A Summary of Aging Effects 

and Their Management in 

Reactor Spent Fuel Pools, 

Refueling Cavities, Tori, and 

Safety-Related Concrete 

Structures

Office of Nuclear Reactor Regulation

NUREG/CR-7111

ORNL/TM-2011/410
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A Summary of Aging 

Effects and Their 

Management in Reactor 

Spent Fuel Pools, 

Refueling Cavities, Tori, 

and Safety-Related 

Concrete Structures

Manuscript Completed: November 2011

Date Published: January 2012

Prepared by:

D.A. Copinger,1 C.B. Oland,2 and D.J. Naus1

1 Oak Ridge National Laboratory

 Managed by UT-Battelle, LLC

 Oak Ridge, TN 37831-6165

2 XCEL Engineering

 1066 Commerce Park Drive

 Oak Ridge, TN 37830-8026

A.H. Sheikh and A. Prinaris, NRC Program Managers

Office of Nuclear Reactor Regulation

NUREG/CR-7111

ORNL/TM-2011/410

iii

ABSTRACT

The Oak Ridge National Laboratory conducted an independent review of operating experience 

at U.S. commercial nuclear power plants regarding spent fuel pool and reactor cavity leakage, 

boiling-water reactor Mark I containment torus corrosion and cracking, and aging degradation of 

safety-related concrete structures. The review was restricted to information in publicly available 

sources, including license renewal applications submitted by the licensees and safety evaluation 

reports prepared by the staff. Information compiled for spent fuel pool and reactor refueling 

cavity leakage focused on the cause and extent of leakage, the effects of borated water on 

materials, the effects on concrete and steel degradation, corrective actions, and the effects of 

material degradation on load-carrying capacity. The review of boiling-water reactor Mark I 

containment information involved identification of the causes of torus corrosion and cracking, 

the locations of corrosion and cracking, and engineering evaluations and acceptance criteria. 

The review of operating experience for age-related degradation of concrete structures 

concentrated on corrosion; loss of prestressing force; concrete cracking, scaling, and spalling,

including freeze-thaw; loss of bond between the concrete and embedded steel reinforcement; 

loss of strength; and increase in porosity and permeability. The results of the review are 

summarized in a series of degradation occurrence tables and discussed in plant-specific case 

studies.

v

CONTENTS

Page

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

LIST OF FIGURES .................................................................................................................... ix

LIST OF TABLES....................................................................................................................... xi

EXECUTIVE SUMMARY ......................................................................................................... xiii

ACKNOWLEDGMENTS...........................................................................................................xvii

ABBREVIATIONS AND ACRONYMS ...................................................................................... xix

1. INTRODUCTION................................................................................................................1

1.1 Purpose.....................................................................................................................1

1.2 Background ...............................................................................................................1

1.2.1 Project History................................................................................................1

1.2.2 Project-Related Documents ...........................................................................3

1.3 Program Description..................................................................................................4

1.3.1 Leakage from the Reactor Refueling Cavity ..................................................4

1.3.2 Spent Fuel Pool Leakage...............................................................................4

1.3.3 Torus Corrosion and Cracking in the Boiling-Water Reactor Mark I 

Containment...................................................................................................4

1.3.4 Age-Related Degradation in Concrete Safety-Related Structures ..................5

2. AGING MANAGEMENT PRACTICES AND PROGRAMS ..................................................7

2.1 Aging Management Practices ....................................................................................7

2.2 Known Problem Areas ...............................................................................................7

2.2.1 ASME Boiler and Pressure Vessel Code, Section XI,

Subsection IWE..............................................................................................7

2.2.2 ASME Boiler and Pressure Vessel Code, Section XI,

Subsection IWL..............................................................................................9

2.2.3 Structures Monitoring Program.....................................................................10

2.2.4 Regulatory Guide 1.127 ...............................................................................10

2.2.5 Protective Coating Monitoring and Maintenance Program............................11

3. DATA ACQUISITION .......................................................................................................13

3.1 Introduction..............................................................................................................13

3.2 Operating Experience Data Acquisition....................................................................13

3.2.1 Licensee Event Reports ...............................................................................13

3.2.2 NRC Generic Communications ....................................................................15

3.2.3 NRC Reports................................................................................................16

3.2.4 NRC Guides.................................................................................................17

3.2.5 NRC Publications .........................................................................................18

3.3 Selected Licensee Inspection Reports.....................................................................18

3.4 License Renewal Applications and Safety Evaluation Reports.................................19

3.4.1 License Renewal Applications......................................................................19

3.4.2 NRC Safety Evaluation Reports of License Renewal Applications ...............19

3.5 Sorting and Binning of Data .....................................................................................19

4. DATA SORTING AND SELECTION FOR FURTHER ANALYSIS .......................................23

4.1 Subject Matter Expert Sorting and Binning ..............................................................23
vi

4.2 Events Discarded after Subject Matter Expert Sorting .............................................23

4.3 Summary of Data Sorting Results for Further Analysis ............................................24

5. PRESENTATION FORMAT AND SUMMARY OF DEGRADATION OCCURRENCES........27

5.1 Format for Summary Presentation of Results ..........................................................27

5.2 Degradation Occurrence Summary..........................................................................28

5.2.1 Leakage from the Reactor Refueling Cavity .................................................28

5.2.2 Spent Fuel Pool Leakage.............................................................................29

5.2.3 Torus Corrosion and Cracking......................................................................29

5.2.4 Concrete Age-Related Degradation..............................................................29

5.3 Case Studies ...........................................................................................................29

6. REVIEW OF DEGRADATION OCCURRENCES ................................................................53

6.1 Introduction..............................................................................................................53

6.2 Leakage from the Reactor Refueling Cavity.............................................................53

6.3 Spent Fuel Pool Leakage.........................................................................................54

6.4 Torus Corrosion and Cracking .................................................................................55

6.5 Age-Related Degradation of Concrete Structures ....................................................56

7. SUMMARY AND CONCLUSIONS AND TOPICS FOR FURTHER CONSIDERATION .......85

7.1 Summary and Conclusions ......................................................................................85

7.1.1 Reactor Refueling Cavity Leakage ...............................................................85

7.1.2 Spent Fuel Pool Leakage.............................................................................86

7.1.2.1 Effect of Borated Water on Materials .............................................87

7.1.2.2 Extent of Concrete and Steel Degradation.....................................88

7.1.3 Torus Corrosion and Cracking......................................................................88

7.1.4 Age-Related Degradation of Reinforced Concrete Structures.......................88

7.2 Topics for Further Consideration..............................................................................89

7.2.1 Reactor Refueling Cavity and Spent Fuel 

Pool Leakage...............................................................................................90

7.2.2 Torus Corrosion and Cracking......................................................................91

7.2.3 Concrete Age-Related Degradation..............................................................92

8. REFERENCES....................................................................................................................95

APPENDIX A: LEAKAGE FROM THE REACTOR REFUELING CAVITY CASE STUDIES... A -1

A.1 Browns Ferry Nuclear Plant, Units 2 and 3 ........................................................... A -1

A.2 Hope Creek Generating Station, Unit 1................................................................. A -5

A.3 Indian Point Nuclear Generating Unit 2............................................................... A -11

A.4 Kewaunee Power Station.................................................................................... A -15

A.5 Oyster Creek Nuclear Generating Station........................................................... A -19

A.6 Prairie Island Nuclear Generating Plant, Units 1 and 2 ....................................... A -25

A.7 Salem Nuclear Generating Station, Units 1 and 2............................................... A -33

APPENDIX B: SPENT FUEL POOL LEAKAGE CASE STUDIES.......................................... B -1

B.1 Crystal River Nuclear Generating Plant, Unit 3 ..................................................... B -1

B.2 Davis-Besse Nuclear Power Station, Unit 1 .......................................................... B -3

B.3 Diablo Canyon Power Plant, Units 1 and 2 ........................................................... B -5

B.4 Duane Arnold Energy Center................................................................................ B -7

B.5 Hope Creek Generating Station, Unit 1................................................................. B -9

B.6 Indian Point Nuclear Generating Unit 2............................................................... B -11
vii

B.7 Kewaunee Power Station.................................................................................... B -19

B.8 Palo Verde Nuclear Generating Station, Unit 1................................................... B -23

B.9 Salem Nuclear Generating Station, Units 1 and 2............................................... B -27

APPENDIX C: BOILING-WATER REACTOR MARK I CONTAINMENT—TORUS CORROSION 

AND CRACKING CASE STUDIES.........................................................................................C -1

C.1 Cooper Nuclear Station ........................................................................................C -1

C.2 Duane Arnold Energy Center................................................................................C -7

C.3 James A. FitzPatrick Nuclear Power Plant..........................................................C -11

C.4 Hope Creek Generating Station, Unit 1...............................................................C -13

C.5 Nine Mile Point Nuclear Station, Unit 1 ...............................................................C -15

C.6 Oyster Creek Nuclear Generating Station...........................................................C -17

C.7 Pilgrim Nuclear Power Station ............................................................................C -21

ix

LIST OF FIGURES

Page

6-1 Cross section of BWR MK I showing location of reactor refueling cavity,

spent fuel pool, and torus as well as one leakage path that has

been observed...............................................................................................................60

6-2 Detail of drywell—reactor cavity seal area and 

identification of potential leakage path...........................................................................60

6-3 Plan view of fuel-handling building showing relative location 

of spent fuel pool, transfer pool, and containment building. ...........................................61

6-4 Cross section of a leak chase system for a PWR plant and a 

postulated path for leakage occurrence.........................................................................61

6-5 Cross section of BWR suppression chamber torus........................................................62

6-6 Trojan nuclear power plant posttensioned concrete containment...................................62

6-7 Summary of degradation occurrences reported

in NUREG/CR-6679 related to nuclear power plant concrete structures,

including associated metal subcomponents...................................................................63

A.2-1 Cross section of reactor building and Mark I containment............................................ A-8

A.2-2 Locations of reactor cavity seal and J13 penetration areas.......................................... A-8

A.2-3 Cross section of reactor cavity seal area. .................................................................... A-9

A.2-4 Cross section of lower drywell area. ............................................................................ A-9

A.5-1 Drywell and reactor cavity section. ............................................................................ A-23

A.5-2 Drywell to reactor cavity seal detail............................................................................ A-24

A.6-1 Potential leakage paths for refueling cavity water. ..................................................... A-29

A.6-2 Locations of observed leakage of refueling cavity water. ........................................... A-30

A.6-3 Cross section of original embedment plate configuration

showing potential leakage paths................................................................................ A-30

A.6-4 Cross section of repair approach for embedded plates.............................................. A-31

A.6-5 Condition of containment shell, grout, and concrete steel reinforcement

In Unit 1 ECCS after grout removal. .......................................................................... A-31

B.9-1 Spent fuel pool leakage path for Salem Unit 1 before 2003. ...................................... B-32

B.9-2 Current spent fuel pool leakage path for Salem Unit 1............................................... B-32

C.1-1 Example of pitting corrosion in torus............................................................................C-4

C.1-2 Example of repair of pitting corrosion in torus..............................................................C-5

C.1-3 Example of pitting corrosion concentrations in torus ....................................................C-5

xi

LIST OF TABLES

Page

3-1 Data Acquisition...........................................................................................................21

4-1 Summary of Results by Nuclear Power Plant...............................................................25

4-2 Summary of Data Sorting and Analysis Results ...........................................................26

5-1 Degradation Occurrence Summary: Leakage from Reactor Refueling Cavity .............30

5-2 Degradation Occurrence Summary: Spent Fuel Pool Leakage ...................................36

5-3 Degradation Occurrence Summary: Torus Corrosion and Cracking ............................42

5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation....................46

6-1 Leakage from Reactor Refueling Cavity—Summary of 

Information Contained in Appendix A...........................................................................64

6-2 Leakage from Spent Fuel Pool—Summary of

Information Contained in Appendix B...........................................................................69

6-3 Torus Corrosion and Cracking—Summary of

Information Contained in Appendix C...........................................................................74

6-4 Age-Related Degradation of Concrete .........................................................................78

C.1-1 Example of Torus Inspection Criteria .........................................................................C-4

xiii

EXECUTIVE SUMMARY

As nuclear plants age, degradations of spent fuel pools (SFPs), reactor refueling cavities, and 

the torus structure of light-water reactor nuclear power plants (NPPs) are occurring at an 

increasing rate, primarily due to environment-related factors. During the last decade, a number 

of NPPs have experienced water leakage from the SFPs and reactor refueling cavities. In 

addition, since 2000, applications for license renewals have noted several cases of corrosion in 

boiling-water reactor (BWR) Mark I torus steel structures. Age-related concrete degradation has 

also been identified. 

What is interesting about these structures is that it is often hard to assess their in situ condition 

because of accessibility problems. For example, the external portion of tori is partially exposed 

and, internally, underwater divers are used periodically to evaluate the prevailing aging effects 

in the pressure-suppression chamber. Similarly, a portion of the listed concrete structures are 

either buried or form part of other structures or buildings, or their external surfaces are invisible 

because they are covered with liners. Historically, the U.S. Nuclear Regulatory Commission

(NRC) monitored their performance and, when appropriate, issued information notices (INs),

including IN 2003-08, IN 2004-05, IN 2006-01, and IN 2011-15 to address and update NPP 

owners about leakage of SFPs and reactor refueling cavities and corrosion of BWR tori.

The Oak Ridge National Laboratory (ORNL), on its part, prepared NUREG/CR-6927, ―Primer on 

Durability of Nuclear Power Plant Reinforced Concrete Structures—A Review of Pertinent 

Factors,‖ issued February 2007, that provides a discussion of concrete durability and the 

relationship between durability and performance, a review of the historical perspective related to 

concrete and longevity, a description of the basic materials that comprise reinforced concrete, 

information on the environmental factors that can impact the performance of NPP concrete 

structures, and a brief history of NPP concrete structures operating experience. 

The objectives of this NUREG document (NUREG/CR-7111) are to (1) identify the cause, 

extent, and effect of leakage from deteriorated seals between the refueling cavity and reactor 

cavity areas, and/or leakage through stainless steel weld seams or through stainless steel base 

metal, (2) identify the cause, extent, and effect of leakage from BWR and pressurized-water 

reactor SFPs through the stainless steel weld seams or through the stainless steel base metal, 

and field activities that were performed to address the leakage, (3) identify possible causes of 

corrosion of the torus of different BWR Mark I plants, including locations and remedial actions,

(4) provide an update on operating experience with respect to NPP reinforced concrete 

structures, (5) summarize mitigating actions (see Chapters 2 and 6) of the industry to manage 

or rectify issues associated with aging effects because of Objectives 1, 2, and 3 above, thus 

extending the safe operating life of NPPs, and, last but not least, (6) extend past studies and 

efforts (see Chapters 1 and 2 and Appendices A, B, and C) to serve as a precursor for the 

industry to identify degradation scenarios that potentially could dominate in the future (e.g., the 

impacts of historical water leakage on the structural integrity of SFPs and refueling cavity liners 

and associated concrete structures). 

The identification of the cause, extent, effects, mitigation, and management of the resulting 

aging effects of leakage from SFPs and reactor refueling cavities, corrosion and cracking of the 

torus structure of light-water reactors, and degradation of safety-related concrete structures are 

considered critical subjects that impact license renewals. This summary of findings spanning 

from 1997 to about mid-2010 reviews past performance and presents the current state of 

increased watchfulness for these structures and components and the bulk materials used for the 
xiv

period of extended operation. It provides an impetus that could help draft additional or 

advanced inspection, monitoring, evaluation techniques, technology development, and aging 

management programs to support the identification of emerging modes of degradation and the 

future generation of aging-effects management for the continued safe operation of the legacy 

NPP fleet, thus fulfilling the NRC‘s mission. Such modes of degradation, for example, may 

surface in reinforced concrete structures where the composite material could be negatively 

impacted by adverse environments of borated water or where there is the possibility of alkali 

aggregate material reactivity. For the torus structure, the continuous undetected pitting 

corrosion translates into potential reduction of the capacity of the structure to resist the loading 

conditions to which it has been designed, including an increased sensitivity to buckling.

In brief, the chapter contents are as follows: 

Chapter 1 offers the reader introductory, background material that includes relatively recent 

related projects that have been conducted at ORNL and regulatory historical documentation of 

interest. This chapter also provides a brief discussion of the topics of interest as identified in 

Objectives 1–4 noted above.

Chapter 2 presents background material related to aging management practices and programs. 

The ―Maintenance Rule‖ and its objective are identified. The chapter also identifies several 

known problem areas and actions taken by the NRC to address these areas (e.g., adoption of 

American Society of Mechanical Engineers Boiler and Pressure Vessel Code Section XI,

Subsections IWE and IWL; publication of NUREG-1522, ―Assessment of Inservice Conditions of 

Safety-Related Nuclear Plant Structures,‖ issued June 1995, and Regulatory Guide 1.127,

Revision 1, ―Inspection of Water Control Structures Associated With Nuclear Power Plants,‖

issued March 1978; and programs that address protective coating and monitoring).

Chapter 3 links the current effort to previous degradation occurrence studies and outlines the 

data acquisition process. Information sources included publicly available documents related to 

operating experience (e.g., licensee event reports, NRC generic communications, NRC 

preliminary notification reports, NRC interim staff guidance, and NRC regulatory guides), NRC 

NUREGs, licensee inspection reports, license renewal applications, and NRC safety evaluation 

reports for license renewal applications. These information sources were screened, and reports 

that appeared to contain information related to one of the four topics of interest were binned 

(i.e., grouped) into the appropriate topic of interest for more detailed review.

Chapter 4 addresses the procedure utilized to further examine the information identified during 

the initial data acquisition process and to select reports for more detailed assessment. As a 

result of this process, 11, 12, 7, and 26 potential information sources were identified related to 

reactor refueling cavity leakage, SFP leakage, torus corrosion and cracking, and age-related 

concrete degradation, respectively.

Chapter 5 describes the presentation format and provides a table that summarizes the 

information with respect to the four topics of interest in terms of the identified NPPs (including 

plant type and occurrence date), structures affected, components impacted, construction 

materials, aging effects, aging mechanisms, environments, and types of source documents

used to obtain the information. When sufficient information was available, a case study was 

prepared for a degradation occurrence listed in the summary table, followed by more detailed 

presentations in Appendices A, B, and C for the reactor refueling cavity, SFP, and torus 

corrosion and cracking, respectively. Seven, nine, and seven case studies were abridged for 

the reactor refueling cavity, SFP, and torus corrosion and cracking, respectively.
xv

Chapter 6 includes brief descriptions of reactor refueling cavities, SFPs, and torus structures. It 

provides an outline of degradation occurrences and how these are addressed during the period 

of extended operation. The chapter also discusses the degradation sources, how they have 

been identified, inspections performed, corrective actions taken, and pertinent structural integrity 

assessments. Case studies for each of these topics of interest are then reviewed, and the 

results are presented here in an abbreviated form with respect to the specific areas of interest 

grouped by plant type. In addition, this chapter provides a review of age-related degradation of 

concrete structures and addresses the methodology used by the licensees to identify the 

concrete degradation and the approaches and procedures used to address, manage the aging 

effects of (see also Chapter 2), and resolve, where applicable, the identified issues. 

Chapter 7 provides a summary and general conclusions derived as a result of the review of 

occurrences of degradation of SFPs, reactor refueling cavities, the torus structure, and 

safety-related concrete structures of light-water reactor NPPs. Topics for further consideration 

are also identified in this chapter.

Appendices A, B, and C provide case studies of leakages of SFPs and reactor cavities, and 

BWR Mark I containment torus corrosion and cracking for selected plants, based on the staffs‘ 

contributions to the safety evaluation reports and the Advisory Committee on Reactor 

Safeguards reviews during public meetings for license renewal. Although several occurrences 

of degradation were identified, sufficient information was not available to develop a statistically

significant trend indicating that reactor refueling cavity, SFP, torus shell, or concrete structure 

degradation was more prevalent for a particular nuclear steam supply system supplier, 

engineering firm, or constructor. 

Throughout the text, the selection of degradation occurrences involved identification of aging 

effects from publicly available documents, followed by associated aging mechanisms and 

environments. The grouping of degradations and how they are dealt with for the continuous 

safe operation of NPPs is expected to facilitate current and future efforts in license renewals. 

Consistency and clarity in presentation of information was maintained to the extent possible 

throughout the report.

xvii

ACKNOWLEDGMENTS

The authors thank Mr. W.P. Poore, Advanced Reactor Systems and Safety Group at Oak Ridge 

National Laboratory, for his assistance in accessing and identifying degradation occurrences 

contained in the various operating experience databases, licensee event report databases, and 

other U.S. Nuclear Regulatory Commission reports.

The authors would also like to thank Dr. Andrew Prinaris, Office of Nuclear Reactor Regulation, 

Division of License Renewal, U.S. Nuclear Regulatory Commission, for his input, fruitful 

discussions, and his many helpful comments and suggestions that improved the quality of the 

report.

xix

ABBREVIATIONS AND ACRONYMS

3-D three dimensional

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ADAMS Agencywide Documents Access and Management System (NRC)

AL administrative letter (NRC)

ALARA as low as reasonably achievable

AMP aging management program

ANSI American National Standards Institute

ASME American Society of Mechanical Engineers

ASME Code ASME Boiler and Pressure Vessel Code

B&W Babcock & Wilcox

BFN Browns Ferry Nuclear

BNL Brookhaven National Laboratory

BWR boiling-water reactor

BWR/1–6 boiling-water reactor/design phase 1, 2, 3, 4, 5, or 6 

c-c center-to-center

CE Combustion Engineering

CFR Code of Federal Regulations

CL centerline

CLB current licensing basis

cm centimeter(s)

CS carbon steel

DBA design-basis accident

DBE design-basis earthquake

DG draft regulatory guide

DLR Division of License Renewal (NRC)

DOD Degradation Occurrence Database

DOT Degradation Occurrence Table

dpm drop(s) per minute

ECCS emergency core cooling system

EN event notification

EPRI Electric Power Research Institute

ENS Emergency Notification System (NRC)

FHB fuel-handling building

GALL generic aging lessons learned

GE General Electric

GL generic letter (NRC)

gpd gallon(s) per day

gph gallon(s) per hour

gpm gallon(s) per minute

HPCI high-pressure coolant injection

HVAC heating, ventilation, and air conditioning

HX heat exchanger

IE inspection enforcement

IN information notice (NRC)

 

 A complete list of abbreviations used by the NRC is provided in NUREG-0544, Revision 4, ―NRC Collection of 

Abbreviations,‖ issued July 1998.
xx

IR industry report

ISI inservice inspection

LER licensee event report (NRC)

LRA license renewal application

LR-ISG license renewal interim staff guidance

m meter(s)

m

3

cubic meter(s)

m

3

/s cubic meter(s) per second

mL milliliter(s)

mL/m milliliter(s) per minute

mm millimeter(s)

mPa megapascal(s)

MK Mark

NDE nondestructive examination

NEI Nuclear Energy Institute

NPP nuclear power plant

NPPD Nebraska Public Power District

NRC U.S. Nuclear Regulatory Commission

NUMARC Nuclear Management and Resources Council

NUREG NRC technical report designation

NUREG/CR NUREG contractor report

OAR owner‘s activity report

ORNL Oak Ridge National Laboratory

PER problem evaluation report

PNO preliminary notification report (NRC)

ppm part(s) per million

PSC pressure-suppression chamber

PSEG PSEG Nuclear, LLC

psi pound(s) per square inch

PWR pressurized-water reactor

RAI request for additional information

RCS reactor coolant system

RD radioactive waste drain

RFC reactor refueling cavity

RFO refueling outage

RIS regulatory issue summary (NRC)

RG regulatory guide (NRC)

RPV reactor pressure vessel

SCC stress-corrosion cracking

SCSS Sequence Coding & Search System

SER safety evaluation report

SFP spent fuel pool

SI structural integrity

SIT special inspection team

SME subject matter expert

SNL Sandia National Laboratories

SRP standard review plans

SS stainless steel

SSC system, structure, and component

TMI Three Mile Island

UT ultrasonic testing
xxi

VT-1, -3 visual examination category per ASME Code

West Westinghouse

1

1. INTRODUCTION

1.1 Purpose

Several of the 104 commercial nuclear power plants (NPPs) (Ref. 1) in the United States have 

experienced some water leakage from their spent fuel pools (SFPs) and reactor refueling 

cavities. In addition, since 2000, the license renewal applications (LRAs) filed by licensees 

have noted several cases of corrosion in the boiling-water reactor (BWR) Mark I containment 

torus steel structures. Concrete degradation has also been indicated in other instances. As 

NPPs age, additional occurrences or emerging modes of degradation of the SFPs, the reactor 

refueling cavities, the BWR Mark I containment tori, and concrete safety-related structures 

continue to be identified.

The nuclear power industry and, in particular, LRAs filed by licensees have discussed the 

possible causes of and various methods for mitigating or alleviating (1) the SFP leakage, (2) the 

reactor refueling cavity leakage, (3) the torus corrosion and cracking in BWR Mark I 

containments, and (4) the concrete degradation. The licensees have performed engineering 

evaluations as part of their current licenses or individual LRAs to justify extending operation of 

their specific NPP beyond the original license expiration date, initially set at 40 years of 

operation.

This project is an independent review of the operating experience of commercial NPPs in the 

United States over the past several years regarding the four phenomena noted above. The 

project also reviewed information provided by the licensees as part of their LRAs that pertains to 

these phenomena. Sources of information used in this project were restricted to those that are 

publicly available.

1.2 Background

1.2.1 Project History

The U.S. Nuclear Regulatory Commission (NRC), in concert with Oak Ridge National 

Laboratory (ORNL), has conducted several programs since 1988 addressing structures at 

NPPs, including the following five programs:

(1) The Structural Aging Program, conducted from 1988 until 1996, developed data and 

information on the aging of NPP concrete structures. The results from this program 

have been directly applied to LRA reviews (Ref. 2).

(2) The Inspection of Aged/Degraded Containments Program addressed factors that could 

potentially affect the capacity of NPP steel containments and the liners of reinforced 

concrete containments. This program was conducted from 1993 to 2001 (Ref. 3).

(3) The Effect of Phosphate Ion on Concrete Program investigated the potential for 

degradation of concrete materials in a phosphate-rich environment and was conducted

from 2004 to 2006. This program also produced a primer on the durability of NPP 

concrete structures (Ref. 4).

(4) The Environmental Effects on Containments and Other NPP Structures Program 

developed information from 2004 to 2008 related to the effects of elevated temperature 
2

on concrete materials and structures and inspection of inaccessible regions of the 

containment metallic pressure boundary and thick-section reinforced concrete structures 

(Refs. 5 and 6).

(5) The High Temperature Effects on Concrete Program, conducted from 2007 to 2010, 

compiled data and information on the effects of elevated temperature on concrete 

properties and performance. In addition, this program addressed methods for analysis 

of concrete structures experiencing thermal loadings (Ref. 7).

The NRC has also conducted many other studies and programs regarding safety-related 

structures assessment and analysis of age-related degradation of structures, NPP containment 

integrity, aging management techniques and determination, and other similar topics (Refs. 8

to 25). NUREG-1522, ―Assessment of Inservice Conditions of Safety-Related Nuclear Plant 

Structures,‖ issued June 1995 (Ref. 9), presents several examples of age-related degradation of

structures and passive components in NPPs. NUREG/CR-6679, ―Assessment of Age-Related 

Degradation of Structures and Passive Components for U.S. Nuclear Power Plants,‖ issued 

August 2000 (Ref. 11), reiterates that the data presented in NUREG-1522 were ―obtained from 

actual walk-downs of structures and components at six older NPPs (licensed before 1977). 

Occurrences of degradation were identified in intake structures/pump houses, service water 

piping, tendon galleries, masonry walls, anchorages, containments, and other concrete 

structures.‖

NUREG/CR-6679 further describes the aging of structures and passive components: 

Structures generally have substantial safety margins when properly designed 

and constructed. However, the available margins for degraded structures are not 

well known. In addition, age-related degradation may affect the dynamic 

properties, structural response, structural resistance/capacity, failure mode, and 

location of failure initiation. A better understanding of the effect of aging 

degradation on structures and passive components is needed to ensure that the 

current licensing basis (CLB) is maintained under all loading conditions. 

Structures include buildings and civil engineering features such as masonry 

walls, canals, embankments, underground structures, and stacks. Passive 

components consist of equipment that do not move or change their state to 

perform their intended function. Examples of passive components are tanks, 

cable tray systems, conduit systems, and heating, ventilation, and air 

conditioning (HVAC) ducts and supports.

ORNL completed a study of concrete durability (NUREG/CR-6927, ―Primer on Durability of 

Nuclear Power Plant Reinforced Concrete Structures—A Review of Pertinent Factors,‖ issued 

February 2007) (Ref. 26), which examined the relationship between durability and performance, 

reviewed the historical perspective related to concrete and longevity, described the basic 

materials that constitute reinforced concrete, and presented information on the environmental 

factors that can affect the performance of NPP concrete structures. An appendix to 

NUREG/CR-6927 provided a brief history of the operating experience of NPP concrete 

structures. 

In addition to this program, ORNL is currently engaged in another NRC program directly related 

to the potential degradation phenomena noted above: ―Technical Assistance for Civil/Structural 

Review of License Renewal Applications.‖ ORNL personnel are providing technical support in 
3

the area of concrete and containment aging to the project team reviewing and evaluating NPP 

LRAs.

1.2.2 Project-Related Documents

The Nuclear Management and Resources Council (NUMARC, the predecessor of the Nuclear 

Energy Institute (NEI)) submitted 11 industry reports (IRs) to the NRC for review in the 1990s 

(Ref. 27). Ten of the reports discussed aging issues of components and structures in NPPs, 

and the last report addressed a screening methodology for the proposed integrated plant 

assessments. Title 10 of the Code of Federal Regulations (10 CFR) Part 54, ―Requirements for 

Renewal of Operating Licenses for Nuclear Power Plants,‖ was originally published in 1991 

(Ref. 28). This Federal regulation established the procedures, criteria, and standards that would 

govern NPP LRAs. On March 1, 1993, the NRC staff recommended in SECY-93-049, 

―Implementation of 10 CFR Part 54,  ̳Requirements for Renewal of Operating Licenses for 

Nuclear Power Plants‘‖ (Ref. 29), that the technical information in the IRs be incorporated into

the proposed draft standard review plan (SRP) for license renewal. In September 1997, the 

NRC issued NUREG-1611, ―Aging Management of Nuclear Power Plant Containments for 

License Renewal‖ (Ref. 15), which reconciled the NUMARC/NEI IRs with the newly published 

inservice inspection requirements for light-water-cooled plants addressing Class MC and 

metallic liners of Class CC components (Subsection IWE) and Class CC concrete components 

(Subsection IWL) contained in Section XI of the American Society of Mechanical Engineers 

(ASME) Boiler and Pressure Vessel Code (ASME Code) (Ref. 30). The initial SRP for the 

review of LRAs (NUREG-1800, ―Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants‖ (Ref. 31)) was issued in 2001, along with the NRC staff 

evaluation of existing aging management programs in NUREG-1801, ―Generic Aging Lessons 

Learned (GALL) Report,‖ issued July 2001 (Ref. 32) (also known as the ―GALL Report‖). The 

GALL Report was built on a previous report (Ref. 33) that systematically compiled information 

on plant aging. In September 2005, the NRC issued Regulatory Guide (RG) 1.188, ―Standard 

Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses‖ 

(Ref. 34). RG 1.188 resolved public comments on three prior draft versions of the RG (Draft 

Regulatory Guide (DG) 1009 (Ref. 35) in 1990, DG-1047 (Ref. 36) in 1996, and DG-1104 

(Ref. 37) in 2000), NUREG-1800, and NUREG-1801 and also incorporated public comments 

(Ref. 38). The NRC revised and updated all three documents in September 2005, and NEI 

published NEI 95-10, ―Industry Guidelines for Implementing the Requirements of 

10 CFR Part 54—The License Renewal Rule,‖ Revision 6 (Ref. 39), in June 2005. The NRC 

staff found that ―Revision 6 of NEI 95-10 was acceptable for use in implementing the license 

renewal rule, without exceptions‖ (Ref. 38).

The NRC‘s Office of Nuclear Reactor Regulation is responsible for ensuring the public health 

and safety through licensing and inspection activities at all commercial nuclear power reactor 

facilities in the United States. The Division of License Renewal (DLR) evaluates LRAs. DLR 

performs its work in accordance with the requirements of 10 CFR Part 54. In addition, DLR 

uses the guidance provided in NUREG-1800 and NUREG-1801 and follows the precepts of 

RG 1.188 (Ref. 34). In December 2010, the NRC published Revision 2 of NUREG-1800 and 

NUREG-1801. 
4

1.3 Program Description

The current program investigated the four phenomena listed in Section 1.1: (1) leakage from 

the reactor refueling cavity, (2) SFP leakage, (3) torus corrosion and cracking in BWR Mark I 

containments, and (4) aging degradation in concrete safety-related structures.

1.3.1 Leakage from the Reactor Refueling Cavity 

This activity investigated the cause and extent of leakage from the deteriorated seals between 

the reactor refueling cavity and the reactor cavity areas, and leakage through the stainless steel 

weld seams and through the stainless steel base metal. This portion of the project also 

gathered information on the effect of borated water on steel (carbon, stainless shapes and 

liners) components, concrete steel reinforcement (i.e., rebar), and concrete.

For BWR NPPs, the primary concern is corrosion of the drywell shell and support structure. In 

the case of pressurized-water reactors (PWRs), borated water leakage may cause corrosion of 

the primary shield liner, reactor supports, and containment structure, or it may affect other 

structures and components on which the leaking water accumulates. This part of the project 

also examined and documented field activities performed by the different licensees to detect a 

leakage path from the reactor cavity; how they determined the extent of deterioration of the 

concrete, rebar, and steel; the methods they used to try to stop the leakage; and approaches 

aimed at evaluating the impact of leakage on the load-carrying capacity of deteriorated concrete 

structures. 

1.3.2 Spent Fuel Pool Leakage

This activity investigated the cause and extent of leakage from BWR and PWR SFPs through 

the stainless steel weld seams and base metal. Information is provided on the effect of borated 

water on the stainless steel liner plate, rebar, and concrete. The impact of water leakage on a 

stainless steel liner leak detection system (e.g., telltale drains) is also scrutinized as part of the 

project. As described in Section 1.3.1 of this report, this part of the study also examined and 

documented field activities performed by the different licensees to detect a leakage path from 

the SFP; how they determined the extent of deterioration of the concrete, rebar, and steel; and 

the methods they used to stop the leakage and evaluate the load-carrying capacity of 

deteriorated concrete structures. 

1.3.3 Torus Corrosion and Cracking in the Boiling-Water Reactor Mark I Containment

This activity addressed the possible causes of corrosion and cracking in the BWR Mark I 

containment torus, the so-called ―inverted lightbulb‖ design, of the 22 BWR Mark I NPPs. This 

investigation included both coated and uncoated tori. The specific location where the corrosion 

was found is flagged and documented. This part of the report summarizes the licensee 

engineering evaluations performed in accordance with Subsection IWE of Section XI of the 

ASME Code. It also lists the acceptance criteria (when available) used by the licensees to 

determine if additional evaluations and monitoring are required for an extended period of 

operation. 
5

1.3.4 Age-Related Degradation in Concrete Safety-Related Structures 

This activity investigated occurrences involving age-related degradation of safety-related 

concrete structures at both PWRs and BWRs other than those associated with reactor refueling 

cavities and SFPs. This portion of the study also investigated the methodology used by 

licensees to identify the concrete degradation, the licensees‘ approaches, and the procedures 

used to resolve concrete degradation issues. The extent of the study, however, was limited 

primarily to events after February 2007 (see Section 3.2.5).

Results for occurrences that were not available in publicly accessible documents about aging 

effects, aging mechanisms, and environments were not included within the scope of this report. 

Also, occurrences that pertain to the following areas were not considered to be age related and 

therefore were not addressed in detail:

 construction defects (voids, honeycombing, delaminations) and material deficiencies 

(wrong material, inadequate strength) 

 shrinkage cracking 

 design errors 

 steel liner corrosion

 liner repairs (liner replacement, steam generator replacement) 

 moisture barrier degradation 

 liner coating degradation 

 bulging or distortion of liner plate 

 liner penetration and sleeve damage

 physical damage to concrete where the degradation mechanism involves a one-time 

event (impact, overload) 

7

2. AGING MANAGEMENT PRACTICES AND PROGRAMS

2.1 Aging Management Practices

Nuclear power plant owners are required to monitor the performance or condition of structures, 

systems, and components (SSCs) against the owner-established goals, in a manner sufficient to 

give reasonable assurance that such SSCs are capable of fulfilling their intended functions 

based on rules in Title 10 of the Code of Federal Regulations (10 CFR) 50.65, as noted in 

―Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,‖ first issued in 1991

(Ref. 40). Often referred to as the ―Maintenance Rule,‖ 10 CFR 50.65 further requires the

licensee to take appropriate corrective action when the performance or condition of an SSC 

does not conform to established goals. The main objective of the Maintenance Rule is to 

monitor the overall continuing effectiveness of maintenance programs used by the licensees of 

operating reactors to ensure that safety-related (and certain nonsafety-related) SSCs are 

capable of performing their intended functions. The rule is performance based and not 

prescriptive.

2.2 Known Problem Areas

The following sections describe the impact of codes and regulations and their subsections on 

actions taken by the U.S. Nuclear Regulatory Commission (NRC) to address known problem 

areas for SSCs and to establish consistency in describing degradation effects, degradation 

mechanisms, and environments that are important to the aging management of these 

structures.

2.2.1 ASME Boiler and Pressure Vessel Code, Section XI, Subsection IWE

Inservice inspection (ISI) requirements of the American Society of Mechanical Engineers 

(ASME) Boiler and Pressure Vessel Code (ASME Code), Section XI, Subsection IWE, for steel 

containments (Class MC) and steel liners for concrete containments (Class CC) are imposed on 

licensees by 10 CFR 50.55a, ―Codes and Standards‖ (Ref. 41). ASME Code Section XI,

Subsection IWE, was incorporated into 10 CFR 50.55a in 1996. Before then, operating 

experience pertaining to the degradation of steel components of containment was gained 

through the inspections required by Appendix J, ―Primary Reactor Containment Leakage 

Testing for Water-Cooled Power Reactors,‖ to 10 CFR Part 50, ―Domestic Licensing of 

Production and Utilization Facilities,‖ and ad hoc inspections conducted by licensees and the 

NRC. 

The following information notices (INs) or NUREG documents describe occurrences of corrosion 

in steel containment shells or liners of reinforced concrete containments: 

 IN 86-99, ―Degradation of Steel Containments,‖ dated December 8, 1986 (Ref. 21) 

 IN 88-82, ―Torus Shells with Corrosion and Degraded Coatings in BWR Containments,‖ 

dated October 14, 1988 (Ref. 22) 

 IN 89-79, ―Degraded Coatings and Corrosion of Steel Containment Vessels,‖ dated 

December 1, 1989 (Ref. 23), and Supplement 1 to IN 89-79, dated June 29, 1990 

(Ref. 24) 
8

 IN 97-10, ―Liner Plate Corrosion in Concrete Containments,‖ dated March 13, 1997 

(Ref. 42)

 IN 2004-09, ―Corrosion of Steel Containment and Containment Liner,‖ dated 

April 27, 2004 (Ref. 43)

 IN 2011-15, ―Steel Containment Degradation and Associated License Renewal Aging 

Management Issues, dated August 1, 2011 (Ref. 44)

 NUREG-1522, ―Assessment of Inservice Conditions of Safety-Related Nuclear Plant 

Structures,‖ issued June 1995 (Ref. 9) 

Generic Letter (GL) 87-05, ―Request for Additional Information Assessment of Licensee 

Measures To Mitigate and/or Identify Potential Degradation of Mark I Drywells,‖ issued in 1987 

(Ref. 45), addressed the potential for corrosion of boiling-water reactor (BWR) Mark I steel 

drywells in the ―sand pocket region.‖ The Section XI, Subsection IWE, aging management 

program considers the liner plate and containment shell corrosion and cracking concerns 

described in these generic communications. Implementation of the ISI requirements of 

Subsection IWE, in accordance with 10 CFR 50.55a, augmented to consider operating 

experience, and as recommended in License Renewal Interim Staff Guidance 

(LR-ISG) 2006-01, ―Final Plant-Specific Staff Aging Management Program for Inaccessible 

Areas of Boiling Water Reactor Mark I Steel Containment Drywell Shell,‖ dated 

November 16, 2006 (Ref. 46), is a necessary element of aging management for steel 

components of steel and concrete containments through the period of extended operation. 

The full scope of Subsection IWE includes steel containment shells and their integral 

attachments; steel liners for concrete containments and their integral attachments; containment 

hatches, airlocks, and moisture barriers; and pressure-retaining bolting. ASME Code 

Section XI, Subsection IWE, and the additional requirements specified in 10 CFR 50.55a(b)(2) 

constitute an existing mandated program applicable to managing the aging of steel 

containments, steel liners of concrete containments, and other containment components. 

The primary ISI method specified in Subsection IWE is visual examination (general visual, VT-3, 

and VT-1). Limited volumetric examination (ultrasonic thickness measurement) and surface 

examination (e.g., liquid penetrant) may also be necessary in some instances to detect aging 

effects. Subsection IWE specifies acceptance criteria, corrective actions, and expansion of the 

inspection scope when degradation exceeding the acceptance criteria is found. The program 

attributes are augmented to incorporate aging management activities, recommended in 

LR-ISG-2006-01 (Ref. 46), needed to address the potential loss of material due to corrosion in 

the inaccessible areas of the BWR Mark I steel containments. 

Degradation of threaded bolting and fasteners in closures for the reactor coolant pressure 

boundary has occurred as the result of boric acid corrosion, stress-corrosion cracking (SCC), 

and fatigue loading (Inspection Enforcement (IE) Bulletin No. 82-02, ―Degradation of Threaded 

Fasteners in the Reactor Coolant Pressure Boundary of PWR Plants,‖ dated June 2, 1982 

(Ref. 47), and GL 91-17, ―Generic Safety Issue 29,  ̳Bolting Degradation or Failure in Nuclear 

Power Plants,‘‖ dated October 17, 1991 (Ref. 48)). It is to be noted that SCC has occurred in 

high-strength bolts used for nuclear steam supply system component supports, as described in 

Electric Power Research Institute (EPRI) Report NP-5769, ―Degradation and Failure of Bolting 

in Nuclear Power Plants,‖ issued April 1998 (Ref. 49). The augmented ASME Code Section XI, 
9

Subsection IWE, incorporating recommendations documented in EPRI NP-5769 and 

EPRI TR-104213, ―Bolted Joint Maintenance and Application Guide,‖ issued December 1995 

(Ref. 50), is necessary to ensure containment bolting integrity.

Inspections are augmented to require surface examination for detection of cracking such as 

described in IN 92-20, ―Inadequate Local Leak Rate Testing,‖ dated March 3, 1992 (Ref. 25), 

and to address recommendations for structural bolting delineated in NUREG-1339, ―Resolution 

of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,‖ issued 

June 1990 (Ref. 51), and industry recommendations delineated in EPRI NP-5769; 

EPRI NP-5067, ―Good Bolting Practices, a Reference Manual for Nuclear Power Plant 

Maintenance Personnel,‖ issued in 1990 (Ref. 52); and EPRI TR-104213 (Ref. 50). The 

program is also augmented to require surface examination of dissimilar metal welds of vent line 

bellows in accordance with examination Category E-F, as specified in the 1992 edition of ASME 

Code Section XI, Subsection IWE. If surface examination is not possible, an appropriate test 

from 10 CFR Part 50, Appendix J, may be conducted for pressure boundary components.

IN 97-10 (Ref. 42) identified specific locations where concrete containments are susceptible to 

liner plate corrosion. Other operating experience indicates that foreign objects embedded in 

concrete have caused through-wall corrosion of the liner plate at a few plants with reinforced 

concrete containments. IN 92-20 (Ref. 25) described an occurrence of containment bellows 

cracking, which resulted in loss of leaktightness. More recently, IN 2006-01, ―Torus Cracking in 

a BWR Mark I Containment,‖ dated January 12, 2006 (Ref. 53), described through-wall cracking 

and its probable cause in the torus of a BWR Mark I containment. The licensee identified the 

cracking in the heat-affected zone at the exhaust pipe torus penetration of the high-pressure 

coolant injection (HPCI) turbine. The licensee concluded that the cracking was most likely 

initiated by cyclic loading due to condensation oscillation during HPCI operation. These 

condensation oscillations induced on the torus shell may have been excessive because of the 

lack of an HPCI turbine exhaust pipe sparger, which many licensees have installed.

Subsection IWE also requires examination of coatings that prevent corrosion, as described in 

NUREG-1801, Revision 2, ―Generic Aging Lessons Learned (GALL) Report,‖ issued 

December 2010.

2.2.2 ASME Boiler and Pressure Vessel Code, Section XI, Subsection IWL 

ASME Code Section XI, Subsection IWL, was incorporated into 10 CFR 50.55a in 1996. Before 

then, the prestressing tendon inspections were performed in accordance with the guidance

provided in Regulatory Guide (RG) 1.35, ―Inservice Inspection of Ungrouted Tendons in 

Prestressed Concrete Containments‖ (Ref. 54), and RG 1.35.1 (Revision 3), ―Determining 

Prestressing Forces for Inspection of Prestressed Concrete Containments‖ (Ref. 55). Operating 

experience pertaining to degradation of reinforced concrete in concrete containments was 

gained through the inspections required by Appendix J to 10 CFR Part 50 and ad hoc 

inspections conducted by licensees and the NRC. NUREG-1522 (Ref. 9) described 

occurrences of cracked, spalled, and degraded concrete for reinforced and posttensioned 

concrete containments. The NUREG also described cracked anchor heads for the prestressing 

tendons at three posttensioned concrete containments. IN 99-10, ―Degradation of Prestressing 

Tendon Systems in Prestressed Concrete Containments,‖ dated April 13, 1999 (Ref. 56), 

described occurrences of degradation in prestressing systems. The Subsection IWL program 

considers the degradation concerns described in these documents. Implementation of 
10

Subsection IWL, in accordance with 10 CFR 50.55a, is a necessary element of aging 

management for concrete containments (Refs. 28 and 32).

2.2.3 Structures Monitoring Program

Although in many plants structures monitoring programs have been implemented only recently, 

plant maintenance has been ongoing since initial plant operations. NUREG-1522 (Ref. 9) 

documents the results of a survey sponsored in 1992 by the NRC‘s Office of Nuclear Reactor 

Regulation to obtain information on the types of distress in the concrete and steel structures and 

components, the type of repairs performed, and the durability of the repairs. Licensees who 

responded to the survey reported cracking, scaling, and leaching of concrete structures. 

Degradation occurrences were attributed to drying shrinkage, freeze-thaw, and abrasion. 

NUREG-1522 also describes the results of NRC staff inspections at six plants. The staff 

observed concrete degradation, corrosion of component support members and anchor bolts, 

cracks and other deterioration of masonry walls, and ground water leakage and seepage into 

underground structures. The observed and reported degradations were more severe at coastal 

plants than those observed in inland plants as a result of brackish and sea water. Recent 

license renewal applicants reported similar degradation and corrective actions taken through 

their structures monitoring programs. Many license renewal applicants have found it necessary 

to enhance their structures monitoring program to ensure that the aging effects of structures and 

components included in 10 CFR 54.4, ―Scope‖ (Ref. 28), are adequately managed during the 

period of extended operation. There is reasonable assurance that implementation of the 

structures monitoring program described above will be effective in managing the aging of the 

in-scope structures and components (Ref. 32).

2.2.4 Regulatory Guide 1.127

RG 1.127, Revision 1, ―Inspection of Water-Control Structures Associated with Nuclear Power 

Plants,‖ issued March 1978 (Ref. 57), describes an acceptable basis for developing an ISI and 

surveillance program for dams, slopes, canals, and other raw-water control structures 

associated with emergency cooling water systems or flood protection of nuclear power plants. 

The RG 1.127 program addresses age-related deterioration, degradation caused by extreme 

environmental conditions, and the effects of natural phenomena that may affect water control 

structures. The RG 1.127 program recognizes the importance of periodic monitoring and 

maintenance of water control structures so that the consequences of age-related deterioration 

and degradation can be prevented or mitigated in a timely manner. RG 1.127 provides detailed 

guidance for the licensee‘s inspection program for water control structures, including guidance 

on engineering data compilation, inspection activities, technical evaluation, inspection 

frequency, and the content of inspection reports. 

RG 1.127-based programs have detected degradation of water control structures at several 

nuclear power plants, and, in some cases, the degradation has required remedial action. 

NUREG-1522 (Ref. 9) described occurrences of and corrective actions taken for severely 

degraded steel and concrete components at the intake structure and pump house of coastal 

plants. Other degradation described in NUREG-1522 includes appreciable leakage from the 

spillway gates, concrete cracking, corrosion of spillway bridge beam seats of a plant dam and 

cooling canal, and appreciable differential settlement of the outfall structure of another. No loss 

of intended functions has resulted from these occurrences. Therefore, it can be concluded that 

the inspections implemented in accordance with the guidance in RG 1.127 have been 

successful in detecting significant degradation before loss of intended function occurs (Ref. 32).
11

2.2.5 Protective Coating Monitoring and Maintenance Program

Accounts of industry experience pertaining to coating degradation inside containment and the 

consequential clogging of sump strainers appear in the following:

 IN 88-82, ―Torus Shells with Corrosion and Degraded Coatings In BWR Containments,‖ 

dated October 14, 1988 (Ref. 22) 

 Bulletin 96-03, ―Potential Plugging of Emergency Core Cooling Suction Strainers by 

Debris in Boiling-Water Reactors,‖ dated May 6, 1996 (Ref. 58) 

 GL 2004-02, ―Potential Impact of Debris Blockage on Emergency Recirculation during 

Design Basis Accidents at Pressurized-Water Reactors,‖ dated September 13, 2004 

(Ref. 59) 

 GL 98-04, ―Potential for Degradation of the Emergency Core Cooling System and the 

Containment Spray System after a Loss-of-Coolant Accident Because of Construction 

and Protective Coating Deficiencies and Foreign Material in Containment,‖ dated 

July 14, 1998 (Ref. 60) 

 ASME Code Case N-597, ―Requirements for Analytical Evaluation of Pipe Wall 

Thinning,‖ dated November 18, 2003 (Ref. 61)

In July 2000, the NRC issued RG 1.54, Revision 1, ―Service Level I, II, and III Protective 

Coatings Applied to Nuclear Power Plants‖ (Ref. 62). Monitoring and maintenance of Service 

Level I coatings conducted in accordance with Regulatory Position C4 are expected to be 

effective in managing degradation of Service Level I coatings and, consequently, to be an 

effective means to manage loss of material due to corrosion of carbon steel structural elements 

inside containment (Ref. 32). 

13

3. DATA ACQUISITION

3.1 Introduction

A previous study, NUREG/CR-6679, ―Assessment of Age-Related Degradation of Structures 

and Passive Components for U.S. Nuclear Power Plants,‖ issued August 2000 (Ref. 11), 

examined and assessed age-related degradation of structures and components at U.S. 

commercial nuclear power plants (NPPs). The purpose of the study, conducted by Brookhaven 

National Laboratory (BNL) under the auspices of the U.S. Nuclear Regulatory Commission‘s 

(NRC‘s) Office of Nuclear Regulatory Research, was to develop a technical basis for the 

validation and improvement of analytical methods to be used to address issues related to the 

degradation of structures and passive components. The study initially collected and evaluated 

NPP degradation occurrences. The study then documented the data in the Degradation 

Occurrence Database (DOD), which is a collection of events that occurred during operation 

from 1985 to 1997. This current study builds on that specific information but emphasizes 

operational events that have occurred since 1997. In this way, the events occurring within the 

industry from 1997 until about mid-2010 will be readily available. The current study 

complements NUREG/CR-6679 in that all occurrences concerning a nuclear power plant 

structure‘s degradation, and those concerning the phenomena mentioned in Chapter 1 of this 

report, will now be accounted for from 1985 through mid-2010.

The database assembled in NUREG/CR-6679 (Ref. 11) and its associated information were 

developed before the publication of NUREG-1800, ―Standard Review Plan for Review of 

License Renewal Applications for Nuclear Power Plants,‖ issued July 2001 (Ref. 31), and 

NUREG-1801, ―Generic Aging Lessons Learned (GALL) Report,‖ issued July 2001 (Ref. 32) 

(see Section 1.2.2 of this report); consequently, there is not a one-to-one correspondence 

between the criteria used for the BNL database and that of the current study. For example, 

NUREG-1800 identifies 10 aging effects and mechanisms that apply to NPP containments. 

NUREG-1801 identifies seven aging effects and mechanisms for structures. In comparison, 

NUREG/CR-6679 lists 18 categories of structures and components and 10 aging effects and 

mechanisms, which are not readily comparable to the items identified in NUREG-1800 and 

NUREG-1801. Moreover, NUREG-1801 lists 50 separate components that are included in 

current aging management programs at U.S. commercial NPPs. Consequently, the data and 

information presented in NUREG/CR-6679 are used to augment the information and data 

presented in this report but cannot be compared directly to the current information.

3.2 Operating Experience Data Acquisition

3.2.1 Licensee Event Reports 

In NUREG-1022, Revision 2, ―Event Reporting Guidelines: 10 CFR 50.72 and 50.73,‖ issued 

October 2000 (Ref. 63), the NRC modified and codified Title 10 of the Code of Federal 

Regulations (10 CFR) 50.73, ―Licensee Event Report System,‖ effective January 1, 1984, to 

define and specify the types of events and conditions reportable to the NRC. NUREG-1022

(Revision 2) notes that ―The purpose of the rule was to standardize the reporting requirements

for all NPP licensees, to eliminate reporting events of low individual significance, and to require 

a more thorough documentation and analyses of reported events.‖ The licensees are required 

to report, among other things, an operation or condition prohibited by a plant‘s technical 

specifications and a degraded or unanalyzed condition of the NPP or its principal safety 
14

barriers. The plant‘s technical specifications require monitoring of the containment and 

associated structures.

Two databases contain the 7,403 licensee event reports (LERS) filed with the NRC for licensed 

NPPs from 1997 through 2009, one managed by Oak Ridge National Laboratory (ORNL) and 

the other by Idaho National Laboratory. These two databases are both searchable and allow for 

retrieval of relevant LERs.

The LERs identified were from the Sequence Coding and Search System (SCSS). The SCSS 

is an electronic database developed to allow users to retrieve commercial nuclear plant 

operating experience data from LERs. Instead of providing the actual LER text, the database 

reduced the LER descriptive text to coded, searchable word sequences that are both 

computer-readable and computer-searchable. The system provides a structured format for the 

detailed coding of such factors as components, systems, causes, and effects. Data on 

component failures include the type and number of components involved, the system to which 

the components belong, the cause and mode of failure, and the effect of failures on plant 

systems. There are over 400 specific component codes and more than 100 cause-and-effect 

code designations.

On the other hand, LER information obtained from the Idaho National Laboratory is essentially 

text based. That is, the text of the LERs is searchable, and certain form data are captured 

individually (e.g., plant name, date of occurrence, basic unit effect), but the events are not 

coded into word sequences. The text search included terms such as ―refueling cavity,‖ ―transfer 

pit,‖ ―corrosion or wastage or erosion,‖ ―refuel pool,‖ and ―liner cladding degradation.‖ However, 

a simple check of the logic indicates that the same word or word combination may be identified 

by the search in the same document but may not have the same meaning. For example, the 

words ―containment‖ and ―corrosion‖ may appear in the same body of text, but the context of the 

word ―containment‖ may have been used to describe a bottle or some other container and not 

be associated with the NPP containment. Similarly, the word ―corrosion‖ may have been used 

to describe something other than the issues of concern for this project. These two words may 

then have been separated within the text and have no relationship to one another (i.e., each 

word is contained in a different sentence). This is an example of a false positive hit in the 

search. However, the search engine used to find relevant events in the text-only database had 

the capability to perform Boolean search logic and nesting, which reduced the large volume of 

text in the LERs to a more manageable size, resulting in fewer LERs to be reviewed. Creating 

the search logic for full-text documents was an iterative process. Often, changes were needed 

in potential terms to make the searches more inclusive, such that the search results would 

include those events of interest while also keeping the number of false positives to a minimum.

The first level of computer screening of the two databases produced 673 LERs for review. Two 

engineers reviewed the LERs (a primary reviewer who examined the LERs in detail and a 

secondary reviewer who corroborated the first reviewer‘s findings). If the two engineers 

disagreed, the event was passed on to the next phase of data acquisition, where they were 

stored (i.e., binning) prior to more detailed review. In this first level of review, 591 events were 

rejected from further consideration; thus, 82 events (or LERs) were passed on to the binning 

stage of the project‘s data acquisition phase.
15

3.2.2 NRC Generic Communications

The NRC employs various types of reports to communicate information regarding NPPs to the 

industry and the public at large. These reports offer a variety of information concerning NPP 

operating experience and convey or discuss NRC policy, as well as other topics of interest to 

the nuclear industry and the public. Many times, these NRC generic communications disclose 

information not readily available elsewhere (these generic communications are available at 

http://www.nrc.gov/reading-rm/doc-collections/gen-comm/). Therefore, these reports were 

screened for operational data and additional information for use in this project.

In the late 1970s and into the early 1980s, the NRC issued circulars to transmit time-sensitive 

information related to public health and safety; however, these were discontinued in 

February 1985 and were excluded from this study, as this information would have been 

addressed by the prior BNL study (Ref. 11). Administrative letters (ALs) are another type of 

NRC communication report. They inform various licensees of specific regulatory or 

administrative information or clarify this information. The NRC discontinued the ALs in 

September 1999, and only the ALs from 1997 through 1999 (19 total) were screened for this 

project. None of the ALs screened were found to have relevant information. The NRC also 

issues generic letters (GLs), which are transmittals by the NRC to request action by the 

licensees, distribute policy positions, or inform the industry about voluntary programs. The GLs 

from 1997 through 2010 were screened (21 total) for information relevant to this project. Some 

of these, where appropriate, were reviewed in detail to determine their relevance to the 

program. For example, GL 97-01, ―Degradation of Control Rod Drive Mechanism Nozzle and 

Other Vessel Closure Head Penetrations,‖ dated April 1, 1997 (Ref. 64), which discusses 

control rod drive mechanism nozzle issues and related reactor pressure vessel penetration 

concerns, was reviewed in detail, identified as extraneous to this project, and then excluded 

from further screening.

The NRC began issuing regulatory issue summaries (RISs) as a means of transmitting 

information affecting nuclear licensees and the nuclear industry. Among other uses, the RISs 

document NRC endorsement of the resolution of issues addressed by industry-sponsored 

initiatives, announce staff technical positions, and discuss material that was previously found in 

ALs. Of the 265 RISs reviewed for relevance to this project, three (Refs. 65–67) were selected 

for a more detailed examination during the binning process of the data acquisition phase.

In 1971, the NRC initiated the issue of bulletins as a means of both requesting information from 

licensees and advising them of new or revised NRC programs that may affect operations. All of

the NRC bulletins from 1997 through the present were reviewed for applicability to this project. 

Four bulletins (Refs. 68–71) were selected for a more thorough review during the binning 

process of the program.

Information notices (INs) appeared as communication tools of significant information to 

licensees in 1979. The INs convey significant information about safety, safeguards, or 

environmental issues. Since 1997, the NRC has issued 473 INs. These were evaluated for 

applicability, and 26 INs were subsequently reviewed in depth to determine if they contained 

information pertinent to the current project. Of these, 16 were included in the binning process 

(Refs. 42, 72–86).
16

3.2.3 NRC Reports

The NRC modified and codified 10 CFR 50.72, ―Immediate Notification Requirements for 

Operating Nuclear Power Reactors‖, effective January 1, 1984, to define and specify the types 

of events and conditions reportable to the NRC. Whereas 10 CFR 50.73 requires a 30-day 

written report to the NRC, 10 CFR 50.72 requires NRC notification via the Emergency 

Notification System (ENS) within 1 hour, 4 hours, or 8 hours, depending on the nature or 

severity of the event. NUREG-1022, Revision 2 (Ref. 63), describes the similarities and 

differences between the two regulations; the various reporting criteria in the two overlap 

considerably. From January 1999 to May 2010, 10,541 immediate reports were made to the 

ENS. A list of these is available at http://www.nrc.gov/reading-rm/doc-collections/event-status/

(Ref. 87); however, unlike the LERs, these events were not codified, nor is the list searchable. 

The reports are listed on a daily basis for each year, and, within each daily listing, there may be 

as many as 15 to 20 events. A text search of each of the reports issued prior to 1999 and each 

of the 10,541 reports issued since January 1999 was not feasible; therefore, a sample search 

was done to find events most likely to be of interest. The sample set of 994 was obtained from 

a combination of a simple Boolean logic text search and a random selection. The random 

selection followed the standard rules of search techniques and it is described below.

The set of 10 CFR 50.72 reports was assumed to be a discrete uniform distribution using a 

binary classification modeled by the Bernoulli distribution. A random sampling of the set of 

reports was performed without replacement following a hypergeometric distribution. The 

hypergeometric distribution satisfies several conditions. For example, the sample population is 

finite, the size of the population is known, the number of items with the attribute of interest is 

known, and each item in the sample is drawn at random. The probability that a significant event 

may have been ―missed‖ and was actually in the set of events not reviewed was also estimated. 

In this instance, significant was defined to be a report concerning the four topics of interest to 

the present study. The concept of ―missed‖ acknowledges an event of significance within the 

sample set with a measured degree of confidence that it was not left out of the sample set. 

Both Type I and Type II errors were accounted for, where a Type I error is an error in which a 

significant event was left out of the review that should have been included, and a Type II error 

was an event included in the sample set that should have been left out of the review.

In addition to conducting a generalized sampling of the set of 10 CFR 50.72 reports, another 

type of search focused on the included operating experience data. Via a text search engine 

utilizing a simple Boolean logic, events potentially reporting reactor refueling cavity leakage, 

spent fuel pool leakage, torus corrosion and cracking, and age-related concrete degradation 

were identified. Specifically, the data sources (10 CFR 50.72 reports) were obtained and stored 

on an ORNL computer for analysis using a desktop search engine. This search engine 

provided the capability for Boolean search logic and nesting, which, in turn, allowed complex 

text searches to be conducted. Thus, it was possible to reduce large volumes of text to more 

manageable numbers for events to be reviewed. 

The event report database (Ref. 87) also contains preliminary notification reports (PNOs). The 

PNOs are brief descriptions of significant safety or safeguards events from each NRC region. 

The PNOs are listed by region, by year, and by number. There is no available database 

containing all 487 PNOs, and the total number of reported PNOs is not exact. Therefore, as 

with the 10 CFR 50.72 reports, this set of events was investigated using the same approach as 

noted above. 
17

Also contained in the database (Ref. 87) are NRC Headquarters daily reports. These reports 

were typically used to communicate with the NRC Headquarters concerning management-level 

information, special reports, and some NRC resident inspector notifications. The NRC 

discontinued these reports on September 1, 2009. Like the PNOs, these reports were collected 

for each region, by year and number. They were not sequentially numbered, and the total 

number of events was approximately 1,400. Therefore, as for the PNOs, this set of reports was 

only sample-searched. 

Two engineers (a primary reviewer who examined the reports in detail and a secondary 

reviewer who corroborated the first reviewer‘s findings, as previously discussed for a similar 

process) reviewed the sample set of these reports. If the two engineers disagreed, the event 

was passed on to the next phase of data acquisition (i.e., binning). The first-level screening 

resulted in a secondary review of 24 PNOs, 62 event notifications (ENs), and 5 Headquarters 

daily reports. This second level of review resulted in the inclusion of one PNO (Ref. 88), seven 

ENs (Refs. 89–95), and no Headquarters reports in the binning process of data acquisition.

In 10 CFR Part 21, ―Reporting of Defects and Noncompliance‖ (Ref. 96), the NRC establishes 

the procedures and requirements for NPP license holders to report any facility, activity, or 

component that fails to comply with the Atomic Energy Act of 1954. Reports made in 

accordance with this regulation are known as ―Part 21 reports.‖ The NRC receives these 

reports and enters them in the Part 21 report database (Ref. 97). The titles of the 487 Part 21 

reports from 1997 through 2010 were reviewed for potential inclusion in the binning process of 

this project. One notification, No. 2005-23, was examined and reviewed in greater detail. 

However, this notification was actually a 10 CFR 50.72 report (EN 41783) dated June 17, 2005, 

and subsequently withdrawn on August 2, 2005. The report involved the pressurizer heater 

elements of a pressurized-water reactor (PWR) and was eliminated from the binning process.

3.2.4 NRC Guides

The NRC has developed staff guidance documents to facilitate the review of LRAs prepared in 

accordance with the License Renewal Rule (Ref. 28). These guidance documents, called 

license renewal interim staff guidance (LR-ISG), provide a process to capture and communicate 

interim guidance for new insights, lessons learned, and emergent issues to create a license 

renewal program that progressively improves (Ref. 98). The NRC tracks and posts the various 

LR-ISGs (Ref. 99). The LR-ISGs were reviewed as a source of potential operating experience 

or lessons-learned information for the four areas of study for this project. LRA-ISG-2006-01, 

―Final License Renewal Interim Staff Guidance LR-ISG-2006-01: Plant-Specific Aging 

Management Program for Inaccessible Areas of Boiling Water Reactor Mark I Steel 

Containment Drywell Shell,‖ dated November 16, 2006 (Ref. 100), was selected for the binning 

process for this project. The remaining LRA-ISGs were rejected from further consideration.

The NRC issues regulatory guides (RGs) ―to describe to the public methods that the staff 

considers acceptable for use in implementing specific parts of the agency‘s regulations, to 

explain techniques that the staff uses in evaluating specific problems or postulated accidents, 

and to provide guidance to applicants.‖ NRC databases list all of the RGs (Ref. 101) and draft 

RGs (Ref. 102). The titles of the RGs and draft RGs were reviewed for applicability to this 

project. Eight RGs (Refs. 54–55, 103–108) were selected for the binning process of the data 

acquisition phase of this project.
18

3.2.5 NRC Publications

NRC publications by the staff (NUREGs) and NRC contractors (NUREG/CRs) were considered 

for possible operating experience information or lessons-learned data to be included as part of 

the data acquisition for this project. NUREG/CR-6927, ―Primer on Durability of Nuclear Power 

Plant Reinforced Concrete Structures—A Review of Pertinent Factors,‖ issued February 2007

(Ref. 26), which has an extensive list of references concerning NRC publications related to 

concrete degradation, was considered to be a comprehensive resource. Therefore, it was 

decided to concentrate the current review on reports issued after this document was published 

(February 2007).

The NRC maintains a current list of staff and contractor reports (Refs. 109 and 110). The 

81 staff reports, from NUREG-1853 through NUREG-1934, were reviewed, and only 

NUREG-1863, ―Review of Responses to NRC Bulletin 2003-02,  ̳Leakage from Reactor 

Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure Boundary Integrity,‘‖ 

issued September 2006 (Ref. 18), was determined to have information relevant to this project 

and hence was included in the binning process. Similarly, the 75 NRC contractor reports, from 

NUREG/CR-6928 through NUREG/CR-7003, were reviewed. Eight of these reports were 

examined in more detail, and, of these eight reports, only NUREG/CR-6986, ―Evaluations of 

Structural Failure Probabilities and Candidate Inservice Inspection Programs,‖ issued May 2009 

(Ref. 111), was considered to have relevant information for the purposes of this project and was 

included in the binning process.

3.3 Selected Licensee Inspection Reports

In 10 CFR 50.55, ―Conditions of Construction Permits, Early Site Permits, Combined Licenses, 

and Manufacturing Licenses,‖ the NRC establishes the terms and conditions of the license or 

permit (e.g., manufacturing permit, construction permit, early site permit, combined license) for 

each of the licensees of NPPs. For example, 10 CFR 50.55 sets forth the requirement for 

notifying the NRC if a substantial safety hazard exists or a defect is found in the construction of 

the NPP. The regulation further delineates specifications in 10 CFR 50.55a, ―Codes and 

Standards,‖ for systems and components of both boiling-water reactors (BWRs) and PWRs, as 

it states that the systems and components must ―meet the requirements of the ASME Boiler and 

Pressure Vessel Code.‖ Also, 10 CFR 50.55a sets forth the requirements for continuous 

examination, investigation, and inspection required to maintain an NPP license. Two subparts 

of 10 CFR 50.55a specifically govern the licensee‘s inspection of containments for both BWRs 

and PWRs. The regulations in 10 CFR 50.55a(b)(2)(viii) and 10 CFR 50.55a(b)(2)(ix) require 

licensees to conduct periodic inspections of their respective containment.

As a result of these Federal regulations, the licensees file regular inspection reports with the 

NRC in accordance with 10 CFR 50.55. These reports are called inservice inspection reports 

(ISIs), owner‘s activity reports, or refueling outage ISIs. Hereafter, for brevity, these reports will 

be collectively referred to as ISIs. The intent is to avoid repetition and redundancy.

The NRC Office of Nuclear Regulatory Research, Division of Engineering, investigated liner 

corrosion ISI reports prepared by the industry during the period from 1999 to February 2010 

(Ref. 112). Reports for NPPs were examined where the containment liner came in contact with 

concrete. For BWRs, this included those with concrete containments (either reinforced or 

posttensioned) with steel liners (11 BWRs) (Ref. 14) and one with a freestanding steel primary 

containment (Nine Mile Point Nuclear Station, Unit 1). All PWRs were included except those 
19

with a large, dry steel cylinder primary containment, those with a reinforced concrete shield 

building (seven PWRs), and those with an ice condenser steel cylinder primary containment 

with a concrete shield building (seven PWRs). NPP ISIs examined included 12 for BWRs and 

55 for PWRs. The breakdown by category was (1) 12 BWRs, (2) seven PWRs with reinforced, 

subatmospheric primary containment, (3) 10 PWRs with reinforced concrete dry containment, 

(4) two PWRs with reinforced ice condenser primary containment, and (5) 36 PWRs with 

posttensioned dry concrete primary containment. The resulting spreadsheet identified 268 ISIs.

The ISI listings in the resulting spreadsheet were reviewed, and a subset of potential reports to 

be examined in more detail was developed. Of the 268 available ISI reports, 92 were thought to 

contain information that would be pertinent to the issues of this project. Of these 92 ISI reports, 

87 were obtained and sent on for detailed review via the binning process. Because 

concrete-related issues were the primary focus of the NRC study, these 87 reports would 

primarily be related to this report‘s fourth topic of investigation, concrete age-related 

degradation.

3.4 License Renewal Applications and Safety Evaluation Reports

3.4.1 License Renewal Applications

As indicated in Section 1.2 of this report, 10 CFR Part 54, ―Requirements for Renewal of 

Operating Licenses for Nuclear Power Plants‖, governs the renewal of operating licenses for 

NPPs. This Federal regulation defines the NPP current licensing basis (CLB) and defines 

systems, structures, and components (SSCs) within the scope of the regulation. Both the CLB 

and SSCs are clearly defined, including what constitutes a safety-related system and which 

nonsafety-related systems may affect the functions of the safety-related systems. The rule 

further defines both the content and extent of an integrated plant assessment. In addition to 

10 CFR Part 54, guidance documents (e.g., Refs. 31, 32, 34, and 39) are used to develop a 

license renewal application (LRA), as well as to conduct its review and acceptance.

As of August 12, 2011, the NRC listed 52 LRAs for 84 individual NPPs (Ref. 113). This includes 

9 LRAs currently undergoing review and 43 LRAs that have completed the acceptance review 

cycle. The 43 completed LRAs represent 71 units, and the 9 LRAs currently undergoing review 

represent 13 units. 

3.4.2 NRC Safety Evaluation Reports of License Renewal Applications

The NRC safety evaluation reports (SERs) for each of the completed LRAs were reviewed to 

determine if the SER contained information relating to the four areas of study for this project. 

The draft SERs for each of the completed LRAs were also reviewed to ascertain if any early 

information was contained in the draft report but not included in subsequent revisions. This 

meant that, in addition to the 32 SERs, an additional 54 draft SERs were reviewed. Thus, the 

review encompassed a total of 86 documents associated with the completed LRAs. Similarly, 

the SERs for the LRAs still in the review cycle were also examined. 

3.5 Sorting and Binning of Data

The information sources discussed in the foregoing sections of this report are tabulated in 

Table 3-1. Following the initial reviews mentioned in Sections 3.1 and 3.2, two subject matter 
20

experts (SMEs) thoroughly reviewed each item identified in Table 3-1. Also, while reviewing a 

particular report for an event listed in Table 3-1, a reviewer may have discovered references to 

other accounts of the same event. In one case, in IN 2004-09, ―Corrosion of Steel Containment 

and Containment Liner,‖ dated April 27, 2004 (Ref. 43), more than six separate events were 

discussed. Each of these six events referenced other documents or records. Thus, multiple 

sources are noted for several events.

The SMEs placed selected items into one of four bins, with each bin corresponding to one of the 

areas of interest for this report. Usually, both SMEs agreed on the selection of and resulting 

placement into a bin; however, if the SMEs did not agree on keeping the item for the binning 

process, the item was kept for the binning process and a more detailed review. That is, if either 

SME selected an item for binning, it was sent to the next phase.

Some items that were kept for the binning process were rejected from further study or analysis 

after a more thorough examination by an SME. Chapter 4 of this report discusses this 

advanced examination of the items. Additionally, if any item selected for binning contained 

information pertaining to more than one area of interest, it was duplicated and retained in both 

bins. For example, if an LER had information regarding both concrete degradation and reactor 

refueling cavity leakage, then it was noted and copied to both areas. After this initial binning 

process, the items were collected under each area of interest to be analyzed as a group. Each 

item was also uniquely identified and gathered into a table listing all the items for each of the 

four areas. 
21

Table 3-1 Data Acquisition

Data Source Number of 

Items

Potential 

Source of 

Information

1

st

Screen 

Reject

Bin

LERs

Licensee Event 

Reports 

(10 CFR 50.73)

1997–2003 5,299 271

2004–2009 2,104 402 591 82

GENERIC COMMUNICATIONS

NRC Administrative Letters 19 0 0 0

NRC Generic Letters 21 1 1 0

NRC Regulatory Issue Summaries 265 3 0 3

NRC Bulletins 13 4 0 4

NRC Information Notices 473 26 9 17

NRC REPORTS

10 CFR Part 21 Reports 544 1 1 0

NRC Preliminary Notification Reports 487 994 

(Sample Search 

Set Results)

24 1

10 CFR 50.72 Reports 10,541 62 7

NRC Daily Reports 1,410 5 0

NRC GUIDES

NRC Regulatory Guides 215 8 0 8

NRC License Renewal Interim Staff Guidance 9 + Multiple 2 1 1

NRC PUBLICATIONS

NRC Staff Reports (NUREGs) 81 1 0 1

NRC Contractor Reports (NUREG/CRs) 75 8 7 1

LICENSEE INSPECTION REPORTS

Selected Licensee Inspection Reports 268 92 5 87

LICENSE RENEWAL APPLICATIONS

License Renewal Applications (LRAs) 46 46 6 40

NRC Safety 

Evaluation Reports 

(SERs) of LRAs

Completed LRA Review 86 86

24 83

LRA Review In Progress 21 21

23

4. DATA SORTING AND SELECTION FOR FURTHER ANALYSIS

4.1 Subject Matter Expert Sorting and Binning

The subject matter experts (SMEs) gathered the information listed for each individual event 

noted from the data sorting and binning process described in the previous chapter and began a 

systematic initial review of the 40 license renewal applications (LRAs), the 83 safety evaluation 

reports (SERs), and the 87 selected inservice inspection (ISI) reports that had not been 

previously reviewed. The initial review of these documents was conducted in a manner like the 

sorting and binning process discussed in Section 3.5 of this report. A second level of review 

was then conducted, in which the reports selected from the first level of review were further 

studied and scrutinized, and items containing information germane to the four areas of study for 

this report were separated into four bins, with each bin corresponding to a particular area of 

study (i.e., reactor refueling cavity (RFC) leakage, spent fuel pool (SFP) leakage, torus 

corrosion and cracking, and concrete degradation). A fifth area was created for events that 

were considered not to be applicable but were assessed as noted below to verify that they 

contained no pertinent information. 

4.2 Events Discarded after Subject Matter Expert Sorting

As noted in the previous paragraph, events that were placed into the fifth area were 

reexamined, and, if they fell into one of the five classifications described below, they were 

excluded from further consideration

First, if the event was determined to be a case of either drywell or containment liner corrosion, 

which is not applicable in this study, it was discarded. Second, if the event was considered to 

be a construction error made during the nuclear power plant‘s (NPP‘s) original construction, it 

was discarded. Third, if an event was determined to be a design deficiency, it was discarded. 

Fourth, events described below that were determined not to be age-related concrete 

degradation were excluded from further study. Construction defects (voids, honeycombing, 

delaminations) and material deficiencies (wrong material, strength too low) were considered not 

to be applicable for this report. Additionally, such things as shrinkage cracking, design errors, 

liner repairs (liner replacement, steam generator replacement), moisture barrier degradation, 

liner coating degradation, bulging or distortion of liner plate, and penetration liner and sleeve 

damage were eliminated from further examination. As delineated in Chapter 5 and appendices, 

some of these items were considered for the SFPs, RFCs, tori, and safety-related concrete 

structures. Finally, physical damage to concrete for which the degradation mechanism involved

a one-time event such as an impact was also discarded from additional study. The fifth and 

final category included events for which information was insufficient to permit a more 

comprehensive analysis. Specific examples of events that were placed into each of these 

categories are discussed below.

Eight events were determined to be a case of either drywell or containment liner corrosion; thus, 

they were not applicable for this study. The eight events occurred at (1) Nine Mile Point Nuclear 

Station, Unit 2, (2) and (3) Susquehanna Steam Electric Station, Units 1 and 2,

(4) Donald C. Cook Nuclear Plant, Unit 1, (5) Dresden Nuclear Power Station, Unit 2,

(6) Sequoyah Nuclear Plant, Unit 2, (7) Surry Power Station, Unit 2, and (8) Salem Nuclear 

Generating Station, Unit 2. 
24

An event that was initially thought to be a case of torus corrosion at the Dresden Nuclear Power 

Station, Unit 3, was evaluated and determined not to warrant further examination because the 

resulting loss of material was deemed to be minor by the SMEs. Section 3.5.2.3.5 of the NRC 

SER (Ref. 114) of the LRA provided the following justification for the omission: 

In its discussion on operating experience, the applicant stated that examinations 

of the Dresden internal drywell accessible steel surfaces during RFOs revealed 

that the original coatings were acceptable other than exhibiting minor surface 

rust, paint flaking and discoloration. The applicant identified no significant 

degradation in the corrective action process records. The internal surfaces of the 

torus for each of the Dresden units were re-coated with an epoxy coating in the 

late 1980‘s during refuel outages D2R11 and D3R10. Surveillance of the coated 

torus internal surfaces during RFOs has resulted in local coating repairs. A 

review of past inspections of the torus shells indicates the majority of the 

problems have been attributed to blistering of coating in small areas, localized 

pitting, and mechanical damage. Since the application of the epoxy protective 

coating on the internal surfaces, torus wall thinning has not been an issue. 

The above is an example of when both SMEs agreed that information was insufficient for the 

conduct of a comprehensive and thorough examination of this event. 

4.3 Summary of Data Sorting Results for Further Analysis

Table 4-1 provides a breakdown of the results by NPP for each of the four areas of interest to 

the program (RFC leakage (―RFC‖), SFP leakage (―SFP‖), torus corrosion and cracking 

(―Torus‖), and age-related concrete degradation (―Concrete‖)). Plants where one of the four 

areas of interest has occurred are indicated by a check mark. Multiple occurrences are 

indicated by more than one check mark. Table 4-2 provides a summary of the data sorting and 

analysis results. The next chapter of this report provides a more detailed summary and 

description of these results.
25

Table 4-1 Summary of Results by Nuclear Power Plant

NPP RFC SFP Torus Concrete

Beaver Valley 1 ✓

Browns Ferry 2 ✓

Browns Ferry 3 ✓

Brunswick 1 ✓

Cooper ✓

Crystal River 3 ✓ ✓✓

Davis-Besse ✓ ✓ ✓✓

Diablo Canyon 1 ✓ ✓

Diablo Canyon 2 ✓ ✓

Duane Arnold ✓ ✓

FitzPatrick ✓

Hope Creek ✓ ✓ ✓

Indian Point 2 ✓ ✓

Kewaunee ✓ ✓ ✓✓

Monticello ✓✓

Nine Mile Point 1 ✓ ✓

Nine Mile Point 2 ✓

Oconee ✓

Oyster Creek ✓ ✓ ✓

Peach Bottom 2 ✓

Peach Bottom 3 ✓

Prairie Island 1 ✓

Prairie Island 2 ✓

Palo Verde 1 ✓

Pilgrim ✓

Salem 1 ✓ ✓ ✓

Salem 2 ✓ ✓ ✓

Seabrook ✓ ✓

Three Mile Island 1 ✓

Turkey Point 3 ✓

Vogtle 1 ✓

Vogtle 2 ✓✓
26

Table 4-2 Summary of Data Sorting and Analysis Results

Category

Reactor

Refueling 

Cavity

Leakage

Spent Fuel Pool 

Leakage

Torus

Corrosion 

and Cracking

Age-Related 

Concrete 

Degradation

No. of Occurrences 11 12 7 26

No. of NPPs 11 12 7 21

No. of Sites 8 10 7 16

No. of Case Studies* 7 9 7 0

Appendix Location* A B C N/A

* Several case studies describing occurrences related to reactor refueling cavity leakage, SFP leakage, 

and torus corrosion and cracking are provided as appendices to this report.
27

5. PRESENTATION FORMAT AND SUMMARY

OF DEGRADATION OCCURRENCES

5.1 Format for Summary Presentation of Results

Following data sorting and binning of information related to each of the four areas of interest to 

this program, a series of tables was generated to summarize the results obtained for each area. 

Each of these tables was formatted according to the following descriptions.

NPP This stands for the nuclear power plant (NPP) name and unit number and follows 

the naming convention used in NUREG-1350, ―2010–2011 Information Digest,‖ 

Volume 23, issued August 2011 (Ref. 1). The plant name has been shortened 

for the sake of brevity when there will be no confusion. 

Plant Type This stands for the NPP type, boiling-water reactor (BWR) or pressurized-water 

reactor (PWR), in conformance with NUREG-1350, Volume 23 (Ref. 1).

Occurrence Date

This corresponds to the year of the occurrence or event. A date range may also 

be displayed (e.g., 2001–2005).

Structure, Component, Material, Aging Effects, and Aging Mechanism

The Degradation Occurrence Database (DOD) compiled by Brookhaven National 

Laboratory (BNL) in NUREG/CR-6679, ―Assessment of Age-Related Degradation 

of Structures and Passive Components for U.S. Nuclear Power Plants,‖ issued 

August 2000 (Ref. 11), and mentioned in Section 3.1 of this report was analyzed, 

and the findings were presented in a table called the Degradation Occurrence 

Table (DOT). It was constructed with 13 columns; the headers for each of the 

columns are defined in NUREG/CR-6679. Since the BNL study was published in 

2000, much effort has gone into creating a standardized approach to aging 

management. The results, NUREG-1800, ―Standard Review Plan for Review of 

License Renewal Applications for Nuclear Power Plants,‖ first issued July 2001

(Ref. 31), and NUREG-1801, ―Generic Aging Lessons Learned (GALL) Report,‖ 

first issued July 2001 (Ref. 32) (i.e., the standard review plan (SRP) on aging 

effects and mechanisms for structures and containments and the GALL Report), 

essentially standardized the examination of NPPs applying for a license renewal 

application (LRA). This current study adapted the DOT column header 

definitions, with adjustments to accurately reflect the types of degradation of 

concrete and steel structures currently known, while still maintaining consistency 

with NUREG-1800 and NUREG-1801. For example, ―system‖ in the DOT 

became ―structure‖ for this study, and, similarly, ―sub component‖ became 

―material.‖ Thereby, the continuity between the DOD and DOT of 

NUREG/CR-6679 and this study is preserved.

NUREG-1800 identifies the various aging effects and mechanisms that apply to 

structures and containments of NPPs as part of the SRP for LRAs for NPPs.
28

Structure—NUREG-1801 indicates that there are three elements of 

concrete containments (both reinforced and post-tensioned): concrete, 

steel, and prestressing systems. Steel containments have two elements: 

steel and concrete. BWR Mark I, II, and III containments have both steel 

and concrete elements.

Component—NUREG-1801 identifies in Chapter II the various components 

found in both steel and concrete containment structures.

Material—NUREG-1801 defines the materials of construction in 

Chapter IX.C.

Aging Effects—Chapter IX.E of NUREG-1801 explains the selected usage 

of many of the standardized aging effects due to associated aging 

mechanisms defined in the GALL Report. Section 3.5 of NUREG-1800 

details those areas of aging management review of LRAs in support of the 

GALL Report.

Aging Mechanisms—Chapter IX.F of NUREG-1801 indicates that ―An aging 

mechanism is considered to be significant when it may result in aging 

effects that produce a loss of functionality of a component or structure...if 

allowed to continue without mitigation.‖ Chapter IX.F lists definitions of the 

various mechanisms associated with the GALL Report. Section 3.5 of 

NUREG-1800 addresses those areas of aging management review and 

aging mechanisms for LRAs in support of the GALL Report.

Environment Chapter IX.D of NUREG-1801 defines the standardized environments used 

in the GALL Report.

Source Document Type

This is a generalized compilation of the types of information sources used 

to determine the structure, component, material, aging effect, and aging 

mechanism for the degradation occurrences listed in the table. When 

sufficient information was provided in the source documents for a specific 

degradation occurrence, a case study was prepared. Section 5.3 provides 

more information on the case studies that have been included as 

appendices to this report. Specific source documents (i.e., references) 

used to prepare each of the case studies is provided in the appropriate 

appendix.

5.2 Degradation Occurrence Summary

5.2.1 Leakage from the Reactor Refueling Cavity

The sorting and binning process by the subject matter experts (SMEs) found 11 separate 

occurrences of leakage from the reactor refueling cavity at 11 different NPPs. These NPPs are 

located at eight different sites throughout the United States. Table 5-1 summarizes the 
29

11 individual occurrences of leakage from the reactor refueling cavity. Case studies for units 

located at the seven of the sites are provided in Appendix A. 

5.2.2 Spent Fuel Pool Leakage

The sorting and binning process by the SMEs found 12 separate occurrences of spent fuel pool 

(SFP) leakage at 12 different NPPs. The 12 NPPs are located at 10 different sites throughout 

the United States. Table 5-2 summarizes the 12 individual occurrences of SFP leakage. A 

detailed description of nine of the degradation occurrences listed in the table is provided in the 

form of case studies located in Appendix B. 

5.2.3 Torus Corrosion and Cracking

The sorting and binning process by the SMEs found seven separate occurrences of torus 

corrosion or cracking at NPPs with a BWR Mark I containment. The seven NPPs involved are 

located at seven different sites throughout the United States. Two of the torus corrosion 

occurrences were at the same NPP but at different times. Table 5-3 summarizes the 

seven individual occurrences of torus corrosion and cracking. A detailed description of seven of 

the degradation occurrences listed in the table is provided in the form of case studies located in 

Appendix C.

5.2.4 Concrete Age-Related Degradation

The sorting and binning process by the SMEs found 26 separate occurrences of age-related 

degradation in safety-related reinforced concrete structures at U.S. NPPs. The 21 NPPs 

involved are located at 16 different sites throughout the United States. Several occurrences of 

degradation were discovered at the same NPP but at different times. Publicly available 

information sources did not provide sufficient information to permit the preparation of case 

studies discussing age-related degradation of the reinforced concrete. Table 5-4 lists the 

26 individual occurrences of age-related degradation in reinforced concrete.

5.3 Case Studies

Each separate occurrence cited in Tables 5-1, 5-2, and 5-3 was investigated. Each 

investigation was extensive and included sources of publicly available information pertaining to 

the event. When the reference sources provided sufficient information about the occurrence, 

results were assembled into a case study. The individual summary descriptions are provided as 

appendices to this report. Appendix A contains case studies for leakage from the reactor 

refueling cavity, Appendix B case studies for SFP leakage, and Appendix C case studies for the 

torus corrosion and cracking in BWR Mark I containments. 
30

Table 5-1 Degradation Occurrence Summary: Leakage from Reactor Refueling Cavit

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Browns Ferry 2

GE BWR MK I

1999

Reactor 

building

Biological 

shield wall and 

containment 

floor

Metal 

containment

Concrete and 

steel reinforcing 

bars

Carbon steel 

drywell shell

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated water 

Browns Ferry 3

GE BWR MK I

1998

Reactor 

building

Biological 

shield wall and 

containment 

floor

Metal 

containment

Concrete and 

steel reinforcing 

bars

Carbon steel 

drywell shell

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated water 
31

Table 5-1 Degradation Occurrence Summary: Leakage from Reactor Refueling Cavity (c

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Hope Creek

GE BWR/4 MK I

2009

Reactor 

building

Shield wall

Metal 

containment

Concrete and 

steel reinforcing 

bars

Carbon steel 

drywell shell

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated water 

Indian Point 2

West PWR

2002–2004

Containment 

building

Containment

Reactor 

refueling cavity 

walls

Liner

Concrete and 

steel reinforcing 

bars

Carbon steel 

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water
32

Table 5-1 Degradation Occurrence Summary: Leakage from Reactor Refueling Cavity (c

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Kewaunee

West PWR

2003

Shield 

building

Reactor 

refueling cavity 

walls

Concrete and 

steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water

Oyster Creek

GE BWR MK I

2005

Reactor 

building

Metal 

containment

Carbon steel 

drywell shell

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated water
33

Table 5-1 Degradation Occurrence Summary: Leakage from Reactor Refueling Cavity (c

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Prairie Island 1

West PWR

1998

Containment Containment 

walls and 

floors

Metal 

Containment

Concrete and 

steel reinforcing 

bars

Carbon steel 

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated

borated water 

Prairie Island 2

West PWR

1998

Containment Containment 

walls and 

floors

Metal 

Containment

Concrete and 

steel reinforcing 

bars

Carbon steel 

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water 
34

Table 5-1 Degradation Occurrence Summary: Leakage from Reactor Refueling Cavity (c

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Salem 1

West PWR

2005

Containment 

building

Reactor cavity 

walls and floor 

and 

containment 

floor

Liner

Concrete and 

steel reinforcing 

bars

Carbon steel 

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water

Salem 2

West PWR

2000

Containment 

building

Reactor cavity 

walls and floor 

and 

containment 

floor

Liner

Concrete and 

steel reinforcing 

bars

Carbon steel 

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded

steel

Treated 

borated water 
35

Table 5-1 Degradation Occurrence Summary: Leakage from Reactor Refueling Cavity (c

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Davis-Besse 1

B&W PWR

2000–2009

Unit 1 

containment 

building

East/West and 

incore 

instrumentation 

tunnels

Concrete 

Steel, steel 

reinforcing bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water 
36

Table 5-2 Degradation Occurrence Summary: Spent Fuel Pool Leakage

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Palo Verde 1

CE PWR

2005

Unit 1 fuel 

building

SFP Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material 

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water

Crystal River 3

B&W PWR

2007

Unit 3 

auxiliary 

building

SFP floor and 

walls

Concrete and 

steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water
37

Table 5-2 Degradation Occurrence Summary: Spent Fuel Pool Leakage (cont.)

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Davis-Besse 1

B&W PWR

2000–2009

Unit 1 

auxiliary 

building

SFP floor and 

walls

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water

Diablo Canyon 1

B&W PWR

2010

Unit 1 fuelhandling 

building

SFP floor and 

walls

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water
38

Table 5-2 Degradation Occurrence Summary: Spent Fuel Pool Leakage (cont.)

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Diablo Canyon 2

West PWR

2010

Unit 2 fuelhandling 

building

SFP floor and 

walls

Concrete and 

steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water

Duane Arnold

GE BWR/4 MK I

1994–2009

Reactor 

building

SFP Concrete and 

steel reinforcing 

bars

Concrete—Increase

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated water 
39

Table 5-2 Degradation Occurrence Summary: Spent Fuel Pool Leakage (cont.)

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Hope Creek

GE BWR/4 MK I

2009

Reactor 

building

SFP floor and 

walls

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength 

Steel—Loss of

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated water 

Indian Point 2

West PWR

2005

Unit 2 fuelhandling 

building

SFP floor and 

walls

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water
40

Table 5-2 Degradation Occurrence Summary: Spent Fuel Pool Leakage (cont.)

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Kewaunee

West PWR

2007

Auxiliary 

building

Reinforced 

concrete walls 

and ceiling for 

drumming 

room

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength 

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water

Salem 1

West PWR

2002

Unit 1 fuelhandling and 

auxiliary 

buildings

Interior 

concrete walls 

for Unit 1 

fuel-handling 

and auxiliary 

buildings

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water
41

Table 5-2 Degradation Occurrence Summary: Spent Fuel Pool Leakage (cont.)

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Salem 2

West PWR

2010

Unit 1 fuelhandling and 

auxiliary 

buildings

Interior 

concrete walls 

for Unit 1 

fuel-handling 

and auxiliary 

buildings

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water

Seabrook Station

West PWR

2011

Fuel-handling 

building and 

auxiliary 

buildings

Interior 

concrete walls 

for 

fuel-handling 

and auxiliary 

buildings

Concrete 

Steel reinforcing 

bars

Concrete—Increase 

in porosity and 

permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Steel—Loss of 

material

Concrete—

Aggressive 

chemical 

attack

Steel—General 

and pitting 

corrosion and 

corrosion of 

embedded 

steel

Treated 

borated water
42

Table 5-3 Degradation Occurrence Summary: Torus Corrosion and Cracking

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Cooper

GE BWR/4 MK I

2009

Suppression 

chamber 

(torus)

Steel elements Carbon steel Loss of material due 

to general, pitting, 

and crevice corrosion

Cracking due to cyclic 

loading

Crevice 

corrosion

General 

corrosion

Pitting 

corrosion

Fatigue

Treated water 

Duane Arnold

GE BWR/4 MK I

2009

Suppression 

chamber 

(torus)

Steel elements Carbon steel Loss of material due 

to general, pitting, 

and crevice corrosion

Cracking due to cyclic 

loading

Crevice 

corrosion

General 

corrosion

Pitting 

corrosion

Fatigue

Treated water 
43

Table 5-3 Degradation Occurrence Summary: Torus Corrosion and Cracking (cont.

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

FitzPatrick

GE BWR/4 MK I

2005

Suppression 

chamber 

(torus)

Steel elements Carbon steel Loss of material due 

to general, pitting, 

and crevice corrosion

Cracking due to cyclic 

loading

Crevice 

corrosion

General 

corrosion

Pitting 

corrosion

Fatigue

Treated water 

Hope Creek

GE BWR/4 MK I

2004

Suppression 

chamber 

(torus)

Steel elements Carbon steel Loss of material due 

to general, pitting, 

and crevice corrosion

Cracking due to cyclic 

loading

Crevice 

corrosion

General 

corrosion

Pitting 

corrosion

Fatigue

Treated water 
44

Table 5-3 Degradation Occurrence Summary: Torus Corrosion and Cracking (cont.

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Nine Mile Point 1

GE BWR/2 MK I

2001

Suppression 

chamber 

(torus)

Steel elements Carbon steel Loss of material due 

to general, pitting, 

and crevice corrosion

Cracking due to cyclic 

loading

Crevice 

corrosion

General 

corrosion

Pitting 

corrosion

Fatigue

Treated water 

Oyster Creek

GE BWR/2 MK I 

2002

Suppression 

chamber 

(torus)

Steel elements Carbon steel Loss of material due 

to general, pitting, 

and crevice corrosion

Cracking due to cyclic 

loading

Crevice 

corrosion

General 

corrosion

Pitting 

corrosion

Fatigue

Treated water 
45

Table 5-3 Degradation Occurrence Summary: Torus Corrosion and Cracking (cont.

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Pilgrim

GE BWR/3 MK I

1999 and 2003

Suppression 

chamber 

(torus)

Steel elements Carbon steel Loss of material due 

to general, pitting, 

and crevice corrosion

Cracking due to cyclic 

loading

Crevice 

corrosion

General 

corrosion

Pitting 

corrosion

Fatigue

Treated water 
46

Table 5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Bellefonte 1

B&W PWR

2009

Containment Coupling—rock 

anchor/tendon 

anchor

Steel Loss of prestress Hydrogeninduced SCCRaw water 

Brunswick 1

GE BWR/4 MK I

2004

Service water 

buildings for 

Units 1 and 2

Interior and 

exterior 

surfaces

Concrete Cracking and spalling Aggressive 

chemical attack

Raw water 

Crystal River 3

B&W PWR

2003

Containment Tendon gallery 

walls

Concrete Increase in porosity 

and permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Aggressive 

chemical attack

Leaching of 

calcium 

hydroxide

Ground water/

soil

Crystal River 3

B&W PWR

2007

Containment Tendons Steel Loss of prestress Stress 

relaxation

Concrete 
47

Table 5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation (con

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environmen

Davis-Besse 1

B&W PWR

2010

Unknown 

building and 

switchyard

Auxiliary 

feedwater pump 

turbine exhaust 

missile barrier

Tower and 

disconnect switch 

concrete 

foundations

Concrete and 

steel reinforcing 

bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Aggressive 

chemical 

attack

Raw water 

Diablo Canyon 1

West PWR

2010

Intake and 

discharge 

structures

Exterior concrete 

surfaces

Concrete and 

steel reinforcing 

bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Aggressive 

chemical 

attack

Raw water 

Diablo Canyon 2

West PWR

2010

Intake and 

discharge 

structures

Exterior concrete 

surfaces

Concrete and 

steel reinforcing 

bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Aggressive 

chemical 

attack

Raw water 

Kewaunee

West PWR

1997

Screen house 

and tunnel

Walls Concrete Cracking Leaching of 

calcium 

hydroxide

Raw water 
48

Table 5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation (con

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects Aging Mechanism Environment 

Kewaunee

West PWR

2003

Not 

reported

Walls Concrete Increase in porosity 

and permeability, 

cracking, loss of 

material (spalling, 

scaling), and loss of 

strength

Aggressive 

chemical attack

Leaching of calcium 

hydroxide

Ground

water/soil

LR

LR

Lic

NR

Monticello

GE BWR/3 MK I

1998

Not 

reported

Not reported Concrete and 

steel 

reinforcing 

bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Corrosion of 

embedded steel

Not reported LR

LR

Monticello

GE BWR/3 MK I

2001/2002

Not 

reported

Not reported Concrete and 

steel 

reinforcing 

bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Corrosion of 

embedded steel

Not reported LR

LR

Nine Mile Point 1

BWR MK I

2005

Service 

water pipe 

tunnel

Walls Concrete Cracking Service-induced 

cracking or other 

aging mechanisms

Ground

water/soil

LR

LR

Lic

NR
49

Table 5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation (con

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Nine Mile Point 2

GE BWR/5 MK II

2005

Service water 

pipe tunnel

Walls Concrete Cracking Serviceinduced 

cracking or 

other aging 

mechanisms

Ground

water/soil

Oconee

B&W PWR

1998

Containment Concrete 

beneath 

tendon bearing 

plate

Concrete Concrete cracking 

and spalling

Serviceinduced 

cracking or 

other concrete 

aging 

mechanisms

Air—indoor 

uncontrolled

Oyster Creek

GE BWR/2 MK I

2001

Containment Drywell shield 

wall

Concrete Cracking Elevated 

temperature

Air—indoor 

uncontrolled

Peach Bottom 2

GE BWR/4 MK I

2001

Emergency 

cooling tower 

and reservoir

Walls Concrete Cracking Leaching of 

calcium 

hydroxide

Raw water 
50

Table 5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation (con

NPP

Plant Type

Occurrence Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Peach Bottom 3

GE BWR/4 MK I

2001

Emergency 

cooling 

tower and 

reservoir

Walls Concrete Cracking Leaching of 

calcium 

hydroxide

Raw water 

Salem 1

PWR

2010

Service 

water intake 

structure

Walls Concrete and steel 

reinforcing bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Aggressive 

chemical 

attack

Corrosion of 

embedded 

steel

Raw water 

Salem 2

West PWR

2010

Service 

water intake 

structure

Walls Concrete and steel 

reinforcing bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Aggressive 

chemical 

attack

Corrosion of 

embedded 

steel

Raw water 
51

Table 5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation (con

NPP

Plant Type

Occurrence 

Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Seabrook

West PWR

2006

Below-grade 

concrete 

structures

Walls and floor 

slabs

Concrete Increase in porosity and 

permeability, cracking, 

loss of material 

(spalling, scaling), and 

loss of strength

Aggressive 

chemical attack

Leaching of 

calcium 

hydroxide

Ground

water/soil

TMI 1

B&W PWR

2004

Containment Dome and ring 

girder

Concrete and 

steel 

reinforcing 

bars

Cracking, loss of bond, 

and loss of material 

(spalling, scaling)

Leaching of 

calcium 

hydroxide

Corrosion

Air—outdoor 

Turkey Point 3

West PWR

2007

Containment Buttress Concrete and 

steel 

reinforcing 

bars

Cracking, loss of bond, 

and loss of material 

(spalling, scaling)

Not reported Air—outdoor 

Vogtle 1

West PWR

1/07/1998 and 

1998

Diesel 

generator 

building

Exhaust pipe 

concrete 

barriers

Concrete and 

steel 

reinforcing 

bars

Cracking, loss of bond, 

and loss of material 

(spalling, scaling)

Service-induced 

cracking or other 

concrete aging 

mechanisms

Air—indoor 

uncontrolled
52

Table 5-4 Degradation Occurrence Summary: Concrete Age-Related Degradation (con

NPP

Plant Type

Occurrence 

Date 

Structure Component Material Aging Effects 

Aging 

Mechanism 

Environment 

Vogtle 2

West PWR 

1998

Diesel 

generator 

building

Exhaust pipe 

concrete 

barriers

Concrete and steel 

reinforcing bars

Cracking, loss of 

bond, and loss of 

material (spalling, 

scaling)

Serviceinduced 

cracking or 

other concrete 

aging 

mechanisms

Air—indoor 

uncontrolled

Vogtle 2

West PWR

1999

Containment Buttress Concrete Concrete cracking 

and spalling

Not reported Air—outdoor 
53

6. REVIEW OF DEGRADATION OCCURRENCES

6.1 Introduction

Detailed descriptions of the areas related to degradation occurrences associated with the 

specific topics of interest to this study (i.e., reactor refueling cavity leakage, spent fuel pool 

(SFP) leakage, and torus corrosion and cracking) are provided in Appendices A, B, and C, 

respectively. The descriptions for each of these topics of interest were reviewed, and the 

results are summarized and presented here with respect to the specific areas of interest. 

Specific references pertaining to information summarized in this chapter are provided in the 

appropriate appendix. Finally, this chapter provides a review of age-related degradation of 

concrete structures. Occasionally, some information applies to more than one topic of interest 

and the subject matter expert has included it where most appropriate.

6.2 Leakage from the Reactor Refueling Cavity

In a pressurized-water reactor (PWR), the reactor refueling cavity is a reinforced concrete 

structure that extends from the reactor cavity to the outlet of the fuel transfer tube at the 

containment building cylindrical wall. The cavity internal surfaces are typically lined with 

stainless steel plate on the order of 6.35 millimeters (mm) (0.25 inches) thick. A leak chase 

system embedded in the walls and slabs collects leakage through the seam welds of the liner. 

The reactor refueling cavity is filled with borated water during refueling to permit underwater 

transport of fuel elements between the SFP and the reactor vessel through the reactor refueling 

cavity and the fuel transfer tube. The discharge end of the fuel transfer tube into the fuel 

transfer canal is sealed with a gasketed flange during plant operation to form the containment 

pressure boundary. The fuel transfer cavity can be isolated from the spent fuel storage pool and 

drained by using a fuel pool gate for maintenance of the fuel-handling system. The gate seal 

consists of short-lived inflatable seals supplied with air by the compressed air system. The 

cavity is drained after refueling and maintained dry during plant operation. The reactor refueling 

cavity pool can be on the order of 3.7 meters (m) by 8.8 m in plan by 14 m deep (12 feet by 

29 feet by 46 feet). Primary age-related degradation mechanisms that can produce leakage 

through the stainless steel liner include fatigue, intergranular stress-corrosion cracking, and 

crevice corrosion. Leakage can also occur as a result of weld defects, blockage of the leakage 

collection system by precipitation of reaction products or foreign matter, damage to the liner, or 

a breakdown of the gasketed seal. Leakage primarily will occur only during refueling and could 

potentially result in erosion of the concrete due to the mildly acidic nature of the borated water, 

or in corrosion of any carbon steel component it contacts (e.g., the metallic pressure boundary 

or concrete steel reinforcement). Leakage that is not captured by the monitoring system can 

migrate through construction joints and cracks in the concrete. 

For boiling-water reactor (BWR) plants, the reactor refueling cavity is located above the reactor 

pressure vessel and adjacent to the SFP, as illustrated in Figure 6-1. The reactor refueling 

cavity is constructed of reinforced concrete, with its inner surface lined with stainless steel to 

provide a leak-tight barrier. Potential causes of leakage from the reactor refueling cavity are 

cracking of the liner or welds due to fatigue resulting from periodic filling of the reactor refueling

cavity and equipment pool during refueling, intergranular stress-corrosion cracking, crevice 

corrosion, or a breakdown of the drywell-to-cavity seal. Leakage of water initiates during 

refueling operations (Ref. 115). Figure 6-2 provides an example of a cross section of the 

drywell-to-cavity seal in a BWR Mark (MK) I and identifies one potential leakage path. 
54

As already discussed, leakage from the reactor refueling cavity primarily occurs only during 

refueling operations when the cavity is flooded, at an estimated flow rate that has ranged from a 

drop or less per minute to on the order of 1.9 to 4.4x10-4cubic meters per second (m

3

/s)

(3 to 7 gallons per minute). The leakage may continue a few days after draining the cavity and 

has been identified at the plants listed previously in Table 5-1. The leakage was primarily found 

by visual inspections that identified the presence of fluid in the gap between the drywell and 

concrete shield (BWR), mineral deposits on surfaces of structures (BWR and PWR), or at 

sumps (PWR). 

Sufficient information was available in publicly available sources to prepare case studies for

seven of the occurrences of reactor refueling cavity leakage. The case studies are provided in 

Appendix A. Sufficient information was not available to develop a statistically significant trend 

indicating that reactor refueling cavity leakage was more prevalent in BWRs or PWRs, or for a 

particular nuclear steam supply system supplier, engineering firm, or contractor. Table 6-1 

provides a summary of results related to leakage from the reactor refueling cavity based on the

information contained in Appendix A. Specific topics addressed in the table include the leakage 

source, primary structures potentially impacted, how leakage was identified, activities to address 

leakage, and assessment of structural impact.

6.3 Spent Fuel Pool Leakage

The fuel storage facility provides for receiving, storing, shielding, shipping, and handling of new 

and spent fuel. The fuel storage facility is an integral part of the reactor building of most BWR 

MK I and MK II containment plant types. For BWR MK III containment types and many PWRs, 

the fuel storage facility is a separate structure; however, in some plants the fuel storage facility 

is part of the auxiliary building (Figure 6-3). The fuel storage structure is a multistory reinforced 

concrete structure supported on bearing walls and/or a basemat. The SFP has reinforced 

concrete walls and floors for radiation shielding and a stainless steel liner that provides a 

leak-tight barrier. A typical SFP for a PWR can be on the order of about 12 m (40 feet) deep 

and 12 m (40 feet) or more in each horizontal direction. The SFP walls are constructed of 

reinforced concrete typically having a thickness between 0.7 and 3 m (2 and 10 feet). Cover 

concrete for the embedded steel reinforcement is on the order of 3.8 to 7.6 centimeters (cm)

(1.5 to 3 inches). The inside surfaces of the SFP are typically lined by stainless steel plates, 

having a thickness of about 6 to 13 mm (0.25 to 0.5 inches), that are joined by full-penetration 

seam welds. Between the seams, the liner plates may also be plug welded to studs embedded 

in the concrete. Some plants used the liner as part of the concrete form for the fuel-handling 

building, and other plants ―wallpapered‖ the liner onto the completed concrete structure after the 

forms were removed. At least one PWR has an unlined SFP, with the concrete sealed with an 

epoxy. Leakage collection systems consisting of channels embedded in the concrete at the 

locations of the weld seams are provided to permit monitoring and collection of any SFP

leakage that might occur at the seam welds. The channels are fabricated from either carbon or 

stainless steel that may or may not be seal welded to the back of the liner. The channels lead 

to a series of telltales piped to a collection system and routed to the liquid radwaste system. 

SFPs for BWR plants are filled with demineralized water, whereas those for PWRs contain 

borated water (e.g., 2,200 to 2,400 parts per million boron, pH ~4.8). Primary age-related 

degradation mechanisms that can produce leakage through the stainless steel SFP liner include 

intergranular stress-corrosion cracking and crevice corrosion. Leakage can also occur as a 

result of seam or plug weld defects, blockage of the leakage collection system by precipitation 

of reaction products or foreign material, and damage to the liner. Leakage that is not captured 

by the monitoring system can migrate through construction joints and cracks in the concrete to 

result in release of contaminated water to the environment. Figure 6-4 provides an example 
55

cross section of a leak chase system and a postulated path for leakage occurrence. With 

respect to leakage that bypasses the leak collection system of PWR SFPs, there is an added 

concern because leakage of the borated water over an extended period of time could potentially 

result in erosion of the concrete due to the mildly acidic nature of the borated water, or corrosion 

of any carbon steel it contacts (e.g., metallic pressure boundary or concrete steel 

reinforcement). Often, exterior walls of the SFP are not accessible; therefore, they cannot be 

monitored for visible signs of degradation. 

Leakage of fluid from the SFP can be a continual process, since it remains filled at all times. 

Leakage has been identified at the plants listed previously in Table 5-2, with reported flow rates 

ranging from a drop or less per minute to on the order of 4.3x10-6 m

3

/s (100 gallons per day 

(gpd)). The leakage was primarily found from drainage through the telltale drains of the leak 

chase system, fluids emerging from cracks in reinforced concrete walls of the SFP, or the 

presence of mineral deposits on structures, the presence of fluid in the seismic gap between the 

fuel-handling building and the auxiliary building, contamination of protective shoe covers, and 

the presence of tritium in ground water. 

Sufficient information was available in publicly available sources to prepare case studies for 

nine of the occurrences of SFP leakage. The case studies are provided in Appendix B. 

Although SFP leakage was more common for PWRs than BWRs, sufficient information was not 

available to develop a statistically significant trend indicating that SFP leakage was more 

prevalent for a particular nuclear steam supply system supplier, engineering firm, or contractor. 

Table 6-2 provides a summary of results related to leakage from the SFP based on the 

information contained in Appendix B. Specific topics addressed in the table include the leakage 

source, primary structures potentially impacted, how leakage was identified, activities to address 

leakage, and assessment of structural impact.

6.4 Torus Corrosion and Cracking

The suppression chamber (or wetwell) of a BWR MK I nuclear power plant (NPP) typically

consists of 16 to 20 mitered cylindrical carbon steel (or carbon steel clad with stainless steel) 

segments joined together to form the shape of a torus that encircles the drywell (Figure 6-1). 

The torus is normally about half-full of demineralized water, which constitutes the pressuresuppression pool. The torus cross section can have a major diameter of between 29 and 34 m 

(95 to 112 feet), a minor diameter between 7.6 and 9.4 m (25 and 31 feet), and a shell thickness 

from 9.53 to 25.4 mm (0.375 to 1 inch). The suppression chamber is penetrated by access 

hatches as well as by vent lines that connect it to the drywell. The inside surfaces of the 

suppression chamber exposed to water are typically coated with an inorganic zinc primer with a 

modified phenolic or epoxy-based top coating. The exterior surfaces of the suppression pool of 

some plants have a lead-based coating. Support for the suppression chamber is provided by 

columns on the inside and outside diameter and by a saddle under the torus (Figure 6-5). The 

columns are rigidly supported at the torus shell and connected with rotating pins at the base to 

allow rotation from thermal expansion of the torus. The torus is anchored to and supported by 

the reinforced concrete foundation slab of the reactor building. Potential degradation 

mechanisms for the suppression chamber in areas that are uncoated, or that are not clad by 

stainless steel, include loss of material due to general atmospheric corrosion and localized 

corrosion (e.g., crevice, differential aeration, galvanic, microbiologically induced, and pitting), 

fatigue, and stress-corrosion cracking of stainless steel. Coating degradation can result from 

several types of stressors: temperature, condensation or immersion, radiation, stress-induced 

physical damage, and damage resulting from corrosion of the base metal.
56

Once the torus coating begins to degrade, the steel substrate is susceptible to moisture that can 

lead to corrosion. Licensees typically perform periodic visual inspections of the suppression 

steel shells by either draining the torus and inspecting it under dry conditions or employing 

divers or using cameras to inspect the submerged surfaces. Degradation of tori coatings 

requiring cleaning and recoating has also been identified (Ref. 22). Measured corrosion rates in 

some torus shells have exceeded the design corrosion rate, and plants have identified areas of 

the torus shell in which the thickness was at or below the minimum specified wall thickness 

(Ref. 22). 

Sufficient information was available in publicly available sources to prepare case studies for 

seven of the occurrences of torus corrosion and cracking. The case studies are provided in 

Appendix C. Although several occurrences of torus corrosion and cracking were identified, 

sufficient information was not available to develop a statistically significant trend indicating that 

the torus corrosion and cracking was more prevalent for a particular nuclear steam supply 

system supplier, engineering firm, or contractor. Table 6-3 provides a summary of results 

related to torus corrosion and cracking based on the information contained in Appendix C. 

Specific topics addressed in the table include inspection methods, field observations, corrective 

and aging management actions, and structural integrity assessments.

6.5 Age-Related Degradation of Concrete Structures

All commercial NPPs in the United States contain concrete structures whose performance and

function are necessary for protection of the safety of plant operating personnel and the general 

public, as well as the environment. The basic laws that regulate the design (and construction) 

of NPPs are contained in Title 10 of the Code of Federal Regulations (10 CFR), ―Energy,‖ that is 

clarified by documents such as regulatory guides, NUREG reports, and standard review plans.

Concrete-based structures in light-water reactor plants provide foundation, support, shielding, 

and containment functions. Typically the safety-related concrete structures contained in 

light-water reactor plants may be grouped into four general categories: primary containments, 

containment internal structures, secondary containments/reactor buildings, and other structures. 

Only information related to primary containment structures for PWR and BWR plants is 

summarized below. Information on other concrete structures is provided elsewhere (Ref. 2). 

Safety-related concrete structures are those that are relied upon to remain functional during and 

following design-basis events and nonsafety-related structures whose failure could prevent 

satisfactory accomplishment of any of the functions as defined in 10 CFR 54.4, ―Scope.‖

Approximately 80 percent of the PWR plants that have been licensed for commercial operation 

in the United States use either reinforced or prestressed concrete primary containments. The 

concrete containments are of three different functional designs: subatmospheric (reinforced 

concrete), ice condenser (reinforced concrete), and large dry (reinforced and prestressed 

concrete). The primary differences between these containment designs relate to volume 

requirements, provisions for accident loadings and pressures, and containment internal 

structures layout. The PWR concrete containment structure generally consists of a concrete 

basemat foundation, vertical cylindrical walls, and dome. Leak tightness of a containment is 

provided by a steel liner attached to the containment inside surfaces. Exposed surfaces of the 

carbon steel liner are typically painted to protect against corrosion and to facilitate 

decontamination, should it be required. Depending on the functional design (e.g., large dry or 

ice condenser), the concrete containments can be on the order of 40 to 50 m in diameter and 60

to 70 m high, with wall and dome thicknesses from 0.9 to 1.4 m, and base slab thicknesses 

from 2.7 to 4.1 m. Figure 6-6 presents the Trojan nuclear plant cooling tower and posttensioned 
57

concrete containment prior to decommissioning and demolition. PWR plants that use a metallic 

primary containment (large dry and ice condenser designs) are usually contained in reinforced 

concrete ―enclosure‖ or ―shield‖ buildings that, in addition to withstanding environmental effects, 

provide radiation shielding and particulate collection and ensure that the free-standing metallic 

primary containment is protected from the natural environment. 

Of the BWR plants in the United States, approximately 30 percent use a reinforced concrete 

primary containment. BWR containments, because of provisions for pressure suppression, 

typically have ―normally dry‖ sections (drywell) and ―flooded‖ sections (wetwell) that are 

interconnected via piping or vents. BWR plants that use steel primary containments have 

reinforced concrete structures that serve as secondary containments or reactor buildings. The 

secondary containment structures generally are safety-related because they provide additional 

radiation shielding; provide resistance to environmental and operational loadings; and house 

safety-related mechanical equipment, spent fuel, and the primary metal containment. Although 

these structures may be massive in cross section in order to meet shielding or load-bearing 

requirements, they generally have smaller net sections than primary containments because of 

reduced exposure under postulated accident loadings.

Exposure to the environment (e.g., temperature, moisture, cyclic loadings) can produce 

degradation of reinforced concrete structures. The rate of deterioration is dependent on the 

component‘s structural design, materials selection, quality of construction, curing, and 

aggressiveness of environmental exposure. Termination of a component‘s service life occurs 

when it no longer can meet its functional and performance requirements. 

Primary mechanisms (factors) that, under unfavorable conditions, can produce premature 

deterioration of reinforced concrete structures include those that impact either the concrete or 

steel reinforcing materials (i.e., mild steel reinforcement or posttensioning systems). 

Degradation of the concrete can be caused by adverse performance of either its cement-paste 

matrix or aggregate materials under chemical or physical attack. In nearly all chemical and 

physical processes influencing the durability of concrete structures, the dominant factors include

the transport mechanisms within the pores and cracks and the presence of water. Degradation 

of mild steel reinforcing materials can occur as a result of corrosion, irradiation, elevated 

temperature, or fatigue effects, with corrosion being the most likely form of attack. 

Posttensioning systems are susceptible to the same degradation mechanisms as mild steel 

reinforcement, plus loss of prestressing force, primarily due to tendon relaxation, and concrete 

creep and shrinkage. Additional information on the durability of NPP reinforced concrete 

structures is available (Ref. 26).

Known problem areas associated with the degradation of reinforced concrete components in 

NPP applications through 1986 are described in NUREG/CR-4652, ―Concrete Component 

Aging and Its Significance Relative to Life Extension of Nuclear Power Plants,‖ issued 

September 1986 (Ref. 116). Because the operating history of these NPPs was limited 

(approximately 20 years or less), many of these problem areas involved the following conditions 

that are not directly related to a specific concrete aging mechanism or environment:

 construction defects (voids, surface honeycombing, delaminations, reinforcing bar 

placement errors) and material deficiencies (wrong concrete mixture, concrete strength 

too low, prestressing tendon wire and button head failure)
58

 concrete shrinkage cracking

 design errors

In 1992, the NRC received survey responses from 29 utilities concerning the types and 

locations of concrete distress, the types of repairs performed, and the durability of the repairs. 

Survey results pertaining to the concrete structures at these plants are described in 

NUREG-1522, ―Assessment of Inservice Conditions of Safety-Related Nuclear Plant 

Structures,‖ issued June 1995 (Ref. 9), and summarized below:

 Locations of Deterioration—Auxiliary building and secondary containment (shield 

building) walls and slabs were noted as the most common locations.

 Type of Deterioration—86 percent of the plants reported cracking; 65 percent reported 

spalling; and over 20 percent of the respondents reported staining, honeycombing, 

efflorescence, and scaling.

 Causes of Deterioration—48 percent (of the respondents) reported deterioration 

resulting from drying shrinkage, 31 percent from freeze-thaw, and 24 percent from 

abrasion.

NUREG-1522 also provided results from the inspections of six plants that were licensed prior to 

1977 where the following types of degradation of the reinforced concrete structures were noted:

 tendon galleries of posttensioned concrete containments

 water leakage and seepage in underground structures

 intake tunnels

NUREG/CR-6679, ―Assessment of Age-Related Degradation of Structures and Passive 

Components for U.S. Nuclear Power Plants,‖ issued August 2000, presented an assessment of 

age-related degradation of structures and passive components for U.S. NPPs (Ref. 11). 

Included in this assessment was a tabulation of degradation occurrences involving concrete 

structures, with the findings reported in NUREG-1522 (Ref. 9). A summary of degradation 

occurrences reported in NUREG/CR-6679 related to NPP concrete structures is presented in 

Figure 6-7. However, the definitions of concrete aging effects and aging mechanisms used to 

describe the degradation included both aging- and nonaging-related conditions, with some of 

the aging mechanisms for specific degradation occurrences reported as not applicable. In 

addition, many of the degradation occurrences reported in the above document were based on 

information that either is not publicly available or is published in a format that is not 

electronically searchable. 

The identification of occurrences of degradation in the present study concentrated on the 

following types of concrete structures: containments, concrete service water intake and 

discharge structures and service water pipe tunnels, above-grade concrete structures, and 

below-grade concrete structures. As a minimum, selection of the occurrences involved 

identification of the aging effects for a damaged structure from information in publicly available 

documents, followed by identification of the associated aging mechanisms and environment. 

Occurrences that pertain to the areas identified in Section 1.3.4 were then excluded. 
59

Application of this methodology required interpretation of text in various types of documents to 

develop an understanding of the relevant circumstances associated with the degradation and 

identification of the root cause and contributing factors of the specific event. Engineering 

judgment was then applied to characterize the aging effect, aging mechanism, and environment 

using the standardized terminology and definitions in NUREG-1801, ―Generic Aging Lessons 

Learned (GALL) Report,‖ first issued July 2001 (Ref. 32). Table 6-4 provides a summary of the 

age-related degradation occurrences that were identified in this study as well as the age-related 

events that were reported in NUREG/CR-6927, ―Primer on Durability of Nuclear Power Plant 

Reinforced Concrete Structures—A Review of Pertinent Factors,‖ issued February 2007

(Ref. 26).

Terms and definitions established by the NRC to describe aging effects, aging mechanisms, 

and environments applicable to concrete structures are published in NUREG-1801 (Ref. 32). 

These terms and definitions are used in the present study as the basis for characterizing the 

age-related degradation occurrences in safety-related concrete structures. Because the terms 

and definitions used to describe concrete aging effects and aging mechanisms in 

NUREG/CR-6679 (Ref. 11) were not consistent with those in NUREG-1801, results obtained in 

the present study will not identify all of the occurrences listed as degradation for concrete 

structures reported in NUREG/CR-6679.

It is to be noted that NUREG-1801 provides the technical basis and guidance to license renewal 

applicants for aging management practices that have been successfully used to monitor and 

manage aging effects in structures, thus assuring that their integrity is maintained during the 

period of extended operation. The programs are continuously updated by NRC staff to handle 

emerging structural integrity issues through license renewal interim staff guidance, newer 

releases/revisions of NUREG-1801, and pertinent research documented in other supplemental 

NRC publications and NUREGs (see Chapters 1 and 2). A license renewal applicant may 

reference NUREG-1801 to demonstrate that its approach is conforming to the recommended 

programs and their technical bases for managing aging effects in concrete structures in the 

period of extended operation. 
60

Figure 6-1 Cross section of BWR MK I showing location of reactor refueling cavity, spent 

fuel pool, and torus as well as one leakage path that has been observed

(Source: “Advisory Committee on Reactor Safeguards Hope Creek License Renewal 

Subcommittee,” Official Transcript of Proceedings Nuclear Regulatory Commission, 

Work Order No. NRC-542, Neal R. Gross and Co., Inc., Court Reporters and Transcribers, 

Washington, D.C., November 3, 2010)

Figure 6-2 Detail of drywell—reactor cavity seal area and 

identification of potential leakage path

(Source: “Advisory Committee on Reactor Safeguards Hope Creek License Renewal 

Subcommittee,” Official Transcript of Proceedings Nuclear Regulatory Commission, 

Work Order No. NRC-542, Neal R. Gross and Co., Inc., Court Reporters and Transcribers, 

Washington, D.C., November 3, 2010)
61

Figure 6-3 Plan view of fuel-handling building showing relative location 

of spent fuel pool, transfer pool, and containment building

(Source: “Advisory Committee on Reactor Safeguards Plant License Renewal 

Subcommittee,” Official Transcript of Proceedings Nuclear Regulatory Commission, 

Work Order No. NRC-577, Neal R. Gross and Co., Inc., Court Reporters and Transcribers, 

Washington, D.C., December 1, 2010)

Figure 6-4 Cross section of a leak chase system for a PWR plant

and a postulated path for leakage occurrence

(Source: Samuel Cuadrado de Jesús, “Advisory Committee on Reactor Safeguards 

(ACRS) License Renewal Full Committee Salem Nuclear Generating Station Safety 

Evaluation Report,” U.S. Nuclear Regulatory Commission, Washington, DC, 

May 12, 2011)
62

Figure 6-5 Cross section of BWR suppression chamber torus

(Source: Electric Power Research Institute, “BWR Containments License Renewal 

Industry Report: Revision 1,” EPRI TR-103840, Palo Alto, CA, July 1994)

Figure 6-6 Trojan nuclear power plant 

posttensioned concrete containment 

(Source: Naus, D.J. and C.B. Oland, “An Investigation of Tendon Sheathing Filler 

Migration Into Concrete,” NUREG/CR-6598. U.S. Nuclear Regulatory Commission: 

Washington, DC. March 1998)
63

Figure 6-7 Summary of degradation occurrences reported in NUREG/CR-6679 related to 

nuclear power plant concrete structures, including associated metal subcomponents

(Source: Braverman, J.I., C.H. Hofmayer, R.J. Morante, S. Shteyngart, and P. Bezler. 

“Assessment of Age-Related Degradation of Structures and Passive Components for 

U.S. Nuclear Power Plants.” NUREG/CR-6679. U.S. Nuclear Regulatory Commission: 

Washington, DC. August 2000)
64

Table 6-1 Leakage from Reactor Refueling Cavity—

Summary of Information Contained in Appendix A

Topic Type

Plant Commentary

Leakage 

source

BWR Failure of the drywell-to-refueling-cavity seal; small cracks in the 

liner; or cracks in either the welds of the reactor cavity seal plates, 

refueling bellows, or reactor cavity drain lines

PWR Liner seam, plug, or structural attachment weld defects; cracks in 

the embedment plates for reactor vessel internals stands support 

and the rod control cluster change fixture; or reactor cavity and fuel 

transfer canal liner cracks

Primary 

structures 

potentially 

impacted

BWR Cylindrical portion of drywell shell and sand bed region of MK I 

containments; and support structures

PWR Reinforced concrete structures; liners of reinforced concrete 

containments; supports; steel containment vessels; and carbon 

steel structures where borated water accumulates

How leakage 

was identified

BWR Water leakage from sand drains (Browns Ferry Nuclear Plant, 

Units 2 and 3)

Water trickling from a drywell shield wall penetration that produced 

ponding on the torus room floor (Hope Creek Generating Station, 

Unit 1)

Water in the gap between the drywell and concrete shield (Oyster 

Creek Nuclear Generating Station)

PWR Water leaking through liner plates that collects in a drainage 

trench (Indian Point Nuclear Generating Unit 2)

Leaching and cracking on the outer concrete surface of the reactor 

refueling cavity wall (Kewaunee Power Station)

Leakage in the emergency core cooling system sump and the 

ceiling of the regenerative heat exchanger room below the reactor 

refueling cavity (Prairie Island Nuclear Generating Plant, Unit 1 

and Unit 2)

White deposits present at several locations in containment (Salem 

Nuclear Generating Station, Unit 1)

Liquid running down the containment liner plate and lagging under 

the fuel transfer canal inside containment and pooling on the 

concrete floor during refueling operations; leakage from the telltale 

drains of the leak chase system (Salem Nuclear Generating 

Station, Unit 2
65

Table 6-1 Leakage from Reactor Refueling Cavity—

Summary of Information Contained in Appendix A (cont.)

Topic Type

Plant Commentary

How leakage 

was identified

(cont.)

PWR 

(cont.)

Boric acid deposits over a large surface area of the containment 

incore instrumentation tunnel walls and undervessel area 

(Davis-Besse Nuclear Power Station)

Activities to 

address 

leakage

BWR Visual inspections of the interior surface of the drywell and the 

interior and exterior surface of the drywell head; ultrasonic 

thickness measurements (Browns Ferry Nuclear Plant, Units 2 

and 3)

Clear the drywell air gap drain lines of blockage; verify that 

reactor cavity seal rupture drain lines are clear of blockage and 

that monitoring instrumentation is functioning properly; monitor 

daily leakage from the penetration sleeve, drywell air gap drain 

lines, and reactor cavity seal rupture drain lines; perform 

boroscope inspections to identify conditions that prevent water 

leakage from reaching the drywell lower air gap drains; observe 

variations in water leakage and how it is affected by water levels 

in the reactor cavity (Hope Creek Generating Station, Unit 1)

Perform visual inspections and apply dye penetrant to the 

reactor refueling cavity liner to identify cracks in the stainless 

steel liner; apply adhesive stainless steel tape to bridge any 

observed large cracks, followed by the application of strippable 

coating; repeat the application of strippable coating to the liner 

prior to any future reactor refueling cavity flooding; verify that 

the reactor refueling cavity concrete trough drain is clear of 

blockage once per refueling cycle; and investigate cost-effective 

repair or replacement options to eliminate or reduce reactor 

refueling cavity leakage (Oyster Creek Nuclear Generating 

Station)
66

Table 6-1 Leakage from Reactor Refueling Cavity—

Summary of Information Contained in Appendix A (cont.)

Topic Type

Plant Commentary

Activities to 

address 

leakage 

(cont.)

PWR Apply patches (coatings) to suspect areas (ineffective); water 

chemistry program for reactor refueling cavity liner; visual 

inspections of accessible surfaces under the structures monitoring 

program for concrete structures (Indian Point Nuclear Generating 

Unit 2)

Increase frequency of visual examination of concrete structures 

under the structures monitoring program for each refueling 

outage; inspect current leakage sites and containment internal 

structures to identify the sites of any additional leakage indications 

and document any new sites or changes in exiting sites in the 

corrective action program (Kewaunee Power Station)

Initially, a spray-on sealer was applied that provided limited 

success due to a difficult application process and procedure 

inadequacies; more recently, reactor vessel internals stands and 

rod control cluster assembly change fixture embedment plates 

were repaired by replacement of existing nuts on attachment bolts 

with blind nuts that were seal-welded to the baseplate, application 

of seal weld between the baseplate and embedment plate, and 

examination of welds by nondestructive examination (NDE), and 

NDE of liner-to-floor embedment plate filet welds; perform visual 

inspections of the liner plate and conduct vacuum box testing of 

liner plate seam welds; manage aging of containment structures 

and containment vessels by using the structures monitoring 

program and the American Society of Mechanical Engineers 

(ASME) Boiler and Pressure Vessel Code (ASME Code) 

Section XI, Subsection IWE, program (Prairie Island Nuclear 

Generating Plant, Unit 1 and Unit 2)

Periodically inspect telltale drains and monitor for leakage when 

the reactor refueling cavity is flooded, manage aging using the 

structures monitoring program and ASME Code Section XI, 

Subsection IWE, program (Salem Nuclear Generating Station, 

Units 1 and 2)

Fill and hold activities were performed during the spring 2010 

refueling outage that identified the SFP elevation at which 

leakage occurs; a plan is being prepared to do vacuum box 

testing to identify the locations of potential leakage; if testing is 

successful, a repair plan will be developed to mitigate leakage 

(Davis-Besse Nuclear Power Station)
67

Table 6-1 Leakage from Reactor Refueling Cavity—

Summary of Information Contained in Appendix A (cont.)

Topic Type

Plant Commentary

Assessment 

of structural 

impact

BWR Ultrasonic measurements of the drywell shell in the sand pocket 

region indicate no damage to integrity (Browns Ferry Nuclear 

Plant, Units 2 and 3)

Ultrasonic examinations of the drywell shell above, around, and 

below the penetration area where leakage was observed and the 

complete circumference of the drywell shell at floor junction 

indicated that the thickness of the drywell shell was above the 

plate thickness used in design analysis; if a repair cannot be 

made prior to entering the period of extended operation, 

augmented inspections will be performed in accordance with 

ASME Code Section XI, Subsection IWE-1240 

(Table-IWE-2500-1, Examination Category E-C), and ultrasonic 

thickness measurements of the drywell shell will be performed 

periodically to provide a corrosion rate to demonstrate that the 

corrosion rate is not sufficient to adversely affect the intended 

function of the drywell shell (Hope Creek Generating Station, 

Unit 1)

Concrete was excavated at two locations to expose the drywell 

shell below the floor slab area and ultrasonic measurements were 

performed to characterize the vertical profile of the drywell shell in 

the sand bed region where water leakage was observed; core 

samples of drywell shell were obtained at seven locations 

representative of wastage to confirm the ultrasonic results; 

three-dimensional finite-element analyses of the as-built and 

degraded condition of the drywell containment vessel were

performed to demonstrate that the ASME Code-allowable 

stresses were met (Oyster Creek Nuclear Generating Station)

PWR Obtain, test (i.e., compressive strength, boron and chloride 

concentration, pH), and examine (i.e., petrography) concrete core 

specimens and examine steel reinforcement removed from areas 

subjected to borated water; and perform chemical analyses of 

water leakage from the reactor refueling cavity (i.e., boron 

concentration, pH, iron, and calcium) (Indian Point Nuclear

Generating Unit 2)

Obtain, test (i.e., compressive strength), and examine 

(i.e., petrography) at least one concrete core specimen from a 

reactor refueling cavity leakage indication site if a core obtained 

from a location below the SFP indicates degradation (Kewaunee 

Power Station)
68

Table 6-1 Leakage from Reactor Refueling Cavity—

Summary of Information Contained in Appendix A (cont.)

Topic

Type

Plant Commentary

Assessment 

of structural 

impact

(cont.)

PWR

(cont.)

Remove concrete from the sump below reactor vessels to 

expose the containment vessels, followed by visual and 

ultrasonic inspections of the containment vessel and assessment 

of the removed concrete; remove a concrete sample that has 

been wetted by borated water leakage from the reactor refueling 

cavity, test for compressive strength, and conduct a petrographic 

examination; loss of concrete due to interaction with borated 

water was estimated and noted to be small relative to the overall 

section thickness of 1.22 to 1.52 m (4 to 5 feet); ASME Code 

design calculations were conducted that indicate the shell and 

bottom head of containment could tolerate general corrosion loss 

of about 12.7 mm (0.5 inches) out of 38.1 mm (1.5 inches) total 

thickness without risk to functionality; the impact on concrete and 

steel reinforcement was determined to be negligible based on 

results presented in the literature (Prairie Island Nuclear 

Generating Plant, Unit 1 and Unit 2)

Based on experimental results, the depth of erosion of concrete 

adjacent to the reactor cavity and fuel transfer canal as a result 

of exposure to borated water was estimated to be on the order of 

7.37 mm (0.29 inches) and therefore not sufficient to impact the 

concrete section or impact the steel reinforcement; perform 

augmented inspections under the fuel transfer canal once per 

containment inservice inspection period as long as leakage is 

observed; a concrete core obtained from the area where leakage 

of borated water is more extensive and more frequent will be 

tested and used as a leading indicator for the impact on reactor 

refueling cavity concrete (Salem Nuclear Generating Station, 

Units 1 and 2)

An engineering assessment that included nondestructive testing, 

visual inspections, and obtaining and testing of five concrete 

cores from areas most affected by leakage of borated water 

indicated that there was no concern with the structural integrity of 

the concrete and embedded steel reinforcement (Davis-Besse 

Nuclear Power Station)
69

Table 6-2 Leakage from Spent Fuel Pool—

Summary of Information Contained in Appendix B

Topic Type

Plant Commentary

Leakage 

source

BWR Small cracks in the liner or seam welds

PWR Small cracks in liner, seam, or plug welds; structural attachment 

weld defects

Primary 

structures 

potentially 

impacted

BWR Cylindrical portion of drywell shell and sand bed region of MK I 

containments; reinforced concrete structures; metallic pressure 

boundary; and support structures

PWR Reinforced concrete structures; metallic pressure boundary; 

supports; and carbon steel structures where borated water 

accumulates

How leakage 

was identified

BWR Leakage from leak chase channels (Duane Arnold Energy 

Center)

Leakage from the leak chase system associated with the north 

wall liner plate when the pool level is increased above the 

normal level for refueling operations (Hope Creek Generating 

Station, Unit 1)

PWR Hairline crack in the SFP concrete wall, mineral deposits at the 

pipe end of the leak chase channel, and ongoing slow leakage 

from leak chase lines (Crystal River Nuclear Generating Plant, 

Unit 3) 

Leakage from leak chase channels, periodic water leakage into 

the emergency core cooling system pump room, and indications 

of cracking and staining on the underside of the SFP and 

transfer pit (Davis-Besse Nuclear Power Station)

Leakage from leak chase channels with no other leakage 

indications (e.g., cracks or boric acid deposits on structures) 

(Diablo Canyon Power Plant, Units 1 and 2)

During excavation activities for the fuel storage building, a crack 

was identified in the SFP concrete wall with moisture observed 

along one of the cracks; 2 weeks later, a second crack 

appeared, leaking fluid was observed, and analysis verified that 

the fluid was consistent with that in the SFP (Indian Point 

Nuclear Generating Unit 2)

White deposits were observed on the wall and ceiling of the 

waste drumming room below the SFP; and ongoing slow 

leakage from three leak chase lines (Kewaunee Power Station)
70

Table 6-2 Leakage from Spent Fuel Pool—

Summary of Information Contained in Appendix B (cont.) 

Topic Type

Plant Commentary

How leakage 

was identified

(cont.)

PWR

(cont.)

Low-level shoe contamination picked up in the auxiliary building 

mechanical penetration room; active water leakage through an 

exterior concrete wall of the auxiliary building; white deposits on 

the reinforced concrete wall of the SFP and seepage into the 

sump room in the fuel-handling building; the presence of 

borated water in the seismic gap between the fuel-handling 

building and auxiliary building; leakage from the telltale drains 

of the leak chase system; the presence of tritium in ground 

water adjacent to the SFP (Salem Nuclear Generating Station, 

Unit 1)

Water seeping from SFP south and east concrete walls; the 

presence of white deposits appearing to be boric acid crystals; 

and chemical analyses of water samples indicating the SFP as 

the source (Palo Verde Nuclear Generating Station, Unit 1)

Moisture present in the sump and leakage of 4.38x10-7 m

3

/s 

(10 gpd) of water from the telltale collection pipe (Seabrook

Station)

Activities to 

address 

leakage

BWR Walkdowns of accessible areas under the SFP did not identify 

the presence of leakage; inspections of SFP surfaces will 

continue during the period of extended operation (Duane 

Arnold Energy Center)

Visual inspections of the north concrete wall of the SFP (Hope 

Creek Generating Station, Unit 1)

PWR The leak chase outlet was cleaned, the leak chase channels 

were verified to be clear by snaking; implement a preventative 

maintenance program to periodically verify that the leak chase 

channels are clear and analyze samples of deposits removed 

from the leak chase system to check for concrete products; and 

maintain the SFP level at the lower end of normal water level 

range (Crystal River Nuclear Generating Plant, Unit 3)

Six of 21 leak chase channels that had been clogged were 

unclogged, resulting in significant release of trapped fluid; the 

leak collection isolation valves were cleaned; the leak chase 

program will monitor borated water leakage from the SFP on a 

monthly basis and, when sufficient volume is available, 

samples will be obtained and analyzed for pH (monthly), iron 

(semiannually), and boron content (Davis-Besse Nuclear Power 

Station)
71

Table 6-2 Leakage from Spent Fuel Pool—

Summary of Information Contained in Appendix B (cont.)

Topic Type

Plant Commentary

Activities to 

address 

leakage (cont.)

PWR

(cont.)

Opening leak detection shutoff valves and observing any water 

accumulation or flow on a weekly basis; video inspections of 

leak chase channels to demonstrate that the channels are not 

blocked; when sufficient volume of leakage is available, 

samples are obtained and analyzed for tritium, gamma isotopic, 

pH, iron, and boron (Diablo Canyon Power Plant, Units 1 and 2)

Leakage was attributed to defects in the liner as a result of poor 

workmanship during initial construction of the liner, and the 

defects were repaired; accessible areas of the SFP liner (about 

40 percent) were inspected using robotic cameras, general 

visual inspection, and vacuum box testing; samples of ground 

water outside the SFP will be tested at a frequency of 3 months 

for the presence of tritium and boron (Indian Point Nuclear 

Generating Unit 2) 

Leakage indication sites are inspected monthly; portions of the 

auxiliary building adjacent to the SFP will be inspected annually 

during the period of extended operation; a multidisciplinary 

team will develop recommendations for inspection, testing, and 

repairs to remediate leakage; liner seam weld leakage 

detection and collection system drain lines will be inspected 

and repaired (if required) to ensure a clear drain path; monitor 

ground water for detectable levels of tritium (Kewaunee Power 

Station)

Inspected and repaired seam welds suspected of leaking; 

perform videoscopic examination of telltale drains and leakage 

channels, clearing of the leak chase system and monitoring of 

telltale drains and clearing of leak chase system every 

18 months; installed a drainage system and a program to 

remove water from the seismic gap between the fuel-handling 

building and auxiliary building; installed a ground water 

extraction (tritium reclaiming) system (Salem Nuclear 

Generating Station, Unit 1)

A foreign object blocking a leak chase channel was removed 

and water was released from leak chase channels by opening 

valves; valves will be opened on a daily basis and water 

drained, recorded, and trended; drain lines were boroscoped to 

ensure that they were clear, with the procedure to be repeated 

at 2-year intervals; shallow aquifer wells were installed down 

gradient for sampling of water to detect the presence of 

radioactivity (Palo Verde Nuclear Generating Station, Unit 1)
72

Table 6-2 Leakage from Spent Fuel Pool—

Summary of Information Contained in Appendix B (cont.)

Topic Type

Plant Commentary

Activities to 

address 

leakage (cont.)

PWR

(cont.)

Hydro-lazing (i.e., clearing) of the SFP leak-off lines; monitoring 

of leak-off from telltales at monthly intervals; analyzing the 

leak-off collection for gamma and tritium (Seabrook Station)

Assessment of 

structural 

impact

BWR No assessment; leakage confined to leak chase system (Duane 

Arnold Energy Center)

No assessment; leakage confined to leak chase system (Hope 

Creek Generating Station, Unit 1)

PWR The only visible indication of degradation is a small hairline 

crack in the SFP concrete wall that is of no structural 

significance but will be inspected and monitored at a yearly 

interval (Crystal River Nuclear Generating Plant, Unit 3)

A concrete crack on the underside of the SFP will be evaluated; 

concrete core bores will be obtained prior to the period of 

extended operation from two areas that have experienced 

leakage to assess the condition of the concrete and embedded 

steel reinforcement (Davis-Besse Nuclear Power Station)

Engineering investigations concluded that long-term leakage 

was acceptable because the amount of leakage is not sufficient 

to affect concrete structures; cited results of EPRI TR-1019168, 

―Boric Acid Attack of Concrete and Reinforcing Steel in PWR 

Fuel Buildings,‖ issued June 2009 (Ref. 117); confirmed that 

leakage was contained within the leak chase channels (Diablo 

Canyon Power Plant, Units 1 and 2)

Testing of 20 concrete cores obtained from five locations in the 

east wall near the location of leakage indicated that the 

concrete compressive strength was above the design value; 

steel reinforcement exposed by coring did not exhibit corrosion; 

windows were placed into the outer wall surface to observe the 

outer layer of steel reinforcement for signs of corrosion; 

analyses of the walls indicated that they were capable of 

resisting loads at least 25 percent greater than design-basis 

loads (Indian Point Nuclear Generating Unit 2) 

A concrete core sample will be obtained from below the SFP at 

the location exhibiting the greatest leakage, tested for 

compressive strength, and examined using petrographic 

methods; steel reinforcement in the core sample area will be 

exposed and inspected for material condition (Kewaunee 

Power Station)
73

Table 6-2 Leakage from Spent Fuel Pool—

Summary of Information Contained in Appendix B (cont.)

Topic Type

Plant Commentary

Assessment of 

structural 

impact (cont.)

PWR

(cont.)

Laboratory testing of the effect of borated water on concrete 

and steel reinforcement (i.e., erosion and section loss rates, 

respectively); detailed structural analysis of the fuel-handling 

building and SFP to demonstrate that the potential impact on 

structural margins was not significant; conducted a baseline 

inspection, according to American Concrete Institute (ACI) 

201.1R-08, ―Guide for Conducting a Visual Inspection of 

Concrete in Service‖ (Ref. 118), and ACI 349.3R-02, 

―Evaluation of Existing Nuclear Safety-Related Concrete 

Structures‖ (Ref. 119), of the fuel-handling building to assess its 

overall structural condition; nondestructive assessment 

(rebound hammer testing) of the relative condition of ―wet‖ and 

―dry‖ portions of the west wall of the sump room; evaluated the 

impact of potential concrete erosion adjacent to the liner; 

perform structural inspections of the Unit 1 sump room wall 

every 18 months and fuel-handling building every 5 years; 

obtain and test concrete core samples from the east and west 

walls of the SFP and observe the condition of steel 

reinforcement exposed by concrete cores; test water drained 

from the telltales and seismic gap for boron, chloride, iron, and 

sulfate concentrations, and pH, and use established 

acceptance criteria to assess the potential for degradation 

(Salem Nuclear Generating Station, Unit 1)

The SFP concrete walls were visually inspected and examined 

using nondestructive testing techniques (ground-penetrating 

radar, impulse response, and ultrasonic pulse velocity); the 

inspection report concluded that borated water leakage did not 

have an adverse effect on the SFP walls (Palo Verde Nuclear 

Generating Station, Unit 1)

A concrete core sample will be obtained from the leakage area 

to evaluate the concrete and steel reinforcement (Seabrook 

Station)
74

Table 6-3 Torus Corrosion and Cracking—

Summary of Information Contained in Appendix C

Topic Commentary

Inspection 

method

Visual inspections performed by divers every other outage to detect 

adverse coating conditions (e.g., flaking, peeling, blistering, 

discoloration, and other signs of distress), corrosion, or pitting (Cooper 

Nuclear Station)

Visual inspections performed each refueling cycle by divers to detect 

discoloration, bubbling, or flaking of the coating (Duane Arnold Energy 

Center)

Visual inspections above the waterline according to ASME Code 

Section XI, Subsection IWE, during refueling outages and below the 

waterline (when drained or water level lowered) (James A. FitzPatrick 

Nuclear Power Plant)

Visual inspections performed by divers according to ASME Code 

Section XI, Subsection IWE (Hope Creek Generating Station, Unit 1)

Visual inspections with examination of prior photo documentation (Nine 

Mile Point Nuclear Station, Unit 1)

Visual inspections performed by divers every other refueling outage to 

detect adverse coating conditions (e.g., cracks, sags, runs, flaking, 

bubbles, and other defects) (Oyster Creek Nuclear Generating Station)

Visual inspections under the containment inservice inspection program 

in line with ASME Code Section XI, Subsection IWE, program 

requirements (Pilgrim Nuclear Power Station)

Field 

observations

Large number of repairs (3,800 comprising 1.1 percent of the torus 

surface below waterline); excessive zinc depletion; pitting at thousands 

of locations, with 18 locations having pits where the thickness has been 

reduced greater than 10 percent of the nominal shell thickness (Cooper 

Nuclear Station)

Coating repairs at 15,487 locations representing 5 percent of the 

underwater coating surface since 1995, with only one pit having 

degradation that exceeded the maximum allowable pit depth of 1.35 mm 

(0.053 inches) or 10 percent of the nominal shell thickness; no coating 

deficiencies requiring repair have been identified above the waterline 

(Duane Arnold Energy Center)
75

Table 6-3 Torus Corrosion and Cracking—

Summary of Information Contained in Appendix C (cont.)

Topic Commentary

Field 

observations 

(cont.)

Nine pitted areas identified by visual exam when the torus was drained 

and cleaned in 1998 were measured to determine pit depth; subsequent 

ultrasonic testing performed each outage found all nine pits to be 

acceptable according to Code requirements; crack identified in the torus 

shell due to vibration fatigue from high-pressure coolant injection steam 

condensation oscillation loading (James A. FitzPatrick Nuclear Power 

Plant)

Sixteen areas representing less than 0.0062 percent of the submerged 

portion of the torus shell were identified with metal loss up to 0.76 mm 

(30 mils) (Hope Creek Generating Station, Unit 1)

Ultrasonic measurements indicated that the torus wall inside surface had 

experienced a loss of section due to corrosion (Nine Mile Point Nuclear 

Station, Unit 1)

Blistering of coating in the shell invert and the upper shell near the 

waterline, with several areas including pitting damage where blisters had 

fractured (Oyster Creek Nuclear Generating Station)

Areas of defects (e.g., depleted zinc, localized pitting corrosion, and 

minor surface rusting) were identified in 1999 and recoated; ultrasonic 

measurements in 2003 identified several measurements below nominal 

wall thickness (Pilgrim Nuclear Power Station)

Corrective 

and aging 

management 

actions

Repair coating by applying an epoxy to areas that have had localized 

zinc coating failures where the depth of the pits exceeds a threshold 

(generally 0.762 to 1.27 mm (30 to 50 mils)), with pits not requiring repair 

monitored at the next inspection (3 years later) for growth; remove 

sludge and inspect the torus in accordance with ASME Code Section XI, 

Subsection IWE, every refueling outage until the torus is recoated; recoat 

the wetted portion of the torus within 3 years after entering the period of 

extended operation (Cooper Nuclear Station)
76

Table 6-3 Torus Corrosion and Cracking—

Summary of Information Contained in Appendix C (cont.)

Topic Commentary

Corrective and 

aging 

management 

actions (cont.)

Maintain photographs, inspection reports and completed checklists, 

records of corrective actions, and other followup information as quality 

assurance documents; manage the torus coating in accordance with 

ASME Code Section XI, Subsection IWE, requirements, the water 

chemistry program, and the containment inservice inspection program to 

minimize the potential for loss of material and cracking; recoat the torus 

interior surface below the waterline prior to the first refueling outage 

during the period of extended operation (Duane Arnold Energy Center)

Manage the torus coating and monitor torus wall thickness using 

augmented ultrasonic thickness examinations in accordance with ASME 

Code Section XI, Subsection IWE, requirements; ultrasonic testing of 

identified pits each refueling outage to evaluate pit depth; coating 

discrepancies are repaired; the crack in the torus shell is repaired and 

the sparger assembly installed to eliminate oscillation 

(James A. FitzPatrick Nuclear Power Plant)

Repairs to each location identified made with an epoxy coating; coatings 

managed by the protective coating monitoring and maintenance 

program; locations to be reinspected under future ASME Code 

Section XI, Subsection IWE, underwater inspections (Hope Creek

Generating Station, Unit 1)

Evaluate corrosion of the torus through inspection and analysis by 

determination of torus shell thickness through ultrasonic testing at 

6-month intervals using a predefined grid system; determination of the 

corrosion rate through analysis of material coupons; and visual 

inspection of accessible external surfaces of the torus support structure 

for corrosion; protective coating monitoring and maintenance program 

(Nine Mile Point Nuclear Station, Unit 1)

The coating is inspected every outage and repaired as required; 

preventative coating monitoring and maintenance program; ASME Code 

Section XI, Subsection IWE, program (Oyster Creek Nuclear Generating 

Station)

Defects were recoated in 1999; ultrasonic measurements in 2003 

indicated that the shell thickness was above the minimum allowable so 

no further action was taken; subsequent inspections conducted 

ultrasonic thickness measurements to monitor change in the thickness of 

the torus over time (Pilgrim Nuclear Power Station)
77

Table 6-3 Torus Corrosion and Cracking—

Summary of Information Contained in Appendix C (cont.)

Topic Commentary

Structural 

integrity 

assessments

Complete an engineering analysis after each inspection to demonstrate 

acceptable thickness of the torus wall as impacted by pitting (Cooper 

Nuclear Station)

The one pit exceeding 10 percent of shell thickness was dispositioned 

under the corrective action program as acceptable without repair in that it 

would not impact the structural integrity of the torus (Duane Arnold 

Energy Center)

No analysis; the responsible design engineer determined that conditions 

were acceptable (James A. FitzPatrick Nuclear Power Plant)

No analysis was required; the loss was less than ASME Code allowable 

and a corrosion allowance of 3.18 mm (125 mils) had been incorporated 

into the original design of the torus (Hope Creek Generating Station, 

Unit 1)

Ultrasonic testing and analysis of corrosion rate data determined from 

coupons was used to demonstrate that the torus shell thickness will 

continue to meet minimum design requirements and that any degradation 

is detected before loss of intended function (Nine Mile Point Nuclear 

Station, Unit 1)

Quantitative assessment (engineering analysis) of pits concluded that pit 

depths were significantly less than an established acceptance criterion 

(Oyster Creek Nuclear Generating Station)

Ultrasonic thickness measurements will continue in areas where torus 

thickness was below the nominal wall thickness, with the results 

compared to those from previous inspection (Pilgrim Nuclear Power 

Station)
78

Table 6-4 Age-Related Degradation of Concrete

NPP

Plant Type Occurrence Description

Bellefonte Unit 1

B&W PWR

During 1975 and 1976, a series of eight rock anchor heads for Units 1 and 2 

failed during construction installation after having been sealed in a highly 

alkaline water solution for a long period. Cause was attributed to high anchor 

head stresses, inclusions in steel, bending of shims and anchor plates, and 

unknown environmental conditions that produced SCC. Anchor heads were 

removed and replaced.

In 2009, the reactor building containment vertical tendon V9 experienced 

failure of the rock anchor/tendon coupling. The failure mode was determined 

to be hydrogen-induced SCC. The root cause of the failure was determined to 

be water containing sulfides in contact with the grease surrounding the 

coupling in a high-stress area. 

Crystal River

Unit 3

B&W PWR

For several prestressing tendon surveillance inspections over the last 20 

years, the lift-off forces in the hoop prestressing tendons were consistently 

found to be lower than the 95-percent predicted values. The cause of the low 

lift-off forces was attributed to high tendon wire relaxation as a result of 

elevated temperature effects. The licensee‘s responsible engineer stated that, 

although several tendons have demonstrated lower than expected lift-off 

values leading to adjacent tendons being tested, the end result in all cases 

thus far has met the set acceptance criteria.

Leaching was identified in the tendon gallery. Concrete core samples will be 

taken at the inside face of the concrete up to the rebar where leaching was 

observed. The cores will be tested to determine if water-soluble chlorides that 

could lead to corrosion of the embedded steel are present. Exposed rebar will 

be examined for any significant corrosion.

Vogtle

West PWR

Visual examination detected an area of spalling on the edge of the 

containment buttresses of Unit 1. An engineering evaluation report concluded 

that the spalling was nonstructural in nature and had no significant effect on 

the structural integrity of the containment. (Note: The aging mechanism and 

the environment for this aging effect were not reported.)

On January 7, 1998, personnel were attempting to find a suspected exhaust 

leak where the diesel generator 1A exhaust pipe exits the roof of the diesel 

generator building of Unit 1. Concrete damage was discovered on the roof to 

the diesel generator 1A and 1B exhaust pipe concrete barriers (design-basis 

missile protection). Concrete had spalled off the inside of the barrier in several 

locations, exposing the rebar in some areas. In addition, extensive surface 

cracks were seen on both the interior and exterior of the barrier. The control 

room and the system engineer were notified of the condition. A preliminary 

evaluation determined that this degradation had no immediate impact on diesel 

generator operability. Further investigation on January 14, 1998, by a civil 

design engineer confirmed the degraded concrete condition previously 

identified. Additional inspections by plant personnel on January 21, 1998, 

found similar degraded barriers on the two Unit 2 diesel generators. Followup 

evaluations utilizing design engineering input also found no adverse impact to 

continued diesel generator operability. Concrete debris was removed from 

exhaust piping on all four diesel generators. (Note: The cause of this event 

was found to be the differential rate of expansion and contraction.)
79

Table 6-4 Age-Related Degradation of Concrete (cont.)

NPP

Plant Type Occurrence Description

Three Mile Island

Unit 1

B&W PWR

Water seeping under three embedded plates on the dome has resulted in some 

minor leaching of the concrete. These plates extend out from a point close to the 

dome apex toward the general area of the vent stack on the west side of the 

containment. This condition was corrected by sealing the concrete to embed 

interface area with a caulking compound to prevent further entry of water. 

Reinforcing steel is exposed on the vertical face of the ring girder.

Grout patches have detached from the dome surface at two locations, leaving 

depressions that can accumulate water. One location is along an embed on the west 

side of the dome. The other is on the west side of the dome close to the crane rail. 

These depressions were filled with epoxy grout to prevent ponding and the 

consequent possibility of progressive freeze-thaw damage.

Cracking <0.02-cm wide (<0.008 inches) was found in the containment ring girder 

and around tendon bearing plates. Cracks were repaired and monitored.

Concrete surface areas with previously documented damage and deterioration were 

reexamined. In all cases, the conditions previously recorded were found to be 

effectively stable. However, in several of these areas, it was determined that 

repair/restoration work was necessary to ensure against further deterioration. The 

repair and restoration work was completed in 2006. With one exception, the repaired 

areas consist of minor restorative work on the concrete surface or sealing against 

water intrusion.

Brunswick

Units 1 and 2

GE BWR/4 MK I

The area surrounding the service water intake structure, adjacent to the intake canal, 

is subject to an aggressive environment due to high levels of chlorides and sulfates in 

the intake water. The service water intake structure is monitored at an increased 

frequency (every 2 years) because of the environment and history of degradation.

Operating experience for the submerged portions of the service water intake 

structure is obtained from divers performing annual preventive maintenance. The 

only degradation observed was a minor spall of the concrete. No rebar was 

exposed, and an evaluation determined the damage to be cosmetic. No repairs were 

required.

The licensee‘s technical staff documented the operating experience related to 

concrete degradation of the Units 1 and 2 service water buildings (alternate 

designation for the service water intake structure). The provided information covered 

only occurrences of degradation for accessible interior and external concrete 

surfaces. Degradation was attributed to the result of exposure to aggressive, raw 

service water. Repairs were made.

Peach Bottom

Units 2 and 3

GE BWR/4 MK I

The emergency cooling tower and reservoir reinforced concrete walls are exposed to 

raw water and have experienced leaching of calcium hydroxide. The pH, sulfate, and 

chloride content of the water are significantly below the threshold limits for 

aggressive environment. Corrective actions were taken before loss of intended 

function.

Monticello

GE BWR/3 MK I

The aging effects detected during the structural inspections were concrete spalling, 

cracking, surface deterioration and flaking, grout deterioration, corroded rebar or 

other steel components, and cracked welds. (Note: The aging mechanisms and the 

environments that caused the concrete cracking and rebar corrosion were not 

reported.)
80

Table 6-4 Age-Related Degradation of Concrete (cont.)

NPP

Plant Type Occurrence Description

Diablo Canyon

Units 1 and 2

West PWR

Since 1996, the seawater intake structure was placed twice under increased 

watchfulness (Maintenance Rule, goal setting (a)(1) status) (Refs. 40 and 41). Each 

occurrence further showed the adverse impacts of a harsh saltwater environment on 

concrete degradation. Concrete experts and technicians inspected and documented 

areas of concrete degradation. Degraded conditions, including delaminations, are 

documented on drawings of the intake structure. These drawings are updated 

following each RFO and used to assess the conditions against design- and 

licensing-basis criteria and for trending purposes in periodically issued reports. The 

developed refurbishment plan embraces concrete repairs and installation of cathodic 

protection anodes at various locations, including the seawall and seawall refuse sump 

overflow opening, traveling screen forebays, circulating water conduits, pump vaults, 

the top deck, and the intake structure pump deck.

Salem

Units 1 and 2

West PWR

In 2002, during performance of preventive maintenance walkdowns to support 

condition monitoring of the service water intake structure, spalling on the exterior 

concrete wall near watertight doors SW-1 and SW-5 was observed. The rebar was 

exposed as a result of the spalling, and corrosion on the rebar was noted. The 

condition was evaluated by design engineering and repaired in accordance with 

station specifications. As a followup to this condition report, a walkdown inspection of 

the area was performed in 2004. It was noted that the spalling condition had been 

repaired and no indication of additional degradation in the structure was present.

Turkey Point

Units 3 and 4

West PWR

Buttress 3 was observed to have three spalls on its face with exposed rebar. These 

areas of spalling are located in the nonstructural concrete cover. The engineering 

disposition found that the concrete cover does not perform a structural function. Its 

purpose is to protect the rebar from exposure to the outside environment. The 

corrosion observed on the exposed rebar was superficial without adverse effect on the 

design function of the rebar. The surrounding concrete was tapped by a hammer and 

no hollow sounds resulted. As a corrective measure, the three subject areas were 

cleaned and coated with a protective coating. (Note: The aging mechanism and the 

environment for this aging effect were not reported.)

During the 20th-year tendon surveillance, the prestresing forces of a number of 

tendons were found to be lower than expected. The cause was attributed to 

excessive wire relaxation due to sustained high temperatures around the tendons.

Extensive cracking of reinforced concrete beams supporting the recirculating water 

pumps of the intake structures was found in 1987–1989. The cause of the cracking 

was corrosion of the embedded concrete steel reinforcement due to harsh 

environmental conditions (i.e., salt water). A corrective program was implemented to 

ensure structural integrity of the beams and minimize future penetration of chloride 

ions. Unit 4 was also affected.

Nine Mile Point

Unit 1 and 2

GE BWR/2 MK I

Minor cracking of the service water pipe tunnel was observed. The service water pipe 

tunnel is susceptible to small wall cracks allowing leakage of ground water. The 

repaired areas of the service water pipe tunnel were inspected, and there was no 

entry of ground water in the areas repaired. Frequency of inspections following the 

repairs has varied from monthly (initially) to quarterly.

 
81

Table 6-4 Age-Related Degradation of Concrete (cont.)

NPP

Plant Type Occurrence Description

Kewaunee

West PWR

During the 1997 periodic structure monitoring inspections of the screen house and

tunnel, cracking with leaching was observed. In March 2003, during similar 

inspections of the screen house and tunnel, multiple concrete degradation 

mechanisms were observed on a wall. The noted deficiencies or aging effects were 

localized and include cracking, leaching, patterned cracking, and a slight surface 

offset. The wall surface, however, appeared dry during the inspection. Cracking with 

leaching was observed previously during the 1997 inspection (e.g., surface offset and 

localized pattern crack formations). Followup inspections in December 2004 indicated 

that the condition of the affected area and the overall wall were stable, with no 

changes observed since the last inspection. No moisture and no new cracking or 

leaching were observed or were apparent. In addition, no other new surface condition 

attributes were observed during the subsequent inspection, which suggests that the 

cracking is passive. The area was reexamined in April 2008 and will be included in a 

long-range rehabilitation plan. The structure status summary continues as 

―acceptable with deficiencies.‖

Minor leaching of calcium hydroxide in an air-outdoor environment has occurred for 

the main auxiliary transformer walls, the turbine building exterior wall, the shield 

building exterior concrete wall, and the screen house forebay exterior concrete wall. 

Water from rain or melting snow passes through cracks or inadequately prepared 

construction joints, causing leaching of calcium compound from concrete. 

Efflorescence, a surface phenomenon consisting of salt deposits that have been 

leached from concrete, was present.

Seabrook

West PWR

Loss of material due to chemical attack of calcium hydroxide is considered to be an 

aging effect requiring management for Seabrook Station. There have been 

indications of leaching in below-grade concrete in Seabrook Station structures other 

than the containment building.

Seabrook Station has scheduled specific actions (e.g., concrete testing) to determine 

the effects of aggressive chemical attack due to high chloride levels in the ground

water. An evaluation will be performed based on the results of the testing and a 

determination of the concrete condition, which may lead to additional testing or 

increased inspection frequency. Testing of concrete may consist of concrete core 

samples, penetration resistance tests, petrographic analysis of the concrete core 

samples, and visual inspection of rebars as they are exposed during the concrete 

coring. Seabrook will evaluate the results of the testing and, if required, undertake 

additional corrective actions in accordance with the structures monitoring program 

corrective action program.
82

Table 6-4 Age-Related Degradation of Concrete (cont.)

NPP

Plant Type Occurrence Description

Farley 2

West PWR

Failure of three anchor heads on the bottom ends of vertical tendons occurred about 

8 years after tensioning. Eighteen cracked anchor heads and several broken wires 

were also found. The cause was attributed to hydrogen stress cracking. All tendons 

and anchor heads from same material heat were inspected, with no additional 

problems noted. Twenty tendons were replaced.

Sequoyah 2

West PWR

Concrete in the outer 2.5 to 5 cm (1 to 2 inches) of the shield building was under 

strength as a result of exposure to freezing and thawing temperatures at an early 

concrete age. The degradation was determined not to impact shield building 

capability.

Calvert Cliffs

Units 1 and 2

CE PWR

During the 20th-year surveillance of the prestressing system, low lift-off values were 

found for vertical tendons. Inspections of adjacent tendons in response to low lift-off 

values revealed that tendon wires had broken. Further examination of wires at the 

tops of tendons revealed additional broken tendon wires. About 30 percent of the 

vertical tendons in Units 1 and 2 were replaced. Engineering evaluation indicated that 

the cause was primarily hydrogen-induced cracking.

Summer

West PWR

During the 4th tendon surveillance, the prestressing forces of a number of vertical 

tendons were found to be lower than expected. The cause was attributed to 

excessive wire relaxation due to sustained high temperatures around the tendons. 

The vertical tendons were retensioned.

Oconee

B&W PWR

Concrete beneath the 50.8-mm (2-inch) thick anchor-bearing plate for tendon 12V6 

had spalled along the outer edge; a cavity existed below the plate. Cracks in the 

concrete beneath the outer edge of the bearing plates were observed for a number of 

tendons. The environment inside the tendon gallery included water infiltration and 

high humidity. (Note: The aging mechanism for the cracking was not reported.)

Oyster Creek

GE BWR/2 MK I

Cracking of the drywell shield wall was attributed to high temperature in the upper 

elevation of the containment drywell. Engineering analysis concluded that stresses 

were well below allowable limits, considering the existing cracked condition. Recent 

inspections identified no significant change in the cracked area.

Millstone Unit 3

West PWR

Accumulated white residue from a porous concrete drainage system was found in two 

lower drain sumps of the engineered safety features building in 1987. It was 

determined that the quantity of cement eroded was minor. The sumps were 

monitored for cement erosion, and the foundations were monitored for settlement.

San Onofre 

Unit 1

CE PWR

Exterior concrete walls of the intake structure and the concrete beams supporting 

service water pumps were cracked extensively. Cracking was due to chloride ion 

penetration that resulted in concrete steel reinforcement corrosion. Walls were 

reinforced with exterior steel plates anchored to concrete, and sacrificial zinc anodes 

were placed onto steel plates to protect against corrosion.

Davis-Besse

Unit 1

B&W PWR

The auxiliary feedwater pump turbine exhaust missile barrier has spalled concrete and 

exposed rebar due to its periodic exposure to a harsh environment. The missile 

barrier continues to perform its design function, and the corrective action program is 

tracking the repair.

Several tower and disconnect switch concrete foundations in the switchyard are 

degraded to the point that concrete has spalled off and rebar is visible. This issue 

was evaluated through the corrective action program. The switchyard‘s ground 

appeared to be saturated with ground water because of insufficient drainage. The 

corrective action program was used to evaluate this issue.
83

Table 6-4 Age-Related Degradation of Concrete (cont.)

NPP

Plant Type Occurrence Description

Beaver Valley

Unit 1

West PWR

Cracks, water infiltration, and calcium deposits in the ceilings and walls of the service 

building, safeguard structure, and steam generator drain tank exist.

Robinson 

Unit 2

Cracking and spalling of concrete (in limited areas) in the walls and ceilings of the 

reactor auxiliary building, emergency diesel generator building, and intake structure 

exist.

85

7. SUMMARY AND CONCLUSIONS AND TOPICS

FOR FURTHER CONSIDERATION

7.1 Summary and Conclusions

As nuclear plants age, occurrences of degradation of spent fuel pools (SFPs), reactor refueling 

cavities, and the torus structure of light-water reactor nuclear power plants (NPPs) are occurring 

at an increasing rate, primarily due to environment-related factors. Several of the 

104 commercial NPPs in the United States have experienced water leakage from the SFPs and 

reactor refueling cavities. In addition, since the year 2000, the license renewal applications 

(LRAs) filed by the licensees have noted several cases of corrosion in the Mark I containment 

torus steel structures of boiling-water reactors (BWRs). Age-related concrete degradation has 

also been indicated in other instances. 

The objectives of this NUREG document are to (1) identify the cause, extent, and effect of 

leakage from deteriorated seals between the refueling cavity and reactor cavity areas, and/or 

leakage through stainless steel weld seams, or through stainless steel base metal, (2) identify 

the cause, extent, and effect of leakage from BWR and pressurized-water reactor (PWR) SFPs

through the stainless steel weld seams, or through the stainless steel base metal, and the field 

activities that were performed to address the leakage, (3) identify possible causes of corrosion 

of the torus of different BWR Mark I plants, including the locations and remedial actions,

(4) provide an update on operating experience with respect to NPP reinforced concrete 

structures, (5) summarize mitigating actions of the industry to manage or rectify issues 

associated with aging effects because of Objectives 1, 2, and 3 above, thus extending the safe 

operating life of NPPs, and, last but not least, (6) extend past studies and efforts to serve as a 

precursor for the industry to identify degradation scenarios that potentially could dominate in the 

future (e.g., the impacts of historical water leakage on the structural integrity of SFPs and 

refueling cavity liners and associated concrete structures). Selection of degradation 

occurrences involved identification of aging effects from publicly available documents, followed 

by the identification of associated aging mechanisms and environments. Consistency and 

clarity in presentation of information was maintained to the extent possible throughout the 

report.

Publicly available documents related to operating experience (e.g., licensee event reports, 

U.S. Nuclear Regulatory Commission (NRC) generic communications, NRC preliminary 

notification reports, NRC interim staff guidance, and NRC regulatory guides), NRC NUREGs, 

licensee inspection reports, license renewal applications, and NRC safety evaluation reports of 

license renewal applications were reviewed and screened. Reports containing information 

related to one of the four topics of interest noted above were binned (i.e., grouped) into the 

appropriate topic of interest for more detailed review. The subject matter expert then completed 

a more detailed review of the potential information sources that resulted in identification of 11, 

12, and 7 occurrences related to reactor refueling cavity leakage, SFP leakage, and torus 

corrosion and cracking, respectively. This process also resulted in identification of 

26 occurrences related to age-related degradation of NPP reinforced concrete structures. 

Publicly available information related to the occurrences identified was then summarized. 

7.1.1 Reactor Refueling Cavity Leakage

Leakage from the reactor refueling cavity primarily occurs only during refueling outages and has 

been identified at eight sites involving 11 units (four BWRs and seven PWRs). The primary 
86

sources of leakage for BWRs have been failure of the drywell-to-refueling cavity seal and cracks 

in liner plate seam welds, refueling bellows, or reactor cavity drain lines. The primary sources of 

leakage for PWRs have been liner plate seam or plug welds and cracks in embedment plates 

for reactor vessel internals stands support and the rod control cluster fixture. For BWRs, the 

primary concern related to leakage from the reactor refueling cavity is the potential for corrosion 

of the drywell shell and support structures. In the case of PWRs, leakage of borated water may 

cause corrosion of the metallic pressure boundary, reactor supports, and containment structure, 

or it may affect other structures and components on which the borated water accumulates. 

Leakage has primarily been identified in BWR plants by water present in the gap between the 

drywell and concrete, or by water trickling from a drywell shield wall penetration. Leakage in 

PWR plants was primarily identified by leakage of water or boric acid deposits on walls and 

equipment, or their presence in sumps. Activities to address leakage from BWRs have primarily 

included visual inspections and ultrasonic testing of the drywell shell, application of strippable 

coatings or adhesive steel tape, inspection and clearing (as required) of the drainage systems, 

and monitoring of leakage. PWR activities to address leakage have included application of 

coatings to suspect areas, visual inspections of accessible surfaces of structures that could be 

potentially impacted, application of sealer coatings, visual inspections and nondestructive 

examinations (NDEs) of liner plate and seam welds, and inspection and clearing (as required) of 

the drainage systems. 

Assessment of the structural impact of leakage for BWRs has included ultrasonic thickness 

measurements of the drywell shell, augmented examinations under American Society of 

Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (ASME Code) Section XI,

Subsection IWE, and finite-element calculations to demonstrate that ASME Code-allowable 

stresses are met. Structural impact assessments for PWRs have included (1) removal of 

concrete cores to inspect concrete steel reinforcement, (2) strength determinations and 

petrographic examination of the concrete, (3) chemical analyses of water leakage, and 

(4) exposure of the containment vessel by concrete coring for visual examinations and 

ultrasonic thickness measurements of the vessel. Wall thickness measurements obtained to 

date have been at or above nominal, and there have not been visible signs of corrosion.

7.1.2 Spent Fuel Pool Leakage 

Leakage from the SFP has been identified at 10 sites involving 12 units (2 BWRs and 

10 PWRs). The primary sources of leakage for BWRs have been small cracks in the liner or 

seam welds. The primary sources of leakage for PWRs have been cracks in the liner plate 

seam or plug welds, or structural attachment weld defects. For BWRs, the primary concern 

related to leakage from the SFP is the potential for corrosion of the cylindrical portion of the 

drywell shell and sand bed region of Mark I containments, reinforced concrete structures, the 

metallic pressure boundary, and support structures. In the case of PWRs, leakage of borated 

water may erode the concrete or produce corrosion of the concrete steel reinforcement, the 

metallic pressure boundary, supports, and carbon steel structures where borated water can 

accumulate. Leakage has primarily been identified in BWR plants through leakage from the 

leak chase system. Leakage in PWR plants has been identified by leakage from the leak chase 

system, seepage associated with cracks in concrete, the presence of white deposits on 

structures, the presence of moisture in the seismic gap between the fuel-handling building and 

auxiliary building, the presence of tritium in ground water, and contamination of protective 

clothing. Activities to address leakage in BWRs have primarily included walkdowns of 

accessible areas around the SFP. PWR activities to address leakage have included inspection 
87

and clearing (as required) of the drainage systems, monitoring and analysis of leakage collected 

by the drainage system, visual inspections of accessible areas of the SFP liner and SFP

concrete surfaces, and sampling of ground water for tritium. No assessments of the structural 

impact of leakage identified for BWRs has been reported because all of the plants indicated that 

the leakage was contained within the leak chase drainage system. Structural assessments of 

the PWRs have included periodic visual inspections; obtaining concrete cores to assess the 

condition of the concrete and the embedded concrete steel reinforcement; baseline inspections 

according to American Concrete Institute (ACI) 201.1R-08, ―Guide for Conducting a Visual 

Inspection of Concrete in Service‖ (Ref. 118), and ACI 349.3R-02, ―Evaluation of Existing 

Nuclear Safety-Related Concrete Structures‖ (Ref. 119); application of NDE techniques; and 

laboratory testing of the effect of borated water on concrete and concrete steel reinforcement. 

SFP leakage has been more common for PWRs, the leakage related to BWRs has been 

confined to the leakage collection system, and the borated water can potentially impact the 

structures it contacts. Additional information related to leakage of borated water from SFPs is 

provided below.

7.1.2.1 Effect of Borated Water on Materials

Borated water leakage from PWR SFPs (and reactor refueling cavities) can cause erosion of 

concrete as a result of borated water‘s acidic nature (a pH of 4.8 to 5.2) or result in corrosion of 

carbon steel materials. Concrete affected by borated water exhibits softening, or erosion, due 

to attack of the cement paste and acid-soluble constituents in the aggregates. The attack 

begins at the exposed surface of the concrete, can progress inward, and will stop when the 

reaction is complete. The rate of degradation of concrete exposed to borated water is controlled 

by the diffusion of borated water into the concrete and depends on factors such as the concrete 

mixture proportions and constituents, pH of the fluid, time of exposure, and temperature. 

Formation of reaction products can slow the rate of concrete erosion because a continuous 

supply of calcium hydroxide is required for the process to continue. Reaction of the borated 

water with cementitious components in the concrete or some aggregate materials 

(e.g., limestone) also tends to somewhat neutralize the acidity of the solution, such that the pH 

of the leaking fluid can approach neutrality or become somewhat alkaline.

The concrete cover protects the carbon steel reinforcing bars from corrosion. Corrosion of the 

concrete steel reinforcement begins when acid attack of the cover concrete progresses to the 

level of the steel reinforcement. Cracks in the concrete cover and construction joints can also 

allow the borated water to access the steel reinforcement and initiate the corrosion process. 

(Cracks that completely penetrate the concrete section or construction joints can also permit the 

borated water to impact other structures, such as the carbon steel pressure boundary.) 

Corrosion of the steel reinforcement produces tensile stresses in the concrete as a result of a 

volume increase associated with formation of the corrosion products. If the corrosion process 

continues, the net section of the steel reinforcement can be reduced and there can be loss of 

bond between the concrete and steel reinforcement that can potentially impact the component 

structural integrity. Although very limited, results presented in the literature and operating 

experience seem to indicate that the interaction of borated water with concrete has not 

produced significant erosion of the concrete because borated water is a relatively ―weak‖ acid. 

Corrosion of the embedded concrete steel reinforcement as a result of exposure to borated 

water has also been relatively minor, with no reported observations of spalled concrete. 

Borated water that has migrated to the metallic pressure boundary (i.e., the liner or 

containment) is of most concern relative to its potential to produce corrosion resulting in loss of 

section or compromised leak tightness. Although results presented in the literature are very 
88

limited, ultrasonic measurements in areas of the metallic pressure boundary potentially exposed 

to borated water leakage have reported that the wall thickness is at or above nominal, and 

evidence of corrosion is not present.

7.1.2.2 Extent of Concrete and Steel Degradation

One study was identified in which laboratory testing was conducted to simulate the impact of 

borated water leakage on concrete. Results of the testing indicated that the projected depth of 

concrete degradation in the floor slab of the SFP after 70 years exposure would be on the order 

of 33.0 millimeters (mm) (1.3 inches) and 11.2 mm (0.44 inches) in the walls of the SFP

(Ref. 120). Because these penetration depths were less than the thickness of the concrete

cover to the embedded steel reinforcement, the steel reinforcement would not be impacted 

unless a crack in the concrete was present. It was noted that results obtained from this study 

were supported by examination of concrete cores removed from the Connecticut Yankee SFP. 

The same study also investigated the impact of borated water on the concrete steel 

reinforcement, with the result that degradation of the steel reinforcement was minor and that 

migration (or wicking) of the borated water along the interface between the concrete and 

embedded steel reinforcement was limited and would not cause a general loss of bond. The 

results of this study were then used to estimate the impact of exposure through the end of plant 

life. The estimated degradation was projected to reduce the available structural margin in the 

limiting cross section of the SFP by less than half a percentage point to 1.6 percent (i.e., a 

design margin ratio of 1.016).

7.1.3 Torus Corrosion and Cracking

Eight occurrences of corrosion of the BWR torus have been identified in seven units located at

seven sites. The primary inspection method used to identify the presence of corrosion or 

degraded protective coatings has been visual, typically performed by divers. Degradation of the 

torus coating reduces its ability to protect the steel substrate from corrosion, and localized 

coating failures expose areas of the substrate to corrosion. Failed coatings can also contribute 

to the amount of sludge and corrosion products that collect in the suppression pool that can 

further increase the corrosion rate. Field observations have indicated that certain units have 

experienced a large number of coating repairs (e.g., in excess of 15,000 at one plant), and 

ultrasonic thickness measurements have generally indicated that the metal loss has not been 

sufficient to impact the structural integrity of the torus. Corrective or aging management actions 

have primarily been to repair coating defects by cleaning and application of an epoxy coating, 

and inspections (or augmented inspections) performed according to ASME Code Section XI,

Subsection IWE, requirements. Assessments of the structural integrity of the torus have 

included conduct of an engineering analysis after each inspection to demonstrate acceptable 

thickness, and performing ultrasonic thickness measurements to establish a corrosion rate to 

demonstrate that the torus shell thickness will continue to meet minimum design requirements 

and that any degradation will be detected prior to loss of intended function.

7.1.4 Age-Related Degradation of Reinforced Concrete Structures

Primary mechanisms (factors) that, under unfavorable conditions, can produce premature 

deterioration of reinforced concrete structures include those that impact either the concrete or 

the steel reinforcing materials (i.e., mild steel reinforcement or posttensioning systems). 

Degradation of the concrete can be caused by adverse performance of either its cement-paste 

matrix or aggregate materials under chemical or physical attack. Degradation of mild steel 
89

reinforcing materials can occur as a result of corrosion, irradiation, elevated temperature, or 

fatigue effects, with corrosion being the most likely form of attack. Posttensioning systems are 

susceptible to the same degradation mechanisms as mild steel reinforcement plus loss of 

prestressing force, primarily due to tendon relaxation, and concrete creep and shrinkage. 

Identification of degradation of reinforced concrete structures in NPPs is primarily through visual 

inspections conducted in accordance with ASME Code Section XI, Subsection IWL, that 

incorporates guidance contained in ACI 201.IR-08 (Ref. 118) and ACI 349.3R-02 (Ref. 119). 

Posttensioning systems are evaluated for loss of prestressing force and degradation using 

guidance provided in ASME Code Section XI, Subsection IWL. Application of NDE methods to 

concrete structures has been limited, with the methods primarily used to quantify existing 

degradation or to investigate areas where degradation is suspected. In some cases concrete 

cores have been obtained to evaluate concrete strength, investigate concrete embedded steel 

reinforcement for corrosion, or perform petrographic examinations. 

In general, the performance of NPP safety-related concrete structures has been very good. 

However, occurrences of concrete degradation in all likelihood will increase as the plants age, 

primarily due to environmental effects. Occurrences of degradation have been identified 

through visual inspections primarily conducted in accordance with Maintenance Rule inspection 

requirements, or in compliance with ASME Code Section XI, Subsection IWL, requirements. 

This study identified 37 occurrences of degradation (26 occurrences from the present study plus 

11 occurrences from previous investigations) that have occurred at 23 sites. Examples of 

degradation identified include concrete cracking, concrete freezing and thawing damage, 

corrosion of steel reinforcement, corrosion of posttensioning tendon wires, anchor head failures 

due to stress-corrosion cracking or hydrogen embrittlement, leaching of tendon gallery concrete, 

and larger than anticipated loss of prestressing forces. Of these occurrences, concrete cracking 

and corrosion of embedded concrete steel reinforcement were the most common.

7.2 Topics for Further Consideration

With aging plants, the regulatory requirements have increased. For license renewals,

NUREG-1800, ―Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants,‖ first issued July 2001 (Ref. 31), presents a well-defined base that is consulted 

during staff evaluations of a licensee‘s application. The technical basis of license renewals for 

structures centers on NUREG-1801, ―Generic Aging Lessons Learned (GALL) Report,‖ first 

issued July 2001 (Ref. 32), and other regulatory documents (e.g., regulatory guides, design

guides) that provide additional guidance to assess licensee programs and their elements. 

Topics for further consideration could include those that enhance such program elements as 

parameters monitored or inspected, and the detection of aging effects.

Technology is needed to develop improved in situ detection techniques for corroded torus areas 

and for evaluating the impact on concrete structures of aging (e.g., potential reduction in 

structural margins) resulting from borated water exposure or expansions due to presence of 

alkali silica or alkali aggregate reactions. Methodologies to assess the life expectancy of these 

components through modeling and simulation, supplemented where applicable with repairs and 

management of the detrimental aging effects, are also desired. For weldments, techniques that 

provide improvements in current capabilities (e.g., relative to that of vacuum box testing) for 

detection of aging effects, such as cracks, porosity, lack of fusion, and incomplete penetration,

would be beneficial. Based on operating experience gained from current inservice coating 

systems, in conjunction with modeling and simulation, methods could be developed for use in 

evaluating the performance of newer, yet untested by the industry, coatings (or ―adhesive‖ steel 

tape-based) systems to effectively stop leakage in reactor refueling cavities and SFPs, or to 
90

protect tori from further corrosion so that they can continue to perform within their design 

assumptions and intended functions during the period of extended operation.

Some of the topics for further consideration listed below are based on an understanding of the 

operating experience at NPPs as described in Appendices A, B, and C, Chapter 6, and 

knowledge of aging effects and aging mechanisms that can adversely affect reinforced concrete 

structures exposed to environments common at existing NPPs. These considerations also 

reflect methods for mitigating the potential consequences of aging effects on reinforced 

concrete structures in the next generation of NPPs. Reinforced concrete‘s behavior is strongly 

entrenched in the collective performance of the following: 

• concrete, composed of chemically fused fine and coarse aggregate, cement, and 

admixtures

• reinforcing steel

• the ―bond zone,‖ the boundary layer between steel and concrete, that, through adhesion 

and mechanical interlock, contributes to the effective performance of the composite 

material

7.2.1 Reactor Refueling Cavity and Spent Fuel Pool Leakage 

Repairs in reactor refueling cavity and SFP structures are difficult and sometimes impractical. 

Their leakage, however, could be stabilized or controlled through technology that could help 

reduce the porosity of or eliminate ―pinholes‖ in liner weldments. Assembling operating 

experience related to the various types of coatings being used by licensees to stop the leakage 

of borated water through cracks in the reactor refueling cavity and SFP stainless steel liners is 

the first step to help identify coatings with good performance histories. This information would 

be useful in developing an improved basis for evaluating proposed plans by licensees to reduce 

or eliminate the reactor refueling cavity and SFP leakage through application of coating 

materials. Development of procedures for the repair of reactor refueling cavity and SFP leakage 

at seam welds (e.g., adhesive steel tape) or plug welds (e.g., composite patches) would also be 

beneficial with respect to reducing or eliminating leakage.

Compiling laboratory and petrographic examination results from concrete cores taken by 

different licensees to quantify the effects of borated water leakage on concrete and steel 

reinforcing bars would contribute to an improved understanding of the significance of the effect 

of borated water on concrete, steel reinforcing materials, and concrete-steel bond. These 

results also have application to the development of quantitative and predictive measures to 

assess the need for corrective actions, such as repairs or replacements, and for structural 

assessments of reinforced concrete structures. Little is understood about the effects on

concrete permeability of lengthy exposures to low acidity environments. Friable and 

increasingly porous concrete resulting from continuous exposure to borated water flow or 

seepage, particularly the concrete adjacent to reinforcing steel, could potentially result in a 

reduction in the confinement of the reinforcing steel that could impact the composite 

performance of the concrete and steel. Lack of adequate adhesion and mechanical bond of 

steel to concrete as a result of a compromised bond zone could potentially result in a reduction 

in structural margins. Similarly, compromised (or loss of) clear cover to the steel reinforcement

due to the exposure of concrete to borated water not only increases the vulnerability of the 

reinforcing steel to the environment but also increases the requirement for bond development 

length that may or may not be available, thus potentially reducing the overall composite 
91

structure‘s capacity to resist the loads to which it was originally designed. An effort, therefore, is 

needed to understand the aged composite‘s behavior (reinforced concrete) and to follow up with 

updated analyses accounting for the modified composite material performance, thus realistically 

assessing the impacted structures‘ design margins. 

Periodic monitoring of the fluid collected by the leak chase channels and testing for items such 

as pH, iron and boron content, the presence of concrete constituents, and chloride 

concentration could provide data useful in developing criteria related to assessing the 

significance and potential impact of the leakage on the concrete and steel reinforcing materials 

and thus the structural margins. Results will also provide information to verify the source of the 

leakage.

As operating experience shows several occurrences of reactor refueling cavity and SFP leakage 

at existing plants, alternative (or improved) designs for reactor refueling cavity and SFP leakage 

collection systems for the next generation of NPPs would be beneficial. Alternative (or 

improved) designs could incorporate provisions for improved access for periodic inservice 

inspection of the reactor refueling cavity and SFP liners and collection system components, and 

the potential to repair or replace areas of the liner that experience inservice damage, including 

through-wall cracks and defects in the liner plate base metal and the seam and plug welds. 

With respect to new plants having an SFP with borated water, operating experience indicates 

that additional detail and improved methods concerning the examination of the plate seam 

welds would be beneficial, and minimization or elimination of the use of plug welds could lead to 

improved leak-tightness of the refueling cavities and SFPs.

7.2.2 Torus Corrosion and Cracking

Diligent monitoring of the torus structure for pitting corrosion is extremely important. Randomly 

developing corrosion pits introduce nonlinearities of unknown implications to the integrity of the 

toroidal structure. To date, because of the difficulty of the in situ measurement and monitoring 

of these imperfections, coupled to that associated with computational/approximation techniques 

to account for their influence, structural analyses for the assessment of torus structural integrity 

during the period of extended operation has been quite challenging. For example, the 

traditional modeling of corroded material next to that of pristine/uncorroded material 

inadvertently introduces computational inaccuracies (localized stresses due to thick/thin 

transitions and introduced eccentricities) that could affect the accuracy of results. Therefore,

improvements of computational techniques are required to assess the impact of corrosion on 

the torus structural integrity.

Development of improved guidelines and more effective inspection techniques for evaluating 

pitting corrosion would be beneficial, as they would lead to more consistent assessments of its 

significance in the torus structure. These guidelines could be used to develop acceptance 

criteria (e.g., pit density) that complement the acceptance standards in ASME Code Section XI, 

Subsection IWE-3500. These complementary acceptance criteria could address specific 

parameters (e.g., pit depth and pit distribution) that need to be considered by the responsible 

individual and establish the types of engineering evaluations required to justify acceptance 

without repair or replacement. 

Compiling operating experience related to the effectiveness of torus coating repairs in 

controlling or eliminating pitting corrosion would aid in identifying coating repairs with good 

performance histories. These data would be useful in developing an improved basis for 

evaluating proposed plans by licensees to repair coating damage or delay the coating repair 
92

until a later date. The results could also be used as the basis for evaluating LRAs for 

consistency with Aging Management Program (AMP) XI.S8, ―Protective Coating Monitoring and 

Maintenance Program,‖ in NUREG-1801 (Ref. 32).

7.2.3 Concrete Age-Related Degradation 

Although there is a good understanding of the behavior of posttensioned and reinforced 

concrete structures in the NPPs, a greater understanding of their performance and durability by

taking into consideration their original design assumptions and the impact of aging will help 

extend their design life, ensure their structural integrity (e.g., structural margins), and reinforce 

the public‘s trust in their continued safe operation. A thorough understanding can help reduce 

the time and cost of repairs, while a lack of understanding could limit the service life of a plant. 

Technology based on past performance or operating experience, therefore, is needed to identify 

and suggest repair techniques to maintain the structural integrity of older plants during the 

period of extended operation. 

To provide an improved process for understanding concrete degradation, a consistent use of 

definitions and terms for describing and standardizing structures, components, materials, 

environments, aging effects, and aging mechanisms in NUREG-1801 when preparing reports 

that describe occurrences of concrete degradation would be beneficial. This would reduce 

possible confusion in characterizing and categorizing occurrences of reinforced concrete 

structure and component degradation. Consistent use of definitions and terminology, therefore, 

would lead to improved and more consistent evaluations of operating experience.

Other issues regarding material durability focus on material reactivity. Slower or less reactive 

forms of alkali-aggregate reactions may be present, resulting in alkali-aggregate reactivity 

occurring even though the aggregate materials may have met the American Society for Testing 

and Materials testing requirements with respect to potential reactivity. Development of an 

improved test procedure to evaluate the potential reactivity of candidate aggregate materials for 

use in repair activities or in construction of new NPP concrete structures would help to ensure 

that alkali-aggregate reactions would not occur in the future. Also, identification of procedures 

to evaluate the existence of or potential for future reactivity of aggregates in existing plants 

(i.e., future expansion) would be beneficial in formulating mitigation strategies, as well as in 

developing assessment criteria. An improved understanding of the resulting concrete 

expansion as well as the current and anticipated rates of expansion is important. The 

occurrence of alkali-aggregate reactivity could reduce concrete‘s ductility as the reinforcing steel 

attempts to keep up through the bond zone with the expanding concrete. There are little

understanding and few data available to perform re-analyses of reinforced concrete structures 

under conditions such as this (Ref. 121).

The knowledge accumulated from the above two examples on material reactivity for cement,

paste, aggregates, and lengthening the life of reinforcing steel under adverse conditions would 

help establish databases that can be used to develop predictive tools. These tools that are 

based on improved understanding of age-related degradation mechanisms and the projected 

durability of materials would help with the assessment of the remaining life of reinforced 

concrete structures in NPPs. 

 

Sacrificial anodes have been used in an attempt to prevent corrosion of carbon steel reinforcing 

bars embedded in concrete exposed to brackish water or seawater. They have been applied to 

both new construction and the repair of existing structures. A review of operating experience 

would provide information on the effectiveness of the sacrificial anodes in reducing the potential 
93

for corrosion of reinforced concrete structures subjected to brackish or salt water (e.g., coastal 

water intake structures). Development of an operating experience database would contribute to 

an improved basis for evaluating LRAs for consistency with AMP XI.S6, ―Structure Monitoring 

Program,‖ and AMP XI.S7, ―RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants,‖ in NUREG-1801 (Ref. 32).

95

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111. — — —. ―Evaluations of Structural Failure Probabilities and Candidate Inservice 

Inspection Programs.‖ NUREG/CR-6986. U.S. Nuclear Regulatory Commission: 

Washington, DC. May 2009.

112. Dunn, D.S., A.L. Pulvirenti, and M.A. Hiser. ―Containment Liner Corrosion Operating 

Experience Summary Technical Letter Report—Revision 1.‖ U.S. Nuclear Regulatory 

Commission: Washington, DC. August 2, 2011.
104

113. U.S. Nuclear Regulatory Commission. ―Status of License Renewal Applications and 

Industry Activities.‖ U.S. Nuclear Regulatory Commission: Washington, DC. Available 

at http://www.nrc.gov/reactors/operating/licensing/renewal/applications.html.

114. Kim, T.J., and R. Auluck. ―Safety Evaluation Report Related to the License Renewal of 

the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power 

Station, Units 1 and 2.‖ NUREG-1796. U.S. Nuclear Regulatory Commission: 

Washington, DC. October 2004.

115. U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the License 

Renewal of Oyster Creek Nuclear Generating Station.‖ NUREG-1875. U.S. Nuclear 

Regulatory Commission: Washington, DC. April 2007.

116. Naus, D.J. ―Concrete Component Aging and Its Significance Relative to Life Extension 

of Nuclear Power Plants.‖ NUREG/CR-4652. U.S. Nuclear Regulatory Commission: 

Washington, DC. September 1986.

117. Electric Power Research Institute. ―Boric Acid Attack of Concrete and Reinforcing Steel 

in PWR Fuel Buildings.‖ EPRI TR-1019168. Electric Power Research Institute: Palo 

Alto, CA. June 2009.

118. American Concrete Institute. ―Guide for Conducting a Visual Inspection of Concrete in 

Service.‖ ACI 201.1R-08. American Concrete Institute‖ Farmington Hills, Michigan. 

2008.

119. American Concrete Institute. ―Evaluation of Existing Nuclear Safety-Related Concrete 

Structures.‖ ACI 349.3R-02. American Concrete Institute: Farmington Hills, Michigan. 

2002.

120. U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the License 

Renewal of Salem Nuclear Generating Station.‖ NUREG-2101. U.S. Nuclear 

Regulatory Commission: Washington, DC. June 2011.

121. Fournier, R., M-A Bérubé, K.K. Folliard, and M. Thomas. ―Report on the Diagnosis, 

Prognosis, and Mitigation of Alkali-Silica Reaction (ASR) in Transportation Structures.‖

FHWA-HIF-09-004. Federal Highway Administration: Washington, DC. 2010.
A- 1

APPENDIX A: LEAKAGE FROM REACTOR REFUELING CAVITY

CASE STUDIES

A.1 Browns Ferry Nuclear Plant, Units 2 and 3

A.1.1 Introduction

On December 31, 2003, the Tennessee Valley Authority submitted a license renewal application 

(LRA) to the U.S. Nuclear Regulatory Commission (NRC) for its Browns Ferry Nuclear (BFN) 

Plant, Units 1, 2, and 3 (Ref. A.1.6.1). Results of the NRC staff‘s evaluation of the LRA were 

published in April 2006, in NUREG-1843, ―Safety Evaluation Report Related to the License 

Renewal of the Browns Ferry Nuclear Plant, Units 1, 2, and 3‖ (Ref. A.1.6.2). The NRC also 

published a supplement to NUREG-1843 in April 2006 (Ref. A.1.6.3).

A.1.2 Field Observations

During the Unit 2 Cycle 9 outage, a portion of the moisture barrier was replaced (Problem 

Evaluation Report (PER) BFPER971516) (Ref. A.1.6.4). Engineering personnel performed an 

examination of the exposed drywell steel containment vessel area below the moisture seal. 

This inspection indicated some minor pitting and localized rust but nothing indicating a 

challenge to nominal wall thickness. No propagation of iron oxide to the concrete surface was 

noted, which would be indicative of steel containment vessel corrosion below the concrete. 

Inspections conducted by the containment inservice inspection program during the Unit 2 

Cycle 10 refueling outage and Unit 3 Cycle 9 refueling outage also identified some damaged 

areas of the moisture barrier (gaps, cracks, low areas or spots, or other surface irregularities) 

that were evaluated by engineering and replaced or repaired (PER 99-005254-000 for the Unit 2 

drywell moisture seal barrier and PER 00-004163-000 for the Unit 3 drywell moisture seal 

barrier) (Ref. A.1.6.4).

A.1.3 Design Characteristics of Reactor Refueling Cavity

The reactor building for each unit completely encloses the reactors, the primary containment 

structures, and the auxiliary and emergency systems of the nuclear steam supply system. A 

major substructure of the reactor building is the reinforced concrete biological shield that 

surrounds the drywell portion of the primary containment. The reactor buildings also house 

features such as the spent fuel pool, steam dryer/moisture separator storage pool, reactor 

cavity, reactor auxiliary equipment, refueling equipment, reactor servicing equipment, and 

control bay. The control bay houses the main control room for plant operation and other 

important auxiliary systems required for plant operation. The reactor building consists of 

monolithic reinforced concrete floors and walls from its foundation to the refueling floor. The 

refueling floor, that is common for all three units, is enclosed by the steel superstructure with 

metal siding and a built-up roof. Blowout or pressure relief panels are installed as part of the 

reactor building metal siding superstructure to relieve pressure during a design-basis accident 

(DBA) or a design-basis earthquake (DBE).
A- 2

A.1.4 Corrective Actions for Reactor Refueling Cavity Leakage

During 1987, each unit‘s drywell was ultrasonically tested near the sand cushion area 

(Ref. A.1.6.4). The results from these tests showed that the nominal thickness was maintained

on each drywell. The following are the results of each unit‘s drywell ultrasonic testing (UT):

• Unit 1—No reading below the nominal thickness of 25.4 millimeters (mm) (1 inch) was 

measured, indicating that the integrity of the drywell liner plate is maintained. Periodic 

leakage from the sand cushion area has been observed. Corrosive species in the 

drainage are suspect of a higher rate of corrosion on the Unit 1 drywell liner plate than 

on Unit 2 and 3. However, objective evidence of serious corrosion damage was not 

noted.

• Unit 2—No reading below the nominal thickness of 25.4 mm (1 inch) was measured,

indicating that no damage to the integrity of the drywell liner plate has occurred.

• Unit 3—No reading below the nominal thickness of 25.4 mm (1 inch) was measured,

indicating that no damage to the integrity of the drywell liner plate has occurred.

During each refueling outage since the mid-1980s, visual inspections of the interior surface of 

the drywell and the interior and exterior surface of the drywell head and torus (suppression 

chamber) are performed to verify structural integrity (SI) (Ref. A.1.6.5). These inspections are

performed per SI 0-SI-4.7.A.2.K, ―Primary Containment Drywell Surface Visual Inspection,‖ and 

BFN Technical Instruction 0-TI-417, ―Inspection of Service Level I, II, III Protective Coatings.‖ 

SI 0-SI-4.7.A.2.K originally included the exam requirements for the visual inspections of the 

protective coatings but was revised in March 2001 to remove those requirements and add the 

reference to BFN Technical Instruction 0-TI-417 for coating inspections. BFN Technical 

Instruction 0-TI-417 was written to incorporate the information for performing visual inspections 

of Service Level I protective coatings (DBA and non-DBA qualified). Procedure 

SI 0-SI-4.7.A.2.K provides for visual inspections of the following:

(1) structural components of the drywell, drywell head, torus (suppression chamber), and 

the exterior surfaces of the drywell head and torus (suppression chamber) (i.e., piping, 

connections, structural supports, penetrations, platform steel, duct supports, concrete 

walls, and steel shell) by visually inspecting for deterioration or structural damage, or 

both

(2) moisture seal barrier located on drywell elevation 167.6 meters (m) (550 feet).

(3) interior surfaces of the drywell and torus (suppression chamber) above level 0.305 m 

(1 foot) below the normal waterline and the exterior surface of the torus (suppression 

chamber) below the waterline each operating cycle for deterioration and any signs of 

structural damage, with particular attention to piping connections and supports, and for 

signs of distress or displacement 

A.1.5 Structural Integrity Assessment and Test Results

Existing degradation of the drywell shells (inside and out) at the time of license renewal has not 

reached the minimum required thickness of 25.4 mm (1 inch) (Ref. A.1.6.2). For Unit 1, 
A- 3

one-time confirmatory ultrasonic thickness measurements will be performed on the vertical 

cylindrical area immediately below the drywell flange (Ref. A.1.6.6). A commitment was made 

to perform these ultrasonic thickness measurements before the Unit 1 restart and before the 

period of extended operation for Units 2 and 3. For Units 2 and 3, the same testing will be 

performed in the portion of the cylindrical section of the drywell in a region where the liner plate 

is 19.05 mm (0.75 inches) thick. This will provide a bounding condition, since the nominal 

thickness of the wall in this region has the least margin. 

A.1.6 References

A.1.6.1 Burzynski, M.J., Tennessee Valley Authority, letter to U.S. Nuclear Regulatory 

Commission, December 31, 2003.

A.1.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of the Browns Ferry Nuclear Plant, Units 1, 2, and 3.‖ 

NUREG-1843. U.S. Nuclear Regulatory Commission: Washington, DC. April 2006.

A.1.6.3 — — —. ―Safety Evaluation Report Related to the License Renewal of the Browns 

Ferry Nuclear Plant, Units 1, 2, and 3.‖ NUREG-1843, Supplement 1. U.S. Nuclear 

Regulatory Commission: Washington, DC. April 2006.

A.1.6.4 Abney, T.E., Tennessee Valley Authority, letter to U.S. Nuclear Regulatory 

Commission, January 31, 2005.

A.1.6.5 Skaggs, M.D., Tennessee Valley Authority, letter to U.S. Nuclear Regulatory 

Commission, May 31, 2005.

A.1.6.6 Crouch, W.D., Tennessee Valley Authority, letter to U.S. Nuclear Regulatory 

Commission, November 16, 2005.

A- 5

A.2 Hope Creek Generating Station, Unit 1

A.2.1 Introduction

On August 18, 2009, PSEG Nuclear, LLC (PSEG) submitted an LRA to the NRC for renewal of 

the Hope Creek Generating Station (Ref. A.2.6.1). Results of the NRC staff‘s evaluation of the 

LRA were published in June 2011, in NUREG-2102, ―Safety Evaluation Report Related to the 

License Renewal of the Hope Creek Generating Station‖ (Ref. A.2.6.2). On November 3, 2010,

a presentation was made to the Advisory Committee on Reactor Safeguards (Ref. A.2.6.3).

A.2.2 Field Observations

During the 2009 refuel outage, about a 6.35-mm (0.25-inch) wide trickle of water was found 

exiting the seal rupture drain line penetration sleeve J13 (see Figure A.2-2) from the drywell air 

gap region and had ponded on the torus floor. Analysis of the ponded water identified it as 

reactor water/refueling water. The water leakage stopped after the refueling cavity was drained 

at the end of the refueling outage. The suspected source of the water was a defect or tear in 

the refuel bellow or the liner. Because water may be trapped between the concrete and the 

drywell steel below penetration sleeve J13, which is located approximately 2.44 m (8 feet) 

above the drywell lower air gap drains, corrosion of the drywell steel containment is possible. 

The air gap drains were inspected in 2009, but there was no blockage or standing water found 

in the air gap region and the drywell shell showed no signs of corrosion. The water leakage 

issue was entered into the corrective action process to determine the cause of the leakage and 

corrective actions to prevent reoccurrence.

A.2.3 Design Characteristics of the Refueling Cavity

The reactor building includes the spent fuel storage pool liner, cask loading pit liner, reactor 

cavity liner, steam dryer/moisture separator storage pool liner, and spent fuel storage pool 

skimmer surge tank liner. The containment has no sand-pocket region. Potential leakage of 

water from the reactor cavity during refueling is removed by the reactor cavity seal rupture drain 

lines that are monitored by instrumentation designed to alarm the main control room in the event 

of leakage. There are also drains at the bottom of the air gap region at the junction where the 

shell becomes embedded in concrete.

A cross section of the reactor building and Mark I containment with the locations of the spent 

fuel pool, reactor cavity seal liner proximity to concrete containment, torus shell, and so forth is 

shown in Figure A.2-1. Further features, including the J13 penetration areas, are shown in 

Figure A.2-2. Cross sections of the reactor cavity seal area and the lower drywell area are 

detailed in Figures A.2-3, and A.2-4, respectively. 

A.2.4 Corrective Actions for Refueling Cavity Leakage

Various activities were performed prior to restart from the 2009 refueling outage, and it was 

determined that the leakage was due to a small crack or cracks in either the welds of the reactor 

cavity seal plates, refueling bellows, or reactor cavity drain lines. Additional activities were 

planned during the 2010 outage to determine the root cause. These activities included 

(1) inspecting reactor cavity seal rupture drain lines for blockage and monitoring leakage daily 

from penetration sleeve J13, the drywell air gap drain lines, and the reactor cavity seal rupture 
A- 6

drain lines, (2) observing variations in water leakage and characterizing how it is affected by the 

water levels in the reactor cavity, and (3) performing boroscope inspections below penetration 

sleeve J13 for conditions that prevent water leakage from reaching the drywell lower air gap 

drains. In addition, the American Society of Mechanical Engineers (ASME) Boiler and Pressure 

Vessel Code (ASME Code) (Ref. A.2.6.4) Section XI, Subsection IWE, program was enhanced 

to (1) verify that the reactor cavity seal rupture drain lines are clear from blockage and that the 

monitoring instrumentation is functioning properly prior to the period of extended operation and 

one additional time during the first 10 years of the period of extended operation, (2) investigate 

the source of any leakage detected by the reactor cavity seal rupture drain line instrumentation 

and perform an assessment of its impact on the drywell shell, (3) monitor the drains daily at the 

bottom of the drywell air gap for leakage when the reactor cavity is flooded, and (4) periodically 

monitor penetration sleeve J13 for water leakage when the reactor cavity is flooded up until 

corrective actions are taken to prevent leakage through J13.

A.2.5 Structural Integrity Assessment and Test Results

One-time UT thickness measurements from inside the drywell in the accessible area of the 

drywell shell directly below penetration sleeve J13 were scheduled to be performed in 2010. 

Inspection and acceptance criteria will be in accordance with ASME Code 

Subsections IWE-2000 and IWE-3000, respectively, and, in the event significant corrosion is 

detected, the condition will be entered in the corrective action program for evaluation and extent 

of condition determination. In addition, the area will be designated for augmented examination 

in accordance with ASME Code Subsection IWE-1240 requirements, as identified in 

Table IWE-2500-1, Examination Category E-C (Ref. A.2.6.4). UT examination of the drywell 

area below penetration J13 down to penetration J37 will be performed after the one-time 

examination in 2010 and during each inspection period (three times in 10 years) until the reactor 

cavity water leakage from penetration J13 is repaired. 

The reactor cavity leakage will be repaired, if practical, before the period of extended operation. 

If repairs cannot be made prior to the period of extended operation, augmented inspections of 

the affected area of the drywell surface will be performed (Ref. A.2.6.5) to demonstrate that 

corrosion is not occurring or corrosion is progressing so slowly that age-related degradation will 

not jeopardize the intended function of the drywell through the period of extended operation. In 

addition, a corrosion rate will be developed based on past UT examinations. This rate will be 

used to project loss of drywell thickness through the period of extended operation, and to 

evaluate the results to determine if the drywell can perform its intended function during the 

period of extended operation with reduced thickness.

A.2.6 References

A.2.6.1 Fricker, C.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

August 18, 2009.

A.2.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Hope Creek Generating Station.‖ NUREG-2102. U.S. Nuclear 

Regulatory Commission: Washington, DC. June 2011.
A- 7

A.2.6.3 ―Official Transcript of Proceedings, Advisory Committee on Reactor Safeguards 

Hope Creek License Renewal Subcommittee.‖ Work Order No. NRC-542. 

Neal R. Gross and Co., Inc., Court Reporters and Transcribers: Washington, DC.

November 3, 2010.

A.2.6.4 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.

A.2.6.5 Brady, B.M., U.S. Nuclear Regulatory Commission, letter to PSEG Nuclear, LLC, 

September 2, 2010.
A- 8

Figure A.2-1 Cross section of reactor building and Mark I containment 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Hope Creek License Renewal Subcommittee.” Work Order No. NRC-542.

November 3, 2010)

Figure A.2-2 Locations of reactor cavity seal and J13 penetration areas 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Hope Creek License Renewal Subcommittee.” Work Order No. NRC-542.

November 3, 2010)
A- 9

Figure A.2-3 Cross section of reactor cavity seal area 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Hope Creek License Renewal Subcommittee.” Work Order No. NRC-542.

November 3, 2010)

Figure A.2-4 Cross section of lower drywell area 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Hope Creek License Renewal Subcommittee.” Work Order No. NRC-542.

November 3, 2010)

A-11

A.3 Indian Point Nuclear Generating Unit 2 

A.3.1 Introduction

By letter dated April 23, 2007 (Ref. A.3.6.1), and as supplemented by letters dated May 3 

(Ref. A.3.6.2) and June 21, 2007 (Ref. A.3.6.3), Entergy Nuclear Operations, Inc., submitted an

LRA to the NRC for Indian Point Nuclear Generating Units 2 and 3. The results of the NRC 

staff‘s evaluation of the LRA were published in November 2009 in NUREG-1930, ―Safety 

Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit 

Nos. 2 and 3‖ (Ref. A.3.6.4).

A.3.2 Field Observations

During the first refueling outage in 1976, leakage from the refueling cavity was observed. It was 

attributed to the lack of leak tightness between the originally designed temporary seal of the 

reactor vessel flange and the reactor cavity. Once leakage was collected in the reactor cavity 

pit sump, it was pumped out. A plant modification followed, in which a newly designed seal 

resolved the problem. Leakage also occurred in the reactor vessel inlet and outlet blow-out 

plugs and instrumentation wireways. Leakage through these paths has been minimized by 

improved sealing methods. 

In 1993, through visual observations, leakage from the refueling cavity was detected, and it was 

concluded to be coming through the stainless steel liner plates when the cavity is filled during 

refueling outages (normally every 24 months) (Ref. A.3.6.5). Leaks last approximately 14 days 

and are a mixture of reactor coolant and refueling water from the storage tank, and they begin 

when the water level reaches approximately 50 percent of the refueling cavity level. Total 

estimated flow rates are on the order of 1.8 to 4.4x10-4cubic meters per second (m

3

/s)

(3 to 7 gallons per minute (gpm)). A small portion of the leakage from the refueling cavity enters 

the reactor cavity, flowing down the interior primary shield walls to a sump located in the reactor 

cavity, from which it is pumped to the containment sump. Leakage inside the reactor cavity has 

been primarily attributed to non-liner leakage associated with reactor cavity seal and nozzle

inspection box cover isolation issues. No samples of the fluid flowing from the leaking areas 

have been analyzed for chemical composition (Ref. A.3.6.4).

Visual examination of the leakage areas has not identified any degradation of concrete.

The 1993 leakage was observed initially from three areas associated with refueling cavity 

construction: the liner seam, plug, and structural attachment welds on the west wall. Damage 

to the liner was determined to have occurred during previous refueling outages due to poor 

cleanliness and maintenance control. This included use of improper material and tools (a wire 

brush contaminated with carbon steel and containing chloride) coming in contact with stainless 

steel. In addition, a cut into the liner plate occurred during removal (cutting out) of temporary 

attachments to the liner (Ref. A.3.6.5). CeramAlloyTM patches at the 24.4- to 25.9-m (80- to 

85-foot) elevation along two horizontal seam welds located on the south wall and patches along 

the seam weld on the north wall approximately 3.0 to 4.6 m (10 to 15 feet) above the cavity floor 

were identified as potential leakage sources (Ref. A.3.6.6). 
A-12

A.3.3 Design Characteristics of the Refueling Cavity

The refueling cavity in the containment building is a robust structure with 1.2-m (4-foot) thick 

walls and low stress levels when compared to the total structural capacity (Ref. A.3.6.4). 

A.3.4 Corrective Actions for Refueling Cavity Leakage

Attempts, with limited success, were made over several outages to mitigate the refueling cavity 

leakage. A sequential action plan with the following elements was developed (Ref. A.3.6.7) for 

a permanent fix to this issue: 

• 2008/2009, research available technologies for leak repairs in the 

refueling cavity.

• Spring 2010 refueling outage—Repair area of north wall weld seams in 

the vicinity of the CeramAlloyTM patch and south wall along area of 

disbonded CeramAlloyTM patch. Analyze water leaking from the refueling 

cavity for boron concentration, pH, iron, and calcium.

• Spring 2012 refueling outage—Repair east wall where large CeramAlloyTM

patch has disbonded and area around access ladder on northwest corner.

• Spring 2014 refueling outage—Repair areas of lower cavity where 

CeramAlloyTM patches have disbonded, and miscellaneous areas 

observed as suspect to leakage from past inspections.

• During each of the preceding outages, areas not permanently repaired 

will be temporarily repaired by the application of InstaCoteTM

.

 Beginning 

with the refueling outage in Spring 2016, no InstaCoteTM will be applied, to 

allow Entergy to determine if repairs have successfully stopped the 

leakage. If not, additional areas will be repaired in subsequent outages 

until the leakage is corrected.

The method to monitor for a degrading condition in the refueling cavity is routine visual 

inspection of accessible concrete surfaces under the structures monitoring program,

accompanied by an inspection of concrete that has been exposed to the intermittent borated 

water leakage for an extended period. For aging management of the cavity steel liner, Entergy 

will rely on the water chemistry control—primary and secondary program. 

A.3.5 Structural Integrity Assessment and Test Results

In 2008, it was noted that the leakage does not pose a threat to the SI of the refueling cavity 

reinforced concrete walls, which are 1.22 m (4 feet) thick, and several documented tests were 

cited that concluded borated water does not significantly degrade concrete properties 

(Ref. A.3.6.8). Furthermore, it was noted that substantial design margins for both steel and 

concrete exist and that the flooded condition and leakage last only 2 weeks out of a refueling 

cycle. Examination of a 1993 core sample removed from the Unit 2 refueling cavity wall showed 

that the depth of penetration of borated water was 12.7 mm (0.5 inch) into the concrete at that 

time. A number of attempts have been made to rectify the leakage, but to date have not been 
A-13

completely successful. Work will continue toward a permanent fix, but this effort will be

prioritized based on safety significance and the availability of site resources (Ref. A.3.6.4).

In 2009, the licensee stated that, during the upcoming 2010 outage, a total of three core bore 

samples will be taken from the reinforced concrete walls that form the outer shell of the reactor 

refueling cavity steel liner (Ref. A.3.6.6). The locations of these core bores will be chosen 

based on the following:

• Locations in the vicinity of observed liner/liner patch degradation in 

relative proximity to the observed leak points on the concrete structure 

noted earlier.

• Accessibility of suspect areas based on the principle of As Low As 

Reasonably Achievable (ALARA) and physical interferences.

The core samples will be tested and chemically analyzed to determine the effect, if any, that 

past leakage has had on the concrete properties. The objectives of the physical and chemical 

tests of the concrete core samples are as follows:

• Determine the compressive strength of concrete.

• Determine boron and chloride concentration in concrete.

• Determine pH of concrete.

A petrographic examination will be performed on the core samples to evaluate the condition of 

the cementitious matrix and, to the extent possible, determine the durability of the concrete. In 

addition, reinforcing steel in the cored areas, when exposed, will be visually inspected to 

determine the extent of loss of material, if any, as a result of the borated water leakage.

It was further noted in 2009 that, if a solution to the leakage has not been achieved, Entergy will 

perform core bore samples and reinforcing steel inspections prior to 10 years into the period of 

extended operation based on the extent and location of the remaining leakage following 

previous repair efforts. The core samples will be tested and chemically analyzed as discussed 

above. Visual inspections of the reinforcing steel will follow to assess loss of material as a 

result of the borated water leakage.

A.3.6 References

A.3.6.1 Dacimo, F.R., Indian Point Energy Center, letter to U.S. Nuclear Regulatory 

Commission, April 23, 2007.

A.3.6.2 Dacimo. F.R., Indian Point Energy Center, letter to U.S. Nuclear Regulatory 

Commission, May 3, 2007.

A.3.6.3 Dacimo. F.R., Indian Point Energy Center, letter to U.S. Nuclear Regulatory 

Commission, June 21, 2007.
A-14

A.3.6.4 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3.‖

NUREG-1930, Volumes 1 and 2. U.S. Nuclear Regulatory Commission: 

Washington, DC. November 2009.

A.3.6.5 Dacimo, F., Entergy Nuclear Northeast—Indian Point Energy Center, letter to 

U.S. Nuclear Regulatory Commission, March 24, 2008.

A.3.6.6 Dacimo, F., Entergy Nuclear Northeast—Indian Point Energy Center, letter to 

U.S. Nuclear Regulatory Commission, June 12, 2009.

A.3.6.7 Dacimo, F., Entergy Nuclear Northeast—Indian Point Energy Center, letter to 

U.S. Nuclear Regulatory Commission, November 6, 2008.

A.3.6.8 Dacimo, F., Entergy Nuclear Northeast—Indian Point Energy Center, letter to 

U.S. Nuclear Regulatory Commission, August 14, 2008.
A-15

A.4 Kewaunee Power Station

A.4.1 Introduction

On August 12, 2008, Dominion Energy Kewaunee, Inc., submitted an LRA to the NRC for its 

Kewaunee Power Station (Ref. A.4.6.1). Results of the NRC staff‘s evaluation of the LRA were 

published in January 2011 in NUREG-1958, ―Safety Evaluation Report Related to the License 

Renewal of Kewaunee Power Station‖ (Ref. A.4.6.2).

A.4.2 Field Observations

Leaching and cracking on the outer concrete surface of the reactor refueling cavity wall (south 

side) was observed in April 2003 (Ref. A.4.6.1). The indications noted were localized and the 

overall SI of the wall appeared sound. The reactor refueling pool was flooded at the time of the 

observation. The hairline cracking was considered passive and did not affect the SI of the 

concrete wall. Based on data from earlier inspection and chemistry sampling, a small amount of 

borated water found its way down the wall, followed the lip of the narrow crack, and deposited 

boric acid crystals when it dried. The accessible wall area was cleaned. During a subsequent 

inspection in October 2004, there was no change in appearance from 2003, nor any indication 

of an active leak or the presence of moisture.

During the 2006 and 2008 refueling outages, three leakage locations were identified 

(Ref. A.4.6.3).

Leakage Site No. 1 is noted above. This cracked location was reinspected with the refueling 

pool flooded. The inspection did not find any active leakage through the crack. Based on the 

October 2004 inspection, it was concluded that no further action was required and that the 

leakage indication at Leakage Site No. 1 in 2003 was due to a small amount of borated water 

from a source external to the reactor refueling cavity pool. 

Leakage Site No. 2, identified in October 2006, was located at the construction joint of the ―A‖ 

reactor coolant system (RCS) vault. Residue was observed streaking and staining the wall and 

there was a small amount of moisture on the wall surface below the location of the construction 

joint, but there was no measurable leakage or accumulation of boric acid crystals. This leakage 

site was again inspected during the next refueling outage in April 2008 and wetting, or moisture, 

was noted with a small amount of accumulation of residue, and the presence of wall staining 

and streaking at the ―A‖ RCS vault wall construction joint was also noted. This leakage site was 

reinspected during the 2009 refueling outage, when multiple inspections were performed at 

different times during the outage. The initial ―as-found‖ inspection was followed by another 

inspection prior to filling the reactor refueling cavity pool, and another inspection after filling the 

pool, and concluded with a final inspection at the end of the outage. After the as-found 

inspection, the residue was removed from the leakage area. No further indication was noted 

until the final inspection 17 days later after the filling of the reactor refueling cavity, when a small 

leakage was discovered. As a result, the frequency of the inspection under the structures 

monitoring program was increased to document and trend the observed conditions and assess 

the integrity of the concrete structure.

Leakage Site No. 3, identified in March 2008, was located at the junction between the reinforced 

concrete biological shield wall and the base of the reactor refueling cavity. This leakage also 
A-16

showed accumulation of residue and streaking and staining on the wall surface. There was no 

quantifiable water flow from the junction and it was considered to be minor leakage. Similar to 

Leakage Site No. 2, Leakage Site No. 3 was further inspected multiple times during the 

refueling outage of 2009. Based on the long delay for leakage indication to reappear on the wall 

surface, potential reactor refueling cavity pool leakage at this location was also considered 

minor. However, the frequency of inspection has been increased under the structures 

monitoring program to each refueling outage in order to document and trend the observed 

conditions and assess the integrity of the concrete structure. 

During the refueling outage in 2009, additional inspections were performed to check for the 

presence of other leakage and to verify that there was no moisture in contact with the reactor 

containment vessel. The containment basement and sump B, which is located nearest to the 

containment vessel, were inspected. No leakage was identified that would indicate potential 

moisture presence in contact with the reactor containment vessel. In addition, this inspection 

did not identify any additional leaks forthcoming from the reactor refueling cavity pool leakage.

A.4.3 Design Characteristics of the Refueling Cavity

The reactor containment vessel is a Class I cylindrical steel structure with a hemispherical dome 

roof and ellipsoidal bottom. The containment vessel is completely enclosed by the shield 

building. An annular space separates the shield building and the containment vessel except at 

the lower portion of the containment vessel that is embedded in concrete. The major concrete 

components are the reactor cavity shield wall, refueling pool, compartment vaults, and the floors 

at various elevations. The reactor cavity concrete shield wall surrounds the reactor vessel and 

provides biological shielding and structural support. The top of the shield wall forms the 

refueling cavity pool.

The reactor vessel flange is sealed to the bottom of the refueling cavity by a reactor cavity seal 

ring that prevents leakage of refueling water into the reactor cavity. A removable missile shield 

cover, constructed of a concrete slab enclosed by steel plates, is located above the reactor 

vessel head. The reactor cavity, refueling pool, and reactor containment vessel sump (sump A) 

are lined with stainless steel liner plates. All the liner plates are welded to structural shapes that 

are embedded and anchored in the reinforced concrete walls and floors. Sand plugs, 

constructed of steel boxes with a stainless steel cover, are installed to protect safety-related 

components located in the recessed areas of the refueling pool floor. Radiation shields at the 

fuel transfer tube penetration are used to protect personnel.

A.4.4 Corrective Actions for Refueling Cavity Leakage

The results of the inspections performed during the 2009 refueling outage were evaluated to 

provide input to determine corrective actions needed for the reactor refueling cavity pool liner 

leakage (Ref. A.4.6.4). A multidisciplinary team was formed to develop a remediation plan to 

identify and remedy reactor refueling cavity liner leakage. The plan is to be implemented during 

the period of extended operation (Ref. A.4.6.5). The plan includes weld examinations and 

identification and resealing of liner penetrations as potential leakage sites. Until the plan is 

implemented, the current leakage sites will continue to be inspected during each refueling 

outage, as well as containment internal structures with the objective of identifying any additional 

leakage indication sites. New leakage indications, or changes in existing leakage rates, will be 

documented in the corrective action program and evaluated. 
A-17

A.4.5 Structural Integrity Assessment and Test Results

Based on other nuclear plant evaluations, the effect of borated water on reinforced concrete SI

is considered to be minimal, and the leakages at the identified locations are very small 

(Ref. A.4.6.2). Consequently, it was concluded that the degradation of the reinforced concrete 

or the metal reactor containment vessel is negligible. To confirm this conclusion, an SI

examination of the concrete slab below the spent fuel pool in the auxiliary building will be 

performed and used as a representative location comparable to Leakage Sites No. 2 and No. 3, 

because the reinforced concrete material and the environments are the same for both locations.

At the minimum, one core bore sample will be obtained near at least one of the refueling cavity 

leakage indication sites if the core sample obtained below the spent fuel pool related to spent 

fuel pool leakage indicates degradation. The core sample will be tested for compressive 

strength and will undergo a petrographic examination.

A.4.6 References

A.4.6.1 Christian, D.A., Dominion Energy Kewaunee, Inc., letter to U.S. Nuclear Regulatory 

Commission, August 12, 2008.

A.4.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Kewaunee Power Station.‖ NUREG-1958. U.S. Nuclear 

Regulatory Commission: Washington, DC. January 2011. 

A.4.6.3 Scace, S.E., Dominion Energy Kewaunee, Inc., letter to U.S. Nuclear Regulatory 

Commission, August 17, 2009.

A.4.6.4 Price, J.A., Dominion Energy Kewaunee, Inc., letter to U.S. Nuclear Regulatory 

Commission, December 28, 2009.

A.4.6.5 Price, J.A., Dominion Energy Kewaunee, Inc., letter to U. S. Nuclear Regulatory 

Commission, February 15, 2010.

A-19

A.5 Oyster Creek Nuclear Generating Station

A.5.1 Introduction

By letter dated July 22, 2005 (Ref. A.5.6.1), AmerGen submitted an LRA to the NRC for the 

Oyster Creek Nuclear Generating Station. Results of the NRC staff‘s evaluation of the LRA 

were published in April 2007 in NUREG-1875, Volumes 1 and 2, ―Safety Evaluation Report 

Related to the License Renewal of Oyster Creek Generating Station‖ (Ref. A.5.6.2).

A.5.2 Field Observations

The Oyster Creek Nuclear Generating Station first discovered water in the gap between the 

drywell and the concrete shield in 1980 and began investigating the cause of the water problem 

in 1983. Water collection varied from a few drops to 1.3x10

-4 m3

/s (2 gpm), depending on 

whether the unit was in operation or was in an outage for refueling. During the spring and 

summer of 1986, the licensee planned work to identify and eliminate this water leakage problem 

(Ref. A.5.6.3).

Water that leaked from the reactor refueling cavity passed over the Firebar-D

®

coating that was 

applied to the drywell shell to allow for formation of the required seismic gap between the 

drywell shell and the encircling concrete shield wall. The Firebar-D

® material is a magnesium 

oxychloride compound. Corrosion of the outside surface of the drywell shell was discovered 

in 1986. The leaking water that accumulated in the sand bed region corroded the embedded 

drywell shell. 

A.5.3 Design Characteristics of the Refueling Cavity

The reactor building houses the spent fuel pool, the steam dryer/moisture separator storage 

pool, the new fuel storage vault, the reactor cavity, reactor auxiliary equipment, refueling 

equipment, and reactor servicing equipment. It also provides secondary containment when the 

primary containment is in service and provides primary containment during reactor refueling and 

maintenance operations when the primary containment system is open. The building is 

designed to Seismic Class I criteria and is constructed of reinforced concrete up to the refueling 

floor level.

The reactor cavity is a stainless-steel-lined reinforced concrete structure located inside the 

reactor building. It is filled with water during refueling operations. Bellows provide the seal 

between the reactor vessel and the drywell and between the drywell and the reactor cavity liner. 

Gaskets provide the seals between the drain lines and the stainless steel liner. Details of the 

reactor cavity seals are shown in Figures A.5-1 and A.5-2.

A.5.4 Corrective Actions for Refueling Cavity Leakage

In the mid- to late 1980s, extensive visual and nondestructive examination (NDE) inspections 

were conducted to determine the source of water intrusion into the seismic gap between the 

drywell concrete shield wall and the drywell shell, and its accumulation in the sand bed region 

(Ref. A.5.6.3). The inspections concluded that the refueling bellows (seals) were not the source 

of water leakage. The bellows were repeatedly tested using helium (external) and air (internal) 

without any indication of leakage. Furthermore, any minor leakage from the refueling bellows 
A-20

would be collected in a concrete trough below the bellows. The concrete trough is equipped 

with a drain line that would direct any leakage to the reactor building equipment drain tank and 

prevent it from entering the seismic gap (see Figures A.5-1 and A.5-2). The drain line had been 

checked before refueling outages to confirm that it was not blocked. 

The only other seal is the gasket for the reactor cavity seal trough drain line. This gasket was 

replaced after the tests showed that it was leaking (see Figure A.5-2). However, the gasket leak 

was ruled out as the primary source of water observed in the sand bed drains because there is 

no clear leakage path to the seismic gap. Minor gasket leakage would be collected in the 

concrete trough below the gasket and would be removed by the drain line similar to leaks from 

the refueling bellows.

Additional visual and NDE (dye penetrant) inspections of the reactor cavity stainless steel liner 

identified a significant number of cracks, some of which were through-wall. Engineering 

analysis concluded that the cracks were most probably caused by mechanical impact or thermal 

fatigue and not intergranular stress-corrosion cracking. These cracks were determined to be 

the source of the refueling water that passes through the seismic gap. To prevent leakage 

through the cracks, an adhesive-type stainless steel tape was installed to bridge any observed 

large cracks, followed by application of a strippable coating. This repair greatly reduced the 

leakage and is implemented in every refueling outage when the reactor cavity is flooded.

In 1992, sand was removed from the sand bed region and loose rust cleaned from the drywell 

shell. An epoxy coating was then applied to the exterior surfaces of the drywell shell in the sand 

bed region (Ref. A.5.6.2). In addition, the concrete floor was rebuilt and reshaped with epoxy to 

allow drainage of any water that may leak into the region. Also, several commitments were to 

be implemented, as follows:

• The reactor cavity concrete trough drain will be verified to be clear from blockage once 

per refueling cycle. Any identified issues will be addressed via the corrective action 

process.

• Consistent with current practice, a strippable coating will be applied to the reactor cavity 

liner to prevent water intrusion into the gap between the drywell shield wall and the 

drywell shell during periods when the refueling cavity is flooded. This commitment 

applies to refueling outages prior to and during the period of extended operation

• Augmented inspections of the drywell will be performed in accordance with ASME Code 

(Ref. A.5.6.4) Section XI Subsection IWE that will consist of ultrasonic (UT) 

examinations of the upper region of the drywell and visual examinations of the protective 

coating on the exterior wall of the drywell shell in the sand bed region. Visual inspection 

of the coating will be supplemented with UT measurements from inside the drywell once 

before entering the period of extended operation and every 10 years thereafter.

• The sand bed region drains will be monitored on a daily basis during refueling outages 

and quarterly during the operating cycle

An additional commitment was made to perform an engineering study prior to the period of 

extended operation to investigate cost-effective replacement or repair options potentially 
A-21

eliminating reactor cavity liner leakage (Ref. A.5.6.2).

A.5.5 Structural Integrity Assessment and Test Results

In 1986, as part of an ongoing effort to investigate the impact of water on the outer drywell shell, 

concrete was excavated at two locations inside the drywell (referred to as trenches) to expose 

the drywell shell for ultrasonic assessment of its thickness. At an elevation of 3.12 m (10 feet, 

3 inches) concrete floor slab level, 120 ultrasonic measurements were taken to characterize the 

vertical profile of corrosion in the sand bed region outside the shell and the minimum thickness 

of the shell. The minimum recorded thickness from the outside of the drywell was 15.7 mm 

(0.618 inches), while the minimum recorded thickness in the sand bed region from the inside 

was 15.3 mm (0.603 inches). These minimum recorded thicknesses are isolated local 

measurements and represent single-point ultrasonic measurements (Ref. A.5.6.2).

Additional inspections using ultrasonic thickness measurements were conducted during 

refueling outages and outages of opportunity between 1986 and 1989 to establish and 

characterize the extent of corrosion of the drywell shell. The initial ultrasonic measurements 

were not based on a sampling process but were taken in areas that correspond to locations 

where water leakage was observed from the sand bed region drains. The ultrasonic

measurements were then expanded around the drywell perimeter and vertically to establish 

locations affected by corrosion. Approximately 1,000 ultrasonic thickness measurements were 

taken to identify the thinnest areas of the drywell shell. In addition, samples of the drywell shell 

were taken at seven locations, believed to be representative of general wastage, to confirm 

ultrasonic results. Based on the results of these inspections, elevations of 3.43 m (11 feet, 

3 inches), 15.29 m (50 feet, 2 inches), and 26.64 m (87 feet, 5 inches) were identified for 

monitoring. The elevation of 3.43 m (11 feet, 3 inches), which corresponds to the sand bed 

region, showed the highest corrosion rate in 1987 (up to 0.993+/-0.086 mm per year 

(39.1+/-3.4 mils per year) based on 1986 and 1987 ultrasonic measurements. The high rate of 

corrosion in the sand bed region prompted removal of the sand as the corrective action. The 

high rate of corrosion in the sand bed region was attributed to galvanic corrosion of the drywell 

shell caused by water retained in the sand because of lack of proper drainage. The results of 

these measurements and subsequent analysis, which considered all design-basis loads and 

load combinations, confirmed that the ―as found‖ condition of the drywell shell thickness satisfies 

ASME Code (Ref. A.5.6.4) Section III minimum thickness requirements.

During the Advisory Committee on Reactor Safeguards meeting on February 1, 2007, a 

commitment was made to perform a three-dimensional (3-D) finite-element analysis of the 

drywell shell prior to entering the period of extended operation (Ref. A.5.6.2). Sandia National 

Laboratories (SNL) developed a detailed 3-D finite-element model of the drywell containment 

vessel using information provided by the NRC and AmerGen. The model was used to evaluate 

the SI of the vessel in terms of the stress limits specified in ASME Code Section III, Division I, 

Subsection NE, and in terms of buckling (stability) limits specified in ASME Code Case N-284. 

The purpose of the SNL analysis was to examine whether the degraded drywell shell could 

withstand the postulated loadings without exceeding the ASME Code (Ref. A.5.6.4) 

requirements for stress and stability. The baseline (i.e., nondegraded) analysis was performed 

to isolate the effects of the degradation. The SNL analysis focused more on the relative 

reduction in design margin due to the corrosion than on the calculated absolute stresses or 

stability limits. The SNL study included stress and buckling analyses for both a representation 

of the containment in its degraded condition and in its original, as-built, condition. The analysis 

confirmed that the ASME allowable stresses are met for all three load cases examined 
A-22

(Ref. A.5.6.2). The SNL analysis was followed by additional analyses prior to the period of 

extended operation, which confirmed the adequacy of the results (Ref. A.5.6.5).

An engineering stress and stability analysis was also conducted that demonstrated compliance 

with ASME Code requirements related to two scenarios: with and without sand. The analyses 

are documented in General Electric (GE) Reports Index Nos. 9-1, 9-2, 9-3, and 9-4 transmitted 

to the NRC staff between December 1990 and in 1991 (Refs. A.5.6.6 to A.5.6.9). Index 

Nos. 9-3 and 9-4 were revised later to correct errors identified during an internal audit and 

resubmitted to the NRC staff in January 1992 (Ref. A.5.6.2). In the NRC staff‘s safety 

evaluation report (SER) dated April 24, 1992, the NRC staff had made an assessment of the GE 

analysis for the load combination incorporating the refueling load and external pressure

(Ref. A.5.6.10). The SER and attached technical evaluation report by Brookhaven National 

Laboratory documented the NRC staff‘s review of the increased capacity reduction factor due to 

the membrane tension and accepted the process of deriving the increased capacity reduction 

factor. The GE analysis assumed a uniform minimum thickness in the sand bed region of 

18.7 mm (0.736 inches). The NRC staff found that the use of the increased capacity reduction 

factor described in the GE analysis was reasonable and consistent with ASME Code 

Case N-284 as well as ASME Code Section VIII, Code Case 2286 (Ref. A.5.6.2).

An additional assessment was performed to address water leakage from cracks in the stainless 

steel reactor cavity liner that were observed in the vicinity of the equipment pool and reactor 

cavity walls, indicating slight corrosion of the reinforcing bar. Based on a representative 

concrete core sample, it was conservatively estimated that the diameter of a typical reinforcing 

rebar in the localized area could be expected to be reduced by 0.051 mm (0.002 inches) per 

year. The walls in question were reinforced with No. 8 and No. 11 rebar. Assuming the 

corrosion continues for the entire 40-year life of the plant, the diameters of the No. 8 and No. 11 

reinforcing bars would be reduced by 8 and 6 percent, respectively. The corrosion was 

localized and the reduced reinforcing bar diameters were judged to have no impact on the 

concrete integrity. Since the corrosion continued to be localized, it was concluded that there 

was no significant impact on the integrity of the reinforced concrete and that the integrity of the 

concrete will be maintained even if the reinforcing bar corrosion continues to the end of the 

period of extended operation. In addition to the assessment, the equipment pool and reactor 

cavity walls were visually inspected and there were no signs of water intrusion or additional

indications of further deterioration. 

A.5.6 References

A.5.6.1 Swenson, C.N., AmerGen Energy Company, LLC, letter to U.S. Nuclear Regulatory 

Commission, July 22, 2005.

A.5.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Oyster Creek Generating Station.‖ NUREG-1875, Volumes 1 

and 2. U.S. Nuclear Regulatory Commission: Washington, DC. April 2007.

A.5.6.3 Gallagher, M.P., AmerGen Energy Company, LLC, letter to U.S. Nuclear Regulatory 

Commission, April 7, 2006.

A.5.6.4 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.
A-23

A.5.6.5 Borchardt, R.W., Executive Director for Operations, U.S. Nuclear Regulatory 

Commission, letter to R. Menendez, United States Senate. November 13, 2009.

A.5.6.6 General Electric Company. GE Report Index No. 9-1, ―An ASME Section VIII 

Evaluation of the Oyster Creek Drywell – Part 1 – Stress Analysis.‖ General Electric 

Company: San Jose, CA. November 1990.

A.5.6.7 — — —. GE Report Index No. 9-2, ―An ASME Section VIII Evaluation of the Oyster 

Creek Drywell – Part 2 – Stability Analysis.‖ General Electric Company: San Jose, 

CA. November 1990.

A.5.6.8 — — —. GE Report Index No. 9-3, ―An ASME Section VIII Evaluation of the Oyster 

Creek Drywell for Without Sand Case – Part 1 – Stress Analysis.‖ General Electric 

Company: San Jose, CA. February 1991.

A.5.6.9 — — —. GE Report Index No. 9-4, ―An ASME Section VIII Evaluation of the Oyster 

Creek Drywell for Without Sand Case – Part 2 – Stability Analysis.‖ General Electric 

Company: San Jose, CA. February 1991.

A.5.6.10 Domerick, A.W., Office of Nuclear Reactor Regulation, U.S Nuclear Regulatory 

Commission, letter to J.J. Barton, Oyster Creek Nuclear Generating Station. 

April 24, 1992.

Figure A.5-1 Drywell and reactor cavity section 

(Source: Gallagher, M.P., AmerGen Energy Company, LLC, letter to U.S. Nuclear 

Regulatory Commission, April 7, 2006.)
A-24

Figure A.5-2 Drywell to reactor cavity seal detail

(Source: Gallagher, M.P., AmerGen Energy Company, LLC, letter to U.S. Nuclear 

Regulatory Commission, April 7, 2006.)
A-25

A.6 Prairie Island Nuclear Generating Plant, Units 1 and 2

A.6.1 Introduction

On April 11, 2008, Nuclear Management Company, LLC, submitted an LRA to the NRC for 

Prairie Island Nuclear Generating Plant, Units 1 and 2 (Ref. A.6.6.1). The results of the NRC 

staff‘s evaluation of the LRA are provided in ―Safety Evaluation Report with Open Items Related 

to the License Renewal of Prairie Island Nuclear Generating Plant Units 1 and 2,‖ issued 

June 2009 (Ref. A.6.6.2) and NUREG-1960, ―Safety Evaluation Report Related to the License 

Renewal of Prairie Island Nuclear Generating Plant Units 1 and 2,‖ issued August 2011

(Ref. A.6.6.3).

A.6.2 Field Observations

Refueling cavity leakage was identified in both Units 1 and 2 (Ref. A.6.6.4). The leakage was 

detected by the ASME Code Section XI, Subsection IWE, program (Ref. A.6.6.5) while it was 

examining the Class MC pressure-retaining vessel (Refs. A.6.6.2 and A.6.6.3). Intermittent 

leakage indications occurred in both units since the late 1980s. The leakage indications 

typically began 2 to 4 days after the refueling cavity was flooded and ended approximately 

3 days after the cavity was drained. A leakage rate of 1.1 to 2.2x10-6 m

3

/s (1 to 2 gallons per 

hour (gph)) has been seen in the emergency core cooling system (ECCS) and regenerative 

heat exchanger room. The leaking fluid was chemically analyzed and determined to be similar 

to refueling water with a boron concentration of 2,700 parts per million (ppm), chloride 

concentration of 7 ppm, sulfate concentration of 0.2 ppm, and pH of 7.8. The increase in pH 

from the refueling cavity water to that found at the leaks was attributed to the acidity being 

neutralized by the carbonates and other minerals in the concrete. Water chemistry results taken 

at the reactor coolant drain tank floor area were similar except that the boron concentration was 

5,329 ppm. This higher level was attributed to residual boron in the area from staining observed 

on the adjacent wall. Other potential sources of leakage, such as the reactor coolant, safety 

injection, and residual heat removal systems, were investigated and no other feasible source of 

leakage was identified. 

During the Unit 1 refueling outage in 1999, leakage was detected at sump B, the sloped wall 

behind the reactor coolant drain tank, the ceiling above the regenerative heat exchangers, the 

reactor coolant pump vault, and the nuclear instrument detector at an elevation of 217.9 m 

(715 feet). Leakage inside the Unit 2 containment was first documented in 1998 during the 

refueling outage, when water was observed entering sump B from cracks in the grout around 

the residual heat removal suction penetration sleeves at an elevation of 211.8 m (694 feet, 

10 inches). This area is grouted from the floor of the sump to the ceiling of the sump back to the 

containment vessel wall. The grout at sump B was removed to inspect the containment vessel 

wall, and no degradation was identified. Containment walkdowns also detected leakage at the 

basement level of containment (an elevation of 212.6 m (697 feet, 6 inches)) outside the north 

wall of the reactor coolant drain tank cubicle. Leakage from the reactor refueling cavity to the 

ECCS sump is postulated to occur as a result of flow under the refueling cavity liner through a 

construction joint between the floor of the transfer pit and through a wall behind the fuel transfer 

tube to the inner wall of the containment vessel, where it travels down and horizontally between 

the containment vessel and concrete to a low point of the containment vessel bottom head and 

then seeps through the grout into the ECCS sump. Leakage into the regenerative heat 

exchanger room is thought to occur from cracks in the concrete ceiling and walls. A potential 
A-26

leakage path and the locations of observed leakage are shown in Figures A.6-1 and A.6-2, 

respectively. 

A.6.3 Design Characteristics of the Reactor Cavity

The auxiliary building is a multilevel, reinforced concrete and steel framed structure built on a 

mat foundation (Ref. A.6.6.1). Safety-related and nonsafety-related structures, systems, and 

components of the auxiliary building include the spent fuel pools and fuel transfer tubes. The 

reactor cavity, refueling cavity, and sump liners are stainless steel components.

A.6.4 Corrective Actions for Refueling Cavity Leakage

Grout was removed in 2002 from around the residual heat removal pipe sleeves in sump B to 

inspect the Unit 1 containment vessel steel. The action was similar to that taken in 1998 during 

the Unit 2 outage. Some discoloration around penetrations C30A and C30B was detected; 

however, no degradation of the penetrations or of the steel containment vessel was observed. 

Absent any degradation, no further action was taken in accordance with ASME Code

Section XI, Subsection IWE.

In a letter dated December 5, 2008 (Ref. A.6.6.4), Northern States Power Company noted that 

the stainless steel reactor cavity liner was tested for faulty welds. Where leaks were found, 

repairs were made for both units. In addition to liner weld leaks, other actual and potential leak 

points were investigated, including the sand plug covers and bolts, neutron detector covers and 

bolts, fuel-lifting device bolts and baseplates, and other liner attachments. Inspections were 

limited to fully or partially accessible areas. 

Sealing methods used to mitigate leakage have only been partially effective (Ref. A.6.6.6). A 

root cause evaluation of a leakage in 2009 indicated embedment plates for the reactor internals 

stands and the rod control cluster assembly change fixture to be the sources. Figure A.6-3 

presents a cross section of the original embedment plate configuration and identifies potential 

leakage paths. Repair of Unit 1 embedment plates for the reactor internals stands and the rod 

control cluster assembly change fixture was a multistep effort. It included (1) removal of existing 

nuts and replacing with blind nuts, (2) seal welding of blind nuts to the baseplate, (3) application 

of a seal weld between the baseplate and the embedment plate, and (4) examination of welds 

by NDE. The repair for the embedment plate configuration is shown in Figure A.6-4. The repair 

eliminated the leakage source with no evidence of leakage in the ECCS sump; however, minor 

leakage (5.0x10-5 m

3

/s (0.5 gph)) has been observed on the ceiling of the regenerative heat 

exchanger room after the refueling cavity had been flooded for 14 days. Vacuum box testing of 

its liner plate seam welds and NDE of the fuel transfer tube welds did not identify any leakage 

sources. Inspections expanded to include NDE of floor embedment fillet welds identified only 

one porosity indication. The rod control cluster assembly guide box wall embedment plates 

were identified as a potential source of leakage in Unit 1, and they were scheduled to be 

repaired during next refueling outage. Repairs for Unit 2 will be addressed with the same 

approach as those performed for Unit 1 (Ref. A.6.6.7).

A.6.5 Structural Integrity Assessment and Test Results

During the Unit 2 outage in 2008, over 150 ultrasonic thickness readings of the containment 

vessel from its exterior surface in the vicinity of the fuel transfer tube and above and behind the 

ECCS sump were obtained. All readings exceeded the two nominal vessel plate thicknesses of 
A-27

38.1 mm (1.5 inches) and 88.9 mm (3.5 inches), respectively. Similar measurements for the 

Unit 1 containment vessel were performed in 2009. The results were the same (Ref. A.6.6.6).

During the refueling outage following embedment plate repairs, concrete will be removed from 

the sump below the reactor vessel to expose the containment vessel. With in situ concrete and 

steel reinforcement exposed, the area will then be inspected (i.e., visual and ultrasonic) and 

evaluated. In addition, concrete will be cored from an area wetted by borated water and tested 

to determine its compressive strength. Furthermore, petrographic examinations will be 

conducted on all removed concrete. A secondary purpose for removal of the concrete is to 

provide access for drainage of accumulated water. During the next two consecutive refueling 

outages following embedment plate repair, areas of each unit previously exhibiting leakage will 

be monitored to confirm that it has not reoccurred. Continued monitoring for leakage and 

degradation will be through periodic examinations of the containment vessels and interior 

surfaces performed in accordance with the ASME Code Section XI, Subsection IWE, program 

and the structures monitoring program (Ref. A.6.6.7). The corrective action program will 

address any new issues.

Assessments have also been made relative to the potential impact of the borated water on the 

reinforced concrete (Ref. A.6.6.8). Additional information is contained in two documents related 

to reactor refueling cavity leakage (Refs. A.6.6.9 and A.6.6.10). The upper-bound estimated 

loss of concrete behind the reactor refueling cavity liner was 7.87 mm (0.31 inches) 

(Ref. A.6.6.9). Because concrete walls are on the order of 1.2- to 1.5-m (4 to 5 feet) thick, the 

anticipated loss of load-carrying capacity would be minor. The impact of the borated water on 

the concrete embedded steel reinforcement was considered to be negligible because the 

construction joints do not have steel reinforcement across them (Ref. A.6.6.7), and the concrete 

cover exceeds the estimated depth of erosion. Figure A.6-5 presents an example of the 

condition of the concrete, steel reinforcement, containment shell, and grout after its removal in 

the Unit 1 ECCS sump in fall 2009. 

The potential impact of concrete erosion on the liner was also evaluated (Ref. A.6.6.11). It was 

noted that the liner is effectively a membrane backed by 1.2- to 1.5-m (4- to 5-foot) thick 

concrete and that large areas of concrete washout are unlikely. However, if washout did occur 

behind the liner, the liner would not be expected to fail due to the ductile nature of stainless 

steel. In addition, visual inspections and vacuum box testing of the liner plate seam welds will 

be performed in the refueling cavity to look for depressions in the liner and for signs of concrete 

washout resulting from the reactor refueling cavity leakage.

An assessment of the containment vessel and concrete structures was performed 

(Ref. A.6.6.12) to determine the minimum wall thickness of potentially corroded areas of the 

containment vessel and the allowable concrete degradation that precludes a challenge to the 

functionality or SI of the containment vessels and internal structures under DBA and DBE

conditions. The results indicated that both the 38.1-mm (1.5-inch) thick containment shell and 

the bottom head could tolerate general corrosion of approximately 12.7 mm (0.5 inch) with no 

significant risk to functionality. The concrete behind the transfer tube was also investigated, as 

it is one of the thinnest sections of concrete inside containment. Accurately determining the 

concrete thickness in this area was not possible using existing drawings, but based on rough 

scaling, the thickness could reach a minimum of about 254 mm (10.0 inches). Review of the 

containment internals structures drawings indicated that no significant loading of this section of 

concrete exists. A large concrete beam located above the transfer tube supports the dead 

weight of concrete above this section. Any loading from concrete above this section would 
A-28

result in compressive stresses only. A design-basis earthquake would result in minimal stress,

as the thin section behind the transfer tube is approximately 3.05 m high by 0.30 m wide 

(10 feet high by I foot wide) and is tied to much heavier sections on four sides. As a result, a 

30-percent margin for the section of concrete around the transfer tube is considered to be a 

conservative estimate consistent with other containment internal structures.

A.6.6 References

A.6.6.1 Wadley, M.D., Nuclear Management Company, LLC, letter to U.S. Nuclear 

Regulatory Commission, April 11, 2008.

A.6.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report with Open Items 

Related to the License Renewal of Prairie Island Nuclear Generating Plant Units 1 

and 2.‖ U.S. Nuclear Regulatory Commission: Washington, DC. June 2009.

A.6.6.3 U.S. Nuclear Regulatory Commission ―Safety Evaluation Report Related to the 

License Renewal of Prairie Island Nuclear Generating Plant Units 1 and 2.‖ NUREG1960. U.S. Nuclear Regulatory Commission: Washington, DC. August 2011. 

A.6.6.4 Wadley, M.D., Northern States Power Company, MN, letter to U.S. Nuclear 

Regulatory Commission, December 5, 2008.

A.6.6.5 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.

A.6.6.6 ―Official Transcript of Proceedings, Advisory Committee on Reactor Safeguards 

Plant License Renewal Subcommittee Prairie Island Nuclear Generating Station.‖

Work Order NRC-2945. Neal R. Gross and Co., Inc., Court Reporters and 

Transcribers: Washington, DC. July 7, 2009.

A.6.6.7 Wadley, M.D., Northern States Power Company, Red Wing, MN, letter to 

U.S. Nuclear Regulatory Commission, April 6, 2009. 

A.6.6.8 Setlur, A.V., Automated Engineering Services Corp., Lisle, IL, letter to L. Polley, 

Northern States Power Company, December 16, 1998.

A.6.6.9 Xcel Energy. ―Refueling Cavity Leakage, Event Date: 1988–2008.‖ Report 

No. RCE 01160372-01, Volumes 1 and 2. Prairie Island Nuclear Generating Station:

Welch, MN. February 3, 2010.

A.6.6.10 Dominion Energy Incorporated. ―Evaluation of Effect of Borated Water Leaks on 

Concrete, Reinforcing Bars, and Carbon Steel Plate of the Containment Vessels at 

Prairie Island Units 1 and 2.‖ Report No. R-4448-00-01, Revision 0. Dominion 

Energy Incorporated: Richmond, VA. March 2009.

A.6.6.11 Wadley, M.D., Northern States Power Company, Welch, MN, letter to U.S. Nuclear 

Regulatory Commission, June 24, 2009. 
A-29

A.6.6.12 Xcel Energy, ―Margin Assessment of Containment Vessels and Interior Concrete 

Structures.‖ Report No. EC 15651. Prairie island Nuclear Generating Plant: Welch, 

MN. February 26, 2010.

Figure A.6-1 Potential leakage paths for refueling cavity water 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee Prairie Island Nuclear Generating 

Station.” Work Order NRC-2945. U.S. Nuclear Regulatory Commission: Washington, 

DC. July 7, 2009)
A-30

Figure A.6-2 Locations of observed leakage of refueling cavity water 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee Prairie Island Nuclear Generating 

Station.” Work Order NRC-2945. U.S. Nuclear Regulatory Commission: Washington, 

DC. July 7, 2009)

Figure A.6-3 Cross section of original embedment plate 

configuration showing potential leakage paths 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee Prairie Island Nuclear Generating 

Station.” Work Order NRC-2945. U.S. Nuclear Regulatory Commission: Washington, 

DC. July 7, 2009)

Leakage Seen in ECCS Sump and 

in Regenerative HX Room (below cavity)
A-31

Figure A.6-4 Cross section of repair approach for embedded plates 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee Prairie Island Nuclear Generating 

Station.” Work Order NRC-2945. U.S. Nuclear Regulatory Commission: Washington, 

DC. July 7, 2009).

Figure A.6-5 Condition of containment shell, grout, and concrete steel reinforcement in 

Unit 1 ECCS after grout removal 

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee Prairie Island Nuclear Generating 

Station.” Work Order NRC-2945. U.S. Nuclear Regulatory Commission: Washington, 

DC. July 7, 2009)

A-33

A.7 Salem Nuclear Generating Station, Units 1 and 2

A.7.1 Introduction

On August 18, 2009, PSEG submitted an LRA to the NRC for Salem Nuclear Generating 

Station (Salem), Units 1 and 2 (Ref. A.7.6.1). The results of the NRC staff‘s evaluation of the 

LRA were published in June 2011 in NUREG-2101, ―Safety Evaluation Report Related to the 

License Renewal of the Salem Nuclear Generating Station‖ (Ref. A.7.6.2).

A.7.2 Field Observations

Leakage of borated water has occurred in Salem Units 1 and 2 reactor cavities during refueling 

outages, but the leaks have been limited to the containment building (Ref. A.7.6.3).

During the 2005 refueling outage, white deposits were observed in several locations of the 

Unit 1 containment. Chemical analyses of the residue indicated the existence of boron and 

concrete constituents, pointing to a reactor cavity or fuel transfer canal borated water leakage. 

Followup walkdowns found evidence of a recent leak (water) in the N16 decay tunnel. Analysis 

of the water indicated that it was consistent with the reactor cavity water, which suggested 

blockage of the six fuel transfer canal telltale drain lines. After cleaning of the telltale lines, four 

of the lines produced leakage of 1 to 60 drops per minute (dpm), but the yield steadily 

decreased to zero during the refueling outage. No active leakage associated with the reactor 

cavity and fuel transfer canal liner was documented during the 2007 or 2008 refueling outages. 

However, during the 2008 refueling outage, another chemical analysis was performed on 

deposits collected from the N16 tunnel. Results again indicated that the collected residue 

originated from either the reactor cavity or the fuel transfer canal. During the 2010 Unit 1 

refueling outage, no active leaks were observed.

For Unit 2, during multiple outages since November 2000, evidence of boric acid deposits was 

found on the containment liner under the fuel transfer canal. In November 2003, liquid was 

observed running down the containment liner plate and lagging under the fuel transfer canal and 

inside the containment, pooling eventually on the concrete floor. No evidence of corrosion was 

observed between the containment liner and the floor joint. A year and a half later, in April 2005 

during a refueling outage, water was observed dripping down the wall on the Unit 2 containment 

liner plate. With two of the six telltales dripping and with white deposits observed in several 

locations on the letdown heat exchanger room walls, an inquiry was initiated. The investigation 

showed that there was no blockage in the two dripping telltales and that the reactor cavity was 

the contributor to the residue. During the 2006 refueling outage, a small amount of leakage was 

observed coming from a telltale in the letdown heat exchanger room. In the next refueling 

outage of Unit 2 in 2008, no active leakage was observed. However, during the 2009 Unit 2 

refueling outage, a 60-dpm active leak was found from the telltale located above the door to the 

letdown heat exchanger room. Analysis of a sample of the water indicated that it was consistent 

with reactor cavity water.

A.7.3 Design Characteristics of the Refueling Cavity

The containment structure for Salem Generating Station, Units 1 and 2 includes the 

containment buildings and the containment internal structures. The containment buildings are 

reinforced concrete containments with a cylindrical wall, a foundation mat, and a hemispherical 
A-34

dome roof. Internal reinforced concrete components include the reactor cavity and primary 

shield walls, the fuel transfer canal, the secondary shield wall (polar crane wall), and the floor 

slab. The floor slab contains a shallow outer and inner trench designed to collect floor drainage 

and direct it to the containment building sumps. The containment building sumps and the 

trenches are lined with stainless steel plates and covered with stainless steel grating or 

perforated stainless steel plates to prevent debris from entering the sumps.

The reactor cavity is a reinforced concrete structure that houses the reactor and provides the 

primary shielding barrier. Internal surfaces of the cavity are lined with 6.35-mm (0.25-inch) thick 

stainless steel plate. The reactor cavity is filled with borated water during refueling to permit 

transfer of fuel elements underwater between the reactor and the spent fuel pool. The refueling 

floor slab is a 0.91- to 1.52-m (3- to 5-foot) thick reinforced concrete component. The slab 

covers the RCS compartments and provides access to the reactor cavity, the fuel transfer canal, 

the polar gantry crane, and other components supported on the floor. The floor slab design 

includes hatches with removable shield plugs to allow crane access to the reactor coolant 

pumps for maintenance.

A.7.4 Corrective Actions for Refueling Cavity Leakage

Chemical analyses of leakage collected during multiple refueling outages at both Units 1 and 2 

identified the source of the leakage as the reactor cavity or the fuel transfer canal (Ref. A.7.6.4). 

Assessments for Units 1 and 2 have concluded that the potential cause of leakage is very small 

cracks in the reactor cavity liner or in the fuel transfer canal liner. The majority of the leakage 

enters the leak collection chases and drains through the telltales. Some of the telltales in the 

letdown heat exchanger room associated with the fuel transfer canal liner were observed to 

have active leaks during refueling outages. A second leakage path occurs in the vicinity of 

where the fuel transfer canal exits containment. The origin of the leakage is indicated as from 

the reactor cavity and fuel transfer canal liner, through the concrete construction joints and 

cracks, followed by percolation down the sides of the containment liner behind the lagging 

inside the containment.

The leakage only occurs when the reactor cavity and fuel transfer canal are flooded up for 

refueling. Active leaks have been observed sporadically only during refueling outages, with 

measured leakage rates less than 100 dpm. Based on the short duration of the refueling 

activities and the very long exposures needed to degrade reinforced concrete, it was concluded 

that remedial actions were not needed; however, the structures monitoring program and the 

ASME Code (Ref. A.7.6.5) Section Xl, Section IWE, program will be used to ensure the 

continued integrity of the in-scope structures. 

The structures monitoring program was enhanced to perform periodic inspection of the telltales 

associated with the reactor cavity and fuel transfer canal liner to ensure that they are free of 

significant blockage. When adequate leakage is collected, an analysis will be performed to 

determine its pH. A commitment was also made to perform augmented inspections under the 

fuel transfer canal where the containment liner is subjected to leakage. These inspections will 

be performed once per containment inservice inspection period as long as leakage is observed.

A.7.5 Structural Integrity Assessment and Test Results

An assessment of the long-term structural adequacy of the Salem Unit 1 fuel-handling building 

(FHB) reinforced concrete structure under potential prolonged exposure of the concrete and 
A-35

reinforcing steel to borated water has been conducted (Ref. A.7.6.4). The assessment made 

the following conclusions: 

• The predicted depth of concrete degradation after 70 years of continuous exposure to 

borated water is 33 mm (1.3 inches).

• The degradation rate of the concrete at the concrete steel reinforcement interface is 

similar to the general rate of attack of concrete without rebar. Therefore, degradation of 

rebar at the construction joints or cracks will not spread rapidly along the rebar to impact 

its bond to concrete.

PSEG concluded that the findings for the FHB are directly applicable to the Unit 1 and 2 reactor 

cavity and fuel transfer canal reinforced concrete structures. The reactor cavity and fuel transfer 

canal are only filled with borated water during refueling outages, which occurs at each unit 

approximately 1 month out of every 18 months (about 5 percent of the operating cycle), since 

the Salem units perform refueling outages every 18 months. By contrast, the Unit 1 FHB 

assessment assumed continuous borated water exposure for 70 years, with a resulting depth of 

degradation of 33.0 mm (1.3 inches). Due to the shorter exposure period for the reactor cavity 

and fuel transfer canal concrete, the expected depth of concrete degradation will be 

substantially less; i.e., 7.4 mm (0.29 inches). Therefore, degradation of the reinforcing steel in 

the reactor cavity and fuel transfer canal reinforced concrete structure would be insignificant.

A.7.5.1 Structural Capacity

Based on experimental test results, it was concluded that degradation of the reactor cavity and 

fuel transfer canal reinforced concrete due to borated water leakage would be insignificant and,

therefore, would have no impact on the intended function of these structures (Ref. A.7.6.4). No 

degradation has been detected during past inspections, and a concrete core will be taken from 

the spent fuel pool at a known leakage location to verify that no degradation has occurred. 

A.7.6 References

A.7.6.1 Fricker, C.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

August 18, 2009.

A.7.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Salem Nuclear Generating Station.‖ NUREG-2101.

U.S. Nuclear Regulatory Commission: Washington, DC. June 2011.

A.7.6.3 Joyce, T.P., PSEG Nuclear, LLC, letter to J. White, U.S. Nuclear Regulatory 

Commission, March 30, 2007.

A.7.6.4 Davison, P.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

May 13, 2010.

A.7.6.5 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.
A-36
B- 1

APPENDIX B: SPENT FUEL POOL LEAKAGE CASE STUDIES

B.1 Crystal River Nuclear Generating Plant, Unit 3

B.1.1 Introduction

By letter dated December 16, 2008, Florida Power Corporation submitted a license renewal 

application (LRA) to the U.S. Nuclear Regulatory Commission (NRC) for its Crystal River

Nuclear Generating Plant, Unit 3 (Ref. B.1.6.1). In December 2010, the NRC issued a safety 

evaluation report (SER) with open items (Ref. B.1.6.2).

B.1.2 Field Observations

A baseline inspection of structures within the scope of the Maintenance Rule (Ref. B.1.6.3) was 

completed in 1997, and a hairline crack on the concrete wall of the spent fuel pool (SFP) was

noted (Ref. B.1.6.1). A subsequent inspection of structures was completed in 2007 consistent 

with the program frequency of not exceeding 10 years. The hairline crack was reinspected and 

found to be dry and stable (i.e., not having increased in size since the last inspection). 

In 2009, prior to a scheduled June walkdown, maintenance activities were completed to assure 

that the leak chase outlets were clean and not plugged. Operating experience logs in October 

of that year noted some of the leak chase lines as having boron accumulation at the outlet with 

ongoing leakage of less than 1 drop per minute, but none were plugged (Ref. B.1.6.4). 

Operating experience for SFP leakage indicated that the leakage was minimal at the lower end 

of the SFP ―normal‖ water level range, but the leakage increased when the level was raised to 

the upper end of the ―normal‖ range. Based on this experience, the SFP level is maintained at a 

low level to minimize liner leakage.

B.1.3 Design Characteristics of the Spent Fuel Pool

The auxiliary building is a reinforced concrete structure from an elevation of 29 meters (m)

(95 feet) (an elevation of 18.6 m (61 feet) in the seawater inlet pits) to an elevation of 49.4 m 

(162 feet), with a sheet metal enclosed structural steel superstructure from an elevation of

49.4 m (162 feet) to an elevation of 63.7 m (209 feet). The auxiliary building partially surrounds 

the reactor building and contains the new fuel racks and two SFPs (Spent Fuel Pools A and B), 

as well as various safety-related equipment and components. 

B.1.4 Corrective Actions for Spent Fuel Pool Liner Leakage

Preventative maintenance is periodically conducted (i.e., snake runs) to verify that each of the 

19 leak chases is clear. Sampled deposits are analyzed for products of concrete degradation.

B.1.5 Structural Integrity Assessment and Test Results

The hairline crack in the SFP south wall will be inspected and monitored at a yearly interval.
B- 2

B.1.6 References

B.1.6.1 Young, D.E., Progress Energy, letter to U.S. Nuclear Regulatory Commission, 

December 16, 2008.

B.1.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report with Open Items 

Related to the License Renewal of Crystal River Unit 3 Nuclear Generating Plant.‖ 

U.S. Nuclear Regulatory Commission: Washington, DC. December 2010.

B.1.6.3 — — —. ―Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.‖

RG 1.160, Revision 2. U.S. Nuclear Regulatory Commission: Washington, DC. 

March 1997.

B.1.6.4 Franke, J.A., Progress Energy, letter to U.S. Nuclear Regulatory Commission, 

October 13, 2009.
B- 3

B.2 Davis-Besse Nuclear Power Station, Unit 1

B.2.1 Introduction

On August 27, 2010, First Energy Nuclear Operating Company submitted an LRA to the NRC 

for its Davis-Besse Nuclear Power Station, Unit 1 (Ref. B.2.6.1).

B.2.2 Field Observations

During Cycle 13 reracking of the SFP, underwater divers used a vacuum box on the weld 

seams in the SFP to determine if there were any detectable leaks; none could be located. At 

that time, there was visible evidence of leakage in emergency core cooling system (ECCS)

Pump Room No. 1, but little leakage was being seen in the leak chases. In February 2001, 

additional action was taken to open and verify that the 21 leak chase valves and piping were

open. Six of the chases were found to be totally blocked. Upon clearing of their blockage, a 

significant amount of trapped fluid was drained. Leak chase channels exhibiting the largest 

drainage are kept constantly open, with the rest closed to reduce the likelihood of the boric acid 

solidifying and blocking the valves and piping. 

One of the leak chase drains has consistently shown small amounts of leakage during the 

monthly test, as documented in the third quarter of the 2008 health report. Two other leak 

chase drains showed occasional leakage, but the leakage was small and the fluid was captured 

by the leak collection system. The corrective action program documented 140 milliliters (mL) of 

leakage collected during July 2008 for one zone valve. The leakage rate was calculated as 

2.8 milliliters per minute (mL/min), which was higher than the trend data average of 1.0 mL/min 

over the previous 12 months. Based on a review of the trend data collected since 1999, 

occasional spikes in flow rate have occurred. The corrective action program item was 

designated for tracking and trending of a condition that occurs periodically in the plant. During 

the third quarter of 2008, the boron concentration appeared erratic in one sample, and the 

condition was documented in the corrective action program. Because the leak collection boron 

concentration is an information-only test, this condition was documented for trending purposes.

B.2.3 Design Characteristics of the Spent Fuel Pool

The auxiliary building includes the SFP, fuel transfer pit (also known as the transfer pit or fuel 

transfer tube pit), and cask pit walls and floors that are lined with 6.35-millimeter (mm)

(0.25-inch) thick stainless steel liner plate. A watertight bulkhead gate separates the SFP from 

the fuel transfer pit and another separates it from the cask pit. Struts are installed on the walls 

between the fuel transfer pit and the SFP when the fuel transfer pit water level is below the 

bottom of the SFP bulkhead gate. The struts prevent the wall from becoming overstressed 

during a seismic event. 

B.2.4 Corrective Actions for Spent Fuel Pool Liner Leakage

The leak chase monitoring program includes periodic monitoring (monthly) of the SFP, the fuel 

transfer pit, and the cask pit liners leak chase system. This routine task requires recording of 

the leakage amount collected, and the calculated leak rate. It also includes activities to cycle 

(i.e., open and close) the SFP, the fuel transfer pit, and the cask pit liner drain valves on a 

monthly basis. Each valve on the drain line capable of being cycled is opened to allow any
B- 4

water that has accumulated in the lines to drain into an open funnel. After a prescribed wait 

time, leakage is collected. The amount collected and the calculated leak rate are recorded for 

each of the 21 drain zones. If leakage collected from any zone drain valve is greater than 

10 mL, then the sample is appropriately labeled and transported to a laboratory for boron 

analysis. Leak chase channel results are reviewed by the SFP system engineer. Collected 

leakage information and boron analysis results are recorded in the work order system. 

Monitoring of leakage from the leak chase system permits early determination and localization 

of any leakage. 

For the period of extended operation, the site-specific program will be enhanced. In addition to 

previous monitoring for boron, samples having leakage rates of 15 mL/min will be documented 

in a condition report and evaluated for possible increases in monitoring frequency and other 

corrective actions. Furthermore, collected leakage will be analyzed monthly for its pH and 

semiannually for its iron content. The results will be monitored and trended to insure that there 

is no corrosion of the reinforcing bars in the walls or floors of the pool and pits. Furthermore, 

the enhanced program will annually inspect accessible outside walls and the floor (from the 

ceiling side) of the pool and pits, documenting indications of migrating leakage in the corrective 

action program. Furthermore, in 2014 and 2020, and as necessary thereafter for effective 

monitoring of steel reinforcement through the structures monitoring program, core bores of the 

affected areas will be collected for testing and evaluation of concrete strength, followed by 

visual inspections of the reinforcement and analysis of corrosion products. Degradations will be 

recorded in the corrective action program and evaluated to determine if any repairs are needed 

so that the SFP will continue to perform its intended functions during the period of extended 

operation. The core bore evaluations will also determine whether or not the SFP leakage has 

affected the concrete and reinforcing steel in a manner that is not bounded by the industry and 

Davis-Besse current operating experience (Refs. B.2.6.2 and B.2.6.3).

B.2.5 Structural Integrity Assessment and Test Results

Leakage outside the leak chase drains has been seen in several places over the years. The 

most extensive visible evidence of leakage was on the wall and ceiling of ECCS pump room 

No. 1 during the period from 2000 to 2001. This leakage has stopped and the area has been 

cleaned. Based on evaluations associated with this leak, there are no concerns regarding the 

strength or integrity of the concrete structure associated with these leaks.

B.2.6 References

B.2.6.1 Allen, B.S., FirstEnergy Operating Company, letter to U.S. Nuclear Regulatory 

Commission, August 27, 2010.

B.2.6.2 Byrd, K.W., First Energy Operating Company, letter to U.S. Nuclear Regulatory 

Commission, May 24, 2011.

B.2.6.3 Byrd, K.W., First Energy Operating Company, letter to U.S. Nuclear Regulatory 

Commission, August 17, 2011.
B- 5

B.3 Diablo Canyon Power Plant, Units 1 and 2

B.3.1 Introduction

On November 23, 2009, Pacific Gas and Electric Company submitted an LRA to the NRC for 

the Diablo Canyon Power Plant, Units 1 and 2 (Ref. B.3.6.1). The SER (with open items) that 

documents the NRC staff‘s technical review of the LRA was published in January 2011 

(Ref. B.3.6.2). 

B.3.2 Field Observations

The Unit 1 SFP has occasional minor leakage primarily during refueling outages, and the Unit 2 

SFP has persistent minor leakage that varies from 50 to 975 mL per week, with a slight increase 

in leakage rate during outages (Refs. B.3.6.3 and B.3.6.4), which is attributed to outage 

activities such as fuel handling, cask movements, and increases in water level (Ref. B.3.6.5). 

Based on the frequency and volume of leakage, samples are analyzed for tritium, gamma 

isotropic, pH, iron, and boron. With small quantities of leakage, there is not always sufficient 

volume to perform all of the analyses. When this occurs, the tests are performed based on the 

stated order. The results indicate that all concentrations are below health hazards or structural 

hazard levels, with concentrations below those recorded in the SFP. 

B.3.3 Design Characteristics of the Spent Fuel Pool

The leak chases are located behind all liner joints (seam welds) for capturing water that 

potentially leaks through the liner and/or liner seams or plug welds (Ref. B.3.6.3). Any leakage 

through the liner is collected in the leak chases and is routed via gravity to a leakage monitoring 

station that has six collection points with isolation valves. 

B.3.4 Corrective Actions for Spent Fuel Pool Liner Leakage

Video inspections of the Unit 1 and Unit 2 leak chase channels were conducted in 2008. No 

liner repairs have been performed on Unit 1 over the life of the plant. Followup video 

inspections were done on two of the leak chase channels for Unit 2 that were experiencing 

chronic minor leakage. The leak chases were reinspected in 2010. SFP liner leakage 

monitoring began in 1988, and the liner leak chases for both units are sampled and evaluated 

on a weekly basis (Ref. B.3.6.3). 

B.3.5 Structural Integrity Assessment and Test Results

Evaluations to date are unable to conclusively identify the root cause of the leakage, and the 

structures potentially affected by the presence of borated water are the SFP concrete and 

structural steel (Ref. B.3.6.3). Previous engineering investigations concluded that the long-term 

leakage is acceptable and will have negligible effects on the concrete and reinforcing steel 

because the boric acid would result in slight surface scaling of the concrete having no cracks. 

The concrete in this state will protect the reinforcing steel from coming into contact with the boric 

acid.
B- 6

B.3.6 References

B.3.6.1 Becker, J.R., Pacific Gas and Electric Company, letter to U.S. Nuclear Regulatory 

Commission, November 23, 2009.

B.3.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report with Open Items 

Related to the License Renewal of Diablo Canyon Nuclear Power Plant, Units 1 

and 2.‖ U.S. Nuclear Regulatory Commission: Washington, DC. January 2011.

B.3.6.3 Becker, J.R., Pacific Gas and Electric Company, letter to U.S. Nuclear Regulatory 

Commission, July 19, 2010.

B.3.6.4 Ferrer, N., U.S. Nuclear Regulatroy Commission, letter to J. Conway, Pacific Gas 

and Electric Company, June 21, 2010.

B.3.6.5 Becker, J.R., Pacific Gas and Electric Company, letter to U.S. Nuclear Regulatory 

Commission, September 30, 2010.
B- 7

B.4 Duane Arnold Energy Center

B.4.1 Introduction

By letter dated September 30, 2008 (Ref. B.4.6.1), and supplemented by a letter dated 

January 23, 2009 (Ref. B.4.6.2), FPL Energy, Duane Arnold Energy Center, submitted an LRA 

to the NRC for the Duane Arnold Energy Center. The results of the NRC staff‘s evaluation of 

the LRA were published in November 2010 in NUREG-1955, ―Safety Evaluation Report Related 

to the License Renewal of Duane Arnold Energy Center‖ (Ref. B.4.6.3).

B.4.2 Field Observations

The SFP at the Duane Arnold Energy Center has been leaking since at least 1994, and the 

leakage has been contained within the fuel pool liner drain system. No moisture or leakage has 

been found due to refueling bellows or fuel pool leakage. Inspections of the sand pocket drain 

lines have indicated that no moisture or leakage is present in the sand pocket area; however, in 

August 1985, moisture was detected in the inaccessible area on the exterior of the drywell shell 

in the torus room near downcomer/vent line penetration X-05C. The leakage rate was 

estimated at approximately 1.1x10-6cubic meters per second (m

3

/s) (1 gallon per hour). 

Chemical analysis was conducted, but it was not sufficient to confirm or disprove that the source 

of the leakage was the SFP; however, no other source was plausible (Refs. B.4.6.4

and B.4.6.5). It has been noted that walkdowns had been completed in accessible areas under 

the pool and no leaks were discovered. 

B.4.3 Design Characteristics of the Spent Fuel Pool

The reactor building encloses the reactor, primary containment new and spent fuel storage 

pools, and other auxiliary systems associated with the nuclear steam supply system. The 

reactor building provides secondary containment for the reactor when in service and primary 

containment for the auxiliary systems and the reactor during periods when the primary 

containment is opened for refueling and servicing. Leakage from the SFP is channeled into one 

or more drainpipe lines to monitor leakage, and the drains are routed to the reactor building floor 

drain sump through a common trough. 

B.4.4 Corrective Actions for Spent Fuel Pool Liner Leakage

In May 1990, a pinhole leak near the toe of a control rod drive line fillet weld to the drywell shell 

was found to be the source of moisture detected in the inaccessible area on the exterior of the 

drywell shell. Subsequent investigations found flaws in the southwest control rod drive 

penetration bundle. Ultrasonic testing (UT) of the drywell shell in the affected area did not 

indicate any loss of thickness due to corrosion. In addition, no leakage was identified at the 

other three control rod drive penetration bundles. Repairs were satisfactorily made to the 

southwest control rod drive bundle in 1990. Since 1990, no recurrence of control rod driveline 

leakage has been experienced or identified.

B.4.5 Structural Integrity Assessment and Test Results

No structural assessment has been reported.
B- 8

B.4.6 References

B.4.6.1 Anderson, R.L., FPL Energy-Duane Arnold Energy Center, letter to U.S. Nuclear 

Regulatory Commission, September 30, 2008.

B.4.6.2 Anderson, R.L., FPL Energy-Duane Arnold Energy Center, letter to U.S. Nuclear 

Regulatory Commission, January 23, 2009.

B.4.6.3 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Duane Arnold Energy Center.‖ NUREG-1955. U.S. Nuclear 

Regulatory Commission: Washington, DC. November 2010.

B.4.6.4 Harris, B.K., U.S. Nuclear Regulatory Commission, letter to C. Costanzo, Florida 

Power & Light Company, September 14, 2009.

B.4.6.5 Costanzo, C.R., NextEra Energy Duane Arnold, LLC, letter to U.S. Nuclear 

Regulatory Commission, October 13, 2009.
B- 9

B.5 Hope Creek Generating Station, Unit 1

B.5.1 Introduction

On August 18, 2009, PSEG Nuclear, LLC (PSEG), submitted an LRA to the NRC for renewal of 

the Hope Creek Generating Station (Ref. B.5.6.1). The results of the NRC staff‘s evaluation of 

the LRA were published in June 2011 in NUREG-2102, ―Safety Evaluation Report Related to 

the License Renewal of Hope Creek Generating Station‖ (Ref. B.5.6.2).

B.5.2 Field Observations

Minimal leakage has been detected when the pool level is increased above the normal level 

and, based on subsequent inspections of the area around the pool, all of the leakage is 

contained within the SFP drain system. 

B.5.3 Design Characteristics of the Spent Fuel Pool

The reactor building includes the spent fuel storage pool liner, cask loading pit liner, reactor 

cavity liner, steam dryer/moisture separator storage pool liner, and spent fuel storage pool 

skimmer surge tank liner. The fuel pool liner drains are connected to the area under the fuel 

pool liner for leak detection.

B.5.4 Corrective Actions for Spent Fuel Pool Liner Leakage

No corrective actions have been reported.

B.5.5 Structural Integrity Assessment and Test Results

The SFP liner plate leak chase system has not been included within the scope of license 

renewal because leak collection channels are not safety-related and are not part of the waterretaining boundary, nor are they required to maintain the structural integrity of the SFP walls 

(Refs. B.5.6.3 and B.5.6.4). The leak chase system is not relied upon in safety analyses or 

plant evaluations to perform a safety function. Therefore, the SFP liner plate leak chase system 

and its components do not have a license renewal intended function.

B.5.6 References

B.5.6.1 Fricker, C.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

August 18, 2009.

B.5.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Hope Creek Generating Station.‖ NUREG-2102. U.S. Nuclear 

Regulatory Commission: Washington, DC. June 2011.

B.5.6.3 Ashley, D.J., U.S. Nuclear Regulatory Commission, letter to T. Joyce, PSEG 

Nuclear, LLC, March 31, 2010.
B-10

B.5.6.4 Davison, P.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

April 22, 2010.
B-11

B.6 Indian Point Nuclear Generating Unit 2

B.6.1 Introduction

By letter dated April 23, 2007 (Ref. B.6.6.1), and as supplemented by letters dated May 3 

(Ref. B.6.6.2) and June 21, 2007 (Ref. B.6.6.3), Entergy Nuclear Operations, Inc., submitted an

LRA to the NRC for Indian Point Nuclear Generating (Indian Point) Units 2 and 3. The results of 

the NRC staff‘s evaluation of the LRA were published in November 2009 in NUREG-1930,

―Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating 

Unit Nos. 2 and 3‖ (Ref. B.6.6.4).

B.6.2 Field Observations

During a 1990 pool reracking project at Unit 2, a small hole occurred in the northeast area of the 

SFP stainless steel liner at about the 27.1-m (89-foot) level. The damage was discovered in 

1992 when boron powder was found on the SFP east exterior concrete wall. Leakage through 

the hole in the pool liner was estimated at 8.6 to 12.9x10-7 m

3

/s (20 to 30 gallons per day (gpd)),

which was unnoticed due to the much larger volume of normal evaporative loss from the pool 

(Ref. B.6.6.5).

On August 22, 2005, additional leakage was identified during the excavation of the fuel-handling 

building (FHB) adjacent to the SFP south wall to install a higher capacity gantry crane, needed 

to load and transport fuel casks in support of the independent spent fuel storage installation 

project (Ref. B.6.6.6). Workers had identified cracks in the wall of the Unit 2 SFP and observed 

a small amount of moisture in a 0.16-mm wide by 2.13-m long (0.0156-inch wide and 7-foot 

long) crack on the south wall at an approximate elevation of 19.8 m (65 feet). Moreover, ground

water contamination was detected in onsite monitoring wells.

During the next 2 weeks, as excavation continued, a second crack was discovered at the 

18.3-m (60-foot) elevation and a temporary collection device was installed to capture leaking 

liquid. The cracks were visually inspected by a civil-structural engineer and the Supervisor of 

Civil-Mechanical Engineering. The condition of the cracks was characterized as typical of 

shrinkage cracking witnessed during postconstruction concrete curing. The crack weeping 

gradually increased following the first measurable liquid sample of 12 mL collected in 

September 2005. Radiological analysis of this water sample confirmed tritium and boron 

content consistent with the Unit 2 SFP. The analysis also revealed that the moisture contained 

trace amounts of cesium-134 and -137, cobalt-60, and boron. The boron concentration was 

about 6 to 15 times less than the concentration in the SFP, and the cesium-134 to -137 

concentration indicated that the activity was about 6 to 10 years old. The crack had calcium 

stains emanating from it, as is expected when moisture leaches through concrete, and there 

was no visual evidence of steel corrosion products (rust). Due to the thickness of the SFP wall, 

the amount of steel reinforcement, and the lack of evidence that the small amounts of moisture 

and boron have caused corrosion of the reinforcing bars, it was concluded that there was

reasonable assurance that the SFP wall was structurally sound and capable of performing its 

intended function (Ref. B.6.6.5). During the next several weeks, the cracks exhibited increased 

leakage to a maximum of between 1 and 2 liters per day. This rate of leakage remained stable 

and then declined to a minimal amount by late December 2005 (Ref. B.6.6.7). Based on an 

analysis, it was determined that the seepage from the crack was consistent with SFP water 

(Ref. B.6.6.7).
B-12

On September 20, 2005, the NRC initiated a special inspection team in accordance with a 

special inspection charter, to investigate the structural and radiological implications of the 

observed Unit 2 SFP leakage and assess the licensee‘s corrective measures, radiological 

evaluation, and investigative actions (Refs. B.6.6.8 and B.6.6.9). The NRC reviewed the 

conditions on site and concluded that there were no near-term safety issues. Specifically, an 

NRC structural specialist and a health physics inspector were sent to the Indian Point facility to 

assist the resident inspectors in monitoring the progress of the investigation. In early 

October 2005, the NRC established Web pages for information on SFP issues at Indian Point 

(Ref. B.6.6.10).

In January 2008, the sources of ground water contamination were noted to be the Unit 1 and 2 

SFPs (Ref. B.6.6.11). While both pools contributed to the tritium contamination of ground water, 

the leaks from the Unit 1 SFP were determined to be the source of other contaminants, such as 

strontium-90, cesium-137, and nickel-63.

B.6.3 Design Characteristics of the Spent Fuel Pool

The SFP wall at Unit 2 consists of thick concrete that is heavily reinforced with its inside surface 

lined with 6.35-mm (0.25-inch) thick stainless steel plates that are anchored to the concrete 

such that there is only a small interstitial space or air gap between the liner and the concrete 

(Ref. B.6.6.12). Unit 2 was designed and licensed without an SFP liner leak collection system. 

The design provisions for the Unit 2 SFP include pool-level instrumentation with alarms in the 

control room and 9.5x10-3 m

3

/s (150 gallons per minute) water makeup capacity in the event of 

a design-basis accident (Ref. B.6.6.12). 

B.6.4 Corrective Actions for Spent Fuel Pool Liner Leakage

All fuel from the Unit 1 SFP was removed to an onsite dry storage location and the Unit 1 SFP 

was drained, thereby essentially eliminating the source of the ground water contamination from 

Unit 1 (Ref. B.6.6.8).

A one-time inspection of the accessible areas of the Unit 2 SFP was conducted beginning in 

2006 (Ref. B.6.6.13). Approximately 40 percent of the liner was accessible for inspection. 

Inspection techniques included use of robotic cameras, general visual, and vacuum box testing. 

Vacuum box testing was used on areas of the liner that were deemed compromised 

(e.g., exhibited indications) based on the general visual and robotic camera inspections. None 

of the suspect areas in the SFP area failed the vacuum box test, indicating that none of the 

indications found were actually leaking (Ref. B.6.6.12). Identified indications were coated as a 

precautionary measure. Essentially 100 percent of the SFP transfer canal liner was inspected 

using the same techniques as used in the SFP, with the addition of UT where applicable. The 

inspections discovered several indications and one weld defect in the transfer canal liner. The 

weld defect failed the vacuum box test. The defect and the indications were repaired. The 

evaluation concluded that the defect and indications were the result of poor construction 

practices and workmanship during the initial construction activities. The combined inspections 

of the SFP and the SFP transfer canal were completed in 2007.

The method to be used to determine if a degraded condition exists for leakage during the period 

of extended operation is to continuously monitor the SFP water level and the chemistry of the 

ground water in the vicinity of the pool exterior walls (Refs. B.6.6.14 and B.6.6.15). The 

absence of leakage will affirm that no degraded conditions exist. If leakage is found, it will be 
B-13

evaluated under the corrective action program. If sampling indicates that ground water contains 

constituents associated with the SFP leakage, then an evaluation is required under the 

corrective action program to assess the potential for degradation and to determine appropriate 

corrective actions, including inspections of all accessible surfaces of the SFP liner, installation of 

monitoring wells in the vicinity, performance of UT examinations, concrete core bore sampling, 

rebar inspections, and inspections necessitating the use of remote camera technology.

B.6.5 Structural Integrity Assessment and Test Results

Actions were taken to determine the source of moisture and potential amount and extent of 

related soil contamination. Implementation of these actions began in September 2005 and led 

to the establishment of a remediation and repair plan and schedule (Ref. B.6.6.5). Specifically, 

the licensee is to do the following:

• Determine rebar location in relation to cracks using a rebar detection device.

• Hand-drill using a small-diameter bit several centimeters (inches) into the SFP wall in the 

area of the moist crack and analyze drill-bit fines for contamination. The task was 

completed in 2005 and showed that the collected fines appeared to be damp in the first 

several inches of depth and then appeared to be dry.

• Place a plastic covering over the moist cracks to attempt to capture a sufficient volume 

of liquid for radiochemistry analysis. The task was completed in 2005 and yielded a 

12-mL sample that contained low levels of cesium-137 and cobalt-60, 1,265 parts per 

million (ppm) boron, and approximately 0.02 microcurie/mL tritium. These results are 

indicative of moisture originating from the pool.

• Sample and analyze the soil beneath the area of the crack for tritium. The task was

completed in 2005 and indicated low levels of tritium near (within 0.3 m (12 inches)) the 

wall, but the levels decreased at 0.6 to 0.9 m (2 to 3 feet) away from the wall to nearly an 

undetectable level.

• Scrape material from an unaffected area of the SFP wall and test for boron content. For 

this effort, dry fines from drilling were used. The analysis indicated low levels of boron 

(less than 400 ppm).

• Determine the typical level of boron in clean concrete. Although this effort was 

undertaken, there is no information available.

• Determine the expected corrosion rates for steel reinforcing rods subjected to an 

environment containing boron.

• Gather historical documentation of SFP stainless steel liner damage and SFP sump 

overflows. Some liner damage information has been recovered, including 

Calculation CGX-00006 (structural evaluation of the Unit 2 fuel pool wall) (Ref. B.6.6.16) 

and Technical Report ME-3802 (Ref. B.6.6.17) (evaluation of SFP walls for Indian Point 

Unit 2). These are considered bounding for the current situation in terms of wall and 

rebar structural integrity. To date, no records on sump overflows have been recovered. 

Only tribal knowledge has been collected.
B-14

• Identify through a ground-penetrating radar inspection (to the extent possible) any crack 

depths. Ground-penetrating radar was determined to not be feasible for this task. The 

task was completed in 2005 by taking two 101.6-mm (4-inch) diameter cores in the area 

of the moist crack. One appeared to be dry, and it was presumed that this was affected 

by boring bit heating. Twenty-four hours later, however, the core was damp. The rebar 

exhibited normal surface oxidation. Visual inspections over 3 days indicate a reduction 

in moisture.

• Gather the radiological results of test core borings performed for dry cask storage inside 

fuel storage building loading bay (4), including its access road. The task, completed in 

2003, indicated the existence of low-level cesium-134, cesium-137, cobalt-58, and 

cobalt-60 surface contamination. 

• Bring in an expert structural engineer from ABS Consulting with past experience in SFP 

leakage. The deliverables for this task, completed in 2005, were calculations of the 

seepage rate.

• Contact James A. FitzPatrick Nuclear Power Plant to obtain recent operating experience 

of its leaking SFP liner. The task was completed in 2005 through a conference call. No 

additional actions were suggested; however, Indian Point found out that 

James A. FitzPatrick Nuclear Power Plant had an active pool liner leak earlier in the 

year. The leakage appeared to cease on its own, indicative of a potential pinhole 

forming and subsequently clogging, or the leak path (e.g., crack in concrete) closing in 

some manner.

• Inspect other accessible exterior areas of the SFP walls for residues/white material. 

Other accessible areas in addition to the south wall include the west wall and the east 

wall outside where the 1990–1992 leak was discovered. The east wall has no evidence 

of a problem subsequent to the 1990–1992 leak discoveries. The west wall in the pipe 

pen has some cracking and dry white streaking with no evidence of moisture. A 

sampling of the white material was to be completed by 2005. The west wall has some 

shrinkage cracking, but there is no evidence of moisture.

Underwater camera inspections of portions of the Unit 2 SFP were initiated on

October 27, 2005. Three areas appearing as potential flaws in the liner were identified in the 

southwest corner of the pool. By December 2005, visual examination and videotaping of about 

50 percent of the SFP liner surface was completed in an effort to identify locations of potential 

leakage. This represents all of the surfaces that can be accessed with the currently available 

video camera equipment because stored spent fuel in portions of the pool prevented full 

examination. Divers physically examined three locations of interest with a vacuum box to 

determine if leakage was present. In each case, however, leakage was not positively detected. 

Methods to apply an underwater coating to these locations to assure that these areas of interest 

remain leak-tight were investigated (Ref. B.6.6.18).

In August 2008, the NRC was informed that all known sources of leakage from the Unit 2 SFP 

have been eliminated based on completed inspections and repairs, and that a one-time 

inspection of the accessible 40 percent of the SFP liner above the fuel racks and 100 percent of 

the SFP transfer canal liner was completed in 2007 using general visual, robotic cameras and 

vacuum box testing techniques (Ref. B.6.6.13). It was noted that ground water outside the 
B-15

Unit 2 SFP would be tested every 3 months for the presence of tritium using samples taken from 

adjacent monitoring wells (Ref. B.6.6.4).

In September 2005, it was concluded that, due to the thickness of the SFP walls, the amount of 

steel reinforcement, and the small volume of moisture and boron percolating or seeping 

through, there was a reasonable assurance that the SFP wall was structurally sound and 

capable of performing its intended function (Ref. B.6.6.5). The data collected so far appear to 

indicate the presence of pinhole(s) in the SFP liner. The location of and whether the leak path 

is active was not determined. 

In February 2006, The NRC completed an inspection at Unit 2 and issued NRC Special 

Inspection Report No. 05000247/200501 that stated ―No safety significant findings were 

identified‖ for the structural integrity of the Unit 2 SFP. The inspector examined the small 

hairline cracks on the south wall of the SFP in assessing the structural integrity of the Unit 2 

SFP. The following documents were included in the NRC review (Ref. B.6.6.7):

 Consolidated Edison Calculation No. CGX-00006-00, ―Seismic Qualification Structural 

Evaluation of the Unit 2 Fuel Pool Wall Considering Deteriorated Condition of Concrete 

Due to Pool Leak‖

 United Engineers and Constructors Technical Report No. 8281, ―Evaluation of Spent 

Fuel Pool Walls - Indian Point 2 Nuclear Power Plant‖

 ABS Consulting Report 1487203-R-001, ―Study of Potential Concrete Reinforcement 

Corrosion on the Structural Integrity of the Spent Fuel Pit.‖ September 2005.

In November 2008 (Ref. B.6.6.19), a design margin assessment for the Unit 2 SFP reinforced 

concrete east and south walls was performed. The capability of the east SFP pit wall and the 

south SFP pit wall to resist the design-basis loads was evaluated. The assessment considered 

potential concrete and reinforcement steel degradation due to observed leakage of fluids 

through these walls. Core boring samples were obtained and tested to evaluate concrete 

properties and to provide access for visual inspection of the concrete and steel reinforcement. 

Finite-element models for both the east and south walls were developed to determine the actual 

forces in the walls due to loading resulting from the design-basis earthquake, hydrostatic forces, 

and dead weight. Due to the symmetry of the spent fuel pit structure, results from the 

evaluation of these two walls are applicable to the remaining north and west walls. 

The capacity of the east wall was evaluated in response to possible degradation due to an 

observed leak in 1992. It was determined that work in the SFP in 1990 initiated the leak by 

inadvertently creating a small hole in the stainless steel liner. This condition was repaired 

in 1992. A total of 20 core bores were taken from five locations on the east wall in the vicinity of 

the observed leakage to determine the condition of the concrete following exposure to borated 

water leakage. At each of the five locations, four individual cores of 101.6 mm (4 inches) in 

diameter and 381 mm (15 inches) in length were taken, resulting in a total depth of penetration 

into the wall of 1.52 m (60 inches). In addition, several windows in the outer surface of the wall 

were created to allow inspection of the outer layer of reinforcing steel. Of the 20 cores taken, all 

but one had compressive strengths that exceeded the design strength of 20.7 megapascals

(MPa) (3,000 pounds per square inch (psi)). This one core outlier had a measured compressive 

strength of 16.5 MPa (2,400 psi). 
B-16

The coring showed that the borated water had little or no effect on the concrete itself. Little or 

no corrosion was also observed in the steel reinforcement except at a location in the wall where 

spalling had occurred, exposing the steel to the environment. Analysis of the rust particles 

showed high chloride content and low boron concentration, indicating that rainwater was the 

primary cause of the observed corrosion. To determine the available margin in the east wall, 

moments were calculated using a finite-element plate model. The results of the analysis 

showed that the east wall was capable of resisting the applicable forces without any reinforcing 

steel and would incur little or no cracking as a result of the design loading. Conservatively 

assuming that the concrete would crack and the bending moments would be carried by the 

reinforcing steel, it was concluded that the load-bearing capacity of the wall is at least 

31 percent greater than required.

The structural margins in the south wall due to possible concrete steel reinforcement 

degradation as a result of observed fluid emanating from a crack discovered in the west corner 

during excavation for the dry cask storage project were evaluated. The reinforcing steel in the 

area of the observed leak was exposed for inspection and noted to have little or no corrosion. 

To determine the actual forces in the south wall due to the design-basis loads, a finite-element 

model of the wall was also developed. Based on the resulting moments from the analysis, the 

margins in the south wall with respect to the ultimate moment capacity of the concrete section 

were determined. The available margins in the east and south walls of the SFP pit with respect 

to the as-designed condition ranged from a low of 25 percent at the base of the wall for the 

vertical steel to a high of 57 percent for the vertical steel at the crack location in the west corner 

of the wall. The margins for the horizontal rebar at wall mid span ranged from 43 percent to 

45 percent and up to 51 percent in the vicinity of the observed crack. 

B.6.6 References

B.6.6.1 Dacimo, F., Entergy Indian Point Energy Center, letter to U.S. Nuclear Regulatory 

Commission, April 23, 2007.

B.6.6.2 Dacimo. F.R., Indian Point Energy Center, letter to U.S. Nuclear Regulatory 

Commission, May 3, 2007.

B.6.6.3 Dacimo. F.R., Indian Point Energy Center, letter to U.S. Nuclear Regulatory 

Commission, June 21, 2007

B.6.6.4 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3.‖

NUREG-1930, Volumes 1 and 2. U.S. Nuclear Regulatory Commission: 

Washington, DC. November 2009.

B.6.6.5 Freedom of Information Act Information, FOIA-2005-0369. ―Hairline Crack in IPEC 

Unit 2 Spent Fuel Pool South Wall, Revision 4.‖ September 15, 2005.

B.6.6.6 Collins, S.J., U.S. Nuclear Regulatory Commission, letter to J.W. Tuffey, New York 

State Emergency Management Office, November 2, 2005.
B-17

B.6.6.7 Blough, A.R., U.S. Nuclear Regulatory Commission, letter to F.R. Dacimo, Entergy 

Nuclear Operations, Inc, March 16, 2006.

B.6.6.8 U.S. Nuclear Regulatory Commission. ―NRC Performing Special Inspection at Indian 

Point 2 Nuclear Plant; Small Amount of Leakage from Spent Fuel Pool Area under 

Review.‖ NRC News, No. I-05-049. U.S. Nuclear Regulatory Commission: 

Washington, DC. September 20, 2005.

B.6.6.9 Blough, A.R., U.S. Nuclear Regulatory Commission, memorandum to J.R. White, 

U.S. Nuclear Regulatory Commission, October 7, 2005.

B.6.6.10 U.S. Nuclear Regulatory Commission. “NRC Establishes Web Page for Information 

on Spent Fuel Pool Issues at Indian Point.‖ NRC News, No. 05-136. U.S. Nuclear 

Regulatory Commission: Washington, DC. October 4, 2005.

B.6.6.11 Pollock, J.E., Site Vice President, Entergy, ―Results of Groundwater Contamination,‖ 

letter to U.S. Nuclear Regulatory Commission, January 11, 2008.

B.6.6.12 U.S. Nuclear Regulatory Commission. ―Liquid Radioactive Release Lessons 

Learned Task Force Final Report.‖ U.S. Nuclear Regulatory Commission: 

Washington, DC. September 1, 2006. Available at 

http://www.nrc.gov/reactors/operating/ops-experience/tritium/lr-release-lessonslearned.pdf.

B.6.6.13 Dacimo, F., Entergy Nuclear Northeast-Indian Point Energy Center, letter to 

U.S. Nuclear Regulatory Commission, August 14, 2008.

B.6.6.14 Green, K., U.S. Nuclear Regulatory Commission, letter to Vice President, 

Operations, Entergy Nuclear Operations, Inc.-Indian Point Energy Center, 

April 3, 2009.

B.6.6.15 Dacimo, F., Entergy Nuclear Northeast-Indian Point Energy Center, letter to 

U.S. Nuclear Regulatory Commission, May 1, 2009.

B.6.6.16 G. Schwartz. ―Hairline Crack in IPEC Unit 2 Spent Fuel Pool South Wall.‖ 

Calculation CGX-00006, Revision 4. Indian Point Energy Center.

September 15, 2005. Available at 

http://pbadupws.nrc.gov/docs/ML0532/ML053270506.pdf.

B.6.6.17 G. Schwartz. ―Hairline Crack in IPEC Unit 2 Spent Fuel Pool South Wall.‖

Calculation Technical Report ME-3802, Revision 4. Indian Point Energy Center. 

September 15, 2005. Available at 

http://pbadupws.nrc.gov/docs/ML0905/ML090550415.pdf.

B.6.6.18 U.S. Nuclear Regulatory Commission. ―Indian Point 2 & 3, Groundwater 

Leakage,Ongoing Activities,‖ U.S. Nuclear Regulatory Commission: Washington, 

DC. 2005. Available at http://www.nrc.gov/info-finder/reactor/ip/ip-groundwaterleakage/on-going-activities/on-going-activities05.html
B-18

B.6.6.19 Dacimo, F., Entergy Nuclear Northeast-Indian Point Energy Center, letter to 

U.S. Nuclear Regulatory Commission, November 6, 2008.
B-19

B.7 Kewaunee Power Station

B.7.1 Introduction

On August 12, 2008, Dominion Energy Kewaunee, Inc. submitted an LRA to the NRC for its 

Kewaunee Power Station (Ref. B.7.6.1). The results of the NRC staff‘s evaluation of the LRA 

were published in January 2011 in NUREG-1958, ―Safety Evaluation Report Related to the 

License Renewal of Kewaunee Power Station‖ (Ref. B.7.6.2).

B.7.2 Field Observations

As discussed in the SER, Section 3.0.3.2.18 (Ref. B.7.6.2), it was noted in a letter dated 

August 17, 2009 (Ref. B.7.6.3), that, after the identification of white deposits on the wall and 

ceiling of the waste drumming room adjacent to the SFP in December of 2007, meetings were 

held to discuss fuel pool makeup, housekeeping and contamination, ground water leakage 

concerns, and the possibility of structural degradation. The affected areas were cleaned and 

put under observation to find the cause of the condition and establish a corrective action plan. 

During monitoring, the residue occurred again in the same area after it had been cleaned, but 

there was no active dripping. In June 2008, monitoring and troubleshooting of the area began 

and included monthly visual inspections examining the change in size, shape, and color of the 

deposit through time-lapse photography.

After a year of monitoring the wall and ceiling of the waste drumming room, it was concluded 

that the residue formation remained constant. The residue formation rate was slow and, 

therefore, it was determined that there was no near-term concern for the integrity of the 

structure or potential loss of intended function. Actions would be implemented if any change in 

leakage trend or other signs of concrete distress were observed. Additional monitoring of the 

ground water to date indicates no detectable level of tritium outside the auxiliary building or in 

the ground water (Refs. B.7.6.4 and B.7.6.5).

B.7.3 Design Characteristics of the Spent Fuel Pool

The SFP is located at an intermediate elevation in the auxiliary building, 4.57 m (15 feet) above 

the basement floor. The auxiliary building is a concrete and steel multistory structure that 

interfaces with the shield building and turbine building. The SFP receives spent fuel from the 

reactor containment vessel through the fuel transfer tube. The penetration sleeve for the fuel 

transfer tube is embedded in the fuel transfer canal wall. The SFP, including the fuel transfer 

canal, is constructed of concrete with a stainless steel liner on its walls and a 2.1-m (7-foot) 

thick concrete base slab.

The SFP and the fuel transfer canal are divided into 10 leak detection zones, 5 for the pools, 

and 5 for the canal. At present, three zones, zone nos. 1, 4, and 5, are indicating leakage of 

approximately 17.7, 8.9, and 26.6x10-5cubic meters (m

3

) per day (6, 3, and 9 ounces per day), 

respectively, which totals 3.79x10-3 m

3

(one gallon) per week. 

B.7.4 Corrective Actions for Spent Fuel Pool Liner Leakage

The presence of spent fuel in the storage pools makes inspection of a large part of the storage 

pool liner impractical due to access restrictions. A monthly leak inspection plan based on 
B-20

available techniques, however, was developed to identify and remediate the SFP liner leakage, 

including leaks of the liner pressure boundary weld seams (Refs. B.7.6.2 and B.7.6.6). Portions 

of the auxiliary building adjacent to the SFP will be inspected annually during the period of 

extended operation to identify any additional leakage indications. Any newly observed 

indications will be documented and entered into the corrective action program. In addition, a 

multidisciplinary team will be formed to develop recommendations for inspection, testing, and 

repairs to remediate the SFP liner leakage. The SFP liner seam weld leakage detection and 

collection system drain lines will be inspected and repaired, if required, to ensure a clear drain 

path. A routine maintenance activity will be created to continue inspection of the drain lines 

through the period of extended operation. 

B.7.5 Structural Integrity Assessment and Test Results

Industry data related to the liner leakage of the reactor cavity and SFP at Indian Point Nuclear 

Generating Units 2 and 3 (Ref. B.7.6.7) and the water seepage from the refueling cavity at 

Prairie Island Nuclear Generating Plant, Units 1 and 2 (Ref. B.7.6.8) were referenced, indicating 

that, even in the presence of borated water, the conditions at the rebar remain sufficiently 

alkaline, resulting in negligible corrosion. 

A concrete core sample will be taken prior to the end of 2011. At least one core bore sample 

will be taken from the waste drumming room reinforced concrete ceiling below the SFP. The 

core sample location and depth will be sufficient to validate the strength of the concrete and the 

extent of any degradation. The core sample will be tested for compressive strength and will be 

subjected to petrographic examination. Reinforcing steel in the core sample area will be 

exposed and inspected for material condition.

B.7.6 References

B.7.6.1 Christian, D.A., Dominion Energy Kewaunee, Inc., letter to U.S. Nuclear Regulatory 

Commission, August 12, 2008.

B.7.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Kewaunee Power Station.‖ NUREG-1958. U.S. Nuclear 

Regulatory Commission: Washington, DC. January 2011. 

B.7.6.3 Scace, S.E., Dominion Energy Kewaunee, Inc., letter to U.S. Nuclear Regulatory 

Commission, August 17, 2009.

B.7.6.4 Price, J.A., Dominion Energy Kewaunee, Inc., letter to U.S. Nuclear Regulatory 

Commission, December 28, 2009.

B.7.6.5 Hernandez, S., U.S. Nuclear Regulatory Commission, letter to D.A. Heacock, 

Dominion Energy Kewaunee, Inc., November 20, 2009.

B.7.6.6 Price, J.A., Dominion Energy Kewaunee, Inc., letter to U. S. Nuclear Regulatory 

Commission, February 15, 2010.
B-21

B.7.6.7 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3.‖

NUREG-1930. U.S. Nuclear Regulatory Commission: Washington, DC. 

November 2009.

B.7.6.8 Holian, B.E., U.S. Nuclear Regulatory Commission, letter to M.A. Schimmel, 

Northern States Power Company, Minnesota, October 16, 2009.

B-23

B.8 Palo Verde Nuclear Generating Station, Unit 1

B.8.1 Introduction

By letter dated December 11, 2008 (Ref. B.8.6.1), as supplemented by letter dated 

April 14, 2009 (Ref. B.8.6.2), Arizona Public Service Company submitted an LRA to the NRC for 

Palo Verde Nuclear Generating Station, Unit 1, Unit 2, and Unit 3. The results of the NRC 

staff‘s evaluation of the LRA were published in April 2011 in NUREG-1961, ―Safety Evaluation 

Report Related to the License Renewal of Palo Verde Nuclear Generating Station, Units 1, 2, 

and 3‖ (Ref. B.8.6.3).

B.8.2 Field Observations

In July 2005, during a routine area tour, an auxiliary operator in the Unit 1 fuel building observed 

water seeping from the SFP south wall at the 32-m (105-foot) elevation in the cleanup pump 

area. There were also white deposits that looked like solidified boric acid. Upon further 

inspection, a second leak was discovered outside of the fuel building at the 31.7-m (104-foot) 

elevation of the SFP east wall. Personnel obtained samples of the water and debris outside of 

the Unit 1 fuel building and identified trace quantities of radioactive cobalt-60, antimony-125, 

and cesium-137. Samples of the leakage indicated that the source of the water was from the 

SFP because boron concentrations were consistent with SFP chemistry. Following the 

discovery of the leakage, the SFP telltale drains were opened and approximately 4.54 m

3

(1,200 gallons) of water were released from the drains. 

B.8.3 Design Characteristics of the Spent Fuel Pool

The SFP is constructed of reinforced concrete with the inner surfaces lined by welded stainless 

steel plates (Ref. B.8.6.4). A built-in leak-detection system collects water from slight liner leaks 

or liner plate weld imperfections and routs it through a leak-chase system to the radioactive 

waste drain (RD) system, thus ensuring that leakage into the environment does not occur. The 

leak chase system, or telltale system, is subdivided into 10 sections, and each section has an 

associated RD valve. The RD valves associated with the SFP telltale system are kept closed.

The telltale RD valves are opened on a daily basis and any accumulated water is drained, then 

the valves are reclosed. Any water is measured and recorded by operations personnel and 

trended by System Engineering. The water drained from the telltale lines is returned to the RD 

system.

B.8.4 Corrective Actions for Spent Fuel Pool Liner Leakage

All contamination that resulted from the leakage was removed from the outer SFP walls, and it 

was verified that no residual activity remained outside the fuel building. Potential environmental 

impacts from the condition were reviewed, and it was determined that no adverse effects 

resulted from the SFP leakage because the small amount of leakage outside the SFP building 

(2.37x10-4 m

3

(8 ounces)) could not reach the local perched or regional ground water due to 

their distances (21.3 and 71.4 m (70 and 300 feet), respectively) below the ground surface 

(Ref. B.8.6.4).

The SFP leakage that occurred in Unit 1 in July 2005 was evaluated (Ref. B.8.6.5). The cause 

of the water backing up in the leak chase system was due to a pressure test plug that had been 

lodged in the drain basin drain line since construction. The basin is the same place where the 
B-24

telltale RD drain valves discharge. The plug was not allowing the basin to drain, and operations 

personnel did not have an alternate means of draining the water out of the basin. A decision 

was made to stop drainage of the telltale drain valves until the issue was corrected. As a 

consequence, water accumulated, filling each leak chase channel. This water seeped to 

adjacent channels via the small gap between the concrete wall and the liner plate. Eventually, 

the water made its way to the exterior face of the fuel pool walls through extremely small cracks 

in two locations. One of these locations was on the south side of the fuel pool inside of the fuel 

building; therefore, the leak was contained. The other leak was on the east side of the fuel pool 

that is also the exterior wall of the fuel building. 

Once the obstruction (plug) was removed from the drain basin drain line, a large amount of 

borated water was released from each RD telltale drain valve line to the RD system for 

processing, thus providing evidence that the leak chase lines were not obstructed. This event 

was entered in the corrective action program. The cause of the issue was identified, and 

corrective actions were taken to eliminate and prevent further leakage to the environment.

Plant personnel open the valves and record drained water on a daily basis to keep water from 

backing up and leaking through the concrete (Ref. B.8.6.3). In addition, drainage from the 

telltale system will be measured and trended, and any abnormalities will be investigated through 

the corrective action program. In order to ensure that the drain lines were clear, all telltale drain 

lines in all units were inspected via boroscope between 2008 and 2009, and subsequently on a 

2-year frequency. 

B.8.5 Structural Integrity Assessment and Test Results

Construction Technology Laboratories performed a nondestructive examination (NDE) of the 

SFP concrete walls (Refs. B.8.6.3 and B.8.6.6). The Construction Technology Laboratories

inspection report concluded that the borated water leakage did not have an adverse impact on 

the concrete. 

Leakage through the concrete has stopped completely in areas that were initially identified as 

showing leakage, based on the fact that there are no longer wetted areas visible (Refs. B.8.6.7

and B.8.6.8). In addition, in 2006 and 2007, shallow aquifer wells were installed down-gradient 

of each unit. These wells are sampled periodically and no radioactivity has been detected. No 

indications of leakage have been identified in Units 2 or 3. 

B.8.6 References

B.8.6.1 Mims, D.C., Arizona Public Service Company Palo Verde Nuclear Generating 

Station, letter to U.S. Nuclear Regulatory Commission, December 11, 2008.

B.8.2.2 Mims, D.C., Arizona Public Service Company Palo Verde Nuclear Generating 

Station, letter to U.S. Nuclear Regulatory Commission, April 14, 2009.

B.8.6.3 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Palo Verde Nuclear Generating Station, Units 1, 2, and 3.‖

NUREG-1961. U.S. Nuclear Regulatory Commission: Washington, DC. April 2011.
B-25

B.8.6.4 Pruett, T.W., U.S. Nuclear Regulatory Commission, letter to J.M. Levine, Arizona 

Public Service Company, November 9, 2005.

B.8.6.5 Mims, D.C., Arizona Public Service Company Palo Verde Nuclear Generating 

Station, letter to U.S. Nuclear Regulatory Commission, February 19, 2010.

B.8.6.6 Regner, L.M., U.S. Nuclear Regulatory Commission, letter to R.K. Edington, Arizona 

Public Service Company, December 29, 2009.

B.8.6.7 Hesser, J.H., Arizona Public Service Company Palo Verde Nuclear Generating 

Station, letter to U.S. Nuclear Regulatory Commission, May 21, 2010.

B.8.6.8 Regner, L.M., U.S. Nuclear Regulatory Commission, letter to R.K. Edington, Arizona 

Public Service Company, April 28, 2010.

B-27

B.9 Salem Nuclear Generating Station, Units 1 and 2

B.9.1 Introduction

On August 18, 2009, PSEG submitted an LRA to the NRC for Salem Nuclear Generating 

Station (Salem), Units 1 and 2 (Ref. B.9.6.1). The results of the NRC staff‘s evaluation of the 

LRA were published in June 2011 in NUREG-2101, ―Safety Evaluation Report Related to the 

License Renewal of Salem Nuclear Generating Station‖ (Ref. B.9.6.2).

B.9.2 Field Observations

In 1980, a small leak was discovered in the SFP telltale drains at Unit 1. Underwater 

inspections determined that the cause was due to leaking seam welds. After repair of the 

leaking seam welds, the leakage was reduced to less than 8.8x10-9 m

3

/s (0.2 gpd) 

(Ref. B.9.6.3).

In September 2002, tests identified evidence of radioactive water leakage through a concrete 

wall located at the 24-meter (78-foot) elevation of the Unit 1 auxiliary building mechanical 

penetration room, a radiologically controlled area. The leak location, about 3 meters (10 feet) 

up a wall surface, was identified while investigating a low-level shoe contamination from the 

area. A task action plan was established to identify and stop sources of leakage and evaluate 

the possibility of undetected leakage outside building structures. Other locations were identified 

where radioactive water was leaking through interior walls or penetrations into both the Unit 1 

auxiliary building and the Unit 1 FHB. Videoscopic inspection of the SFP telltale drains and 

leakage channels revealed that most of the telltale drains were blocked. As a result of the 

blockage, leakage through the seam welds and the plug welds accumulated in small gaps 

between the stainless steel liner and concrete. As the water level in the gap increased, 

hydrostatic pressure forced the water outside through penetrations, construction joints, and 

small cracks in the SFP concrete (Ref. B.9.6.1). Ultimately, the water migrated into the seismic 

gap between the FHB and the auxiliary building and there was evidence of seepage into the 

sump room in the FHB via a construction joint at the base of the pool (Ref. B.9.6.4). 

Figure B.9-1 shows the SFP water leakage path into the seismic gap. In 2003, the blockage 

was removed from the drain system. Since 2003, the leakage through the drain system has 

been monitored, and the volume of leakage averages 4.3x10-6 m

3

/s (100 gpd) (Ref. B.9.6.3). 

Figure B.9-2 shows the current leakage paths. In 2010, evidence of a small leak was noted to 

be present in the Unit 2 telltale drain system. Although it was verified that the drain lines were 

open, the small amount of leakage will be monitored.

Relative to Unit 1 SFP leakage, it has been noted (Ref. B.9.6.2) that conditions indicate that,

based on sampling of water collected from the seismic gap drain located next to the east wall,

approximately 5.4x10-9 m

3

/s (0.125 gpd) is migrating through the inaccessible east wall. There 

is no evidence of through-wall leakage on the accessible west wall since the telltale drains were 

cleared in 2003. Leakage through the south wall was not considered feasible because the wall 

is 11.9 m (39 feet) thick, and, based on tritium levels, leakage is not occurring through the north 

wall. 

B.9.3 Design Characteristics of the Spent Fuel Pool

The SFP pressure boundary is fabricated from stainless steel plates welded together using a 

continuous backer strip to create a liner. After welding, each seam weld was vacuum tested.
B-28

To mitigate the consequences of a seam weld leak, continuous stainless steel leak chase 

channels were installed directly beneath each seam weld prior to concrete placement to serve 

as part of a telltale collection system. The channels were anchored to the concrete and 

positioned so the two legs of each channel straddled the seam weld and were even with the 

finished concrete surface. The leak chase system is designed such that any leakage collected 

in the channels is directed and discharged through 17 drain lines into the sump room trench 

outside the SFP in the FHB. The liner plates were also anchored to the concrete by stainless 

steel structural attachment studs embedded in the concrete. These studs extended through 

holes in the liner plates and were plug welded to the liner plates. This method of construction 

created an air gap between the concrete surface and the liner plates. In addition, the design did 

not specify welding of the channel legs to the liner plate. The SFP liner contains about 640 m 

(2,100 linear feet) of seam welds and about 1,400 plug welds. The liner creates a pressure 

boundary to confine the borated water that surrounds the spent fuel. The borated water in the 

SFP has 2,200–2,400 ppm boron and is acidic with a pH of 4.8. The bottom of the SFP liner is 

located at 27.4-meters (89-feet) elevation. Support for the liner plates is provided by reinforced 

concrete structural elements.

B.9.4 Corrective Actions for Spent Fuel Pool Liner Leakage

Leakage from the SFP is likely from small cracks in seam welds (2,100 linear feet) of adjoining 

liner plates or at plug welds (1,400 total) that connect the liner plates to the steel embedded in 

the surrounding concrete as a result of differential thermal expansion between the liner and the 

concrete structure (Ref. B.9.6.3). In 1995, 95 percent of all seam welds were inspected via 

vacuum box testing and no through-wall cracks were found, suggesting that the leakage was 

occurring below the sensitivity of the test (Ref. B.9.6.3). It has been estimated that the leakage 

rate could be the result of a single or multiple cracks having dimensions of 0.0254 mm wide by 

152 mm long (0.001 inch wide and 6 inches long). The current direction is to monitor the telltale 

leakage, clear the leak chase system every 18 months to ensure proper drainage, and minimize 

the hydrostatic pressure buildup and any leakage to the environment. 

B.9.5 Structural Integrity Assessment and Test Results

A structural assessment of the FHB was performed (Refs. B.9.6.3 and B.9.6.4). It included the 

following: 

• A baseline inspection of the building was conducted consistent with American Concrete 

Institute (ACI) guidelines to assess the overall condition of the structure. PSEG has 

committed to continue monitoring of the structure in accordance with ACI 349.3R-02, 

―Evaluation of Existing Nuclear Safety-Related Concrete Structures‖ (Ref. B.9.6.5).

• An assessment of the potential reduction in structural margin due to postulated 

degradation of the structure over the remaining plant life was performed. This effort 

included testing to demonstrate the impact of boric acid on reinforced concrete and to 

quantify the degradation rate.

The assessment concluded the following:

• Overall, the concrete appears to be in good structural condition. 
B-29

• The appearance of leaching or chemical attack and corrosion staining of undefined 

source on concrete surfaces does not indicate significant structural deterioration at this 

time. 

• There were no indications of concrete surface expansion due to reinforcing steel 

corrosion. 

To address the through-wall leakage and any possible associated degradation, the following 

commitments were made (Ref. B.9.6.2):

• Perform periodic structural examinations of the FHB per ACI 349.3R to ensure 

that the structural condition is in agreement with analysis.

• Monitor telltale leakage and inspect the leak chase system to ensure that there is 

no blockage.

• Test water drained from telltales and the seismic gap for boron, chloride, iron, 

and sulfate concentrations, and for pH. Sample readings outside the acceptance 

criteria, noted below as an illustrative example, will be entered into and evaluated 

in the corrective action program.

Chemical 

analysis

Acceptance Criteria Frequency for 

monitoring SFP Telltales

(West Wall)

SFP Telltales

(East Wall)

pH 6.0 < pH < 7.5 7.0 < pH < 8.5 Monthly

Chloride < 500 ppm < 500 ppm Every 6 months

Sulfate < 1,500 ppm < 1,500 ppm Every 6 months

Boron Information Only Information Only Monthly

Iron Information Only Information Only Every 6 months

• Perform one shallow core in each of the Unit 1 SFP walls (east and west) that 

have shown ingress of borated water through the concrete. Core samples will 

expose rebar, which will be examined for corrosion. East and west wall cores 

are to be taken by the end of 2015 and 2013, respectively.

• Perform a structural examination per ACI 349.3R every 18 months of the Unit 1 

SFP wall in the sump room where previous inspections have shown ingress of 

borated water through the wall.

Laboratory studies were conducted to quantify the potential degradation of concrete in the FHB 

structure (Ref. B.9.6.3). The following conclusions are based on results of these studies: 

• Borated water attacks the calcium hydroxide component of the cement paste, causing 

loss of bonding of the coarse and fine aggregates. 

• The predicted depth of borated water intrusion in the concrete after 70 years exposure to 

SFP water at 37.8 degrees Centigrade (100 degrees Fahrenheit) is anticipated to be 

33.0 mm (1.30 inches). This includes a two-sigma statistical uncertainty of the test data 

and an adjustment for temperature. Since the concrete clear cover for the walls and 
B-30

slab is greater than this projected degradation depth, the borated water will not reach 

rebar during the 70-year period. 

• The wicking effect at the rebar/concrete interface was observed to be minor. That is, the 

degradation rate of the concrete at the rebar/concrete interface is similar to the general 

rate of attack of concrete without rebar. Therefore, degradation of rebar at the 

construction joints or cracks will not spread rapidly along the interface with the rebar,

and loss of bond with the concrete will not be compromised.

The impact of borated water on the concrete embedded steel reinforcement was also 

addressed, with the following conclusions (Ref. B.9.6.2):

• The rebar of concern is the outer rebar, as the limiting margin cases involve 

compression on the poolside and tension on the outside. Accordingly, the borated water 

must seep through several feet of concrete before reaching the rebar. The acidic water 

would react with concrete along the transit path, resulting in diminishing acidity. The 

corrosion rate of carbon steel in de-aerated boric acid is 0.004 mm/year (0.1575 mils or 

157.5 microinches/year) in a 2,400-ppm solution. However, this rate is conservative with 

regard to the situation in the FHB because the pH when the borated water reaches the 

rebar will be increased due to its reaction with the concrete.

• A reference study from Germany, published in a reputable journal, documented a 

carefully controlled study of corrosion of embedded rebar from flow of boric acid through 

a simulated crack (Ref. B.9.6.6). It showed negligible corrosion for the most aggressive 

conditions after a period of 2 years.

• Experience at another U.S. pressurized-water reactor showed no visible corrosion of 

embedded reinforcing steel from boric acid flow through a crack over several years. 

Rust stains on the sump room walls are minor and result in the deposition of small 

amounts of iron oxide.

• Borated water that leaks through the stainless steel liner will be partially deaerated as it 

reacts with and corrodes the carbon steel leak chase channels.

• Oxygen in the borated water that reaches the embedded concrete steel reinforcement by 

traveling through concrete cracks will be quickly consumed during initial oxidation 

reaction with the reinforcement.

• Oxygen that is consumed will not be replenished, since the water migration path to the 

steel reinforcement is relatively stagnant.

Corrosion of the carbon steel leak chase channels is not a concern because the channels have 

no impact on the structural integrity of the FHB and their sole function is to collect SFP leakage 

and route it to the sump via telltales.

The potential impact of erosion of the concrete in the floor of the SFP on the Unit 1 SFP liner 

was considered (Ref. B.9.6.2). It was noted that an assessment has determined that the liner is 

sufficiently ductile to accommodate the load from spent fuel racks, even if the foot of a rack was 

positioned over an area of degraded concrete.
B-31

The impact on structural capacity resulting from the long-term effects of exposure of concrete 

and steel reinforcing bars to borated water has also been evaluated (Ref. B.9.6.4). Projected 

degradation through the end of plant life was estimated to reduce the available margin in the 

limiting section by less than one-half percentage point to 1.6 percent (i.e., a design margin ratio 

of 1.016). Therefore, the conservative design-basis analysis of record was considered to not be 

invalidated by the postulated degradation. 

B.9.6 References

B.9.6.1 Fricker, C.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

August 18, 2009.

B.9.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Salem Nuclear Generating Station.‖ NUREG-2101.

U.S. Nuclear Regulatory Commission: Washington, DC. June 2011.

B.9.6.3 Davison, P.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

May 13, 2010.

B.9.6.4 Joyce, T.P., PSEG Nuclear, LLC, letter to J. White, U.S. Nuclear Regulatory 

Commission, March 30, 2007.

B.9.6.5 American Concrete Institute. ―Evaluation of Existing Nuclear Safety-Related 

Concrete Structures.‖ ACI 349.3R-02. American Concrete Institute: Farmington 

Hills, MI. 2002.

B.9.6.6 Ramm, W., and M. Biscoping. ―Autogenous Healing and Reinforcement Corrosion of 

Water-Penetrated Separation Cracks in Reinforced Concrete.‖ Nuclear Engineering 

and Design 179: 191–200. 1998.

B.9.6.7 ―Official Transcript of Proceedings, Advisory Committee on Reactor Safeguards

Plant License Renewal Subcommittee.‖ Work Order No. NRC-577. Neal R. Gross 

and Co., Inc., Court Reporters and Transcribers: Washington, DC. 

December 1, 2010.
B-32

Figure B.9-1 Spent fuel pool leakage path for Salem Unit 1 before 2003

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee.” Work Order No. NRC-577. 

Neal R. Gross and Co., Inc., Court Reporters and Transcribers: Washington, DC. 

December 1, 2010.)

Figure B.9-2 Current spent fuel pool leakage path for Salem Unit 1

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee.” Work Order No. NRC-577. 

Neal R. Gross and Co., Inc., Court Reporters and Transcribers: Washington, DC. 

December 1, 2010.)

Before 2003

Clog 
C-1

APPENDIX C: BOILING-WATER REACTOR MARK I CONTAINMENT—

TORUS CORROSION AND CRACKING CASE STUDIES

C.1 Cooper Nuclear Station

C.1.1 Introduction

By letter dated September 24, 2008 (Ref. C.1.6.1), Nebraska Public Power District submitted a 

license renewal application (LRA) to the U.S. Nuclear Regulatory Commission (NRC) for the 

Cooper Nuclear Station. The results of the NRC staff‘s evaluation of the LRA were published in 

October 2010 in NUREG-1944, ―Safety Evaluation Report Related to the License Renewal of

Cooper Nuclear Station‖ (Ref. C.1.6.2).

C.1.2 Field Observations

Since 1974, 3,800 coating repairs comprising 13.5 square meters (145 square feet), or 

1.1 percent of the torus surface area below the waterline, have been made (Ref. C.1.6.2). 

Eighteen locations have been reported to have pits where the nominal thickness has been 

reduced by greater than 10 percent of the nominal shell thickness (Ref. C.1.6.3). Figure C.1-1 

provides an example of a torus pit, and Figure C.1-2 provides an example of a torus pit coating 

repair. The locations of pit concentrations are presented in Figure C.1-3. Reference C.1.6.4 

notes that no pits have been identified that require repair in accordance with the American 

Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (ASME Code)

(Ref. C.1.6.5).

C.1.3 Design Characteristics of the Torus

The primary containment is a Mark I low-leakage pressure-suppression containment design that 

houses the reactor vessel, the reactor recirculating loops, and other connections of the reactor 

coolant system (Ref. C.1.6.1). The major components of the primary containment include a 

drywell, a torus (or pressure-suppression chamber (PSC)), and the connecting vent system 

between the drywell and the torus.

The drywell houses the reactor vessel and associated components. The drywell is a carbon 

steel structure surrounded by a reinforced concrete biological shield wall. Internal structures 

consist of a drywell fill slab, reactor pedestal, sacrificial shield wall and its lateral support, and 

structural steel. The reinforced concrete fill slab in the bottom of the drywell supports the 

reactor pedestal and other structures and components inside the drywell. A gap separates the 

drywell from the reactor building reinforced concrete in the area around the cylindrical portion 

and the spherical portion above the support transition point at the lower radius. The reinforced 

concrete drywell floor contains the drywell floor drain and equipment drain sumps. The reactor 

pedestal is a reinforced concrete cylinder supporting the reactor pressure vessel, the sacrificial 

shield wall, and floor framing.

One personnel access lock is provided for access to the drywell. The lock has two gasketed 

doors in series. A personnel access hatch is provided on the drywell head. This hatch is bolted 

in place. The drywell has two equipment access hatches bolted in place. The drywell top head, 

the two equipment hatches, the drywell and torus manways, the control rod drive removal hatch, 

and the stabilizer assembly inspection ports have double-gasketed closures to maintain 
C-2

containment leak tightness. The drywell design accommodates pressures and temperatures 

resulting from a breach of the reactor coolant pressure boundary up to and including an 

instantaneous circumferential break of the reactor recirculation piping and provides holdup for 

decay of radioactive material. When operating at power, the drywell is filled with nitrogen to 

preclude the presence of oxygen.

The torus is located below the drywell and encircles and contains treated (demineralized) water, 

which forms the suppression pool. The torus is a carbon-steel pressure vessel anchored to and 

supported by the reinforced concrete foundation slab of the reactor building.

C.1.4 Corrective Actions for Torus Corrosion and Cracking

The containment inservice inspection program and the Service Level I coating program are 

used to provide assurance that there is proper maintenance of the protective coatings in 

containment, such that they will not degrade and become a debris source that may challenge 

the emergency core cooling system (ECCS) (Ref. C.1.6.6). The Service Level I coating 

program is used to provide specific instructions for maintenance of safety-related coatings 

applied to concrete and steel surfaces within the drywell and torus (Ref. C.1.6.7). Although the 

containment inservice inspection program is not used to inspect Service Level I coating, the 

coatings in the purview of the program that show signs of degradation are reported for review 

and evaluation under the Service Level I coating program. The program specifies visual 

inspections during each refueling outage (RFO) of the coating surfaces for adverse coating 

conditions such as flaking, peeling, blistering, discoloration, and other signs of distress. Divers 

visually inspect coatings on the torus below the waterline. Coatings showing signs of 

degradation are documented in the corrective action program, reviewed, and evaluated for 

acceptability, repair, or replacement. The inspections are done in compliance with requirements 

in ASME Code Section XI, Subsection IWE.

Repairs are typically made only in areas that experience localized zinc coating failures where 

the pit depths exceed a threshold (generally 0.76 to 1.27 millimeters (mm) (30 to 50 mils)) 

(Ref. C.1.6.2). Table C.1-1 presents an example of inspection criteria (Ref. C.1.6.8). The 

coating is repaired locally by applying an epoxy that is intended to arrest the pitting. However, 

coating at pits that do not exceed the threshold is not required, but the pitting is monitored at the 

next inspection (3 years later) for growth. This process, however, can result in localized 

galvanic corrosion that can yield higher and unpredictable corrosion rates (pitting) than that of 

general corrosion. It has also contributed to the amount of sludge and corrosion products 

collecting in the suppression pool, which can further increase the corrosion rate. To address 

this concern, the following commitments will be implemented (Ref. C.1.6.9):

• The wetted portion of the torus will be recoated within 3 years after entering the 

period of extended operation (but not later than January 18, 2017). 

• Sludge will be removed and the wetted portion of the torus inspected every 

refueling outage until the torus is recoated.

• An engineering analysis will be completed following each torus inspection that 

demonstrates that the projected pitting of the torus, up to the time that the torus 

is recoated, will not result in reduction of torus wall thickness below minimum 

acceptable values.
C-3

C.1.5 Structural Integrity Assessment and Test Results

An engineering evaluation determined that loss of material at the 18 pits identified above was 

acceptable (Ref. C.1.6.3). Supplementary volumetric examinations (ultrasonic thickness

measurements) at these 18 pits located under water have not been performed. However, 

augmented visual testing of the wetted surfaces of the torus is performed once during each 

inspection period (three times in 10 years) as required by the ASME Code.

According to reference calculations, the minimum corrosion allowance available after 

considering the existing pits that have been identified and repaired until 2008 is 0.787 mm 

(31 mils). A corrosion rate of 0.066 mm per year (2.6 mils per year) has been determined based 

on the maximum pit growth observed over approximately 13 years (Ref. C.1.6.4). The rate was 

determined by comparing the results of the 2005 inspections to those identified approximately 

13 years earlier. Using this rate, it was concluded that the torus is acceptable until at least 2014 

(Ref. C.1.6.2). 

C.1.6 References

C.1.6.1 Minahan, S.B., Nebraska Public Power District, letter to U.S. Nuclear Regulatory 

Commission, September 24, 2008.

C.1.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Cooper Nuclear Station.‖ NUREG-1944. U.S. Nuclear 

Regulatory Commission: Washington, DC. October 2010. 

C.1.6.3 O‘Grady, B.J., Nebraska Public Power District, letter to U.S. Nuclear Regulatory 

Commission, December 21, 2009.

C.1.6.4 Minahan, S.B., Nebraska Public Power District, letter to U.S. Nuclear Regulatory 

Commission, July 29, 2009.

C.1.6.5 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.

C.1.6.6 Tran, T., U.S. Nuclear Regulatory Commission, letter to S.B. Minahan, Nebraska 

Public Power District, September 28, 2009.

C.1.6.7 Minahan, S.B., Nebraska Public Power District, letter to U.S. Nuclear Regulatory 

Commission, October 22, 2009.

C.1.6.8 ―Official Transcript of Proceedings, Advisory Committee on Reactor Safeguards 

Plant License Renewal Subcommittee.‖ Work Order No. NRC-237. Neal R. Gross 

and Co., Inc., Court Reporters and Transcribers: Washington, DC. May 5, 2010.

C.1.6.9 O‘Grady, B.J., Nebraska Public Power District, letter to U.S. Nuclear Regulatory 

Commission, May 4, 2010.
C-4

Table C.1-1 Example of Torus Inspection Criteria

Region 

Classification

Pit Type Pit Depth Coating Repair 

Required (yes/no)

Near Penetration Shallow 0 to < 30 mil Yes

Deep > 30 mil Yes

Near Ring Girder Noted < 50 mil No

Shallow > 50 mil < 90 mil Yes

Deep > 90 mil Yes

General Shell Noted < 90 mil No

Shallow > 90 mil < 150 mil Yes

Deep > 150 mil Yes

Source: Ref. C.1.6.7.

Figure C.1-1 Example of pitting corrosion in torus

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee.” Work Order No. NRC-237. 

Neal R. Gross and Co., Inc., Court Reporters and Transcribers: Washington, DC. 

May 5, 2010.)
C-5

Figure C.1-2 Example of repair of pitting corrosion in torus

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee.” Work Order No. NRC-237. 

Neal R. Gross and Co., Inc., Court Reporters and Transcribers: Washington, DC. 

May 5, 2010.)

Figure C.1-3 Example of pitting corrosion concentrations in torus

(Source: “Official Transcript of Proceedings, Advisory Committee on Reactor 

Safeguards Plant License Renewal Subcommittee.” Work Order No. NRC-237. 

Neal R. Gross and Co., Inc., Court Reporters and Transcribers: Washington, DC. 

May 5, 2010.)

C-7

C.2 Duane Arnold Energy Center

C.2.1 Introduction

By letter dated September 30, 2008 (Ref. C.2.6.1), and supplemented by a letter dated 

January 23, 2009 (Ref. C.2.6.2), FPL Energy, Duane Arnold Center, submitted an LRA to the 

NRC for the Duane Arnold Energy Center. The results of the NRC staff‘s evaluation of the LRA 

were published in November 2010 in NUREG-1955, ―Safety Evaluation Report Related to the 

License Renewal of Duane Arnold Energy Center‖ (Ref. C.2.6.3).

C.2.2 Field Observations

Numerous areas of zinc depletion of the torus coating and minor pitting and other indications 

were identified while conducting ASME Code (Ref. C.2.6.4) Section XI, Subsection IWE,

inspections. Since 1995, over 15,000 repairs have been made to the torus coating 

(Ref. C.2.6.5). This represents about 5 percent of the underwater torus area. Only one pit had 

degradation that exceeded the maximum allowable pit depth of 1.35 mm (53 mils) (10 percent of 

13.56 mm (0.534 inch), the nominal shell thickness). That pit measured 1.42 mm (56 mils) in 

depth and 6.35 mm (0.25 inch) in diameter. The pit was dispositioned in the corrective action 

program as acceptable without repair.

Inspections performed during recent outages have not identified any coating deficiencies above 

the waterline that have required repair (Ref. C.2.6.6).

C.2.3 Design Characteristics of the Torus

The primary containment is a Mark I containment system, employing a drywell and a separate 

PSC (Ref. C.2.6.1). The drywell houses the reactor vessel, the reactor recirculation loops, and 

branch connections of the reactor coolant system that have isolation valves at the primary 

containment boundary. The PSC (torus) consists of an air volume and a suppression water 

volume. The drywell and torus are connected through a vent system that directs flow from the 

drywell into the suppression water of the torus through submerged downcomers. 

The torus shell was initially coated in 1973 and recoated in 1985. The normal life of the torus 

coating is less than 20 years (Ref. C.2.6.3). 

C.2.4 Corrective Actions for Torus Corrosion and Cracking

The ASME Code Section XI, Subsection IWE inspection procedure was revised to inspect the 

torus coating during each outage until it is recoated.

The scope of the coatings program includes inspection of the interior and exterior surfaces of 

the suppression chamber (torus), vent lines, and downcomers, and the interior and accessible 

exterior surfaces of the drywell (Ref. C.2.6.3). Inspections are performed during each refueling 

cycle. Visual inspections of the suppression chamber and drywell are conducted to note any 

evidence of deterioration (e.g., discoloration, bubbling or flaking of the coating, corrosion, or 

pitting). Qualification testing and evaluation of the Service Level I coatings used for new 

applications or repair activities inside containment are performed in accordance with American 

National Standards Institute (ANSI) N101.2, ―Protective Coatings (Paints) for Light-Water 
C-8

Nuclear Reactor Containment Facilities‖ (Ref. C.2.6.7). The coating specialist also reviews 

inspection results to determine if updates are required to the unqualified and degraded coatings 

log, and evaluates whether the quantity of unqualified and degraded coatings is acceptable. 

Corrective actions are initiated, as appropriate, based on evaluations performed by the coating 

specialists.

Photographs, inspection reports and completed checklists, records of corrective actions, and 

other followup information are maintained as quality assurance records (Ref. C.2.6.8). These 

records are available for review to support aging management during the period of extended 

operation. The torus inspection procedure requires a review of previously performed inspection 

results and documentation of current results (Ref. C.2.6.3). Furthermore, the procedure 

specifies that it should include photographs with noted deficiencies tracked by appropriate 

documentation to track resolution. Examinations of the submerged portion of the suppression 

chamber are performed by specialty contractors, and the results and repairs are documented in 

the inspection report and procedure. Additionally, the initial and final inspections are 

videotaped, with the tapes made available for review during subsequent inspections.

C.2.5 Structural Integrity Assessment and Test Results

No structural integrity assessments have been performed. Only one pit had degradation that 

exceeded the maximum allowable pit depth of 1.35 mm (0.053 inches) (10 percent of the 

13.56-mm (0.534-inch) nominal shell thickness). This pit measured 1.42 mm (0.056 inches) in 

depth and 6.35 mm (0.25 inches) in diameter. The pit was dispositioned in the corrective action 

program as acceptable without repair.

A commitment was made to completely recoat the torus interior surface below the waterline as 

well as extending it to well above any fluctuations in the water level, including the 0.61-meter

(2-foot) wide splash band at water level (Ref. C.2.6.3).

C.2.6 References

C.2.6.1 Anderson, R.L., FPL Energy-Duane Arnold Energy Center, letter to U.S. Nuclear 

Regulatory Commission, September 30, 2008.

C.2.6.2 Anderson, R.L., FPL Energy-Duane Arnold Energy Center, letter to U.S. Nuclear 

Regulatory Commission, ―Response to Issues Raised in Previous Status of License 

Renewal Application for the Duane Arnold Energy Center,‖ January 23, 2009.

C.2.6.3 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Duane Arnold Energy Center.‖ NUREG-1955. U.S. Nuclear 

Regulatory Commission: Washington, DC. November 2010. 

C.2.6.4 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.

C.2.6.5 Costanzo, C.R., NextEra Energy Duane Arnold, LLC, letter to U.S. Nuclear 

Regulatory Commission, December 14, 2009.
C-9

C.2.6.6 Costanzo, C.R., NextEra Energy Duane Arnold, LLC, letter to U.S. Nuclear 

Regulatory Commission, April 2, 2010.

C.2.6.7 American National Standards Institute, Subcommittee N101.5, American Institute of 

Chemical Engineers. ―Protective Coatings (Paints) for Light Water Nuclear Reactor 

Containment Facilities.‖ ANSI N101.2. American Institute of Chemical Engineers: 

New York, NY. 1972.

C.2.6.8 Costanzo, C.R., NextEra Energy Duane Arnold, LLC, letter to U.S. Nuclear 

Regulatory Commission, October 13, 2009.

C-11

C.3 James A. FitzPatrick Nuclear Power Plant

C.3.1 Introduction

By letter dated July 31, 2006 (Ref. C.3.6.1), Entergy Nuclear Operations, Inc., submitted an LRA 

to the NRC for renewal of the operating license for the James A. FitzPatrick Nuclear Power 

Plant. The results of the NRC staff‘s evaluation of the LRA were published in April 2008 in 

NUREG-1905, ―Safety Evaluation Report Related to the License Renewal of 

James A. FitzPatrick Nuclear Power Plant‖ (Ref. C.3.6.2).

C.3.2 Field Observations

Pitting in the wetted area of the torus shell was identified in 1998 when the torus was drained to 

replace the ECCS suction strainers (Ref. C.3.6.2). Further inspection of the torus identified 

pitting in 10 areas in 4 of the 16 torus bays. The pitting occurred at locations that had 

experienced some degradation of the original coating. The pitted areas have not been 

recoated, but they are considered as leading indicators of torus shell condition and are being 

monitored periodically with ultrasonic testing (UT) and visual inspection. 

In June 2005, a through-wall leak in the torus shell was identified. The leak was due to a 

114.3-mm (4.5-inch) crack located in the same bay as the high-pressure coolant injection 

(HPCI) steam exhaust discharge pipe. The root cause of the flaw was vibration fatigue from 

HPCI steam condensation oscillation loading. Followup torus inspections identified similar flaws 

in two other locations in the same bay. Corrective action included repair of the flaws and the 

installation of an HPCI steam exhaust sparger assembly that directs steam flow away from the 

torus shell. The addition of the sparger significantly reduced steam condensation oscillation 

loads on the torus shell.

C.3.3 Design Characteristics of the Torus

The reactor building totally encloses the primary containment, the refueling and reactor 

servicing areas, the new and spent fuel storage facilities, and other reactor auxiliary systems 

(Ref. C.3.6.1). It serves as containment during reactor refueling and maintenance operations 

when the primary containment is open, and as an additional barrier when the primary 

containment is functional. The primary containment is a Mark I pressure-suppression 

containment housing the reactor vessel, the reactor recirculation loops, and other branch 

connections of the reactor coolant system. Major components of primary containment include a 

drywell, a PSC, and the connecting vent system between the drywell and torus. The torus is a 

carbon steel pressure vessel anchored to and supported by the reinforced concrete foundation 

slab of the reactor building. 

C.3.4 Corrective Actions for Torus Corrosion and Cracking

The interior torus suppression pool areas above and below the waterline were inspected in 

accordance with the ASME Code (Ref. C.3.6.3) Section XI, Subsection IWE, program during 

RFOs. A general visual examination was performed of the area above the waterline. Below the 

waterline is normally inaccessible unless the torus water level is lowered or drained for a work 

activity. The torus was last drained and cleaned in 1998 for the installation of the ECCS

strainers. The visual examination identified nine of the most severe areas of pitting. The depths 

of the pits were measured at that time and a portion of these areas are monitored and 
C-12

measured by means of UT from the outside of the torus shell every outage. Over a 5-year 

period, all nine of the pitted areas examined by performing UT were found to be acceptable in 

accordance with the ASME Code requirements.

The through-wall leak in the torus was repaired in July 2005. The root-cause analysis 

determined that condensation oscillation from the HPCI turbine steam discharge provided the 

energy that initiated cracking. Subsequently, UT was performed at this location. In RFO 17, a 

visual examination was scheduled to investigate the extent of the condition. Two cracks were 

noted near where the HPCI discharge line had been modified with a sparger assembly designed 

to eliminate condensation oscillation.

C.3.5 Structural Integrity Assessment and Test Results 

The torus preservation program verifies that sample locations are tracked for wall thinning. The 

reports are entered into a nondestructive examination database and are used for tracking to 

assure that adequate wall thickness is maintained. In 2004, during RFO 16, the thickness 

examinations were made of the nine pitted locations identified during the 1996 ASME Code 

Section XI, Subsection IWE examination (two at bay B, two at bay H, two at bay K, and three at 

bay O around the torus). Of the areas sampled, only three locations had pit depths that 

exceeded the design thickness.

C.3.6 References

C.3.6.1 Dietrich, P., Entergy Nuclear Operations, Inc., letter to U.S. Nuclear Regulatory 

Commission, July 31, 2006.

C.3.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of James A. FitzPatrick Nuclear Power Plant.‖ NUREG-1905.

U.S. Nuclear Regulatory Commission: Washington, DC. April 2008.

C.3.6.3 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers. New York, NY. 2007.
C-13

C.4 Hope Creek Generating Station, Unit 1

C.4.1 Introduction

On August 18, 2009, PSEG Nuclear, LLC, submitted an LRA to the NRC for renewal of the 

Hope Creek Generating Station (Ref. C.4.6.1). The results of the NRC staff‘s evaluation of the 

LRA were published in June 2011 in NUREG-2102, ―Safety Evaluation Report Related to the 

License Renewal of Hope Creek Nuclear Generating Station‖ (Ref. C.4.6.2).

C.4.2 Field Observations

In 2004, the torus shell and interior coatings were inspected by divers performing underwater 

ASME Code (Ref. C.4.6.3) Section XI, Subsection IWE program inspections (Ref. C.4.6.2). 

There were 16 areas with metal loss reported as ranging up to 0.753 mm (30 mils), and 

99.99 percent of the coating was found to be smooth and tightly adhered to the base metal with 

no significant defects. The identified coating deficiencies were primarily small, localized areas 

of mechanical or impact damage. Other than minor general corrosion of the exposed surfaces, 

there was no damage to the base metal. The loss of material thickness of the torus at the 

16 local areas did not exceed 10 percent of the nominal plate thickness of the torus shell

(i.e., 25.4 mm (1 inch) nominal plate thickness). These areas were cleaned and recoated in the 

subsequent outage. Re-inspection of these areas will be performed during future ASME Code 

Section XI, Subsection IWE, program underwater inspections.

C.4.3 Design Characteristics of the Torus

The primary containment is a Mark I design and consists of a drywell, a PSC, and a vent system 

connecting the drywell and the PSC (Ref. C.4.6.1). The PSC, or torus, is a toroidal-shaped 

steel pressure vessel encircling the base of the drywell that is partially filled with demineralized 

water and includes internal steel framing and access hatches. The PSC is mounted on support 

structures that transmit loads to the reactor building foundation. Major components inside the 

PSC include ECCS suction strainers, the PSC (torus) spray header, the vent line header and 

downcomers, and T-quenchers.

C.4.4 Corrective Actions for Torus Corrosion and Cracking

Affected areas were cleaned and the underwater coating was repaired. The Service Level I

Amercoat®90 coating system is managed in accordance with GALL AMP XI.S8, ―Protective 

Coating Monitoring and Maintenance Program‖ (Ref. C.4.6.4). Underwater inspections are 

performed under the ASME Code Section XI, Subsection IWE, program (Ref. C.4.6.3).

Although the condition of the penetration and downcomer support base metal was acceptable, 

the inside of a number of penetrations and 32 downcomers supports were recoated to prevent 

further degradation (Ref. C.4.6.1).

C.4.5 Structural Integrity Assessment and Test Results

No structural integrity assessment of the torus was performed. Evaluation of the loss of material 

determined that it was acceptable because the reduction in torus shell thickness had not 
C-14

exceeded 10 percent of the nominal plate thickness and was under the 3.175-mm (125-mils) 

torus corrosion allowance included in the design of the torus shell. 

C.4.6 References

C.4.6.1 Fricker, C.J., PSEG Nuclear, LLC, letter to U.S. Nuclear Regulatory Commission, 

August 18, 2009.

C.4.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Hope Creek Generating Station.‖ NUREG-2102. U.S. Nuclear 

Regulatory Commission. Washington, DC. June 2011.

C.4.6.3 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers. New York, NY. 2007.

C.4.6.4 U.S. Nuclear Regulatory Commission. ―Protective Coating Monitoring and 

Maintenance Program.‖ GALL AMP XI.S8 in ―Generic Aging Lessons Learned 

(GALL) Report.‖ NUREG-1801. U.S. Nuclear Regulatory Commission: Washington, 

DC, July 2001.
C-15

C.5 Nine Mile Point Nuclear Station, Unit 1

C.5.1 Introduction

By letter dated May 26, 2004 (Ref. C.5.6.1), Constellation Energy Group, LLC, submitted an

LRA to the NRC for renewal of the operating licenses for Nine Mile Point Nuclear Station (Nine 

Mile Point), Units 1 and 2. Constellation Energy Group, LLC, submitted an amended LRA to the 

NRC on July 14, 2005 (Ref. C.5.6.2). The results of the NRC staff‘s evaluation of the LRA were 

published in September 2006 in NUREG-1900, ―Safety Evaluation Report Related to the 

License Renewal of Nine Mile Point Nuclear Station, Units 1 and 2‖ (Ref. C.5.6.3).

C.5.2 Field Observations

Torus wall thinning was observed in Unit 1 in the late 1980s following an extended plant 

shutdown. The wall thinning was attributed to the layup conditions inside the torus during the 

extended shutdown (Ref. C.5.6.1).

An inspection report in 2001, referenced in Ref. C.5.6.4, noted that photo documentation from 

previous torus entries indicated that the waterline region may potentially exhibit generalized, 

nonspecific corrosion, and that supplemental examinations will be performed from the outside 

surface of the torus by taking ultrasonic thickness measurements of the torus shell plates at the 

waterline region to determine the general torus shell thickness and if minimum wall thickness 

requirements have been violated by corrosion. Of the 360 readings taken, the lowest recorded 

point (pit depth) was 1.11 mm (44 mils) in bay 3-I at location B6. Since the allowable minimum 

wall thickness was 10.08 mm (0.397 inches) at this location, the recorded readings were found 

to be acceptable.

C.5.3 Design Characteristics of the Torus

The primary containment is a Mark I design that consists of a drywell, a suppression chamber in 

the shape of a torus, and a connecting vent system between the drywell and the suppression 

chamber (Ref. C.5.6.3). The torus is a freestanding carbon steel pressure vessel that consists 

of 20 pipe-shaped segments or bays that are mitered and welded together. The diameter of the 

pipe-shaped segments is 8.23 meters and the total length of the torus is 112 meters. Carbon 

steel plates having a nominal thickness of 11.7 mm, including a corrosion allowance of 1.6 mm,

were used to fabricate the torus shell (Ref. C.5.6.5). Most areas on the outside surface of the 

torus are accessible for visual inspection, but the surface is coated to prevent corrosion. 

Structural support is provided by a series of steel columns that are welded to the torus shell and 

rest on a concrete floor slab. Four columns are provided in every other bay; two on the outer 

side and two on the inner side of the torus. The inside of the torus is partially filled with 

demineralized water, and all surfaces above and below the water line are not coated. The 

bottom surface of the torus is about 450 mm above the concrete floor. A concrete biological 

shield wall surrounds the torus, creating an enclosure called the torus room.

C.5.4 Corrective Actions for Torus Corrosion and Cracking

The Torus Corrosion Monitoring Program is credited for managing the aging of the Nine Mile 

Point Unit 1 suppression chamber (torus) (Ref. C.5.6.3). Nine Mile Point Unit 1 is required to 

monitor the torus wall thickness and corrosion rate in order to establish reasonable assurance 
C-16

that the minimum wall thickness is not reached. The effects of loss of material on the intended

function(s) of the torus shell are managed in accordance with 10 CFR 54.21(c)(1)(iii).

C.5.5 Structural Integrity Assessment and Test Results

The torus corrosion-monitoring program determines by inspections, measurements, and 

analyses (Refs. C.5.6.2 and C.5.6.3) the (1) torus shell thickness through UT, (2) corrosion rate 

through material coupons, and (3) corrosion condition of the accessible external surfaces of the 

torus support structure through visual inspections (Refs. C.5.6.1, C.5.6.2, and C.5.6.3).

Torus wall UT measurements are obtained at approximately 6-month intervals over a predefined 

grid system, and corrosion sample coupons are analyzed during each RFO. Corrosion rates 

are determined through analysis of both data sets, with the most conservative corrosion rate for 

a particular torus bay used to evaluate aging of the structure. The UT results and corrosion 

data are trended for future reference. Visual inspection findings for the external support 

structure are compared to previous inspection results. Monitoring in this manner ensures that

the torus shell material will not be reduced to less than the minimum required wall thickness, 

and that any degradation is detected before there is a loss of intended function. The torus 

corrosion-monitoring program is adjusted continually to account for industry experience and 

research. Inspection reports indicate no significant changes in the torus wall corrosion rate 

(Ref. C.5.6.3).

C.5.6 References

C.5.6.1 Spina, J.A., Constellation Energy, letter to U.S. Nuclear Regulatory Commission, 

May 26, 2004.

C.5.6.2 Spina, J.A., Constellation Energy, letter to U.S. Nuclear Regulatory Commission, 

July 14, 2005.

C.5.6.3 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Nine Mile Point Nuclear Station, Units 1 and 2.‖ NUREG-1900,

Volumes 1 and 2. U.S. Nuclear Regulatory Commission: Washington, DC. 

September 2006.

C.5.6.4 Montgomery, B.S., Constellation Energy, letter to U.S. Nuclear Regulatory 

Commission, July 23, 2003.

C.5.6.5 Chicago Bridge and Iron Company Manufacturers Data Report for Nuclear Vessels.

Form N-1, Vessel No. G-1293. Chicago Bridge and Iron Company: Greenville, PA.

1965.
C-17

C.6 Oyster Creek Nuclear Generating Station

C.6.1 Introduction

By letter dated July 22, 2005 (Ref. C.6.6.1), AmerGen Energy Company, LLC, submitted an

LRA to the NRC for the Oyster Creek Nuclear Generating Station. The results of the NRC 

staff‘s evaluation of the LRA were published in April 2007 in NUREG-1875, ―Safety Evaluation 

Report Related to the License Renewal of Oyster Creek Generating Station‖ (Ref. C.6.6.2).

C.6.2 Field Observations

Pitting corrosion less than or equal to 1.02 mm (40 mils) was not repaired during the 1984 torus 

repair and recoating effort because, based on available margins, it was found to be acceptable 

without any size restriction and satisfied minimum uniform thickness requirements. 

Inspection of the immersed coating in 2002 found blistering that was primarily in the shell invert, 

but also on the upper shell near the waterline (Ref. C.6.6.2). The majority of the blisters 

remained intact and continued to protect the base metal. However, in several areas there was 

pitting damage where the blisters had fractured. In addition to blistering, random blemishes that 

exposed the base metal were identified in the torus immersion region coating (e.g., minor 

mechanical damage) during the torus coating inspections. They ranged in size from 1.59 

to 12.7 mm (0.0625 to 0.5 inches) in diameter. Pitting in these areas was qualitatively 

evaluated. Pit spreads ranged from less than 0.254 mm (10 mils) to slightly more than 1.02 mm 

(40 mils) in a few isolated cases. Quantitative pit depth measurements were taken in several 

locations in the immersion area of bay 1. Pit depths at these sites ranged from 0.23 to 1.07 mm 

(8 to 42 mils) and were judged to be representative of typical conditions found on the shell. 

Prior to the 2002 inspection, four pits greater than 1.02 mm (40 mils) were identified. The pit 

depths were 1.47 mm (58 mils) (one pit in 1988), 1.27 mm (50 mils) (two pits in 1991), and 

1.74 mm (69 mils) (one pit in 1992). The pits were evaluated against the local pit depth 

acceptance criteria and found acceptable. The fractured blisters were repaired to reestablish 

the protective coating barrier. The following areas have been mapped for trending and analysis 

during future inspections: one pit of 1.07 mm (42 mils) in bay 1; one pit of 1.74 mm (69 mils) in 

bay 2; two pits of 1.27 mm (50 mils) in bay 6; and one pit of 1.47 mm (58 mils) in bay 10. Shell 

thicknesses were evaluated against code requirements and found to satisfy all design- and 

licensing-basis requirements.

Recent inspections indicate that the average torus shell thickness remains at 9.78 mm 

(0.385 inches). Based on inspections performed through 1993, it was concluded that the torus 

shell thickness has remained virtually unchanged following the repair and recoating efforts 

performed in 1984. 

C.6.3 Design Characteristics of the Torus

The primary containment structure comprises the primary containment, containment 

penetrations, and internal structures (Ref. C.6.6.1). The primary containment is a Mark I design 

that consists of a drywell, a PSC, and a vent system connecting the drywell and the suppression 

chamber. The reactor building encloses the containment and provides secondary containment, 
C-18

structural support, shielding, and shelter to the containment, as well as protection for 

components housed within against external design-basis events.

 

The as-built torus wall thickness, as discussed above, is 9.78 mm (0.385 inches). The 

suppression chamber (torus) and vent system were originally coated with Carboline®

Carbo-Zinc 11 paint.

The vent system consists of 10 circular vent lines, which form a connection between the drywell 

and the PSC. The lines enter the suppression chamber through penetrations provided with 

expansion bellows and join into a common header contained within the air space of the 

suppression chamber. The header discharge is through 120 downcomer pipes, which terminate 

below the water level in the torus. The header and the downcomer pipes are supported from 

the suppression chamber shell.

C.6.4 Corrective Actions for Torus Corrosion and Cracking

Inspection of the suppression chamber and vent system coatings is done by divers every other 

RFO and for all 20 torus bays during the period of extended operation. The coatings are 

monitored for cracks, sags, runs, flaking, blisters, bubbles, and other defects. The protective 

coating monitoring and maintenance and ASME Code (Ref. C.6.6.3) Section XI, 

Subsection IWE, programs are credited to manage loss of material due to corrosion for the 

period of extended operation.

To date, pit depths have been found to be acceptable. Only fractured blisters have been 

repaired. Therefore, the integrity of the torus shell has been verified to have adequate shell 

thickness margins to ensure that design- and licensing-basis requirements can be maintained.

C.6.5 Structural Integrity Assessment and Test Results

Acceptance criteria for pits are based on engineering analysis that uses the method of ASME 

Code Case N-597 (Ref. C.6.6.4) as guidance for the calculation of pit depths that will not violate 

the local stress requirements of either ASME Code Section III, 1977 Edition, or Section VIII, 

1962 Edition (Ref. C.6.6.2). The acceptance criteria for pit depth note that isolated pits of 

3.175 mm (0.125 inches) in diameter have an allowable maximum depth of 6.63 mm 

(0.261 inches) anywhere in the shell provided the center-to-center distance between the subject 

pit and neighboring isolated pits or areas of pitting corrosion is greater than 508 mm 

(20.0 inches). This criterion includes old pits or old areas of pitting corrosion that have been 

filled or recoated. Multiple pits that can be encompassed by a 63.5-mm (2.5 inches) diameter 

circle shall be limited to a maximum pit depth of 3.58 mm (0.141 inches) provided the 

center-to-center distance between the subject pitted area and neighboring isolated pits or areas 

of pitting corrosion is greater than 508 mm (20.0 inches). This criterion also includes old pits or 

old areas of pitting corrosion that have been filled or recoated.

C.6.6 References

C.6.6.1 Swenson, C.N., AmerGen Energy Company, LLC, letter to U.S. Nuclear Regulatory 

Commission, July 22, 2005.
C-19

C.6.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Oyster Creek Generating Station.‖ NUREG-1875, Volumes 1 

and 2. U.S. Nuclear Regulatory Commission: Washington, DC. April 2007.

C.6.6.3 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.

C.6.6.4 — — —. ―Requirements for Analytical Evaluation of Pipe Wall Thinning.‖ ASME 

Code Case N-597. American Society of Mechanical Engineers: New York, NY. 

November 18, 2003.

C-21

C.7 Pilgrim Nuclear Power Station

C.7.1 Introduction

By letter dated January 25, 2006 (Ref. C.7.6.1), Entergy Nuclear Operations, Inc., submitted an

LRA to the NRC for the Pilgrim Nuclear Power Station. The results of the NRC staff‘s 

evaluation of the LRA were published in November 2007 in NUREG-1891, ―Safety Evaluation 

Report Related to the License Renewal of Pilgrim Nuclear Power Station‖ (Ref. C.7.6.2).

C.7.2 Field Observations

In 1999, the submerged regions of all 16 torus bays as well as the drywell to torus vent areas 

with water accumulation were inspected (Ref. C.7.6.1). The results revealed areas of defects 

such as depleted zinc, localized pitting corrosion, and minor surface rusting. Degraded areas 

were recoated to prevent further corrosion and were reexamined.

During RFO 14 in April 2003, ultrasonic thickness examination of the torus shell resulted in 

several measurements that were below the nominal wall thickness of 16 mm (0.629 inches) 

(Ref. C.7.6.1). As the measurements were all greater than the minimum allowable thickness of 

14.3 mm (0.563 inches), no further actions were taken.

C.7.3 Design Characteristics of the Torus

The primary containment is a Mark I containment consisting of a drywell (which encloses the 

reactor vessel and the recirculation system), a PSC, and a connecting vent system 

(Ref. C.7.6.1). 

C.7.4 Corrective Actions for Torus Corrosion

The torus is inspected under the ASME Code (Ref. C.7.6.3) Section XI, Subsection IWE,

program. Degraded areas identified in 1999 were recoated. Ultrasonic measurements in 

April 2003 identified areas below nominal wall thickness, but the areas were all greater than the 

minimum allowable thickness, so no further action was taken.

C.7.5 Structural Integrity Assessment and Test Results

Containment inservice inspection examinations continue to monitor the thickness of the torus 

shell. In April 2003, the results of the containment inservice inspection general visual walkdown 

of the primary containment during RFO 14 (April 2003) were compared to those of the previous 

inspection (Ref. C.7.6.1). The only new indication was in the control rod drive penetration area

where there was some surface corrosion, but not of significance. The control rod drive was 

found to be structurally acceptable. No significant corrosion was found in other areas. 

C.7.6 References

C.7.6.1 Balduzzi, M.A., Entergy Nuclear Operations, Inc., letter to U.S. Nuclear Regulatory 

Commission, January 25, 2006.
C-22

C.7.6.2 U.S. Nuclear Regulatory Commission. ―Safety Evaluation Report Related to the 

License Renewal of Pilgrim Nuclear Power Station.‖ NUREG-1891. U.S. Nuclear 

Regulatory Commission: Washington, DC. November 2007.

C.7.6.3 American Society of Mechanical Engineers. ―ASME Boiler and Pressure Vessel 

Code.‖ American Society of Mechanical Engineers: New York, NY. 2007.



UNITED STATES 

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

--------------------

OFFICIAL BUSINESS
NUREG/CR-7111 A Summary of Aging Effects and Their Management in Reactor Spent Fuel 

Pools, Refueling Cavities, Tori, and Safety-Related Concrete Structures