of vent valve assemblies during subsequent 

operations of the plant. Thus, the staff did not observe any vent valve assembly 

operating experience that, if left unresolved, could potentially result in a need for 

amending TS 5.5.4 under the TS change requirements of 10 CFR 54.22 or to adjusting 

the AMP’s augmented inspection protocols for upper and lower vent valve retaining rings 

during the period of extended operation.

• Ultrasonic Test (UT) inspections are of the upper core barrel (UCB), lower core barrel 

(LCB), lower thermal shield (LTS), upper thermal shield (UTS), flow distributor (FD), and 

surveillance specimen holder tube (SSHT) bolts.

The applicant stated that no recordable indications were observed during the UT 

inspections of these bolts in either 1984 or 1990. A more detailed operating experience

evaluation of the inspections performed on the UCB, LCB, UTS, LTS, FD, and SSHT 

bolts and heat treatments for replaced Alloy X-750 bolts has been given in the staff’s 

evaluation of the “operating experience” program element for the applicant’s PWR

Reactor Vessel Internals Program, as documented in SER Section 3.0.3.3.6. In the 

summary of that evaluation, the staff concluded that there have not been any relevant 

flaw or material degradation indications from past inspections of the UCB, LCB, FD, 

UTS, LTS, or SSHT bolts that would cause the structural integrity of the bolts to be 

called into question. Therefore, the staff concludes that the applicant’s bases for 

performing UT inspections of the UCB, LCB, and FD bolts (as “primary category” 
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components for the program) and potentially performing UT inspections of the UTS, 

LTS, and SSHT bolts (as “expansion” category components for the program) remains 

acceptable without need for change under A/LAI #2.

• Core clamping measurements were taken of the differential height between the top of 

the plenum rib pads and the reactor vessel seating surface.

The applicant stated that it performed this one-time measurement to satisfy the EPRI 

MRP physical measurement recommendations defined in Section 4.3.1 of the 

MRP-227-A, which recommends that a one-time physical measurement be performed of 

the differential distance from the top of the plenum rib pads in the plenum cover 

assembly to the reactor vessel seating surface.

The staff also noted that the applicant’s program will call for the applicant to implement 

VT-3 visual inspections of the plenum cover weldment rib pads, plenum cover support 

flange, and core support shield (CSS) to flange once every 10 years. The staff noted 

that: (a) the applicant’s augmented physical measurement criteria associated with these 

inspections are consistent with EPRI MRP’s physical measurement criteria for these 

components defined in Table 4-1 of MRP-227-A, and (b) the applicant has already 

completed its one-time activity to perform the physical measurement of this differential 

distance. In Table 5-1 of the MRP-227-A report, the EPRI MRP sets the following 

acceptance criteria on the performance of these differential measurements:

The measured differential height from the top of plenum rib 

pads to the vessel seating surface shall average less than 

0.004 inches when compared to the as-built configuration.

By letter dated June 5, 2015, the applicant amended the LRA to: (a) identify the number 

of physical measurements that were performed to measure the top of plenum rib 

pads-to-vessel seating surface distances, and (b) summarize the difference of the 

average value of these measurements from the height that was documented for this 

parameter in the original design documents. The applicant stated that a total of eight 

physical measurements were performed of this height parameter and that the average 

height differed by less than 0.004 inches from the top of the plenum rib pads to the 

reactor vessel seating surface height documented in the original design records. The 

applicant also stated that the physical measurement readings were uniform and did not 

reveal any evidence of wear in these reactor vessel internals components.

The staff noted that the supplemental information provided by the applicant provides 

sufficient demonstration that there have not been any changes to the component 

configurations or degradation of the plenum rib pads that otherwise, if detected, could 

potentially change the criteria of the “primary” category inspections that will be applied to 

the components in accordance with MRP-227-A. Therefore, based on this review, the 

staff concludes that the applicant has demonstrated that the subsequent VT-3 visual 

examinations of the plenum rib pads during the period of extended operation are justified 

as proposed in MRP-227-A because: (a) the applicant has completed the physical 

measurements of the components in accordance with the guidelines in MRP-227-A, 

(b) the physical measurement results have not shown evidence of wear in the 

components or changes to the configurations of these components, (c) the physical 

measurement results support the conclusion that the visual inspection criteria in 

MRP-227-A for inspecting these components do not need to be adjusted, and 
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(d) consistent with the RVIIP, the applicant will implement the applicable visual 

inspections of the plenum rib pads during the period of extended operation, as 

recommended in MRP-227-A.

The operating experience related to one-time physical measurements of the plenum rib 

pads is closed, and the applicant has completed its commitment to perform a one-time 

set of physical measurements of the plenum rib pad-to-reactor seating surface height.

Evaluation of the Applicant’s Bases for Resolving Those A/LAIs That Apply to the RVI 

Components at Davis-Besse as a B&W-Designed Light Water Reactor Facility.

In the staff’s supplemental evaluation of the MRP-227-A report dated December 16, 2011

(ADAMS Accession No. ML11308A770), the staff included the following A/LAIs that an applicant 

implementing MRP-227-A report would need to address as part of its LRA. The B&W PWR 

applicable A/LAIs are A/LAI #s 1, 2, 4, 6, 7, and 8. A/LAIs #s 3 and 5 are applicable only to the 

design of Combustion Engineering or Westinghouse PWRs and do not apply to Davis-Besse.

The staff verified that the applicant had provided acceptable responses for resolving A/LAI #8, 

Subitems 1-4, in the applicant’s letter of September 16, 2011 (ADAMS Accession 

No. ML11264A059). The applicant provided updated responses to A/LAI #s 1, 2, 4, 6, 7, and 8 

in the letter of April 21, 2015.

The staff’s evaluations and bases for accepting the applicant’s responses to A/LAI #8, 

Subitems 1-4, are documented in SER Section 3.0.3.3.6. The evaluations that follow provide 

the staff’s assessments of the applicant’s bases for resolving the requests in A/LAI #s 1, 2, 4, 6, 

7, and 8, Subitem 5, which were not resolved during the staff’s initial review of the PWR Reactor 

Vessel Internals Program, as previously documented in SER Section 3.0.3.3.6.

Applicant’s Response to Resolve A/LAI #1

In A/LAI #1, the staff asked the applicant to submit an evaluation demonstrating that the 

failure modes, effects and criticality analyses (FMECAs) and functionality analyses for 

B&W-designed internals in MRP-227-A are bounding for the design of RVI components at 

its facility or else to identify the process that will be used to identify differences in the design 

of their components from that assessed in MRP-227-A. The applicant stated that the design 

of the RVI components at Davis-Besse is bounded by the design and operating history 

assumptions for B&W-designed reactors, as defined in MRP-227-A, the FMECA report 

(MRP-190), and the B&W design functionality analysis (MRP-229, Revision 3).

The staff previously evaluated the basis for concluding that the analysis in MRP-277-A was 

bounding for the assessment of the RVI components at Davis-Besse in SER 

Section 3.0.3.3.6. In addition, the staff verified that, in the letter of April 21, 2015, the 

applicant identified those differences in the plant’s RVI design from that assumed and 

assessed in the MRP-227-A report or its background reports, and that the applicant has 

resolved these differences as part of the applicant’s basis for resolving the request in 

A/LAI #2. Thus, the staff concludes that the applicant has appropriately demonstrated that 

the analytical assumptions in MRP-227-A are bounding for the design of the RVI 

components at Davis-Besse, with the exception of those design deviations that the applicant 

has identified in its response to A/LAI #2. The staff evaluates the applicant’s basis for 

reconciling these design differences in the staff’s evaluation of the applicant’s response to 

A/LAI #2, which follows in the next subsection.
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Applicant’s Response to Resolve A/LAI #2

In A/LAI #2, the staff asked the applicant to compare the design information for the RVI 

components at the plant to the corresponding information for the components in Tables 4-1 

and 4-2 of MRP-189, Revision 1, and in Table 4-4 of MRP-191. Using the results of this 

comparison, the staff asked the applicant to identify any changes that would need to be 

made to the inspection criteria for the components in MRP-227-A.

The applicant stated that the methods in MRP-189, Revision 1, were used to evaluate the 

aging mechanisms and resultant aging effects on the components that could result in 

risk-significant degradation and to determine whether any necessary modifications of the

program defined in MRP-227-A would be necessary. The applicant also stated that it 

performed a comparison of the RVI design at Davis-Besse to the component information 

and criteria in Tables 4-1 and 4-2 of MRP-189, Revision 1, and Table 4-4 of MRP-191. The 

applicant determined that all RVI components at Davis-Besse were in conformance with the 

aging assessments for B&W-designed RVI components in these reports, with the exception 

of the following components: (a) vent valve miscellaneous locking device parts, and 

(b) nickel alloy locations in the lower grid assembly.

In regard to the deviation for the vent valve assembly locking devices, the applicant stated 

that any aging effects that could potentially induce a failure of the original vent valve 

miscellaneous locking device parts are adequately managed by other existing plant 

programs. The applicant stated that this includes applicable programmatic controls in the 

American Society of Mechanical Engineers (ASME) Code Section XI and the applicable vent 

valve testing and inspection requirements for the vent valve assemblies that are included 

and implemented in accordance with the plant’s TS.

The staff reviewed the TS requirements and the MRP-227-A “primary” category inspection 

criteria for the vent valve assemblies to determine whether the criteria would adequately 

manage the components in the vent valve assemblies, including any locking devices in the 

assemblies. The staff noted that the TS for Davis-Besse include TS #5.5.4, “Reactor Vessel 

Internals Vent Valve Program,” which requires the applicant to implement the following 

testing and inspection activities of the vent valve assemblies on a 24-month surveillance 

frequency:

• Verify by visual inspection that the valve body and valve disc exhibit no abnormal 

degradation.

• Verify the valve is not stuck in an open position.

• Verify by manual actuation that the valve is fully open when a force less than or 

equal to 400 lbs is applied vertically upward.

The staff also noted that the PWR Reactor Vessel Internals Program and MRP-227-A 

“primary” category inspection protocols would call for the applicant to perform inspections of 

the vent valve top and bottom retaining rings on a 10-year inspection frequency. The staff 

noted that the collective set of visual inspections that would be implemented in accordance 

with the requirements of TS 5.5.4 and the PWR Reactor Vessel Internals Program for vent 

valve upper and lower retaining rings would not necessarily cover visual inspections of any 

locking devices that are part of the vent valve assemblies. Therefore, the staff reviewed 

additional information that was provided in Non-Proprietary AREVA Report 

No. ANP-3359NP, Revision 0, “Davis Besse Reactor Vessel Internals, License Renewal 

Scope and MRP-189, Revision 1 Comparison,” to determine whether implementation of the 
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surveillance testing requirements in TS 5.5.4 could accomplish alternative aging 

management criteria for locking devices in the vent valve assemblies. These vent valve 

assemblies are designed to fully open in order to relieve pressure and ensure proper 

emergency coolant flow during a postulated LOCA event.

In Appendix A.1 of the SRP-LR, the NRC defines that performance monitoring programs test 

the ability of a structure or component to perform its intended function(s) and are one 

category of AMPs that may be used to manage the effects of aging. The staff noted that the 

surveillance requirements in TS 5.5.4 could be considered adequate performance 

monitoring program activities if the surveillance requirements were capable of indicating a 

potential vent valve assembly problem such that the applicant’s Corrective Action Program

would initiate an investigation of the issue, including any potential failure issues with the vent 

valve locking devices. The staff noted that TS 5.4.4 does require the applicant to perform a 

surveillance test requirement (i.e., performance monitoring requirement) to manually actuate 

the vent valve discs to the fully open position when a vertical force is applied to them. The 

staff determined that implementation of the applicable TS requirements would provide 

adequate performance monitoring activities for the vent valve assembly components 

(including applicable locking devices) because:

(a) Implementation of the surveillance requirements would be used to verify that the vent 

valve discs would be capable of fully opening when subjected to a flow-induced 

force, as would be needed during a postulated LOCA event.

(b) The applicant’s Corrective Action Program would initiate an investigation of any vent 

valve assembly problem that had prevented the valve disc from fully opening at the 

required force during performance of the TS surveillance test requirement.

(c) Consistent with the program element criteria in SRP-LR Section A.1.2.3 for 

performance monitoring programs, this constitutes sufficient performance monitoring 

protocols for identifying any potential vent valve locking device issues that could 

potentially prevent the valve disc from achieving its intended fully open position 

requirement, which is necessary to be achieved during a postulated LOCA event.

Based on this review, the staff finds that the vent valve surveillance requirements in 

TS 5.5.4, when taken into account with the RVIIP’s “primary component” inspection criteria 

for the vent valve upper and lower retaining rings, provide for adequate management of the 

vent valve assembly components (including applicable locking devices) because the staff 

has confirmed that the combination of condition monitoring activities (i.e., inspection 

activities) and surveillance testing activities (i.e., performance monitoring activities) meet the 

criteria for implementing performance monitoring and condition monitoring activities in 

Appendix A.1 of the SRP-LR and are acceptable to manage potential aging effects in the 

vent valve assembly components during the period of extended operation. The staff also 

finds that the MRP-227-A I&E protocols, as applied to the vent valve retaining ring 

components under the RVIIP, do not need to be further adjusted in accordance with the 

request in A/LAI #2.

In regard to the exceptions for the nickel alloy components in the lower grid and upper grid 

assemblies, the staff noted that the applicant proposed alternative “primary” and “expansion” 

categories for the components. Specifically, the staff noted that, in Appendix D and the 

Tables of TR No. ANP-3290, Revision 1, the applicant identified the following two deviations 
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from the generic design of the lower grid and upper grid assemblies assumed in 

MRP-227-A:

• Regarding inclusion of nickel alloy dowel-to-guide block welds as “primary” category 

components for the B&W-designed lower grid assemblies in MRP-227-A, the 

applicant stated the original dowel and dowel weld were removed from the DavisBesse design during initial fabrication and replaced with a dowel, dowel cap, and 

dowel welds made from stainless steel materials. The applicant also stated that the 

guide blocks were welded directly to the lower grid forging and that the lower grid 

assembly design at Davis-Besse therefore no longer includes nickel alloy 

dowel-to-guide block welds.

• Regarding inclusion of nickel alloy dowel-to-upper grid fuel assembly support pad 

welds as “expansion” category components for the upper grid assembly in 

MRP-227-A, the applicant stated that this type of weld configuration does exist at 

Davis-Besse, even though it was previously thought not to exist in the plant design. 

The applicant also verified that the dowel-to-lower grid fuel assembly support pad 

welds in the upper grid assembly are made from nickel alloy weld materials.

The applicant stated that, since these two component items are linked in MRP-227-A, 

alternative “primary” and “expansion” category criteria need to be defined for the DavisBesse program that will meet the same objective or level of conservatism for the original 

“primary” and “expansion” category links proposed for lower grid and upper grid assemblies 

in MRP-227-A. The applicant proposed the following alternative augmented inspection 

criteria to achieve this objective:

• elevation of the nickel alloy dowel-to-lower grid fuel assembly support pad welds in 

the lower grid assembly from “expansion” category components in MRP-227-A to 

“primary” category components for the RVIIP, with the components serving as the 

new lead indicators for nickel alloy locations in the lower grid and upper grid 

assemblies, noting that, for these components, the applicant stated that VT-3 type of 

visual inspections will be performed on the welds no later than two refueling outages 

from the beginning of the period of extended operation, with subsequent VT-3 

inspections to be performed on a 10-year re-inspection basis

• identification of the nickel alloy dowel-to-upper grid fuel assembly support pad welds 

in the upper guide assembly as the appropriate “expansion” category component 

links for the “primary” category inspections that will be performed on the nickel alloy 

dowel-to-lower grid fuel assembly support pad welds in the lower grid assembly

• criteria for initiating inspections of the nickel alloy dowel-to-upper grid fuel assembly 

support pad welds in the upper grid assembly (as the “expansion” category 

components) if confirmed evidence of relevant conditions is noted at two or more 

dowel-to-lower grid fuel assembly support weld locations in the lower grid assembly, 

and for completing the expanded inspections of the dowel-to-upper grid fuel 

assembly support pad welds in the upper grid assembly by the completion of the 

subsequent refueling outage

The staff noted that the generic program for B&W-designed RVI components in MRP-227-A

assumes that nickel alloy dowel-to-guide block welds are present in the plant’s lower grid 

assembly design, which is not the case for the modified design of the lower grid assembly at 

Davis-Besse. 
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Therefore, the staff noted that the proposed changes to the “primary” and “expansion” 

category component designations for nickel alloy welds in the lower grid and upper grid 

assemblies were appropriate because they accomplish the following general objectives:

(a) assign new alternative nickel alloy component locations (i.e., the nickel alloy 

dowel-to-lower grid fuel assembly support pad welds in the lower grid assembly) that 

will serve as the new leading “primary” category nickel alloy component locations in 

the lower grid and upper grid assemblies in order to account for the fact that the 

current design no longer includes any lower grid assembly dowel-to-guide block 

welds made from nickel alloy materials

(b) revise the current “expansion” category criteria for the nickel alloy dowel-to-upper 

grid fuel assembly support pad welds, such that the potential for performed 

expanded inspections of the components will now be linked to the results of the 

primary category” inspections that will be performed on the nickel alloy dowel-to- fuel 

assembly support pad welds in the lower grid

(c) establish appropriate “primary component” inspection result threshold criteria that will 

be used to initiate expanded inspections of the nickel alloy dowel-to-upper grid fuel 

assembly support pad welds in the upper grid assembly based on the results of the 

primary category inspections that will be performed on the nickel alloy 

dowel-to-upper grid fuel assembly support pad welds in the lower grid assembly 

during the period of extended operation

Based on this review, the staff finds that the changes in the “primary” and “expansion” 

category inspection criteria for these nickel alloy weld locations are acceptable because the 

staff has verified that the changes are consistent with: (a) the actual design of nickel alloy 

components in the lower grid and upper grid assemblies of the plant, and (b) the general 

intent of the criteria in MRP-227-A to establish lead “primary” and “expansion” category 

criteria for nickel alloy locations in B&W-designed lower grid and upper grid assemblies.

Based on this review, the staff finds that the applicant’s bases for resolving the requests in 

A/LAI #2 to be comprehensive and complete and A/LAI #2 is resolved with respect to the 

applicant’s PWR Reactor Vessel Internals Program and RVIIP.

Applicant’s Response to Resolve A/LAI #4

According the request in A/LAI #4, the applicant would need to implement enhanced visual 

inspections (EVT-1 inspections) of the upper flange weld in the core support structure no 

later than two refueling outages from the beginning of the period of extended operation and 

on a 10-year re-inspection basis, if the applicant could not provide evidence that the weld 

was stress relieved during initial weld fabrication. Therefore, in A/LAI #4, the staff asked 

applicants of B&W-designed PWRs to provide sufficient confirmation that the upper flange 

welds in the core support structures had been appropriately stress relieved as part of the 

processes that were used to fabricate the weld.

The applicant’s bases for responding to A/LAI #4 are given in Section 6.2.3.2 of 

TR No. ANP-3290, Revision 1, as supplemented with specific details in TR No. 3285, 

Revision 0, “Confirmation of Stress Relief for the DB-1 [Davis-Besse] Core Support 

Structure Upper Flange Weld.” The applicant stated that the original fabrication records for 

the RVI components confirm that the upper flange weld in the core support structure was 
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stress relieved as part of the processes that were used to fabricate the weld. By letter 

dated May 20, 2015, the applicant amended the RVIIP submittal and stated that the 

fabrication record confirming stress relief of the core support structure upper flange weld is 

given in Enclosure B of AREVA Record No. 51-9191898-000, “Reactor Vessel Internals 

Welds Stress Relief Records Search for the Operating 177-FA B&W Units,” dated 

October 30, 2012.

The staff noted that TR No. ANP-3285, Revision 0, provides the details and summarizes the 

results of the applicant’s fabrication record search. Specifically, the staff noted that the 

technical report indicates that the applicant did a search of the fabrication records for all 

double V-groove, double U-groove, and J-groove configured RVI welds listed in Table 4-2 of 

the MRP-189, Revision 1, report and that the fabrication records demonstrate that the welds 

were stress relieved during weld fabrication using a low frequency, vibratory stress 

equalization process. Therefore, the information in TR No. ANP-3285, Revision 0, as 

supplemented in the applicant’s letter of May 20, 2015, provides sufficient demonstration 

that the upper flange weld in the core support structure was appropriately stress relieved 

immediately after the time of weld fabrication and provides an adequate basis for concluding 

that this weld will not need to be inspected under the augmented inspection protocols in 

MRP-227-A.

The staff did note that the upper flange weld in the core support structure may be defined by 

the applicant as a weld that is required to be inspected in accordance with Examination 

Category B-N-3 requirements of ASME Code Section XI for removable core support 

structure components. The staff noted that, if the core support structure upper flange weld 

is defined as an Examination Category B-N-3 component, the weld will be required to be 

inspected in accordance with Examination B-N-3 requirements specified in 

Table IWB-2500-1 of ASME Code Section XI and that the MRP-227-A protocols would not 

relieve the applicant of its obligations to perform these inspections in accordance the 

applicable ASME Code Section XI requirements, as invoked by 10 CFR 50.55a(g)(4). For 

these types of components, ASME Code Section XI requires all accessible surfaces of the 

removable core support structures to be inspected using ASME-defined VT-3 visual 

inspection methods once every 10-year ISI interval.

Based on this review, the staff concludes that the applicant has provided adequate 

demonstration that it does not need to implement augmented EVT-1 visual inspections of 

the core support structure upper flange weld under the I&E protocols in MRP-227-A

because the applicant has provided sufficient demonstration that the core support structure 

upper flange weld has been appropriately stress relieved immediately after fabrication of the 

weld. However, the staff also concludes that, if this weld is part of the removable core 

support structure for the facility, the applicant will continue to be required to perform the 

appropriate ASME Section XI Examination Category B-N-3-defined VT-3 inspections of the 

weld (i.e., implement the appropriate ISI requirements) during each applicable 10-year ISI 

interval for the reactor unit. The request in A/LAI #4 is resolved with respect to the 

applicant’s PWR Reactor Vessel Internals Program and RVIIP.

Applicant’s Response to Resolve A/LAI #6

A/LAI #6 relates to the basis for managing aging in the following B&W-designed “expansion” 

category RVIs that are either inaccessible to inspection or for which adequate inspection 

methods have yet to be developed by the U.S. nuclear power generation industry: (a) axial 

and girth welds in the core barrel, (b) former plates, (c) external baffle-to-baffle bolts and 
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their locking devices, (d) core barrel-to-former bolts and their locking devices, and 

(e) internal baffle-to-baffle bolts. Specifically, the staff asked B&W applicants to justify the 

acceptability of these components for continued operation through the period of extended 

operation by performing an evaluation or by proposing a scheduled replacement of the 

components. As part of their applications to implement the approved version of MRP-227, 

the staff asked the applicants to provide a justification for the continued operability of each 

of the inaccessible or uninspectable components and, if necessary, provide, for NRC review 

and approval, their plan for replacing the components.

The staff noted that, in the letter of April 21, 2015, as supplemented in the letter of 

May 20, 2015, the applicant updated its basis for managing aging in these “expansion” 

category components and amended USAR Supplement Table A-1 to include Commitment 

No. 52, in which the applicant committed to submitting the plant-specific analysis or 

replacement schedule for these components to the staff for review and approval. The staff 

evaluates the applicant’s new commitment and basis for resolving A/LAI #6 in the USAR 

Supplement subsection of this supplemental evaluation.

Applicant’s Response to Resolve A/LAI #7

A/LAI #7 relates to the basis for managing the loss of fracture toughness due to thermal 

aging or neutron irradiation embrittlement in B&W-designed RVIs that are made from either 

cast austenitic stainless steel (CASS), martensitic stainless steel, or precipitation hardened 

stainless steel materials. In A/LAI #7, the staff recommended that applicants of 

B&W-designed reactors develop plant-specific analyses that will be applied to the incore 

monitoring instrumentation (IMI) guide tube assembly spiders and control rod guide tube 

(CRGT) spacer castings or to additional RVI components that may be fabricated from 

CASS, martensitic stainless steel, or precipitation hardened stainless steel materials in order 

to demonstrate that the components will maintain their functionality during the period of 

extended operation. The staff stated that the plant-specific analysis for the components 

should be consistent with the plant’s CLB and the need to maintain the functionality of the 

components under all conditions of operation for the CLB. The staff asked the applicant to 

provide the plant-specific analysis as part of its submittal to apply the MRP-227-A report to 

the CLB for its facilities (i.e., in this case, as part of the LRA).

The staff noted that, in the letter of April 21, 2015, as supplemented in the letter of 

May 20, 2015, the applicant updated its basis for managing neutron irradiation embrittlement 

and thermal aging embrittlement in RVI components made from CASS, martensitic stainless 

steel, or precipitation hardened stainless steel materials and amended USAR Supplement 

Table A-1 to include Commitment No. 53. In this commitment, the applicant committed to 

submitting a plant-specific analysis for RVI components made from these materials to the 

staff for review and approval. The staff evaluation of the applicant’s new commitment and 

basis for resolving A/LAI #7 is documented in the USAR Supplement subsection of this 

supplemental evaluation.

Applicant’s Response to Resolve A/LAI #8, Subitem 5

In A/LAI #8, Subitem 5, the staff addressed the need to identify all analyses that qualify as 

time-limited aging analyses (TLAAs) for RVI components. Specifically, under the 

requirements of 10 CFR 54.21(c)(1), the applicant is required to identify all analyses in the 

CLB that conform to the definition of a TLAA in 10 CFR 54.3(a) and to include an evaluation 

of the TLAAs in the LRA. The staff stated that MRP-227-A does not specifically address the 
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resolution of TLAAs that may apply to an applicant’s RVI components. Therefore, in 

A/LAI #8, Subitem 5, the staff asked PWR applicants implementing the MRP-227-A report to 

evaluate the CLB for their facilities to determine if they have plant-specific TLAAs that apply 

to their RVI components, and if so, to include and evaluate them in their LRAs in 

accordance the requirements of 10 CFR 54.21(c)(1)(i), (ii), or (iii).

In A/LAI #8, Subitem 5, the staff included additional request criteria for the CLBs that may 

include cumulative usage factor (CUF) TLAAs for specific RVI components in the plant 

designs. For those CLBs that did include these types of TLAAs, the staff stated that the 

applicant may use the PWR Reactor Vessel Internals Program as the basis for accepting the 

CUF analyses in accordance with 10 CFR 54.21(c)(1)(iii) only if the RVI components in the 

CUF analyses will be periodically inspected for fatigue-induced cracking in the components 

during the period of extended operation. In this case, the staff stated that the periodicity of 

the inspections of these components shall be justified to be adequate to resolve the TLAA. 

Otherwise, the staff stated that acceptance of the CUF TLAAs should be done in 

accordance with either 10 CFR 54.21(c)(1)(i) or (ii), or in accordance with the requirement in 

10 CFR 54.21(c)(1)(iii), using the applicant’s program that corresponds to AMP X.M1, 

“Fatigue Monitoring,” in the GALL Report, Revision 2. To satisfy the evaluation 

requirements of ASME Code Section III, Subsections NG-2160 and NG-3121, the staff 

stated that the existing fatigue CUF analysis evaluation should address how the effects of 

the reactor coolant system (RCS) water environment will be factored into the basis for 

accepting the TLAA, in accordance with 10 CFR 54.21(c)(1)(i), (ii), or (iii).

The applicant stated that, for RVI components with CUF analyses, the TLAAs will be 

accepted in accordance with 10 CFR 54.21(c)(1)(iii) and that fatigue-induced cracking of the 

components will be adequately managed during the period of extended operation using the 

PWR Reactor Vessel Internals Program. The applicant further stated that fatigue-induced 

cracking will be managed by inspections defined for the components in MRP-227-A, which 

have been incorporated into the RVIIP.

The applicant stated that, in LRA Amendments 15 and 24, LRA Sections A.1.32 and B.2.32 

were revised to state that the program includes management of the TLAA for reduction in 

fracture toughness of the RVI components and that the TLAA will be managed in 

accordance with the implementation of the MRP-227-A guidelines, as amended by the 

MRP-227-A SE, including all activities associated with the FENOC responses to 

plant-specific action items identified in Section 4.2 of the supplemental evaluation. The 

applicant stated that, in the SER for the LRA, the NRC staff determined that the PWR 

Reactor Vessel Internals Program is an acceptable basis for accepting the reduction of 

ductility TLAA, in accordance with 10 CFR 54.21(c)(1)(iii), and for managing changes in the 

ductile fracture toughness properties of the RVI components during the period of extended 

operation. However, the applicant stated that the applicable analysis in Appendix E of TR

No. BAW-10008, Part 1, Revision 1, will require an update for the period of extended 

operation. Therefore, in Commitment No. 54, the applicant committed to submitting the 

updated evaluation under this A/LAI at least 6 months prior to entering into the period of 

extended operation (i.e., by October 22, 2016).

The applicant stated that two flow-induced vibration (FIV) analyses for RVI components 

were performed as part of the CLB and qualify as TLAAs for the LRA. The applicant stated 

that the FIV analysis of the RV internals and the incore instrument nozzles was 

dispositioned in accordance with 10 CFR 54.21(c)(1)(i) and has been demonstrated to 

remain valid for the period of extended operation. The applicant stated that the FIV analysis 
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(i.e., high-cycle CUF analysis) for the reactor vessel surveillance capsule holder tubes was 

dispositioned in accordance with 10 CFR 54.21(c)(1)(ii) and has been projected to the end 

of the period of extended operation.

The staff verified that the LRA includes the following TLAAs for the RVI components at 

Davis-Besse: (a) reduction of ductile fracture toughness TLAA for the RVI components, as 

discussed and evaluated in LRA Section 4.2.7, (b) FIV endurance limit analyses for the RVI 

components and the incore instrumentation nozzles, as discussed and evaluated in LRA

Section 4.3.2.2.2.2 (as amended), (c) the low-cycle fatigue CUF analyses for replaced UCB

bolts, LCB bolts, and LTS bolts performed in accordance with a low-cycle metal fatigue 

method (i.e., low-cycle CUF analysis), as discussed and assessed in LRA

Section 4.3.2.2.2.1, and (d) high-cycle FIV CUF analysis for the reactor vessel surveillance 

capsule specimen tubes, as discussed and evaluated in LRA Section 4.3.2.2.2.3 (as 

amended).

The staff verified that the evaluation of the FIV endurance limit analysis for the RVI 

components and incore instrumentation nozzles would remain unchanged, as documented 

in SER Section 4.3.2.2.2. For this analysis, the staff reconfirmed that the analysis remains 

valid for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i).

The staff verified that the evaluation of the high-cycle CUF analysis for the replaced reactor 

vessel surveillance capsule specimen tubes would remain unchanged, as documented in 

SER Section 4.3.2.2.3. For this analysis, the staff reconfirmed that the analysis has been 

adequately projected to the end of the period of extended operation, in accordance with 

10 CFR 54.21(c)(1)(ii). The staff also verified that consideration of environmental effects 

associated with the reactor coolant does not need to be factored into the high-cycle CUF 

analysis because the analysis is based on an assessment of vibrations and not on an 

assessment of the impacts that cumulative design transient occurrences and environmental 

effects will have on low-cycle fatigue calculations.

For the reduction of ductile fracture toughness TLAA, the staff noted that the applicant 

changed its basis for accepting the TLAA in accordance with 10 CFR 54.21(c)(1)(iii) from 

that evaluated in SER Section 4.2.7. In this SER section, the staff previously accepted the 

applicant’s basis for using the PWR Reactor Vessel Internals Program to accept the 

reduction of ductility TLAA in accordance with 10 CFR 54.21(c)(1)(iii) and to manage 

potential reductions in the ductile fracture toughness properties of the RVI components 

during the period of extended operation. However, in its letter of April 21, 2015, the 

applicant stated that it would update the reduction-of-ductility analysis in 

TR No. BAW-10008 to project the analysis to the end of the period of extended operation. 

The staff noted that the applicant committed to submitting the updated analysis to the NRC 

for review and approval at least 6 months prior to entering into the period of extended 

operation (i.e., by October 22, 2016). Thus, the staff determined that an updated evaluation 

of this TLAA was necessary in order to assess the applicant’s updated basis for accepting 

the TLAA in accordance with 10 CFR 54.21(c)(1)(iii). The staff evaluates the change in the 

basis for dispositioning the reduction of ductility TLAA in accordance with 

10 CFR 54.21(c)(1)(iii) in Section 4.2.7 of this SSER.

For the low-cycle CUF analyses that were performed for the replaced UCB bolts, LCB bolts, 

and LTS bolts, the applicant amended the TLAA evaluation for these components in a letter 

dated June 05, 2015. The applicant stated that a combination of the PWR Reactor Vessel 

Internals Program (LRA AMP B.2.32) and the Fatigue Monitoring Program (B.2.18) will be 
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used to ensure that fatigue-induced cracking will be adequately managed for the period of 

extended operation, in accordance with 10 CFR 54.21(c)(1)(iii). The staff evaluates the 

basis for accepting these TLAAs in accordance with 10 CFR 54.21(c)(1)(iii) in 

Section 4.3.2.2.2 of this SSER.

The staff did not identify any other analyses in the CLB that would qualify as TLAAs for the 

RVI components, in accordance with the definition for TLAAs in 10 CFR 54.3(a). Based on 

this review, the staff finds that the applicant has identified those TLAAs that apply to the RVI 

components at Davis-Besse and appropriately addressed A/LAI #8, Subitem 5, through the 

applicant’s identification of these TLAAs in the LRA. A/LAI #8, Subitem 5, is resolved with 

respect to the PWR Reactor Vessel Internals Program and the RVIIP for Davis-Besse.

USAR Supplement

The applicant’s USAR supplement summary description for its PWR Reactor Vessel Internals 

Program is documented in Section A.1.32 of the LRA, which was amended in a letter dated 

March 9, 2012, and subsequently by letter May 20, 2015. This section supplements and 

updates the staff’s previous evaluation of the USAR supplement summary description in LRA

Section A.1.32, as documented in the USAR Supplement subsection of SER Section 3.0.3.3.6.

In the USAR Supplement subsection of SER Section 3.0.3.3.6, the staff stated that USAR 

Supplement Table A-1 in the LRA included LRA Commitment No. 15, which committed the 

applicant to submitting the inspection plan for the RVI components at Davis-Besse to the staff 

for review and approval no later than 2 years after issuance of the renewed operating license or 

2 years prior to the beginning of the period of extended operation (i.e., April 22, 2015), 

whichever is earlier. The staff noted that the applicant’s submittal of the inspection plan for the 

RVI components fulfills Commitment No. 15 because: (a) the applicant had submitted the 

inspection plan to the NRC for review and approval by April 22, 2015, (b) at the time of the 

submittal of the inspection plan, the staff had yet to issue a renewed operating license for the 

Davis-Besse facility, and (c) based on (a) and (b), the submittal of the RVI inspection plan on 

April 21, 2015, satisfies the time of submittal condition for submitting the inspection plan by 

April 22, 2015. Commitment No. 15 on the LRA is closed.

The staff also noted that the submittal of the RVI inspection plan added three new commitments 

to USAR Supplement Table A-1, which were included in the USAR Supplement relative to the 

applicant’s activities for implementing of the PWR Reactor Vessel Internals during the period of 

extended operation:

(1) The applicant included Commitment No. 52 in order to address the NRC’s action request 

in A/LAI #6. The applicant committed to the performance of analyses justifying the 

acceptability of the core barrel cylinder, including vertical and circumferential seam 

welds, former plates, external baffle-to-baffle bolts and their locking devices, core 

barrel-to-former bolts and their locking devices, and internal baffle-to-baffle bolts for 

continued operation through the period of extended operation or to the replacement of 

these component items. The applicant also committed to submitting either the detailed 

analyses or replacement schedule to the NRC for review and approval within 1 year of 

any degradation that is detected in the “primary” category components linked to these 

“expansion” category” components and exceeds the acceptance criteria for the 

applicable aging effects in the MRP-227-A report.
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The staff noted that a commitment was appropriate to resolve this A/LAI because the 

applicant would not need to implement an assessment of one of the referenced 

“expansion” category components unless degradation was detected in the linked 

“primary” category component. The staff also noted that the applicant would only need 

to submit the analysis or replacement schedule of the referenced “expansion” category 

component to the NRC for review and approval if an applicable monitored aging effect in 

the linked “primary” category component was determined to exceed the limit for that 

aging effect in Table 5-1 of the MRP-227-A report. Therefore, based on this review, the 

staff finds that Commitment No. 52, as placed on USAR Table A-1, is acceptable 

because it is consistent with the guidelines approved in MRP-227-A and therefore 

resolves the request in A/LAI #6.

(2) The applicant included Commitment No. 53 in order to address the NRC’s action request 

in A/LAI #7. The applicant stated that it is developing a plant-specific analysis to 

demonstrate that the IMI guide tube assembly spiders, CRGT spacer castings, and 

additional RVI component items made from CASS, martensitic stainless steel, or 

martensitic precipitation-hardened stainless steel materials (e.g., CSS vent valve top and 

bottom retaining rings) will maintain their functionality during the period of extended 

operation. The applicant stated that the analysis will: (a) consider the possible loss of 

fracture toughness in these component items due to thermal embrittlement and/or 

irradiation embrittlement and may also need to consider limitations on accessibility for 

inspection and the resolution or sensitivity of the inspection techniques, and (b) will be 

consistent with the CLB for Davis-Besse and the need to maintain the functionality of the 

component items being evaluated under all licensing basis conditions of operation. The 

applicant also committed to submitting the plant-specific analyses to the NRC for review 

and approval at least 1 year prior to the MRP-227-A implementation date for inspecting 

the applicable “primary” category component items.

The staff noted the action in Commitment No. 53 was consistent with the criteria in the 

MRP-227-A report and the NRC’s criteria for resolving A/LAI #7, as defined in the 

December 16, 2011, supplemental evaluation for MRP-227-A. Therefore, based on this 

review, the staff finds that Commitment No. 53, as placed on USAR Table A-1, is 

acceptable because: (a) it is consistent with the guidelines approved in MRP-227-A and 

resolves the request in A/LAI #7, and (b) the applicant will submit the analysis to the 

NRC for review and approval at least 1 year prior to the MRP-227-A implementation date 

for inspecting the applicable “primary” category component items.

(3) The applicant included Commitment No. 54 in order to address the adequacy of the 

applicant’s RVI reduction of ductility TLAA, as identified in response to A/LAI #8, 

Subitem 5. The applicant committed to the submittal of an evaluation for the period of 

extended operation that will assess the effect of irradiation on the mechanical properties 

and deformation limits of those RV internals that were evaluated for the current term in 

Appendix E of TR No. BAW-10008, Part 1, Revision 1. The applicant also committed to 

submitting the evaluation for NRC review and approval by October 22, 2016. The staff 

evaluates Commitment No. 54 in Section 4.2.7 of this SSER, which provides the staff’s 

updated evaluation of the basis for accepting the reduction-of-ductility TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii).

Based on the above evaluation, the closure of LRA Commitment No. 15, and the inclusion of 

Commitment Nos. 52, 53, and 54, the staff finds that the information in the USAR supplement,
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as amended, is an adequate summary description of the program, as required by 

10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant’s PWR Reactor Vessel 

Internals 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 USAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.3.7 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program

Summary of Technical Information in the Application. Subsequent to the submittal of the LRA, 

the staff issued LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and Corrosion Under Insulation,” which revised several GALL 

Report AMPs, including the guidance for AMP XI.M38. By letter dated February 19, 2014, the 

applicant provided the results of its review and changes to the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Program associated with the recommendations in 

LR-ISG-2012-02, Section B, “Representative Minimum Sample Size for Periodic Inspections” in 

GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components.”

Staff Evaluation. To ensure that the GALL Report AMP XI.M38 inspections include a 

representative sample size, the staff issued LR-ISG-2012-02, which recommends a periodic 

minimum sample size, frequency, and inspection location for each material, environment, and 

aging effect combination for in-scope components. The revision included a provision to inspect 

20 percent of each representative population of in-scope components, with a maximum sample 

size of 25 components, in each 10-year period during the period of extended operation.

By letter dated February 19, 2014, the applicant amended LRA Section B.2.41 to reflect the 

results of its review related to LR-ISG-2012-02, Section B. The applicant revised the program 

description of its Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program. 

The revised LRA Section B.2.41 program description now also states that, as a minimum, every 

10 years, starting from the period of extended operation, a representative sample of 20 percent

of each representative population (defined as components that have the same material, 

environment, and aging effect combination) or a maximum of 25 components per representative 

population will be inspected. The revision to the program description also states that, where 

practical, the inspection will include a representative sample of the system population and will 

focus on the bounding or lead components most susceptible to aging because of time in service 

and the severity of the operating conditions. The revised program description also states that 

this minimum sample size will not override the opportunistic basis of the AMP.

The applicant amended the “scope of program” element to also include periodic inspections of a 

representative sample size. The applicant also revised the “detection of aging effects” program 

element to make it consistent with its revised program descriptions as discussed above.

Finally, the applicant amended the “monitoring and trending” program element in its entirety.

The revised element now states the following:

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program 

uses standardized monitoring and trending activities to track degradation. 

Deficiencies are documented using approved processes and procedures such 
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that results can be trended. Inspections are performed at frequencies identified 

in “Detection of Aging Effects” program element.

The staff finds the applicant’s revisions to its Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Program acceptable because the resulting sample size, inspection locations, 

frequency, and “monitoring and trending” program element are consistent with the 

recommendations provided in AMP XI.M38, as revised by LR-ISG-2012-02.

USAR Supplement. The staff reviewed the changes to LRA Section A.1.41 as amended by 

letter dated February 19, 2014, and noted that the applicant’s program description is consistent 

with the recommended description in SRP-LR Table 3.0-1, as revised by LR-ISG-2012-02.

The staff determines that the information in the USAR supplement, as amended, is an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the proposed changes to the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program, as amended by letter 

dated February 19, 2014, the staff determined that those program elements for which the 

applicant claimed consistency with AMP XI.M38, as revised by LR-ISG-2012-02, 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 USAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.3.9 Shield Building Monitoring Program

Summary of Technical Information in the Application. Subsequent to the issuance of the SER 

dated September 3, 2013, the applicant amended the plant-specific AMP in LRA Section B.2.43, 

“Shield Building Monitoring Program,” in response to the staff’s requests for additional 

information to address the potential impact of more recent operating experience related to the 

shield building laminar cracking. As a result of indications of laminar crack propagation in the 

shield building identified by the applicant during baseline inspections conducted in 

August/September of 2013, the staff noted that additional information was needed to evaluate 

the potential impact of this operating experience on the shield building AMP. By letters dated 

July 3, 2014, and January 28, 2015, the applicant updated the “detection of aging effects,” 

“monitoring and trending,” “acceptance criteria,” and “operating experience” program elements 

and the Shield Building Monitoring Program section of the USAR supplement to account for this 

recent plant-specific operating experience, as discussed in the staff evaluation below.

Staff Evaluation. The staff reviewed the updated program elements of the applicant’s revised 

plant-specific Shield Building Monitoring 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 of the shield building laminar cracking 

during the period of extended operation through the effective incorporation of these program 

elements. This review did not address the adequacy of the CLB, or the impacts of laminar 

cracking on the licensing basis that is ensured through processes outside of license renewal. 

Additional information on that review following the issuance of the SER can be found in the 

staff’s Inspection Report (IR) 05000346/2013009, “Design and Licensing Basis of the Shield 

Building,” dated May 12, 2014, IR 05000346/2014008, “Inspection of Apparent Cause 

Evaluation Efforts for Propagation of Laminar Cracking in Reinforced Concrete Shield Building 
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and Closure of Unresolved Item Involving Shield Building Laminar Cracking Licensing Basis,”

dated May 28, 2015, and other associated documents.

During its review, the staff asked followup RAIs and the applicant revised the Shield Building 

Monitoring Program. Unless otherwise noted, the staff’s evaluation relates to the final version of 

the AMP found in the applicant’s RAI response letter dated November 20, 2012, as amended by 

LRA Amendments 51 and 54 provided by letters dated July 3, 2014, and January 28, 2015, 

respectively, to account for the plant-specific operating experience of laminar crack propagation 

identified in August/September 2013. The followup RAIs and the responses provided after the 

issuance of the SER dated September 3, 2013, are summarized briefly below, followed by the 

staff’s evaluation of the revised program elements as found in the final version of the AMP and 

clarified in the RAI responses.

• RAI B.2.43-4 issued by letter dated April 15, 2014: RAI B.2.43-4 requested information, 

with sufficient technical detail, of any modifications or enhancements that may be made 

to the Shield Building Monitoring Program or the Structures Monitoring Program to 

account for plant-specific operating experience related to: (1) discovery of previously 

unidentified cracks in the shield building core bore holes (also referred to as “core holes” 

or “bore holes”) during the baseline inspection conducted in August/September 2013; 

and (2) broken/cracked rebar found, in February 2014, at several mechanical splice 

locations during hydro-demolition activities to create a temporary construction opening in 

the shield building to support the SG replacement.

• Response to RAI B.2.43-4 provided by letter dated July 3, 2014: The applicant provided 

information that several of the previously unidentified cracks resulted from propagation 

of existing laminar cracks by the “ice wedging” phenomenon. The applicant provided 

modifications to the Shield Building Monitoring Program with regard to increased 

number, location, and increased frequency, and a strategy for monitoring core holes for 

laminar cracks and its propagation. The response included LRA Amendment 51, which 

revised LRA Sections A.1.43, “Shield Building Monitoring Program,” and B.2.43 to reflect 

the changes in the core hole monitoring sample, schedule, strategy, summary, and 

evaluation results incorporating the plant-specific operating experience that identified 

propagation of existing laminar cracks in 2013. The applicant further stated that the 

“rebar failure did not represent an aging management issue” because the broken or 

cracked rebar resulted from stress conditions induced by the physical process of hydrodemolition during the creation of the temporary construction opening, which was not an 

aging effect. By letter notification dated July 8, 2014, to the Atomic Safety and Licensing 

Board, the applicant submitted, as Enclosure 2, the apparent cause evaluation report 

entitled “Full Apparent Cause Evaluation Report - Shield Building Laminar Crack 

Propagation (Condition Report 2013-14097 dated 9/11/2013)” (hereafter referred to as 

FACE Report), for the 2013 identified crack propagation.

• RAIs B.2.43-5 (followup) and B.2.43-6 (followup) issued by letter dated 

September 29, 2014: RAI B.2.43-5 requested that the applicant discuss the technical 

rationale or criteria used to justify the selection of additional core holes, with identified 

crack propagation, for future inspections following discovery, and the number of 

subsequent inspections and/or time period for which they will continue to be inspected 

before possible removal from the sample. RAI B.2.43-6 requested that the applicant 

justify how the opportunistic inspection of rebar when exposed will adequately manage 

potential aging effects of corrosion on rebar located adjacent to laminar cracks, 

considering the plant-specific conditions of the shield building laminar cracking that is not 

passive, the presence of trapped water in the cracks, and potentially aggressive 
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environmental conditions; or provide information of modifications or enhancements that 

may be made to applicable AMPs to address the staff concern regarding implementation 

of opportunistic inspection of rebar to manage potential aging effects of corrosion.

• Responses to RAIs B.2.43-5 (followup) and B.2.43-6 (followup) provided by letter dated 

October 28, 2014: In response to RAI B.2.43-5, the applicant provided information that 

the selection of additional core holes for future examination of the laminar cracking will 

be based on the extent and direction of observed cracking, by monitoring the crack size, 

shape, and progression using 23 representative, strategically-selected core holes, 3 of 

which monitor the leading edge of identified propagation. The current extent of laminar 

cracking and its propagation is understood based on the examination of 80 core holes 

and impulse response testing conducted during 2011 through 2013. Of these, eight core 

holes were found in 2013 to have previously unidentified cracking. The applicant 

explained that 5 of these core holes, which were previously uncracked and into which 

the leading edge of an existing crack propagated, were included in the sample of 23, 3 of 

which were added to monitor the leading edge of propagation. A core hole may be 

removed from the sample only if it has been cracked circumferentially all around and can 

no longer bound cracking limits, in which case a new leading edge core hole may be 

installed. In the RAI B.2.43-6 response, the applicant explained that opportunistic 

inspections of rebar are adequate to manage aging effects of rebar corrosion because: 

(1) the environment within the concrete adjacent to the laminar crack is alkaline (as 

evidenced by chemical analysis of water in core holes indicating pH values greater 

than 10), (2) the mitigating nature of the applied exterior coating, and (3) the 

opportunistic inspection of the rebar in the construction opening made in the shield 

building in 2011, after over 30 years of operation, determined that the presence of 

cracking had not resulted in unacceptable rebar material loss or corrosion. The 

applicant also explained that since the grade elevation is more than 31 ft below the 

lowest elevation with laminar cracking, interaction between the potentially aggressive 

ground water and the laminar cracking condition is not credible.

• RAIs B.2.43-7 and B.2.43-8 issued by letter dated December 30, 2014: RAI B.2.43-7 

requested that the applicant: (1) provide information of quantitative acceptance criteria 

for the shield building laminar cracking defined by bounding limits of cracking 

characterized in terms of crack width, crack planar limit, distribution, and/or any other 

appropriate parameters, against which the core hole inspection findings are compared

and evaluated to determine (a) if the condition is bounded by and conforms to the design 

basis documentation referenced in the AMP, and (b) if corrective actions 

(e.g., re-evaluation of design basis documentation, repair) are needed to ensure that the 

structure and component intended functions are maintained consistent with all CLB 

design conditions during the period of extended operation, and (2) explain how the 

evaluation criteria hierarchy in Figure 5.1 of ACI 349.3R will be applied to the core hole 

inspection findings of laminar cracking to determine whether or not the condition is 

acceptable after evaluation. RAI B.2.43-8 requested that the applicant clarify and 

explain if core holes with worst-case observed laminar crack widths to-date are included 

in the representative sample of 23 core bore holes that will be monitored to determine if 

the condition is bounded by the design basis documentation, or to provide the bases for 

their exclusion.

• Responses to RAIs B.2.43-7 and B.2.43-8 provided by letter dated January 28, 2015: In 

response to RAI B.2.43-7, the applicant provided quantitative acceptance criteria in 

terms of crack width and planar limit against which core hole inspection findings will be 

evaluated to determine if corrective actions are necessary. The applicant also explained 
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how the evaluation criteria in Figure 5.1 of ACI 349.3R would be applied based on 

inspection findings of whether the cracks are passive and/or quantitative acceptance 

criteria are met. The response included LRA Amendment 54, which revised the 

“acceptance criteria” program element to include the quantitative acceptance criteria. In 

response to RAI B.2.43-8, the applicant clarified that currently 14 of the 23 core holes in 

the sample were cracked, and covered a range of crack widths including 3 core holes 

with the maximum observed crack widths of 0.01 inch to 0.013 inch.

The staff notes that the Shield Building Monitoring Program was revised in LRA 

Amendments 51 and 54, provided by letters dated July 3, 2014, and January 28, 2015, 

respectively, to account for the plant-specific operating experience of previously unidentified 

cracks and crack propagation discovered in 2013, which was addressed by RAIs B.2.43-4 

through B.2.43-8 and their responses issued after the staff’s SER dated September 3, 2013. 

By letter dated October 6, 2015, the Shield Building Monitoring Program was further revised in 

LRA Admendment No. 60 to incorporate the additional plant-specific operating experience of 

limited of limited crack propagation observed during inspections performed in 2015, and as a 

result of discussions held during the September 23, 2015, Advisory Committee on Reactor 

Safeguards Subcommittee meeting on the Davis-Besse LRA. These LRA amendments revised 

the “detection of aging effects,” “monitoring and trending,” “acceptance criteria,” and “operating 

experience” program elements, and the USAR supplement of the Shield Building Monitoring 

Program.

Based on the evaluation of the program elements below, the staff finds the November 20, 2012 

AMP, as amended by LRA Amendment 51, dated July 3, 2014, LRA Amendment 54, dated 

January 28, 2015, and LRA Amendment No. 60 dated October 6, 2015, acceptable. The 

applicant has adequately addressed the staff's concerns described in the RAIs to account for 

the 2013 operating experience related to the propagation of laminar cracking. The staff also 

finds that the applicant has sdequately addressed and incorporated the crack propagation 

observed in 2015 into the AMP by LRA Admendment No. 60.

Scope of the Program. There are no changes or updates to this section of the SER.

Preventive Actions. There are no changes or updates to this section of the SER.

Parameters Monitored or Inspected. There are no changes or updates to this section of the 

SER.

Detection of Aging Effects. LRA Section B.2.43, as amended by letter, dated July 3, 2014, in 

response to RAI B.2.43-4 (evaluated in this and the following sections), states that visual 

inspections will be performed on a representative sample of the shield building wall structural 

subcomponents by inspection of internal surfaces of core bores. The applicant stated that the 

representative sample size currently consists of a minimum of 23 (20 in the previous 

November 20, 2012, version of the AMP) core bore locations to include 8 of the 10 flute 

shoulders with a higher prevalence of event-driven laminar cracking. The locations also include 

four bores above the 780 ft elevation (within the upper 20 ft of the structure where cracking was 

also identified outside of the flute shoulders) and one at each main steam line penetration. The 

applicant stated that locations of the inspections will be chosen from the core bores that have 

been installed in the shield building wall, including new core bores installed as required to 

identify changes in the limits of cracking in areas with previously identified crack propagation. 

The applicant also stated that approximately 10 core bore inspection locations in the current 

sample are uncracked but strategically located adjacent to areas of known cracking; thereby 

providing the ability to monitor crack propagation. The applicant further stated that past 
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evidence of crack propagation will be additionally considered in choosing future inspection 

locations. The program element also includes provisions to supplement visual inspections with 

other established nondestructive examination (NDE) techniques and testing, as necessary. The 

applicant also stated that the inspections would occur annually prior to the period of extended 

operation (i.e., in 2015 and 2016), and in 2017 and 2018 after entering the period of extended 

operation. If no aging effects (defined as no discernable change in crack width or general 

appearance of crack or confirmation that no visible cracks have developed in previously 

uncracked core holes) are identified, then the frequency of visual inspections may be 

progressively changed to at least once every 2 years through 2026, and may be changed to at 

least once every 4 years thereafter if the 2-year frequency does not detect any degradation. 

Changes to the inspection schedule and parameters monitored will be evaluated if aging 

degradation is detected.

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 this element should address how the 

program would be capable of detecting or identifying the occurrence of age-related degradation 

prior to the loss of function. This element should also discuss “when” and “how” data will be 

collected for the program. This element should also justify the sample size of an inspection 

program based on sampling, and should justify the inspection frequency and method.

As described in detail in the “operating experience” program element, by letter dated 

April 15, 2014, the staff issued RAI B.2.43-4. This RAI in part requested that the applicant 

describe and justify modifications or enhancements, if any, that may be potentially made to the 

AMPs credited for the shield building for license renewal, to account for the plant-specific 

operating experience related to laminar cracking propagation identified in August/September 

2013.

In its response dated July 3, 2014, to this part of RAI B.2.43-4, related to the 

August/September 2013 discovery of previously unidentified cracks, the applicant characterized 

the “newly” identified cracks as propagation of laminar cracking by the phenomenon of 

“ice-wedging”. The applicant further stated that the minimum representative sample of 

monitoring core bores in the Shield Building Monitoring Program is increased from 20 to 23 as a 

result of this plant-specific operating experience. The applicant also stated that three monitoring 

bores will be used to aid in identifying changes in the limits of cracking in areas with previously 

identified crack propagation and that new core bores may be installed, if needed, during each 

inspection cycle in order to bound crack limits. The applicant further stated that the frequency of 

internal visual inspection for the 23 monitoring bores is changed to annual inspections for a 

minimum of 4 years (2015-2018). The applicant stated that, following acceptable results of the 

1-year interval inspections, the interval will be changed to a 2-year interval in 2019, and a 

maximum 4-year interval after 2026. Further, the applicant stated that these inspection intervals 

will be evaluated for effectiveness and modifications to the Shield Building Monitoring Program 

will be determined in the Corrective Action Program should there be an identified significant 

change in cause, rate of crack growth, or a condition that is not bounded by the design basis 

documentation. The applicant revised the USAR Supplement in LRA Section A.1.43 to address 

the change in the core monitoring schedule. The applicant revised the “detection of aging 

effects,” “monitoring and trending,” “acceptance criteria,” and “operating experience” program 

elements of the Shield Building Monitoring Program to incorporate changes due to the 

plant-specific operating experience of crack propagation. The staff notes that these changes 

have been reflected and evaluated in the staff evaluation of respective program elements in this 

and following sections. The staff evaluation of the part of the response to RAI B.2.43-4 that 
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relates to operating experience aspects is provided further below in the “operating experience” 

program element section.

The staff reviewed the applicant’s response dated July 3, 2014, to part of RAI B.2.43-4 

regarding changes to the AMP resulting from its review of the 2013 plant-specific operating 

experience of laminar crack propagation and found portions of it acceptable. The staff finds the 

response with regard to the minimum representative sample size (minimum of 23) of core holes 

examined in future inspections and the strategy for distribution of core holes locations inspected 

acceptable because they cover areas of high prevalence of laminar cracking. In addition, 

consideration of past evidence of crack propagation in choosing inspection locations and 

provision for the addition of new core holes for inspection are incorporated in the program. The 

staff also finds the proposed inspection intervals acceptable because they are conservatively 

biased and increased progressively only if no aging effects are identified. The applicant also 

provided an adequate LRA update to reflect these considerations. However, the staff found that 

the basis or criteria used for selecting 3 out of the 8 core bore holes with discernable change in 

laminar cracking conditions in the sample size of 23 core holes for subsequent consecutive 

inspections of the shield building wall, and the number and/or time period of subsequent 

consecutive inspections in which they will be included in the representative sample for 

inspection after discovery, was not fully or clearly described. By letter dated 

September 29, 2014, the staff issued followup RAI B.2.43-5 (followup) requesting the applicant 

to provide: (1) additional discussion and detail of the technical rationale or criteria used to justify 

the selection of additional core holes with identified crack propagation for future inspections 

after discovery of a change in crack conditions, and (2) the minimum number and/or time period 

of subsequent consecutive inspections in which they will be inspected after discovery of a 

change in crack conditions before they may be removed from the representative sample.

In its response by letter dated October 28, 2014, to the first part of RAI B.2.43-5, the applicant 

stated that the selection of additional core bores for future examination of the laminar cracking 

identified within the shield building will be based on the extent and direction of propagation of 

laminar cracking in the structure. The applicant also stated that based on its current knowledge 

of the size and extent of the original pre-existing sub-surface crack, and the cause and rate of 

crack propagation due to ice-wedging, it is monitoring the crack size, shape and progression by 

the use of 23 strategically selected core bores, 3 of which were chosen to monitor the leading 

edge of crack propagation; these 23 bores are representative of the remaining cracked areas. 

The applicant stated that if crack planar propagation passes completely through one of the three 

leading edge core bores, then the need to add a new leading edge core bore adjacent to that 

bore will be evaluated to maintain at least three leading edge monitoring bores.

The applicant explained that it determined through causal analysis that the crack propagation, 

identified in 2013 inspections in the architectural flute shoulder areas, is a result of “ice 

wedging,” which requires a previously existing crack, the presence of water, and a freezing 

cycle. The applicant further explained that the extent and location of cracking for the entire 

shield building was mapped using impulse response testing and validated by over 80 core bores 

examined in 2011-12. During the 2013 monitoring of core bores for the laminar cracking 

condition, “new” cracking was identified in eight bores. The applicant stated that it conducted 

informational impulse response mapping at five locations (covering approximately 2,200 square 

feet) for overall perimeter identification and examined all 80 existing bore locations, as part of 

the extent of condition investigation. The applicant further stated that the 2013 discovery of 

changes in the condition of cracks in the structure provides a validation that the visual 

inspection method of bore monitoring is an effective means of identifying small changes in 

laminar cracking in the shield building. The features of the eight bores with observed changes 
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in laminar cracking were assessed and divided into two categories: Category 1, consisting of 

five bores where the leading edge of an existing crack propagated into previously uncracked 

concrete (i.e., perimeter expansion); and Category 2, consisting of three bores where changes 

(e.g., a crack offshoot developing in the bore) were identified in a previously cracked bore with 

no planar propagation.

The applicant explained that of the 5 Category 1 bores, 2 bores were already within the 

population of the originally proposed 20 bores selected for long-term monitoring under the 

Shield Building Monitoring Program. Therefore, the remaining 3 bores are added to the 

program for monitoring, to form the representative sample of 23 bores within the area of 

cracking, such that changes in planar limits of the crack are monitored and bounded. The 

applicant noted that two of the five Category 1 bores intersect the same leading edge 

(i.e., located approximately at the same elevation and horizontally offset from each other) and, 

therefore, the other three bores are used to monitor the leading edge of crack propagation. 

Further, the applicant clarified that Category 2 bores were not incorporated into the monitoring 

program since they do not provide information related to identifying the leading edge 

(i.e., perimeter) of the crack.

In its response dated October 28, 2014, to the second part of RAI B.2.43-5, the applicant stated 

that there is no minimum number or time period of subsequent consecutive inspections for 

which core bore holes with identified crack propagation will be inspected following discovery 

before they may be removed from the representative sample because it intends to perform 

inspections of the 23 monitoring bores throughout the period of extended operation. The 

applicant further explained that a bore hole added to the inspection scope for the purposes of 

monitoring laminar cracking limits may be removed from scope if it has been cracked 

360 degrees around and can no longer bound cracking limits. However, prior to removal from 

the scope of inspection, the need to install a new leading edge core bore adjacent to the bore 

being removed will be evaluated in order to maintain the population of at least three leading 

edge core bores for monitoring crack propagation. The applicant further clarified that the 

progressively increasing inspection intervals proposed in the program will be evaluated for 

effectiveness by the Shield Building Monitoring Program. Should there be an identified change 

to the cause of the condition, significant change to the rate of crack growth, or a condition 

adverse to the bounding nature of the design basis documentation, the applicant stated that it 

would evaluate and determine modifications to the Shield Building Monitoring Program using its 

Corrective Action Program. The applicant explained that bore holes are also examined for 

changes in crack width. Therefore, even if a bore hole is cracked 360 degrees around and is no 

longer able to define planar limits, any previously identified changes to width will be entered into 

the Corrective Action Program, and that information will be used in the decision-making process 

to determine whether changes are required to the inspection schedule (e.g., increase inspection 

frequency) or parameters monitored (e.g., increase the number of core bores monitored). In a 

telephone conference call held on February 20, 2015, the applicant clarified that the “leading 

edge” of planar laminar cracks is where the inspection would observe a plane extend or expand 

compared to previous core bore inspection results. The applicant further clarified that leading 

edge monitoring is achieved through inspection of bores, and impulse response mapping if 

required. The applicant also clarified that a representative core bore provides information 

regarding crack width and/or the planar limits of cracking.

The staff noted that the applicant’s criteria for the selection of additional core bores for future 

examination of the laminar cracking identified within the shield building were based on the 

extent and direction of propagation of laminar cracking in the structure, which is determined 

based on expanded core hole inspections, and supplemental impulse response testing, if 
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required. The staff noted that the applicant selected additional core bores for future 

examinations to monitor crack propagation by reviewing the cracking features of all core bores 

with observed crack propagation in the last inspection cycle, and identifying those that uniquely 

define the leading edge (planar perimeter limit) of crack propagation, which resulted in the 

addition of three core bores to define the leading edge or planar limits of observed crack 

propagation. The staff also noted that according to the applicant’s criteria, it intends to maintain 

at least three leading edge core bores in the representative sample. The staff finds the 

applicant’s response to the first part of RAI B.2.43-5 acceptable because the applicant 

explained its criteria for selecting additional bores to monitor crack propagation based on a 

review of inspection findings from the last inspection cycle and identifying those core holes with 

identified crack propagation that uniquely define the leading-edge limits of crack propagation, 

which the staff determines to be a reasonable approach for monitoring the planar limits of crack 

propagation. The staff finds the applicant’s response to the second part of RAI B.2.43-5 

acceptable because it: (1) clarified that there is no specified number or time period of 

inspections criteria for core holes with identified crack propagation for subsequent examinations 

following discovery; and (2) explained that results of an engineering evaluation of the inspection 

findings, with regard to change in crack width, planar limits, and cause and rate of crack growth, 

in its Corrective Action Program will be used as the basis to remove and add core holes to the 

representative inspection sample or to make other changes to the monitoring program for future 

examinations, which the staff determines to be a reasonable approach to making changes to the 

AMP, as necessary, to ensure adequate management of crack propagation. The staff’s 

concerns described in RAI B.2.43-5 are resolved.

The staff noted that the response dated July 3, 2014, to RAI B.2.43-4 did not identify changes to 

the Shield Building Monitoring Program with regard to monitoring the rebar for corrosion but 

documented operating experience of the presence of water within the pre-existing cracks that

under freezing temperatures may cause the cracks to propagate. Further, the staff noted that 

the Shield Building Monitoring Program as submitted by letter dated November 20, 2012, 

proposed to monitor rebar for corrosion by visual inspection, only on an opportunistic basis, 

when exposed for some undefined reason. The presence of water and air trapped within the 

existing laminar cracks of the coated shield building wall increases the potential for corrosion of 

the adjacent rebar layers. Further, the groundwater chemistry at the Davis-Besse site is 

considered to be aggressive [i.e., chlorides = 2,870 ppm (max) and sulfates = 1,700 ppm (max)] 

which may also be indicative that the shield building is or has been exposed to potentially 

aggressive (i.e., high chloride content) air-outdoor environment. Given the above plant-specific 

conditions and operating experience of existing laminar cracking that may propagate, the 

presence of trapped water in the cracks, and potentially aggressive environmental conditions, 

the staff needed additional technical justification and basis regarding the AMP’s implementation 

of opportunistic inspections to monitor aging effects in the rebar located near the laminar 

cracking. By letter dated September 29, 2014, the staff issued RAI B.2.43-6 (followup)

requesting the applicant to explain, with sufficient technical detail and basis, how the 

opportunistic inspection of rebar, when exposed, will adequately manage the potential aging 

effects of corrosion for rebar layers located near laminar cracking; or to provide any 

modifications or enhancements that will be made to the Shield Building Monitoring Program to 

address the staff’s concern regarding the implementation of opportunistic inspection of rebar 

when exposed to adequately manage potential aging effects of corrosion for rebar layers 

located near laminar cracking.

In its response to RAI B.2.43-6 by letter dated October 28, 2014, the applicant stated that the 

opportunistic inspection of rebar when exposed will adequately manage the potential aging 
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effects of corrosion for rebar layers located near laminar cracking, and no modifications or 

enhancements to the AMPs are necessary, for the reasons described below:

• FENOC visually inspected rebar in areas of laminar cracking at the construction opening 

during October/November, 2011, after over 30 years of operation, and determined that 

the presence of cracking itself has not resulted in unacceptable rebar material loss or 

corrosion.

• The presence of potentially aggressive environmental conditions (groundwater) is not a 

condition associated with the laminar cracking because impulse response mapping 

completed on exterior portions of the shield building during 2012 did not identify laminar 

cracking below elevation 615 ft, which is more than 31 ft above grade elevation at the 

site. Therefore, postulated scenarios of interaction between groundwater and the 

laminar cracking condition are not considered credible.

• As a corrective action related to the discovery of laminar cracking, an exterior coating 

was applied to the shield building during 2012, which is a means to limit the availability 

of oxygen and moisture required to sustain a corrosive environment (ACI Report 

222R-85, “Corrosion of Metals in Concrete”). Therefore, despite the identification of 

water within the concrete, the introduction of additional oxygen and moisture into the 

shield building concrete has been limited such that the postulated corrosion rate of rebar 

is expected to remain minimal, with a decreasing trend.

• Chemical analysis of the water found in the core bores, conducted as part of the causal 

analysis of the observed laminar crack propagation, concluded that the water 

constituents were typical of water that was in contact with the concrete for a period of 

time, and exhibited high pH values averaging greater than 10. Therefore, the water itself 

with salt and high pH is not conducive to generating corrosion in the rebar.

The applicant summarized that it has elected to conduct opportunistic inspections of the rebar 

based on the supporting evidence that the alkali environment within the concrete is inhibiting 

corrosion and the mitigating nature of the coating. The applicant also explained that rebar 

corrosion would result in visual indications such as staining, cracking, or spalling of the exterior 

of the shield building structure or in core bores that are located near rebar, which are indications 

monitored for under the Structures Monitoring Program to adequately manage the aging effects 

of potential rebar corrosion.

The staff reviewed the applicant’s response to RAI B.2.43-6 and noted that the protective 

exterior coating applied to the shield building provides a means to limit the ingress and 

availability of oxygen and moisture or other deleterious elements required to sustain a corrosive 

environment. The staff also noted that the high pH obtained from the chemical analysis of water 

found in the core holes indicate an alkaline environment of the concrete and water around the 

rebar adjacent to the laminar cracks that is not conducive to corrosion. The staff noted from the

applicant’s 2011-2012 root cause analysis for laminar cracking and the 2013-2014 apparent 

cause evaluation (FACE Report) for the laminar crack propagation that the majority of laminar 

cracking discovered in 2011-2012 and all of the 2013 observed crack propagation occurred in 

the flute shoulder regions of the shield building, which has a significantly larger cover depth to 

the laminar crack adjacent to the outer hoop reinforcement. Further, the FACE Report indicates 

that the laminar cracks are hairline tight with the maximum observed crack width being in the 

range of 0.010 to 0.013 inch, with the majority being smaller than 0.005 inch. Additionally, 

although the groundwater at the site is considered aggressive, the lowest elevation of observed 

laminar cracking is located over 31 ft above the grade elevation, which does not establish a 

nexus between the groundwater and laminar cracking. These factors and the fact that 
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opportunistic inspection of the rebar in 2011 in the area of the construction opening, after 

over 30 years of plant operation and after the initiation of laminar cracking during the 1978 

blizzard, identified minimal to no rebar corrosion, which indicates that the presence of hairline 

laminar cracking, in itself, does not increase the risk for potential rebar corrosion. Additionally, 

visual indications of rebar corrosion, such as surface staining, cracking, spalls, and indications 

of corrosion products in the core holes are monitored under the Structures Monitoring Program. 

Therefore, the staff finds that the opportunistic inspection of rebar is an adequate method to 

manage potential rebar corrosion adjacent to laminar cracking in the shield building. The staff 

thus finds the applicant’s response acceptable because the applicant provided justification to 

reasonably support the adequacy of opportunistic visual inspections to manage the aging 

effects of rebar corrosion. The staff’s concern described in RAI B.2.43-6 is resolved.

The staff observed, in its RAI B.2.43-7 dated December 30, 2014, and described in the 

“acceptance criteria” program element evaluation section further below, that the laminar crack 

width is a critical parameter that could affect the bond strength and the capacity of the shield 

building’s outside hoop rebar, adjacent to the laminar cracking, to perform its intended function. 

Although the “detection of aging effects” program element states that the representative sample 

of core holes are examined for discernable changes in general appearance and crack width of 

existing laminar cracks; and for indications of new cracking, it was not clear to the staff if the 

representative sample of 23 core bore holes to be inspected includes and tracks core bore 

holes with worst case observed crack widths. By letter dated December 30, 2014, the staff 

issued RAI B.2.43-8 requesting the applicant to clarify whether the core bore holes with the 

worst case observed laminar crack widths to date are included in the representative sample of 

23 core bore holes that will be monitored during the period of extended operation to determine if 

the condition is bounded by the design basis documentation referenced in the AMP. The 

applicant was also requested to provide the number of core holes included in the sample and 

the basis for such number or to provide a basis for their exclusion.

In its response to RAI B.2.43-8, dated January 28, 2014, the applicant stated that the core hole 

with the worst case observed laminar crack width to date, which is 0.013 inch, is included in the 

representative sample of the 23 core bore holes that will be monitored in the period of extended 

operation. The applicant also stated that the current monitoring program includes inspection of 

14 bore locations with identified laminar cracking with a range of crack width sizes, as indicated 

in SER Table 3.0.3.3.9-1 below.

Table 3.0.3.3.9-1 Crack Widths of Cracked Core Bores in Inspection Sample

Approximate Crack Width, Inch

Number of Core Bores 

in Sample

0.005 inch and lesser 8

0.006 inch to 0.009 inch 3

0.010 inch and greater 3

The applicant also stated that crack width was a parameter inherent to the reinforcement bond 

and splice evaluations completed at the University of Kansas and Purdue University, and is 

therefore treated as a limiting parameter and monitored by the AMP for a “discernable change” 

in general appearance and width. The applicant further stated that crack width is recorded on 

each bore inspection form retained under its records management program and is added to site 

drawings to facilitate trending. The applicant clarified that the selection of the bores with 

cracking in the sample was based on the prevalence of cracking as discussed in the responses 
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to RAIs B.2.43-2 and B.2.43-2a. As noted previously, the applicant also clarified in a telephone 

conference call held on February 20, 2015, that a representative core bore provides information 

regarding crack width and/or the planar limits of cracking.

The staff noted from the applicant’s response that its representative sample of 23 core bores 

inspected includes 14 core holes with a range of laminar crack widths, including 3 with the 

maximum observed crack widths ranging from 0.010 inch to 0.013 inch. The basis for selection 

of these core holes was to cover the spectrum of locations with high prevalence of laminar 

cracking. The staff also noted that each representative bore in the inspection sample provides 

information regarding crack width (helps monitor maximum crack width) and/or the planar limits 

of cracking (i.e., helps monitor planar propagation). The staff finds the applicant’s response 

acceptable because the representative inspection sample of 23 core holes consists of core 

holes that define maximum observed crack widths as well as planar propagation limits and,

therefore, includes appropriate monitoring and trending of the limiting “crack width” parameter to 

effectively detect aging effects of potential propagation on the bond capacity of the rebar 

adjacent to the laminar cracking. The staff’s concerns described in RAI B.2.43-8 are resolved.

In LRA Amendment No. 60 dated October 6, 2015, the applicant further revised the “detection of 

aging effects” program element to state that the representative inspection sample of 23 core 

holes was increased to 28, and that the current distribution of core bores included 9 (previously 

8) of the 10 flute shoulders with a high prevalence of laminar cracking. The program element 

was also revised to state that visual inspections will be supplemented by impulse response (IR) 

mapping and/or other established NDE methods. The applicant stated that IR mapping will be 

performed on a total of eight 100 square foot grid areas of the exposed exterior of the shield 

building; inspections will be performed in four areas in 2016 and four areas in 2018. For the IR 

mapping to be conducted in the 2016 and 2018 inspections, two grids will be in areas known to 

have cracks and two grids in areas not currently known to contain laminar cracks, with all areas 

being away from existing core bores. These IR mapping inspections will be performed with the 

objective to identify changes in the limits of cracking outside the areas inspected by visual 

examination of core bores. The applicant stated that IR mapping will also be used to 

supplement visual inspections in a minimum 100 square foot area near leading edge core bores

with identified crack propagation to provide an indication of the extent of cracking propagation 

for condition monitoring. The applicant also stated that IR mapping will be performed in 

accordance with vendor procedures and if crack growth is identified the condition will be entered 

into FENOC’s Corrective Action Program.

The staff notes that the core bore inspection interval begins with inspections performed once

every year and that the inspection interval may be progressively incremented, only if the cracks 

remains passive, to 2 years and a maximum of 4 years. The staff finds the interval of inspection

acceptable because (1) it starts out conservatively at 1 year to include a complete winter cycle 

when propagation is likely, (2) it may be incremented only if aging effects are not identified, and 

(3) the maximum inspection interval of 4 years is more stringent than the GALL Report’s

recommended inspection frequency of 5 years for exterior concrete surfaces. The staff also 

notes that the program supplements visual inspections with IR mapping and/or other NDE 

methods and testing. As discussed in the “parameters monitored or inspected” program 

element, the staff finds the visual inspection method acceptable because visual inspection of 

core bores is a definitive method for detecting and characterizing changes in the laminar cracks.

Further, the staff finds the use of IR mapping as a supplement to visual inspections of core 

bores acceptable because it is an effective NDE method to detect propagation or new 

indications of laminar cracking and to update the planar extent of cracking condition in the shield 

building. The staff further notes that the identification of laminar crack propagation in 
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August/September 2013 and 2015 by visual inspection of core holes indicate that the visual 

method of inspection of representative core holes is effective in detecting aging effects prior to 

loss of intended function.

Based on its review of the program as amended by responses to RAIs B.2.43-4 through 

B.2.43-8 in letters dated July 3, 2014, October 28, 2014, and January 28, 2015, and LRA 

Amendment No. 60 dated October 6, 2015, the staff confirmed that the “detection of aging 

effects” program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4 and, 

therefore, the staff finds it acceptable.

Monitoring and Trending. LRA Section B.2.43, as amended by letter dated July 3, 2014, states 

that the Shield Building Monitoring Program will include a baseline inspection, performed prior to 

the period of extended operation and followed by periodic inspections of a representative and 

strategically located sample of a minimum of 23 core holes; includes consideration of past 

evidence of crack propagation in choosing inspection locations; and provides for the addition of 

new core holes for inspection. As previously discussed in the SER, inspection findings will be 

documented and evaluated by qualified engineering personnel such that the results can be 

trended. The applicant further stated that findings that do not meet the acceptance criteria will 

be evaluated and tracked using the Corrective Action Program.

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 this element should describe how data 

collected are evaluated.

The staff notes, based on the response to RAI B.2.43-8 evaluated in the “detection of aging 

effects” program element, that the data collected through inspections of the strategically located 

representative sample of 23 core holes includes appropriate recording and trending of the 

limiting “crack width” parameter required to evaluate aging effects on the bond strength of the 

rebar adjacent to the laminar cracking and will result in timely corrective or mitigative actions.

In LRA Amendment No. 60 dated October 6, 2015, the applicant revised the “monitoring and 

trending” program element to state that IR mapping will be completed on a minimum area of 100 

square feet in the vicinity of a core bore with identified laminar crack propagation “to provide a 

relative indication of the extent of cracking propagation for condition monitoring.” Based on the 

results obtained from the evaluation of new plant-specific operating experience observed during 

monitoring activities of the shield building performed in 2015, the applicant increased the 

minimum number of representative core bore holes to be inspected from 23 to 28, with a 

minimum of 14 of the core bore locations being currently uncracked. The applicant also 

increased the distribution of the inspections to include 9 (previously 8) out of 10 flute shoulder 

with high prevalence of laminar cracking. The 2015 plant-specific operating experience is 

documented and evaluated below in the “operating experience” program element subsection of 

this AMP.

Based on its review, the staff finds the monitoring and trending actions are acceptable because 

the inspection findings are being documented and evaluated by personnel qualified in 

accordance with industry standards, specifically ACI 349.3R, as recommended by the 

GALL Report. If inspection results do not meet the acceptance criteria, they will be evaluated 

and tracked, and the inspection frequency and sample size will be revised as necessary, and/or 

appropriately addressed in the Corrective Action Program.

The staff thus confirmed that the “monitoring and trending” program element satisfies the 
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criterion defined in SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.

Acceptance Criteria. By letter dated July 3, 2014, in response to the staff’s RAI B.2.43-4, which 

addressed the 2013 plant-specific operating experience of laminar crack propagation, the 

applicant provided LRA Amendment 51. The staff’s detailed discussion of RAI B.2.43-4 is 

documented in the “detection of aging effects,” and “operating experience,” program element 

evaluation of this AMP. In LRA Amendment 51 the applicant revised, in part, LRA 

Section B.2.43 to add that conditions to be evaluated following each inspection cycle for 

determination of acceptable results include conformance with the plant design and licensing 

basis, as well as comparison with previously determined crack propagation rates to identify 

potential changes in the driving force of the condition. Also, in LRA Amendment 54 dated 

January 28, 2015, in response to RAI B.2.43-7 discussed further below, the applicant revised, 

the “acceptance criteria” program element to reflect the above quantitative acceptance criteria, 

against which core hole inspection results will be evaluated to determine the need for any 

corrective actions. The staff reviewed the applicant’s revised “acceptance criteria” program 

element against the criteria in SRP-LR Section A.1.2.3.6, which states that the acceptance 

criteria of the program and its basis should be described. The acceptance criteria, against 

which the need for corrective actions are evaluated, should ensure that the intended functions 

are maintained consistent with all CLB design conditions during the period of extended 

operation. The SRP-LR also states that the program should include a methodology for 

analyzing the results against applicable acceptance criteria. The acceptance criteria could be 

specific numeric values, or could consist of a discussion of the process for calculating specific 

numerical values of conditional acceptance criteria.

In its review of the “acceptance criteria” program element, as revised by LRA Amendment 51, 

the staff identified the following concerns related to implementation of the “acceptance criteria” 

program element of the AMP:

• The primary structural concern of the laminar cracking and its propagation with regard to 

the capability of the shield building to perform its intended functions is the potential loss 

of bond between the concrete and the rebar at the location of the laminar cracks and the 

ability for stress transfer to take place between the concrete and the rebar. This would 

be a function of the laminar crack width and length (or planar limit) along the rebar or 

rebar lap-splice. In this regard, it was not clear to the staff what quantitative (numerical) 

limits of laminar cracking characteristics [i.e., crack width, crack length (or planar limit), 

number of locations, and distribution, etc.,] are bounded by the design basis 

documentation referenced in the Shield Building Monitoring Program to determine the 

need for corrective actions (e.g., re-evaluation of design basis documentation, repair).

• The “acceptance criteria” program element in the Shield Building Monitoring Program 

specifies that the core bore inspection findings on the concrete laminar cracking will be 

compared and evaluated against two sets of pre-determined criteria to identify the need 

for corrective actions prior to loss of structure or component intended functions. These 

criteria include: (1) whether the laminar cracking is not passive (i.e., indications of new 

cracking, discernible change in previously identified cracks, or changes in previously 

determined crack propagation rates), and (2) whether the overall observed conditions 

are bounded by evaluations in the plant design and licensing basis documentation. With 

regard to the second case, the program does not appear to provide pre-determined 

quantitative acceptance criteria against which quantitative inspection findings can be 

compared and evaluated to determine the need for corrective actions (e.g., re-evaluation 

of design basis documentation, repair).
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• The staff noted that Chapter 5 of ACI 349.3R does not provide quantitative acceptance 

criteria applicable to concrete laminar cracking. It was not clear to the staff how the 

evaluation criteria hierarchy in Figure 5.1 of ACI 349.3R will be applied to the core hole 

inspection findings of concrete laminar cracking, considering that only qualitative criteria 

related to whether laminar cracks are active or passive is available from Chapter 5 

ACI 349.3R that would apply to laminar cracking.

Based on the concerns identified above related to implementing the “acceptance criteria” 

program element, by letter dated December 29, 2014, the staff issued RAI B.2.43-7 requesting 

that the applicant:

(1) Provide information on quantitative (numerical) acceptance criteria for the shield building 

laminar cracking defined by bounding limits of laminar cracking characterized in terms of 

crack width, crack length (or planar limit), distribution, and/or any other appropriate 

parameters, against which the core hole inspection findings are compared and evaluated 

to determine (a) if the condition is bounded by and conforms to the design basis 

documentation referenced in the AMP (e.g., FENOC calculation C-CSS-099.20-063), 

and (b) if corrective actions (e.g., re-evaluation of design basis documentation, repair) 

are needed to ensure that the structure and component intended functions are 

maintained consistent with CLB design conditions during the period of extended 

operation.

(2) Explain how the evaluation criteria hierarchy in Figure 5.1 of ACI 349.3R will be applied 

to the core hole inspection findings of laminar cracking from the Shield Building 

Monitoring Program to determine whether or not the condition is acceptable after 

evaluation.

In its response to the first part of RAI B.2.43-7 by letter dated January 28, 2015, the applicant 

stated that the quantitative acceptance criteria for core bore inspections will be (a) the maximum 

crack width of 0.013 inch and (b) the maximum circumferential laminar crack planar limits 

(in percent, rounded to the nearest whole number) as identified in SER Table 3.0.3.3.9-2 below 

by region (elevation) of the shield building structure.

Table 3.0.3.3.9-2 Shield Building Laminar Cracking Planar Limits

Region Elevation (ft)

Planar Limit (percent 

[cracked])

1 801.0 – 812.75 0

2 774.5 – 801.0 70

3 643.0 – 774.5 20

4 565.0 – 643.0 0

The applicant clarified that the percent values provided are based on maximum currently 

observed cracked areas derived with respect to the entire surface area (i.e., vertical height 

multiplied by circumference) of the Region, and that Regions 1 and 4 are identified in the table 

as 0 percent cracked. The applicant also acknowledged that minor cracking exists in Region 4, 

which is negligible (i.e., less than 1 percent). In a telephone conference call on 

February 20, 2015, the applicant clarified that Region 1 was intended to be representative of the 

shield building dome above the spring line, which is monitored by the Structures Monitoring 

Program. The applicant also clarified in the call that there are no core holes in Region 1, and it 
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is only Regions 2 through 4 that are monitored by core hole inspections in the Shield Building 

Monitoring Program.

In its response to RAI B.2.43-7, the applicant also clarified that its design calculation reflects the 

results of the Purdue University and University of Kansas lap-splice test programs for the design 

basis capacity of the exterior hoop rebar that could potentially be affected by laminar cracking. 

The applicant stated that the test programs developed laminar cracks along the complete splice 

length and neglected the staggered location of lap splices in the actual shield building design, 

and that the results are bounding and conservative. Therefore, the splice distribution and crack 

length and width in relation to splice location are not considered an acceptance criteria 

parameter. The applicant also stated that the values of acceptance criteria above are bounded

by the shield building design calculation. The applicant explained that if any of the quantitative 

acceptance criteria are not met based on core hole inspection findings, then the indications or 

conditions will be evaluated under the Corrective Action Program, which may result in corrective 

actions such as increased inspection frequency, re-evaluation of design basis documentation, or 

repair, as appropriate. As part of its RAI response, the applicant revised, in LRA Amendment 

54, the “acceptance criteria” program element to reflect the above quantitative acceptance 

criteria, against which core hole inspection results will be evaluated to determine the need for 

corrective actions (if any).

In its response to the second part of RAI B.2.43-7, by letter dated January 28, 2015, the 

applicant stated that the 3-tiered evaluation criteria hierarchy illustrated in Figure 5.1 of 

Chapter 5 of ACI 349.3R was and will be applied to the shield building for the purposes of 

condition determination and functionality. The applicant stated that since the shield building 

laminar cracking condition is not passive at this time, Section 5.1, “Acceptance without further 

evaluation,” and Section 5.2, “Acceptance after review,” of ACI 349.3R are not applicable, and 

therefore, the structure was placed into the Figure 5.1 category of “Conduct Further Enhanced 

Inspections, Testing and Analyses,” based on the guidance of Section 5.3, “Conditions requiring 

further evaluation.” The applicant also stated that inspections and analysis of the structure were 

completed as described in Section 5.3 of ACI 349.3R, inclusive of the research lap-splice testing 

conducted at Purdue University and the University of Kansas, and of the revised design 

calculations. The applicant concluded that the “as-found condition is acceptable after 

evaluation” with regard to the structural adequacy of the shield building to perform its intended 

functions, as documented in its design basis calculation. The applicant stated that this places 

the structure in the “accept condition without further evaluation” conclusion of Figure 5.1 for the 

current condition. However, the applicant further explained that because of crack propagation 

identified in 2013, the condition is currently considered “not passive” and may change over time; 

therefore, the shield building is subject to ongoing monitoring by the Shield Building Monitoring 

Program during the period of extended operation. The applicant indicated that the option from 

Figure 5.1 being currently applied to address the “not passive” condition is to monitor core holes 

at an increased frequency, until no aging effects are occurring on the laminar cracks based on 

future inspections, as indicated in the “detection of aging effects” program element revised by 

letter dated July 3, 2014. The applicant also stated that inspection findings will continue to be 

evaluated under the Corrective Action Program when conditions adverse to quality are 

identified.

In a telephone conference call on February 20, 2015, the applicant clarified that if the crack size 

and/or planar limits change in future inspections, the new condition would be entered into its 

Corrective Action Program and would require re-evaluation against the structural evaluation 

hierarchy in Figure 5.1 of ACI Report 349.3R to ensure that the appropriate inspection 

frequency and scope are applied and an acceptable conclusion is reached for the condition 
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found at each inspection cycle. During the call the applicant also clarified its implementation 

process for the program’s acceptance criteria. The applicant clarified that it would write a 

condition report in the FENOC Corrective Action Program based on any one or more of the 

following inspection findings:

• evidence of coating degradation that exceeds the criteria specified in the quantitative 

acceptance criteria for coatings in Chapter 5, Sections 5.1.4 and 5.2.4, of ACI Report 

349.3R

• evidence of reinforcing bar corrosion or degradation

• any indication of new cracking

• a discernable change in previously identified cracks, such as a change in crack width or 

planar size

• a crack width greater than 0.013 inch

• maximum planar crack limits exceeding a value shown in SER Table 3.0.3.3.9-2 above

During the telephone conference call, the applicant also clarified that its evaluation of the 

condition through the Corrective Action Program would result in comparing the inspection 

results to design calculation limits to ensure the condition is bounded. For a change in crack 

planar limits or if a crack expands into a non-cracked bore, the Corrective Action Program 

review would trigger an evaluation to determine whether a new core bore needs to be installed 

to monitor future changes in the planar limits.

In its review of the first part of the RAI B.2.43-7 response, the staff noted that the laminar “crack 

width” is the limiting parameter with regard to the impact of the laminar cracking on the bond 

capacity of the outer hoop rebar and, thereby on the intended functions of the shield building. 

The staff also noted that the parameter defining the “planar limit” of cracking provides the 

means of tracking and trending the extent of laminar cracking in the shield building. Together, 

these parameters provide the means of tracking and evaluating potential crack propagation to 

determine if corrective actions are needed prior to loss of intended function. The applicant 

clarified, in a conference call on February 20, 2015, that if any of the quantitative limits (crack 

width, defined planar limit) for the crack parameters defined in the acceptance criteria are not 

met, or if there is any discernable change in the laminar cracks, the condition will be evaluated 

in the Corrective Action Program. The staff finds the response to the first part of RAI B.2.43-7 

acceptable because the applicant defined quantitative acceptance criteria in terms of the critical 

crack width and planar limit parameters, against which core hole inspection findings are 

evaluated to ensure that corrective actions are taken, as appropriate, prior to the loss of 

intended functions of the shield building.

In its review of the second part of the RAI B.2.43-7 response, the staff noted that if the core hole 

inspection finding determines that there is a discernable change in the cracking or if the 

quantitative acceptance criteria are not met, the condition is considered as “not passive” and 

considered as a condition requiring further evaluation in accordance with Section 5.3 of 

ACI 349.3R. Further, even though the condition is found acceptable with regard to structural 

adequacy following further technical evaluation and/or testing, the condition is considered “not 

passive” and subject to monitoring at an increased frequency until it is established through 

several consecutive future inspections that the condition is passive. The staff finds the 

response to the second part of RAI B.2.43-7 acceptable because the applicant clearly explained 

its application of the evaluation criteria hierarchy in Figure 5.1 of ACI 349.3R to core hole 
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inspection findings, which the staff determined to be appropriate. The staff’s concerns 

described in RAI B.2.43-7 are resolved.

By letter dated October 6, 2015, the applicant revised the “acceptance criteria” program element 

to state that concrete found to be cracked during IR mapping will be compared to the shield 

building baseline inspection and if crack growth is identified the condition will be entered into 

FENOC’s Corrective Action Program.

As described above, the staff reviewed the applicant’s updated acceptance criteria for findings

from the core bore inspections, IR mapping, and the concrete surface inspections and finds 

them acceptable. The acceptance criterion for the core bore inspections is effectively no 

discernable change in laminar cracking, and the defined quantitative limits for crack width and 

planar limit are both met. Any indication of crack growth, or a new crack, will be evaluated and 

entered into the Corrective Action Program. The acceptance criteria for core bore inspection 

findings, against which the need for corrective actions are evaluated, will ensure that the shield 

building intended functions are maintained consistent with CLB conditions during the period of 

extended operation.

The staff thus confirmed that the “acceptance criteria” program element satisfies the criterion 

defined in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable.

Operating Experience. The staff reviewed the applicant’s “operating experience” program 

element against the acceptance criteria in SRP-LR Section A.1.2.3.10, which states that 

consideration of future plant-specific and operating experience relating to AMPs should be 

discussed. Operating experience with similar existing programs should be discussed. The 

operating experience of AMPs that are existing programs, including past corrective actions 

resulting in program enhancements or additional programs, should be considered. Additionally, 

for new AMPs, an applicant should commit to a review of future plant-specific and industry 

operating experience for new programs to confirm their effectiveness.

The staff noted that the applicant previously reviewed industry operating experience and 

plant-specific experience with maintenance rule inspections of the shield building when 

developing the new program. In addition, the staff noted that the “operating experience” 

program element of the AMP states that future operating experience would be reviewed and 

incorporated into the program as necessary.

During Fall 2013 and early 2014, the staff became aware of the following plant-specific 

operating experience related to the shield building: (1) discovery of previously unidentified 

laminar cracks in several core bore holes during the baseline inspection conducted in

August/September 2013, and (2) broken or cracked (damaged) rebar found in February 2014 

near several mechanical splice locations during hydro-demolition activities for the creation of a 

temporary construction opening to support steam generator replacement. As indicated in the 

previous paragraph, the “operating experience” program element of the Shield Building 

Monitoring Programs states that future operating experience would be reviewed and 

incorporated into the program as necessary. The staff was concerned if this plant-specific 

operating experience had any impact on the AMPs credited for the shield building aging 

management for license renewal. Therefore, by letter dated April 15, 2014, the staff issued 

RAI B.2.43-4 requesting the applicant to describe and justify modifications or enhancements, if 

any, that may be potentially made to the AMPs, credited for the shield building for license 

renewal, to account for (1) plant-specific operating experience related to cracking identified in

August/September 2013, and (2) the damaged rebar found in February 2014 in the temporary 
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construction opening area. The staff also requested that the applicant provide its basis if no 

changes to the AMPs were required.

The applicant provided its response to RAI B.2.43-4 by letter dated July 3, 2014. In its response 

to the second part of RAI B.2.43-4, related to the damaged rebar, the applicant stated that no 

revision to the AMPs will be made as a result of the rebar that were found broken or cracked in 

the shield building construction opening area in February 2014. The applicant stated that the 

rebar failure near the mechanical splice locations in the temporary construction opening area 

did not represent an aging management issue because it was caused by hydro-demolition from 

changes in rebar restraint, an increase in rebar dowel length, a decrease in temperature, and an 

increase in stress cycles from hydro-demolition trimming which collectively caused fatigue 

failure. The applicant also stated that all exposed rebar were examined and the damaged rebar 

were replaced prior to restoration of the construction opening.

The staff finds the applicant’s response to the second part of RAI B.2.43-4, related to the 

February 2014 rebar damage, acceptable because the rebar failure resulted from the physical 

process of hydro-demolition for creation of the temporary construction opening, it was evaluated 

and addressed prior to restoration of the opening, and it did not represent an aging effect or 

aging management issue for license renewal. The staff’s concern described in the second part 

of RAI B.2.43-4 is resolved.

In its response to the first part of RAI B.2.43-4, related to the August/September 2013 discovery 

of previously unidentified cracks, the applicant characterized the “newly” identified cracks as 

propagation of laminar cracking by the phenomenon of “ice-wedging” and stated that the 

minimum representative sample of monitored core bores in the Shield Building Monitoring 

Program was increased from 20 to 23 as a result of this plant-specific operating experience with 

3 additional bores added to aid in identifying changes in the limits of cracking in areas with 

previously identified crack propagation. The applicant further stated that the frequency of 

internal visual inspection for the 23 monitoring bores is changed to annual inspections for a 

minimum of 4 years (2015-2018) and then progressively increased to a 4-year interval 

after 2026 if no aging effects are found. Further, the applicant stated that these inspection 

intervals will be evaluated for effectiveness and modifications to the Shield Building Monitoring 

Program will be determined in the Corrective Action Program, should there be an identified 

significant change in cause, rate of crack growth, or a condition that is not bounded by the 

design basis documentation. The applicant revised the USAR Supplement of the AMP in LRA 

Section A.1.43 to address the changes regarding selection of additional core hole locations in 

the representative inspection sample. The applicant also revised the description of the AMP in 

LRA Section B.2.43 to include an operating experience summary of the previously unidentified 

crack conditions found in 2013 and results of the evaluation of the crack progression. The 

applicant revised the “detection of aging effects,” “monitoring and trending,” “acceptance 

criteria,” and “operating experience” program elements of the Shield Building Monitoring 

Program to incorporate changes due to the plant-specific operating experience of crack 

propagation. The staff notes that these changes have been reflected and evaluated in the staff 

evaluation sections above for the respective program elements of the Shield Building Monitoring 

Program.

The applicant supplemented the “operating experience” program element with the following 

description of the 2013 plant-specific operating experience:

Inspections of 12 core bores were completed in 2013 under the “Design Guidelines for 

Maintenance Rule Evaluation of Structures” Procedure EN-DP-01511. During that cycle 
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of inspections, a crack was observed in one of the core bores. This finding, upon a 

review of records, was determined to be a pre-existing crack given that the extracted 

concrete core was cracked at the location identified. Given this finding, the inspection 

population was increased, eventually leading to inspection of all available core bores. 

This re-inspection identified a total of 7 core bores with similar conditions that were 

determined to be pre-existing. This re-inspection also identified eight conditions where 

the laminar cracking conditions were determined to have undergone a discernable 

change.

The cracking propagation was determined to be a result of ice-wedging (freezing water 

at a pre-existing crack leading edge). This condition requires water, freezing 

temperatures and pre-existing cracks. Because the [s]hield [b]uilding has been coated 

[Fall 2012] it contains a finite amount of water. It is not practical to remove the water in 

an accelerated manner given the cumulative magnitude of leading crack edges and 

transportability of water. It is also not practical to remove the existing cracks or prevent 

freezing temperatures. The rate of cracking propagation is estimated at 0.4 to 

0.7 inches per freezing cycle based on laboratory simulation. By application of the 

evaluation criteria hierarchy of ACI 349.3R “Evaluation of Existing Nuclear 

Safety-Related Concrete Structures” Figure 5.1, the condition was acceptable through 

evaluation. The condition was not passive; however, it was bounded by design basis 

documentation. The Shield Building Monitoring Program was changed to ensure 

conformance with the design requirements and to maintain the USAR functions.

The shield building laminar cracking condition has been evaluated with respect to the 

design basis functions of the shield building. The condition is documented in FENOC 

Calculation C-CSS-099.20-063, as supported by Bechtel Report “Effect of Laminar 

Cracks on Splice Capacity of No. 11 Bars based on Testing Conducted at Purdue 

University and University of Kansas for Davis-Besse Shield Building,” that the shield 

building meets all design requirements specified in the USAR and it will perform its 

USAR described design functions. This analysis bounds the identified changes in the 

laminar cracking condition from the conditions identified in 2011.

The staff evaluation of the applicant’s response to the first part of RAI B.2.43-4, related to the 

“operating experience” program element, is provided here. The staff noted that the applicant’s 

causal analysis characterized the 2013 plant-specific operating experience as laminar crack 

propagation determined to be the result of an “ice-wedging” mechanism (i.e., freezing and 

expansion of water at a pre-existing crack leading edge). The applicant determined that for this 

condition to occur requires pre-existing cracks, water in the laminar cracks, and freezing 

temperatures. The staff finds that the applicant’s response to RAI B.2.43-4 with regard to the 

“operating experience” program element of the Shield Building Monitoring Program is 

acceptable because: (1) it provided an adequate review and characterization of the plantspecific operating experience of previously unidentified cracks discovered in 2013 and their

apparent cause, (2) it confirmed the effectiveness of the AMP and identified areas for 

enhancements, and (3) it described modifications and enhancements to the applicable program 

elements to appropriately account for the plant-specific operating experience to ensure 

adequate aging management. The staff’s concern with regard to the “operating experience” 

program element aspects of RAI B.2.43-4 is resolved. The staff evaluation of the applicant’s 

response to the remaining aspects of the first part of RAI B.2.43-4, with regard to change in 

sample size and inspection frequency, are addressed in the “detection of aging effects” program 

element and are also acceptable. Therefore, the staff’s concerns described in RAI B.2.43-4 are 

resolved.
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By letter dated October 6, 2015, the applicant revised the “operating experience” program 

element to incorporate plant-specific operating experience resulting from the shield building 

monitoring activities performed in 2015. The applicant stated that it completed the inspection of 

23 core bores in 2015 and observed cracking propagation in two of the locations where 

propagation was identified in 2013, as well as in one additional location. The applicant stated 

that the condition was evaluated with respect to design basis functions, and determined to be 

acceptable and bounded by the plant’s design basis documentation (FENOC Calculations 

C-CSS-099.20-063 and C-CSS-099.20-069). The staff notes, as described in the “detection of 

aging effects” and “monitoring and trending” program elements above, that based on evaluation 

of the 2015 plant-specific operating experience, the applicant increased its core bore inspection 

sample size from 23 to 28.

Based on its review of LRA Section B.2.43 submitted by letter dated November 20, 2012, and 

as amended by letters dated July 3, 2014, January 28, 2015, and October 6, 2015, and the 

applicant’s responses to RAIs B.2.43-4 through B.2.43-8, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience related to the 

applicant’s program, which demonstrates that it can adequately manage the detrimental effects 

of aging on SSCs within the scope of the program and that implementation of the program has 

resulted in the applicant taking appropriate corrective actions. The staff thus confirmed that the 

“operating experience” program element satisfies the criterion in SRP-LR Section A.1.2.3.10 

and, therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A.1.43, as amended by letters dated July 3, 2014, and 

October 6, 2015, provides the USAR supplement for the Shield Building Monitoring Program. 

The staff reviewed this USAR supplement description of the program against the recommended 

description for this type of program as described in SRP-LR Table 3.0-1.

The staff noted that the supplement description contained an appropriate level of detail, 

including a discussion of the parameters monitored or inspected, representative core bore 

sample size, method and frequency of inspections, inspection location distribution and 

consideration of past evidence of crack propagation in choosing inspection locations, 

acceptance criteria, inspector qualifications, and a reference to the appropriate industry 

guidance documents, specifically ACI 349.3R. The staff also notes that the applicant committed 

(Commitment No. 46) to implement the new Shield Building Monitoring Program prior to 

October 22, 2016 (i.e., 6 months prior to entering the period of extended operation) for 

managing aging of applicable components. The applicant also committed (Commitment No. 20) 

to use the acceptance criteria of ACI 349.3R for inspection of the coatings.

Based on its review, the staff finds that the information in the USAR supplement, as amended 

by letters dated July 3, 2014, and October 6, 2015, is an adequate summary description of the 

program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant’s plant-specific Shield Building 

Monitoring Program, as submitted by letter dated November 20, 2012, and as amended by RAI

response letters dated July 3, 2014, October 28, 2014, and January 28, 2015; and LRA 

Amendment No. 60 dated October 6, 2015; the staff concludes that the applicant has 

demonstrated that the effects of aging on the shield building laminar cracking 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 

USAR supplement for this AMP, as amended by letter dated July 3, 2014, and concludes that it 

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).
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3.0.3.3.10 Service Level III Coatings and Linings Monitoring Program

Summary of Technical Information in the Application. After the LRA was submitted, based on 

reviews of recent industry operating experience and several LRAs, the staff identified an issue 

concerning loss of coating integrity of internal coatings of piping, piping components, heat 

exchangers, and tanks. By letter dated November 26, 2013, the staff issued RAI 3.0.3-3 

requesting that the applicant address how it will manage loss of coating integrity for internal 

coatings on in-scope piping, heat exchangers, and tanks.

As amended by letter dated January 31, 2014, LRA Section B.2.44 describes the new Service 

Level III Coatings and Linings Monitoring Program as plant specific. The LRA states that the 

AMP addresses organic (e.g., elastomeric or polymeric) and inorganic (e.g., zinc-based) internal 

coatings and linings (e.g., rubber, cementitious) on in-scope piping, piping components, heat 

exchangers, and tanks to manage the effects of loss of coating integrity. The LRA also states 

that the AMP proposes to manage this aging effect through periodic visual inspections of the 

coatings.

Staff Evaluation. The staff reviewed program elements one through six 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. The staff’s review of the “corrective actions,” 

“confirmation process,” and “administrative controls” program elements are documented in SER 

Section 3.0.4.

The staff recommended actions to manage loss of coating integrity for internal coatings of 

piping, piping components, heat exchangers, and tanks. The staff has determined that 

additional recommendations are appropriate to manage loss of coating integrity for internal 

coatings of piping, piping components, heat exchangers, and tanks. The staff has concluded 

that the following recommended actions provide one acceptable approach for managing the 

associated aging effects for components within the scope of license renewal. Throughout the 

remainder of this SER Section, the statement, “staff’s recommended actions to manage loss of 

coating integrity,” is in reference to this subsection of the SER. The staff concluded the 

following:

• Periodic visual inspections of coatings to detect blistering, cracking, flaking, peeling, 

delamination, rusting, spalling (for cementitious coatings), and physical damage should 

be conducted. For purposes of license renewal, physical damage would be limited to 

age-related mechanisms such as that occurring downstream of a throttled valve as a 

result of cavitation versus damage caused by inspection activities (e.g., chipping of the 

coating due to installation of scaffolding, removal and reinstallation of inspection ports). 

Inspections are conducted for each coating material and environment combination. The 

coating environment includes both the environment inside the component (e.g., raw 

water) and the metal to which the coating is attached.

• Baseline inspections should be conducted in the 10-year period prior to the period of 

extended operation. Subsequent inspections should be based on the results of these 

and follow-on inspections as follows:

(a) If no peeling, delamination, blisters, or rusting are observed during inspections, and 

cracking, flaking, or spalling (in cementitious coatings) has been found acceptable, 

subsequent inspections should be conducted 6 years after the most recent 
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inspection. Peeling, delamination, blisters, or rusting can be indicative of loss of 

adhesion that could result in the coating becoming debris or not being able to 

perform a corrosion deterrence function. Cracking, flaking, or spalling, although 

indicators of some degree of coating degradation, are not significant enough to 

require more frequent inspections as long as the condition has been found 

acceptable by qualified personnel. For example, despite cracking being found, the 

base metal could still be isolated from the environment and the coating retain 

sufficient integrity so as not to become debris.

(b) If the prior inspection results do not meet “a.” above, and a coatings specialist has 

determined that no remediation is required, subsequent inspections should be 

conducted 4 years after the most recent inspection. More frequent inspections are 

warranted to confirm the coatings specialist’s evaluation. If two sequential 

subsequent inspections demonstrate no change in coating condition, subsequent 

inspections may be conducted at 6-year intervals.

(c) Given that coatings in redundant trains are exposed to the same environment, the 

inspection interval may be extended to 12 years as long as: (a) the identical coating 

material was installed with the same installation requirements in redundant trains 

(e.g., piping segments, tanks) with the same operating conditions and at least one of 

the trains is inspected every 6 years, and (b) the coating is not in a location subject 

to turbulence that could result in mechanical damage to the coating.

(d) Given that the coatings installed on the internal surfaces of diesel fuel oil storage 

tanks are generally exposed to a static environment, the inspection interval may be 

conducted in accordance with GALL Report AMP XI.M30, “Fuel Oil Chemistry,” as 

long as the inspection results meet “a.,” above.

• The extent of inspections should include all accessible tank and heat exchanger internal 

surfaces. The staff recognizes that, for piping, extensive amounts of coating could be 

installed. GALL Report AMPs such as XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” are based on sampling a portion of the 

population. The staff has concluded that using a sampling-based extent of inspections is 

appropriate for coatings installed on the internal surfaces of piping. Where 

documentation exists that manufacturer recommendations and industry consensus 

documents (i.e., those recommended in RG 1.54, “Service Level I, II, and III Protective 

Coatings Applied to Nuclear Plants” or earlier versions of those standards) were used 

during installation, the extent of piping inspections may be 25 1-foot axial length 

circumferential segments of piping or 20 percent of the total length of each coating 

material and environment combination. This extent of sampling is consistent with 

several GALL Report AMPs. However, where documentation does not exist that 

manufacturer recommendations and industry consensus documents were used during 

installation, the staff has concluded that a larger extent of inspection is appropriate, 

consisting of 73 1-foot axial length circumferential segments of piping or 50 percent of 

the total length of each coating material and environment combination. Regardless of 

the extent of inspections, the inspection surface includes the entire inside surface of the 

1-foot sample. If geometric limitations impede movement of remote or robotic inspection 

tools, the number of inspection segments is increased in order to cover an equivalent 

length.
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• The staff has concluded that, where loss of coating integrity cannot result in downstream 

effects such as reduction in flow, drop in pressure, or reduction in heat transfer for 

in-scope components, a representative sample of external wall thickness measurements 

can be used to confirm the acceptability of the corrosion rate of the base metal in lieu of 

visual inspections of the coating. The wall thickness measurements are an appropriate 

method to manage loss of coating integrity in this case because base metal corrosion is 

the only effect of loss of coating integrity.

• RG 1.54 provides the staff position for training and qualifying individuals involved in 

coating inspections and evaluating degraded conditions.

• A pre-inspection review of the previous two inspections should be conducted, including 

reviewing the results of inspections and any subsequent repair activities. A coatings 

specialist should prepare the post-inspection report to include: a list and location of all 

areas evidencing deterioration, a prioritization of the repair areas into areas that must be 

repaired before returning the system to service and areas where repair can be 

postponed to the next refueling outage, and where possible, photographic 

documentation indexed to inspection locations. When corrosion of the base material is 

the only issue related to coating degradation of the component and when external wall 

thickness measurements are used in lieu of internal visual inspections of the coating, the 

corrosion rate of the base metal should be trended. These recommendations are 

consistent with ASTM D7167-05, “Standard Guide for Establishing Procedures to 

Monitor the Performance of Safety-Related Coating Service Level III Lining Systems in 

an Operating Nuclear Power Plant,” which is referenced in RG 1.54.

• Based on the staff’s review of industry documents (e.g., ASTM, EPRI), the staff has 

concluded that, with the exception of Service Level I qualification testing, there are no 

acceptance criteria in recognized industry consensus documents. Acceptance of 

degraded coatings is established by the coatings specialist. RG 1.54 states that, for 

Service Level I coatings: (a) peeling and delamination is not permitted, (b) cracking is 

not considered a failure unless it is accompanied by delamination or loss of adhesion,

and (c) blisters are limited to intact blisters that are completely surrounded by sound 

coating bonded to the surface. The staff has established the following acceptance 

criteria for loss of coating integrity, based on the recommendations in RG 1.54.

(a) Indications of peeling and delamination are not acceptable and the coating is 

repaired or replaced.

(b) Blisters can be evaluated by a coatings specialist qualified in accordance with an 

ASTM International standard endorsed in RG 1.54, including staff guidance 

associated with the use of a particular standard. Blisters should be limited to a few 

intact small blisters that are completely surrounded by sound coating bonded to the 

substrate. If the blister is not repaired, physical testing (e.g., lightly tapping the 

coating, adhesion testing) is conducted to ensure that the blister is completely 

surrounded by sound coating bonded to the surface. Acceptance of a blister to 

remain in service should be based both on the potential effects of flow blockage and 

degradation of the base material beneath the blister.

(c) If coatings are credited for corrosion prevention (e.g., corrosion allowance in design 

calculations is zero, the “preventive actions” program element credited the coating) 

and the base metal has been exposed or it is beneath a blister, the component’s 

base material in the vicinity of the degraded coating is examined to determine if the 

minimum wall thickness is met and will be met until the next inspection.
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(d) Indications such as cracking, flaking, and rusting are to be evaluated by a coatings 

specialist qualified in accordance with an ASTM International standard endorsed in 

RG 1.54, including staff guidance associated with the use of a particular standard.

(e) Minor cracking and spalling of cementitious coating is acceptable, provided there is 

no evidence that the coating is debonding from the base material.

(f) As applicable, wall thickness measurements meet design minimum wall 

requirements.

(g) Results of adhesion testing, when conducted, meet or exceed the degree of 

adhesion recommended in engineering documents specific to the coating and 

substrate.

• Coatings that do not meet the acceptance criteria should be repaired or replaced. 

Testing or examination is conducted to ensure that the extent of repaired or replaced 

coatings encompasses sound coating material. These recommendations are consistent 

with ASTM D7167-05, “Standard Guide for Establishing Procedures to Monitor the 

Performance of Safety-Related Coating Service Level III Lining Systems in an Operating 

Nuclear Power Plant,” which is referenced in RG 1.54.

Scope of Program. LRA Section B.2.44 states that the scope of the program includes internal 

coatings and linings for the fire water storage tank; portions of the underground fire water main 

piping and piping components; the diesel oil storage tank; main lubricating oil pump casings in 

the EDGs and station blackout diesel generator; piping in the circulating water system; and 

valves, strainers, and pumps in the service water system.

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 structures and components for which loss of coating integrity will be managed.

The staff finds the applicant’s “scope of program” program element to be adequate because the 

scope of internally coated in-scope piping, heat exchangers, and tanks has been identified.

Based on its review of the application, as amended by letter dated January 31, 2014, the staff 

confirmed that the “scope of program” program element satisfies the criterion defined in SRP-LR 

Section A.1.2.3.1 and, therefore, the staff finds it acceptable.

Preventive Actions. LRA Section B.2.44 states that the Service Level III Coatings and Linings 

Monitoring Program is a condition monitoring program that 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 some condition monitoring programs do not rely on 

preventive actions and thus, this information need not be presented.

The staff finds the applicant’s “preventive actions” program element to be adequate because

this program is a condition monitoring program that need not rely on preventive actions.

Based on its review of the application, as amended by letter dated January 31, 2014, the staff 

confirmed that the “preventive actions” program element satisfies the criterion defined in 

SRP-LR Section A.1.2.3.2 and, therefore, the staff finds it acceptable.
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Parameters Monitored or Inspected. LRA Section B.2.44 states that visual inspections of the 

coatings and linings will be used to detect blistering, cracking, flaking, peeling, delamination, 

physical damage of coatings, and rusting of the underlying base metal.

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 the program should identify 

the aging effects that the program manages and provide a link to the parameters that will be 

monitored and that the parameter monitored or inspected should be capable of detecting the 

presence and extent of aging effects.

The staff noted that the applicant did not address spalling in cementitious coatings; however, it 

is addressed in the “detection of aging effects” program element. The staff finds the applicant’s 

“parameters monitored or inspected” program element to be adequate because the aging 

effects and parameters monitored or inspected are consistent with the staff’s recommended 

actions to manage loss of coating integrity.

Based on its review of the application, as amended by letter dated January 31, 2014, the staff 

confirmed that the “parameters monitored or inspected” program element satisfies the criteria 

defined in SRP-LR Section A.1.2.3.3 and, therefore, the staff finds it acceptable.

Detection of Aging Effects. LRA Section B.2.44 states that baseline visual inspections will be 

conducted in the 10-year period prior to the period of extended operation, followed by periodic 

inspections. A coatings specialist will establish the periodicity of subsequent inspections, which, 

will be based on an evaluation of the effect of a coating failure on the in-scope component’s 

intended function, potential problems identified during prior inspections, and known service life 

history. The periodicity of subsequent inspections is subject to a maximum interval between 

inspections as follows:

• six years if no peeling, delamination, blisters, or rusting are observed and any cracking 

and flaking have been found acceptable

• six years for cementitious coatings where no cracking or spalling is observed

• twelve years if (a) the identical coating material was installed with the same installation 

requirements in redundant trains (e.g., piping segments) with the same operating 

conditions and at least one of the trains is inspected every 6 years, and (b) the coating is 

not in a location subject to turbulence

• every other refueling outage if the inspection results do not meet the criteria in the first 

two bullets, above, but a coating specialist has determined that no remediation is 

required, noting that the subsequent inspections will include locations that resulted in 

subsequent inspections being conducted, as well as new locations, and that following 

two sequential subsequent inspections that demonstrate no change in coating condition, 

subsequent inspections may be conducted at 6-year intervals

• a refueling outage interval for the two intervals following a coating repair or replacement 

or for newly installed coatings, to establish a performance trend on the coatings, after 

which the inspection interval may be increased by the coatings program owner as 

described above

• every 5 years for the fire water storage tank inspection interval, as established in 

NFPA 25, Section 9.2.6
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The program also includes both the extent of inspections (i.e., all accessible internal surfaces of 

in-scope internally coated tanks will be inspected and a representative sample of internally 

coated piping components consisting of at least 73 1-foot axial length circumferential segments 

of piping or 50 percent of the total length of each coating material and environment combination 

will be inspected) and the qualifications of individuals involved in coating inspection activities.

The program also states the following:

• Visual inspections are conducted in accordance with ASTM D7167-05, “Standard Guide 

for Establishing Procedures to Monitor the Performance of Safety-Related Coating 

Service Level III Lining Systems in an Operating Nuclear Power Plant.”

• Coatings surveillance personnel will be knowledgeable on coatings, meeting the 

requirements of ASTM D4537-12; “Standard Guide for Establishing Procedures to 

Qualify and Certify Personnel Performing Coating and Lining Work Inspection in Nuclear 

Facilities.”

• The coatings program owner will be a nuclear coatings specialist meeting the 

requirements of ASTM D7108-12, “Standard Guide for Establishing Qualifications for a 

Nuclear Coatings Specialist.”

• Wall thickness measurements can be performed in lieu of internal inspections to confirm 

the acceptability of the corrosion rate of the base metal if: (a) the degradation of 

coatings cannot result in downstream effects such as reduction in flow, drop in pressure, 

or reduction in heat transfer for in-scope components and (b) corrosion of the base 

material is the only issue related to coating degradation of the component; external.

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 should describe: (a) how 

the program element will be capable of detecting the occurrence of age-related degradation 

prior to the loss of the current licensing-basis intended function(s) of in-scope components; 

(b) the when, where, and how data is collected; and (c) the basis of the sample size and 

location selection.

The staff finds the applicant’s “detection of aging effects” program element to be adequate, in 

part because baseline inspections are conducted prior to the period of extended operation; the 

type of inspections, inspection intervals, extent of inspections, and sample size are consistent 

with the staff’s recommended actions to manage loss of coating integrity; and the qualifications 

of individuals conducting and overseeing coating inspections are consistent with the standards 

listed in RG 1.54 “Service Level I, II, and III Protective Coatings Applied to Nuclear Plants.” In 

addition, conducting internal coating inspections of fire water storage tanks at 5-year intervals is 

consistent with LR-ISG-2012-02 AMP XI.M27. However, the RAI response did not address how 

inspection locations would be selected and the length of piping that will be examined if 

geometric limitations impede access to the entire internal circumference of any piping segment. 

By letter dated July 7, 2014, the staff issued RAI 3.0.3-3a requesting that the applicant state the 

criteria for selecting a representative sample of internally coated piping and piping components 

and state the length of piping that will be examined if geometric limitations impede access to the 

entire internal circumference of any piping segment.

In its response dated July 29, 2014, the applicant stated that the criteria for the selection of 

inspection locations would be based on several factors. Examples of these factors include the 

effect of coating failure, areas with aggressive environmental conditions, problem areas based 

on plant-specific operating experience, and areas where physical damage could occur. The 
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applicant also stated that the axial length of inspected piping would be increased if geometric 

limitations prevented inspection of the complete circumferential surface area of the sample. The 

applicant provided an example consistent with the staff’s recommended actions to manage loss 

of coating integrity, above. The staff noted that the above changes were incorporated into LRA

Section B.2.44.

The staff finds the applicant’s response acceptable because the factors presented in the 

applicant’s response are inclusive of areas where the potential for loss of coating integrity is 

highest and the extent of pipe inspections ensures that, despite potential access limitations, an 

appropriate amount of piping will be inspected, consistent with the staff’s recommended actions 

to manage loss of coating integrity. The staff’s concern described in RAI 3.0.3-3a is resolved.

Based on its review of the application, as amended by letter dated January 31, 2014, and 

review of the applicant’s response to RAI 3.0.3-3a, the staff confirmed that the “detection of 

aging effects” program element satisfies the criteria defined in SRP-LR Section A.1.2.3.4 and, 

therefore, the staff finds it acceptable.

Monitoring and Trending. LRA Section B.2.44 states that, prior to performing inspections, a 

pre-inspection review of at least the previous two inspection reports will be conducted to identify 

areas where degraded coatings exist and any subsequent repair activities. Inspection results 

are reviewed by a qualified nuclear coatings specialist. Identified degradation that does not 

meet the acceptance criteria is documented and evaluated in accordance with the Corrective 

Action Program. The coatings program owner (or designee qualified as a nuclear coatings 

specialist) will evaluate inspection results and prepare the inspection report to include a list and 

location of all areas evidencing deterioration, a prioritization of the repair areas into areas that 

must be repaired before returning the system to service and areas where repair can be 

postponed to the next inspection, and where possible, photographic evidence indexed to 

inspection locations. When corrosion of the base material is the only issue related to coating 

degradation of the component and external wall thickness measurements are used in lieu of 

internal visual inspections of the coating, the corrosion rate of the base metal is trended.

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 noted that the applicant stated that previous inspection results would be reviewed and 

areas of coating degradation are to be documented and evaluated. In addition, when wall 

thickness measurements are used to monitor coated base material, the corrosion rate will be 

trended. The staff finds the applicant’s “monitoring and trending” program element to be 

adequate because it is consistent with the staff’s recommended actions to manage loss of 

coating integrity.

Based on its review of the application, as amended by letter dated January 31, 2014, the staff 

confirmed that the “monitoring and trending” program element satisfies the criteria defined in 

SRP-LR Section A.1.2.3.5 and, therefore, the staff finds it acceptable.

Acceptance Criteria. LRA Section B.2.44 states the definitions for potential degraded coating 

conditions (e.g., blistering - formation of bubbles in a coating film) and the corresponding 

acceptance criteria.
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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 the acceptance criteria of the program and its basis 

should be described and the acceptance criteria should ensure that the component’s intended 

function(s) are met.

The staff noted that the acceptance criteria are as follows: (a) acceptable coatings are free of 

peeling or delamination, (b) blistering will be evaluated by a nuclear coatings specialist to 

determine acceptability, (c) adhesion testing should be conducted to ensure that the blister is 

completely surrounded by sound coating bonded to the surface, (d) cracking, flaking, rusting, 

and physical damage will be evaluated by a nuclear coatings specialist to determine 

acceptability, (e) where access to the interior of components is permitted, adhesion testing 

should be conducted for coated areas that are determined to be suspect, deficient, or degraded 

as directed by the coatings program owner, (f) minor cracking and spalling of cementitious 

coatings is acceptable, provided there is no evidence that the coating is debonding from the 

base material, (g) wall thickness measurements meet design minimum wall requirements, and 

(h) adhesion testing results meet or exceed the degree of adhesion recommended in 

engineering documents specific to the coating and substrate. Coatings that do not meet the 

acceptance criteria will be documented in the Corrective Action Program. Corrective actions 

may include determining the cause of the coating failure, leaving the degraded coatings as-is 

until the next scheduled inspection, replacing, or repairing the coating. The staff finds the 

applicant’s “acceptance criteria” program element to be adequate, in part, because it is 

consistent with the staff’s recommended actions to manage loss of coating integrity. However, 

the staff noted that the applicant stated that adhesion testing should be conducted to ensure the 

blister is completely surrounded by sound coating bonded to the surface and where access to 

the interior of components is permitted. By letter dated July 7, 2014, the staff issued 

RAI 3.0.3-3b requesting that the applicant state what criteria will be used to determine when 

adhesion testing will be conducted.

In its response dated July 29, 2014, the applicant revised LRA Sections A.1.44 and B.2.44 to 

state that adhesion testing would be conducted in accordance with standards endorsed in 

RG 1.54, where physically possible, when the acceptance criteria for peeling, delamination, or 

blistering are met.

The staff finds the applicant’s response acceptable because adhesion testing will be conducted 

to ensure that the extent of indications of peeling, delamination, and blistering are understood, 

consistent with the staff’s recommended actions to manage loss of coating integrity, above. The 

staff recognizes that the applicant’s statement, “where physically possible,” is reasonable

because adhesion testing will not be able to be performed in all configurations due to access 

restrictions perpendicular to the degraded coating. In these instances, the knowledge and 

experience of the nuclear coatings specialist is relied upon to conduct an acceptable evaluation 

of the degraded coatings. The staff’s concern described in RAI 3.0.3-3b is resolved.

Based on its review of the application, as amended by letter dated January 31, 2014, and on its 

review of the applicant’s response to RAI 3.0.3-3b, the staff confirmed that the “acceptance 

criteria” program element satisfies the criteria defined in SRP-LR Section A.1.2.3.6 and, 

therefore, the staff finds it acceptable.

The staff finds the applicant’s response to RAI 3.0.3-3, RAI 3.0.3-3a, and RAI 3.0.3-3b 

associated with the “scope of program,” “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 
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program elements acceptable as documented above. The staff’s concern associated with these 

program elements in RAI 3.0.3-3 is resolved.

Operating Experience. LRA Section B.2.44 summarizes operating experience related to the 

Service Level III Coatings and Linings Monitoring Program. The applicant’s review of 

plant-specific operating experience related to Service Level Ill coatings revealed that the epoxy 

lining for the four service water system strainers has degraded in the past and significant base 

metal pitting has occurred. This operating experience provided the basis for the existing 

strainer replacement schedule. No downstream affects from the degraded coating were 

identified.

The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, as amended by LR-ISG-2011-05, which states that currently available 

operating experience applicable to new programs and consideration of future plant-specific and 

industry operating experience relating to AMPs should be discussed. The staff’s evaluation of 

the applicant’s consideration of future operating experience is documented in SER 

Section 3.0.5.

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, as amended by letter dated January 31, 2014, the staff 

finds that the applicant has appropriately evaluated plant-specific and industry operating 

experience. The staff confirmed that the “operating experience” program element satisfies the 

criteria in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A.1.44, as revised by letter dated July 29, 2014, provides the 

USAR supplement for the Service Level III Coatings and Linings Monitoring Program.

The staff reviewed this USAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1 for plant-specific 

programs.

The staff also noted that the applicant committed to implementing the new Service Level III 

Coatings and Linings Monitoring Program prior to October 22, 2016, for managing the effects of 

aging for applicable components.

The staff finds that the information in the USAR supplement is an adequate summary 

description of the program.
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Conclusion. On the basis of its technical review of the applicant’s Service Level III Coatings and 

Linings Monitoring 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 USAR supplement for this AMP and concludes 

that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.4 Aging Management Related to Recurring Internal Corrosion

3.0.3.4.1 Recurring Internal Corrosion

Summary of Technical Information in the Application. By letter dated February 19, 2014,the 

applicant provided changes to the Davis-Besse LRA to address the updated guidance in 

LR-ISG-2012-02, for loss of material due to recurring internal corrosion. Based on its reviews, 

the applicant identified recurring internal corrosion in the service water system at Davis-Besse 

and provided a new LRA Section 3.3.2.2, “Aging Management Review Results for Which 

Further Evaluation Is Recommended by NUREG-1801.” The new LRA Section 3.3.2.2.16, 

“Loss of Material Due to Recurring Internal Corrosion,” is associated with LRA Table 3.3.1, 

item 3.3.1-127, and addresses metallic piping components in auxiliary systems exposed to raw 

water for recurring loss of material. The LRA amendment states that ultrasonic thickness 

measurements identified piping segments in the service water system that were below 

procedural limits. The applicant evaluated the reduced wall thickness of the piping segments 

using the Corrective Action Program and replaced piping and associated components as 

required. The new LRA section also states that NDE methods, employing visual examinations 

and UT, are used to detect loss of material, prior to any loss of component intended function. 

When visual inspections detect surface irregularities that could indicate wall loss below nominal 

wall thickness, followup volumetric wall thickness examinations are performed. The applicant 

also stated that inspection procedures include acceptance criteria that are based on code 

requirements, design-basis calculations, or analyses of system performance (i.e., allowable wall 

thickness). The applicant concluded by stating that the Open-Cycle Cooling Water System 

Program uses the Corrective Action Program to document degradations and to evaluate 

corrosion rates, so that piping and related components are replaced prior to loss of function.

As part of the LRA amendment, the applicant also addressed AMR items 3.2.1-66 and 3.4.1-61, 

which are associated with the Further Evaluation items in the Engineered Safety Features 

Systems and the Steam and Power Conversion Systems, respectively. For both of these items, 

the applicant stated that Davis-Besse has no in-scope components subject to recurring internal 

corrosion in the related systems; therefore, these AMR items are not applicable.

Staff Evaluation. In its review of the amendment to the LRA, the staff noted that the applicant 

did not include all aspects of the acceptance criteria specified in LR-ISG-2012-02 for recurring 

internal corrosion. The applicant did not address the adequacy of augmented or lack of 

augmented inspections that will be performed and did not discuss the decision points, where 

increased inspections would be implemented. In addition, the applicant did not discuss how 

buried or underground components will be inspected, or how leaks in these components would 

be identified. Based on these concerns, by letter dated July 7, 2014, the staff issued 

RAI 2.3.3.26-2 requesting that the applicant provide a more comprehensive response that 

addresses all aspects of the Further Evaluation section for recurring internal corrosion included 

in LR-ISG-2012-02.
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In its response dated July 29, 2014, the applicant addressed each of the five elements 

associated with the further evaluation for recurring internal corrosion that were delineated in 

LR-ISG-2012-02. In addition, the applicant revised LRA Section 3.3.2.2.16 in its entirety, to 

reflect the changes for each of the five elements. The applicant clarified that the effects of 

aging, including recurring internal corrosion, will be managed by the open-cycle cooling water 

system during the period of extended operation. The applicant stated that the program’s 

examination methods, visual inspections, and augmented volumetric examinations have been 

demonstrated to be sufficient to detect recurring aging effects prior to any loss of component 

intended functions. With regard to the adequacy of inspections, the applicant stated that 

augmented volumetric inspections are performed where indications of wall loss below nominal 

pipe wall thickness are detected. In addition, corrosion rates are evaluated through the 

Corrective Action Program to replace components prior to loss of function. The applicant stated 

that wall thickness will be trended and the frequency of the inspections will be adjusted based 

on the observed trends. With regard to inspections of components not easily accessed and the 

identification of leaks in any buried components, the applicant stated that it will use UT and 

video cameras to provide information on the internal condition of the piping. Furthermore, 

system leaks will be identified through flow monitoring.

The staff finds the applicant’s revised response acceptable because the examination methods 

proposed by the applicant will be sufficient to detect recurring internal corrosion. Specifically, 

the visual inspections followed by the augmented volumetric examinations will be adequate for 

detecting indications of wall loss below nominal pipe wall thicknesses, and subsequent 

inspection frequencies can be adjusted based on observed corrosion rates.

Based on the program identified, the staff also determines that the applicant’s program meets 

SRP-LR Section 3.3.2.2.8 (as modified by LR-ISG-2012-02). For the item associated with LRA

Section 3.3.2.2.16, 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). In addition, the staff evaluated the applicant’s 

claim that AMR items 3.2.1-66 and 3.4.1-61 are not applicable and finds it acceptable, based on 

the associated statements in its response dated February 19, 2014.

3.0.3.5 Staff Evaluation of LRA Changes To Incorporate LR-ISG-2012-01, “Wall Thinning 

Due to Erosion Mechanisms”

Summary of Technical Information in the Application. By letter dated June 23, 2014, the 

applicant provided its evaluation of LR-ISG-2012-01, “Wall Thinning Due to Erosion 

Mechanisms.” The applicant used keywords from the LR-ISG to search its corrective action 

database for previously identified issues related to erosion, flashing, or cavitation at 

Davis-Besse. The applicant’s review identified issues of cavitation that had been addressed by 

either design or operational changes to eliminate the issue. In addition, the applicant noted that 

erosion in raw water systems is being managed by the Open-Cycle Cooling Water AMP. The 

applicant stated that plant operating experience shows that an additional monitoring program is 

not needed to manage erosion, flashing, or cavitation.

Staff Evaluation. The staff independently searched the applicant’s operating experience 

database as part of its review of the Flow-Accelerated Corrosion Program during the onsite 

AMP Audit. During its reviews, the staff did not identify any concerns related to cavitation or 

erosion. The staff also noted that its evaluation of the applicant’s Open-Cycle Cooling Water 

Program, as documented in SER Section 3.0.3.2.12, includes activities to manage loss of 
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material due to erosion. The staff finds the applicant’s evaluation of LR-ISG-2012-01 

acceptable and agrees with the applicant’s determination that an additional monitoring program 

is not needed for managing wall thinning due to erosion mechanisms.

Conclusion. The staff has concluded that the applicant’s evaluation of LR-ISG-2012-01 has not 

resulted in any changes to the staff’s previously issued SER Section 3.0.3.2.12.

3.1 Aging Management of Reactor Vessel, Internals, Reactor Coolant System 

and Reactor Coolant Pressure Boundary, and Steam Generators

3.1.1 Summary of Technical Information in the Application

The staff does not have any changes or updates to this section of the SER.

Table 3.1-1 Revisions to SER Table 3.1-1

Component 

Group 

(GALL Report

Item No.) 

Aging Effect/ 

Mechanism 

AMP in 

GALL Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments 

Staff 

Evaluation 

Steel with 

stainless steel or 

nickel-alloy 

cladding primary 

side 

components; SG 

upper and lower 

heads, 

tubesheets and 

tube-to-tube 

sheet welds

(3.1.1-35)

Cracking due to 

SCC and 

PWSCC

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry 

and for nickel 

alloy, comply 

with applicable

NRC Orders and 

provide a 

commitment in 

the USAR 

supplement to 

implement 

applicable 

Bulletins and 

GLs and 

staff- accepted 

industry 

guidelines.

No, but 

applicant 

commitment 

needs to be 

confirmed

ISI, PWR Water 

Chemistry, 

Steam 

Generator Tube 

Integrity

Consistent with 

GALL Report

(see SER 

Section

3.1.2.2.16(1))

Chrome plated 

steel, stainless 

steel, 

nickel-alloy SG 

anti-vibration 

bars exposed to 

secondary 

feedwater/steam 

(3.1.1-74) 

Cracking due to 

SCC, loss of 

material due to 

crevice 

corrosion and 

fretting 

Steam 

Generator Tube 

Integrity and 

Water Chemistry 

No Loss of material 

and cracking 

Consistent with 

the 

GALL Report

(See revisions to 

SER Section

3.1.2.1.1)

3.1.2 Staff Evaluation

3.1.2.1 AMR Results Consistent with the GALL Report

The staff does not have any changes or updates to this section of the SER.
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3.1.2.1.1 AMR Results Identified as Not Applicable

The applicant submitted an annual update to the LRA by letter dated June 23, 2014, as 

amended by letter dated September 16, 2014. In its LRA update, the applicant revised LRA

Table 3.1-1, AMR item 3.1.1-74, to address cracking due to SCC and loss of material due to 

crevice corrosion and fretting as applicable aging effects for SG secondary side components. 

These components are fabricated of chrome plated steel, stainless steel, and nickel alloy and 

are exposed to secondary water and steam. Specifically, the applicant updated LRA

Table 3.1.2-4 to manage cracking and loss of material for SG tube support rods (also called tie 

rods) using the Steam Generator Tube Integrity Program and Water Chemistry Program.

In its review, the staff finds the applicant’s update regarding AMR item 3.1.1-74 acceptable 

because the Steam Generator Tube Integrity Program includes visual inspections of SG

secondary side components to confirm the integrity of these components and the Water 

Chemistry Program monitors and controls secondary-side water chemistry to minimize 

environmental effects on cracking and loss of material in these components, consistent with the 

GALL Report.

3.1.2.1.5 Aging Management of Reactor Vessel Internals (RVI) Vent Valve Assembly 

Components

LRA Table 3.1.1, as amended in a letter dated March 9, 2012 (ADAMS Accession 

No. ML12094A383), includes AMR item 3.1.1-11 which addresses CASS RVI vent valve upper 

and lower retaining rings exposed to a borated reactor coolant with neutron fluence 

environment. In this AMR item, the applicant states that the vent valve upper and lower 

retaining rings will be managed for reduction of fracture toughness due to thermal aging 

embrittlement. For this AMR item that cites generic note E, the LRA credits the PWR Reactor 

Vessel Internals Program to manage the applicable aging effect.

GALL Report AMP XI.M16A, PWR Vessel Internals, as updated in NRC LR-ISG-2011-04, 

recommends use of condition monitoring activities to manage reduction of fracture toughness in 

the vent valve upper and lower retaining rings of B&W-designed PWRs, including Davis-Besse.

2

 

The staff noted that, in general, this program applies either volumetric or visual inspection 

methods to manage aging effects of cracking, loss of material, and changes in dimension that 

may be occurring in the RVI components, and to manage loss of preload of bolts, keys, or other 

fasteners in bolted or fastened RVI assemblies. The staff also noted that this program uses the 

condition monitoring methods that are applied for detection cracking as an indirect basis for 

detecting and managing those changes that may be occurring in a component’s material 

properties, including reduction of the fracture toughness property for a component’s specific 

material of fabrication.

In the applicant’s letter of April 21, 2015, the applicant identified a deviation with respect to the 

design of the vent valve assemblies at Davis-Besse when compared to the generic vent valve 

assembly design that was evaluated in the MRP-227-A and MRP-189, Revision 1 reports. 

However, in this letter, the applicant stated that the I&E methods in MRP-227-A for 

 2 The condition monitoring bases for inspecting the upper and lower retaining rings in the vent valve assemblies are

given in EPRI TR No. 1022863, “Materials Reliability Program: Pressurized Water Reactor Internals Inspection 

and Evaluation Guidelines” (MRP-227-A), December 2011. Henceforth, this report will be referred to as 

MRP-227-A or the MRP-227-A report. Refer to ADAMS Accession No. ML12017A193 for the transmittal letter 

from the EPRI-MRP that submitted the report to the NRC Document Control Desk and ADAMS Accession 

Nos. ML12017A194, ML12017A196, ML12017A197, ML12017A191, ML12017A192, ML12017A195, and 

ML12017A199 for the sections in the MRP-227-A report.
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B&W-designed vent valve assembly components would not need to be further adjusted for 

aging management because the CLB had existing program surveillance testing and inspection 

requirements in the TS that would accomplish adequate aging management of those specific 

vent valve assembly components (including vent valve locking devices) not assessed in the 

MRP-189, Revision 1, report.

The staff noted that, for RVI vent valve assembly components in B&W-designed reactors like 

Davis-Besse, implementation of the MRP-227-A guidelines only applies visual VT-3 inspections 

to the upper and lower retaining rings in the vent valve assemblies and does not implement 

inspections of the valve bodies or any other miscellaneous parts of the vent valve assemblies. 

However, the staff also noted that the CLB includes TS 5.5.4, “Reactor Vessel Internals Vent 

Valve Program,” which requires the applicant to implement the following surveillance inspection 

and testing requirements to the vent valve assemblies once every 24 months:

(a) Verify by visual inspection that the valve body and disc exhibits no abnormal 

degradation.

(b) Verify the valve is not stuck in an open position.

(c) Verify by manual actuation that the valve is fully open when a force of less than or equal 

to 400 lbs is applied vertically upward.

However, the staff noted that the applicant did not credit the TS 5.5.4 surveillance requirements 

as additional condition monitoring and performance monitoring activities for those vent valve 

bodies and parts that are not scheduled for inspection in accordance with MRP-227-A. Thus, in 

its review of AMR item 3.1.1-11, the staff did not find the applicant’s proposal to manage aging 

using the PWR Reactor Vessel Internals Program to be acceptable because the AMR basis did 

not credit the TS 5.5.4 requirements as additional condition monitoring and performance 

monitoring activities for the vent valve assembly components. Therefore the deviation with 

respect to the assessment of vent valve assembly components in MRP-189, Revision 1, had yet 

to be resolved with respect to the AMR in AMR item 3.1.1-11.

The staff discussed this matter with the applicant in a teleconference on May 19, 2015. To 

address this issue, the applicant submitted an amended version of AMR item 3.1.1-11 for the 

vent valve assembly components in a letter dated June 5, 2015. In the amended version of the 

AMR item 3.1.1-11, the applicant amended the AMR item to add in a plant-specific AMR item 

note that credits the applicable requirements of TS 5.5.4 as being additional condition 

monitoring and performance monitoring activities that apply to the vent valve assembly 

components, including the vent valve bodies and miscellaneous vent valve parts. This is in 

addition to the use of the PWR Reactor Vessel Internals Program for implementing inspections 

of the upper and lower vent valve assembly retaining rings during the period of extended 

operation.

The staff reviewed the changes to AMR item 3.1.1-11. The staff noted that the addition of the

TS 5.5.4 requirements to AMR item 3.1.1-11 is consistent with the CLB for Davis-Besse. 

Furthermore, in Section 3.0.3.3.6 of this SSER, the staff provides its supplemental evaluation of 

the applicant’s PWR Reactor Vessel Internal Program, and response to A/LAI #2, which was 

issued on implementation of the MRP-227-A report. In this evaluation, the staff provides its 

basis for concluding that the PWR reactor Vessel Internals Program, when taken into account 

with the surveillance inspection and testing requirements in TS 5.5.4, provides for adequate 

aging management of those aging effects that apply to the vent valve assembly components at 
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Davis-Besse. Therefore, based on this review, the staff finds that the amended version of AMR 

item 3.1.1-1 is acceptable because: (a) the applicant has credited both the augmented criteria 

in MRP-227-A for inspecting vent valve upper and lower retaining rings (as implemented in 

accordance with the PWR Reactor Vessel Internals Program) and the surveillance inspection 

and testing requirements in TS 5.5.4 as the bases for managing aging in the vent valve 

assembly components, (b) the staff has determined the collective set of condition monitoring 

and performance monitoring criteria for vent valve assembly components in MRP-227-A and

TS 5.5.4 provide for adequate aging of vent valve assembly components, and (c) the staff has 

determined that the applicant’s bases for managing aging of vent valve assembly components is 

consistent with the CLB. The deviation from the assessment basis in MRP-189, Revision 1, for 

vent valve assembly components is resolved both with respect to the applicant’s PWR Reactor 

Vessel Internals Program and the AMR bases in AMR item 3.1.1-11 of the LRA.

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

3.1.2.2.16 Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion 

Cracking

Item1. In LRA Table 3.1.2-4, as amended by letter dated June 23, 2014, item 3.1.1-35 

addresses nickel Alloy 690 primary side steam generator upper and lower heads, tubesheets, 

and tube-to-tubesheet welds exposed to borated reactor coolant ,which are being managed for 

cracking due to primary water stress corrosion cracking (PWSCC). For the AMR item that cites 

generic note E, the LRA credits the Inservice Inspection, PWR Water Chemistry, and Steam 

Generator Tube Integrity Programs to manage the aging effect. The GALL Report recommends 

GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, IWC, and 

IWD,” for Class 1 components, and GALL Report AMP XI.M2, “Water Chemistry,” to ensure that 

these aging effects are adequately managed.

For the item associated with generic note E, GALL Report AMP XI.M1 recommends periodic 

visual, surface, and/or volumetric examination and GALL Report AMP XI.M2 recommends using 

water chemistry controls to manage aging. In its review of components associated with 

item 3.1.1-35 for which the applicant cited generic note E, the staff noted that the Inservice 

Inspection Program proposes to manage nickel Alloy 690 primary side steam generator upper 

and lower heads, tubesheets, and tube-to-tubesheet welds by performing periodic visual, 

surface, or volumetric examination and leakage testing. The PWR Water Chemistry Program 

proposes to manage aging effects by using water chemistry controls. In addition, the Steam 

Generator Tube Integrity Program proposes to manage aging through a combination of 

prevention, inspection, evaluation, removal of tubes from service (plugged) and leakage 

monitoring. The applicant indicated that preventive measures used per the Steam Generator 

Tube Integrity Program include primary-side and secondary-side water chemistry monitoring 

and control, and foreign material exclusion requirements. The staff notes that there has been 

no cracking due to PWSCC identified in tube-to-tubesheet welds fabricated of Alloy 690 material 

in the U.S. operating fleet; therefore, the staff finds that performing visual, surface, or volumetric 

examination is not required for managing cracking due to PWSCC of the tube-to-tubesheet 

welds.

The staff’s evaluation of the applicant’s Inservice Inspection, PWR Water Chemistry, and Steam

Generator Tube Integrity Programs are documented in SER Sections 3.0.3.1.12, 3.0.3.1.15, 

and 3.0.3.1.18. In its review of components associated with item 3.1.1-35, the staff finds the 

applicant’s proposal to manage aging using the Steam Generator Tube Integrity Program 
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acceptable because water chemistry control and NDE techniques may be used to control and 

detect cracking due to PWSCC in nickel Alloy 690 primary-side tube-to-tubesheet welds. Again, 

staff notes that cracking due to PWSCC has not been identified in tube-to-tubesheet welds

fabricated of Alloy 690 material in the U.S. operating fleet.

The staff concludes that 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).

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

3.1.2.3.5 Steam Generators—Primary Side: Tube—Aging Management Evaluation

In LRA Table 3.1.2-4, the applicant stated that the thermally-treated nickel Alloy 690 primaryside SG tubes exposed to treated water are being managed for reduction of heat transfer by the 

Steam Generator Tube Integrity Program. The AMR item cites generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

item IV.D1.R-47, which addresses nickel alloy SG tubes exposed to secondary feedwater 

(treated water) or steam and recommends GALL Report AMP XI.M2, “Steam Generators,” and 

AMP XI.M19, “Water Chemistry,” to manage cracking; however, the applicant has identified this 

additional aging effect. The staff also noted that the applicant addressed the GALL Report

identified aging effects for this component, material, and environment combination in AMR items 

in LRA Table 3.1.2-4.

The staff’s evaluation of the applicant’s Steam Generator Tube Integrity Program is documented 

in SER Section 3.0.3.1.18. The staff finds the applicant’s proposal to manage aging using the 

Steam Generator Tube Integrity Program acceptable because performing periodic cleaning of 

the SG secondary side internals, including tubes and tubesheet, will remove accumulated 

deposits from the SG, thus ensuring that the ability of the tubes to transfer heat is not hindered.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the 

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging for 

these components 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).

3.2 Aging Management of Engineered Safety Features

3.2.1 Summary of Technical Information in the Application

The staff does not have any changes or updates to this section of the SER.

3.2.2 Staff Evaluation

The staff does not have any changes or updates to this section of the SER.
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3.2.2.1 AMR Results Consistent with the GALL Report

3.2.2.1.7 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-49, addresses stainless steel piping, piping components, piping 

elements, and tanks exposed to treated borated water, which will be managed for loss of 

material due to pitting and crevice corrosion by the One-Time Inspection Program. The staff’s 

evaluation of item 3.2.1-49 is documented in SER Section 3.2.2.1.7. By letter dated 

February 19, 2014, the applicant amended LRA Table 3.2.1, item 3.2.1-49, and LRA

Table 3.2.2-4 to state that loss of material due to pitting and crevice corrosion on the internal 

surfaces of the stainless steel BWST will be managed by the Aboveground Steel Tanks 

Inspection Program. The revised AMR item associated with the BWST cites generic note E.

The staff’s evaluation of the applicant’s revised Aboveground Steel Tanks Inspection Program is 

documented in SSER Section 3.0.3.2.1. The staff finds the applicant’s proposal to manage the 

internal surfaces of the BWST using the Aboveground Steel Tanks Inspection Program 

acceptable because the program includes periodic examinations of the internal surfaces of 

in-scope tanks, which are capable of detecting the applicable aging effects.

The staff concludes that the applicant has demonstrated that the effects of aging for this 

component will be adequately managed so that the intended function(s) will remain 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

3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion

Items 1-5. The staff does not have any changes or updates to this section of the SER.

Item 6. By letter dated February 19, 2014, the applicant amended LRA Section 3.2.2.2.3,

item 6, to also address the BWST. As amended, the LRA states that loss of material due to 

pitting and crevice corrosion for the stainless steel BWST will be managed by the Aboveground 

Steel Tanks Inspection Program. The revised AMR item 3.2.1-08 associated with the BWST 

cites generic note E.

The staff’s evaluation of the applicant’s revised Aboveground Steel Tanks Inspection Program is 

documented in SSER Section 3.0.3.2.1. The staff finds the applicant’s proposal to manage the 

internal surfaces of the BWST exposed to condensation using the Aboveground Steel Tanks 

Inspection Program acceptable because the program includes periodic examinations of the 

internal surfaces of in-scope tanks, which are capable of detecting the applicable aging effects.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.2.2.2.3, item 6, criteria. For those items that apply to LRA

Section 3.2.2.2.3.6, the staff determines 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).
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3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

3.2.2.3.4 Engineered Safety Features Systems—Decay Heat Removal and Low-Pressure 

Injection System—Aging Management Review Results—LRA Table 3.2.2-4

In LRA Table 3.2.2-4, revised by letter dated September 16, 2011, the applicant stated that the 

external surfaces of the BWST exposed to outdoor air will be managed for loss of material by 

the External Surfaces Monitoring Program. The AMR item cites generic note G. By letter dated 

February 19, 2014, the applicant amended LRA Table 3.2.2-4 to add plant-specific note 0215, 

for the LRA Table 3.2.2-4 item that cites the BWST. Plant-specific note 0215 states that, for 

outdoor insulated components, the External Surfaces Monitoring Program manages corrosion 

under insulation. By letter dated July 29, 2014, the applicant further revised LRA Table 3.2.2-4. 

The revised AMR item related to the BWST cites generic note G. The applicant also deleted 

plant-specific note 0215, and cited plant-specific note 0217. Plant-specific note 0217 states 

that, for the exterior surfaces of the BWST, corrosion under insulation and cracking will be 

managed by the Aboveground Steel Tanks Inspection Program.

The staff’s evaluation of the applicant’s revised Aboveground Steel Tanks Inspection Program is 

documented in SSER Section 3.0.3.2.1. Based on its review of the revisions associated with 

the applicant’s Aboveground Steel Tanks Inspection Program, the staff finds the applicant’s 

revised program acceptable because it will include baseline bare metal surface examinations 

under the insulation of the BWST that are capable of detecting loss of material and cracking,

with subsequent periodic activities to either inspect the external surfaces of the insulation for 

damage that would allow moisture penetration or continue with bare metal inspections.

In LRA Table 3.2.2-4, the applicant stated that stainless steel bolting exposed to outdoor air will 

be managed for loss of material by the Bolting Integrity Program. The AMR items cite generic 

note F. The applicant also stated that the external surfaces of stainless piping exposed to 

outdoor air will be managed for loss of material by the External Surfaces Monitoring Program. 

The AMR items cite generic note G. By letter dated February 19, 2014, the applicant amended 

LRA Table 3.2.2-4, to add plant-specific note 0215 for these items. Plant-specific note 0215 

states that, for outdoor insulated components, the External Surfaces Monitoring Program 

manages corrosion under insulation.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SSER Section 3.0.3.2.5. Based on its review of the revisions associated with the applicant’s 

External Surfaces Monitoring Program, the staff finds the applicant’s revised program 

acceptable because it will include baseline bare metal surface examinations under the insulation 

that are capable of detecting loss of material with subsequent periodic activities to either inspect 

the external surfaces of the insulation for damage that would allow moisture penetration or 

continue with bare metal inspections. The staff’s evaluation of the Bolting Integrity Program is 

documented in SER Section 3.0.3.2.2. In its review of the Bolting Integrity Program, the staff 

determined that the visual examinations performed under the program are capable of detecting 

loss of material.

By letter dated February 19, 2014, the applicant amended LRA Table 3.2.2-4 to include a new 

item to address loss of material for the BWST exposed to concrete (external) that will be 

managed by the Aboveground Steel Tanks Program. The new item cites generic note G and 

plant-specific note 0216. Plant-specific note 0216 states that, for tanks supported on earthen or 

concrete foundations, corrosion may occur at inaccessible locations, such as the tank bottom.
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The staff’s evaluation of the applicant’s revised Aboveground Steel Tanks Inspection Program is 

documented in SSER Section 3.0.3.2.1. The staff finds the applicant’s proposal to manage the 

bottom of the BWST using the Aboveground Steel Tanks Inspection Program acceptable 

because the program includes periodic examinations of the tank’s bottom, which are capable of 

detecting the applicable aging effects.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the 

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging for 

these components 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).

3.2.3 Conclusion

The staff does not have any changes or updates to this section of the SER.

3.3 Aging Management of Auxiliary Systems

Revisions to SER Table 3.3-1

Staff Evaluation for Auxiliary System Components in the GALL Report

Component

Group 

(GALL Report

Item No.)

Aging 

Effect/ 

Mechanism

AMP in 

GALL Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments Staff Evaluation

Stainless steel 

high-pressure 

pump casing in 

PWR chemical 

and volume 

control system

(3.3.1-9) 

Cracking due 

to SCC and 

cyclic loading 

Water Chemistry 

and a 

plant-specific 

verification 

program. The 

AMP is to be 

augmented by 

verifying the 

absence of 

cracking due to 

SCC and cyclic 

loading. A 

plant-specific 

AMP is to be 

evaluated. 

Yes Not Applicable Not Applicable to 

Davis-Besse (see 

SER 

Section 3.3.2.2.4(3))

3.3.1 Summary of Technical Information in the Application

The staff does not have any changes or updates to this section of the SER.
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3.3.2 Staff Evaluation

3.3.2.1 AMR Results Consistent with the GALL Report

3.3.2.1.6 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-25, addresses copper-alloy bolting, piping, and valve bodies 

exposed to condensation (external), which will be managed for loss of material due to corrosion 

by the Bolting Integrity (for bolting) and the External Surfaces Monitoring Programs (for piping). 

LRA Table 3.3.1, item 3.3.1-27, addresses stainless steel piping components exposed to 

condensation (external), which will be managed for loss of material due to corrosion by the 

External Surfaces Monitoring Programs. The LRA items cite generic note E for these 

components. By letter dated February 19, 2014, the applicant amended these items to also cite 

plant-specific note 0345. Plant-specific note 0345 states that for indoor insulated components 

exposed to condensation (because the in-scope component is operated below the dew point), 

corrosion under insulation is managed by the External Surfaces Monitoring Program.

The staff’s evaluation of the applicant’s revised External Surfaces Monitoring Program is 

documented in SSER Section 3.0.3.2.5. Based on its review of the revisions associated with 

the applicant’s External Surfaces Monitoring Program, the staff finds the applicant’s revised 

program acceptable because it will include baseline bare metal surface examinations under the 

insulation that are capable of detecting loss of material and cracking, with subsequent periodic 

activities to either inspect the external surfaces of the insulation for damage that would allow 

moisture penetration or continue with bare metal inspections. The staff’s evaluation of the 

Bolting Integrity Program is documented in SER Section 3.0.3.2.2. In its review of the Bolting 

Integrity Program, the staff determined that the visual examinations performed under the 

program are capable of detecting loss of material.

The staff concludes that 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

3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading

Item 3. LRA Section 3.3.2.2.4.3, associated with LRA Table 3.3.1, item 3.3.1-9, addresses 

cracking due to SCC and cyclic loading in stainless steel high-pressure pump casings exposed 

to treated water in the PWR chemical and volume control system. As documented in SER 

Section 3.3.2.2.4, item 3, the applicant stated that the makeup pumps in the makeup and 

purification system are susceptible to cracking due to cyclic loading only and that this aging 

effect would be managed by the PWR Water Chemistry and One-Time Inspection Programs.

However, by letter dated June 23, 2014, the applicant amended LRA Section 3.3.2.2.4.3 to state 

that cyclic loading is not identified as an aging effect and, as a result, this item is not applicable. 

The applicant also amended Commitment No. 13 associated with the One-Time Inspection 

Program to delete the reference to the inspection of the makeup pump casings. The applicant 

stated that the design of the pumps is such that their external casings, which have a pressure 

boundary function, are not subject to cyclic loading because they receive fluid discharged from 

the pumps’ inner casings at a steady pressure, flow rate, and temperature. The applicant also 
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stated that the pump inner casings, which do not have a license renewal function, bear the 

mechanical loading associated with the 12 stages of the pumps. The applicant further stated 

that one of the two pumps operates continuously during normal operation, at which time it is 

exposed to a treated water environment with a relatively constant temperature of 120 oF, and 

thus thermal cyclic loading is not a concern.

The staff evaluated the applicant’s claim and finds it acceptable because the portion of the 

pump casing with a license renewal function (i.e., the external casing) is not subject to the 

pressure increases developed by the 12 stages of the pump that could promote cracking due to 

cyclic loading. In addition, because one of the makeup pumps operates continuously during 

normal operation, the external casing of the operating pump is exposed to a relatively constant 

internal water pressure and temperature. As a result, the design and usage of the pumps 

minimize the exposure of their external casings to cyclic loading from both mechanical and 

thermal sources.

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

3.3.2.3.1 Auxiliary Systems—Auxiliary Building HVAC System—Aging Management Review 

Results—LRA Table 3.3.2.1

LRA Table 3.3.2-1, states that copper-alloy piping and copper alloy with greater than 15 percent

zinc valve bodies exposed to outdoor air (external) will be managed for loss of material by the 

External Surfaces Monitoring Program. The AMR items cite generic note G. By letter dated 

February 19, 2014, the applicant amended LRA Table 3.3.2-1 to add plant-specific note 0344 

for these items. Plant-specific note 0344 states that, for outdoor insulated components, the 

External Surfaces Monitoring Program manages corrosion under insulation.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SSER Section 3.0.3.2.5. Based on its review of the revisions associated with the applicant’s 

External Surfaces Monitoring Program, the staff finds the applicant’s revised program 

acceptable because it will include baseline bare metal surface examinations under the insulation 

that are capable of detecting loss of material and cracking, with subsequent periodic activities to 

either inspect the external surfaces of the insulation for damage that would allow moisture 

penetration or continue with bare metal inspections.

By letter dated February 19, 2014, the applicant amended LRA Table 3.3.2-1 by adding steel 

bolting exposed to condensation, which will be managed for cracking, loss of material, and loss 

of preload by the Bolting Integrity Program. The AMR items cite generic notes B and H. The 

generic note H item also cites plant-specific note 0345. Plant-specific note 0345 states that, for 

indoor insulated components exposed to condensation (because the in-scope component is 

operated below the dew point), corrosion under insulation is managed by the External Surfaces 

Monitoring Program.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SSER Section 3.0.3.2.5. Based on its review of the revisions associated with the applicant’s 

External Surfaces Monitoring Program, the staff finds the applicant’s revised program 

acceptable because it will include baseline bare metal surface examinations under the insulation 

that are capable of detecting loss of material and cracking, with subsequent periodic activities to 

either inspect the external surfaces of the insulation for damage that would allow moisture 

penetration or continue with bare metal inspections. The staff’s evaluation of the Bolting 

Integrity Program is documented in SER Section 3.0.3.2.2. In its review of the Bolting Integrity 
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Program, the staff determined that the visual examinations performed under the program are 

capable of detecting cracking, loss of material, and loss of preload.

On the basis of its review, the staff concluded that the applicant has demonstrated that the 

effects of aging for these components 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).

3.3.2.3.6 Auxiliary Systems—Circulating Water System—Aging Management Review 

Results—LRA Table 3.3.2-6

Carbon steel (coated) and gray cast iron (coated) piping, piping components, and tanks 

exposed to raw water and lubricating oil.

As amended by letter dated January 31, 2014, LRA Tables 3.3.2-6, 3.3.2-12, 3.3.2-14, 3.3.2-15, 

3.3.2-26, and 3.3.2-30 state that carbon steel (coated) and gray cast iron (coated) piping, piping 

components, and tanks exposed to raw water and lubricating oil will be managed for loss of 

coating integrity by the Service Level III Coatings and Linings Monitoring Program. The AMR 

items cite generic note H.

The staff’s evaluation of the applicant’s Service Level III Coatings and Linings Monitoring 

Program is documented in SER Section 3.0.3.3.10. The staff finds the applicant’s proposal to 

manage loss of coating integrity using the Service Level III Coatings and Linings Monitoring 

Program acceptable because the program includes periodic visual inspections that are capable 

of detecting degraded coatings and followup physical testing, repair, and replacement activities 

when inspection results do not meet acceptance criteria.

On the basis of its review, the staff concludes 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).

3.3.2.3.12 Auxiliary Systems—Emergency Diesel Generators System—Aging Management 

Review Results—LRA Table 3.3.2-12

Carbon steel (coated) and gray cast iron (coated) piping, piping components, and tanks 

exposed to raw water and lubricating oil.

The staff’s evaluation for carbon steel (coated) and gray cast iron (coated) piping, piping 

components, and tanks exposed to raw water and lubricating oil, which will be managed for loss 

of coating integrity by the Service Level III Coatings and Linings Monitoring Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.6.

3.3.2.3.14 Auxiliary Systems—Fire Protection System—Aging Management Review 

Results—LRA Table 3.3.2-14

Carbon steel (coated) and gray cast iron (coated) piping, piping components, and tanks 

exposed to raw water and lubricating oil.

The staff’s evaluation for carbon steel (coated) and gray cast iron (coated) piping, piping 

components, and tanks exposed to raw water and lubricating oil, which will be managed for loss 
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of coating integrity by the Service Level III Coatings and Linings Monitoring Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.6.

3.3.2.3.15 Auxiliary Systems—Fuel Oil System—Aging Management Review Results—LRA

Table 3.3.2-15

By letter dated February 19, 2014, the applicant amended LRA Table 3.3.2-15 to include a new 

item to address loss of material for steel tanks exposed to concrete (external). The new item 

cites generic note G and plant-specific note 0346. Plant-specific note 0346 states that, for 

storage tanks supported on earthen or concrete foundations, corrosion may occur at 

inaccessible locations.

The staff’s evaluation of the applicant’s revised Aboveground Steel Tanks Inspection Program is 

documented in SSER Section 3.0.3.2.1. The staff finds the applicant’s proposal to manage the 

bottom of the tanks using the Aboveground Steel Tanks Inspection Program acceptable 

because the program includes periodic examinations of the tank’s bottom, which are capable of 

detecting the applicable aging effects.

Carbon steel (coated) and gray cast iron (coated) piping, piping components, and tanks 

exposed to raw water and lubricating oil.

The staff’s evaluation for carbon steel (coated) and gray cast iron (coated) piping, piping 

components, and tanks exposed to raw water and lubricating oil, which will be managed for loss 

of coating integrity by the Service Level III Coatings and Linings Monitoring Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.6.

3.3.2.3.26 Auxiliary Systems—Service Water System—Aging Management Review Results—

LRA Table 3.3.2-26

Carbon steel (coated) and gray cast iron (coated) piping, piping components, and tanks 

exposed to raw water and lubricating oil.

The staff’s evaluation for carbon steel (coated) and gray cast iron (coated) piping, piping 

components, and tanks exposed to raw water and lubricating oil, which will be managed for loss 

of coating integrity by the Service Level III Coatings and Linings Monitoring Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.6.

3.3.2.3.30 Auxiliary Systems—Station Blackout Diesel Generator System—Aging 

Management Review Results—LRA Table 3.3.2-30

Carbon steel (coated) and gray cast iron (coated) piping, piping components, and tanks 

exposed to raw water and lubricating oil.

The staff’s evaluation for carbon steel (coated) and gray cast iron (coated) piping, piping 

components, and tanks exposed to raw water and lubricating oil, which will be managed for loss 

of coating integrity by the Service Level III Coatings and Linings Monitoring Program and is 

associated with generic note H, is documented in SER Section 3.3.2.3.6.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not addressed in the 

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging for 
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these components 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).

3.3.3 Conclusion

The staff does not have any changes or updates to this section of the SER.

3.4 Aging Management of Steam and Power Conversion Systems

3.4.1 Summary of Technical Information in the Application

The staff does not have any changes or updates to this section of the SER.

3.4.2 Staff Evaluation

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation Is 

Recommended

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

Item 1. LRA Section 3.4.2.2.2.1 is associated with LRA Table 3.4.1, item 3.4.1-06 and 

addresses steel and stainless steel tanks exposed to treated water (internal), which will be 

managed for loss of material by the One-Time Inspection and the PWR Water Chemistry 

Programs. LRA Table 3.4.2-2 also states that the interior steel surfaces of the condensate 

storage tank exposed to moist air (internal) will be managed for loss of material by the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program. By letter dated 

February 19, 2014, the applicant revised LRA Table 3.4.2-2. As part of the revision, the 

applicant introduced a new item to address loss of material for steel tanks exposed to concrete 

(external). The new AMR item cites generic note G and plant-specific note 0416. The applicant 

also amended LRA Table 3.4.2-2, items associated with the condensate tank to remove the 

One-Time Inspection and PWR Water Chemistry Programs. The applicant stated that it will use 

the Aboveground Steel Tanks Inspection Program to manage for loss of material for the steel 

surfaces of the condensate tank exposed to treated water (internal) and moist air (internal). 

These AMR items cite generic notes E and G.

The staff’s evaluation of the applicant’s revised Aboveground Steel Tanks Inspection Program is 

documented in SSER Section 3.0.3.2.1. The staff finds the applicant’s proposal to manage the 

internal surfaces of the tanks exposed to condensation using the Aboveground Steel Tanks 

Inspection Program acceptable because the program includes periodic examinations of the 

internal surfaces of in-scope tanks, which are capable of detecting the applicable aging effects. 

The staff also finds the applicant’s proposal to manage the bottom of the BWST using the 

Aboveground Steel Tanks Inspection Program acceptable because the program includes 

periodic examinations of the tank’s bottom, which are capable of detecting the applicable aging 

effects.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.4.2.2.2, item 1 criteria. For those items that apply to LRA
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Section 3.4.2.2.2.1, the staff determines 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).

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

The staff does not have any changes or updates to this section of the SER.

3.4.3 Conclusion

The staff does not have any changes or updates to this section of the SER.

3.5 Aging Management of Structures and Structural Components

The staff does not have any changes or updates to this section of the SER.

3.6 Aging Management of Electrical and Instrumentation and Controls

The staff does not have any changes or updates to this section of the SER.

4-1

SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

There are no changes or updates to this section of the SER.

4.1.1 Summary of Technical Information in the Application

The applicant provided additional information related to the time-limited aging analyses (TLAAs)

after issuance of the SER. The additional information is added and evaluated in 

Section 4.1.2.1.

4.1.2 Staff Evaluation

There are no changes or updates to this section of the SER, other than the amendments to LRA

Section 4.1.2.1 that were identified by the applicant and are evaluated in the following 

subsections.

4.1.2.1 Evaluation of the Applicant’s Identification of Time-Limited Aging Analyses

Other than the changes identified for the evaluations in Sections 4.1.2.1.3 and 4.1.2.1.4 that 

follow, the staff evaluation of the applicant’s bases for identifying TLAAs in the LRA are as 

documented in SER Section 4.1.2.1. The evaluations in Sections 4.1.2.1.3 and 4.1.2.1.4 that 

follow supersede those that were provided in SER Sections 4.1.2.1.3 and 4.1.2.1.4.

4.1.2.1.3 LRA Update of June 23, 2014—Changes to Metal Fatigue TLAAs for the 

Once-Through Steam Generators

On June 23, 2014, the applicant submitted an LRA update in order to comply with the LRA 

update requirements in 10 CFR 54.21(b). As part of this submittal, the applicant stated that the 

original once-through steam generators (OTSGs) in the Davis-Besse nuclear plant were 

replaced in the Cycle 18 (Spring 2014) refueling outage. Based on this plant modification, the 

applicant amended LRA Table 4.1-1 and LRA Section 4.3.2.2.6 to propose changes to the 

TLAAs on metal fatigue of the OTSGs and auxiliary feedwater nozzles of the facility. The staff’s 

evaluations of the amendments of LRA Table 4.1-1 and LRA Section 4.3.2.2.6 are given in 

Section 4.3.2.2 of this SSER.

4.1.2.1.4 LRA Update of June 23, 2014—Changes to the Flaw Evaluation TLAA for the 

Once-Through Steam Generators

On June 23, 2014, the applicant submitted an LRA update in order to comply with the LRA 

update requirements in 10 CFR 54.21(b). As part of this submittal, the applicant stated that the 

original OTSGs in Davis-Besse were replaced in the Cycle 18 (Spring 2014) refueling outage. 

The applicant stated that the flaw evaluation TLAA previously given in LRA Section 4.7.5.2, 

“OTSG 1-2 Flaw Evaluations,” is no longer applicable to the current licensing basis (CLB). 
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4-2

Therefore, the applicant deleted LRA Section 4.7.5.2 from the scope of the LRA, including the 

reference to LRA Section 4.7.5.2 in LRA Table 4.1-1. The staff’s evaluation of the applicant’s 

basis for deleting LRA Section 4.7.5.2 is contained in Section 4.7.5.2 of this SSER.

4.1.2.2 Evaluation of the Applicant’s Identification of Those Exemptions in the CLB That Are 

Based on TLAAs

There are no changes or updates to this section of the SER. Therefore, the evaluation in SER 

Section 4.1.2.2 remains valid as previously written.

4.1.3 Conclusion

There are no changes or updates to this section of the SER. Therefore, the conclusion in SER 

Section 4.1.3 remains valid as previously written.

4.2 Reactor Vessel Neutron Embrittlement

4.2.7 Reduction in Fracture Toughness of Reactor Vessel Internals

4.2.7.1 Summary of Technical Information in the Application

LRA Section 4.2.7 describes the applicant’s TLAA for the reduction in fracture toughness of the 

RVI. The applicant cited USAR Appendix 4A, which describes the detailed stress analysis of 

the internals under accident conditions for the current term of operation. According to the 

applicant, the analysis shows that the internals will not fail because the stresses are within

established limits. The applicant stated that the effect of irradiation on the mechanical 

properties and deformation limits for the RVI was also evaluated for the current term of 

operation. The applicant also stated that the aforementioned analysis concluded that the RVI 

will have adequate ductility to absorb local strain at the regions of maximum stress intensity and 

that irradiation will not adversely affect deformation limits.

The applicant stated that the impact of the measurement uncertainty recapture (MUR) power 

uprate on the structural integrity of the RVI components was evaluated. The applicant 

concluded that the temperature changes due to the MUR power uprate are bounded by those 

used in the existing analyses. As part of the MUR power uprate, the applicant stated that, “[a]s 

appropriate, FENOC commits to incorporate recommendations from MRP [Materials Reliability 

Program] inspection guidelines into the RVI program at Davis-Besse Nuclear Power Station, 

Unit No. 1.”

The applicant stated that this TLAA will be managed during the period of extended operation 

through the PWR RVI Program.

Based on the information above, the applicant concluded that the effects of neutron 

embrittlement on the reduction in fracture toughness for the RVI will be appropriately managed 

during the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(iii).

By letter dated April 21, 2015, the applicant amended the LRA and submitted the inspection 

plan for the RVI components at Davis Besse in order to fulfill the conditions and criteria 

specified in LRA Commitment No. 15, which was included as a commitment in USAR 
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Supplement Table A-1, and stated that the applicant would submit the inspection plan for the 

RVI components to the NRC for review and approval by April 22, 2015. This RVIIP was 

included in the letter of April 21, 2015, and is documented in nonproprietary AREVA 

TR No. ANP-3920, Revision 1, “Reactor Vessel Internals Inspection Plan for Davis Besse 

Nuclear Plant Unit No. 1 – Licensing Report,” dated March 2015.

In the RVIIP, the applicant responded to Applicant/Licensee Action Item (A/LAI) #8, Subitem 5, 

and confirmed that the CLB includes an evaluation of the potential drops in the ductile fracture 

toughness property of the components, as evaluated in B&W TR No. BAW-10008, Revision 1.

By letter dated May 20, 2015, the applicant amended USAR Supplement Table A-1 to include 

Commitment No. 54, which was linked to the USAR Supplement summary description for the 

PWR Reactor Vessel Internals Program (i.e., LRA Section A.1.32), and in which the applicant

committed to submit an updated reduction of ductility fracture toughness to the NRC for review 

and approval by October 22, 2016.

4.2.7.2 Staff Evaluation

The evaluation in this section of the SSER supersedes the staff’s previous evaluation of the 

reduction of ductility TLAA previously given in SER Section 4.2.7. The staff’s evaluation of the 

applicant’s basis for managing loss of fracture toughness in CASS RVI components is 

documented in SER Section 4.2.7, as supplemented by the evaluation in Section 3.0.3.3.6 of

this SSER.

The staff reviewed LRA Section 4.2.7 on the reduction in fracture toughness for the RVI, as 

supplemented with information contained in the applicant’s letter of April 21, 2015, to verify, 

pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of neutron embrittlement on the RVI will be 

adequately managed for the period of extended operation.

The staff reviewed the applicant’s TLAA consistent with the review procedures in SRP-LR 

Section 4.7.3.1.3, which state that the applicant shall propose to manage the aging effects 

associated with the TLAA using an AMP in the same manner as described in the IPA in

10 CFR 54.21(a)(3). SRP-LR Section 4.7.3.1.3 also states that the applicable AMP is reviewed 

to verify that the effects of aging on the intended functions are adequately managed, consistent 

with the CLB for the period of extended operation.

Exposure of stainless steel RVI components to high-energy neutron radiation during the period 

of extended operation could result in a significant reduction in fracture toughness, depending on 

the material, irradiation temperature, and neutron fluence.

The staff determined that the reduction in fracture toughness of the stainless steel RVI is a 

TLAA that should be managed during the period of extended operation. The staff reviewed LRA

Section 4.2.7 to determine if the applicant’s TLAA of the reduction in fracture toughness for the 

RVI demonstrates that the effects of embrittlement on these components will be adequately 

managed during the period of extended operation, pursuant to 10 CFR 54.21(c)(1)(iii). The 

applicant appropriately referenced the Davis-Besse PWR Reactor Vessel Internals Program for 

managing the loss of fracture toughness for the stainless steel RVI components. The staff 

reviewed the Davis-Besse PWR Reactor Vessel Internals Program, as described in LRA

Section B.2.32, and amended through LRA Amendment 15, and confirmed that it manages loss 

of fracture toughness due to neutron embrittlement of RVI components.
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The staff noted that in the applicant’s letter of April 21, 2015, the applicant submitted the RVIIP 

for the RVI components at Davis-Besse, which includes AREVA Nonproprietary 

TR Nos. ANP-3285, ANP-3359NP, and ANP-3920, Revision 1 (collectively given in ADAMS 

Accession Nos. ML15113B133 and ML15113B134). The staff noted that, in TR No. ANP-3920, 

Revision 1, the applicant responded to A/LAI #8, Subitem 5, and confirmed that the reduction of 

ductility fracture toughness analysis in TR No. BAW-10008, Revision 1, is a TLAA for the LRA. 

The staff noted that, in the letter of April 21, 2015, as supplemented by the letter of 

May 20, 2015, the applicant stated that the reduction of ductility analysis for the RVI 

components will be updated and projected to the end of the period of extended operation. The 

applicant also stated that the updated analysis will be submitted to the NRC for review and 

approval and that the commitment for the analysis provides an updated basis for accepting the 

reduction of ductility analysis in accordance with the requirement in 10 CFR 54.21(c)(1)(iii).

The staff verified that the letter of May 20, 2015, includes LRA Commitment No. 54, which was 

incorporated into USAR Supplement Table A-1 and committed to the following actions by the 

applicant:

In response to MRP-227-A Applicant/Licensee Action Item 8, update and submit 

for NRC review and approval an evaluation for the period of extended operation 

regarding the effect of irradiation on the mechanical properties and deformation 

limits of the RV internals that was evaluated for the current term of operation in 

Appendix E of Topical Report BAW-10008, Part 1, Revision 1 supplemented by 

DB-1 [Davis-Besse] USAR Appendix 4A.

The staff noted that the applicant also committed to submitting the updated analysis to the NRC 

for review and approval by October 22, 2016 (i.e., at least 6 months prior to entering into the 

period of extended operation, which will begin on April 22, 2017) and linked these actions in 

Commitment No. 54 to the USAR Supplement (i.e., LRA Section A.1.32) for the PWR Reactor 

Vessel Internals Program. As explained in SER Section 3.0.3.3.6, the staff has determined that 

the applicant’s PWR Reactor Vessel Internals Program provides an adequate means of using 

sampling-based inspections to detect flaw indications that may be indicative of a change in 

fracture toughness properties of the materials used to fabricate the components. This includes 

a reduction in fracture toughness that may be induced by a drop in the ductile behavior property 

of the materials or by neutron irradiation embrittlement or thermal embrittlement mechanisms. 

Therefore, the staff finds that the PWR Reactor Vessel Internals Program and the inclusion of 

Commitment No. 54 to the USAR Supplement provides an acceptable basis for approving the 

TLAA in accordance with 10 CFR 54.21(c)(1)(iii) because:

(a) The applicant will be projecting the reduction of ductility fracture toughness analysis in 

TR No. BAW-10008, Revision 1, to the end of the period of extended operation and will 

be submitting the analysis for NRC review and approval by at least 6 months prior to 

entering into the period of extended operation.

(b) The applicant will also be implementing a set of sample-based inspections of the RVI 

components in accordance with the Reactor Vessel Internals Program, which will 

provide adequate indications of any aging-related effects (including effects that may 

induce changes in applicable material properties of the RVI components) that may occur 

in the RVI components during the period of extended operation.

(c) The updated analysis, when coupled with the inspections performed in accordance with 

the Reactor Vessel Internals Program, provides an adequate basis for demonstrating 
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that loss of fracture toughness (including that induced by changes in ductility) will be 

adequately managed during the period of extended operations.

(d) This is an adequate basis for demonstrating that the implementation of the PWR Reactor 

Vessel Internals Program and Commitment No. 54 provides an acceptable basis for 

accepting the reduction of ductility TLAA in accordance with 10 CFR 54.21(c)(1)(iii) 

because: (a) implementation of the AMP and commitment will demonstrate that the 

impact of a reduction of fracture toughness (including ductile fracture toughness) on the 

intended functions of the RVI components will be adequately managed by inspection or 

analysis during the period of extended operation, and (b) this is consistent with the 

acceptance criteria in Section 4.7.2.1 of the SRP-LR.

The staff noted that the applicant’s proposal to implement MRP-227-A as the basis for its

plant-specific PWR Reactor Vessel Internals Program must address all of the plant-specific and 

vendor-specific action items associated with the plant-specific implementation of MRP-227-A, as 

specified in Section 4.2 of the staff’s supplemental evaluation on MRP-227. The staff’s 

evaluation of the PWR Reactor Vessel Internals Program is provided in SER Section 3.0.3.3.6, 

as supplemented by Section 3.0.3.3.6 of this SSER.

Based on the above evaluation, the staff finds that the applicant demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the fracture toughness of the RVI will be 

adequately managed by the PWR Reactor Vessel Internals Program for the period of extended 

operation.

Additionally, the staff finds that the applicant’s TLAA is consistent with SRP-LR 

Section 4.7.2.1 because the effects of aging on the intended function will be adequately 

managed for the period of extended operation.

USAR Supplement

LRA Section A.2.2.7 provides the USAR supplement summary description for the reduction in 

RVI fracture toughness TLAA evaluation. The staff noted that the USAR supplement summary 

description provided an adequate basis for accepting the TLAA, in accordance with 

10 CFR 54.21(c)(1)(iii).

By letter dated May 20, 2015, the applicant amended USAR Supplement Table A-1 to include 

Commitment No. 54. The staff noted that this commitment was linked to USAR Supplement 

Section A.1.32 for the PWR Reactor Vessel Internals Program and that, in Commitment No. 54, 

the applicant committed to the following actions:

In response to MRP-227-A Applicant/Licensee Action Item 8, update and submit 

for NRC review and approval an evaluation for the period of extended operation 

regarding the effect of irradiation on the mechanical properties and deformation 

limits of the RV internals that was evaluated for the current term of operation in 

Appendix E of Topical Report BAW-100081, Part 1, Revision 1 supplemented in 

DB-1 [Davis-Besse]USAR Appendix 4A.

The staff also noted that the applicant committed to submitting the updated analysis by 

October 22, 2016 (i.e., at least 6 months prior to entering into the period of extended operation). 

The staff’s basis for accepting Commitment No. 54 and using the commitment to accept this 

TLAA, in accordance with 10 CFR 54.21(c)(1)(iii), is given in Section 4.2.7.2 of this SSER. 

Based on the information in the USAR supplement summary descriptions A.2.2.7 and A.1.32, 
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and the inclusion of LRA Commitment No. 54 in USAR Table A-1, the staff finds that the USAR 

supplement contains an adequate basis for accepting the reduction of ductility analysis for the 

RVI components, in accordance with the requirement in 10 CFR 54.21(c)(1)(iii).

Based on its review of the USAR supplement, the staff concludes that the information in the 

USAR supplement is an adequate summary description of the evaluation, as required by 

10 CFR 54.21(d), and is consistent with SRP-LR Section 4.7.3.2.

4.2.7.3 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 reduction in fracture 

toughness on the integrity of RVI components will be adequately managed for the period of 

extended operation. The staff also concludes that the USAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d), and, 

therefore, is acceptable.

4.3 Metal Fatigue

4.3.2 Class 1 Fatigue

4.3.2.2 Class 1 Vessels, Pumps, and Major Components

4.3.2.2.1 Summary of Technical Information in the Application

On June 23, 2014, the applicant submitted an LRA update in order to comply with the LRA 

update requirements in 10 CFR 54.21(b). As part of this submittal, the applicant stated that the 

original OTSGs in Davis-Besse were replaced in the Cycle 18 (Spring 2014) refueling outage. 

Based on this plant modification, the applicant amended LRA Section 4.3.2.2.6 to propose 

changes to the TLAAs on metal fatigue of the OTSG primary and secondary side components, 

OTSG internal components, and auxiliary feedwater (AFW) headers, nozzles, and nozzle 

thermal sleeves of the facility.

In addition, by letter dated April 21, 2015, as amended in letters dated May 20, 2015, and 

June 5, 2015, the applicant amended the LRA to provide the RVIIP for Davis-Besse. As a result 

of these letters, the applicant amended its basis in LRA Section 4.3.2.2.6 for accepting the 

low-cycle fatigue TLAA for the RVI components, in accordance with 10 CFR 54.21(c)(1)(iii).

The following subsections reflect the changes to the applicant’s low-cycle fatigue TLAAs for 

OTSG and RVI components. Otherwise, the summaries of the technical information for 

low-cycle fatigue TLAAs that apply to Class 1 vessels, pumps, and major equipment are as 

documented in SER Section 4.3.2.2.1.

Reactor Vessel Internals. LRA Section 4.3.2.2.2 describes the metal fatigue analysis for the 

RVI components, which include the plenum assembly and the core support assembly,

consisting of the core support shield, core barrel, lower grid, flow distributor, incore instrument 

guide tubes, thermal shield, and surveillance specimen holder tubes. The applicant’s metal 

fatigue TLAAs of RVIs are summarized below:
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Low-Cycle Fatigue. LRA Section 4.3.2.2.2.1 states that the design of the RVIs meets the stress 

requirements of ASME Code Section III, but the design code did not require a fatigue analysis to 

be performed. The applicant stated that it performed fatigue analyses for the Alloy X-750 

high-temperature annealed and aged condition heat treatment (HTH) bolts, which were 

designed to ASME Code Section III, to replace the majority of the vessel internals Alloy A-286 

bolts. The applicant also stated that the CUFs for the Alloy X-750 HTH replacement bolts were 

based on the system design transients in LRA Table 4.3-1 and were found to be less than 1.0. 

The upper thermal shield bolts, flow distributor bolts, and guide block bolts have not been 

replaced. In the applicant’s letters of May 20, 2015, and June 5, 2015, the applicant confirmed 

that the low-cycle fatigue analyses (i.e., CUF analyses) were performed for the UCB bolts, LCB 

bolts, and LTS bolts that were replaced in the plant design using bolts made from HTH X-750 

materials. The applicant dispositioned the low-cycle fatigue TLAA of the RVIs, in accordance 

with 10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue will be managed for the 

period of extended operation using a combination of the Fatigue Monitoring Program (LRA 

AMP B.2.18) and the PWR Reactor Vessel Internals Program (LRA AMP B.2.32).

Reactor Vessel Internals and Incore Instrument Nozzles Flow-Induced Vibration. LRA

Section 4.3.2.2.2.2 discusses RVI metal fatigue and incore instrument nozzles subjected to FIV. 

The summary of technical information for the FIV fatigue TLAA is documented in SER 

Section 4.3.2.2.1. The applicant dispositioned the fatigue TLAA for the FIV of RVIs in 

accordance with 10 CFR 54.21(c)(1)(i), that the existing analysis remains valid for the period of 

extended operation.

Surveillance Capsule Holder Tubes Flow-Induced Vibration. LRA Section 4.3.2.2.2.3, as 

amended by letter dated June 17, 2011, discusses the high-cycle metal fatigue analysis 

(i.e., FIV cumulative usage factor [CUF analysis) of the surveillance capsule holder tubes. The 

summary of technical information for this TLAA is documented in SER Section 4.3.2.2.1. The 

applicant stated that it dispositioned the high-cycle metal fatigue TLAA for the surveillance 

capsule holder tubes in accordance with 10 CFR 54.21(c)(1)(ii) and that the analysis has been 

projected to the end of the period of extended operation.

Once-Through Steam Generators. LRA Section 4.3.2.2.6 states that the OTSG components 

exposed to RCS pressure are the hemispherical heads, the tubesheet, and the straight inconel 

tubes between the tubesheets. The applicant’s metal fatigue TLAAs related to the OSTGs are

separated into four parts, as summarized below.

On June 23, 2014, the applicant submitted an LRA update in order to comply with the LRA 

update requirements in 10 CFR 54.21(b). As part of this submittal, the applicant identified that 

the original OTSGs at Davis-Besse were replaced in the Cycle 18 (Spring 2014) refueling 

outage. Based on this plant modification, the applicant amended LRA Section 4.3.2.2.6 to 

propose changes to the TLAAs on metal fatigue of the OTSG primary and secondary side 

components, OTSG internal components, and AFW headers, nozzles, and nozzle thermal 

sleeves of the facility.

OTSGs Fatigue. LRA Section 4.3.2.2.6.1 states that the primary (tube) and secondary (shell)

sides of the OTSGs were designed to the 1968 edition of ASME Code Section III, inclusive of

1968 summer addenda, and were analyzed for fatigue by the original equipment manufacturer. 

The CUFs for OTSG locations, which are less than 1.0, were based on the system design 

transients given in LRA Table 4.3-1. The applicant stated that the SG remote weld plugs have a 

limited design life of 33 heatup/cooldown cycles to maintain a fatigue usage of less than 1.0.

The applicant’s Fatigue Monitoring Program tracks the incurred cycles of these design 
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transients to ensure action is taken before reaching their design number of cycles for each 

transient. The applicant dispositioned the TLAA for the OTSGs in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue will be managed for the period of 

extended operation by the Fatigue Monitoring Program.

By letter June 23, 2014, the applicant indicated that the OTSGs at Davis-Besse had been 

replaced and the new fatigue analyses had been performed for specific components in the 

replacement OTSGs, including those in the primary and secondary sides of the replacement 

OTSGs, associated with the replacement OTSG internals, and specific components in the AFW 

system (including AFW headers, nozzles, and nozzle thermal sleeves). The staff’s evaluation of 

the new fatigue analyses for the replacement OTSG components is contained in 

Section 4.3.2.2.2 of this SSER.

OTSG Tube Sleeves Fatigue. LRA Section 4.3.2.2.6.2 describes the fatigue analysis for the 

tube sleeves that were used to repair leaking tubes of the OTSGs. In accordance with USAR 

Section 5.5.2.3, the applicant stated that the SG tubes may be plugged or repaired by 

mechanical (rolled) sleeving; however, Section III of the ASME Code does not provide design 

rules for mechanically roll-expanded attachments, and theoretical stress analyses are 

inadequate. The applicant stated that, in accordance with provisions of Appendix II, 

Section 1500, of ASME Code Section III, fatigue tests were performed to demonstrate the 

structural adequacy of the sleeves to withstand cyclic loadings based on the design transients.

The applicant indicated that the pressure cycling tests used 360 startup cycles to bound all 

B&W 177 fuel assembly plants. The applicant stated that, per USAR Table 5.1-8, its design 

basis is 240 startups, and it projected only 128 startups for 60 years of operation, as described 

in LRA Table 4.3-1. The applicant dispositioned the TLAA associated with fatigue testing of the 

OTSG tube sleeves, in accordance with 10 CFR 54.21(c)(1)(i) disposition, that the analysis will 

remain valid for the period of extended operation.

In the LRA update dated June 23, 2014, the applicant stated that the original OTSGs in the 

plant design were replaced in the Spring 2014 refueling outage and that the new OTSGs no 

longer included any OTSG tube sleeves. The applicant stated that LRA Section 4.3.2.2.6.2 is 

being deleted as a result of the changes to the OTSG design. The staff’s evaluation of the 

applicant’s basis for deleting these metal fatigue analyses from the scope of the LRA is 

contained in Section 4.3.2.2.2 of this SSER.

OTSG Auxiliary Feedwater Modification. LRA Section 4.3.2.2.6.3 describes the fatigue analysis 

for the repair to the OTSGs AFW system. The modification was installed (in 1982) with an 

external header on each SG. The applicant stated that the AFW thermal sleeve stresses were 

also analyzed by B&W, and the analysis, performed in accordance with the requirements of the 

ASME Code for Class 1 components, provided a basis for demonstrating that the AFW thermal 

sleeve is capable of withstanding 40,000 cycles of AFW injection transients. The riser flange 

attachment to the SG shell was also analyzed per ASME Code requirements and was 

acceptable for a design life of 875 cycles of heatup/cooldown, bolt-up and unbolt, and AFW 

initiations. Transients 30A and 30B in LRA Table 4.3-1, which have 60-year projections of 387 

and 442 cycles, respectively, are each less than the 875 design cycles for the riser flange 

attachment. The applicant stated that design transients are tracked for the number of 

occurrences under its Fatigue Monitoring Program to ensure that action is taken before the 

design cycles are reached. The applicant dispositioned the TLAAs of AFW repair, in 

accordance with 10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the AFW modification will 

be managed for the period of extended operation by the Fatigue Monitoring Program.
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In the LRA update dated June 23, 2014, the applicant stated that the original OTSGs in the 

plant design were replaced in the Spring 2014 refueling outage and that the metal fatigue 

analyses for the repaired AFW nozzle design for the original OTSGs is not applicable to the 

CLB for the replacement OTSGs, which were installed during the Spring 2014 refueling outage. 

The applicant stated that LRA Section 4.3.2.2.6.3 is being deleted as a result of the OTSG 

replacement activities and the associated changes to the designs of the AFW systems. The 

staff’s evaluation of the applicant’s basis for deleting these metal fatigue analyses from the 

scope of the LRA is contained in Section 4.3.2.2.2 of this SSER.

OTSGs Tubes and Tube Stabilizers Flow-Induced Vibration. LRA Section 4.3.2.2.6.4 describes 

the fatigue analysis performed for FIV of the OTSG tubes and the tube stabilizers. The 

applicant stated that its latest analysis report showed the highest CUF for any existing tube 

configuration was 0.443 for an unrepaired tube next to the open lane, and the 60-year projected 

CUF value of 0.665 is acceptable. The applicant stated that the 60-year projected CUFs for the 

3/8-inch tube-stabilizers, calculated using both high-cycle (FIV) and low-cycle (transients) 

fatigue, remains below the design limit of 1.0. The applicant dispositioned the fatigue TLAA 

associated with FIV of SG tubes and tube stabilizers, in accordance with 10 CFR 54.21(c)(1)(ii), 

that the TLAAs have been projected through the period of extended operation.

In the LRA update letter dated June 23, 2014, the applicant stated the original OTSGs in the 

plant design were replaced in the Spring 2014 refueling outage and that the previous FIV

analysis for the original OTSG tube and tube stabilizers did not apply to the replacement 

OTSGs that were installed during the Spring 2014 refueling outage. Therefore, by letter dated 

June 23, 2014, the applicant proposed to delete LRA Section 4.3.2.2.6.4 from the scope of the 

LRA. The staff’s evaluation of the applicant’s basis for deleting these FIV analyses from the 

scope of the LRA is contained in Section 4.3.2.2.2 of this SSER.

4.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.2, which consists of metal fatigue TLAAs for ASME Code 

Section III Class 1 vessels, pumps, and major components, to confirm, pursuant to the 

following, and dependent on the applicant’s evaluation:

• 10 CFR 54.21(c)(1)(i), that the analyses remain valid during the period of extended 

operation

• 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period of 

extended operation

• 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be 

adequately managed for the period of extended operation

In the LRA update letter dated June 23, 2014, the applicant stated that the original OTSGs in 

the plant design were replaced in the Spring 2014 refueling outage.

In addition, by letter dated April 21, 2015, as amended in letters dated May 20, 2015, and 

June 5, 2015, the applicant amended the LRA to provide the RVIIP for Davis-Besse. As a result 

of these letters, the applicant amended the metal fatigue TLAAs for RVI components in LRA

Section 4.3.2.2.6, and in particular, the applicant’s basis for accepting the low-cycle fatigue 

TLAA for the RVI components, in accordance with 10 CFR 54.21(c)(1)(iii).
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The following subsections reflect the staff’s updated evaluations of the metal fatigue TLAAs for 

OTSG and RVI components. Otherwise, the staff’s evaluations of the metal fatigue analyses for 

Class 1 vessels, pumps, and major equipment are as documented in SER Section 4.3.2.2.2.

Reactor Vessel Internals

Low-Cycle Fatigue. The staff reviewed LRA Section 4.3.2.2.2.1 on low-cycle fatigue of the RVI 

to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions 

will be adequately managed for the period of extended operation.

The staff reviewed the applicant’s TLAA and the corresponding disposition, consistent with the 

review procedures in SRP-LR Section 4.3.3.1.1.3, which state that the reviewer should verify 

the appropriateness of the applicant’s program for monitoring and tracking the number of critical 

thermal and pressure transients for the selected RCS components. The SRP-LR further states 

that the reviewer should verify that the applicant identified the appropriate program, as 

described and evaluated in the GALL Report. Furthermore, the reviewer should also ensure 

that the applicant’s program contains the same program elements that the staff evaluated and 

relied upon in approving the corresponding generic program in the GALL Report.

The staff noted that, as discussed in LRA Section 4.3.2.2.2.1, the applicant has not replaced the 

upper thermal shield bolts, flow distributor bolts, or guide block bolts, and no fatigue analysis 

was performed for these bolts because it was not required during the original design. However, 

the staff noted that LRA Table 3.1.2-2, Row Nos. 42 and 110, for upper thermal shield bolts and 

flow distribution bolts, respectively, credit a TLAA to manage cumulative fatigue damage. It was 

not clear to the staff what TLAA was being referenced, since LRA Section 4.3.2.2.2.1 states that 

fatigue analyses were not performed for the RVIs. By letter dated May 2, 2011, the staff issued 

RAI 4.3-3 requesting that the applicant identify the fatigue TLAA that is being credited to 

manage cumulative fatigue damage of the components identified by the AMR items in LRA

Table 3.1.2-2, Row Nos. 42 and 110.

In its response dated June 17, 2011, the applicant stated that it has not replaced the upper 

thermal shield bolts, flow distributor bolts, or guide block bolts; therefore, a correction is required 

to Row Nos. 42 and 110 of LRA Table 3.1.2-2. The staff noted that the applicant amended LRA

Table 3.1.2-2 to remove the AMR items associated with stainless steel upper thermal shield 

bolts and flow distributor bolts exposed to borated reactor coolant that are being managed for 

cracking due to fatigue by a TLAA. Although these components do not have a fatigue TLAA 

associated with them, the staff noted that they will be managed by the applicant’s PWR Reactor 

Vessel Internals Program for cracking during the period of extended operation. The staff finds 

the removal of these AMR items acceptable because a fatigue analysis was not performed for 

these components; therefore, they do not have a TLAA associated with them. The staff’s 

concern described in RAI 4.3-3 is resolved.

The staff reviewed the CUF values provided by the applicant, in Table 3-1 of AREVA Document 

51-9157140-001, in response to RAI 4.3-12 (letter dated June 17, 2011) and confirmed that the 

design CUF values for the replaced UCB, LCB, and LTS bolts are less than the design limit of 

1.0. The staff noted that the applicant credited the cycle-counting activities of its Fatigue 

Monitoring Program as the basis for managing cumulative fatigue damage that may occur in the 

reactor vessel during the period of extended operation and will initiate corrective actions to 

ensure the design cycles and design limit of 1.0 will not be exceeded.
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By letter dated June 05, 2015, the applicant amended LRA Section 4.3.2.2.1 to indicate that a 

combination of the Fatigue Monitoring Program (LRA AMP B.2.16) and the PWR Reactor

Vessel Internals Program (LRA AMP B.2.32) will be used to demonstrate that the low-cycle 

fatigue analyses (i.e., low-cycle CUF analyses) for replaced UCB, LCB, and LTS bolts are 

acceptable, in accordance with 10 CFR 54.21(c)(1)(iii), and that the impacts of 

“cracking-fatigue” on the intended functions of these components will be adequately managed 

during the period of extended operation. The staff noted that the change in the basis for 

accepting the TLAA under 10 CFR 54.21(c)(1)(iii) was necessary because it was needed to 

resolve the applicant basis for responding to A/LAI #8, Subitem 5, on the methodology in EPRI 

MRP TR No. 1022863, “Materials Reliability Program: Pressurized Water Reactor Internals 

Inspection and Evaluation Guidelines (MRP-227-A)” (ADAMS Accession Nos. ML12017A191 –

ML12017A197 and ML12017A199), dated January 2012. This A/LAI was issued in the NRC’s 

safety evaluation on the MRP-227-A report, dated December 16, 2011 (ADAMS Accession 

No. ML11308A770).

The staff noted that, under this amended basis, the PWR Reactor Vessel Internals Program 

would implement UT inspections of the UCB and LCB bolts because the components are 

designated as “primary” category components in the MRP-227-A report. Therefore, under this 

basis, the PWR Reactor Vessel Internals Program would be implementing direct volumetric 

inspections of the UCB and LCB bolts during the period of extended operation. The staff 

determined that this forms an acceptable basis for monitoring and managing any 

fatigue-induced cracking in the UCB and LCB bolts during the period of extended operation 

because it is consistent with the “monitoring and trending” element in GALL AMP XI.M16A, 

“PWR Vessel Internals.” The staff also noted that, consistent with GALL AMP X.M1, the 

implementation of the Fatigue Monitoring Program provides an acceptable basis for managing 

fatigue-induced cracking in these components because it directly monitors for design transient 

occurrences at the plant and provides an acceptable basis for determining whether the CUF 

values of the components will remain within a CUF acceptance limit of 1.0. Therefore, the staff 

concludes that the combination of the Fatigue Monitoring Program and the PWR Reactor Vessel 

Internals Program provides an acceptable basis for accepting the CUF analyses for UCB and 

LCB bolts in accordance with 10 CFR 54.21(c)(1)(iii) because the applicant will perform both 

cycle counting and direct inspections of the components during the period of extended 

operation, which is consistent with the criteria in GALL Report AMP XI.M16A and in SRP-LR 

Section 4.3.2.1.1.3 and GALL Report AMP X.M1.

The basis is slightly different for the low-cycle CUF analyses that apply to the replaced LTS 

bolts, which are “expansion” category components in the MRP-227-A report. The staff noted 

that, under the MRP-227-A protocols for these “expansion” category bolts, the PWR Reactor 

Vessel Internals Program would only implement augmented UT inspections of the components 

if relevant indications of cracking were detected in the UCB or LCB bolts, which are the 

“primary” category components linked to potential inspections of LTS bolts. Thus, the staff 

concluded that the PWR Reactor Vessel Internals Program does not provide the main basis for 

accepting the CUF analyses for the LTS bolts, in accordance with 10 CFR 54.21(c)(1)(iii),

because the program would not implement inspections of “expansion” components unless 

degradation was detected in the “primary” category components linked to the LTS bolts, as 

defined “expansion” category components for the AMP. Instead, the staff concluded that it 

would be acceptable to use the Fatigue Monitoring Program as the main basis for accepting the 

CUF analyses for these bolts, in accordance with 10 CFR 54.21(c)(1)(iii), because the applicant 

will use the Fatigue Monitoring Program to perform cycle-counting of the components during the 

period of extended operation, which is consistent with the criteria in SRP-LR Section 4.3.2.1.1.3 

and in GALL Report AMP X.M1.
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Therefore, consistent with the recommendation of GALL Report AMPs X.M1 and XI.M16A, the 

staff finds that the combined cycle-counting activities in the applicant’s Fatigue Monitoring 

Program and inspection protocols for the PWR Reactor Vessel Internals Program are 

acceptable to manage fatigue-induced cracking (cumulative fatigue damage) in the replaced 

UCB, LCB, and LTS bolts during the period of extended operation and to accept the low-cycle 

fatigue analyses for these components in accordance with 10 CFR 54.21(c)(1)(iii). Additionally, 

it is consistent with SRP-LR Section 4.3.2.1.1.3 for the following reasons:

• The applicant’s Fatigue Monitoring Program monitors and tracks the number of design 

basis transients that will occur through the period of extended operation.

• The applicant’s Fatigue Monitoring Program includes action limits and corrective actions 

that will ensure that the CUF design limit of 1.0 will not be exceeded during the period of 

extended operation.

• The use of the applicant’s Fatigue Monitoring Program is consistent with the 

recommendations of the GALL Report AMP X.M1 for managing cumulative fatigue 

damage.

• Additionally, implementing the applicant’s PWR Reactor Vessel Internals Program will 

provide a direct means of inspecting for fatigue-induced cracking that may be occurring 

in the replaced UCB and LCB bolts during the period of extended operation, and for 

inspecting the LTS bolts if degradation exceeding the levels defined in Table 5-1 of 

MRP-227-A is detected in the UCB or LCB bolts.

The staff’s evaluation of the applicant’s Fatigue Monitoring Program is documented in SER 

Section 3.0.3.2.6. The staff’s evaluation of the PWR Reactor Vessel Internals Program is 

documented in Section 3.0.3.3.6 of this SSER. A/LAI #8, Subitem 5, is resolved with respect to 

the basis for accepting the low-cycle fatigue analyses for the UCB, LCB, and LTS bolts, in 

accordance with 10 CFR 54.21(c)(1)(iii).

Reactor Vessel Internals and Incore Instrumentation Nozzles Flow-Induced Vibration. The staff 

reviewed LRA Subsection 4.3.2.2.2.2 on FIV of the RVI components and incore instrument 

nozzles to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the FIV analysis for these components 

remains valid during the period of extended operation. The staff performed its review in 

accordance with the requirement in 10 CFR 54.21(c)(1)(i) and the acceptance criteria in 

SRP-LR Section 4.3.2.1.1.1.

The staff noted the applicant’s submittal of the RVIIP (as documented in the letters of 

April 21, 2015, and supplemented by information in the letters of May 20, 2015, and 

June 5, 2015) did not result in any need to change the applicant’s evaluation of the FIV analysis 

for the RVI components or incore instrumentation nozzles or the applicant’s basis for accepting 

this TLAA, in accordance with 10 CFR 54.21(c)(1)(i). Therefore, the staff’s prior evaluation of 

the FIV analysis for the RVI components or incore instrumentation nozzles remains valid for this 

SSER, as documented in SER Section 4.3.2.2.2. The evaluation in SER Section 4.3.2.2.2 

provides the staff’s basis for concluding that the FIV analysis for the RVI components or incore 

instrumentation nozzles is acceptable, in accordance with 10 CFR 54.21(c)(1)(i), and meets the 

acceptance criteria in SRP-LR Section 4.3.2.1.1.1.

Based on this review, the staff finds the applicant demonstrated, pursuant to

10 CFR 54.21(c)(1)(i), that the FIV analysis of the RVIs and incore instrument nozzles remains 

valid during the period of extended operation.
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Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.1 because the 

endurance limit assumed in the original analysis would not be exceeded and the implicit CUF 

value of zero remains valid during the period of extended operation.

Surveillance Capsule Holder Tubes Flow-Induced Vibration. The staff reviewed LRA 

Subsection 4.3.2.2.2.3 on the high-cycle fatigue analysis (i.e., FIV-based CUF analysis) of the 

surveillance capsule holder tubes to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis 

has been projected to the end of the period of extended operation. The staff performed its 

review in accordance with the requirement in 10 CFR 54.21(c)(1)(ii) and the acceptance criteria 

in SRP-LR Section 4.3.2.1.1.2.

The staff noted that the applicant’s submittal of the RVIIP (as documented in the letters of 

April 21, 2015, and supplemented by information in the letters of May 20, 2015, and 

June 5, 2015) did not result in any need to change the applicant’s evaluation of the high-cycle 

fatigue analysis for the reactor vessel surveillance capsule holder tubes or the applicant’s basis 

for accepting this TLAA in accordance with 10 CFR 54.21(c)(1)(ii). Therefore, the staff’s prior 

evaluation of the high-cycle fatigue analysis for the reactor vessel surveillance capsule holder 

tubes remains valid for this SSER, as documented in SER Section 4.3.2.2.2.

The evaluation in SER Section 4.3.2.2.2 provides the staff’s basis for concluding that the 

high-cycle fatigue analysis for the reactor vessel surveillance capsule holder tubes is 

acceptable, in accordance with 10 CFR 54.21(c)(1)(ii), and meets the acceptance criteria in 

SRP-LR Section 4.3.2.1.1.2.

Based on this review, staff finds the applicant demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), 

that the surveillance capsule holder tubes FIV analysis has been projected to the end of the 

period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.1.2 because the applicant demonstrated that the projected CUF values will be 

less than the ASME Code Section III, design limit of 1.0 through the period of extended 

operation with significant margin.

Once-Through Steam Generators Fatigue. The evaluation in this section of the SSER 

supersedes the staff’s evaluation of the metal fatigue analyses for OTSG components in 

Section 4.3.2.2.2, Subsection, “Once-Through Steam Generator Fatigue,” of the staff’s SER.

In the LRA update dated June 23, 2014, the applicant updated LRA Section 4.3.2.2.6, “OnceThrough Steam Generators,” and LRA Section 4.3.2.2.6.1, “OTSGs Fatigue,” to indicate that the 

limiting components in the replacement OTSGs for Davis-Besse were assessed with updated 

fatigue analyses. The staff also noted that, in this LRA update, the applicant amended LRA 

AMR Table 3.1.2-4 to include updated AMR items for the following components in the 

replacement OTSG designs that were reanalyzed with updated metal fatigue analyses (i.e., that 

received updated CUF analyses):

• replacement OTSG primary boundary bolts

• replacement OTSG primary manway and inspection opening covers

• replacement OTSG primary side tubes

• replacement OTSG primary side tube plugs

• replacement OTSG primary side upper and lower heads

• replacement OTSG primary side inlet and outlet nozzles
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• replacement OTSG primary side upper and lower tubesheets

• replacement OTSG primary side tube-to-tubesheet welds

• replacement OTSG secondary side AFW headers, risers, nozzles, and nozzle thermal 

sleeves

• replacement OTSG secondary side shrouds and shroud support rings and lugs

• replacement OTSG secondary side manways and handhole covers

• replacement OTSG secondary side main feedwater (MFW) header support plates and 

gussets

• replacement OTSG secondary side MFW headers and risers

• replacement OTSG secondary side MFW nozzles and MFW nozzle thermal sleeves

• replacement OTSG secondary side steam outlet nozzles, vent nozzles, drain nozzles, 

and level sensing nozzles

• replacement OTSG secondary side shells

• replacement OTSG secondary side tube support plates

• replacement OTSG secondary side tube support plate spacers

• replacement OTSG secondary side tube support rods (i.e., tie rods)

• replacement OTSG base support stools and base support platforms

The staff noted that, in these AMR items, the applicant stated that “cracking – fatigue” of the 

replacement OTSG components would be adequately managed for the period of extended 

operation using a metal fatigue TLAA.

The staff noted that, in its LRA amendment, the applicant did not amend LRA Section 4.3.2.2.6 

and LRA Section 4.3.2.2.6.1 to specify the replacement OTSG, MFW, or AFW components that 

were analyzed in accordance with an updated metal fatigue analysis (i.e., in accordance with an 

updated ASME Section III CUF analysis) or to identify how the updated metal fatigue analyses 

for these components were being accepted, in accordance with 10 CFR 54.21(c)(1)(i), (ii), or 

(iii).

By letter dated August 19, 2014, the staff issued RAI 4.3.2.2.6.1-1 (followup), requesting in 

Part 1 of the RAI that the applicant identify all replacement OTSG components that had been 

analyzed in accordance with an ASME Code Section III metal fatigue analysis (i.e., CUF 

analysis). In RAI 4.3.2.2.6.1-1, Part 2, for each replacement OTSG component that had been 

analyzed in accordance with an updated CUF analysis, the staff asked the applicant to perform 

a comparison of the CUF analysis for the component to the six criteria for defining a TLAA in 

10 CFR 54.3(a) and to justify why the updated CUF analysis for the component would not need 

to be identified as a TLAA in accordance with the requirement in 10 CFR 54.21(c)(1).

In RAI 4.3.2.2.6.1-1, Part 3, for each replacement OTSG component that was analyzed in 

accordance with a metal fatigue analysis that conforms to the definition of a TLAA, as defined in 

10 CFR 54.3(a), the staff asked the applicant to justify acceptance of the metal fatigue analysis 

in accordance with the requirements in 10 CFR 54.21(c)(1)(i), (ii), or (iii).

The applicant responded to RAI 4.3.2.2.6.1-1, Parts 1, 2, and 3 in a letter dated 

September 16, 2014. In its response to RAI 4.3.2.2.6.1-1, Part 1, the applicant stated that the 
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replacement OTSG components that have been analyzed with updated metal fatigue analyses 

have been identified in the applicant’s update of LRA Table 3.1.2-4, as provided in the FENOC 

letter dated June 23, 2014, and that the fatigue analyses for these replacement OTSG 

components were performed in accordance with the 2001 Edition of the ASME Code Section III, 

inclusive of the 2003 Addenda. The applicant clarified that LRA Section 4.3.2.2.6.3, as 

previously revised in the letter dated June 23, 2014, is not needed as a separate section and 

remains as “Not used.” The applicant stated that, unlike the original OTSGs, where, by 

modification, the AFW headers were relocated to the outside of the SG and the modification 

was evaluated separately, the AFW headers in the replacement OTSGs are also located on the 

outside of the OTSGs. The applicant stated that the updated fatigue analysis (CUF analysis) for 

the AFW headers is included with the scope of the evaluation that is given in the amended 

version of LRA Section 4.3.2.2.6.1, as discussed in the letter dated June 23, 2014.

In its response to RAI 4.3.2.2.6.1-1, Part 2, the applicant stated that the new CUF analyses for 

the subject replacement OTSG components, including the new CUF analyses for the AFW

headers, nozzles and nozzle thermal sleeves, meet the six criteria for defining TLAAs in 

accordance with 10 CFR 54.3(a). In its response to RAI 4.3.2.2.6.1-1, Part 3, the applicant 

stated that the new CUF analyses for the replacement OTSG components were calculated 

using the applicable design transients for the components and that the CUF values for the 

components are all less than the acceptance criterion of 1.0 for ASME Code-calculated CUF 

values. The applicant also stated that the design transients used in the fatigue analyses for the 

subject replacement OTSG components are included in LRA Table 4.3-1, “60-year Projected 

Cycles.” The applicant stated that, as provided in LRA Section 4.3.2.2.6.1, the number of 

occurrences of design transients is tracked and will continue to be tracked by the Fatigue 

Monitoring Program to ensure that: (a) action is taken before the cycle limits for the design 

transients are reached, and (b) the effects of “cracking – fatigue” on the intended functions of 

the replacement OTSGs (and their components) will be adequately managed by the Fatigue 

Monitoring Program during the period of extended operation, in accordance with 

10 CFR 54.21(c)(1)(iii).

The staff noted that, in the LRA amendment, the applicant amended LRA Table 3.1.2-4 to 

identify the specific replacement OTSG components that had been within the scope of a metal 

fatigue TLAA (i.e., CUF analysis) and these components are within the scope of the metal 

fatigue TLAA assessment that is given in LRA Section 4.3.2.2.6.1. These are the specific 

replacement OTSG components that have been identified earlier in this SER section (refer to 

the components in the previous bulleted list of this SSER section).

The staff noted the applicant indicated that it will use the Fatigue Monitoring Program as the 

basis for managing the impact of “cracking – fatigue” on the intended functions of these 

replacement OTSGs during the period of extended operation and that the basis was consistent 

with the acceptance criterion in SRP-LR Section 4.3.2.1.1.3, which states that an applicant’s 

Fatigue Monitoring Program may be used to accept a metal fatigue analysis in accordance with 

10 CFR 54.21(c)(1)(iii) and to manage the impacts of “cracking – fatigue” on the intended 

functions of the components during the period of extended operation. Therefore, the staff 

determined that the applicant provided an acceptable basis for accepting the updated fatigue 

analyses for the replacement OTSG components in accordance with 10 CFR 54.21(c)(1)(iii) 

because the applicant’s basis was consistent with the acceptance criteria guidance in SRP-LR 

Section 4.3.2.1.1.3.
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Therefore, based on this review, the staff finds that the applicant has appropriately amended the 

LRA and provided an acceptable metal fatigue TLAA for the replacement OTSG components 

because of the following:

(a) The applicant has appropriately amended the LRA to include the specific replacement 

OTSG components that are within the scope of a CUF analysis.

(b) The applicant has shown that these CUF analyses are applicable TLAAs for the LRA.

(c) The applicant will use its Fatigue Monitoring Program to manage the impacts of 

“cracking – fatigue” on the intended functions of the replacement OTSGs and the 

replacement AFW header during the period of extended operation.

(d) This provides an acceptable basis for accepting these TLAAs, in accordance with the 

criterion in 10 CFR 54.21(c)(1)(iii), and for demonstrating that the effects of “cracking –

fatigue” on the intended functions of the replacement OTSGs, and their components, will 

be adequately managed during the period of extended operation.

RAI 4.3.2.2.6.1-1, Parts 1, 2, and 3, are resolved.

Once-Through Steam Generator Tube Sleeves Fatigue. The evaluation in this section of the 

SSER supersedes the staff’s evaluation of the metal fatigue analysis for OTSG tube sleeves in 

SER Section 4.3.2.2.2. The staff noted that, in the LRA, the applicant stated that the design of 

the original OTSGs included some sleeved OTSG tubes and that the design basis for the OTSG 

tube sleeves included a metal fatigue analysis that conformed to the definition of a TLAA in 

10 CFR 54.3(a). The staff noted that the applicant dispositioned the metal fatigue analysis for 

the OTSG tube sleeves in accordance with the TLAA acceptance criterion in 

10 CFR 54.21(c)(1)(i), which requires the applicant to demonstrate that the analysis will remain 

valid for the period of extended operation.

In the LRA update letter dated June 23, 2014, the staff noted that the applicant indicated the 

original OTSGs in the plant design were replaced during the Spring 2014 refueling outage and 

that the new OTSG did not include any tube sleeves. Therefore, the staff noted that the 

applicant stated that the previous metal fatigue analysis (as discussed in LRA

Section 4.3.2.2.6.2) for tube sleeves in the original OTSGs did not apply to the design of 

replacement OTSGs.

The staff verified that, in the letter dated June 23, 2014, the applicant amended LRA

Table 2.3.1-4, “Steam Generators Components Subject to Aging Management Review” to 

identify those components in the replacement OTSG designs that were required to be within the 

scope of the LRA. The staff noted that the revised version of LRA Table 2.3.1-4 did not identify 

any replacement OTSG tube sleeves that would need to be within the scope of the LRA, based 

on the updated design of the OTSGs. Based on the contents of the amended table for the 

replacement OTSG components, the staff noted that the previous metal fatigue analysis for 

OTSG tube sleeves in the LRA Section 4.3.2.2.6.2 does not apply to the updated CLB for the 

replacement OTSGs because the replacement OTSGs do not include any tube sleeves.

As a result, the staff determined that the previous metal fatigue analysis for the tube sleeves in 

the original OTSG design does not conform to Criterion 6 in 10 CFR 54.3(a) because the 

analysis is no longer contained or incorporated by reference in the updated CLB for the OTSGs. 

Therefore, based on this review, the staff finds that the applicant has provided an acceptable 
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basis for deleting the metal fatigue TLAA for the OTSG tube sleeves from the scope of LRA

Table 4.1-1 and LRA Section 4.3.2.2.6.2 because the staff has verified the following:

(a) The analysis does not conform to Criterion 6 in 10 CFR 54.3(a).

(b) The analysis does not meet the definition of a TLAA, as defined in 10 CFR 54.3(a), for 

the updated CLB that applies to the replacement OTSGs.

Once-Through Steam Generators Auxiliary Feedwater Modification. The evaluation in this 

section of the SSER supersedes the staff’s evaluation of the metal fatigue analyses for 

components in the modified AFW system design, as given in SER Section 4.3.2.2.2.

The staff noted that, in the LRA, the applicant stated that the original AFW headers internal to 

the SGs were found damaged during the 1982 refueling outage and that the ensuing repair 

modification installed an external AFW header on each of the original OTSGs. The applicant 

also indicated that the modification of the plant design included some rerouting of AFW piping 

and supports and a fatigue analysis for the repaired AFW nozzle design on the OTSGs. The 

staff noted that, in the original version of the LRA, the applicant had identified this metal fatigue 

analysis as a TLAA that was dispositioned in accordance with the TLAA acceptance criterion in 

10 CFR 54.21(c)(1)(iii), which requires an applicant to demonstrate that the effects of aging on 

the intended functions of the components will be adequately managed during the period of 

extended operation.

The staff noted that, in the LRA update letter dated June 23, 2014, the applicant stated that the 

original OTSGs in the plant design were replaced in the Spring 2014 refueling outage and that 

the metal fatigue analyses for the repaired AFW nozzle design on the original OTSGs is not 

applicable to the updated CLB for the replacement OTSGs. Instead, the staff verified that the 

applicant included its new CUF analyses for the external AFW headers, nozzles, and nozzle 

thermal sleeves in the replacement OTSGs within the scope of the metal fatigue TLAAs that are 

included in the updated version of LRA Section 4.3.2.2.6.1, as identified and discussed in the 

LRA update dated June 23, 2014.

As a result, the staff determined that the metal fatigue analysis for the previous, modified AFW

design does not conform to Criterion 6 in 10 CFR 54.3(a) because the analysis is not contained 

or incorporated by reference in the updated CLB for the replacement OTSGs. Therefore, based 

on this review, the staff finds that the applicant has provided an acceptable basis for deleting the 

metal fatigue TLAA for the AFW modification from the scope of LRA Table 4.1-1 and LRA

Section 4.3.2.2.6.3 because the staff has verified the following:

(a) The analysis does not conform to Criterion 6 in 10 CFR 54.3(a).

(b) The analysis does not meet the definition of a TLAA, as defined in 10 CFR 54.3(a), for 

the CLB that applies to the replacement OTSGs.

Instead, the staff has confirmed that the applicant included the updated metal fatigue analyses 

for the new external AFW headers and the new AFW nozzles and nozzle thermal sleeves in the 

scope of the June 23, 2014, LRA update (i.e., revision) of LRA Section 4.3.2.2.6.1. The staff 

evaluated the new fatigue analyses for these components in Section 4.3.2.2.2, Subsection 

“Once-Through Steam Generator Fatigue” of this SSER and has determined that the new 

analyses are acceptable because the applicant will use its Fatigue Monitoring Program to 

accept the metal fatigue analyses for these components, in accordance with the criterion in 
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10 CFR 54.21(c)(1)(iii), and to manage the impacts of “cracking – fatigue” on the intended 

functions of these components during the period of extended operation.

Once-Through Steam Generators Tubes and Tube Stabilizers Flow-Induced Vibration. 

The evaluation in this section of the SSER supersedes the staff’s previous evaluation of the FIV

analyses for tubes and tube stabilizers in the original OTSGs, as given in SER 

Section 4.3.2.2.2.

The staff noted that, in Section 4.3.2.2.6.4 of the LRA, the applicant stated that the design of the 

original OTSGs included tubes and tube stabilizers and the design basis for the tubes and tube 

stabilizers included a cyclical flow-vibration analysis which conformed to the definition of a TLAA 

in 10 CFR 54.3(a). The staff noted that, in the original version of the LRA, the applicant

dispositioned the FIV analysis for the OTSGs tube and tube stabilizers, in accordance with the 

TLAA acceptance criterion in 10 CFR 54.21(c)(1)(ii), which requires the applicant to 

demonstrate that the analysis has been projected through to the end of the period of extended 

operation.

The staff noted that, in the LRA update letter dated June 23, 2014, the applicant stated that the 

original OTSGs in the plant design were replaced in the Spring 2014 refueling outage and the 

previous FIV analysis for original OTSG tube and tube stabilizers did not apply to the 

replacement OTSGs. Therefore, in the letter dated June 23, 2014, the applicant proposed to 

delete LRA Section 4.3.2.2.6.4 from the scope of the LRA.

It was not evident to the staff why the tubes and or other components in the replacement 

OTSGs would not have been required to be analyzed with an FIV analysis, similar to how the 

tubes and tube stabilizers in the original OTSGs were analyzed for FIVs, or why such an FIV

analysis would not need to be identified as a TLAA for the replacement OTSGs or specific 

subcomponents in the replacement OTSGs. Therefore, by letter dated August 19, 2014, the 

staff issued RAI 4.3.2.2.6.4-1 (LRA Update followup), requesting that the applicant provide 

additional clarification on whether the design code or codes for the replacement OTSGs, or 

specific components in the replacement OTSGs, required an FIV analysis. If it is determined 

that the design code for the replacement OTSGs did require an FIV analysis, the staff asked the 

applicant to justify why the applicable FIV analysis would not need to be identified as a TLAA, in 

accordance with the definition criteria for TLAAs in 10 CFR 54.3(a).

The applicant responded to RAI 4.3.2.2.6.4-1 (LRA Update followup) by letter dated 

September 16, 2014. In its response, the applicant stated that the design specification for the 

replacement OTSGs did require the applicant to perform a flow-induced and turbulence-induced 

vibration analysis for components in the replacement OTSG tube bundles. The applicant stated 

that the analyses were performed to show that fatigue failures, excess tube fretting and tube 

wear, or wear of other SG internals, will not occur during future plant operation (including 

operation of the replacement OTSGs). The applicant stated that the replacement OTSGs were 

installed in the Spring 2014 refueling outage and were qualified for 40 years of service from the 

time of installation. The applicant stated that replacement OTSGs will experience only about 

23 years of operation by the end of the period of extended operation. The applicant stated that 

the inservice time of the replacement OTSGs will not exceed the time associated with a 40-year 

qualified life. Therefore, the applicant stated that the flow-induced and turbulence-induced 

vibration analysis for the replacement OTSG components does not meet the six criteria in 

10 CFR 54.3(a) and does not a constitute a TLAA that would require evaluation, in accordance 

with the requirement in 10 CFR 54.21(c)(1).
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Based on the applicant’s response, the staff noted that a time-dependent flow-induced and 

turbulence-induced vibration analysis is part of the updated CLB for the internal components of 

the replacement OTSGs at Davis-Besse. The staff also noted that the time-dependent 

flow-induced and turbulence-induced vibration analysis for the internal replacement OTSG 

components would qualify the operation of the internal OTSG components beyond the time 

associated with the period of extended operation. Therefore, based on this review, the staff 

determined that the time-dependent flow-induced and turbulence-induced vibration analysis for 

the internal replacement OTSG components does not conform to Criterion 3 in 10 CFR 54.3(a) 

because the analysis does not involve time-dependent assumptions defined by the current 

operating term. Therefore, based on this review, the staff finds that the applicant has provided 

an acceptable basis for concluding that the LRA does not need to include an FIV TLAA for the 

internal components in the replacement OTSGs because the staff has verified the following:

(a) The analysis does not conform to Criterion 3 in 10 CFR 54.3(a).

(b) The analysis does not meet the definition of a TLAA, as defined in 10 CFR 54.3(a), for 

the CLB that applies to replacement OTSGs.

RAI 4.3.2.2.6.4-1 (LRA Update followup) is resolved.

4.3.2.2.3 USAR Supplement

Applicable subsections in LRA Section A.2.3 provide the USAR supplements that summarize

the metal fatigue TLAAs for Class 1 vessels, pumps, and major equipment. The staff reviewed 

the applicable USAR supplements in LRA Sections A.2.3.1 (including Subsections A.2.3.1.1, 

A.2.3.1.3, and A.2.3.1.5) and A.2.3.2 (including Subsections A.2.3.2.1 – A.2.3.2.8), consistent 

with the review procedures in SRP-LR Section 4.3.3.3, which state that the reviewer verifies that 

the applicant provided information to be included in the USAR supplement that includes a 

summary description of the evaluation of the metal fatigue TLAA. This evaluation supplements 

the staff’s previous evaluation, in SER Section 4.3.2.2.3, of the USAR supplement sections that 

apply to Class 1 vessels, pumps, and major equipment.

By letter dated June 23, 2014, the applicant amended USAR Supplement A.2.3.10.2, “Once 

Through Steam Generators,” as follows in order to account for OTSG and AFW system design 

changes that resulted from the OTSG replacement activities in Spring 2014:

A.2.3.2.10 Once Through Steam Generator

The primary (tube) and secondary (shell) sides of the once through steam 

generators are designed to ASME Section III, 1968 Edition through Summer 

1968 Addenda 2001 Edition with 2003 Addenda. The steam generators were 

analyzed for fatigue by the original equipment manufacturer. The cumulative 

usage factors for the limiting primary and secondary side steam generator 

locations were calculated based on design transients, and are all less than 1.0.

In addition, the steam generator remote weld plugs have a limited design life of 

33 heatup/cooldown cycles to maintain a fatigue usage of less than 1.0. The 

number of occurrences of design transients is tracked by the Fatigue Monitoring 

Program to ensure that action is taken before the design cycles are reached. As 

such, the effects of aging due to fatigue are managed for the period of extended 

operation in accordance with 10 CFR 54.21(c)(1)(iii).
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The staff verified that the changes to USAR Supplement Section A.2.3.2.10 were appropriate for 

changes that were made to the plant design as a result of the OTSG replacement activities that 

were implemented in the Spring 2014 refueling outage and for the new fatigue analyses that 

were performed for specific primary side and secondary side components in the replacement 

OTSGs, including specific replacement OTSG internal components and portions of piping 

systems entering the replacement OTSGs, as identified in Section 4.3.2.2.2 of this SSER.

By letter dated June 23, 2014, the applicant amended LRA Appendix A to delete LRA

Section A.2.3.1.5, “Steam Generator Remote Welded Plugs,” from the scope of the USAR 

Supplement for the LRA. The applicant stated that the USAR supplement summary description 

for the OTSG remote welded plugs in LRA Section A.2.3.1.5 is being deleted from the scope of 

the USAR supplement as a result of the OTSG replacement design modification activities that 

were implemented in the Spring 2014 refueling outage.

The staff noted that, in the applicant’s LRA update letter dated June 23, 2014, the applicant 

included its metal fatigue TLAAs (i.e., CUF analyses) for primary side tube plugs in the 

replacement OTSGs as a revision to the scope of LRA Section 4.3.2.2.6.1. Therefore, the staff 

reviewed the scope of USAR Supplement Section A.2.3.10.2, as updated in the letter dated 

June 23, 2014, to determine whether the USAR supplement for the OTSGs had provided a 

sufficient USAR supplement summary description for the primary side tube plugs that were 

included in the design of the applicant’s replacement OTSGs.

The staff determined that the scope of USAR Supplement Section A.2.3.10.2 includes primary 

and secondary side OTSG component locations with a CUF analysis, which now includes the 

primary side plugs in the replacement OTSGs. Thus, the staff concludes that the applicant had 

provided an acceptable basis for deleting USAR Supplement Section A.2.3.1.5 from the scope 

of the LRA because the staff has verified that the USAR supplement summary description for 

the fatigue analyses of the primary side tube plugs in the replacement OTSGs is adequately 

summarized and addressed in the version of USAR Supplement Section A.2.3.10.2 that was 

included in the letter dated June 23, 2014.

By letter dated June 23, 2014, the applicant revised LRA Appendix A to delete USAR 

Supplement Section A.2.3.2.6, “Steam Generator Tube Sleeve Fatigue,” from the scope of the 

USAR supplement for the LRA. The applicant stated that the USAR supplement summary 

description for the tube sleeves in LRA Section A.2.3.2.6 is being deleted from the scope of the 

USAR supplement as a result of the OTSG replacement design modification activities that were 

implemented in the Spring 2014. The applicant stated that the replacement OTSGs do not 

currently have any sleeves in the OTSG design. Therefore, the staff finds that the applicant has 

provided an acceptable basis for deleting LRA Section A.2.3.2.6, “Steam Generator Tube 

Sleeve Fatigue,” from the scope of the USAR supplement for the LRA because tube sleeves are 

not currently included in the design of the replacement OTSGs. 

By letter dated June 23, 2014, the applicant amended LRA Appendix A to delete LRA

Section A.2.3.2.7, “Auxiliary Feedwater Header Modification,” from the scope of the USAR 

supplement for the LRA. The applicant stated that the USAR supplement summary description 

in LRA Section A.2.3.2.7 is being deleted from the scope of the USAR supplement as a result of 

the OTSG replacement design modification activities that were implemented in the Spring 2014 

refueling outage.

The staff noted that, in the applicant’s LRA update letter dated June 23, 2014, the applicant 

deleted the metal fatigue TLAAs in LRA Section 4.3.2.2.6.3 from the scope of the LRA. Instead, 
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the staff verified that the applicant included the new metal fatigue analyses for the AFW nozzles 

and nozzle thermal sleeves that were included in the replacement OTSGs and identified these 

analyses as TLAAs in the amended version of LRA Section 4.3.2.2.6.1 that was included in the 

letter dated June 23, 2014.

The staff reviewed the scope of USAR Supplement Sections A.2.3.10.2, as updated in the letter 

dated June 23, 2014, in order to determine whether the USAR supplement for the OTSGs had 

provided a sufficient USAR supplement summary description for the fatigue analyses of the 

AFW nozzles and nozzle thermal sleeves that were installed during the Spring 2014 design 

modification. The staff determined that the scope of USAR Supplement Section A.2.3.10.2 

includes primary and secondary side OTSG component locations for which a CUF analysis was 

performed, which now includes the AFW headers, nozzles, and nozzle thermal sleeves used in 

the design of the replacement OTSGs. Therefore, the staff finds that the applicant had provided 

an acceptable basis for deleting USAR Supplement Section A.2.3.2.7 because the staff has 

verified that the USAR supplement summary description of the fatigue analyses for the AFW 

headers, nozzles, and nozzle thermal sleeves is adequately summarized and addressed in the 

version of USAR Supplement Section A.2.3.10.2 that was included in the letter dated 

June 23, 2014.

By letter dated June 23, 2014, the applicant amended LRA Appendix A to delete LRA

Section A.2.3.2.8, “Steam Generator Tubes and Tube Stabilizers Flow-Induced Vibration,” from 

the scope of the USAR supplement for the LRA. The applicant stated that the USAR 

supplement summary description in LRA Section A.2.3.2.8 is being deleted from the scope of 

the USAR supplement as a result of the OTSG replacement design modification activities that 

were implemented in the Spring 2014 refueling outage. In its response to RAI 4.3.2.2.6.4-1 

dated September 16, 2014, the applicant clarified that the updated FIV analyses for tubes and 

tube stabilizers in the replacement OTSGs do not qualify as TLAAs because they were not 

analyzed in terms of a time-limited assumption defined by the current operating period.

As previously discussed in Section 4.3.2.2.2 of the this SSER, the staff verified that the FIV

analyses for the tubes and tube stabilizers in the replacement OTSGs were not analyzed in 

terms of a time-limited assumption defined by the current operating period. Specifically, the 

staff noted that the assessment of high-cycle vibrations in the FIV analyses of the replacement 

OTSG tube and tube stabilizer components goes well beyond the end of the proposed period of 

operation for the Davis-Besse facility. Therefore, the staff determined that the applicant had 

provided an acceptable basis for concluding that the updated flow-vibration analyses for these 

components do not constitute TLAAs because they do not conform to Criterion 3 in 

10 CFR 54.3(a). Therefore, based on this analysis, the staff concluded that the applicant has 

provided an acceptable basis for deleting USAR Supplement Section A.2.3.2.8 from the scope 

of LRA Appendix A because the updated FIV analyses for these components do not qualify as 

TLAAs that need to be identified, in accordance with the requirement in 10 CFR 54.21(c)(1).

By letter dated June 5, 2015, the applicant amended the USAR Supplement Section A.2.3.2.1, 

“Reactor Vessel Internals Bolts,” as follows:

A.2.3.2.1 Reactor Vessel Internals Bolts

Although the reactor vessel internals are designed to meet the stress 

requirements of ASME Section III, they are not code components. 

Consequently, a fatigue analysis of the reactor vessel internals was not required 

and not performed as part of the original design.
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FENOC has replace[d] the majority of the stainless steel, Alloy 286, bolts for the 

reactor vessel internals with Alloy X-750 HTH bolts at Davis Besse. The 

replacement bolts were designed to ASME Section III, and are provided with 

fatigue analyses. FENOC has not replaced the upper thermal shield bolts, flow 

distributor bolts, or guide block bolts at Davis Besse. Design cumulative usage 

factors for the reactor vessel internals bolts are based on design cycles.

The effects of fatigue on the reactor vessel internals bolts will be managed by the 

Fatigue Monitoring Program and the PWR Reactor Vessel Internals Program for 

the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).

The staff has evaluated and accepted the applicant basis for using these AMPs to accept the 

fatigue analyses for replaced RVI bolts in the “Reactor Vessel Internals, Low-Cycle Fatigue,”

subsection of Section 4.3.2.2.2 of this SSER. Therefore, the staff finds the updated version of 

USAR Supplement Section A.2.3.2.1 to be acceptable because it is consistent with the 

applicant’s updated basis to use both the Fatigue Monitoring Program and the PWR Reactor 

Vessel Internals Program as the bases for accepting these metal fatigue TLAAs, in accordance 

with 10 CFR 54.21(c)(1)(iii).

Based on its review of the USAR supplement, as amended by letters dated June 17, 2011, 

June 23, 2014, and June 5, 2015, the staff finds it meets the acceptance criteria in SRP-LR 

Section 4.3.2.3. Additionally, the staff determines that the applicant provided an adequate 

summary description of its actions to address the fatigue TLAAs of Class 1 vessels, pumps, and 

major components (including fatigue analyses for limiting locations in the primary sides and 

secondary sides of the replacement OTSGs and the fatigue analyses for replaced RVI bolts), as 

required by 10 CFR 54.21(d).

4.3.2.2.4 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)(i), that the FIV analyses for the RVIs and incore 

instrumentation nozzles remain valid during the period of extended operation. The staff also 

concludes that the applicant demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

high-cycle fatigue analysis (i.e., vibrational-based CUF analysis) of the reactor vessel 

surveillance capsule holder tubes has been projected to the end of the period of extended 

operation. The staff also concludes that the applicant demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging related to fatigue of the RV, RVIs, control rod 

drive housings, RCP casings, pressurizer components, OTSG primary and secondary shell 

components, OTSG plugs, and OTSG AFW components will be adequately managed for the 

period of extended operation. The staff also concludes that the USAR supplement contains 

appropriate summary descriptions of the TLAAs, as required by 10 CFR 54.21(d).

4.3.2.3 Class 1 Piping and Valves

4.3.2.3.1 Summary of Technical Information in the Application

In the LRA update letter dated June 23, 2014, the applicant stated that the original OTSGs in 

the plant design were replaced in the Spring 2014 refueling outage. Several of the sections 

below have been changed by adding information to reflect this plant modification.
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Class 1 Piping Fatigue

By letter dated June 23, 2014, the applicant amended LRA Section 4.3.2.3 and stated that it had 

replaced some of the hot leg piping in the main reactor coolant loops as part of the replacement 

OTSG activities that were implemented in the Spring 2014 refueling outage. The applicant 

stated that the new design code of record for the Class 1 piping sections is the 2001 Edition of 

ASME Code Section III, inclusive of the 2003 Addenda.

4.3.2.3.2 Staff Evaluation

Class 1 Piping Fatigue

The staff noted that, by letter dated June 23, 2014, the applicant amended LRA Section 4.3.2.3 

and stated that it had replaced some of the hot leg piping in the main reactor coolant loops as 

part of the OTSG replacement activities that were implemented in the Spring 2014 refueling 

outage. The staff also noted that the applicant stated that the code of record for the new 

Class 1 piping sections is the 2001 Edition of ASME Code Section III, inclusive of the 2003 

Addenda. The staff noted that this design code of record requires the applicant to perform a 

fatigue analysis (CUF analysis) for the new (replaced) piping segments in the RCS hot leg 

piping. The applicant conservatively identified the new CUF analysis as a TLAA for the LRA. 

Therefore, the staff determined the previous basis in 10 CFR 54.21(c)(1)(iii) for accepting the 

metal fatigue TLAA for Safety Class 1 piping is still valid and applicable to the evaluation of the 

CUF analyses that the applicant performed and applied to new hot leg piping segments 

because the applicant will use its Fatigue Monitoring Program to manage the impact of 

“cracking – fatigue” on the intended functions of the Safety Class 1 piping, including those for 

the hot leg portions of the piping.

4.3.2.3.3 USAR Supplement

Applicable subsections in LRA Section A.2.3 provide the USAR supplements that summarize 

the metal fatigue TLAAs for Class 1 piping and valves. The staff reviewed the applicable USAR 

supplements for Class 1 piping in LRA Sections A.2.3.1 (including Subsections A.2.3.1.1 – 

A.2.3.1.5) and A.2.3.2.11, consistent with the review procedures in SRP-LR Section 4.3.3.3, 

which state that the reviewer verifies that the applicant provided information to be included in 

the USAR supplement that includes a summary description of the evaluation of the metal fatigue 

TLAA. This evaluation supplements the staff’s previous evaluation in SER Section 4.3.2.3.3 of 

the USAR supplement sections that apply to the metal fatigue analyses for Class 1 piping and 

valves.

By letter dated June 23, 2014, the applicant amended LRA Section A.2.3.2.11 to include the 

following USAR supplement summary statement for the Safety Class 1 piping at the plant:

A portion of the reactor coolant system hot leg piping was replaced in support of steam 

generator replacement in the spring of 2014. Applicable ASME Code of Construction for the 

replaced hot leg piping is Section III, 2001 Edition with 2003 Addenda. 

The staff found the amendment to the USAR supplement summary description in LRA

Section A.2.3.2.11 to be appropriate for the replacement piping in the hot leg portions of the 

main coolant loops because the amendment describes the modifications that were made to the 

Safety Class 1 piping and identifies the appropriate design code of record for the hot leg piping 

that was replaced during the Spring 2014 OTSG refueling outage.
Time Limited Aging Analyses

4-24

4.3.2.3.4 Conclusion

There are no changes or updates to this section of the SER. Therefore, the previous conclusion 

for its evaluation of the metal fatigue TLAA for Class 1 piping remains valid as documented in

SER Section 4.3.2.3.4. Based on this review, the staff concludes that the applicant 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging related to fatigue of 

the Class 1 piping will be adequately managed for the period of extended operation. The staff 

also concludes that the USAR supplement contains appropriate summary descriptions of the 

TLAA, as required by 10 CFR 54.21(d).

4.7 Other Plant-Specific Time-Limited Aging Analyses

4.7.5 Inservice Inspection—Fracture Mechanics Analyses

4.7.5.2 Once-Through Steam Generator 1-2 Flaw Evaluations

4.7.5.2.1 Summary of Technical Information in the Application

LRA Section 4.7.5.2 describes the applicant’s TLAA for the OTSG 1-2 flaw evaluations. In the 

LRA, the applicant concluded that the effects of fatigue on the OTSG 1-2 flaws will be 

appropriately managed during the period of extended operation by the Fatigue Monitoring 

Program (LRA Section B.2.16), in accordance with 10 CFR 54.21(c)(1)(iii).

By letter dated June 23, 2014, the applicant provided an LRA update and deleted 

Section 4.7.5.2, “Once-Through Steam Generator 1-2 Flaw Evaluations,” from the LRA. The 

applicant stated that, based on the installation of the replacement SGs, LRA Section 4.7.5.2 as 

previously revised by FENOC in the letter dated June 3, 2011 (ADAMS Accession 

No. ML11159A132), is no longer applicable to the CLB for Davis-Besse. This section 4.7.5.2 

replaces the previous section 4.7.5.2 of the SER.

4.7.5.2.2 Staff Evaluation

The staff initially reviewed LRA Section 4.7.5.2 on the OTSG 1-2 flaw evaluation to verify, 

pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the OTSG 1-2 flaws will be 

adequately managed for the period of extended operation. However, the staff noted that, on 

June 23, 2014, the applicant provided an LRA update and deleted Section 4.7.5.2 from the LRA. 

The applicant stated that, based on the installation of the replacement SGs, LRA

Section 4.7.5.2, as previously revised by FENOC in the letter dated June 3, 2011 (ADAMS 

Accession No. ML11159A132), is no longer applicable to the CLB for Davis-Besse.

The staff noted that during the Spring 2014 refueling outage, the applicant replaced the OTSGs 

at Davis-Besse. The staff noted that the replacement OTSGs do not contain the flaws that were 

detected in the previous OTSGs. Therefore, the staff determined that the previous flaw 

evaluation TLAA for the original OTSG design does not conform to Criterion 6 in 10 CFR 54.3(a) 

because the analysis is no longer contained or incorporated by reference in the updated CLB for 

the replacement OTSGs. Therefore, based on this review, the staff finds that the applicant has 

provided an acceptable basis for deleting the flaw evaluation TLAA for the OTSGs from the 

scope of LRA Table 4.1-1 and LRA Section 4.7.5.2 because the staff has verified the following:

(a) The analysis does not conform to Criterion 6 in 10 CFR 54.3(a).
Aging Management Review Results

4-25

(b) The analysis does not meet the definition of a TLAA, as defined in 10 CFR 54.3(a), for 

the updated CLB that applies to the replacement OTSGs.

4.7.5.2.3 USAR Supplement

As revised in LRA Amendment 8 by letter dated June 3, 2011, LRA Section A.2.6.2 provides the 

USAR supplement summary description for the TLAA of the OTSG 1-2 flaw evaluations. LRA 

Amendment 8 revised the disposition for the analysis of the OTSG 1-2 flaws in LRA

Section A.2.6.2 from 10 CFR 54.21(c)(1)(iii) to 10 CFR 54.21(c)(1)(i), consistent with the revised 

disposition identified in LRA Amendment 8, Section 4.7.5.2. The staff initially reviewed the 

applicant’s amended USAR supplement summary description for this TLAA and determined that 

it is consistent with the TLAA discussed in LRA Section 4.7.5.2, as amended. On 

June 23, 2014, the applicant provided an LRA update and deleted USAR Supplement A.2.6.2 

from the LRA. The applicant stated that, as a result of OTSG replacement activities that were 

implemented in the Spring 2014 refueling outage, LRA Section A.2.6.2, “OTSG 1-2 Flaw

Evaluations,” previously revised by FENOC letter dated June 3, 2011 (ADAMS Accession 

No. ML11159A132), is no longer applicable to the CLB for the replacement OTSGs at the plant. 

The applicant deleted LRA Section A.2.6.2 from the scope of the LRA. The staff finds this 

change acceptable because the previous flaw evaluation for the original OTSGs is not 

applicable to the updated CLB for the replacement OTSGs at the plant.

Therefore, based on the OTSG replacements, the staff finds that the USAR supplement no 

longer needs to include a USAR supplement summary description for the flaw evaluation that 

was performed for the original OTSGs at the plant because the staff has verified that the flaw 

evaluation is not applicable to the updated CLB for the replacement OTSGs.

4.7.5.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration that the CLB no longer contains any referenced flaw evaluation for the OTSGs 

that conforms to the definition of a TLAA in 10 CFR 54.3(a).

5-1

SECTION 5

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) reviewed the license renewal application (LRA) for Davis-Besse Nuclear 

Power Station (Davis-Besse). On November 4, 2015, FirstEnergy Nuclear Operating 

Company, and the staff of the United States (U.S.) Nuclear Regulatory Commission (NRC) (the 

staff) met with the full ACRS committee to discuss issues associated with the review of the LRA. 

On November 12, 2015, the full committee issued its report discussing the results of the review. 

Copies of the ACRS letter and the staff’s response are provided on the following pages of this 

SER section.
5-2
5-3
5-4
5-5
5-6
5-7
5-8
5-9
5-10
5-11
5-12
5-13
5-14
6-1

SECTION 6

CONCLUSION

The staff concludes that the additional information provided by FirstEnergy Nuclear Operating 

Company does not alter the conclusion proffered in the safety evaluation report issued in 

September 2013 and that the requirements of 10 CFR 54.29(a) have been met.

A-1

APPENDIX A

DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL 

COMMITMENTS

During the review of the Davis-Besse Nuclear Power Station (Davis-Besse) license renewal

application by the staff of the U.S. Nuclear Regulatory Commission (NRC), FirstEnergy Nuclear 

Operating Company (FENOC) made commitments related to aging management programs 

(AMPs) to manage aging effects for structures and components.

The following table contains the final complete list of these commitments, along with the 

implementation schedules and sources for each commitment.
A-2

Davis Besse Nuclear Power Station, Unit No. 1

License Renewal Future Commitments

(Through LRA Amendment 59)

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

1. Enhance the Aboveground Steel Tanks Inspection Program to:

• Include a volumetric examination of tank bottoms to 

detect evidence of loss of material due to crevice, 

general, or pitting corrosion, or to confirm a lack thereof. 

Establish the examination technique, the inspection 

locations, and the acceptance criteria for the 

examination of the tank bottoms. Require that 

unacceptable inspection results be entered into the 

FENOC Corrective Action Program. The volumetric 

examination of the tank bottoms will be performed within 

5 years after entering the period of extended operation. 

Additional opportunistic tank bottom inspections will be 

performed whenever the tanks are drained.

• Include tank inspections conducted in accordance with 

Table 4a, “Tank Inspection Recommendations,” of 

License Renewal Interim Staff Guidance 

LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage 

Tanks, and Corrosion Under Insulation.”

• Include an inspection of the borated water storage tank 

(BWST) exterior surface prior to the period of extended 

operation for loss of material and cracking. Sufficient 

insulation will be removed to determine the condition of 

the exterior surface of the tank. At a minimum, either 25 

1-square-foot sections or 20 percent of the surface area 

of insulation will be removed to permit inspection of the 

exterior surface of the tank. The sample inspection 

points will be distributed in such a way that inspections 

will be performed near the tank bottom, at points where 

structural supports, pipe, or instrument nozzles 

penetrate the insulation and where water could collect,

such as on top of stiffening rings. In addition, inspection 

A.1.2

B.2.2

Responses to NRC RAIs

B.2.2-1 from NRC Letter 

dated

April 20, 2011;

RAI A.1-1 from

NRC Letter

dated

March 26, 2013;

NRC LR-ISG-2012-02,

and

NRC RAI

3.0.3.4.3-02

from NRC Letter

dated

July 7, 2014

Prior to

October 22, 2016
A-3

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

locations will be based on the likelihood of corrosion 

under insulation occurring. As an alternative to removing 

the insulation, subsequent inspections may consist of an 

examination of the exterior surface of the insulation for 

indications of damage to the protective outer layer of the 

insulation when the results of the initial inspection meet 

the following criteria:

1. no loss of material due to general, pitting, or crevice 

corrosion, beyond that which could have been present 

during initial construction, is observed, and

2. no evidence of stress corrosion cracking (SCC) is 

observed.

The subsequent inspections will be performed during each 

10-year period of the period of extended operation. If these 

subsequent inspections reveal damage to the exterior surface 

of the insulation, or there is evidence of water intrusion 

through the insulation, periodic inspections under the 

insulation will continue as conducted for the initial inspection 

and will be performed during each 10-year period of the period 

of extended operation.

2. Implement the Boral® Monitoring Program as described in 

LRA Section B.2.5.

A.1.5

B.2.5

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

3. Enhance the Buried Piping and Tanks Inspection Program to:

• Add (1) bolting for buried Fire Protection System piping 

and (2) the emergency diesel fuel oil storage tanks

(DB-T153-1, DB-T153-2) to the scope of the program.

• Conduct annual ground potential surveys of the cathodic 

protection system. Monitor cathodic protection voltage 

A.1.7

B.2.7

Responses to NRC RAIs

B.2.7-1 from NRC Letter 

Prior to

October 22, 2016
A-4

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

and current monthly to determine the effectiveness of 

cathodic protection systems and, thereby, the 

effectiveness of corrosion mitigation. Trend voltage, 

current, and ground potential readings and evaluate for 

adverse changes.

• Require that the activity of the jockey fire pump or 

equivalent parameter be monitored on at least a monthly 

interval. Conduct a flow test by the end of the next 

refueling outage when unexplained changes in jockey 

pump activity are observed.

• Require that the directed buried pipe inspection 

locations be selected based on risk.

• Require that the minimum number of buried in-scope 

piping inspections during the 30-40, 40-50, and 

50-60-year operating period is one steel piping segment. 

Perform the directed buried steel pipe inspections each 

10-year interval, based upon Table 4a, “Inspections of 

Buried Pipe,” in the XI.M41 aging management program 

described in LR-ISG-2011-03. Each inspection will have 

a minimum of 10 feet of piping inspected.

• Require that, IF the cathodic protection system for the 

emergency diesel generator (EDG) fuel oil storage tanks 

(DB-T153-1 and DB-T153-2) meets the availability 

criteria of Table 4c, “Inspections of Buried Tanks for all 

Inspection Periods” (i.e., footnotes 3.i, 3.ii and 3.iii) of 

LR-ISG-2011-03, Appendix A, “Revised GALL Report 

AMP XI.M41,” THEN no Table 4c inspections of tanks 

DB-T153-1 and DB-T153-2 are required. Otherwise, 

perform inspections of tanks DB-T153-1 and 

DB-T153-2, in accordance with Table 4c of 

LR-ISG-2011-03.

• Require that ultrasonic testing (UT) thickness 

measurements of the manways and vents for EDG fuel 

oil storage tanks T153-1 and T153-2 will be performed 

prior to entering the period of extended operation and 

every 10 years during the period of extended operation 

dated

April 20, 2011;

A.1-1 from

NRC Letter

dated

March 26, 2013;

and

2011-03-1 and 2011-03-2 

from

NRC Letter dated

February 11, 2014
A-5

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

to ensure that the metal thickness in those areas 

remains satisfactory.

• Require that underground piping in the decay heat 

removal and low pressure injection system located in 

the borated water piping trench will be visually inspected 

during the 30-40, 40-50, and 50-60-year operating 

periods to confirm the absence of aging effects.

• Require that, if adverse indications are detected, the 

inspection sample sizes, within the affected piping 

categories, are initially doubled and if adverse 

conditions are discovered in the expanded sample, the 

size of the follow-on inspections is determined by 

establishing the extent of condition and extent of cause, 

consistent with the FENOC Corrective Action Program. 

Scheduling of additional examinations is based on the 

severity of the degradation identified and commensurate 

with the consequences of a leak or loss of function, but 

in all cases, the expanded sample inspection should be 

completed within the 10-year interval in which the 

original adverse indication was identified. Further 

inspections are conducted in locations with similar 

materials and environment, or the piping is replaced on 

a schedule based upon either the station’s need to 

return the system to service for non-Technical 

Specification-related systems or the allowed outage time 

for Technical Specification-related systems.

• Require that an inspection of buried fire protection 

system bolting will be performed, when the bolting 

becomes accessible during opportunistic or focused 

inspections.

• Require that the inspections of buried piping be 

conducted using visual (VT-3 or equivalent) inspection 

methods. Excavation shall be a minimum of 10 linear 

feet of piping, with all surfaces of the pipe exposed.

• Include the following acceptance criteria in the program 

procedure:
A-6

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

o The cathodic protection survey acceptance criteria for 

protected piping and tanks, with the exception of the 

manways and vents at the top of the mound over EDG

fuel oil storage tanks T153-1 and T153-2, are the -850 

mV relative to a copper/copper sulfate reference 

electrode (CSE), instant off and limiting critical potential 

not more negative than 1200 mV. For the manways 

and vents at the top of the mound over tanks T153-1 

and T153-2, the acceptance criterion is the 100 mV 

minimum polarization testing criteria listed in National 

Association of Corrosion Engineers (NACE)

SP0169 2007;

o For coated piping or tanks, there should be either no 

evidence of coating degradation or the type and extent 

of coating degradation should be insignificant as 

evaluated by an individual possessing a NACE Coating 

Inspector Program Level 2 or 3 inspector qualification 

or an individual has attended the Electric Power 

Research Institute (EPRI) Comprehensive Coatings 

Course and completed the EPRI Buried Pipe Condition 

Assessment and Repair Training Computer-Based 

Training Course. Where damage to the coating has 

been evaluated as significant and the damage was 

caused by nonconforming backfill, an extent-ofcondition evaluation should be conducted to ensure 

that the as-left condition of backfill in the vicinity of 

observed damage will not lead to further degradation;

o If metallic piping or tanks show evidence of corrosion, 

the remaining wall thickness in the affected area is 

determined to ensure that the minimum wall thickness 

is maintained; and,

o Changes in jockey pump activity or equivalent 

parameter that cannot be attributed to causes other 

than leakage from buried piping are not occurring.
A-7

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

4. Implement the Collection, Drainage, and Treatment 

Components Inspection Program as described in LRA

Section B.2.9.

A.1.9

B.2.9

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

5. Implement the Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements

Inspection as described in LRA Section B.2.11.

Enhance the Electrical Cable Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements

Inspection to:

Include high-voltage connections to confirm the absence of 

aging effects for metallic electrical connections.

A.1.11

B.2.11

Responses to NRC RAIs

3.6-3 from

NRC Letter

dated

April 5, 2011,

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

6. Implement the Electrical Cables and Connections Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements 

Program as described in LRA Section B.2.12.

A.1.12

B.2.12

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-8

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

7. Implement the Electrical Cables and Connections Not Subject 

to 10 CFR 50.49 Environmental Qualification Requirements 

Used in Instrumentation Circuits Program as described in LRA

Section B.2.13.

A.1.13

B.2.13

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

8. Enhance the External Surfaces Monitoring Program to:

• Add to the scope of the program systems that credit the 

program for license renewal but do not have 

Maintenance Rule intended functions.

• Perform opportunistic inspections of surfaces that are 

inaccessible or not readily visible during normal plant 

operations or refueling outages, such as surfaces that 

are insulated. Surfaces that are accessible will be 

inspected at a frequency not to exceed one refueling 

cycle.

• Perform, in conjunction with the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Program, 

inspection and surveillance of elastomers and polymers 

exposed to air-indoor uncontrolled or air-outdoor 

environments, but not replaced on a set frequency or 

interval (i.e., are long-lived), for evidence of cracking 

and change in material properties (hardening and loss of 

strength) and loss of material due to wear. Specify 

acceptance criteria of no unacceptable visual indications 

of cracks or discoloration that would lead to loss of 

function prior to the next inspection, and of no hardening 

as evidenced by a loss of suppleness during 

manipulation.

• Perform inspection of the control room emergency 

ventilation system air-cooled condensing unit cooling 

coil tubes and fins and the station blackout diesel 

generator radiator tubes and fins for visible evidence of 

A.1.15

B.2.15

Responses to NRC RAIs

3.3.2.2.5-1 and B.2.2-2 from 

NRC Letter

dated

April 20, 2011;

RAI 3.3.2-2 from NRC Letter 

dated

May 2, 2011;

RAI 3.3.2.2.5-2 from

NRC Letter dated

July 12, 2011;

Supplemental RAI OIN-352 

from

NRC Region III IP-71002 

Inspection;

RAI A.1-1 from

NRC Letter

dated

March 26, 2013;

and

NRC LR-ISG2012-02

Prior to

October 22, 2016
A-9

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

external surface conditions that could result in a 

reduction in heat transfer. Specify acceptance criteria of 

no unacceptable visual indications of fouling (build up of 

dirt or other foreign material) that would lead to loss of 

function prior to the next scheduled inspection.

• Manage cracking of copper alloys with greater than 

15-percent zinc and stainless steel components 

exposed to an outdoor air environment through plant 

system inspections and walkdowns for evidence of 

leakage. Specify acceptance criteria of no unacceptable 

visual indications of cracks that would lead to loss of 

function prior to the next scheduled inspection.

• Include inspection parameters and acceptance criteria 

for polymers, elastomers and metallic components as 

applicable in system inspection and walkdown 

documentation. Retain system inspection and walkdown 

documentation in plant records.

• Inspect or remove portions of insulation from outdoor 

insulated components, and indoor insulated components 

exposed to condensation (because the in-scope 

component is operated below the dew point), to 

determine whether the exterior surface of the 

component is degrading or has the potential to degrade. 

Inspect a minimum of 20 percent of the in-scope piping

length, or 20 percent of the surface area for components 

whose configuration does not conform to a 1-foot axial 

length determination (e.g., valve, accumulator), after the 

insulation is removed. Alternatively, any combination of 

a minimum of 25 1-foot axial length sections and 

components for each material type is inspected. 

Inspection locations should focus on the bounding or 

lead components most susceptible to aging because of 

time in service, severity of operating conditions 

(e.g., amount of time that condensate would be present 

on the external surfaces of the component), and lowest 

design margin. The inspections will be conducted during 
A-10

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

each 10-year period of the period of extended operation. 

The following are alternatives to removing insulation:

a. Subsequent inspections may consist of an 

examination of the exterior surface of the insulation 

with sufficient acuity to detect indications of damage 

to the jacketing or protective outer layer of the 

insulation when the results of the initial inspection 

meet the following criteria:

i. No loss of material due to general, pitting, or 

crevice corrosion, beyond that which could have 

been present during initial construction is 

observed, and

ii. No evidence of SCC is observed.

If the external visual inspections of the insulation 

reveal damage to the exterior surface of the insulation 

or jacketing, or there is evidence of water intrusion 

through the insulation (e.g., water seepage through 

insulation seams/joints), periodic inspections under the 

insulation should continue as conducted for the initial 

inspection.

b. 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 corrosion 

under insulation (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 piping that has tightly 

adhering insulation is visually inspected for damage to 

the moisture barrier with the same frequency as for 

other types of insulation inspections. These 

inspections are not credited towards the inspection 

quantities for other types of insulation.
A-11

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

9. Enhance the Fatigue Monitoring Program to:

• Provide for updates of the fatigue usage calculations on 

an as-needed basis if an allowable cycle limit is 

approached. When the number of accrued cycles is 

within 75% of the allowable cycle limit for any transient, 

a condition report will be generated. For any transient 

whose cycles are projected to exceed the allowable 

cycle limit by the end of the next plant operating cycle 

(Davis-Besse operating cycles are normally 2 years in 

duration), the program will require an update of the 

fatigue usage calculation for the affected component(s).

• Establish an acceptance criterion for maintaining the 

cumulative fatigue usage below the Code design limit of 

1.0 through the period of extended operation, including 

environmental effects where applicable.

A.1.16

B.2.16

Responses to NRC RAIs

B.2.16-3, B.2.16-4

and

B.2.16-5

from

NRC Letter

dated

April 20, 2011

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

10. Enhance the Fire Water Program to:

• Include inspections and testing conducted in 

accordance with Appendix D, Table 4a, “Fire Water 

System Inspection and Testing Recommendations,” of 

LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage 

Tanks, and Corrosion Under Insulation.”

• Include augmented testing and inspections beyond 

those of Table 4a for portions of water-based fire 

protection system components that are (a) normally dry 

but periodically subjected to flow (e.g., dry-pipe or 

pre-action sprinkler system components) and (b) cannot 

be drained or allow water to collect:

1. In each 5-year interval, beginning 5 years prior to the 

period of extended operation, a flow test or flush 

sufficient to detect potential flow blockage will be 

conducted, or a visual inspection of 100 percent of the 

internal surface of piping segments will be conducted.

2. In each 5-year interval of the period of extended 

operation, 20 percent of the length of piping segments 

A.1.18

B.2.18

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013;

NRC LR-ISG2012-02;

and

NRC RAI

B.2.18-2 from

NRC Letter

dated

July 7, 2014

Prior to

October 22, 2016
A-12

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

that cannot be drained or piping segments that allow 

water to collect will be subject to volumetric wall 

thickness inspections. Measurement points are 

obtained to the extent that each potential degraded 

condition can be identified (e.g., general corrosion, 

microbiologically-influenced corrosion (MIC)). The 

20 percent of piping that is inspected in each 5-year 

interval will be in different locations than previously 

inspected piping.

If the results of a 100-percent internal visual inspection 

are acceptable, and the segment is not subsequently 

wetted, no further augmented tests or inspections are 

necessary.

• Perform representative sprinkler head sampling 

(laboratory field service testing) or replacement prior to 

50 years inservice (installed), and at 10-year intervals 

thereafter, in accordance with the 2011 Edition of 

National Fire Protection Association (NFPA) 25, or until 

there are no untested sprinkler heads that will see 

50 years of service through the end of the period of 

extended operation.

• Include a requirement that, when visual inspections are 

used to detect loss of material, the inspection technique 

is capable of detecting surface irregularities that could 

indicate wall loss to below nominal pipe wall thickness 

due to corrosion and corrosion product deposition. 

Where such irregularities are detected, followup 

volumetric wall thickness examinations are performed.

• Include a requirement 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 its source is determined and 

corrected.
A-13

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

11. Implement the Inaccessible Power Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements 

Program as described in LRA Section B.2.21.

Enhance the Inaccessible Power Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements 

Program to:

• Include inaccessible underground lower service voltage 

cables (400VAC to 2kV).

• Not use ‘significant voltage’ (defined as being subjected 

to system voltage for more than 25 percent of the time) 

as a criterion for inclusion into the program.

• Include inspection of electrical manholes that contain 

power cables within the scope of the program.

• Inspect electrical manholes at least once per year. The 

frequency of inspections for accumulated water will be 

established and adjusted based on plant-specific 

inspection results. Also, manhole inspections will be 

performed in response to event-driven occurrences 

(e.g., heavy rain or flooding).

• Include a requirement in preventive maintenance (PM)

activities PM 4297, PM 4294, PM 8025, and PM 4296 to 

generate a condition report in cases where in-scope 

inaccessible non-environmental qualification (EQ) power 

cable manhole inspection identifies submerged cables. 

Although the Inaccessible Power Cables Not Subject to 

10 CFR 50.49 Environmental Qualification 

Requirements Program is a new program, preventive 

maintenance activities exist for inspection of water 

accumulation in the manholes associated with the inscope inaccessible non-EQ power cables.

• Perform cable testing on a frequency of at least every 

6 years. Testing will be evaluated for more frequent 

performance based on test results and operating 

experience.

A.1.21

B.2.21

Responses to NRC RAIs 

B.2.21-1 and B.2.21-3 from 

NRC Letter

dated

April 5, 2011,

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-14

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

12. Enhance the Masonry Wall Inspection Program to:

• Include and list the structures within the scope of license 

renewal that credit the program for aging management.

• Add an action to follow the documentation requirement 

of 10 CFR 54.37, including submittal of records of 

structural evaluations to records management.

• Specify that, for each masonry wall, the extent of 

observed masonry cracking or degradation of steel edge 

supports or bracing is evaluated to ensure that the 

current evaluation basis is still valid. Corrective action is 

required if the extent of masonry cracking or steel 

degradation is sufficient to invalidate the evaluation 

basis. An option is to develop a new evaluation basis 

that accounts for the degraded condition of the wall 

(i.e., acceptance by further evaluation).

• Specify that, for the masonry walls within the scope of 

license renewal, inspections will be conducted at least 

once every 5 years, with provisions for more frequent 

inspections in areas where significant loss of material or 

cracking is observed, to ensure there is no loss of 

intended function between inspections.

A.1.27

B.2.27

Responses to NRC RAIs 

B.2.39-5 from NRC Letter 

dated

April 5, 2011,

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-15

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

13. Implement the One-Time Inspection as described in LRA

Section B.2.30.

A.1.30

B.2.30

Responses to NRC RAIs

3.3.2.2.4.3-1 from

NRC Letter

dated

May 2, 2011;

Supplemental Question –

Makeup Pump Casing 

Inspections,

A.1-1 from

NRC Letter dated

March 26, 2013;

and

2014 Annual Update

Prior to

October 22, 2016

14. Implement the PWR Reactor Vessel Internals Program as 

described in LRA Section B.2.32.

A.1.32

B.2.32

Response to

NRC RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

15. In association with the PWR Reactor Vessel Internals 

Program, a plant-specific inspection plan for ensuring the 

implementation of Materials Reliability Program (MRP)-227 

guidelines, as amended by the safety evaluation for MRP-227, 

and Davis-Besse’s responses to the plant-specific action 

items, as identified in Section 4.2 of the safety evaluation for 

MRP-227, will be submitted for NRC review and approval.

* NOTE: The inspection plan will be submitted no later than 

2 years after issuance of the renewed operating license or 

2 years prior to the beginning of the period of extended 

operation (April 22, 2015), whichever is earlier.

A.1.32

B.2.32

Response to NRC RAI

B.2.32-1 from

NRC Letter

dated

July 11, 2011

Complete 
A-16

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

16. Enhance the Reactor Head Closure Studs Program as follows:

• Select an alternative stable lubricant that is compatible 

with the fastener material and the environment. A 

specific precaution against the use of compounds 

containing sulfur (sulfide), including molybdenum 

disulfide (MoS2), as a lubricant for the reactor head 

closure stud assemblies will be included in the program.

• Preclude the future use of replacement closure stud 

bolting fabricated from material with actual measured 

yield strength greater than or equal to 150 kilo-pounds 

per square inch (ksi), except for use of the existing 

spare reactor head closure stud bolting.

A.1.34

B.2.34

Responses to NRC RAIs 

B.2.34-1 from NRC Letter 

dated

June 20, 2011,

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

17. Enhance the Reactor Vessel Surveillance Program as follows:

• The Capsule Insertion and Withdrawal Schedule for 

Davis-Besse will be revised to schedule testing of the 

TE1-C capsule.

A.1.35

B.2.35

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

18. Implement the Selective Leaching Inspection as described in 

LRA Section B.2.36.

A.1.36

B.2.36

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-17

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

19. Implement the Small Bore Class 1 Piping Inspection as 

described in LRA Section B.2.37.

A.1.37

B.2.37

Responses to NRC RAIs 

B.2.37-2 from NRC Letter 

dated

April 20, 2011,

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Completed within the 

six year period prior 

to

October 22, 2016

20. Enhance the Structures Monitoring Program to:

• Include and list the structures within the scope of license 

renewal that credit the program for aging management.

• Include aging effect terminology (e.g., loss of material, 

cracking, change in material properties, and loss of 

form).

• List American Concrete Institute (ACI) 349.3R, 

“Evaluation of Existing Nuclear Safety-Related Concrete 

Structures,” and American National Standards 

Institute/American Society of Civil Engineers 

(ANSI/ASCE) 11-90 as references and indicate that they 

provide guidance for the selection of parameters 

monitored or inspected.

• Clarify that a “structural component” for inspection 

includes each of the component types identified within 

the scope of license renewal as requiring aging 

management.

• Require the responsible engineer to review site raw 

water pH, chlorides, and sulfates test results prior to the 

inspection to take into account the raw water chemistry 

for any unusual trends during the period of extended 

operation. Raw water chemistry data shall be collected 

at least once every 5 years. Data collection dates shall 

A.1.39

B.2.39

Responses to NRC RAIs 

B.2.39-4, B.2.39-5, B.2.39-6

and B.2.39-7 from NRC 

Letter dated April 5, 2011; 

RAIs B.2.39-11 and 

3.5.2.3.12-4 from NRC Letter 

dated July 21, 2011;

Supplemental RAI B.2.39-11 

from telecon held with the 

NRC on September 13, 2011;

Supplemental RAI OIN-380 

from Region III IP-71002 

Inspection; RAI B.2.4-1a from

NRC Letter dated

November 14, 2012;

RAI B.2.43-3a from NRC 

Letter

dated January 4, 2013;

Prior to

October 22, 2016
A-18

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

be staggered from year to year 

(summer-winter-summer) to account for seasonal 

variation.

• Perform an inspection for loss of material for carbon 

steel structural components subject to aggressive 

groundwater. Require the use of the FENOC Corrective 

Action Program for identified concrete or steel 

degradation.

• Specify that, upon notification that a below-grade 

structural wall or other in-scope concrete or metal 

structural component will become accessible through 

excavation, a followup action is initiated to the 

responsible engineer to inspect the exposed surfaces 

for age-related degradation. Such inspections will 

include concrete examination using acceptance criteria 

from GALL Report AMP XI.S6, Program Element 6. 

Degradation found that exceeds the acceptance criteria 

will be trended and processed through the FENOC 

Corrective Action Program.

• List ACI 349.3R, ANSI/ASCE 11-90, and EPRI 

Report 1007933 as references and indicate that they 

provide guidance for detecting aging effects.

• Add an action to follow the documentation requirement 

of 10 CFR 54.37, including submittal of records of 

structural evaluations to records management.

• Add sufficient acceptance criteria and critical 

parameters to trigger an increased level of inspection 

and initiation of corrective action. Indicate that 

ACI 349.3R provides acceptable guidelines that will be 

considered in developing acceptance criteria for 

concrete structural elements, steel liners, joints, and 

waterproofing membranes. The acceptance criteria for 

visual inspection of coatings on in-scope concrete 

structures will be in accordance with ACI 349.3R. Plantspecific quantitative degradation limits, similar to the 

three-tier hierarchy acceptance criteria from Chapter 5 

and RAI A.1-1 from NRC 

Letter dated March 26, 2013
A-19

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

of ACI 349.3R, will be developed and added to the 

inspection procedure. The Structures Monitoring 

Program procedure will also be enhanced to reflect the 

“Periodic Evaluation” criteria defined in Chapter 3.3 of 

ACI 349.3R. The Structures Monitoring Program 

procedure will include the “prioritization process” to 

develop a representative sample of areas to inspect in 

accordance with ACI 349.3R.

• Require that personnel performing the structural 

inspections meet qualifications that are commensurate 

with ACI 349.3R, Chapter 7, “Qualifications of 

Evaluation Team.”

• The program procedure will be enhanced by specifying 

that, for the structures within the scope of license 

renewal, inspections will be conducted at least once 

every 5 years.

• Conduct a baseline inspection of the structures within 

the scope of license renewal prior to entering the period 

of extended operation.

• Require optical aids, scaling technologies, mechanical 

lifts, ladders or scaffolding for tall structures or difficultto-reach areas of structures, to allow visual inspections 

that meet the guidelines of Chapter 5 of ACI 349.3R. 

Select the areas to be inspected in accordance with the 

guidelines of Chapter 5 of ACI 349.3R to reflect the 

“Periodic Evaluation” criteria defined in Chapter 3.3 of 

ACI 349.3R. Include the “prioritization process” in the 

selection methodology to develop a representative 

sample of areas to inspect in accordance with 

ACI 349.3R.

• Monitor elastomeric vibration isolators and structural 

sealants for cracking, loss of material, and hardening.

• Supplement visual inspection of elastomeric vibration 

isolation elements by feel to detect hardening if the 

vibration isolation function is suspect.
A-20

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

• Identify that:

o loose bolts and nuts and cracked high-strength bolts

are not acceptable unless accepted by engineering 

evaluation

o structural sealants that are acceptable if the observed 

loss of material, cracking, and hardening will not result 

in loss of sealing

o elastomeric vibration isolation elements that are

acceptable if there is no loss of material, cracking, or 

hardening that could lead to the reduction or loss of 

isolation function.

• Require that high-strength (i.e., American Society for 

Testing and Materials (ASTM) A540 Grade B23) 

structural bolting materials with an actual measured 

yield strength greater than or equal to 150 ksi and 

greater than 1 inch in nominal diameter are monitored 

for SCC. Perform periodic visual inspections of 

susceptible ASTM A540 bolting to identify locations 

where ASTM A540 bolting may be exposed to a 

potentially corrosive environment for SCC. Complete the 

initial visual inspections prior to entering the period of 

extended operation, and perform recurring inspections 

at an interval not to exceed 5 years. Perform volumetric 

examination (i.e., ultrasonic testing (UT)) on a sampling 

basis of bolting exposed to a corrosive environment, as 

determined by engineering evaluation, to a depth of at 

least 12 inches.

• Require that personnel performing UT examinations of 

structural bolting have a current ASME Code Section XI, 

Appendix VIII, Supplement 8 endorsement.

• Revise the applicable structural bolting specifications to 

prevent future use of ASTM A540 bolting with measured 

yield strength equal to or exceeding 150 ksi.
A-21

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

21. Enhance the Water Control Structures Inspection to:

• Include the Service Water Discharge Structure that is 

within the scope of license renewal.

• Include parameters monitored and inspected for water 

control structures, including the Service Water 

Discharge Structure, in accordance with applicable 

inspection elements listed in Section C.2 of Regulatory 

Guide 1.127 Revision 1. Descriptions of concrete 

conditions will conform to the appendix to the publication 

ACI 201. The use of photographs for comparison of 

previous and present conditions will be included as part 

of the inspection program.

• Specify that water control structure periodic inspections 

are to be performed at least once every 5 years.

• Add an action to follow the documentation requirement 

of 10 CFR 54.37, including submittal of records of 

structural evaluations to records management.

• Add sufficient acceptance criteria and critical 

parameters to trigger an increased level of inspection 

and initiation of corrective action. Indicate that 

ACI 349.3R provides acceptable guidelines that will be 

considered in developing acceptance criteria for water 

control structures. Plant-specific quantitative 

degradation limits, similar to the three-tier hierarchy 

acceptance criteria from Chapter 5 of ACI 349.3R, will 

be developed and added to the inspection procedure. 

The Structures Monitoring Program procedure will also 

be enhanced to reflect the “Periodic Evaluation” criteria 

defined in Chapter 3.3 of ACI 349.3R. The Structures 

Monitoring Program procedure will include the 

“prioritization process” to develop a representative 

sample of areas to inspect in accordance with 

ACI 349.3R.

A.1.40

B.2.40

Responses to NRC RAIs 

B.2.39-6 from NRC Letter 

dated

April 5, 2011;

Supplemental RAI OIN-379 

from Region III IP-71002 

Inspection;

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-22

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

• Conduct a baseline inspection of the structures within 

the scope of license renewal prior to entering the period 

of extended operation.

• Require that loose bolts and nuts, cracked high-strength 

bolts, and degradation of piles and sheeting (sheet 

pilings) are accepted by engineering evaluation or 

subject to corrective actions. Engineering evaluation will 

be documented and based on codes, specifications, and 

standards such as American Institute of Steel 

Construction specifications, Structural Engineering 

Institute (SEI)/ASCE) 11, and codes, specifications, or 

standards referenced in the Davis-Besse current 

licensing basis.

22. Enclose or otherwise protect the safety-related station 

ventilation radiation monitors located in the Turbine Building 

such that leakage and spray from surrounding piping systems 

does not adversely affect the intended function of the radiation 

monitors.

Response to

NRC RAI

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

23. In association with the time-limited aging analysis for effects of 

environmentally assisted fatigue of the high-pressure injection 

(HPI) nozzle safe end including the associated Alloy 82/182 

weld (weld that connects the safe end to the nozzle), replace 

the HPI nozzle safe end, including the associated Alloy 82/182 

weld, for all four HPI nozzles prior to the period of extended 

operation. Apply the Fatigue Monitoring Program to evaluate 

the environmental effects and manage cumulative fatigue 

damage for the replacement HPI nozzle safe ends and 

associated welds.

A.2.3.4.2

A.2.7.4

Responses to NRC RAIs 

4.7.4 1 from NRC Letter 

dated

April 15, 2011;

RAI 4.3-18 from NRC Letter

dated

June 17, 2011;

RAI 4.7.4-1 from NRC Letter 

dated

October 11, 2011;

Prior to

October 22, 2016
A-23

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

RAI A.1-1 from

NRC Letter

dated

March 26, 2013;

24. Apply the elements of corrective actions, confirmation process, 

and administrative controls in the Quality Assurance Program 

Manual to the credited aging management programs and 

activities for safety-related and nonsafety-related structures 

and components determined to require aging management for 

the period of extended operation.

A.1

Response to NRC RAI 3.0 

from

NRC letter dated

May 2, 2011, and RAI A.1-1 

from NRC letter dated

March 26, 2013

Prior to

October 22, 2016

25. Not used.

26. Obtain and evaluate for degradation a concrete core bore from 

two representative inaccessible concrete components of an 

in-scope structure subjected to aggressive groundwater prior 

to entering the period of extended operation. Based on the 

results of the initial core bore sample, evaluate the need for 

collection and evaluation of representative concrete core bore 

samples at additional locations that may be identified during 

the period of extended operation as having aggressive 

groundwater infiltration. Select additional core bore sample 

locations based on the duration of observed aggressive 

groundwater infiltration. Document identified concrete or steel 

degradation in the FENOC Corrective Action Program.

Responses to NRC 

RAI B.2.39-3 from NRC 

Letter dated

April 5, 2011;

RAI B.2.39-11 from

NRC Letter dated

July 21, 2011;

and

Supplemental RAI B.2.39-11 

from telecon held with 

the NRC on

September 13, 2011

COMPLETE 
A-24

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

27. DBNPS Surveillance Test Procedure DB-PF-03009, 

Revision 06, “Containment Vessel and Shielding Building 

Visual Inspection,” Subsection 2.1.2, shall be enhanced to 

state, “Personnel who perform general visual examinations of 

the exterior surface of the Containment Vessel and the interior 

and exterior surfaces of the shield building shall meet the 

requirements for a general visual examiner in accordance with 

Nuclear Operating Procedure NOP-CC-5708, ‘Written Practice 

for the Qualification and Certification of Nondestructive 

Examination Personnel.’ These individuals shall be 

knowledgeable of the types of conditions which may be 

expected to be identified during the examinations.”

Responses to NRC RAIs

B.2.1-1 from NRC Letter 

dated

April 5, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

28. Enhance the Fuel Oil Chemistry Program to:

• Require that internal surfaces of EDG fuel oil storage 

tanks and day tanks, diesel oil storage tank, diesel fire 

pump day tank, and station blackout diesel generator 

day tank are periodically drained (at least once every 

10 years) for cleaning and are visually inspected to 

detect potential degradation. If degradation is identified 

in a diesel fuel tank by visual inspections, a volumetric 

inspection is performed.

• Require that biological activity be monitored and trended 

at least quarterly.

A.1.20

B.2.20

Responses to NRC RAIs 

B.2.20-1 and B.2.20-2 from 

NRC Letter dated

April 5, 2011;

Supplemental RAI OIN-368 

from

NRC Region III IP-71002 

Inspection;

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-25

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

29. Enhance the Cranes and Hoists Inspection Program to:

• Include visual inspections for loose bolts and missing or 

loose nuts in crane, monorail, and hoist inspection 

procedures at the same frequency as inspections of rails 

and structural components.

A.1.10

B.2.10

Responses to NRC RAI

B.2.10-2 from NRC Letter 

dated

April 20, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

30. Enhance the Leak Chase Monitoring Program to:

• Include acceptance criteria such that measurement of 

leakage from any monitoring line exceeding 15 ml/min 

will be documented in the Corrective Action Program for 

evaluation and potential corrective actions. Evaluation 

will include consideration of more frequent monitoring.

• Analyze collected leak chase drainage for pH monthly 

and for iron every 6 months. The initial acceptance 

criteria will be 7.0 to 8.0 for pH. The results for iron will 

be monitored and trended to ensure that there is no 

indication of corrosion of the reinforcing bars in the walls 

or floor of the pool and pits. An acceptance criterion for 

the iron analyses will be developed after 3 years of 

measurements. Analyses that exceed the limits will be 

documented in the Corrective Action Program.

• Perform the leak chase inspection and cleaning 

recurring PM activity every 18 months.

• Inspect once per year for leakage migrating through the 

accessible outside walls and floor (from the ceiling side) 

of the pool and pits. Document the inspection results 

and retain in plant records. Indication of leakage through 

the walls will be documented in the Corrective Action 

Program.

A.1.25

B.2.25

Responses to NRC RAI

B.2.25-5 from NRC Letter 

dated

April 5, 2011;

RAIs B.2.25-7 and B.2.39-10 

from

NRC Letter

dated

July 21, 2011;

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-26

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

31. Incorporate reference to and the preventative actions of the 

Research Council for Structural Connections “Specification for 

Structural Joints Using ASTM A325 or A490 Bolts” into the 

Davis-Besse specifications and implementing procedures that 

address Davis-Besse structural bolting within the scope of 

license renewal.

Responses to NRC RAIs 

B.2.39-8 from NRC Letter 

dated

April 5, 2011,

and

A.1-1 from NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

32. Enhance the Closed Cooling Water Chemistry program to:

• Document the results of periodic inspections of 

opportunity, performed when components are opened 

for maintenance, repair, or surveillance.

• Ensure that a representative sample of piping and 

components will be inspected on a 10-year interval, with 

the first inspection taking place prior to entering the 

period of extended operation.

• Ensure that component cooling water radiochemistry is 

sampled on a weekly interval to verify the integrity of the 

letdown coolers and seal return coolers.

A.1.8

B.2.8

Responses to NRC RAI

B.2.8-1 from NRC Letter 

dated

April 20, 2011;

Supplemental RAI 2.3.3.18-4 

from telecon

held with the NRC on

November 9, 2011;

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

33. Refueling Canal Leakage Mitigation

Phase 1

Perform the following actions to reduce or mitigate the 

refueling canal leaks inside containment:

1. Select and implement a leak detection method to 

locate the leakage area.

2. Evaluate temporary and permanent repair methods to 

stop or significantly reduce the leakage, and 

implement a repair plan.

Responses to NRC RAIs

B.2.39-9 from

NRC Letter dated

July 27, 2011;

RAI A.1-1 from

NRC Letter

dated

March 26, 2013;

and

2014 Annual Update

Phase 1:

Action 1 

COMPLETE

Action 2 

COMPLETE
A-27

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

Phase 2

Perform the following actions to evaluate the impact of 

refueling canal leaks on concrete and reinforcing steel 

structures. Discontinue core bores, testing, and reinforcing 

steel inspections when indications of refueling canal leakage 

are no longer present:

1. Perform a core bore in the south wall of the east-west 

section of the core flood pipe tunnel.

a. Assess borated water degradation of the 

concrete by testing the core bore sample for 

compressive strength and by petrographic 

examination, and evaluate the results.

a. Conduct a visual examination of the concrete and 

reinforcing steel to identify aging effects 

(e.g., concrete degradation or steel corrosion). 

Enter identified aging effects into the FENOC 

Corrective Action Program and evaluate in 

accordance with the requirements of the current 

licensing basis Maintenance Rule Program.

2. If leakage from the refueling canal has not been 

eliminated or resumes by the beginning of the period 

of extended operation, then evaluate the concrete 

structures in a manner similar to the way that they 

were evaluated under Phase 2, Action 1. However, 

use acceptance criteria from ACI Report 349.3R for 

the evaluation.

3. If leakage from the refueling canal has not been 

eliminated or resumes during the period of extended 

operation, then evaluate the concrete structures again 

in a manner similar to the way that they were 

evaluated under Phase 2, Action 2. Perform 

evaluations every 10 years until the end of the period 

of extended operation.

Phase 2:

Action 1 

COMPLETE

Action 2 prior to 

December 31, 2023

Action 3 – Ongoing
A-28

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

34. Enhance the Bolting Integrity Program to:

• Select an alternative stable lubricant that is compatible 

with the fastener material and the environment. A 

specific precaution against the use of compounds 

containing sulfur (sulfide), including molybdenum 

disulfide (MoS2), as a lubricant will be included in the 

program.

A.1.4

B.2.4

Responses to NRC RAIs

B.2.4-3 from NRC Letter 

dated

April 20, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

35. Perform the following actions for each of two examinations 

(Phase 1 and Phase 2) of the Containment Vessel in the sand 

pocket region:

• Perform nondestructive examination of the Containment

Vessel from the outer surface at five areas of 

previously-identified groundwater in-leakage.

o Examine the vessel at a minimum of three vertical grid 

locations at 12 inches nominal horizontal spacing at 

each area. Examine the Containment Vessel at a 

minimum of three elevations:

a. approximately 3 inches below the existing 

grout-to-vessel interface in the sand pocket region

b. at the existing grout-to-vessel interface level in the 

sand pocket region

c. approximately 3 inches above the existing 

grout-to-vessel interface in the sand pocket region

• Compare the UT thickness readings to minimum ASME 

Code vessel thickness requirements and to the results 

obtained during previous UT examinations of the 

Containment Vessel. Determine the need for 

maintenance or repair of the Containment Vessel based 

on the results and evaluation of the examinations.

Response to NRC 

RAI B.2.22-5 from 

NRC Letter

dated

July 21, 2011,

and

2014 Annual Update

Phase 1 

COMPLETE

and

Phase 2 prior to 

December 31, 2025
A-29

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

• Document the results of each of the two examinations in 

the work order system. Document and evaluate adverse 

conditions in accordance with the FENOC Corrective 

Action Program for an evaluation of potential 

degradation of the steel Containment Vessel thickness 

over the longer term.

36. Perform the following actions related to the Containment 

Vessel sand pocket region each refueling outage:

• Perform visual inspection of 100 percent of the 

accessible areas of the wetted outer surface of the 

Containment Vessel in the sand pocket region.

• Perform visual inspection of accessible dry areas of the 

outer surface of the Containment Vessel in the sand 

pocket region and the areas above the grout-to-steel 

interface up to Elevation 566 feet + 3 inches, - 1 inch.

• Perform visual inspection for deterioration (e.g., missing 

or damaged grout) of accessible grout and the 

containment exterior moisture barrier in the sand pocket 

area.

• Perform opportunistic visual inspections of inaccessible 

areas of the Containment Vessel in the sand pocket 

region when such areas are made accessible.

• Perform opportunistic visual inspections for deterioration 

(e.g., missing or damaged grout) of inaccessible grout in 

the sand pocket region when such areas are made 

accessible. Inaccessible grout is the grout below the 

normally exposed surface of the grout in the sand 

pocket area.

• Address issues of pitting or MIC, and degraded grout, 

moisture barrier or sealant identified during the 

inspections using the FENOC Corrective Action 

Program.

• Sample the water in the sand pocket region when 

sufficient volumes are available. The number of sampled 

Responses to NRC RAI

B.2.22-5 from NRC Letter

dated

July 21, 2011,

and

Supplemental RAI B.2.22-5 

from telecons

held with the NRC on

October 5 and 

November 14, 2011

Ongoing 
A-30

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

water volumes will be determined by the number of 

water volumes observed and the size of those water 

volumes. Analyze the sample(s) for pH, chlorides, iron,

and sulfates. Treat or wash (or a combination thereof) 

the sand pocket area to reduce measured chloride 

concentrations to less than 250 parts per million (ppm) if 

the concentration of chlorides in a sample exceeds 

250 ppm.

Note: Water samples may be taken at different times 

during each outage. Engineering judgment may be used 

to determine the priority of the chemical analyses to be 

performed if sufficient water is not available in a given 

sample for all analyses.

37. Perform and evaluate core bores of the emergency core 

cooling system Pump Room No. 1 wall and the Room 109 

ceiling.

• The core bores will be deep enough to expose 

reinforcing bar in the wall and ceiling. The core samples 

from the core bores will be examined for signs of 

corrosion or chemical effects of boric acid on the 

concrete or reinforcing bars. The examination will 

include a petrographic examination. The reinforcing 

steel that will be exposed for a visual inspection will 

have corrosion products collected for testing. 

Degradation identified from the samples will be entered 

into the FENOC Corrective Action Program. The core 

bores will be performed in areas where leakage has 

been observed in the past.

• The first set of core bores will be performed prior to the 

end of 2014 (Phase 1).

• The second set of core bores will be performed prior to 

the end of 2020 (Phase 2).

• Further core bores will be conducted, if warranted, 

based on the evaluation of the results of the inspection 

and testing of the core bores or if spent fuel pool 

leakage through the wall or ceiling recurs after the 

Responses to NRC 

RAI B.2.39-2 from 

NRC Letter

dated

April 5, 2011, and

RAI B.2.39-10 from

NRC Letter

dated

July 21, 2011

Phase 1 COMPLETE

and

Phase 2 prior to

December 31, 2020
A-31

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

second set of core bores is performed. If spent fuel pool 

leakage through another wall or ceiling is identified, then 

core bores will be performed in a manner similar to that 

stated for the emergency core cooling system Pump 

Room No. 1 wall and the Room 109 ceiling.

38. Evaluate the concrete cracking observed on the underside of 

the spent fuel pool for necessary repairs.

Note: A core bore of the Room 109 ceiling will be performed

by the end of 2014 (see license renewal Commitment No. 37). 

Degradation identified from the samples will be entered into 

the FENOC Corrective Action Program. The condition of the 

concrete and the reinforcing steel will be evaluated at that time 

to assist in determining what repairs, if any, need to be made 

to the underside of the spent fuel pool concrete. The criterion 

for determining the need to repair the cracking will be the 

continued capability of the structures to perform their intended 

functions during the period of extended operation.

Responses to NRC

RAI B.2.39-2 from 

NRC Letter

dated

April 5, 2011; RAI

B.2.39-10 from

NRC Letter

dated

July 21, 2011;

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

39. Address the potential for borated water degradation of the 

steel containment vessel through the following actions:

• Access the inside surface of the embedded steel 

containment at a vertical height no greater than 

10 inches above bottom dead center. A core bore will be 

completed by the end of 2014 (Phase 1). If necessary, a 

second core bore will be completed by the end of 2020 

(Phase 2). If there is evidence of the presence of 

borated water in contact with the steel containment 

vessel, conduct nondestructive testing to determine 

what effect, if any, the borated water has had on the 

steel containment vessel. Based on the results of the 

nondestructive testing, perform a study to determine the 

effect through the period of extended operation of any 

identified loss of thickness in the steel containment due 

to exposure to borated water.

Responses to NRC 

RAI B.2.22-2 from 

NRC Letter 

dated

April 5, 2011;

RAI B.2.22-6 from

NRC Letter

dated

July 27, 2011;

Supplemental RAI B.2.22-6 

from NRC telecon

held on

May 9, 2013;

and

2014 Annual Update

Phase 1 

COMPLETE

Phase 2 prior to 

December 31, 2020
A-32

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

40. Implement the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Program as described in LRA

Section B.2.41.

A.1.41

B.2.41

Responses to NRC RAIs

3.3.2.2.5-1 and 3.3.2.71-2 

from NRC Letter

dated

April 20, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

41. Establish a PM task to periodically replace the flexible 

connections exposed to fuel oil in the Fuel Oil System.

Responses to NRC RAI

3.3.2.3.12-2 from

NRC Letter

dated

May 2, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

42. Enhance the Fatigue Monitoring Program to:

• Evaluate additional plant-specific component locations 

in the reactor coolant pressure boundary that may be 

more limiting than those considered in 

NUREG/CR-6260. This evaluation will include 

identification of the most limiting fatigue location 

exposed to reactor coolant for each material type 

(i.e., CS, LAS, SS, and NBA) and that each bounding 

material/location will be evaluated for the effects of the 

reactor coolant environment on fatigue usage. Nickelbased alloy items will be evaluated using 

NUREG/CR-6909. Submit the evaluation to the NRC 

1 year prior to the period of extended operation.

A.1.16

B.2.16

Response to NRC RAI

B.2.16-2 from NRC Letter 

dated

April 20, 2011

Prior to

April 22, 2016
A-33

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

43. Ensure that the current station operating experience review 

process includes future reviews of plant-specific and industry 

operating experience to confirm the effectiveness of the 

License Renewal aging management programs, to determine 

the need for programs to be enhanced, or indicate a need to 

develop new aging management programs.

Responses to NRC RAI

B.1.4-1 from NRC Letter 

dated

May 19, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

COMPLETE 

44. Cathodically protect the EDG fuel oil storage tanks 

(DB-T153-1 and DB-T153-2) and the in-scope fuel oil and 

Service Water buried piping in accordance with 

NACE SP0169-2007 or NACE RP0285-2002.

Responses to NRC RAIs

B.2.7-1 from NRC Letter 

dated

April 20, 2011, as modified 

per telecon with the NRC 

held on

June 7, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

COMPLETE 

45. Implement the Nuclear Safety-Related Coatings Program as 

described in LRA Section B.2.42.

A.1.42

B.2.42

Responses to NRC RAIs

XI.S8-1 from NRC Letter 

dated

April 5, 2011,

and

A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-34

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

46. Implement the Shield Building Monitoring Program as 

described in LRA Section B.2.43.

A.1.43

B.2.43

Responses to NRC RAIs

B.2.16-2 from NRC Letter 

dated

December 27, 2012,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

47. Enhance the Inservice Inspection (ISI) Program - IWE to:

• Include surface examinations to monitor for cracking of 

containment stainless steel penetration sleeves, 

dissimilar metal welds, bellows, and steel components 

that are subject to cyclic loading but have no current 

licensing basis fatigue analysis.

The inspection sample size will include 10 percent of the 

containment penetration population that is subject to 

cyclic loading but has no current licensing basis fatigue 

analysis. Penetrations included in the inspection sample 

will be scheduled for examination in each 10-year ISI 

interval that occurs during the period of extended 

operation. Should fatigue analyses be performed in the 

future for the subject containment penetrations, the 

surface examinations will no longer be required.

A.1.22

B.2.22

Responses to NRC RAI

B.2.22-7 from

NRC Letter

dated

July 21, 2011;

Supplemental RAI B.2.22-7 

from NRC telecons

held on

September 13 and 16, 2011;

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016
A-35

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

48. Complete an investigation and needed repairs or modification 

of the degraded portion of the safety-related intake canal 

embankment.

Responses to NRC RAI

B.2.40-2 from

NRC Letter

dated

July 21, 2011,

and

RAI A.1-1 from

NRC Letter

dated

March 26, 2013

Complete 

49. Enhance the Nickel-Alloy Management Program to:

• Provide for inspection of dissimilar metal butt welds in 

accordance with the requirements of ASME Code Case 

N-770-1, “Alternative Examination Requirements and 

Acceptance Standards for Class 1 PWR Piping and 

Vessel Nozzle Butt Welds Fabricated with UNS N06082 

or UNS W86182 Weld Filler Material With or Without 

Application of Listed Mitigation Activities, Section XI, 

Division 1,” as modified by 10 CFR 50.55a(g)(6)(ii)(F).

A.1.28

B.2.28

Responses to NRC RAI

B.2.28-1 from NRC Letter

dated

July 27, 2011,

and

RAI A.1-1 from NRC Letter

dated

March 26, 2013

Prior to

October 22, 2016

50. Enhance the ISI Program – IWF to:

• Include monitoring of ASTM A490 high-strength bolting 

(i.e., actual measured yield strength greater than or 

equal to 150 ksi or 1,034 MPa) in sizes greater than 

1 inch nominal diameter for cracking using volumetric 

examination. The volumetric examinations will be 

performed in accordance with the requirements of 

ASME Boiler and Pressure Vessel Code Section V, 

Article 5, Appendix IV, 2007 Edition through 

2008 Addenda. The representative sample size will be 

equal to 20 percent (rounded up to the nearest whole 

number) of the entire IWF population of ASTM A490 

high-strength bolts in sizes greater than 1 inch nominal 

diameter, with a maximum sample size of 25 bolts. The 

selection of the representative sample will consider 

A.1.23

B.2.23

Supplemental response to 

NRC RAI B.2.4-1b from 

NRC Letter

dated

February 14, 2013, and from 

telephone conference calls 

held on

April 11, April 24, May 2, and 

May 28, 2013

Prior to

October 22, 2016
A-36

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

susceptibility to SCC (e.g., actual measured yield 

strength) and as low as reasonably achievable (ALARA) 

radiation dose reduction principles. The frequency of 

examination will be once each 10-year ISI interval,

beginning with the fourth interval that started 

September 21, 2012.

• Include monitoring of ASTM A540 high-strength bolting 

(i.e., actual measured yield strength greater than or 

equal to 150 ksi or 1,034 MPa) in sizes greater than 

1 inch in nominal diameter for cracking. Periodic visual 

inspections of susceptible ASTM A540 bolting will be 

conducted prior to the period of extended operation and 

at an interval not to exceed 5 years to identify locations 

where the A540 bolting may be exposed to a potentially 

corrosive environment for SCC. If the visual inspections 

identify one or more bolts in a potentially corrosive 

environment, then an engineering evaluation will be 

performed to determine whether the bolting material had 

been subjected to a corrosive environment for SCC. The 

bolts determined to have been subjected to a corrosive 

environment for SCC comprise the population subject to 

sampling for volumetric examinations. The 

representative sample size is equal to 20 percent 

(rounded up to the nearest whole number) of the bolts in 

the sample population, with a maximum sample size of 

25 bolts. The volumetric examinations are performed in 

accordance with the requirements of ASME Code 

Section V, Article 5, Appendix IV. Volumetric 

examinations will be performed no later than the 

subsequent refueling outage following visual 

identification of bolting subject to a corrosive 

environment. Deferral of volumetric examinations to the 

subsequent refueling outage is not permitted if the visual 

inspection indicates evidence of contaminant 

penetration through the coatings. The frequency of 

examination is once each 10-year ISI interval, beginning 

with the 4th interval that started September 21, 2012. 

For ASTM A540 high-strength bolts that are not 

exposed to a corrosive environment, the volumetric 
A-37

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

examinations are waived based on plant-specific 

operating experience associated with the volumetric 

examination of the Davis-Besse reactor head closure 

studs (60 each) constructed of high-strength 

ASTM A540 material, where the studs are examined 

once each ISI interval, and after three intervals, no 

unacceptable indications have been noted.

• As an alternative to the visual examinations and the 

subsequent volumetric examinations of ASTM A540 

bolts subjected to a corrosive environment, the ISI 

Program – IWF provides an option to perform periodic 

volumetric examinations as follows. The program 

includes monitoring of ASTM A540 high-strength bolting 

(i.e., actual measured yield strength greater than or 

equal to 150 ksi or 1,034 MPa) in sizes greater than 

1 inch nominal diameter for cracking using volumetric 

examination. The volumetric examinations are 

performed in accordance with the requirements of 

ASME Code Section V, Article 5, Appendix IV. The 

representative sample size is equal to 20 percent 

(rounded up to the nearest whole number) of the entire 

IWF population of ASTM A540 high-strength bolts in 

sizes greater than 1 inch nominal diameter, with a 

maximum sample size of 25 bolts. The selection of the 

representative sample considers susceptibility to SCC

(e.g., actual measured yield strength) and ALARA 

radiation dose reduction principles. The frequency of 

examination is once each 10-year ISI interval, beginning 

with the 4th interval that started September 21, 2012.

51. Implement the Service Level III Coatings and Linings 

Monitoring Program.

A.1.44

B.2.44

Response to NRC RAI

3.0.3-3

from NRC Letter

dated

November 26, 2013

Prior to

October 22, 2016
A-38

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

52. In response to MRP-227-A Applicant/Licensee Action Item 6, 

submit for NRC review and approval an evaluation justifying 

the acceptability of inaccessible and non-inspectable 

component items (core barrel cylinder including vertical and 

circumferential seam welds, former plates, external 

baffle-to-baffle bolts and their locking devices, core 

barrel-to-former bolts and their locking devices, and internal 

baffle-to-baffle bolts) for continued operation through the 

period of extended operation and, if necessary, provide a plan 

for replacement of the components.

A.1.32

B.2.32

Within 1 year of the 

detection of 

degradation 

exceeding the 

acceptance criteria of 

the linked MRP-227-A 

primary component 

items leading to 

expansion

53. In response to MRP-227-A Applicant/Licensee Action Item 7, 

develop and submit for NRC review and approval a plantspecific analysis to demonstrate that the Incore Monitoring 

Instrumentation (IMI) guide tube assembly spiders, Control 

Rod Guide Tube (CRGT) spacer castings, and additional RV 

Internals component items that may be fabricated from CASS, 

martensitic stainless steel, or martensitic 

precipitation-hardened stainless steel materials (e.g., Core 

Support Shield (CSS) vent valve top and bottom retaining 

rings) will maintain their functionality during the period of 

extended operation. The analysis will consider the possible 

loss of fracture toughness in these component items due to 

thermal embrittlement and/or irradiation embrittlement and 

may also need to consider limitations on accessibility for 

inspection and the resolution/sensitivity of the inspection 

techniques. The Davis-Besse analysis will be consistent with 

the licensing basis and the need to maintain the functionality of 

the component items being evaluated under all licensing basis 

conditions of operation.

A.1.32

B.2.32

One year prior to the 

MRP-227-A 

inspection of the 

applicable component 

items
A-39

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

54. In response to MRP-227-A Applicant/Licensee Action Item 8, 

update and submit for NRC review and approval an evaluation 

for the period of extended operation regarding the effect of 

irradiation on the mechanical properties and deformation limits 

of the RV internals that was evaluated for the current term of 

operation in Appendix E of Topical Report BAW-10008, Part 1, 

Revision 1, supplemented by Davis-Besse USAR 

Appendix 4A.

A.1.32

B.2.32

Prior to

October 22, 2016

55. Perform the following actions to improve and maintain the 

fidelity of the data in the Flow-Accelerated Corrosion Program:

• Perform a review of the CHECWORKS SFA model to 

determine which inputs are critical to the determination 

of fitness for service and which inputs are noncritical. 

This action will document the listing of all input fields 

within the software, and whether their accuracy affects 

the output of the model.

• Perform a validation of the data inputs into 

CHECWORKS SFA. This task will include the validation 

of any input which would have consequence, as used by 

the CHECWORKS SFA software in the determination of 

fitness for service of piping and components for the 

Flow-Accelerated Corrosion Program. Data contained 

within the CHECWORKS SFA model that does not 

affect fitness for service will be annotated during this 

validation as being noncritical to the function of the 

software, while still attempting to validate it.

• Document the results of the validation of the 

CHECWORKS SFA database. This action will create a 

document (e.g., Reference Material, Program Manual) 

that will serve as a listing of inputs into the 

CHECWORKS SFA database and be maintained as a 

quality record.

• Revise the CHECWORKS SFA model to correct the 

restriction orifices’ size/dimension for the orifice and flow 

elements identified in the Steam Line Failure Root 

Cause Evaluation.

A.1.19

B.2.19

Prior to

October 22, 2016
A-40

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

• Establish a list of components for the site that meet the 

bulleted items within Section 4.4.4 of NSAC-202L, 

Revision 4.

Compile the inspection history of the relevant

components.

Perform an evaluation for any components without

inspection data and add components requiring

inspection to 19RFO scope. These locations are to

specifically include:

o locations downstream of orifices, flow elements, 

venturis, thermowells, angle valves, flow control valves, 

or level control valves

o locations or lines known to contain backing rings or 

counterbore

o field-fabricated tees and laterals

o nozzles

o complex geometric locations such as components 

located within two diameters of each other (e.g., an 

elbow welded to a tee)

o components downstream of replaced components 

(upstream if expander), and components that have 

been replaced in the past if not upgraded to resistant 

material

o components (including straight pipe) immediately 

downstream of flow-accelerated corrosion-resistant 

components (e.g., containing chromium greater than 

0.10%)

o locations immediately downstream of turning vanes

o expansion joints

• Revise the Flow-Accelerated Corrosion Program 

procedure as follows:
A-41

APPENDIX A: DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL COMMITMENTS

Item 

Number Commitment

Updated Safety Analysis 

Report (USAR) Supplement 

Section No/ Comments

Implementation 

Schedule 

o Add requirements to the procedure that would involve 

review and selection of examination scope based on 

recommendations from NSAC-202L, Revision 4, 

Section 4.4.4. This action requires documentation of 

the basis for selection or exclusion of the scope for the 

given outage. Documentation would be in the form of 

discussion in the Outage Technical Report (pre-outage) 

and Outage Summary Report (post-outage).

o Add a step that would require review, approval, and 

documentation of updates to the CHECWORKS SFA 

database. The scope of these changes would exclude 

data collected and evaluated during outages but would 

be inclusive of all others (e.g., plant uprates, plant 

modifications, engineering change packages). 

Documentation for this step would be through an 

Engineering Evaluation Request.

B-1

APPENDIX B

CHRONOLOGY

This appendix contains a chronological listing of the routine correspondence between the staff 

of the U.S. Nuclear Regulatory Commission (NRC or the staff) and FirstEnergy Nuclear 

Operating Company (FENOC or the applicant) and other correspondence regarding the staff’s 

reviews of the Davis-Besse Nuclear Power Station (Davis-Besse), Docket Number 50-346, 

license renewal application (LRA).

Table B-1. Chronology

Date Subject

September 20, 2013 Letter from Lieb R. A., FENOC: License Renewal Application Amendment 

No. 46 - Annual Update (TAC No. ME4640). (ADAMS Accession No. ML13269A027)

October 18, 2013 Letter from Lieb R. A., FENOC: Review of the Safety Evaluation Report Related to the 

License Renewal of Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS 

Accession No. ML13294A463)

November 26, 2013 Letter to Lieb R. A., FENOC: Request for Additional Information for the Review of the 

Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS Accession 

No. ML13294A500)

December 6, 2013 Summary of Telephone Conference Calls Held on November 19 and 22, 2013, Between 

the U.S. Nuclear Regulatory Commission and FirstEnergy Nuclear Operating Company, 

Concerning Draft Requests for Additional Information Pertaining to the Davis-Besse 

Nuclear Power Station, Unit 1, License Renewal Application (TAC No. ME4640). (ADAMS 

Accession No. ML13330B026)

January 31, 2014 Letter from Lieb R. A., FENOC: Reply to Request for Additional Information for the 

Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal 

Application (TAC No. ME4640) and License Renewal Application Amendment No. 47. 

(ADAMS Accession No. ML14035A164)

February 11, 2014 Letter to Lieb R. A., FENOC: Request for Additional Information for the Review of the 

Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS Accession 

No. ML14029A201)

February 19, 2014 Letter from Lieb R. A., FENOC: Davis-Besse Nuclear Power Station, Unit No. 1, License 

Renewal Application (TAC No. ME4640) Amendment No. 48. (ADAMS Accession 

No. ML14055A067)

March 4, 2014 Summary of Telephone Conference Call Held on February 5, 2014, Between the U.S. 

Nuclear Regulatory Commission and FirstEnergy Nuclear Operating Company, 

Concerning Draft Requests for Additional Information Pertaining to the Davis-Besse 

Nuclear Power Station, Unit 1, License Renewal Application (TAC No. ME4640). (ADAMS 

Accession No. ML14056A152)

March 11, 2014 Letter from Lieb R. A., FENOC: Reply to Request for Additional Information for the 

Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal 

Application (TAC No. ME4640) and License Renewal Application Amendment No. 49. 

(ADAMS Accession No. ML14072A008)

April 15, 2014 Letter to Lieb R. A., FENOC: Request for Additional Information for the Review of the 

Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS Accession 

No. ML14097A454)
B-2

Date Subject

April 22, 2014 “Summary of Telephone Conference Held on March 27, 2014, Between the U.S. Nuclear 

Regulatory Commission and FirstEnergy Nuclear Operating Company Concerning 

Commitment No. 13 of the Safety Evaluation Report Pertaining to the Davis-Besse 

Nuclear Power Station, Unit 1, License Renewal Application.” (TAC No. ME4640). 

(ADAMS Accession No. ML14099A339)

June 23, 2014 Letter from Lieb R. A., FENOC: License Renewal Application Amendment 

No. 50 - Annual Update (TAC Nos. ME4640 and ME4613). (ADAMS Accession 

No. ML14175B381)

July 3, 2014 Letter from Lieb R. A., FENOC: Reply to Request for Additional Information for the 

Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal 

Application (TAC No. ME4640) and License Renewal Application Amendment No. 51. 

(ADAMS Accession No. ML14184B184)

July 7, 2014 Letter to Lieb R. A., FENOC: Request for Additional Information for the Review of the 

Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS Accession 

No. ML14178A962)

July 29, 2014 Letter from Lieb R. A., FENOC: Reply to Request for Additional Information for the 

Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal 

Application (TAC No. ME4640) and License Renewal Application Amendment No. 52. 

(ADAMS Accession No. ML14211A023)

August 19, 2014 Letter to Lieb R. A., FENOC: Request for Additional Information for the Review of the 

Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS Accession 

No. ML14218A145)

September 16, 2014 Letter from Lieb R. A., FENOC: Reply to Request for Additional Information for the 

Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal 

Application (TAC No. ME4640) and License Renewal Application Amendment No. 53. 

(ADAMS Accession No. ML14259A067)

September 29, 2014 Letter to Lieb R. A., FENOC: Request for Additional Information for the Review of the 

Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS Accession 

No. ML14258A285)

October 28, 2014 Letter from Summers T. J., FENOC: Reply to Request for Additional Information for the 

Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal 

Application (TAC No. ME4640). (ADAMS Accession No. ML14301A369)

December 30, 2014 Letter to Lieb R. A., FENOC: Request for Additional Information for the Review of the 

Davis-Besse Nuclear Power Station (TAC No. ME4640). (ADAMS Accession 

No. ML14353A425)

January 28, 2015 Letter from Lieb R. A., FENOC: Reply to Request for Additional Information for the 

Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal 

Application (TAC No. ME4640) and License Renewal Application Amendment No. 54. 

(ADAMS Accession No. ML15028A540)

April 8, 2015 Letter from Lieb R. A., FENOC: Notification of Completion of License Renewal 

Commitments Related to the Review of the Davis-Besse Nuclear Power Station, Unit 

No. 1, License Renewal Application (TAC No. ME4640) and License Renewal Application 

Amendment No. 55. (ADAMS Accession No. ML15098A443)

April 20, 2015 Summary of Telephone Conference Call Held on February 20, 2015, Between the U.S. 

Nuclear Regulatory Commission and FirstEnergy Nuclear Operating Company, To Clarify 

the Responses to Requests for Additional Information Pertaining to the Davis-Besse 

Nuclear Power Station, Unit 1, License Renewal Application (TAC No. ME4640). 

(ADAMS Accession No. ML15056A456)

April 21, 2015 Letter from Lieb R. A., FENOC: Davis-Besse Nuclear Power Station Unit No. 1, License 

Renewal Reactor Vessel Internals Inspection Plan (TAC No. ME4640). (ADAMS 

Accession No. ML15113B132)
B-3

Date Subject

April 21, 2015 Letter from Lieb R. A., FENOC: Davis-Besse Nuclear Power Station Unit No. 1, License 

Renewal Reactor Vessel Internals Inspection Plan, non-proprietary AREVA Report 

No. ANP-3920, Revision 1, “Reactor Vessel Internals Inspection Plan for Davis Besse 

Nuclear Plant Unit No. 1 – Licensing Report (TAC No. ME4640). (ADAMS Accession 

No. ML15113B133)

April 21, 2015 Letter from Lieb R. A., FENOC: Davis-Besse Nuclear Power Station Unit No. 1, License 

Renewal Reactor Vessel Internals Inspection Plan, Non-proprietary AREVA NP Licensing 

Report No. ANP-3285, Revision 0, “Confirmation of Stress Relief for the DB-1

[Davis-Besse] Core Support Structure Upper Flange Weld (TAC No. ME4640). (ADAMS 

Accession No. ML15113B134)

May 20, 2015 Letter from Lieb R. A., FENOC: Supplemental Information for the Review of the 

Davis-Besse Nuclear Power Station, Unit No. 1, Reactor Vessel Internals Inspection Plan 

(TAC No. ME4640) and License Renewal Application Amendment No. 56. (ADAMS 

Accession No. ML15140A705)

May 28, 2015 Letter to Lieb R. A., FENOC: Davis-Besse Nulear Power Station - Inspection of Apparent 

Cause Evaluation Efforts for Propagation of Laminar Cracking in Reinforced Concrete 

Shield Building and Closure of Unresolved Item Involving Shield Building Laminar 

Cracking Licensing Basis. Inspection Report R 05000346/2014008. (ADAMS Accession 

No. ML15148A489)

June 5, 2015 Letter from Lieb R. A., FENOC: Supplemental Information for the Review of the 

Davis-Besse Nuclear Power Station, Unit No. 1, Reactor Vessel Internals Inspection Plan 

(TAC No. ME4640) and License Renewal Application Amendment No. 57. (ADAMS 

Accession No. ML15156B144)

June 12, 2015 Letter from Lieb R. A., FENOC: Supplemental Information for the Review of the 

Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal Application 

(TAC No. ME4640) and License Renewal Application Amendment No. 58. (ADAMS 

Accession No. ML15163A195)

June 29, 2015 Letter from Boles B.D., FENOC: License Renewal Application Amendment 

No. 59 - Annual Update (TAC No. ME4640). (ADAMS Accession No. ML15180A252)

July 13, 2015 Request For Withholding Information From Public Disclosure (TAC No. ME4640) 

(ADAMS Accession No. ML15189A056)

July 24, 2015 Summary of Telephone Conference Calls Held on May 06 and May 19, 2015, Between 

the U.S. Nuclear Regulatory Commission and FirstEnergy Nuclear Operating Company, 

Concerning the Reactor Vessel Internals Inspection Plan Pertaining to the Davis-Besse 

Nuclear Power Station, License Renewal Application (TAC No. ME4640). (ADAMS 

Accession No. ML15196A516)

October 6, 2015 Letter from Boles B.D., FENOC: License Renewal Application Amendment No. 60

(TAC No. ME4640). (ADAMS Accession No. M15279A365)

November 12, 2015 Advisory Committee on Reactor Safeguards Report on the Safety Aspects of the License 

Renewal Application for Davis-Besse Nuclear Power Station (ADAMS Accession 

No. ML15316A125)

December 1, 2015 Letter from V. M. McCree, NRC , to J. W. Stetkar, ACRS: Response to the Advisory 

Committee on Reactor Safeguards Report on the Safety Aspects of the License Renewal 

Application for Davis-Besse Nuclear Power Station, Unit 1 (ADAMS Accession 

No. ML15307A191)

C-1

APPENDIX C

PRINCIPAL CONTRIBUTORS

This appendix lists the principal contributors for the development of this supplemental safety 

evaluation report and their areas of responsibility.

APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

O. Aloysious Reviewer-Reactor Systems

S. Cuadrado DeJesus Reviewer-Structural

Y. Diaz-Sanabria Management Oversight

A. Foli Reviewer-Electrical

B. Fu Reviewer-Reactor Systems

J. Gavula Reviewer-Mechanical

D. Hoang Reviewer-Electrical

W. Holston Reviewer-Mechanical

R. Kalikian Reviewer-Mechanical

G. Kulesa Management Oversight

J. Lubinski Management Oversight

T. Lupold Management Oversight

J. Marshall Management Oversight

M. Marshall Management Oversight

J. Medoff Reviewer-Reactor Systems

C. Miller Management Oversight

S. Min Reviewer-Reactor Systems

D. Morey Management Oversight

R. Plasse Project Manager

G. Thomas Reviewer-Structural

J. Uribe Reviewer-Mechanical

J. Wise Reviewer-Mechanical

M. Yoo Reviewer-Reactor Systems

D-1

APPENDIX D

REFERENCES

This appendix lists the references used throughout this supplemental safety evaluation report 

for review of the license renewal application (LRA) for Davis-Besse Nuclear Power Station.

APPENDIX D: REFERENCES

NRC Documents

GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 1989.

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.

LR-ISG-2011-03, “Generic Aging Lessons Learned (GALL) Report Revision 2 AMP XI.M41, ‘Buried and 

Underground Piping and Tanks’,” August 2012.

LR-ISG-2012-01, “Wall Thinning Due to Erosion Mechanisms,” May 2013.

LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation,” November 2013.

RG 1.54, “Service Level I, II, and III Protective Coatings Applied To Nuclear Power Plants.”

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.

10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” (2012).

Industry Documents

Electric Power Research Institute (EPRI) Comprehensive Coatings Course.

EPRI Comprehensive Coatings Course.

EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course.

EPRI Report TR-105090, “Guidelines to Implement the License Renewal Technical Requirements of 10 CFR 54 for 

Integrated Plant Assessments and Time-Limited Aging Analyses.”

EPRI Pressurized Water Reactor (PWR) SG Examination Guidelines.

EPRI MRP Technical Report (TR) No. 1022863, “Materials Reliability Program: Pressurized Water Reactor 

Internals Inspection and Evaluation Guidelines (MRP-227-A),” dated January 2012.

EPRI MRP No. 1018292, “Materials Reliability Program: Screening, Categorization, and Ranking of 

B&W-Designed PWR Internals Component Items (MRP-189-Revision 1),” dated 2009.

NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54–The License Renewal Rule,” 

Revision 6, June 2005.

NEI 97-06, “Steam Generator Program Guidelines,” August 2005.
D-2

APPENDIX D: REFERENCES

Industry Codes and Standards

American Society of Mechanical Engineers (ASME) ASME Code, Section XI, 1995 Edition through the 1996 

Addenda.

ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components,” 2007 Edition with 

2008 Addenda.

ASTM D7167-05, “Standard Guide for Establishing Procedures to Monitor the Performance of Safety-Related 

Coating Service Level III Lining Systems in an Operating Nuclear Power Plant,”.

National Fire Protection Association (NFPA) 25, “Standard for the Inspection, Testing, and Maintenance of 

Water-Based Fire Protection Systems,” 2011.

National Association of Corrosion Engineers (NACE) RP0285-2002, “Corrosion Control of Underground Storage 

Tank Systems by Cathodic Protection”.

National Association of Corrosion Engineers (NACE) International SP0169-2007, “Control of External Corrosion on 

Underground or Submerged Metallic Piping Systems,” NACE International, Houston, TX, March 2007.






NUREG

-2193

Supplement 1

Safety Evaluation Report Related to the License Renewal of 

Davis-Besse Nuclear Power Station