Safety Evaluation Report 

Related to the License 

Renewal of Limerick 

Generating Station, 

Units 1 and 2

Office of Nuclear Reactor Regulation

NUREG-2171

Supplement 1
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Safety Evaluation Report 

Related to the License 

Renewal of Limerick 

Generating Station, 

Units 1 and 2

Supplement 1

Docket Nos. 50-352 and 50-353

Manuscript Completed: September 2014

Date Published: September 2014

Office of Nuclear Reactor Regulation

NUREG-2171

Supplement 1

iii

ABSTRACT

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

application (LRA) for Limerick Generating Station (LGS), Units 1 and 2, as submitted by Exelon 

Generation Company, LLC (Exelon or the applicant). By letter dated June 22, 2011, Exelon 

submitted its LRA to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the LGS 

operating licenses for an additional 20 years. The NRC staff (the staff) issued a safety 

evaluation report (SER) related to the license renewal of Limerick Generating Station, Units 1 

and 2, dated January 10, 2013, (Agencywide Documents Access and Management System

Accession No. ML13015A191), 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.

v

TABLE OF CONTENTS

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

ABBREVIATIONS ................................................................................................................... vii

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

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

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

SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING 

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

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

3.0.3.3 Staff Evaluation of LRA Changes to Incorporate 

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

Surfaces, Fire Water Systems, Atmospheric Storage 

Tanks, and Corrosion Under Insulation”............................ 3-10

3.0.3.4 Aging Management Related to Loss of Coating Integrity 

for Internal Coatings on In-Scope Mechanical SSCs......... 3-30

3.1 Aging Management of Reactor Coolant System ........................................ 3-48

3.2 Aging Management of Engineered Safety Features Section...................... 3-48

3.3 Aging Management of Auxiliary Systems................................................... 3-48

3.4 Aging Management of Steam and Power Conversion Systems ................. 3-51

3.5 Aging Management of Containments, Structures, and Component 

Supports.................................................................................................... 3-52

3.6 Aging Management of Electrical and Instrumentation and Control 

Systems .................................................................................................... 3-53

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

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

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

APPENDIX A LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE 

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

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

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

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

vii

ABBREVIATIONS

ACRS Advisory Committee on Reactor Safeguards

ADAMS Agencywide Documents Access and Management System

AERM aging effect requiring management

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

CAP corrective action program

CFR Code of Federal Regulations

CLB current licensing basis

CLSM controlled low strength material

CUI corrosion under insulation

EDG emergency diesel generator

EPRI Electric Power Research Institute

Exelon Exelon Generation Company, LLC

GALL Generic Aging Lessons Learned

GL generic letter

HDPE high-density polyethylene

HPCI high-pressure coolant injection

LGS Limerick Generating Station

LRA license renewal application

LR-ISG license renewal interim staff guidance
viii

MCR main control room

mV millivolt(s)

NACE National Association of Corrosion Engineers

NFPA National Fire Protection Association

NRC U.S. Nuclear Regulatory Commission

OE operating experience

ohm-cm ohm-centimeter(s)

PIV post indicating valves

ppm part(s) per million

psid pound(s) per square inch differential

RAI request for additional information

RCIC reactor core isolation cooling

RECW reactor enclosure cooling water

RG regulatory guide

SCC stress-corrosion cracking

SER safety evaluation report

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

Nuclear Power Plants, Rev.2”

SSC system, structure, and component

SSER supplemental safety evaluation report

SW service water

UFSAR updated final safety analysis report

UT ultrasonic testing

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 Limerick Generating Station (LGS), Units 1 and 2, as submitted by Exelon 

Generation Company, LLC (Exelon or the applicant). By letter dated June 22, 2011, Exelon 

submitted its LRA to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the LGS 

operating licenses for an additional 20 years. The NRC staff (the staff) issued a safety 

evaluation report (SER) related to the license renewal of LGS, Units 1 and 2, dated 

January 10, 2013 (Agencywide Documents Access and Management System (ADAMS)

Accession No. ML13015A191), 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 additional information provided by the applicant 

since the staff’s issuance of the SER in January 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, 3, Appendix A, and Appendix B.

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 the

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

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

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

Table 1.4-1 shows the current set of LR-ISGs addressed in this SSER, as well as the SSER 

sections in which the staff addresses them. This SSER also discusses operating experience 

concerning loss of coating integrity of internal coatings of piping, piping components, heat 

exchangers, and tanks. 

 
1-2

Table 1.4-1 Current License Renewal Interim Staff Guidance

ISG Issue

(Approved ISG Number) Purpose SER 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)

This LR-ISG provides changes to 

GALL Report AMP XI.M41 as an 

acceptable approach for 

managing the effects of aging of 

buried and underground piping 

and tanks.

SSER Section 3.0.3.2.12

“Wall Thinning Due to Erosion 

Mechanisms”

(LR-ISG-2012-01)

This LR-ISG provides an alternate 

approach to manage the effects of 

aging for wall thinning due to 

various erosion mechanisms for 

piping and components through 

AMP XI.M17, “Flow-Accelerated 

Corrosion.”

SSER Section 3.0.3.1.8

“Aging Management of Internal 

Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and 

Corrosion under Insulation”

(LR-ISG-2012-02)

This LR-ISG revises the guidance 

related to aging management 

activities associated with AMPs 

XI.M38, “Inspection of Internal 

Surfaces in Miscellaneous Piping 

and Ducting Components,” XI.M27, 

“Fire Water System,” XI.M29, 

“Aboveground Metallic Tanks,” 

XI.M41, “Buried and Underground 

Piping and Tanks,” Recurring 

Internal Corrosion, and Corrosion 

Under Insulation (CUI).

SSER Section 3.0.3.3
2-1

SECTION 2 

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW

The staff does not have any changes or updates to this section of the safety evaluation report.

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

Summary of Changes. By letter dated September 25, 2013, the applicant stated that Exelon 

Generation Company, LLC (Exelon or the applicant), had performed a review of License 

Renewal Interim Staff Guidance (LR-ISG) -2012-01, “Wall Thinning Due to Erosion 

Mechanisms.” The applicant also stated that Limerick Generating Station (LGS) recently 

implemented the guidance contained in this LR-ISG through its Flow-Accelerated Corrosion 

program. Based on its review, the applicant provided changes to license renewal application 

(LRA) Sections A.2.1.10 and B.2.1.10, to reflect the changes allowed by this LR-ISG, by 

including wall thinning mechanisms other than flow-accelerated corrosion to be managed by the 

Flow-Acceleration Corrosion program. 

Staff Evaluation. The U.S. Nuclear Regulatory Commission (NRC) staff (the staff) notes that, as 

described in the safety evaluation report (SER), LGS’s Flow-Accelerated Corrosion program is 

based on Electric Power Research Institute (EPRI) guidelines in NSAC-202L-R3, which 

provides guidance for susceptible-not-modeled piping. The staff also notes that, as described in 

LR-ISG-2012-01, piping or locations that are being monitored for wall thinning due to erosion 

mechanisms may be included with these susceptible-not-modeled lines and treated in a 

comparable fashion. The staff finds the applicant’s proposal acceptable because it has 

implemented the guidance contained in LR-ISG-2012-01 for managing wall thinning due to 

erosion mechanisms.

Conclusion. The staff has concluded that no changes are required to the Flow-Accelerated 

Corrosion program. The program is adequate to manage the applicable aging effects.

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or Enhancements

3.0.3.2.12 Buried and Underground Piping and Tanks

Summary of Technical Information in the Application. LRA Section B.2.1.29 describes the 

existing Buried and Underground Piping and Tanks program as consistent, with enhancements, 

with GALL Report AMP XI.M41 “Buried and Underground Piping and Tanks.” The LRA states 

that the AMP addresses the external surfaces of metallic buried and underground piping and 

tanks exposed to soil and the outdoor air environments to manage the effects of loss of 

material. The LRA also states that the AMP proposes to manage this aging effect through 

electrochemical verification of cathodic protection, nondestructive evaluation of pipe wall 

thickness of underground piping, visual inspections of the pipe during opportunistic excavations, 
3-2

external coatings, cathodic protection, and the quality of backfill used. This program augments 

other programs that manage the aging of internal surfaces of buried and underground piping 

and tanks. By letters dated June 17, 2013, and August 16, 2013, the applicant amended its 

Buried and Underground Piping and Tanks program to address 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,’” which was issued in its final 

version on August 2, 2012.

Staff Evaluation. During the staff audit (Agencywide Documents Access and Management 

System (ADAMS) Accession No. ML12018A332), the staff reviewed the applicant’s claim of 

consistency with the GALL Report. The staff compared program elements 1-6 of the applicant’s 

program to the corresponding program elements of GALL Report AMP XI.M41.

For the “preventive actions,” “detection of aging effects,” and “acceptance criteria” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below.

The “preventive actions” program element in GALL Report AMP XI.M41 states that one 

acceptable way to mitigate loss of material for buried steel piping is to provide external coatings

and cathodic protection. During its audit, the staff found that the Buried and Underground 

Piping and Tanks program states that the plant drainage system piping is neither coated nor 

cathodically protected, and the circulating water system piping is not coated. By letter dated 

January 17, 2012, the staff issued request for additional information (RAI) B.2.1.29-1 requesting 

the applicant to state the basis for how the aging of buried components in the plant drainage 

and circulating water systems will be adequately managed such that their intended functions will 

be maintained consistent with the current licensing basis (CLB) if cathodic protection and 

external coatings are not provided for the plant drainage system and external coatings are not 

provided for the circulating water system.

In its response, dated February 15, 2012, the applicant stated that, based on further review, the 

plant drainage system is coated with a somastic coating, the circulating water system is coated 

with coal tar epoxy, both coatings are recommended by National Association of Corrosion 

Engineers (NACE) SP0169-2007, and the plant drainage system piping is not cathodically 

protected because it is constructed from cast iron, a corrosion-resistant material.

The staff found the applicant’s response acceptable because both piping systems are coated 

with coatings recommended by NACE SP0169-2007, which is referenced by GALL Report 

AMP XI.M41 as an acceptable standard for coatings. The staff does not agree with the 

applicant’s stated basis for not installing cathodic protection (i.e., cast iron is a 

corrosion-resistant material). However, buried cast iron piping will not experience sufficient 

corrosion to result in a loss of piping function because cast iron components are designed with a 

thicker wall that allows much longer buried service. The staff’s concern described in 

RAI B.2.1.29-1 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M41 states that, if 

adverse indications are detected, one acceptable way to ensure that an adequate extent of 

condition review is conducted is to double the inspection sample size within the affected piping 

category, and if adverse indications are found in the expanded sample, the inspection sample 

size is again doubled, with the doubling of the inspection sample size continuing as necessary. 

During its audit, the staff found that the Buried and Underground Piping and Tanks program 
3-3

states that adverse conditions detected during inspections will be evaluated and the potential 

inspection expansion will be determined in accordance with the corrective action program 

(CAP). By letter dated January 17, 2012, the staff issued RAI B.2.1.29-2 requesting the 

applicant to state the basis for how the CAP inspection expansion size will be sufficient to detect 

degradation before it causes an in-scope component to not be capable of meeting its CLB 

function(s).

In its response dated February 15, 2012, the applicant stated that:

The LGS Buried and Underground Piping and Tanks aging management 

program enhancement is revised to include criteria such that if adverse 

indications are detected during inspection of in-scope buried piping, inspection 

sample sizes within the affected piping categories are doubled. If adverse 

indications are found in the expanded sample, the inspection sample size is 

again doubled. This doubling of the inspection sample size continues as dictated 

by the corrective action program. This criterion is in accordance with GALL 

Report AMP XI.M41, ‘Buried and Underground Piping and Tanks.’

It was not clear to the staff whether the applicant’s CAP would require doubling of the inspection 

sample size until a subsequent set of inspections detected no adverse conditions. The staff’s 

concern described in RAI B.2.1.29-2 was not resolved.

By letter dated March 22, 2012, the staff issued followup RAI B.2.1.29-2.1 requesting the 

applicant to clarify what it means by “[t]his doubling of the inspection sample size continues as 

dictated by the corrective action program.” 

In its response, dated March 30, 2012, the applicant amended the last sentence of the 

enhancement to state, “[t]his doubling of the inspection sample size continues as necessary.” 

The applicant revised LRA Sections A.2.1.29, B.2.1.29, and Enhancement No. 1, accordingly.

The staff found the applicant’s response acceptable because the enhancement is consistent 

with the wording in AMP XI.M41. The staff’s concern described in RAI B.2.1.29-2 and 

B.2.1.29-2.1 was resolved. However, the staff noted that LR-ISG-2011-03 revised the 

recommendations associated with inspection scope expansion when an adverse condition is 

detected. By letter dated June 17, 2013, the applicant revised Enhancement No. 1. The staff’s 

evaluation of this change is documented in the below discussion associated with 

Enhancement No. 1.

The “acceptance criteria” program element in GALL Report AMP XI.M41 states that one 

acceptable way to ensure that the cathodic protection system is providing effective protection is 

to use the soil to pipe potential acceptance criteria found in NACE SP0169-2007. NACE 

SP0169-2007, Section 7.1.2.7, states that excessive levels of cathodic protection can cause 

external coating disbondment. During its audit, the staff found that the applicant’s “Cathodic 

Protection Design Basis Document” stated that the cathodic protection system is required to 

maintain an energized voltage of not less than 850 millivolts (mV) negative potential with 

respect to a copper-copper sulfate reference electrode. By letter dated January 17, 2012, the 

staff issued RAI B.2.1.29-3 requesting the applicant to state an upper limit acceptance criterion 

for pipe to soil potential measurements, and to state the basis for using the stated value.
3-4

In its response, dated February 15, 2012, the applicant stated that the program has been 

amended to require that if during cathodic protection surveys a negative polarized potential 

exceeds −1100 mV relative to a copper-copper sulfate electrode, an issue report will be 

documented in the CAP. The applicant also stated that the −1100 mV value is consistent with 

Peabody’s Control of Pipeline Corrosion, Second Edition 2001, NACE. In addition, the applicant 

revised LRA Sections A.2.1.29 and B.2.1.29 to reflect the additional acceptance criteria.

The staff found the applicant’s response acceptable because the applicant has added an 

acceptance criterion that will ensure that excessive levels of cathodic protection will be 

addressed through the CAP, and the criterion, −1100 mV, is consistent with 

NACE SP0169-2007 and industry guidelines for cathodic protection. The staff’s concern 

described in RAI B.2.1.29-3 was resolved.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements associated with enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows. By letters dated June 17, 2013, and August 16, 2013, the applicant 

revised Enhancement Nos. 1, 3, and 5 through 8. The staff’s evaluation of these revisions is 

shown below.

Enhancement 1. LRA Section B.2.1.29, as amended by the applicant’s response to 

RAIs B.2.1.29-2 and B.2.1.29-2.1, and letter dated June 17, 2013, states an enhancement to 

the “detection of aging effects” program element. In this enhancement, the applicant stated 

that, “[i]If adverse indications are detected during inspection of in-scope buried piping, 

inspection sample sizes within the affected piping categories are doubled. If adverse indications 

are found in the expanded sample, an analysis is conducted to determine the extent of condition 

and extent of cause. The size of the follow-on inspections will be determined based on the 

extent of condition and extent of cause.” The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M41 and finds it acceptable because 

when it is implemented it will be consistent with LR-ISG-2011-03 and it can ensure that the 

scope of inspections will be appropriate for the extent of conditions.

Enhancement 2. LRA Section B.2.1.29 states an enhancement to the “preventive actions,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria” 

program elements. In this enhancement, the applicant stated that it will coat the underground 

emergency diesel generator (EDG) system fuel oil piping before the period of extended 

operation in accordance with NACE standards. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMP XI.M41 and finds it acceptable 

because when it is implemented it will be consistent with LR-ISG-2011-03 AMP XI.M41 

Table 2b, Preventive Actions for Underground Piping and Tanks, which recommends that 

underground piping be coated in accordance with NACE standards.

Enhancement 3. As amended by letter dated June 17, 2013, LRA Section B.2.1.29 states an 

enhancement to the “parameters monitored or inspected,” “detection of aging effects,” and 

“acceptance criteria” program elements. In this enhancement, the applicant stated that it will 

perform direct visual inspections and volumetric inspections of the underground EDG system 

fuel oil piping and components during each 10-year period beginning 10 years before entry into 

the period of extended operation. Before the period of extended operation, all in-scope EDG 

system fuel oil piping and components located in underground vaults will undergo a 100-percent 
3-5

visual inspection. Volumetric inspections also will be performed. After entering the period of 

extended operation, 2 percent of the linear length of EDG system fuel oil piping and 

components within the scope of license renewal and located in underground vaults will undergo 

direct visual inspections and volumetric inspections every 10 years. Inspection locations after 

entering the period of extended operation will be selected based on susceptibility to degradation 

and consequences of failure. The applicant also stated that “[v]isual inspections will be 

performed by a NACE Coating Inspector Program Level 2 or 3 qualified inspector or an 

individual that has attended the EPRI Comprehensive Coatings Course and completed the 

EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training 

Course.” The staff reviewed this enhancement against the corresponding program elements in 

LR-ISG-2011-03 and finds it acceptable because when it is implemented the requirements for 

visual inspection of external surfaces and qualification and training will be consistent with 

LR-ISG-2011-03 and will ensure that sufficient piping is inspected by an individual with the 

appropriate knowledge, skills, and abilities assesses coating conditions.

Enhancement 4. LRA Section B.2.1.29 states an enhancement to the “parameters monitored or 

inspected,” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that it will perform two sets of volumetric inspections of the safety-related 

service water (SW) system underground piping and components during each 10-year period 

beginning 10 years before entry into the period of extended operation. Each set of volumetric 

inspections will assess either the entire length of a run or a minimum of 10 feet of the linear 

length of the piping and components within the scope of license renewal. Inspection locations 

will be selected based on susceptibility to degradation and consequences of failure. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M41 and found it acceptable because when it is implemented it will be consistent with 

the visual inspection of external and volumetric inspection of internal surfaces recommendations 

of GALL Report AMP XI.M41.

Enhancement 5. As amended by letter dated June 17, 2013, LRA Section B.2.1.29 states an 

enhancement to the “parameters monitored or inspected” and “detection of aging effects” 

program elements. In this enhancement, the applicant stated that a NACE Coating Inspector 

Program Level 2 or 3 qualified inspector or an individual that has attended the EPRI 

Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment 

and Repair Training Computer Based Training Course will conduct visual inspections of 

safety-related SW piping. The staff reviewed this enhancement against the corresponding 

program elements in LR-ISG-2011-03 and finds it acceptable because when it is implemented it 

will ensure that potential coating degradation will be evaluated by an individual with appropriate 

knowledge, skills, and abilities to conduct the inspections.

Enhancement 6. As amended by letter dated June 17, 2013, LRA Section B.2.1.29 states an 

enhancement to the “preventive actions,” “detection of aging effects,” “monitoring and trending,” 

and “acceptance criteria” program elements. In this enhancement, the applicant stated that it 

will perform trending of cathodic protection testing results to identify changes in the 

effectiveness of the system and to ensure that the rectifiers required to protect piping within the 

scope of license renewal remain operational at least 85 percent of the time, and cathodic 

protection effectiveness will be maintained greater than 80 percent. The staff reviewed this 

enhancement against the corresponding program elements in LR-ISG-2011-03 and finds it 

acceptable because when it is implemented it will be consistent with LR-ISG-2011-03 and it can 

ensure that cathodic protection is available for the recommended amount of time and the 

system is providing an adequate level of protection.
3-6

Enhancement 7. LRA Section B.2.1.29, as amended by the response to RAI B.2.1.29-3, states 

an enhancement to the “preventive actions,” “detection of aging effects,” “monitoring and 

trending,” and “acceptance criteria” program elements. In this enhancement, the applicant 

stated that it will modify the yearly cathodic protection survey acceptance criterion to meet 

NACE standards. As stated above in the staff evaluation portion of this supplemental safety 

evaluation report (SSER), RAI B.2.1.29-3 was issued requesting that the applicant state an 

upper limit acceptance criterion for pipe to soil potential measurements, and state the basis for 

using the stated value. The staff evaluated the applicant’s response to RAI B.2.1.29-3 and the 

amended Enhancement No. 7 against the corresponding program elements in GALL Report 

AMP XI.M41 and found it acceptable because, when it is implemented, it will be consistent with 

NACE SP0169-2007, which is referenced by GALL Report AMP XI.M41 as an acceptable 

standard for cathodic protection, and industry guidelines for cathodic protection.

By letter dated June 17, 2013, the applicant revised this enhancement to state that the 

acceptance criteria used to measure the effectiveness of the cathodic protection system for 

buried steel piping will be either a −850 mV polarized potential or a −100 mV polarization. The 

applicant stated that use of the −100 mV polarization criteria will be subject to being 

demonstrated effective through use of buried coupons, electrical resistance probes, or 

placement of reference cells in the immediate vicinity of the piping being measured. The staff 

noted that the use of the −850 mV polarized potential criterion is consistent with 

LR-ISG-2011-03. However, LR-ISG-2011-03, Table 6a, “Cathodic Protection Acceptance 

Criteria,” footnote 2, states 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. ISO 15589-1, “Petroleum and natural gas industries – Cathodic protection 

of pipeline transportation systems,” First Edition, Section 5.3.2.2 states that the use of the 

−100 mV polarization critetion should not be used in cases of pipelines connected to or 

consisting of mixed metals. While the staff recognizes that buried coupons, electrical resistance 

probes, or placement of reference cells can be used as effective means to detect corrosion 

rates or localized effectiveness of cathodic protection, the program does not state details such 

as what industry consensus documents will be used to install the devices. By letter dated 

August 1, 2013, the staff issued RAI B.2.1.29-4 Request (4) requesting that the applicant state 

which industry consensus documents will be used to install and use the corrosion rate 

monitoring devices or reference electrodes.

In its response dated August 16, 2031, the applicant revised LRA Sections A.2.1.29 and 

B.2.1.29, and Commitment No. 29 to remove the 100mV polarization criterion. The staff finds 

the applicant’s response and enhancement acceptable because, in lieu of providing further 

information regarding how it would measure the effectiveness of using the 100 mV polarization 

criterion, it eliminated use of this criterion. The staff’s concern described in RAI B.2.1.29-4

Request (4) is resolved.

Enhancement 8. By letter dated June 17, 2013, the applicant stated an enhancement to the 

“acceptance criteria” program element. In this enhancement, the applicant stated that 

“[w]henever pipe is excavated and damage to the coating is significant and the damage was 

caused by nonconforming 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.” The staff reviewed this enhancement against the corresponding program 

elements in LR-ISG-2011-03 and finds it acceptable because when it is implemented it will be 
3-7

consistent with LR-ISG-2011-03 and can ensure that an appropriate extent of condition is 

conducted when backfill conditions have led to coating damage.

Based on the revisions to the Buried and Underground Piping and Tanks program in the 

amendment letter dated June 17, 2013, the staff determined the need for additional information 

related to the “detection of aging effects” program element, which resulted in the issuance of 

RAIs as discussed below. 

LRA Section B.2.1.29 states that direct inspections of buried piping are not required because of 

the preventive and mitigative measures included in the program. However, this was based in 

part because GALL Revision 2, AMP XI.M41, “Buried and Underground Piping and Tanks,” 

Table 4a, “Inspections of Buried Pipe,” did not state that buried nonsafety-related systems

should be inspected. The circulating water and plant drainage systems are within the scope of 

license renewal and are nonsafety-related. While these systems are coated and buried in 

acceptable backfill, only the circulating water system is cathodically protected. LR-ISG-2011-03 

Table 4a removed the distinction between code class safety-related, hazmat, and 

nonsafety-related piping.Table 4a states that all in-scope piping is subject to inspections. By 

letter dated August 1, 2013, the staff issued RAI B.2.1.29-4 Request (1) requesting that the 

applicant state (a) the number of inspections that will be conducted per unit on the in-scope 

buried plant drainage system piping; (b) whether the piping is buried in cementitious backfill; 

and (c) where not buried in cementitious backfill, if the pipe is coated.

In its reply dated August 16, 2013, the applicant stated:

• Both the safety-related service water system valve pit drains and main, safeguard, and 

auxiliary transformer dike drains are at atmospheric pressure and experience 

intermittent water flow.

• The in-scope plant drainage system piping is cast iron, which is a corrosion resistant 

material. As stated above, in the Staff Evaluation portion of this SSER section, the staff 

does not agree that cast iron piping is corrosion resistant; however, cast iron 

components are designed with a thicker wall that allows much longer buried service.

• The piping is coated and backfilled in a controlled low strength material (CLSM). Backfill 

may also be concrete or material in accordance with ASTM International (formerly 

known as American Society for Testing and Materials) D448-08, per plant specifications. 

Five excavations of the plant drainage system were performed since June of 2012, and 

all were found in their specified fill material. Resistivity measurements were taken of the 

backfill material around the pipe and were greater than 10,000 ohm-cm, which indicates 

low corrosivity. Eleven excavations of other plant system piping were performed since 

October of 2010 in various locations. The condition of the fillcrete was found to be in 

very good condition and was analyzed for pH and chlorides. The measured pH was 

10.4 and chlorides were less than 40 [parts per million] ppm. The high pH is the result of 

hydroxyl ions and alkalis present in the pore solutions in the CLSM microstructure, not 

from dissolved salt, which is consistent with the low chloride levels. The results of the 

pH and chloride testing further support that the fillcrete material has low corrosivity and, 

therefore, provides additional corrosion protection of the piping. In addition, there is no 

adverse plant–specific operating experience concerning external corrosion of plant 

drainage system piping. 
3-8

• If in-scope piping is excavated for any reason and coating is exposed, inspection of the 

coating will be performed by a NACE Coating Inspector Program Level 2 or 3 qualified

inspector or an individual that has attended the EPRI Comprehensive Coatings Course

and completed the EPRI Buried Pipe Condition Assessment and Repair Training

Computer Based Training Course.

The staff finds the applicant’s proposal that plant drainage piping would only be inspected on an 

opportunistic basis acceptable. The staff has concluded that there is reasonable assurance that 

buried in-scope plant drainage piping will meet its CLB intended function(s) without a declared 

minimum number of inspections during the period of extended operation because:

• As evidenced by five excavations of the plant drainage system conducted since June of 

2012, resistivity measurements of the backfill material around the pipe were greater than 

10,000 ohm-cm. Based on U.S. Department of Transportation, Federal Highway 

Administration, Publication No. FHWA-NHI-00-044, “Corrosion/Degradation of Soil 

Reinforcements for Mechanically Stabilized Walls and Reinforced Soil Slopes,” 

September 2000, soils with resistivity readings greater than 10,000 ohm-cm are 

considered noncorrosive.

• The piping is exposed to atmospheric pressure and, therefore, if there are holes in the 

piping, it is much less likely that local supporting soil would be washed away. In 

addition, it is very likely that water would continue to be conducted away from the 

SW system valve pits and transformer dike areas.

• The piping is coated which results in increased resistance to external corrosion.

• As evidenced by 11 excavations of other plant system piping conducted since 

October 2010, the condition of the fillcrete was found to be in very good condition, the 

measured pH was 10.4, and chlorides were less than 40 ppm.

• There is no adverse plant–specific operating experience concerning external corrosion 

of plant drainage system piping.

The staff noted that the applicant will use coating inspectors qualified consistent with the 

recommendations in LR-ISG-2011-03 which will ensure that an individual with the appropriate 

knowledge, skills, and abilities assesses coating conditions. The staff issued RAI B.2.1.29-4 

Request (2) requesting that the applicant state whether inspection locations selected for buried 

in-scope plant drainage system piping would be based on risk. The staff notes that, with its 

acceptance of the response to RAI B.2.1.29-4 Request (1), Request (2) is not necessary 

because opportunistic inspections are not based on risk. The staff’s concerns described in 

RAI B.2.1.29-4 Requests (1) and (2) are resolved.

Based on its audit, and review of the applicant’s responses to RAIs B.2.1.29-1, B.2.1.29-2, 

B.2.1.29-2.1, B.2.1.29-3, and B.2.1.29-4 Requests (1), (2), and (4), the staff finds that the 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of LR-ISG-2011-03. In addition, the staff 

reviewed the enhancements associated with the “preventive actions,” “parameters monitored or 

inspected,” “detection of aging effects,” “monitoring and trending,” and “acceptance criteria” 

program elements and finds that when implemented, they will make the AMP adequate to 

manage the applicable aging effects.
3-9

Operating Experience. LRA Section B.2.1.29 summarizes operating experience (OE) related to 

the Buried and Underground Piping and Tanks program. The applicant stated that, in 

October 2010, an opportunistic inspection of fire protection and domestic water piping showed 

that there was no degradation of the coatings and wrappings on the piping and components. 

The applicant also stated that, in May 2008, inspections of all underground safety-related SW 

piping showed surface corrosion and some pitting. As a result, volumetric examinations were 

conducted, some repairs and replacements were completed, all piping was recoated, and future 

inspection activities were scheduled for inspecting all piping in all underground valve pits within 

the scope of license renewal on a 2-year frequency.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects, and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the audit report, the staff conducted an independent search of the plant OE

information to determine whether the applicant had adequately evaluated and incorporated OE

related to this program. During its review, the staff found no OE to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation. However, subsequent to the audit, LR-ISG-2011-03 was issued which 

states that, if cathodic protection is not provided, a 10-year search of plant-specific OE should 

be conducted to determine if adverse conditions have occurred in the impacted systems. Given 

that the plant drainage system is not cathodically protected, this 10-year search should be 

conducted. The search should include components that are not within the scope of license 

renewal if they are constructed from similar materials and buried in a similar environment. In 

addition, LR-ISG-2011-03 states that a basis should be provided for why cathodic protection is 

not provided during the period of extended operation. By letter dated August 1, 2013, the staff 

issued RAI B.2.1.29-4 Request (3) requesting that the applicant provide the results of a 10-year 

search of plant-specific OE related to the plant drainage system and state the basis for why 

cathodic protection will not be provided.

In its response dated August 16, 2013, the applicant stated that a review of plant-specific OE

from January 1, 2000, through April 21, 2010, was performed to support the development of the 

aging management reviews (AMRs) prepared for the LRA. An additional review was performed 

from April 22, 2010, through August 1, 2013. These reviews identified 615 condition reports for 

both the in-scope and not-in-scope portions of the plant drainage system. No adverse 

conditions were identified for buried piping external surfaces.

The staff finds the applicant’s response acceptable because its response supported the staff’s 

need for plant-specific OE information in order to assess the acceptability of not providing 

cathodic protection for the buried in-scope plant drainage system piping. In addition, the staff 

noted that the applicant’s supporting information for conducting only opportunistic inspections of 

this system (e.g., low soil corrosivity, intact coatings, acceptable backfill), further supports the 

case for not providing cathodic protection. The staff’s concern described in RAI B.2.1.29-4 

Request (3) is resolved.

Based on its audit and review of the applicant’s response to RAI B.2.1.29-4 Request (3), the 

staff finds that the applicant has appropriately evaluated plant-specific and industry OE. 

Operating experience related to the applicant’s program demonstrates that it can adequately 

manage the effects of aging on systems, structures, and components (SSCs) within the scope 

of the program, and that implementation of the program has resulted in the applicant’s taking 

corrective actions.
3-10

UFSAR Supplement. As amended by letters dated June 17, 2013, and August 16, 2013, LRA 

Section A.2.1.29 provides the updated final safety analysis report (UFSAR) supplement for the 

Buried and Underground Piping and Tanks program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the description in 

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

Rev. 2” (SRP-LR), Table 3.0-1, as revised by LR-ISG-2011-03.

The staff also noted that the UFSAR supplement contained a Commitment No. 29 to implement 

the enhancements, as described in the LRA, before the period of extended operation. The staff 

finds that the information in the UFSAR supplement is an adequate summary description of the 

program.

Conclusion. On the basis of its audit and review of the Buried and Underground Piping and 

Tanks program, the staff determines that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

LR-ISG-2011-03. Also, the staff reviewed the enhancements and confirmed that their 

implementation will make the AMP adequate to manage the applicable aging effects and that 

the UFSAR supplement contained Commitment No. 29 to implement the enhancements before 

the period of extended operation. The staff also reviewed the UFSAR supplement for this AMP 

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

10 CFR 54.21(d).

3.0.3.3 Staff Evaluation of LRA Changes to Incorporate LR-ISG-2012-02, “Aging 

Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and 

Corrosion Under Insulation”

3.0.3.3.1 Recurring Internal Corrosion

Summary of Changes. By letter dated March 12, 2014, the applicant provided its evaluation of 

LR-ISG-2012-02, Section A, “Recurring Internal Corrosion,” and identified changes to the LRA. 

The applicant stated that it had identified recurring internal corrosion in several raw water 

systems, which are subject to ongoing inspections and piping replacements through the 

Open-Cycle Cooling Water System program. The applicant also stated that enhancements to 

the Open-Cycle Cooling Water System program had previously been made as documented in 

NRC SER Section 3.0.3.2.4, and these enhancements provide a combination of inspections, 

replacements, and material improvements to detect the presence of, and minimize the 

susceptibility to, recurring internal corrosion. 

In addition, the applicant identified recurring internal corrosion in the portion of the fire water 

system associated with the backup diesel fire pump that is exposed to untreated raw water. 

Although LRA Sections A.2.1.18 and B.2.1.18 initially included an enhancement for the Fire 

Water System program to perform volumetric inspections of associated above-ground piping 

every 10 years, the applicant stated that it would further enhance this program to perform 

additional inspections to address recurring internal corrosion. As a result, the applicant 

provided a new enhancement (Enhancement No. 10) to perform annual wall-thickness 

measurements at five selected locations using ultrasonic or other suitable techniques until 

degradation of the backup fire water piping no longer meets the criteria for recurring internal 

corrosion.
3-11

Staff Evaluation. For components managed by the Open-Cycle Cooling Water System 

program, the identification of flaws can be addressed through the application of American 

Society of Mechanical Engineers (ASME) Code Case N-513-3, “Evaluation Criteria for 

Temporary Acceptance of Flaws in Moderate Energy Class 2 or 3 Piping, Section XI, Division I.” 

The considerations for applying this approach include augmented volumetric examinations to 

assess the degradation of the affected system, which typically consists of an initial sample of 

the five most susceptible locations and additional samples whenever other flaws are detected. 

Based on this, the applicant’s previous enhancements are sufficient to address recurring 

internal corrosion in those systems managed by the Open-Cycle Cooling Water System 

program. 

However, since ASME code cases do not apply to fire water system piping, for any flaws 

detected through the Fire Water System program, there did not appear to be comparable 

guidance for conducting augmented inspections of additional samples, if degradation is 

detected. Consequently, by letter dated April 24, 2014, the staff issued RAI 3.0.3.3.1-1 

requesting the applicant to provide additional information regarding program activities whenever 

further degradation is identified during the annual inspections of the backup fire water system 

piping.

In its response dated May 21, 2014, the applicant revised Enhancement No. 10 for the Fire 

Water System program by providing information for additional inspections when wall-thickness 

measurements for recurring internal corrosion identify pipe degradation. The applicant 

proposed graduated inspection expansion criteria based on the extent of wall loss identified 

during these inspections. These criteria consisted of four, two, or no additional locations for wall 

loss greater than 50 percent, wall loss between 50 percent and 30 percent and the calculated 

remaining life is less than two years, or wall loss less than 30 percent, respectively. The 

applicant also revised LRA Sections A.2.1.18 and B.2.1.18, and Commitment No. 18, item 10, to 

reflect these criteria for additional inspection guidance. The staff finds the applicant’s response 

acceptable because the additional inspections performed by the applicant will, depending on the 

degree of wall loss identified, better quantify the extent of the recurring internal corrosion within 

the fire water system piping. The staff’s concern described in RAI 3.0.3.3.1-1 is resolved.

Conclusion. Based on the information provided, the staff concludes that the applicant 

appropriately identified and addressed recurring internal corrosion for the systems managed by 

the Open-Cycle Cooling Water System program and the Fire Water System program. By 

providing enhancements to both programs for augmented inspections, the staff concludes that 

the applicant met the criteria discussed in LR-ISG-2012-02, Section A, and 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).

3.0.3.3.2 Representative Minimum Sample Size for Periodic Inspections in GALL Report 

AMP XI.M38

Summary of Changes. By letter dated March 12, 2014, the applicant provided the results of its 

review and changes to the LRA 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.’”
3-12

Staff Evaluation. To ensure that the GALL Report AMP XI.M38 inspections include a 

representative sample, the staff revised the guidance through LR-ISG-2012-02 to specify the

minimum sample size, frequency, and inspection location. The revision included a provision to 

inspect 20 percent of a 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. 

In addition, the revision allows an inspection performed on a component in a more severe 

environment to be credited as an inspection performed in a less severe environment for the 

same material.

In its letter dated March 12, 2014, the applicant revised LRA Sections A.2.1.26, B.2.1.26, and 

Table A.5 to reflect the results of its review related to LR-ISG-2012-02, Section B. The 

applicant stated that it will revise its Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program to ensure that a representative sample of components is

inspected in each 10-year period during the period of extended operation. The applicant also 

stated that a representative sample of 20 percent of the population (defined as components 

having the same combination of material, environment, and aging effect) or a maximum of 

25 components per population will be inspected. Where practical, the applicant stated that the 

inspections will focus on the components most susceptible to aging due to time in service and 

severity of operating conditions. In addition to the minimum sampling, the applicant further 

stated that opportunistic inspections will continue in each 10-year period. 

The applicant also stated that an inspection conducted on a component in a more severe 

environment may be credited as an inspection for a component in a less severe environment 

when the material and aging effects are the same. Alternatively, similar environments can be 

combined into a larger population provided that the inspections occur on components located in 

the most severe environment. 

The staff finds the applicant’s revisions to its Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components program acceptable because the resulting sample size, 

inspection locations, and frequency are consistent with the recommendations in AMP XI.M38, 

as revised by LR-ISG-2012-02.

UFSAR Supplement Changes. The staff reviewed the changes to the UFSAR supplement 

description of the program as supplemented by letter dated March 12, 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 also noted that the revisions described 

are consistent with the applicant’s revisions to Commitment No. 26.

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 March 12, 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 

UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).
3-13

3.0.3.3.3 Fire Water System

Summary of Changes. By letter dated March 12, 2014, the applicant provided the results of its 

review of the changes regarding managing the aging effects associated with fire water systems 

in LR-ISG-2012-02 Section C, “Flow Blockage of Water-Based Fire Protection System Piping, 

GALL Report AMP XI.M27, ‘Fire Water System,’” and associated appendices.

Staff Evaluation. The applicant addressed each of the 16 recommended inspections and tests 

listed in LR-ISG-2012-02 AMP XI.M27, Table 4a, “Fire Water System Inspection and Testing 

Recommendations.” The staff’s evaluation of the applicant’s review follows.

Sprinkler Systems—Sprinkler Inspections. The staff noted that National Fire Protection 

Association (NFPA) 25 Section 5.2.1.1 recommends annual visual inspections of sprinklers. 

The applicant stated that the fire water system includes 120 in-scope sprinkler systems,

including wet pipe sprinkler systems, dry pipe preaction sprinkler systems, deluge systems, and 

deluge systems for charcoal filters. The Fire Water System program currently includes visual 

inspections of the majority of sprinkler systems for age-related degradation every 18 months 

consistent with the NRC-approved Fire Protection Program. Certain sprinkler systems that are 

not accessible during normal operation and are visually inspected at different intervals are as 

follows:

• Main and auxiliary transformer deluge systems are visually inspected during plant 

refueling outages but no less frequently than a refueling interval.

• Other transformer deluge systems are visually inspected on a 3-year frequency during 

the equipment outages.

• Visual inspection of nozzles for charcoal filter deluge systems is performed in 

conjunction with filter media replacement. Although no degradation has been identified 

during the visual inspections of the charcoal filter deluge systems, the program will be 

enhanced to perform the inspections once per refueling outage interval, coincident with 

filter media sampling and testing activities.

The applicant also stated that a review of plant-specific OE, including 669 sprinkler system 

procedure-driven inspections since 2000, has not revealed any age-related degradation that 

would warrant increasing the procedure driven sprinkler system visual inspections from every 

18 months to annually.

The staff reviewed the applicant’s program including the exception to NFPA 25 Section 5.2.1.1 

and finds it acceptable because: (a) consistent with the applicant’s statement regarding a lack 

of past inspection findings, the staff’s independent search of plant-specific OE during the audit 

did not reveal any evidence that age-related sprinkler degradation was occurring; (b) the 

inspection frequencies are consistent with the staff-approved Fire Protection Report for the 

applicant; and (c) there is a large enough number of sprinklers installed at the applicant’s site 

sufficient to establish an adverse performance trend, even with plant-specific inspections being 

completed less frequently than every 12 months.

Sprinkler Systems—Sprinkler Testing. The staff noted that NFPA 25 Section 5.3.1 recommends 

testing or replacement of sprinklers that have been in service for 50 years. The applicant stated 

that Enhancement No. 1 of the Fire Water System program already addresses sprinkler head 
3-14

replacement or testing in accordance with NFPA 25 Section 5.3.1.1.1. The enhancement states 

that sprinklers will be tested or replaced by their 50-year inservice date and every 10 years 

thereafter. The applicant revised LRA Sections A.2.1.18 and B.2.1.18 to update the referenced 

NFPA 25 edition for sprinkler testing from 2002 to 2011.

The staff finds the applicant’s program acceptable because it is consistent with LR-ISG-2012-02 

AMP XI.M27.

Standpipe and Hose Systems—Flow Tests. The staff noted that NFPA 25 Section 6.3.1 

recommends that a flow test be conducted every 5 years at the hydraulically most remote hose 

connections of each zone of the standpipe system as well as main drain tests. The applicant 

stated that the Fire Water System program includes a flow test at the hydraulically most limiting 

location in each major structure every 5 years and hose station flow and shutoff valve tests for 

each hose station every 3 years. The staff’s evaluation of main drain tests is documented below

in the Valves and System-Wide Testing evaluation.

The staff finds the applicant’s program acceptable because it is consistent with LR-ISG-2012-02 

AMP XI.M27.

Private Fire Service Mains—Underground and Exposed Piping Flow Tests. The staff noted that 

NFPA 25 Section 7.3.1 recommends that underground and exposed piping flow tests be 

conducted every 5 years to determine the internal conditions of the piping. The applicant stated 

that it conducts the following tests: (a) an underground main flow test is performed every 

18 months and, during the period of extended operation, at least once a year; (b) fire hydrant 

flow tests are performed annually; and (c) flow tests of the most hydraulically remote hose 

stations in each zone of the standpipe system are performed every 5 years.

The staff noted that, as stated in the Standpipe and Hose System—Flow Tests evaluation 

above, the applicant conducts hose station flow and shutoff valve tests for each hose station 

every 3 years. Also, the underground portions of the fire water system will be flow tested more 

frequently than recommended in NFPA 25. The staff reviewed the applicant’s program, 

including this exception to NFPA 25 Section 7.3.1, and finds the program acceptable because 

the underground piping is tested more frequently than recommended by NFPA 25 Section 7.3.1 

and the hose station tests provide insight into the internal condition of the associated portions of 

the exposed piping. This results in sufficient data for the applicant to determine if the internal 

condition of the underground and exposed piping is degrading.

Private Fire Service Mains—Hydrants. The staff noted that NFPA 25 Section 7.3.2 

recommends annual hydrant testing. The applicant stated that the Fire Water System program 

includes annual testing of fire hydrants.

The staff finds the applicant’s program acceptable because it is consistent with LR-ISG-2012-02 

AMP XI.M27 and annual testing of fire hydrants provides insights into the internal conditions in 

the underground and exposed fire water system piping.

Fire Pumps—Suction Screens. The staff noted that NFPA 25 Section 8.3.3.7 recommends 

inspection and cleaning of fire pump suction screens after testing or system actuations. The 

applicant stated that the fire pumps do not have suction screens. The water sources for the fire 

water system are the cooling tower basin and the plant SW system. The cooling tower supply 

does not have screens. The supply from the plant SW system, which connects to the fire water 
3-15

system downstream of the fire pumps, includes a duplex basket strainer that is cleaned based 

on differential pressure indication. The inspection and cleaning of the stay-fill supply basket 

strainer does not provide indication of the condition of the fire water system. Therefore, it is not 

necessary to clean this strainer after system tests or actuations.

The staff noted that LR-ISG-0212-02 AMP XI.M27, Table 4a, footnote 1, states, “[t]his table 

specifies those inspections and tests that are related to age-managing applicable aging effects 

associated with loss of material and flow blockage for passive long-lived in-scope components 

in the fire water system.” The staff finds the applicant’s program acceptable because there are 

no strainers upstream of the fire pumps and the material that would collect on the plant SW

system duplex basket strainer would not be indicative of conditions in the fire water system.

Water Storage Tanks—Exterior Inspections. The staff noted that NFPA 25 Section 9.2.5.5 

recommends that the exterior insulated surfaces and support structure of fire water storage 

tanks be inspected on an annual basis. The applicant stated that it would maintain the backup 

water storage tank in the scope of its Aboveground Metallic Tanks program, which has exterior 

inspections on a refueling outage interval. By letter dated April 24, 2014, the staff issued 

RAI 3.0.3.3.3-1 requesting that the applicant state why inspection of the backup water storage 

tank external insulated surfaces on a biennial basis is sufficient to provide reasonable 

assurance that the CLB intended function(s) of the backup water storage tank will be met for the 

period of extended operation or revise the program to conduct annual inspections.

In its response dated May 21, 2014, the applicant stated that the Aboveground Metallic Tanks 

program will be enhanced to include an annual visual inspection of the external surfaces of the 

tank’s insulation to detect potential evidence of deterioration of the spray-on polyurethane 

foam-type insulation or fiberglass fabric outer layer, or water intrusion. LRA Sections A.2.1.19 

and B.2.1.19 and Commitment No. 19 state that rips, tears, and gaps in the insulation skin will 

be repaired and evidence of water intrusion beneath the insulation will be evaluated in 

accordance with the CAP.

Based on inspections of the tank during the audit, the staff noted that, if the outer insulation skin 

remains intact, there is a low likelihood for water to penetrate to the tank’s external surface. The 

staff finds the applicant’s response and program acceptable because conducting annual 

external visual inspections of the fire water storage tanks is consistent with LR-ISG-2012-02 

AMP XI.M27 and the likelihood of loss of material on the external surfaces of the tank is very 

low as long as the outer insulation skin remains intact. The staff’s concern described in 

RAI 3.0.3.3.3-1 is resolved. The staff’s evaluation of managing corrosion under insulation (CUI)

for the fire water storage tanks is documented in SSER Section 3.0.3.3.5.

Water Storage Tanks—Interior Inspections. The staff noted that NFPA 25 Sections 9.2.6 and 

9.2.7 recommend that the internal surfaces of coated tanks be inspected every 5 years, and the 

inspections should include detection of pitting, corrosion, and local or general failure of the 

interior coating. The staff also noted that tanks on ring-type foundations with sand in the middle 

should be inspected for evidence of voids beneath the floor. The staff further noted that if loss 

of material or loss of coating integrity is detected, adhesion testing, dry film thickness 

measurements, ultrasonic testing (UT) thickness readings, wet-sponge testing, and vacuum box 

testing of the seams should be conducted. The staff noted that the applicant’s review of

Section D, “Revisions to the scope and inspection recommendations of GALL Report 

AMP XI.M29, ‘Aboveground Metallic Tanks,’” of LR-ISG-2012-02 stated that the backup water 

storage tank is internally coated and sits on a compacted oil-treated sand bed.
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The applicant stated that the Aboveground Metallic Tanks program includes internal surface 

visual inspections of the backup water storage tank conducted every 5 years and UT 

measurements of the tank bottom within 5 years prior to entering the period of extended 

operation and every 5 years thereafter. The applicant also stated that, if no tank bottom plate 

material loss is identified after the first two UT inspections, the volumetric inspections will be 

performed whenever the tank is drained during the period of extended operation. The program 

was further enhanced to:

• Perform visual inspections of the backup water storage tank wetted and nonwetted 

internal surfaces.

• Require that tank internal inspections be performed within 5 years before entering the 

period of extended operation and every 5 years thereafter.

• Require nondestructive examination of the tank bottom where visual inspection identifies 

pitting or general corrosion to below nominal wall thickness and to determine remaining 

wall thickness where bare metal has been exposed.

• Require that where pitting and general corrosion to below the nominal wall thickness 

occurs or any coating failure occurs in which bare metal is exposed, additional 

inspections and tests are performed, including adhesion testing of the coating in the 

vicinity of the coating failure and nondestructive examination to determine remaining wall 

thickness where bare metal has been exposed. In addition, adhesion testing will be 

performed in the vicinity of blisters even though bare metal may not be exposed.

The staff noted that not all of the testing and inspections recommended by NFPA 25 have been 

addressed by the applicant’s review and enhancements. By letter dated April 24, 2014, the staff 

issued RAI 3.0.3.3.3-2 requesting that the applicant state the basis for reasonable assurance 

that the backup water storage tank will meet its CLB intended function(s) without conducting: 

(a) inspections for evidence of voids beneath the floor; and (b) dry film thickness 

measurements, wet-sponge testing, and vacuum box testing of the seams if loss of material or 

loss of coating integrity is detected.

In its response dated May 21, 2014, the applicant stated the Aboveground Metallic Tanks 

program will be enhanced to include a statement that, if the drained tank internal surface 

inspections identify pitting, corrosion, or failure of the coatings, the tests in NFPA 25 

(2011 Edition) Section 9.2.7 will be performed. The applicant stated that, in some instances,

vacuum box testing may not be practical and, in such cases, a magnetic particle examination 

will be conducted on weld seams. The applicant further stated that the tank bottom will be 

inspected for voids in accordance with NFPA 25 (2011 Edition) Section 9.2.6.5.

The staff noted that the purpose of vacuum box testing is to detect crack and through-wall pits in 

welds that would result in leaks. The staff finds the applicant’s response and program 

acceptable because the tests and inspections of the internal surfaces of the tank will be 

consistent with LR-ISG-2012-02 AMP XI.M27 and because magnetic particle examinations are 

capable of detecting cracks and pits in welds. The staff’s concern described in RAI 3.0.3.3.3-2 

is resolved.

Valves and System-Wide Testing—Main Drain Test. The staff noted that NFPA 25, 

Section 13.2.5, recommends that a main drain test should be conducted annually at each fire 
3-17

water system riser. The applicant stated that the primary purpose of the test is to identify 

significant obstructions to flow such as a failed valve disc or mispositioned valve. The staff 

recognizes that NFPA 25 Section A.13.2.5 aligns with the applicant’s statement; however, the 

staff included main drain testing in LR-ISG-2012-02 AMP XI.M27 because the testing can also 

detect partial flow blockage due to corrosion product buildup.

The applicant stated that it does not perform a main drain test at each riser. The applicant 

described the alternative testing as follows:

• Flow testing is performed at the hydraulically most limiting location in each major 

structure every 5 years. The tests are conducted at a total of 20 risers including those 

located in each of the reactor and turbine enclosures, as well as the control and 

radwaste enclosure. The riser drain valves are 1-inch size and have limited flow 

capability. The higher flow rates through the fire hose station will reveal flow 

obstructions more readily than if the drain valves were used. In addition, the use of the 

drain valves does not include the risers or the distribution piping to hose stations and 

spray systems in the flow path and would not reveal any obstructions to flow in that 

piping. For each test, static pressure (no flow) is compared to the line pressure at test 

flow. Although the acceptance criteria for tests are location specific, an acceptance 

criterion of 20 [pounds per square inch differential] psid is typical. Test results are 

trended to identify if any corrective actions are required to maintain the design flowrates 

at these hydraulically limiting locations. Currently, all of these tests are performed in the 

same year. The Fire Water System program will be enhanced to schedule the 

performance of these tests such that a portion of the tests are performed each year 

throughout the 5-year cycle.

• Hose station flow and shutoff valve tests for each hose station are performed every 

3 years and consist of verifying hose station valve operability and flow through the 

connection with no indication of obstruction. This testing is performed on a total of 

144 hose stations distributed throughout each of the reactor and turbine enclosures, as 

well as the control and radwaste enclosure. In addition, three more hose stations in the 

turbine enclosures are tested on a refuel cycle frequency since they are not accessible 

during plant operation. These tests identify flow obstructions in the fire system piping 

and demonstrate that there are no significant changes in the condition of the piping 

system that could result in loss of intended function.

• The Fire Water System program will be enhanced to perform a representative sample of 

main drain tests on an annual basis. A main drain test will be performed in each of the 

reactor and turbine enclosures, as well as the control and radwaste enclosure. When 

there is a 10-percent reduction in full flow pressure compared to the original test or 

previously performed tests, the issue will be entered into the corrective action program 

for evaluation.

The staff reviewed this exception to NFPA 25 Section 13.2.5. Although the applicant has not 

proposed to perform a main drain test at each riser, the staff finds the exception and program 

acceptable because the proposed alternative and reduced scope main drain testing is sufficient 

to establish reasonable assurance that flow blockage will be detected prior to a CLB intended 

function not being met for the period of extended operation. The staff based this conclusion on: 

(a) the alternative flow tests, both in number and scope of locations, provide insights concerning 

potential accumulation of corrosion products that are comparable to those gained from 

conducting the main drain tests recommended in LR-ISG-2012-02 AMP XI.M27; (b) the number 
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of tests the applicant has proposed to perform (an average of 59 flow-related tests a year) which 

far exceeds the maximum of 25 inspections cited in random sampling programs recommended 

in GALL Report AMPs XI.M32, XI.M33, and XI.M38; and (c) the flow-related tests include six

annual main drain tests; and (d) the scope of testing, which will encompass piping located in six 

different buildings.

Valves and System-Wide Testing—Deluge Valves. The staff noted that NFPA 25, 

Sections 13.4.3.2.2 through 13.4.3.2.5, recommend that each deluge valve be trip tested 

annually at full flow. The staff also noted that NFPA 25 allows that, where the nature of the 

protected property is such that water cannot be discharged unless protected equipment is shut 

down (e.g., energized electrical equipment), a full flow system test can be conducted at the next 

scheduled shutdown, not to exceed 3 years. NFPA 25 also allows that, where the nature of the 

protected property is such that water cannot be discharged, the nozzles or open sprinklers are 

inspected for correct orientation and the system tested with air to ensure that the nozzles are 

not obstructed.

The applicant stated that there are 32 fire water deluge systems at the station, which vary in 

frequency of testing from an annual test to every 3 years. Fifteen of the systems are flow tested 

with water. Thirteen of the systems are flow tested with air. The remaining four systems are not 

part of the NRC-approved fire protection program and are not flow tested. The Fire Water 

System program will be enhanced to perform air testing on these four systems every 2 years. 

Visual inspections associated with the testing ensure that the patterns are not impeded by 

plugged nozzles. The fire water system also includes 19 deluge systems that are associated 

with heating ventilation and air conditioning system charcoal filters. The Fire Water System 

program will be enhanced to perform the charcoal filter deluge valve exercise testing and air 

flow nozzle testing on a refueling cycle frequency.

The staff finds the applicant’s program, with enhancement, acceptable because it is consistent 

with LR-ISG-2012-02 AMP XI.M27.

Water Spray Fixed Systems—Strainers. The staff noted that NFPA 25, Sections 10.2.1.6, 

10.2.1.7, and 10.2.7, as modified by LR-ISG-2012-02 AMP XI.M27, recommend removal, 

inspection, and cleaning of fire water system strainers after each actuation and every refueling 

outage interval. The applicant stated that the fire water system includes line strainers on the 

supply to several deluge headers for plant equipment. The Fire Water System program will be 

enhanced to inspect and clean these strainers after each deluge system actuation. Line 

strainers to deluge systems that are subject to full flow tests will be inspected and cleaned on a 

frequency consistent with the deluge system test frequency. The applicant also stated that 

cleaning strainers more frequently than the testing frequency does not provide any meaningful 

information about the condition of the deluge and fire water system piping since the only time 

the strainer has flow is during testing.

The staff reviewed this exception to inspecting strainers every refueling outage interval and the 

staff finds the exception and program acceptable because debris will not accumulate on the 

screens when there is no flow and the applicant will inspect the strainers after each actuation of 

the deluge system.

Water Spray Fixed Systems—Operation Test. The staff noted that LR-ISG-2012-02 AMP 

XI.M27, states that testing spray nozzle discharge patterns on a refueling outage interval is one

acceptable way to ensure that there are no obstructions to the discharge patterns. The staff 
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also noted that NFPA 25 Section 10.3.4.3 and LR-ISG-2012-02 AMP XI.M27 include a provision 

to allow for testing with air where water cannot be discharged due to the nature of the protected 

property. The applicant stated that, with the exception of the transformer deluge systems, the 

spray systems are located in areas where water cannot be discharged without impacting the 

protected property and critical equipment. The applicant also stated that:

• Air flow testing of dry pipe preaction spray headers to confirm no obstructions to flow will 

be conducted at a frequency of 3 years.

• Air flow testing of open deluge nozzles to confirm no plugged nozzles will be conducted 

at a frequency of 3 years.

• Air flow testing of deluge systems nozzles for charcoal filter systems to confirm no 

plugged flow nozzles will be conducted whenever the charcoal filter media is replaced. 

However, the Fire Water System program will be enhanced to perform air flow testing of 

the charcoal filter deluge systems every refueling interval.

• Water flow testing of transformer deluge nozzles to confirm no obstructions to flow will 

be conducted. The main power and auxiliary transformers are tested on a refueling 

cycle frequency and other transformer deluge systems are tested every 3 years.

• Water flow testing of wet pipe sprinkler systems spray headers to confirm the headers 

do not have any flow obstructions will be conducted at least every 18 months.

The staff noted that some of the inspection frequencies exceed a refueling outage interval. The 

staff also noted that the applicant did not provide a basis for the longer inspection intervals 

(e.g., plant-specific OE, alternative testing). By letter dated April 24, 2014, the staff issued 

RAI 3.0.3.3.3-3 requesting that the applicant state the basis for the longer inspection intervals 

associated with some water spray fixed systems operational testing.

In its response dated May 21, 2014, the applicant stated that the existing testing frequency is 

consistent with the NRC-approved fire protection program described in the plant-specific 

Technical Requirements Manual. The dry-pipe preaction spray headers are pressurized with 

dry instrument air. The applicant also stated that a review of testing conducted since 2000 

(210 air flow tests for dry-pipe preaction systems and 84 air flow tests for deluge systems) 

revealed only one instance of flow obstruction (February 2002). The applicant further stated 

that there are nine deluge systems associated with the main power and auxiliary transformers 

that are tested on a refueling cycle interval. There are six deluge systems associated with 

transformers for the offsite power distribution system for both reactor units. The Technical 

Specifications require that each reactor unit maintain two independent, physically separated, 

circuits between the offsite and onsite distribution systems. The applicant stated that the 3-year 

testing frequency of these six deluge systems balances offsite power availability and reliability of 

the equipment.

The staff noted that NFPA 25 (2011 Edition) Section 13.4.3.2.2.4 states that full flow testing 

[preaction valves and deluge valves] shall not exceed 3 years. The staff finds the applicant’s 

response and program for the dry pipe preaction spray headers acceptable because the 

likelihood of loss of material that could result in flow blockage is very low in a dry air 

environment and only 1 test out of 210 revealed a flow obstruction, with subsequent testing 

since February 2002 not revealing any obstructions, and therefore a 3-year interval of testing is 

acceptable. The staff finds the applicant’s response and program for the deluge systems 

acceptable because they are either tested on a refueling outage interval, which is consistent 
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with LR-ISG-2012-02 AMP XI.M27, or for those tested on a 3-year interval: (a) the applicant 

provided a reasonable availability versus reliability justification, (b) plant-specific OE

demonstrates a low likelihood of flow blockage, and (c) NFPA 25 allows a maximum 3-year 

interval for testing. The staff’s concern described in RAI 3.0.3.3.3-3 is resolved.

Foam Water Sprinkler Systems—Strainers. The staff noted that NFPA 25 Section 11.2.7.1, as 

modified by LR-ISG-2012-02 AMP XI.M27, recommends removal, inspection, and cleaning of 

foam water sprinkler system strainers after each actuation and every refueling outage interval. 

The applicant stated that the fire water system includes a foam system to provide fire protection 

for the fuel oil storage tank. The system is flow tested annually. The water supply line to the 

foam system includes a Y-strainer which is currently cleaned every 5 years concurrent with 

foam tank cleaning. The Fire Water System program will be enhanced to include inspection and 

cleaning of the foam water supply strainer after each foam system test or actuation and no less 

frequently than once per refueling interval.

The staff finds the applicant’s program acceptable because, with enhancement, it is consistent 

with LR-ISG-2012-02 AMP XI.M27.

Foam Water Sprinkler Systems—Operational Test Discharge Patterns. The staff noted that 

NFPA 25 Section 11.3.2.6, as modified by LR-ISG-2012-02, recommends an annual operational 

discharge test of foam water sprinkler systems to ensure that spray nozzles are not obstructed. 

Where the nature of the protected property is such that foam cannot be discharged, the nozzles 

are inspected for correct orientation and the system tested with air to ensure the nozzles are not 

obstructed. The applicant stated that the fire water system:

includes a foam system that discharges foam inside the fuel oil storage tank in 

the event of a fire. In this application, the foam cannot be discharged into the 

tank containing fuel oil to verify the foam nozzle is not obstructed for test 

purposes. A foam system flow test is performed annually which demonstrates 

the flow path for foam to the top of the fuel oil tank is unobstructed. The annual 

test also verifies that the foam hose reel station flow path is unobstructed. The 

flow path for the foam into the fuel oil tank interior includes a fixed foam maker 

and does not include spray nozzles. The foam maker is an air-aspirating 

discharge device designed to provide the required rate of foam solution with an 

air inlet to generate expanded foam. There are no small openings, similar to a 

nozzle, which could clog from corrosion products on the foam supply. As such, 

an air test of the foam maker to confirm no obstructions does not provide relevant 

information to assess the condition of the foam system piping.

The staff reviewed the applicant’s test method and the exception to checking for nozzle 

obstruction and finds it acceptable because the flow test is capable of detecting obstructions,

there are no small openings in the foam maker discharge device that could become blocked by 

corrosion products, the water supply Y-strainer is inspected on an annual basis (as described 

above) and these inspections are capable of detecting corrosion product accumulation, and the 

test is conducted annually.

Foam Water Sprinkler Systems—Storage Tanks. The staff noted that LR-ISG-2012-02 

AMP XI.M27 recommends that an internal visual inspection for corrosion be conducted every 

10 years for foam water sprinkler system storage tanks. The applicant stated that the Fire 

Water System program currently performs a tank internal inspection at least every 10 years.
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The staff finds the applicant’s program acceptable because it is consistent with LR-ISG-2012-02 

AMP XI.M27.

Obstruction Investigation—Obstruction, Internal Inspection of Piping. The staff noted that 

NFPA 25 Sections 14.2 and 14.3 provide recommendations for internal inspections of sprinkler 

piping. The applicant stated that the fire water system includes three types of sprinkler systems: 

wet pipe systems, dry pipe preaction systems, and deluge systems. The staff’s evaluation of 

the applicant’s proposal for each of these follows:

• Wet pipe sprinkler systems: The applicant stated that there are 31 wet pipe systems 

that are constantly filled with water and not subject to intermittent wet and dry conditions. 

Water flow testing of wet pipe sprinkler systems spray headers to confirm the headers 

do not have any flow obstructions is performed at least every 18 months by passing flow 

through the headers and system inspector’s test valve downstream of the sprinkler 

heads. A review of flow test results for the past 10 years did not reveal any instances of 

flow obstructions or blockage resulting from corrosion of internal surfaces. Draining 

water from the piping to allow visual internal inspections introduces a fresh supply of 

oxygen to support the corrosion process. In addition, the wet pipe sprinkler systems are 

each constructed of the same materials and exposed to the same process conditions 

and environments. Therefore, rather than drain all sprinkler systems every 5 years to 

perform internal inspections as recommended in LR-ISG-2012-02, the Fire Water 

System program will be enhanced for wet pipe sprinkler systems as follows: (a) solids 

discharged from the wet pipe sprinkler systems through the inspector’s test valve during 

flow testing will be collected and evaluated, and abnormal discharge or indication of 

obstructed flow will be entered into the corrective action program for evaluation; 

(b) visual internal inspections for corrosion and obstructions to flow will be performed on 

a 5-year frequency consistent with NFPA 25 with 5 of the 31 wet pipe sprinkler systems 

being selected for these internal inspections; and (c) an internal visual inspection will be 

performed after any wet pipe sprinkler system actuation prior to return to service.

The staff notes that introducing fresh water into a wet pipe sprinkler system does 

introduce new supplies of oxygen which can promote corrosion, and therefore,

alternative tests and inspections could result in less corrosion in the system. The staff 

finds the applicant’s exception to NFPA Section 14.2, with enhancements to the 

program, acceptable because: (a) flow tests are capable of detecting gross obstructions 

or blockage; (b) plant-specific results of flow testing to date have not revealed any 

instances of flow obstructions or blockage; (c) collecting solids discharged through the 

inspector’s test valve during flow testing will reveal any loose transportable corrosion 

products which can be addressed by the corrective action program; and (d) given that 

the internal environment is reasonably uniform throughout the system, the five internal 

inspections conducted in accordance with NFPA 25 would be capable of detecting fixed 

corrosion that could be causing obstructions and blockage (e.g., tubercules).

• Dry pipe preaction sprinkler systems: The applicant stated that there are 38 dry pipe 

preaction sprinkler systems that are normally dry and filled with pressurized air until 

actuated. The design for the preaction systems provides station instrument air to 

maintain the dry pipe preaction spray headers pressurized using dry air with a dew point 

normally less than −40°F. The dry pipe preaction sprinkler systems are not periodically 

tested with water. Therefore, the dry pipe preaction sprinkler systems are not subject to 

intermittent wet and dry conditions that promote corrosion of internal surfaces. The 
3-22

preaction water control valves are periodically serviced every refueling interval resulting 

in access to the spray header internal surfaces. The Fire Water System program will be 

enhanced to perform the following for dry pipe preaction sprinkler systems: (a) an 

internal visual inspection for evidence of corrosion and flow obstruction of the internal 

surfaces made accessible during the deluge valve maintenance activity every refueling 

interval, and (b) an internal visual inspection after any dry pipe preaction sprinkler 

system actuation prior to return to service.

The staff finds the applicant’s exception to NFPA Section 14.2 and enhancements to the 

program acceptable because: (a) consistent with GALL Report item AP-4, there is a 

very low likelihood of loss of material occurring on the internal surfaces of steel pipe 

exposed to dry air; and (b) given that the internal environment is reasonably uniform 

throughout the system, the visual inspections of surfaces made accessible during deluge 

valve maintenance would provide insights into whether flow blockage existed in any 

portions of the system.

• Deluge systems: The applicant stated that there are 51 deluge systems that are 

normally exposed to building air at atmospheric pressure. With the exception of the 

deluge systems for plant transformers, the deluge systems are not flow tested with 

water. The transformer deluge systems are periodically flow tested with water through 

the spray nozzles on either a 2-year or 3-year interval. Other deluge systems are not 

periodically tested with water and are not subject to intermittent wet and dry conditions 

that promote corrosion of internal surfaces. These deluge systems are air flow tested on 

a frequency of either 2 or 3 years to confirm that there are no obstructions to flow. 

Deluge valves that are automatically actuated are periodically serviced at least every 

3 years resulting in access to the spray header internal surfaces. The Fire Water 

System program will be enhanced to perform the following for deluge systems: 

(a) perform an internal visual inspection for evidence of corrosion and flow obstruction 

on a representative sample of deluge systems of the internal surfaces made accessible 

during the valve maintenance activity every 3 years; (b) the representative sample will 

include inspection of at least 10 of the 51 deluge systems; and (c) perform an internal 

visual inspection after any deluge system actuation prior to return to service.

The staff noted that for steel piping exposed to uncontrolled indoor air, GALL Report 

items E-25, E-29, and EP-42 recommend that loss of material be managed by GALL 

Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components.” AMP XI.M38 recommends that for each material, environment, 

and aging effect combination, 20 percent of the components (with a maximum of 25) 

should be inspected in each 10-year interval of the period of extended operation. The 

staff also noted that the applicant proposed to inspect a representative population of 

virtually 20 percent every 3 years. The staff finds the applicant’s exception to NFPA 

Section 14.2, and enhancements to the program, acceptable because: (a) the deluge 

systems are subjected to flow testing which could detect the presence of corrosion 

products that are not fixed; (b) given that the internal environment is reasonably uniform 

throughout the system, the internal inspection of a representative sample of 10 of the 

51 deluge systems every 3 years would provide insights into whether flow blockage 

existed in any portions of the system.

In summary, the staff finds that the proposed testing in accordance with NFPA 25 and 

alternative tests are sufficient to provide reasonable assurance that obstructions and blockage 

would be detected in the wet pipe systems, dry pipe preaction systems, and deluge systems.
3-23

The applicant also stated that, if degraded conditions are identified, the CAP will be used to 

perform an obstruction evaluation and determine the extent of condition and need for increased 

inspections. The staff finds this acceptable because it is consistent with NFPA 25 Section 14.3 

(e.g., Section 14.3.1, items 2, 4), as recommended by LR-ISG-2012-02 AMP XI.M27.

In addition to addressing each of the 16 recommended inspections and tests listed in 

LR-ISG-2012-02 AMP XI.M27 Table 4a, the applicant stated the following:

• The Fire Water System program will be enhanced to perform internal visual inspections 

described above to identify internal corrosion and obstructions to flow. If degraded 

conditions are identified, the corrective action program will be used to perform an 

obstruction evaluation and determine the extent of condition and need for increased 

inspections.

The staff found this acceptable because it is consistent with LR-ISG-2012-02 

AMP XI.M27.

• The Fire Water System program will be enhanced to conduct followup volumetric 

inspections if internal visual inspections detect surface irregularities that could be 

indicative of wall loss below nominal wall thickness.

The staff found this acceptable because it is consistent with LR-ISG-2012-02 

AMP XI.M27.

• As the result of industry operating experience, the sprinkler system piping configurations 

were reviewed and walkdowns were performed in 2012 to confirm that the piping was 

suitably sloped for drainage after system actuations or testing. The Fire Water System 

program will be enhanced to state that sprinkler and deluge systems that are normally 

dry but may be wetted as the result of testing or actuations will have augmented tests 

and inspections on piping segments that cannot be drained or piping segments that 

allow water to collect. These augmented inspections, if required, will be performed in 

each 5-year interval beginning 5 years prior to the period of extended operation and 

consist of either a flow test or flush sufficient to detect potential flow blockage or a visual 

inspection of 100 percent of the internal surface of piping segments that cannot be 

drained or piping segments that allow water to collect. In addition, in each 5-year 

interval of the period of extended operation, 20 percent of the length of piping segments 

that cannot be drained or piping segments that allow water to collect is subject to 

volumetric wall thickness inspections.

The staff found this acceptable because it is consistent with LR-ISG-2012-02

AMP XI.M27.

The staff noted that LRA Section B.2.1.18 was amended to reflect the addition of Enhancement

Nos. 3 through 9, as described above. The program was also enhanced (Enhancement No. 10) 

to address recurring internal corrosion in the backup fire water piping. The staff’s evaluation of 

this enhancement is documented in SSER Section 3.0.3.3.1.

UFSAR Supplement. The staff reviewed the changes to the UFSAR supplement description of 

the program as amended by letter dated March 12, 2014, and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1 as revised by LR-ISG-2012-02. The staff also 

noted that the enhancements described above are reflected as changes to Commitment No. 18.
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Conclusion. On the basis of its review of the proposed changes to the Fire Water System 

program as amended by letters dated March 12, 2014, and May 21, 2014, the staff determines 

that those program elements for which the applicant claimed consistency with LR-ISG-2012-02 

AMP XI.M27 are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determines that the AMP, with the exceptions, is adequate to manage the 

applicable aging effects. Also, the staff reviewed the enhancements and confirmed that their 

implementation through Commitment No. 18 prior to the period of extended operation will make 

the AMP adequate to manage the applicable aging effects. The staff concludes that the 

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

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.3.4 Aboveground Metallic Tanks

Summary of Changes. By letter dated March 12, 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 D, “Revisions to the Scope and Inspection Recommendations of GALL Report 

AMP XI.M29,” and associated appendices. The staff’s evaluation of the applicant’s revisions 

follows.

Staff Evaluation. To insure that the aging effects associated with tank surfaces are properly age 

managed, the staff revised its guidance (LR-ISG-2012-02, Section D, “Revisions to the Scope 

and Inspection Recommendations of GALL Report AMP XI.M29”) to include periodic internal 

visual examinations and surface inspections on the external surfaces of in-scope tanks. The 

revised guidance provided specific recommendations for inspection technique and frequency for 

tank surfaces depending on material, environment, and the applicable aging effect requiring 

management (AERM). In addition, the revised guidance included certain indoor large-volume 

tanks (e.g., greater than 100,000 gallons). The revised guidance also specifically excluded 

firewater storage tanks from the scope of GALL Report AMP XI.M29 and recommended use of 

GALL Report AMP XI.M27, as revised by LR-ISG-2012-02.

By letter dated March 12, 2014, the applicant revised LRA Sections A.2.1.19, B.2.1.19, and 

Commitment No. 19 for its Aboveground Metallic Tanks program, to address the staff’s

recommendations as described in LR-ISG-2012-02 Section D. 

In its letter dated March 12, 2014, the applicant stated that it does not have any indoor tanks 

that meet the staff’s updated guidance for inclusion into the Aboveground Metallic Tank GALL 

Report AMP XI.M29. The staff reviewed the applicant’s LRA and UFSAR and did not note any 

indoor storage tanks (e.g., greater than 100,000 gallons), that are in the scope of the revised 

GALL Report AMP XI.M29. The applicant also stated that it will continue to maintain the backup 

[fire] water storage tank in the scope of its Aboveground Metallic Tanks program. The staff’s 

evaluation of the inclusion of the backup water storage tank and associated changes to LRA 

Sections A.2.1.19 and B.2.1.19 and Commitment No. 19 is documented in SSER 

Section 3.0.3.3.3.
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3.0.3.3.5 Corrosion Under Insulation

Summary of Changes. By letter dated March 12, 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” (CUI) and associated appendices. The staff’s 

evaluation of the applicant’s revisions follows.

Staff Evaluation. To insure that loss of material and cracking underneath insulation are properly 

age-managed, the staff revised its guidance (LR-ISG-2012-02 Section E) to include the 

recommendation for examining surfaces underneath insulation and the condition of insulation 

jacketing. The recommended changes resulted in revisions to GALL Report AMPs XI.M29 and 

XI.M36, “Aboveground Metallic Tanks” and “External Surfaces Monitoring of Mechanical 

Components,” respectively. The revised guidance included recommendations to periodically 

(each 10-year period) inspect 20 percent of each population of in-scope components, with a 

maximum sample size of 25, during the period of extended operation. In addition, the revised 

guidance recommended that inspection locations be based on the likelihood of CUI occurring.

The applicant revised LRA Sections A.2.1.25, B.2.1.25, and Commitment No. 25 for its External 

Surfaces Monitoring of Mechanical Components program to address the staff’s

recommendations to manage CUI as described in LR-ISG-2012-02 Section E. The staff’s 

evaluation of the applicant’s revisions to its Aboveground Metallic Tanks program is 

documented in SSER Sections 3.0.3.3.3 and 3.0.3.3.4.

In its letters dated March 12, 2014, and May 21, 2014, the applicant stated that its External 

Surfaces Monitoring of Mechanical Components program will be revised to include a sample of 

outdoor component surfaces, except tanks, that are insulated and a sample of indoor insulated 

components exposed to condensation (due to the in-scope component’s being operated below 

the dewpoint). The sample size consists of a minimum of 20 percent of the in-scope piping 

length for each material type (i.e., steel, stainless steel, copper alloy, and aluminum), or, for 

components with configurations that do not conform to a 1-foot axial length determination 

(e.g., valves, accumulators), 20 percent of the surface area. An alternative approach is to 

remove the insulation and inspect any combination of a minimum of twenty-five 1-foot axial 

length sections and components for each material type. For indoor tanks, insulation will be 

removed from either twenty-five 1-square-foot sections or 20 percent of tanks surface area. 

Inspections will be conducted in each air environment (e.g., air-outdoor, moist air) in which 

condensation or moisture on the surfaces of the component could occur routinely or seasonally. 

Tank sample inspection points are distributed in such a way that inspections occur on the tank 

dome and sides, near the bottom, at points where structural supports or instrument nozzles 

penetrate the insulation, and where water might collect, such as on top of stiffening rings. The 

applicant also stated that these under-the-insulation inspections will be performed every 

10 years during the period of extended operation. The applicant further stated that inspections 

subsequent to the initial inspection will consist of examination of the exterior surface of the 

insulation for indications of damage to the jacketing or protective outer layer of the insulation if 

the initial inspection verifies no loss of material beyond that which could have been present 

during initial construction and no evidence of cracking. However, if the external visual 

inspections of the insulation reveal damage to the exterior surface of the insulation or if there is 

evidence of water intrusion through the insulation, then periodic under-insulation inspections to 

detect CUI will continue. 
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The applicant stated that the program does not require removal of tightly adhering insulation 

that is impermeable to moisture unless there is evidence of damage to the moisture barrier. 

The applicant stated that, instead, the program includes visual inspection of the entire 

accessible population of piping and components during each 10-year period of the period of 

extended operation. 

The staff finds the applicant’s LRA revisions to its External Surfaces Monitoring of Mechanical 

Components program acceptable because the applicant’s revisions to its 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.

UFSAR Supplement Changes. The staff reviewed the changes to the UFSAR supplement 

description of the program as amended by letters dated March 12, 2014, and May 21, 2014, and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1, as revised 

by LR-ISG-2012-02. The staff noted that the revision (inclusion of cracking) described in 

LRA Sections A.2.1.25, and B.2.1.25 was not incorporated into Commitment No. 25. The staff 

accepts this minor oversight because the UFSAR supplement includes a statement that the 

applicant must confirm that cracking is not present during the initial representative bare metal 

inspections under insulation in order to conduct future inspections of the insulation external 

surface in lieu of removing insulation. The UFSAR supplement would be used to evaluate the 

acceptability of future procedure changes.

Conclusion. On the basis of its review of the proposed changes to the External Surfaces 

Monitoring of Mechanical Components program as amended by letters dated March 12, 2014, 

and May 21, 2014, the staff determines that those program elements for which the applicant 

claimed consistency with LR-ISG-2012-02 AMP XI.M36 are consistent. The staff concludes that 

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

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.3.6 External Volumetric Examination of Internal Piping Surfaces of Underground Piping 

Removed from GALL Report AMP XI.M41

Summary of Changes. By letter dated March 12, 2014, the applicant provided the results of its 

review of the changes regarding managing the aging effects associated with internal surfaces of 

underground piping in LR-ISG-2012-02 Section F, “ External Volumetric Examination of Internal 

Piping Surfaces of Underground Piping Removed from GALL Report AMP XI.M41, “Buried and 

Underground Piping and Tanks” and associated appendices.”

Staff Evaluation. The staff noted that LR-ISG-2012-02 Section F revises GALL Report 

AMP XI.M38 to allow for the condition of the internal surfaces of buried and underground piping 

being assessed based on inspections of the interior surfaces of accessible piping where the 

material, environment, and aging effects are similar for both the accessible and the buried or 

underground components.

The applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program does not include any components in which this situation is 

applicable. Therefore, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 
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Components program is retained as described in the LRA Sections A.2.1.26 and B.2.1.26, 

LRA Table A.5 Commitment No. 26, and SER Section 3.0.3.1.16. Volumetric inspections of 

underground piping will remain part of the Buried and Underground Piping and Tanks program 

described in LRA Sections A.2.1.29 and B.2.1.29, LRA Table A.5 Commitment No. 29, and SER 

Section 3.0.3.2.12.

The staff finds the applicant’s proposal acceptable because the Buried and Underground Piping 

and Tanks program, Enhancement Nos. 3 and 4 adequately manage loss of material on the 

internal surfaces of underground piping by using volumetric examinations.

Conclusion. The staff has concluded that no changes are required to either the Internal 

Surfaces in Miscellaneous Piping and Ducting Components program or the Buried and 

Underground Piping and Tanks program. The programs are adequate to manage the applicable 

aging effects.

3.0.3.3.7 Specific Guidance for Use of the Pressurization Option for Inspecting Elastomers in 

GALL Report AMP XI.M38

Summary of Changes. By letter dated March 12, 2014, the applicant provided the results of its 

review of the changes regarding managing aging effects associated with elastomers in 

LR-ISG-2012-02 Section G, “Specific Guidance for Use of the Pressurization Option for 

Inspecting Elastomers in GALL Report AMP XI.M38,” and associated appendices.

Staff Evaluation. The staff noted that LR-ISG-2012-02 Section G revises GALL Report 

AMP XI.M38 to provide guidance for the inspection of elastomers by pressurization.

The applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program performs inspection of elastomeric materials with the 

manipulation option, as described in GALL Report AMP XI.M38. The pressurization option is 

not used. Therefore, there is no change to the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting program for this issue.

The staff finds the applicant’s proposal acceptable because physical manipulation is an 

adequate method to detect hardening and loss of strength in elastomers.

Conclusion. The staff has concluded that no changes are required to the Internal Surfaces in 

Miscellaneous Piping and Ducting Components program. The program is adequate to manage

the applicable aging effects.

3.0.3.3.8 Key Miscellaneous Changes to the GALL Report and SRP-LR

Summary of Changes. By letter dated March 12, 2014, the applicant provided the results of its 

review of the changes regarding managing aging effects associated with key miscellaneous 

changes in LR-ISG-2012-02 Section H, “Key Miscellaneous Changes to the GALL Report and 

SRP-LR,” and associated appendices.

Staff Evaluation. The staff noted that LR-ISG-2012-02 Section H addressed several 

miscellaneous changes to the GALL Report and SRP-LR. The staff’s evaluation of the 

applicant’s review of each follows:
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Revised Definition of Hardening and Loss of Strength. The staff noted that the definition of 

“hardening and loss of strength” in Section IX.E of the GALL Report was revised to replace the 

term “weathered” with the term “degraded” because weathering is generally associated with 

aging as a result of contact with outdoor weather conditions. In addition, cracking and loss of 

sealing were added to the examples associated with degraded elastomers. These changes 

provided a more complete list of aging effects and result in the definition’s being more 

consistent with program element 3, “parameters monitored or inspected,” of GALL Report 

AMP XI.M38. Likewise, program element 3, “parameters monitored or inspected,” of GALL 

Report AMP XI.M38 was revised to include loss of sealing.

The applicant stated that the aging management activities in the Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components are sufficient to identify the applicable aging 

mechanism for elastomers. No changes to the LRA or the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program are required to address this issue.

The staff noted that, based on its review of the LRA AMR items citing hardening and loss of 

strength as an aging effect (e.g., flexible connections, hoses, expansion joints, fire barriers), 

three more programs than stated by the applicant are used to manage the aging effect, 

including the Open-Cycle Cooling Water System, Fire Protection, and External Surfaces 

Monitoring of Mechanical Components programs. The staff finds the applicant’s proposal 

(i.e., no changes to the LRA) acceptable because the revised definition did not change the 

intent of the inspections of elastomeric materials for these programs.

Revised Definition of Elastomer Degradation. The staff noted that the definition of elastomer 

degradation in Section IX.F of the GALL Report was revised to include change in material 

properties as an aging effect example to make the definition more consistent with program 

element 3, “parameters monitored or inspected,” of GALL Report AMP XI.M38.

The applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program utilizes the elastomer manipulation option for inspecting 

elastomeric components, which is appropriate to detect change in material properties. No 

changes to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting program are 

required to address this issue.

The staff noted that, based on a review of the LRA AMR items associated with elastomer 

degradation, many more programs than stated by the applicant are used to manage the 

associated aging effects (e.g., hardening and loss of strength). Examples other than those cited 

in the above change include the Structures Monitoring, Metal Enclosed Bus, and 10 CFR 

Part 50 Appendix J programs. The staff finds the applicant’s proposal (i.e., no changes to the 

LRA) acceptable because the revised definition did not change the intent of the inspections of 

elastomeric materials for these programs.

Alternative AMP for Inspection of Polymeric Components. The staff noted that the LR-ISG 

clarified GALL Report AMP XI.M38 to allow internal surfaces of polymers to be inspected from 

the external surface when the material and environment combinations are the same.

The applicant stated that the external environment of those elastomers within the Internal 

Surfaces in Miscellaneous Piping and Ducting Components program is the air-indoor, 

uncontrolled environment. There are no LRA AMR items that utilize the air-indoor, uncontrolled 
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environment as the internal environment for any elastomer in this program, and therefore this 

provision is not applicable.

The staff finds the applicant’s proposal (i.e., no changes to the LRA) acceptable because the 

change only clarified the GALL Report AMP XI.M38 to allow an alternative to internal surface 

inspections that already existed in GALL Report AMP XI.M36, “External Surfaces Monitoring of 

Mechanical Components.”

Revised Definition of Fouling. The staff noted that the GALL Report definition of fouling was 

revised to be more reflective of the discussions in LR-ISG-2012-02 related to flow blockage of 

water-based fire protection system piping. Specifically the terms “flow or pressure” were added 

as consequences of fouling to the existing terms “reduction of heat transfer and loss of 

material.”

The applicant stated that the expanded definition of fouling does not impact the LRA and fouling 

caused by flow blockage specific to the fire protection systems is addressed in its response to 

Section C of LR-ISG-2012-02.

The staff finds the applicant’s proposal (i.e., no changes to the LRA) acceptable because

potential flow blockage was adequately addressed by enhancements to the Fire Water System 

program described in SSER Section 3.0.3.3.3.

High-Density Polyethylene Components. The staff noted that the SRP-LR and GALL Report 

were revised to add an AMR item for high-density polyethylene (HDPE) piping exposed to an 

underground environment.

The applicant stated that the additional AMR item does not impact the LRA because it does not 

have in-scope HDPE piping. 

The staff evaluated the applicant’s claim and finds it acceptable because the staff’s review of 

the LRA and UFSAR found that the applicant has no in-scope HDPE piping.

Waste Water Environment. The staff noted that the SRP-LR and GALL Report were revised to 

include waste water as an applicable environment for an existing AMR item, 3.3.1-72, 

associated with selective leaching.

The applicant stated that, while the revised item does apply to their site, the LRA already 

appropriately addresses selective leaching of gray cast iron in waste water in LRA 

Table 3.3.2-13. No changes to the LRA are required.

The staff evaluated the applicant’s proposal (i.e., no changes to the LRA) and finds it acceptable 

because, as documented in SSER Section 3.3.2.3.13, the applicant has appropriately 

addressed selective leaching of gray cast iron in waste water by managing this aging effect with 

the Selective Leaching program, which is consistent with LR-ISG-2012-02.

Components Exposed to Raw Water that Are Not Covered by NRC Generic Letter (GL) 89-13. 

The staff noted that the SRP-LR and GALL Report were revised to add AMR items for 

components exposed to raw water that are not covered by NRC GL 89-13, “Service Water 

System Problems Affecting Safety-Related Equipment.” The new AMR items recommend GALL 
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Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components.”

The applicant stated that the LRA already contains nonsafety-related components not covered 

by NRC GL 89-13 that are within the scope of the LGS Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program. No changes in the LRA are required.

The staff evaluated the applicant’s proposal (i.e., no changes to the LRA) and finds it acceptable 

because, as documented in SER Section 3.3.2.1.8, the applicant has appropriately addressed 

loss of material for components not covered by NRC GL 89-13 by managing this aging effect 

with the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

program, which is consistent with LR-ISG-2012-02.

Managing Loss of Material on the Internal Surfaces of Submerged Pump Casings. The staff 

noted that the SRP-LR and GALL Report were revised to allow the use of GALL Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components,” to manage loss of 

material on the internal surfaces of submerged pump casings exposed to waste water, as long 

as the material and environment combinations are the same for the internal and external 

surfaces.

The applicant stated that the situation of submerged pumps in a waste water environment is not 

applicable at LGS. No changes to the LRA are required.

The staff evaluated the applicant’s claim and finds it acceptable because the staff’s review of 

the LRA and UFSAR found that the applicant has no submerged pumps exposed externally to 

waste water.

Jacketed Insulation. The staff noted that the SRP-LR and GALL Report were revised to add 

jacketed insulation exposed to outdoor air and uncontrolled indoor air being managed with 

GALL Report AMP XI.M36 for degradation of thermal insulation due to moisture intrusion.

Changes to the LRA to address degradation of thermal insulation and the staff’s acceptance of 

the applicant’s proposal are documented in SSER Section 3.5.2.3.10.

Conclusion. The staff concludes that the applicant has adequately addressed the changes 

described in LR-ISG-2012-02 Section H.

3.0.3.4 Aging Management Related to Loss of Coating Integrity for Internal Coatings on 

In-Scope Mechanical SSCs

Summary of Changes. Based on reviews of LRAs and industry OE conducted by the staff, the 

staff identified an issue concerning loss of coating integrity of internal coatings of piping, piping 

components, heat exchangers, and tanks. By letter dated February 10, 2014, the staff issued 

RAI 3.0.3-1, requesting that the applicant address several questions associated with managing 

loss of coating integrity associated with coatings installed on the internal surfaces of in-scope 

piping, piping components, heat exchangers, and tanks. The staff’s evaluation of the response 

follows.

Staff Evaluation. Based on reviews of LRAs and industry OE conducted by the staff, the staff 

has determined that additional recommendations beyond those in the GALL Report are 
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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 

SSER section, the phrase “staff’s recommended actions to manage loss of coating integrity” 

refers to this subsection of the SSER.

• 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 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.
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• 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 Regulatory Guide (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 

twenty-five 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 seventy-three 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 to cover an equivalent length.

• 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 (all revisions) describes the methods the staff considers acceptable for training 

and qualification of individuals involved in coating inspections and evaluating degraded 

conditions.

• A preinspection 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 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 
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Service Level I coatings: (a) peeling and delamination shall not be permitted,

(b) cracking is not considered a failure unless it is accompanied by delamination or loss 

of adhesion, and (c) blisters shall be 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 use of a particular standard. Blisters should be limited to a few 

intact small blisters which 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.

 (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 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) Adhesion testing results, when conducted, meet or exceed the degree of adhesion 

recommended in engineering documents specific to the coating and substrate.

• Coatings that do not meet 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.

• The staff has also concluded that the UFSAR supplement for the program(s) used to 

manage loss of coating integrity should include statements to the effect that: (a) the 

program consists of visual inspections of coatings, (b) for coated surfaces determined to 

not meet the acceptance criteria, physical testing should be performed where physically 

possible (i.e., sufficient room to conduct testing) with the test consisting of destructive or 

nondestructive adhesion testing using ASTM International Standards endorsed in RG 

1.54, “Service Level I, II, and III Protective Coatings Applied to Nuclear Plants,” and (c) 
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the training and qualification of individuals involved in coating/lining inspections should 

be conducted in accordance with ASTM International Standards endorsed in RG 1.54.

In its response dated March 14, 2014, the applicant stated that there are nine in-scope systems 

with internal coatings, including the reactor enclosure cooling water (RECW) heat exchangers, 

main control room (MCR) chiller condenser, circulating water system piping, cement-lined 

portions of the fire water system piping (buried yard mains), EDG diesel oil storage tanks, 

reactor core isolation cooling (RCIC) system turbine bearing pedestals and high-pressure 

coolant injection (HPCI) system turbine bearing pedestals and oil reservoir, galvanized portions 

of the fire water system (transformer deluge system piping, foam extinguishing system piping), 

galvanized portions of the plant drainage system (normal waste, oily waste, sanitary waste, and 

storm drain piping), and fire water system backup water storage tank.

The applicant stated that coating inspections are not required for the following:

• Galvanized portions of the fire water system (transformer deluge system piping and 

foam extinguishing system piping): the applicant stated that galvanized piping is not 

subject to unanticipated or accelerated corrosion of the base metal due to coating 

holidays. In the case of galvanized steel, since zinc has a lower electrode potential than 

steel, the zinc coating acts as a large sacrificial anode coupled with a small cathode 

where the steel substrate is exposed in the coating holiday. Since there is a relatively 

small cathode surface and a relatively large anode surface, there is no accelerated 

corrosion. In regard to flow blockage, a 10-year search of plant-specific operating 

experience did not reveal any issues with delamination, blistering, flaking, or peeling in 

the transformer deluge system and foam extinguishing system galvanized piping. The 

Fire Water System program, as amended by letter dated March 12, 2014 (review of 

LR-ISG-2012-02), includes flow testing of the transformer deluge systems and foam 

extinguishing system. The flow tests for the main and auxiliary transformers are 

performed every 2 years, and for the other transformers the flow tests are performed 

every 3 years. The foam extinguishing system is flow tested annually. These flow tests 

verify the absence of blockage which could occur due to coating failure.

The staff acknowledges that the zinc-based coating would act as a sacrificial anode; 

however, there have been instances in the industry where the sacrificial coating has 

been consumed and the base metal corroded. By letter dated April 24, 2014, the staff 

issued RAI 3.0.3.4-1 Part (1) requesting that the applicant state how it will determine that 

an adequate amount of the coating remains intact throughout the period of extended 

operation for the galvanized portions of the fire water system.

In its response dated May 21, 2014, the applicant stated that the existing Fire Water 

System program enhancement associated with performing 10 internal visual inspections 

of the deluge systems to detect potential loss of material and flow obstructions was 

revised to state that 2 of the 10 inspections will be conducted on galvanized transformer 

deluge piping. These inspections will occur every 3 years.

The staff finds the applicant’s response acceptable because, in addition to flow tests that 

will provide direct indication of potential flow blockage, the applicant will conduct periodic 

visual inspections that are capable of detecting potential loss of the galvanized coating 

and any associated loss of material. The staff’s concern described in RAI 3.0.3.4-1 

Part (1) is resolved.
3-35

• Galvanized portions of the plant drainage system (normal waste, oily waste, sanitary 

waste, and storm drain piping): as stated above, galvanized piping is not subject to 

accelerated corrosion of the base metal caused by coating holidays. A 10-year search 

of plant-specific operating experience did not reveal any issues with delamination, 

blistering, flaking, or peeling in the galvanized normal waste, oily waste, and storm drain 

piping that could result in flow blockage. However, the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program, as amended by letter dated 

March 12, 2014 (review of LR-ISG-2012-02), will be used to manage the aging effect of 

loss of material, which is an indication of the loss of coating, in galvanized plant drainage 

system piping exposed to a waste water environment.

The staff noted that, in regard to unanticipated or accelerated corrosion of the base 

metal caused by coating holidays, based on a review of LRA Section 2.3.3.13, it is not 

likely that any of the in-scope components will be exposed to chemical compounds that 

could cause accelerated corrosion of the base material if coating degradation resulted in 

exposure of the base metal. The staff also noted that, as amended by letter dated 

March 12, 2014, the periodic inspections of a representative sample of each material, 

environment, and aging effect combination for the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components program can consist of inspecting 

components in a more severe environment. Given that the GALL Report definition of 

galvanized steel states, “[i]n the presence of moisture, galvanized steel is classified 

under the category ‘Steel,’” it is not clear to the staff whether the applicant would select 

uncoated steel pipe in lieu of galvanized pipe in developing the scope of the 

representative sample of steel piping exposed to waste water. The staff noted that, 

depending on the characteristics of the waste water environment (e.g., alternating 

wetting and drying), portions of the galvanized piping may be most susceptible to 

corrosion; although alternatively, it could be viewed as not susceptible because of the 

galvanic coating. By letter dated April 24, 2014, the staff issued RAI 3.0.3.4-1 Part (2) 

requesting that the applicant state whether the steel and galvanized steel portions of the 

plant drainage system (normal waste, oily waste, sanitary waste and storm drain piping) 

would be treated as two separate populations when determining a representative 

sample for the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program.

In its response dated May 21, 2014, the applicant stated that steel and galvanized steel 

components exposed to a moisture environment will be considered as in the same 

population; however, 10 of the 25 inspections will be of the normal waste, oily waste, 

sanitary waste and storm drain galvanized piping, and 15 of the internal inspections will 

be of the radioactive floor and equipment drain carbon steel piping. The LRA program 

and UFSAR supplement were revised accordingly.

The staff noted that treating steel and galvanized steel components exposed to a 

moisture environment as a single population is consistent with the definition of 

galvanized steel in GALL Report Section IX.C. The staff finds the applicant’s response 

and proposal to use the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components program to manage loss of material acceptable because, during 

each 10-year period of the period of extended operation, a sufficient quantity of 

galvanized piping and steel piping will be visually inspected to provide insight into the 

internal conditions of the drain piping. The staff’s concern described in RAI 3.0.3.4-1 

Part (2) is resolved.
3-36

In regard to potential flow blockage, the staff finds the applicant’s response and proposal 

to use the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components program to manage flow blockage acceptable because, although there is a 

low potential for flow blockage because galvanized coatings do not degrade in large 

cohesive sheets, the program will conduct periodic (not to exceed 10 years) internal 

visual inspections of a representative sample of the galvanized piping that are capable 

of ensuring that flow blockage does not occur.

The applicant also stated that the fire water system backup water storage tank internal coating 

is not addressed in the response to this RAI. The staff noted that the applicant addressed how 

loss of coating integrity would be managed for this tank in its response to LR-ISG-2012-02 

dated March 12, 2014. The staff’s evaluation of this response is documented in SSER 

Section 3.0.3.3.3.

Inspection Methods and Parameters Monitored. The applicant further stated that the coating 

inspection method will be visual inspections. Internal coatings will be inspected for signs of 

coating failures and precursors to coating failures including peeling, delamination, blistering, 

cracking, flaking, chipping, rusting, and mechanical damage. Coated surfaces that are 

accessible upon component disassembly or entry are visually inspected during each inspection 

interval. The staff finds the examination method, precursor indications, and extent of 

inspections acceptable because they are consistent with the staff’s recommended actions to 

manage loss of coating integrity.

Inspection Timing, Frequency and Extent. The applicant stated that coating inspection activities 

will be included in the following programs and described the inspection timing, frequency, and 

extent as follows:

Aging Management Program Components

Open-Cycle Cooling Water System RECW heat exchangers, MCR chiller 

condensers, circulating water system piping

Fire Water System Cement-lined portions of the fire protection 

system piping (buried yard mains)

Fuel Oil Chemistry EDG diesel oil storage tanks

Lubricating Oil Analysis RCIC turbine bearing pedestals and HPCI 

turbine bearing pedestals and oil reservoir

• RECW Heat Exchangers. The service water side of these heat exchangers is internally 

coated with an epoxy coating, which is currently inspected at a 2-year frequency as part 

of the Open-Cycle Cooling Water System program. These coatings are 

nonsafety-related. Failure of the coatings could result in unanticipated or accelerated 

corrosion of the base metal only. The service water side of the RECW heat exchangers 

is within the scope of the rule under 10 CFR 54.4(a)(2) for spatial interaction only. The 

coatings were last inspected in April 2012 (1A), October 2013 (1B), January 2013 (2A), 

and April 2013 (2B). The 1A, 1B and 2A heat exchangers had coating degradation that 

required repair or replacement. The coating of 2B heat exchanger was found to be in 

good condition. Since coating degradation that required repair or replacement has been 
3-37

identified in the service water side of the RECW heat exchangers, visual inspections at a 

2-year frequency are appropriate. Baseline inspections will occur in the 10-year period 

prior to the period of extended operation. The frequency of subsequent inspections will 

be established based on the baseline inspections.

The staff has concluded that one acceptable basis for alternative inspection frequencies 

would be to meet the following four conditions. The staff lacks sufficient information 

related to two of these four conditions (i.e., items 3 and 4 below).

 (1) The staff noted that, based on a review of LRA Tables 3.0-1 and 3.3.2-12, it would 

not be expected that the nonsafety-related service water system would contain 

chemical compounds that could cause unanticipated or accelerated corrosion of 

the base material if coating degradation resulted in exposure of the base metal.

 (2) The staff noted that the RECW heat exchangers are in scope for 

10 CFR 54.4(a)(2) spatial interaction only.

 (3) It is not clear to the staff whether the coated components are located in the vicinity 

of uncoated components that could cause a galvanic couple to exist.

 (4) The staff does not know whether the corrosion allowance used for the RECW heat 

exchangers assumed that the component was not coated.

In addition to the open questions on items 3 and 4 above, the response to 3.0.3-1 did 

not state an upper limit on the period of time prior to a subsequent internal coating 

inspection for the RECW heat exchangers, MCR chiller condensers (see below) and 

circulating water system piping (see below) and incorporate this limit into the 

Open-Cycle Cooling Water System program, UFSAR supplement, and Commitment 

No. 12. By letter dated April 24, 2014, the staff issued RAI 3.0.3.4-1 Part (3) requesting 

that the applicant provide the information on potential galvanic couple and corrosion 

allowance, state the maximum interval to subsequent coating inspections, and 

incorporate the inspection interval into the program, UFSAR supplement, and 

Commitment No. 12.

In its response dated May 21, 2014, the applicant stated that the maximum interval for 

subsequent inspections of the RECW heat exchangers, MCR chiller condensers and 

circulating water system piping will be consistent with draft LR-ISG-2013-01

AMP XI.M42, “Service Level III (augmented) Coatings Monitoring and Maintenance 

Program,” Table 4a, “Inspection Intervals for Service Level III (augmented) Coatings for 

Tanks, Piping, and Heat Exchangers.” The staff notes that draft LR-ISG-2013-01 was 

issued on January 6, 2014, ADAMS Accession No. ML13262A442. Commitment No. 12 

was revised accordingly.

The staff noted that the draft LR-ISG-2013-01 Table 4a is consistent with the staff’s 

recommended actions to manage loss of coating integrity and, therefore, the information 

related to potential galvanic couple and corrosion allowance is not required. The staff 

finds the applicant’s response and proposed inspection frequency for the RECW heat 

exchangers, MCR chiller condensers and circulating water system piping acceptable 

because conducting baseline inspections in the 10-year period prior to the period of 

extended operation and the subsequent inspection intervals are consistent with the 

staff’s recommended actions to manage loss of coating integrity; and revising 

Commitment No. 12 is sufficient to ensure that the AMP implementing documents will be 

revised appropriately. The staff’s concern described in RAI 3.0.3.4-1 Part (3) is 

resolved.
3-38

• MCR Chiller Condensers. The service water side of these heat exchangers is internally 

coated with an epoxy coating, which is currently inspected by the Open-Cycle Cooling 

Water System program (as part of GL 89-13, “Service Water System Problems Affecting 

Safety-Related Equipment,” program activities) at a 1-year frequency. These coatings 

are safety-related. The service water side of the MCR chiller condensers are within the 

scope of 10 CFR 54.4(a)(1). Failure of these coatings could result in unanticipated or 

accelerated corrosion of the base metal or could prevent a downstream in-scope 

component from satisfactorily performing its intended function. Baseline inspections will 

occur in the 10-year period prior to the period of extended operation. As discussed 

above in the staff’s evaluation of the RECW heat exchangers, the applicant has 

committed to perform subsequent inspections of the MCR chiller condensers with a 

frequency consistent with staff’s recommended actions to manage loss of coating 

integrity. Therefore, the staff finds the applicant’s proposed inspection frequency for 

these condensers acceptable.

• Circulating Water System Piping. Internal inspection of the coal tar coated circulating 

water system piping is currently being performed and will continue to be performed in 

the period of extended operation as part of Open-Cycle Cooling Water System program. 

These coatings are nonsafety-related. Failure of these coatings could result in 

unanticipated or accelerated corrosion of the base metal or could prevent a downstream 

in-scope component from satisfactorily performing its intended function. The coated 

portions of the in-scope circulating water piping will receive a baseline visual inspection 

within 10 years prior to the period of extended operation. The scope of the inspection 

will be seventy-three 1-foot axial sections. As discussed above in the staff’s evaluation 

of the RECW heat exchangers, the applicant has committed to perform subsequent 

inspections of the circulating water system piping with a frequency consistent with draft 

LR-ISG-2013-01 AMP XI.M42.

The staff finds the applicant’s proposed interval of inspections acceptable because 

conducting baseline inspections in the 10-year period prior to the period of extended 

operation, the scope of the inspections (i.e., seventy-three 1-foot axial sections), and the 

inspection intervals are consistent with the staff’s recommended actions to manage loss 

of coating integrity.

• Cement-Lined Portions of the Fire Protection System Piping. The internal surfaces of 

the buried cement lined fire main header is currently being managed and will continue to 

be managed in the period of extended operation by the Fire Water System program. 

This piping is normally inaccessible. Failure of the cement lining could result in 

unanticipated or accelerated corrosion of the base metal or could prevent a downstream 

in-scope component from satisfactorily performing its intended function. Currently the 

internal surfaces are not visually inspected. Instead, the cement lined fire main header 

is flow tested every 18 months and will be flow tested at least once every year in the 

period of extended operation as part of the Buried and Underground Piping and Tanks 

program. The flow test procedure measures system hydraulic resistance as a means of 

evaluating the internal piping conditions and verifying that degradation has not occurred. 

Additionally, the fire hydrants connected to the fire main header are flow tested annually. 

Evidence of flow blockage during these tests would provide an indication of main header 

cement liner degradation. Finally, a system flush is performed at least once per 

12 months as part of demonstrating system operability. These activities will continue 

through the period of extended operation. A review of plant-specific OE for the past 

10 years did not identify any failures in the cement lining of the fire water piping. 
3-39

Three opportunistic inspections performed during replacement of post indicating valves 

(PIV) did not identify degradation of the cement lining. Within 10 years prior to the 

period of extended operation, five additional inspections will be performed during PIV 

replacement activities. In addition, in October of 2012 Exelon Power Labs, LLC 

performed an opportunistic analysis of a portion of cement-lined pipe and identified that 

the inner cement lining was in good condition with no cracks identified. Opportunistic 

inspections of the cement lined pipe will continue to be performed during the period of 

extended operation as part of the Fire Water System program when normally 

inaccessible surfaces are made accessible due to required plant activities.

The staff noted that LRA Sections A.2.1.18 and B.2.1.18 state that, “[t]he fire water 

system is normally maintained at required operating pressure and is monitored such that 

loss of system pressure is immediately detected and corrective actions initiated.” The 

staff finds the applicant’s proposal to manage loss of the cement lining in the buried fire 

main header with the Fire Water System program acceptable because: (a) periodic 

header and fire hydrant flow tests are capable of detecting changes in flow resistance 

potentially indicative of cement lining debris buildup; (b) opportunistic inspections have 

not revealed any degradation of the cement lining; (c) opportunistic inspections will be 

performed during the period of extended operation; and (d) should localized cement 

lining degradation occur such that a through-wall hole occurs, the monitoring of 

operating pressure could detect the leak and corrective actions could be implemented 

prior to loss of the current licensing basis intended function(s) of the fire water system.

• Emergency Diesel Generator Diesel Oil Storage Tanks. Cleaning and internal 

inspection of the tanks is currently being performed and will continue to be performed in 

the period of extended operation as part of the Fuel Oil Chemistry program. The 

program includes periodic internal inspection of each fuel oil tank at least once during 

the 10-year period prior to the period of extended operation and at least once every 

10 years during the period of extended operation. Currently, these tanks are drained, 

cleaned, and inspected on a 10-year frequency. The sump area and bottom vertical foot 

of the tanks are coated with an epoxy coating. These coatings are safety-related. 

Failure of these coatings could result in unanticipated or accelerated corrosion of the 

base metal or could prevent a downstream in-scope component from satisfactorily 

performing its intended function. The internal coating of all eight of the tanks was last 

visually inspected in 2008. One tank was identified as having two areas of chipped 

coating in the bottom section of the sump which exposed the carbon steel substrate. 

A technical evaluation was performed by the site coating coordinator to evaluate the 

as-found coating defects. The coating damage was evaluated to be mechanical 

damage and not age-related degradation. Only a small amount of surface rust staining 

was visible on the exposed carbon steel. Significant rusting would not be expected 

since current fuel oil chemistry practices limit the amount of water, sediment, and 

particulate contamination collected in the tank. The edges of the damaged coating were 

scraped to sound coating, re-inspected, and found to have satisfactory adhesion. 

Several smaller chips were also identified on the sump side walls. Due to the nature of 

the defects, coating repair was not required. The technical evaluation concluded that 

the tank could be returned to service without recoating these areas where the coating 

had been chipped and that the inspection frequency of 10 years was still appropriate. 

Additionally, minor coating deficiencies were identified in three other tanks. These 

conditions were within acceptance criteria. However, baseline inspections will occur in 

the 10-year period prior to the period of extended operation. The frequency of 

subsequent inspections will be established based on the baseline inspections.
3-40

The staff noted that, 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 consistent with GALL Report AMP XI.M30 if no peeling, 

delamination, blisters, or rusting are observed during inspections, and cracking or flaking 

has been found acceptable, as documented in the staff’s recommended actions to 

manage loss of coating integrity. Therefore there is a basis for conducting inspections of 

fuel oil storage tank coatings on the 10-year inspection frequency in the Fuel Oil 

Chemistry program in lieu of a 6-year interval. However, as stated above, “a small 

amount of surface rust staining was visible” during tank inspections and therefore, the 

emergency diesel generator diesel oil storage tank coatings do not meet the above 

criteria (e.g., no rusting). The staff recognizes that an area of minor coating damage 

that has been characterized as not being age-related and where physical inspections 

demonstrate that there is sound coating and satisfactory adhesion in the vicinity of the 

degradation may warrant the extended inspection frequencies of GALL Report 

AMP XI.30. However, the response to RAI 3.0.3-1 and the associated program changes 

did not discuss other critical considerations for allowing a longer inspection interval when 

small areas of degraded coatings is detected including: (a) demonstration that sufficient 

wall thickness is available to ensure that the current licensing basis function of the tank 

can be met; (b) alternative indications that leakage is occurring (e.g., level 

instrumentation); and (c) the factors to be used by the applicant to determine if loose 

coatings could transport. In addition, the response to RAI 3.0.3-1 stated that, “[t]he 

frequency of subsequent inspections will be established based on the baseline 

inspections.” This statement appears to conflict with the specific inspection frequency 

specified in the Fuel Oil Chemistry program and the staff’s recommended actions to 

manage loss of coating integrity. By letter dated April 24, 2014, the staff issued 

RAI 3.0.3.4-1 Part (4) requesting that the applicant state the intent of the statement 

related to the subsequent inspection frequencies being determined based on the 

baseline inspection results; and, the basis for the periodicity of inspections for the 

emergency diesel generator diesel oil storage tank coatings if the prior inspection 

detected peeling, delamination, blisters, rusting, or unacceptable cracking and flaking.

In its response dated May 21, 2014, the applicant revised Commitment No. 20 to state 

that each fuel oil tank will be internally inspected at least once during the 10-year period 

prior to the period of extended operation and at least once every 10 years during the 

period of extended operation. The wording, “[t]he frequency of subsequent inspections 

will be established based on the baseline inspections” was deleted. The applicant also 

stated that:

o The current condition of the coating in the eight tanks is excellent with only minor 

mechanical damage (not age-related).

o Preventive actions in the Fuel Oil Chemistry program mitigate the potential for loss 

of material (e.g., oil sampling, periodic draining of accumulated water and 

sediment).

o The emergency diesel generator diesel oil storage tanks are equipped with level 

instrumentation and alarms that provide indication that leakage is occurring.

o Should coating debris transport from the tank, the engine-driven and motor-driven 

fuel pump piping located downstream from the tanks are each equipped with 

basket strainers and duplex filters. The strainers and filters have differential 

pressure instrumentation and high differential pressure alarms. During the monthly 
3-41

run of each diesel, basket strainer differential pressure and duplex filter inlet and 

outlet pressures are recorded.

o The acceptance criteria for coating degradation and requirements for physical 

inspections will be in accordance with program element 6 of draft LR-ISG-2013-01 

AMP XI.M42. Commitment No. 20 was revised accordingly.

The staff noted that the acceptance criteria and physical inspection recommendations of 

draft LR-ISG-2013-01 AMP XI.M42 include: (a) indications of peeling and delamination 

are not acceptable and the coatings are repaired or replaced, (b) blisters are evaluated 

by a coatings specialist qualified in accordance with an ASTM International standard 

endorsed in Regulatory Guide (RG) 1.54, “Service Level I, II, and III protective Coatings 

Applied to Nuclear Power Plants,” (c) the cause of blisters needs to be determined if the 

blister is not repaired, (d) physical testing is conducted to ensure that a blister is 

completely surrounded by sound coating bonded to the surface, (e) if coatings are 

credited for corrosion prevention, the component’s base material in the vicinity of a 

blister is inspected to determine if unanticipated corrosion has occurred, and 

(f) 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.

The staff finds the applicant’s response and proposal to manage the coatings using the 

Fuel Oil Chemistry program acceptable because: (a) plant-specific operating experience 

has demonstrated that only minor nonage-related coating damage has been noted to 

date, (b) only a small amount of surface rust staining was visible on the exposed carbon 

steel tank surface where the coating had been damaged and the applicant’s program will 

include a requirement to inspect the tank’s base material if the coating has been credited 

for corrosion prevention, (c) the tanks are equipped with level instrumentation and 

alarms that provide indication that leakage is occurring, and (d) basket strainer 

differential pressure and duplex filter inlet and outlet pressures are recorded during 

monthly diesel runs and these indications are capable of detecting potential coating 

debris. In summary, there is reasonable assurance that the loss of material will not 

result in the tank inventory leaking to below minimum required levels based on the Fuel 

Oil Chemistry program preventive actions and indications and alarms available to the 

operators; and coating debris would be promptly detected based on the monthly diesel 

runs. Additionally, the acceptance criteria and physical inspections of degraded 

coatings provide additional assurance that loss of material and coating debris would not 

impact the current licensing basis intended function(s) of the EDGs. The staff’s concern 

described in RAI 3.0.3.4-1 Part (4) is resolved.

• RCIC Turbine Bearing Pedestals and HPCI Turbine Bearing Pedestals and Oil 

Reservoir. The RCIC turbine bearing pedestals and HPCI turbine bearing pedestals and 

oil reservoir were originally coated internally with Rust-Ban ® paint. Failure of these 

coatings could result in unanticipated or accelerated corrosion of the base metal or could 

prevent a downstream in-scope component from satisfactorily performing its intended 

function. The pedestals and reservoir are managed by the Lubricating Oil Analysis 

program, which includes oil sampling and oil change activities that are capable of 

detecting coating degradation. The oil sampling includes testing for particulate in the oil, 

every 91 days, which would indicate degradation of the internal coating of the bearing 

pedestals and reservoir or of the base metal. The HPCI and RCIC turbine oil is drained 

each refueling outage during the turbine inspection. The HPCI oil reservoir is cleaned 

and inspected each refueling outage. The HPCI and RCIC bearing pedestals are also 
3-42

drained and opened each outage for bearing and drive accessory inspections. These 

inspections include a visual assessment of coating condition. Any internal coating that is 

found degraded during these periodic inspections is removed. The uncoated substrate 

is not recoated. The RCIC turbine bearing pedestals and HPCI turbine bearing 

pedestals and oil reservoir coating will receive a baseline visual inspection within 

10 years prior to the period of extended operation. The frequency of subsequent 

inspections will be established based on the baseline inspections. 

The staff noted that the response to RAI 3.0.3-1 states that failure of the coatings could 

result in unanticipated or accelerated corrosion of the base metal and yet it also states 

that degraded coatings are removed and the uncoated substrate is not recoated. The 

response also states that the internal coatings are inspected on a refueling outage basis; 

however, it also states that the frequency of subsequent inspections will be established 

based on the baseline inspections. The response to 3.0.3-1 did not state an upper limit 

on the period of time prior to subsequent internal coating inspections, and the response 

did not incorporate this limit into the program, UFSAR supplement, and Commitment 

No. 27. By letter dated April 24, 2014, the staff issued RAI 3.0.3.4-1 Part (5) requesting 

that the applicant state: (a) the basis for not recoating areas where the coating has 

been removed; and (b) the maximum interval to subsequent coating inspections and 

incorporate the inspection interval into the program, UFSAR supplement and 

Commitment No. 27.

In its response dated May 21, 2014, the applicant stated that the EPRI Terry Turbine 

Maintenance Guides for the RCIC and HPCI state to not attempt to repaint the surfaces 

of the oil reservoir or pedestals. The applicant clarified its response to RAI 3.0.3-1 that 

stated that failure of the coatings in the RCIC turbine bearing pedestals and HPCI 

turbine bearing pedestals and oil reservoir could result in unanticipated or accelerated 

corrosion of the base metal. The clarification stated that unanticipated or accelerated 

corrosion could occur if the lubricating oil has been contaminated (e.g., from moisture 

intrusion); however, when contaminants are not present, lubricating oil systems do not 

suffer appreciable loss of material since the environment is not conducive to corrosion. 

The Lubricating Oil Analysis AMP provides for sampling, analysis, and condition 

monitoring for the identification of specific wear products and contamination in the 

lubricating oil environments. Oil sampling frequency for the HPCI and RCIC systems is 

every 91 days. These activities ensure that the oil environment in the oil reservoir and 

pedestals is maintained within acceptable limits to prevent or mitigate age-related 

degradation. Therefore coating is not necessary to mitigate aging effects. The applicant 

further stated that baseline inspections for the RCIC turbine bearing pedestals and HPCI 

turbine bearing pedestals and oil reservoir will occur in the 10-year period prior to the 

period of extended operation and the maximum interval of subsequent coating 

inspections will be consistent with draft LR-ISG-2013-01 AMP XI.M42 Table 4a. 

Commitment No. 27 was revised accordingly. The revised Commitment No. 27 also 

states that the acceptance criteria for coating degradation and the requirements for 

physical inspections when degradation is identified will be in accordance with element 6 

of draft LR-ISG-2013-01 GALL Report AMP XI.M42.

The staff noted that Technical Report 1007460, “Terry Turbine Maintenance Guide, 

RCIC Application EPRI,” Section 19.2 states that turbine bearing pedestal degraded 

coatings should be removed and the surfaces not recoated. Likewise, Technical 

Report 1007459, “Terry Turbine Maintenance Guide, HPCI Application,” Section 4.3 

states that the oil reservoir should be inspected for flaking, blisters, and other signs of 
3-43

coating degradation and the surfaces not recoated and Section 19.2 states that for 

turbine bearing pedestals degraded coatings should be removed and the surfaces not 

recoated. The staff also noted that the EPRI documents were developed to provide 

improved maintenance practices that lead to improved turbine reliability.

The staff finds the applicant’s response and proposal to manage the coatings for the 

RCIC turbine bearing pedestals and HPCI turbine bearing pedestals and oil reservoir

using the Lubricating Oil Analysis program acceptable because: (a) the staff’s review of 

EPRI Technical Reports 1007460 and 1007459 confirmed that it is not recommended 

that the RCIC turbine bearing pedestal and HPCI turbine bearing pedestal and turbine 

oil reservoir be recoated when degraded coatings are removed, (b) the RCIC and HPCI 

turbine oil is sampled frequently enough to detect potential degraded coatings, 

(c) conducting baseline inspections in the 10-year period prior to the period of extended 

operation, the subsequent inspection intervals, the acceptance criteria for coating 

degradation, and the requirements for physical inspections when degradation is 

identified are consistent with the staff’s recommended actions to manage loss of coating 

integrity, and (d) revising Commitment No. 27 is sufficient to ensure that the AMP 

implementing documents will be revised appropriately. The staff’s concern described in 

RAI 3.0.3.4-1 Part (5) is resolved.

Training and Qualifications. The applicant described specific training and qualification 

requirements as follows.

• Examiners currently performing coating assessment inspections of the emergency diesel 

generator diesel oil storage tanks and MCR chiller condensers are qualified to at least 

one of the following: (a) ASTM D 4537-91, “Standard Guide for Establishing Procedures 

To Qualify and Certify Personnel Performing Coating Work Inspection in Nuclear 

Facilities,” and American National Standards Institute (ANSI) N45.2.6-1978, to a 

minimum of level II, or (b) VT-3 to a minimum of Level II including documented 

orientation in performing coating surveillance. Additionally, examiners currently 

performing GL 89-13 program inspections of the MCR chiller condensers are qualified to 

engineer certification guides, which include knowledge of EPRI TR-1019157, “Guideline 

on Nuclear Safety-Related Coatings,” Rev. 2 and a knowledge objective requirement to 

describe the inspection of coatings in heat exchangers. As amended by letter dated 

May 21, 2014, the applicant revised LRA Sections A.2.1.12 and B.2.1.12, and 

Commitment No. 12 to require that the inspections of the MCR chiller condensers and 

circulating water system piping will be performed by inspectors qualified to international 

standards endorsed in Regulatory Guide (RG) 1.54, “Quality Assurance Requirements 

for Protective Coatings Applied to Water-Cooled Nuclear Power Plants,” including 

ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II. In addition, as 

amended by letter dated May 21, 2014, the applicant revised LRA Sections A.2.1.27 and 

B.2.1.27, and Commitment No. 27 to require that the inspections of the RCIC turbine 

bearing pedestals and HPCI turbine bearing pedestals and oil reservoir will be 

performed by inspectors qualified to international standards endorsed in RG 1.54, 

including, ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.

The staff noted that examiner qualifications meeting the recommendations in RG 1.54 

are consistent with the staff’s recommended actions to manage loss of coating integrity. 

The staff finds the use of ASTM D 4537-91 and ANSI N45.2.6-1978 to qualify examiners 

acceptable because: (a) ASTM D 4537 is endorsed by RG 1.54, Revision 1; and (b) 

ANSI N45.2.6 certification is an acceptable basis for qualifying coatings inspectors 
3-44

based on RG 1.54, June 1973, Section C.1., which mandates conformance to the ANSI 

N45.2 quality assurance standards. The staff also noted that EPRI TR-1019157 

contains material on coating nomenclature, inspections of surface preparation and 

coating application, typical degradation mechanisms, and review and analysis of 

inspection results.

In regard to using a visual examination (VT-3) Level II qualified examiner to conduct 

coating inspections, the staff noted that ASME Code Section XI, “Rules for Inservice 

Inspection of Nuclear Power Plant Components,” Subarticle IWA-2300, “Qualification of 

Nondestructive Personnel,” and ASTM D 4537 contain similar vision testing and 

educational requirements. However, given that VT-3 examinations are associated with 

determining the general mechanical and structural condition of components and their 

supports, providing a “documented orientation in performing coating surveillance” lacks 

sufficient specificity for the staff to conclude that the orientation is equivalent to 

ASTM D 4537 Section 9, “Examination.” In addition, it is unclear to the staff whether a 

VT-3 Level II qualified examiner will have 3 or 6 months (depending on their education 

level) experience in coating inspection activities. By letter dated April 24, 2014, the staff 

issued RAI 3.0.3.4-1 Request (6) requesting that the applicant: (a) provide a sufficient 

level of detail related to the orientation in performing coating surveillances provided to 

inspectors for the staff to independently conclude that the orientation is consistent with 

ASTM D 4537 Section 9; and (b) state whether VT-3 Level II qualified examiners will 

have 3 or 6 months (depending on their education level) experience in coating 

inspection activities.

In its response dated May 21, 2014, the applicant stated that, “VT-3 qualified examiners 

will not be used for either the baseline or periodic inspection of coatings. Individuals 

performing the inspection of coatings will be qualified to international standards 

endorsed in RG 1.54, including, ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum 

of level II.” The LRA program, UFSAR supplement, and associated Commitment Nos.

12, 20, 27 for the Open-Cycle Cooling Water System, Fuel Oil Chemistry, and 

Lubricating Oil Analysis programs have been revised accordingly. 

The staff finds the applicant’s response acceptable because VT-3 inspectors will not be 

used to conduct coating inspections for in-scope components. The staff’s evaluation of 

the use of ASTM D 4537-91 and ANSI N45.2.6-1978 to qualify coatings inspectors is 

documented in the first section under Training and Qualifications, above. The staff’s 

concern described in RAI 3.0.3.4-1 Request (6) is resolved.

• The applicant also stated that, in the event the initial inspection of the emergency diesel 

generator diesel oil storage tanks and MCR chiller condensers is not performed by an 

ANSI N45.2.6 inspector and the coating condition is considered suspect or requires 

coating repair, then a qualified N45.2.6 inspector will perform a detailed inspection and 

oversee and inspect coatings recoats, touchups, or repair activities. This level of 

qualification will continue through the period of extended operation for these inspections.

The staff noted that the LRA program, UFSAR supplement, and associated 

Commitments Nos. 12, 20, 27 for the Open-Cycle Cooling Water System, Fuel Oil 

Chemistry, and Lubricating Oil Analysis programs contain similar wording. It is not clear 

to the staff why initial inspections that are not conducted by an ANSI N45.2.6 inspector 

would be credited as a baseline inspection. It is also not clear whether the statement 

“this level of qualification” refers to ANSI N45.2.6 qualified individuals or those without 

ANSI N45.2.6 qualifications.
3-45

By letter dated April 24, 2014, the staff issued RAI 3.0.3.4-1 Part (7) requesting that the 

applicant: (a) for the Open-Cycle Cooling Water System, Fuel Oil Chemistry, and 

Lubricating Analysis programs, state the basis for why inspections conducted by 

individuals who do not have an ANSI N45.2.6 qualification should be credited as a 

baseline inspection; and (b) clarify the intent of the statement, “this level of qualification.”

In its response dated May 21, 2014, the applicant stated that, “[i]ndividuals performing 

the inspection of coatings will be qualified to international standards endorsed in 

RG 1.54, including, ASTM D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.” 

The LRA program, UFSAR supplement, and associated Commitments Nos. 12, 20, 27 

for the Open-Cycle Cooling Water System, Fuel Oil Chemistry, and Lubricating Oil 

Analysis programs have been revised accordingly.

The staff finds the applicant’s response acceptable because personnel conducting 

baseline coating inspections will be qualified in accordance with standards endorsed in 

RG 1.54 or ANSI N45.2.6-1978. The staff’s evaluation of the use of ASTM D 4537-91 

and ANSI N45.2.6-1978 to qualify coatings inspectors is documented in the first section 

under Training and Qualifications, above. The staff’s concern described in RAI 3.0.3.4-1 

Part (7) is resolved.

• Examiners performing service water side inspections of the RECW heat exchangers are 

qualified to engineer certification guides, which include knowledge of EPRI TR-1019157 

and a knowledge objective requirement to describe the inspection of coatings in heat 

exchangers. This level of qualification will continue through the period of extended 

operation. This is acceptable because the service water side of the RECW heat 

exchangers is in scope for 10 CFR 54.4(a)(2) spatial interaction only. Therefore, coating 

failure will not prevent an in-scope component from satisfactorily accomplishing any of 

its functions due to flow blockage.

The staff noted that, as amended, the Open-Cycle Cooling Water System program, 

UFSAR supplement, and associated Commitment No. 12 did not include a requirement 

for these inspectors to have knowledge of EPRI TR-1019157 and a knowledge objective 

requirement to describe the inspection of coatings in heat exchangers. Without these 

requirements being included in the program, it is unclear to the staff whether they will be 

incorporated into plant-specific training documents for the period of extended operation. 

By letter dated April 24, 2014, the staff issued RAI 3.0.3.4-1 Part (8) requesting that the 

applicant amend LRA Sections A.2.1.12 and B.2.1.12, and Commitment No. 12, to state 

that these inspectors have knowledge of EPRI TR-1019157 and a knowledge objective 

requirement to describe the inspection of coatings in heat exchangers.

In its response dated May 21, 2014, the applicant revised LRA Sections A.2.1.12 and 

B.2.1.12, and Commitment No. 12 to state that coating inspections of the RECW heat 

exchanger will be conducted by inspectors with a demonstrated working knowledge of 

EPRI Report 1019157.

The staff finds the applicant’s response and the use of examiners with a demonstrated 

working knowledge of EPRI TR-1019157 to conduct inspections of the RECW heat 

exchangers acceptable because: (a) the GALL Report AMPs for programs inspecting 

the internal and external surfaces of other components in scope for 10 CFR 54.4(a)(2) 

spatial interaction only allow plant-specific qualifications for all inspections; (b) given that 

flow blockage is not an applicable aging effect, the purpose of the inspection is related to 

degradation of coatings that have exposed base metal, which is more easily detected 

than more minor indications of coating degradation, (c) the applicant’s response 
3-46

demonstrated that degraded coating conditions were detected by the examiners (see 

RECW Heat Exchangers, above); and (d) EPRI TR-1019157 contains sufficient 

information related to coatings and inspection parameters to appropriately orient 

inspectors to detect coating degradation related to exposure of base metal. The staff’s 

concern described in RAI 3.0.3.4-1 Part (8) is resolved.

Trending. The applicant stated that the as-found condition of coatings is documented in 

inspection reports or in completion remarks in the inspection work order. The results of 

previous inspections are used to determine changes in the condition of the coating over time. 

Trending of coating degradation is utilized to establish appropriate inspection frequencies for 

components with internal coatings.

The staff noted that the qualification level of the individual completing the inspection reports or 

completion remarks in the inspection work order was not stated. By letter dated April 24, 2014, 

the staff issued RAI 3.0.3.4-1 Part (9) requesting that the applicant state the qualification level of 

the individual completing the inspection reports or completion remarks in the inspection work 

order.

In its response dated May 21, 2014, the applicant stated that, with the exception of inspections 

of the RECW heat exchangers, inspection reports will be prepared by individuals qualified to 

ASTM D 4537 and ANSI N45.2.6. Inspection results for the RECW heat exchangers will be 

documented in a heat exchanger report by the inspector.

The staff finds the applicant’s response acceptable because, as documented above in Training 

and Qualifications, ASTM D 4537 and ANSI N45.2.6 are consistent with the staff’s 

recommended actions to manage loss of coating integrity and RECW heat exchanger 

examinations will be conducted by inspectors with a demonstrated working knowledge of EPRI 

Report 1019157. The staff’s concern described in RAI 3.0.3.4-1 Part (9) is resolved.

Acceptance Criteria. The applicant stated that inspections are performed for signs of coating 

failures and precursors to coating failures including peeling, delamination, blistering, cracking, 

flaking, chipping, rusting, and mechanical damage. Coating defects are entered into the CAP

for evaluation. As necessary, visual inspection may be supplemented by additional testing such 

as dry film thickness, adhesion, continuity, or other inspection technique as determined by the 

inspector to accurately assess coating condition.

The staff noted that the applicant did not state which precursors to coating failures would be 

considered not acceptable (e.g., peeling, delamination). The staff also noted that the applicant 

did not state the extent of blistering that would be found acceptable. By letter dated 

April 24, 2014, the staff issued RAI 3.0.3.4-1 Part (10) requesting that the applicant state which 

precursors to coating failures would be considered not acceptable and the extent of blistering 

that would be found acceptable.

In its response dated May 21, 2014, the applicant stated the acceptance criteria for peeling, 

delamination, blistering, cracking, flaking, and rusting will be in accordance with draft 

LR-ISG-2013-01 AMP XI.M42 program element 6. Commitment Nos. 12, 20, and 27 were 

revised accordingly.

The staff noted that the RAI response did not include concrete-related aging mechanisms 

(e.g., spalling); however, Commitment No. 12 states, “[t]he acceptance criteria for coating 
3-47

degradation and the requirements for physical inspections when degradation is identified will be 

in accordance with Element 6 of GALL Report AMP XI.M42 in draft LR-ISG-2013-01 dated 

January 6, 2014.” The staff finds the applicant’s response and acceptance criteria for the 

applicable programs acceptable because they are consistent with the staff’s recommended 

actions to manage loss of coating integrity and concrete acceptance criteria is included in 

program element 6 of draft LR-ISG-2013-01 AMP XI.M42. The staff’s concern described in 

RAI 3.0.3.4-1 Part (10) is resolved.

Corrective Actions. The applicant stated that currently the Site Coating Coordinator (not 

qualified in accordance with ASTM D 7108, “Standard Guide for Establishing Qualifications for a 

Nuclear Coatings Specialist”) provides oversight of safety-related coating activities and 

evaluates coating deficiencies. As stated in Enhancement No. 1 and Commitment No. 37 of the 

Protective Coating Monitoring and Maintenance Program, the position of Nuclear Coatings 

Specialist will be created prior to the period of extended operation. This individual will be 

qualified to ASTM D 7108.

It is not clear to the staff whether an individual qualified to ASTM D 7108 will evaluate the 

results of the baseline coating inspections conducted prior to the period of extended operation. 

It is also not clear to the staff whether testing or examination will be conducted to ensure that 

the extent of repaired or replaced coatings encompasses sound coating material. By letter 

dated April 24, 2014, the staff issued RAI 3.0.3.4-1 Request (11) requesting that the applicant 

state: (a) whether an individual qualified to ASTM D 7108 will evaluate the results of the 

baseline coating inspections conducted prior to the period of extended operation; and 

(b) whether testing or examination will be conducted to ensure that the extent of repaired or 

replaced coatings encompasses sound coating material.

In its response dated May 21, 2014, the applicant stated a coatings specialist qualified to 

ASTM D-7108 will evaluate baseline coating inspections conducted prior to the period of 

extended operation. Testing or examination (e.g., wet film thickness, dry film thickness, 

discontinuity, and adhesion) of repaired or replaced coating will be performed based on the type 

of coating system and type of repair. By letter dated June 4, 2014, the applicant amended LRA 

Sections A.2.1.12, A.2.1.20, and A.2.1.27 to state that the results of coating inspections will be 

evaluated by a coatings specialist qualified in accordance with ASTM D-7108.

The staff noted that the changes to Commitment Nos. 12, 20, and 27 to cite program element 6 

of draft LR-ISG-2013-01 AMP XI.M42 for acceptance criteria provides sufficient guidance to 

encompass the testing and examination statements because the “acceptance criteria” program 

element of AMP XI.M42 includes recommendations associated with physical testing. The staff 

finds the applicant’s response acceptable because appropriately qualified individuals will 

evaluate the results of coating inspections and because followup testing will be performed 

consistent with the staff’s recommended actions to manage loss of coating integrity. The staff’s 

concern described in RAI 3.0.3.4-1 Part (11) is resolved. 

UFSAR Supplement. The staff reviewed the changes to the UFSAR supplement descriptions of 

the programs used to manage loss of coating integrity as amended by letters dated 

March 12, 2014, May 21, 2014, and June 4, 2014, and noted that it contains adequate detail to 

manage the licensing basis associated with loss of coating integrity. The staff also noted that 

the enhancements described above are reflected as changes to Commitment Nos. 12, 20, and 

27.
3-48

Conclusion. On the basis of its review of the proposed changes to the Open-Cycle Cooling 

Water System, Fire Water System, Fuel Oil Chemistry, and Lubricating Oil Analysis programs 

as amended by letters dated March 14, 2014, May 21, 2014, and June 4, 2014, the staff 

determines that those program elements for which the applicant claimed consistency with the 

staff’s guidance are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determines that the AMPs, with the exceptions, are adequate to manage the 

applicable aging effects. Also, the staff reviewed the enhancements and confirmed that their 

implementation through Commitment No. 12, 18, 20, and 27 prior to the period of extended 

operation will make the AMPs adequate to manage the applicable aging effects. The staff 

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

managed so that the intended function(s) will be maintained consistent with the CLB for the 

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

UFSAR supplements for these AMPs and concludes that they provide an adequate summary 

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

3.1 Aging Management of Reactor Coolant System

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

3.2 Aging Management of Engineered Safety Features Section

3.2.2.3.3 High Pressure Coolant Injection System—Summary of Aging Management Review—

LRA Table 3.2.2-3

Gray Cast Iron Tank (with Internal Coatings) Exposed to Lubricating Oil. As amended by letter 

dated March 14, 2014, in LRA Tables 3.2.2-3 and 3.2.2-4, the applicant stated that gray cast 

iron tanks (with internal coatings) exposed to lubricating oil will be managed for loss of coating 

integrity by the Lubricating Oil Analysis program. The AMR items cite generic note H.

The staff’s evaluation of the acceptability of using the Lubricating Oil Analysis program to 

manage loss of coating integrity for the internal coatings of these tanks is documented in SSER 

Section 3.0.3.4.

On the basis of its review, the staff concludes for items in LRA Tables 3.2.2-3 and 3.2.2-4, that 

the applicant has appropriately evaluated the material and environment combinations not 

addressed in the GALL Report, and their intended function(s) will be maintained consistent with 

the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.2.2.3.4 Reactor Core Isolation Cooling—Summary of Aging Management Review—LRA 

Table 3.2.2-4

The staff’s evaluation for gray cast iron tanks (with internal coatings) exposed to lubricating oil, 

which will be managed for loss of coating integrity by the Lubricating Oil Analysis program and 

cite generic note H, is documented in SSER Section 3.2.2.3.3.

3.3 Aging Management of Auxiliary Systems
3-49

3.3.2.1.1 Loss of Material Due to General, Pitting, or Crevice Corrosion, and Cracking Due to 

Stress Corrosion Cracking 

LRA Table 3.3.1, item 3.3.1-132 addresses insulated steel, stainless steel, copper-alloy, 

aluminum, or copper-alloy (greater than 15 percent zinc) piping, piping components, and tanks 

exposed to condensation or air-outdoor, which will be managed for loss of material due to

corrosion and cracking due to stress-corrosion cracking (SCC). As amended by letter dated 

March 12, 2014, the applicant revised LRA Tables 3.3.2-16, 3.3.2-17, and 3.3.2-26 to state that 

insulated stainless steel piping and piping components exposed to indoor air environment will 

be managed for loss of material due to corrosion by the External Surfaces Monitoring of 

Mechanical Components program. The AMR items cite generic note A and include 

plant-specific notes 1 and 3, stating that the insulation for stainless steel components meets the 

requirements in NRC RG 1.36, “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.” 

Based on this, the applicant claimed that the levels of leachable contaminants are controlled so 

that SCC is not promoted; therefore, loss of material is the only AERM for this material and 

environment.

The staff reviewed the applicant’s claim that cracking was not an AERM. The staff noted that 

NRC RG 1.36 includes recommendations for qualification tests and chemical analyses to 

demonstrate that the ion concentrations of SCC-inducing leachable contaminants are within 

acceptable limits. The staff’s review of the applicant’s UFSAR did not identify instances of 

insulation with SCC-promoting leachable contaminants for the in-scope stainless steel piping. 

In addition, staff’s review of OE during its onsite audit did not reveal any instances of SCC for 

in-scope insulated stainless steel piping at the applicant’s facility. Based on the above, the staff 

finds the applicant’s claim acceptable. 

The staff concludes that for LRA item 3.3.1-132, associated with insulated stainless steel piping 

and piping components exposed to indoor environments, 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 for the period of extended operation as 

required by 10 CFR 54.21(a)(3).

3.3.2.1.18.1 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced 

Corrosion; and Fouling that Leads to Corrosion

LRA Table 3.3.1, item 3.3.1-64 addresses steel, copper-alloy piping, piping components, and 

piping elements exposed to raw water which will be managed for loss of material due to general, 

pitting, crevice, and microbiologically-influenced corrosion; and fouling that leads to corrosion. 

As amended by letter dated March 12, 2014, LRA Table 3.3.2-9 was revised to state that the 

internal surfaces of the backup fire water storage tank exposed to raw water would be managed 

for loss of material by the Aboveground Metallic Tanks program. This item cites generic note E. 

The staff’s evaluation of the applicant’s use of the Aboveground Metallic Tanks program to 

manage loss of material on the internal surfaces of the backup fire water storage tank is 

documented in SSER Section 3.0.3.3.3.

The staff finds the applicant’s proposal to manage aging of the internal surfaces of the backup 

fire water storage tank using the Aboveground Metallic Tanks program acceptable because the 

program has been enhanced to include tests and inspections that are consistent with 

LR-ISG-2012-02 AMP XI.M27.
3-50

The staff concludes that for LRA item 3.3.1-64, as cited for the backup fire water storage tank,

the applicant has demonstrated that the effects of aging for this component will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation as required by 10 CFR 54.21(a)(3).

3.3.2.1.18.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-89 addresses steel, copper-alloy piping, piping components, and 

piping elements exposed to moist air or condensation (internal) which will be managed for loss 

of material due to general, pitting, and crevice corrosion. As amended by letter dated 

March 12, 2014, LRA Table 3.3.2-9 was revised to state that the internal surfaces of the backup 

fire water storage tank exposed to air- or other gas–wetted (internal) would be managed for loss 

of material by the Aboveground Metallic Tanks program. This item cites generic note E. The 

staff’s evaluation of the applicant’s use of the Aboveground Metallic Tanks program to manage 

loss of material on the internal surfaces of the backup fire water storage tank is documented in 

SSER Section 3.0.3.3.3.

The staff finds the applicant’s proposal to manage aging of the internal surfaces of the backup 

fire water storage tank using the Aboveground Metallic Tanks program acceptable because the 

program has been enhanced to include tests and inspections that are consistent with 

LR-ISG-2012-02 AMP XI.M27.

The staff concludes that for LRA item 3.3.1-89, as cited for the backup fire water storage tank,

the applicant has demonstrated that the effects of aging for this component will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation as required by 10 CFR 54.21(a)(3).

3.3.2.3.8 Emergency Diesel Generator System—Summary of Aging Management Review—

LRA Table 3.3.2-8

Carbon Steel Tanks (with Internal Coatings) Exposed to Fuel Oil. As amended by letter dated 

March 14, 2014, in LRA Table 3.3.2-8, the applicant stated that carbon steel tanks (with internal 

coatings) exposed to fuel oil will be managed for loss of coating integrity by the Fuel Oil 

Chemistry program. The AMR item cites generic note H.

The staff’s evaluation of the acceptability of using the Fuel Oil Chemistry program to manage 

loss of coating integrity for the internal coatings of these tanks is documented in SSER 

Section 3.0.3.4.

On the basis of its review, the staff concludes for items in LRA Table 3.3.2-8, that the applicant 

has appropriately evaluated the material and environment combinations not addressed in the 

GALL Report, and their intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.9 Fire Protection System—Summary of Aging Management Review—LRA 

Table 3.3.2-9

Cement Piping, Piping Components, and Piping Elements and Carbon Steel Tanks (with 

Internal Coatings) Exposed to Raw Water. As amended by letter dated March 14, 2014, in LRA 

Table 3.3.2-9, the applicant stated that the cement piping, piping components, and piping 
3-51

elements and carbon steel tanks (with internal coating) exposed to raw water will be managed 

for loss of coating integrity by the Fire Water System and Aboveground Metallic Tanks 

programs, respectively. The AMR items cite generic note H. The staff noted that plant-specific 

note 11 clarifies that the piping is cement-lined versus being constructed from concrete.

The staff’s evaluation of the acceptability of using the Fire Water System and Aboveground 

Metallic Tanks programs to manage loss of coating integrity for these components is 

documented in SSER Sections 3.0.3.3.3 and 3.0.3.4.

On the basis of its review, the staff concludes for items in LRA Table 3.3.2-9, that the applicant 

has appropriately evaluated the material and environment combinations not addressed in the 

GALL Report, and their intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.12 Nonsafety-Related Service Water System—Summary of Aging Management 

Review—LRA Table 3.3.2-12

Carbon Steel Piping, Piping Components, Piping Elements, and Heat Exchangers (with Internal 

Coatings) Exposed to Raw Water. As amended by letter dated March 14, 2014, in LRA 

Tables 3.3.2-12, 3.3.2-22, and 3.4.2-1, the applicant stated that carbon steel piping, piping 

components, piping elements, and heat exchangers (with internal coating) exposed to raw water

will be managed for loss of coating integrity by the Open-Cycle Cooling Water System program. 

The AMR items cite generic note H.

The staff’s evaluation of the acceptability of using the Open-Cycle Cooling Water System 

program to manage loss of coating integrity for these components is documented in SSER 

Section 3.0.3.4.

On the basis of its review, the staff concludes for items in LRA Tables 3.3.2-12, 3.3.2-22, and 

3.4.2-1, that the applicant has appropriately evaluated the material and environment 

combinations not addressed in the GALL Report, and their intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.3.22 Safety Related Service Water System —Summary of Aging Management Review—

LRA Table 3.3.2-22

The staff’s evaluation for carbon steel piping, piping components, and heat exchangers (with 

internal coating) exposed to raw water, which will be managed for loss of coating integrity by the 

Open-Cycle Cooling Water System program and cite generic note H, is documented in SSER 

Section 3.3.2.3.12

3.4 Aging Management of Steam and Power Conversion Systems

3.4.2.1.1 Loss of Material Due to General, Pitting, or Crevice Corrosion, and Cracking Due to 

Stress Corrosion Cracking 

LRA Table 3.4.1, item 3.4.1-63 addresses insulated steel, stainless steel, copper-alloy, 

aluminum, or copper-alloy (greater than 15 percent zinc) piping, piping components, and tanks 

exposed to condensation or air-outdoor, which will be managed for loss of material due to 
3-52

corrosion and cracking due to SCC. As amended by letter dated March 12, 2014, the applicant 

revised LRA Tables 3.4.2-2 and 3.4.2-7 to state that insulated stainless steel piping and piping 

components exposed to indoor air environment will be managed for loss of material due to 

corrosion by the External Surfaces Monitoring of Mechanical Components program. The AMR 

items cite generic note A and include plant-specific notes 1 and 2, stating that the insulation for 

stainless steel components meets the requirements in NRC RG 1.36, “Nonmetallic Thermal 

Insulation for Austenitic Stainless Steel.” Based on this, the applicant claimed that the levels of 

leachable contaminants are controlled so that SCC is not promoted; therefore, loss of material is 

the only AERM for this material and environment.

The staff reviewed the applicant’s claim that cracking is not an AERM. The staff noted that NRC 

RG 1.36 includes recommendations for qualification tests and chemical analyses to 

demonstrate that the ion concentrations of SCC-inducing leachable contaminants are within 

acceptable limits. The staff’s review of the applicant’s UFSAR did not identify instances of 

insulation with SCC-promoting leachable contaminants for the in-scope stainless steel piping. 

In addition, staff’s review of OE during its onsite audit did not reveal any instances of SCC for 

in-scope insulated stainless steel piping at the applicant’s facility. Based on the above, the staff 

finds the applicant’s claim acceptable.

The staff concludes that for LRA item 3.4.1-63, associated with insulated stainless steel piping 

and piping components exposed to indoor environments, 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 for the period of extended operation as 

required by 10 CFR 54.21(a)(3).

3.4.2.3.1 Circulating Water System —Summary of Aging Management Review—LRA 

Table 3.4.2-1

The staff’s evaluation for carbon steel piping, piping components, and heat exchangers (with 

internal coating) exposed to raw water, which will be managed for loss of coating integrity by the 

Open-Cycle Cooling Water System program and cite generic note H, is documented in SSER 

Section 3.3.2.3.12.

3.5 Aging Management of Containments, Structures, and Component Supports

3.5.2.3.10 Piping and Component Insulation Commodity Group—Summary of Aging 

Management Evaluation

Calcium Silicate, Fiberglass, and Fiberglass Molded Insulation, and Insulation Jacketing 

Exposed to Air-Indoor Uncontrolled and Outdoor Air. By letter dated March 12, 2014, the 

applicant amended LRA Table 3.5.2-10 to state that calcium silicate, fiberglass, and fiberglass 

molded insulation, and insulation jacketing exposed to air-indoor uncontrolled and outdoor air 

will be managed for reduced thermal insulation resistance by the External Surfaces Monitoring 

of Mechanical Components program. These AMR items cite item 3.4.1-64 and generic note A. 

The amended table also states that cellular glass and ceramic fiber insulation, and insulation 

jacketing exposed to air-indoor uncontrolled and outdoor air will be managed for reduced 

thermal insulation resistance by the External Surfaces Monitoring of Mechanical Components 

program. These AMR items cite item 3.4.1-65 and generic note A.
3-53

The staff noted that LR-ISG-2012-02 added the two cited AMR items, 3.4.1-64 and 3.4.1-65, to 

address these material, environment, aging effect, and program combinations, and the staff 

confirmed the applicant’s claim of consistency. The staff concludes that for LRA items 3.4.1-64 

and 3.4.1-65, 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 for the period of extended operation as required by 10 CFR 54.21(a)(3).

Also, by letter dated March 12, 2014, the applicant amended LRA Table 3.5.2-10 to cite generic 

note F in lieu of generic note J for foamed plastic, Min-k, mineral fiber, and NUKON insulation, 

and insulation cement and finishing cement, and plastic mastic jacketing exposed to air-indoor 

uncontrolled and outdoor air, which will be managed for reduce thermal insulation resistance by 

the External Surfaces Monitoring of Mechanical Components program.

The staff’s evaluation of the applicant’s External Surfaces Monitoring of Mechanical 

Components program is documented in SER Section 3.0.3.1.15. The staff finds the applicant’s 

proposal to manage aging using the External Surfaces Monitoring of Mechanical Components 

program acceptable because, as amended by letter dated March 12, 2014, the program 

includes periodic inspections of either the bare metal surfaces under the insulation or the 

external surfaces of the insulation jacketing that are capable of detecting damage to the 

jacketing that would allow moisture penetration, which is consistent with the recommended 

approach in LR-ISG-2012-02.

3.6 Aging Management of Electrical and Instrumentation and Control Systems

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

4-1

SECTION 4 

TIME LIMITED AGING ANALYSES

The staff does not have any changes or updates to this section of the safety evaluation report.

5-1

SECTION 5 

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

The staff has provided the Advisory Committee on Reactor Safeguards with a copy of this 

supplemental safety evaluation report.

6-1

SECTION 6 

CONCLUSION

The staff concludes that the additional information provided by Exelon Generation 

Company, LLC, does not alter the conclusion proffered in the safety evaluation report issued in 

January 2013 and that the requirements of Title 10 of the Code of Federal Regulations

section 54.29(a) have been met. 

A-1

APPENDIX A 

LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE 

RENEWAL COMMITMENTS

During the review of the Limerick Generating Station (LGS), Units 1 and 2 license renewal 

application by the staff of the U.S. Nuclear Regulatory Commission, Exelon Generation 

Company, LLC (Exelon), made commitments related to aging management programs 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

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

1 Existing American Society of Mechanical Engineers (ASME)

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

program is credited.

A.2.1.1 Ongoing 

2 Existing Water Chemistry program is credited. A.2.1.2 Ongoing 

3 Existing Reactor Head Closure Stud Bolting program is credited. A.2.1.3 Ongoing 

4 Existing BWR Vessel ID Attachment Welds program is credited. A.2.1.4 Ongoing 

5 Existing BWR Feedwater Nozzle program is credited. A.2.1.5 Ongoing 

6 BWR Control Rod Drive Return Line Nozzle is an existing program 

that will be enhanced to:

1. Specify an extended volumetric inspection of the 

nozzle-to-cap weld to assure that the inspection includes 

base metal to a distance of one pipe wall thickness or 

0.5 inches, whichever is greater, on both sides of the weld.

A.2.1.6 Program to be 

enhanced before th

period of extended 

operation

7 Existing BWR Stress Corrosion Cracking program is credited. A.2.1.7 Ongoing 

8 Existing BWR Penetrations program is credited. A.2.1.8 Ongoing 
A-3

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

9 BWR Vessel Internals is an existing program that will be enhanced 

to:

1. Perform an assessment of the susceptibility of reactor 

vessel internal components fabricated from Cast 

Austenitic Stainless Steel (CASS) to loss of fracture 

toughness caused by thermal aging embrittlement. If 

material properties cannot be determined to perform the 

screening, they will be assumed susceptible to thermal 

aging for the purposes of determining program 

examination requirements.

2. Perform an assessment of the susceptibility of reactor 

vessel internal components fabricated from CASS to loss 

of fracture toughness caused by neutron irradiation 

embrittlement.

3. Specify the required periodic inspection of CASS 

components determined to be susceptible to loss of 

fracture toughness caused by thermal aging and neutron 

irradiation embrittlement.

A.2.1.9 Program to be 

enhanced before th

period of extended 

operation.

The initial 

inspections will be 

performed either 

before or within 

5 years after enterin

the period of 

extended operation

10 Existing Flow-Accelerated Corrosion program is credited. A.2.1.10 Ongoing 
A-4

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

11 Bolting Integrity is an existing program that will be enhanced to:

1. Provide guidance to ensure proper specification of bolting 

material, lubricant and sealants, storage, and installation 

torque or tension to prevent or mitigate degradation and 

failure of closure bolting for pressure retaining 

components.

2. Prohibit the use of lubricants containing molybdenum 

disulfide for closure bolting for pressure retaining 

components.

3. Minimize the use of high-strength bolting (actual measured 

yield strength equal to or greater than 150 ksi) for closure 

bolting for pressure retaining components. High-strength 

bolting, if used, will be monitored for cracking.

4. Perform visual inspection of bolting for the residual heat 

removal system, core spray system, high-pressure coolant 

injection system, and reactor core isolation cooling system 

suppression pool suction strainers for loss of material and 

loss of preload during each ISI inspection interval.

A.2.1.11 Program to be 

enhanced before th

period of extended 

operation
A-5

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

12 Open-Cycle Cooling Water System is an existing program that will 

be enhanced to:

1. Perform internal inspection of buried safety-related service 

water (SW) piping when it is accessible during 

maintenance and repair activities.

2. Perform periodic inspections for loss of material in the 

nonsafety-related SW system at a minimum of five 

locations on each unit once every refueling cycle.

3. Replace the supply and return piping for the core spray 

pump compartment unit coolers.

4. Replace degraded RHRSW piping in the pipe tunnel.

5. Perform periodic inspections for loss of material in the 

safety-related SW system at a minimum of 10 locations 

every 2 years.

The open-cycle cooling water system aging management program 

also manages the loss of coating integrity in the SW side of the 

main control room chiller condensers and reactor enclosure cooling 

water heat exchangers, and, in circulating water system piping.

A.2.1.12 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule 

as identified in the 

commitment
A-6

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

12 (continued) • As described below, baseline inspections will occur in the 

10-year period prior to the period of extended operation. The 

maximum interval of subsequent coating inspections will 

comply with Table 4a of GALL Report AMP XI.M42 in draft LRISG-2013-01 dated January 6, 2014 (ADAMS Accession 

No. ML13262A442).

• The inspection of the main control room chiller condensers will 

be performed by inspectors qualified to ASTM D 4537-91 and 

ANSI N45.2.6-1978 to a minimum of level II.

• The inspection of the reactor enclosure cooling water heat 

exchangers will be performed by inspectors with a 

demonstrated working knowledge of EPRI Report 1019157, 

“Guideline on Nuclear Safety-Related Coatings.” 

• The inspection of seventy-three 1-foot axial length 

circumferential segments of coated circulating water system 

piping will be performed by inspectors qualified to ASTM 

D 4537-91 and ANSI N45.2.6-1978 to a minimum of level II.

• The acceptance criteria for coating degradation and the 

requirements for physical inspections when degradation is 

identified will be in accordance with Element 6 of GALL Report 

AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014.
A-7

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

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LRA Section

Enhancement 

or 

Implementatio

Schedule

13 Closed Treated Water Systems is an existing program that will be 

enhanced to:

1. Perform condition monitoring and performance monitoring, 

including periodic testing and opportunistic and periodic 

NDE, to verify the effectiveness of water chemistry control 

to mitigate aging effects. A representative sample of 

piping and components will be selected based on 

likelihood of corrosion and inspected at an interval not to 

exceed once in 10 years during the period of extended 

operation.

2. Perform condition monitoring for the loss of material 

caused by cavitation erosion in the reactor enclosure 

cooling water piping to the 2A reactor water cleanup 

system (RWCU) nonregenerative heat exchanger. An 

initial inspection frequency of 4 years has been 

established. The inspection frequency will be re-evaluated 

and adjusted as necessary based on trend data.

A.2.1.13 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule 

as identified in the 

commitment
A-8

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

14 Inspection of Overhead Heavy Load and Light Load (Related to 

Refueling) Handling Systems is an existing program that will be 

enhanced to:

1. Perform annual periodic inspections as defined in the 

appropriate ASME B30 series standard for all cranes, 

hoists, and equipment handling systems within the scope 

of license renewal. For handling systems that are 

infrequently in service, such as those only used during 

refueling outages, annual periodic inspections may be 

deferred until just before use.

2. Perform inspections of structural components and bolting 

for loss of material caused by corrosion, rails for loss of 

material caused by wear and corrosion, and bolted 

connections for loss of preload.

3. Evaluate loss of material caused by wear or corrosion and 

any loss of bolting preload on cranes, hoists, and 

equipment handling systems per the appropriate 

ASME B30 series standard.

4. Perform repairs to cranes, hoists, and equipment handling 

systems per the appropriate ASME B30 series standard.

A.2.1.14 Program to be 

enhanced before th

period of extended 

operation

15 Compressed Air Monitoring is an existing program that will be 

enhanced to:

1. Perform periodic analysis and trending of air quality 

monitoring results.

A.2.1.15 Program to be 

enhanced before th

period of extended 

operation

16 Existing BWR reactor water cleanup system is credited. A.2.1.16 Ongoing 
A-9

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

17 Fire Protection is an existing program that will be enhanced to:

1. Provide additional inspection guidance to identify 

degradation of fire barrier walls, ceilings, and floors for 

aging effects such as cracking, spalling, and loss of 

material.

2. Provide additional inspection guidance for identification of 

excessive loss of material caused by corrosion on the 

external surfaces of the halon and carbon dioxide 

systems.

A.2.1.17 Program to be 

enhanced before th

period of extended 

operation
A-10

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

18 Fire Water System is an existing program that will be enhanced to:

1. Replace sprinkler heads or perform 50-year sprinkler head 

testing using the guidance of NFPA 25 “Standard for the 

Inspection, Testing and Maintenance of Water-Based Fire 

Protection Systems” (2011 Edition), Section 5.3.1.1.1. 

This testing will be performed before the 50-year inservice 

date and every 10 years thereafter.

2. Inspect selected portions of the water based fire protection 

system piping located aboveground and exposed to the 

fire water internal environment by non-intrusive volumetric 

examinations. These inspections shall be performed 

before the period of extended operation and will be 

performed every 10 years thereafter.

3. Inspect and clean line strainers for deluge systems after 

each actuation. Strainers for deluge systems subject to 

full flow testing will be inspected and cleaned on a 

frequency consistent with the deluge test frequency.

4. Inspect and clean the foam system water supply strainer 

after each system actuation and no less than once per 

refueling interval.

5. Perform external visual inspection of deluge piping and 

nozzles for the HVAC charcoal filters for signs of leakage, 

corrosion, physical damage, and correct orientation once 

per refueling interval.

6. Perform flow tests for the hydraulically most remote hose 

stations once every 5 years, scheduling the testing so that 

some of the tests are performed in each year of the 5-year 

interval.

A.2.1.18 Program to be 

enhanced before th

period of extended 

operation
A-11

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

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LRA Section

Enhancement 

or 

Implementatio

Schedule

18 (continued) 7. Perform a main drain test annually for the fire water piping 

in each of the following locations: Unit 1 Reactor 

Enclosure, Unit 2 Reactor Enclosure, Unit 1 Turbine 

Enclosure, Unit 2 Turbine Enclosure, Control Enclosure, 

and Radwaste Enclosure. Flow blockage or abnormal 

discharge identified during flow testing or any change in 

pressure during the test greater than 10% at a specific 

location is entered into the corrective action program for 

evaluation.

8. Perform charcoal filter deluge valve exercise testing and 

air flow testing at least once per refueling interval and 

perform air flow testing for the deluge systems for the 

hydrogen seal oil units and lube oil reservoirs every 

2 years.
A-12

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

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Enhancement 

or 

Implementatio

Schedule

18 (continued) 9. Perform the following for fire water system sprinkler and

deluge systems:

• Perform visual internal inspections, consistent with 

NFPA 25, for corrosion and obstructions to flow on at 

least five wet pipe sprinkler systems every 5 years.

• Collect and evaluate solids discharged from wet pipe 

sprinkler system flow testing. Flow testing through 

the inspector's test valve will be performed on an 

interval no greater than 18 months for each wet pipe 

system.

• Perform visual internal inspections for corrosion and 

obstructions to flow for dry pipe preaction sprinkler 

systems of surfaces made accessible when preaction 

and water deluge valves are serviced on an interval 

no greater than a refueling interval.

• Perform visual internal inspections for corrosion and 

obstructions to flow for deluge systems of surfaces 

made accessible when deluge valves are serviced on 

at least 10 deluge systems on an interval no greater 

than 3 years. To provide reasonable assurance of the 

presence of sufficient coating, two of the ten 

inspections will be associated with the galvanized 

transformer deluge system piping. 

• Perform a visual internal inspection for corrosion and 

obstructions to flow for any wet pipe, dry pipe 

preaction, or deluge system after any system 

actuation prior to return to service.
A-13

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

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LRA Section

Enhancement 

or 

Implementatio

Schedule

18 (continued) (9. continued)

• Perform an obstruction evaluation for conditions that 

indicate degraded flow.

• Perform followup volumetric inspections for pipe wall 

thickness if internal visual inspections detect surface 

irregularities that could be indicative of wall loss below 

nominal wall thickness.

• Sprinkler and deluge systems that are normally dry 

but may be wetted as the result of testing or 

actuations will have augmented tests and inspections 

on piping segments that cannot be drained or piping 

segments that allow water to collect. These 

augmented inspections will be performed in each 

5-year interval beginning 5 years prior to the period of 

extended operation and consist of either a flow test or 

flush sufficient to detect potential flow blockage or a 

visual inspection of 100% of the internal surface of 

piping segments that cannot be drained or piping 

segments that allow water to collect. In addition, in 

each 5-year interval of the period of extended 

operation, 20% of the length of piping segments that 

cannot be drained or piping segments that allow water 

to collect is subject to volumetric wall thickness 

inspections.
A-14

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

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Enhancement 

or 

Implementatio

Schedule

18 (continued) 10. Perform wall thickness measurements using UT or other 

suitable techniques at five selected locations every year to 

identify loss of material in the carbon steel backup fire 

water piping. When these examinations identify pipe 

degradation, additional examinations will be performed in 

accordance with the following criteria:

• At least four additional locations will be examined if 

wall loss is greater than 50% of nominal wall 

thickness, 

• Two additional locations will be examined if wall loss 

is 30% to 50% of nominal wall thickness and the 

calculated remaining life is less than 2 years, 

• No additional examinations will be performed if wall 

loss is less than 30% of nominal wall thickness. 

The Fire Water System aging management program also manages 

the loss of coating integrity in the buried cement lined fire main 

header.

• System flow testing activities measure system hydraulic 

resistance as a means of evaluating the internal piping 

condition. 

• Opportunistic internal inspections evaluate the condition of the 

cement lined fire main header.

• Within 10 years prior to the period of extended operation, five 

internal visual inspections of the cement lining in the fire main 

header will be performed.
A-15

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

19 Aboveground Metallic Tanks is an existing program that will be 

enhanced to:

1. Include ultrasonic testing (UT) measurements of the 

bottom of the backup water storage tank. Tank bottom UT 

inspections will be performed within 5 years before 

entering the period of extended operation and every 

5 years thereafter. If no tank bottom plate material loss is 

identified after the first two inspections, the remaining 

inspections will be performed whenever the tank is drained 

during the period of extended operation.

2. Provide visual inspections of the backup water storage 

tank external surfaces and include, on a sampling basis, 

removal of insulation to permit inspection of the tank 

surface. An inspection performed prior to entering the 

period of extended operation will include a minimum of 

25 locations to demonstrate that the tank painted surface 

is not degraded under the insulation. Subsequent tank 

external surface visual inspection will be conducted on a 

2-year frequency and include a minimum of four locations. 

Annual visual inspections will be performed of the tank 

insulation surface for degradation. Rips, tears, and gaps

in the insulation skin will be repaired. Evidence of water 

intrusion beneath the insulation will be evaluated in 

accordance with the LGS corrective action program.

A.2.1.19 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule 

as identified in the 

commitment
A-16

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

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Enhancement 

or 

Implementatio

Schedule

19 (continued) 3. Perform visual inspections of the backup water storage 

tank wetted and nonwetted internal surfaces. Tank 

internal inspections will be performed within 5 years prior 

to entering the period of extended operation and every 

5 years thereafter. The tank bottom will be inspected for 

evidence of voids beneath the floor in accordance with 

NFPA 25, Section 9.2.6.5. Where pitting and general 

corrosion to below the nominal wall thickness occurs or 

any coating failure occurs in which bare metal is exposed, 

additional inspections and tests shall be performed in 

accordance with NFPA 25, Section 9.2.7. These tests 

include adhesion testing of the coating in the vicinity of the 

coating failure, dry film thickness measurements, spot wet 

sponge testing, and nondestructive examination to 

determine remaining wall thickness where bare metal has 

been exposed. Tank bottom weld seams in the area of 

degraded coating will be leak tested in accordance with 

NFPA 25, Section 9.2.7, by vacuum-box testing or 

magnetic particle (MT) examination. In addition, adhesion 

testing shall be performed in the vicinity of blisters even 

though bare metal may not be exposed.
A-17

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

20 Fuel Oil Chemistry is an existing program that will be enhanced to:

1. Periodically drain water from the fire pump engine diesel 

oil day tank and the fire pump diesel engine fuel tank.

2. Perform internal inspections of the fire pump engine diesel 

oil day tank, the fire pump diesel engine fuel tank, and the 

diesel generator day tanks, at least once during the 

10-year period before the period of extended operation 

and at least once every 10 years during the period of 

extended operation. Each diesel fuel tank will be drained, 

cleaned and the internal surfaces either volumetrically or 

visually inspected. If evidence of degradation is observed 

during visual inspections, the diesel fuel tanks will require 

followup volumetric inspection.

3. Perform periodic analysis for total particulate 

concentration and microbiological organisms for the fire 

pump engine diesel oil day tank and the fire pump diesel 

engine fuel tank.

4. Perform periodic analysis for water and sediment and 

microbiological organisms for the diesel generator diesel 

oil storage tanks.

5. Perform periodic analysis for water and sediment content, 

total particulate concentration, and the levels of 

microbiological organisms for the diesel generator day 

tanks.

6. Perform analysis of new fuel oil for water and sediment 

content, total particulate concentration and the levels of 

microbiological organisms for the fire pump engine diesel 

oil day tank and the fire pump diesel engine fuel tank.

A.2.1.20 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule

as described in the 

commitment
A-18

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

20 (continued) 7. Perform analysis of new fuel oil for total particulate 

concentration and the levels of microbiological organisms 

for the diesel generator diesel oil storage tanks.

The Fuel Oil Chemistry aging management program also manages 

the loss of coating integrity in the eight main fuel oil storage tanks. 

• Each fuel oil tank will be internally inspected at least once 

during the 10-year period prior to the period of extended 

operation and at least once every 10 years during the period of 

extended operation

• The inspection of the eight main fuel oil storage tanks will be 

performed by inspectors qualified to ASTM D 4537-91 and 

ANSI N45.2.6-1978 to a minimum of level II

• The acceptance criteria for coating degradation and the 

requirements for physical inspections when degradation is 

identified will be in accordance with Element 6 of GALL Report 

AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014. 

21 Existing Reactor Vessel Surveillance program is credited. A.2.1.21 Ongoing 
A-19

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

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or 

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Schedule

22 One-Time Inspection is a new program that will be used to verify 

the system-wide effectiveness of the Water Chemistry, Fuel Oil 

Chemistry and Lubricating Oil Analysis programs.

A.2.1.22 Program to be 

implemented before 

the period of 

extended operation

One-time inspection

will be performed 

within the 10 years 

before the period of 

extended operation

23 Selective Leaching is a new program that will include one-time 

inspections of a representative sample of susceptible components 

to determine if loss of material caused by selective leaching is 

occurring.

A.2.1.23 Program to be 

implemented before 

the period of 

extended operation

One-time inspection

will be performed 

within the 5 years 

before the period of 

extended operation
A-20

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

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LRA Section

Enhancement 

or 

Implementatio

Schedule

24 One-Time Inspection of ASME Code Class 1 Small-Bore Piping is a 

new program that will manage the aging effect of cracking in 

stainless steel and carbon steel Class 1 small-bore piping that is 

less than nominal pipe size (NPS) 4-inches, and greater than or 

equal to NPS 1-inch.

A.2.1.24 Program to be 

implemented before 

the period of 

extended operation

One-time inspection

will be performed 

within the 6 years 

before the period of 

extended operation
A-21

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

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Enhancement 

or 

Implementatio

Schedule

25 External Surfaces Monitoring of Mechanical Components is a new 

program that manages aging effects of metallic and elastomeric 

materials through periodic visual inspection of external surfaces for 

evidence of loss of material. Visual inspections are augmented by 

physical manipulation as necessary to detect hardening and loss of 

strength of elastomers

A sample of outdoor component surfaces that are insulated and a 

sample of indoor insulated components exposed to condensation 

(due to the in-scope component being operated below the dew 

point), are periodically inspected, under the insulation, every

10 years during the period of extended operation. Inspections 

subsequent to the initial inspection will consist of examination of the 

exterior surface of the insulation for indications of damage to the 

jacketing or protective outer layer of the insulation if the initial 

inspection verifies no loss of material beyond that which could have 

been present during initial construction. If the external visual 

inspections of the insulation reveal damage to the exterior surface 

of the insulation or if there is evidence of water intrusion through 

the insulation, then periodic inspections under insulation to detect 

corrosion under insulation will continue.

A.2.1.25 Program to be 

implemented before 

the period of 

extended operation
A-22

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

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or 

Implementatio

Schedule

26 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components is a new program that manages aging effects of 

metallic and elastomeric materials through visual inspections of 

internal surfaces for evidence of loss of material. Visual 

inspections are augmented by physical manipulation as necessary 

to detect hardening and loss of strength of elastomers.

This opportunistic approach is supplemented to ensure a 

representative sample of components within the scope of this 

program are inspected. At a minimum, in each 10-year period 

during the period of extended operation, a representative sample of 

20% of the population (defined as components having the same 

combination of material, environment, and aging effect) or a 

maximum of 25 components per population is inspected. Where 

practical, the inspections focus on the bounding or lead 

components most susceptible to aging because of time in service, 

and severity of operating conditions. Opportunistic inspections 

continue in each 10-year period despite meeting the sampling 

minimum requirement. For the waste water environment, a 

maximum of 25 components per population will be inspected. To 

provide reasonable assurance of the presence of sufficient coating, 

10 of the 25 internal inspections will be of the normal waste, oily 

waste, sanitary waste and storm drain galvanized piping, and 15 of 

the internal inspections will be of the radioactive floor and 

equipment drain carbon steel piping.

A.2.1.26 Program to be 

implemented before 

the period of 

extended operation
A-23

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

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Enhancement 

or 

Implementatio

Schedule

27 Existing Lubricating Oil Analysis program is credited.

The Lube Oil Analysis aging management program also manages 

the loss of coating integrity in the RCIC turbine bearing pedestals 

and HPCI turbine bearing pedestals and oil reservoir. 

• As described below, baseline inspections will occur in the 

10-year period prior to the period of extended operation. The 

maximum interval of subsequent coating inspections will 

comply with Table 4a of GALL Report AMP XI.M42 in 

draft LR-ISG-2013-01 dated January 6, 2014 (ADAMS 

Accession No. ML13262A442).

• The inspection of the RCIC turbine bearing pedestals and 

HPCI turbine bearing pedestals and oil reservoir will be 

performed by inspectors qualified to ASTM D 4537-91 and 

ANSI N45.2.6-1978 to a minimum of level II. 

• The acceptance criteria for coating degradation and the 

requirements for physical inspections when degradation is 

identified will be in accordance with Element 6 of GALL Report 

AMP XI.M42 in draft LR-ISG-2013-01 dated January 6, 2014.

A.2.1.27 Ongoing 
A-24

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

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or 

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Schedule

28 Monitoring of Neutron-Absorbing Materials Other than Boraflex is 

an existing program that will be enhanced to:

1. Perform test coupon analysis on a 10-year frequency, 

beginning no earlier than 2020 for Unit 1 and 2021 for 

Unit 2.

2. Initiate corrective action if coupon test result data indicates 

that acceptance criteria will be exceeded before the next 

scheduled test coupon analysis.

3. Resume the accelerated exposure configuration for the 

Boral coupons (surrounded by freshly discharged fuel 

assemblies) at each of five additional refueling cycles, 

beginning with the next refueling for each unit (2013 for 

Unit 2, 2014 for Unit 1).

4. Maintain the coupon exposure such that it is bounding for 

the Boral material in all spent fuel racks, by relocating the 

coupon tree to a different spent fuel rack cell location each 

cycle and by surrounding the coupons with a greater 

number of freshly discharged fuel assemblies than that of 

any other cell location.

A.2.1.28 Program to be 

enhanced before th

period of extended 

operation.

Inspection schedule 

as described in the 

commitment.
A-25

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

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LRA Section

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or 

Implementatio

Schedule

29 Buried and Underground Piping and Tanks is an existing program 

that will be enhanced to:

1. If adverse indications are detected during inspection of 

in-scope buried piping, inspection sample sizes within the 

affected piping categories are doubled. If adverse 

indications are found in the expanded sample, an analysis 

is conducted to determine the extent of condition and

extent of cause. The size of the follow-on inspections will 

be determined based on the extent of condition and extent 

of cause.

2. Coat the underground emergency diesel generator (EDG) 

system fuel oil piping before the period of extended 

operation. The coating will be in accordance with Table 1 

of National Association of Corrosion Engineers (NACE)

SP0169-2007 or Section 3.4 of NACE RP0285-2002.

A.2.1.29 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule

as described in the 

commitment
A-26

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

29 (continued) 3. Perform direct visual inspections and volumetric 

inspections of the underground Emergency Diesel 

Generator System fuel oil piping and components during 

each 10-year period beginning 10 years prior to the entry 

into the period of extended operation. Prior to the period 

of extended operation all in scope Emergency Diesel 

Generator System fuel oil piping and components located 

in underground vaults will undergo a 100 percent visual 

inspection. Volumetric inspections will also be 

performed. After entering the period of extended 

operation, 2 percent of the linear length of in scope 

Emergency Diesel Generator System fuel oil piping and 

components located in underground vaults will undergo 

direct visual inspections and volumetric inspections every 

10 years. Inspection locations after entering the period of 

extended operation will be selected based on susceptibility 

to degradation and consequences of failure. Visual 

inspections will be performed by a NACE Coating 

Inspector Program Level 2 or 3 qualified inspector or an 

individual that has attended the EPRI Comprehensive 

Coatings Course and completed the EPRI Buried Pipe 

Condition Assessment and Repair Training Computer 

Based Training Course.
A-27

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

29 (continued) 4. Perform two sets of volumetric inspections of the 

safety-related SW system underground piping and 

components during each 10-year period beginning 

10 years before the entry into the period of extended 

operation. Each set of volumetric inspections will assess 

either the entire length of a run of in-scope safety-related 

SW system piping and components in the underground 

vault or a minimum of 10 feet of the linear length of 

in-scope safety-related SW system piping and 

components in the underground vault. Inspection 

locations will be selected based on susceptibility to 

degradation and consequences of failure.

5. Specify that visual inspections of safety-related SW 

system underground piping and components will be 

performed by a NACE Coating Inspector Program Level 2 

or 3 qualified inspector or an individual that has attended 

the EPRI Comprehensive Coatings Course and completed 

the EPRI Buried Pipe Condition Assessment and Repair 

Training Computer Based Training Course.

6. Perform trending of the cathodic protection testing results 

to identify changes in the effectiveness of the system and 

to ensure that the rectifiers remain operational at least 

85% of the time, and cathodic protection effectiveness will 

be maintained >80%.
A-28

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

29 (continued) 7. Modify the yearly cathodic protection survey acceptance 

criterion to meet NACE SP0169-2007 standards and add 

a statement that if negative polarized potential exceeds 

−1100mV relative to copper/copper sulfate electrode an 

issue report will be entered into the corrective action 

program. In performing cathodic protection surveys, only 

the −850mV polarized potential criterion for steel piping 

will be used for acceptance criteria and determination of 

cathodic protection system effectiveness, unless the 

−100mV polarization criterion can be demonstrated 

effective through use of buried coupons, electrical 

resistance probes, or placement of reference cells in the 

immediate vicinity of the piping being measured.

8. Whenever pipe is excavated and damage to the coating is 

significant and the damage was caused by nonconforming 

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.

30 ASME Section XI, Subsection IWE is an existing program that will 

be enhanced to:

1. Manage the suppression pool liner and coating system to:

a. Remove any accumulated sludge in the 

suppression pool every refueling outage.

b. Perform an ASME IWE examination of the 

submerged portion of the suppression pool each 

ISI period.

A.2.1.30 Program to be 

enhanced before th

period of extended 

operation
A-29

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

30 (continued) c. Use the results of the ASME IWE examination to 

implement a coating maintenance plan to perform 

the following prior to the period of extended 

operation:

• Local areas (less than 2.5 inches in 

diameter) of general corrosion that are 

greater than 50 mils plate thickness loss 

will be recoated in the outage they are 

identified. This plate thickness loss 

criterion for local areas will also be used to 

determine when the submerged portions 

of the liner require augmented inspection 

in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• Areas of general corrosion greater than 

25 mils average plate thickness loss will 

be recoated based on ranking of affected 

surface area, high to low. This plate 

thickness loss criterion for areas of 

general corrosion will also be used to 

determine when the submerged portions 

of the liner require augmented inspection 

in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• For plates with greater than 25 percent 

coating depletion, the affected area will be 

recoated based on ranking of affected

surface area depleted and metal thickness 

loss.

The coating 

maintenance plan 

will be initiated in th

2012 refueling 

outage for Unit 1 an

the 2013 refueling 

outage for Unit 2.
A-30

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

30 (continued) d. Use the results of the ASME IWE examination to 

implement a coating maintenance plan to perform 

the following during the period of extended 

operation:

• Local areas (less than 2.5 inches in 

diameter) of general corrosion that are 

greater than 50 mils plate thickness loss 

will be recoated in the outage they are 

identified. This plate thickness loss 

criterion for local areas will also be used to 

determine when the submerged portions 

of the liner require augmented inspection 

in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• Areas of general corrosion greater than 

25 mils average plate thickness loss will 

be recoated in the outage they are 

identified. This plate thickness loss 

criterion for areas of general corrosion will 

also be used to determine when the 

submerged portions of the liner require 

augmented inspection in accordance with 

ASME Section XI, Subsection IWE, 

Category E-C.

• For plates with greater than 25% coating 

depletion, the affected area will be 

recoated no later than the next scheduled 

inspection.
A-31

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

30 (continued) The coating maintenance plan will continue through the 

period of extended operation to ensure the coating 

protects the liner to avoid significant material loss.

2. Use the results of the ASME IWE inspection of the 

submerged portions of the suppression pool downcomers 

to perform the following:

• Local areas (less than or equal to 5.5 inches in 

any direction) that have 40 mils or more metal 

thickness loss will be recoated. This downcomer 

metal thickness loss criteria for local areas will 

also be used to determine when the submerged 

portions of the downcomers require augmented 

inspection in accordance with ASME Section XI, 

Subsection IWE, Category E-C.

• Areas of general corrosion (greater than 

5.5 inches in any direction) that have 30 mils or 

more metal thickness loss will be recoated. This 

downcomer metal thickness loss criteria for areas 

of general corrosion will also be used to 

determine when the submerged portions of the 

downcomers require augmented inspection in 

accordance with ASME Section XI, 

Subsection IWE, Category E-C.

3. When IWE examinations are conducted, perform 

ultrasonic thickness measurements on four areas of 

submerged suppression pool liner affected by general 

corrosion.

The downcomer 

recoat and 

augmented 

inspection criteria w

be implemented pri

to receipt of the 

renewed licenses.

The ultrasonic 

thickness 

measurement 

requirements will be 

implemented prior t

receipt of the 

renewed licenses.
A-32

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

30 (continued) 4. Provide guidance for proper specification of bolting 

material, lubricant and sealants, and installation torque or 

tension to prevent or mitigate degradation and failure of 

structural bolting.

31 ASME Section XI, Subsection IWL is an existing program that will 

be enhanced to:

1. Include second-tier acceptance criteria of ACI 349.3R.

A.2.1.31 Program to be 

enhanced before th

period of extended 

operation

32 ASME Section XI, Subsection IWF is an existing program that will 

be enhanced to:

1. Provide guidance for proper specification of bolting 

material, lubricant and sealants, and installation torque or 

tension to prevent or mitigate degradation and failure of 

structural bolting.

A.2.1.32 Program to be 

enhanced before th

period of extended 

operation

33 Existing 10 CFR Part 50, Appendix J program is credited. A.2.1.33 Ongoing 
A-33

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

34 Masonry Walls is an existing program that will be enhanced to:

1. Add the following structures with masonry walls to the 

program scope:

a. administration building warehouse 

b. fuel oil pumphouse 

c. transformer foundation dike walls

2. Provide additional guidance for inspection of masonry 

walls for shrinkage, separation, and for gaps between the 

supports and walls that could impact the wall’s intended 

function.

3. Require an inspection frequency of not greater than 

5 years.

4. Require that personnel performing inspections and 

evaluations meet the qualifications specified within 

ACI 349.3R.

A.2.1.34 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule

as described in the 

commitment
A-34

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

35 Structures Monitoring is an existing program that will be enhanced 

to:

1. Add the following structures:

a. admin building warehouse

b. fuel oil pumphouse

c. SW pipe tunnel

d. yard structures

• aux fire water storage tank foundation

• backup fire pump house and foundation

• well pump #3 enclosure and foundation

• railroad bridge

• manholes 001 and 002

• fuel oil storage tank dike

• transformer foundations and dikes

A.2.1.35 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule

as described in the 

commitment
A-35

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

35 (continued) 2. Add the following components and commodities:

a. pipe, electrical, and equipment component support 

members

b. pipe whip restraints and jet impingement shields

c. panels, racks, and other enclosures

d. sliding surfaces

e. sump and pool liners

f. electrical cable trays and conduits

g. electrical duct banks

h. tube tracks

i. doors

j. penetration seals

k. blowout panels

l. permanent drywell shielding

m. roof scuppers
A-36

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

35 (continued) 3. Monitor groundwater chemistry on a frequency not to 

exceed 5 years for pH, chlorides, and sulfates and verify 

that it remains nonaggressive, or evaluate results 

exceeding criteria to assess impact, if any, on below-grade 

concrete.

4. Provide guidance for proper specification of bolting 

material, lubricant and sealants, and installation torque or 

tension to prevent or mitigate degradation and failure of 

structural bolting. Revise storage requirements for 

high-strength bolts to include recommendations of 

Research Council on Structural Connections (RCSC) 

Specification for Structural Joints Using High Strength 

Bolts, Section 2.0.

5. Monitor concrete for areas of abrasion, erosion, and 

cavitation degradation, drummy areas that can exceed the 

cover concrete thickness in depth, popouts and voids, 

scaling, and passive settlements or deflections.

6. Perform inspections on a frequency not to exceed 5 years.

7. Perform inspections of subdrainage sump pit internal 

concrete on a 5-year frequency as a leading indicator the 

condition of below grade concrete exposed to ground 

water.

8. Require that personnel performing inspections and 

evaluations meet the qualifications specified within 

ACI 349.3R.
A-37

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

35 (continued) 9. Perform inspection of elastomeric vibration isolation 

elements and structural seals for cracking, loss of material 

and hardening. Visual inspections of elastomeric vibration 

isolation elements are to be supplemented by 

manipulation to detect hardening when vibration isolation 

function is suspect.

10. Monitor accessible sliding surfaces to detect significant 

loss of material caused by wear, corrosion, debris, or dirt, 

which could result in lockup or reduced movement.

11. Perform opportunistic inspection of below grade portions 

of in-scope structures in the event of excavation that 

exposes normally inaccessible below grade concrete.

12. Include applicable acceptance criteria from ACI 349.3R.

13. Clarify that loose bolts and nuts and cracked high-strength 

bolts are not acceptable unless accepted by engineering 

evaluations.
A-38

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

36 RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants is an existing program that will be enhanced 

to:

1. Require inspection of structural bolting integrity (loss of 

material and loosening of the bolts).

2. Require monitoring of aging effects for increase of porosity 

and permeability of concrete structures and loss of 

material for steel components.

3. Require the proper functioning of dike drainage systems.

4. Require increased inspection frequency if the extent of the 

degradation is such that the structure or component may 

not meet its design basis if allowed to continue 

uncorrected until the next normally scheduled inspection.

5. Require (a) evaluation of the acceptability of inaccessible 

areas when conditions exist in the accessible areas that 

could indicate the presence of, or result in, degradation to 

such inaccessible areas, and (b) examination of the 

exposed portions of the below-grade concrete when 

excavated for any reason.

6. Monitor raw water chemistry at least once every 5 years 

for pH, chlorides, and sulfates and verify that it remains 

nonaggressive, or evaluate results exceeding criteria to 

assess impact, if any, on submerged concrete.

A.2.1.36 Program to be 

enhanced before th

period of extended 

operation

Inspection schedule

as described in the 

commitment
A-39

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

36 (continued) 7. Require visual examinations of the Spray Pond and 

Pumphouse submerged wetwell concrete for signs of 

degradation during maintenance activities. If significant 

concrete degradation is identified, a plant-specific AMP

should be implemented to manage the concrete aging 

during the period of extended operation.

8. Require that active cracks in structural concrete or extent 

of corrosion in steel are documented and trended, until the 

condition is no longer occurring or until a corrective action 

is implemented.

9. Require acceptance and evaluation of structural concrete 

using quantitative criteria based on Chapter 5 of 

ACI 349.3R. 

10. Provide guidance for proper specification of bolting 

material, lubricant and sealants, and installation torque or 

tension to prevent or mitigate degradation and failure of 

structural bolting. Revise storage requirements for 

high-strength bolts to include recommendations of 

Research Council on Structural Connections (RCSC) 

Specification for Structural Joints Using High Strength 

Bolts, Section 2.0.

37 Protective Coating Monitoring and Maintenance Program is an

existing program that will be enhanced to:

1. Create the position of Nuclear Coatings Specialist 

qualified to ASTM D 7108 standards.

A.2.1.37 Program to be 

enhanced before th

period of extended 

operation
A-40

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

38 Insulation Material for Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements 

is a new program that will be used to manage aging of the 

insulation material for non-EQ cables and connections. Accessible 

cables and connections located in adverse localized environments 

will be visually inspected at least once every 10 years for 

indications of reduced insulation resistance, such as embrittlement, 

discoloration, cracking, melting, swelling, or surface contamination.

A.2.1.38 Program and initial 

inspections to be 

implemented before 

the period of 

extended operation

Inspection schedule

as described in the 

commitment

39 Insulation Material for Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements 

Used in Instrumentation Circuits is a new program that will be used 

to manage aging of non-EQ cable and connection insulation of the 

in-scope portions of the process radiation monitoring and neutron 

monitoring systems.

Calibration and cable tests will be performed and results will be 

assessed for reduced insulation resistance before the period of 

extended operation and at least once every 10 years during the 

period of extended operation.

A.2.1.39 Program and initial 

assessment of 

calibration and test 

results to be 

implemented before 

the period of 

extended operation

Assessment 

schedule identified 

commitment
A-41

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

40 Inaccessible Power Cables Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements is a new program that 

will be used to manage the aging effects and mechanisms of 

non-EQ, in-scope, inaccessible power cables.

Cables will be tested using a proven test for detecting reduced 

insulation resistance of the cable’s insulation system. The cables 

will be tested at least once every 6 years. More frequent testing 

may occur based on test results and operating experience (OE).

Periodic actions will be taken to prevent inaccessible cables from 

being exposed to significant moisture. Manholes associated with 

the cables included in this AMP will be inspected for water 

collection with subsequent corrective actions (e.g., water removal), 

as necessary. Before the period of extended operation, the 

frequency of inspections for accumulated water will be established 

and adjusted based on plant-specific OE with cable wetting or 

submergence, including water accumulation over time and event 

driven occurrences such as heavy rain or flooding. Operation of 

dewatering devices will be confirmed before any known or 

predicted heavy rain or flooding event. During the period of 

extended operation, the inspections will occur at least annually.

A.2.1.40 Program and initial 

tests and inspection

to be implemented 

before the period of 

extended operation

Test and Inspection 

schedule identified 

commitment
A-42

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

41 Metal Enclosed Bus is a new program that will be used to manage 

aging of in-scope metal enclosed bus. The internal portions of bus 

enclosure assemblies, bus insulation, bus insulating supports and 

elastomers will be visually inspected. A sample (20% with a 

maximum sample size of 25) of the accessible metal enclosed bus 

bolted connection population will be tested using thermography. 

The inspections and thermography will be performed at least once 

every 10 years for indications of aging degradation.

A.2.1.41 Program and initial 

tests and inspection

to be implemented 

before the period of 

extended operation

Test and inspection 

schedule identified 

commitment

42 Fuse Holders AMP is a new program that applies to fuse holders 

located outside of active devices that have been identified as 

susceptible to aging effects. 

Fuse holders subject to increased resistance of connection or 

fatigue, will be tested, by a proven test methodology, at least once 

every 10 years for indications of aging degradation. Visual 

inspection is not part of this program.

A.2.1.42 Program and initial 

tests to be 

implemented before 

the period of 

extended operation

Test schedule 

identified in 

commitment

43 Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements program is a new 

program that will implement one-time testing of a representative 

sample (20 percent with a maximum sample size of 25) of non-EQ 

electrical cable connections to ensure that either aging of metallic 

cable connections is not occurring or that the existing preventive 

maintenance program is effective such that a periodic inspection 

program is not required.

A.2.1.43 Program and 

one-time tests to be 

implemented before 

the period of 

extended operation
A-43

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

44 Fatigue Monitoring is an existing program that will be enhanced to:

1. Monitor additional plant transients that are significant 

contributors to fatigue usage and to impose administrative 

transient cycle limits corresponding to the limiting numbers 

of cycles used in the environmental fatigue calculations.

A.3.1.1 Program to be 

enhanced before th

period of extended 

operation

45 Existing Environmental Qualification (EQ) of Electric Components 

program is credited.

A.3.1.2 Ongoing 
A-44

APPENDIX A: LIMERICK GENERATING STATION, UNITS 1 AND 2 LICENSE RENEWAL COMM

Item Commitment UFSAR

Supplement 

Section/

LRA Section

Enhancement 

or 

Implementatio

Schedule

46 The OE program is an existing program that will be enhanced to:

1. Explicitly require the review of OE for aging-related 

degradation.

2. Establish criteria to define aging-related degradation.

3. Establish identification coding for use in identification, 

trending, and communications of aging-related 

degradation.

4. Require communication of significant internal 

aging-related degradation, associated with system, 

structures, and components in the scope of license 

renewal, to other Exelon plants and to the industry. 

Criteria will be established for determining when 

aging-related degradation is significant.

5. Require review of external OE for information related to 

aging management, and evaluation of such information for 

potential improvements to LGS aging management 

activities.

6. Provide training to those responsible for screening, 

evaluating and communicating OE items related to aging 

management.

A.1.6 Program to be 

enhanced no later 

than the date that th

renewed operating 

licenses are issued

47 Re-evaluate the flaw in the Unit 1 RPV nozzle to safe-end weld 

VRR-1RD-1A-N2H in accordance with ASME Section XI, 

subsection IWB-3600 for the 60-year service period corresponding 

to the LR term.

Appendix C Before the period o

extended operation
B-1

APPENDIX B 

CHRONOLOGY

This appendix lists chronologically the routine licensing correspondence between the staff of the 

U.S. Nuclear Regulatory Commission (NRC) (the staff) and Exelon Generation Company, LLC 

(Exelon). This appendix updates the correspondence regarding the staff’s review of the 

Limerick Generating Station (LGS) license renewal application (LRA) (under Docket 

Nos. 50-352 and 50-353) since the issuance of the Final safety evaluation report (SER) in 

January 2013.

APPENDIX B: CHRONOLOGY

Date Subject

2/14/2013 Letter from Stetkar J., ACRS, to Macfarlane A., Chairman NRC, 

“Report on the Safety Aspects of the License Renewal Application for 

the Limerick Generating Station,” (ADAMS Accession 

No. ML13058A150)

2/21/2013 Letter from Gallagher M., Exelon Generation Co., LLC, to U.S. NRC 

Document Control Desk, “Review of the Safety Evaluation Report 

related to the Limerick Generating Station License Renewal 

Application,” (ADAMS Accession No. ML13053A374)

6/17/2013 Letter from Gallagher M., Exelon Generation Co., LLC, to U.S. NRC 

Document Control Desk, “10 CFR 54.21(b) Annual Amendment to the 

Limerick Generating Station License Renewal Application and Review 

of Interim Staff Guidance,” (ADAMS Accession No. ML13168A432)

8/1/2013 Letter from Plasse R., U.S. NRC, to Gallagher M., Exelon Generation 

Co., LLC, “Request for Additional Information for the Review of the 

Limerick Generating Station, Units 1 and 2, License Renewal 

Application (TAC Nos. ME6555 AND ME6556),” (ADAMS Accession 

No. ML13204A112)

8/16/2013 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC 

Document Control Desk, “Response to NRC Request for Additional 

Information, dated August 1, 2013, Related to Limerick Generating 

Station License Renewal Application,” (ADAMS Accession 

No. ML13228A308)

9/5/2013 Meeting Summary from Plasse R., U.S. NRC, “Summary of Telephone 

Conference Call held on July 16, 2013, between the U.S. Nuclear 

Regulatory Commission and Exelon Generation Company, LLC, 

Concerning Requests for Additional Information Pertaining to the 

Limerick Generating Station License Renewal,” (ADAMS Accession 

No. ML13238A316)

9/25/2013 Letter from Gallagher M., Exelon Generation Co., LLC, to U.S. NRC

Document Control Desk, “Review of Interim Staff Guidance 

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

(ADAMS Accession No. ML13268A353)
B-2

APPENDIX B: CHRONOLOGY

Date Subject

2/10/2014 Letter from Plasse R., U.S. NRC, to Gallagher M., Exelon Generation 

Co., LLC, “Request for Additional Information for the Review of the 

Limerick Generating Station, Units 1 and 2, License Renewal 

Application (TAC Nos. ME6555 AND ME6556),” (ADAMS Accession 

No. ML14034A060)

3/12/2014 Letter from Gallagher M., Exelon Generation Co., LLC, to U.S. NRC

Document Control Desk, “Review of Interim Staff Guidance 

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

Systems, Atmospheric Storage Tanks, and Corrosion Under 

Insulation,” (ADAMS Accession No. ML14034A376)

3/14/2014 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC 

Document Control Desk, “Response to NRC Request for Additional 

Information, dated February 10, 2014, Related to Limerick Generating 

Station License Renewal Application,” (ADAMS Accession 

No. ML14071A378)

4/24/2014 Letter from Plasse R., U.S. NRC, to Gallagher M., Exelon Generation 

Co., LLC, “Request for Additional Information for the Review of the

Limerick Generating Station, Units 1 and 2, License Renewal 

Application (TAC Nos. ME6555 AND ME6556),” (ADAMS Accession 

No. ML14107A212)

5/21/2014 Letter from Gallagher M., Exelon Generation Co, LLC, to U.S. NRC 

Document Control Desk, “Response to NRC Request for Additional 

Information, dated April 24, 2014, and Minor Changes to the LRA 

Supplement dated March 12, 2014, Related to Limerick Generating 

Station License Renewal Application,” (ADAMS Accession 

No. ML14142A172)

6/4/2014 Letter from Gallagher M., Exelon Generation Co., LLC, to U.S. NRC

Document Control Desk, “10 CFR 54.21(b) Annual Amendment to the 

Limerick Generating Station License Renewal Application and 

Revision to UFSAR Supplement Related to the Response to 

RAI 3.0.3.4-1,” (ADAMS Accession No. ML14155A144)
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

Y. Diaz-Sanabria Management Oversight

J. Gavula Reviewer-Mechanical

W. Holston Reviewer-Mechanical

R. Kalikian Reviewer-Mechanical

D. Morey Management Oversight

R. Plasse Project Manager

C. Ng Project Manager

J. Wise Reviewer-Mechanical

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 Limerick Generating 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.

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

US Department of Transportation, Federal Highway Administration, Publication

No. FHWA-NHI-00-044, “Corrosion/Degradation of Soil Reinforcements for Mechanically 

Stabilized Walls and Reinforced Soil Slopes,” September 2000.

Electric Power Research Institute (EPRI) Nuclear Safety Analysis Center (NSAC)-202L-R3, 

“Recommendations for an Effective Flow-Accelerated Corrosion Program.” Nonproprietary 

version, August 2007.

EPRI Comprehensive Coatings Course.

EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training 

Course.

EPRI Technical Report 1007460, “Terry Turbine Maintenance Guide, RCIC Application,” 

September, 2012.
D-2

APPENDIX D: REFERENCES

EPRI Technical Report 1007459, “Terry Turbine Maintenance Guide, HPCI Application,”

November, 2012.

EPRI TR-1019157, “Guideline on Nuclear Safety-Related Coatings,” Revision 2.

American National Standards Institute (ANSI) N45.2.6-1978.

NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54–The 

License Renewal Rule,” Revision 6, June 2005.

Industry Codes and Standards

American Society of Mechanical Engineers (ASME) Code Section XI, “Rules for Inservice 

Inspection of Nuclear Power Plant Components,” Subarticle IWA-2300, “Qualification of 

Nondestructive Personnel, 2007 Edition with 2008 Addenda.

ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components,”

2007 Edition with 2008 Addenda.

ASME Code Case N-513, “Evaluation Criteria for Temporary Acceptance of Flaws in 

Moderate Energy Class 2 or 3 Piping,” January 26, 2009.

National Association of Corrosion Engineers (NACE), Peabody’s Control of Pipeline 

Corrosion, Second Edition, 2001.

ASTM D 4537-91, “Standard Guide for Establishing Procedures To Qualify and Certify 

Personnel Performing Coating Work Inspection in Nuclear Facilities.

ASTM D5163-08, “Standard Guide for Establishing a Program for Condition Assessment of 

Coating Service Level I Coating Systems in Nuclear Power Plants,” 2008.

ASTM D7108-05, ‘Standard Guide for Establishing Qualifications for a Nuclear Coatings 

Specialist” 

ASTM D448-08, “Standard Classification for Sizes of Aggregate for Road and Bridge 

Construction”

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 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.
D-3

APPENDIX D: REFERENCES

National Fire Protection Association (NFPA) 25, “Standard for Inspection, Testing, and 

Maintenance of Water-Based Fire Protection Systems,” NFPA, Quincy, MA, 2008.

National Fire Protection Association (NFPA) 25, “Standard for Inspection, Testing, and 

Maintenance of Water-Based Fire Protection Systems,” NFPA, Quincy, MA, 2011.






UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

------------------

OFFICIAL BUSINESS
 

 

NUREG-2171

Supplement 1

Safety Evaluation Report Related to the License Renewal of 

Limerick Generating Station, Units 1 and 2

September 2014