Safety Evaluation Report

Related to the License Renewal of 

Vermont Yankee Nuclear Power 

Station

Docket No. 50-271

Entergy Nuclear Operations, Inc.

Office of Nuclear Reactor Regulation 

NUREG-1907

Supplement 2
Safety Evaluation Report

Related to the License Renewal of 

Vermont Yankee Nuclear Power 

Station

Docket No. 50-271

Entergy Nuclear Operations, Inc.

Manuscript Completed: March 2011 

Date Published: April 2011 

Office of Nuclear Reactor Regulation 

NUREG-1907

Supplement 2
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iii 

ABSTRACT

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

application for Vermont Yankee Nuclear Power Station (VYNPS) as filed by Entergy Nuclear 

Operations, Inc. and Entergy Nuclear Vermont Yankee, LLC. (Entergy or the applicant). By 

letter dated January 25, 2006, Entergy submitted its application to the United States Nuclear 

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

20 years. The NRC staff published a safety evaluation report (SER) in two volumes, dated 

May 2008, which summarizes the results of its safety review of the renewal application for 

compliance with the requirements of Title 10, Part 54, of the Code of Federal Regulations, 

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

The NRC staff published Supplement 1 to the SER in October 2009 which documented the 

safety review results of confirmatory environmentally adjusted fatigue cumulative usage factors 

analyses for the reactor core spray nozzle and the reactor pressure vessel recirculation outlet 

nozzle at VYNPS. The applicant provided these analyses in response to the staff’s proposed 

license condition that would require Entergy to perform these fatigue analyses no later than 2 

years prior to entering the period of extended operation. 

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

since the issuance of Supplement 1 to the SER. This information includes annual updates 

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

industry operating experience. This document only lists the changes to the SER and 

Supplement 1. 
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v

TABLE OF CONTENTS

Abstract......................................................................................................................................iii

Abbreviations ............................................................................................................................ vii

SECTION 1 Introduction and General Discussion .................................................................. 1-1

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

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

SECTION 2 Structures Systems and Components Subject to Aging Management Review.... 2-1

SECTION 3 Aging Management Review Results ................................................................... 3-1

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

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

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

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements

.................................................................................................................................. 3-9

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report ............... 3-16

3.3 Aging Management of Auxiliary Systems.................................................................. 3-18

3.3.2 Staff Evaluation................................................................................................... 3-18

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended......................................................................................................... 3-18

3.5 Aging Management of SC Supports.......................................................................... 3-19

3.5.2 Staff Evaluation................................................................................................... 3-19

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ... 3-19

3.6 Aging Management of Electrical and Instrumentation and Controls System.............. 3-20

3.6.2 Staff Evaluation................................................................................................... 3-20

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report ... 3-20

SECTION 4 Time Limited Aging Analysis.............................................................................. 4-1

4.3 Metal Fatigue Analyses............................................................................................... 4-1

4.3.3 Effects of Reactor Environment on Fatigue Life .................................................... 4-1

4.3.3.1 Summary of Technical Information in the Application ................................... 4-1

4.3.3.2 Staff Evaluation ............................................................................................ 4-1

4.3.3.3 UFSAR Supplement..................................................................................... 4-3

4.3.3.4 Conclusion ................................................................................................... 4-3

SECTION 5 Review by the Advisory Committee on Reactor Safeguards.............................. 5-1

SECTION 6 Conclusion ........................................................................................................ 6-1

Appendices

Appendix A: List of Commitments ......................................................................................... A-1 

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

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vii 

ABBREVIATIONS 

ACRS Advisory Committee on Reactor Safeguards 

AMP aging management program 

API American Petroleum Institute 

ASME American Society of Mechanical Engineers 

ASTM American Society for Testing and Materials

AWWA America Water Works Association 

CLB current licensing basis 

CFR Code of Federal Regulations 

CRD control rod drive 

CUF cumulative usage factor 

CUFen environmentally assisted fatigue cumulative usage factor 

EPRI Electric Power Research Institute 

Fen environmental fatigue life correction factor 

GALL Generic Aging Lessons Learned 

GL Generic Letter 

GSI generic safety issue 

LER licensee event report

LRA license renewal application 

mg milligram 

ml milliliter 

NFPA National Fire Protection Association 

NRC Nuclear Regulatory Commission 

NUMARC Nuclear Management and Resources Council 

ppm parts per million 

RG Regulatory Guide 

RPV reactor pressure vessel 

RR reactor recirculation 

SER safety evaluation report 

STI Steel Tank Institute 

SSER supplemental safety evaluation report 

UFSAR updated final safety analysis report 

ULSD Ultra-Low Sulfur Diesel 

USAS United States of America Standard 
 

viii 

VHS Vernon Hydroelectric Station 

VYNPS Vermont Yankee Nuclear Power Station 
 

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SECTION 1

INTRODUCTION AND GENERAL DISCUSSION 

1.1 Introduction

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

application (LRA) for Vermont Yankee Nuclear Power Station (VYNPS) as filed by Entergy 

Nuclear Operations, Inc. and Entergy Nuclear Vermont Yankee, LLC. (Entergy, or the 

applicant). By letter dated January 25, 2006, Entergy submitted its application to the United 

States Nuclear Regulatory Commission (NRC) for renewal of the VYNPS operating license for 

an additional 20 years. The NRC staff (the staff) issued a safety evaluation report (SER) in two 

volumes, dated May 2008, which summarizes the results of its safety review of the renewal 

application for compliance with the requirements of Title 10, Part 54, of the Code of Federal 

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

Power Plants.” 

The NRC staff published Supplement 1 to the SER in September 2009 which documented the 

safety review results of confirmatory environmentally adjusted fatigue cumulative usage factors 

analyses for the reactor core spray nozzle and the reactor pressure vessel recirculation outlet 

nozzle at VYNPS. The applicant provided these analyses in response to the staff’s proposed 

license condition that would require Entergy to perform these fatigue analyses no later than 2 

years prior to entering the period of extended operation. 

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

since the staff’s issuance of Supplement 1 to the SER in September 2009. This information 

includes annual updates required by 10 CFR 54.21(b), and updated information and 

commitments in response to recent industry operating experience. This SSER supplements 

portions of SER Sections 3, 4, Appendix A, and Appendix B. 

1.7 Summary of Proposed License Conditions

As noted in this section of the SER, a fourth license condition required that the applicant 

perform and submit to the NRC for review and approval, an American Society of Mechanical 

Engineers Code analysis for the reactor recirculation outlet nozzle and the core spray nozzle at 

least 2 years prior to the period of extended operation. With Entergy’s submissions dated 

January 15, and March 12, 2009, this license condition has been met, as documented in 

Section 6, “Conclusion,” of Supplement 1. 

An additional license condition has been identified since the issuance of the SER. In 

accordance with Atomic Safety and Licensing Board Order LBP-08-25, dated 

November 24, 2008, which stated that the Board’s legal conclusion is subject to the mandatory 

proviso that a renewed license includes the following express condition: 
 

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Notwithstanding any other provision, Entergy shall continue to perform and 

implement the continuous parameter monitoring, moisture content monitoring, and 

visual inspections specified in the AMP [Steam Dryer Monitoring Plan], at the 

intervals specified in GE-SIL-644 [General Electric Services Information Letter 

644], Revision 2. These shall continue for the full term of the PEO [period of 

extended operation] unless this provision of the license is duly amended. 

The remaining license conditions proposed in the SER remain applicable. 
 

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SECTION 2 

STRUCTURES SYSTEMS AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW 

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

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SECTION 3 

AGING MANAGEMENT REVIEW RESULTS 

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

3.0.3 Aging Management Programs

Safety evaluation report (SER) Table 3.0.3-1 “VYNPS [Vermont Yankee Nuclear Power Station] 

Aging Management Programs” presents the aging management programs (AMPs) credited by 

the applicant and described in license renewal application (LRA) Appendix B and subsequent 

LRA supplements. The table also indicates the system, structure and components (SSCs) that 

credit the AMPs and the Generic Aging Lessons Learned (GALL) AMP with which the applicant 

claimed consistency and shows the SER section in which the staff’s evaluation of the program is 

documented. The following is an amendment to SER Table 3.0.3-1 which lists the AMPs the 

applicant has added subsequent to the issuance of the SER. Note that all references to the 

GALL Report in this SER refer to Revision 1. 

Table 3.0.3-1a VYNPS Aging Management Programs

VYNPS AMP 

(LRA Section)

GALL Report 

Comparison

GALL Report 

AMPs

LRA Systems or 

Structures 

That Credit the AMP

Staff's 

SER Section

Neutron Absorber 

Monitoring Program 

(B.1.31) 

Plant specific 

program 

N/A auxiliary systems 3.0.3.3.9 

Protective Coating 

Program (B.1.32) 

Consistent XI.S8 SC supports 3.0.3.1.13 

3.0.3.1 AMPs Consistent with the GALL Report

3.0.3.1.3 Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program 

Summary of Technical Information in the Application. The staff does not have any changes or 

updates to this section of the SER. 

Staff Evaluation. The staff’s evaluation of the applicant’s proposed Non-Environmental 

Qualification Inaccessible Medium-Voltage Cable Program is documented in Section 3.0.3.1.3 

of the SER. The applicant provided additional information subsequent to the issuance of the 

SER. The staff’s evaluation of the additional information related to the Non-Environmental 

Qualification Inaccessible Medium-Voltage Cable Program is discussed below. 

The applicant, in letters dated September 3, and December 21, 2010, and February 4, 2011, 

provided supplemental information that provided enhancements to the Non-Environmental 

Qualification Inaccessible Medium-Voltage Cable Program. Vermont Yankee Nuclear Power 

Station (VYNPS) stated that these enhancements reflect recent industry, NRC, and VYNPS 

correspondence as well as industry correspondence related to Generic Letter (GL) 2007-01 
 

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“Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or 

Cause Plant Transients.” The applicant proposed the following changes to LRA Sections 

A.2.1.19 and B.1.17 for the Non-Environmental Qualification Inaccessible Medium-Voltage 

Cable Program: 

• Removal of the “exposure to significant voltage” criterion (defined as system voltage for 

more than 25 percent of the time) 

• Expand the voltage range to include 400V to 2kV inaccessible power cables 

• Increase inspections for water collection in manholes from at least once every two years to 

at least once every year 

• Cable testing under the Non-Environmental Qualification Inaccessible Medium-Voltage 

Cable Program is revised from at least once every 10 years to at least once every 6 years 

• Include condition-based inspections of manholes based on potentially high water table 

conditions indicated by high river level and after periods of heavy rain 

• Corrective actions address modifying the cable test frequency and the manhole inspection 

frequency based on test or inspection results 

The applicant stated that the 4.16kV cables between the unit auxiliary transformer and Bus 1 

and Bus 2 are an exception in that these cables will not be tested prior to the period of extended 

operation under the applicant’s Non-Environmental Qualification Inaccessible Medium-Voltage 

Cable Program. The applicant stated that these cables have no previous evidence of exposure 

to moisture, are continuously energized during normal operation, and are currently subject to 

insulation resistance testing during each refueling outage. In addition, the applicant further 

stated that these cables are to be replaced and tested with the unit auxiliary transformer 

replacement scheduled for the first refueling outage following the commencement of the period 

of extended operation. The staff finds the applicant’s exception to not test the 4.16kV cables 

between the unit auxiliary transformer and Bus 1 and Bus 2 prior to the period of extended 

operation acceptable because there is operating history that shows no previous exposure to 

moisture, the cables are scheduled for replacement, and subsequent testing of the new cable 

will be performed under the applicant’s Non-Environmental Qualification Inaccessible 

Medium-Voltage Cable Program during the period of extended operation. 

The applicant stated that a review of the VYNPS response to GL 2007-01 indicated that VYNPS 

reported no failures involving low-voltage inaccessible cables. The applicant also stated that 

operating experience subsequent to the response to GL 2007-01, as researched in the 

corrective action database, also indicated that VYNPS has not experienced age-related failures 

of inaccessible low voltage cables subject to aging management. 

The application of Generic Aging Lessons Learned (GALL) AMP XI.E3 to inaccessible medium 

voltage cables was based on the operating experience available at the time Revision 1 of the 

GALL Report was developed. More recent industry operating experience indicate that the 

presence of water or moisture can be a contributing factor in inaccessible power cable failures 

at lower service voltages (400V and above). The staff identified operating experience identified 

in licensee responses to GL 2007-01, “Inaccessible or Underground Power Cable Failures that 

Disable Accident Mitigating Systems or Cause Plant Transients,” which included failures of 

power cables operating at service voltages of less than 2kV where water was considered a 

contributing factor. The staff has concluded that, based on this recently identified operating 

experience, these cables should be addressed in an AMP. Therefore, the applicant’s 
 

3-3 

enhancement of the LRA to expand the voltage range of the Non-Environmental Qualification 

Inaccessible Medium-Voltage Cable Program to include greater than or equal to 400V 

inaccessible power cables is consistent with the staff’s recommendation. 

The staff also finds that an increased manhole inspection frequency to at least once a year with 

the inspection frequency based on inspection results is consistent with industry operating 

experience. The addition of condition based (event driven) inspections reflects industry 

operating experience and is consistent with staff recommendations. 

The increase in testing frequency from at least every ten years to at least every six years is 

consistent with industry operating experience, and plant specific operating experience has also 

not revealed failures of inaccessible power cable within the scope of the Non-Environmental 

Qualification Inaccessible Medium-Voltage Cable Program. In addition, the operating 

experience program will continue to evaluate industry and plant-specific operating experience 

during the period of extended operation. 

The removal of the “exposure to significant voltage” criterion increases the scope of 

inaccessible medium voltage power cables included in the applicant’s Non-Environmental 

Qualification Inaccessible Medium-Voltage Cable Program and is also consistent with industry 

operating experience and staff recommendations. 

The staff finds that, with the enhancements discussed above, the Non-Environmental 

Qualification Inaccessible Medium-Voltage Cable Program will adequately manage the aging 

effects of inaccessible power cables, consistent with industry operating experience, such that 

there is reasonable assurance that inaccessible power cables (400V to 35kV) subject to 

significant moisture will be adequately managed during the period of extended operation. 

UFSAR Supplement. In LRA Section A.2.1.19, the applicant provided the UFSAR supplement 

for the Non-Environmental Qualification Inaccessible Medium-Voltage Cable Program. By 

letters dated September 3, 2010, and December 21, 2010, the applicant revised LRA Section 

A.2.1.19 to include 400V to 35kV inaccessible power cables and condition based inspections. 

The applicant also deleted the “exposure to significant voltage” criteria, and revised inaccessible 

power cable inspections and test frequencies. Commitment No.13 was also revised by the 

applicant to incorporate the change in inspection and test frequencies. 

The applicant committed (Commitment No. 13) to implement its Non-Environmental 

Qualification Inaccessible Medium-Voltage Cable Program by March 21, 2012. 

The staff reviewed LRA Section A.2.1.19 as amended by letters dated September 3, 2010, and 

December 21, 2010, and concludes that this section of the UFSAR supplement provides an 

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

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

3.0.3.1.6 One-Time Inspection Program 

Summary of Technical Information in the Application. The staff does not have any changes or 

updates to this section of the SER. 
 

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

Program is documented in Section 3.0.3.1.6 of the SER. The applicant provided additional 

information subsequent to the issuance of the SER. The staff’s evaluation of the additional 

information related to the One-Time Inspection Program is discussed below. 

By letter dated October 14, 2010, the applicant provided supplemental information related to the 

One-Time Inspection Program. The applicant stated that it will revise the program to inspect 

American Society of Mechanical Engineers (ASME) Code Class 1 small-bore socket welds 

using volumetric examinations and that the inspection volume is in accordance with guidelines 

established in MRP-146, “Materials Reliability Program Management of Thermal Fatigue in 

Normally Stagnant Non-Isolable Reactor Coolant System Branch Lines,” June 2005. The staff 

noted that MRP-146 recommends examination of the base metal half an inch beyond the toe of 

the weld. 

The staff noted that this proposed inspection methodology may not be adequate to manage 

age-related degradation of ASME Code Class 1 small-bore piping, because industry operating 

experience has demonstrated numerous failures in small bore piping, predominantly in the form 

of cracking in the weld metal. The staff noted that that many of these failures are documented 

in Licensee Event Reports (LERs). The staff is concerned that MRP-146 recommends only 

examination of the base metal of the small-bore piping and does not recommend examination of 

the socket weld metal where cracking may be occurring. The staff is also concerned that 

cracking in the socket weld metal could be occurring and remains undetected if examinations of 

the socket weld metal is not performed. It was not clear to the staff if the applicant’s proposal 

was to inspect the base metal only without inspecting the weld metal. Therefore, the staff sent a 

draft request for additional information to the applicant requesting that the applicant justify how 

the examination volume is sufficient and capable of detecting cracking in the subject welds. In 

addition, the staff requested that the applicant justify the adequacy of the sampling 

methodology. The staff held a teleconference with the applicant on November 22, 2010, to 

discuss the staff’s draft RAI. 

In its response dated December 21, 2010, the applicant provided supplemental information to its 

One-Time Inspection Program and Commitment No. 53. The applicant stated that it will perform 

volumetric examinations of 10 percent of its ASME Code Class 1 small-bore welds, up to a 

maximum of 25 welds for socket welds and butt welds. The applicant further stated that the 

inspection will be volumetric, using demonstrated ultrasonic techniques capable of examining 

both the weld metal and the base metal. The staff finds that the proposed inspection 

methodology, which includes a volumetric examination capable of detecting cracking in welds, 

acceptable because it is consistent with the recommendations of the “detection of aging effects” 

program element of GALL AMP XI.M35 to inspect ASME Code Class 1 small bore piping with a 

volumetric examination. 

With regard to the applicant’s proposed inspection methodology, which consists of inspecting 10 

percent of the weld population up to a maximum of 25 welds for both butt welds and socket 

welds, the staff notes that it will be a focused inspection which will select the most susceptible 

and risk-significant welds to ensure a high probability of detecting cracking, if it exists. The staff 

also notes that if cracking is detected during the inspection, there will be an extent of condition 

review to evaluate the inspection sample size to ensure that it is adequate to identify cracking 

that could occur at other locations. The staff finds the applicant’s proposed inspection 
 

3-5 

methodology acceptable because the inspections will focus on the most susceptible and risksignificant welds and an adequate number of inspections will be performed to ensure that 

cracking is detected which is consistent with the recommendations of GALL AMP XI.M35. 

The applicant also stated in the December 21, 2010, letter that for socket weld examinations, in 

lieu of a volumetric examination, it may perform a destructive examination, in which each 

destructive weld examination will be considered equivalent to performing two volumetric weld 

examinations. The staff finds the applicant’s proposed alternative acceptable because welds 

that are destructively examined provide more information when compared to the information 

obtained from a weld that is examined with nondestructive techniques. 

The applicant stated in the December 21, 2010, letter that inspections will be completed by 

December 2016. The applicant will potentially be entering the period of extended operation in 

March 21, 2012. The staff finds it reasonable and timely for the applicant to complete the small 

bore piping inspections by December 2016, since this would allow sufficient time for the 

applicant to plan and schedule outage inspections prior to this date. This timeline will also be 

sufficient for the applicant to qualify a demonstrated technique to volumetrically inspect small 

bore socket welds; to develop plant-specific procedures; and to qualify personnel to perform the 

inspections. 

Based on its review, the staff determined that the applicant’s proposed aging management of 

ASME Code Class 1 small bore piping is adequate because the program includes a sufficient 

number of welds to be inspected, an adequate selection methodology that focuses on 

susceptibility, welds and risk-significance, and the program will also be implemented in a 

reasonable timeframe. 

By letter dated January 21, 2011, the applicant submitted supplemental information regarding 

the sampling of components inspected by the One-Time Inspection Program. The applicant 

stated that representative samples are chosen from each population where a population is a 

group of components with the same material and environment combination. The applicant also 

stated that the sample size will be based on Chapter 4 of Electric Power Research Institute 

(EPRI)-TR 107514, “Age Related Degradation Inspection Method and Demonstration,” except 

for populations of less than 100 where the criterion will be modified such that the sample size is 

at least 20 percent of the population with no less than 2 inspections. The applicant further 

stated that inspection locations will focus on the bounding or lead component most susceptible 

to aging due to time in-service and severity of operating conditions, where practical. The staff 

finds the applicant’s supplemental information acceptable because the applicant’s sampling 

methodology ensures that a representative sample of material and environment combinations is 

considered, ensures sample locations will focus on the most susceptible components, and 

includes an appropriate sample size. 

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

SER. 

UFSAR Supplement. The staff does not have any changes or updates to this section of the 

SER. 

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

3-6 

3.0.3.1.7 Selective Leaching Program 

Summary of Technical Information in the Application. The staff does not have any changes or 

updates to this section of the original SER. 

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

is documented in Section 3.0.3.1.7 of the SER. The applicant provided additional information 

subsequent to the issuance of the SER. The staff’s evaluation of the additional information 

related to the Selective Leaching Program is discussed below. 

By letter dated January 21, 2011, the applicant submitted supplemental information regarding 

the sampling of components inspected by the Selective Leaching Program. The applicant 

stated that representative samples are chosen from each population where a population is a 

group of components with the same material and environment combination. The applicant also 

stated that the sample size will be based on Chapter 4 of EPRI-TR 107514 except for 

populations of less than 100 where the criterion will be modified such that the sample size is at 

least 20 percent of the population with no less than 2 inspections. The applicant further stated 

that inspection locations will focus on the bounding or lead component most susceptible to 

aging due to time in-service and severity of operating conditions, where practical. The staff 

finds the applicant’s response acceptable because the applicant’s sampling methodology 

ensures a representative sample of material and environment combinations is considered, 

ensures sample locations will focus on the most susceptible components, and includes an 

appropriate sample size. 

By letter dated January 21, 2011, the applicant also revised its Selective Leaching Program to 

allow hardness verification using mechanical inspection techniques including destructive testing 

(when the opportunity arises), chipping, or scraping. The applicant stated that a hardness 

measurement of all the components in the sample population may not be feasible due to 

component location and configuration. The staff finds the applicant’s addition of these 

mechanical inspection techniques to detect selective leaching acceptable because they are 

standard industry techniques which are capable of detecting loss of material due to selective 

leaching. 

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

SER. 

UFSAR Supplement. The staff does not have any changes or updates to this section of the 

SER. 

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

3.0.3.1.13 Protective Coating Program 

Summary of Technical Information in the Application. By letter dated December 21, 2010, the 

applicant amended its LRA to include the new Protective Coating Program in LRA Section 

B.1.32. In a supplement dated February 4, 2011, the applicant provided a detailed description 

of their Protective Coating Program. The program description provided by the applicant is as 

follows: 
 

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The Protective Coating Program manages the effects of aging on Service Level I 

coatings inside containment. 

Service Level I protective coatings are not credited to manage the effects of 

aging, however, proper maintenance of protective coatings inside containment is 

essential to ensure operability of post-accident safety systems that rely on water 

recycled through the containment. The proper monitoring and maintenance of 

Level I coatings ensures there is no coating degradation that would impact safety 

functions. 

The applicant states that the VYNPS Protective Coatings Program complies with Regulatory 

Guide 1.54 Revision 2 with respect to inspection and maintenance of Service Level I Coatings 

and is consistent with the program elements described in GALL AMP XI.S8. 

Staff Evaluation. The staff reviewed the applicant’s program focusing on how the program 

manages aging effects through the effective incorporation of 10 elements. Specifically, the staff 

reviewed the following program elements of the applicant’s program: (1) “scope of the program,” 

(2) “preventive actions,” (3) “parameters monitored or inspected,” (4) “detection of aging 

effects,” (5) “monitoring and trending,” (6) “acceptance criteria.” 

The staff confirmed consistency with GALL AMP XI.S8 for elements (1) “scope of the program,” 

(2) “preventive actions,” and (3) “parameters monitored or inspected.” The applicant provided 

enhancements to elements (4) “detection of aging effects,” (5) “monitoring and trending,” and (6) 

“acceptance criteria.” The enhancements and the staff’s evaluation for those elements are 

described below. 

 (4) Detection of Aging Effects 

Enhance the Protective Coating Program by clearly defining qualifications 

for inspection personnel, the inspection coordinator, and the inspection 

results evaluator, as defined by [American Society for Testing and 

Materials] ASTM D 5163-08 and for inspection to include a thorough 

visual on all coatings near sumps or screens associated with the 

Emergency Core Cooling Systems (ECCS) 

Enhance the Protective Coating Program by clearly identifying the 

instruments and equipment required for the inspection which include but 

may not be limited to flashlights, mirrors, measuring instruments, 

magnifiers, cameras and binoculars. 

GALL AMP XI.S8 recommends ASTM D5163-05 for defining the criteria for qualifying inspection 

personnel, the inspection coordinator and the inspection results evaluator. The staff finds the 

applicant’s proposed enhancement to the “detection of aging effects” element acceptable 

because the qualification requirements defined in ASTM D5163-08 are consistent with the 

criteria in ASTM D5163-05 and are therefore consistent with the recommendations in the GALL 

Report. 
 

3-8 

The applicant’s enhancement to identify the acceptable instruments and equipment is consistent 

with the GALL Report recommendations that visual inspections be completed. Therefore, the 

staff finds the applicant’s proposal acceptable. 

(5) Monitoring and Trending 

Enhance the Protective Coating Program to specify that the coating 

inspector conduct a pre-inspection review of the previous two inspection 

reports. Also, revise the program to specify that the inspection report 

prioritize the repair areas as either needing repair during the same outage 

or as acceptable to postpone to future outages with appropriate 

surveillance in the interim period. 

GALL AMP XI.S8 recommends a pre-inspection review of the previous two monitoring reports, 

and that the inspection report should prioritize repair areas as either needing repair during the 

same outage or postponed to future outages, but under surveillance in the interim period. 

Based on its review the staff determines that the applicant’s proposed enhancement to the 

“monitoring and trending” element is consistent with the GALL Report recommendations and 

therefore acceptable. 

 (6) Acceptance Criteria 

Enhance the program to specify the acceptance criteria in accordance 

with ASTM D 5163-08 and to specify an evaluation of the inspection 

reports by the responsible coating evaluator who prepares a summary of 

findings and recommendations for future surveillance or repair. 

GALL AMP XI.S8 recommends ASTM D5163-05 for determining acceptability of coatings. As 

previously stated, the recommendations in ASTM D 5163-08 are consistent with ASTM D5163-

05. Based on its review the staff determines that the applicant’s proposed enhancement to the 

“acceptance criteria” element is consistent with the GALL Report recommendations and 

therefore acceptable. 

The staff confirmed that the applicant has demonstrated that the condition of Service Level I 

containment coatings are adequately managed to ensure that post-accident accumulation of 

failed coating debris on containment sump strainers does not exceed the strainers design limits, 

consistent with the CLB, for the period of extended operation. Based on its review, the staff 

finds that elements one through six of the applicant’s Protective Coating Program, with 

acceptable enhancements, are consistent with the program elements of GALL AMP XI.S8, and 

therefore acceptable. 

Operating Experience. The staff reviewed the operating experience described in the applicant’s 

February 4, 2011, supplement. A summary of the operating experience is described below. 

As early as 1972, the coating system in the torus vapor space exhibited signs of degradation. 

The coating system was an inorganic zinc primer topcoated with a phenolic epoxy. The topcoat 

was blistered and cracked as a result of errors in the application of the inorganic zinc primer. 

The applicant stated that errors in the application of the primer resulted in an inadequate bond 

with the topcoat. The applicant’s original remediation method was to scrape the blistered 
 

3-9 

topcoat and recoat the area. Subsequent remediation methods involved scraping the loose 

topcoat and leaving the primer exposed. During the 1998 refueling outage, the applicant 

blasted and recoated the lower torus shell from one foot above the waterline. The new coating 

was an un-topcoated inorganic zinc coating. 

An inspection of the torus coatings in 2010 verified that the coatings below the waterline had 

experienced no degradation. There was one area that required repair due to tape having been 

left between the coating and the substrate. The foreign material (tape) was removed and the 

area was recoated. 

In May 2010 the applicant inspected the primary containment. This inspection identified 

degraded coatings in the upper elevations of the drywell. The applicant determined that 

degradation was limited to the topcoat of the coating system and was attributed to elevated 

temperature in the upper elevations of the drywell. The applicant documented the affected 

surface area and evaluated the impact of the degraded coatings on ECCS performance. The 

applicant’s evaluation showed that the degraded coatings did not threaten ECCS performance. 

Based on its review of the application the staff finds that operating experience related to the 

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

aging and that implementation of the program has resulted in the applicant taking appropriate 

corrective actions. The staff confirmed that the OE program element satisfies the criterion 

defined in the GALL Report and SRP-LR Section A.1.2.3.10. The staff finds this program 

element acceptable. 

UFSAR Supplement. In LRA Section A.2.1.38 the applicant provided the UFSAR supplement 

for the Protective Coating Program. The staff reviewed this UFSAR supplement description of 

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

as described in SRP-LR Table 3.5-2. The staff also notes that the applicant committed 

(Commitment No. 55) to enhance the safety-related coatings program and procedures to be 

consistent with the recommendations of GALL AMP XI.S8. 

The staff reviewed this section and determines that the information in the UFSAR supplement is 

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

Conclusion. On the basis of its review of the applicant's Protective Coating Program, the staff 

finds all program elements consistent with the GALL Report. The staff concludes that the 

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

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions and/or Enhancements

3.0.3.2.1 Buried Piping Inspection Program 

Summary of Technical Information in the Application. The staff does not have any changes or 

updates to this section of the SER. 
 

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

Program is documented in Section 3.0.3.2.1 of the SER. The applicant provided additional 

information subsequent to the issuance of the SER. The staff’s evaluation of the additional 

information related to the Buried Piping Inspection Program is discussed below. 

By letters dated October 14 and December 21, 2010, and February 4 and 10, 2011, the 

applicant described changes to its Buried Piping Inspection Program based upon industry and 

plant-specific operating experience. 

In LRA Section B.1.1, the applicant originally stated that steel piping was excavated and 

inspected on several occasions during the past seven years and these inspections did not 

reveal loss of material due to external surface corrosion. In its responses dated October 14 and 

December 21, 2010, and February 4 and 10, 2011, the applicant stated that the following 

lengths of buried in-scope piping were inspected and found to be in good condition with no loss 

of material: approximately six feet of service water piping in 2003, approximately eight feet 

each of fire protection and service water piping in 2008, and in approximately 40 feet of fuel oil 

piping in 2010. Additionally, the applicant stated that a review of plant records indicated no 

age-related failures of in-scope buried piping due to external corrosion. To help clarify the 

salient points of the Buried Piping Inspection Program, the applicant also provided the following 

program information: 

• Buried in-scope piping is coated with tar wrap or epoxy coating. 

• Original construction backfill consisted of gravel and sand mix with particle sizes less than 

one-half inch. Recent backfill activities have consisted of gravel and sand mix with particle 

sizes less than one and one-half inch. As evidenced by recent piping excavations and 

inspections, the backfill is free of debris and large rocks that may damage coatings on piping 

during placement. 

• Buried in-scope piping is not protected by a cathodic protection system. 

• The below-grade environment is non-aggressive, as per LRA Section 3.5.2.2.1.1, with pH 

greater than 5.5, chlorides less than 500 parts per million (ppm), and sulfates less than 

1,500 ppm. The applicant also stated that buried in-scope piping is located above the 

groundwater level. 

• A ten-foot minimum length of piping will be visually inspected during each excavated 

inspection. 

• Locations for inspections will be selected based on an assessment of the impact risk and 

corrosion risk to ensure that the most susceptible locations will be inspected. Impact risk 

considers factors such as environmental risk, impact on plant operation, and safety 

classification while corrosion risk considers factors such as soil resistivity, soil drainage, 

piping material, and coating. 

• The fiberglass piping exposed to soil in LRA Table 3.3.2-6 is a ten foot length of vent piping 

for the John Deere fuel oil storage tank. No aging effect requiring management or AMP is 

proposed because the pipe is not exposed to ultraviolet light, ozone, or high voltage current, 

and it is well above the water table. This length of fiberglass piping is not continuously 

exposed to water or hydraulic pressure. 

• As an alternative to inspecting buried fire protection piping, the applicant will monitor 

leakage for the system by trending unexplained electric fire pump starts. The fire protection 

system is provided with makeup from the service water system through a line with an 

installed orifice capable of making up at a rate of thirty gallons per minute. The fire 
 

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protection system pumps are sized to provide adequate system flow to compensate for the 

potential loss of thirty gallons per minute. 

• Prior to the period of extended operation, the applicant will inspect a minimum of two 

ten-foot segments of the buried in-scope standby gas treatment piping. 

• The applicant will inspect eight percent of the fuel oil piping (approximately forty feet, 

equivalent to four inspections), two ten-foot segments of the standby gas treatment system, 

and four ten-foot segments of the service water system during each ten-year period within 

the period of extended operation. 

• Soil samples will be obtained prior to the period of extended operation and once every ten 

years during the period of extended operation. The applicant also stated it will sample two 

locations near each in-scope system. The applicant further stated that soil composition, pH, 

chlorides, sulfates, redox potential, and resistivity would be used to determine the 

corrosiveness of the soil using America Water Works Association (AWWA) Standard C105 

Appendix A rating factors. 

• If the soil corrosivity rating factor exceeds 10, or soil resistivity is less than 20,000 ohm-cm, 

the applicant will increase the number of inspections of the fuel oil system to six (equivalent 

to 12 percent), standby gas treatment system to three, and service water system to six 

during each ten-year period during the period of extended operation. 

• The applicant will use trending in the corrective action program to identify the need for 

additional inspections of susceptible locations, alternative coatings or replacement. 

• Non-visual methods will be capable of detecting both general and pitting corrosion and will 

be qualified methods with demonstrated capability. 

• The applicant reviewed its System Walkdown Program (LRA Section B.1.28) in light of 

plant-specific operating experience, (i.e., a leak that occurred in the underground advanced 

off gas system piping). As a result of this review, the applicant has determined that some 

in-scope underground piping (i.e, below grade, but are contained within a tunnel or vault 

such that they are in contact with air and are located where access for inspection is 

restricted) is not readily accessible during normal operation and refueling outages; however, 

all in-scope underground piping will be inspected at least once every five years. Direct 

visual inspections of all in-scope underground piping were conducted, which included the 

service water system in 2008 and the emergency core cooling system in 2010. LRA Section 

A.2.1.32 was revised to include inspection attributes and intervals for piping that is 

inaccessible during plant operation. 

The staff finds this program acceptable because: 

• Buried in-scope piping is coated with tar wrap or epoxy coating. 

• Original construction backfill plant-specific specifications ensure that damage will not occur 

to piping coatings and recent inspections have demonstrated that the backfill meets the 

specifications. 

• A ten-foot minimum length of piping will be visually inspected during each excavated 

inspection. 

• Locations for inspections will be selected based on a risk assessment combining impact risk 

and corrosion risk to ensure that the most susceptible locations will be inspected. 

• The fiberglass vent piping for the John Deere fuel oil storage tank is not exposed to any 

environmental stressors that would result in an aging effect requiring management. 

• The proposed alternative to inspecting buried fire protection piping is consistent with 

alternatives for inspecting fire protection systems as stated in GALL AMP XI.M41. 
 

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• The soil sampling frequency, parameters, and analysis rating factors are consistent with 

AWWA Standard C105 Appendix A, a recognized industry standard for determining soil 

corrosivity. 

• The number of inspections conducted or being conducted in the ten-year period prior to the 

period of extended operation (nine inspections total) and those that will be conducted during 

the period of extended operation (ten inspections total during each ten year period within the 

period of extended operation), including any increased inspections if the soil is determined 

to be corrosive, establish a reasonable basis for the staff to conclude that the current 

licensing basis (CLB) function(s) of the buried in-scope systems will be maintained. 

• If non-visual methods will be used to inspect buried pipe in lieu of excavated direct 

inspections, the applicant stated that the method will be qualified with performance 

demonstrations to ensure that it is capable of detecting both general and pitting corrosion. 

• All in-scope underground piping will be inspected at least once every five years and the 

applicant revised LRA Section A.2.1.32 to include inspection intervals for piping that is 

inaccessible during plant operation. 

On the basis of its review of the applicant’s revised commitments for the Buried Piping 

Inspection Program, the staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the revised 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). 

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

SER. 

UFSAR Supplement. The staff reviewed the revised UFSAR supplement description of the 

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

described in SRP-LR Tables 3.2-2 and 3.3-2. The staff also noted that the applicant provided a 

new commitment (Commitment No. 54) to implement the soil sampling and inspections as 

described above. The staff further noted that Commitment No. 44 was replaced with 

Commitment No. 54 in that the former commitment stated a lesser number of inspections and 

allowed for inspections without excavating the pipe. 

Conclusion. The staff does not have any changes or update to this section of the SER. 

3.0.3.2.7 BWR Vessel Internals Program 

Summary of Technical Information in the Application. The staff does not have any changes or 

update to this section of the SER. 

Staff Evaluation. The staff’s evaluation of the applicant’s proposed BWR Vessel Internals 

Program is documented in Section 3.0.3.2.7 of the SER. The applicant provided additional 

information subsequent to the issuance of the SER. The staff’s evaluation of the additional 

information related to the BWR Vessel Internals Program is discussed below. 

In the VYNPS License Renewal application annual update letter dated December 30, 2010, the 

applicant described changes to its BWR Vessel Internals Program, which is documented in LRA 
 

3-13 

Section B.1.7 and described as consistent, with exceptions and enhancements, with GALL AMP 

XI.M9, “BWR Vessel Internals.” The applicant made the following modifications to the program 

as discussed below: 

• LRA Commitment No. 29 was modified to change the timeframe for completion of a plantspecific analysis to determine acceptance criteria for continued inspection of core plate hold 

down bolting in accordance with BWRVIP-25 and submit the inspection plan and analysis to 

the NRC from two years down to one year prior to the period of extended operation. 

The staff reviewed the revised LRA Commitment No. 29 and noted that the proposed revision of 

the commitment, supplying an analysis one year prior to the period of extended operation 

instead of two years prior will allow the staff adequate time to review the potential analysis 

before the applicant enters the period of extended operation. Therefore, the staff finds the 

proposed commitment modification acceptable. 

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

SER. 

UFSAR Supplement. The staff does not have any changes or updates to this section of the 

SER. 

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

3.0.3.2.9 Diesel Fuel Monitoring Program 

Summary of Technical Information in the Application. The staff does not have any changes or 

updates to this section of the SER. 

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

Program is documented in Section 3.0.3.2.9 of the SER. The applicant provided additional 

information subsequent to the issuance of the SER. The staff’s evaluation of the additional 

information related to the Diesel Fuel Monitoring Program is discussed below. 

By letters dated December 30, 2010, and February 4, 2011, the applicant provided changes to 

its Diesel Fuel Monitoring Program based upon plant operating procedures and industry 

guidance. 

LRA Section B.1.9 as supplemented by letter dated March 23, 2007, describe the existing 

Diesel Fuel Monitoring Program as consistent, with exceptions and enhancements, with GALL 

AMP XI.M30, “Fuel Oil Chemistry.” In the supplemental letters, the applicant revised its use of 

several guidance documents related to this AMP by updating revision numbers as well as 

applicability. As a result, the applicant made the following modifications to exceptions and 

enhancements along with the corresponding commitments as discussed below: 

• The program element “program description” was modified to change the revision number of 

ASTM Standard D975 to revision 09. 

GALL AMP XI.M30 states that ASTM D975-04 or other appropriate standards may be used to 
 

3-14 

develop fuel oil quality acceptance criteria. The staff noted that the ASTM D975-09 standard 

contains all of the requirements contained in the D975-02 and D975-04 editions, with an 

additional requirement for Ultra-Low Sulfur Diesel (ULSD). The staff finds this ASTM Standard 

revision change to be acceptable based on the use of a more stringent version of the ASTM 

standard than is recommended by the GALL Report. 

• The note applicable to Exception 1 was clarified to state that the D2276 acceptance criterion 

is more stringent that of D6217, and is therefore the reason why ASTM D6217 is not 

necessary for the determination of particulates. 

The staff finds that the applicant is using one of the methods (ASTM D2276) which is 

recommended by the GALL Report. During the review, the applicant stated that the ASTM 

D6217 provides guidance on determining particulate contamination by sample filtration at an 

offsite laboratory. However, the use of ASTM D2276 provides for guidance on determining 

particulate contamination using a field monitor which provides for rapid assessment of changes 

in contamination. In addition, the applicant stated that the acceptance criteria for ASTM D2276 

is more stringent than for ASTM D6217, namely 10 milligrams (mg) per milliliter(ml) versus 

24 mg/ml. The staff finds the use of only ASTM D2276 to be conservative. 

The staff finds this exception acceptable based on using the more stringent of the ASTM 

standards recommended by the GALL Report with the added advantage of the quick 

assessment of contamination changes. 

• Exception 3 was modified to state that ASTM Standard D2709 is used for determination of 

water standards. The note relating to Exception 3 was also clarified to state that ASTM 

Standard D2709 is the appropriate standard for the determination of water and sediment in 

the VYNPS fuel oil. 

The GALL Report recommends both ASTM Standards D1796 and D2709 for determining the 

water and sediment contamination in diesel fuel. Both of these standards are applicable to the 

diesel fuel used at VYNPS. The ASTM Standards D1796 and D2709 are both referenced in 

ASTM D975 which VYNPS references in the plant technical specifications bases. 

The staff finds this exception acceptable since either standard would be appropriate for the 

VYNPS diesel fuel; the staff accepted the use of ASTM D2709 to determine the water and 

sediment in the diesel fuel. 

• Enhancement 2 was modified to state that UT measurements of the fuel oil storage bottom 

surface will have acceptance criterion in accordance with American Petroleum Institute (API) 

standard API 653 and UT measurements of the fire pump diesel storage (day) tank bottom 

surface will have acceptance criterion in accordance with Steel Tank Institute (STI) standard 

STI SP001. LRA Commitment No. 4 was also updated to reflect this change. 

By letter dated February 4, 2011, the applicant also stated that the fuel oil storage tank was 

fabricated in accordance with National Fire Protection Association Standard, NFPA No. 30. 

Section 22.17.2 of the standard states that each aboveground steel tank shall be inspected and 

maintained in accordance with API 653, “Tank Inspection, Repair, Alteration, and 

Reconstruction” or STI SP001, “Standard for Inspection of Aboveground Storage Tanks.” 
 

3-15 

GALL AMP XI.M30 does not provide an acceptance criterion for the bottom surface thickness of 

the diesel fuel storage tank. The staff noted that periodic ultrasonic thickness measurements of 

the fuel oil storage and fire pump diesel storage (day) tank bottom surfaces performed in 

conjunction with industry standard acceptance criterion and a rigid corrective action program will 

provide additional assurance that the effects of aging will be detected before the loss of 

intended function. 

On this basis, the staff finds this enhancement acceptable since, with the enhancement 

implemented, the Diesel Fuel Monitoring Program, will be consistent with GALL AMP XI.M30 

and will provide additional assurance that the effects of aging will be adequately managed. 

• Enhancement 3 was modified to change the revision number of ASTM Standard D975 to 

revision 09. LRA Commitment No. 46 was updated to reflect this change. 

GALL AMP XI.M30 states that ASTM D975-04 or other appropriate standards may be used to 

develop fuel oil quality acceptance criteria. The staff notes that the ASTM D975-09 standard 

contains all of the requirements contained in the D975-02 and D975-04 editions, with an 

additional requirement for ULSD. The staff finds this ASTM Standard revision change to be 

acceptable based on the use of a more stringent version of the ASTM standard recommended 

by the GALL Report. 

On this basis, the staff finds this enhancement acceptable since the ultrasonic testing will be 

accomplished in accordance with industry standards and will provide additional assurance that 

the effects of aging will be adequately managed. 

• Enhancement 5 was modified to change the revision number of ASTM Standard D975 to 

revision 09 and also refer to ASTM Standard D2709 as previously discussed in the changes 

to Exception 3. LRA Commitment No. 47 was updated to reflect these changes. 

GALL AMP XI.M30 states that ASTM D975-04 or other appropriate standards may be used to 

develop fuel oil quality acceptance criteria. The staff noted that the ASTM D975-09 standard 

contains all of the requirements contained in the D975-02 and D975-04 editions, with an 

additional requirement for ULSD. The staff finds this ASTM Standard revision change to be 

acceptable based on the use of a more stringent version of the ASTM standard recommended 

by the GALL Report. 

On this basis, the staff finds this enhancement acceptable since, with the enhancement 

implemented, the Diesel Fuel Monitoring Program will be consistent with GALL AMP XI.M30 

and will provide additional assurance that the effects of aging will be adequately managed. 

On the basis of its review of the applicant’s revised exceptions, enhancements, and 

commitments for the Diesel Fuel Monitoring Program, the staff concludes that the applicant has 

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

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the revised 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). 
 

3-16 

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

SER. 

UFSAR Supplement. The staff does not have any changes or updates to this section of the 

SER. 

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

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

3.0.3.3.6 Vernon Dam FERC Inspection 

Summary of Technical Information in the Application. The staff does not have any changes or 

updates to this section of the SER. 

Staff Evaluation. The staff’s evaluation of the applicant’s proposed Vernon Dam FERC 

Inspection Program is documented in Section 3.0.3.3.6 of the SER. The applicant provided 

additional information subsequent to the issuance of the SER. The staff’s evaluation of the 

additional information related to the Vernon Dam FERC Inspection Program is discussed below. 

In the VYNPS LRA Annual Update letter dated December 30, 2010, the applicant described 

changes to its Vernon Dam FERC Inspection Program, which is documented in LRA Section 

B.1.27.3 and described as an existing, plant-specific program. The applicant made the following 

modifications to the program as discussed below: 

• LRA Commitment No. 50 was modified to correct a typographical error and change the 

reference document to BVY 97-025. 

The staff reviewed the revised LRA Commitment No. 50, and noted that the typographical error 

occurred in the original commitment only, and that the staff had completed and documented it in 

the SER as the BVY 97-025 reference document as intended. The staff finds that the revised 

LRA Commitment No. 50 adequately documents the correct document reference. 

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

SER. 

UFSAR Supplement. The staff does not have any changes or updates to this section of the 

SER. 

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

3.0.3.3.9 Neutron Absorber Monitoring Program 

Summary of Technical Information in the Application. By letter dated December 21, 2010, the 

applicant amended its LRA to include the new Neutron Absorber Monitoring Program in LRA 

Section B.1.31. By letters dated February 4 and 10, 2011, the applicant provided a detailed 

description of the program as well as a commitment to perform surveillance testing of Boral 
 

3-17 

coupons prior to the period of extended operation. The applicant provided the following 

program description: 

The Neutron Absorber Monitoring Program is a new program that manages loss 

of material and reduction of neutron absorption capacity of Boral neutron 

absorption panels in the spent fuel racks. The program will rely on periodic 

inspection, testing, monitoring and analysis of the criticality design to assure that 

the required five percent subcriticality margin is maintained during the period of 

extended operation. 

The program will be initiated prior to the period of extended operation. One 

coupon will be tested prior to the PEO to measure B-10 areal density and to 

assess the geometric and physical condition of the tested coupon. If coupons 

are not able to be retrieved and tested or if coupons cannot be demonstrated 

representative of the Boral in the Holtec racks, then neutron attenuation testing 

using in-situ methods, as described in BVY 11-010, (BADGER or blackness 

testing method) will be completed prior to the end of 2014. 

Staff Evaluation. The staff compared elements one through six of the applicant’s program to the 

corresponding elements of GALL AMP XI.M40. The staff confirmed that these elements are 

consistent with the corresponding elements of GALL AMP XI.M40. The staff finds that elements 

one through six of the applicant’s Neutron Absorber Monitoring Program are consistent with the 

corresponding program elements of GALL AMP XI.M40 and, therefore, acceptable. 

The applicant has Boral that was manufactured by two different companies. Seven racks were 

manufactured by Nuclear Energy Services (NES). Two racks were manufactured by Holtec. 

Coupons are available for the NES racks; however, none are available for the Holtec racks. 

The applicant has committed to remove and perform testing on a coupon from the NES racks 

prior to the period of extended operation. The testing will include areal density measurement to 

determine the materials neutron attenuation capability. The applicant will perform an evaluation 

to determine if the coupon is representative of both the Holtec and the NES racks. If the coupon 

cannot be verified to represent the Holtec racks, then in-situ testing will be performed to verify 

the material condition and neutron attenuation capability of the Holtec racks. 

The staff finds that the applicant’s commitment (Commitment No. 52) to perform testing prior to 

the period of extended operation, in addition to the testing described in the Neutron Absorber 

Monitoring Program, will effectively manage the loss of neutron-absorbing capacity and 

degradation of Boral. 

Operating Experience. By letter dated February 4, 2011, the applicant provided an LRA 

amendment related to LRA Section B.1.31 and summarized operating experience related to the 

Neutron Absorber Monitoring Program. 

In 1989, when nine of the VYNPS spent fuel pool storage racks were replaced with Boral racks, 

three strings of monitoring coupons were installed—each monitoring string consisted of eight 

304L stainless steel coupons and three Boral coupons. The applicant analyzed coupons in 

1991 and 1996. In 1996, the Boral coupon on a string exhibited blistering on the bottom side of 

the coupon. The applicant determined that the blistering did not result in degradation of the 

Boral’s neutron absorption capability. The applicant has not tested coupons since the 1996 test 
 

3-18 

because no deterioration of the material was identified when comparing the 1991 testing to the 

1996 testing. To confirm that the neutron absorbing capacity of the material has not degraded 

since the 1996 testing, the applicant committed to perform areal density testing of a coupon 

prior to the period of extended operation. 

The staff reviewed the operating experience information in the LRA amendment to determine if 

the applicable aging effects and industry and plant-specific operating experience were reviewed 

by the applicant. The staff confirmed that the “operating experience” program element satisfies 

the guidance in SRP-LR Section A.1.2.3.10, since the operating experience supports the 

conclusion that the Neutron Absorber Monitoring Program will be able to effectively manage the 

loss of neutron-absorbing capacity and degradation of Boral. The staff finds this program 

element acceptable. 

UFSAR Supplement. In LRA Section A.2.1.37 the applicant provided the UFSAR supplement 

for the Neutron Absorber Monitoring Program. The staff notes that the applicant committed 

(Commitment No. 52) to implement the Neutron Absorber Monitoring Program prior to entering 

the period of extended operation and to test one coupon prior to the period of extend operation 

to measure B-10 areal density and assess the geometric and physical condition of the tested 

coupon. The applicant further committed to perform in-situ testing if coupons cannot be 

retrieved or cannot be determined to be representative of the Hotec racks prior to the end of 

2014. 

The staff reviewed LRA Section A.2.1.37 and determined that the information in the UFSAR 

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

10 CFR 54.21(d). 

Conclusion. On the basis of its review of the applicant's Neutron Absorber Monitoring Program, 

the staff finds all program elements consistent with the GALL Report. The staff concludes that 

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

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.3 Aging Management of Auxiliary Systems

3.3.2 Staff Evaluation 

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion 

The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6. 

LRA Section 3.3.2.2.6 addresses the loss of material and cracking of Boral spent fuel storage 

racks exposed to a treated water environment due to general corrosion. 
 

3-19 

SRP-LR Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss of 

material due to general corrosion may occur in the neutron-absorbing sheets of BWR and PWR 

spent fuel storage racks exposed to treated water or treated borated water. The GALL Report 

recommends further evaluation of a plant-specific AMP to ensure that these aging effects are 

adequately managed. 

By letter dated February 15, 2011, the applicant revised LRA Section 3.3.2.2.6 to state that: 

Loss of material and cracking are aging effects requiring management for Boral 

spent fuel storage racks exposed to a treated water environment. These aging 

effects are managed by the Water Chemistry Control-BWR Program. 

The Neutron Absorber Monitoring Program manages the reduction in neutronabsorbing capacity and loss of material. 

The staff’s evaluations of the applicant’s Water Chemistry Control-BWR Program and Neutron 

Absorber Monitoring Program are documented in SER Sections 3.0.3.1.11 and 3.0.3.3.9 

respectively. 

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.6 criteria. For those line items that apply to LRA Section 3.3.2.2.6, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

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

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3). 

3.5 Aging Management of SC Supports 

3.5.2 Staff Evaluation

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

3.5.2.3.6 Bulk Commodities Summary of Aging Management Evaluation—LRA Table 3.5.2-6 

In addition to the AMR results documented in the SER dated May 2008 for LRA Table 3.5.2-6, 

by letter dated December 30, 2009, the applicant proposed to manage fiberglass reinforced 

plastic (FRP) material for component types cooling tower vents and louvers exposed to weather 

environment using the Structures Monitoring Program. 

The staff reviewed the applicant’s Structures Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.17. The Structures Monitoring Program is in accordance 

with 10 CFR 50.65 (Maintenance Rule) and based on Regulatory Guide (RG) 1.160 “Monitoring 

the Effectiveness of Maintenance at Nuclear Power Plants,” and Nuclear Management and 

Resources Council (NUMARC) 93-01 ”Industry Guideline for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants.” These two documents provided the guidance for 

development of the Structures Monitoring Program to monitor the condition of structures and 

structural components within the scope of the Maintenance Rule, such that there is no loss of 
 

3-20 

structure or structural component intended function. The line item references Note J and plantspecific Note 505, which states, “aging effects are not expected for fiberglass reinforced plastic 

(FRP). However, the identified AMP will be used to confirm the absence of significant aging 

effects for the period of extended operation.” Since the applicant has credited an appropriate 

aging management program for the period of extended operation, the staff finds these AMR 

results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, and AMP combinations not evaluated in the GALL Report. 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 for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.6 Aging Management of Electrical and Instrumentation and Controls System

3.6.2 Staff Evaluation 

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

3.6.2.3.2 Aging Effect or Mechanism in Table 3.6.1 that are Not Applicable for VYNPS 

The staff documented its review of LRA Table 3.6.1, which provides a summary of aging 

management evaluations for the electrical and instrument and controls (I&Cs) structures and 

components evaluated in the GALL Report, in SER Section 3.6.2.3.2. SER Section 3.6.2.3.2 

states in part that: 

In response to the staff’s concern about not testing inaccessible medium cables 

at [Vernon Hydroelectric Station ] VHS, the applicant, in a letter dated 

March 23, 2007, revised LRA Table 3.6.2-1 and stated that VYNPS will include 

testing of the underground medium-voltage cables at VHS in the Non-EQ 

Inaccessible Medium-Voltage Cable Program. Testing will be performed before 

the extended operation and within 10 -year periods after the initial test. This is 

Commitment No. 43. 

By letters dated September 3 and December 21, 2010, and February 4, 2011, the applicant 

expanded the scope of the Non-EQ Inaccessible Medium-Voltage Program to include lowvoltage (400V to 2kV) inaccessible power cables. In the LRA supplement to the Non-EQ 

Inaccessible Medium-Voltage Program, the applicant revised cable test frequencies to at least 

once every 6 years. As part of this change, the applicant also changed the cable inspection 

frequency for Commitment No. 43 from at least every 10 years to at least once every 6 years. 

The change to Commitment No. 43 is consistent with the LRA supplement changes for LRA 

Sections B.1.17 and A.2.1.19. The change in program scope for the Non-EQ Inaccessible 

Medium-Voltage Program is discussed in SER Section 3.0.3.1.3. 

The remainder of SER Section 3.6.2.3.2 is unaffected by this supplemental SER. 
 
 

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4-1 

SECTION 4 

TIME LIMITED AGING ANALYSIS 

4.3 Metal Fatigue Analyses

4.3.3 Effects of Reactor Water Environment on Fatigue Life 

4.3.3.1 Summary of Technical Information in the Application

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

(SER).

4.3.3.2 Staff Evaluation

SER Section 4.3.3.2 presents the staff’s evaluation of the applicant’s time limited aging analysis 

(TLAA) related to the effects of reactor water environment on fatigue life. The staff’s analysis in 

SER Section 4.3.3.2 was supplemented in SER Supplement 1. The following is the staff’s 

evaluation of additional information provided by the applicant and is supplemental to the 

information provided in the SER and SER Supplement 1. 

By letter dated February 8, 2011, the applicant provided supplemental information regarding its 

environmentally-assisted fatigue (EAF) evaluations to confirm and justify that the plant-specific 

locations listed in LRA Table 4.3-3 are bounding for the generic NUREG/CR-6260 components. 

The applicant stated that, subsequent to LRA submittal, refined and confirmatory analyses were 

completed for the NUREG/CR-6260 components. The applicant also stated that, for each 

NUREG/CR-6260 component, the combination of the cumulative usage factor (CUF) and 

environmental fatigue life correction factor (Fen) was evaluated for each constituent material to 

determine the most limiting CUFen. The applicant discussed that, for example, the low alloy 

steel core spray nozzle, the nickel alloy safe end, and the stainless steel piping associated with 

the core spray nozzle were all evaluated. 

For the reactor vessel shell and lower head, the applicant compared the CUFen of control rod 

drive (CRD) penetration locations to that of the shroud support and confirmed that the CRD 

penetration locations are less limiting than the shroud support. The staff notes that, by letter 

dated January 30, 2008, the applicant provided an updated CUFen of 0.74 for the shroud 

support and the staff compared this to the CUFen of 0.08 for the reactor pressure vessel (RPV) 

vessel shell bottom head. Based on its review, the staff finds that the comparison of CUFen 

values for the shroud support, the RPV vessel shell bottom head, and the CRD penetrations 

supports the applicant’s previous conclusion that the shroud support, with a CUFen of 0.74, 

remains the limiting location for EAF for the reactor vessel shell and bottom head. 

The staff reviewed UFSAR Section 4.8.5 and notes that the residual heat removal system piping 

was designed in accordance with ANSI B31.1. The staff also reviewed UFSAR Section 

11.8.3.10 and notes that the feedwater system piping was designed in accordance with United 
 

4-2 

States of America Standard (USAS) B31.1. The staff notes that ANSI B31.1 and USAS B31.1 

do not require an analysis of cumulative fatigue usage for piping design; instead, secondary 

stresses (e.g., stress due to thermal expansion and anchor movements) are analyzed for fatigue 

using stress intensification factors and stress range allowables to account for thermal cycling. 

However, in order to address EAF, as indicated in the close-out of Generic Safety Issue (GSI)-

190, the applicant, by letter dated September 17, 2007, calculated a CUFen of 0.74 for the 

reactor recirculation (RR) ASME Code Class 1 piping (return tee) and a CUFen of 0.29 for the 

feedwater piping rise to the RPV nozzle to address the effects of reactor water environment. 

Based on these existing fatigue evaluations which include cumulative usage factors, the staff 

finds that the applicant’s previous conclusion conservatively considered a bounding location in 

the residual heat removal system piping and feedwater system piping to address the effects of 

reactor water environment. 

Based on its review, the staff finds the applicant’s conclusion acceptable because the applicant 

reviewed (1) its design basis ASME Code Class 1 fatigue evaluations and its refined and 

confirmatory analyses for its plant-specific NUREG/CR-6260 locations and (2)confirmed and 

justified that its CUFen are bounding for the generic NUREG/CR-6260 components. 

By letter dated February 8, 2011, the applicant also provided supplemental information, 

regarding its EAF evaluations to confirm and justify that the locations selected for EAF analyses 

in LRA Table 4.3-3 are the most limiting locations for the plant. The applicant stated that it 

reviewed the design basis Class 1 fatigue analyses not already addressed as NUREG/CR-6260 

components. The applicant stated that the environmental effects were evaluated for each 

material at the reviewed locations, and the NUREG/CR-6909 methodology was used to obtain 

CUF and Fen values for Alloy 600 materials. The staff finds that the use of NUREG/CR-6909, 

"Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials," for Alloy 600 

materials is acceptable because it incorporates the most recent fatigue data for determining the 

Fen factor for nickel alloys. 

The applicant also stated in the letter dated February 8, 2011, that it did not apply EAF Fen

values to the CUF for the mainsteam outlet nozzle because this location is exposed to dry 

steam, not reactor water, when the plant is in operation. The applicant also stated that EAF Fen

values are also not applied to the closure studs and the refueling bellows because these 

locations are not exposed to the reactor water environment. The staff finds it acceptable that 

the applicant did not apply EAF Fen values to the CUF for the mainsteam outlet nozzle, the 

closure studs, and the refueling bellows because the test data demonstrates that the 

environmental effects on component fatigue life occur when the components are exposed to 

water environment. 

The applicant stated that it evaluated the shroud repair hardware and determined that the 

limiting locations are the Alloy 600 shroud repair rod threaded ends and the shroud support 

plate slotted holes. Furthermore, the stainless steel repair bracket was also evaluated. The 

applicant stated that these items are not part of the reactor coolant pressure boundary. The 

staff notes that, even when the applicant applied conservative Fen factors, the applicant 

calculated CUFen values of less than 0.4 for these locations, which is less than the CUFen of 

0.74 for the shroud support, which is a NUREG/CR-6260 location. 
 

4-3 

The applicant stated that it determined that the closure flange and the CRD return nozzle 

remain exempt from fatigue evaluations in accordance with the requirements in paragraph N415.1 of ASME Code Section III. The staff notes that subparagraphs (a)-(f) of N-415.1, detailing 

the requirements outlined in ASME Code Section III, permit exemption from fatigue analysis. 

The staff notes that this exemption was based on the premise that the stress from pressure, 

temperature, and mechanical loads would not be significant. The staff finds it acceptable that 

the closure flange and the CRD return nozzle are not evaluated for the effects of reactor water 

environment on component fatigue life because these components are exempt from fatigue 

analyses, in accordance with the requirements in paragraph N-415.1 of ASME Code Section III. 

Based on its review, the staff finds the applicant’s conclusion acceptable because (1) the 

applicant confirmed and justified that its CUFen values of its plant-specific NUREG/CR-6260 

locations are bounding for the plant, (2) the applicant considered the effect of different material 

types on Fen in determining the limiting locations, (3) the applicant used the methodology that is 

consistent with NUREG/CR-6909 in the evaluation of Alloy 600 components , and (4) the 

applicant justified that components not exposed to reactor water and components exposed to 

dry steam are not subjected to the effects of reactor coolant environment and (5) it is consistent 

with the recommendations in the GALL AMP X.M1, to consider environmental effects for the 

NUREG/CR-6260 locations, at a minimum. 

4.3.3.3 UFSAR Supplement 

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

4.3.3.4 Conclusion 

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

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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.
 

THIS PAGE INTENTIONALLY LEFT BLANK
6-1 

SECTION 6 

CONCLUSION

The staff concludes that the additional information provided by Entergy Nuclear Operations, 

Inc., does not alter the conclusion stated in the SER and that the requirements of 

10 CFR 54.29(a) have been met. 
A−1 

APPENDIX A 

VYNPS LICENSE RENEWAL COMMITMENTS

During the review of the Vermont Yankee Nuclear Power Station (VYNPS) license renewal application (LRA) by the staff of the US 

Nuclear Regulatory Commission (NRC) (the staff), Entergy Nuclear Operations, Inc. (the applicant) made commitments related to 

aging management programs (AMPs) to manage the aging effects of structures and components prior to the period of extended 

operation. The following table lists these commitments along with the implementation schedules and the sources for each 

commitment.

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

1 Guidance for performing examinations of buried piping will be enhanced to 

specify that coating degradation and corrosion are attributes to be evaluated.

March 21, 2012 B.1.1

2 Fifteen (15) percent of the top guide locations will be inspected using 

enhanced visual inspection technique, EVT-1, within the first 18 years of the 

period of extended operation, with at least one-third of the inspections to be 

completed within the first 6 years and at least two-thirds within the first 12 

years of the period of extended operation. Locations selected for examination 

will be areas that have exceeded the neutron fluence threshold.

As stated in the 

commitment

B.1.7

3 The Diesel Fuel Monitoring Program will be enhanced to ensure ultrasonic 

thickness measurement of the fuel oil storage and fire pump diesel storage 

(day) tank bottom surfaces will be performed every 10 years during tank 

cleaning and inspection.

March 21, 2012 B.1.9
A−2 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

4 The Diesel Fuel Monitoring Program will be enhanced to specify that UT 

measurements of the fuel oil storage tank bottom surface will have 

acceptance criterion in accordance with American Petroleum Institute 

standard API 653 and UT measurements of the fire pump diesel storage (day) 

tank bottom surface will have acceptance criterion in accordance with Steel 

Tank Institute standard STI SP001.

March 21, 2012 B.1.9

5 The Fatigue Monitoring Program will be modified to require periodic update of 

cumulative fatigue usage factors (CUFs), or to require update of CUFs if the 

number of accumulated cycles approaches the number assumed in the 

design calculation. 

March 21, 2012 B.1.11

6 A computerized monitoring program (e.g., FatiguePro) will be used to directly 

determine cumulative fatigue usage factors (CUFs) for locations of interest.

March 21, 2012 B.1.11

7 The allowable number of effective transients will be established for monitored 

transients. This will allow quantitative projection of future margin.

March 21, 2012 B.1.11

8 Procedures will be enhanced to specify that fire damper frames in fire barriers 

will be inspected for corrosion. Acceptance criteria will be enhanced to verify 

no significant corrosion.

March 21, 2012 B.1.12.1

9 Procedures will be enhanced to state that the diesel engine subsystems 

(including the fuel supply line) will be observed while the pump is running. 

Acceptance criteria will be enhanced to verify that the diesel engine did not 

exhibit signs of degradation while it was running; such as fuel oil, lube oil, 

coolant, or exhaust gas leakage.

March 21, 2012 B.1.12.1

10 Fire Water System Program procedures will be enhanced to specify that in 

accordance with NFPA 25 (2002 edition), Section 5.3.1.1.1, when sprinklers 

have been in place for 50 years a representative sample of sprinkler heads 

will be submitted to a recognized testing laboratory for field service testing. 

This sampling will be repeated every 10 years.

March 21, 2012 B.1.12.2
A−3 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

11 The Fire Water System Program will be enhanced to specify that wall 

thickness evaluations of fire protection piping will be performed on system 

components using non-intrusive techniques (e.g., volumetric testing) to 

identify evidence of loss of material due to corrosion/MIC (bio-fouling). These 

inspections will be performed before the end of the current operating term and 

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.

March 21, 2012 B.1.12.2

12 Implement the Heat Exchanger Monitoring Program as described in LRA 

Section B.1.14.

March 21, 2012 B.1.14

13 Implement the Non-EQ Inaccessible Medium-Voltage Cable Program as 

described in LRA Section B.1.17.

Inspections for water accumulation in manholes containing inaccessible lowvoltage and medium-voltage cables with a license renewal intended function 

will be performed at least once every year. Additional condition-based 

inspections of these manholes will be performed based on: a) potentially high 

water table conditions, as indicated by high river level, and b) after periods of 

heavy rain. The inspection results are expected to indicate whether the 

inspection frequency should be modified.

Inaccessible low-voltage cables (400 V to 2 kV) with a license renewal 

intended function are included in this program. Inaccessible low-voltage 

cables will be tested for degradation of the cable insulation prior to the period 

of extended operation and at least once every six years thereafter. A proven, 

commercially available test will be used for detecting deterioration due to 

wetting of the insulation system for inaccessible low-voltage cables.

March 21, 2012 B.1.17
A−4 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

14 Implement the Non-Environmental Qualification Instrumentation Circuits Test 

Review Program as described in LRA Section B.1.18.

March 21, 2012 B.1.18

15 Implement the Non-Environmental Qualification Insulated Cables and 

Connections Program as described in LRA Section B.1.19.

March 21, 2012 B.1.19

16 Implement the One-Time Inspection Program as described in LRA 

Section B.1.21.

March 21, 2012 B.1.21

17 Enhance the Periodic Surveillance and Preventive Maintenance Program to 

assure that the effects of aging will be managed as described in LRA 

Section B.1.22.

March 21, 2012 B.1.22

18 Enhance the Reactor Vessel Surveillance Program to proceduralize the data 

analysis, acceptance criteria, and corrective actions described in the program 

description in LRA Section B.1.24.

March 21, 2012 B.1.24

19 Implement the Selective Leaching Program as described in LRA 

Section B.1.25.

March 21, 2012 B.1.25

20 Enhance the Structures Monitoring Program to specify that process facility 

crane rails and girders, condensate storage tank (CST) enclosure, CO2 tank 

enclosure, N2 tank enclosure and restraining wall, CST pipe trench, diesel 

generator cable trench, fuel oil pump house, service water pipe trench, 

man-way seals and gaskets, and hatch seals and gaskets are included in the 

program.

March 21, 2012 B.1.27.2

21 Guidance for performing structural examinations of wood to identify loss of 

material, cracking, and change in material properties will be added to the 

Structures Monitoring Program.

March 21, 2012 B.1.27.2
A−5 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

22 Guidance for performing structural examinations of elastomers (seals and 

gaskets) to identify cracking and change in material properties (cracking when 

manually flexed) will be enhanced in the Structures Monitoring Program 

procedure.

March 21, 2012 B.1.27.2

23 Guidance for performing structural examinations of PVC cooling tower fill to 

identify cracking and change in material properties will be added to the 

Structures Monitoring Program procedure.

March 21, 2012 B.1.27.2

24 System walkdown guidance documents will be enhanced to perform periodic 

system engineer 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). lnspections shall include areas surrounding the subject 

systems to identify hazards to those systems. lnspections of nearby systems 

that could impact the subject system 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).

March 21, 2012 B.1.28

25 Implement the Thermal Aging and Neutron Irradiation Embrittlement of Cast 

Austenitic Stainless Steel (CASS) Program as described in LRA 

Section B.1.29.

March 21, 2012 B.1.29

26 Procedures will be enhanced to flush the John Deere Diesel Generator 

cooling water system and replace the coolant and coolant conditioner every 

three years.

March 21, 2012 B.1.30.1
A−6 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

27 At least 2 years prior to entering the period of extended operation, for the 

locations identified in NUREG/CR-6260 for BWRs of the VY vintage, VY will 

refine our current fatigue analyses to include the effects of reactor water 

environment and verify that the cumulative usage factors (CUFs) are less 

than 1. This includes applying the appropriate Fen factors to valid CUFs 

determined in accordance with one of the following:

1. For locations, including NUREG/CR-6260 locations, with existing fatigue 

analysis valid for the period of extended operation, use the existing CUF to 

determine the environmentally adjusted CUF.

2. More limiting VY-specific locations with a valid CUF may be added in 

addition to the NUREG/CR-6260 locations.

3. Representative CUF values from other plants, adjusted to or enveloping 

the VY plant-specific external loads may be used if demonstrated applicable 

to VY.

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.

During the period of extended operation, VY may also use one of the 

following options for fatigue management if ongoing monitoring indicates a 

potential for a condition outside the analysis bounds noted above:

(1) Update and/or refine the affected analyses described above.

(2) Implement an inspection program that has been reviewed and approved 

by the NRC (e.g., periodic nondestructive examination of the affected 

locations at inspection intervals to be determined by a method acceptable to 

the NRC). 

(3) Repair or replace the affected locations before exceeding a CUF of 1.0.

March 21, 2012

March 21, 2010 

for performing a 

fatigue analysis 

that addresses 

the effects of 

reactor coolant 

environment on 

fatigue (in 

accordance with 

an NRC 

approved version 

of the ASME 

Code)

A.2.2.3/B.1.11

28 Revise program procedures to indicate that the Instrument Air Program will 

maintain instrument air quality in accordance with ISA S7.3

March 21, 2012 B.1.16
A−7 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

29 VYNPS will perform one of the following:

1. Install core plate wedges, or,

2. Complete a plant-specific analysis to determine acceptance criteria 

for continued inspection of core plate hold down bolting in accordance 

with BWRVIP-25 and submit the inspection plan and analysis to the 

NRC one year prior to the period of extended operation for NRC 

review and approval.

March 21, 2012 B.1.7

30 Revise System Walkdown Program to specify CO2 system inspections every 

6 months.

March 21, 2012 B.1.28

31 Revise Fire Water System Program to specify annual fire hydrant gasket 

inspections and flow tests.

March 21, 2012 B.1.12.2

32 Implement the Metal Enclosed Bus Program.

Details are provided in an LRA Amendment 16, Attachment 3 and LRA 

Amendment 23, 7.

March 21, 2012 B.1.32

33 Include within the Structures Monitoring Program provisions that will ensure 

an engineering evaluation is made on a periodic basis (at least once every 

five years) of groundwater samples to assess aggressiveness of groundwater 

to concrete. Samples will be monitored for sulfates, pH and chlorides.

March 21, 2012 B.1.27

34 Implement the Bolting Integrity Program.

Details are provided in an LRA Amendment 16, Attachment 2 and LRA 

Amendment 23, Attachment 5.

March 21, 2012 B.1.31

35 Provide within the System Walkdown Training Program a process to 

document biennial refresher training of Engineers to demonstrate inclusion of 

the methodology for aging management of plant equipment as described in 

EPRl Aging Assessment Field Guide or comparable instructional guide.

March 21, 2012 B.1.28
A−8 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

36 If technology to inspect the hidden jet pump thermal sleeve and core spray 

thermal sleeve welds has not been developed and approved by the NRC at 

least two years prior to the period of extended operation, VYNPS will initiate 

plant-specific action to resolve this issue. That plant-specific action may be 

justification that the welds do not require inspection.

March 21, 2010 B.1.24

37 Continue inspections in accordance with the steam dryer monitoring plan, 

Revision 3 in the event that the BWRVIP-139 is not approved prior to the 

period of extended operation.

March 21, 2010 B.1.24

38 The BWRVIP-116 report which was approved by the Staff will be 

implemented at VYNPS with the conditions documented in Sections 3 and 4 

of the Staff's final SE dated March 1, 2006, for the BWRVIP-116 report.

March 21, 2012 B.1.24

39 If the VYNPS standby capsule is removed from the reactor vessel without the 

intent to test it, the capsule will be stored in a manner which maintains it in a 

condition which would permit its future use, including during the period of 

extended operation, if necessary.

March 21, 2012 B.1.24

40 This Commitment has been deleted and replaced with Commitment 43 N/A N/A

41 This Commitment has been deleted and replaced with Commitment 43 N/A N/A

42 Implement the Bolted Cable Connections Program. Details are provided in 

LRA Amendment 23, Attachment 7.

March 21, 2012 B.1.33

43 Establish and implement a program that will require testing of the two 13.8 kV 

cables from the two Vernon Hydro Station 13.8 kV switchgear buses to the 

13.8 kV / 69 kV step up transformers before the period of extended operation 

and at least once every 6 years after the initial test.

March 21, 2012 B.1.17

44 This Commitment has been deleted and replaced with Commitment 54. N/A N/A
A−9 

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

45 Enhance the Service Water Integrity Program to require a periodic visual 

inspection of the RHRSW pump motor cooling coil internal surface for loss of 

material.

March 21, 2012 B.1.26

46 Enhance the Diesel Fuel Monitoring Program to specify that fuel oil in the fire 

pump diesel storage (day) tank will be analyzed according to ASTM D975 and 

for particulates per ASTM D2276. Also, fuel oil in the John Deere diesel 

storage tank will be analyzed for particulates per ASTM D2276.

March 21, 2012 B.1.9

47 Enhance the Diesel Fuel Monitoring Program to specify that fuel oil in the 

common portable fuel oil storage tank will be analyzed according to ASTM 

D975, per ASTM D2276 for particulates, and per ASTM D2709 for water and 

sediment.

March 21, 2012 B.1.9

48 Perform an internal inspection of the underground Service Water piping 

before entering the period of extended operation. 

March 21, 2012 B.1.1

49 Revise station procedures to specify fire hydrant hose testing, inspection, and 

replacement, if necessary, in accordance with NFPA code specifications for 

fire hydrant hoses.

March 21, 2012 B.1.12

50 During the period of extended operation, review the Vernon Dam owner 

FERC required report(s) at a minimum of every five years to confirm that the 

Vernon Dam owner is performing the required FERC inspections. Document 

deficiencies in the Entergy Corrective Actions Program and evaluate 

operability as described in BVY 96-043 and BVY 97-043 if it is determined 

that the required inspections are not being performed.

March 21, 2012 B.1.27.3

51 Entergy will perform an evaluation of operating experience at extended power 

uprate (EPU) levels prior to the period of extended operation to ensure that 

operating experience at EPU levels is properly addressed by the aging 

management programs. The evaluation will include Vermont Yankee (VY) 

and other BWR plants operating at EPU levels.

March 21, 2012 B.1.31
A−10

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

52 Implement the Neutron Absorber Monitoring Program as described in LRA 

Section B.1.31. 

Test one coupon prior to the PEO to measure B-10 areal density and assess 

the geometric and physical condition of the tested coupon. If coupons are not 

able to be retrieved and tested or if coupons cannot be demonstrated 

representative of the Boral in the Holtec racks, then perform neutron 

attenuation testing using in-situ methods, as described in BVY 11-010, 

(BADGER or blackness testing method) prior to the end of 2014.

March 21, 2012 B.1.31

53 During the period of extended operation, VYNPS will perform periodic 

volumetric examinations of small-bore Class 1 socket and butt welds. The 

examinations will include 10% of the Class 1 weld population greater than or 

equal to 1 and less than 4 inch NPS up to a total of 25 welds of each weld 

type. In lieu of a volumetric examination for socket welds, a destructive 

examination may be performed. Each destructive exam will be equivalent to 

two ultrasonic examinations when determining the number of completed 

inspections. The examination method will be a volumetric examination of the 

base and weld metal using a demonstrated ultrasonic examination technique. 

Inspection results will determine the need for additional or periodic 

examinations. The examinations will be performed by December 2016.

March 21, 2012 B.1.21
A−11

Number Commitment Enhancement or 

Implementation 

Schedule

LRA Section

54 Prior to the PEO, VYNPS will inspect portions of the standby gas treatment 

system buried piping. The inspections will consist of direct visual examination 

of a minimum of two sections of piping and cover the entire circumference of 

at least ten linear feet of piping in each section. 

During the PEO, inspections of two carbon steel piping segments in the 

standby gas treatment system and four carbon steel piping segments in the 

service water system will be performed every 10 years if measured soil 

resistivity is > 20,000 ohm-cm and the soil corrosivity index is 10 or less using 

AWWA C105. If the soil resistivity is < 20,000 ohm-cm or the soil corrosivity 

index is higher than 10 points using AWWA C105, the number of inspections 

of the standby gas treatment system buried piping will be increased to three 

and the number of inspections of the service water system buried piping will 

be increased to six. Each of these direct visual inspections following 

excavation will cover the entire circumference of at least ten linear feet of 

piping. 

During the PEO, two inspections covering at least 8% of the total length of inscope buried fuel oil piping (~40 feet) will be performed at least once every 10 

years. If the soil resistivity is < 20,000 ohm-cm or the soil corrosivity index is 

higher than 10 points using AWWA C105, the percentage of fuel oil buried 

piping inspected will be increased to 12%.

Soil samples will be taken prior to the period of extended operation and at 

least once every 10 years thereafter to confirm the initial sample results.

March 21, 2012 B.1.1
B–1 

APPENDIX B 

CHRONOLOGY

This appendix contains a chronological listing of the licensing correspondence between the staff 

of the U.S. Nuclear Regulatory Commission and Entergy Nuclear Operations, Inc. This 

appendix updates the correspondence regarding the staff’s review of the Vermont Yankee 

Nuclear Power Station license renewal application (under Docket No. 50-271) since the 

publication of Supplement 1 to NUREG-1907 in October 2009. 

CHRONOLOGY

Date Subject

September 30, 2009 NUREG-1907 "Safety Evaluation Report Related to the License 

Renewal of Vermont Yankee Nuclear Power Station," 

Supplement 1 (ML092740567)

December 30, 2009 License Renewal Application Annual Update Vermont Yankee 

Nuclear Power Station Docket No. 50-271 License No. DPR-28 

(BVY 09-073) (ML100050072)

September 3, 2010 Audit Report Regarding the Vermont Yankee Nuclear Power 

Station License Renewal Application (TAC NO. MC9668)

(ML102070412)

September 30, 2010 License Renewal Application Supplemental Information Vermont 

Yankee Nuclear Power Station Docket No. 50-271 License No. 

DPR-28 (BVY 10-050) (ML102500065)

October 14, 2010 License Renewal Application Supplemental Information Vermont 

Yankee Nuclear Power Station Docket No. 50-271 License No. 

DPR-28 (BVY 10-052) (ML102920153)

December 21, 2010 License Renewal Application Supplemental Information Vermont 

Yankee Nuclear Power Station Docket No. 50-271 License No. 

DPR-28 (BVY 10-058) (ML103630357)

December 30, 2010 License Renewal Application Annual Update Vermont Yankee 

Nuclear Power Station Docket No. 50-271 License No. DPR-28 

(BVY 10-069) (ML110040117)

February 4, 2011 License Renewal Application Supplemental Information Vermont 

Yankee Nuclear Power Station Docket no. 50-271 License No. 

DPR-27 (BVY 11-007) (ML110400114)

February 4, 2011 License Renewal Application Supplemental Information Vermont 

Yankee Nuclear Power Station Docket no. 50-271 License No. 

DPR-27 (BVY 11-010) (ML110400113)

February 8, 2011 License Renewal Application Supplemental Information Vermont 

Yankee Nuclear Power Station Docket no. 50-271 License No. 

DPR-27 (BVY 11-012) (ML110460051)

February 10, 2011 License Renewal Application Supplemental Information Vermont 

Yankee Nuclear Power Station Docket No. 50-271 License No. 

DPR-28 (BVY 11-013) (ML110490053)