Safety Evaluation Report

Related to the License Renewal 

of Indian Point Nuclear

Generating Plant, Units 2 and 3

Docket Nos. 50-247 and 50-286

Office of Nuclear Reactor Regulation

NUREG-1930

Supplement 2

 
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Safety Evaluation Report

Related to the License Renewal 

of Indian Point Nuclear

Generating Plant, Units 2 and 3

Docket Nos. 50-247 and 50-286

Manuscript Completed: November 2014

Date Published: July 2015

Office of Nuclear Reactor Regulation

NUREG-1930

Supplement 2

iii 

ABSTRACT 

This document is the second supplement to NUREG-1930, “Safety Evaluation Report Related to 

the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3,” for the license 

renewal application (LRA) for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3). 

By letter dated April 23, 2007, as supplemented by letters dated May 3 and June 21, 2007, 

Entergy Nuclear Operations, Inc., (“Entergy” or “the applicant”) submitted an LRA in accordance 

with Title 10, “Energy,” of the Code of Federal Regulations (10 CFR) Part 54, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants.” Entergy requested renewal of the 

IP2 and IP3 operating licenses (Facility Operating License Numbers DPR-26 and DPR-64, 

respectively) for a period of 20 years beyond the expirations of the initial operating licenses at 

midnight on September 28, 2013, for IP2, and at midnight on December 12, 2015, for IP3. The 

Commission’s regulation in 10 CFR 2.109, “Effect of Timely Renewal Application,” implements 

the “timely renewal” provision of Section 9(b) of the Administrative Procedure Act, Title 5, 

“Government Organization and Employees,” of the United States Code (U.S.C.) Section 558(c). 

Under this regulation, if a licensee requests a renewed license at least 5 years before expiration 

of its current license, the request is considered “timely,” and the facility is allowed to continue to 

operate under its existing license until the U.S. Nuclear Regulatory Commission (NRC) 

completes its review and reaches a decision on the license renewal request. At midnight on 

September 28, 2013, IP2 entered this period of operation under the above provision. 

The staff published its safety evaluation report (SER) in the two volumes of NUREG-1930 in 

November 2009, which summarized the results of its safety review of the LRA for compliance 

with the requirements of 10 CFR Part 54. In August 2011, the staff issued Supplement 1 to 

NUREG-1930 (supplemental safety evaluation report (SSER) 1), which documented the staff’s 

review of supplemental information provided by the applicant since the issuance of the SER as 

documented in NUREG-1930. This supplement to NUREG-1930 (SSER 2) documents the 

staff’s review of supplemental information provided by the applicant since the issuance of the 

SSER 1. This information includes information committed to by Entergy as documented in 

Commitment No. 30 (pertaining to reactor vessel internals), information required by 

10 CFR 54.21(b), updated information and commitments, as well as information provided in 

response to staff requests for additional information. This document discusses only the 

changes to the SER and SSER 1. 

v 

TABLE OF CONTENTS 

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

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

ABBREVIATIONS AND ACRONYMS ...................................................................................................... vii

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

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

SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING 

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

2.3 Scoping and Screening Results: Mechanical Systems .................................................................. 2-1

2.3.1.2 Reactor Vessel Internals .................................................................................................. 2-1

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

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

3.0.3 Aging Management Programs ................................................................................................ 3-1

3.0.3.1 Aging Management Programs Consistent with the GALL Report ................................... 3-1

3.0.3.2 Programs Consistent with the GALL Report with Exceptions or 

Enhancements ................................................................................................................. 3-8

3.0.3.3 Programs Not Consistent with or Not Addressed in the GALL Report .......................... 3-13

3.1 Aging Management of Reactor Coolant System .......................................................................... 3-59

3.1.1 Summary of Technical Information in the Application .......................................................... 3-59

3.1.2 Staff Evaluation ..................................................................................................................... 3-59

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ..................... 3-68

3.2 Aging Management of Engineered Safety Features Systems ..................................................... 3-68

3.2.1 Summary of Technical Information in the Application .......................................................... 3-68

3.2.2 Staff Evaluation ..................................................................................................................... 3-68

3.2.2.1 AMR Results Consistent with the GALL Report ............................................................ 3-68

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further 

Evaluation is Recommended ......................................................................................... 3-69

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ..................... 3-70

3.3 Aging Management of Auxiliary Systems .................................................................................... 3-70

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

3.3.2 Staff Evaluation ..................................................................................................................... 3-70

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

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further 

Evaluation is Recommended ......................................................................................... 3-75

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ..................... 3-77

3.4 Aging Management of Steam and Power Conversion Systems .................................................. 3-81

3.4.1 Summary of Technical Information in the Application .......................................................... 3-81

3.4.2 Staff Evaluation ..................................................................................................................... 3-81

3.4.2.1 AMR Results Consistent with the GALL Report ............................................................ 3-82

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further 

Evaluation is Recommended ......................................................................................... 3-82

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ..................... 3-83

3.5 Aging Management of Containments, Structures, and Component Supports ............................. 3-88

3.6 Aging Management of Electrical and Instrumentation and Control Systems ............................... 3-88

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

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

vi 

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

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

 Commitments for License Renewal of Indian Point Nuclear Generating Unit 

Nos. 2 and 3 ..................................................................................................................... A-1

 Chronology ........................................................................................................................ B-1

 Principal Contributors .......................................................................................................C-1

 References ....................................................................................................................... D-1
vii 

ABBREVIATIONS AND ACRONYMS 

A/LAI Applicant/Licensee Action Item 

AC alternating current 

ACI American Concrete Institute 

ADAMS Agencywide Documents Access and Management System 

AERM aging effect requiring management 

AMP aging management program 

AMR aging management review 

APEC area potential—earth current 

ASA American Standards Association [now the American National 

 Standards Institute (ANSI)] 

ASME [formerly an abbreviation for the American Society of Mechanical 

 Engineers, now part of the organization’s formal name] 

B&W Babcock & Wilcox 

BSD black start diesel 

BWR boiling water reactor 

CASS cast austenitic stainless steel 

CE Combustion Engineering 

CEA control element assembly 

CFR Code of Federal Regulations 

CII containment inservice inspection 

CLB current licensing basis 

CO2 carbon dioxide 

CP cathodic protection 

CRGT control rod guide tube 

CUF cumulative usage factor 

CUFen environmentally-adjusted cumulative usage factor 

DFP diesel fire pump 
Abbreviations and Acronyms 

viii 

dpa displacement(s) per atom 

EDG emergency diesel generator 

EFPH effective full-power hour(s) 

EFPY effective full-power year(s) 

EPRI Electric Power Research Institute 

EQ environmental qualification 

EVT enhanced visual testing 

Fen environmental fatigue correction factor 

FMECA failure modes, effects, and criticality analysis/analyses 

FSAR final safety analysis report 

GALL Generic Aging Lessons Learned [Report] 

GL generic letter 

GT gas turbine 

HAZ heat-affected zone 

HTH high-temperature annealed and aged condition heat treatment 

HVAC heating, ventilation, and air conditioning 

IASCC irradiation-assisted stress corrosion cracking 

IE [neutron] irradiation embrittlement 

I&E inspection and evaluation 

IGSCC intergranular stress corrosion cracking 

IPEC Indian Point Energy Center 

IP1 Indian Point Nuclear Generating Unit 1 

IP2 Indian Point Nuclear Generating Unit 2 

IP3 Indian Point Nuclear Generating Unit 3 

ISG interim staff guidance 

ISI inservice inspection 
Abbreviations and Acronyms 

ix 

ksi kilopound(s) per square inch 

kV kilovolt(s) 

L3P low-low-leakage loading pattern 

L4P low-low-low-leakage loading pattern 

LOCA loss-of-coolant accident 

LR-ISG license renewal interim staff guidance 

LRA license renewal application 

LRSS lower radial support system 

LWR light-water reactor 

MEB metal-enclosed bus 

MIC microbiologically influenced corrosion 

MoS2 molybdenum disulfide 

MRP Materials Reliability Program 

mV millivolt(s) 

NDE nondestructive examination 

NEI Nuclear Energy Institute 

NFPA National Fire Protection Association 

NRC U.S. Nuclear Regulatory Commission 

NRR Office of Nuclear Reactor Regulation 

NSSS nuclear steam supply system 

OE operating experience 

P-T pressure/temperature [curve] 

PEO period of extended operation 

PT [liquid] penetrant testing 

PTS pressurized thermal shock 

PVC polyvinyl chloride 
Abbreviations and Acronyms 

x 

PWR pressurized water reactor 

PWROG Pressurized Water Reactor Owners Group 

PWSCC primary water stress corrosion cracking 

RAI request for additional information 

RCCA rod cluster control assembly 

RCP reactor coolant pump 

RHR residual heat removal 

RIS Regulatory Issue Summary 

RPV reactor pressure vessel 

RTPTS reference temperature for pressurized thermal shock 

RVI reactor vessel internal(s) 

RWST refueling water storage tank 

SBO station blackout 

SC structure and component 

SCC stress corrosion cracking 

SE safety evaluation 

SER safety evaluation report 

SPU stretch power uprate 

SRP-LR standard review plan for review of license renewal applications 

 for nuclear power plants 

SS stainless steel 

SSER supplemental safety evaluation report 

SSC system, structure, or component 

SSCs systems, structures, and components 

TE thermal embrittlement 

TJ technical justification 

TLAA time-limited aging analysis 

TS technical specification 
Abbreviations and Acronyms 

xi 

UCP upper core plate 

UFSAR updated final safety analysis report 

USP upper support plate 

UT ultrasonic testing 

V volt(s) 

VAC volt(s) of alternating current 

VT visual testing 

W Westinghouse 

1-1 

SECTION 1 

INTRODUCTION AND GENERAL DISCUSSION 

1.1 Introduction 

This document is the second supplement to NUREG-1930, “Safety Evaluation Report Related to 

the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3,” for the license 

renewal application (LRA) for Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3). 

By letter dated April 23, 2007, as supplemented by letters dated May 3 and June 21, 2007, 

Entergy Nuclear Operations, Inc., (“Entergy” or “the applicant”) submitted an LRA in accordance 

with Title 10, “Energy,” of the Code of Federal Regulations (10 CFR) Part 54, “Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants.” Entergy requested renewal of the 

IP2 and IP3 operating licenses (Facility Operating License Numbers DPR-26 and DPR-64, 

respectively) for a period of 20 years beyond the expirations of the initial operating licenses at 

midnight on September 28, 2013, for IP2, and at midnight on December 12, 2015, for IP3. The 

Commission’s regulation in 10 CFR 2.109, “Effect of Timely Renewal Application,” implements 

the “timely renewal” provision of Section 9(b) of the Administrative Procedure Act, Title 5, 

“Government Organization and Employees,” of the United States Code (U.S.C.) Section 558(c). 

Under this regulation, if a licensee requests a renewed license at least 5 years before expiration 

of its current license, the request is considered “timely,” and the facility is allowed to continue to 

operate under its existing license until the U.S. Nuclear Regulatory Commission (NRC) 

completes its review and reaches a decision on the license renewal request. At midnight on 

September 28, 2013, IP2 entered this period of operation under the above provision. 

The staff published its safety evaluation report (SER) in the two volumes of NUREG-1930 in 

November 2009, which summarized the results of its safety review of the LRA for compliance 

with the requirements of 10 CFR Part 54. In August 2011, the staff issued Supplement 1 to 

NUREG-1930 (supplemental safety evaluation report (SSER) 1), which documented the staff’s 

review of supplemental information provided by the applicant since the issuance of the SER as 

documented in NUREG-1930. This supplement to NUREG-1930 (SSER 2) documents the 

staff’s review of supplemental information provided by the applicant since the issuance of the 

SSER 1. This information includes information committed to by Entergy as documented in 

Commitment No. 30 (pertaining to reactor vessel internals), information required by 

10 CFR 54.21(b), updated information and commitments, as well as information provided in 

response to staff requests for additional information. This document discusses only the 

changes to the SER and SSER 1. This SSER supplements portions of SER Sections 2 and 3 

and Appendices A and B. 

2-1 

SECTION 2 

STRUCTURES AND COMPONENTS SUBJECT TO 

AGING MANAGEMENT REVIEW 

2.3 Scoping and Screening Results: Mechanical Systems 

2.3.1.2 Reactor Vessel Internals 

2.3.1.2.1 Summary of Technical Information in Application 

In Sections 2.3A.1.2 and 2.3B.1.2 of the SER, with regard to the scoping and screening of the 

reactor vessel intervals (RVI), the staff concluded that that the applicant had adequately 

identified the RVI components within the scope of license renewal, as required by 

10 CFR 54.4(a), and those subject to an aging management review (AMR) as required by 

10 CFR 54.21(a)(1). In the SER, Section 2.3A.1.2 addressed IP2 and Section 2.3B.1.2 

addressed IP3; however, the section below addresses both IP2 and IP3 because the scoping 

and screening information is identical. 

In LRA Amendment 9 (Ref. 1), changes to some of the component names were made in 

Section 2.3.1.2, which describes and lists the major assemblies and their subcomponents that 

form the RVI. A revised Table 2.3.1-2-IP2, 1 “Reactor Vessel Internals Components Subject to 

Aging Management,” contains similar changes. The previous components were in some cases 

subdivided into more subcomponents. The intended functions from the previous components 

were maintained for the new components’ names, although in some cases an intended function 

specific to only a particular subcomponent was maintained only for that subcomponent. For 

example, five core barrel assembly subcomponents (ring, shell, thermal shield, flange, and axial 

flexure plates) were previously combined in one table entry in Table 2.3.1-2-IP2. In LRA 

Amendment 9, three core barrel assembly subcomponents (ring, shell, and thermal shield) have 

been placed in one table entry while the core barrel assembly, axial flexure plate (thermal shield 

flexures), and core barrel assembly flange each have a separate table entry. Previously, all 

these subcomponents had intended functions of structural support, flow distribution, and 

shielding. In LRA Amendment 9, the core barrel assembly, axial flexure plates (thermal shield 

flexures) and the core barrel assembly flange only have the intended function of structural 

support, while the other three core barrel assembly subcomponents (ring, shell, and thermal 

shield) continue to have the intended functions of structural support, flow distribution, and 

shielding. 

2.3.1.2.2 Staff Evaluation 

The staff notes that the previous RVI components and subcomponents have in some cases 

been subdivided into additional subcomponents, although no components were removed from 

 

1 This table was incorrectly numbered as Table 2.3.1-4-IP2 in LRA Amendment 9, which was corrected in 

the RAI 1 response. 
Structures and Components Subject to Aging Management Review 

2-2 

scope. The changes appear to have been made to facilitate alignment of the components with 

the component designations for RVI components from Revision 2 of NUREG-1801, “Generic 

Aging Lessons Learned Report” (the GALL Report), and Electric Power Research Institute 

(EPRI) Materials Reliability Program (MRP) Technical Report 1016596, “Materials Reliability 

Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines 

(MRP-227-Rev. 0)” (Ref. 2). However, the component designations are not identical to those in 

Revision 2 of the GALL Report or in EPRI MRP Technical Report 1022863, “Materials Reliability 

Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines 

(MRP-227-A)” (Ref. 3). The staff’s evaluation of the equivalency of the Indian Point Energy 

Center (IPEC) RVI component designations to those in MRP-227-A is provided in 

Section 3.0.3.3.10 of this SER supplement. The staff compared the revised intended functions 

to the information in Appendix C, “Component Functional Descriptions for Westinghouse 

Reactor Internals,” to MRP-191, “Materials Reliability Program: Screening, Categorization, and 

Ranking of Reactor Internals Components for Westinghouse and Combustion Engineering PWR 

Design” (Ref. 16), and finds that the revised intended functions are consistent with the intended 

functions used to develop the aging management recommendations of MRP-227-A. Therefore, 

the staff finds the revised intended functions acceptable. 

LRA Amendment 9 states that LRA Tables 2.3.1-2-IP2 and 2.3.1-2-IP3 list the mechanical 

components subject to AMR and component intended functions for the RVI. However, 

Table 2.3.1-2-IP3 is missing, and the table for IP2 listing the components subject to AMR is 

numbered Table 2.3.1-4-IP2. Therefore, in Request for Additional Information (RAI) 1, the staff 

requested that the applicant provide Table 2.3.1-2-IP3 and correct the numbering of the table 

for IP2. In its response to RAI 1 by letter dated June 14, 2012 (Ref. 4), the applicant provided a 

correctly numbered Table 2.3.1-2-IP2 and provided Table 2.3.1-2-IP3, which the applicant 

stated is identical to Table 2.3.1-2-IP2. The staff reviewed the revised tables and finds that they 

are acceptable. The staff’s concern in RAI 1 is, therefore, resolved. 

2.3.1.2.3 Conclusion 

The staff reviewed LRA Amendment 9 to determine whether the changes the applicant made to 

the component descriptions change the staff’s previous conclusions that the applicant had 

identified all of the systems, structures, and components (SSCs) within the scope of license 

renewal and that the applicant had correctly identified all components subject to an AMR. On 

the basis of its review, the staff concludes that the changes to the RVI components and 

subcomponents within the scope of license renewal are acceptable and sustain the previous 

conclusion that the applicant has appropriately identified those components within scope of 

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1). 
3-1 

SECTION 3 

AGING MANAGEMENT REVIEW RESULTS 

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

3.0.3 Aging Management Programs 

3.0.3.1 Aging Management Programs Consistent with the GALL Report 

3.0.3.1.2 Buried Piping and Tanks Inspection Program 

Summary of Technical Information in the Application. By letters dated January 30, 2012, 

September 26, 2012, October 18, 2012, November 29, 2012, March 5, 2013, and July 15, 2013, 

the applicant provided additional information related to the Buried Piping and Tanks Inspection 

Program after the issuance of Supplement 1 to the SER. The changes were identified as 

omissions or corrections related to systems and components credited in the auxiliary feedwater 

pump room fire event, identification of underground piping components based on a change in 

understanding of the definition of “underground piping,” and a change in the criteria for selecting 

buried pipe inspection locations based on changes in License Renewal Interim Staff Guidance 

(LR-ISG) 2011-03, “Changes to the Generic Aging Lessons Learned (GALL) Report Revision 2 

Aging Management Program (AMP) XI.M41, ‘Buried and Underground Piping and Tanks.’” The 

additional information is discussed below. 

By letters dated June 12, 2013 and September 3, 2013, the staff issued RAIs 3.0.3.1.2-4 

and 3.0.3.1.2-4a respectively, requesting that the applicant address questions related to 

cathodic protection (CP) effectiveness and acceptance criteria and the extent-of-condition 

criteria when backfill is found to have damaged in-scope buried piping coatings. The applicant 

responded to these RAIs by letters dated July 24, 2013, and October 3, 2013, respectively. 

Staff Evaluation. The staff’s previous evaluation of the applicant’s proposed Buried Piping and 

Tanks Inspection Program is documented in Section 3.0.3.1.2 of SSER 1. 

Changes Related to the Scope of Program. By letters dated January 30, and 

September 26, 2012, the applicant added the Indian Point Nuclear Generating Unit No. 1 (IP1) 

river water service and the IP2 circulating water systems to the scope of the Buried Piping and 

Tanks Inspection Program. The applicant added portions of these systems to the scope of 

license renewal as a result of a further evaluation of the auxiliary feedwater pump room fire 

event (see Section 2.3A.4.5 of the SER). Additionally, as amended by letter dated 

July 15, 2013, the applicant added the IP2 instrument air system to the scope of this program 

because it identified buried in-scope copper-alloy piping exposed to soil with an intended 

function that supports the auxiliary feedwater pump room fire event. The staff finds these 

changes acceptable because the applicant, on identifying buried components with an intended 

function that supports the auxiliary feedwater pump room fire event, properly added them to the 

scope of the Buried Piping and Tanks Inspection Program. 

Changes Related to Selecting Inspection Locations. As amended by letter dated 

March 5, 2013, the applicant revised its program to not exclusively differentiate inspection 
Aging Management Review Results 

3-2 

locations based on the code or safety-related classification of the piping systems or on whether 

the piping contained hazardous materials. The applicant stated that inspection locations will be 

based on plant-specific risk ranking. The applicant also stated that the total number of 

inspections would not change. The number of excavated direct visual inspections is 

summarized as follows: 

• at IP2, at least 20 locations of steel piping will be inspected in the 10-year period before 

the period of extended operation, and 

• at IP3, at least 11 locations of steel piping and 3 locations of stainless steel piping will be 

inspected in the 10-year period before the period of extended operation, so 

• in summary, prior to the period of extended operation, there will be 31 inspections of 

steel piping and 3 inspections of stainless steel piping; 

• at IP2, at least 14 locations of steel piping will be inspected in each 10-year period 

during the period of extended operation, and 

• at IP3, at least 14 locations of steel piping and 2 locations of stainless steel piping will be 

inspected in each 10-year period during the period of extended operation, so 

• in summary, during each 10-year period during the period of extended operation, there 

will be 28 inspections of steel piping and 2 inspections of stainless steel piping. 

The staff finds the applicant’s change acceptable because the change is consistent with the 

guidance in LR-ISG-2011-03, which eliminated the code or safety-related and hazardous 

materials categorization in lieu of the applicant selecting inspection locations based on the risk 

ranking of the buried piping systems. 

Changes Related to Underground Piping. In its response to RAI 3.0.3.1.2-1 dated 

March 28, 2011, the applicant stated that it did not have any underground piping. The staff 

conducted a conference call with the applicant on October 11, 2012, in which the applicant 

sought guidance on the use of the term “restricted” as it related to its use in the description of 

underground piping contained in the “Program Description” in LR-ISG-2011-03. During this call, 

the staff stated that piping located in vaults, for which access requires more than simply opening 

a locked access cover, should be classified as underground piping. 

Based on this guidance, the applicant amended its LRA by letter dated October 18, 2012. The 

applicant stated that portions of the IP3 service water, IP3 city water, and IP2 and IP3 fuel-oil 

systems are located in vaults and are therefore considered underground piping. The applicant 

also stated that the underground components would be inspected under the Buried Piping and 

Tanks Inspection Program at a frequency that meets or exceeds the recommendations of GALL 

Report AMP XI.M41, “Buried and Underground Piping and Tanks.” The October 18, 2012, letter 

did not address whether the piping was coated. By letter dated November 29, 2012, the 

applicant stated that the underground piping was not coated. The applicant added Commitment 

No. 48, which states that underground piping will be visually inspected prior to the period of 

extended operation and then on a frequency of at least once every 2 years during the period of 

extended operation. The commitment further states that the inspection frequency will be 

maintained unless the piping is subsequently coated in accordance with LR-ISG-2011-03. 

Visual inspections will be augmented with surface or volumetric inspections if indications of 

significant loss of material are observed, and adverse indications will be entered into the 
Aging Management Review Results 

3-3 

corrective action program. The applicant revised LRA Sections A.2.1.5, A.3.1.5, and B.1.6 to 

reflect the inclusion of underground piping in the program, and the inspection details were 

included in Commitment No. 48. 

The staff finds the changes acceptable because: (a) although the piping is not coated, the 

applicant has significantly increased the frequency of inspections, every 2 years versus every 

10 years, as recommended in LR-ISG-2011-03; (b) the applicant is inspecting all of the 

underground piping instead of two percent of the pipe, as recommended in LR-ISG-2011-03; 

(c) the visual inspections are capable of detecting loss of material before the point at which the 

intended function of the piping would not be met; (d) the inspection frequencies will remain at 

every 2 years unless the piping is coated; and (e) the commitment has been incorporated in the 

updated final safety analysis report (UFSAR) supplement. 

Changes Related to Cathodic Protection. The applicant’s response to RAI 3.0.3.1.2-1 stated 

that the only cathodically protected in-scope buried piping was the city water line in the vicinity 

of the Algonquin gas pipelines. However, the staff understood that CP had recently been 

installed on portions of the auxiliary feedwater system and was being considered for installation 

on the service water system. The inclusion of safety-related systems, such as auxiliary 

feedwater and service water, in the scope of systems protected by CP resulted in the staff’s 

need to evaluate the parameters monitored and the acceptance criteria for the CP system in 

order for CP to be credited as an input for selection of risk-ranked piping inspection locations. 

By letter dated June 12, 2013, the staff issued RAI 3.0.3.1.2-4, with Item (1) requesting that the 

applicant: 

a) State how often CP surveys will be conducted. 

b) State what parameters will be monitored during CP surveys. 

c) State how the availability of the CP system will be monitored and state the 

associated availability acceptance criterion that will be used in order to credit the 

CP system during the risk ranking process. 

d) State how the effectiveness of the CP system will be monitored and state the 

associated effectiveness acceptance criterion that will be used in order to credit 

the CP system during the risk ranking process. 

e) State the following: 

• Whether an instant on negative 850 [millivolt] mV relative to a copper/copper 

sulfate reference electrode, instant off negative 850 mV relative to a 

copper/copper sulfate reference electrode, 100 mV minimum polarization, or 

alternative acceptance criteria will be used to demonstrate the effectiveness 

of the CP system. 

• If the instant on negative 850 mV relative to a copper/copper sulfate 

reference electrode criterion is used, state how voltage drops other than 

those across the structure to electrolyte boundary will be determined. 

• If the 100 mV minimum polarization criterion is used, state how it is known 

that the effects of mixed potentials (e.g., presence of a copper grounding 
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grid) are minimal and why the most anodic metal in the system is adequately 

protected. 

• If an alternative means of demonstrating the effectiveness of the CP system 

is used, state the alternative acceptance criteria. 

f) State the upper level voltage acceptance criterion (i.e., no more negative than) 

for CP and the basis for the value. 

g) State what CP system parameters will be trended. 

h) Appropriately revise License Renewal Application (LRA) Sections A.2.1.5 and 

A.3.1.5 to reflect crediting the CP system as a preventive measure for portions of 

the buried in scope piping. 

In its response dated July 24, 2013, the applicant stated that, based on plant-specific operating 

experience, CP was installed on portions of the IP2 auxiliary feedwater/condensate buried 

piping in early 2012 and CP is currently being installed on portions of the IP3 condensate 

storage lines. The applicant also stated that, based on inspection results demonstrating limited 

coating degradation and acceptable wall thickness indicated by ultrasonic testing (UT) 

measurements, the applicant is evaluating whether installation of CP on IP2 service water 

piping is necessary. The responses to specific RAI questions are as follows: 

a) CP surveys will be conducted at least once every 12 months. 

b) The CP surveys will monitor the instant-off pipe-to-soil potentials. 

c) CP availability will be determined by calculating the percent of time that the rectifiers are 

in service (i.e., current output greater than zero volts or zero amps). Out-of-service time 

for testing is not counted against the availability. The CP availability criterion is 

85 percent or more. 

d) CP effectiveness will be determined by measuring soil-to-pipe potential. The test points 

are evaluated against an instant-off negative 850 mV relative to a copper/copper sulfate 

reference electrode criterion. If a test point does not meet this criterion, it is evaluated 

against a 100 mV polarization criterion, provided that the test location is evaluated for 

the potential (adverse) influence of mixed metals. The CP effectiveness criterion is 

80 percent or more of the test points meeting the above criteria. 

e) Acceptance criteria are as follows: 

• A soil-to-pipe instant-off negative 850 mV relative to a copper/copper sulfate 

reference electrode criterion is the preferred acceptance criterion. 

• The instant-on negative 850 mV relative to a copper/copper sulfate reference 

electrode criterion will not be used. 

• The 100 mV polarization criterion will be used when the instant-off negative 850 mV 

is not met, subject to: (a) the effect of mixed metals is evaluated; (b) for new CP 

system installations, the absence of exposed copper grounding is confirmed, and 
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3-5 

(c) for existing CP systems, corrosion monitoring probes may be installed near the 

pipe to confirm adequate protection for the in-scope buried components. 

• The use of alternative means for demonstrating CP effectiveness is not anticipated. 

f) An upper voltage acceptance criterion of negative 1200 mV will be used for instant-off 

measurements. 

g) Rectifier current output, test station potential measurements, and rectifier voltage output 

will be trended. 

h) In regard to revising the LRA to reflect crediting the CP system as a preventive measure 

for portions of the buried in-scope piping, the applicant stated: 

The IPEC CP systems will not be credited as preventive measures 

for the in-scope buried piping. CP systems installed to protect 

license renewal in-scope buried piping will be used to minimize 

corrosion in areas that have been found susceptible to corrosion 

based on indirect inspections (i.e., guided wave inspections) or 

testing (e.g., APEC [area potential—earth current] surveys). To 

the extent they are proven effective, the CP systems at IPEC will 

be considered in risk ranking to ensure that the in-scope buried 

piping systems that are more susceptible to external corrosion 

continue to receive a higher risk ranking when determining 

inspection priority. Therefore, no revision to License Renewal 

Application Sections A.2.1.5 and A.3.1.5 is necessary because 

Entergy is not crediting the CP system as a preventive measure 

for in-scope buried piping. 

The staff finds the applicant’s response to RAI 3.0.3.1.2-4, Item (1), sections (a), (b), (c), (f), 

and (g) acceptable, and portions of (d) and (e) acceptable, because the periodicity of CP 

surveys, monitoring for instant-off pipe-to-soil potentials, an 85-percent availability criterion, an 

80-percent effectiveness criterion, an upper voltage limit of negative 1200 mV, and the 

parameters that will be trended are consistent with the guidance in LR-ISG-2011-03, and 

therefore are sufficient to determine whether a CP system has performed adequately enough to 

credit it for determining appropriate pipe inspection locations. 

The staff did not find the applicant’s response to other portions of (d) and (e) acceptable 

because, although LR-ISG-2011-03 allows the use of the 100 mV polarization criterion when the 

effects of mixed potentials are minimal and the most anodic metal in the system is adequately 

protected, the applicant did not provide a sufficient basis for how this will be determined. The 

staff did not find the applicant’s response to section (h) acceptable because the program and 

UFSAR supplement should reflect the purpose of the CP system (e.g., input for risk ranking of 

inspection locations) and its acceptance criteria. By letter dated September 3, 2013, the staff 

issued RAI 3.0.3.1.2-4a requesting that the applicant: (a) provide additional information related 

to the use of corrosion rate monitoring devices and coupons if the 100 mV polarization criterion 

will be used; (b) revise its Buried Piping and Tanks Inspection Program to reflect the purpose of 

the CP system and its acceptance criteria; and (c) revise the UFSAR Supplement to reflect the 

purpose of the CP system. 
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In its response dated October 3, 2013, the applicant stated that for the purposes of crediting the 

cathodic protection system, it will use the polarization potential of at least (i.e., more negative 

than) -850 mV instant-off as the CP acceptance criterion as well as an upper voltage 

acceptance criterion of -1200 mV. The applicant revised its Buried Piping and Tanks Inspection 

Program to reflect the purpose of the CP system and include the acceptance criteria as 

described above. The applicant also revised its UFSAR supplements to reflect the purpose of 

the CP system. 

The staff finds the applicant’s response to RAI 3.0.3.1.2-4a acceptable because: (a) the 

applicant will only use the -850 mV instant-off criterion with an upper voltage acceptance 

criterion of -1200 mV, (b) the program reflects the purpose of CP system and its acceptance 

criteria, (c) the UFSAR Supplements reflect the purpose of the CP system, and (d) the 

acceptance criteria and UFSAR Supplement program descriptions are consistent with the 

guidance in LR-ISG-2011-03. The staff’s concerns described in RAIs 3.0.3.1.2 4, Item (1), 

and 3.0.3.1.2-4a are resolved. 

Operating Experience. The staff noted that exhibits filed in the evidentiary record during 

hearings conducted in association with the Indian Point LRA described direct visual inspections 

of recently excavated buried in-scope piping that detected rocks in the backfill in the vicinity of 

piping. By letter dated June 12, 2013, the staff issued RAI 3.0.3.1.2 4, Item (2), requesting that 

the applicant state what criteria will be used to conduct an extent-of-condition evaluation when 

non-conforming backfill causes damage to coatings with base metal exposure, as discovered 

during excavated direct visual inspections. 

By letter dated July 24, 2013, the applicant stated that it had excavated and directly visually 

examined more than two dozen buried pipe segments and that: (a) these inspections did not 

indicate that “poor backfill quality or metal loss caused by external corrosion is a systemic issue 

at IPEC”; (b) the direct visual inspections “have not revealed evidence of damage to pipe 

coatings caused by rocks or debris in the backfill”; (c) during the inspection of three pipe 

segments in October 2012, some small rocks (less than two inches in diameter) were found to 

be in contact with the outer wrap of the buried pipe, but there was no associated damage; and 

(d) December 2012 inspections also revealed some rocks in the backfill, but they were not in 

contact with the pipe. The applicant also stated that if future inspections reveal significant 

coating damage caused by nonconforming backfill, it will double the inspection sample size. If 

adverse indications are found in the expanded inspection sample, the size of followup 

inspections will be based on an extent-of-condition and extent-of-cause analysis (subject to the 

extent of piping or tanks susceptible to the observed degradation mechanism). In addition, the 

timing of the inspections will be based on the severity of the degradation and will be 

commensurate with the consequences of a leak or loss of function from the affected pipe. The 

applicant further stated that expanded sample inspections will be completed within the 10-year 

interval in which the original adverse indication was identified. 

The staff finds the applicant’s response to RAI 3.0.3.1.2 4, Item (2), acceptable because it is 

consistent with the guidance in the “detection of aging effects” program element of 

LR-ISG-2011-03, which ensures that an appropriate expansion of inspection is conducted when 

adverse conditions are detected. The staff’s concern described in RAI 3.0.3.1.2.4, Item (2), is 

resolved. 

UFSAR Supplement. As described above, the applicant revised LRA Sections A.2.1.5 

and A.3.1.5 to describe the purpose of the CP system. The staff confirmed that these sections 

are consistent with the guidance in LR-ISG-2011-03. 
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Conclusion. On the basis of its review of the applicant's response to RAIs 3.0.3.1.2-4 

and 3.0.3.1.2-4a, and of the additional information provided by the applicant related to the 

Buried Piping and Tanks Inspection Program, the staff finds that those program elements for 

which the applicant claimed consistency with LR-ISG-2011-03 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 current licensing 

basis (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). 

3.0.3.1.9 One-Time Inspection Program 

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

information related to the One-Time Inspection Program after the issuance of Supplement 1 to 

the SER. The additional information is discussed below in the “Staff Evaluation” section. 

Staff Evaluation. The staff’s evaluation of the applicant’s proposed One-Time Inspection 

Program is documented in SER Section 3.0.3.1.9. By letter dated March 18, 2013, the applicant 

revised LRA Section B.1.27, “One-Time Inspection,” to state that the inspection sample size will 

be at least 20 percent of each material-environment population or a maximum of 

25 components, which is consistent with the guidance in AMP XI.M32, “One-Time Inspection,” 

in Revision 2 of the GALL Report. Previously, the sample size in the One-Time Inspection 

Program was based on a method that demonstrates a 90-percent confidence that 90 percent of 

the population does not experience degradation. 

The staff finds the applicant’s revised sampling methodology acceptable because it is consistent 

with the guidance in the GALL Report, Revision 2, for one-time inspections. 

The staff noted that the applicant completed the one-time inspections for the One-Time 

Inspection Program, and an NRC License Renewal Team Inspection included a review of the 

One-Time Inspection Summary report, the completed inspection tracking matrix, and multiple 

one-time inspection reports. In an NRC inspection report dated September 19, 2013, the 

inspectors concluded that the applicant had completed all actions necessary for Commitment 

No. 19 associated with this program. 

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

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

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

3.0.3.1.13 Selective Leaching Program 

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

information related to the Selective Leaching Program after the issuance of Supplement 1 to the 

SER. The additional information is discussed below in the “Staff Evaluation” section. 

Staff Evaluation. The staff’s evaluation of the applicant’s proposed Selective Leaching Program 

is documented in SER Section 3.0.3.1.13. By letter dated March 18, 2013, the applicant revised 

LRA Section B.1.33, “Selective Leaching,” to state that the inspection sample size will be at 

least 20 percent of each material-environment population or a maximum of 25 components, 
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which is consistent with the guidance in AMP XI.M33, “Selective Leaching of Materials,” in 

Revision 2 of the GALL Report. Previously, the sample size in the Selective Leaching Program 

was based on a method that demonstrates a 90-percent confidence that 90 percent of the 

population does not experience degradation. 

The staff noted that the guidance in the GALL Report, Revision 2, includes the revised sampling 

criteria described by the applicant as well as a recommendation to focus inspections on 

bounding or lead components most susceptible to aging because of time in service, severity of 

operating conditions, and lowest design margin. The applicant’s revision to the Selective 

Leaching Program did not include the additional recommendation to inspect components most 

susceptible to aging. By letter dated June 12, 2013, the staff issued RAI 3.0.3.1.13-1 requesting 

that the applicant state and justify the criteria that will be used to select the inspection locations 

in the Selective Leaching Program. 

In its response dated July 24, 2013, the applicant stated that inspections focus on the bounding 

or leading components most susceptible to aging because of time in service, severity of 

operating conditions, and lowest design margin. The applicant also stated that, where possible, 

low-flow/stagnant areas, drains, and low points are inspected because these locations are 

considered the most susceptible to aging effects. 

The staff finds the applicant’s response acceptable because the applicant’s criteria for selecting 

inspection locations are consistent with those in the updated staff guidance in the GALL Report, 

Revision 2. 

The staff noted that the applicant completed these one-time inspections for the Selective 

Leaching Program, and an NRC License Renewal Team Inspection included a review of the 

inspection sampling plan, results, and associated corrective actions. In an inspection report 

dated September 19, 2013, the inspectors concluded that the applicant had completed all 

actions necessary for Commitment No. 23 associated with this program. 

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

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

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

3.0.3.2 Programs Consistent with the GALL Report with Exceptions or Enhancements 

3.0.3.2.11 Metal-Enclosed Bus Inspection Program 

Summary of Technical Information in the Application. LRA Section B.1.20, as modified by 

letters dated May 6, 2013 and August 16, 2013, describes the Metal-Enclosed Bus (MEB) 

Inspection Program as an existing program consistent with GALL Report aging management 

program (AMP) XI.E4, “Metal Enclosed Bus,” with enhancements and exceptions. 

The applicant stated that the following MEBs are included in the program: 

• IP2 and IP3: 6.9 kilovolt (kV) bus between station auxiliary transformers and switchgear 

buses 1 through 6 

• IP3: 6.9 kV bus associated with the gas turbine substation 
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3-9 

• IP2: 480 volt (V) bus associated with Substation A 

• IP2 and IP3: 480 V bus between emergency diesel generators and switchgear buses 2A, 

3A, 5A, and 6A 

The applicant stated that the MEB Inspection Program includes the bus and bus connections, 

the bus enclosure assemblies, and the bus insulation and insulators. In addition, the applicant 

stated that a sample of the accessible bolted connections will be inspected for loose 

connections. The applicant also stated that MEB enclosure assemblies will be inspected for 

loss of material and elastomer degradation under the MEB Inspection Program instead of the 

Structures Monitoring Program for external surfaces. The applicant further stated that the 

internal parts of the MEB will be inspected for foreign debris, excessive dust buildup, evidence 

of moisture intrusion, degradation of bus insulators and insulation. The applicant indicated that 

the MEB inspection includes visual inspections as well as quantitative measurements such as 

thermography and connection resistance measurements. 

By letter dated May 6, 2013, the applicant made changes to the LRA Sections B.1.20 

and A.2.1.19 and to Commitment No. 13 regarding the MEB Inspection Program. Specifically, 

after further evaluation, the applicant concluded that the IP2 480 V bus associated with 

Substation A is not required to start the diesel fire pump (DFP). The IP2 480 V bus was 

originally included within the scope of license renewal as an enhancement to the MEB 

Inspection Program element “scope of program” because it provides AC power used to charge 

the DFP batteries. The applicant subsequently determined that the 480 V MEB is not used for 

starting the DFP but only provides AC power to maintain the charge of the DFP batteries, and it 

is the DFP batteries that deliver DC power for starting the DFP and provide power to the DFP 

control system. In addition, the applicant stated that a loss of the 480 V bus initiates an 

automatic start of the DFP using the DFP batteries. Based on its review, the applicant 

concluded that the 480 V bus associated with Substation A does not perform a license renewal 

intended function based on 10 CFR 54.4, “Scope,” and can be removed from the scope of the 

MEB Inspection Program. 

Staff Evaluation. The staff’s evaluation of the applicant’s MEB Inspection Program is 

documented in SER Section 3.0.3.1.6. After the issuance of the SER, the applicant, by letter 

dated May 6, 2013, proposed changes to Enhancement 1 of the MEB Inspection Program, as 

described above. 

The staff believed that the MEB associated with 480 V Substation A should remain within the 

scope of license renewal because it provides AC power to the DFP battery chargers. The DFP 

batteries start the DFP during fire events. Further, the staff was concerned that a failure of the 

MEB to supply the DFP battery chargers could result in depletion of the batteries, which would 

prevent the DFP from performing its license-renewal intended function. 

The staff was also concerned that removal of the MEB associated with IP2 480 V Substation A 

from the MEB Inspection Program might not be in accordance with the requirements of 

10 CFR 54.4(a)(3), which requires, in part, that all SSCs relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the Commission's 

regulation for fire protection (10 CFR 50.48, “Fire Protection”) be within the scope of license 

renewal. This is reiterated in Section 2.1.3.1.3 of Revision 1 of NUREG-1800, “Standard 

 
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Review Plan for Review of License Renewal Applications for Nuclear Power Plants,” which 

includes the following example: 

...if an NSR [nonsafety-related] diesel generator is required for safe shutdown 

under the fire protection plan, the diesel generator and all SSCs specifically 

relied upon for that generator to comply with NRC regulations shall be included 

within the scope of license renewal under 10 CFR 54.4(a)(3). Such SSCs may 

include, but should not be limited to, the cooling water system or systems relied 

upon for operability, the diesel support pedestal, and any applicable power 

supply cable specifically relied upon for safe shutdown in the event of a fire. 

By letter dated July 17, 2013, the staff issued RAI 3.0.3.2.11-1 requesting that the applicant 

provide further technical justification as to why the 480 V MEB associated with Substation A is 

not relied on to demonstrate compliance with NRC regulations. 

By letter dated August 16, 2013, the applicant stated the following to justify why 480 V MEB 

associated with Substation A is not relied on for compliance with 10 CFR 50.48: 

The IP2 diesel fire pump (DFP) serves as backup for the electric fire pumps in 

the event the electric fire pumps can’t provide the pressure required for the 

water-based fire protection systems. The DFP is designed with a number of 

features, including auto start capability, to ensure its reliability. The DFP starts 

automatically upon the following conditions. 

1. Water pressure drop in the IPEC fire main water system 

2. Loss of electrical supply to the DFP room or to the DFP auxiliaries 

Alternating current (AC) power to the DFP room is provided by a 480 VAC feed 

that utilizes cables and metal-enclosed bus (MEB) from Substation A, which is 

owned and operated by Consolidated Edison Company. The 480 VAC feed 

connects to a step-down transformer, which, in turn, is connected to a 120 VAC 

lighting panel. The lighting panel provides 120 VAC power to the dual battery 

charger located in the DFP controller panel. 

Either of two batteries can start the DFP. The batteries are charged from the 

engine alternator during DFP operation and by the battery charger during 

standby conditions. The battery charger automatically maintains the charge on 

the two batteries. A panel located in the central control room alerts the operators 

if AC power is lost and if the DFP is running. The diesel fire pump will 

automatically start as sensed by loss of Feeder 13W84, Substation A, or loss of 

AC power to the charger. 

Thus, by design, in its normal alignment, a failure of the power source to the 

battery charger will not prevent the diesel fire pump (DFP) from performing its 

intended function. Loss of AC power to the battery charger actuates an 

automatic start of the DFP using the energy stored in the batteries. Prior to a 

loss of the power source to the battery charger, the batteries will be in a charged 

state capable of starting the DFP. They will not be “depleted and unable to 

perform their intended function.” 
Aging Management Review Results 

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The components that provide power to the battery charger, including the 

480 VAC metal-enclosed bus, are not relied on to demonstrate compliance with 

the Commission's regulation for fire protection (10 CFR 50.48). Therefore, those 

components do not perform a license renewal intended function as defined in 

10 CFR 54.4. As stated above, the batteries, and not the incoming AC power 

supply, are relied upon to provide power to start the diesel fire pump (DFP) 

engine upon a valid demand for DFP operation in the event of a fire. After the 

DFP engine starts, its electrical power needs are met by an engine-driven 

alternator, which also provides power to maintain the charge on the batteries. In 

short, because the nonsafety-related AC power source (including feeder, 

substation, electrical breakers and metal-enclosed bus) is not relied upon to start 

or run the DFP, its failure will not prevent the DFP from performing its license 

renewal intended function. 

Entergy performs routine testing and monitoring associated with the DFP. On a 

weekly basis, Entergy checks the battery bank voltage and measures the 

electrolyte levels to ensure that the individual cells are charged. On a monthly 

basis, Entergy starts the DFP using the batteries and runs it for at least 

30 minutes. As part of the monthly test, Entergy confirms that the operators 

receive an alarm indicating the engine is running. An alternate battery bank is 

selected for starting the DFP for each monthly test. In addition, Entergy initiates 

a loss of power to the battery charger once a year to test the auto-start feature of 

the DFP. This test also confirms that the operators receive the charger failure 

alarm. IPEC administrative controls regarding fire system impairments specify 

the required actions, time frames, and compensatory measures to restore 

non-functional (impaired) fire protection equipment. Any condition that would 

challenge the ability of the DFP to automatically start from its normal standby 

condition (i.e., from the fully charged battery bank(s)) would render the DFP 

non-functional (impaired) and require corrective actions to restore the DFP in 

seven days. This provides additional assurance that the batteries are always 

fully charged and available to perform their intended function in supporting the 

auto start capability of the DFP. 

The staff finds that the DFP serves as backup for the electric fire pumps and is relied on to 

demonstrate compliance with NRC fire-protection regulations. However, the DFP does not 

specifically rely on the 480 V bus or battery charger to demonstrate compliance with 

10 CFR 50.48 regulations. Further, the applicant’s stated weekly DFP and battery-bank 

operability testing provides an additional means to ensure that the batteries are fully charged. 

The monthly testing includes starting and running the DFP and verification of battery voltage 

and electrolyte level. The DFP monthly test uses the batteries and confirms the DFP control 

room alarms (i.e., the DFP is running). The DFP testing also includes starting the DFP using 

alternate battery banks for each monthly test. DFP functional tests are performed every 

18 months and include verification that the DFP starts on the autostart signal with confirmation 

of charger failure alarms. Control room alarms indicate when AC power is lost and when the 

DFP is running. The DFP will automatically start on the loss of 480 V MEB and loss of power to 

the charger. DFP battery inspections are also performed every 18 months. Therefore, the staff 

concludes, in accordance with the guidance of SRP-LR Section 2.1.3.1.3, that the IP2 480 

V MEB associated with Substation A does not perform a license-renewal intended function and 

does not require aging management in accordance with 10 CFR 54.4(a)(3). The staff’s concern 

described in RAI 3.0.3.2.11-1 is resolved. 
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Based on its audit, and review of the applicant’s response to RAI 3.0.3.2.11-1, the staff finds 

that program elements one through six for which the applicant claimed consistency with the 

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

AMP XI.E4, “Metal Enclosed Bus.” In addition, the staff reviewed the revised enhancement 

associated with the “scope of program” program element and finds that the removal of the MEB 

associated with Substation A from the “scope of program,” is appropriate. 

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

UFSAR Supplement. By letter dated May 6, 2013, the applicant revised LRA Section A.2.1.19 

to remove the IP2 480 V bus associated with Substation A. The change is consistent with the 

removal of the MEB from the “scope of program” program element in LRA Section B.1.20, 

“Metal-Enclosed Bus Inspection Program.” The applicant also revised Commitment No. 13 to 

reflect the change in the MEB Inspection Program’s license renewal scope. 

The staff reviewed the revisions and finds them acceptable because, as described previously, 

the DFP does not specifically rely on the IP2 480 V bus associated with Substation A to perform 

a license-renewal intended function; therefore, the 480 V bus associated with Substation A is 

not required to be within the scope of license renewal under 10 CFR 54.4(a)(3). Therefore, the 

UFSAR supplement for the MEB Inspection Program is consistent with the corresponding 

program description in SRP-LR Table 3.0 1. 

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

May 6, 2013, is an adequate summary description of the program. 

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

3.0.3.2.15 Structures Monitoring Program 

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

information related to the Structures Monitoring Program after the issuance of SSER 1 in 

two separate letters. 

In a letter dated May 6, 2013, the applicant stated that in Amendment 5 to the LRA, which 

included an annual update to the LRA, aging management review results for sump screens, 

strainers, and flow barriers in the Structures Monitoring Program were revised as a result of a 

material change from carbon steel to stainless steel. According to the GALL Report, aging 

management is not required for material made from stainless steel in an air-indoor uncontrolled 

environment. Therefore, the annual update showed for “sump screens, strainers and flow 

barriers” that there were no aging effects requiring management (AERM) and no AMP was 

necessary. Amendment 5 updated tables in Sections 2 and 3 of the LRA, but did not update 

Appendix A, Appendix B, or the NRC commitment list. Accordingly, in the May 6, 2013, letter, 

the applicant updated Appendix A, Appendix B, and Commitment No. 25 to eliminate sump 

screens, strainers, and flow barriers from the scope of the Structures Monitoring Program. 

In a letter dated May 14, 2013, the applicant provided an update to additional information that 

was previously provided in a letter dated November 6, 2008. The applicant stated that as a 

result of additional research with respect to methods available for detection of leaks in 

water-filled structures, the action plan, as identified and documented previously in the SER for 

Unit 2 refueling cavity repair, was changed and a new course of action formulated based on 

new acoustic monitoring capabilities that have been successful at other facilities. As a result of 
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3-13 

a change in plans, the Instacote material was not applied to seal the refueling cavity liner walls 

and floors, nor was any repair work performed in 2010 or 2012. The applicant further stated 

that this change in plans does not affect the associated Commitment No. 36, which is to perform 

a one-time inspection and evaluation of the Unit 2 reactor cavity before the period of extended 

operation. Also, additional core bores will be taken and a sample of the leakage water will be 

analyzed if the leakage has not stopped before the end of the first 10 years of the period of 

extended operation. 

The applicant performed acoustic monitoring during the spring 2012 outage and identified 

five areas of leakage. According to the new action plan, the applicant will prepare a 

modification package to repair the Unit 2 reactor cavity liner and will initiate weld repairs to the 

Unit 2 cavity liner starting during the 2014 outage. The repairs may occur during multiple 

refueling outages. 

Staff Evaluation. The staff’s evaluation of the applicant’s proposed Structures Monitoring 

Program is documented in Section 3.0.3.2.15 of the SER. The staff noted that GALL Report 

Item III.B1-3.TP-8 indicates that an AMP is not necessary for stainless steel material in an 

air-indoor environment. Therefore, the staff determined that deletion of the stainless steel sump 

screens, strainers, and flow barriers located in the indoor air environment from the Structures 

Monitoring Program, as identified in the May 6, 2013, letter, is acceptable. 

Operating Experience. The staff reviewed the proposed changes to the action plan regarding 

the reactor cavity leakage as described in the May 14, 2013, letter. The staff found the change 

in action plan for detecting and repairs of reactor cavity liner plate welds acceptable because 

the applicant has used a new technology (acoustic monitoring) to locate the defective weld 

locations during the 2012 refueling outage and plans to repair the welds starting during the 

2014 refueling outage. Coating the liner plate with Instacote is not a permanent solution to 

prevent leakage through the defective welds. In addition, this change in plans does not affect 

Commitment No. 36, which states that the applicant will perform a one-time inspection and 

evaluation of a sample of potentially affected IP2 refueling cavity before September 28, 2013, to 

assess the condition of concrete and reinforcing steel in the cavity wall in an area that is 

susceptible to exposure to borated water leakage. Commitment No. 36 also states that the 

applicant will take additional core bore samples if the leakage is not stopped and the leakage 

fluid will be sampled before the end of the first 10 years of the period of extended operation. 

UFSAR Supplement. In LRA Sections A.2.1.35 and A.3.1.35, the applicant provided the 

UFSAR supplement for the Structures Monitoring Program. In a letter dated May 6, 2013, the 

applicant deleted sump screens, strainers, and flow barriers from the list of structures and 

components that require aging management in LRA Sections A.2.1.35 and A.3.1.35, and 

Commitment No. 25. The staff finds this change acceptable because stainless steel sump 

screens, strainers, and flow barriers do not require aging management. 

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

3.0.3.3 Programs Not Consistent with or Not Addressed in the GALL Report 

3.0.3.3.9 Reactor Vessels Internals 

Summary of Technical Information in the Application. LRA Section B.1.42, submitted in 

Reference 5, describes the RVI Program as a new plant-specific program. The RVI Program 

manages aging of all RVI components within the scope of license renewal for IP2 and IP3. 
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According to Tables 3.1.2-2-IP2 and 3.1.2-2-IP3, all RVI components are made from either 

stainless steels or nickel-based alloys and are exposed to environments consisting of treated 

borated water, treated borated water > 140 °F, or treated borated water > 482 °F, and the 

components may also be exposed to neutron fluence. The AERMs are change in dimensions, 

cracking, loss of material, loss of preload, and reduction of fracture toughness. 

The RVI Program is based on MRP-227-A (Ref. 3). The RVI Program relies mainly on 

inspections conducted using visual, volumetric, and surface examination techniques. The 

inspection schedules and techniques are consistent with the guidance of MRP-227-A for RVI 

designed by Westinghouse. However, the RVI Program also credits preventive actions under 

the “Water Chemistry Control—Primary and Secondary Program.” By letter dated 

September 28, 2011 (Ref. 6), the applicant submitted a detailed RVI Inspection Plan intended to 

fulfill LRA Commitment No. 30, which required submittal of the detailed RVI program 

implementing the industry program no later than 2 years before the start of the period of 

extended operation (which began on September 28, 2013, for IP2). The applicant stated that 

the September 28, 2011, RVI Inspection Plan is consistent with the staff’s safety evaluation (SE) 

of MRP-227 dated June 22, 2011. The applicant submitted a revised RVI AMP and a revised 

RVI Inspection Plan as Attachments 1 and 2 to its letter dated February 17, 2012, (Ref. 5); the 

applicant stated that these reflect the issuance of MRP-227-A. The February 17, 2012, RVI 

AMP revised the RVI AMP contained in LRA Amendment 9 dated July 14, 2010, and the RVI 

Inspection Plan replaced the September 28, 2011, RVI Inspection Plan; therefore, the staff 

based its review on the February 17, 2012, submittal. The staff’s evaluation of the RVI 

Inspection Plan is contained in Section 3.0.3.3.10 of this SER supplement. 

Staff Evaluation. Typically, for plant–specific AMPs, the staff reviews program elements one 

through six of the applicant’s program against the acceptance criteria for the corresponding 

elements as stated in Section A.1.2.3 of Revision 1 of the SRP-LR. The staff’s review generally 

focuses on how the applicant’s program manages aging effects through the effective 

incorporation of these program elements. 

After the submittal of MRP-227 and before the issuance of the safety evaluation (SE) on 

MRP-227, Revision 2 of the GALL Report was issued, providing new AMR line items and aging 

management guidance in AMP XI.M16A, “PWR Vessel Internals.” This AMP was based on staff 

expectations for the guidance to be provided in MRP-227-A. Because Revision 2 of the GALL 

Report was published before the issuance of the final SE for MRP-227-A, the staff published 

LR-ISG-2011-04, “Updated Aging Management Criteria for Reactor Vessel Internal Components 

for Pressurized Water Reactors” (Ref. 7), which modifies the guidance of AMP XI.M16A to be 

consistent with MRP-227-A. 

Therefore, because LR-ISG-2011-04 represents the most recent staff guidance for RVI 

programs, the staff used LR-ISG-2011-04 as guidance in performing its review of the elements 

of the RVI AMP rather than relying on the generic guidance of SRP-LR, Revision 1, 

Section A.1.2.3. The staff’s review of the “corrective actions,” “confirmation process,” and 

“administrative controls” programs elements are documented in Section 3.0.4 of Vol. 2 of the 

SER (Ref. 8). However, the applicant included some information for these elements specific to 

the RVI AMP, so the staff evaluation of the information specific to the RVI AMP is included in 

the appropriate subsection of this SER supplement. 

Scope of Program. LRA Section B.1.42 states that the program scope is based on the 

MRP-227-A guidelines and that the categorization of components for Westinghouse pressurized 

water reactors (PWRs) as presented in MRP-227-A applies to the IP2 and IP3 vessel internals. 
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The applicant also indicated that the component inspections identified in Tables 4-3 and 4-6 of 

MRP-227-A for Primary and Expansion group components define the scope of the IP2 and 

IP3 RVI Program inspections. Components in Table 4-9 of MRP-227-A subject to aging 

management by existing programs are also included in the program scope. RVI components 

that are not included in Table 4-3, 4-6, or 4-9 are considered to be within the program scope but 

require no specific inspections. 

The staff reviewed the applicant’s description of the “scope of program” program element 

against the criteria of Section XI.M16A of LR-ISG-2011-04, which recommend that the 

components to be inspected, inspection methods, and inspection schedules be based on 

MRP-227-A. LR-ISG-2011-04 also notes that Section XI, “Inservice Inspection of Nuclear Power 

Plant Components,” of the ASME Boiler and Pressure Vessel Code (“ASME Code”) includes 

inspection requirements for PWR removable core support structures in Table IWB-2500-1, 

Examination Category B-N-3, which are in addition to any inspections that are implemented in 

accordance with MRP-227-A. 

The staff reviewed Tables 3.1.2-2-IP2 and 3.1.2-2-IP3 in LRA Amendment 9 (Ref. (1) to confirm 

that the components within the scope of the program are consistent with MRP-227-A. The staff 

notes that the component descriptions in the AMR table are different in some cases from the 

terminology used in MRP-227-A. However, Table 5-1 of the RVI Inspection Plan (Ref. 5) 

provides cross-references of the component names from LRA Amendment 9 to the component 

names from MRP-227-A’s Primary, Expansion, and Existing Programs components for RVI 

designed by Westinghouse. The staff’s review of Table 5-1 of the RVI Inspection Plan confirms 

that all of the components in these categories from MRP-227-A have an equivalent in the AMR 

tables of LRA Amendment 9. In addition, Tables 5-2, 5-3, and 5-4 of the RVI Inspection Plan 

are essentially identical to Tables 4-3, 4-6, and 4-9 of MRP-227-A with respect to the 

components to be inspected, inspection methods, and inspection schedules for RVI 

components in the Primary, Expansion, and Existing Programs inspection categories. Because 

the AMR line items in Table IV.B2, “Reactor Vessel, Internals, and Reactor Coolant System—

Reactor Vessel Internals (PWR)—Westinghouse,” in LR-ISG-2011-04 are consistent with MRP 

227-A, conformance of the AMR tables to MRP-227-A means that the components within the 

scope of the program are also consistent with LR-ISG-2011-04. 

LRA Section B.1.42 also confirms that the components to be inspected and the nondestructive 

examination (NDE) methods are consistent with MRP-227-A. 

Based on its review of the LRA and Reference 5, the staff finds that the scope of the IP2 and 

IP3 RVI Program meets the criteria of Section X1.M16A of LR-ISG-2011-04 and is therefore 

acceptable. 

Preventive Actions. LRA Section B.1.42 states that the RVI Program is a condition monitoring 

program that does not include preventive actions. However, the applicant credits the Water 

Chemistry Control—Primary and Secondary Program with minimizing the potential for loss of 

material, stress corrosion cracking (SCC), primary water stress corrosion cracking (PWSCC), 

and irradiation-assisted stress corrosion cracking (IASCC). The applicant also noted that both 

IP units implemented a low leakage core loading pattern within the first 30 years of operation 

and that there have been no design changes to the RVI beyond those identified in industry 

guidance or recommended by Westinghouse. 

The staff reviewed the applicant’s description of the “preventive actions” program element 

against the criteria of Section XI.M16A of LR-ISG-2011-04, which states that the MRP-227-A 
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relies on PWR water chemistry control to prevent or mitigate aging effects that can be induced 

by corrosive aging mechanisms (e.g., loss of material induced by general corrosion, pitting 

corrosion, crevice corrosion, or stress corrosion cracking or any of its forms (SCC, PWSCC, or 

IASCC)). Section XI.M16A of LR-ISG-2011-04 further states that reactor coolant water 

chemistry is monitored and maintained in accordance with the Water Chemistry Program, as 

described in GALL AMP XI.M2, “Water Chemistry.” 

LRA Section B.1.41 described the existing Water Chemistry Control—Primary and Secondary 

Program as consistent with Chapter XI.M2, “Water Chemistry,” of Revision 1 of the GALL 

Report, with enhancement. The staff’s evaluation of the Water Chemistry Control Program is 

documented in Section 3.0.3.2.17 of the SER (Ref. 8), in which the staff agreed with the 

applicant’s assertion that the program was consistent with the GALL Report, Revision 1. 

The staff finds the applicant’s “preventive actions” program element to be adequate because it 

meets the criteria of Section XI.M16A of LR-ISG-2011-04 for this program element that reactor 

coolant water chemistry be monitored and maintained in accordance with the Water Chemistry 

Program, which (as noted above) is consistent (with enhancement) with the corresponding 

GALL program. 

Based on its review of the LRA, the staff finds that the criteria for the preventive actions of 

Section XI.M16A of LR-ISG-2011-04 are met; therefore, this program element is acceptable. 

Parameters Monitored/Inspected. LRA Section B.1.4.2 states that the RVI Program will monitor 

the effects of aging on the intended functions of the internals through periodic and conditional 

examinations and other aging management methods, as required. LRA Section B.1.4.2 states 

that the component inspections identified in MRP-227-A Tables 4-3 and 4-6 (for Primary and 

Expansion group components respectively) set forth the parameters monitored by the Indian 

Point Energy Center (IPEC) RVI Program inspections; it further states that the program will use 

NDE techniques to detect loss of material through wear; identify changes in dimension due to 

void swelling and irradiation growth, distortion, or deflection distortion of components; and locate 

cracks induced by SCC, PWSCC, IASCC, or fatigue/cyclical loading. LRA Section B.1.42 also 

indicated the following with regard to specific NDE techniques used to detect specific aging 

effects: 

• Loss of preload, due to thermal and irradiation-enhanced stress relaxation or creep, is 

indirectly monitored by inspecting for gross surface conditions that may indicate 

loosening in applicable bolted, fastened, keyed, or pinned connections. 

• The reduction of fracture toughness, induced by either thermal aging (thermal 

embrittlement (TE)) or neutron irradiation embrittlement (IE), is indirectly monitored by 

using visual or volumetric examination techniques to monitor for cracking in the 

components and by applying applicable reduced fracture-toughness properties in flaw 

evaluations where this is warranted. 

• Visual examinations (VT-3) will be used to detect wear and detect distortion or cracking 

through indications such as gaps or displacement along component joints and broken or 

damaged bolt locking systems. 

• Direct measurements of spring height will be used to detect distortion of the internals 

hold down spring. 
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• Enhanced visual examinations (EVT-1) will be used to detect broken components and 

crack-like surface flaws of components and welds. 

• Volumetric (ultrasonic) examinations will be used to locate cracking of bolting. 

The staff reviewed the applicant’s “parameters monitored/inspected” program element against 

the criteria of LR-ISG-2011-04 Section XI.M16A, which recommends that for plants with RVI of 

Westinghouse design, the RVI Program should meet the parameters monitored/inspected 

criteria consistent with the applicable tables in Section 4, “Aging Management Requirements,” of 

MRP-227-A. The staff verified that the parameters monitored and inspected and the methods 

identified by the applicant are consistent with the parameters monitored and the inspection 

methods from MRP-227-A Tables 4-3 and 4-6. In addition, Tables 5-2, 5-3, and 5-4 of the 

applicant’s RVI Inspection Plan provide information for the components in the three inspection 

categories (Primary, Expansion, and Existing Programs), which include the applicability 

(e.g., to IP2 and/or IP3), aging effects to be looked for, linked components for Primary and 

Expansion components, and the associated examination techniques, examination frequencies, 

and required examination coverage. The staff notes that these tables are essentially identical to 

Tables 4-3, 4-6, and 4-9 of MRP-227-A. 

Based on its review of the LRA and Reference 5, the staff finds the applicant’s description of the 

“parameters monitored/inspected” program element to be acceptable because it is consistent 

with the criteria of LR-ISG-2011-04 Section XI.M16A, which cites the guidance of MRP-227-A. 

Detection of Aging Effects. LRA Section B.1.42 states that the RVI Program will detect 

cracking, loss of material, reduction of fracture toughness, loss of preload, and dimensional 

changes (distortion) of vessel internals components in accordance with the specific provisions of 

MRP-227-A. LRA Section B.1.42 further states that the NDE systems (i.e., the combinations of 

equipment, procedure, and personnel) used to detect these aging effects will be qualified in 

accordance with MRP-228, “Materials Reliability Program: Inspection Standard for PWR 

Internals,” and that the RVI Program will conduct inspections of Primary group components as 

delineated in MRP-227-A Table 4-3. Additionally, LRA Section B.1.42 states that indications 

from EVT-1 or UT inspections may result in additional inspections of Expansion group 

components, as determined by Expansion criteria delineated in MRP-227-A Table 5-3. LRA 

Section B.1.42 further states that the relationships between Primary group component 

inspection findings and additional inspections of Expansion group components are as described 

in MRP-227-A Table 4-6. 

Based on its review of the RVI Inspection Plan (Ref. 5), the staff found that the information in 

Table 5-2 for each Primary inspection category item and Table 5-3 for each Expansion 

inspection category item, including the effect/mechanism inspected for, the examination 

method/frequency, and the required examination coverage, is consistent with MRP-227-A 

Table 4-3 (for Primary inspection category items) and Table 4-6 (for Expansion inspection 

category items). 

With respect to detection of aging effects, LR-ISG-2011-04, Chapter X1.M16A states, in part, 

that the inspection methods are defined and established in Section 4 of MRP-227-A and that 

standards for implementing the inspection methods are defined and established in MRP-228. 

LR-ISG-2011-04 also describes the inspection methods to be used for detection of various 

aging mechanisms, all of which are consistent with MRP-227-A. LR-ISG-2011-04 states that 

inspection coverages for Primary and Expansion RVI components are implemented consistent 

with Sections 3.3.1 and 3.3.2 of Revision 1 of the NRC’s SE for MRP-227. However, the staff 
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notes that these minimum inspection coverage requirements were incorporated in MRP-227-A 

as required by Condition 4 of Revision 1 of the staff’s final SE for MRP-227. Therefore, 

consistency with MRP-227-A Section 4 will ensure that this recommendation is met. 

For the Primary and Expansion group components, the staff finds that the applicant’s program 

will meet the criteria of LR-ISG-2011-04 Section X1.M16A because the applicant’s program will 

conduct inspections of these components in accordance with MRP-227-A Tables 4-3 and 4-6. 

In addition, based on the staff’s review of Tables 5-2 and 5-3 from the RVI Inspection Plan 

(Ref. 5), the item, aging effect/mechanism, examination methods, examination coverage, and 

schedules (including reexamination frequency) described are consistent with the corresponding 

information for Primary and Expansion inspection category components in Tables 4-3 and 4-6 of 

MRP-227-A, with no additional plant-specific components. The staff found, based on its review 

of the applicant’s response to Applicant/Licensee Action Item (A/LAI) 2 from the final SE for 

MRP-227, Revision 0, detailed in Section 3.0.3.3.9.3, that no components required inspection in 

the Primary or Expansion categories other than those recommended in MRP-227-A. Further, 

because the applicant’s RVI Program states that the NDE systems (i.e., the combinations of 

equipment, procedure, and personnel) used to detect these aging effects will be qualified in 

accordance with MRP-228, this criterion of LR-ISG-2011-04 Section XI.M16A is met. 

Based on its review of the LRA and Reference 5, the staff finds the applicant’s description of the 

“detection of aging effects” program element to be acceptable because the components to be 

inspected as Primary and Expansion components, the NDE methods, the schedule, and the 

qualification of NDE systems are consistent with MRP-227-A and MRP-228, as recommended 

in LR-ISG-2011-04 Section X1.M16A. 

Monitoring and Trending. LR-ISG-2011-04 Section XI.M16A recommends using the methods of 

MRP-227 Section 6 for monitoring, recording, evaluating, and trending the data from the 

program inspection results. MRP-227 Section 6 includes recommendations for flaw depth sizing 

and for crack growth determinations as well as for performing applicable limit load, linear elastic, 

and elastic-plastic fracture analyses of relevant flaw indications. LR-ISG-2011-04 

Section XI.M16A also states that “examination and re-examinations that are implemented in 

accordance with MRP-227-A, together with the criteria of MRP-228 for inspection 

methodologies, inspection procedures, and qualification of inspection personnel, provide timely 

detection, reporting, and implementation of corrective actions for the aging effects and 

mechanisms managed by the program.” 

Section 7 of the AMP, “Corrective Actions,” states that any detected condition that fails to meet 

the examination acceptance criteria must be processed through the corrective action program. 

Section 7 further states that (1) example methods for analytical disposition of unacceptable 

conditions are discussed or cited in Section 6 of MRP-227-A and (2) the evaluation methods 

include recommendations for flaw depth sizing and for crack growth determinations as well for 

performing applicable limit load, linear elastic, and elastic-plastic fracture analyses of relevant 

flaw indications. Section 7 further states that these methods or other NRC-approved evaluation 

methods may be used. However, in the staff’s final SE for MRP-227, Revision 0 (Ref. 9), the 

staff noted that in an RAI response, EPRI stated that topical report WCAP-17096-NP, “Reactor 

Internals Acceptance Criteria Methodology and Data Requirements” (Ref. 10), is the document 

that will be used as the framework to develop those generic and plant-specific evaluations 

triggered by findings in the RVI examinations, and also that the staff is currently reviewing 

WCAP-17096-NP, Revision 2. In RAI 4, the staff therefore requested that the applicant clarify 

whether the IPEC RVI Program will use the guidance of WCAP-17096-NP, Revision 2, for 

evaluating the acceptability of relevant conditions found by the inspection conducted under the 
Aging Management Review Results 

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RVI Inspection Plan. In its response to RAI 4 by letter dated June 14, 2012 (Ref. 4), the 

applicant indicated that it plans to use the guidance of WCAP-17096-NP, Revision 2, for 

evaluating the acceptability of relevant conditions found by the inspections conducted under the 

RVI Inspection Plan. RAI 4 is, therefore, resolved. 

The applicant stated in the “Detection of Aging Effects” section of the RVI Program that “[t]he 

NDE system (i.e., the combinations of equipment, procedure, and personnel) used to detect [the 

relevant] aging effects will be qualified in accordance with MRP-228.” Therefore, the staff finds 

that this criterion of LR-ISG-2011-04 Section XI.M16A is met. 

LR-ISG-2011-04 also states that the program applies applicable fracture toughness properties, 

including reductions for thermal aging or neutron embrittlement, to the flaw evaluations of the 

components in cases in which cracking is detected in a RVI component and is extensive enough 

to warrant a supplemental flaw-growth or flaw-tolerance evaluation. The staff notes that 

MRP-227-A Section 6 provides guidance on the fracture toughness properties to be used. 

Therefore, the staff finds that the applicant’s AMP meets this criterion because it will follow the 

recommendations of MRP-227-A Section 6. 

LR-ISG-2011-04 also states that (1) “[f]or singly represented components, the program includes 

criteria to evaluate the aging effects in the inaccessible portions of the components and the 

resulting impact(s) on the intended function(s) of the components,” and (2) “[f]or redundant 

components (such as redundant bolts, screws, pins, keys, or fasteners, some of which are 

accessible to inspection and some of which are not accessible to inspection), the program 

includes criteria to evaluate the aging effects in the population of components that are 

inaccessible to the applicable inspection technique and the resulting impact on the intended 

function(s) of the assembly containing the components.” In the SE for MRP-227, the staff found 

that MRP-227 adequately addresses inaccessible locations provided that Condition 4 of the SE 

is met, which required that the percentage of the total (inaccessible plus accessible) area or 

population that must be inspected is 75 percent. This recommendation is implemented in 

Primary and Expansion category component inspections specified in Tables 5-2 and 5-3 of the 

RVI Inspection Plan (Ref. 5). Because the applicant’s AMP will implement the inspection 

coverage and sampling recommendation, which are incorporated in the tables in Section 4.0 of 

MRP-227-A, the staff finds that this recommendation of LR-ISG-2011-04 is met. 

Based on its review of the LRA, the staff finds the applicant’s description of the “monitoring and 

trending” program element acceptable because the AMP is consistent with the criteria of 

LR-ISG-2011-04 Section XI.M16A for this element. 

Acceptance Criteria. LRA Section B.1.42, in the “Acceptance Criteria,” section, states that the 

RVI Program acceptance criteria are from Section 5 of MRP-227-A. LRA Section B.1.42 further 

states that Table 5-3 and Sections 5-1 through 5-3 of MRP-227-A provide the acceptance 

criteria for inspections of the Primary and Expansion group components and that the criteria for 

expanding the examinations from the Primary group components to include the Expansion 

group components are also delineated in MRP-227-A, Table 5-3. Finally, LRA Section B.1.42 

states that the examination acceptance criteria include (i) specific, descriptive, relevant 

conditions for the visual (VT-3) examinations; (ii) requirements for recording and dispositioning 

surface breaking indications that are detected and sized for length by the enhanced visual 

(EVT-1) examinations; (iii) requirements for system-level assessment of bolted assemblies with 

unacceptable volumetric UT examination indications that exceed specified limits, and 

(iv) requirements for fit up limits on physical measurements of the hold-down springs. 
Aging Management Review Results 

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The staff compared the applicant’s proposed acceptance criteria to the guidance of 

LR-ISG-2011-04 Section XI.M16A, which recommends that Section 5 of MRP-227-A 

(specifically Table 5-3 for Westinghouse-designed RVI) provides the specific examination and 

flaw evaluation acceptance criteria for the Primary and Expansion Component examinations. 

The staff finds the applicant’s reference to Section 5 and Table 5-3 of MRP-227-A to be 

acceptable because it meets the criteria of LR-ISG-2011-04. 

For baffle-former bolts, MRP-227-A Table 5-3 states that the examination acceptance criteria for 

the UT shall be established as part of the examination’s technical justification (TJ). MRP-228 

provides additional guidance on preparation of TJs. However, the IP2 and IP3 RVI Program 

does not indicate whether a TJ has been or will be developed for the baffle-former bolts. 

Therefore, in RAI 5, the staff requested that the applicant submit a TJ for the IP2 and 

IP3 baffle-former bolts or discuss the plans and schedule for development of the TJ and 

submission to the NRC. 

In its response to RAI 5 by letter dated June 14, 2012 (Ref. 4), the applicant indicated that it had 

not developed the TJ yet because the MRP-227-A inspection requirements for baffle-former 

bolts specify that the inspections must be completed by 35 EFPY (effective full-power years), 

which is expected to be reached in 2019 for IP2 and in 2021 for IP3. The applicant indicated 

that the TJ would be completed by 6 months before the inspection. The staff found the 

applicant’s response to RAI 5 acceptable because the inspection schedule is consistent with 

MRP-227-A and it clarified that the TJ will be developed before the inspection. In addition, the 

staff determined that it does not need to review the TJ to make a safety finding on the 

applicant’s AMP because (1) MRP-227-A and the staff’s final SE for MRP-227, Revision 0 do 

not specify that TJs must be submitted for staff review and approval; (2) UT examinations of 

baffle-former bolts have been performed since the late 1990’s, thus, there is reasonable 

assurance that these examinations can be implemented effectively at IP2 and IP3; and (3) 

finalizing the TJ closer to the date of the inspection will allow for the latest UT technology and 

lessons learned from previous baffle-former bolt examinations to be incorporated. The staff’s 

concern in RAI 5 is therefore resolved. 

Based on its review of the LRA, the staff finds the applicant’s description of the “acceptance 

criteria” program element acceptable because the acceptance criteria will be in accordance with 

the MRP-227-A recommendations, thus meeting the guidance of LR-ISG-2011-04 

Section X1.M16A. 

Corrective Actions. The applicant’s description of the corrective actions attribute of the program 

includes the following elements: 

• Conditions adverse to quality such as failures, malfunctions, deviations, defective 

material and equipment, and nonconformances are promptly identified and corrected. 

• In the case of significant conditions adverse to quality, measures are implemented to 

ensure that the cause of the nonconformance is determined and that corrective action is 

taken to preclude recurrence. 

• In addition, the cause of the significant condition adverse to quality and the corrective 

action implemented is documented and reported to appropriate levels of management. 

• The Entergy Quality Assurance Program (under Appendix B, “Quality Assurance Criteria 

for Nuclear Power Plants and Fuel Reprocessing Plants,” to 10 CFR Part 50, “Domestic 
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Licensing of Production and Utilization Facilities”), including relevant corrective action 

controls, applies to the RVI Program. Any detected condition that fails to meet the 

examination acceptance criteria must be processed through the corrective action 

program. 

• The evaluation methods include recommendations for flaw depth sizing and for crack 

growth determinations as well for performing applicable limit load, linear elastic, and 

elastic-plastic fracture analyses of relevant flaw indications. 

• Example methods for analytical disposition of unacceptable conditions in Section 6 of 

MRP-227 or other demonstrated and verified alternative methods may be used. 

• The alternative of component repair and replacement of PWR internals is subject to the 

applicable requirements of Section XI of the ASME Code. 

The staff reviewed the applicant’s proposed corrective actions element for the RVI Program and 

finds that it meets the criteria of LR-ISG-2011-04 Section XI.M16A. In particular, 

LR-ISG 2011-04 recommends processing any unacceptable conditions through the plant’s 

corrective action program. The applicant’s description of the corrective actions attribute 

includes provisions to use the methodologies in Section 6 of MRP-227-A or other acceptable 

alternatives to analytically disposition unacceptable conditions, which is consistent with 

LR-ISG-2011-04. In RAI 4, the staff requested additional information on the applicant’s use of 

the methodology of WCAP-17096-NP for analytically dispositioning unacceptable conditions 

(see evaluations of the “Monitoring and Trending” and “Acceptance Criteria” AMP elements for 

the staff’s evaluation of this issue). The applicant also indicated that if component repair or 

replacement are performed, these activities will meet the applicable requirements of Section XI 

of the ASME Code, which is also consistent with the criteria of LR-ISG-2011-04. The staff 

therefore finds the corrective actions element of the applicant’s program to be acceptable. 

LR-ISG-2011-04 Section XI.M16A also allows the option of using previously approved 

alternative corrective action bases. However, the applicant did not cite any such bases. 

Additionally, the staff’s review and acceptance of the IPEC generic corrective actions process is 

documented in Section 3.0.4 of THE SER (Ref. 8). 

Based on its review of the LRA, the staff finds the applicant’s “corrective actions” program 

element acceptable because the description is consistent with the criteria of LR-ISG-2011-04 

Section XI.M16A for this program element. 

Confirmation Process. The applicant referred to Section B.0.3 of the LRA for a description of 

this attribute. This attribute is generic for all the IPEC AMPs. 

The staff’s review and acceptance of the applicant’s confirmation process is documented in 

Section 3.0.4 of NUREG-1930 (Ref. 8). 

Regarding the Confirmation Process, LR-ISG-2011-04 Section XI.M16A states that site quality 

assurance procedures, review and approval processes, and administrative controls are 

implemented in accordance with the recommendations of Nuclear Energy Institute (NEI) 03-08, 

“Guidelines for the Management of Materials Issues” (Ref. 11), and the requirements of 

Appendix B to 10 CFR Part 50 or their equivalent as applicable. LR-ISG-2011-04 

Section XI.M16A further states that the implementation of the guidance in MRP-227-A, in 

conjunction with NEI 03-08 and other guidance documents, reports, or methodologies cited in 
Aging Management Review Results 

3-22 

this AMP, provides an acceptable level of quality and an acceptable basis for confirming the 

quality of inspections, flaw evaluations, and corrective actions. 

The RVI AMP states in the program description that IPEC will implement and maintain the RVI 

Program in accordance with the guidance in Addendum A, “RCS Materials Degradation 

Management Program Guidelines,” to NEI 03-08 and that any deviations from mandatory, 

needed, or good-practice implementation activities established in MRP-227-A or MRP-228 will 

be managed in accordance with the NEI 03-08 implementation protocol. 

Because the attributes of the applicant’s confirmation process (including conformance to 

Appendix B to 10 CFR 50) were approved in the SER (Ref. 8) and the AMP also meets the 

guidance of NEI 03-08, the staff finds that the applicant’s confirmation process is consistent with 

LR-ISG-2011-04 Section XI.M16A and is therefore acceptable. 

Administrative Controls. The applicant referred to Section B.0.3 of the LRA for a description of 

this attribute. This attribute is generic for all of the IPEC AMPs. 

The staff’s review and acceptance of the applicant’s administrative controls attribute is 

documented in Section 3.0.4 of the SER (Ref. 8). This attribute is not changed by this 

amendment. Therefore, the staff considers the administrative controls as applied to the RVI 

Program to be acceptable. 

LR-ISG-2011-04 Section XI.M16A states that the administrative controls for these types of 

programs, including their implementing procedures and review and approval processes, are 

implemented in accordance with the recommended industry guidelines and criteria in NEI 03-08, 

and are under existing site 10 CFR 50 Appendix B Quality Assurance Programs, or their 

equivalent, as applicable. LR-ISG-2011-04 Section XI.M16A further states that the evaluation in 

Section 3.5 of the NRC's SE, Revision 1, of MRP-227 provides the basis for endorsing 

NEI 03-08, and that this includes endorsement of the criteria in NEI 03-08 for notifying the NRC 

of any deviation from the inspection and evaluation (I&E) methodology in MRP-227-A and for 

justifying the deviation no later than 45 days after its approval by a licensee executive. 

The RVI AMP states in the program description that IPEC will implement and maintain the RVI 

Program in accordance with the guidance in Addendum A to NEI 03-08 and that any deviations 

from mandatory, needed, or good practice implementation activities established in MRP-227-A 

or MRP-228 will be managed in accordance with the NEI 03-08 implementation protocol. 

Conformance to the NEI 03-08 implementation protocol, as stated in the RVI AMP Program 

Description, will ensure that the criteria of LR-ISG-2011-04 Section XI.M16A regarding 

administrative controls are met, including notification of the NRC of any deviations from 

MRP-227-A guidance. 

Because the staff concluded in the SER that the applicant’s administrative controls are in 

accordance with Appendix G, “Fracture Toughness Requirements,” to 10 CFR 50 and that the 

RVI AMP meets the NEI 03-08 implementation requirements, including notification of the NRC 

of deviations from MRP-227-A, the staff finds that the administrative controls element of the RVI 

AMP is consistent with LR-ISG-2011-04 Section XI.M16A and is therefore acceptable. 

Operating Experience. LRA Section B.1.42 summarizes operating experience related to the 

RVI Program. Because this is a new program and IPEC has not implemented any RVI 

inspections using the guidance of MRP-227-A, there is no plant-specific operating experience. 
Aging Management Review Results 

3-23 

The applicant discussed the applicable industry experience related to RVI, particularly the 

experience related to baffle-former bolt cracking. The applicant indicated that it has 

appropriately responded to industry operating experience for RVI and cited as an example the 

replacement of guide-tube support pins (split pins) in both units. The applicant also indicated 

that it recognizes cracking of baffle-former bolts as a potential issue for the IPEC units and has 

been monitoring industry developments and recommendations regarding these components. 

The applicant also discussed the experience at IPEC with implementing the required ASME 

Section XI inspections of RVI, which consist of visual VT-3 inspections, in which it has found no 

degradation. The applicant also stated that as implemented, this program will account for 

applicable future operating experience during the period of extended operation. 

In the “Monitoring and Trending” section, LRA Section B.1.42 states that records of inspection 

results are maintained in a way that allows comparison with subsequent inspection results. LRA 

Section B.1.42 additionally states that IPEC will share inspection results with the industry in 

accordance with the good-practice recommendations of MRP-227-A and that IPEC will provide 

a summary report of all inspections and monitoring, items requiring evaluation, and new repairs 

to the MRP Program Manager. The IPEC-specific results will be incorporated in an overall 

industry report that will track industry progress and will aid in evaluation of potentially significant 

issues, identification of fleet trends, and determination of any needed revisions to the 

MRP-227-A guidelines. 

LR-ISG-2011-04 Section XI.M16A states, with respect to operating experience, that the review 

and assessment of relevant operating experience for its impacts on the program, including 

implementing procedures, are governed by NEI 03-08 and Appendix A of MRP-227-A, and that, 

consistent with MRP-227-A, the reporting of inspection results and operating experience is 

treated as a “Needed” category item under the implementation of NEI 03-08. LR-ISG-2011-04 

Section XI.M16A further states that the program is informed and enhanced when necessary 

through the systematic and ongoing review of both plant-specific and industry operating 

experience, as discussed in Appendix B of the GALL Report, which is documented in 

LR-ISG-2011-05, “Ongoing Review of Operating Experience.” 

The information from Section 5 of the AMP is consistent with the recommendation in 

Chapter XI.M16A of Revision 2 of the GALL Report for participation in the industry’s monitoring 

and trending effort with respect to operating experience (OE). In addition, in the staff’s 

evaluation of the RVI Inspection Plan in Section 3.0.3.3.10, the staff found that IPEC’s RVI 

Program complies with the reporting requirements of MRP-227-A Section 7, which are 

consistent with NEI 03-08. 

MRP-227-A, Appendix A summarizes industry operating experience regarding age-related 

degradation of RVI components through 2010, including a failure of clevis insert bolts at one 

Westinghouse-design reactor in 2010. Subsequent to the issuance of MRP-227-A, new 

information became available. Specifically, an apparent cause analysis by the affected licensee 

indicated that the most likely cause of the bolt failures is PWSCC. Therefore, in RAI 17, the 

staff requested that the applicant address this recent operating experience, and either modify its 

inspection requirement for the IP2 and IP3 clevis insert bolts as necessary to manage the 

effects of PWSCC or provide a technical justification for the adequacy of the existing inspection 

requirements. In its September 27, 2013, response to RAI 17 (Ref. 12), the applicant provided 

a technical justification for the adequacy of the existing inspection requirements. The applicant 

cited Westinghouse InfoGram IG-10-1, “Reactor Internals Lower Radial Support Clevis Insert 

 
Aging Management Review Results 

3-24 

Cap Screw Degradation,” dated March 31, 2010 (Ref. 13), in support of its response. The key 

points of the applicant’s response are summarized as follows: 

• The main design function of the lower radial support system (LRSS), of which the clevis 

insert bolts (capscrews) are a part, is the prevention of tangential or rotational motion of 

the lower internals assembly while permitting axial displacement and differential radial 

expansion. These supports are designed to prevent excessive tangential displacement 

of the lower internals during seismic events and loss-of-coolant accident (LOCA) 

conditions and also to limit displacements and misalignments in order to avoid 

overstressing the core barrel and to ensure that the control rods can be freely inserted. 

• The main aging effect of concern is wear due to flow-induced vibration. Failure of 

capscrews could result in increased wear, which would occur over several cycles (as 

well as during seismic events and LOCA conditions) and does not impact the function of 

the LRSS. This is based on the OE at the plant that had experienced clevis insert bolt 

failures. 

• There is a high degree of redundancy in the LRSS. Both IP2 and IP3 have six radial 

supports spaced at 60-degree intervals around the circumference of the reactor pressure 

vessel (RPV). Because of the small clearances involved, it is unlikely that complete 

disengagement of the clevis inserts would occur. If one clevis insert became 

nonfunctional, the other lower radial supports are capable of resisting all of the internal 

and external asymmetric loads. 

• Crack detection before bolt failure is not required because of inherent design 

redundancy. 

• Westinghouse performed an evaluation of the potential for creation of loose parts (and 

damage from loose parts) caused by clevis insert bolt degradation and concluded that 

no significant degradation of mechanical components is expected as a result of potential 

loose parts in the primary system. This is because separated capscrew heads will 

remain captured in the clevis insert counterbores. Although lock bars experienced 

wear-related degradation at the plant with the bolt failures, the potential for damage from 

loose lock bars is minimal. 

• The visual inspections performed using video cameras during each ten-year interval 

under ASME Code Section XI are capable of identifying wear or dislodged components 

of the clevis insert capscrews or dowel pins at any location, if they exist. 

• The Alloy X-750 material used in the IP2 and IP3 clevis insert bolts is not in the most 

susceptible heat-treatment condition for PWSCC. 

Although the applicant stated in its response to RAI 17 that the ASME Code Section XI video 

camera inspections are capable of identifying wear or dislodged components of the clevis insert 

capscrews or dowel pins, the staff requested additional clarification in RAI 17-A regarding the 

ASME Code Section XI inspection of the clevis inserts in order to ensure that the type of 

degradation documented in Westinghouse lnfoGram IG-10-1 would be reliably detected at IP2 

and IP3. 

In its June 9, 2014, response to RAI 17-A (Ref. 14), the applicant stated that the clevis insert 

bolts at IP2 and IP3 are inspected as part of the Category B-N-2 Item Number B13.60 
Aging Management Review Results 

3-25 

inspections. The response also states that at IPEC, the ASME Code Section XI examination of 

the clevis inserts directly views all the clevis insert bolt heads, dowel pins, and locking devices 

for each clevis insert and, therefore, Entergy’s ASME Code Section XI inservice inspection (ISI) 

program does not require modification. Also, the applicant stated that the most recent ASME 

Code Section XI inspection of the clevis insert bolts was conducted at IP2 in 2006 with no 

recordable indications and at IP3 in 2009 with no recordable indications. 

The staff evaluated the information provided by the applicant in response to RAI 17 and 

RAI 17-A. The staff also considered the latest information related to clevis insert bolt OE 

presented by the Pressurized Water Reactor Owners Group (PWROG) during the June 2014 

“Industry and NRC Coordination Meeting Materials Program Technical Exchange” (Ref. 15). 

The PWROG presentation indicated that 29 of the 48 bolts at a U.S. nuclear power plant were 

either partially or completely fractured, while only 7 of these failed bolts were detected visually. 

The PWROG information also indicated that visual inspections may not detect every failed bolt. 

However, the PWROG noted that bolt failure is primarily a commercial (economic) rather than a 

safety issue, that there is no immediate safety issue, and that visual inspection of wear surfaces 

and general condition will provide the appropriate level of aging management without the need 

for bolt inspections. The PWROG plans to issue a technical bulletin that will recommend 

(a) performing VT-3 examination to look for specific conditions of the interfacing surfaces of the 

radial keys, clevis inserts, and bolt heads that would indicate the functional performance of the 

LRSS and (b) managing bolt degradation to reduce economic risk. 

The OE also supports the applicant’s position that crack detection before bolt failure is not 

needed because the problem was detected by means of complete failures of several bolts out of 

the population while the overall design function of the LRSS was not compromised. 

A higher-resolution visual examination than the VT-3 visual examination currently performed, 

consisting of an EVT-1 enhanced visual examination, would not be more effective than the VT-3 

examination at detecting cracked bolts before they completely fail, because the cracking 

occurred in the bolt shank-to-head region, which is hidden. The only other inspection option is 

UT inspection. Requiring UT for the clevis insert bolts, which would probably involve significant 

tooling and procedure development, is not warranted at this time based on the limited number of 

failures of these bolts and the high degree of redundancy in the LRSS. Because the applicant 

confirmed that its ASME Code Section XI VT-3 examination of the clevis inserts directly views 

the bolt heads, dowel pins, and locking devices, the ASME Code Section XI examination should 

detect failed bolts. Although not all failed or cracked bolts were detected visually at the plant 

that experienced the clevis insert bolt failures, enough failed bolts were detected to alert the 

licensee that there was a problem before the function of the LRSS could be compromised. 

Therefore, the staff finds that the licensee’s VT-3 visual examination of the clevis insert bolts is 

adequate to manage aging of these bolts. 

Based on its evaluation of the applicant’s responses to RAIs 17 and 17-A, the staff finds that the 

applicant has provided an adequate technical justification for maintaining the current 

MRP-227-A inspection requirements for the clevis insert bolts. The staff’s concerns in RAI 17 

and RAI 17-A are thus resolved. 

During its review, the staff found no operating experience to indicate that the applicant’s 

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

extended operation. 

Based on its review of the LRA as modified by Reference 5, the staff finds the applicant’s 

“operating experience” program element to be acceptable because it (a) meets the criteria of 
Aging Management Review Results 

3-26 

LR-ISG-2011-04 Section XI.M16A by providing for a systematic and ongoing review of 

plant-specific and industry operating experience and (b) conforms to the guidance of NEI 03-08 

with regard to reporting of operating experience. Further, the staff finds that the applicant has 

appropriately responded to past operating experience such as that related to SCC of split pins 

and the recent OE related to clevis insert bolts. 

UFSAR Supplement. LRA Sections A.2.1.41 and A.3.1.41, as amended in Reference 5, provide 

the UFSAR supplements for the RVI Program. 

The staff reviewed this UFSAR supplement description of the program against the description 

for AMP XI.M16A in revised SRP-LR Table 3.0-1 in LR-ISG-2011-04 and noted that the UFSAR 

supplement is consistent with the description of the program in Table 3.0-1 in LR-ISG-2011-04 

and is therefore acceptable. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program. 

Conclusion. On the basis of its review of the applicant’s RVI AMP, 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 FSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.3.10 Reactor Vessel Internals Inspection Plan 

This section contains the staff’s evaluation of the applicant’s RVI Inspection Plan, as amended 

in Reference 5. The RVI Inspection Plan is not an AMP; rather, it is a more detailed document 

that implements the elements of the RVI AMP. As such, the RVI Inspection Plan is a supporting 

document for the staff’s review of the RVI AMP. An important aspect of the RVI Inspection Plan 

is the applicant’s responses to the eight A/LAIs from the staff’s final SE for MRP-227 dated 

December 16, 2011 (Ref. 9). The staff’s review of the RVI Inspection Plan focused on assuring 

that these action items have been adequately addressed. The staff also reviewed the 

applicant’s RVI Inspection Plan for general consistency with MRP-227-A with respect to the 

categorization of components for inspection, inspection methods, acceptance criteria, criteria 

triggering expansion of inspections, and evaluation methods for relevant conditions found during 

inspections. 

This subsection is divided into the following subsections: an overview of the process used to 

develop the MRP-227-A aging management recommendations; regulatory evaluation; a brief 

summary of the major sections of the applicant’s RVI Inspection Plan; the staff’s technical 

evaluation of the RVI Inspection Plan, focusing on the A/LAIs and conditions of the staff’s final 

SE for MRP-227, Revision 0; and the staff’s conclusions. 

Overview of the MRP-227-A Process. As the initial step in the process for developing the 

inspection recommendations of MRP-227-A, components were screened for eight different 

aging mechanisms. Components determined to be below the screening criteria for all aging 

mechanisms were designated Category A while those exceeding the criteria for at least 

one mechanism were designated “non-A.” For the “non-A” components, failure modes, effects, 

and criticality analyses (FMECA) were performed to categorize each component as Category A, 

B, or C, with A being the least affected and C being the most affected. The components 

determined to belong to Category A in the initial screening were also reviewed by the FMECA 

expert panel to confirm their Category A status. Category B and C components were 
Aging Management Review Results 

3-27 

determined to need further evaluation and were subject to a functionality assessment. As a 

result of the functionality assessment, each RVI component was assigned to one of 

four functional groups: 

• Primary: those PWR internals that are highly susceptible to the effects of at least 

one of the eight aging mechanisms were placed in the Primary group. 

MRP-227-A generally specifies inspections of Primary components or other 

aging management activities, such as analyses, with most inspections required 

within two refueling outages of the start of the period of extended operation. The 

Primary group also includes components which have shown a degree of 

tolerance to a specific aging degradation effect, but for which no highly 

susceptible component exists or for which no highly susceptible component is 

accessible. 

• Expansion: those PWR internals that are highly or moderately susceptible to the 

effects of at least one of the eight aging mechanisms, but for which functionality 

assessment has shown a degree of tolerance to those effects, were placed in the 

Expansion group. The schedule for implementation of aging management 

requirements for Expansion components will depend on the findings from the 

examinations of the Primary components at individual plants. 

• Existing Programs: those PWR internals in the Existing Programs group are 

susceptible to the effects of at least one of the eight aging mechanisms, and 

generic and plant-specific existing AMP elements are capable of managing those 

effects. 

• No Additional Measures: those PWR internals for which the effects of all eight 

aging mechanisms are below the screening criteria were placed in the No 

Additional Measures group. Additional components were placed in the No 

Additional Measures group as a result of FMECA and the functionality 

assessment. No further action is required by these guidelines for managing the 

aging of the No Additional Measures components. 

Aging management strategy development combined the results of functionality assessment with 

component accessibility, operating experience, existing evaluations, and prior examination 

results to determine the appropriate aging management methodology, baseline examination 

timing, and the need for and timing of subsequent inspections. 

Augmented inspection recommendations are identified for each Primary and Expansion 

category component. The recommendations for the Primary components also identify timelines 

for the inspection. The inspection strategy generally employs VT-3 level visual examinations to 

evaluate general component condition, EVT-1 level enhanced visual examinations to identify 

surface-breaking flaws, and VT-1 level visual examinations to identify surface discontinuities 

such as gaps. Cracking in baffle-former bolts and core shroud bolts is monitored with 

UT techniques. 

Regulatory Evaluation. 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for 

Nuclear Power Plants,” addresses the requirements for reactor license renewal. The regulation 

in 10 CFR Section 54.21, “Contents of Application—Technical Information,” requires that each 

application for license renewal contain an integrated plant assessment (IPA) and an evaluation 

of time-limited aging analyses (TLAAs). The plant-specific IPA shall identify and list those 
Aging Management Review Results 

3-28 

structures and components subject to an AMR and demonstrate that the effects of aging 

(e.g., cracking, loss of material, loss of fracture toughness, dimensional changes, and loss of 

preload) will be adequately managed so that the intended functions of those structures and 

components will be maintained consistent with the CLB for the period of extended operation as 

required by 10 CFR 54.29(a). In addition, 10 CFR 54.22, “Contents of Application—Technical 

Specifications,” requires that an LRA include any technical specification (TS) changes or 

additions necessary to manage the effects of aging during the period of extended operation as 

part of the LRA. 

Structures and components subject to an AMP shall encompass those structures and 

components that (1) perform an intended function, as described in 10 CFR 54.4, without moving 

parts or without a change in configuration or properties and (2) are not subject to replacement 

based on a qualified life or specified time period. These structures and components are referred 

to as “passive” and “long-lived” structures and components, respectively. 

On January 12, 2009, EPRI submitted Revision 0 of MRP-227 for NRC staff review and 

approval; it was intended as guidance for applicants in developing their plant-specific AMP for 

RVI components. 

After the submittal of MRP-227 and before the issuance of the staff’s SE for MRP-227, 

Revision 2 of the GALL Report was issued, providing new AMR line items and aging 

management guidance in AMP XI.M16A, “PWR Vessel Internals.” This GALL AMP was based 

on staff expectations for the guidance to be provided in MRP-227-A. 

Revision 1 to the final SE for MRP-227, Revision 0, was issued on December 16, 2011 (Ref. 9), 

with seven conditions and eight A/LAIs. The topical report conditions were specified to ensure 

that certain information was revised generically in the final NRC-approved version of MRP-227 

(MRP-227-A) and the A/LAIs were specified for applicants and licensees to address 

plant-specific issues which could not be resolved generically in Revision 1 of the final SE for 

MRP-227-A. On January 9, 2012, EPRI published the NRC-approved version of the topical 

report, MRP-227-A (Ref. 3). MRP-227-A contains a discussion of the technical basis for the 

development of plant-specific AMPs for RVI components in PWR vessels and also provides 

inspection and evaluation guidelines for PWR applicants to use in their plant-specific AMPs. 

MRP-227-A provides the basis for renewed license holders to develop plant-specific inspection 

plans to manage aging effects on RVI components, as described by their FSAR commitments. 

The scope of components considered for inspection under MRP-227-A includes core support 

structures (typically denoted as Examination Category B-N-3 by ASME Code Section XI) and 

those RVI components that serve an intended license renewal safety function under criteria in 

10 CFR 54.4(a)(1). The scope of the program does not include consumable components such 

as fuel assemblies, reactivity control assemblies, and nuclear instrumentation because these 

components are not typically within the scope of the components that are required to be subject 

to an AMP, as defined by the criteria in 10 CFR 54.21(a)(1). 

Because Revision 2 of the GALL Report was published before the issuance of the final SE for 

MRP-227-A, the staff published LR-ISG-2011-04 (Ref. 7), which modifies the guidance of 

AMP XI.M16A to be consistent with MRP-227-A. 

The IP2 and IP3 LRA contained a list of commitments. Commitment No. 30 states: “For aging 

management of the RVI, IPEC will (1) participate in the industry programs for investigating and 

managing aging effects on reactor internals; (2) evaluate and implement the results of the 
Aging Management Review Results 

3-29 

industry programs as applicable to the reactor internals; (3) upon completion of these programs, 

but not less than 24 months before entering the period of extended operation, submit an 

inspection plan for reactor internals to the NRC for review and approval.” 

By letter dated September 28, 2011, Entergy submitted the “Indian Point Energy Center 

Reactor Vessel Internals Inspection Plan” (RVI Inspection Plan) intended to satisfy Item #3 of 

Commitment No. 30 to the License Renewal Application regarding the Aging Management 

Programs for RVI (Ref. 6). By letter dated February 17, 2012 (Ref. 5), Entergy submitted a 

revised RVI Inspection Plan reflecting the issuance of MRP-227-A. 

Technical Evaluation. The staff reviewed the RVI Inspection Plan to determine whether it 

demonstrated that the effects of aging on the subject RVI components covered by the report 

would be adequately managed so that the components’ intended functions would be maintained 

consistent with the current licensing basis for the period of extended operation, in accordance 

with 10 CFR 54.21(a)(3). Revision 1 of the SE for MRP-227, Revision 0, concluded that the 

MRP-227, Revision 0, report provides an acceptable demonstration that PWR applicants for 

license renewal will adequately manage the aging effects of the RVI components within the 

scope of the report, provided that the conditions and the A/LAIs in the SE are met. MRP-227-A 

incorporated all the conditions from the staff’s SE. Therefore, the staff’s technical evaluation of 

the RVI Inspection Plan focused on determining whether the plan is consistent with the 

recommendations of MRP-227-A and whether it addresses the plant-specific A/LAIs. 

Action Items from Safety Evaluation of MRP-227, Revision 0. The staff’s final SE for MRP-227, 

Revision 0 (Ref. 9), contained eight A/LAIs. The staff determined that A/LAIs 1, 2, 3, 5, 7, and 8 

are applicable to IPEC and that A/LAIs 4 and 6 are not applicable to Westinghouse-designed 

RVI and therefore are not applicable to IPEC. 

A/LAI 1 

According to Section 4.2.1 of Reference 9, each applicant or licensee is responsible for 

assessing its plant’s design and operating history and demonstrating that the approved version 

of MRP-227 is applicable to the facility. The action item states that each applicant or licensee 

shall refer, in particular, to the assumptions regarding plant design and operating history made 

in the FMECA and functionality analyses for reactors of their design (i.e., by Westinghouse, 

Combustion Engineering (CE), or Babcock & Wilcox (B&W)) which support MRP-227 and 

describe the process used for determining plant-specific differences in the design of their RVI 

components or plant operating conditions which result in different component inspection 

categories. The action item also states that the applicant or licensee shall submit this 

evaluation for NRC review and approval as part of its application to implement the approved 

version of MRP-227. 

Applicant Evaluation 

The applicant stated that IPEC has assessed its plant design and operating history and 

has determined that MRP-227 is applicable to its facility. The applicant further stated 

that the assumptions regarding plant design and operating history made in MRP-191 

(Ref. 16) are appropriate for IPEC and that there are no differences in component 

inspection categories at IPEC. The applicant additionally indicated that IP2 operated for 

the first 8 years of operation with a high-leakage core pattern and IP3 operated for the 

first 10 years with a high-leakage core pattern; thus, both units are bounded by the 

FMECA and functionality analyses which were based on the assumption of 30 years of 
Aging Management Review Results 

3-30 

operation with high leakage core loading patterns. The applicant concluded that IPEC is 

bounded by the assumptions in MRP-191. The applicant further stated that IPEC has 

always operated as a base-load plant which operates at fixed power levels and does not 

vary power on a calendar or load-demand schedule. 

Staff Evaluation 

According to Section 2.4 of MRP-227-A, the following general assumptions were made 

in the analyses used to develop the MRP-227-A inspection recommendations: 

• 30 years of operation with high leakage core loading patterns (fresh fuel 

assemblies loaded in peripheral locations) followed by implementation of 

a low-leakage fuel management strategy for the remaining 30 years of 

operation; 

• base load operation, i.e., typically operates at fixed power levels and does 

not usually vary power on a calendar or load demand schedule; and 

• no design changes beyond those identified in general industry guidance 

or recommended by the original vendors. 

MRP-227-A Section 2.4 also states that (1) the guidelines are based on a broad set of 

assumptions about plant operation which encompass the range of current plant 

conditions for the U.S. domestic fleet of PWRs and (2) the functionality assessments and 

supporting aging management strategies in MRP-231, “Materials Reliability Program: 

Aging Management Strategies for B&W Pressurized Water Reactor Internals,” and 

MRP-232, “Materials Reliability Program: Aging Management Strategies for 

Westinghouse and Combustion Engineering PWR Internal Components,” provide the 

basis for these guidelines. MRP-227-A Section 2.4 further states that these evaluations 

were based on representative configurations and operational histories, which were 

generally conservative but not necessarily bounding in every parameter. 

In RAI 6, the staff requested that the applicant provide additional information to support 

its conclusion that MRP-227-A is applicable to IP2 and IP3. In its September 28, 2012, 

response to RAI 6, the applicant provided additional detail on its process for 

demonstrating that IP2 and IP3 meet the three basic assumptions listed above, as well 

as additional details on the results of this assessment. The staff considers the following 

information from the licensee’s response to RAI 6 to be relevant: 

1. IP2 and IP3 started to change from a high-leakage to a low-leakage loading 

pattern in Fuel Cycle 6 and Fuel Cycle 4 respectively. In Fuel Cycle 6 (12/29/82) 

at 9 years of operation, IP2 switched to use of a low-low-leakage loading pattern 

(L3P), and IP3 switched to low-low in Fuel Cycle 7 (6/24/1984). Then, in Fuel 

Cycle 12 (4/20/93) at 19 years of operation, IP2 switched to use of a 

low-low-low-leakage loading pattern (L4P); IP3 made the same change in Fuel 

Cycle 14 (4/7/2005). Therefore, the applicant stated that IP2 and IP3 meet the 

fluence and fuel-management assumptions in MRP-191 and MRP-232 and the 

criteria for application of the MRP-227-A aging management strategy. 

2. The IP2 RVI operate between Thot and Tcold, which are not less than 

approximately 514 °F (515.5 °F before stretch power uprate (SPU)) for Tcold and 
Aging Management Review Results 

3-31 

not higher than 605.8 °F (611.7 °F before SPU) for Thot. The IP3 RVI operate 

between Thot and Tcold, which are not less than approximately 517 °F (541.9 °F 

before SPU) for Tcold and not higher than 603 °F(600.8 °F before SPU) for Thot. 

The design temperature for both vessels is 650 °F. Therefore, the applicant 

stated that IP2 and IP3 historical operation is within original design-basis 

parameters and is consistent with the assumptions used to develop the aging 

management strategy in MRP-227-A with regard to temperature operational 

parameters. 

3. IP2 and IP3 have operated under base-load conditions over the life of the plant. 

4. Modifications to the IP2 and IP3 RVI made over the lifetime of the plant are those 

identified in general industry guidance or specifically directed by Westinghouse. 

IP2 and IP3 performed SPUs in 2004 and 2005, at which time analyses were 

performed on RVI components and it was determined that the structural integrity 

of the reactor internals was maintained at the SPU conditions. The design has 

been maintained over the lifetime of the plant as specified by Westinghouse, and 

IP2 and IP3 have not made any modifications since May 2007, which meets the 

requirements of MRP-227-A. Operational parameters with regard to fluence and 

temperature are compliant with criteria in MRP-227-A and the components and 

materials are the same as those considered in MRP-191. Therefore, the 

applicant stated that the IP2 and IP3 stress values are reasonably represented 

by the assumptions in MRP-191, MRP-227-A, and MRP-232. 

As described in Revision 1 of the staff’s SE for MRP-227, Revision 0, the staff did not 

specifically state that verification of the three basic bulleted assumptions above was 

sufficient to verify plant-specific applicability of the guidelines. Section 3.2.5.1 of the 

staff’s final SE for MRP-227-A provides additional background on the staff’s concerns 

regarding plant-specific applicability verification. A series of public and non-public 

meetings were conducted (References 17 through 21), at which the NRC, Westinghouse, 

the Electric Power Research Institute (EPRI), and utility representatives discussed the 

staff’s regulatory concerns and determined a path for a comprehensive and consistent 

utility response to demonstrate applicability of MRP-227-A, specifically for 

Westinghouse- and CE-designed PWR RVI. A summary of the proprietary meeting 

presentations and supporting proprietary generic design-basis information is contained in 

Westinghouse proprietary report WCAP-17780-P (Ref. 22). WCAP-17780-P provides 

background proprietary design information regarding variances in stress, fluence, and 

temperature in the plants designed by Westinghouse and CE to support NRC reviews of 

utility submittals to demonstrate plant-specific applicability of MRP-227-A. 

As a result of the technical discussions with the staff, the basis for a plant to respond to 

the NRC’s RAI to demonstrate compliance with MRP-227-A for originally licensed and 

uprated conditions was determined to be satisfied with plant-specific responses to the 

following two questions (References 19 and 21): 

Question 1: Does the plant have non-weld or bolting austenitic stainless 

steel (SS) components with 20 percent cold work or greater, and, if so, do 

the affected components have operating stresses greater than 30 ksi 

[kilopounds per square inch]? (If both conditions are true, additional 

components may need to be screened in for stress corrosion cracking, 

SCC.) 
Aging Management Review Results 

3-32 

Question 2: Does the plant have atypical fuel design or fuel management 

that could render the assumptions of MRP-227-A, regarding core 

loading/core design, non-representative for that plant? [Reference 19 

indicated that this question covers power uprates as well as other core 

design and fuel management aspects.] 

By letter dated October 14, 2013 (MRP 2013-025, “MRP-227-A Applicability Template 

Guideline” (Ref. 23)), EPRI provided to applicants a non-proprietary document 

containing guidance for responding to the two questions above. With respect to 

Question 1, Reference 23 provides guidance for applicants to assess whether RVI 

components at their plants, other than those identified in the generic evaluation, have 

the potential for cold work greater than 20 percent. With respect to Question 2, 

Reference 23 provides quantitative criteria to allow an applicant to assess whether a 

particular plant has atypical fuel design or fuel management. For 

Westinghouse-designed plants such as IP2 and IP3, these criteria are: 

(1) The heat generation rate must be less than or equal to 68 watts/cm3. 

(2) The maximum average core power density must be less than 124 watts/cm3. 

(3) The active fuel to upper core plate (UCP) distance must be greater than 

12.2 inches. 

The staff’s review of Reference 23, and the supporting technical information in 

WCAP-17780-P will be documented and issued in the near future. The staff has 

determined that if an applicant or licensee demonstrates that its plant(s) comply with the 

guidance in MRP 2013-025, there is reasonable assurance that the I&E guidance of 

MRP-227-A will be applicable to the specific plant(s). The guidance in MRP 2013-025 

provides an acceptable basis for licensees to prepare responses to the generic 

RAI questions. The staff has further determined that the recommended criteria provide 

(1) a systematic process for an applicant or licensee to assess whether its RVI contain 

cold-worked materials that may be susceptible to SCC and (2) quantitative measures of 

whether a plant is operating with a low-leakage core design as assumed by MRP-227-A. 

The staff also determined that the criteria and guidance for verification of plant-specific 

applicability are acceptable because (1) the information provided on evaluation of cold 

work in WCAP-17780-P provides an adequate technical basis for the guidance in 

MRP 2013-025 for responding to Question 1 and (2) the sensitivity studies of variations 

in neutron fluence, RVI geometry, and temperature documented in WCAP-17780-P, as 

well as the information on power uprate effects on fluence and temperature documented 

in WCAP-17780-P, provide an acceptable technical basis for the guidance in MRP 

2013-025 for responding to Question 2, with the exception of one open item detailed in 

Section 3.3.2 that is not applicable to Westinghouse-designed RVI and thus is not 

applicable to IP2 or IP3. 

In RAI 6-A, the staff requested that the applicant respond to the following questions, 

which are essentially identical to the questions given in MRP 2013-025: 

1. Do the IP2 and IP3 RVI have non-weld or bolting austenitic stainless steel 

components with 20% cold work or greater, and if so do the affected 

components have operating stresses greater than 30 ksi? If so, perform a 
Aging Management Review Results 

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plant-specific evaluation to determine the aging management 

requirements for the affected components. 

2. Have IP2 and IP3 ever utilized atypical fuel design or fuel management 

that could make the assumptions of MRP-227-A regarding core 

loading/core design non-representative for that plant, including power 

changes/uprates? If so, describe how the differences were reconciled 

with the assumptions of MRP-227-A or provide a plant-specific aging 

management program for affected components as appropriate. 

In its January 16, 2014, response to RAI 6-A, Question 1 (Ref. 24), the applicant stated it 

followed the guidance of Reference 23. Specifically, the applicant stated that it 

evaluated the IP2 and IP3 RVI according to the MRP-191 industry generic component 

listings and screening criteria (including consideration of cold work as defined in 

MRP-175, “Materials Reliability Program: PWR Internals Material Aging Degradation 

Mechanism Screening and Threshold Values” (Ref. 25), noting the requirements of 

Section 3.2.3). In addition to consideration of the material fabrication, forming, and 

finishing process, the applicant stated that a general screening definition of a resulting 

reduction in wall thickness of 20 percent was applied as an evaluation limit. The 

applicant stated that it had confirmed that all of the Indian Point Unit 2 and Unit 3 

components, as applicable for the design, are included directly in the MRP-191 

component lists, except for the components identified in Table 1 of the applicant’s 

response. Table 1 of the applicant’s response listed the IP2 and IP3 components 

fabricated from materials different from the generic material identified in MRP-191. 

(These are the same components as those with the material differences evaluated in the 

applicant’s calculation audited by the staff as documented in the staff’s audit report 

(Ref. 27).) The applicant further stated that this evaluation included an evaluation of all 

modifications performed on the RVI that confirmed that no non-bolting components were 

subject to cold work greater than 20 percent as a result of construction, except for those 

components of material types already assumed to have greater than 20 percent cold 

work in the generic evaluations. Finally, the applicant concluded that there was no 

impact to the MRP-227-A sampling inspection aging management requirements as a 

result of this review. The staff finds the applicant’s response to RAI 6-A Question 1 to be 

acceptable because the applicant confirmed that all of the IP2 and IP3 RVI components 

with differences from the generic material identified in MRP-191, and those components 

affected by modifications to the RVI, do not have greater than 20 percent cold work 

unless they are already included in a material category that is generically assumed to 

have greater than 20 percent cold work (such as bolting). 

In response to RAI 6-A, Question 2, the applicant confirmed that both IP2 and 

IP3 switched to an out-in (low-leakage) core design before 30 EFPY of operation and 

stated that all future operation would use low-leakage fuel management. The applicant 

provided the specific value of the maximum average core power density for IP2 and IP3 

for the last four operating cycles, which is less than 124 watts/cm3 as specified by 

Reference 23. The applicant also provided the specific range of the heat-generation rate 

figure of merit based on the last four cycles of operation for IP2 and IP3, which did not 

exceed 68 watts/cm3. The applicant also provided the nominal distance between the top 

of the active fuel to the UCP for first 21 cycles for IP2 and the first 18 cycles for IP3, both 

of which are greater than the value of 12.2 inches required by Reference 23. For all 

three parameters, the applicant stated that these values were representative of 

anticipated future operation during the period of extended operation. Therefore, 
Aging Management Review Results 

3-34 

because the applicant’s response indicates that IP2 and IP3 meet the numerical criteria 

of Reference 23, the staff finds that IP2 and IP3 do not have atypical fuel design or fuel 

management that could make the assumptions of MRP-227-A regarding core loading or 

core design non-representative for that plant. 

In sum, the applicant adequately addressed the two factors for which the staff 

determined that additional plant-specific information was necessary to verify applicability 

of MRP-227-A to IP2 and IP3 – (1) cold work induced stress; and, (2) fuel management 

– by confirming that IP2 and IP3 comply with the criteria defined in the guidance 

document (Ref. 23). Furthermore, the applicant confirmed that IP2 and IP3 will continue 

to comply with these limits during the period of extended operation. Therefore the staff 

finds the applicant’s response acceptable, the staff’s concerns in RAI 6 and RAI 6-A are 

resolved, and Action Item 1 is resolved for IP2 and IP3. 

A/LAI 2 

According to Section 4.2.2 of Reference 9, this action item states that, to be consistent with the 

requirements addressed in 10 CFR 54.4, each applicant or licensee is responsible for identifying 

which RVI components are within the scope of LR for its facility. This action item states that 

“[a]pplicants/licensees shall review the information in Tables 4-1 and 4-2 in MRP-189, 

Revision 1, and Tables 4-4 and 4-5 in MRP-191 and identify whether these tables contain all of 

the RVI components that are within the scope of LR for their facilities in accordance with 

10 CFR 54.4.” (Note: Table 4-4 of MRP-191 is the applicable table for Westinghouse-designed 

RVI). The action item further states that “[i]f the tables do not identify all the RVI components 

that are within the scope of LR, the applicant or licensee shall identify the missing component(s) 

and propose any necessary modifications to the program defined in MRP-227, as modified by 

[the final SE for MRP-227, Revision 0], when submitting its plant-specific AMP. The AMP shall 

provide assurance that the effects of aging on the missing component(s) will be managed for 

the period of extended operation.” 

Applicant Evaluation 

The applicant stated that IPEC reviewed the information in Table 4-4 of MRP-191 and 

determined that this table contains all the RVI components that are within the scope of 

license renewal. The applicant also stated that this is shown in Table 5-7 of the 

inspection plan. 

Staff Evaluation 

The intent of this action item is to ensure that all components that are within scope of LR 

for a plant have been considered in the process used to develop the aging management 

requirements for the RVI, so that a plant-specific AMP can be developed for any 

component(s) not covered by the generic evaluation. The staff finds the applicant’s 

response to A/LAI 2 generally acceptable because the applicant verified that all of the 

IPEC RVI components are addressed in Table 4-4 of MRP-191. The staff notes that 

Table 5-1 contains a cross-index between the component designations in Entergy 

Letter NL-10-063 (LRA Amendment 9, Ref. 1) and the component names as designated 

in MRP-191, Table 4-4. All of the IPEC component designations correspond to an 

equivalent component designation in MRP-191, Table 4-4 with the exception of the 

Lower Internals Assembly—Column Cap. Therefore, in RAI 7, the staff requested that 

the applicant verify that the column cap would be subject to the same inspection 
Aging Management Review Results 

3-35 

requirements that are applied to the lower support assembly’s lower support column 

bodies (cast) in MRP-227, Table 4-6. In its September 28, 2012, response to RAI 7

(Ref. 27), the applicant confirmed that the column cap is subject to the same inspection 

requirements as the lower support column bodies (cast), because the lower support 

column and column cap form a single welded assembly that was considered as one 

complete unit denoted as the lower support column assemblies—lower support column 

bodies in MRP-191. Therefore, the column caps would be covered by the MRP-227-A 

Expansion inspection of the lower support column bodies. The staff’s concern in RAI 7 

is therefore resolved. In addition, as clarified by the applicant’s RAI 7 response, the 

staff’s review of Table 5-1 of the RVI Inspection Plan confirms that all of the RVI 

components within the scope of LR have an equivalent generic component in MRP-191 

and thus are covered by the MRP-227-A aging management recommendations. 

In its September 28, 2012, response to RAI 6 (Ref. 27), the applicant noted that there 

were some differences between materials in the IP2 and IP3 components and the 

generic material assumed for these components in MRP-191. The applicant stated that 

most of the IP2 and IP3 RVI component materials are consistent with or nearly 

equivalent to those materials identified in MRP-191 Table 4-4 for 

Westinghouse-designed plants except for a few components that were fabricated from 

CF8 cast austenitic stainless steel (CASS) material rather than the Type 304 stainless 

steel (SS) identified in MRP-191. The applicant further stated that these items, along 

with the items that were fabricated from different but essentially equivalent materials, are 

summarized in a Westinghouse proprietary letter. On April 24 and 25, 2013, as 

documented in the staff’s October 17, 2013, audit report, the staff audited the proprietary 

calculation in which the plant-specific material differences from MRP-191 are evaluated 

(Ref. 26). The staff found the applicant’s evaluation of the material differences to be 

acceptable because in all but one case, the materials were essentially equivalent to the 

generic material in MRP-191, and the applicable degradation mechanisms and the 

severity of the mechanisms are bounded by the results for the MRP-191 generic 

material. In the case mentioned above in which the plant-specific component is 

fabricated from CF8 rather than from Type 304, the applicant performed a plant-specific 

FMECA for this component that resulted in no new aging management requirements for 

this component. The staff found the applicant’s plant-specific FMECA acceptable 

because it followed the same process used to develop the generic aging management 

requirements for RVI components in MRP-227-A. 

The staff finds the applicant’s response to A/LAI 2 acceptable because the applicant 

verified that all components within the scope of LR are covered by MRP-191, which the 

staff confirmed, and the staff’s audit determined that the applicant’s evaluation of 

components found to be fabricated from materials different from the generic material 

assumed in MRP-191 was acceptable. 

A/LAI 3 

According to Section 4.2.3 of Reference 9, this action item requires applicants and licensees of 

CE and Westinghouse plants to perform a plant-specific analysis either to justify the 

acceptability of the applicant’s or licensee’s existing programs or to identify changes to the 

programs that should be implemented to manage the aging of certain components for the period 

of extended operation. The action item also requires the results of this plant-specific analyses 

and a description of the plant-specific programs being relied on to manage aging of these 

components to be submitted as part of the applicant’s or licensee’s AMP. The Westinghouse 
Aging Management Review Results 

3-36 

components identified for this type of plant-specific evaluation are the guide-tube support pins 

(split pins) (Section 4.4.3 of MRP-227-A). 

Applicant Evaluation 

The applicant described its program for aging management of the guide-tube support 

pins (split pins) in its response to this action item. The original split pins in both units 

have been replaced. At IP2, the original Alloy X-750 split pins were replaced in 1995 

with an improved Alloy X-750 Revision B material 2 made from more selective material 

with more continuous carbide coverage on the grain boundaries and tighter quality 

controls to provide greater resistance to stress corrosion cracking. The applicant further 

stated that IP2 plans to begin preliminary split-pin replacement engineering and 

walkdowns in 2014 and to replace the split pins in 2016. 

The applicant stated that at IP3 the original Alloy X-750 split pins were replaced in 2009 

with cold-worked Type 316 stainless steel, and that the cold-worked Type 316 stainless 

steel is a significant improvement over Alloy X-750. The applicant further stated that, 

based on operating experience, the IP3 split pins are expected to last through the end of 

the period of extended operation. 

Staff Evaluation 

The applicant has replaced split pins in both units with split pins fabricated with a more 

SCC-resistant material. For IP3, the applicant indicated that the replacement split pins 

are expected to last through the end of the period of extended operation. In RAI 8, the 

staff requested more detail on the operating experience supporting this conclusion and 

whether inspections of the IP3 split pins are planned during the period of extended 

operation. In RAI 8, the staff also requested more detail on the criteria for the 

replacement split pins at IP2. In its June 14, 2012, response to RAI 8 (Ref. 4), the 

applicant stated that cold-worked Type 316 split pins have been in service in PWRs 

since 1997 with no recorded failures. The applicant indicated that future replacement of 

the IP2 split pins would also use cold-worked Type 316 stainless steel. The applicant 

indicated that no inspections of split pins are currently planned for the period of extended 

operation; however, the need for inspections would be reevaluated if failures of split pins 

of the same material occurred in other PWRs. The staff reviewed the applicant’s 

response and a summary of information from the literature on the SCC susceptibility of 

cold-worked Type 316 stainless steel in PWRs in Reference 22 and concludes that the 

applicant’s response to RAI 8 with respect to the predicted life of the IP3 replacement 

split pins is acceptable because (1) there has been no OE indicating occurrence of SCC 

of Type 316 split pins and (2) the applicant will address any future related OE under its 

internal OE evaluation process. The staff’s concern in RAI 8 is thus resolved. 

The staff understands that the ASME Code VT-3 visual examination of the split pins, if 

performed, would be of limited value because the pins are mostly inaccessible for 

inspection and the ASME Code only requires visual inspection of “accessible surfaces.” 

However, because no basis for the proposed replacement date of the IP2 split pins was 

 

2 Revision B is a proprietary Westinghouse specification for Alloy X-750 material. 
Aging Management Review Results 

3-37 

provided, in RAI 16, the staff asked the applicant to justify the proposed replacement 

date for the IP2 split pins, considering that no inspections are planned before 

replacement, and to propose inspections if these are necessary to justify the 

replacement date or if replacement is delayed. In response to RAI 16, by letter dated 

November 20, 2012 (Ref. 28), the applicant provided an evaluation justifying the planned 

replacement date for the IP2 split pins. The applicant’s evaluation included a description 

of the design changes that were made in the currently installed split pins at IP2, 

compared to the original split pins. These design changes resulted in lower 

susceptibility to SCC by lowering the residual stresses, reducing stress concentration 

effects, improving surface condition, and increasing the material’s resistance to SCC. 

The applicant also noted that the pin material was procured to a newer Westinghouse 

specification which incorporates all the requirements in the Revision B specification as 

well as addressing EPRI recommendations provided in EPRI Report N-7032. The 

applicant also indicated that the material was procured to the HTH condition3, which is 

heat treated at a higher temperature than earlier heat treatments applied to Alloy X-750 

material. The applicant confirmed that the IP2 pins meet the requirements of the 

Revision B specification, the HTH condition, and the recommendations of EPRI N-7032 

through a review of the Certified Material Test Reports. 

The applicant’s response also included an evaluation of the operating experience from 

plants in the Westinghouse fleet having the same material as the IP2 spit pins. The 

evaluation normalized the operating time to split pin failure for the other plants (in terms 

of effective full-power hours (EFPH)) using an Arrhenius relationship to adjust for 

differences in the operating temperature and stress of the IP2 pins versus the pins in the 

other plants. 

The applicant’s response to RAI 16 also provided the equation for the stress caused by 

temperature in the shank region, which is a function of the pin geometry and the 

temperature range during heatup to full operating temperature. 

The applicant presented data for shank failures and failures of pin leaves for other plants 

with the Revision B material. 

For split pin shank failures, there were 12 plants and 37 individual pin failures in the data 

set. An average pin failure time of 296,700 EFPH and a standard deviation of 

48,500 EFPH were determined from the data. The projected operating time for IP2 

in 2016 of 152,000 EFPH is considerably below the lower two-standard-deviation bound 

(-2σ) of 199,700 EFPH. 

For the failures of pin leaves, only two plants had failures. The average failure time for 

the pin leaves is 238,200 EFPH and the minimum time was 232,700 EFPH. 

Based on the projected operating time for IP2 until pin replacement compared to the 

normalized operating times to pin failure from the reference plants, the applicant 

concluded there was a very low probability of split pin cracking due to SCC before the 

planned replacement date. 

 

3 high-temperature annealed and aged condition heat treatment
Aging Management Review Results 

3-38 

A review of operating experience related to Alloy X-750 split pins summarized in EPRI 

document 1002792, “Materials Handbook for Nuclear Plant Pressure Boundary 

Applications,” reveals that the HTH condition for this alloy is more resistant to SCC than 

other heat treatments applied to this alloy, but is not immune from SCC if stress levels 

are high enough and surface damage is present. The staff agrees that the design 

improvements incorporated in the currently installed Alloy X-750 split pins at IP2 should 

minimize these deleterious effects because the design improvements will reduce the 

overall stress level in the split pins and result in a better surface condition. 

The staff also reviewed the split pin failure data from other plants presented by the 

applicant. The staff estimated the failure rate of the split pins at the planned 

replacement time for IP2 by fitting the failure data for the pin shanks to two different 

statistical distributions. If a normal distribution is assumed, the probability that a pin 

would fail at 152,000 EFPH or less is 0.0014 or 0.14 percent. If a Weibull distribution is 

assumed, the failure probability at 152,000 EFPH is 0.0075 or 0.75 percent. 

The applicant also stated in its response to RAI 16 that if the planned replacement of the 

IP2 split pins is not implemented in 2016, it would provide the staff with detailed 

inspection plan for the split pins by March 2015. In RAI 16-A the staff requested the 

applicant to add a commitment to provide the inspection plan. In its 

September 27, 2013, response to RAI 16-A (Ref. 12), the applicant proposed 

Commitment No. 50 to provide the staff a detailed inspection plan for the IP2 split pins, 

including inspection methods, inspection coverage, and inspection frequency, by 

March 31, 2015, if the planned replacement of the pins would not be accomplished 

in 2016. In RAI 16-B, the staff requested the applicant to submit the schedule for initial 

inspection, inspection methods, inspection coverage, and inspection frequency for the 

IP2 split pins if the IP2 split pins are not replaced by 2016 and requested that 

Commitment No. 50 be modified accordingly. In its June 9, 2014, response to RAI 16-B 

(Ref. 14), the applicant revised Commitment No. 50 to state, “Replace the IP2 split pins 

during the 2016 refueling outage (2R22).” The staff finds the revised Commitment 

No. 50 acceptable. 

Based on the design changes made in the current IP2 split pins to reduce SCC 

susceptibility, the operating experience of other plants with material similar to the current 

IP2 split-pin material, and the staff’s independent review confirming the conservatism of 

the applicant’s life prediction for the split pins, the staff finds the applicant’s justification 

of its planned replacement date to be acceptable. The staff’s concern in RAIs 16, 16-A, 

and 16-B are thus resolved. 

The staff finds that the applicant’s plant-specific program for split pins is acceptable 

because the existing pin replacement date has been justified and the date formalized 

through a license commitment and because materials with enhanced SCC resistance 

are used or will be used for the pins. 

A/LAI 5 

According to Section 4.2.5 of Reference 9, and as applicable to IPEC, this action item requires 

applicants and licensees to identify plant-specific acceptance criteria to be applied when 

performing the physical measurements required by the NRC-approved version of MRP-227-A 

for loss of compressibility for Westinghouse hold down springs. The action item states that the 
Aging Management Review Results 

3-39 

applicant or licensee shall include its proposed acceptance criteria and an explanation of how 

the proposed acceptance criteria are consistent with the plant’s licensing basis and the need to 

maintain the functionality of the component being inspected under all licensing basis conditions 

of operation as part of its submittal to apply the approved version of MRP-227. 

Applicant Evaluation 

In response to A/LAI 5, the applicant stated that the IPEC plant-specific acceptance 

criteria for hold-down springs will be developed before the first required physical 

measurement, as will an explanation of how the proposed acceptance criteria are 

consistent with the IPEC licensing basis and the need to maintain the functionality of the 

hold-down springs under all licensing basis conditions. The applicant further stated that 

(1) the acceptance criteria will ensure that the remaining compressible height of the 

spring shall provide hold-down forces within the IPEC design tolerance and (2) if a 

plant-specific acceptance criterion is not developed for the hold-down spring, IPEC will 

replace the spring in lieu of performing the first required physical measurement. 

Staff Evaluation 

In reviewing the applicant’s response to A/LAI 5, the staff noted that MRP-227-A, 

Table 4-3, calls for direct measurement of the hold-down spring height within three 

cycles of the beginning of the license renewal period. If the first set of measurements is 

not sufficient to determine remaining life, spring height measurements must be taken 

during the next two outages in order to extrapolate the expected spring height to 

60 years. 

The staff needed clarification as to how IPEC would determine whether the first set of 

measurements could be extrapolated to demonstrate acceptable spring functionality 

through 60 years; therefore, in RAI 9, the staff requested the following information: 

(1) the specific acceptance criteria for spring height and/or hold-down force from the 

IP2/IP3 licensing basis, (2) the procedure by which the remaining hold-down forces will 

be projected to end-of-life based on one measurement, and (3) what results of the first 

spring measurements would indicate a need for successive measurements. 

In its September 28, 2012, response to RAI 9 (Ref. 27), the applicant indicated that the 

acceptance criteria are a function of spring height as a function of time relative to the 

required hold-down force. The applicant further indicated that the details of the 

measurements are proprietary and cited a Westinghouse letter. The decrease in the 

hold-down spring height is assumed to occur linearly over time. The approach linearly 

interpolates the required minimum spring height at the time of measurement between 

the spring height at startup and the minimum spring height at 60 years. If the first spring 

height measurement is less than the required height, successive (additional) 

measurements of spring height will be performed or the hold-down spring will be 

replaced. 

The staff audited the proprietary calculation of the hold-down spring acceptance criteria 

on April 24 and 25, 2013 as documented in its October 2013, audit report (Ref. 26). The 

calculation clarified the relationship of the acceptance criteria with the IP2 and IP3 

design bases. Also during the audit, Westinghouse presented information explaining the 

conservatism of assuming that the hold-down spring force decreases linearly with time. 
Aging Management Review Results 

3-40 

The staff finds the response to RAI 9 acceptable because the applicant described the 

criteria for determining whether the spring measurement is acceptable. The pre-startup 

spring height measurement and the spring height measurement to be performed later 

provide two data points for the decrease of spring height over time. Further, if the spring 

height is below what it should be according to the linear assumption, the proposed 

corrective actions are reasonable. The staff’s concern in RAI 9 is therefore closed. 

The staff finds the applicant’s response to A/LAI 5 acceptable because the applicant has 

provided a plant-specific acceptance criterion for the remaining compressible height or 

hold-down force of the hold-down spring. 

A/LAI 7 

As applicable to IPEC, this action item requires the applicants and licensees of Westinghouse 

reactors to develop plant-specific analyses to be applied for their facilities to demonstrate that 

lower support column bodies will maintain their functionality during the period of extended 

operation. These analyses should also consider the possible loss of fracture toughness in these 

components due to TE and IE. The action item further states that the plant-specific analysis 

shall be consistent with the plant’s licensing basis and the need to maintain the functionality of 

the components being evaluated under all licensing basis conditions of operation. Lastly, the 

action item states that applicants and licensees shall include the plant-specific analysis as part 

of their submittal to implement the approved version of MRP-227. 

Applicant Evaluation 

The applicant stated that the IPEC plant-specific analyses to demonstrate the lower 

support column bodies will maintain their functionality during the period of extended 

operation will include consideration of the possible loss of fracture toughness in these 

components due to TE and IE. The analyses will be consistent with the IPEC licensing 

basis and with the need to maintain the functionality of the lower support column bodies 

under all licensing basis conditions of operation. The applicant further stated that IPEC 

will submit this information to the NRC before the period of extended operation. 

Staff Evaluation 

In the aging management review tables submitted in LRA Amendment 9, the applicant 

credits the “Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic 

Stainless Steel (CASS) Program” for managing loss of fracture toughness of the lower 

core support column bodies, as well as several other CASS components. The staff’s 

SER, NUREG-1930, indicates that the staff determined that this program was consistent 

with AMP XI.M13, “Thermal Aging and Neutron Irradiation Embrittlement of Cast 

Austenitic Stainless Steel (CASS) Program,” in Revision 1 of the GALL Report. 

Section XI.M13 of Revision 1 of the GALL Report recommends supplemental visual 

inspections (equivalent to an EVT-1) for CASS RVI components that either (1) are 

susceptible to thermal aging based on chemistry and other manufacturing parameters or 

(2) receive a neutron fluence greater than 1 × 1017 n/cm2, unless it can be demonstrated 

that the stresses on the component are either compressive or low in magnitude if tensile. 

The RVI Program is credited with managing cracking of the core support column bodies 

and other CASS components. Under the RVI Program, the core support column bodies 

are Expansion components that would be subject to an EVT-1 visual examination for 

cracking due to IASCC if cracking were found in the associated Primary component. 
Aging Management Review Results 

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Because the plant-specific analysis for A/LAI 7 and the GALL Section XI.M13 Program 

could both potentially involve screening for TE or IE, stress analyses, and flaw tolerance 

evaluations, and both the RVI Program and GALL XI.M13 Program could potentially 

require inspections, in RAI 10 the staff requested that the applicant discuss the 

relationship of the two programs and the plant-specific analysis. 

In its September 28, 2012, response to RAI 10 (Ref. 27), the applicant stated that the 

RVI Program is the base program that addresses the RVI components that require aging 

management and specifies inspection requirements. The Thermal Aging and Neutron 

Irradiation Embrittlement of CASS Program at IPEC augments the RVI Program by 

evaluating the potential susceptibility of plant-specific CASS components based on 

component-specific chemistry. The staff finds the applicant’s response to RAI 10 

acceptable because it clarified the relationship and the division of activities between 

Revision 1 of the GALL Report’s XI.M13 Program and the RVI Program with respect to 

RVI CASS components. The staff’s concern in RAI 10 is thus resolved. 

The staff determined that, for IP2 and IP3, the only CASS components requiring a 

plant-specific evaluation under Action Item 7 are the lower core support column bodies 

(column caps), because these are the only Primary or Expansion category CASS 

components in Westinghouse-designed RVI. The lower core support column bodies 

(cast) are Expansion components in MRP-227-A. The applicant’s September 28, 2012, 

response to RAI 7 clarified that the lower support column bodies and column caps form 

a single welded assembly that is equivalent to the generic MRP-227-A component lower 

core support column bodies (cast). However, as clarified in the September 27, 2013, 

response to RAI 11-B (Ref. 12), only the column cap, which makes up the upper portion 

of the lower core support column body assembly, is CASS. The Primary link for the 

lower support column bodies (cast) is the control-rod guide tube’s (CRGT’s) lower flange 

welds. 

Because the applicant deferred providing the analysis for review by the staff, in RAI 11 

the staff requested additional information on the approach to be used and on the 

acceptance criteria for the plant-specific analysis, as well as a commitment to submit the 

plant-specific analysis. Section 3.3.7 of Revision 1 of the staff's final SE for Revision 0 

of MRP-227 lists three possible options for the type of plant-specific analysis used to 

fulfill the requirements of this action item. The three approaches are (1) functionality 

analyses of the set of like components, (2) component-specific flaw tolerance 

evaluations, or (3) a screening approach demonstrating that the CASS Components are 

not susceptible to thermal embrittlement, neutron embrittlement, or the combined effects 

of both. In its June 14, 2012, initial response to RAI 11 (Ref. 4), the applicant deferred 

providing the information on the approach until September 28, 2012, but proposed 

Commitment No. 47 stating that it “...will perform and submit analyses that demonstrate 

that the lower support column bodies will maintain their functionality during the period of 

extended operation considering the possible loss of fracture toughness due to thermal 

and irradiation embrittlement. The analyses will be consistent with the IP2/IP3 licensing 

basis and will be submitted prior to the PEO.” 

In its September 28, 2012, final response to RAI 11 (Ref. 27), the applicant indicated 

that the plant-specific evaluation would use a screening approach. The applicant 

provided screening criteria for susceptibility to TE based on the material chemistry, delta 

ferrite content, and casting method. The applicant cited NRC letter “License Renewal 

Issue No. 98-0030, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel 
Aging Management Review Results 

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Components,” dated May 19, 2000 (Ref. 29), as the source of the screening criteria. 

Essentially, these criteria determine the potential susceptibility to TE based on whether 

the CASS is high molybdenum or low molybdenum, the delta ferrite content, and 

whether static or centrifugal casting was used to make the component. 

The staff’s May 19, 2000, letter notes that, for CASS RVI components, there is a 

potential synergistic effect between TE and IE that could reduce the fracture toughness 

to a greater degree than would be predicted based on the additive effect of both 

mechanisms. Therefore, the staff’s May 19, 2000, letter specifies a threshold neutron 

fluence of 1 × 1017 n/cm2 above which the TE screening criteria may not be applied. For 

components subject to this potential synergistic effect, a component-specific evaluation 

was recommended that would evaluate the mechanical loading on the components. 

Supplemental inspections would be indicated for components subject to significant 

tensile stresses under any loading condition. According to MRP-191, the range of the 

maximum neutron fluence for the lower support column bodies for 

Westinghouse-designed RVI is 1 × 1022 n/cm2 to 5 × 1022 n/cm2, which is well above the 

threshold identified in the staff’s May 19, 2000, letter. Therefore, in accordance with the 

guidance of the staff’s May 19, 2000, letter, the TE screening criteria cannot be applied 

to the upper portion of the column caps. 

Because the applicant did not address the potential synergistic effect of TE and IE in its 

response to RAI 11, the staff requested that the applicant address this effect in 

RAI 11-A. In its May 7, 2013, response to RAI 11-A (Ref. 30), the applicant provided its 

revised approach for screening for loss of fracture toughness and its position on the 

need to consider the synergistic effect. The applicant described screening criteria 

similar to the TE screening criteria in the staff’s May 19, 2000, letter, with the 

modification that materials that screened out for TE would screen in for IE if the 

components receive a neutron fluence greater than or equal to 6.7 × 1020 n/cm2 

(1 displacement per atom (dpa)). 

The applicant’s justification for the modified screening criteria is summarized as follows: 

TE susceptibility of CASS depends on the distribution of the ferrite phase in the 

microstructure. If the ferrite is distributed in such a way that it forms a continuous phase, 

the material can become susceptible to brittle fracture at relatively low neutron fluences. 

Whether the ferrite can form a continuous phase is a function of the amount of ferrite in 

the material, which is the basis for the screening criteria in the staff’s May 19, 2000, 

letter. Therefore, if a CASS material screens out for TE, IE of the ferrite constituent 

would be insignificant because the ferrite phase would be isolated within the austenitic 

matrix. However, if the material did screen in for TE, there is no need to consider the 

effect of IE on the ferrite phase as well because the end-of-life (saturation) fracture 

toughness would be unacceptable because of TE alone, thus creating the need for the 

functionality analysis to be performed. The onset of IE of the austenite phase of CASS 

occurs at fluences of around 1 dpa (6.7 × 1020 n/cm2). The applicant cited 

NUREG/CR-6960, “Crack Growth Rates and Fracture Toughness of Irradiated Austenitic 

Stainless Steels in BWR [Boiling-Water Reactor] Environments” (Ref. 31), and 

NUREG/CR-7027, “Degradation of LWR [Light-Water Reactor] Core Internal Materials 

due to Neutron Irradiation” (Ref. 32), in support of the use of this fluence value. 

Therefore, the applicant concluded that the fracture toughness will either be controlled 

by TE of ferrite (for high ferrite CASS) or IE of austenite (for low ferrite CASS). 
Aging Management Review Results 

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The applicant’s response to RAI 11-A also indicated that the lower support columns 

screen in for IE based on the criteria of MRP-191 because the columns are expected to 

receive a fluence of 1 × 1022 n/cm2 (15 dpa) to 5 × 1022 n/cm2 (75 dpa) as reported in 

Table 4-6 of MRP-191. The applicant further indicated that because “the effects of 

embrittlement are only significant in the presence of pre-existing flaws (such as from the 

casting process) and tensile stresses capable of propagating these flaws, the screening 

analysis will identify regions of individual columns where thermal and irradiation effects 

could embrittle the material and would also be subject to significant tensile stresses...” 

The applicant further indicated that a functionality assessment would be conducted for 

such regions to determine the impact of column fracture on the lower core support 

columns. The applicant also stated that, based on the lack of any documented history of 

fracture in the lower core support columns, it will be assumed that only a limited number 

of columns could actually contain flaws of significant size, and that the assessment will 

evaluate distributions of fractured columns that can be tolerated without the loss of the 

critical core support function. 

The response to RAI 11-A indicated that a functionality assessment would be performed 

that would determine tolerable distributions of fractured columns, but did not provide a 

detailed basis for the incidence of flaws in the columns in the absence of inspection data 

(i.e., how many columns will be assumed to be cracked) and did not define the tensile 

stress level that would be considered significant in the functionality analysis. These 

issues were the subject of RAI 11-B. In its September 27, 2013, response to Part 1 of 

RAI 11-B (Ref. 12), the applicant provided more detail on the basis for assuming a very 

low incidence of cracking for the columns. A liquid penetrant-testing (PT) examination 

and radiography of the columns were required during manufacturing of the columns; no 

surface-breaking defects were detected on any of the columns. The applicant’s 

response also addressed the possibility of service-induced defects. The applicant’s 

response indicated that, although both IASCC and fatigue screened in as possible 

cracking mechanisms during the development of MRP-227-A, the stresses in the 

columns are too low to cause IASCC, which (according to MRP-175) would require 

stresses of 70 ksi or greater at the neutron fluence levels expected for the columns at 

IPEC, compared to the nominal normal operating stresses on the columns, which are on 

the order of 20 ksi. The response to RAI 11-B did not provide the expected neutron 

fluence for the column caps. Using the curve of stress versus dpa corresponding to 

IASCC susceptibility from MRP-191 Section 3.2, the staff determined that a stress of 

70 ksi corresponds to a neutron exposure of 7 dpa. By contrast, using the same curve, if 

the maximum stress is 20 ksi, the staff determined a neutron exposure of approximately 

60 dpa would be required for IASCC. Thus, the neutron fluence for the IP2 and IP3 

column caps is considerably less than the estimated neutron exposure for the generic 

Westinghouse lower core support columns of 15 to 75 dpa used for screening purposes 

in MRP-191. 

With respect to cracking due to fatigue, the applicant’s response to RAI 11-B indicated 

that environmentally adjusted fatigue cumulative usage factors (CUFen) have been 

calculated for the IP2 columns, and these values are less than 1.0, demonstrating that 

fatigue initiation is not expected during the life of the plant. In Part 2 of RAI 11-B, the 

staff asked if there was a specific numerical threshold representing “significant tensile 

stress.” In response, the applicant stated that there was a value in Section XI.M13 of the 

GALL Report, Revision 1, but that no complete columns were screened out based on 

stress. 
Aging Management Review Results 

3-44 

In Part 3 of RAI 11-B, the staff requested details on the materials and fabrication of the 

columns. The key parts of the applicant’s response are that the upper portion of the 

columns are statically cast Type CF-8, the lower part is wrought stainless steel, and a 

weld between the cast and wrought portions is located approximately 18 inches below 

the lower core plate. 

In Part 4 of RAI 11-B, the staff requested a summary of the most recent ASME Code 

Section XI Inservice Inspection of the lower support columns at IP2 and IP3, including 

the dates of the inspections, coverage obtained, and the size, location and orientation of 

any recordable or rejectable indications. The applicant’s September 27, 2013 response 

indicated that the most recent inspection dates for the ASME Section XI Category B-N-3 

inspection of the core support structure were May 2006 for IP2 and March 2009 for IP3, 

but for both units, only the wrought portion of the lower support column bodies below the 

dome lower support plate was inspected. The applicant further stated the inspections for 

both units were satisfactory with no recordable or rejectable indications noted. The staff 

notes that the applicant’s response to Part 4 of RAI 11-B confirms that the CASS portion 

of the columns is not accessible for the ASME Code Section XI required VT-3 visual 

examination, and that no meaningful information regarding the structural integrity of the 

columns can be obtained from the most recent ASME Code Section XI examinations of 

the columns. 

In its response to Part 5 of RAI 11-B, the applicant revised its commitment date for IP2 

to provide its detailed functionality analysis for the lower core support columns from 

March 1, 2015, to August 15, 2014, in order to provide the staff the requested 18-month 

period to review the detailed analysis before the 2016 refueling outage for IP2, during 

which the MRP-227-A Primary inspections will be performed (Commitment 47). 

During a phone call on December 18, 2013, the staff informed the applicant that the staff 

is considering the development of screening criteria for loss of fracture toughness due to 

the combined effects of TE and IE for CASS reactor RVI components, which would be 

consistent with the approach in MRP-227-A. This alternative would be based on ferrite 

content derived from certified material test reports for the CASS components. If 

applicants/licensees meet the screening criteria, a detailed analysis for CASS 

components would not be required to be submitted. 

By letter dated January 28, 2014 (Ref. 33), the applicant provided plant-specific 

information on the ferrite content and susceptibility to TE of the column caps. Based on 

its evaluation of the plant-specific material information for the column caps, the applicant 

concluded that the IP2 and IP3 column caps are not susceptible to TE because the 

column caps are low molybdenum material (Type CF8) and all have ferrite content less 

than or equal to 20 percent, as calculated from the material chemical composition from 

the certified material test report for each material heat, using Hull’s Formula (Hull’s 

Equivalent Factors). 

The staff developed updated criteria that take into account fracture toughness data on 

CASS subject to both thermal aging and neutron irradiation, as documented in 

Reference 34. The updated criteria allow screening for TE and IE of irradiated CASS 

components. According to the staff’s updated criteria, low-molybdenum statically cast 

CASS with a ferrite content less than 15 percent can be screened out for TE and any 

synergistic effects of TE and IE, and is only susceptible to IE at fluences greater than 

1 × 1021 n/cm2 (1.5 dpa). This ferrite value represents a reduction in the ferrite content 
Aging Management Review Results 

3-45 

from the screening values from the staff’s May 19, 2000, letter to accommodate possible 

combined effects. The ferrite content of the IP2 and IP3 column caps meets this 

criterion because all heats have calculated ferrite content less than 15 percent. 

Therefore, the staff finds that the IP2 and IP3 lower core support column (column caps) 

are not susceptible to TE. Because of the neutron fluence of the upper portion of the 

column caps, the column caps are susceptible to IE, but not to any potential synergistic 

effect of TE and IE. 

The staff evaluated the information provided by the applicant in its response to A/LAI 7, 

RAI 11, RAI 11-A, and RAI 11-B along with the supplementary ferrite content 

information. Based on the information on stress provided by the applicant, and the 

expected upper bound on neutron fluence for the columns, the staff finds that cracking 

due to IASCC is unlikely. Appendix B to MRP-175, "Materials Reliability Program: PWR 

Internals Material Aging Degradation Mechanism Screening and Threshold Values” 

(Ref. 25), also reported IASCC test data for CASS demonstrating extremely high 

resistance to IASCC. Therefore, the staff finds the applicant’s determination of the low 

likelihood of IASCC to be reasonable based on the low operational stresses relative to 

the IASCC threshold for CASS and the high inherent IASCC resistance of this material. 

The applicant’s CUFen values indicate that fatigue crack initiation is not expected, and 

original manufacturing flaws are not expected because of the PT examinations 

performed during manufacturing. The information on ferrite content and material grade 

provides adequate justification to rule out a concern with TE for, or any synergistic effect 

of TE and IE on, the column caps. Although the upper portion of the column caps (within 

about 5 inches of the lower core plate) will receive neutron fluence sufficient for IE, this 

portion of the column cap should not have significant residual stress because it is remote 

from the weld. Apart from any weld residual stresses, the stresses on the column caps 

during normal operation should be compressive. Therefore, initiation or growth of cracks 

is unlikely during normal operation. Even if tensile stresses occur during a design basis 

accident, without a preexisting crack, column caps with reduced fracture toughness will 

not fracture. 

The staff was concerned that the linked Primary component for the column caps, the 

CRGT assembly lower flange welds, is not a good predictor of IE for the column caps 

because the CRGT lower flange welds may receive substantially lower neutron fluence 

than the column caps (based on the estimated neutron fluence tabulated in MRP-191 for 

the two components). IASCC is the only mechanism of cracking that was screened in 

for the column caps. The CRGT lower flange welds are also not a good predictor for 

IASCC of the column caps, because the CRGT lower flange welds are susceptible to 

SCC and fatigue cracking, but not IASCC. Therefore, in RAI 11-C, the staff requested 

that the applicant modify the RVI Inspection Plan to provide a link to a Primary 

component or components that is an appropriate predictor of IE and IASCC of the 

column caps. In its August 5, 2014, response to RAI 11-C (Ref. 35), the applicant 

indicated that it would modify the RVI Inspection Plan to link the column caps as an 

Expansion component to the lower core barrel cylinder girth welds (“girth welds”). The 

response also stated that “[c]onsistent with existing guidance in MRP-227-A, 

confirmation of a surface crack greater than two inches in length will be taken as an 

indication of active cracking in the lower core barrel cylinder girth weld, and that “[t]his 

confirmation will require expansion of the inspection to the Indian Point lower support 

column bodies (column caps). The link between the CRGT lower flange welds and the 

lower support column bodies (column caps) provided in MRP-227-A remains 

unchanged.” The response further stated that “...the “Expansion” inspection will be 
Aging Management Review Results 

3-46 

conducted within two refueling outages of the original observation of cracking in the 

lower core barrel cylinder girth weld.” The applicant provided an extensive justification 

for the selection of the lower core barrel cylinder girth welds as the linked Primary 

component. The applicant’s justification for the selection of the lower core barrel 

cylinder girth welds as an appropriate lead component for IE and IASCC is summarized 

by the staff as follows: 

 The materials are similar in that austenitic stainless steel weld materials have a 

similar microstructure to low ferrite CASS materials. 

 The operating temperatures are expected to be similar because both 

components are exposed to reactor coolant at core inlet temperature and have 

relatively small temperature increases due to gamma heating. 

 The girth welds’ predicted neutron fluence at the end of life is similar to that of the 

column caps. The peak fluence in the girth welds is predicted to be 

2.51 × 1021 n/cm2 (4 dpa) while the peak fluence in the column caps is predicted 

to be 4.11 × 1021 n/cm2 (6 dpa), attenuating to 2.07 × 1021 n/cm2 (3 dpa) within 

1.6 inches below the lower core plate. 

 Because material, temperature, and neutron fluence are relatively similar, stress 

is expected to be the dominant factor in determining which component is more 

susceptible to IASCC. The girth welds are expected to have higher tensile 

stresses because of weld residual stress while the column caps have primarily 

compressive stresses; therefore, the welds would have a higher IASCC 

susceptibility. 

The applicant justified the scheduling of the Expansion inspection of the column caps 

within two refueling outages based on the following: 

 It is reasonable to expect a significant delay in the onset of cracking in the 

column caps based on the difference in stress. Existing analysis of laboratory 

data indicates that large stresses are required to initiate IASCC at fluences below 

10 dpa. The column caps are projected to be primarily in a compressive stress 

state; therefore, they are expected to have a higher threshold fluence for IE and 

IASCC than the core barrel. 

 Completion of the Expansion inspection within two refueling outages (each fuel 

cycle is 24 months in duration) represents only 13 percent more than the 

approximately 32 effective full-power years of service experienced before the 

inspection of the core barrel cylinder girth weld. This provides reasonable 

assurance that IE and IASCC degradation, if any, will be detected in a timely 

fashion. 

The applicant concluded that the fact that the IP2 and IP3 column caps are not 

susceptible to TE, combined with the addition of the new Primary link to an appropriate 

lead component for IE and IASCC, will assure functionality of the column caps during the 

period of extended operation. Therefore, the applicant deleted Commitment No. 47. 
Aging Management Review Results 

3-47 

The staff notes that IASCC of the welds would be more likely to occur in the girth weld’s 

heat-affected zone (HAZ) rather that the fusion zone of the weld. IASCC in the HAZ of 

austenitic stainless steel welds in RVI has been observed in BWRs but not in PWRs, 

while no IASCC has been noted in CASS RVI components in either BWRs or PWRs. 

Therefore, the staff considers IASCC more likely to occur in an austenitic stainless steel 

HAZ in a PWR than in a CASS component in a PWR. 

The staff finds the applicant’s selection of the lower core barrel cylinder girth welds as a 

Primary link for the column caps to be acceptable based on the following: 

 The applicant demonstrated that the column caps and welds have similar 

material, neutron fluence, and temperature, while the welds are likely to have 

higher tensile stresses, which makes IASCC more likely to initiate in the welds. 

The susceptibility to IE depends primarily on fluence, which is similar for both 

components. IE alone cannot lead to failure without a mechanism for cracking, 

thus it is most important that the Primary component is an appropriate lead 

component for IASCC. 

 The welds are subject to an EVT-1 visual examination, a technique which is 

capable of detecting tight cracks such as IASCC cracks. 

The staff finds the applicant’s proposal to conduct the Expansion inspection of the 

column caps within two refueling outages of the initial discovery of cracking in the welds 

to be acceptable because two refueling outages represents a relatively small percentage 

of the total lifetime of the columns, and the applicant justified that the stresses are 

estimated to be significantly lower in the column caps, which would result in lower 

IASCC susceptibility. The lower stresses would result in a longer time to initiate IASCC 

in the column caps compared to the welds, if IASCC were to start at all. For the 

maximum fluence of the column caps provided in the RAI 11-C response, the IASCC 

screening criteria from MRP-191 Table 3-2 would require a minimum stress of 70 ksi. 

The girth welds would be more likely to have localized residual tensile stresses 

exceeding this screening value than the column caps, which are subject to mainly 

compressive stresses during operation. In addition, the weld in the lower support 

columns is remote from the high fluence area of the column caps, so no tensile weld 

residual stresses are expected in the column caps. Further, the staff notes that for the 

original expansion from the CRGT lower flange weld to the column caps specified in 

MRP-227-A, the Expansion inspection of the column caps was required within three fuel 

cycles, compared to the two cycles proposed for the expansion from the lower core 

barrel cylinder girth welds. Therefore, the proposed schedule for expansion from the 

girth welds is more conservative than that of the recommended MRP-227-A Expansion 

inspection. 

The staff finds that the applicant has adequately addressed A/LAI 7 based on the 

following: (1) The applicant evaluated the risk-significant CASS components of the RVI 

(the lower support columns (column caps)); (2) the applicant has screened the column 

caps for TE and IE using plant-specific materials data and determined that the column 

caps are not susceptible to TE (and the staff confirmed the results of the screening using 

its own screening criteria); (3) the applicant provided information on fabrication NDE 

demonstrating that pre-existing flaws are unlikely to exist in the column caps; (4) the 

applicant provided information on the expected stresses and neutron fluence for the 
Aging Management Review Results 

3-48 

column caps that demonstrated that service-induced cracking due to IASCC is unlikely; 

and (5) the applicant modified its RVI Inspection Program to include a link to a lead 

component that is an appropriate predictor of IASCC and IE for the column caps, with an 

appropriate schedule for performing the Expansion inspection if necessary. Therefore, 

the staff finds that the information provided by the applicant provides reasonable 

assurance that the functionality of the column caps will be maintained during the period 

of extended operation for IP2 and IP3, and deletion of Commitment 47 is acceptable. 

Based on this review, the staff’s concerns in RAIs 11, 11-A, 11-B, and 11-C are 

resolved. 

A/LAI 8 

This action item specifies that applicants and licensees provide a submittal for NRC review and 

approval to credit their implementation of MRP-227-A as an AMP for the RVI components at 

their facilities. This action item states that the submittal shall include the information identified in 

Section 3.5.1 of staff’s final SE for MRP-227, Revision 0. 

Section 3.5.1 of Reference 9 states that in addition to the implementation of MRP-227, 

Revision 0, in accordance with NEI 03-08, applicants and licensees whose licensing basis 

contains a commitment to submit a PWR RVI AMP and/or inspection program shall also provide 

a submittal for NRC review and approval to credit their implementation of MRP-227, as 

amended by [the staff’s final SE]. Section 3.5.1 of Reference 9 further states that an applicant’s 

or licensee’s application to implement MRP-227, as amended by the SE, shall include items (1) 

and (2) below, and that applicants who submit applications for license renewal after the 

issuance of the SE shall, in accordance with the GALL Report, Revision 2 (NUREG-1801), 

submit the information provided in the following items (1) through (5) for staff review and 

approval. 

1. An AMP for the facility that addresses the 10 program elements defined in 

NUREG-1801, Revision 2, AMP XI.M16A. 

2. To ensure that the MRP-227, Revision 0 program and the plant-specific action items will 

be carried out, applicants and licensees are to submit an inspection plan which 

addresses the identified plant-specific action items for staff review and approval 

consistent with the licensing basis for the plant. If an applicant or licensee plans to 

implement an AMP which deviates from the guidance provided in MRP-227, as 

approved by the NRC, the applicant or licensee shall identify where its program deviates 

from the recommendations of MRP-227, as approved by the NRC, and shall provide a 

justification for any deviation which includes a consideration of how the deviation affects 

both Primary and Expansion inspection category components. 

3. The regulation at 10 CFR 54.21(d) requires that an FSAR supplement for the facility 

contain a summary description of the programs and activities for managing the effects of 

aging and the evaluation of TLAAs for the period of extended operation. Those 

applicants for LR citing MRP-227, as approved by the staff, for their RVI component 

AMP shall ensure that the programs and activities specified as necessary in MRP-227, 

as approved by the NRC, are summarily described in the FSAR supplement. 

4. The regulation at 10 CFR 54.22 requires each applicant for LR to submit any TS 

changes (and the justification for the changes) that are necessary to manage the effects 
Aging Management Review Results 

3-49 

of aging during the period of extended operation as part of its LRA. For the plant CLBs 

that include mandated inspection or analysis requirements for RV internals either in the 

operating license for the facility or in the facility TS, the applicant or licensee shall 

compare the mandated requirements with the recommendations in the NRC-approved 

version of MRP-227. If the mandated requirements differ from the recommended criteria 

in MRP-227, as approved by the NRC, the conditions in the applicable license conditions 

or TS requirements take precedence over the MRP recommendations and shall be 

complied with. 

5. Under 10 CFR 54.21(c)(1), the applicant is required to identify all analyses in the CLB for 

its RVI components that conform to the definition of a TLAA in 10 CFR 54.3 and shall 

identify these analyses as TLAAs for the application in accordance with the TLAA 

identification requirement in 10 CFR 54.21(c)(1). MRP-227, as approved by the NRC, 

does not specifically address the resolution of TLAAs that may apply to applicant or 

licensee RVI components. Hence, applicants and licensees who implement MRP-227, 

as approved by the NRC, shall still evaluate the CLB for their facilities to determine 

whether they have plant-specific TLAAs that shall be addressed. If so, the applicant’s or 

licensee’s TLAA shall be submitted for NRC review along with the applicant’s or 

licensee’s application to implement the NRC-approved version of MRP-227. 

For those cumulative usage factor (CUF) analyses that are TLAAs, the applicant may 

use the PWR Vessel Internals Program as the basis for accepting these CUF analyses 

in accordance with 10 CFR 54.21(c)(1)(iii) only if the RVI components in the CUF 

analyses are periodically inspected for fatigue-induced cracking in the components 

during the period of extended operation. The periodicity of the inspections of these 

components shall be justified to be adequate to resolve the TLAA. Otherwise, 

acceptance of these TLAAs shall be done in accordance with either 

10 CFR 54.21(c)(1)(i) or (ii), or in accordance with 10 CFR 54.21(c)(1)(iii) using the 

applicant’s program that corresponds to the GALL Report, Revision 2, AMP X.M1, “Metal 

Fatigue of Reactor Coolant Pressure Boundary Program.” To satisfy the evaluation 

requirements of ASME Code Section III, Subsections NG-2160 and NG-3121, the 

existing fatigue CUF analyses should include the effects of the reactor coolant system 

water environment. 

The staff notes that, according to the wording of A/LAI 8, because the IP2 and IP3 LRA was 

submitted before the issuance of the staff’s final SE for MRP-227, the applicant would only be 

required to submit the information for Items (1) and (2). However, because the IP2 and IP3 

renewed licenses have not been issued yet, the staff evaluated the applicant’s compliance with 

Items (1) through (5). 

Item 1 

Applicant Evaluation 

With respect to Item 1 of A/LAI 8, the applicant stated that a description of the IPEC RVI 

AMP was included in Amendment 9 to the License Renewal Application (NL-10-063, 

July 14, 2010) (Ref. 1). The applicant further stated that the AMP description has been 

revised to be consistent with MRP-227-A and that the revised AMP description has been 

submitted under letter NL-12-037 (Ref. 5). The applicant stated that this document 
Aging Management Review Results 

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comprises an inspection plan which addressed the identified plant-specific action items 

contained in Revision 1 to the [NRC staff’s] Final Safety Evaluation for MRP-227, and 

that IPEC is not requesting any deviations from the guidance provided in MRP-227-A. 

Staff Evaluation 

The staff notes that, by letter dated July 14, 2010 (Ref. 1), as amended by letter dated 

February 17, 2012 (Ref. 5), the applicant provided a completely new Section B.1.42 of 

the LRA consisting of the RVI Program, which addresses the 10 AMP attributes. The 

staff’s evaluation of the AMP’s 10 program elements is found in Section 3.0.3.3.9 of this 

SER supplement. On the basis of its review, the staff finds that the applicant has 

provided the necessary information to satisfy Item 1. 

Item 2 

Applicant Evaluation 

The applicant stated in Attachment 2 to its February 17, 2012, letter that [Attachment 2 

to its February 17, 2012, letter] comprises an inspection plan which addresses the 

identified plant-specific action items contained in Revision 1 of the NRC Final Safety 

Evaluation for MRP-227. The applicant also stated that IPEC is not requesting any 

deviations from the guidance provided in MRP-227-A. 

Staff Evaluation 

The applicant’s February 17, 2012, letter (Ref. 5) addresses Item 2 of A/LAI 8 because it 

includes the RVI Inspection Plan which addresses the applicable plant-specific A/LAIs. 

Therefore, the staff finds that the applicant has provided the necessary information to 

satisfy Item 2. 

Item 3 

Applicant Evaluation 

In its February 17, 2012, letter (Ref. 5), the applicant provided revised FSAR 

Sections A.2.1.41 (for IP2) and A.3.1.41 (for IP3), both titled “RVI Aging Management 

Activities,” which provide a summary of the RVI Program. The summary explains that 

the RVI Program is based on MRP-227-A and MRP-228. The FSAR section also 

indicated that the RVI Program will be implemented in accordance with Addendum A to 

NEI 03-08. 

Staff Evaluation 

Section 3.0.3.3.9.4 contains the staff’s evaluation of the revised FSAR sections. The 

staff finds that the applicant has provided the necessary information to satisfy Item 3. 

Item 4 

Applicant Evaluation 

The applicant did not identify any TS changes related to the RVI Program. 
Aging Management Review Results 

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Staff Evaluation 

The staff examined the TS for IP2 and IP3 and verified that there are no TS surveillance 

requirements that would conflict with the requirements of MRP-227-A. Therefore, the 

staff finds that the applicant has provided the necessary information to address Item 4. 

Item 5 

Applicant Evaluation 

The applicant did not identify any new TLAAs related to RVI in Reference 5. 

Staff Evaluation 

Entergy’s identification of TLAAs was approved by the staff in the SER (Ref. 8). 

In its response to A/LAI 8, the applicant stated that the RVI AMP description has been 

revised to be consistent with MRP-227-A and that IPEC’s response to A/LAI 8 does not 

request any deviations from the guidance provided in MRP-227-A. 

LRA Section 4.3.1.2 provides the applicant’s TLAA and associated CUF values for the 

IP2 and IP3 RVI. The staff noted that, in Amendment 3 to the LRA dated 

March 24, 2008 (Ref. 36), the applicant amended LRA Section 4.3.1.2 to state that 

“fatigue on the RVI will be managed by the Fatigue Monitoring Program in accordance 

with 10 CFR 54.21(c)(1)(iii) for both IP2 and IP3.” In Section 4.3.1.2 of the SER, the 

staff concluded that the applicant has demonstrated, under 10 CFR 54.21(c)(1)(iii), that, 

for the RVI, the effects of aging on the intended function(s) would be adequately 

managed for the period of extended operation. 

A/LAI 8 also indicates that the Fatigue Monitoring Program may be used as the basis for 

accepting CUF analyses in accordance with 10 CFR 54.21(c)(1)(iii), in which case the 

evaluation requirements of ASME Code Section III Section NG are to be satisfied. 

Neither the LRA, nor the SER, nor the applicant’s response to A/LAI 8 addresses 

whether the CUF analyses for the RVI satisfied the requirements of 

Subsections NG-2160 and NG-3121 of Section XI of the ASME Code related to the 

effects of the reactor water environment. Therefore, in RAI 12 the staff requested 

clarification with respect to whether the applicant will use its RVI Program, its Fatigue 

Monitoring Program, or a combination of both to manage fatigue of the RVI during the 

period of extended operation. If the RVI Program is to be used as a basis for managing 

fatigue of any RVI components with CUF analyses, the staff requested information on 

the examination methods and frequency and a justification showing that the frequency is 

adequate. If the Fatigue Monitoring Program will be used, the staff requested that the 

applicant verify that the requirements of ASME Code Section III, Subsections NG-2160 

and NG-3121, as delineated in A/LAI 8, will be satisfied. 

In its response to RAI 12, by letter dated June 14, 2012, the applicant indicated that, for 

RVI components that are not covered by a TLAA analysis, IPEC will use the RVI 

Program to manage the effects of aging due to fatigue on the RVI. The applicant stated 

that, as provided in Section 3.5.1 of the NRC’s SE for MRP-227-A for locations with a 
Aging Management Review Results 

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fatigue TLAA, IPEC will manage the effects of aging due to fatigue through the Fatigue 

Monitoring Program in accordance with 10 CFR 54.21(c)(1)(iii). 

The applicant further stated in its RAI 12 response that the Fatigue Monitoring Program 

as described in LRA Section B.1.12 provides assurance that the CUF remains below the 

allowable limit of 1.0 and that, to be consistent with Section 3.5.1 of the SE for 

MRP-227-A, the existing RVI fatigue calculations will be reviewed before the units enter 

the period of extended operation to evaluate the effects of the reactor coolant system 

water environment on the CUF. The applicant further stated that, specifically, under 

Commitment No. 43, Entergy would review the IPEC design basis ASME Code Class 1 

fatigue evaluations to determine whether the locations identified in NUREG/CR-6260, 

“Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power 

Plant Components,” that have been evaluated for the effects of the reactor coolant 

environment on fatigue usage are the limiting locations for the IP2 and 

IP3 configurations. Finally, the applicant stated that this review includes ASME Code 

Class 1 fatigue evaluations for RVI, and that if more limiting locations are identified, the 

most limiting location will be evaluated for the effects of the reactor coolant environment 

on fatigue usage. 

In RAI 15, the staff requested that the applicant (1) clarify whether the review described 

in the response to RAI 12 will include CUF calculations for the RVI that incorporate 

environmental factors (Fen); (2) clarify what action will be taken if the consideration of 

environmental effects results in a CUF exceeding 1.0 for any RVI component; (3) clarify 

the meaning of the term “ASME Code Class 1 fatigue evaluations” because, technically, 

this term only applies to reactor coolant pressure boundary components (ASME Class 1 

rules do not cover RVI components); (4) provide a new commitment and UFSAR 

supplement to address the review of RVI for environmentally assisted fatigue as part of 

the Fatigue Monitoring Program in response to A/LAI 8 of the staff’s SE for MRP-227-A, 

in lieu of the proposal to use Commitment No. 43. 

In its October 17, 2012, response to RAI 15 (Ref. 37), the applicant revised its response 

to RAI 12 to indicate that it intends to use the RVI Program to manage the cumulative 

fatigue damage aging effect for RVI components that have a TLAA analysis that 

determined a CUF. The staff had a number of concerns with the applicant’s description 

of how it intended to use RVI Program to manage fatigue of RVI components. Among 

the staff’s concerns were that (1) inspections might never be required for Expansion 

components subject to fatigue unless degradation is found in the linked Primary 

component; (2) the adequacy of the periodicity of the RVI inspections (generally 

10 years) might not be adequate to manage fatigue cracking; and (3) some components 

susceptible to fatigue cracking are “No Additional Measures” components and so have 

no specified examination techniques, periodicity, coverage, or acceptance criteria under 

MRP-227-A. Therefore, the staff issued followup RAI 15-A requesting that the applicant 

clarify how these issues would be addressed. 

In its May 7, 2013, response to RAI 15-A (Ref. 30), the applicant stated that it would rely 

on the Fatigue Monitoring Program to manage the effects of fatigue on the RVI during 

the period of extended operation rather than the RVI Program as previously indicated in 

the original response to RAI 15. The applicant also provided a revised response to 

RAI 15, which indicated that the CUFs for the limiting RVI components would be 

recalculated using Fen factors provided in NUREG/CR-5704, “Effects of LWR Coolant 

Environments on the Fatigue Design Curves of Austenitic Stainless Steels,” for stainless 
Aging Management Review Results 

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steel components or NUREG/CR-6909, “Effects of LWR Coolant Environments on the 

Fatigue of Reactor Materials,” for nickel-based alloy components. In response to the 

staff’s request that the applicant clarify what actions will be taken if the consideration of 

environmental effects results in a CUFen exceeding 1.0, the applicant stated that 

corrective actions would include further CUF reanalysis and/or repair or replacement of 

the affected components before the CUFen reaches 1.0. The applicant also clarified that 

the term “Class 1” was inadvertently included in the response to RAI 12 and that the 

phrase “ASME Code Class 1 fatigue evaluations for reactor vessel internals” is changed 

to read “ASME Code Subsection NG fatigue evaluations for reactor vessel internals.” 

The applicant also provided a new commitment (Commitment No. 49) to recalculate the 

CUF values to include reactor coolant environmental effects and take corrective actions 

if necessary, as described above. The applicant also included a revised list of regulatory 

commitments providing the new Commitment No. 49 and showing an implementation 

schedule of before September 28, 2013, for IP2 and before December 12, 2015 for IP3 

(i.e., before the start of the period of extended operation for both units). The applicant 

also provided a markup of the UFSAR supplement sections A.2.2.2 and A.3.2.2 for 

“Class 1 Metal Fatigue.” 

By letter dated July 26, 2013, the staff issued RAI 15-B, requesting that the applicant 

revise UFSAR Supplement Sections A.2.2.2 and A.3.2.2 for consistency with its 

response to RAI 15-A. In its response to RAI 15-B dated September 27, 2013 (Ref. 12), 

the applicant revised LRA Sections A.2.2.2 and A.3.2.2 to include new 

subsections A.2.2.2.3 and A.3.2.2.3 for “Subsection NG Fatigue Analysis of Reactor 

Pressure Vessel Internals,” which contain a description of the methodology described in 

the response to RAI 15-A, and also include the commitment dates for completing these 

analyses. The applicant also deleted the discussion of RVI from LRA Sections A.2.2.2.1 

and A.3.2.2.1, “Class 1 Metal Fatigue.” The staff finds these revisions acceptable. 

The staff finds the applicant’s response to RAI 15-A technically acceptable because the 

methods proposed for managing fatigue of the RVI are consistent with those allowed by 

A/LAI 8 from MRP-227-A. Specifically, the applicant will use its Fatigue Monitoring 

Program to manage fatigue of RVI, and will consider the effects of the reactor coolant 

environment on fatigue. Additionally, the cited sources for the Fen factors to correct for 

the effects of the environment are consistent with those that are acceptable according to 

the GALL Report, Revision 2, Section X.M.1, “Fatigue Monitoring.” The staff’s concerns 

in RAIs 12, 15, 15-A, and 15-B are thus resolved. 

Summary—A/LAI 8 

Based on the above, the staff finds that the applicant has provided the information required by 

A/LAI 8, Items (1) through (5). 

Conditions from Safety Evaluation of MRP-227, Revision 0. The conditions from Revision 1 of 

the final SE for MRP-227, Revision 0, address changes the staff required to be made in the final 

approved version of the topical report (MRP-227-A). Because MRP-227-A had not been issued 

at the time that the applicant prepared the initial version of its RVI Inspection Plan, in Table 5-8 

of the RVI Inspection Plan the applicant provided a brief description of how each condition is 

addressed in the RVI Inspection Plan. The staff reviewed the applicant’s resolution of each of 

these conditions. 
Aging Management Review Results 

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Staff Evaluation 

Condition 1—This condition required moving several components from the No Additional 

Measures inspection category to the Expansion inspection category. The applicable 

components for Westinghouse-designed RVI are the upper core plate and the lower support 

forging or casting. This condition did not change from Revision 0 to Revision 1 of the SE. The 

staff verified that the IPEC RVI Inspection Program incorporates this change. 

Condition 2—This condition required changing the inspection category of several components 

from Expansion to Primary. The applicable components for Westinghouse-designed RVI are 

the upper and lower core barrel girth welds and the lower core barrel flange weld. The staff 

notes that the component description was changed from “all upper and lower core barrel welds” 

in Revision 0 of the staff’s SE to only “the girth welds” in Revision 1 of the staff’s SE. The staff 

verified that the IPEC RVI Inspection Program incorporates this change. 

Condition 3—This condition does not apply to components in Westinghouse-designed reactors, 

so it is not applicable. 

Condition 4—This condition required (a) the minimum examination coverage to be defined as 

75 percent of the total accessible and inaccessible area or volume or (b) when addressing a set 

of like components, that the inspection examine a minimum sample size of 75 percent of the 

total population of like components in the Expansion category. The staff verified that the 

examination coverage specified in Table 5-3 of the IPEC RVI Inspection Program for Expansion 

components meets this condition. 

Condition 5—As applicable to Westinghouse-designed RVI, this condition required that the 

examination frequency of baffle-former bolts be changed from “10 to 15 years” to “10 years.” 

The staff verified that Table 5-2 of the IPEC RVI Inspection Program meets this condition. 

Condition 6—This condition required a baseline 10-year reexamination interval to be applied to 

all Expansion components once (a) degradation is identified in the associated Primary 

inspection category components and (b) examination of the Expansion category component 

begins, unless the applicant or licensee provides an evaluation to the staff justifying a longer 

interval between inspections. The staff verified that Table 5-3 of the IPEC RVI Inspection 

Program incorporates this condition. 

Condition 7—This condition required the inclusion of a reference to RVI AMP XI.M16A in the 

GALL Report, Revision 2 in Appendix A to MRP-227-A. As such, this condition does 

necessitate changes in the IPEC RVI Inspection Plan or AMP. 

The staff finds that all conditions applicable to Westinghouse-designed RVI have been 

incorporated in the inspection and evaluation requirements for IP2 and IP3. 

Summary—Action Items and Conditions from Safety Evaluation of MRP-227, Revision 0 

Based on the information evaluated in this section, the staff finds that the applicant has 

adequately addressed all of the A/LAIs and conditions described in the staff’s final SE for 

MRP-227, Revision 0 (Ref. 9), that are applicable to IP2 and IP3. 

Staff’s Evaluation of the RVI Inspection Plan’s Consistency with MRP-227-A. In addition to its 

review of the A/LAIs, the staff reviewed the information provided in IPEC’s RVI Inspection Plan 
Aging Management Review Results 

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for general consistency with MRP-227-A. Section 1.0 of MRP-227-A is the executive summary, 

so it is not specifically addressed below. 

Background (Section 2.0 of MRP-227-A) 

Section 2.0 of MRP-227-A contains general background, a discussion of the scope, and 

applicability information. 

The staff verified that the scope of the applicant’s RVI Inspection Plan is consistent with that 

described in MRP-227-A Section 2.0 (i.e., is limited to the RVI structural components). 

Section 2.0 of the RVI Inspection Plan provides significant detail on the items within the scope 

of the plan. The applicability information of Section 2.4 of MRP-227-A is addressed in detail in 

Section 3.0.3.3.10.3.1 of this SSER under the discussion of A/LAI 1. 

Component Categorization and Aging Management Strategy Development (Section 3.0 of 

MRP-227-A) 

This section of MRP-227-A provides information on the RVI design characteristics for the 

three different nuclear steam supply system (NSSS) designs, an overview of the applicable 

degradation mechanisms and effects, and a description of the process used to develop the 

aging management strategy recommendations of MRP-227-A, including screening for 

degradation mechanisms, categorization, and FMECA. 

In Section 2.0 of the RVI Inspection Plan, the applicant provided a description of the design of 

the IP2 and IP3 internals. This section also provides verbal descriptions and figures showing 

the general arrangement and specific subcomponents of the generic Westinghouse-designed 

RVI. The figures are consistent with those included in MRP-227-A. The description of the 

upper internals assembly provided in the IPEC RVI Inspection Plan is similar to that provided in 

MRP-227-A Section 3.1.3, and notes that the upper support plate (USP) design at IPEC is 

designated as a “top hat” design. The description of the lower internals assembly is also similar 

to the corresponding description in MRP-227-A, with some plant-specific information added. 

For example, the description notes that at IPEC, corner brackets are installed behind and bolted 

to the baffle plates. 

Section 3.1 of the RVI Inspection Plan summarizes the guidance of the MRP I&E Guidelines 

necessary to understand the implementation of MRP-227-A but does not duplicate the full 

discussion of the technical bases. Because the end result of the process described in Section 3 

of MRP-227-A is the categorization of the components and inspection and evaluation 

recommendations for the various inspection categories, the consistency of the applicant’s 

program with these results can be evaluated by assessing the consistency of the aging 

management requirements specified in the applicant’s RVI Program with MRP-227-A. The 

aging management requirements in the IPEC RVI Program were found to be consistent with 

MRP-227-A, as documented in Section 3.0.3.3.9 of this SER Supplement. 

Based on the above, the staff finds that the RVI Inspection Plan is consistent with the 

information provided in Section 3 of MRP-227-A with respect to the component categorization 

and aging management strategy development. 
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Aging Management Requirements (Section 4.0 of MRP-227-A) 

This section of MRP-227-A provides tables describing the recommended inspections 

(technique, schedule of initial and subsequent inspections, and inspection coverage) for RVI 

components in the Primary, Expansion, and Existing Programs categories. The staff confirmed 

that the information in Tables 5-2, 5-3, and 5-4 of the RVI Inspection Plan is consistent with that 

in Tables 4-3 (Primary), 4-6 (Expansion), and 4-9 (Existing Programs) in MRP-227-A. 

Examination Acceptance Criteria and Expansion Requirements (Section 5.0 of 

MRP-227-A) 

Table 5-3 of MRP-227-A provides the acceptance criteria for the Primary and Expansion 

category components of Westinghouse-designed RVI and the Expansion criteria defining when 

the inspection results for the Primary components trigger inspections of the Expansion 

components. The staff checked the corresponding information in Table 5-5 of the RVI 

Inspection Plan and finds it to be consistent with the information in Table 5-3 of MRP-227-A. 

Evaluation Methodologies (Section 6.0 of MRP-227-A) 

This section of MRP-227-A provides recommended flaw evaluation methods to be used when 

the examinations recommended in Section 4.0 reveal relevant conditions. The applicant did not 

include any information in the RVI Inspection Plan addressing evaluation methodologies. 

However, as noted in the staff’s evaluation of IPEC’s RVI AMP in Section 3.0.3.3.9 of this SER 

supplement, the applicant stated that it would apply the evaluation methodologies of Section 6.0 

of MRP-227-A or other NRC-approved evaluation methods in the description of the “corrective 

action” program element. 

In addition, in the staff’s final SE for MRP-227, Revision 0, the staff noted that in an 

RAI response, EPRI stated that (a) topical report WCAP-17096-NP is the document that will be 

used as the framework to develop the generic and plant-specific evaluations triggered by 

findings in the RVI examinations and (b) the staff is currently reviewing WCAP-17096-NP, 

Revision 2. Therefore, in RAI 4, the staff requested that the applicant address the use of 

WCAP-17096-NP, Revision 2, as the basis for the methods to be used to evaluate relevant 

inspection findings. The applicant’s response to RAI 4 is evaluated in Section 3.0.3.3.9.1 of this 

SER supplement. 

Implementation Requirements (Section 7.0 of MRP-227-A) 

Section 7 of MRP-227 provides a summary of the implementation requirements established by 

the nuclear industry for the guidelines described in MRP-227. The implementation requirements 

are defined by the latest edition of NEI 03-08, which includes implementation categories used in 

MRP-227 such as: (a) “Mandatory,” which requires implementation of the guidelines at all 

plants; (b) “Needed,” which provides an option for implementing the guidelines wherever 

possible or implementing alternative approaches, or (c) “Good Practice,” which recommends 

implementation of the guidelines as an option whereby significant operational and reliability 

benefits can be achieved at a given plant. Failure to meet a “Needed” or a “Mandatory” 

requirement is a deviation from the guidelines and a written justification for deviation must be 

prepared and approved as described in Appendix B to NEI 03-08. A copy of the deviation is 

sent to the MRP so that, if needed, improvements to the guidelines can be developed. A copy 

of the deviation is also sent, for information, to the NRC. Section 7 of MRP-227 specified the 

following with respect to the implementation of specific MRP-227 guidelines: 
Aging Management Review Results 

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1. Each PWR unit shall develop and document an AMP for the PWR RVI components 

within thirty-six months following the issuance of MRP-227-A. This is a "Mandatory" 

requirement. 

2. Each PWR unit shall implement Tables 4-1 through 4-9 and Tables 5-1 through 5-3 of 

MRP-227 for the applicable design within twenty-four months following the issuance of 

MRP-227-A. This is a "Needed" requirement. 

3. Examination of the RVI components shall comply with the MRP-228 Revision 0, 

"Materials Reliability Program: Inspection Standard for PWR Internals.” This is a 

"Needed" requirement. 

4. Examination results that do not meet the examination acceptance criteria defined in 

Section 5 of the MRP-227 guidelines shall be recorded and entered in the plant 

corrective action program and dispositioned. This is a “Needed” requirement. 

5. A summary report of all inspections and monitoring, evaluation, and new repairs shall be 

provided within one hundred and twenty days of the completion of an outage during 

which the RVI components were examined. The summary of the examination results 

shall be included in an industry report that is updated every six months. This report will 

monitor the industry progress on the AMP related to PWR RVI components and it will 

also list the emerging operating experience. This is a "Good Practice" requirement. 

6. If an engineering evaluation is used to disposition an examination result that does not 

meet the examination acceptance criteria in Section 5, this engineering evaluation shall 

be conducted in accordance with a NRC-approved evaluation methodology. This is a 

“Needed” requirement. 

Because IPEC has developed and documented its AMP for RVI components through the 

submittal of LRA Amendment 9, as modified by its February 17, 2012, letter (Ref. 5), and this 

has occurred within 36 months of the issuance of MRP-227-A, the applicant has met the 

mandatory requirements. The information provided in Section 4.4 of the RVI Inspection Plan is 

consistent with the “Needed” and “Good Practice” requirements of Items 2 through 6 above. 

Therefore, the staff finds that the implementation requirements for the RVI Inspection Plan are 

consistent with the implementation requirements defined in MRP-227-A and are thus 

acceptable. 

Staff’s Evaluation of Consistency between the LRA and the RVI Inspection Plan. The staff 

compared the information in Tables 5-2, 5-3, and 5-4 of the RVI Inspection Plan to the 

information included in Tables 3.1.2-2-IP2 and 3.1.2-2-IP3 of the LRA, as amended by LRA 

Amendment 9, which provide the summary of the aging management review for IP2 and IP3. 

Any component that credits the RVI AMP in these tables should be included in either Table 5-2 

or Table 5-3 of the RVI Inspection Plan, which contain the inspection requirements for the 

Primary and Expansion components for IP2 and IP3. Because Tables 5-2 and 5-3 of the RVI 

Inspection Plan use the component nomenclature from MRP-227-A (which differs from the IP2 

and IP3 plant-specific nomenclature used in LRA Tables 3.1.2-2-IP2 and 3.1.2-2-IP3), Table 5-1 

of the RVI Inspection Plan provided a cross-index between the LRA and MRP-227-A 

nomenclature. The staff found that all of the components crediting the RVI AMP in LRA 

Tables 3.1.2-2-IP2 and 3.1.2-2-IP3 are included in Tables 5-2 and 5-3 of the RVI Inspection 

Plan. In addition, the staff compared LRA Tables 3.1.2-2-IP2 and 3.1.2-2-IP3 for consistency 

with Table 5-4 of the RVI Inspection Plan, which identifies the applicant’s Existing Program 
Aging Management Review Results 

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components corresponding to Table 4-9 of MRP-227-A. This review identified some apparent 

inconsistencies between the RVI Inspection Plan’s Table 5-4, “Existing Program Components at 

IPEC Units 2 and 3,” and Tables 3.1.2-2-IP2 and 3.1.2-2-IP3 with respect to the existing 

program (AMP) credited with managing the aging effect. Specifically, for the flux thimble guide 

tubes and clevis insert bolts at IPEC, the Water Chemistry Program—Primary and Secondary is 

assigned to manage loss of material in Tables 3.1.2-2-IP2 and 3.1.2-2-IP3, while in Table 5-4 of 

the RVI Inspection Plan, different programs are listed as the existing program managing loss of 

material for these components. Therefore, in RAI 13, the staff requested that the applicant 

clarify these apparent inconsistencies. 

In its October 17, 2012, response to RAI 13 (Ref. 37), the applicant clarified these apparent 

inconsistencies, noting that in the IPEC license renewal aging management review, the flux 

thimble tubes (and the flux thimble guide tubes external to the reactor vessel) were evaluated as 

part of the reactor vessel and the aging management review results were presented in LRA 

Tables 3.1.2-1-IP2 and -IP3. The applicant further indicated that as a consequence, the 

“Bottom Mounted Instrumentation System—Flux thimble tubes” listed in Table 5-4 of the RVI 

Inspection Plan are the same as the “Bottom mounted instrumentation—flux thimble tubes” 

listed in LRA Tables 3.1.2-1-IP2 and -IP3. The applicant stated that (a) these LRA tables 

identify “loss of material—wear” as an applicable aging effect and identify the “Flux Thimble 

Tube Inspection Program” as the AMP and (b) this is consistent with Table 5-4 of the RVI 

Inspection Plan. Finally, the applicant stated that the LRA table line items (in Tables 3.1.2-2-IP2 

and 3.1.2-2-IP3) that indicate loss of material managed by the Water Chemistry—Primary and 

Secondary Program refer to loss of material due to pitting and crevice corrosion, not by wear. 

The staff notes that loss of material due to pitting and crevice corrosion for the flux thimble tubes 

is not identified as an AERM in MRP-227-A, so it is acceptable for the applicant to identify a 

different AMP to manage loss of material due to this mechanism. The staff reviewed the 

applicant’s identified AMP for the flux thimble tubes against the recommendation of MRP-227-A. 

Table 4-9 of MRP-227-A cites the GALL Report, Revision 1, as the source of the AMP 

requirements, surface examination by eddy current testing as the examination method, and 

eddy current surface examination as described in the plant response to Bulletin 88-09 as the 

required examination coverage. GALL Report, Revision 1, Table IV.B2, identifies the 

recommended AMP for the flux thimble tubes as the “Flux Thimble Tube Inspection Program” 

described in Section XI.M37 of the GALL Report, Revision 1. Consistent with the GALL Report, 

Revision 1, LRA Tables 3.1.2-1-IP2 and 3.1.2.1-IP3 identify the “Flux Thimble Tube Inspection 

Program” as the applicable AMP for managing loss of material due to wear. In the SER 

(Ref. 8), the staff found that the applicant’s “Flux Thimble Tube Inspection Program” was 

consistent (with enhancements) with the GALL Report, Revision 1, and that the effects of aging 

would thus be adequately managed. Therefore, the applicant’s AMP for the flux thimble tubes is 

acceptable because it is consistent with both the recommendations of the GALL Report, 

Revision 1, and MRP-227-A, Table 4-9. 

In LRA Tables 3.1.2-2-IP2 and -IP3, loss of material due to wear was identified as an aging 

effect for the clevis inserts, but not for the clevis insert bolts. In its October 17, 2012, response 

to RAI 13, the applicant stated that this is consistent with the GALL Report, Revision 1, which 

does not identify an aging effect of loss of material due to wear for the bolts. The applicant 

further stated that MRP-227-A identifies loss of material due to wear as an aging effect for the 

clevis insert bolts and that the RVI Inspection Plan manages this aging effect accordingly. The 

applicant stated that the LRA table line items for clevis insert bolts that indicate loss of material 

managed by the Water Chemistry—Primary and Secondary Program refer to loss of material 

due to pitting and crevice corrosion, not by wear. Finally, the applicant stated that, for 

consistency with MRP-227-A and the RVI Inspection Plan, the following line item would be 
Aging Management Review Results 

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added to LRA Tables 3.1.2-2-IP2 and -IP3. The staff finds this response acceptable because 

the applicant modified the AMP in the LRA which manages loss of material due to wear of the 

clevis insert bolts for consistency with MRP-227-A, which identifies the bolts as Existing 

Programs components with wear managed by the Inservice Inspection Program. 

Component 

Type

Intended 

Function

Material Environment Aging Effect 

Requiring 

Management

Aging 

Management 

Program

NUREG1801 

Item

Table 1 

Item

Notes

Lower 

internals 

assembly 

• clevis 

insert bolt 

Structural 

support 

Nickel 

alloy 

Treated 

borated water 

Loss of 

material – 

wear 

Inservice 

Inspection 

-- -- H 

The staff finds the applicant’s response to RAI 13 acceptable because it has clarified or 

corrected the apparent inconsistencies between LRA Tables 3.1.2-2-IP2 and -IP3 and Table 5-4 

of the RVI Inspection Plan, demonstrating that the aging management of the Bottom Mounted 

Instrumentation System—flux thimble tubes and the clevis insert bolts will be consistent with 

MRP-227-A. The Staff’s concern in RAI 13 is therefore resolved. 

Conclusion. The staff concludes that the proposed RVI Inspection Plan implements the 

elements of the RVI AMP in an acceptable manner. The bases for the staff’s conclusion are 

that (1) the applicant’s program is consistent with the generic RVI inspection and evaluation 

guidelines of MRP-227-A; (2) the applicant adequately addressed all of the A/LAIs of the final 

SE for MRP-227, Revision 0, that are applicable to Westinghouse-designed RVI or generically 

to all NSSS designs; and (3) the RVI Inspection Plan addresses the conditions of the final SE 

for MRP-227, Revision 0. 

3.1 Aging Management of Reactor Coolant System 

3.1.1 Summary of Technical Information in the Application

By letter dated July 14, 2010, the applicant submitted Amendment 9 to its LRA to include the 

RVI AMP. The applicant removed its previous commitment to submit a reactor vessel internals 

inspection program and, as a result, it made several changes to the LRA. 

3.1.2 Staff Evaluation

The abbreviated Table 3.1-1, below, summarizes the staff’s evaluation of components, aging 

effects, and AMPs in light of the changes associated with the RVI Program. Columns 1 through 

5 represent the applicant’s statements in the amended LRA. References to the staff’s 

evaluation are provided in Column 6. 
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Table 3.1-1. Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor 

Coolant System Components in the GALL Report 

Component Group 

(GALL Report 

Item No.) 

Aging 

Effect/Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Stainless steel and 

nickel alloy reactor 

vessel internals 

components exposed 

to reactor coolant 

and neutron flux 

(3.1.1-22) 

Loss of fracture 

toughness due to 

neutron irradiation 

embrittlement, void 

swelling 

FSAR supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 

months before the 

extended period 

an RVI inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Reactor Vessel 

Internals Program 

See SER 

Section 3.1.2.2.6 

Stainless steel and 

nickel alloy reactor 

vessel internals 

screws, bolts, tie 

rods, and hold-down 

springs 

(3.1.1-27) 

Loss of preload 

due to stress 

relaxation 

FSAR supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 

months before the 

extended period 

an RVI inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Reactor Vessel 

Internals Program 

See SER 

Section 3.1.2.2.9 
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Component Group 

(GALL Report 

Item No.) 

Aging 

Effect/Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Stainless steel 

reactor vessel 

internals components 

(e.g., upper internals 

assembly, RCCA 

guide tube 

assemblies, 

baffle/former 

assembly, lower 

internal assembly, 

shroud assemblies, 

plenum cover and 

plenum cylinder, 

upper grid assembly, 

control rod guide 

tube (CRGT) 

assembly, core 

support shield 

assembly, core 

barrel assembly, 

lower grid assembly, 

flow distributor 

assembly, thermal 

shield, 

instrumentation 

support structures) 

(3.1.1-30) 

Cracking due to 

SCC, irradiationassisted SCC 

Water Chemistry 

and FSAR 

supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval less 

than 24 months 

before the 

extended period 

an RVI inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Reactor Vessel 

Internals Program 

See SER 

Section 3.1.2.2.12

Stainless steel and 

nickel alloy reactor 

vessel internals 

components 

(3.1.1-33) 

Changes in 

dimensions due to 

void swelling 

FSAR supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval less 

than 24 months 

before the 

extended period 

an RVI inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Reactor Vessel 

Internals Program 

See SER 

Section 3.1.2.2.15
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Component Group 

(GALL Report 

Item No.) 

Aging 

Effect/Mechanism 

AMP in GALL 

Report 

Further 

Evaluation 

in GALL 

Report 

AMP in LRA, 

Supplements, or 

Amendments 

Staff Evaluation

Stainless steel and 

nickel alloy reactor 

vessel internals 

components 

(e.g., upper internals 

assembly, RCCA 

guide tube 

assemblies, lower 

internal assembly, 

CEA shroud 

assemblies, core 

shroud assembly, 

core support shield 

assembly, core 

barrel assembly, 

lower grid assembly, 

flow distributor 

assembly) 

(3.1.1-37) 

Cracking due to 

SCC, PWSCC, 

irradiation-assisted 

SCC 

Water Chemistry 

and FSAR 

supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 

months before the 

extended period 

an RVI inspection 

plan based on 

industry 

recommendation. 

No, but 

licensee 

commitment 

needs to be 

confirmed 

Water Chemistry 

Control – Primary 

and Secondary 

and either the 

Reactor Vessel 

Internals Program 

or the Inservice 

Inspection 

Program (for the 

lower core plate 

only) 

See SER 

Section 3.1.2.2.17

Steel reactor vessel 

flange, stainless 

steel and nickel alloy 

reactor vessel 

internals exposed to 

reactor coolant 

(e.g., upper and 

lower internals 

assembly, CEA 

shroud assembly, 

core support barrel, 

upper grid assembly, 

core support shield 

assembly, lower grid 

assembly) 

(3.1.1-63) 

Loss of material 

due to wear 

Inservice 

Inspection (IWB, 

IWC, and IWD) 

No Inservice 

Inspection and the 

Reactor Vessel 

Internals Program 

See SER 

Section 3.1.2.1.11

In LRA Amendment 9, the “Discussion” column in LRA Table 3.1.1, “Summary of Aging 

Management Programs of the Reactor Coolant System Evaluated in Chapter IV of 

NUREG-1801,” was changed to replace wording referring to the commitment to implement the 

industry program in Sections A.2.1.4.1 and A.3.1.4.1 of Appendix A to the UFSAR Supplement 

with a reference to the RVI Program. In LRA Tables 3.1.2-2-IP2 and 3.1.2-2-IP3, “Reactor 

Vessel Internals, Summary of Aging Management Review,” the information for components 

aligned with the line items listed in LRA Table 3.1.1 in the “Aging Management Programs” 

column is changed from “RVI Commitment” to “Reactor Vessel Internals.” 

 
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The line items listed above in LRA Table 3.1.1 are all line items pertaining to RVI components 

for which, according to Table 1 in Volume 1 of Revision 1 of the GALL Report, the need for 

further evaluation is waived if the applicant’s commitment to implement the RVI Program 

developed by industry is confirmed. Table 1 in Volume 1 of Revision 1 of the GALL Report 

described the commitment as follows: “FSAR supplement commitment to (1) participate in 

industry RVI aging programs (2) implement applicable results (3) submit for NRC approval 

> 24 months before the extended period an RVI inspection plan based on industry 

recommendation.” The original IP2 and IP3 LRA included a commitment consistent with this 

wording for the items listed in the table above. 

The staff finds the changes to the “Discussion” column information in LRA Table 3.1.1 and the 

changes to the assigned AMP in LRA Tables 3.1.2-2-IP2 and 3.1.2-2-IP3 to be acceptable 

because the changes reflect the replacement of the commitment to implement the RVI Program 

consistent with the program developed by industry, with the actual RVI Program. In addition, 

the staff notes that in LR-ISG-2011-04 none of these components would require further 

evaluation. 

The staff reviewed the changes to LRA Table 3.1.1 in LRA Amendment 9 and concludes that 

the changes are acceptable because the items now cite the RVI Program rather than a 

commitment. Based on the staff’s review of the changes of the listed line items, the effects of 

aging for the affected RVI components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation 

as required by 10 CFR 54.21(a)(3). 

Detailed evaluation of these changes can be found in SER Sections 3.1.2.2.6, 3.1.2.2.9, 

3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17. 

3.1.2.1.10 Aging Effects Requiring Management for RVI Components 

In LRA Amendment 9, the applicant revised Tables 3.1.2.2-IP2 and 3.1.2.2-IP3, both entitled 

“RVI Summary of Aging Management Review.” The major change to these tables is in the 

“Aging Management Programs” column, where “RVI commitment” has been replaced with 

“Reactor Vessel Internals.” This change reflects a change from crediting the commitment to 

implement the industry program when it was completed, tracked by Commitment No. 30, to 

crediting the new RVI AMP described in LRA Section B.1.42 with management of aging for the 

AERMs applicable to the IP2 and IP3 RVI. The other notable change to these tables is the 

replacement of generic note “A” with generic note “E” wherever the RVI AMP was credited. 

Generic note “A” reads, “Consistent with NUREG-1801 item for component, material, 

environment, aging effect and AMP is consistent with NUREG-1801 AMP.” Generic note “E” 

reads “Consistent with NUREG-1801 material, environment, and aging effect but a different 

AMP is credited.” The change from generic note A to generic note E reflects the fact that citing 

the RVI commitment is consistent with the GALL Report, Revision 1, while citing the RVI AMP is 

not consistent with the GALL Report, Revision 1. However, crediting the RVI Program is 

consistent with LR-ISG-2011-04, which updates the guidance in Revision 2 of the GALL Report 

to reflect MRP-227-A and thus contains the most current guidance acceptable to the staff for 

managing aging of RVI. Other changes include changes to some component types and addition 

of some completely new line items. These changes are consistent with the changes in the 

scoping and screening information evaluated in Section 2.3.1.2 of this SER supplement. For 

some components, AMPs other than the RVI AMP are credited with managing certain AERMs. 

For example, the Water Chemistry Control—Primary and Secondary AMP is credited with 

managing the AERM “loss of material” for several components. These AERMs continue to cite 
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generic note “A” because the component, material, environment, aging effect, and AMP are 

consistent with the GALL Report, Revision 1. 

The component, material, environment, and aging effect information is consistent with the GALL 

Report, Revision 1, which was the most current NRC guidance at the time these changes were 

submitted, although slightly different component terminology is used in some cases. The AMP 

credited for managing aging is consistent with LR-ISG-2011-04, which updates the GALL 

Report, Revision 2, guidance to reflect MRP-227-A and thus contains the most current guidance 

acceptable to the staff for managing aging of RVI, with two exceptions. First, the “Thermal 

Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) 

Program” is credited for managing reduction of fracture toughness for the “lower internals 

assembly – lower core support castings – column cap – lower core support column bodies 

(column caps),” whereas LR-ISG-2011-04 specifies the RVI Program. The relationship between 

the “Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel 

(CASS) Program” and the RVI AMP was clarified in the applicant’s September 28, 2012, 

response to RAI 10, which is discussed in more detail in SER Section 3.0.3.3.10. The staff’s 

review of the applicant’s RVI Inspection Plan, detailed in SER Section 3.0.3.3.10, confirmed that 

the MRP-227-A aging management recommendations for the column caps will be met. Second, 

the ISI Program is credited for managing aging of several components. All of the components 

for which the ISI Program is credited for managing aging effects are classified as Existing 

Programs components within MRP-227-A; the ASME Code Section XI ISI Program is the 

existing program credited for managing aging of these components in Table 4-9 of MRP-227-A. 

Therefore, there is no effective discrepancy with LR-ISG-2011-04. Further, in its review of the 

RVI AMP detailed in SER Section 3.0.3.3.9, the staff verified that the IPEC RVI Inspection Plan 

implements all of the Existing Programs inspections of MRP-227-A. Therefore, the two 

apparent exceptions to LR-ISG-2011-04 have been reconciled and determined to result in 

equivalent aging management to the criteria of LR-ISG-2011-04. 

Based on the above, the staff finds the changes to LRA Tables 3.1.2.2-IP2 and 3.1.2.2-IP3 

acceptable because component, material, environment, and aging-effect information is 

consistent with the GALL Report, Revision 1, and the credited AMPs are consistent with the 

most current NRC guidance for RVI aging management in LR-ISG-2011-04, with two exceptions 

that were determined by the staff to be equivalent with the criteria of LR-ISG-2011-04. 

In the LRA, for several aging effects applicable to the RVI, the applicant credited Commitment 

No. 30 for fulfilling the further evaluation requirements. Commitment No. 30 states: “For aging 

management of the RVI, IPEC will (1) participate in the industry programs for investigating and 

managing aging effects on reactor internals; (2) evaluate and implement the results of the 

industry programs as applicable to the reactor internals; (3) on completion of these programs, 

but not less than 24 months before entering the period of extended operation, submit an 

 
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inspection plan for reactor internals to the NRC for review and approval.” The “further 

evaluation” sections affected are: 

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void 

Swelling 

3.1.2.2.9 Loss of Preload Due to Stress Relaxation 

3.1.2.2.12 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking 

3.1.2.2.15 Changes in Dimensions Due to Void Swelling 

3.1.2.2.17 Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking 

In LRA Amendment 9, the listed LRA sections were revised to credit the RVI Program in place 

of Commitment No. 30. The following sections evaluate the changes to the listed LRA sections 

and are intended to replace the previous SER sections in their entirety. The staff notes, in the 

LRA sections listed above provided in LRA Amendment 9, the applicant cited MRP-227 rather 

than MRP-227-A. Because the applicant did not cite the staff approved version of MRP-227, in 

RAI 2 the staff requested the applicant update the reference to MRP-227-A. In its response to 

RAI 2 by letter dated June 14, 2012, the applicant provided revisions of the LRA sections listed 

above changing the references to MRP-227-A. Therefore, RAI 2 is resolved. 

3.1.2.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement and Void 

Swelling 

By letter dated July 14, 2010, Entergy amended LRA Section 3.1.2.2.6 to remove its previous 

commitment. In response to RAI 2 by letter dated June 14, 2012, Entergy revised LRA 

Section 3.1.2.2.6 to state that “The RVI Program will implement the EPRI Pressurized Water 

Reactor Internals Inspection and Evaluation Guidelines, MRP-227-A. The RVI Program will use 

nondestructive examinations (NDE) and other inspection methods to manage aging effects for 

reactor vessel internals.” 

The staff’s evaluation of the applicant’s program to address this aging effect is documented in 

SER Section 3.0.3.3.9. 

3.1.2.2.9 Loss of Preload due to Stress Relaxation 

By letter dated July 14, 2010, Entergy amended LRA Section 3.1.2.2.9 to remove its previous 

commitment. In response to RAI 2 by letter dated June 14, 2012, Entergy revised LRA 

Section 3.1.2.2.9 to state that “The RVI Program will implement the EPRI Pressurized Water 

Reactor Internals Inspection and Evaluation Guidelines, MRP-227-A. The RVI Program will use 

nondestructive examinations (NDE) and other inspection methods to manage aging effects for 

reactor vessel internals.” 

The staff’s evaluation of the applicant’s program to address this aging effect is documented in 

SER Section 3.0.3.3.9. 
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3.1.2.2.12 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking 

By letter dated August 22, 2011 (Ref. 38), Entergy amended LRA Section 3.1.2.2.12 to remove 

its previous commitment and to state that “[c]racking due to SCC and IASCC in PWR stainless 

steel reactor internals exposed to reactor coolant will be managed by the Water Chemistry 

Control—Primary and Secondary and the Reactor Vessel Internals (RVI) Programs.” 

In its June 14, 2012, response to RAI 3, Entergy further amended LRA Section 3.1.2.2.12 to 

state that: 

Cracking due to SCC and IASCC in PWR stainless steel reactor internals 

exposed to reactor coolant will be managed by the Water Chemistry Control—

Primary and Secondary Program and the Reactor Vessel Internals (RVI) or 

Inservice Inspection (ISI) Programs. The RVI program will implement the EPRI 

Pressurized Water Reactor Internals Inspection and Evaluation Guidelines, 

MRP-227-A. The RVI Program will use nondestructive examinations (NDE) and 

other inspection methods to manage aging effects for reactor vessel internals. 

The RVI Program includes inspections of core support structures using the 

existing ASME Section Xl, ISI Program as delineated in MRP-227-A, Table 4-9. 

Where credited for the management of cracking, the existing ISI Program is listed 

in Tables 3.1.2-2-1P2 and 3.1.2-2-1P3 in lieu of the RVI Program. 

In RAI 3, the staff requested that the applicant justify the use of the ISI Program to manage 

cracking. In its June 14, 2012, response to RAI 3, the applicant justified its use of the ISI 

Program to manage the aging effect of cracking for the “Upper Support Plate, Support Assembly 

(Including Ring)” on the basis that this component is categorized as an Existing Programs 

component by MRP-227-A, with the ISI Program identified as the existing program in Table 4-9 

of MRP-227-A. The staff notes that in Tables 3.1.2-2-1P2 and 3.1.2-2-1P3, the ISI Program is 

also assigned to manage cracking of the “Lower Internals Assembly—Lower Core Plate,” which 

is also an Existing Programs component in MRP-227-A. For Existing Programs components 

defined in MRP-227-A that rely on the ISI Program, the staff found in its final SE for MRP-227, 

Revision 0 (Ref. 9), that the inspections specified by the ISI Program are adequate to manage 

the aging effect of cracking. Therefore, the staff finds that crediting the ISI Program with 

managing cracking of the “Upper Support Plate, Support Assembly (Including Ring)” and the 

“Lower Internals Assembly—Lower Core Plate” is acceptable because the ISI Program is 

adequate to manage cracking in this component. The staff’s evaluation of the applicant’s ISI 

Program is documented in the SER (Ref. 8),” Section 3.0.3.3.4. 

The staff finds the applicant’s proposal to use the Water Chemistry Control Program (Primary 

and Secondary) to be acceptable for managing cracking due to SCC and IASCC of stainless 

steel RVI components because the Water Chemistry Control Program (Primary and Secondary) 

will control contaminants that can contribute to SCC of stainless steel. The staff’s evaluation of 

the applicant’s Water Chemistry Control Program is documented in Section 3.0.3.2.17 of the 

SER (Ref. 8). 

In addition, the staff notes that LR-ISG-2011-14, “Updated Aging Management Criteria for 

Reactor Vessel Internal Components for Pressurized Water Reactors” (Ref. 7), updates the 

GALL Report, Revision 2, guidance to reflect MRP-227-A and thus contains the most current 

guidance acceptable to the staff for managing aging of RVI. Use of the RVI Program AMP and 

Water Chemistry AMP to manage SCC and IASCC of RVI is consistent with the guidance in 
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LR-ISG-2011-14 Section XI.M16A. Under “Preventive Actions,” LR-ISG-2011-14 states that 

MRP-227-A relies on PWR water-chemistry control to prevent or mitigate aging effects that can 

be induced by corrosive aging mechanisms (e.g., loss of material induced by general, pitting 

corrosion, crevice corrosion, or stress corrosion cracking or any of its forms [SCC, PWSCC, or 

IASCC]), and that reactor coolant water chemistry is monitored and maintained in accordance 

with the Water Chemistry Program as described in GALL AMP XI.M2, “Water Chemistry.” The 

applicant’s use of the ISI Program to manage cracking due to SCC and IASCC is equivalent to 

use of the RVI Program for the components in question because MRP-227-A specifies the ISI 

Program as the existing program credited for inspection for cracking of these components. 

Therefore, the applicant’s use of the RVI Program, ISI Program, and Water Chemistry Control 

Program is consistent with the staff’s most current guidance for aging management of RVI. 

The staff therefore finds the applicant’s use of the combination of the RVI Program, ISI 

Program, and Water Chemistry Control Program (Primary and Secondary) to be acceptable 

because (1) the RVI Program and ISI Program will detect cracking due to SCC and IASCC, the 

Water Chemistry Program will mitigate SCC by minimizing contaminants, and (3) use of these 

programs is consistent with or equivalent to the staff’s most current guidance for aging 

management of RVI. 

The staff’s evaluation of the applicant’s RVI Program is documented in Section 3.0.3.3.9 of this 

SER supplement. 

Based on the programs identified, the staff finds that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3). 

3.1.2.2.15 Changes in Dimensions due to Void Swelling 

By letter dated July 14, 2010, Entergy amended LRA Section 3.1.2.2.15 to remove its previous 

commitment. In response to RAI 2 by letter dated June 14, 2012, Entergy revised LRA 

Section 3.1.2.2.15 to state that “[t]he RVI Program will implement the EPRI Pressurized Water 

Reactor Internals Inspection and Evaluation Guidelines, MRP-227-A. The RVI Program will use 

nondestructive examinations (NDE) and other inspection methods to manage aging effects for 

reactor vessel internals.” 

The staff’s evaluation of the applicant’s program to address this aging effect is documented in 

SER Section 3.0.3.3.9. 

3.1.2.2.17 Cracking due to Stress Corrosion Cracking, Primary Water Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking 

By letter dated July 14, 2010, Entergy amended LRA Section 3.1.2.2.17 to remove its previous 

commitment. In response to RAI 2 by letter dated June 14, 2012, Entergy revised LRA 

Section 3.1.2.2.17 to state that “[t]he RVI Program will implement the EPRI Pressurized Water 

Reactor Internals Inspection and Evaluation Guidelines, MRP-227-A. The RVI Program will use 

nondestructive examinations (NDE) and other inspection methods to manage aging effects for 

reactor vessel internals.” 

The staff’s evaluation of the applicant’s program to address this aging effect is documented in 

SER Section 3.0.3.3.9. 
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The staff noted that the applicant proposes to use the Inservice Inspection Program, in addition 

to the Water Chemistry Control—Primary and Secondary Program, to manage cracking of the 

stainless steel lower internals assembly—lower core plate. The GALL Report, Revision 1, 

recommends Water Chemistry and a commitment to implement the RVI Program. The 

Inservice Inspection program is credited for managing aging of several components. All of the 

components for which the Inservice Inspection Program is credited are classified as “Existing 

Programs” components within MRP-227-A; the ASME Code Section XI Inservice Inspection 

Program is the existing program credited with managing aging of the lower core plate in 

Table 4-9 of MRP-227-A. Further, in its review of the RVI Program, detailed in SER 

Section 3.0.3.3.9, the staff verified that the RVI Inspection Plan implements all of the “Existing 

Programs” inspections specified in MRP-227-A. Based on its review of the stainless steel lower 

core plate, the staff finds the applicant’s proposal to manage cracking due to IASCC using the 

Inservice Inspection Program acceptable because the applicant will perform the visual 

inspections required by ASME Code Section XI and these visual inspections are capable of 

detecting cracking. 

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

3.1.2.3.2 Reactor Vessel Internals—Summary of Aging Management Review 

By letter dated October 17, 2012, the applicant amended LRA Tables 3.1.2-2-IP2 

and 3.1.2-2-IP3 to add nickel-alloy clevis insert bolts which are exposed to treated borated 

water and will be managed for loss of material due to wear by the Inservice Inspection Program. 

The staff’s evaluation of this component, material, environment, and aging effect is documented 

in SER Section 3.0.3.3.10. 

3.2 Aging Management of Engineered Safety Features Systems 

3.2.1 Summary of Technical Information in the Application 

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

3.2.2 Staff Evaluation 

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

3.2.2.1 AMR Results Consistent with the GALL Report 

LRA Tables 3.2.2-1-IP2 through 3.2.2-5-IP2 and 3.2.2-1-IP3 through 3.2.2-5-IP3 summarize the 

results of AMRs for the auxiliary system components and indicate AMRs that are claimed to be 

consistent with the GALL Report. 

Since the issuance of Supplement 1 to the SER (SSER 1), Entergy has amended the LRA in 

annual updates to the LRA or in response to requests for additional information (RAIs). 
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The staff reviewed the information in the amendments to the LRA. The staff verified that the 

material presented in the amendments to the LRA was applicable and that the applicant 

identified the appropriate GALL Report AMRs. 

The staff reviewed the amendments to confirm that the applicant: (a) provided a brief description 

of the system, components, materials, and environments; (b) stated that the applicable aging 

effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects 

for the auxiliary systems components that are subject to an AMR. 

The staff reviewed the applicant’s revisions noted above and found that the additional AMR 

results are consistent with the GALL Report for these combinations of materials and 

environments. On the basis of its review, the staff finds that all applicable aging effects were 

identified and that the aging effects listed are appropriate for the combination of materials and 

environments identified. 

The staff also reviewed an AMR item that cited generic note D in error and an item that cited 

generic note E. The staff evaluated whether all plausible aging effects were identified and 

whether the aging effects listed were appropriate for the combination of materials and 

environments specified. Details of the staff’s evaluation are discussed in Section 3.2.2.1.5. 

3.2.2.1.5 Loss of Material Due to General Corrosion 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2.5-7-IP2 to include 

carbon steel filter housings exposed externally to indoor air and will be managed for loss of 

material by the External Surfaces Monitoring Program. These items cite LRA Table 3.2-1, 

item 3.2.1-32 and generic note E. The staff noted that item 3.2.1-32 is associated with an 

internal indoor air environment. Item 3.2.1-32 in SRP-LR Table 3.2-1 recommends GALL 

Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” to manage loss of material for steel piping and ducting components and internal 

surfaces exposed to air - indoor uncontrolled. However, these items are exposed externally to 

indoor air. GALL Report item A-80 recommends that steel piping components exposed 

externally to indoor air should be managed for loss of material by the External Surfaces 

Monitoring Program. The staff finds the applicant’s use of the External Surfaces Monitoring 

Program acceptable because it is consistent with the GALL Report. 

By letter dated September 26, 2013, the applicant amended LRA Table 3.3.2-13-IP2 by adding 

carbon steel piping and filter housings and gray cast iron turbochargers which are exposed 

internally to indoor air and will be managed for loss of material. These AMR items, which cite 

LRA Table 3.2 1, item 3.2.1-32, and generic note E, credit the External Surfaces Monitoring 

Program. However, by letter dated December 12, 2013, the applicant removed these line items 

from the scope of license renewal because it had re-evaluated the CLB and determined that it 

no longer relies on the black start diesel (GT3-BSD), so it removed from the scope of license 

renewal all previously included components associated with GT3-BSD. 

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling 

(1) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-13-IP2 

by adding copper alloy greater than 15 percent zinc (inhibited) heat exchanger tubes 
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which are exposed externally to lubricating oil, and will be managed for fouling. This 

AMR item, which cites item 3.2.1-9 and generic note D and plant-specific note 316, 

credits the Oil Analysis Program and the One-Time Inspection Program. The staff’s 

evaluation of this material, environment, aging effect, and program combination is 

documented in SER Section 3.2.2.2.4, item (1). 

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

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

3.3 Aging Management of Auxiliary Systems 

3.3.1 Summary of Technical Information in the Application 

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

3.3.2 Staff Evaluation 

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

3.3.2.1 AMR Results Consistent with the GALL Report 

LRA Tables 3.3.2-1-IP2 through 3.3.2-18-IP2, 3.3.2-1-IP3 through 3.3.2-18-IP3, 3.3.2-19-1-IP2 

through 3.3.2-19-44-IP2, and 3.3.2-19-1-IP3 through 3.3.2-19-65-IP3 summarize the results of 

AMRs for the auxiliary system components and indicate AMRs that are claimed to be consistent 

with the GALL Report. 

Since the issuance of SSER 1, Entergy has amended the LRA in annual updates to the LRA or 

in response to requests for additional information (RAIs). 

The staff reviewed the information in the amendments to the LRA. The staff verified that the 

material presented in the amendments to the LRA was applicable and that the applicant 

identified the appropriate GALL Report AMRs. 

The staff reviewed the amendments to confirm that the applicant: (a) provided a brief description 

of the system, components, materials, and environments; (b) stated that the applicable aging 

effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects 

for the auxiliary systems components that are subject to an AMR. 

By letter dated December 20, 2011, the applicant submitted an annual update to the LRA, 

identifying changes made to the CLB that materially affect the contents of the LRA. For the 

IP2 nitrogen system, the applicant revised LRA Table 3.3.2-5-IP2 to delete AMR entries for a 

stainless steel flow element exposed internally to gas with an aging effect of “none” and 

exposed externally to indoor air with an aging effect of “none.” Additionally, the applicant 

revised LRA Table 3.3.2-3-IP3 to add a stainless steel flow element exposed internally to 

treated water with an aging effect of “loss of material” and exposed externally to indoor air with 

an aging effect of “none,” and generic notes A and B. 
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By letter dated September 26, 2012, the applicant submitted an update to its LRA which 

amended LRA tables associated with the auxiliary feedwater pump room fire event. The 

applicant identified changes during an extent-of-condition review that resulted from the 

discovery of previously provided information that was either incorrect or omitted from the LRA. 

The applicant amended LRA tables associated with LRA Section 3.3 to add components made 

of carbon steel and copper alloy exposed to indoor air or outdoor air. 

By letter dated December 27, 2012, the applicant submitted an annual update to the LRA, 

identifying changes made to the CLB that materially affect the contents of the LRA. The 

applicant amended LRA tables associated with LRA Section 3.3 to add components made of 

stainless steel, carbon steel, copper alloy with greater than 15 percent zinc, gray cast iron, 

copper alloy, and aluminum bronze exposed to indoor air, treated water, treated borated water 

greater than 140 °F, raw water, and fuel oil. 

By letter dated September 26, 2013, the applicant submitted a partial annual update to the LRA, 

identifying changes made to the CLB that materially affect the contents of the LRA. The 

applicant amended LRA Table 3.3.2-13-IP2 for the fuel oil system to add components made of 

stainless steel, carbon steel, copper alloy greater than 15 percent zinc, gray cast iron, and 

aluminum exposed to indoor air or treated water. By letter dated December 12, 2013, the 

applicant removed these components from the scope of license renewal because it had 

re-evaluated the CLB and determined that it no longer relied on the black start diesel 

(GT3-BSD), so it removed from the scope of license renewal all previously included components 

associated with GT3-BSD. 

By letter dated December 12, 2013, the applicant submitted an annual update to the LRA, 

identifying changes made to the CLB that materially affect the contents of the LRA. The 

applicant amended LRA tables associated with LRA Section 3.3 to add components made of 

stainless steel and copper alloy with greater than 15 percent zinc exposed to indoor air, treated 

water, treated borated water, and treated borated water greater than 140 °F. The AMR items 

cite generic notes A and C. 

The staff reviewed the applicant’s revisions noted above and found that the additional AMR 

results are consistent with the GALL Report for these combinations of materials and 

environments. On the basis of its review, the staff finds that all applicable aging effects were 

identified and that the aging effects listed are appropriate for the combination of materials and 

environments identified. 

3.3.2.1.12 Loss of Material due to General, Pitting and Crevice Corrosion 

By letter dated October 18, 2012, the applicant amended LRA Tables 3.3.2-2-IP3, 3.3.2-13-IP2 

and 3.3.2-13-IP3 by adding carbon steel piping which is externally exposed to condensation and 

will be managed for loss of material. These AMR items, which cite LRA Table 3.3.1, 

items 3.3.1-58 and 3.3.1-60 and generic note E, credit the Buried Piping and Tanks Inspection 

Program to manage the aging effect for these components. The GALL Report recommends 

GALL Report AMP XI.M36, “External Surfaces Monitoring,” to assure that these aging effects 

are adequately managed. GALL Report AMP XI.M36 recommends using periodic external 

visual examinations to manage aging. 

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.1.2. In its letter dated October 18, 2012, the applicant stated 
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that portions of the IP3 service water, IP3 city water, and IP2 and IP3 fuel oil systems are 

located in vaults or pipe trenches. 

Based on its review of components associated with items 3.3.1-58 and 3.3.1-60, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging of 

underground piping using the Buried Piping and Tanks Inspection Program acceptable because 

(a) although the piping is not coated, the applicant has significantly increased the frequency of 

inspections, to every 2 years versus every 10 years as recommended in LR-ISG-2011-03; 

(b) the applicant is inspecting all of the underground piping instead of two percent of the pipe as 

recommended in LR-ISG-2011-03; (c) the visual inspections before the period of extended 

operation and those conducted during the period of extended operation are capable of detecting 

loss of material before the intended function of the piping not being met; and (d) the inspection 

frequencies would not be revised to every 10 years as recommended by LR-ISG-2011-03 

unless the piping is coated. 

The staff concludes that for LRA Items 3.3.1-58 and 3.3.1-60, the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation 

as required by 10 CFR 54.21(a)(3). 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-13-IP2 by 

adding gray cast iron valve bodies which are exposed to indoor air (external) and will be 

managed for loss of material by the External Surfaces Monitoring Program. These items cite 

LRA Table 3.3 1, item 3.3.1-14, generic note D, and plant-specific note 316. Item 3.3.1-14 in 

SRP-LR Table 3.3 1 is used for steel piping, piping components, and piping elements exposed 

to lubricating oil. The staff recognizes that the applicant used the wrong table 1 line item; 

nevertheless, GALL Report item A-80 (SRP-LR item 3.3.1-57) states that gray cast iron valve 

bodies exposed to indoor air (external) should be managed for loss of material by the External 

Surfaces Monitoring Program. The staff finds the applicant’s use of the External Surfaces 

Monitoring Program acceptable because it is consistent with the GALL Report. 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-7-IP2 by adding 

carbon steel piping and valve bodies which are exposed to condensation (internal) and will be 

managed for loss of material. These AMR items, which cite item 3.3.1-71 and generic note E, 

credit the Periodic Surveillance and Preventive Maintenance Program. The GALL Report 

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

Piping and Ducting Components,” to assure that these aging effects are adequately managed. 

GALL Report AMP XI.M38 recommends periodic opportunistic visual inspections to detect loss 

of material. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff noted that the Periodic Surveillance 

and Preventive Maintenance Program proposes to manage the aging of carbon steel piping and 

valve bodies through the use of periodic visual examinations (conducted every 5 years) to 

detect loss of material for a representative population of each material and environment 

combination. The staff also noted that the program permits increasing the inspection’s sample 

size if aging effects are detected. Unacceptable inspection findings are evaluated in 

accordance with the corrective action process to determine the need for accelerated inspection 

frequency and for monitoring and trending the results. Based on its review of these 

components, the staff finds the applicant’s proposal to manage aging using the Periodic 

Surveillance and Preventive Maintenance Program acceptable because (a) periodic visual 
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inspections are performed which are capable of detecting loss of material; (b) the inspection 

sample size is increased if aging effects are detected, providing reasonable assurance that 

aging effects can be detected if they are occurring in other components; and (c) inspection 

findings are evaluated through the corrective action process, assuring that the intended 

functions of these components will be maintained consistent with the CLB for the period of 

extended operation. 

3.3.2.1.13 Loss of Material due to General and Pitting Corrosion 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-13-IP2 by 

adding gray cast iron compressor housings and carbon steel silencers which are exposed to 

internal condensation and will be managed for loss of material. These AMR items, which cite 

item 3.3.1-53 and generic note E, credit the Periodic Surveillance and Preventive Maintenance 

Program. The GALL Report recommends GALL Report AMP XI.M24, “Compressed Air 

Monitoring,” to assure that these aging effects are adequately managed. The staff’s evaluation 

of loss of material due to general and pitting corrosion for steel compressed-air system piping, 

piping components, and piping elements exposed to condensation (internal) being managed by 

the Periodic Surveillance and Preventive Maintenance Program is documented in SER 

Section 3.3.2.1.3. However, gray cast iron is known to be susceptible to selective leaching in 

certain environments. It was not clear to the staff whether sufficient condensation could 

accumulate in the compressor housing to cause selective leaching. By letter dated 

June 12, 2013, the staff issued RAI 3.4.2.1.9-1 requesting that the applicant provide clarification 

about whether sufficient condensation could accumulate in any portions of the gray cast iron 

compressor and strainer housings to such a degree that selective leaching could occur, and if 

selective leaching could occur, how the aging effect would be managed. In its response dated 

July 24, 2013, the applicant stated that the gray cast iron compressor and strainer housing in 

Table 3.4.2-5-13-IP2 have a drain trap system to prevent accumulation of condensation. The 

applicant also stated that selective leaching in a condensation environment has not been 

observed at Indian Point. 

The staff finds the response to RAI 3.4.2.1.9-1 acceptable because drain traps are capable of 

preventing an accumulation of condensation, and if condensation does not accumulate, 

selective leaching will not occur. 

The staff’s concern described in RAI 3.4.2.1.9-1 is resolved. 

3.3.2.1.14 Loss of Material due to Pitting and Crevice Corrosion 

By letter dated September 26, 2012, the applicant amended LRA Tables 3.4.2-5-7-IP2 

and 3.4.2-5-7-IP2 by adding stainless steel tubing, valve bodies, dryer housings, filter housings, 

and aluminum valve bodies which are exposed to condensation (internal) and will be managed 

for loss of material. The AMR items, which cite item 3.3.1-54 and generic note E, credit the 

One-Time Inspection Program. The staff’s evaluation of loss of material for stainless steel 

piping and piping components exposed to condensation being managed by the One-Time 

Inspection Program is documented in SER Section 3.3.2.1.3. The addition of aluminum valve 

bodies does not alter the staff’s evaluation because pitting and crevice corrosion can be as 

effectively detected in aluminum components as in stainless steel. 
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3.3.2.1.15 No Aging Effect Requiring Management 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-7-IP2 by adding 

aluminum valve bodies exposed to indoor air (external) and treated air (internal), citing LRA 

Table 3.3.1, item 3.3.1-54. These items have no AERM and no recommended AMP. The staff 

finds the applicant’s proposal acceptable because GALL Report items TP-8, EP-3, and AP-36 

recommend no AERM or AMP for aluminum exposed to indoor air (external) and treated air 

(internal). 

3.3.2.1.16 Loss of Material due to General Corrosion 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-7-IP2 by adding 

carbon steel filter housings which are exposed to indoor air (internal) and will be managed for 

loss of material by the Periodic Surveillance and Preventive Maintenance Program. These 

items cite LRA Table 3.3 1, item 3.3.1 57, and generic note A. The SRP LR states that loss of 

material for this material and environment combination should be managed by GALL Report 

AMP XI.M36, “External Surfaces Monitoring.” GALL Report AMP XI.M36 recommends using 

periodic visual inspections at least once per refueling cycle to manage loss of material. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The Periodic Surveillance and Preventive 

Maintenance Program proposes to manage the aging of carbon steel filter housings through the 

use of periodic visual inspections, which are conducted at least once every 5 years. The staff 

noted that the program permits increasing the inspection’s sample size if aging effects are 

detected. The staff also noted that unacceptable inspection findings are evaluated in 

accordance with the corrective action process to determine the need for accelerated inspection 

frequency and for monitoring and trending the results. Based on its review of these 

components, the staff finds the applicant’s proposal to manage aging using the Periodic 

Surveillance and Preventive Maintenance Program acceptable because (a) periodic visual 

inspections are performed which are capable of detecting loss of material; (b) the inspection 

sample size is increased if aging effects are detected, providing reasonable assurance that 

aging effects can be detected if they are occurring in other components; and (c) inspection 

findings are evaluated by the corrective action process, assuring that the intended functions of 

these components will be maintained consistent with the CLB for the period of extended 

operation. 

3.3.2.1.17 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced 

Corrosion, Fouling, and Lining/Coating Degradation 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-5-IP2 by adding 

gray cast iron piping and valve bodies which are exposed to raw water (internal) and will be 

managed for loss of material. These AMR items, which cite item 3.3.1-76 and generic note E, 

credit the Periodic Surveillance and Preventive Maintenance Program. The GALL Report 

recommends GALL Report AMP XI.M20, “Open Cycle Cooling Water System,” to assure that 

these aging effects are adequately managed. GALL Report AMP XI.M20 recommends periodic 

visual inspections to detect loss of material. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff noted that the Periodic Surveillance 

and Preventive Maintenance program proposes to manage the aging of gray cast iron piping 

and valve bodies through the use of periodic visual examinations (which are conducted at least 
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once every 5 years) to detect loss of material for a representative population of each material 

and environment combination. The staff also noted that the program permits increasing the 

inspection’s sample size if aging effects are detected. The staff further noted that unacceptable 

inspection findings are evaluated in accordance with the corrective action process to determine 

the need for accelerated inspection frequency and for monitoring and trending the results. 

Based on its review of these components, the staff finds the applicant’s proposal to manage 

aging using the Periodic Surveillance and Preventive Maintenance Program acceptable 

because (a) periodic visual inspections are performed which are capable of detecting loss of 

material; (b) the inspection sample size is increased if aging effects are detected, providing 

reasonable assurance that aging effects can be detected if they are occurring in other 

components; and (c) inspection findings are evaluated by the corrective action process, 

assuring that the intended functions of these components will be maintained consistent with the 

CLB for the period of extended operation. 

3.3.2.1.18 Loss of Material Due to Pitting, Crevice, Galvanic, and Microbiologically-Influenced 

Corrosion, and Fouling 

By letter dated September 26, 2012, the applicant amended LRA Table 3.3.2-19-13-IP2 by 

adding copper alloy heat exchanger bonnets which are exposed to raw water (internal) and will 

be managed for loss of material. This AMR item, which cites item 3.3.1-82 and generic note E, 

credits the Periodic Surveillance and Preventive Maintenance Program. The GALL Report 

recommends GALL Report AMP XI.M20, “Open Cycle Cooling Water System,” to assure that 

these aging effects are adequately managed. GALL Report AMP XI.M20 recommends periodic 

visual inspections to detect loss of material. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventative Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff noted that the Periodic Surveillance 

and Preventative Maintenance Program proposes to manage the aging of copper alloy heat 

exchanger bonnets through the use of periodic visual inspections which are conducted at least 

once every 5 years. The staff noted that the program permits increasing the inspection’s 

sample size if aging effects are detected. The staff also noted that unacceptable inspection 

findings are evaluated in accordance with the corrective action process to determine the need 

for accelerated inspection frequency and for monitoring and trending the results. Based on its 

review of these components, the staff finds the applicant’s proposal to manage aging using the 

Periodic Surveillance and Preventive Maintenance Program acceptable because (a) periodic 

visual inspections are performed which are capable of detecting loss of material; (b) the 

inspection sample size is increased if aging effects are detected, providing reasonable 

assurance that aging effects can be detected if they are occurring in other components; and 

(c) inspection findings are evaluated by the corrective action process, assuring that the intended 

functions of these components will be maintained consistent with the CLB for the period of 

extended operation. 

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 

(1) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-2-IP2 by 

adding elastomer expansion joints which are exposed to air-indoor (external) and will be 

managed for cracking and change in material properties. This AMR item, which cites 

item 3.3.1-11 and generic note E, credits the Periodic Surveillance and Preventive 
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Maintenance Program. The GALL Report recommends further evaluation of a 

plant-specific AMP to assure that these aging effects are adequately managed. The 

staff’s evaluation of this material, environment, aging effect, and program combination is 

documented in SER Section 3.3.2.2.5, Item (1). 

3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion 

(1) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-13-IP2 

by adding carbon steel filter housings, piping, pump casings, tanks, and carbon steel 

and gray cast iron valve bodies which are internally exposed to lubricating oil and will be 

managed for loss of material. This AMR item, which cites item 3.3.1-14, generic note D, 

and plant-specific note 316, credits the Oil Analysis and the One-Time Inspection 

Programs. The staff’s evaluation of this material, environment, aging effect, and 

program combination is documented in SER Section 3.3.2.2.7, Item (1). 

(3) By letter dated September 26, 2013, the applicant amended LRA Table 3.3.2-13-IP2 to 

add stainless steel flexible bellows and carbon steel piping and silencers which are 

exposed internally to exhaust gas and will be managed for loss of material. These AMR 

items, which cite item 3.3.1-18, credit the Periodic Surveillance and Preventive 

Maintenance Program. However, by letter dated December 12, 2013, the applicant 

removed these line items from the table because it had re-evaluated the CLB and 

determined that it no longer relies on the black start diesel (GT3-BSD), so it removed 

from the scope of license renewal all previously included components associated with 

the black start diesel. 

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced 

Corrosion and Fouling 

(2) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-13-IP2 

by adding carbon steel heat exchanger shells which are exposed to lubricating oil and 

will be managed for loss of material. This AMR item, which cites item 3.3.1-21, generic 

note D, and plant-specific note 316, credits the Oil Analysis and One-Time Inspection 

Programs. The staff’s evaluation of this material, environment, aging effect, and 

program combination is documented in SER Section 3.3.2.2.9, Item (2). The staff noted 

that in its September 26, 2012, amendment, the applicant did not address fouling as an 

applicable aging effect for this material and environment combination. However, the 

staff finds that the visual one-time inspections for loss of material are equally capable of 

detecting fouling. 

3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion 

(3) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-9-IP2 by 

adding copper alloy valve bodies which are exposed to condensation (external) and will 

be managed for loss of material. By letter dated December 27, 2012, the applicant 

submitted an annual update to its LRA, identifying changes to the CLB that materially 

affect the LRA. For the IP3 service water system, the applicant revised LRA 

Table 3.3.2-2-IP3 to add an AMR item for aluminum bronze pump casing exposed 

externally to condensation. These AMR items, which cite item 3.3.1-25 and generic 

note E, credit the External Surfaces Monitoring Program. The GALL Report 

recommends a plant-specific AMP to detect loss of material. 
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The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is 

documented in SER Section 3.0.3.2.5. The staff noted that the External Surfaces 

Monitoring Program proposes to manage the aging of components through the use of 

periodic visual inspections. A visual inspection is conducted for component surfaces at 

least once per refueling cycle. The intervals of inspections may be adjusted as 

necessary based on plant-specific inspection results and industry experience. Based on 

its review of these components associated with item 3.3.1-25, the staff finds the 

applicant’s proposal to manage aging using the External Surfaces Monitoring Program 

acceptable because visual inspections which are capable of detecting loss of material 

are conducted for component surfaces at least once per refueling cycle. 

(4) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-9-IP2 by 

adding copper alloy with greater than 15 percent zinc (inhibited) heat exchanger tubes 

which are exposed to lubricating oil (external) and will be managed for loss of material. 

This AMR item, which cites item 3.3.1-26, generic note D, and plant-specific note 316, 

credits the Oil Analysis Program and the One-Time Inspection Program. The staff’s 

evaluation of this material, environment, aging effect, and program combination is 

documented in SER Section 3.3.2.2.10, Item (4). The staff noted that the SER 

evaluation was associated with copper alloy components, whereas these items are 

composed of copper alloy with greater than 15 percent zinc (inhibited). The aging 

effects for copper alloy and copper alloy with greater than 15 percent zinc (inhibited) are 

the same based on the definition of “copper alloy greater than 15 percent zinc” in GALL 

Report Section IX.C, “Selected Definitions and Use of Terms for Describing and 

Standardizing Materials.” 

(5) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-9-IP2 by 

revising the material designation of the carbon steel nozzles to stainless steel nozzles; 

these are exposed to condensation (external) and will be managed for loss of material. 

This AMR item, which cites item 3.3.1-27 and generic note E, credits the External 

Surfaces Monitoring Program. The GALL Report recommends a plant-specific AMP to 

detect loss of material. The staff’s evaluation of this material, environment, aging effect, 

and program combination is documented in SER Section 3.3.2.2.10, Item (5). 

(6) By letter dated September 26, 2012, the applicant amended LRA Tables 3.4.2-5-7-IP2 

and 3.4.2-5-13-IP2 by adding copper alloy and copper alloy with greater than 15 percent 

zinc tubing, valve bodies, and heat exchanger tubes which are exposed to condensation 

(internal) and will be managed for loss of material. These AMR items, which cite 

item 3.3.1-28 and generic note E, credit the Periodic Surveillance and Preventive 

Maintenance Program. The staff’s evaluation of this material, environment, aging effect, 

and program combination is documented in SER Section 3.3.2.2.10, Item (6). 

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

3.3A.2.3.1 Service Water System—Summary of Aging Management Review—LRA 

Table 3.3.2-2-IP2 

Plastic piping exposed internally to raw water and externally to indoor air. By letter dated 

September 26, 2013, the applicant amended LRA Table 3.3.2-2-IP2 by adding plastic piping 

exposed to raw water (internally) and indoor air (externally). For the internal piping surfaces 

exposed to raw water, the applicant stated that changes in material properties will be managed 

by the Service Water Integrity Program. For the external piping surfaces exposed to indoor air, 
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the applicant stated that there is no aging effect and did not propose an AMP. The AMR items 

cite generic note F. The staff’s evaluation of plastic piping exposed externally to indoor air is 

documented in SER Section 3.3A.2.3.15. 

In its evaluation for plastic piping exposed internally to raw water, the staff noted that the 

applicant’s aging management approach is consistent with the guidance in the GALL Report, 

Revision 2. GALL Report, Revision 2, items VII.C1.AP-238 and VII.C1.AP-239 state that plastic 

piping exposed to raw water is susceptible to cracking, blistering, and changes in color due to 

water absorption and recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water 

System,” to manage these aging effects. GALL Report AMP XI.M20 recommends that the 

inspection scope, methods, and frequency be in accordance with the applicant’s response to 

NRC Generic Letter (GL) 89-13, “Service Water System Problems Affecting Safety-Related 

Components.” 

The staff’s evaluation of the applicant’s Service Water Integrity Program is documented in SER 

Section 3.0.3.1.14. The staff noted that the applicant’s program relies on the implementation of 

the recommendations of GL 89-13 to assure that the effects of aging on the service water 

system are adequately managed. The applicant’s response to GL 89-13 in a letter dated 

February 2, 1990, states that visual inspections are used to identify fouling, sedimentation, and 

corrosion of the internal surfaces of service water system components (Ref. 39). Although the 

staff recognizes that the applicant’s response to GL 89-13 does not specifically address 

changes in material properties of plastic piping, the staff finds the applicant’s proposal 

acceptable because the visual inspections are capable of detecting changes in color and 

surface condition that indicate changes in material properties. 

3.3A.2.3.10 Fuel Oil System—Summary of Aging Management Review—LRA 

Table 3.3.2-13-IP2 

Copper alloy heat exchanger tube exposed externally to indoor air. By letter dated 

September 26, 2013, the applicant amended LRA Table 3.3.2-13-IP2 by adding copper alloy 

with greater than 15 percent zinc heat exchanger tubes which are exposed externally to indoor 

air and will be managed for fouling. This AMR item, which cites generic note G, credits the 

Periodic Surveillance and Preventive Maintenance Program. By letter dated 

December 12, 2013, the applicant removed this line item from the table because it had 

re-evaluated the CLB and determined that it no longer relied on the black start diesel 

(GT3-BSD), so it removed from the scope of license renewal all previously included components 

associated with GT3-BSD. 

Aluminum turbochargers exposed internally to exhaust gas. By letter dated 

September 26, 2013, the applicant amended LRA Table 3.3.2-13-IP2 by adding aluminum 

turbochargers which are exposed internally to exhaust gas and will be managed for loss of 

material by the Periodic Surveillance and Preventive Maintenance Program. The AMR item 

cites generic note G. By letter dated December 12, 2013, the applicant removed this line item 

because it had re-evaluated the CLB and determined that it no longer relied on the black start 

diesel (GT3-BSD), so it removed from the scope of license renewal all previously included 

components associated with GT3-BSD. 

Stainless steel flexible bellows and carbon steel silencers exposed internally to exhaust gas. By 

letter dated September 26, 2013, the applicant amended LRA Table 3.3.2-13-IP2 by adding 

stainless steel flexible bellows and carbon steel silencers which are exposed to exhaust gas 

(internal) and will be managed for cracking fatigue. These AMR items, which cite generic 
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note H, credit the Periodic Surveillance and Preventive Maintenance Program. By letter dated 

December 12, 2013, the applicant removed these line items because it had re-evaluated the 

CLB and determined that it no longer relied on the black start diesel (GT3-BSD), so it removed 

from the scope of license renewal all previously included components associated with 

GT3-BSD. 

3.3A.2.3.35 Water Treatment Plant System, Nonsafety-Related Components Potentially 

Affecting Safety Function—Summary of Aging Management Review—LRA 

Table 3.3.2-19-43-IP2 

By letter dated September 26, 2012, the applicant amended LRA Table 3.3.3-19-43-IP2 by 

adding stainless steel bolting which is exposed to outdoor air and will be managed for loss of 

material by the Bolting Integrity Program. The AMR item cites generic note G. The staff’s 

evaluation of this material, environment, aging effect, and program combination is documented 

in SER Section 3.3A.2.3.4. The staff noted that the applicant did not include cracking as an 

AERM. When stainless steel materials are exposed to outdoor air they can be susceptible to 

cracking depending on plant-specific environmental conditions. SER Section 3.0.3.2.2, “Bolting 

Integrity Program,” addresses cracking by stating that, “[t]he program periodically inspects 

closure bolting for signs of leakage that may be caused by crack initiation, loss of preload, or 

loss of material due to corrosion. The program also includes preventive measures to preclude 

or minimize loss of preload and cracking.” The staff finds the applicant’s proposal acceptable 

because the inspector will be inspecting for signs of leakage which would occur regardless of 

the aging effect (i.e., as a result of loss of material, cracking, or loss of preload). 

3.3B.2.3.13 City Water System—Summary of Aging Management Review—LRA 

Table 3.3.2-17-IP3 

Copper piping exposed to outdoor air. By letter dated October 18, 2012, the applicant amended 

LRA Table 3.3.2-17-IP3 by adding copper piping which is exposed to outdoor air and will be 

managed for loss of material by the Buried Piping and Tanks Inspection Program. The AMR 

item cites generic note G. The applicant stated that this piping is located in underground vaults 

or pipe trenches. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The guidance in GALL Report, Revision 2, item AP-159, 

states that loss of material due to pitting and crevice corrosion is the only applicable aging 

effect. Accordingly, the staff finds that the applicant has identified all credible aging effects for 

this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.1.2. The staff finds the applicant’s proposal to manage aging 

using the Buried Piping and Tanks Inspection Program acceptable because (a) although the 

piping is not coated, the applicant has significantly increased the frequency of inspections to 

every 2 years from every 10 years as recommended in LR-ISG-2011-03; (b) the applicant is 

inspecting all of the underground piping instead of two percent of the pipe as recommended in 

LR-ISG-2011-03; (c) the visual inspections before the period of extended operation and those 

conducted during the period of extended operation are capable of detecting loss of material 

before the piping would be unable to perform its intended function; and (d) the inspection 

frequencies would not be revised to every 10 years as recommended by LR-ISG-2011-03 

unless the piping is coated. 
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On the basis of its review, for these items in LRA Table 3.3.2-17-IP3, the staff concludes that 

the applicant has demonstrated that the effects of aging for the items will be adequately 

managed so that their intended function(s) will be maintained in ways consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2B.3.21 City Water Makeup System, Nonsafety-Related Components Potentially Affecting 

Safety Functions—Summary of Aging Management Review—LRA 

Table 3.3.2-19-13-IP3 

Copper alloy flow element and tubing and gray cast iron valve bodies exposed internally to 

treated water. By letter dated December 27, 2012, the applicant amended LRA 

Tables 3.3.2-19-13-IP3 and 3.4.2-5-4-IP2 by adding copper alloy flow elements and tubing and 

gray cast iron valve bodies which are exposed internally to treated water and will be managed 

for loss of material by the Periodic Surveillance and Preventive Maintenance Program. The 

AMR item cites generic note G and plant-specific note 305, which states that this treated-water 

environment includes water that has been treated but is not maintained by the chemistry-control 

program. The staff’s evaluation of this material, environment, aging effect, and program 

combination is documented in SER Section 3.3A.2.3.14. 

Copper alloy with greater than 15 percent zinc strainer housings exposed internally to treated 

water. By letter dated December 12, 2013, the applicant amended LRA Table 3.3.2-19-13-IP3 

by adding copper alloy with greater than 15 percent zinc strainer housings which are exposed 

internally to treated water and will be managed for loss of material with the Periodic Surveillance 

and Preventive Maintenance Program. The AMR item cites generic note G. The staff’s 

evaluation of this material, environment, aging effect, and program combination is documented 

in SER Section 3.3A.2.3.14. 

3.3.2B.3.42 Fuel Oil Systems—Summary of Aging Management Review—LRA 

Table 3.3.2-13-IP3 

Aluminum turbocharger exposed internally to exhaust gas. By letter dated December 27, 2012, 

the applicant amended LRA Table 3.3.2-13-IP3 by adding aluminum turbochargers which are 

exposed internally to exhaust gas and will be managed for loss of material by the Periodic 

Surveillance and Preventive Maintenance Program. The AMR item cites generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff finds the applicant’s proposal acceptable 

based on its review of the GALL Report and ASM Metals Handbook Desk Edition, Second 

Edition (Ref. 40), which states that aluminum has good corrosion resistance in natural 

atmospheres, fresh waters, seawater, and many chemicals and their solutions, as well as not 

being susceptible to stress corrosion cracking. The staff finds that the applicant has identified 

all credible aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff finds the applicant’s proposal to 

manage aging using the Periodic Surveillance and Preventive Maintenance Program acceptable 

because the program uses periodic visual inspection of internal and external surfaces. These 

visual inspections are capable of detecting a loss of material due to pitting and crevice 

corrosion, and microbiologically influenced corrosion (MIC). 
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Copper alloy heat exchanger tube exposed internally to indoor air. By letter dated 

December 27, 2012, the applicant amended LRA Table 3.3.2-13-IP3 by adding copper alloy 

with greater than 15 percent zinc heat exchanger tubes which are exposed externally to indoor 

air and will be managed for fouling by the Periodic Surveillance and Preventive Maintenance 

Program. The AMR item cites generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Items EP-10 and SP-6 in Revision 2 of the GALL Report 

state that there is no AERM or AMP. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff finds the applicant’s proposal to 

manage fouling as a possible aging effect by using the Periodic Surveillance and Preventive 

Maintenance Program acceptable because, even though fouling is not expected to occur, the 

program uses periodic visual inspection of external surfaces, which is capable of detecting 

fouling. 

Stainless steel flexible bellows exposed internally to exhaust gas. By letter dated 

December 27, 2012, the applicant amended LRA Table 3.3.2-13-IP3 by adding stainless steel 

flexible bellows and carbon steel silencer which are exposed internally to exhaust gas and will 

be managed for cracking fatigue by the Periodic Surveillance and Preventive Maintenance 

Program. The AMR item cites generic note H. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Item AP-33 in Revision 2 of the GALL Report states that 

cracking is the only applicable aging effect for stainless steel exposed to exhaust gas; therefore, 

the staff finds that the applicant has identified all credible aging effects for this component, 

material, and environment combination. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff finds the applicant’s proposal to 

manage aging using the Periodic Surveillance and Preventive Maintenance Program acceptable 

because the program uses periodic visual inspection of internal and external surfaces. These 

visual inspections are capable of detecting cracking. 

3.4 Aging Management of Steam and Power Conversion Systems 

3.4.1 Summary of Technical Information in the Application 

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

3.4.2 Staff Evaluation 

There are no changes or updates to this section of the SER. 
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3.4.2.1 AMR Results Consistent with the GALL Report 

LRA Tables 3.4.2-1-IP2 through 3.4.2-5-13-IP2 and 3.4.2-1-IP3 through 3.4.2-4-IP3 summarize 

the results of AMRs for the steam and power conversion system components and indicate 

AMRs that are claimed to be consistent with the GALL Report. 

Since the issuance of SSER 1, Entergy has amended the LRA in annual updates to the LRA, in 

response to an RAI, or to correct previous RAI responses. 

The staff reviewed the information in the amendments to the LRA. The staff verified that the 

material presented in the amendments to the LRA was applicable and that the applicant 

identified the appropriate GALL Report AMRs. 

The staff reviewed the amendments to confirm that the applicant: (a) provided a brief description 

of the system, components, materials, and environments; (b) stated that the applicable aging 

effects were reviewed and evaluated in the GALL Report; and (c) identified those aging effects 

for the auxiliary systems components that are subject to an AMR. 

By letter dated January 30, 2012, the applicant submitted corrections to the LRA, identifying an 

omission in a previous response to an RAI. For the IP2 river water service system, the 

applicant revised LRA Table 3.4.2-5-11-IP2 to add AMR entries for carbon steel bolting and 

piping exposed externally to soil with an aging effect of “loss of material,” and generic notes C 

and A, respectively. 

By letter dated September 26, 2012, the applicant submitted a correction to its LRA which 

amended LRA tables associated with the auxiliary feedwater pump room fire event. The 

changes were identified during an extent-of-condition review that resulted from the discovery of 

previously provided information that was either incorrect or omitted. The applicant amended 

several LRA tables to add or remove components made of copper alloy greater than 15 percent 

zinc (inhibited and uninhibited), copper alloy, glass, titanium, elastomeric material, gray cast 

iron, carbon steel, and stainless steel exposed to lubricating oil, condensation, treated water, 

raw water, outdoor air, indoor air, and treated water greater than 140 °F. 

By letter dated December 27, 2012, the applicant submitted an annual update to the LRA, 

identifying changes made to the CLB that materially affect the contents of the LRA. The 

applicant amended LRA Table 3.4.2-5-4-IP2 to add gray cast iron valve bodies made of gray 

cast iron exposed to indoor air. 

The staff reviewed the applicant’s revisions, noted above, and found that the additional AMR 

results are consistent with the GALL Report for these combinations of materials and 

environments. On the basis of its review, the staff finds that all applicable aging effects were 

identified and that the aging effects listed are appropriate for the combination of materials and 

environments identified. 

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

3.4.2.2.6 Cracking Due to Stress Corrosion Cracking 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-2-IP2 by adding 

stainless steel expansion joints and sight glasses which are exposed to treated water greater 
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than 140 °F (internal) and will be managed for cracking. These AMR items, which cite 

item 3.4.1-14, generic note A, and plant-specific notes 314 and 404, credit the Water Chemistry 

Control—Primary and Secondary and the One-Time Inspection Programs. The staff’s 

evaluation of this material, environment, aging effect, and program combination is documented 

in Section 3.4.2.2.6 of the SER. 

3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion 

(1) By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-2-IP2 by 

adding stainless steel expansion joints and sight glasses which are exposed to treated 

water greater than 140 °F (internal) and will be managed for loss of material. These 

AMR items, which cite item 3.4.1-16, generic note A, and plant-specific note 404, credit 

the Water Chemistry Control—Primary and Secondary and the One-Time Inspection 

Programs. The staff’s evaluation of this material, environment, aging effect, and 

program combination is documented in Section 3.4.2.2.7, item (1) of the SER. 

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

3.4.2A.3.5 IP2 Auxiliary Feedwater Pump Room Fire Event—Summary of Aging Management 

Review—LRA Table 3.4.2-5-1-IP2 through 3.4.2-5-13-IP2 

LRA Table 3.4.2-5-2-IP2 Condensate System 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-2-IP2 by adding 

an elastomeric expansion joint which is exposed internally to treated water and will be managed 

for cracking and change in material properties by the Periodic Surveillance and Preventive 

Maintenance Program. The AMR items cite generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. GALL Report Table IX.E, “Aging Effects,” states that 

elastomeric components are subject to hardening and loss of strength. The staff noted that 

hardening in elastomers can result in cracking. Therefore, the staff finds that the applicant has 

identified all credible aging effects for this component, material, and environment combination. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff finds the applicant’s proposal to 

manage aging using the Periodic Surveillance and Preventive Maintenance Program acceptable 

because (a) periodic visual inspections and physical manipulation of the flexible connections are 

performed which are capable of detecting cracking and changes in material properties of 

elastomeric components; (b) the inspection sample size is increased if aging effects are 

detected, providing reasonable assurance that aging effects can be detected if they are 

occurring in other components; and (c) inspection findings are evaluated by the corrective action 

process, assuring that the intended functions of these components will be maintained consistent 

with the CLB for the period of extended operation. 

The applicant amended LRA Table 3.4.2-5-2-IP2 by also adding titanium heat exchanger tubes 

which are exposed to treated water (internal) and steam (external) and will be managed for loss 

of material and fouling by the Water Chemistry Control—Primary and Secondary Program. The 

AMR items cite generic note F. Additionally, by letter dated July 15, 2013, the applicant 

amended these line items by adding plant-specific note 404, which states that, “[t]he One-Time 
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Inspection Program will verify effectiveness of the Water Chemistry Control—Primary and 

Secondary Program.” 

The staff's evaluation of the Water Chemistry Control—Primary and Secondary Program is 

documented in SER Section 3.0.3.2.17. The program includes periodic monitoring and control 

of known detrimental contaminants such as chlorides, fluorides, dissolved oxygen, and sulfate 

concentrations below the levels known to result in loss of material or cracking. Water chemistry 

is in accordance with industry guidelines such as EPRI TR-102134, “Pressurized Water Reactor 

Secondary Water Chemistry Guidelines-Revision 5” for secondary water chemistry (Ref. 41). 

The staff's evaluation of the One-Time Inspection Program is documented in SER 

Section 3.0.3.1.9. The staff finds it acceptable to use the One-Time Inspection Program 

because the program uses nondestructive techniques that are capable of detecting loss of 

material and fouling such as visual, ultrasonic, and surface examinations of a representative 

sample of in-scope components to verify whether the Water Chemistry Control—Primary and 

Secondary Program has been effective at managing loss of material and fouling. The staff 

noted that the One-Time Inspection Program does not state that eddy current examinations will 

be conducted for heat exchanger tubing; however, SER Section 3.0.3.2.16 establishes that the 

applicant has an eddy current inspection program for heat exchangers that conducts visual 

inspections and eddy current exams. 

The applicant amended LRA Table 3.4.2-5-2-IP2 also by deleting (a) carbon steel piping and 

thermowells exposed internally to treated water and (b) stainless steel thermowells and tubing 

exposed internally to treated water greater than 140 °F with an aging effect of cracking due to 

fatigue. The applicant stated that cracking due to fatigue is not an applicable AERM for these 

specific components in the condensate system because “water temperatures are not expected 

to reach levels where fatigue is a concern.” During a teleconference call on July 30, 2014, 

Entergy stated that its determination that cracking due to fatigue is not an aging effect of 

concern is supported by information in Appendix H to EPRI Report No. 1010639, “Non-Class 1 

Mechanical Implementation Guideline and Mechanical Tools, Revision 4.” Appendix H to EPRI 

Report 1010639 suggests that systems or portions of systems with operating temperatures 

below 220 °F for carbon steel or 270 °F for austenitic stainless steel may generally be excluded 

from fatigue concerns because the fluid temperature would not be expected to vary by more 

than 150 °F for carbon steel or 200 °F for stainless steel (Ref. 42). 

The staff reviewed the criteria for performing cyclical loading analyses in the 1955 Edition of 

American Standards Association (ASA) B31.1, “American Standard Code for Pressure Piping” 

(Ref. 43), which is the code of record for IP2 non-Class 1 secondary piping systems, in order to 

determine whether the subject components could be susceptible to cracking due to fatigue. The 

staff noted that for Westinghouse-designed PWRs, the normal operating temperatures for 

secondary-side coolant in the condensate system could range from room temperature when the 

system is in the cold condition to a conservative maximum temperature of 200 °F for 

condensate system operations in a hot condition. The staff also noted that the expansion stress 

methodology of ASA B31.1 Section 622 demonstrates that with a temperature range less than 

200 °F, it is reasonable to assume that these components would not be subject to thermal 

fatigue. Therefore, the staff finds that the deletion of these AMR items from LRA 

Table 3.4.2-5-2-IP2 is acceptable because the operating temperature range for the condensate 

system is not sufficiently large enough to initiate fatigue-induced cracking of piping, piping 

components, and piping elements in the system. 
Aging Management Review Results 

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LRA Table 3.4.2-5-4-IP2 City Water System 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-4-IP2 by noting 

that the stainless steel piping exposed to outdoor air should have cited generic note G. The 

stainless steel piping exposed to outdoor air is being managed for loss of material by the 

External Surfaces Monitoring Program. The staff’s evaluation of this material, environment, 

aging effect, and program combination is documented in SER Section 3.4A.2.3.5. 

LRA Table 3.4.2-5-5-IP2 Wash Water System 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-5-1P2 by adding 

fiberglass piping which is exposed to outdoor air (external) and raw water (internal) and will be 

managed for change in material properties by the External Surfaces Monitoring and Periodic 

Surveillance and Preventive Maintenance Programs respectively. The AMR items cite generic 

note F. The staff noted that the applicant revised the “Parameters Monitored and Inspected 

Methods for Specific Aging Effects and Mechanisms” table in LRA Section B.1.29 to state that 

changes in material properties for fiberglass include cracking, blistering, and change in color, 

and that a visual inspection (VT-3 or equivalent) will be used to detect the aging effect.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that fiberglass has excellent resistance 

to water as evidenced by its common use for boat hulls. The staff noted that based on a review 

of Fibres, Plastics, and Rubbers: A Handbook of Common Polymers, by W.J. Roff (Ref. 44) and 

Plastic Piping Institute TR-9/2002, “Recommended Design Factors and Design Coefficients for 

Thermoplastic Pressure Pipe” (Ref. 45), fiberglass-reinforced piping and piping components, in 

the absence of specific environmental stressors such as high radiation or ozone concentrations, 

will not exhibit aging effects. However, the ultraviolet light in sunlight can result in changes in 

material properties. These changes in material properties will manifest themselves as cracking, 

blistering, and changes in color. 

The staff’s evaluation of the applicant’s External Surfaces Monitoring and Periodic Surveillance 

and Preventive Maintenance Programs is documented in SER (2009) Sections 3.0.3.2.5 

and 3.0.3.3.7 respectively. The staff finds the applicant’s proposal to manage aging using the 

External Surfaces Monitoring and Periodic Surveillance and Preventive Maintenance Programs 

acceptable because the External Surfaces Monitoring Program uses periodic visual inspections 

which are capable of detecting cracking, blistering, and change in color and the Periodic 

Surveillance and Preventive Maintenance Program uses periodic visual inspections of a 

representative sample of the internals of piping exposed to raw water which are capable of 

detecting cracking, blistering, and change in color. 

LRA Table 3.4.2-5-7-IP2 Instrument Air System 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-7-IP2 to add 

plastic heat exchanger tube sheets exposed to treated water (internal) and condensation 

(external). The applicant stated that there is no aging effect and no AMP is needed. The AMR 

items cite generic note F. 

The staff reviewed the associated items in the LRA and could not confirm that no credible aging 

effects are applicable for this component, material and environment combination. Regulatory 

Issue Summary (RIS) 2012-02, dated January 24, 2012, “Insights into Recent License Renewal 
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Application Consistency with the Generic Aging Lessons Learned Report,” provided guidance to 

the industry in regard to further information required in license renewal applications. In regard 

to plastic materials, the RIS recommends that when plastic is cited as a material, the applicant 

should provide further information in a plant-specific note because the term “plastic” is not 

sufficient to evaluate potential aging effects. The RIS states, 

The plant-specific note should state the actual material type or grade 

(e.g., polyvinyl chloride (PVC), fiberglass-reinforced vinyl ester) and identify 

environmental considerations that are not obvious from the LRA, FSAR, or 

license renewal drawings, such as exposure to ultraviolet light, ozone, high 

temperatures, chemicals, or radiation. The staff requires this information 

because susceptibility to aging varies widely with the specific material type and 

environment. 

By letter dated June 12, 2013, the staff issued RAI 3.4A.2.3.5-1 requesting that the applicant 

provide the specific type of plastic material used for the various components listed in LRA 

Table 3.4.2-5-7-IP2 and state any applicable aging effects for their given environment, including 

potential radiation effects. In its response dated July 24, 2013, the applicant stated that the 

plastic heat exchanger tube sheets used in the instrument air compressor after-coolers are 

made of Micarta (a phenolic resin laminate) and are exposed to an air temperature less than 

200 °F and treated water from 70 to 110 °F. The applicant also stated that the plastic tube 

sheets are not exposed to ultraviolet light, ozone, high temperatures, aggressive chemicals, or 

radiation. The applicant further stated that it will manage for change in material properties by 

inspecting both sides of the tube sheets for cracking, blistering, and change in color once every 

5 years using the Periodic Surveillance and Preventative Maintenance Program. The applicant 

stated that there has been no plant-specific operating experience involving degradation of these 

tube sheets. The applicant revised LRA Table 3.4.2-5-7-IP2, LRA Section A.2.1.28, and LRA 

Section B.1.29, “Periodic Surveillance and Preventive Maintenance Program,” accordingly. 

The staff noted that the Plastics Engineering Handbook of the Society of the Plastic 

Industry, Inc. (Ref. 46), states that phenolic materials are generally suitable for use at 

temperatures up to 300 °F. The staff also noted that the applicant’s temperatures are well 

below 300 °F. In addition, the trade journal American Machinist stated in a 1913 issue (Ref. 47) 

that: (a) Micarta is not brittle and will not warp, expand, or shrink with age or exposure to 

weather; (b) it is insoluble in all ordinary solvents and is impervious to moisture; and (c) it is 

unaffected by heat until a temperature sufficient to cause carbonization is reached. The staff 

further noted that aging effects such as cracking would be readily apparent to the applicant 

because either instrument air would enter the cooling system or cooling water would enter the 

instrument air supply. The staff finds the applicant’s use of the Periodic Surveillance and 

Preventive Maintenance Program acceptable because: (a) industry generic information provides 

a reasonable basis that the material is not susceptible to aggressive aging in the plant-specific 

environment; (b) plant-specific operating experience has demonstrated that the tube sheets 

haven’t degraded significantly enough to result in leakage; and (c) the visual inspections 

conducted every 5 years are capable of detecting cracking, blistering, and change in color. 

The staff finds the applicant’s response to RAI 3.4A.2.3.5-1 acceptable because the applicant 

will conduct periodic visual inspections of both sides of the tube sheet every 5 years, which will 

be capable of detecting cracking, blistering, and changes in color. Additionally, based on 

plant-specific operating experience, this combination of material and environment has not 

demonstrated any degradation. The staff’s concern described in RAI 3.4A.2.3.5-1 is resolved. 
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By letter dated July 15, 2013, the applicant amended LRA Table 3.4.2-5-7-IP2 by adding 

copper-alloy piping which is exposed to soil (external) and will be managed for loss of material 

by the Buried Piping and Tanks Inspection Program. The AMR item cites generic note G. 

The staff reviewed the associated item in the LRA and considered whether the aging effect 

proposed by the applicant constitutes all of the credible aging effects for this component, 

material, and environment description. Based on its review of GALL Report item AP-174, which 

states that loss of material due to pitting and crevice corrosion is the only applicable aging 

effect, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination. 

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection Program is 

documented in SER Section 3.0.3.1.2. The staff finds the applicant’s proposal to manage aging 

using the Buried Piping and Tanks Inspection Program acceptable because the piping is coated, 

which mitigates the potential for exposure to the soil environment, and the visual inspections 

conducted by the Buried Piping and Tanks Inspection Program are capable of detecting 

damage to the pipe’s coating and loss of material. 

On the basis of its review, the staff concludes (for this item in LRA Table 3.4.2-5-7-IP2) that the 

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

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

LRA Table 3.4.2-5-10-IP2 Lube Oil System 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-10-IP2 by 

correcting the environment for the titanium heat exchanger tubes exposed to raw water and lube 

oil. The AMR items cite generic note F. This amendment corrected the environment by noting 

that the external surfaces of the tubes are exposed to lube oil in lieu of raw water and the 

internal surfaces are exposed to raw water in lieu of lube oil. Additionally, by letter dated 

July 15, 2013, the applicant amended these line items by adding plant-specific note 405, which 

states that, “[t]he One-Time Inspection Program will verify effectiveness of the Oil Analysis 

Program.” The staff’s evaluation of this material, environment, aging effect, and program 

combination is documented in SER Section 3.4A.2.3.5, LRA Table 3.4.2-5-10-IP2, “Lube Oil 

System.” The staff finds that, with the exception of the following discussion on eddy current 

testing of heat exchanger tubes, changing the external and internal environment of the tubes 

does not impact the staff’s evaluation and conclusion in the cited SER Section. The staff noted 

that the One-Time Inspection Program does not state that eddy current examinations will be 

conducted for heat exchanger tubing; however, SER Section 3.0.3.2.16 establishes that the 

applicant has an eddy current inspection program for heat exchangers that conducts visual 

inspections and eddy current exams. 

LRA Table 3.4.2-5-13-IP2 Station Air System 

By letter dated September 26, 2012, the applicant amended LRA Table 3.4.2-5-13-IP2 by 

adding copper alloy with greater than 15 percent zinc heat exchanger tubes which are exposed 

to condensation (internal) and will be managed for fouling by the Periodic Surveillance and 

Preventative Maintenance Program. The AMR item cites generic note G. 

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 
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material, and environment description. Copper-zinc alloys with greater than 15 percent zinc are 

susceptible to selective leaching and SCC as stated in GALL Report, Table IX.C, “Selected 

Definitions & Use of Terms for Describing and Standardizing.” This occurs when the 

components are exposed to ammonia or amines, provided that sufficient tensile stresses are 

present. The staff noted that it is not common for selective leaching to occur on heat exchanger 

tubes because fluid velocities within the heat exchanger tubing are typically high enough to 

preclude any significant accumulation of condensation. The staff also noted that LRA 3.6.2.2.2 

states, “IPEC is not located near the seacoast where salt spray is considered, nor is IPEC 

located near a facility that discharges heavy pollutants.” The staff verified, using overhead 

imagery, that the Indian Point Energy Center is not located near any source of ammonia 

(e.g., factories or large agricultural sites that could use significant quantities of fertilizer) that 

could cause SCC in the heat exchanger tubes. Given that selective leaching and SCC are not 

applicable, the applicant has identified the applicable aging effects for this material and 

environment. 

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.3.7. The staff noted that the applicant proposes 

to use the Periodic Surveillance and Preventive Maintenance Program to manage the aging of 

copper alloy with greater than 15 percent zinc heat exchanger tubes through the use of periodic 

visual inspections, which are conducted at least once every 5 years. The staff noted that the 

program permits increasing the inspection’s sample size if aging effects are detected. The staff 

also noted that unacceptable inspection findings are evaluated in accordance with the corrective 

action process to determine the need for accelerated inspection frequency and for monitoring 

and trending the results. Based on its review of this component, the staff finds the applicant’s 

proposal to manage aging using the Periodic Surveillance and Preventive Maintenance 

Program acceptable because (a) periodic visual inspections are performed which are capable of 

detecting fouling; (b) the inspection sample size is increased if aging effects are detected, 

providing reasonable assurance that aging effects can be detected if they are occurring in other 

components; and (c) inspection findings are evaluated by the corrective action process, 

assuring that the intended functions of these components will be maintained consistent with the 

CLB for the period of extended operation. 

3.5 Aging Management of Containments, Structures, and Component Supports 

There are no changes or updates to this section of the safety evaluation report. 

3.6 Aging Management of Electrical and Instrumentation and Control Systems 

There are no changes or updates to this section of the safety evaluation report. 
4-1 

SECTION 4 

TIME-LIMITED AGING ANALYSES 

4.1 Identification of Time-Limited Aging Analyses 

There are no changes or updates to this section of the 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 Entergy Nuclear 

Operations, Inc., does not alter the conclusions stated in the SER and that the requirements of 

10 CFR 54.29(a) have been met. 
 
A-1

COMMITMENTS FOR LICENSE RENEWAL OF INDIAN POINT NUCLEAR GENERATING 

UNIT NOS. 2 AND 3 

During the review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) license renewal application (LRA) by the 

staff of the U.S. Nuclear Regulatory Commission (NRC) (“the staff”), Entergy Nuclear Operations, Inc. (“Entergy” or “the applicant”) made commitments related to aging management programs (AMPs) to manage the aging effects for certain structures and components during the period of extended operation (PEO). The following table lists these commitments along with the applicant’s stated implementation schedules and sources for each commitment. This list supersedes the list published in Appendix A of NUREG-1930, Supplement 1. 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

1 Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to perform thickness 

measurements of the bottom surfaces of the condensate storage tanks, city water tank, and fire water tanks once during the first ten years of the period of extended operation. Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to require trending of thickness measurements when material loss is detected. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 

2 Enhance the Bolting Integrity Program for IP2 and IP3 to clarify that actual yield strength is 

used in selecting materials for low susceptibility to SCC and clarify the prohibition on use of lubricants containing [molybdenum disulfide] MoS2 for bolting. 

The Bolting Integrity Program manages loss of preload and loss of material for all external bolting. 

IP2: Completed IP3: Completed 

NL-07-039 NL-07-153 NL-13-122 
A-2

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

3 Implement the Buried Piping and Tanks Inspection Program for IP2 and IP3 as described in 

LRA Section B.1.6. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection. Include in the Buried Piping and Tanks Inspection Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Establish 

inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using inspection techniques with demonstrated effectiveness. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 NL-09-106 NL-09-111 NL-11-101 

4 Enhance the Diesel Fuel Monitoring Program to include cleaning and inspection of the 

IP2 GT-1 gas turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil day tanks, IP2 SBO/Appendix R diesel generator fuel oil day tank, and IP3 Appendix R fuel oil storage 

tank and day tank once every ten years. Enhance the Diesel Fuel Monitoring Program to include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10 mg/l. Water and sediment acceptance criterion will be less than or equal to 0.05%. Enhance the Diesel Fuel Monitoring Program to include thickness measurement of the bottom of the following tanks once every ten years. IP2: EDG fuel oil storage tanks, EDG fuel oil day tanks, SBO/Appendix R diesel generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 NL-08-057 
Appendix

A

A-3 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; IP3: Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank. Enhance the Diesel Fuel Monitoring Program to specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program. Enhance the Diesel Fuel Monitoring Program to direct samples be taken and include direction to remove water when detected. Revise applicable procedures to direct sampling of the onsite portable fuel oil contents prior to transferring the contents to the storage tanks. Enhance the Diesel Fuel Monitoring Program to direct the addition of chemicals including biocide when the presence of biological activity is confirmed. 

5 Enhance the External Surfaces Monitoring Program for IP2 and IP3 to include periodic 

inspections of systems in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2). 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 

6 Enhance the Fatigue Monitoring Program for IP2 to monitor steady state cycles and feedwater 

cycles or perform an evaluation to determine monitoring is not required. Review the number of allowed events and resolve discrepancies between reference documents and monitoring procedures. Enhance the Fatigue Monitoring Program for IP3 to include all the transients identified. Assure all fatigue analysis transients are included with the lowest limiting numbers. Update the number of design transients accumulated to date. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 
A-4

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

7 Enhance the Fire Protection Program to inspect external surfaces of the IP3 RCP oil collection 

systems for loss of material each refueling cycle. Enhance the Fire Protection Program to explicitly state that the IP2 and IP3 diesel fire pump engine sub-systems (including the fuel supply line) shall be observed while the pump is running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation while running; such as fuel oil, lube oil, coolant, or exhaust gas leakage. Enhance the Fire Protection Program to specify that the IP2 and IP3 diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating cycle. Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480 V switchgear room, and [emergency diesel generator] EDG room [carbon dioxide] CO2 fire 

suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 
Appendix

A

A-5 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

8 Enhance the Fire Water Program to include inspection of IP2 and IP3 hose reels for evidence 

of corrosion. Acceptance criteria will be revised to verify no unacceptable signs of degradation. Enhance the Fire Water Program to replace all or test a sample of IP2 and IP3 sprinkler heads required for 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner. Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP3 fire protection piping on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the 

appropriate inspection interval to ensure aging effects are identified prior to loss of intended function. Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks. Acceptance criteria will be enhanced to verify no significant corrosion. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 NL-08-014 

9 Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to implement comparisons 

to wear rates identified in WCAP-12866. Include provisions to compare data to the previous performances and perform evaluations regarding change to test frequency and scope. Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific values based on evaluation of previous test results. Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance criteria. Also stipulate that flux thimble tubes that cannot be inspected over the tube length and cannot be shown by analysis to be satisfactory for continued service must be removed from service to ensure the integrity of the reactor coolant system pressure boundary. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 
A

-6

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

10 Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include the following heat 

exchangers in the scope of the program. 

 Safety injection pump lube oil heat exchangers  RHR heat exchangers  RHR pump seal coolers  Non-regenerative heat exchangers  Charging pump seal water heat exchangers  Charging pump fluid drive coolers  Charging pump crankcase oil coolers  Spent fuel pit heat exchangers  Secondary system steam generator sample coolers  Waste gas compressor heat exchangers  SBO/Appendix R diesel jacket water heat exchanger (IP2 only) 

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to perform visual inspection on heat exchangers where non-destructive examination, such as eddy current inspection, is not possible due to heat exchanger design limitations. Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment combinations when determining sample population of heat exchangers. Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to establish minimum tube wall thickness for the new heat exchangers identified in the scope of the program. Establish acceptance criteria for heat exchangers visually inspected to include no indication of tube erosion, vibration wear, corrosion, pitting, fouling, or scaling. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 NL-09-018 

11 Deleted N/A NL-09-056 

NL-11-101 

12 Enhance the Masonry Wall Program for IP2 and IP3 to specify that the IP1 intake structure is 

included in the program. 

IP2: Completed IP3: Completed 

NL-07-039 NL-13-122 
Appendix

A

A-7 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

13 Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to visually inspect the 

external surface of MEB enclosure assemblies for loss of material at least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will be no significant loss of material. Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct. Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative measurements such as thermography or contact resistance measurements. The first inspection will occur prior to the period of extended operation. The plant will process a change to applicable site procedure to remove the reference to “re-torquing” connections for phase bus maintenance and bolted connection maintenance. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 NL-08-057 NL-13-077 

14 Implement the Non-EQ Bolted Cable Connections Program for IP2 and IP3 as described in 

LRA Section B.1.22. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 

15 Implement the Non-EQ Inaccessible Medium-Voltage Cable Program for IP2 and IP3 as 

described in LRA Section B.1.23. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.E3, Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 NL-11-032 NL-11-096 NL-11-101 

16 Implement the Non-EQ Instrumentation Circuits Test Review Program for IP2 and IP3 as 

described in LRA Section B.1.24. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 
A

-8

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

17 Implement the Non-EQ Insulated Cables and Connections Program for IP2 and IP3 as 

described in LRA Section B.1.25. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 

18 Enhance the Oil Analysis Program for IP2 to sample and analyze lubricating oil used in the 

SBO/Appendix R diesel generator consistent with the oil analysis for other site diesel generators. Enhance the Oil Analysis Program for IP2 and IP3 to sample and analyze generator seal oil and turbine hydraulic control oil. Enhance the Oil Analysis Program for IP2 and IP3 to formalize preliminary oil screening for water and particulates and laboratory analyses including defined acceptance criteria for all components included in the scope of this program. The program will specify corrective actions in the event acceptance criteria are not met. Enhance the Oil Analysis Program for IP2 and IP3 to formalize trending of preliminary oil screening results as well as data provided from independent laboratories. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-11-101 

19 Implement the One-Time Inspection Program for IP2 and IP3 as described in LRA 

Section B.1.27. This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.M32, One-Time Inspection. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 

20 Implement the One-Time Inspection – Small Bore Piping Program for IP2 and IP3 as described 

in LRA Section B.1.28. This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 

21 Enhance the Periodic Surveillance and Preventive Maintenance Program for IP2 and IP3 as 

necessary to assure that the effects of aging will be managed such that applicable components 

IP2: Completed NL-07-039 

NL-13-122 
Appendix

A

A-9 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation. 

IP3: December 12, 2015 

22 Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 revising the specimen 

capsule withdrawal schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected through the end of the period of extended operation. 

Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 

23 Implement the Selective Leaching Program for IP2 and IP3 as described in LRA 

Section B.1.33. This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.M33, Selective Leaching of Materials. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 

24 Enhance the Steam Generator Integrity Program for IP2 and IP3 to require that the results of 

the condition monitoring assessment are compared to the operational assessment performed 

for the prior operating cycle with differences evaluated. 

IP2: Completed IP3: Completed 

NL-07-039 NL-13-122 

25 Enhance the Structures Monitoring Program to explicitly specify that the following structures 

are included in the program. 

 Appendix R diesel generator foundation (IP3)  Appendix R diesel generator fuel oil tank vault (IP3)  Appendix R diesel generator switchgear and enclosure (IP3)  city water storage tank foundation  condensate storage tanks foundation (IP3) 

 containment access facility and annex (IP3)  discharge canal (IP2/3)  emergency lighting poles and foundations (IP2/3)  fire pumphouse (IP2)  fire protection pumphouse (IP3)  fire water storage tank foundations (IP2/3)  gas turbine 1 fuel storage tank foundation 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 NL-08-057 NL-13-077 NL-08-127 NL-11-032 NL-11-101 
A-1

0

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

 maintenance and outage building—elevated passageway (IP2)  new station security building (IP2) nuclear service building (IP1)  primary water storage tank foundation (IP3)  refueling water storage tank foundation (IP3)  security access and office building (IP3)  service water pipe chase (IP2/3)  service water valve pit (IP3)  superheater stack  transformer/switchyard support structures (IP2)  waste holdup tank pits (IP2/3) 

Enhance the Structures Monitoring Program for IP2 and IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspected for each structure as applicable. 

 cable trays and supports  concrete portion of reactor vessel supports  conduits and supports  cranes, rails and girders  equipment pads and foundations  fire proofing (pyrocrete)  HVAC duct supports  jib cranes  manholes and duct banks  manways, hatches and hatch covers  monorails  new fuel storage racks  sumps 

Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and IP3 will also inspect 
Appendix

A

A-11 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurring. Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, gaskets, seismic joint filler, and roof elastomers) to identify cracking and change in material properties and for inspection of aluminum vents and louvers to identify loss of material. Enhance the Structures Monitoring Program for IP2 and IP3 to perform an engineering evaluation of groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least once every five years). IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides. Additionally, to assess potential indications of spent fuel pool leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months. Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the IP3 intake structure at least once every 5 years. Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of the degraded areas of the water control structure once per 3 years rather than the normal frequency of once per 5 years during the PEO. Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria for inspections of concrete structures in accordance with [American Concrete Institute] ACI 349.3R, “Evaluation of Existing Nuclear Safety-Related Concrete Structures” prior to the period of extended operation. 

26 Implement the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) 

Program for IP2 and IP3 as described in LRA Section B.1.37. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 NL-07-153 
A-12

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program. 

27 Implement the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic 

Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section B.1.38. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program. 

IP2: Completed IP3: Completed 

NL-07-039 NL-13-122 NL-07-153 

28 Enhance the Water Chemistry Control—Closed Cooling Water Program to maintain water 

chemistry of the IP2 SBO/Appendix R diesel generator cooling system per [Electric Power Research Institute] EPRI guidelines. Enhance the Water Chemistry Control—Closed Cooling Water Program to maintain the IP2 and IP3 security-generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines. 

IP2: Completed IP3: Completed 

NL-07-039 NL-13-122 NL-08-057 

29 Enhance the Water Chemistry Control—Primary and Secondary Program for IP2 to test 

sulfates monthly in the [refueling water storage tank] RWST with a limit of < 150 ppb. 

IP2: Completed NL-07-039 

NL-13-122 

30 For aging management of the reactor vessel internals, IPEC will (1) participate in the industry 

programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. 

IP2: Completed IP3: Completed 

NL-07-039 NL-13-122 NL-11-107 

31 Additional [pressure/temperature] P-T curves will be submitted as required per 10 CFR 50, 

Appendix G prior to the period of extended operation as part of the Reactor Vessel Surveillance Program. 

IP2: Completed IP3: December 12, 2015 

NL-07-039 NL-13-122 

32 As required by 10 CFR 50.61(b)(4), IP3 will submit a plant-specific safety analysis for 

plate B2803-3 to the NRC three years prior to reaching the [reference temperature for pressurized thermal shock] RTPTS screening criterion. Alternatively, the site may choose to implement the revised [pressurized thermal shock] PTS rule when approved. 

IP3: December 12, 2015 NL-07-039 

NL-08-127 
Appendix

A

A-13 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

33 At least 2 years prior to entering the period of extended operation, for the locations identified in 

LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring Program, IP2 and IP3 will implement one or more of the following: (1) Consistent with the Fatigue Monitoring Program, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid [cumulative usage factors] CUFs less than 1.0 when accounting for the effects of reactor water environment. This includes applying the appropriate [environmental fatigue correction factor] Fen factors to valid 

CUFs determined in accordance with one of the following: 

1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of extended operation, use the existing CUF. 2. Additional plant-specific locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component. 3. Representative CUF values from other plants, adjusted to or enveloping the IPEC plant-specific external loads may be used if demonstrated applicable to IPEC. 4. An analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case) may be performed to determine a valid CUF. 

(2) Consistent with the Fatigue Monitoring Program, Corrective Actions, repair or replace the affected locations before exceeding a CUF of 1.0. 

IP2: Completed IP3: Completed 

NL-07-039 NL-13-122 NL-07-153 NL-08-021 NL-10-082 

34 IP2 SBO / Appendix R diesel generator will be installed and operational by April 30, 2008. This 

committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) and, therefore, 

a license amendment pursuant to 10 CFR 50.90 is not required. 

IP2: Completed NL-13-122 

NL-07-078 NL-08-074 NL-11-101 
A-14

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

35 Perform a one-time inspection of representative sample area of IP2 containment liner affected 

by the 1973 event behind the insulation, prior to entering the period of extended operation, to 

assure liner degradation is not occurring in this area. Perform a one-time inspection of representative sample area of the IP3 containment steel liner at the juncture with the concrete floor slab, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area. Any degradation will be evaluated for updating of the containment liner analyses as needed. 

IP2: Completed IP3: December 12, 2015 

NL-08-127 NL-13-122 NL-11-101 NL-09-018 

36 Perform a one-time inspection and evaluation of a sample of potentially affected IP2 refueling 

cavity concrete prior to the period of extended operation. The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel. Additional core bore samples will be taken, if the leakage is not stopped, prior to the end of the 

first ten years of the period of extended operation. A sample of leakage fluid will be analyzed to determine the composition of the fluid. If 

additional core samples are taken prior to the end of the first ten years of the period of 

extended operation, a sample of leakage fluid will be analyzed. 

IP2: Completed NL-08-127 

NL-11-101 NL-13-122 NL-09-056 NL-09-079 

37 Enhance the Containment Inservice Inspection (CII-IWL) Program to include inspections of the 

containment using enhanced characterization of degradation (i.e., quantifying the dimensions of noted indications through the use of optical aids) during the period of extended operation. The enhancement includes obtaining critical dimensional data of degradation where possible through direct measurement or the use of scaling technologies for photographs, and the use of 

consistent vantage points for visual inspections. 

IP2: Completed IP3: Completed 

NL-08-127 NL-13-122 

38 For Reactor Vessel Fluence, should future core loading patterns invalidate the basis for the 

projected values of RTPTS or CVUSE [Charpy V-notch upper-shelf energy], updated calculations 

will be provided to the NRC. 

IP2: Completed IP3: December 12, 2015 

NL-08-143 NL-13-122 

39 Deleted N/A NL-09-079 40 Evaluate plant-specific and appropriate industry operating experience and incorporate lessons 

learned in establishing appropriate monitoring and inspection frequencies to assess aging 

IP2: Completed NL-09-106 

NL-13-122 
Appendix

A

A-15 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

effects for the new aging management programs. Documentation of the operating experience 

evaluated for each new program will be available on site for NRC review prior to the period of extended operation. 

IP3: December 12, 2015 

41 IPEC will inspect steam generators for both units to assess the condition of the divider plate 

assembly. The examination technique used will be capable of detecting PWSCC in the steam generator divider plate assembly. The IP2 steam generator divider plate inspections will be completed within the first ten years of the period of extended operation (PEO). The IP3 steam generator divider plate inspections will be completed within the first refueling outage following the beginning of the PEO. 

IP2: After the beginning of the PEO and prior to September 28, 2023 IP3: Prior to the end of the first refueling outage following the beginning of the PEO. 

NL-11-032 NL-11-074 NL-11-090 NL-11-101 

42 IPEC will develop a plan for each unit to address the potential for cracking of the primary to 

secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options. Option 1 (Analysis) IPEC will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible to PWSCC, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary must be approved by the NRC as a license amendment request. Option 2 (Inspection) IPEC will perform a one-time inspection of a representative number of tube-to-tubesheet welds in each steam generator to determine if PWSCC cracking is present. If weld cracking is identified: 

a. The condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and 

IP2: Prior to March 2024 IP3: Prior to the end of the first refueling outage following the beginning of the PEO. IP2: Between March 2020 and March 2024 IP3: Prior to the end of the first refueling outage following the beginning of the PEO. 

NL-11-032 NL-11-074 NL-11-090 NL-11-096 
A-1

6

Appendix A

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

b. An ongoing monitoring program will be established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators. 

43 IPEC will review design basis ASME Code Class 1 fatigue evaluations to determine whether 

the NUREG/CR-6260 locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations for the IP2 and IP3 configurations. If more limiting locations are identified, the most limiting location will be evaluated for the effects of the reactor coolant environment on fatigue usage. IPEC will use the NUREG/CR-6909 methodology in the evaluation of the limiting locations consisting of nickel alloy, if any. 

IP2: Completed IP3: December 12, 2015 

NL-11-032 NL-13-122 NL-11-101 

44 IPEC will include written explanation and justification of any user intervention in future 

evaluations using the WESTEMS “Design CUF” module. 

IP2: Completed IP3: December 12, 2015 

NL-11-032 NL-11-101 NL-13-122 

45 IPEC will not use the NB-3600 option of the WESTEMS program in future design calculations 

until the issues identified during the NRC review of the program have been resolved. 

IP2: Completed IP3: December 12, 2015 

NL-11-032 NL-11-101 NL-13-122 

46 Include in the IP2 [Inservice Inspection] ISI Program that IPEC will perform twenty-five 

volumetric weld metal inspections of socket welds during each 10-year ISI interval scheduled 

as specified by IWB-2412 of the ASME Section XI Code during the period of extended 

operation. In lieu of volumetric examinations, destructive examinations may be performed, where one destructive examination may be substituted for two volumetric examinations. 

IP2: Completed NL-11-032 

NL-11-074 NL-13-122 

47 Deleted N/A NL-14-093 48 Entergy will visually inspect IPEC underground piping within the scope of license renewal and 

subject to aging management review prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by [License Renewal Interim Staff Guidance] LR-ISG-2011-03. Visual inspections will be supplemented 

with surface or volumetric nondestructive testing if indications of significant loss of material are 

IP2: Completed IP3: Prior to December 12, 2015 

NL-12-174 NL-13-122 
Appendix

A

A-17 

APPENDIX A: INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL COMMITMENTS 

No. Commitment Implementation 

Schedule 

Source 

observed. Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement). 

49 Recalculate each of the limiting CUFs provided in Section 4.3 of the LRA for the reactor vessel 

internals to include the reactor coolant environment effects (Fen) as provided in the IPEC 

Fatigue Monitoring Program using NUREG/CR-5704 or NUREG/CR-6909. In accordance with the corrective actions specified in the Fatigue Monitoring Program, corrective actions include further CUF re-analysis, and/or repair or replacement of the affected components prior to the [cumulative usage factor considering environmental effects] CUFen reaching 1.0. 

IP2: Completed IP3: Prior to December 12, 2015 

NL-13-052 NL-13-122 

50 Replace the IP2 split pins during the 2016 refueling outage (2R22). IP2: Prior to completion 

of 2R22 IP3: N/A 

NL-13-122 NL-14-067 

B-1 

CHRONOLOGY 

This appendix contains a chronological listing of the routine correspondence between the staff 

of the U.S. Nuclear Regulatory Commission (“NRC” or “the staff”) and Entergy Nuclear 

Operations, Inc. (“Entergy” or “the applicant”), as well as other correspondence regarding the 

staff’s review of the license renewal application (LRA) for Indian Point Nuclear Generating Unit 

Nos. 2 and 3, Docket Numbers 50-247 and 50-286, issued since the publication of 

NUREG-1930, Supplement 1, in August 2011. 

Document Date Title 

04/23/2007 

Indian Point Nuclear Generating Units 2 and 3, License Renewal 

Application. (ADAMS Accession No. ML071210512) 

04/23/2007 

Indian Point Nuclear Generating Units 2 and 3, License Renewal 

Application, Cover. (ADAMS Accession No. ML071210516) 

04/23/2007 

Indian Point Nuclear Generating Units 2 and 3, License Renewal 

Application, Page i, Preface, through Chapter 4.0, Page 4.7-4. (ADAMS 

Accession No. ML071210517) 

04/23/2007 

Indian Point Nuclear Generating Units 2 and 3, License Renewal 

Application, Appendix A, “Updated Final Safety Analysis Report 

Supplement.” (ADAMS Accession No. ML071210520) 

04/23/2007 

Indian Point Nuclear Generating Units 2 and 3, License Renewal 

Application. Appendix B, “Aging Management Programs and Activities.” 

(ADAMS Accession No. ML071210523) 

04/23/2007 

Indian Point Nuclear Generating Units 2 and 3, License Renewal 

Application, Appendix C [not used in this application]. (ADAMS Accession 

No. ML071210524) 

04/23/2007 

Indian Point Nuclear Generating Units 2 and 3, License Renewal 

Application. Appendix D, “Technical Specification Changes.” (ADAMS 

Accession No. ML071210527) 

05/03/2007 

Indian Point Nuclear Generating Units 2 and 3—Supplement to License 

Renewal Application. (ADAMS Accession No. ML071280700) 

06/21/2007 

Letter from Entergy Nuclear Operations, Inc., to NRC, Indian Point Nuclear 

Generating Unit 2, Station Blackout (SBO) / Appendix R Diesel Generator 

Commitment, Response to NRC Review Status of License Renewal 

Application. (ADAMS Accession No. ML071800318) 

08/11/2009 

Letter from Entergy to U.S. NRC Regarding Safety Evaluation Report 

Related to the License Renewal of Indian Point Nuclear Generating Unit 

Nos. 2 and 3. (ADAMS Accession No. ML092150012) 

08/11/2009 

Safety Evaluation Report Related to the License Renewal of Indian Point 

Nuclear Generating Unit Nos. 2 and 3, Docket Nos. 50-247 and 50-286. 

(ADAMS Accession No. ML092240268) 
Appendix B 

B-2 

Document Date Title 

11/30/2009 

NUREG-1930, “Safety Evaluation Report Related to the License Renewal 

of Indian Point Nuclear Generating Unit Nos. 2 and 3, Docket Nos. 50-247 

and 50-286,” Volume 1. (ADAMS Accession No. ML093170451) 

11/30/2009 

NUREG-1930, “Safety Evaluation Report Related to the License Renewal 

of Indian Point Nuclear Generating Unit Nos. 2 and 3, Docket Nos. 50-247 

and 50-286,” Volume 2. (ADAMS Accession No. ML093170671) 

07/14/2010 

Letter from Entergy to U.S. NRC, “Amendment 9 to License Renewal 

Application (LRA) – Reactor Vessel Internals Program, Indian Point Nuclear 

Generating Unit Nos. 2 & 3.” (ADAMS Accession No. ML102010102) 

08/22/2011 

Letter from Entergy to U.S. NRC, “Clarification for Request for Additional 

Information (RAI) Aging Management Programs.” (ADAMS Accession 

No. ML11243A085) 

08/31/2011 

Letter from U.S. NRC to Entergy Regarding Supplement to Safety 

Evaluation Report Related to the License Renewal of Indian Point Nuclear 

Generating Unit Nos. 2 and 3. (ADAMS Accession No. ML11201A033) 

08/31/2011 

NUREG-1930, Supplement 1, “Safety Evaluation Report Related to the 

License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3, 

Docket Nos. 50-247 and 50-286.” (ADAMS Accession No. ML11242A215) 

09/28/2011 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - License Renewal Application - Completion of Commitment 30 

re Reactor Vessel Internals Inspection Plan. (ADAMS Accession 

No. ML11280A121) 

12/20/2011 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - Amendment 11 to License Renewal Application. (LRA). 

(ADAMS Accession No. ML11363A175) 

01/30/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating Unit Nos. 1, 2 & 3 - Correction to Previous Response 

Regarding Unit 1 Buried Piping. (ADAMS Accession No. ML12039A178) 

02/17/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point, Units 2 and 3, 

License Renewal Application - Revised Reactor Vessel Internals Program 

and Inspection Plan Compliant with MRP-227-A. (ADAMS Accession 

No. ML12060A312) 

04/19/2012 

Letter from U.S. NRC to Entergy Transmitting Inspection Report 

IR 05000247-12-008, on 03/05/2012 - 03/08/2012, Indian Point Nuclear 

Generating Unit 2, Review of License Renewal Activities. (ADAMS 

Accession No. ML12110A315) 

05/15/2012 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating Unit 

Nos. 2 and 3, License Renewal Application RAI Set 19 - RVIs 

MRP-227 05-2012. (ADAMS Accession No. ML12125A342) 

06/14/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 and 3 - Reply to Request for Additional Information Regarding the 

License Renewal Application. (ADAMS Accession No. ML12184A037) 

07/30/2012 

Letter from U.S. NRC to Entergy Regarding Project Manager Change for 

the License Renewal of Indian Point, Units 2 & 3 (TAC ME5407 

and MD5408). (ADAMS Accession No. ML12199A025) 
Appendix B 

B-3 

Document Date Title 

09/12/2012 

08/08/2012 Summary of Telephone Conference Call Held between 

U.S. NRC and Entergy Nuclear Operations, Inc., Concerning 

RAI Set 2012-02, Reactor Vessel Internals Program Pertaining to the 

Indian Point, Units 2 & 3, License Renewal Application. (ADAMS Accession 

No. ML12223A367) 

09/26/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating Units 1, 2 & 3 - Correction to Previous Responses Regarding 

Unit 1 Buried Piping and Unit 2 Auxiliary Feedwater Pump Room Fire 

Event. (ADAMS Accession No. ML12285A084) 

09/28/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating Units 2 & 3 - Reply to Request for Additional Information 

Regarding the License Renewal Application. (ADAMS Accession 

No. ML12285A232) 

10/16/2012 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating 

Units 2 and 3, License Renewal Application, Set 2012-03 (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML12278A077) 

10/17/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - Reply to Request for Additional Information Regarding the 

License Renewal Application. (ADAMS Accession No. ML12300A391) 

10/18/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point, Units 2 & 3, 

Clarification of Underground Piping Information Provided in 

Letter NL-11-032 Regarding the License Renewal Application. (ADAMS 

Accession No. ML12310A061) 

10/31/2012 

10/11/2012 Summary of Telephone Conference Call Held Between the 

U.S. NRC and Entergy Nuclear Operations, Inc., Concerning the Indian 

Point Nuclear Generating Unit Nos. 2 and 3 License Renewal Application. 

(ADAMS Accession No. ML12289A880) 

11/20/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 and 3 - Reply to Request for Additional Information Regarding the 

License Renewal Application. (ADAMS Accession No. ML12340A154) 

11/29/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating Unit Nos. 2 & 3 - Additional Clarification of Underground Piping 

Information Provided in Letter NL-12-149 Regarding the License Renewal 

Application. (ADAMS Accession No. ML12354A314) 

12/27/2012 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating, Units 2 and 3 - Amendment 12 to License Renewal 

Application. (ADAMS Accession No. ML13003A178) 

03/05/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - Revision to the Response to Request for Additional 

Information (RAI) about Aging Management Programs. (ADAMS Accession 

No. ML13074A020) 

03/18/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 and 3 - Amendment 13 to License Renewal Application Pertaining 

to One-Time Inspection and Selective Leaching Programs. (ADAMS 

Accession No. ML13094A369) 
Appendix B 

B-4 

Document Date Title 

05/01/2013 

Letter from Entergy to U.S. NRC Regarding Actions Required Before Entry 

into Period of Extended Operation Associated with License Renewal 

Application for Indian Point Energy Center Unit 2. (ADAMS Accession 

No. ML13142A203) 

05/06/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - License Renewal Application - Update to Electrical MEB and 

Structures Monitoring Program Scope, Aging Management Programs. 

(ADAMS Accession No. ML13142A013) 

05/07/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating, Units 2 & 3 - Reply to Request for Additional Information 

Regarding the License Renewal Application. (ADAMS Accession 

No. ML13142A202) 

05/14/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating, Unit 2, Update to Previous Plans Regarding Refueling Cavity 

Repairs. (ADAMS Accession No. ML13141A402) 

06/12/2013 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the review of the Indian Point Nuclear Generating Unit 

Nos. 2 and 3, License Renewal Application, Set 2013-02 (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML13162A606) 

07/02/2013 

Summary of Conference Call Held on June 4, 2013, Between the 

U.S. Nuclear Regulatory Commission and Entergy Nuclear 

Operations, Inc., Concerning Responses to RAIs Regarding the Reactor 

Vessel Internals Program at Indian Point Nuclear Generating Unit 

Nos. 2 and 3. (ADAMS Accession No. ML13171A368) 

07/05/2013 

Letter from U.S. NRC to Entergy Transmitting Inspection Report 

IR 05000247-13-009; 05/6/2013 to 05/23/2013; Indian Point Nuclear 

Generating Unit 2; License Renewal Team Inspection. (ADAMS Accession 

No. ML13186A179) 

07/15/2013 

Letter from Entergy to U.S. NRC Regarding Correction to a Previous 

Response Regarding the Unit 2 Auxiliary Feedwater Pump Room Fire 

Event. (ADAMS Accession No. ML13200A021) 

07/17/2013 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating Unit 

Nos. 2 and 3, License Renewal Application, Set 2013-03 (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML13186A169) 

07/19/2013 

Letter from U.S. NRC to Entergy Regarding Project Manager Change for 

the License Renewal of Indian Point, Units 2 and 3 (TAC Nos. MD5407 

and MD5408). (ADAMS Accession No. ML13134A367) 

07/24/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point, Units 2 and 3, 

Response to Request for Additional Information for the Review of the Indian 

Point Nuclear Generating Units 2 and 3, License Renewal Application. 

(ADAMS Accession No. ML13211A173) 

07/26/2013 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating Unit 

Nos. 2 and 3, License Renewal Application, Set 2013-04 (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML13204A199) 
Appendix B 

B-5 

Document Date Title 

08/15/2013 

07/19/2013 Summary of Conference Call Held between the U.S. NRC and 

Entergy Nuclear Operations, Inc., Concerning Draft Request for Additional 

Information Related to Amendment 9 to License Renewal Application. 

(ADAMS Accession No. ML13211A264) 

08/16/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - Letter In Reply to Request for Additional Information 

Regarding the License Renewal Application. (ADAMS Accession 

No. ML13247A171) 

08/19/2013 

Letter from U.S. NRC to Entergy Regarding Indian Point Nuclear 

Generating Unit No. 2 - Actions To Be Completed Before Entering the 

Period of Timely Renewal. (ADAMS Accession No. ML13197A034) 

08/28/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating Unit 2 Implementation of License Renewal Regulatory 

Commitments. (ADAMS Accession No. ML13247A175) 

08/29/2013 

08/13/2013 Summary of Conference Call Held on August 13, 2013, 

between the U.S. NRC and Entergy Nuclear Operations, Inc., Concerning 

Request for Additional Information Responses on Cathodic Protection – 

Indian Point Nuclear Generating Unit Nos. 2 and 3. (ADAMS Accession 

No. ML13231A040) 

09/03/2013 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating, 

Units 2 and 3, License Renewal Application, Set 2013-05 (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML13240A076) 

09/13/2013 

Indian Point Nuclear Generating Unit 2 - NRC License Renewal Team 

Inspection Report 05000247/2013010 (ADAMS Accession 

No. ML13263A020) 

09/19/2013 

Letter from U.S. NRC to Entergy Regarding Indian Point Nuclear 

Generating Unit 2 - NRC License Renewal Team Inspection 

Report 05000247/2013010. (ADAMS Accession No. ML13263A020) 

09/23/2013 

Summary of Conference Call Held on July 2, 2013, Between the U.S. NRC 

and Entergy Nuclear Operations, Inc., Concerning May 6, 2013 Letter 

Regarding Changes to Metal Enclosed Bus Inspection Program for Indian 

Point Nuclear Generating Unit Nos. 2 and 3. (ADAMS Accession 

No. ML13184A082) 

09/26/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating, Unit No. 2 - Amendment 14 to License Renewal Application. 

(ADAMS Accession No. ML13274A238) 

09/27/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating Unit Nos. 2 & 3 - Reply to Request for Additional Information 

Regarding the License Renewal Application. (ADAMS Accession 

No. ML13277A007) 

10/03/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating, Units 2 & 3 - Reply to Request for Additional Information 

Regarding the License Renewal Application. (ADAMS Accession 

No. ML13282A140) 
Appendix B 

B-6 

Document Date Title 

11/19/2013 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating, 

Units 2 and 3, License Renewal Application, Set 2013-06 (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML13318A450) 

12/12/2013 

Letter from Entergy to U.S. NRC Regarding Indian Point, Unit 2 and 3, 

Amendment 15 to License Renewal Application. (ADAMS Accession 

No. ML13354B873) 

01/02/2014 

Letter from Entergy to U.S. NRC Regarding Indian Point Nuclear 

Generating, Units 2 and 3, Reply to Request for Additional Information 

Regarding the License Renewal Application. (ADAMS Accession 

No. ML14014A276) 

01/09/2014 

Summary of Conference Call Held on December 18, 2013, Between the 

U.S. NRC and Entergy Nuclear Operations, Inc., Concerning Applicant or 

Licensee Action Item 7 from MRP-227-A. (ADAMS Accession 

No. ML13354C017) 

01/16/2014 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - Reply to Request for Additional Information Regarding the 

License Renewal Application. (ADAMS Accession No. ML14027A413) 

01/16/2014 

Letter from Entergy to U.S. NRC Regarding Indian Point, Units 1 and 2, 

Enclosure 2 to NL-14-010, Attachment 2, Final Response to U.S. NRC 

RAI 6-A Items 1 and 2 on the RVI Program and RVI Inspection Plan. 

(ADAMS Accession No. ML14027A415) [Note: this letter is replaced by the 

September 8, 2014 letter] 

01/28/2014 

Letter from Entergy to U.S. NRC Regarding Indian Point, 

Units 2 & 3 - Additional Information Regarding the License Renewal 

Application - Action Item 7 from MRP-227-A. (ADAMS Accession 

No. ML14038A150) 

03/21/2014 

02/20/2014 Summary of Conference Call Held on February 20, 2014, 

Between the U.S. NRC and Entergy Nuclear Operations, Inc., Concerning a 

Draft Request for Additional Information on LR-ISG-2012-02 and Draft 

LR-ISG-2013-01. (ADAMS Accession No. ML14078A399) 

04/01/2014 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating Unit 

Nos. 2 and 3, License Renewal Application, Set 2014-01 (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML14084A387) 

04/09/2014 

Letter from U.S. NRC to Entergy Regarding Request for Additional 

Information for the Review of the Indian Point Nuclear Generating Unit 

Nos. 2 and 3, License Renewal Application, Set 2014-02. (ADAMS 

Accession No. ML14094A173) 

04/24/2014 

03/26/2014 Summary of Conference Call Held on March 26, 2014, 

Between the U.S. NRC and Entergy Nuclear Operations, Inc., Concerning a 

Draft Request for Additional Information on the Reactor Vessel Internals 

Program (ADAMS Accession No. ML14105A354) 
Appendix B 

B-7 

Document Date Title 

06/09/2014 

Letter from Entergy to U.S. NRC Regarding Reply to Request for Additional 

Information Regarding the License Renewal Application, Indian Point 

Nuclear Generating Unit Nos. 2 and 3, License Renewal Application, 

Set 2014-02 (TAC Nos. MD5407 and MD5408), dated April 9, 2014. 

(ADAMS Accession No. ML14176A159) 

08/01/2014 

Summary of Conference Calls Held on June 19 and July 16, 2014, 

Between the U.S. NRC and Entergy Nuclear Operations, Inc., Regarding 

Entergy’s Response to a Request for Additional Information on Applicant or 

Licensee Action Item 7 from MRP-227-A. (ADAMS Accession 

No. ML14206B128) 

08/05/2014 

Letter from Entergy to U.S. NRC Regarding Reply to Request for Additional 

Information Regarding the License Renewal Application, Indian Point 

Nuclear Generating Unit Nos. 2 and 3, Docket Nos. 50-247 and 50-286, 

License Nos. DPR-26 and DPR-64. (ADAMS Accession 

No. ML14225A777) 

08/14/2014 

Letter from U.S. NRC to Mr. James A. Gresham, Westinghouse Electric 

Company, Subject: Review of Draft Audit Report Regarding Indian Point 

Nuclear Generating Unit Nos. 2 and 3 License Renewal Application (TAC 

Nos. MD5407 and MD5408). (ADAMS Accession No. ML14206B174)

08/14/2014 

Letter from U.S. NRC to Entergy Regarding Indian Point Nuclear 

Generating Unit Nos. 2 and 3 - Request for Withholding Information from 

Public Disclosure (TAC Nos. MD5407 and MD5408). (ADAMS Accession 

No. ML14217A206) 

09/08/2014 

Letter from Entergy to U.S. NRC Regarding Reply to Request for Additional 

Information Regarding the License Renewal Application, Indian Point 

Nuclear Generating Unit Nos. 2 and 3, Docket Nos. 50-247 and 50-286, 

License Nos. DPR-26 and DPR-64. (ADAMS Accession 

No. ML14267A270) [Note: this letter replaces the January 16, 2014 letter] 

09/09/2014 

Letter from Mr. James A. Gresham, Westinghouse Electric Company, to 

U.S. NRC, Subject: Submittal of “Westinghouse Review of Draft NRC Audit 

Report Regarding Indian Point Nuclear Generating Unit Nos. 2 and 3.” 

(ADAMS Accession No. ML14259A115) 

09/10/2014 

Summary of Conference Call Held on July 30, 2014, Between the 

U.S. NRC and Entergy Nuclear Operations, Inc., Regarding a Draft 

Request for Additional Information on Removal of Certain Aging 

Management Review Items. (ADAMS Accession No. ML14238A726) 

09/25/2014 

Letter from U.S. NRC to Mr. James A. Gresham, Westinghouse Electric 

Company, Subject: Request for Withholding Information from Public 

Disclosure Regarding the Aging Management Audit Report Associated with 

Indian Point Nuclear Generating Unit Nos. 2 and 3 License Renewal 

Application. (ADAMS Accession No. ML14265A226) 

10/06/2014 

U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor 

Regulation, Division of License Renewal Aging Management Audit Report 

(Non-Proprietary). (ADAMS Accession No. ML14266A273) 
Appendix B 

B-8 

Document Date Title 

10/15/2014 

Letter from U.S. NRC to Entergy Regarding Indian Point Nuclear 

Generating Unit Nos. 2 and 3 - Request for Withholding Information from 

Public Disclosure (TAC Nos. MD5407 and MD5408). (ADAMS Accession 

No. ML14268A476) 
C-1 

PRINCIPAL CONTRIBUTORS 

This appendix lists the principal contributors for the development of this supplement to the 

safety evaluation report and their areas of responsibility. 

Principal Contributors 

Name Responsibility

Diaz-Sanabria, Yoira Management Oversight 

Doutt, Cliff Reviewer – Electrical 

Gardner, William Reviewer – Mechanical 

Green, Kimberly Project Manager 

Hiland, Patrick Management Oversight 

Hiser, Allen Management Oversight 

Holston, William Reviewer – Mechanical 

Hovanec, Christopher Reviewer – Materials 

Lubinski, John Management Oversight 

Marshall, Michael Management Oversight 

Medoff, James Reviewer – Mechanical 

Miller, Chris Management Oversight 

Morey, Dennis Management Oversight 

Nickell, Cimberly Reviewer – Mechanical 

Poehler, Jeffrey Reviewer – Materials 

Rosenberg, Stacey Management Oversight 

Sheikh, Abdul Reviewer – Structures 

Wise, John Reviewer – Materials 

D-1 

REFERENCES 

This appendix lists the references used throughout this supplement to the safety evaluation 

report for review of the license renewal application for Indian Point Nuclear Generating Unit 

Nos. 2 and 3. 

1. Dacimo, Fred, Vice President, Entergy Nuclear Operations, Inc. (“Entergy”), letter to 

Document Control Desk, U.S. Nuclear Regulatory Commission (NRC), “Amendment 9 to 

License Renewal Application (LRA) - Reactor Vessel Internals Program, Indian Point 

Nuclear Generating Unit Nos. 2 & 3, Docket Nos. 50-247 and 50-286, License 

Nos. DPR-26 and DPR-64,” NL-10-063, July 14, 2010, Agencywide Documents Access 

and Management System (ADAMS) Accession No. ML102010102. 

2. Electric Power Research Institute (EPRI), “Materials Reliability Program: Pressurized 

Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227-Rev. 0),” 

Report 1016596, Palo Alto, CA, December 2008, ADAMS Accession No. ML090160205. 

3. EPRI, “Materials Reliability Program: Pressurized Water Reactor Internals Inspection 

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Appendix D 

D-2 

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the Electric Power Research Institute and Industry Representatives,” January 29, 2013, 

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ADAMS Accession No. ML13154A152. 
Appendix D 

D-3 

22. Westinghouse, “Reactor Internals Aging Management MRP-227-A Applicability for 

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WCAP-17780-P, Rev. 0, June 2013, Pittsburgh, PA. Proprietary information. Not publicly 

available.

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Point Units 2 and 3 (Non-Proprietary),” LTR-RIAM-13-117, Revision 1, Attachment 2 to 

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and MD5408),” October 2014, ADAMS Accession No. ML14266A273. 

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Additional Information Regarding the License Renewal Application, Indian Point Nuclear 

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Regarding the License Renewal Application - Action Item 7 from MRP-227-A, Indian 
Appendix D 

D-4 

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NUREG

-1930

Supplement 2

Safety Evaluation Report Related to the License Renewal of 

Indian Point Nuclear Generating Plant, Units 2 and 3