NUREG/CR-6876

BNL-NUREG-74000-2005

Risk-Informed Assessment of

Degraded Buried Piping Systems in

Nuclear Power Plants

Brookhaven National Laboratory

U.S. Nuclear Regulatory Commission

Office of Nuclear Regulatory Research

Washington, DC 20555-0001
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NUREG/CR-6876

BNL-NUREG-74000-2005

Risk-Informed Assessment of

Degraded Buried Piping Systems in

Nuclear Power Plants

Manuscript Completed: April 2005

Date Published: June 2005

Prepared by

J. I. Braverman, G. DeGrassi, G. Martinez-Guridi

R J. Morante, C. H. Hofmayer

Brookhaven National Laboratory

Upton, NY 11973-5000

T. Y. Chang, NRC Project Manager

Prepared for

Division of Engineering Technology

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

NRC Job Code W6684
ABSTRACT

This report describes the research performed to assess the effects of age-related degradation of

buried piping at nuclear power plants (NPPs). The evaluation of buried piping was conducted in

order to develop analytical methods and degradation acceptance criteria (DAC) that can be

used to assess the condition of degraded buried piping. The research focused on a riskinformed approach to evaluate the most common aging effects in buried piping consisting of

general wall thinning and localized loss of materialpitting. The effects of degradation over time

were included in the methodology developed to assess buried piping.

To achieve the goals of this research effort, fragility modeling procedures for degraded buried

piping have been developed and the effect of degradation on fragility and plant risk has been

determined. The measure used for plant risk was based on the change in core damage

frequency (ACDF) due to internal events during full power operation. The analytical approach

provides the technical basis for evaluating the structural adequacy of degraded buried piping

and for developing guidelines for assessing the effect of degraded conditions on plant risk.

The results of this research demonstrate that, for a buried pipe meeting the conditions of the

DAC, a pipe thickness loss less than approximately 45% of the original nominal pipe wall

thickness, identified at the time of inspection, is not expected to have an immediate significant

effect on plant risk. The effects of degradation over time were considered in developing the DAC

in a manner that provides the number of years required for the buried pipe to reach a

degradation level that would potentially have a significant effect on plant risk. The types of

buried piping systems, configurations, materials, applicable pipe loads (e.g., pressure,

surcharge, live load, etc.) and other conditions that must be satisfied to use the DAC have been

developed and presented in this report. The results obtained are based on the service

conditions that buried piping is designed for (e.g., pressure induced stresses less than % of the

minimum ultimate strength of the material and relatively low temperatures) and recognizing that

seismic induced stresses in buried piping are self-limiting since deformations or strains are

limited by seismic motion of the surrounding media. In addition, the DAC were developed from

probabilistic risk assessments which accounted for the contribution to risk of the postulated

degradation of buried piping systems at NPPs. It should be noted that even if a degraded buried

pipe meets the DAC, it is expected that the licensee will evaluate the conditions that led to the

degradation and may need to repair the degraded pipe based on the evaluation findings, the

level of degradation, and the plant's current licensing basis.

The methodology and degradation acceptance criteria (DAC) developed in this report are

intended to provide guidance to the NRC staff for making an assessment in a timely manner

whether degraded conditions, identified at a plant site, potentially have an immediate significant

effect on plant risk. This knowledge is important in order to provide input that can help

determine whether immediate repairs are warranted, or whether the appropriate investigation,

inspection, aging management, or other actions can be determined in the normal course of

evaluating the condition. The methodology and DAC can not be used by the industry as a

design tool to justify existing degraded conditions; licensees are still required to meet their

commitments regarding their current licensing basis.

iii
FOREWORD

This report documents a risk-informed assessment of degraded buried piping systems

in nuclear power plants. This study is part of a research program initiated by the U.S. Nuclear

Regulatory Commission (NRC) and carried out by the Brookhaven National Laboratory,

to assess the effect of age-related degradation on structures and passive components

in nuclear power plants.

This study included all buried piping systems within the scope of the Maintenance Rule and

the License Renewal Rule, as set forth in Title 10, Section 50.65 and Part 54, of the Code of

Federal Regulations (10 CFR 50.65 and 10 CFR Part 54), respectively. As such, the study

evaluated the most common aging effects observed in buried piping, namely general wall thinning

and localized loss of materialpitting. Toward that end, the researchers performed three major

tasks to develop (1) a methodology to assess pipe fragility (the failure probability of buried piping

as a result of various input loads), (2) a time-dependent methodology to assess the effect

of degraded buried piping on plant risk, and (3) degradation acceptance criteria (DAC) for buried

piping.

The methodologies developed in this study can be used to derive risk insights concerning

the impact of wall thinning in buried piping. However, appropriate use of these methodologies

requires a justifiable estimate of the pipe wall degradation rate. Consequently, this report

discusses degradation rates and provides representative values. Nonetheless, users of

these methodologies should present acceptable justification that the degradation rate used

in a given assessment is appropriate for the particular piping evaluated.

Moreover, risk-informed decision-making requires additional risk insights concerning the impact

of wall thinning in buried piping on large early release frequency (LERF). Although this report

does not directly address LERF, it does provide a method to assess the risk-significance related

to core damage frequency (CDF). Users can extend that method to evaluate the risksignificance related to LERF.

In addition, it is important to note that when a degraded condition is identified in a given pipe,

it is often not immediately known whether that pipe complies with the licensing basis or whether

it has a significant effect on plant risk, and it may take time for the licensee to evaluate

the degraded condition. In such instances, the methodologies presented in this report provide

tools to help the NRC staff make a quick, independent assessment to determine whether

the identified degradation has the potential for an immediate, significant effect on plant risk.

Nonetheless, licensees cannot and shall not use the methodologies discussed in this report

to justify exemptions to current regulations or to request changes to a plant's licensing basis.

Carl J. Paperiello, Director I

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

v
CONTENTS

Page

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

Foreword.................................................................................................................v

Executive Summary ............. xi

Acknowledgements................................................................................................. xv

1 Introduction ......... ; . 1

1.1 Background ..

1.2 Objective. ...... '. . . 1

1.3 Scope . . ' ..... ; 2,

1.4 Approach ..... 2

2 Buried Piping Systems at Nuclear-Power Plants .. . 5

2.1 Types of Buried Piping Systems ;;5...

'2.2 Material and Design Parameters .5

2.3 Analysis and Design of Buried Piping ............................................. ;.7

3' Aging Mechanisms and Consequential Degradation Effects ......................... 25

3.1 Potential Aging Mechanisms and Effects .25

3.2 Operating'Experience .29

3.3 Important Important Aging Aging Effects Effects for for Use Use in in this Study. 32

3.4 Degradation Rates For Corrosion and Localized

Loss of MateriaVPitting ............... 32

4 Detection'of Age-Related Degradation and Condition Assessment .. 41

4.1 Inspection Methods .......................... - 41

4.2 Regulatory Requirements and Technical Guidance ......................... 44

4.3 Industry Programs to Manage Aging .46

5 Fragility Evaluation of Degraded Buried Piping Systems . .49

5.1 Governing Load(s) forRisk-Informed Study .49

5.2 Methodology for Developing Buried Piping Fragility . 64

5.3 Fragility Curves for Undegraded and Degraded Buried Piping . 75

6 Risk Evaluation of Degraded Buried Piping Systems . . .97

6.1 Selection of Plants ...................... 98

6.2 Defin'ing'Acceptable"Risk ' .. ;:;.; ....................... 99

6.3 Considerations for Developing Methods for Estimating the Risk of

Buried Piping .......... ;. . . . . . . . . 102

6.4 Derivation of the Conditional Probability of Failure of a Buried Pipe.. 105

6.5 'A System is Normally Operating and Its Failure Causes an

Initiating Event... 108

6.6 'A-System'is Normally in Standby and Its Failure Does Not Cause

an Initiating Event ............-.-. '..:. 110

.. . ;. , . -. ... :,,, 

7 Degradatio'n Acceptance Criteria ......... ............................ 117

7.1 Calculation of Acceptable Wall Loss.. 117

7.2 Development of Degradation Acceptance Criteria .124

7.3 Guidance on the Use of Degradation Acceptance Criteria. 128

:i vii
8 Conclusions and Recommendations ..................................... 145

8.1 Conclusions .................................................... 145

8.2 Recommendations .................................................... 149

9 References ................................................... 153

Figures

5.1 Probability Density Function for SA-106 Grade B Tensile Strength ............... 78

5.2 Cumulative Distribution Function for SA-1 06 Grade B Tensile Strength ........ 78

5.3 Fragility Curve for SA-1 06 Carbon Steel Pipe as a Function of

Hoop Stress .79

5.4a Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-1 06 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss 79

5.4b Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss 80

5.5 Probability of Failure for a 30 in. (76.2 cm) Standard Wall SA-1 06 Carbon

Steel Pipe Under Design Pressure vs. Wall Loss .80

5.6a Probability Density Function for Failure Pressure of a 30 in. (76.2 cm)

Standard Wall SA-1 06 Gr. B Pipe - Analysis vs. Test Comparison

(40-60% Wall Loss) .81

5.6b Probability Density Function for Failure Pressure of a 30 in. (76.2 cm)

Standard Wall SA-1 06 Gr. B Pipe - Analysis vs. Test Comparison

(60-80% Wall Loss) .81

5.6c Probability Density Function for Failure Pressure of a 30 in. (76.2 cm)

Standard Wall SA-1 06 Gr. B Pipe - Analysis vs. Test Comparison

(80-100% Wall Loss) .............. . . ...................................... 82

5.7a Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe as

a Function of Internal Pressure - Analysis vs. Test Comparison

(40-60% Wall Loss) ............ 82

5.7b Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe as

a Function of Internal Pressure - Analysis vs. Test Comparison

(60-80% Wall Loss) ............ 83

5.7c Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-1 06 Gr. B Pipe as

a Function of Internal Pressure - Analysis vs. Test Comparison

(80-100% Wall Loss) ............. 83

5.8 Probability Density Function for SA-106 Gr. B Pipe Tensile Strength

Sensitivity Study Cases 1 through 4 ...................................................... 84

5.9a Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe

with 50% Wall Loss Sensitivity Study Cases 1 through 4 .............................. 84

5.9b Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe

with 75% Wall Loss Sensitivity Study Cases 1 through4 ............................... 85

5.9c Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe

with 80% Wall Loss Sensitivity Study Cases 1 through 4 ............................... 85

5.1 Oa Fragility Curves for a 2 in. (5.08 cm) Standard Wall SA-106 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 86

5.1Ob Fragility Curves for a 4 in. (10.2 cm) Standard Wall SA-106 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 86

5.1Oc Fragility Curves for an 8 in. (20.3 cm) Standard Wall SA-106 Carbon Steel

viii

III
Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 87

5.10d Fragility Curves for a 16 in. (40.6 cm) Standard Wall SA-106 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 87

5.1Oe Fragility Curves for a 24 in. (61.0 cm) Standard Wall SA-106 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss.... 88

5.1 of Fragility Curves for a 42 in. (107 cm) Diameter x .562 in. (1.43 cm) Wall,

SA-106 Carbon Steel Pipe as a Function of Internal Pressure with Varying

Levels of Wall Loss ............ 88

5.11 a Fragility Curves for a 2 in. (5.08 cm) Standard Wall SA-1 06 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 89

5.11 b Fragility Curves for a 4 in. (10.2 cm) Standard Wall SA-1 06 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 89

5.11 c Fragility Curves for an 8 in. (20.3 cm) Standard Wall SA-1 06 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 90

5.11 d Fragility Curves for a 16 in. (40.6 cm) Standard Wall SA-1 06 Carbon Steel

Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss .... 90

5.11 e Fragility Curves for a 24 in. (61.0 cm) Standard Wall SA-1 06 Carbon Steel Pipe

as a Function of Internal Pressure with Varying Levels of Wall Loss ............ 91

5.11f Fragility Curves for a 42 in. (107 cm) Diameter x .562 in. (1.43 cm) Wall

SA-106 Carbon Steel Pipe as a Function of Internal Pressure with Varying

Levels of Wall Loss .91

5.12a Probability of Failure for a 2 in. (5.08 cm) Standard Wall SA-106 Carbon

Steel Pipe Under Design Pressure vs. Wall Loss .92

5.12b Probability of Failure for a 4 in. (10.2 cm) Standard Wall SA-1 06 Carbon

Steel Pipe Under Design Pressure vs. Wall Loss .92

5.12c Probability of Failure for an 8 in. (20.3 cm) Standard Wall SA-106 Carbon

Steel Pipe Under Design Pressure vs. Wall Loss .93

5.12d Probability of Failure for a 16 in. (40.6 cm) Standard Wall SA-1 06 Carbon

Steel Pipe Under Design Pressure vs. Wall Loss .93

5.12e Probability of Failure for a 24 in. (61.0 cm) Standard Wall SA-1 06 Carbon

Steel Pipe Under Design Pressure vs. Wall Loss .94

5.12f Probability of Failure for a 42 in. (107 cm) Diameter x .562 in. (1.43 cm)

Wall SA-106 Carbon Steel Pipe Under Design Pressure vs. Wall Loss ........ 94

5.13 Probability of Failure for SA-1 06 Carbon Steel Pipe Under Design

Pressure vs. Wall Loss - All Sizes ................................................... 95

6.1 Relevant Events From the Start of Life of a Buried Pipe ............................... 113

6.2 Roadmap for Selection of the Method to be Used for Each Type of

System ................................................... 113

Tables

2.1 Buried Piping Systems at Nuclear Power Plants - WRC Bulletin

446 Survey ................................................ 10

2.2 Buried Piping Systems at Nuclear Power Plants Based on Twelve

LRAs Reviewed ................................................ 12

2.3 Nuclear Power Plants with Buried Piping ................................................ 21

2.4 Buried Piping Material and Design Parameters ............................................ 23

3.1 Degradation Mechanisms of Buried Commodities ........................................ 34

ix
- L

3.2 NUREG-1801 Generic Aging Lessons Learned (GALL) Report, April

2001, Information Contained in GALL Related to Buried Piping .................... 35

3.3 Buried Piping Aging Mechanisms and Aging Effects ..................................... 39

6.1 Buried Piping Systems and Descriptions of Twelve NPPs That Submitted

Their License Renewal Application .114

6.2 Conditional Core Damage Probabilities Used in the Methodology for

Category 1 Buried Piping Systems .115

6.3 Conditional Core Damage Frequencies Used in the Methodology for

Category 2.2.a Buried Piping Systems .116

7.1 Sample Calculation of Percentage Wall Loss Criteria For Design Pressure

Loading of Category I Buried Piping Systems ................................... 133

7.2 Sample Calculation of Percentage Wall Loss Criteria For Design Pressure

Loading of Category 2.2.a Buried Piping Systems .135

7.3 Degradation Acceptance Criteria Providing the Number of Years That

Would Potentially Have a Significant Effect on Plant Risk .137

7.4 Applicable Buried Piping Systems for Use of Degradation Acceptance

Criteria .141

7.5 Risk-informed Degradation Acceptance Criteria Summary For

Buried Piping Systems at NPPs .142

x

III
- -

:. :~ EXECUTIVE SUMMARY -- ;

As U.S. nuclear power plants (NPPs) continue to operate, aging of plant structures, systems, and components is becoming an important area that needs to be understood in order to maintain and continue the safe operation of the plants. To address issues related to. degradation, the NRC sponsored a number of studies in the past, many of which focused on active components. Age-related degradation of active components can usually be managed by monitoring their performance parameters such as pressure, temperature, or electrical signal. Age-related degradation of structures and passive components, however, in most cases cannot be managed in a similar way. Therefore, the NRC sponsored studies to assess the effects of age-related degradation on structures and passive components.

One of these studies, reported in NUREG/CR-6679, included a scoping study of all structures and passive components found at U.S. NPPs.The purpose of this scoping study was to identify which structures and passive components warrant more detailed assessment in subsequent phases of the research study. Five structures and passive components were identified in the scoping study: concrete members, buried piping, steel tanks, anchorages, and masonry walls. The evaluation of age-related degradation of'concrete members was completed and reported in NUREG/CR-6715. The assessment of buried piping followed and is presented in this report.:

The purpose of the study described in this report was to develop analytical methods and risk- informed degradation acceptance criteria that could be used to assess the risk significance of degraded conditions of buried piping at NPPs. The methodology developed for this study relied on performing fragility analyses of buried piping at various levels of degradation and then evaluating the effect of the buried piping'degradation on plant risk.

Section 1 of the report discusses the background of aging degradation of structures-and passive components found in' NPPs and presents the objective of the research study. Then this section explains the scope of the; study by des6ribing the types of buried piping systems,- aging effects, loadings, and material types included. This section also outlines the major steps in the development of the analytical approach and the degradation acceptance criteria (DAC) for

degraded buried piping. -

Section 2 specifically identifies the buried piping systems found at NPPs and the common material and design parameters applicable to buried piping. Much of this information was based on a survey of buried piping reported in a Welding Research Council Bulletin, submittals of license renewal applications, and referenced documents developed by the Electric Power Research Institute. Section 2 also discusses the codes and analysis methods that are available and that have been used in the nuclear industry. More detailed descriptions including the equations'used to analyze and design buried piping is-presented later in Section 5.

Section 3 discusses the various aging mechanisms and resulting aging effects that may develop in buried piping. Aging mechanisms such as general corrosion, pitting corrosion, crevice corrosion, galvanic corrosion, selective leaching, microbiologically influenced corrosion, fouling/biofouling, erosion, and cavitation'are described. These aging mechanisms primarily result into two types of aging effects, general wall thinning and localized loss of material/ pitting. This section also describes the operating experience of buried piping by reviewing NRC generic correspondences, information reported in license renewal applications, and other documents. -

Section 4 addresses inspection methods that are used to examine the conditions of buried piping. These methods include visual inspection; use of cameras, ultrasonic test (UT) devices,

.xi
electromagnetic test devices, pipeline pigs, and cathodic protection systems. Some of these

methods require access to the interior and/or exterior of the buried pipe, while others can be

performed by remote means. This section of the report also discusses the current regulatory

requirements and technical guidance that exist in the nuclear industry related to buried piping.

The regulatory requirements and technical guidance documents described include 10 CFR

50.65 - Maintenance Rule, NRC Inspection Procedures, 10 CFR Part 54 - License Renewal

Rule, and associated documents such as the Standard Review Plan and the Generic Aging

Lessons Learned (GALL) report. In addition to the above, industry programs related to aging

management, such as NUMARC 93-01 and NEI 95-10 are described.

Section 5 describes the fragility evaluation performed for degraded buried piping. It begins by

assessing the governing load(s) for use in the risk-informed study. The loads that were reviewed

and addressed in this study consist of internal pressure, soil surcharge (dead load),

groundwater, surface loads, temperature, soil movement, and seismic loads. A methodology for

calculating buried piping fragility was developed and applied to a range of steel buried piping

with varying sizes (diameters). Fragility curves were developed for wall thinning based on pipe

stress equations assuming uniform wall thinning. Then a statistical evaluation of available test

data on pressure tests of degraded pipes, removed from service and which exhibit localized loss

of material and pitting, was performed. The fragility data for the aging effects were developed for

varying levels of degradation which were utilized later in Section 7 to develop degradation

acceptance criteria (DAC).

Section 6 contains the risk evaluation of degraded buried piping systems. To estimate the effect

of buried piping degradation on plant risk, five nuclear plant sites having buried piping systems

were selected for this study. In order to develop the DAC, a quantitative measure of "acceptable

risk" was needed. Section 6 defines what can be considered as acceptable risk for use in this

evaluation. This was done based on the recommendations presented in the NRC Regulatory

Guide 1.174, Revision 1, entitled, 'An Approach For Using Probabilistic Risk Assessment In

Risk-informed Decisions On Plant-Specific Changes To The Licensing Basis." The acceptance

guidelines in the regulatory guide led to the selection of an acceptable change in core damage

frequency (ACDF) corresponding to what is considered to be 'very small changes" as defined in

the Regulatory Guide. In this study, this small change in core damage frequency (ACDF)

constitutes what is considered to be the risk acceptance criteria.

To develop risk-informed acceptance criteria corresponding to different levels of observed

degradation of the buried piping, the impact of this degradation on plant risk as a function of

time must be calculated. Section 6 describes the time-dependent methodologies developed for.

assessing the risk significance of a system with degraded buried piping at an NPP. The

methodologies provide two main outcomes: 1) the increase in projected risk as a function of

time due to degraded buried piping, and 2) the maximum number of years required for the

buried pipe to reach a degradation level that would potentially have a significant effect on plant

risk, given that the degraded pipe has not failed at the time of inspection. Some parameters

required by these methodologies were obtained by executing the SAPHIRE computer code with

the Standardized Plant Analysis Risk (SPAR) version 3 models of the five selected plants. A

SPAR model is a level-1 probabilistic risk assessment (PRA) model of internal events during

full-power operation.

Section 7 describes how the methodology developed in Section 6 was used to develop the DAC

for buried piping. This methodology utilized the set of equations developed in Section 6 to

determine the acceptable pipe wall loss corresponding to the risk acceptance criteria. In order to

utilize these equations to determine the number of years required for the buried pipe to reach

xii

Ill
risk significance, an appropriate degradation rate was needed. Since the degradation rate is a

function of many variables (i.e., a function of various plant and piping system conditions), the

DAC were determined for a range of expected degradation rates that would occur at NPPs. The

DAC were prepared in tabular form as a function of degradation rate, pipe size, and observed

wall loss at the time of inspection. Tables containing the DAC provide the number of years

required for the buried pipe to reach a degradation level that would potentially have a significant

effect on plant risk. This section of the report also provides the guidance for the use of the DAC,

including the acceptable range of conditions permitting its use, and recommendations if the

DAC cannot be satisfied.

The final DAC is presented in Table 7.5 and detailed guidance for its use is provided in Section

7.3. This table and Section 7.3 can be used by NRC staff to determine the risk significance of a

degraded buried piping condition that may be identified at an NPP. Examples for the application

of the DAC to specific pipe degradation conditions, and guidance for selection of appropriate

degradation rates are presented in Section 7.3.

Section 8 summarizes the conclusions of the research effort regarding the evaluation of

degraded buried piping at NPPs and provides recommendations for expanding the applicability

of the DAC and updating some of the plant information used in the study. Conclusions are

described for the: current understanding of buried piping degradation, detection of age-related

degradation and condition assessment, fragility evaluation, risk assessment, and degradation

acceptance criteria. The results demonstrate that for a buried pipe meeting the conditions of the

DAC, a pipe thickness loss less than about 45% of the original nominal pipe wall thickness, at

the time of inspection, is not expected to have an immediate significant effect on plant risk. The

types of buried piping systems, configurations, materials, and other conditions that must be

satisfied to use the DAC have been developed and presented in this report. The results

obtained are based on the service conditions that buried piping is designed for (e.g., pressure

induced stresses less than 1% of the minimum ultimate strength of the material and relatively low

temperatures) and recognizing that seismic induced stresses in buried piping are self-limiting

since deformations or strains are limited by seismic motion of the surrounding media. In

addition, the DAC were developed from a probabilistic risk assessment which accounted for the

contribution to risk of the postulated degradation of buried piping systems at NPPs. It should be

noted that even if a degraded buried pipe meets the DAC, it is expected that the licensee will

evaluate the conditions that led to the degradation and may need to repair the degraded pipe

based on the evaluation findings, the level of degradation, and the plant's licensing

commitments.

If buried pipe degradation is identified at an NPP, it may not be evident whether the pipe still

complies with the plant licensing commitments or whether the degradation potentially has an

immediate significant effect on plant risk. Normally, the licensee performs an evaluation of the

degraded condition which may include further inspections, testing, calculation/design review,

and other actions to determine the severity of the condition, risk implications, and whether an

immediate repair is needed. Since these steps may take time, often beyond a week, the

methodology and DAC developed in this report provides guidance to the NRC staff for making

an assessment in a timely manner whether the degraded condition potentially has an immediate

significant effect on plant risk. This knowledge is important in order to provide input that can

help determine whether immediate repairs are warranted, or whether the appropriate

investigation, inspection, aging management, or other actions can be determined in the normal

Nominal pipe wall thickness is the thickness of the pipe wall specified by ASME B36.10M-2004 without

consideration for manufacturing tolerance.

xiii
course of evaluating the condition. The methodology and DAC can not be used by the industry

to justify existing degraded conditions; licensees are still required to meet their commitments

regarding the plant's current licensing basis.

xiv

III
ACKNOWLEDGEM ENTS

The Office of Nuclear Regulatory Research of the U.S. Nuclear Regulatory Commission

sponsored the research program described in this report. The authors gratefully acknowledge

the efforts of Dr. T. Y. Chang, NRC Project Manager, for his support and technical guidance in

performing this study. His interest and advice in all phases of the research effort have been

appreciated and have greatly improved the results of this study. In addition, the authors

gratefully acknowledge the efforts of Dr. Arthur Buslik, also of the Office of Nuclear Regulatory

Research of the U.S. Nuclear Regulatory Commission, for his advice on developing a method

for evaluating the effect of buried piping degradation on plant risk as a function of time, and his

reviews of draft versions of this document. We also thank our colleague at Brookhaven National

Laboratory, Dr. John Lehner, for his review of the risk evaluation presented in Section 6.

The authors extend their appreciation to Mr. Gary Vine, Electric Power Research Institute, Inc.

(EPRI) representative in Washington, DC, for assisting the staff in obtaining a number of EPRI

reports related to buried piping. These reports contain valuable information about industry

experience, material and design information, data on degradation, condition monitoring and

historical performance for various buried piping systems. Information from these documents

were extremely helpful in ensuring that the research described in this report covers, to the

extent possible, the range of buried piping configurations, materials, aging mechanisms and

effects, and current inspection techniques at U.S. nuclear power plants.

xv
1 INTRODUCTION

1.1 Background

The majority of U.S. nuclear power plants have been in operation for over twenty years. Many of

these plants are approaching 30 years of operation' and are submitting license renewal

applications to the NRC to extend their operating licenses from 40 to 60 years. As U.S. nuclear

power plants continue to operate it becomes essential to assess the effects of age-related

degradation of their plant structures,'syste's, and components.

The importance of aging has been'recognized and has led to a number of regulatory,:

requirements such as the Maintenance Rule (10 CFR 50.65), which identifies requirements for

monitoring the effectiveness of maintenance at nuclear power plants (NPPs). Another regulation

is the License Renewal Rule (10 CFR Part 54) Which requires that license renewal applicants

demonstrate that the effects of aging will be managed so that the intended function(s) of

structures, systems, and components will be maintained consistent with the current licensing

basis through the period of extended operation.

Aging is a concern because past studies and inspections have identified instances of aging

degradation and this trend may increase if not properly understood and managed. Although

research on aging has been ongoing for some time, there is a lack of knowledge of how,

degradation could affect the structural response and 'resistance of structures and passive

components to various design loads.- The degree to which aging can affect the performance of

structures and passive components is also important because there is a lack of reliable

inspection techniques and limited accessibility for some structures and passive components

such Ets buried piping.

To address age-related issues, the NRC'has funded a number of studies in the past, many of

which related to active components and particular key safety-related passive components (e.g.,

reactor pressure vessel, steam generators, containments). Age-related degradation of active

components can usually be managed by monitoring their performance parameters such as

pressure, temperature, or electrical signal. Most age-related degradation of structures and

passive components, however, cannot be managed in a similar way. Therefore, the NRC has

sponsored studies to assess the effects of age-related degradation on structures and passive

components.

One of these studies, reported in NUREG/CR-6679, included a scoping study of all structures

and passive components found at U.S. NPPs.;The purpose of this scoping study was to identify

which structures and passive components warrant more detailed assessment in subsequent

phases of the research study. Five structures and passive components were identified in the

scoping study: concrete members, buried piping, steel tanks, anchorages, and masonry walls.

The detailed assessment for age-related degradation of concrete members was completed and

described in NUREG/CR-6715. The assessment for age-related degradation of buried piping

followed and is presented in this report.

1.2 Objective . .~,**,. -,;. -

The objective of the 'research program described in this report is to develop analytical methods

and risk-informed degradation acceptance-criteria (DAC) for assessing degraded buried piping

at NPPs. To achieve this objective, fragility modeling procedures for degraded buried piping

1
have been developed and the effect of degradation on fragility and overall plant risk has been

determined. The analytical approach provides the technical basis for evaluating degraded

buried piping at NPPs and for developing guidelines for assessing the effect of degraded

conditions on plant risk.

The DAC are not intended to be used by the industry as a design tool to justify existing

degraded conditions. Licensees are still required to meet their commitments regarding their

current licensing basis. The DAC are intended to provide guidance to the NRC staff for making

an assessment in a timely manner whether degraded conditions, identified at a plant site,

potentially have an immediate significant effect on plant risk. This knowledge is important in

order to provide input that can help determine whether immediate repairs are warranted, or

whether the appropriate investigation, inspection, aging management, or other actions can be

determined in the normal course of evaluating the condition. If the degraded condition exceeds

the criteria then immediate repair would be needed unless otherwise justified. If the degradation

condition is less than the criteria, then it is expected that the licensee will still evaluate the

conditions that led to the degradation and may need to repair the degraded pipe based on the

evaluation findings, the level of degradation, and the plant's current licensing basis.

1.3 Scope

The scope of this research study consists of all buried piping systems within the scope of the

Maintenance Rule 10 CFR 50.65 and the NRC License Renewal Rule 10 CFR Part 54. This

includes buried piping that are: safety-related, or non-safety related but a failure could affect

other safety-related components, or that meet several other criteria defined within the scope of

the maintenance rule and license renewal rule.

All currently available information was utilized to identify what buried piping systems exist at

NPPs. Potential aging effects for buried pipes were reviewed and those determined to be the

most predominant types of aging effects were evaluated for their effect on plant risk. Design

basis loadings applicable to buried piping systems were identified and those that were

determined to be significant or major contributors to plant risk were evaluated in detail. Materials

used for buried piping were also identified and those that were most common were studied.

1.4 Approach

If the failure of a buried pipe is found at a NPP, then it is clear that the pipe will need to be

repaired. However, if an inspection reveals that a buried pipe has not failed, but it has degraded,

the regulatory question that arises is: "does the pipe have to be repaired immediately, or is it

acceptable for the plant to continue operation?" This question can be answered by determining

whether the degradation poses a significant risk to the plant at this time or some time in the

future.

The approach that was implemented to achieve the objective described above is summarized

below.

Buried piping degradation phenomena

Identify buried piping aging mechanisms and aging effects, buried piping systems found at

NPPs, operating experience, most predominant aging effects, inspection/detection methods,

and aging management programs for buried piping. This effort is described in Sections 2

through 4.

2

III
Fragility evaluation of degraded buried piping

Evaluate the effects of various levels of degradation on the structural performance of buried

piping. This requires determining the types of load(s) that can significantly affect the structural

adequacy of buried piping, identifying statistical data for the important parameter(s), and

developing fragility curves for undegraded and degraded conditions. This evaluation is

presented in Section 5.

Risk evaluation of degraded buried piping

Develop a quantitative definition of risk significance based on available nuclear regulatory

requirements, guides, and industry standards. A methodology is developed that estimates the

effect of reductions in fragility on plant risk. The probabilistic risk assessment (PRA) models of

selected NPPs are evaluated to obtain the required parameters for the methodology. The

methodology includes consideration of degradation over time so that the number of years

required for the buried pipe to reach risk significance could be calculated. This methodology is

described in Section 6.

Degradation acceptance criteria

Use the methodology described above to develop the degradation acceptance criteria (DAC) for

buried piping. This can be achieved by utilizing the formulations developed in Section 6 to

calculate the acceptable pipe wall loss corresponding to the risk significance criteria. Then, the

number of years to reach this pipe wall loss can be determined given a degradation rate, pipe

size, and pipe wall thickness at the time of inspection. The results are compiled in a simplified

foAri to create the DAC, and any conditions that must be satisfied in order to use the DAC are

also developed.

3
2 BURIED PIPIING SYSTEMS AT NUCLEAR POWER PLANTS

2.1 Types of Buried Piping Systems

One useful source for identifying the types of buried piping that exist at NPPs is the Welding

Research Council Bulletin 446. This bulletin describes the practices followed in the design and

repair of buried pipe in the power, process, pipeline, and waterworks industries. Part IlIl of the

bulletin identifies information on buried piping systems obtained from surveys of various

industries including the nuclear power industry. A list of buried piping systems and associated

design information provided by the bulletin is presented in Table 2.1 of this report.

Although this list does not represent a complete description of all types of buried piping systems

found at NPPs, it does provide information for the most common types of buried piping found at

NPPs and important material and design information which will be discussed further in Sections

2.2 and 2.3.

Another useful source for identifying buried piping found at NPPs is contained in the license

renewal applications (LRAs)'submitted by utilities to the NRC for approval of extending the

operating licenses of their plants from 40 to 60 years. Twelve LRAs have been reviewed for

descriptions of the buried piping systems at the plants. A summary of the available information

for buried piping at these twelve plants is presented in Table 2.2. General plant information for

these 12 NPPs is presented in Table 6.1.'

Table 2.2 presents the types of buried piping systems used at NPPs. This table also presents

the material of the piping, diameter/thickness, interior and exterior coating, and some additional

information. Table 2.2 provides a separate tabulation for each of the twelve plants in

alphabetical order. While this table provides a-more complete listing of the types of buried piping

systems at NPPs, detailed design information was not contained within the LRAs. This table is

very useful to compile a list of the most predominant types of buried piping that are found at

NPPs and the piping material.

Table 2.2 also presents for each plant some additional information about aging management

programs and operating experience that was discussed in the LRAs. This information will be

discussed further in Sections 3 and 4 of this report.

It is evident from Table 2.2 that some piping systems such as the service water system and

diesel fuel oil system have buried piping at many plants while other systems such as the

recirculation spray system or standby gas system have buried piping at very few plants. Table

2.3 shows the distribution of the types of systems containing buried piping at the twelve plants'"

for which the LRA was reviewed. For the twelve plants, the buried piping systems that are most

common to NPPs in decreasing order are: service water, diesel fuel oil, fire protection,

emergency feedwater, condenser circulating water, condensate, containment spray, standby

gas treatment, and safety injection systems. The remaining buried piping systems listed in Table

2.3 appear only once at a given NPP.

2.2 Material and Design Parameters . A .

Buried piping found at NPPs are constructed from carbon steel, du9tile iron,'cast iron, stainless

steel, galvanized steel, low-alloy steel, copper-nickel, Yoloy, fiberglass, concrete, and cementlined steel pipe. Yoloy steel is high strength low-alloy steel with enhanced corrosion resistance

(ASTM A-714). Because of its significant weight, concrete pipe is generally used for large

5
.LL

diameter lines such as the water intake piping from sources of cooling water (e.g., lakes, rivers,

and reservoirs). These large diameter lines are directly accessible for visual inspection and

typically are examined periodically by plant personnel.

Identification of buried piping material and design parameters is difficult to obtain for NPPs from

publicly available sources. Table 2.4 summarizes the type of material utilized for each buried

piping system obtained from the WRC Bulletin 446 and the twelve LRAs reviewed. Blank entries

indicate that information was not available. This table shows that buried piping used in the

service water, diesel fuel oil, and emergency feedwater systems primarily utilize carbon steel

material. Buried piping used in the fire protection systems primarily utilize cast iron, ductile iron,

and carbon steel material. For the remaining systems there was insufficient data to draw any

general conclusions.

Pipe diameter and schedule for buried piping depend on the system. Based on the information

obtained from the WRC Bulletin, which is presented in Table 2.1, service water buried piping

diameters typically range from 10.2 to 76.2 cm (4 to 30 in.). The pipe schedule is likely to be

standard weight considering the relatively low pressures in the piping. Diesel fuel oil buried

piping is generally small diameter pipe, 7.62 cm (3 in.) or less based on the two plants

surveyed. Standard weight is utilized for 6.35 cm (2 1/2 in.) or more pipe diameter and schedule

80 pipe is used for 5.08 cm (2 in.) or less. Buried piping used in the emergency feedwater

system may be 30.5 or 35.6 cm (12 or 14 in.) based on the two plants surveyed. Data for the

remaining systems shown in Table 2.1 are not sufficient to make general conclusions.

Design pressures for all the buried piping shown in Table 2.1 are considered relatively low,

ranging from atmospheric or static head to 1.03 MPa (150 psig). Some lines shown in Table 2.4

have higher pressures; however, most of these lines are very unique for buried piping. Design

temperatures for all buried piping shown in Table 2.1 are also relatively low, ranging from

ambient to 60'C (140 0F). Some lines shown in Table 2.4 would also have higher temperatures

but as stated before, these lines are very unique for buried piping.

Another important parameter for the design of buried piping is the depth of the buried piping

below grade. Table 2.1 indicates that buried piping is generally placed 0.914 to 3.05 m (3 to 10

ft) below grade. Piping such as the diesel fuel oil storage might be enclosed in secondary pipe.

Because this type of piping is so unique, the evaluation described in this report will not include

piping enclosed within a secondary pipe.

The length of buried piping can vary greatly depending on the particular plant and system.

Based on EPRI Report 1006994 (2002), buried piping at five plants reviewed in the report range

in total length from 2,768 to 25,163 m (9,080 to 82,555 ft). These lines contain changes in

elevation and many elbows, and have limited access at several stations. For service water

buried piping, the results of a survey (EPRI Survey 95-110, "Inspecting Inaccessible Service

Water Piping,") were presented in EPRI Report GC-1 08827 (1998). This survey showed that

buried service water piping ranged in size from 40.6 to 107 cm (16 to 42 in.), had uninterrupted

total lengths of 30.5 to 1,524 m (100 to 5,000 ft), with as few as 2 elbows to a maximum of 50

elbows. Internal linings of piping included coal tar enamel, plastic, and concrete lined; however,

most had no internal lining. Access to piping typically was by inspection ports, valves, blind or

open flanges, or a spool piece.

6

III
2.3 Analysis and Design of Buried Piping

Buried piping was generally designed to ASME Section III or ASME B31.1 Codes. The design of

buried piping was often augmented by additional design requirements based on industry

practice. Some analysis procedures were based'on other industry codes such as AWWA M-1 1

or architect/engineer in-house developed procedures.

Typically, the material and diameter of the pipe is selected to satisfy flow requirements. Then,

the minimum thickness of the pipe is determined based on internal pressure. The applicable

code or standard defines the wall thickness equation to use to calculate the minimum required

thickness. -

As an example, for steel piping in accordance with ASME B31.1 - Power Piping:

PD0 + tm=2s~y+A .- '(2.1)

2(SE +Py)

where

tm = minimum required wall thickness due to pressure alone

P =intemal design pressure

Do = pipe outside diameter

S = maximum allowable stress in material at design temperature

E = joint efficiency factor

y temperature dependent coefficient which varies from 0.4 at 4820C (9000F) to 0.7

above 6770C (12500 F)

A = additional thickness required for items such as corrosion, erosion and mechanical

strength where necessary

For seamless buried pipe at low temperature, E = 1.0 and y = 0.4. After the minimum required

wall thickness (ti) is calculated, as shown above, the minimum pipe wall thickness is increased

to account for manufacturing tolerance.'

Additional loads that buried piping at NPPs are typically designed for-include: earth/soil, surface

loads, groundwater, thermal expansion, and seismic. Other loads that are not as common but

might be considered are: surface impact loads, fluid transients, and soil subsidence.

Good descriptions of the design and analyses of buried piping are provided in a number of

references such as Buried Pipe Design (Moser, 2001), American Lifelines Alliance Report

(2001), and WRC Bulletins 425 and 446 (Antaki, 1997 and 1999). Buried Pipe Design (Moser,

2001) describes how to design gravity flow pipes and pressure pipes for rigid and flexible buried

piping. It explains how to analyze buried piping for internal and external loads for various

metallic and non-metallic pipes in accordance with applicable codes and standards. WRC

Bulletin 446 (Antaki, 1999) describes the practices followed for the design and repair of buried

piping in the power, process, pipeline and waterworks industries. The design section reviews

buried pipe design requirements of several codes such as ASME B31.1 for Power, B31.3 for

Process, B31.4 for Oil Pipelines, B31.8 for.Gas Pipelines, and AWWA for Waterworks. Specific

equations are provided in accordance with these'codes for design of buried piping for internal

pressure, soil loads, surface loads, soil subsidence, temperature, water hammer, and seismic.

WRC Bulletin 425 (Antaki, 1997) has more detailed information regarding analysis methods for

buried piping. More recently, the American Lifelines Alliance Report (2001) has been developed

7
which provides a very complete description with some examples for the design of buried piping

for various loads. This document represents a consensus of practicing engineers and

academics.

For seismic analysis of buried piping, NUREG-0800, SRP Section 3.9.2 states that the following

items should be considered: (1) the inertial effects due to an earthquake upon buried piping

systems, (2) the effects of the static resistance of the surrounding soil on piping deformations or

displacements, differential movements of piping anchors, bent geometry and curvature

changes, etc., and (3) when applicable, the effects due to local soil settlements, soil arching,

etc. Section 3.7.2 of NUREG-0800 provides guidance for Category I buried piping, conduits,

tunnels, and auxiliary systems, indicating that in addition to the above three items, the seismic

analysis should also consider (1) relative deformations imposed by seismic waves traveling

through the surrounding soil or by differential deformations between the soil and anchor points,

and (2) lateral earth pressures and groundwater effects acting on the structures. For guidance

on the load combinations, system operating transients, and stress limits, NUREG-0800, Section

3.9.3 provides information that would be applicable to mechanical components including buried

piping.

For detailed guidance on seismic analysis of buried piping, the ASCE Report (1983) 'Seismic

Response of Buried Pipes and Structural Components" presents a description of a methodology

for the seismic analysis and design of buried piping and structures at NPPs. This document

discusses routing considerations, investigation of soil conditions along the route, and

determination of earthquake loads. Because of the complexity of performing a 3-dimensional

dynamic analysis of the piping/structure and surrounding soil, a simplified approach is

considered. This approach, which is based on expressions derived by Newmark (1967) and

expanded by Yeh (1977), calculates the instantaneous axial strain and bending strains of the

buried pipe/structure due to compression, shear, and surface waves. These equations are

applicable to long straight pipe sections. For bends, expressions developed by Shah and Chu

(1974) and Goodling (1978 and 1980) are described. The ASCE report also provides an

example for the seismic analysis of a buried steel pipe. An important observation made by the

report is that "seismic effects on buried structures are self-limited since deformations or strains

are limited by seismic motions of the surrounding media." Therefore, seismic stresses should be

considered in a similar fashion as thermal stress which would classify them as secondary

stresses not primary stresses.

A more recent ASCE Standard, ASCE 4-98 (2000), describes the seismic analysis of safetyrelated nuclear structures which includes a section on "special structures" such as buried piping

and conduits. The section on buried pipes and conduit provides equations/criteria for calculating

stresses and strains for straight sections of buried pipe; pipe near anchor points, sharp bends,

or intersections; and effects of anchor point movements. The equations for axial strain and

maximum curvature for long straight sections of pipe are based on the ASCE Report (1983)

described above. For forces on bends, intersections, and anchor points, an expression is

provided for calculating an upper bound for the axial force and guidance is provided for the

analysis of bending moments and shears by treating the structure as a beam on an elastic

foundation subjected to an applied axial force. The commentary section of the ASCE 4-98

(2000) states that although shear strains are theoretically also developed in a straight buried

structure by traveling wave effects, these shear strains are relieved and converted into

curvature strains by very small amounts of local relative lateral displacement between the buried

structure and the surrounding soil. Therefore the ASCE standard concludes that "except under

abnormal circumstances of very strong and stiff soil (such as might exist with permafrost or

8

IIl
frozen ground) immediately' urrounding the buried structure, shoea strains are negligible and

can be ignored."

Another useful document, which describes how to apply the Code (ASME B31 .1) rules to

restrained buried piping, is Appendix VII of ASME B31.1 (1998). This Appendix, which is

nonmandatory, acknowledges that experience over the years has demonstrated that the Code

rules may have been conservatively applied to the design and analysis of buried piping

systems. The Appendix states that because buried piping stresses are secondary in nature, and

since the piping is continuously supported and restrained, higher total stresses may be

permitted as follows:

SC5 SSA + Sh (2.2)

where

SA is allowable expansion stress range

Sh is the basic material allowable stress at maximum operating temperature

Although the Appendix does not address earthquake loadings, it does provide guidance on how

to develop a computer model of buried piping for evaluation of various loads that buried piping is

subjected to. This includes calculation of element lengths'and lateral soil springs based on the

modulus of subgrade reaction.

Further discussions on the analysis of buried piping for internal pressure, soil, surface,

temperature, and seismic loadings are presented in Section 5 of this report. Section 5 evaluates

the contribution of each of the loadings to the total stress expected in buried piping and the risk

significance associated for these loads, in an effort to identify the governing loads for

consideration in the probability-based fragility analysis.

9
Table 2.1 Buried Piping Systems at Nuclear Power Plants - WRC Bulletin 446 Survey

Sse MaeilDiameter*/ Joint Coating Pressure TepCm nt

System Material Thickness Layout Type Depth Extolint. Temp Comments

(in.) _____ ____ _____________________________

Emergency CS 6,10, 20, Note 1 Butt- 3 to 10 It. Unknown/ Inlet: Inlet: ASME IlIl design; loads: seismic soil

Service (SA1 06 24, 30/ welded, below None 125 psig Ambient; strains, thermal expansion, wt. Of

Water Gr. B) Dresser grade Dischge: Dischge: overburden, live loads; analysis method:

(7 plants) couplings atmo- 1400F AE procedure, AWWA M-1 1, Goodling

near spheric (1983).

bends

Emergency CS 12, 14/ Note 2 Butt- 3 to 10 ft. Unknown/ 125 psig Ambient ASME IlIl design; loads: seismic soil

Feedwater (SAl 06 welded below Unknown strains, wt. Of overburden, live loads;

(2 plants) Gr. B) grade AE analysis procedure based on AWWA

M-11.

Condenser Di 10/ Note 3 Bell and 3 ft below Unknown/ Static 140eF ASME B31.1 design; loads: restrained

Cooling spigot grade Cement head thermal expansion, wt. Of overburden,

Water live loads; analysis method: Goodling

(1983).

Emergency CS 3/ Note 2 Butt- 3 to 1 Oft. Unknown/ 125 psig Ambient ASME IlIl design; loads: seismic soil

Diesel Fuel (SA106 welded below Unknown strains, wt. Of overburden, live loads;

Oil Gr. B) grade AE analysis procedure based on AWWA

___ M-11.

Fire Yoloy 12/ Note 4 3 to 10 ft. Unknown/ Static Ambient ASME IlIl design; loads: seismic soil

Protection below Cement head strains, restrained thermal expansion,

grade wt. Of overburden, live loads; analysis

method: Igbal and Goodling (1973).

Auxiliary CS 4 to 24/ Note 5 Flanged Buried in Three laye 111 psig 1380F ASME B31.7-1969 Addendum and

Salt Water (SA106 Standard or trenches coating, (design) (design) provisions of ASME B31.lb-1973; loads:

Gr. B) weight pipe Dresser with cathodic dead, surcharge, soil pressure, live,

and fittings couplings bedding, protection/ pressure, thermal, seismic, tsunami

side & top 1/8" lining (additional detailed information on loads,

envelope combinations, and allowables provided).

Diesel Fuel CS / Sch 80 Note 6 Butt- Enclosed Devguard 150 psig 120°F ASME B31.7-1969 w/1970 Addendum

Oil Storage (SA1 06 (52 in.), welded or in 238/ (design) (design) and provisions of ASME B31.1b-1 973;

Gr. B or Std wt flanged secondar Pickled & Title 23, Div 3, Chap 16 California Code;

A) (>2 'hin.) y pipe passivated loads: same as above ground pipe due to

enclosure in secondary pipe.

1 in. = 2.54 cm; 1 ft = 30.5 cm; 1 psi = 6.89 kPa; °C = (OF - 32)/1.8

10
Notes:

1. Yard piping, several long runs > 15.2 to 30.5 m (50 to 100 ft), with 450 and 900 bends.

2. Yard piping, long runs > 30.5 m (100 ft), with 450 and 90° bends.

3. Cooling water discharge from condenser. Yard piping, long straight run to large diameter header.

4. Yard piping, long straight run to large diameter header.

5. Several thousand feet of piping, with elbows, flanged joints, and Dresser couplings connecting the intake structure with turbine building.

Concrete thrust blocks with ASTM A615 Grade 60 reinforcing steel are provided at all changes in direction.

6. About 30.5 m (100 ft) of piping, with elbows, flanged joints, and expansion joints connecting the underground diesel fuel oil storage tanks to

the turbine building transfer vaults.

Acronyms:

CS - Carbon steel

Dl - Ductile Iron ,

NPS - Nominal pipe size

. .... . ....... 

Diameter (nominal pipe size) corresponds to a standardized outside diameter (O.D.) as defined in ASME B36.10M-2004. For nominal pipe sizes

14 inches and above, the actual O.D. is equal to the nominal pipe size. For nominal pipe sizes 12 In. and smaller, the actual O.D. is greater than

the nominal pipe size, (e.g., 2 Inch nominal pipe actually corresponds to 2.375 in. O.D.).

11
Table 2.2 Buried Piping Systems at Nuclear Power Plants

Based on Twelve LRAs Reviewed

Arkansas Nuclear One - Unit 1

Sysem ateialDiameter/ Coating Cmet | System | Material | Thickness Ext./lnt. Comments

Service Water CS External Coating/ Note 1

Fuel Oil CS External coating/ Note 1

Notes:

1. Buried pipe inspections will be performed to ensure that loss of material due to external surface corrosion of buried piping is adequately

managed. When underground piping is uncovered during plant maintenance or modification activities, visual inspections of protective

coatings will be performed. Sampling of underground pipe would become warranted if observations of defective protective coatings or

losses of material on external pipe surfaces were seen during inspections.

Calvert Cliffs Nuclear Power Plant Units 1 & 2

System Material Diameter/ Coating Comments ______Thickness ExtJInt.

Auxiliary CS Wrapping, coating, cathodic Note 1

Feedwater protection/Unknown

Diesel Fuel Oil CS Wrapping, coating, cathodic Notes 2, 3 __ __ _ __ _ _ _ _ protection/Unknown_ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Saltwater CS, Cl Wrapping, enamel coating, Note 4

I Cs, ___I _Icathodic protection/Lining

Notes:

1. Under a new Auxiliary Feedwater (AFW) buried pipe inspection program, representative samples of buried piping will be selected for

visual inspection to ensure that the pipe wrappings/coatings are adequately protecting the pipe from the external environment. Any

evidence of the effects of crevice corrosion, galvanic corrosion, general corrosion, MIC, and pitting will initiate corrective actions.

2. In 1996, portions of four buried pipelines were inspected. It was discovered that the pipe wrap (trade name, "TRUE COAT, an extruded

polyvinyl coating covered with a black tape) was slightly damaged during construction, but the piping was in pristine condition after 20

years of operation.

12

k; I
3. Under a new Diesel Fuel Oil (DFO) buried pipe inspection program, variations in environmental conditions (including cathodic protection)

will be considered to select representative samples of buried piping for inspection to ensure that the pipe coating/wrapping and cathodic

protection system are adequately protecting the pipe from external aging degradation mechanisms.

4. The existing plant preventive maintenance (PM) program requires periodic inspections of internal linings. A new age-related degradation

inspection program covering components not inspected under the PM program will require inspections of representative samples of

susceptible areas for'signs of internal liner degradation and corrosion.

Catawba Nuclear Power Station, Units 1 & 2

System Material Diameter/ Coating Comments Thickness Ext./nt.

Condenser Cs Coal tar epoxy/ Internal Notes 1 2

Circulating Water coating

Diesel Generator Ss Coal tar epoxy/ Internal

Fuel Oil coating

Fire Protection C, Dl Coal tar epoxy/ Internal .. _ coating : ... ... , ...

Nuclear Service Coal tar epoxy/ Internal

Water coating __ __3_.-

Standby Coal tar epoxy/ Internal

Shutdown Diesel Ss, CS coating

Notes:

1. Condenser Circulating Water System Internal Coating Inspection Program is used to provide symptomatic evidence of the condition of 'all

buried piping external surfaces. Visual inspections of intake and discharge piping for internal coating degradation performed every five

years. Externally generated through-wall pits will be revealed through observance of blistering, peeling, or missing internal coatings as well

as signs of corrosion'of underlying pipe and inleakage of soil or groundwater.

2. Original interior coating was not properly applied and is failing. As a result, the Condenser Circulating Water System is scheduled to be

entered every outage for blasting and recoating and/or walkdown of areas not recoated. These inspections have not Identified any

through-wall pits originating from pipe exterior. -

3. During the 2000 outage, the Nuclear Service Water System piping was cleaned to remove fouling buildup. Internal Inspection revealed a

row of through-wall pits. Excavation and examination of external coating revealed that the coating had been cut during construction

allowing the underground environment to contact pipe surface. Except for the cut, the external coating was In good shape. Other instances

of externally generated through-wall leaks of buried components have been identified and attributed to construction-related damage.

13
Edwin I. Hatch Nuclear Power Plant Units 1 & 2

System Material Diameter/ Coating Comments Thickness ExtHeInt.

Residual Heat 18 in. Enamel coated, coal tar

Removal Service CS (portion)/ fiber wrapped/

W ater__ _ _ _ _ _ _ _ _ _ _ _ _ _

High Pressure Enamel coated, coal tar

Coolant Injection fiber wrapped/

Reactor Core Enamel coated, coal tar

Isolation Cooling fiber wrapped/

Plant Service CS 30 in. Enamel coated, coal tar Note 1

Water (portion)/ fiber wrapped/

Standby Gas Enamel coated, coal tar

Treatment fiber wrapped/

Diesel Fuel Oil Enamel coated, coal tar

Supply S fiber wrapped/

Leaking piping, deterioration of

coatings within fire water storage

Fire Protection tank and fouling of lines due to

corrosion product buildup have

been reported

1 in. = 2.54 cm

Notes:

1. Long runs > 30.5 m (100 ft), with 450 and 900 bends.

McGuire Nuclear Station, Units 1 & 2

System Material Diameter! Coating Comments ___________Thickness Extilnt.

Condenser CS Coal tar epoxy/ Internal Notes 1, 2

Circulating Water coating

Diesel Generator SS Coal tar epoxy/ Internal

Fuel Oil coating

Fire Protection GS, DI Coal tar epoxy! Internal _ _ _ _ _ _ _ _ _ _ _ _ I _ _ _ _ _ _ _ _ _ _ c o a tin g_ _ _ _ _ _ _ _ _ _ _ _ _ _ _

14
System Material Diameter/ Coating Comments _____________ _______Thickness Ext.IAnt.________________

Nuclear Service CS Coal tar epoxy/ Internal

Water coating

Standby Ss C Coal tar epoxy/ Internal

Shutdown Diesel S C coating I

Notes:

1. Condenser Circulating Water System Internal Coating Inspection Program is used to provide symptomatic evidence of the condition of all

buried piping external surfaces. Visual inspections of intake and discharge piping for internal coating degradation performed every five

years. Externally generated through-wall pits will be revealed through observance of blistering, peeling, or missing internal coatings as well

as signs of corrosion of underlying pipe -and inleakage of soil or groundwater.

2. Two leaks occurred to date. One was a crack in a weld resulting from waterhammer events. The other was a pinhole that was larger on

the outside than the inside, indicating that corrosion initiated on external pipe surface. Pinhole was repaired with a steel pipe plug.

"' t I". . . f , - j INI7 1' 1 1' . t.

. - ;' .  .  , I

No : rthAn Po. -na -S t .atI U 1 :&

North Anna Power Station, Units 1 & 2

System Material Diameter! Coting Comments ______Thickness Ext.IAnt.

Quench Spray

(Containment SS External coating/ Stray) ''

Emergency - CS, LS External coating/ Diesel Generator__ _ _ _ _ _ _ _ _ _ _ _ _ _

Maintenance activities have not

Fire Protection Cl External coating/ identified any significant external

degradation to date

ecrat SS External coating/ S pray ._ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _

Residual Heat ; Removal Ss External coating/

Safety Injection Ss External coating/

Maintenance activities have not

Service Water CS, LS External coating/ identified any significant external

degradation to date

15
Oconee Nuclear Station 1, 2, & 3

System Material Diameter/ Coating Comments ______________________Thickness Ext.Ilnt. _______________

A small hole in branch line pipe

observed in 1992. Root cause:

galvanic or pitting corrosion at a

Condenser pinhole coatings void. Circulating Water CS, Ss External coating/ A 2.54 cm (1 in.) diameter hole

discovered in 3.35 m (11 ft)

diameter piping in 1997. Root

cause: local galvanic cell created

by a void in exterior coating.

High Pressure External coating/

Service Water

Service Water External coating/ Note 1

(Keowee)

Standby

Shutdown Facility External coating/

Diesel Generator

Fuel Oil

Turbine

Generator External coating/ Note I

Cooling Water

(Keowee)

Notes:

1. The onsite emergency power source for Oconee is the Keowee Hydroelectric Station, which is located at the Keowee dam on Lake Keowee.

16
Peach Bottom Atomic Power Station Units 2 & 3

System Material Thickness ECxot./ntg. Comments

Standby Gas Cs Note 1

Treatment ' ___- _:: _Note_1

High Pressure Nts1

Service Water CS Notes 1, 2

Emergency Notes 1, 2

'Service Water Cs.Nts12

Fire Protection Clined Notes 1, 3

Emergency CS Notes 1, 2

Emergency CS Note 1,4

D iesel G enerator __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _

Notes:

1. The Outdoor, Buried and Submerged Component Inspection Activities program provides for management of loss of material and cracking

of external surfaces of components subject to outdoor, buried, and raw water external environments. This program includes visual

Inspection of buried commodities whenever they are uncovered during excavation. Component inspections include inspection of external

surfaces for the presence of pitting, corrosion, and other abnormalities.

2. The ISI program provides for monitoring of pressure boundary integrity for outdoor and buried components through pressure tests, flow

tests, and inspections.

3. The Fire Protection Activities program provides for inspection, monitoring, and performance testing of fire protection systems and

components to detect aging effects prior to loss of intended function. Degradation due to corrosion buildup, blofouling, and silting are

detected by performance testing based on NFPA 24 standards. The program includes continuous monitoring of system pressure to detect

leakage of buried fire main piping and valves, and periodic flow test to detect blockage and component degradation in buried fire main

piping and valves..:-

4. The Lubricating and Fuel Oil Quality Testing Activities Program manages loss of material and cracking in components that contain fuel oil.

Testing of fuel oil for the presence of corrosion particles or water provides a means for detecting loss of material for fuel oil storage tanks

and underground fuel oil piping.- -

17
St. Lucie Units 1 & 2

System Material Diameter/ Coating Comments ______Thickness Extilnt.

Fire Protection Cl

Intake Cooling CS, SS Note 1

W ater__ _ _ _ _ _ _ _ _ _ _ _ _ _

Auxiliary Ss

Feedwater _

Condensate SS Note 2

Notes:

1. The Intake Cooling Water system Inspection Program addresses internal inspection of the Intake Cooling Water piping to identify and

manage loss of material on the external surface of buried piping.

2. A one-time visual inspection will be performed to determine the extent of the loss of material due to pitting and microbiologically influenced

corrosion on the external surfaces of the buried piping that connects the St. Lucie Unit 1 and Unit 2 condensate storage tanks. The results

of this inspection will be evaluated to determine the need for additional inspections.

Surry Power Station, Units 1 & 2

System Material Diameter! Coating Comments ___________Thickness Ext.Ilnt.

Condensate External coating/

Containment Ss External coating/

Spray_ _ _ _ _ __ _ _ _ _

Emergency CS, LS External coating/

Diesel Generator __ _ _ __ _ _ _ _ _ _ _ _ _ _ _

Feedwater CS, LS External coating/

Maintenance activities have not

Fire Protection Cl External coating/ identified any significant external

degradation to date

Safety Iniection SS External coating!

Security CS, LS External coating/

CS, LS,

Service Water CN, SS, External coating/

FG

18
Turkey Point Units 3 & 4

System Material Diameter/ Coating Comments

Thickness Ext./Int.

Intake Cooling

Water __

Fire Protection Cl, CS

Standby Steam

Generator

Feedwater Ss

System

Virgil C. Summer Nuclear Station Unit I

System Material Diameter/ Coating Comments ________________ Thickness Ext./Tnt._______________

Diesel Generator CS External coating, wrapping/ Notes 1,2 Services__ _ _ _ _ _ _ _ _ _ _ _ _ _

Emergency CS External coating, wrapping/ Note 1

Feedwater _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Fire Service DI External coating, wrapping/ Note 1

Service Water CS External coating, wrapping/ Note 1

Notes:

1. The Buried Piping and Tanks Inspection program is a new Inspection activity that will manage loss of material due to crevice, galvanic,

general, pitting, and microbiologically influenced corrosion (MIC) on the external surfaces of components exposed to an underground

environment. Under this program, the condition of coatings and wrappings will be determined by visual inspection whenever buried

components are excavated for maintenance or for other reasons. If coatings or wrappings are damaged or removed as part of the

maintenance activity, the underlying metal will be visually inspected for degradation.

2. During an evaluation, the Cathodic Protection System was found to provide inadequate protection to the diesel generator fuel oil storage

tanks and associated underground piping. As a result, an ultrasonic examination of the fuel oil storage tanks and associated piping was

perform'ed. The tank Inspection indicated a very slow (or negligible) rate of wall thinning. Approximately 10.7 m (35 ft) of fuel oil piping was

inspected and found to be in good condition with no corrosion identified.

19
General Notes For Entire Table:

Materials:

CS - Carbon Steel

LS - Low-alloy Steel

SS - Stainless Steel

GS - Galvanized Steel

Cl - Cast Iron

FG - Fiberglass

CN - Copper-Nickel

DI - Ductile Iron

Yoloy - high strength low alloy steel with enhanced corrosion resistance (ASTM A-714)

Information presented in this table was obtained from the License Renewal Applications for each plant submitted to the US NRC, and is available

at the NRC web site or through the NRC Public Document Room.

20
Table 2.3 Nuclear Power Plant Systems with Buried Piping

Source of Number of Plants' Number of Plants' System Information's (From: WRC 446) (From: LRAs)

Sevc ae 3 w(8),a,cc,c,h(2),m,n, 81 SeOice Water o(2),sl,vsst,p _ _1_ 5

Diesel Fuel Oil4 w(2),a,cc,c(2),h,m(2) 12 ____ ____ ___Fuel__ n,o,vs,s,p _ _ 2__ __ _ _ _ _12__ __ _ _ _ _

Fire Protection5 w,c,h,m,n,slvs,s,t,p 1 9

Emergency Feedwater 6 w(2),cc,sl,vs,s,t 2 5

Condenser Circulating wcmo

W ater 7 ___________.

Condensate sls2

Containment Spray8 n,s 2

Standby Gas Treatment h,p 2

Safety Injection n,s 2

High Pressure Coolant

Injection h__

Reactor Core Isolation h 1

Cooling

Recirculation Spray n 1

Residual Heat Removal n 1

Turbine Generator 1

Cooling Water 1

Security s 1

Emergency Cooling p 1

Water

Notes:

1. Identification of systems that include buried piping obtained from WRC Bulletin 446 survey and

from information provided in License Renewal Applications (LRAs). Plants included in WRC

survey were not specifically identified.

2. See legend below for plant identification.

3. Includes Service Water, Emergency Service Water, Auxiliary Salt Water, Saltwater, Nuclear

Service Water, Residual Heat Removal Service Water, Plant Service Water, High Pressure

Service Water, Intake Cooling Water.

4. Includes Diesel Fuel Oil, Emergency Diesel Fuel Oil, Diesel Fuel Oil Storage, Fuel Oil, Diesel

Generator Fuel Oil, Standby Shutdown Diesel, Diesel Fuel Oil Supply, Emergency Diesel

Generator, Diesel Generator Services, Standby Shutdown Facility Diesel Fuel Oil.

5. Includes Fire Protection and Fire Service.

6. Includes Emergency Feedwater, Auxiliary Feedwater, Feedwater, Standby Steam Generator

Feedwater.

7. Includes Condenser Circulating Water and Condenser Cooling Water.

8. Includes Containment Spray and Quench Spray.

:- 21
Legend:

w - WRC Bulletin 446 survey

a - Arkansas Nuclear One - Unit 1

cc - Calvert Cliffs 1 & 2

c - Catawba 1 & 2

h - Edwin I. Hatch 1 & 2

m - McGuire 1 & 2

n - North Anna 1 & 2

o - Oconee 1, 2, & 3

p - Peach Bottom 2 & 3

sl - St. Lucie 1 & 2

vs - V. C. Summer 1

s-Surry1 &2

t - Turkey Point 3 & 4

22

ni
Table 2.4 Buried Piping Material and Design Parameters

Nominal

System Source of Information Material 1.2 Diameter/Thickness

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _(in .)

4, 6, 10, 20, 24,'301 Serv.ce Watr 3 WRC Bulletin 446 CS (SA-106 Gr. B) [81 S d weight0

Se-Twelve LRAs CS[10], LS[2], SS[2], ____ _____ ___ ____ ___ ____ ___ C I[21, C N , FG ,

-\; l1, ,<2 I Sch 80 '°

WRC Bulletin 446 .- CS (SA-106 Gr. B)[2j >X2 / Std wt. 10

Diesel Fuel Oil 3/

Twelve LRAs CS[9], SS[2], LS[2]

Fire Protection5 WRC Bulletin 446 Yoloy [1] 12

Twelve LRAs CI[5], DI[3], CS[2], GS

Emergency WRC Bulletin 446 CS (SA-106 Gr. B) [2] 12,141

Feedwater 6 Twelve LRAs CS02], SS[2], LS

Condenser WRC Bulletin 446 Dl 10/

Circulating Water 7 Twelve LRAs CS[3], SS

Condensate Twelve LRAs SS

Snpray nTwelve LRAs SS[2]

Standby Gas Tev RsC

Treatment Twelve LRAs CS

Safety Injection Twelve LRAs SS[2]

High Pressure Twelve LRAs

Coolant Iniection

Reactor Core Twelve LRAs

Isolation Cooling wleLq

Recirculation Spray Twelve LRAs SS

Residual Heat Twelve LRAs SS

Removal

Turbine Generator Twelve LRAs

Cooling Water _ _ _ _ _ _ _ _ _

Security Twelve LRAs CS, LS

Emergency Cooling Twelve LRAs CS

W ater I _ _ __ _ __I__ _ _ _ _ _ _ _ _ I__ _ _ _ _ _ _ _ _

1 in. = 2.54 cm

Notes:

1. Values in square brackets denote number of plants which identified having the material; without

brackets denote only one plant.

2. See legend below for pipe material definition.

- 23
-. L

3. Includes Service Water, Emergency Service Water, Auxiliary Salt Water, Saltwater, Nuclear

Service Water, Residual Heat Removal Service Water, Plant Service Water, High Pressure

Service Water, Intake Cooling Water.

4. Includes Diesel Fuel Oil, Emergency Diesel Fuel Oil, Diesel Fuel Oil Storage, Fuel Oil, Diesel

Generator Fuel Oil, Standby Shutdown Diesel, Diesel Fuel Oil Supply, Emergency Diesel

Generator, Diesel Generator Services, Standby Shutdown Facility Diesel Fuel Oil.

5. Includes Fire Protection and Fire Service.

6. Includes Emergency Feedwater, Auxiliary Feedwater, Feedwater, Standby Steam Generator

Feedwater.

7. Includes Condenser Circulating Water and Condenser Cooling Water.

8. Includes Containment Spray and Quench Spray.

9. Auxiliary Salt Water system 4 to 24 in. / standard weight.

10. Diesel Fuel Oil Storage

Materials:

CS - Carbon Steel

LS - Low-alloy Steel

SS - Stainless Steel

GS - Galvanized Steel

Cl - Cast Iron

FG - Fiberglass

CN - Copper-Nickel

Dl - Ductile Iron

Yoloy - high strength low alloy steel with enhanced corrosion resistance (ASTM A-714)

24

11
3 AGING MECHANISMS AND CONSEQUENTIAL DEGRADATION EFFECTS

3.1 Potential Aging Mechanisms and Effects

Age-related degradation of buried piping is of interest in the nuclear power industry because of

safety concerns and economic considerations. Instances of pipe degradation have been

identified at NPPs and research has been expended on understanding what causes aging

degradation of buried piping.

Degradation of buried piping can occur within'the' pipe and/or external to the pipe. Different

types of degradation can occur in all tyopes of pipe materials (metals, plastics, or concrete).

Degradation may develop due to environmental conditions alone or may be initiated due to poor

design, installation, or maintenance.

There are a number of sources for identification of the aging mechanisms, or causes of

degradation, and the aging effects resulting from the aging mechanism. A list of the most

important aging mechanisms'applicable to buried commodities, which would include buried

piping, (Esselman et al., 1997) is presented in Table 3.1. This list encompasses most aging

rnechanism's'that bould potentially occur; however, some of the aging mechanisms would not

generally apply to buried piping at NPPs.' As'an example, aging mechanisms related to polymer

pipe would not be a concern because polymer pipe is rarely used for buried pipe at NPPs.

Freeze-thaw of buried pipe would also not be' a concern in general because this aging

mechanism would only be potentially significant for concrete pipe in cold climates where the.

frost line would be deep and in such locations, good design practices at NPPs would preclude

this fr6m occurring by placing the buried piping below the frost line.

A listing of aging mechanisms and aging effects for structures and passive components is also

presented in NUREG-1801 Generic Aging Lessons Learned (GALL) Report. The aging

mechanisms and aging effects from the GALL Report, related to buried piping, is presented in

Table 3.2. The GALL Report was developed by the NRC to document the staff's basis for

determining which generic existing programs are adequate to address aging and which

programs need to be augmented for license renewal of NPPs. More discussion on the GALL

Report is provided later in Section 4.2 of this report.

The aging mechanisms and aging effects~ presented in Table 3.2 were not intended to be a

complete listing of every possible degradation phenomena,' but rather a listing of the

degradations that are expected to occur at NPPs. The applicant (licensee) would still be

expected to review his plant design, operating experience, and industry wide experience to

include any additional aging effects that could potentially occur at the plant.

A review of the various aging mechanisms from Table 3.2 for steel piping shows that the list of

aging mechanisms is consistent with thelist presented in Table 3.1. The only aging effect

identified in Table 3.2 is loss of material which is intended to capture all forms of loss of material

such as general wall thinning and localized pitting or holes through the pipe wall. -

A compilation of the aging mechanisms and corresponding aging effects from the'above

sources and other reference material is provided in Table 3.3. This table also presents for each

aging mechanisrni/effect,' the pipe material that may be susceptible to the aging

effect/mechanism, the mnanifestation, and some additional information related to the

degradation.

25
3.1.1 Aging Mechanisms

The primary aging mechanisms that directly affect buried metallic/steel piping are described

below. Aging mechanisms affecting polymer piping are not discussed because polymer buried

piping are rarely used at NPPs. Aging mechanisms of concrete pipe are also not discussed

because buried concrete pipe is primarily used at NPPs for large diameter lines due to their

significant weight. These large diameter lines provide the ability for personnel to gain access

and perform periodic inspections. Therefore, the focus of this research study is limited to buried

metallic pipe. Information for aging mechanisms and effects of concrete pipe would be similar to

those already described for concrete members in NUREG/CR-6715.

General Corrosion

General corrosion is a degradation of the pipe surface that results in loss of material over a

region without appreciable localized attack. Corrosion is caused by a direct current that flows

from a metal such as a buried pipe to an electrolyte such as the soil material. Corrosion occurs

at the location where the current exits the pipeline to enter the soil. Corrosion depends on the

electrical resistance and potential of the electric circuit that is developed. Corrosion varies with

the moisture content of the soil. If the soil is dry, very little corrosion is expected to occur, while

in soils with higher moisture content, the resistivity drops and higher rates of corrosion would

occur.

Corrosion is also a function of the level of oxygen in the soil. Where oxygen is more plentiful, the

rate of corrosion is initially high and then is slowed by the corrosion products that remain

adhered to the pipe surface. Corrosion products however cannot be relied upon to prevent

corrosion because they do not adhere tightly to the pipe, may be thin, and may not exist

throughout the pipe.

General corrosion rates vary depending on many design and environmental parameters. A

discussion of general corrosion rates in steel pipe is provided in Section 3.4

Because of the poor corrosion resistance of carbon steel pipes, they are often lined or coated

on the inside with bonded polymeric coatings, cement-mortar, or elastomers. On the outside,

buried pipes are usually protected by coal tar epoxy coatings and wrappings. Buried piping is

also protected at many plants by a cathodic protection system which is described in Section 4.1

of this report.

Pitting Corrosion

Pitting corrosion is a localized form of corrosion that forms cavities or holes in the material.

Pitting corrosion occurs when chemical attack breaks through the passive film that protects the

metal surface. Once a pit penetrates the passive film, an electrochemical (galvanic) reaction

develops. The metal in the pit becomes anodic while the surface outside the pit is cathodic. The

exposed surface outside the pit is cathodically protected and can lead to a large cathode to

anode ratio which can accelerate the anodic reaction in the pit. The reaction in the pit leads to a

reduction in the pH and an increase in the chloride ion concentration. The acidic chloride

environment is aggressive to most metals and thereby propagates the pit growth. It is possible

for most of a pipe section to show little corrosion while some deep pits may develop.

26

III
Crevice Corrosion

Crevice corrosion is a localized corrosion that may occur in small areas of stagnant solutions in

crevices, joints, and contacts between metals and metals or metals and nonmetals. Examples of

crevice geometries include flanges, gaskets, threaded joints, disbanded protective

linings/coatings, fasteners, lap joints, and surface deposits. As in pitting corrosion, the metallic

material in the stagnant crevice region develops a more anodic property compared to the

exposed bulk surface adjacent to the crevice.

As described in EPRI Report TR-102410 (1993), negative ions such as chlorides and sulfates

migrate to the crevice region creating metal chlorides; which results in an increased level of

acidity (low pH) in the crevice. When the level of chloride ion and pH reaches a critical

threshold, crevice corrosion is initiated. The level of chloride ion and pH depends on the pipe

material. As an example, for.Type 316 stainless steel, a chloride level of 142,000 parts per

million and a pH of 1.65 can lead to initiation of crevice corrosion. Other factors that promote

crevice corrosion are small gap dimensions and increasing depth of corrosion.

Galvanic Corrosion

Galvanic corrosion refers to corrosion that occurs when two dissimilar metals are coupled in a

corrosive electrolyte such as soil containing moisture. When a galvanic couple forms, one of the

metals become the anode and corrodes faster than it would by itself, while the other becomes

the cathode and corrodes slower that it would alone. The driving force for the corrosion is the

potential difference between the different materials. The less-noble metal will become the anode

of the corrosion cell and will corrode at a faster rate. An example of this is a copper water line

that may be run to steel pipes or tanks. .- l -

Selective Leaching

Selective leaching, also known as dealloying, is the removal (leaching) of one element from an

alloy by the corrosion. The more active element in the galvanic series is dissolved away leaving

the more noble one; The most common examples of selective leaching are cast iron

graphitization and dezincification. Graphitization is the process by which cast iron pipe corrodes.

As the iron matrix is leached away, a brittle'sponge-like structure of graphite remains. The cast

iron retains its appearance and shape but it becomes weaker structurally. Under dezincification,

zinc is removed from brass alloys leaving a porous copper structure.

Microbiologicallv Influenced Corrosion

Microbiologically influenced corrosion, known as MIC, is corrosion caused by the presence

and/or activities of microorganisms in'biofilms on the surface of the pipe. Microorganisms have

been observed in a variety of environments that include seawater, natural freshwater (lakes,

rivers, wells), soils, and sediment. The microbiological organisms include bacteria, fungi, and

algae. They have been known to tolerate a wide range of temperatures, pH values, oxygen

concentrations, and extreme hydrostatic pressure. These microorganisms can influence

corrosion by effects such as the destruction of the protective surface films, creating corrosive

deposits, and/or altering anodic and cathodic reactions depending on the environment and

organism(s) involved.'MIC affects most alloys such as steel (including stainless and

galvanized), ductile iron, and copper. It is more common to find MIC inside buried piping;

however, it may also occur on the outside of the pipe. Bacterial corrosion can occur outside,

.27
11L

buried pipe, generally in moist soils, such as clays, and it thrives in locations where there is a lot

of organic matter.

Fouling/Biofouling

Fouling is the deposition of material that may impair or degrade a pipeline and can reduce or

block fluid flow. The fouling may be due to build-up of silting or corrosion products, or due to

macro-organisms (biofouling). Corrosion causes fouling by creating mounds from the corrosion

byproducts which are much larger than the metal material that is lost. Biofouling refers to the

growth of marine organisms in submerged surfaces that impair the flow or degrade the pipeline.

Biofouling can be caused by organisms such as plant sea mosses, barnacles and mollusks

(oysters and mussels). These are a concern for raw water systems such as the service water

system that use open waters, estuaries, and rivers containing macro-organisms. Biofouling is

usually most widespread in warm conditions and in low velocity seawater. Marine organisms

attach themselves to some metals and alloys more readily than others. Steels, titanium, and

aluminum will foul more easily. Copper-based alloys, such as copper-nickel, are more resistant

to biofouling.

Erosion

Erosion is the removal of material on a pipe surface due to the fluid motion. Erosion is

accelerated when abrasive material such as solid particles is suspended in the fluid and/or high

velocity flow is present. Erosion can also be detrimental when conditions exist that create

turbulence, flow restrictions, obstructions, and abrupt changes in flow direction. These often

occur in bends, tees, pump impellers, and valves. Carbon steels and copper alloys are generally

more susceptible to erosion while stainless steel and nickel-based allows are less affected by

erosion.

Cavitation

Cavitation occurs when a fluid's operational pressure drops below its vapor pressure creating a

negative pressure (vacuum). This condition causes gas pockets and bubbles to form and then

collapse. Cavitation can occur at locations such as the suction of a pump, the discharge of a

valve or regulator, and geometry-affected pipe locations (e.g., elbows and expansions). Loss of

material due to cavitation is normally eliminated by design which avoids large pressure drops

and reducing hydrodynamic pressure gradients.

3.1.2 Aging Effects

The major aging effects for buried metallic piping is loss of material and loss or reduction of flow

in the pipe. Most of the aging mechanisms shown in Tables 3.1 through 3.3 lead to loss of

material and only fouling/biofouling result in the loss or reduction of flow. Reduction in flow due

to fouling/biofouling can be addressed by monitoring system performance parameters such as

system flow and pressure, periodic examination of equipment fed by the system, and other

means (see Section 3.2 Operating experience). Therefore, the study presented in this report

was based on the aging effect of loss of material.

Loss of material is grouped into two types: general thinning over a region of the pipe wall

surface and localized loss of material/pitting which can develop pits or holes in the pipe surface.

If undetected, general wall thinning can lead to sudden failure of the buried piping. Pitting is

harder to detect and is more difficult to design against than general wall thinning. In addition to

28

n'
localized loss of thickness, pits can be harmful by inducing stress risers that could initiate stress

corrosion cracking and fatigue. However, fatigue is not usually a concern for buried piping at*

NPPs because of the low number of load cycles that the piping experiences over its lifetime.

3.2 Operating Experience

Buried piping degradation has occurred at some NPPs and it is a concern that needs to be

addressed on an ongoing basis. The operating experience of buried piping has generally been

good; however, there have been some systems that have had greater instances of degradation

than others. -

NRC Generic Correspondences

A number of NRC Generic Correspondences related to degradation of the service water system

have been issued. In some cases, it is not clear whether the degradation occurrences described

in the generic correspondences were in the buried portions of the piping system; however, if

these occurred above ground, it would also be'a concern for the buried piping regions.

On April 10, 1981, the NRC issued IE Bulletin 81-03 to request holders of operating licenses

and holders of construction permits at NPPs to submit information relating to flow blockage of

cooling water to safety system components by Asiatic clams and mussel. Asiatic clams were

identified in the service water system for'containment cooling units at Arkansas Nuclear One,

Unit 2. Following this discovery, inspection of other equipment cooled by service water in both

plant units revealed some'fouling or plugging due to buildup of silt, corrosion products, and

debris (mostly clam shell pieces). During an outage, clams and shells were found to have

accumulated to depths of 0.914 to 1.37 m (3 to 4 Yz ft) in certain areas of the intake bays for Unit

2.

NRC Information Notice (IN) 81-21,'issued on July 21, 1981, identified that situations not

explicitly discussed in IE Bulletin 81-03 may occur and result in a loss of direct access to the

ultimate-heat sink. The situations identified are: debris from shell fish other than Asiatic clams

and mussels may cause flow blockage, flow blockage can cause high pressure drops that lead

to certain problems in heat exchangers, and change in operation (e.g., long outages with no

flow through seawater systems) appears to permit buildup of mussels where previous

inspections showed no appreciable problem.

IN 85-24 was issued on March 26, 1985 to alert NPPs that a potentially significant problem

pertaining to' the selection and application of protective coatings for safety-related piping exists.

The issue arose in the spraypond piping system in 1982 at Palo Verde Nuclear Generating

Station Unit 1 where delamination and peeling of the interior epoxy lining in three .61.0 cm (24

in.) diameter elbows 'occurred. Indications were that this was caused by improper application of

the- epoxy coating. This IN also identified at the same plant, degradation of the-epoxy coating in

train A of the spray pond piping leading to the diesel generators which resulted in complete

blockage of the generator governor oil coolers. The epoxy coating degradation included severe

blistering, moisture entrapment between'layers of the coating, delamination, peeling, and

widespread rusting.

IN 85-30 was issued on April 19, 1985 to alert NPPs of significant corrosion pitting due to MIC

identified in stainless steel piping sections of a service water system after an extended plant

outage. This degradation was identified on January 26, 1984, at the H. B. Robinson Unit 2 plant

which was shut down and remained shut down throughout the year to replace the lower

. :29
."L

assemblies of the steam generator and perform other maintenance work. On November 19,

1984, minor pinhole leaks were found in the heat affected zones of circumferential welds joining

15.2 cm (6 in.) diameter, schedule 10, 304 stainless steel piping that provides service water to

the four containment chilling units. Visual inspection of the entire system revealed minor

leakage at 32 welds inside and 22 welds outside containment. Further radiographic examination

indicated that localized corrosion pitting occurred on the inside surface at many other weld joint

locations.

In 1987, the Office for Analysis and Evaluation of Operational Data (AEOD) in the NRC initiated

a study and evaluation of the failures and degradations in service water systems at NPPs. The

results of the study, which covered the period between 1980 to early 1987, were published in

NUREG-1275. The results indicate that of the 980 operational events involving the service water

system, 276 were deemed to have potential generic safety significance. Of these generic

significant events, 58 percent involved system fouling, followed by 17 percent due to personnel

and procedural errors, 10 percent due to seismic deficiencies, 6 percent due to single failures

and other design deficiencies, 4 percent due to flooding, and 4 percent due to significant

equipment failures. The fouling mechanisms included corrosion and erosion (27 percent),

biofouling (10 percent), foreign material and debris intrusion (10 percent), sediment deposition

(9 percent), and pipe coating failure and calcium carbonate deposition (1 percent). The study

identified several actions as potential NRC requirements.

NRC Generic Letter 89-13 was issued on July 18, 1989 to request each licensee and applicant

to inform the NRC whether it has established programs to implement the recommendations of

the Generic Letter or that it has pursued an equally effective alternative course of action. This

request was instituted because as described in the Generic Letter, the staff has been studying

the problems associated with service water cooling systems for a number of years. Based on

the degradation occurrences reported in IE Bulletin 81-03, IN 81-21, Generic Issue 51

("Proposed Requirements for Improving Reliability of Open Cycle Service Water Systems), and

the AEOD Case Study, the staff issued Generic Letter 89-13 to address the various forms of

degradations in the service water systems. The recommended actions identified in the Generic

Letter to be taken by the licensees include various surveillance programs; control techniques;

test programs; frequent maintenance; inspection programs; confirmation of system performance

in accordance with the licensing basis for the plant; and confirmation that the maintenance

practices, operating and emergency procedures, and training are adequate. A supplement to

the Generic Letter 89-13 was issued by the NRC on April 4, 1990 which contains the questions

and answers read into the transcripts during several workshops the NRC conducted in 1989.

Other NRC Information Notices related to degradation of piping systems that contain buried

piping are IN 88-37 "Flow Blockage of Cooling Water to Safety System Components," June 14,

1988, IN 90-39 "Recent Problems with Service Water Systems," June 1, 1990, IN 94-79

"Microbiologically Influenced Corrosion of Emergency Diesel Generator Service Water Piping,"

November 23, 1994, and IN 86-96 "Heat Exchanger Fouling Can Cause Inadequate Operability

of Service Water Systems," November 20, 1986.

Operating Experience Reported in License Renewal Applications

Another source of operating experience at NPPs is contained in the License Renewal

Applications (LRAs) recently submitted for twelve plants. These LRAs have been reviewed for

descriptions of operating experience for buried piping. A short description of the operating

experience that was reported for buried piping systems at each plant is presented in Table 2.2

under the "Comment" column. It should be noted that some of the LRAs did not provide specific

30
or complete operating experience for the buried piping and so there probably would be some

additional cases of degraded buried piping. ,

From Table 2.2, the following degradation occurrences in buried piping have been reported in

the LRAs: I. . r. '

SYSTEM PLANT DEGRADATION

Service Water Catawba Fouling, through-wall pits

Diesel Fuel Oil Calvert Cliffs', ' Pipe wrap damage

Fire Protection Hatch . Coating deterioration, fouling of lines due to Fi rondenrCir tn g Hatch 'corrosion

ConenerCicuatng Catawba, McGuire. Interior coating failure, crack in weld, pinhole Water ________I__ ____-_______________I___

It should be noted that a few of the LRAs indicate that some of the degradations were initially

caused by improper application of coatings, construction methods, or in one instance

waterhammer load.

Although this listing of degradations is not extensive, it indicates that the primary manifestations

of degradation are deterioration of the Interior or exterior coating, through-wall pits or holes, and

fouling.

Operating Experience Presented in EPRI Reports

Operating experience with buried piping is also described in EPRI reports. Much of the

information is presented in the form of case histories contained in various EPRI reports such as

EPRI TR-103403 (1993), TR-102174 (1993), TR-101541 (1993), 1006994 (2002), and a

technical report prepared for EPRI by G. J. Licina (1988). Descriptions of the degradations are

primarily contained in papers presented at EPRI sponsored workshops, reported in proceedings

and compendium type documents, and were obtained from surveys. Many of the case histories

describe degradation'of piping in the service water system, where problems in buried piping

have been-identified. As reported, the primary cause of degradation in service water systems is

corrosion and fouling. The type of corrosion and fouling mechanisms vary significantly

depending on the plant location, pipe material, external and internal environmental conditions,

operation of the system, and maintenance procedures. Various forms of corrosion are present in

most service water systems and pipe materials. These include general corrosion, MIC, crevice

corrosion, galvanic corrosion, erosion, pitting; fouling, and soil related corrosion. As a result,

EPRI has and is continuing to sponsor numerous studies to address service water system

degradation. '

NUREG-1522 -

In June 1995, the NRC published NUREG-1522 which describes the condition of structures and

civil engineering features at operating nuclear power plants. The NUREG contains descriptions

of age-related degradation, which were obtained from many different sources. The most

significant information came from site visits at six older NPPs licensed before 1977. The report

-31
alL

indicated that there was internal coating degradation of buried piping at three of the six plants visited. Remedial action was taken by the licensees after the degradation resulted in inadequate flow conditions or unacceptable water quality.

3.3 Important Aging Effects for Use in this Study

Although there are numerous aging mechanisms possible for buried piping, the analysis described in this report is based on the aging effect or manifestation of the degradation, not what causes the degradation. This approach is taken because to achieve the objective of developing degradation acceptance criteria (DAC), the degradation criteria will need to be developed in terms of observable levels of degradation which normally correspond to aging effects such as loss of material in the pipe wall. Based on Table 3.3, the primary aging effects that are caused by almost all aging mechanisms are thinning of the pipe wall over a region and localized loss of material/pitting in the pipe wall. The remaining aging effect of loss/reduction in flow is not addressed because this aging effect can be monitored by measuring performance parameters of the system such as flow rates, pressure, and sampling of the fluid.

Degradation to the internal or external coatings as reported in Table 2.2 for some plants is not considered because the coating is a protective material whose deterioration can lead to wall thinning or pitting of the pipe wall at some time in the future, only if no action is taken. As long as degradation of the steel pipe has not occurred, degradation of the coating does not affect overall plant risk. The purpose of this study is to develop DAC on degraded buried piping and not acceptance criteria on the coating material. It is expected that any degradation identified with the interior or exterior coating of buried piping will be repaired unless otherwise justified.

3.4 Degradation Rates For Corrosion and Localized Loss of MaterialPitting

The rate of degradation of steel buried piping is a function of environmental variables, metallurgical variables, and hydrodynamic variables. Environmental variables that can affect the degradation rates occur on the exterior surface of the buried pipe and inside surface of the pipe. For the external surface of the pipe, the rate of degradation is a function of parameters such as aggressive chemicals, oxygen, pH level, and stray currents that may exist in the soil material and groundwater (if present). The rate of degradation on the interior pipe surface is a function of fluid parameters such as fluid velocity, temperature, aggressive chemicals, pH level, dissolved oxygen, and biological elements. Metallurgical variables consist of the chemical composition of various elements in the pipe material such as the weight percentage of chromium, molybdenum, and copper in the steel, which may affect the degradation rate. Hydrodynamic variables such as fluid velocity, piping configuration, and roughness of the pipe inner surface also affect the

degradation rate.

Other variables that may affect the degradation rate are: time, type of corrosion/degradation, and whether the piping is pressurized. Depending on the conditions and time period of interest, the degradation rate may not be constant with respect to time. The two types of aging effects which are evaluated in this study (general wall thinning and localized loss of materialpitting) may have some effect on the degradation rate of the buried pipe. In addition, the degradation rate is also expected to be affected by piping that is normally operating and thus 'continuously" subject to internal pressure, and by piping that is normally in standby and thus is not subject to

internal pressure at all times.

Based on the above discussion, it is evident that predicting an accurate degradation rate for buried piping systems is difficult to achieve, and beyond the scope of this research program.

32

Il
Therefore, a literature search was performed to determine what are typical degradation rates for

buried piping systems that might be appropriate for use in nuclear power plants. Based on EPRI

Report TR-103403 (1993), general corrosion rates vary from 1 to >10 mils/year (1 mil per year =

0.0254 mm per year (0.001 in. per year)) for carbon steel and low alloy steels in fresh water at

temperatures of 1.670C to 40.60C (350F to 1050 F). Assuming 3 mils/year and a 40 year life, this

results in a loss of thickness equal to approximately 0.318 cm (1/8 in.), which should have been

considered as corrosion allowance in the original design of buried pipe. Corrosion rates of

stainless steels, nickel based alloys, and copper alloys have much lower corrosion rates, often

less than 1 mil per year. These materials would be' used in buried piping subjected to more

aggressive environments such as seawater or brackish waters, or where safety concerns

require more corrosion-resistant material.

Since there wasn't much more information that could be identified specifically for buried piping,

data on degradation rates for above ground piping systems were also searched. Degradation

occurrences reported in NRC Information Notices were identified and reviewed. Information

Notices that provided quantitative data on degradation rates are IN 2001-09; IN 86-106,

Supplement 3; IN 87-36; IN 91-18; and IN 92-35. A review of these Information Notices

indicates that the degradation rates for the reported occurrences generally went as high as 60

mils per year, with one case for localized thinning at 90 mils per year. It should be noted that

most of these cases occurred in high energy lines such as feedwater systems and it could be

argued that their degradation rates are more severe than what would be expected in buried

piping systems operating at lower pressures, temperatures, and fluid velocities. On the other

hand, these above ground piping systems are not subjected to the external environment that

buried piping may be exposed to. Often this external environment in buried piping is mitigated

by means of external coatings on the pipe or sometimes by the use of cathodic protection

systems. The information provide by these Information Notices do'give a measure of perhaps

the upper bound of what might be expected in buried piping systems.

Based on the above discussion, it appears that a reasonable range of degradation rates for

buried piping would be between 1 and 100 mils per.year. This information is only provided as

guidance on typical values that have been reported.'The selection of an appropriate degradation

rate is the responsibility of the individual performing the assessment, based on the conditions

that exist for a particular buried piping system.

.33
Table 3.1 Degradation Mechanisms of Buried Commodities (Esselman et al., 1997)

Corrosion Attack of Metals

Uniform Corrosion

Pitting

Crevice Corrosion

Intergranular Corrosion

Environmentally Induced Corrosion (including Stress

Corrosion Cracking)

Microbiologically Influenced Corrosion

Galvanic Corrosion

Selective Leaching/Dealloying

Polymer Degradation

Chemical Attack

Thermal Decomposition

Mechanically Induced Damage

Concrete Degradation

Leaching

Abrasion

Freeze-Thaw

Chemical Attack

Cracking

Reinforcement Corrosion

Mechanical Failure from Imposed Loading

Differential Settlement

Freeze-Thaw and Frost Heave

Heavy Ground-Surface Loading Fatigue

Imposed Anchor Displacement Fatigue

Tree Root Encroachment

Ground Water Erosion

Rotating Equipment

Soil Arching

Failure of Deqradation Protection

Protective Coating Degradation

Cathodic Protection Failure

Protective Conduit or Encasement Failure

34

IlI
Table 3.2 NUREG-1801 GENERIC AGING LESSONS LEARNED (GALL) REPORT, APRIL 2001

INFORMATION CONTAINED IN GALL RELATED TO BURIED PIPING

GALL: VII Auxiliary Systems, C1 Open-C ycle Cooling Wa er System (Serv ce Water System), Cl .1 Piping

Structure and/or Aging Further

Item Component Material Environment Effect/Mechanism Agin Management Program (AMP) Evaluation

C1.1-a Piping Carbon steel Raw, Loss of material/ Chapter XI.M20, 'Open-Cycle Cooling No

C1.1.1 Piping and fittings (with or (for fresh untreated salt General (only for Water System" and Chapter XI.M33,

without internal lining or water only), water or fresh carbon steel "Selective Leaching of Materials"

coating) aluminum- water without

bronze, brass, lining/coating or

copper-nickel, with degraded

stainless steel lining/coating),

selective leaching

(only for

aluminum-

::-, -. -- -bronzej brass,

andcopper-., . . ;

.nickel), pitting, ,-

- - crevice, galvanic,

.. nmicrobiologically

influenced

corrosion and. -

biofouling

C1.1-b Piping - Carbon Steel Soil Loss of material/ Chapter XL.M28, "Buried Piping and No

C1.1.2 Underground piping and General, pitting, Tanks Surveillance," or

fittings (external surface, crevice, and Yes,

with or without organic microbiologically Chapter XL.M34, "Buried Piping and detection of

coating or wrapping) influenced Tanks Inspection" aging

corrosion effects and

operating

experience

are to be

further

evaluated

C1.1-c Piping Cast Iron Soil Loss of material Chapter XL.M33, "Selective Leaching No

C1.1.2 Underground piping and selective leaching of Materials"

fittings (external surface, and general

with or without organic corrosion,

coating or wrapping)

35
GALL: VII Auxiliary Systems, G. Fire Protection

Structure and/or Aging Further

Item Component Material Environment Effect/Mechanism Aging Management Program (AMP) Evaluation

G.6-b Water-based fire protection Carbon steel, Raw water Loss of material/ Chapter XI.M27, "Fire Water System" No

system cast iron, General, galvanic,

G.6.2 Filter, fire hydrant, bronze, pitting, crevice,

mulsifier, pump casing, copper, microbiologically

sprinkler, strainer, and stainless steel influenced

valve bodies (including corrosion and

containment isolation biofouling

valves)

GALL: VII Auxiliary Systems, H1 Diesel Fuel Oil System

Structure and/or Aging Further

Item Component Material Environment Effect/Mechanism Aging Management Program (AMP) Evaluation

H1.1-a Piping Carbon steel Outdoor Loss of material/ A plant-specific aging management Yes, plant

H1.1.1 Aboveground piping and ambient General, pitting, program is to be evaluated. specific

fittings conditions and crevice

corrosion

H1.1-b Piping Carbon steel Soil and Loss of material/ Chapter XI.M28, 'Buried Piping and No

H1.1.2 Underground piping and ground-water General, Tanks Surveillance," or

fittings galvanic, pitting, Yes

crevice and Chapter XL.M34, 'Buried Piping and detection of

microbiologically Tanks Inspection" aging

influenced effects and

corrosion operating

experience

are to be

further

evaluated

36
GALL: VilI Steam and Power Conversion System, E. Condensate System,

Structure and/or Aging Further

Item Component Material Environment Effect/Mechanism Aging Management Program (AMP) Evaluation

E.5-d Condensate storage Carbon steel Soil and Loss of material/ Chapter Xi.M28, "Buried Piping and No

E.5.1 Tank (buried, external ground water General, pitting, Tanks Surveillance," or

surface) crevice, and Yes

microbiologically Chapter XI.M34, "Buried Piping and detection of

influenced Tanks Inspection" aging

corrosion effects and

operating

experience

are to be

further':

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _e v a luava l a te

GALL: Vill Steam and Power Conversion System, G. Auxiliary Feedwater System (PWR)

Structure and/or Aging Further

Item Component Material Environment Effect/Mechanism Aging Management Program (AMP) Evaluation

G.1 -c Auxiliary feedwater piping Carbon Treated water Loss of material/ Chapter XI.M2, 'Water Chemistry," for Yes,

G.1.1 Piping and fittings steel General, pitting, PWR secondary water in EPRI detection of

(aboveground) and crevice TR-1 02134 aging

G.1.2 Piping and fittings (buried) corrosion effects is to

The AMP is to be augmented by be

verifying the effectiveness of water evaluated

chemistry control. See Chapter XI.M32,

One-Time Inspection," for an

acceptable verification program.

G.1 -d Auxiliary feedwater piping Carbon Untreated Loss of material/ A plant-specific aging management Yes, plant

G.1.1 Piping and fittings steel water from General, pitting, program is to be evaluated. specific

(aboveground) backup water crevice, and

G.1.2 Piping and fittings (buried) supply microbiologically

influenced

corrosion, and biofouling

37
G.1 -e Auxiliary feedwater piping Carbon Soil and Loss of material/ Chapter XI.M28, 'Buried Piping and No

G.1.2 Piping and fittings (buried) steel groundwater General, pitting, Tanks Surveillance," or

external surface crevice, and

microbiologically Chapter XI.M34, "Buried Piping and Yes,

influenced Tanks Inspection" detection of

corrosion aging

effects and

operating

experience

are to be

further

evaluated

38

r
Table 3.3 Buried Piping Aging Mechanisms and Aging Effects

Aging Aging Effects Material Manifestation COMMENTS

Mechanisms AigEecs Type ______________________

General Loss of material cs, ci Thinning of pipe over a region

corrosion

Pitting Loss of material cs, ss Localized pits/holes in pipe wall

corrosion

Crevice Loss of material cs, ss, Localized loss of material in Generally requires stagnant or low flow

corrosion cu, ni regions of contact between

__ , _ metals or metals and nonmetals

Galvanic Loss of material cs, c Can develop in metals that are further apart in the

corrosion "Galvanic Series." The lower noble metal will corrode.

Selective Loss of material ci

leaching

Microbiologi Loss of material, cs, ss, Can be internal & external Conditions that promote aging effect are stagnant or

cally & ross/reduction concrete2 operation with low or intermittent flow. Use of onceinfluenced in flow cs - blockage which can reduce through systems using water from lakes, cooling

corrosion flow, pitting ponds, or water sources with high organic material.

(MIC)

ss - pitting through wall 2 Concrete pipe is primarily used for large diameter

generally at welds lines which are/should be periodically inspected

Biofouling Loss of material, cs, ss

& loss/reduction __ in flow

Fouling Loss of material, cs, ci, ss

& loss/reduction

in flow

Erosion Loss of material Various Loss of material primarily at Primarily a concern for higher fluid velocity and

elbows and bends suspended particles.

Cavitation Loss of material Various Thinning of pipe Not common because aging mechanism is normally

III I_ designed out from piping system.

Legend

Material: cs is carbon steel (including low alloy steel), ss is stainless steel, ci is cast Iron, cu is copper, ni is nickel-based alloys

39
4 DETECTION OF AGE-RELATED DEGRADATION AND CONDITION ASSESSMENT

4.1 Inspection Methods

Inspection methods for the degradation of buried piping can be based on visual, nondestructive, or destructive methods; Since degradation mechanisms can cause aging effects on

the interior and/or exterior of buried piping systems, information about the condition of the inside

and outside surface of buried piping is important. Large diameter lines such as portions of the

service water system usually can be examined by manual visual inspection provided there is

access to the line. Smaller diameter lines however, are not easily accessible and require other

techniques which have been improved significantly over recent years. The methods that can be

used to inspect the condition of buried piping are described below. The use'of a particular

method depends on the size of the line, access to the interior or exterior surface, pipe material,

aging effect of interest, and cost.

Visual Inspection

This is the most common form of inspection of the condition of the interior or exterior buried

piping. For interior examination of large diameter lines, inspections are usually performed during

plant outages where a trained individual (inspector) enters the pipeline to examine the condition

of the pipe surfaces, coatings (if applicable), welds, and mechanical joints. If the water in the

line is not drained, inspections can still be performed using trained divers. The inspector can

identify any fouling of the pipe, loss of wall thickness, degradation of coating, and identify the

extent of any other degradation. Loss of wall thickness can be identified using a pit gauge to

measure pit depth, ultrasonic test (UT) meter to measure general loss of material, and tape

measure to record the area of the corroded region. Inspection for coating degradation would

include examination for cracking, blistering, debonding, peeling, erosion, and general loss of

coating material. During the inspection the inspector can collect any built-up material due to

fouling or corrosion by-products for subsequent analysis. In addition, the inspector can insert

and remove coupons which can be evaluated for degradation of the pipe material.

Sometimes, an indication of the condition of the interior surface for buried piping can be

determined by examining accessible entry points where the buried piping rises above the,

ground surface or enters into buildings. This may not be reliable though if conditions of the

buried piping section are different than the accessible portions of pipe above ground or within

the buildings. This may be due, as an example, tostagnant water in the buried piping section

which may not exist in the other regions being examined.

Visual inspections from inside the pipe cannot identify degradation on the outside surface of the

pipe unless corrosion or pitting penetrates the thickness of the pipe. Therefore, to obtain

complete knowledge of the condition of a buried pipe, examination of the inside and outside

surface is recommended. The same visual inspection methods described above can be used to

examine the exterior surface of the pipe; however, excavation would be needed to gain access

to the exterior pipe surface.

Cameras .

Cameras can be used for visual inspection of buried pipes. These cameras provide visual type

information without the need for direct personnel inspection or excavation to gain access to

buried pipe. These cameras are useful for smaller diameter lines where direct visual inspection

by personnel is not possible. Presently, these cameras are tethered and may be difficult to

41
.1

operate in tees, bends, vertical segments, and have a limited range in terms of length of

operation in the buried pipe.

Ultrasonic Test (UT)

The UT method is used to measure wall thickness in pipe. The UT method is based on the

pulse echo principle in which a short ultrasonic pulse is generated in the transducer head and

transferred into the body to be measured. The pulse travels through the pipe wall and then

reflects from the back of the pipe wall or surface of a discontinuity and is returned to the

transducer. The transmission time of the pulse from when it enters the pipe wall to when it

returns is recorded with UT equipment. Multiplication of this transmission time by the speed of

sound in the pipe material provides the thickness of the pipe wall. This method can be used to

accurately identify degradation of buried pipe which results in wall thinning. Some of the UT

equipment are hand held devices and can be used in submerged conditions.

Because UT is a slow process and is not practical to examine long lengths of buried pipe or

large surface areas, it is usually used to perform inspections in areas of concern and as a 'spot

check" for sample locations. Areas of concern for which UT would be utilized include regions

where a leak is observed, at welded joints, and areas where loss of material is noted.

A technique called guided wave ultrasonic scanning method can be used to inspect buried pipe

over long runs from a single set-up point. The method requires that access to the pipe at one

point be made (on the order of 61.0 cm (24 in.) along the pipe) and the scan can be made in

each direction to distances of about 27.4 m (90 ft). It works for pipe sizes in the range of 2.54 to

91.4 cm (1 to 36 in.) in diameter or more.

Electromagnetic Test

Electromagnetic test methods use an electric current or magnetic field to detect discontinuities

or variations in materials. The electric current can be applied directly or by a magnetic field

which is a more common approach. This method is often called 'eddy current testing. The

frequency used, conductivity, and magnetic permeability of the material determine the depth of

penetration of the eddy currents in the component. The method can only be used on conducting

materials.

A low frequency electromagnetic technique is available for detecting and quantifying

degradation on the inside, outside, and within the pipe wall in a single scan. According to a

manufacturer of such test equipment (TesTex, Inc.), the device is hand held, can inspect

through coatings, and can test at a rate of 4.57 to 6.10 m (15 to 20 ft) per minute over a width of

approximately 7.62 to 10.2 cm (3 to 4 in.). It can detect pitting, wall thinning, and cracking. The

separation between the sensors and the pipe surface can be as much as 0.953 cm (0.375 in.).

The unit which is primarily used to examine pipe from the outside surface, can inspect ferrous

and stainless steel pipe material and can operate while the piping is in-service or out of service.

This equipment has already been utilized at NPPs for detection of MIC in service water systems

and fire protection piping (it is not clear whether it was used for above ground or buried piping).

There are some limitations regarding depth of penetration for measurements, distances

separating device to the pipe (which may require cleaning or surface preparation), and accuracy

(level of defect detection). Therefore, once locations of degradation are identified using this

technique, it is recommended to follow-up with UT examination to obtain more accurate

readings of the affected areas.

42
Pireline Pias (In-Line Inspection) !!,

Pipeline 'pigs" are devices that are inserted into pipelines to perform maintenance or inspection

functions. Pipeline pigs for cleaning or emptying pipelines have been used for many years in

numerous pipeline industries. Depending on the need, different pigs are used to clean the

pipeline, dewater the pipeline, sweep out air pockets, check pipe inner diameter, or remove

condensate in pipelines. In addition to these maintenance operations, "smart pigs" have been

developed which can detect and determine the extent of degradation in pipelines. These smart

pigs are computerized, self-contained devices that are propelled forward by the liquid flowing

through the pipe and record the condition as they move along. Smart pigs can be fitted with

corrosion tools such as magnetic field or ultra-sound to detect changes in pipe wall thicknesses,

crack detection tools utilizing ultrasound to detect cracks, and geometry tools to identify

deviations in a pipeline internal diameter or locations of dents in the pipe. A major advantage

with the smart pigs is that they allow remote inspection capability where excavation or access

by direct visual examination is either too costly or not possible.

Based on EPRI Report GC-109054 (1997); smart pigs are about 2.44Tm (8 ft) long and can

travel inside the pipe at the flow rate of the fluid, typically 4.02 to 14.5 km/hr (2.5 to 9 mph) or

about 1.22 to 3.96 m/s (4 to 13 ft/s). The location of the pig is tracked by 3 to 4 odometer wheels

which identify the distance the pig travels along the pipe with respect to a reference location

such as a circumferential weld. They are able to negotiate pipe bends and elbows while they

record data using electronic probes or transducers. Smart pigs can be untethered operating on

batteries for several days. They contain 1 to 4 computers which store the data recorded from

magnetic flux leakage (MFL) and ultrasonic (UT) thickness measurements. MFL sensitivity to

pipe wall thinning is about 10% with an 80% confidence level, while UT sensitivity for a 2.54 cm

(1 in.) diameter pit is approximately 0.203 cm (0.08 in.) deep in 1.27 cm (1/2 in.) thick pipe wall

thickness. Additional technical information is available in the referenced EPRI report.

More detailed description and guidance on the use of NDE methods for smart in-line inspection

devices (pigs) are presented in EPRI Report GC-108827 (1998). Since straight sections of

buried pipe at NPPs are relatively short and contain a number of elbows or bends, the report

suggests that tethered, self-propelled vehicles provide the best option for examination of buried

pipe in the nuclear industry. The EPRI report describes the use of magnetic flux leakage,

ultrasonic immersion, remote field eddy current, and low frequency eddy current methods with

the in-line inspection devices. Guidance on the applicability of these methods to conditions such

as types of aging effects, pipe sizes, and lining within a pipe is provided in the report. In

addition, the availability and capability of these devices to examine buried piping is discussed.

Cathodic Protection System

Although a cathodic protection system is not an inspection method, it can provide some

information which would indicate whether buried piping is adequately protected against

corrosion or in the case of abnormal electrical readings, degradation problems may be

developing. Many buried piping systems are cathodically protected. Cathodic protection is a

technique which connects a metal of higher potential (anode) to the buried metallic piping. This

creates an electrochemical cell that causes the lower potential pipe to become a cathode

thereby protecting it from corrosion. In Galvanic cathodic protection systems, anodes are used

which have a natural potential more reactive than that of the structure being protected. In

impressed current systems an external power source to impress a current on the buried piping

is used. impressed current cathodic systems have many advantages but they must be

monitored regularly (as often as monthly or bimonthly). It is. this monitoring that provides an

. 43
indication of the effectiveness of the cathodic protection system and readings of the current or

voltage that are out of range is a sign of some breakdown in the protective system or an

indication that degradation may be developing.

Other Methods

There are other methods that have been developed using different technologies or variations of

the technologies described above. These include remote field eddy current, magnetic flux

leakage, and infrared thermography. Test methods for priestesses concrete pipe include

acoustic emission, impact-echo, hammer testing, and remote field eddy current. Although NDE

methods for concrete pipe are not as well developed, concrete pipe is used primarily for large

diameter lines which would likely permit direct visual inspection.

4.2 Regulatory Requirements and Technical Guidance

There are a number of regulatory requirements (e.g., 10 CFR 50, Appendix A, General Design

Criteria) that apply to buried piping systems, but many of these requirements relate to initial

plant design and pressure/functional testing. NRC generic correspondences such as Generic

Letters and Information Notices have been issued on degradation of buried piping. These have

been described in Section 3.2 of this report. Other regulatory requirements or technical

documents that relate to degradation of buried piping are discussed below.

10 CFR 50.65 - Maintenance Rule

On July 10, 1991, the NRC published 10 CFR 50.65 entitled, 'Requirements for Monitoring the

Effectiveness of Maintenance at Nuclear Power Plants," referred to as the Maintenance Rule.

The purpose of the regulation, which went into effect on July 10, 1996, is to monitor the

effectiveness of maintenance activities for safety significant plant equipment in order to

minimize the likelihood of failures and abnormal events caused by the lack of effective

maintenance. The final rule requires that licensees monitor the performance or conditions of

structures, systems, and components (SSCs) against licensee-established goals in a manner

sufficient to provide reasonable assurance that the SSCs will be capable of performing their

intended functions. Such monitoring needs to be established commensurate with safety and,

where practical, take into account industry operating experience. For buried piping that meets

the scope definition in paragraph 10 CFR 50.65 (b) of the Maintenance Rule, the licensee would

be required to monitor the performance or condition of the piping.

Several other NRC documents related to the Maintenance Rule contain additional technical

information and guidance: "Statements of Consideration for 10 CFR 50.65," Regulatory Guide

1.160, Rev. 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and

several NRC inspection procedures.

NRC Inspection Procedures

NRC Inspection Procedure 62706, 'Maintenance Rule," provides instructions to the staff for

verifying implementation of 10 CFR 50.65. It specifies the inspection requirements, inspection

guidance, and referenced material that provide additional guidance on acceptable methods to

implement the requirements of the Maintenance Rule.

NRC Inspection Procedure 62002, "Inspection of Structures, Passive Components, and Civil

Features at Nuclear Power Plants," provides guidance to the staff to (1) evaluate by visual

44

Il
examination and/or review of licensee documentation the condition of structures, passive

components, and civil engineering features and (2) verify implementation of 10 CFR 50.65. The

inspection procedure lists buried piping, pipe supports, and equipment anchorages as one of

ten groups of SSCs that would be included for review under the Maintenance Rule. Specific

guidance is provided in paragraph 03.01(e) of the Inspection Procedure for buried piping. It

indicates that the documentation of the licensee's maintenance program, including preventive

maintenance for buried piping, is reviewed. Seismic Category I buried piping should be able to

perform its functions under vibratory loads resulting from seismic events. The cathodic

protection system (if present) should be functional and the inspector should review the

licensee's documentation and surveillance to ensure that the system is protecting all elements

served by the cathodic protection system. Licensees should include acceptance criteria for

corrosion of piping, pipe supports, and anchorages. Buried piping maintenance programs

should include visual examinations when piping is accessible.

10 CFR Part 54- License Renewal Rule

The requirements for obtaining the renewal of a nuclear power plant operating license for up to

an additional 20 years are presented in 10 CFR Part 54 - License Renewal Rule. Under this

rule, the applicants are required to identify all SSCs that are within the scope of the rule. A

screening review is then required to identify those SSCs that are "passive and long-lived"

structures and components. For the passive, long-lived structures and components, the,

applicant must demonstrate that the effects of aging will be managed so that the intended

function(s) will be maintained consistent with the current licensing basis through the period of

extended operation. Depending on the system, NPPs have buried piping that fall within the

scope of the License Renewal Rule.

In July 2001, the NRC published the 'Standard Review Plan for Review of License Renewal

Applications for Nuclear Power Plants" (SRP-LR)'(NUREG-1 800). The SRP-LR was prepared to

provide guidance for staff reviewers in performing safety reviews of applications to renew

licenses of NPPs in accordance with 10 CFR Part 54. The SRP-LR in many cases references

the 'Generic Aging Lessons Learned " (GALL) report. The GALL report (NUREG-1 801) presents

an evaluation of existing generic programs to document the conditions under which these

programs are considered adequate to mange identified aging effects without change and the

conditions under which existing programs should be augmented. The GALL report includes

tables for various passive-structures and components within the scope of the License Renewal

Rule. The tables' list for each structure or component the material type, environment, aging -

effect/mechanism, aging management program, and whether further evaluation is needed. The

information obtained from the GALL report for buried piping is presented in Table 3.2 and is

discussed in Section 3.1 of this'report.

The GALL report also contains evaluations of acceptable aging management programs for the

various structures and components within the scope of the License Renewal Rule. Aging

management programs evaluated in GALL include Buried Piping and Tanks Surveillance,

Buried Piping and Tanks Inspection, Open-Cycle Cooling Water System, Selective Leaching of

Materials, Fire Water System, Water Chemistry and a related One-Time Inspection Program. In

some cases'a plant-specific program would be required. The GALL evaluates the aging

management programs using 10 attributesdconsisting of the scope of program, preventive

actions, parameters monitored/inspected, detection of aging effects, monitoring and trending,

acceptance'criteria, corrective actions, confirmation process, administrative controls, and

operating experience.

45
4.3 Industry Programs to Manage Aging

As a result of the concern with degradation to SSCs, the nuclear industry has various programs

that manage aging. These programs have been instituted for a number of reasons including

NRC regulatory requirements; state and local codes; cost considerations for replacement,

repair, and down time; environmental concerns; and increased safety. The programs include

preventive maintenance and corrective maintenance, maintenance procedures, inspection and

examination procedures, testing programs, and coating programs. That is why for many

licensees who are applying for license renewal, they are able to take advantage of existing

programs that manage aging rather than developing and committing to new programs.

A major driving force to expand and improve these programs to manage aging was the

Maintenance Rule and License Renewal Rule which were discussed earlier. To support NPPs in

developing acceptable maintenance and aging programs to address the Maintenance Rule and

the License Renewal Rule, the industry developed guidance documents, NUMARC 93-01

(1996) and NEI 95-10 (1996).

NUMARC 93-01

NUMARC 93-01 (1996), "Industry Guideline for Monitoring the Effectiveness of Maintenance at

Nuclear Power Plants," was issued in April 1996. This document describes an acceptable

approach for individual NPPs to implement the requirements of the Maintenance Rule and to

build on the progress, programs, and facilities already established to improve maintenance. The

guideline provides an approach for identifying the SSCs within the scope of the Maintenance

Rule. It then describes the approach for developing plant-specific risk and performance

criteria/goals, and monitoring the SSCs against the criteria. If performance criteria are not being

met, then goals are established to make the necessary improvements in performance. For

buried piping within the Maintenance Rule, it is expected that either existing plant-specific

programs are relied upon or new plant-specific programs have been developed.

NEI 95-10

NEI 95-10 (1996), "Industry Guideline for Implementing the Requirements of 10 CFR Part 54-

The License Renewal Rule," was issued in March 1996. This document provides an acceptable

approach that licensees can follow for implementation of the License Renewal Rule. The

guideline describes methods for identifying the scope, identifying the intended functions,

identifying the structures and components subject to aging management review, assuring that

aging effects are managed, application of inspections for license renewal, identifying and

evaluating time-limited aging analyses, and describing a format and content of a license renewal

application. In Appendix B of the guideline, a table is presented which includes under the

category "non-class I piping components," underground piping and identifies it as a passive

component.

Industry Life Cycle Management Programs

In an effort to manage aging degradation, improve equipment reliability, and reduce

obsolescence of important structures, systems, and components (SSCs), the industry is

developing Life Cycle Management" (LCM) processes. To assist the nuclear industry in this

endeavor, the Electric Power Research Institute (EPRI) is researching and preparing LCM

Sourcebooks for selected systems and components. As indicated in EPRI Overview Report

1003058 (2001), the objective of the LCM sourcebook effort is to provide plant system

46
engineers with generic information, data, and guidance which can be utilized to develop longterm reliability plans for SSCs.

One of two prototype sourcebooks already prepared covers the passive SSC of buried piping

(EPRI Report 1006616, 2002). This LCM sourcebook covers buried large-diameter piping,

which is defined as buried piping 50.8 cm (20 in.) and larger that are within the condenser

circulating water system (CCW), essential service water system (ESW), and the non-essential

service water system (NESW). The buried piping sourcebook describes operating experience

and performance history, guidance for plant-specific condition and performance assessment,

aging mechanisms, alternative LCM plans, determination of failure rates, guidance for economic

modeling, and information sources and references. This document also includes a technical

evaluation of a hypothetical case to illustrate the process of performing an LCM evaluation and

also some summaries of buried piping aging management programs from specific NPPs.

47
5 FRAGILITY EVALUATION OF DEGRADED BURIED PIPING SYSTEMS

In this section, the fragility of buried piping is determined for undegraded and degraded pipe.

Fragility is the cumulative probability of failure, in this case for the pipe, for a given value of input

load. The governing loads acting on buried pipe are identified and then the applicable equations

are used to perform the fragility analysis. The results of the fragility analysis developed in this

section are later combined with the risk assessment analysis from Section 6 to develop

degradation acceptance criteria. The description of how the fragility results and risk assessment

results were used to develop degradation acceptance criteria is presented in Section 7.

In this section of the report, the units of measure are first given in English units followed by Si

(metric) units in parenthesis because many of the equations and parameters are derived based

on English units.

5.1 Governing Load(s) for Risk-Informed Study'

The loads that buried piping systems are generally designed for consist of internal fluid

pressure, soil surcharge (dead weight of soil above the pipe), groundwater, surface loads

(permanent loads, or live loads such as cars, trucks, etc.), seismic, and thermal expansion.

Other- loads that are not common but might be considered are surface impact loads, fluid

transients, buoyancy, and soil/building settlement.

5.1.1 -Internal Pressure Loads

These loads are due to the internal pressure of fluid (water) inside the buried pipe. Design of

buried piping typically begins with sizing the required pipe diameter and thickness based on the

internal pressure. After selecting the desired pipe material and diameter to meet certain flow

requirements, the designer calculates the minimum required pipe thickness needed to withstand

the design pressures at the design temperatures. The equations used to calculate the minimum

required wall thickness depend on the code or standard applicable to the intended use. More

discussion about the specific equations used to calculate the required minimum wall thickness is

presented in Section 5.2.

5.1.2 Soil Surcharge (Dead Load)

As discussed in Section 1.2 of WRC Bulletin 446 (Antaki, 1999), soil loads are an important

consideration for rigid pipes and non-ductile pipes such as concrete or cast iron. Soil loads are

also important for pipes with large D/t (diameter to thickness) ratios. Many of the equations that

have been developed for calculating earth loads on buried pipe are often based on the Marston

load theory (discussed in Moser, 2001).

A. Vertical Soil Load on Pipe

Rigid Pipe i ^ ,;

For rigid pipe buried in a trench, the maximum vertical soil pressure at the top of the pipe is

carried primarily by the pipe. The resulta't load on the pipe can be calculated by the following

equation [WRC Bulletins 425 and 446 (Antaki, 1997 and 1999), Moser, 2001; and ASCE

Manuals and Reports of Engineering Practice No. 77JWEF Manual of Practice FD-20)]:

-49
-1

yBd 2 [1 -e 2Kp'(H/Bd) ]

2Kp' (5.1)

which can be rewritten as:

V = CdYBd2 (5.2)

where

[1 _ e-2KpI(I Ia)] Cd = 2-e (5.3)

OTrench where

V = soil load per unit length of pipe (force/length)

Pv = soil pressure load on pipe (force/length2 ) = V / D

D = outside diameter of pipe

y = total unit weight of soil (weight density)

Bd = width of trench

K = Rankine's ratio (for active pressure)

/7/T

Pv

. I

H

D

11 LH

4 I-.

1 - sing

1+sino'

where Q = friction angle in soil Bd

p'= tan A' = coefficient of friction between the backfill material and sides of trench

H = height of fill above the pipe

As explained by Moser (2001), for very rigid pipe (clay, concrete, heavy walled cast iron, etc.)

the fill material at the side of the pipe is more compressible than the pipe and therefore, the pipe

may carry a very large portion of the load V.

Flexible Pipe

For flexible pipe, where the pipe stiffness is close to the soil stiffness, the pipe and side fill

support the surcharge load. Therefore, the load on a flexible pipe can be substantially less than

on a rigid pipe. The maximum resultant load for flexible pipe is expressed as [WRC Bulletins

425 and 446 (Antaki, 1997 and 1999), and Moser (2001)]:

V = CdyDBd (5.4)

where

V = soil load per unit length of pipe (force/length)

Pv = soil pressure load on pipe (force/length2) = V / D

Cd and the other parameters are as defined above

50

11
Steel Pipe

For soil loads on buried steel buried pipe the American Lifelines Alliance (2001) considers steel

pipe to be flexible and recommends that the pressure loading due to the soil above the pipe be

based on a prism of soil with a width equal to the pipe diameter and a height equal to the depth

of fill over the pipe. This leads to the equation for soil pressure on the pipe as:

V=yHD (5.5)

where

V = soil load per unit length of pipe (force/length)

P, = soil pressure load on pipe (force/length2) = V / D

'y and H are as defined above

For steel pipe, the rigid pipe equations lead to an overprediction of pipe loads while the flexible

pipe equations are considered minimum loads. The prism load approach for steel pipe results in

loads that are in-between the loads calculated using the rigid and flexible pipe equations. Over a

long period of time actual pipe loads may approach the prism load, and therefore the prism load

approach is recommended as a basis for design (Moser 2001).

Example

To gain an understanding of the significance of surcharge soil loads on buried pipe, consider the

following example:

Pipe size = 24 in. (61.0 cm)

Pipe schedule = standard thickness = 0.375 in. (0.953 cm)

Wet sand unit weight = 130 lb/ft3 (2,083 kg/m3) (considered as an upper bound value)

Trench Depth = 7 ft (2.13 m) to top of pipe,.'

Trench width = 56 in. (142 cm)

For sand,

K = 0.33 and tt'= 0.50 (based on Table 2.1 presented in Moser, 2001)

H/Bd = (7 x 2)/156 = 1.5

Using equation (5.3), Cd = 1.18

Maximum soil pressure load on pipe:

For rigid pipe, using equation (5.2), V = 278 lb/in'(4,965 kg/m)

(Considering the diameter) r = 11.6 psi (80.0 kPa) pressure

For flexible pipe, using equation (5.4), V = 119 lb/in (2,125 kg/m)

(Considering the diameter) ''~;''- ' --i 4.97 psi (34.3 kPa) pressure'

For steel pipe, using 'equatio' (55), V- = 152 lb/in (2,714 kg/m)

(Considering the diameter)' = 6.32 psi (43.6 kPa) pressure

Thus, for the steel pipe using the soil prism method, the soil pressure of 6.32 psi (43.6 kPa)

acting on top of the pipe is in'between'the values for the flexible pipe and the rigid pipe.

51
-01

B. Side Wall Compressive Stress in Pige

To determine the compressive stress that develops at each side of the pipe, the following

equation can be used:

V

0=-

2t

where t = thickness of the pipe

Example

IV

at t a

(5.6)

Using the results from the previous example, this leads to the following sidewall stress:

For rigid pipe, a = 371 psi (2.56 MPa)

For flexible pipe, a = 159 psi (1.10 MPa)

For steel pipe, a = 203 psi (1.40 MPa)

Therefore, even for the worst case of a very rigid pipe relative to the soil, the maximum

compressive stress in the side wall is only 371 psi (2.56 MPa).

C. Maximum Through-Wall Bending Stress

The through-wall bending stress in the buried pipe developed under the surcharge load can be

calculated using an approach presented in the American Lifelines Alliance Report (2001). This

approach, which is based on the modified Iowa deflection formula, calculates the ovality

(amount of pipe vertical deflection with respect to the pipe diameter).

where

Ay DIKbPV

D [()eq +0.061E']

Ro 3

D = pipe outside diameter

Ay = vertical deflection of pipe

Di = deflection lag factor (-1.0 to 1.5)

Kb = bedding constant (-0.1) Ovalitv o

P, = Vertical pressure on pipe due to soil load

R = pipe radius

(El),q = equivalent pipe wall stiffness per inch of pipe length

(which includes any pipe lining and/or coating if applicable)

E' = modulus of soil reaction of pipe bedding (soil beneath the pipe)

(5.7)

f PiRe

I = - (per unit length of pipe), 12 where t = pipe wall thickness

52

fi
Recommendations for some of the above parameters are provided (Moser, 2001) as follows:

The deflection lag factor accounts for the continued deflection of the pipe over time after

installation of the pipe. Deflections over 40 years could increase as much as 30% and so a

design value of 1.5 for DI is recommended. The Iowa deflection formula for ovality however, is

based on the Marston load approach. Therefore, if the prism load is used for design rather than

the Marston load, the deflection lag factor should be reduced to 1.0 because the long-term load

on the pipe will not exceed the prism load.

The modulus of elastic reaction (E') represents the stiffness of the soil surrounding the pipe.

Average modulus of soil reaction values 'areavailable based on test data.'Values of E' can vary

from 0 for poorly graded and poorly compacted soil up to 3,000 psi (20.7 MPa) for coarse

grained soil that is well compacted (Moser, 2001).

The stress in the pipe is calculated by substituting the ovality calculated above into the following

equation (American Lifelines Alliance Report, 2001) for through-wall stress:

abw 4E (D);; (5.8)

where abW =through-wall bending stress ''

Example

Using the same example as before 24 in. (61.0 cm), standard schedule pipe, 7 ft (2.13 m) soil

cover), the maximum through-wall bending stress is calculated using the soil pressure

previously calculated for steel pipe and the following parameters:

P, = 6.32 psi (43.6 kPa)

D, = 1.0 (since the prism load is used not the Marston load)

E' = assume 1,000 psi (6.89 MPa) for moderate compaction of bedding and well-graded soil,

based on Moser (2001), Table 3.4.-

I= (1375) = 0.00439 in4 per inch of pipe lenrgth (0.0720 cm4 per centimeter of pipe)

Kb = 0.1

Using equation (5.7) leads to Y= .00469 D

Using equation (5.8) leads to ab = 8.51 ksi (58.7 MPa)

This stressis considered to be low, well below the yield stress and'only about 14% of the

ultimate stress value for a typical buried carbon steel pipe.

5.1.3 Groundwater

If the water table is above the buried pipe, theni the effect of the water on the soil surcharge can

be evaluated using the following equation (American Lifelines Alliance, 2001):

Pv =Tyhw +RW'YdH (5.9)

53
where

P, = earth dead load pressure on the pipe (force/length2)

Yd= dry unit weight of fill (weight density)

H = height of fill above the pipe

h= height of water above pipe

yw = unit weight of water (weight density)

RW = water buoyancy factor = 1- 0.33(h,/H)

Note: For the range of buried steel pipe sizes of interest in this study, up to about 42 inches

(107 cm), the upward buoyancy force on a worst-case empty pipe is less than the downward

loads of pipe weight and saturated soil weight. The 42 inch (107 cm) maximum pipe size is

selected as an upper bound because it covers most buried pipe sizes at NPPs, is normally

commercially available in varying schedules, and larger diameters would probably violate the DAt

requirements developed in Section 5.1.5 of this report.

Example

Use the same example as before for dead load and conservatively assume that the water table

is at the ground surface and that Yd (dry unit weight of fill) is equal to 120 lb/ft3 (1,922 kg/M3).

The soil and groundwater load on the pipe calculated using equation (5.9) is 6.94 psi (47.8 kPa),

which is only 9.8% higher than the 6.32 psi (43.6 kPa) soil pressure previously calculated.

5.1.4 Surface Loads

Surface loads could include dead loads such as buildings, tanks, etc., and/or live loads

(temporary loads) such as equipment, vehicles, and railways. For this study, it will be assumed

that there are no buildings or other large uniform dead loads on the surface. Instead, the

evaluation will consider the more likely case of a live load due to a large truck which imposes a

concentrated load at the surface. An equation for calculating stress in a semi-infinite elastic

medium due to concentrated loads applied at the surface was developed by Boussinesq. The

solutions assume that the soil is an elastic, homogeneous, and isotropic material which often is

not the case. However, when properly applied, the Boussinesq solutions have been shown to

give reasonable results for soils based on actual tests (Moser, 2001).

Based on the Boussinesq solution, the pressure Pp decreases as the square of the soil cover H

and is given by American Lifelines Alliance (2001) as:

2 u H2E + (d)2] P (5.10)

where

Pp = pressure transmitted to the pipe wall H

Ps = concentrated load at the surface, above the pipe

H = depth of soil cover above pipe P

d =offset distance from pipe to line of application of | I | |

surface load Q

54

Mn
For severe surface loads such as truck traffic, an AASHTO H20 truck loading will be considered.

The H20 truck loading corresponds to a 32,000 lb (142 kN) load under one axle. For each side

of the axle a wheel loading of 16,000 lb (71.2 kN) concentrated load over a small area is

evaluated and the resulting pressure loadinig on a pipe has been tabulated. The pressure

loading on the pipe as a function of the soil cover, for the H20 truck loading (which is

independent of pipe size) is presented below. The values for pressure include an impact factor

of 1.5 to account for bumps or irregularities in the road. The tabulated values are obtained from

the American Lifelines Alliance (2001).

Live Load Pressure (Pp ) Transferred to Pipe Due to H20 Truck Loading

American Lifelines Alliance (2001)

Height ofcover (ft) 1 2 3 4 5 6 7 8 10

Live load Pp (lb/in2) 12.5 5.56 4.17 2.78 1.74 1.39 1.22 0.69 Negligible

1 ft = 0.3048 m; 1 lb/in2 = 6.89 kPa

This table shows that the live load pressure-due to a truck load diminishes very rapidly with

increasing depth of the pipe. At ten feet (3.05 m) the pressure is considered negligible. As

reported in the American Lifelines Alliance Report (2001), an impact factor of 1.0 would be

applicable to highways for depths over 3 feet'(0.914 m). This would mean that the pressure load

on the pipe for a 3 feet (0.9 14 m) cover (minimum value considered for this study) would be

4.17 psi x 1.0/1.5 = 2.78 psi (19.2 kPa). At 7 ft (2.13 m) the soil pressure in the'pipe would be

0.813 psi (5.61 kPa) (very small)

5.1.5 Combined Loading for Vertical External Soil Pressure Loads

A. Buckling Evaluation

As a check on the potential for buckling of ihe pipe under the soil surcharge dead load,

groundwater, and surface live load, the following equation can be used to calculate what is

referred to as ring buckling (American Lifelines Alliance, 2001):

1321W3'E'(EI)eq (5.11()

PBFSD3

where

PB = allowable vertical soil pressure on pipe to preclude ring buckling

FS = factor of safety; 2.5 for H/D 2 2 and 3.0 for H/D • 2

H = depth of soil cover above pipe

D = diameter of pipe RW= water buoyan'cy factor = 1-0.33(hH), 0 < hW c H

hw= height of water surface above top of pipe

B' = empirical coefficient of elastic support (dimensionless)

Given in AWWA Manual 11 as

-55
- n

Bf= 1

1+4e 065H/D)

E' = modulus of soil reaction (see Section 5.1.2 of this report for more information)

(EI)eq = equivalent stiffness considering bare pipe, lining, and coating (if applicable)

E = modulus of elasticity of material

I = moment of inertia of material = t

3/12

Example

Using the same example as before; a 24 in. (61.0 cm) diameter, standard schedule pipe, with a

depth of soil cover equal to 7 ft (2.13 m), water table conservatively assumed at the ground

surface, and a modulus of soil reaction E' of 1,000 psi (6.89 MPa), the critical buckling soil

pressure load (Pcdtjca,) is calculated as follows:

B1'= 1 , = 0.239 1 +4e (-0.0( 7XI2 /

2 4))

Rw = 1-0.33 (7/7) = 0.67

= 1 3 2 (0.6 7 )(0 2. 3 9 )( 1 000)(29xX0)(0.00439) =217 psi (1.50 MPa)

This is compared to the total applied soil pressure load for dead load (6.94 psi (47.8 kPa) with

groundwater included) plus live load (1.22 x (1.0/1.5) = 0.8 13 psi (5.61 kPa)), which is equal to

7.75 psi (53.4 kPa). The total applied soil pressure load of 7.75 psi (53.4 kPa) is well below the

217 psi (1.50 MPa) critical soil pressure load that would cause ring buckling in the pipe.

For comparison, using a 3 ft (0.914 m) cover, P~itcal results in a critical soil pressure of 207 psi

(1.43 MPa), which is only slightly lower than the 217 psi (1.50 MPa) calculated above. Thus, it is

very unlikely that the steel pipe would buckle for the range of parameters being studied in this

research effort.

B. Pipe Stress

Example

Using the same example as before; the total dead load and live load, including the effect of the

water table at ground surface is 7.75 psi (53.4 kPa). Following the same approach as before for

soil surcharge loads:

Pipe sidewall compressive stress -

From equation (5.6), a = V/2t =7.75 psi x 24 in/(2x.375) = 248 psi (1.71 MPa)

(negligible)

56

"I
Pipe through-wall bending stress -

From equations (5.7) and (5.8) a= 10.4 ksi (71.7 MPa) (considered to be low)

Note that the above calculation was for the 7 ft (2.13 m) soil cover case. If the 3 ft (0.914 m)

(proposed minimum soil cover for this study discussed in Section 5.1.4) was used, the

contribution from dead load would drop off faster than the increase in the live load, and so the 7

ft (2.13 m) case is more conservative.

Effect of Varving DAt and Soil Modulus

To see whether the relatively low stress for combined external loadings applies to other

configurations, consider the variation in stressdue to other pipe diameters and schedules. This

can be done by'using the same example 'as before and solving for the maximum through-wall

bending stress for varying DAt ratios for pipe. The effect of varying DAt is shown for soil modulus

of 2,000,1,000, and 500 psi (13.8, 6.89, and 3.45 MPa).

Maximum Through-Wall Bending Stress

Diameter to thickness ratio (D/t) _20 40 60 80 100 120 140

E' = 2000 psi 1.77 5.30 7.08 7.03 6.36 5.62 4.98

Max. through-wall E' -1000 psi 1.81 6.19 9.96 11.4 11.2 10.4 9.44

bending stress (ksi)-

E'= 500 psi 1.84 6.76 12.5 16.5 18.0 18.0 17.1

1 psi = 0.00689 MPa; 1 ksi = 6.89 MPa

The above tabulation indicates that for E' = 1000 psi (6.89 MPa), with higher DAt ratios there is

an increase in through-wall bending stress to a maximum of 11.4 ksi (78.6 MPa) and then for D/t

ratios above 80, the bending stress decreases. For E' = 500 psi, (3.45 MPa) the bending stress

rises to a maximum of 18.0 ksi (124 MPa) at DAt of 100 to 120 and then decreases for higher DAt

ratios.

Effect of Varvinq' Soil Cover Depth

The amount of soil cover to the top of the buried pipe can also affect the level of stress in the

pipe. Therefore, it is suggested to limit the- depth of soil cover to an amount that would not

develop significant stresses in the pipe. For this study it is recommended to limit the maximum

pipe bending stress from combined external soil loadings (surcharge, groundwater, and surface

live load) to 15 ksi (103 MPa) (25% of the minimum ultimate strength of A 106 Gr. B pipe).

.Using the modulus of soil reaction equal to 1,000 psi (6.89 MPa) (well graded and moderate

compaction), this leads to the following acceptable soil cover depth for use in this study:

57
Acceptable Soil Cover

Diameter to thickness ratio (D/t) 20 30 40 50 60 70 80

Acceptable soil cover for this study (ft) 64 30 18 14 11 10 10

1 ft = 0.3048 m

The above table was prepared for the range of pipe sizes and schedules considered in this

research effort. A D/t limit of 80 was utilized because most buried piping at NPPs have D/t ratios

less than or equal to 80. The maximum pipe size identified at NPPs from Tables 2.1 and 2.2 is

30 in. (76.2 cm). For 30 in. (76.2 cm) pipe, having standard schedule wall thickness (t = 0.375

in. (0.953 cm)), the D/t ratio equals 80. Smaller diameter standard schedule pipes will have

lower D/t ratios.

Effect of Wall Thinning

The sensitivity for reduction in wall thickness due to aging effects was evaluated for its effect on

the pipe through-wall bending stress. Using the same 24 in. (61.0 cm), t = 0.375 in. (0.953 cm)

pipe example as before, but varying the wall thickness, the stress increase due to reductions in

pipe wall thickness is shown below:

Stress Variation as a Function of Wall Loss

Reduction in Wall 0 10 20 30 40 50 60 70

Thickness (%) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Ovality (Ay/D as %) 0.58 0.68 0.78 0.90 1.0 1.1 1.2 1.2

Max. through-wall 10.4 11.0 11.4 11.4 11.0 10.0 8.55 6.69

bending stress (ksi) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

1 ksi = 6.89 MPa

The above results indicate that a reduction in wall thickness increases the ovality somewhat;

however, the bending stress slightly increases and then falls for reductions in wall thickness

beyond 30%. It is interesting to note that with reductions in wall thickness beyond 30%, the

bending stress actually gets smaller. Although this may be unexpected, it can be understood by

examining the equations for ovality and stress. This behavior occurs because as the pipe wall

reductions get very large, the pipe becomes more flexible and its contribution to carrying the soil

pressure load is much smaller than that of the adjacent soil surrounding the pipe. The equation

for calculating stress though is linearly proportional to the pipe thickness so the stress continues

to drop off as the pipe thickness is reduced.

The results shown above are very important because they demonstrate that the stresses due to

vertical external soil loads (surcharge (dead load), groundwater, and live load) are low and are

not significantly affected by wall thinning. This is evident because of the following:

* For the configurations and parameters discussed, the stress in the pipe is considered

low (10.4 ksi (71.7 MPa) for the example studied with 7 ft (2.13 m) soil cover depth and

will be kept below 25% of the ultimate strength of the pipe for all bounding cases).

58

III
. Most significantly, the tabulation for the effects of wall thinning demonstrate that up to

30% wall thinning there is very little effect on the through-wall bending stress and

beyond 30%, the stresses actually begin to reduce.

Based on these findings, the vertical external soil loads due to surcharge (dead load),

groundwater, and live load were not explicitly included in the fragility analysis. However, the,

stresses due to these loads were considered in'developing the degradation acceptance criteria

which is described in Section 7.2.

5.1.6 Temperature

Differential temperature in buried piping causes an unrestrained pipe to expand in accordance

with the following equations:

a(T 2 -T) (5.12)

AL-L - - - (5.13)

where

E = longitudinal strain in pipe'

a = coefficient of thermal expansion of the pipe

T2 = maximum operating temperature

T, = installation temperature

AL = total change in length of a straight pipe segment

L = length of pipe segment -

If a pipe is not restrained then there would be no stresses induced by the change in

temperature. However, in buried piping pipe/soil friction and bends at each end of a straight pipe

section can act to restrain the expansion'of the pipe. If a very conservative assumption is made

that the pipe/soil friction or the bends at the end of straight pipe section fully restrain the pipe,

then the maximum stress in the pipe is calculated by:

a=Eaa( 2 -T) . (5.14)

where

'a = compressive stress'

E = modulus'of elasticity of pipe

Example

Use the same buried pipe example as before and assume a maximumroperating temperature

equal to 150OF (65.60C) (Table 2.1 suggests maximum temperature of 140OF (60.0OC). For

ambient temperature/installation temperature assume 70OF (21.1 OC).

a= (29 x 106 psi) x (6.345x1 06in/in OF) x (150'F-701F) /1000 = 14.7 ksi (101 MPa) ; .' , !.

This stress is considered very conservative because'the soil/pipe friction'would only develop for

very long straight sections. For pipe segments with bends, this stress is also very.conservative

k! 59
- - |

because the soil at the bends is not infinitely stiff and thus any slight compression in the soil

would relieve this thermal induced compressive stress.

Effect of wall thinning:

Based on equation (5.14) it is evident that the pipe stress is independent of the pipe thickness.

Therefore, wall thinning that may arise from aging effects does not increase the pipe stress. For

purposes of this study, temperature effects will not be included in the fragility analysis based on

the following:

* For the configurations and parameters discussed, the maximum stress in the pipe is low

(14.7 ksi (101 MPa)) compared to the ultimate strength of carbon steel pipe (-60 ksi

(414 MPa)).

* The maximum calculated stress was based on the very conservative assumption of fully

restrained pipe segment. This would require very long pipe segments which are aligned

in a straight line.

* Thermally induced stresses are secondary type stresses that are self-limiting.

* Most significantly, the effects of wall thinning have no effect on the longitudinal stress in

the pipe.

* The temperature effects of concern act longitudinally in the pipe; whereas, the pressure

induced stresses used in the fragility analysis act circumferentially.

5.1.7 Soil Movement

Soil movement can occur due to differential soil settlement, soil settlement between building and

surrounding soil, and seismic induced soil movement. Buried piping at NPPs is typically routed

in well-graded soil with adequate compaction which will preclude soil settlements. If a particular

site may be susceptible to soil movement, then this would have been addressed during the

design and construction stage of the plant. Settlement causing relative displacements between

building structures and buried piping is also assumed to have been adequately addressed in the

design and construction stage. If soil settlement could occur at a plant, then settlement of

building structures and civil engineering features would have already materialized since most

NPPs have already been in operation for more than 20 years. Furthermore, stresses due to

relative displacement are considered as secondary type stresses which are self-limiting (i.e., do

not continue to grow). Therefore, for the purpose of this study, soil movement will not be

included in the fragility analysis. If soil movement has occurred or exists at a plant, then any

buried piping degradation will need to be addressed on a case-by-case basis.

5.1.8 Seismic

Seismic loading is comprised of two effects; wave passage and seismic anchor movements.

Concerns also exist with the adequacy of the supporting soil with respect to ground failure

(liquefaction, landsliding, lateral spreading, and settlements).

A. Wave Passage Effects

Wave passage effects for axial and bending strains in straight sections of buried pipe away from

anchor points, sharp bends, or intersections are as follows (ASCE 4-98):

aximum axial strain (Ea)=x = V- (5.15) atc

60

Hi
where

va= maximum ground velocity'

a= coefficient equal to 2.0 for shear waves and 1.0 for compressional and Rayleigh

waves :

c = apparent wave velocity..

For straight sections remote from anchor points, sharp bends, or intersections, the maximum

axial force calculated from equation (5.15) may be reduced because of slippage between the

pipe surface and the surrounding soil. In this case the maximum force can be calculated by

(ASCE 4-98):

(Ea)ax = '--(5.16)

where

flax = maximum friction force per unit length between the pipe and surrounding soil

A = apparent wavelength of the dominant seismic wave associated with peak ground

velocity

ESt = secant modulus of elasticity associated with an axial strain for the buried pipe

A = net cross-sectional area of the pipe -

Maximum Curvature (Bending) (p = ( (5.17)

where

aa = maximum ground acceleration

ak = 1.6 for compressional waves and 1.0 for shear and Rayleigh waves

c = apparent wave velocity

Forces on buried pipe bends, intersections, and anchor points can be calculated using (ASCE

4-98):

! .'A ', l . . . . .

Maximum axial force Fa EsctAp( a)max (5.-18)

where (E.)m= the smaller of (5.15) and (5.16)

Bending moments and shears according to ASCE 4-98 shall be determined from an analysis

which treats the buried pipe as a beam on an elastic foundation subjected to the applied axial

load Fa, that was calculated considering elbow flexibility and lower-bound friction force' values in

the longitudinal leg.

Observations Made in This Study .

In assessing the seismic wave passage effects, several observations are noted as follows:

61
The American Lifelines Alliance (2001) only considers axial strain induced in buried pipe due to

wave propagation. It states that "Flexural strains due to ground curvature are neglected since

they are small for typical pipeline diameters."

Analytical studies performed in this research effort have determined that the calculated strains

(and corresponding stresses) due to wave propagation are not significantly affected by

reductions in pipe wall thickness.

The maximum stresses due to pressure, soil surcharge, groundwater, and surface loads, occur

in the hoop (circumferential) direction of the pipe. Seismic induced stresses primarily develop

longitudinal stresses (due to flexure of the pipe), and therefore, are not additive to the other

loadings. The longitudinal stresses due to pressure, which would be additive to seismic, are only

one-half the hoop stresses. Also, when considering seismic induced stresses as secondary type

stresses, the pipe would not rupture when the ultimate stress (strength) of the pipe is reached

because of the large ductility available in carbon steel and stainless steel pipe material.

ASCE Report (1983) states that Ult is important to emphasize that seismic effects on buried

structures are self-limited since deformations or strains are limited by seismic motions of the

surrounding media." Therefore, seismic stresses should be considered in a similar fashion as

thermal stresses which would classify them as secondary stresses not primary stresses.

ASCE 4-98, commentary section, indicates that shear strains can develop in a straight buried

pipe by traveling wave effects; however, due to very small relative lateral deformation between

the buried pipe and the surrounding soil, these shear strains are relieved and converted into

curvature strains. Therefore, shear strains are 'considered negligible and can be ignored'

unless abnormal circumstances of very strong and stiff soil (e.g., frozen ground) exists

immediately surrounding the pipe.

In a report on seismic design of oil and gas pipeline systems, the ASCE Report (1984)

discusses the capability of modern buried pipelines fabricated from ductile steel pipe with full

penetration butt welds at joints. The report states that "Such pipelines possess good inherent

ductility. There does not appear to be any case of a buried petroleum transmission pipeline ever

having ruptured from the effects of ground shaking." The report indicates that ruptures or severe

distortions of buried piping are usually caused by relative displacements associated with fault

movements, landslides, liquefaction, loss of support, or differential motion at abrupt interfaces

with buildings, tanks, or rock.

Based on the above discussion, it is concluded that seismic wave passage effects do not need

to be considered in the fragility analysis used to develop risk-informed degradation acceptance

criteria.

B. Seismic Anchor Movements

In addition to the strain and forces imposed on buried piping, the seismic event can cause

strains and forces due to the relative displacement between anchor points such as buildings and

the adjacent soil. The strains/forces generated in the pipe due to seismic anchor movements

(SAMs) are also considered to be self-limiting and are secondary type stresses. Furthermore, it

is assumed for this research effort that sufficient flexibility was initially designed into the buried

piping system (flexible transition into building structures). Therefore, the only question remaining

is whether reductions in pipe wall thickness have a detrimental effect on the pipe when SAMs

are imposed.

62

ni
The effect of SAMs for buried pipe attachments to a building structure can be approximated by

looking at two cases as follows: ;

1. Sidesway of a beam fixed at both ends subjected to an imposed lateral displacement.

;(5.19)

1 2EI

and

-,. .,: (5.20)

Solving equation (5.19) for P and substituting it into equation (5.20), and then calculating the

maximum bending stress leads to the following equation:

okB -"~ )M ' 

CTxt la

12EI .12 ,

where

c = distance from the neutral axis of a pipe to the outside surface

-1 = momentof inertia of pipe

From this equation it is evident that the maximum bending stress in a pipe due to sidesway

anchor movement is independent of the thickness of the pipe. Therefore, a reduction in.

thickness due tomwall hinning Will not increase the bending stress of the pipe.

2. Axa lnainor compression -of a beam.-

F = KA (5.22)

AE ' A,(5.23)

I ,=mmn-fietao ie-;l,

SFbomituhisK fromin iquition (5.23).into equation (5.22), and then ctalelating the maximum axial stresn'leads to'thefollow ing equation:r th b

2.es lnaiono W'xa opeso'faba.

F = 'l (5.24)

A I

:63
-

where A = cross-sectional area of pipe

From this equation it is evident that the axial stress in a pipe due to anchor movement along the

pipe axis is also independent of the thickness of the pipe. Therefore, a reduction in thickness

due to wall thinning will not increase the axial stress of the pipe.

Based on the above discussion and the solutions for sidesway and axial elongation or

compression of a buried pipe, it can be concluded that seismic anchor movements do not need

to be considered in this study effort for developing risk-informed degradation acceptance

criteria.

C. Soil Adequacy

As noted earlier another concern with earthquakes is that they may cause failure of the soil to

provide sufficient support to buried piping as well as other plant structures. This may be caused

by liquefaction, landsliding, lateral spreading, and settlements. NPPs are normally sited at

locations that have good soil conditions and are not placed at or near fault locations. Buried

piping at NPPs is typically routed in well-graded soil with adequate compaction which will

preclude soil settlements. If a particular site may be susceptible to soil movement under a

seismic event, then this would have been addressed during the design and construction stage

of the plant. Therefore, it is assumed that competent soil conditions have been ensured during

the design stage of licensing plants and that soil adequacy does not have to be considered in

the fragility analysis used to develop risk-informed degradation acceptance criteria.

5.2 Methodology for Developing Buried Piping Fragility

For the purpose of this study, pipe failure is defined as a catastrophic pipe rupture which results

in the total loss of a buried piping system's capability to perform its intended function. In Section

5.1, it was shown that stresses due to soil loads including surcharge (dead load), groundwater

and live load are low and are not significantly affected by wall thinning. Thermal and seismic

loads produce secondary stresses which are self-limiting in nature and are also not significantly

affected by reductions in wall thickness. On the other hand, stresses due to internal pressure

are primary stresses which are directly affected by loss of material due to age-related

degradation mechanisms. The hoop stress due to internal pressure is inversely proportional to

the wall thickness. Therefore, as the pipe degrades, the safety factor for pressure design

decreases, thereby increasing the probability of a pipe rupture failure in the buried pipe. The

following sections describe the methodology for developing buried piping fragility curves for

internal pressure loading. Stresses due to other loads were also considered and incorporated

into the degradation acceptance criteria as discussed in Section 7.1.

5.2.1 Buried Piping Internal Pressure Design Requirements

Both the ASME B31.1 Power Piping Code and the ASME Boiler and Pressure Vessel Code,

Section 111, NC/ND-3600, provide minimum wall thickness requirements for pressure design of

piping components. The intent of the requirements is to limit the maximum primary membrane

stress in the pipe to an allowable stress value equal to %A of the minimum ultimate tensile

strength of the material. ASME B31.1 specifies that the minimum wall thickness for design

pressures and for temperatures not exceeding those for the various materials specified in its

allowable stress tables, including allowances for mechanical strength, shall not be less than that

determined by Equations (5.25) or (5.26) below:

64

nI]
tm= ( p) + A (5.25)

tm Pd + 2SEA + 2yPA (5.26)

t- =: ' .. .

where

tm = minimum required wall thickness

P = internal design pressure

Do = outside diameter of pipe

d = inside diameter of pipe

SE ;- maximum allowable stress due to internal pressure and weld joint efficiency

A = additional thickness required for items such as corrosion or erosion

y= 0.4 for temperatures less than 900DF (4820C) and D,/tm ratio greater than 6

The additional thickness, A, is to compensate for material removed in threading or grooving, to

provide for corrosion and/or erosion, or to provide for mechanical strength where necessary.

After the minimum wall thickness tm is determined by equation (5.25) or (5.26), the minimum

pipe wall thickness shall be increased by an amount sufficient to provide the manufacturing

tolerance allowed in the applicable pipe specification or required by the process. The next

heavier commercial wall thickness shall then be selected from standard thickness schedules or

from manufacturers' schedules. The design pressure shall not exceed the 'value calculated by

Equations (5.27) or (5.28) as follows:

.2SE(t (5.27)

Do -2y~tm-A) .

p. . (5.28)

d-2y(t -A)+ 2tm

The above equations apply to straight pipe under internal pressure. The Code does not require

minimum thickness analysis for other piping components. Standard fittings that'are purchased

and used in accordance with specified ANSI standards are considered acceptable because their

pressure-temperature ratings are based on burst tests, thereby assuring that the fitting will

withstand the design pressure. For nonstandard fittings, the code provides design rules. For

pipe bends, the wall thickness after bending must satisfy the minimum thickness requirement for

straight pipe. For fabricated branch connections, reinforcement requirements are provided to

assure that the area of metal removed from the branch connection is replaced in close proximity

to the area removed. The use of standard fittings and application of design rules provides a

conservative pressure design basis for components other than straight pipe and reasonable

assurance that these components are as strong or stronger than the straight'pipe in the system.

Therefore in the assessment of the probability of pressure failure, it is reasonable to assume

that the straight pipe is the weak link in the buried piping system.

For piping designed to the ASME Boiler and Pressure Vessel Code, Section 111, NC/ND-3600,

the pressure design requirements are essentially the same. They provide the same minimum

wall thickness equations, allow the use of standard ANSI fittings without analysis, and provide

design rules for nonstandard fittings. The most significant difference is that the allowable

65
materials and allowable stresses are those given in the tables of the ASME Boiler and Pressure

Vessel Code, Section II, Appendix D. For the steel materials commonly used in buried piping

systems, however, the stress allowables are the same as the ASME B31.1 stress allowables.

5.2.2 Development of Fragility Curves for Uniform Wall Thinning

A series of fragility curves were developed for pipe failure under internal pressure loading.

These curves were generated for undegraded pipes and for degraded pipes with varying

degrees of uniform wall loss. The methodology and assumptions applied in the development of

these curves are described below.

A review of the WRC Bulletin 446 survey results summarized in Table 2.1 of this report indicates

that SA-106 Grade B carbon steel pipe is widely used in buried piping systems. This piping

material is used in various critical nuclear plant systems including service water, diesel fuel oil,

and emergency feedwater systems. Typical pipe diameters cover a wide range from less than 2

inches (5.08 cm) NPS (nominal pipe size) for diesel fuel systems up to 30 inches (76.2 cm)

NPS for service water systems. The systems are typically low temperature (ambient to 1400F

(600C)) and low pressure (up to 150 psig (1.03 MPa)). On this basis, an SA-106 Grade B carbon

steel buried piping system within this range of dimensional and operational parameters was

selected as a representative buried piping system.

In the development of the fragility curves for degraded piping, it was assumed that general

corrosion results in wall thinning that is uniformly distributed around the circumference and

length of the pipe. Although it is highly unlikely that wall thinning will be uniform, this assumption

should provide conservative probability of failure estimates for the buried piping systems. This

assumption greatly simplified the analytical effort. More refined analyses, such as finite element

analyses, could have been performed to consider effects of local thinning, but at the onset, this

was judged not to be required because of the anticipated large margins to failure. Sensitivity

studies and evaluations of burst test data of degraded piping presented in later sections of this

report support the conservatism of this approach.

The strength of the pipe is dependent on its tensile properties and its dimensional properties.

The maximum hoop stress, Sh, due to internal pressure in a thin-walled pipe is calculated in

accordance with the following equation:

PD Sh= 2 (5.29)

where

Sh = hoop stress

P = internal pressure

D = average diameter

t = wall thickness

Nominal pipe size (or nominal pipe diameter) corresponds to a standardized outside diameter (O.D.) as

defined in ASME B36.1OM-2004. For nominal pipe sizes 14 inches and above, the actual O.D. is equal to

the nominal pipe size. For nominal pipe sizes 12 in. and smaller, the actual O.D. is greater than the

nominal pipe size, (e.g., 2 inch nominal pipe actually corresponds to 2.375 in. O.D.).

66

ni
For this study, it was assumed that pipe failure (rupture) occurs when the hoop stress due to

internal pressure reaches the ultimate tensile strength, Su, of the material. The failure pressure,

Pi, may be defined as follows:

p ;(5.30)

From the probabilistic standpoint, the tensile strength, pipe diameter and pipe thickness may be

considered random variables to determine the probability of failure of the system as a function

of internal pressure. The ASME SA-1 06 material specification provides tensile strength

requirements and permissible variations in diameter and wall thickness. For SA-106 Grade B,

the minimum tensile strength is 60 ksi (414 MPa). Although the specification does not provide

an average or upper bound value, it is well known that material certification tests typically show

average strength values of 20 percent or more compared to minimum required strength values.

The minimum wall thickness at any 'point shall be no less than 12.5 percent below the specified

nominal wall thickness'. No maximum wall thickness is defined. Allowable variations in outside

diameter are dependent on the nominal diameter and range from ±1/64 inch (0.397 mm) for

pipe diameters up to 1 z inch (3.81 cm) NPS, up to -3/16 inch to +1/32 inch (-4.76 mm to

+0.794 mm) for pipe diameters greater than 34 inch (86.4 cm) NPS. The variations in diameter

are very small and would have an insignificant impact (<1%) on pipe stress for a given pressure.

Therefore, for the probabilistic evaluation, this variation was not considered and pipe diameter

was treated as a constant. Variations in wall thickness were explicitly investigated in order to

develop different fragility curves for undegraded pipes and for degraded pipes with varying

percentages of wall loss. Fragility curves for undegraded pipes were conservatively based on

the minimum wall thickness allowed by the material specification. For degraded pipes, the

fragility curves were based on the nominal thickness minus a percentage wall loss.due to

degradation. The material tensile strength was treated as a random variable with a lower bound

value equal to the minimum required value of 60 ksi (414 MPa), a mean value equal to the

minimum plus 20 percent (72 ksi (496 MPa)), and an upper bound value equal to the minimum

plus 40 percent (84 ksi (579 MPa)). The value of the tensile strength was assumed to have a

normal distribution centered about the'mean with lower and upper bound values corresponding

to the 5th and 95th percenitile values, respectively. A normal (or Gaussian) distribution is defined

by the following probability density function:

f(x;C(2)- 1 [x - (5.31) - - ~cy,-,2TT -.2v

where

x = random variable

= mean

a = standard deviation - i

The cumulative normal distribution, which gives the probability of a randomly selected value

from a normal distribution with parameters ja and a being less than x, is given by the following

equation: :

Nominal pipe wall thickness is the thickness of the pipe wall specified by ASME B36.1OM-2004 without

consideration for manufacturing tolerance. Hereinafter, this term will also be referred to as simply: wall

thickness. -.

--67
F(x;p;a)= (z 2 [ Jdz (5.32)

From a table of standard cumulative normal distribution (Hahn and Shapiro, 1967), the 5h and

95th percentile values for a normal distribution correspond to the mean ± 1.645 times the

standard deviation (a ± 1.645c). Therefore, for the SA-1 06 Grade B pipe material with a mean

tensile strength A1 = 72 ksi (496 MPa) and 5th percentile and 95h percentile tensile strength equal

to j± ± 12 ksi (82.7 MPa), the tensile strength standard deviation a equals 12/1.645 = 7.3 ksi

(50.3 MPa). By applying these values of mean and standard deviation in Equations 5.31 and

5.32, the probability density function and the cumulative distribution function for the tensile

strength were calculated and are plotted in Figures 5.1 and 5.2.

The probability density function shows the anticipated distribution of tensile strength for any

randomly selected sample of SA-106 Grade B carbon steel pipe. The cumulative distribution

function curve represents the probability that the tensile strength of a randomly selected pipe

sample is less than or equal to a specific value. For example, the figure indicates that the

probability that the tensile strength is lower than its mean value of 72 ksi (496 MPa) is 50

percent, as expected. Similarly, the probability that the tensile strength is below its lower bound

value of 60 ksi (414 MPa) is 5 percent, and the probability that it is below its upper bound value

of 84 ksi (579 MPa) is 95 percent.

A fragility curve is the cumulative distribution function of the probability of failure for a given

value of input load. For this case, it was assumed that failure occurs when the hoop stress in the

pipe is equal to the tensile strength of the pipe material. Therefore the cumulative distribution

function curve also represents the fragility curve for a pipe with probability of failure plotted as a

function of the hoop stress. Figure 5.3 presents the fragility curve for the SA-106 carbon steel

pipe in terms of hoop stress. In order to identify the probability values at the low end, the

probability of failure was plotted on a semi-logarithmic scale. For SA-106 Grade B carbon steel

piping, this curve gives the probability of failure at any given level of applied stress. For

example, if the hoop stress in the pipe is 30 ksi (207 MPa), the probability of failure is less than

1 0-. At a stress level of 90 ksi (621 MPa), the probability of failure is 1.0. For a stress level of 45

ksi (310 MPa), the probability of failure is 104.

The probability of failure curve may also be presented as a function of internal pressure. As an

example, a 30 in. (76.2 cm) standard weight pipe with outer diameter of 30 in. (76.2 cm) and

wall thickness of 0.375 in. (0.953 cm) was considered as a representative large buried pipe. For

the undegraded case, a minimum wall thickness of 12.5 percent below nominal (0.328 in. (0.833

cm)) was used. By applying Equation 5.30, the mean, lower bound and upper bound failure

pressures were calculated as follows:

Mean Pf = 2(.328)(72000)/(30 - .328) = 1592 psi (11.0 MPa)

Lower Bound Pt = 2(.328)(60000)/(30 - .328) = 1327 psi (9.15 MPa)

Upper Bound Pf = 2(.328)(84000)/(30 - .328) = 1857 psi (12.8 MPa)

The standard deviation = (1857 - 1592)/1.645 = 161 psi (1.11 MPa)

The fragility curve for this case was calculated by using the above values in Equation 5.32. In

order to generate fragility curves for a degraded pipe, the calculations were repeated for the

68

n
same size pipe subjected to uniform wall thinning with wall losses of 25%, 50%, and 75% of

nominal wall thickness. When degradation is considered (reduction in wall thickness), the

average pipe diameter needed for use in equation (5.30) is calculated assuming the inside

diameter of the undegraded pipe is held constant and the outside diameter and thickness of the

pipe'is reduced due to the degradation. However,- it should be noted that the assumption of

whether the reduction in wall thickness occurs on the inside or outside of the pipe has a

negligible effect on equation (5.30) and the final results. The mean and standard deviation for

the failure pressures of the undegraded and degraded pipe are summarized below.

Condition Wall Thickness Failure Pressure (psi) Condition (in.) - Mean Std. Deviation

Undegraded (Min. Wall) 0.328 1592 161.

25% wall loss 0.281 ', 1367 139

50% wall loss 0.188 ' 914 93

75% wall loss 0.094 459 47

1 in. 2.54 cm; 1 psi = 0.00689 MPa

The fragility curves for the undegraded and the degraded cases are shown in Figure 5.4a. The

same curves are plotted on a semi-logarithrmic scale in Figure 5.4b in order to identify the lower

values of probability of failure. These fragility curves can be used to determine the probability of

failure for a degraded or undegraded 30 in. (76.2 cm) standard weight pipe at any internal

pressure. For example, Figure 5.4b shows that with in internal pressure of 1000 psi (6.89 MPa),

the probability of failure of an undegraded pipe with minimum allowable wall thickness is 1.OE04. If the pipe has degraded and lost 25% of its nominal wall thickness, the probability of failure

increases to 4.OE-03. With a 50% wall loss, the probability is 0.8. With a 75% wall loss, the

probability is 1.0.

As discussed in Section 5.2.1, the design pressure in a pipe is prescribed by Code rules. For

piping designed to'either ASME B31.1 or ASME Section III, Class 2 or 3, the requirements are

identical. For a given design pressure, the minimum wall thickness is determined by the smaller

value from Equations (5.25) or (5.26). The design pressure shall not exceed the value

calculated by Equations (5.27) or (5.28). For pipe designed to the requirements of either Code,

'the specified maximum allowable stress for pressure design of SA-1 06 Grade B pipe is 15 ksi

(103 MPa). In practice, the Code equations would be used to determine the minimum wall

thickness. An additional thickness, A, to account for erosion/corrosion, threading and grooving,

and other factors would be included. The minimum thickness would then be increased by the

manufacturing tolerance,' and finally, the next heavier standard wall thickness would be

selected. For the purpose of determining a conservative maximum pressure value for use in this

study, it was assumed that the 30 in. (76.2 cm) standard weight pipe was designed exactly to

the minimum required wall thickness requirement with no additional thickness, A, and with

actual wall thickness equal to the minimum allowed by the SA-1 06 Grade B material

specification. The maximum value for the design pressure was then calculated from Equation

(5.27) as follows:

'P = [(2)(15000)(.328)]/[30-(2)(.4)(.328)] = 330 psi (2.28 MPa)

Figure 5.4b shows that for a 30 in. (76.2 cm) standard weight degraded pipe with 75% wall loss

'subjected to an internal pressure equal to its maximum allowable design pressure of 330 psi

69
(2.28 MPa), the probability of failure is about 3.OE-03. If the pipe has wall loss of 50% or less,

the probability of failure is less than 1.OE-08.

If it is conservatively assumed that the internal pressure in a pipe is equal to its maximum

allowable design pressure, the probability of failure may be plotted as a function of wall loss in

the pipe. For the 30 in. (76.2 cm) standard wall pipe, this is shown in Figure 5.5. This curve may

be used to determine the probability of failure due to internal pressure loading for a 30 in. (76.2

cm) standard wall SA-106 Grade B carbon steel degraded pipe with uniform wall thinning at any

percentage wall loss.

The methodology described above may be applied to develop fragility curves and probability of

failure versus wall loss curves for other pipe sizes. In Section 5.3, the methodology was applied

to develop a series of additional curves for pipes ranging in size from 2 to 42 in. (5.08 to 107

cm) in diameter. This methodology may be extended to other ductile steel piping materials if the

following conditions are met: (1) the piping is designed in accordance with either the ASME

B31.1 or Section III, NC/ND-3600 Code rules, (2) the material property distributions are

consistent with the distributions used in this study, and (3) the anticipated failure mode can be

characterized as a ductile pipe rupture failure which occurs when the pipe hoop stress reaches

the ultimate tensile stress of the material.

5.2.3 Fragility Curves for Localized ThinninglPitting

The fragility curves developed by analysis in Section 5.2.2 were based on the assumption that

the aging effects due to corrosion may be conservatively characterized as uniform wall thinning

around the entire circumference and length of a buried pipe. In general, however, the effects of

corrosion are more likely to be localized. An alternate approach for the development of fragility

curves was investigated based on a review of test results from samples of corroded pipes that

were removed from service and pressure tested to failure.

ASME B31G-1 991, "Manual for Determining the Remaining Strength of Corroded Pipelines, A

Supplement to ASME B31 Code for Pressure Piping," provides guidelines to assist pipeline

operators in making decisions on whether a corroded region of a buried pipe may safely remain

in service or whether it needs to be repaired or replaced. The manual provides a procedure as

well as formulas, charts and tables to evaluate corroded piping on the basis of the maximum

depth and length of the corroded area. The manual states that the procedure is applicable to all

pipelines within the scope of the ASME B31 Code for Pressure Piping. However, it specifies the

following limitations on the applicability of the procedure:

(a) The manual is limited to corrosion on weldable pipeline steels categorized as carbon steels

or high strength low alloy steels. Typical of these materials are those described in ASTM A53, A-106, and A-381, and API 5L.

(b) The manual applies only to defects in the body of line pipe which have relatively smooth

contours and cause low stress concentration (e.g., electrolytic or galvanic corrosion, loss of

wall thickness due to erosion).

(c) The procedure should not be used to evaluate the remaining strength of corroded girth or

longitudinal welds or adjacent heat affected zones, defects caused by mechanical damage,

such as gouges and grooves, or defects introduced during pipe manufacture.

(d) The criteria for corroded pipe to remain in service presented in the manual are based only

upon the ability of the pipe to maintain structural integrity under internal pressure. It should

70

ti
not be the sole criterion when the pipe is subject to significant secondary stresses (e.g.,

bending), particularly if the corrosion has a significant transverse component.

(e) The intent of the procedure is to determine whether a degraded pipe has sufficient strength

to remain in service. It is not intended to predict when leaks or rupture failures will occur.

The procedure and acceptance criteria prescribed in the manual were developed under a

research effort conducted by the American Gas Association. The overall objective of the

program was to examine the fracture initiation behavior of various sizes of corrosion defects by

determining the relationship between the size of a defect and the level of internal pressure that

would cause a leak or rupture. The guidelines and acceptance criteria contained in the manual

were developed and validated based on an extensive series of pressure tests which utilized

both laboratory pipe specimens with machined defects and actual full-size corroded pipe

specimens. Several hundred full-scale tests were conducted on all types of defects to establish

general defect behavior. Mathematical expressions to calculate the pressure strength of

corroded pipes were developed on the basis of these tests. The mathematical expressions were

semi-empirical but were founded on well-established principles of fracture mechanics. During

1970 and 1971, 47 pressure tests were conducted on several pipe sizes to evaluate the

effectiveness of the mathematical expressions in determining the strength of corroded areas.

Actual field specimens of pipes that had sustained corrosion damage' were removed from

service and were tested to failure either in-place or in a large, full-scale test cell. The diameters

of the pipes tested ranged from 16 in. through '30 in. (40.6 cm through 76.2 cm) and wall

thicknesses ranged from 0.312 in. to 0.375 in. (0.792 cm to 0.953 cm). The yield strengths of

the pipe materials ranged from 25,000 psi to 52,000 psi (172 MPa to 359 MPa). These final test

results validated the acceptance curve presented in the manual. '

From the information available in the ANSI B31 G manual, it was not clear whether the loss of

material in the degraded pipes, used for the pressure tests, occurred on the inside surface of'

the pipe, outside surface, or both. This is not expected to have any significant effect on the

results of this study.

The results of the final 47 pressure tests of actual corroded pipes presented in ANSI B31 G were

evaluated in our study to determine whether fragility curves for localized thinning/pitting corrosion could be developed from this test data. However, due to the small size of the test

sample, it was concluded that the level of confidence in fragility curves developed from a

statistical evaluation of this data would be limited. Instead, a statistical evaluation of this test

data was performed to provide a comparison to the fragility curves developed by analysis. This

comparison was made to determine whether the fragility results obtained using the analytical

approach developed in Section 5.2.2 bound the test data, and therefore can also be

conservatively used for localized loss of material or pitting. In B31 G, the test results were

presented on a plot of corrosion depth/wall thickness ratio versus corrosion length. Each data

point on the plot represented one full-sizepressure test on a corroded pipe. Since the tests

involved different pipe sizes and materials, the failure pressure stress for each test was reported

as a percentage of the specified minimum yield stress of the material (based on nominal pipe

dimensions). For the statistical evaluation, the test data was divided into three sample sets

based on varying corrosion depths. The ranges of ratios of maximum corrosion depth to nominal

pipe wall thickness for the three sample sets were 40% to 60%, 60% to 80%','and 80% to 100%.

For the purpose of this evaluation,it was conservative y assumed that the failure pressure was

independent of the length of the corrosion'defect. The mean and standard deviation of the

failure pressure data within each'sample set were calculated and the results are summarized in

the table below:

- 71
-

Range of Corrosion Number Of Data Points Failure Stress (% Min.Yield)

Depth in Saml Se

(% wall thickness) ampe et Mean Std. Dev.

80% - 100% 6 132.3 49.7

60% - 80% 28 128.4 21.9

40%- 60% 11 142.4 26.2

For comparison against the fragility curves generated by analysis, these results were applied to

the representative pipe analyzed in Section 5.2.2 using dimensional and material properties of a

30 in. (76.2 cm) standard wall SA-106 Grade B carbon steel pipe. The values of the mean and

standard deviation of the failure stresses for each range were calculated using the specified

minimum yield stress of 35 ksi (241 MPa). The corresponding failure pressure mean and

standard deviation for each range were determined by solving Equation (5.29) for pressure. The

probability density function and cumulative distribution function curves were then generated for

each range of corrosion depth. For the comparison of analysis to test results, the probability

density function and cumulative distribution function (fragility) curves were regenerated for 40%,

60% and 80% uniform wall loss for the 30 in. (76.2 cm) pipe using the analytical methodology

described in Section 5.2.2. A comparison of analysis versus test results for the failure pressure

mean and standard deviation is summarized in the table below. Comparisons of analysis versus

test probability density function curves for the three ranges of degradation are shown in Figures

5.6a through 5.6c. Comparisons of fragility curves for the three ranges are presented in Figures

5.7a through 5.7c.

ANALYSIS TEST

% Uniform Failure Pressure (psi) % Local Wall Failure Pressure (psi)

Wall Loss Mean Std. Dev. Loss Mean Std. Dev.

40% 1096 111 40-60% 1261 232

60% 732 74 60 -80% 1137 194

80% 367 37 80-100% 1172 441

1 psi = 0.00689 MPa

The table comparison clearly demonstrates the conservatism of the analysis based on the

uniform wall thinning assumption in predicting the mean failure pressure. However, the standard

deviations for the test data are much larger than the standard deviations from the analysis. This

is believed to be primarily due to the small sample sizes of the test data and is not likely to be

representative of the entire population. It is noted that the 80 - 100% wall loss sample set

72

fl
includes only six points and has the largest standard deviation. On the other hand, the 60 - 80%

wall loss sample set includes 28 points and has the smallest standard deviation.

The comparison of probability density functions shown in Figures 5.6a through 5.6c

demonstrates the overall conservatism of analysis versus test results. The large test data curve

spreads (especially for the 80-100% wall loss test sample set) illustrate the effect of the large

standard deviations of the test data. The comparison of fragility curves shown in Figures 5.7a

through 5.7c shows that the analysis curves generally predict higher probability of failure at any

given pressure. Due to the large standard deviations, the test fragility curves have a widerspread and in some cases exceed the analysis curves at the low-pressure end. This, however,

is believed to be a reflection of the uncertainty in assuming that the statistical distribution of the

small sample set applies to the entire population. If more test data were available, the curves

would be defined with a higher degree of confidence and the spread of the test curves would

most likely be reduced. -

In conclusion, although the above comparison is not statistically rigorous due to the small test

data sample sizes, it provides a reasonable level of confidence that the fragility curves

developed by analysis assuming uniform wall thinning also predict conservative estimates of the

probability of failure of a degraded pipe that exhibits localized or pitting corrosion.

5.2.4 Fragility Curve Sensitivity StudiesIn Section 5.2.2, the development of the fragility curves for buried piping with uniform wall

thickness reduction treated the tensile strength as a random variable with a normal distribution

centered about the mean with lower bound (LB) and upper bound (UB) values corresponding to

the 5th and 95' percentile values, respectively. The material specification for SA-106 Grade B

carbon steel pipe material specifies a minimum tensile strength of 60 ksi (414 MPa) which was

assumed to be the LB value. Based on typical material certification test results, it was assumed

that the mean tensile strength value was 20 percent higher than the minimum value (72 ksi (496

MPa)). The UB value was assumed to be 40 percent higher than the minimum (84 ksi (579

MPa)). This information and the assumption that pipe failure occurs when the pipe stress due to

internal pressure reaches the material tensile strength provided the basis for defining the-,

probability density function and the probability of failure (fragility) curves.

The above assumptions on material strength distribution were based on typical anticipated

material property distributions. In order to provide a quantitative measure of the sensitivity of

variations in the tensile strength'distribution on the results, a sensitivity study was also carried

out. Additional material property combinaitions were analyzed to determine the effect of different

tensile strength distributions both in terms of mean value and variations from the mean.

Probabilities of failure were recalculated usirig lower mean strength (10 percent above

minimum) and different values of lower 'and upper bound percentiles (1% and 99%). The

following three additional cases were analyzed and compared to the baseline case:

73
CaeN. LB Mean UB UB

Case No. T.S. T.S. T.S. LB Percentile Percentile

1 (baseline) 60 ksi 72 ksi (120%) 84 ksi (140%) 5% 95%

2 60 ksi 72 ksi (120%) 84 ksi (140%) 1% 99%

3 60 ksi 66 ksi (110%) 72 ksi (120%) 5% 95%

4 60 ksi 66ksi(110%) 72ksi(120%) 1% 99%

1 ksi = 6.89 MPa

The same procedures that were used for the first case were applied to develop the probability

density functions and probability of failure curves for the three additional cases. The mean

values for each case are listed above. The standard deviations were calculated as follows:

Case 2:

From a table of standard cumulative normal distribution, the 1st and 99 t percentile values

correspond to the mean + 2.33 standard deviations (p. ± 2.33a):

p. = 72 ksi (496 MPa), a = (72-60)/2.33 = 5.15 ksi (35.5 MPa)

Case 3:

The 5h" and 95" percentile values correspond to the mean + 1.645 standard deviations (pl ±

1.645cy):

, = 66 ksi (455 MPa), a = (66-60)/1.645 = 3.65 ksi (25.2 MPa)

Case 4:

It = 66 ksi (455 MPa), a = (66-60)/2.33 = 2.58 ksi (17.8 MPa)

The probability density functions for the four cases were calculated in accordance with Equation

(5.31) and were plotted in Figure 5.8. A comparison of the curves illustrates that the baseline

case has the widest distribution. Case 2 which has the same mean value but a smaller standard

deviation shows a narrower distribution as expected. Cases 3 and 4 both have a lower mean

value and lower standard deviations. Both curves show narrower distributions than the baseline

case as anticipated. As a result of the widest distribution of the baseline case, the probabilities

of failure at the low stress levels are expected to be higher. This was demonstrated using the 30

in. (76.2 cm) representative pipe as an example and is discussed below.

Using the methodology developed in Section 5.2.2, fragility curves for a 30 in. (76.2 cm)

standard wall pipe were calculated as probability of failure versus internal pressure for the

revised material strength distributions of Cases 2 though 4. A comparison of the probability of

failure versus internal pressure curves for the four cases with different levels of wall loss is

shown in Figures 5.9a though 5.9c. For the 50% wall loss case, Figure 5.9a shows that the

baseline case (Case 1) predicts the highest probability of failure for internal pressures of up to

74

ill
750 psi (5.17 MPa). At the design' pressure6of 330 psi (2.27 MPa) (also shown in this figure), the

probability of failure is less than 1 04 for all cases.' Figure' 5.9b shows that with 75% wall loss,''the

baseline case predicts the highest probability of failure at the pressures up to 380 psi (2.62

MPa). At the design pressure of 330 psi (2.27 MPa), the probability of failure for the baseline

case is 3 x 103 which is higher than the other cases. At 80% wall loss, Figure 5.9c shows that

the baseline case predicts highest probability of failure for internal pressure-up to 305 psi (2.10

MPa). At the design pressure of 330 psi (2.27 MPa), Cases 3 and 4 predict higher probabilities

of failure. -

In conclusion, this sensitivity study investigated the effects of variations in the distribution of the

tensile strength of a typical piping material. The results demonstrated that the distribution used

in the baseline case provides conservative probabilities of failure for piping subjected to its

allowable design pressures with wall losses of up to 75% of the wall thickness.

5.3 Fragility Curves for Undegraded and Degraded Buried Piping

Using the methodology described in Section 5.2.2, a series of fragility curves were developed

for buried piping systems with an anticipated range of dimensional parameters. The WRC

Bulletin 446 survey reported buried pipe systems with pipe diameters varying from less than 2

in. (5.08 cm) to as large as'30 in. (76.2 cm). Based on the results of a survey (EPRI Survey 95-.

110, 'Inspecting Inaccessible Service Water Piping,") summarized in EPRI Report GC-1 08827

(1998), buried service water piping ranged in size from 16 to 42 in. (40.6 to 107 cm); Therefore,

fragility curves were developed for the representative standard weight (ST) piping dimensions

shown below. For 42 in. (107 cm) standard weight pipe, the D/t ratio exceeds the limit of 80.

Therefore, a thickness of 0.562 in. (1.43 cm) which meets this limit was used for this study.

NPS/Schedule (Wt) Outer Diameter (in.) 'Wall Thickness (in.)

2 inch Sch 40 (ST) 2.375 0.154

4 inch Sch 40 (ST) '_''_4.5 ' ';' -_0.237

8 inch Sch 40 (ST) 8.625 '0.322

16 inch Sch 30 (ST) 16.075

24 inch Sch 20 (ST) 24.0 0.375

30 inch (ST) 30.0 0.375

42 inch -(0.562 wall) 42.0 - 0.562

1 in. =2.54 cm

Following the procedure described in Section 5.2.2, for each pipe size, the design pressure and

the mean and standard deviation of the failure pressure were calculated for an undegraded pipe

with minimum allowable wall thickness and for a degraded pipe with 25%, 50% and 75% wall

loss. These results as well as the ratios s of hean failure pressure to design pressure are

summarized below:

' , , ' .; ! i . , '

- 75
Pipe Diameter Cnion Design Pressure Mean Failure Fatiurf e/Dsin (NPS) Condition (psi) Pressure (psi) Failure/Design

Undegraded 8662 4.84

(Min Wall) 8662_4.84

2 inch 25% Wall Loss 1790 7489 4.18

50% Wall Loss 5080 2.84

75% Wall Loss 2586 1.44

Undegraded 6957 4.83

(Min W all) __ _ _ _ _ _ _

4 inch 25% Wall Loss 1440 6004 4.17

50% Wall Loss 4059 2.82

75% Wall Loss 2059 1.43

Undegraded 4863 4.81

(Min Wall)

8 inch 25% Wall Loss 1010 4188 4.15

50% Wall Loss 2820 2.79

75% Wall Loss 1424 1.41

Undegraded 3015 4.79

(Min Wall) 3015_4.79

16 inch 25% Wall Loss 630 2592 4.11

50% Wall Loss 1738 2.76

75% Wall Loss 874 1.39

Undegraded 1996 4.75

(M in W all)__ _ _ _ _ _ _ _

24 inch 25% Wall Loss 420 1714 4.08

50% Wall Loss 1147 2.73

75% Wall Loss 576 1.37

Undegraded 1592 4.82

(M in W all) _ _ _ _ _ _ _ _

30 inch 25% Wall Loss 330 1367 4.14

50% Wall Loss 914 2.77

75% Wall Loss 459 1.39

Undegraded 1706 4.74

(Min Wall) 1706_4.74

42 inch 25% Wall Loss 360 1465 4.07

50% Wall Loss 980 2.72

75% Wall Loss 492 1.37

1 psi = 0.00689 MPa

The above results show that both the design pressures and mean failure pressures decrease

with increasing pipe sizes. This is consistent with the increase in DOt ratios with increasing

diameter for standard weight pipes. However, for the same wall thinning condition, the ratio of

mean failure pressure to design pressure, which may be considered the mean design margin,

76

Hi
remains fairly constant for all the pipe sizes. This indicates that the design margins are relatively

independent of pipe diameter.

The procedure described in Section 5.2.2 was used to generate fragility curves as a function of

internal pressure for each pipe size considered. These are shown in Figures 5.1 Oa through

5.10f using linear scales and in Figures 5.11 a through 5.1 1f using semi-logarithmic scales.

Assuming that the internal pressure equals the design pressure, plots of probability of failure

versus percent wall loss were generated for each size pipe. These are shown in Figures 5.1 2a

through 5.12f.

The probability of failure versus percent wall loss plots for all pipe sizes were summarized on a

single graph which is shown in Figure 5.13. This figure demonstrates that for pipes operating at

their design pressure, the probability of failure of a degraded pipe does not vary significantly

with pipe diameter.

; 77
-

0.06

0.05

a

0

*0- 0.04

C

LL

U.

o 0.03

.012 0.02-

a..

0.01

AN

U a a . .

0 20 40 60 80 100 12

1 ksl = 6.89 MPa Tensile Strength (ksi)

Figure 5.1 Probability Density Function for SA-106 Grade B Tensile Strength

20

0.9

0.8

C

0

_ 0.7 C

UC 0.6

.0

, 0.3

A>C.)

0.2

0.1

:________________ L _______________

0

0 20 40 60 80 100 120

1 ksi = 6.89 MPa Tensile Strength (ksi)

Figure 5.2 Cumulative Distribution Function for SA-106 Grade B Tensile Strength

78

lI
rw=r~n

1.OE-01

1.0E-02

N 1.OE-03

L

~D2 1.OE-05 0.

I .OE-06

1.OE-07

I I .OE-08 , * I. *. . . . . . - - - - - -I -_ 4I -! r * _ _ _

0 20 40 60 80 100 120

1 ksl = 6.89 MPa Hoop Stress (ksi)

Figure 5.3 Fragility Curve for SA-106 Carbon Steel Pipe as a Function of Hoop Stress

;..,.-, r ... .

1.

0.

0.

O.

2 .0

D0

0

0

0

0----7 ---- i- -- -

.9 - - - - - I- - - - ----- 1--- I I

. '4 _

- Z55aiZ' --- --- - -- -

.5------I .

- - - - - -...-I- - - -

ZZZZ ii - L

.3----

.2 - - - - - - I--

.1......-- --

.0--- -- 0

0 500 1000 1500 2000

1 psi = 0.00689 MPa Internal Pressure (psi)

Figure 5.4a Fragility Curves for a 30 in.' (76.2 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure With Varying Levels of Wall Loss

(. 79
1 .OE+OO

1.0E-01

/ z- I ,

1.OE-02 " I I -i -. f / I7 

3

U. co

16

Z0

0

co

1.OE-03 t---- |_ J-2 b- - "-iua4 "

I2 1 I 1 .OE-04

1.OE-05 I I I I/ /

1 .OE-06

1.OE-07 I I /

1 .OE-08

0

1 psi = 0.00689 MPa

500 1000 1500

Internal Pressure (psi)

2000

Figure 5.4b Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure With Varying Levels of Wall Loss

1.OE+00 _

1 0E 02 ______t-_

1.OE-04 _

1.0 12

1.OE-16

0 10 20 30 40 50 60 70 80 90 100

Wall Loss (%)

Figure 5.5 Probability of Failure for a 30 in. (76.2 cm) Standard Wall SA-106 Carbon Steel Pipe

Under Design Pressure vs. Wall Loss

80

a
,t.

-

eg

0

a

rs

U.,

C

a)

2

IL

0 500 1000 1500 2000

1 psi = 0.00689 MPa Failure Pressure (psi)

Figure 5.6a Probability Density Function for Failure Pressure of a 30 in. (76.2 cm) Standard

Wall SA-106 Gr. B Pipe - Analysis vs.; Test Comparison (40- 60% Wall Loss)

0.012' -

_ _ I -I 80% Wall +-l ass l l 

II (A alys )I

- I.0 I I I I I

C

0

r-C. ILi

2*1i

'a0~

0.0o

I 60Y6 Wall Loss

, __-_ It Srs

v

0

0 1

500 1000w _ ~!:' I ! I 1500 2000

1 psi = 0.00689 MPa Failure Pressure (psi) '. , : - ! - .. .. I I

Figure 5.6b Probability Density Function for Failure Pressure of a 30 in. (76.2 cm) Standard

Wall SA-1 06 Gr. B Pipe - Analysis vs. Test Comparison (60 - 80% Wall Loss)

81
0012

0.01

C

0

C

. _

a)CU

o 0.004

0.002

LI ______ =-= I I I= ===

i Wall 80% .oss=TII = = - - - 1 ~~~~~~(A r~alysi s) _ _ _ _ _ _ _ _ _ __ _

0 It nfUq0

0

0 500 1000 1500 2000

1 psi = 0.00689 MPa Failure Pressure (psi)

Figure 5.6c Probability Density Function for Failure Pressure of a 30 in. (76.2 cm) Standard

Wall SA-1 06 Gr. B Pipe - Analysis vs. Test Comparison (80 - 100% Wall Loss)

0.9

0.8

0.7

0

<x= O 6

U2. 0.5

:a

0~-0 0.4

0.3

0.2

0.1

____-- -

A lysi)

(Ana ysis)L

I 40 -6SM0 Low

(Te! t

0

0 500 1000 1500 2000

1 psi = 0.00689 MPa Internal Pressure (psi)

Figure 5.7a Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe as a

Function of Internal Pressure - Analysis vs. Test Comparison (40 - 60% Wall Loss)

82
-

1

0.9

0.8

0.7

CD0

*, 0.6 IL

2! 0. 5

'U

co

*D 0.4 04

0.3

0.2

0.1

0

WX61/ Wal Lpt _ _ ( nalys s) __I

___ |0% all Iss

_ = 0 6 I ass

restl

7- = E

0

1 psi = 0.00689 MPa

500 1000

Intemal Pressure (psi)

1500 2000

Figure 5.7b Fragility Curves for a 30 in., (76.2 cm) Standard Wall SA-106 Gr. B Pipe as a

Function of Internal Pressure - Analysis vs. Test Comparison (60 - 80% Wall Loss)

1

0.9

0.8

0.7

c)

% 0.6

Li-

*.?- 0. 5

'U

-0 0.4

0.3

0.2

0.1

0

.O I I 1r 1 6 1 - I - I I 0 [7-1

mats)

I1 80 I1000 Los

(re!t)

l T - I E '*lr{T~)| |

0

1 psi = 0.00689 MPa

500 4 1000

Internal Pressure (psi)

1500 2000

Figure 5.7c Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe as a

Function of Internal Pressure - Analysis vs. Test Comparison (80 - 100% Wall Loss)

83
0.16

0.14

0.12

0

.o

C a Ot 0.11 LU.

.r_

CD 0.08

-o

5c' 0.06

2

0.04

0.02

r I I I I T-1t r---r- r 7 7 7 r I Y I 1

I 1

0 tiL7,,- - -Cas 2

. Case h 3A a

-Case 4

5, H illl

_ __ __ __ a_'8ALM II II/

_ __ _ _ __ _ c fL _W \S1 1 1

n

0 20 40 60 80 100 120

1 ksi = 6.89 MPa Stress (ksi)

Figure 5.8 Probability Density Function for SA-1 06 Gr. B Pipe Tensile Strength

Sensitivity Study Cases 1 through 4

1.02+00

1.OE-01

1.0E-02

Q

-3 1.OE-03 .a

LL

co

>. 1.0E-04

.0

2 1.OE-05 IL

-

_t

//

It

-4.-

TI

I LI 1.OE-06 -

rI.0E-07 -

1.0E-08 1

200

1 psi = 0.00689 MPa

-Case I

1---Case 2

-z - 'Case 3

3 *. * rCases4 r t

--- ,,g rsl I

I

-1

I I Il * I

400 600

Internal Pressure (psi)

800 1000

Figure 5.9a Fragility Curves for a 30 in. (76.2 cm) Standard Wall SA-106 Gr. B Pipe with 50%

Wall Loss Sensitivity Study Cases 1 through 4

84

III
1.0E+00

1.0E-03

2 1.OE-04 (Ud

.0

tL _ _ _ ~ _ _ _ -C ase 1 ==

tO~~s06 _ _ = __ _ o-' Case l 2

= ._o __ - - 'Case34

1 E0 J__ L,_= . ..... Desion Pressurne

1.OE.0

1.0E48__-7T07 _ ._ ._ II I = I = I

1.0 E-08

100 200 300 400 500

1 psi= 0.00689 MPa Internal Pressure (psi)

Figure 5.9b Fragility Curves for a 30 in-. (76.2 cm) Standard Wall SA-1 06 Gr. B Pipe with 75%

Wall Loss Sensitivity Study Cases 1 through 4

1.0E-01

1.OE-02 _ - |

2 1.0E-03 --

0~

1.OE-04

2 .y I I 1 IOi-IE

1.0E-05 1 .OE 068 ;|| ~- l.-e3 T

100 200- 300 400- 500

1 psi = 0.00689 MPa Internal Pressure (psi)

Figure 5.9c Fragility Curves for a'30 in..(76.2 cm) Standard Wall SA-106 Gr. B Pipe with 80%

Wall Loss Sensitivity Study Cases 1 through 4

85
1.0 L1 111 1 11 1 1 1 I I I II -II 11111 I 1

0.9 - - - -

0.7 1 _ 17iA I- 4 E -I _B Lf I IA II YII 0.8 - ---

0.7 _ 0 % 4a I - - - - - -

M 0.6 50 W II Ss i 

~.0.5

.00.4

0.3

0.2 L

0.1

0.0 .  . I I I . I I . - I . . . I I . ... . . . . . . - I  . I I I I I I I I . I . I

0 1000 2000 3000

1 psi = 0.00689 MPa

4000 5000 6000 7000 8000 9000 10000

Internal Pressure (psi)

Figure 5.1Oa Fragility Curves for a 2 in. (5.08 cm) Standard Wall SA-1 06 Carbon Steel Pipe as

a Function of Internal Pressure with Varying Levels of Wall Loss

0

._

Z0

0.

1.0 I I I I I I I I kII1 I I I I I I1

ll~ I1r ~ ~~i 1a l l1 1 l VI I I 1 0.9-

09 rl~rllI I m I I I 1l 1 A I l IT I IA I/ I ILI

0.8 -

0.7

0.6 - r n 4 

0.5-

0.4-

0.3

0.2

0.1 -

.0 I - i 1 1 1 Z I I I I I I 0

0 1000

1 psi = 0.00689 MPa

2000 3000 4000 5000 6000 7000 8000

Internal Pressure (psi)

Figure 5.10b Fragility Curves fora 4in. (10.2 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure with Varying Levels of Wall Loss

86

ml
I -

O .  : I . I . I     . I . - - I I I . I I . I . . . . i . . - . I I I . I I . . . I  . . LI lI-I 1 I

0.9 - II1H-IM IIIIIVIIIIIIIIIIII I I I H-/lk I 1L.t~ K, I I 0.8 111 i1 HAI . 1.1 TIZT ,JT

0.8 '-ll -1 If _---1--E Q F _- M Lffi 7 U I MA

0.7

0.6

z

._

.a, 0.5

-0 0.4 2

0L

0.3

VI I I

I H

0.2

0.1

I I I U -J-1 1.1 I I I I I I I I I I I I I I I I I I I I I I I I 0.0 1 1 1 I ' I 1 I I I i I

0 500 1000 1500

1 psi = 0.00689 MPa

2000 2500 3000 3500 4000 4500 5000 5500 6000

":'Internal Pressure (psi)

Figure 5.1 Oc Fragility Curves for an 8 in. (20.3 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure with Varying Levels of Wall Loss

0

.0!

.0

02

1.0

0.9

0.7

0.6 -lt - - - wasl 5- |

0.5 - n r e

0.4-

0.2

0.1 1 I U -

oLL0

0 so

1 psi = 0.00689 MPa

0 1000 ' 1500 2000 2500 3000 3500 4000

. Internal Pressure (psi)

Figure 5.1 Od Fragility Curves for a 16 in. (40.6 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure with Varying Levels of Wall Loss,

. 87
1.0 IA /

/

0.9 1

0.8

0.7

5D

*j 0.6 LL

2:. 0.5-

0 0.4

0.3

0.2

0.1

0.0

I / / /

IL LI 1 d

it I/ L L

_0e l _110 s Z=IL _ _hr - 1L IILII - wI11, z~ IZI=U

_e _dec _ _ _I

_ =1l -r/ -s=-

0

1 psi = 0.00689 MPa

soo 1000 1500 2000 2500

Internal Pressure (psi)

Figure 5.1Oe Fragility Curves for a 24 in. (61.0 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure with Varying Levels of Wall Loss

1.0

0.9

0.8

0.7

5D

jA 0.6 IL

Z. 0.5

.0 0.4

0

M

0.3

0.2

0.1

0.0

I~~~~~~~~~ l1111 I A T

I 1 1 1 0 1

2 % I all ss

udecae I

I I 17 I I 1 11 L I I i 1i1 1 1 1 1 1

Figur I F ~ 5 glt Curves fo1 4 in 1 ( 07 cm Di t r .562 ISIA-I0I6 in (1 4 cm Wa 

0

1 psi = 0.00689 MPa

500 1000 1500 2000 2500

Intemal Pressure (psi)

Figure 5.1 Of Fragility Curves for a 42 in. (1 07 cm) Diameter x .562 in. (1.43 cm) Wall SA-1 06

Carbon Steel Pipe as a Function of Internal Pressure with Varying Levels of Wall Loss

88

III
1 .OE400

1.OE-01

1.OE-02

,' 1.06-03

L

,. 1.0E44

._

2 1.OE-045

r5

1.0E-06

1.OE-07

0 10D0 2000 3000 4000-' 5000 6000 7000 8000 9000 10000

1 psi = 0.00689 MPa Intemal Pressure (psi)

Figure 5.11 a Fragility Curves for a 2 in. (5.08 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure With Varying Levels of Wall Loss

LL

0

1 .OE-04

co.0

l.OE-08

0 10

1 psi = 0.00689 MPa

)oo 2000 .3000 -: 4000 50

: Internal Pressure (psi)

DO 6000 7000 8000

Figure 5.1 1b Fragility Curves for a 4 in. (10.2 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure With Varying Levels of Wall Loss

89
I

1 .OE+O0

I.OE-01 -

1.OE-02 -

0

.2 1.OE-03 -

u2~ 1.OE2-045-

.0

t .OE4-06 -..

1.OE-07 y -

1.OE8 -_ I

0 500

1 psi = 0.00689 MPa

I1I I1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000

Intemal Pressure (psi)

Figure 5.11 c Fragility Curves for an 8 in. (20.3 cm) Standard Wall SA-1 06 Carbon Steel Pipe as

a Function of Internal Pressure With Varying Levels of Wall Loss

1.0E+00 l rl

1.OE-01

LQ I .1.0E-043 - _

2 1.OE-04 - - - -- -

DL -_i

0 500 1000 1500 2000 2500 3000 3500 4000

1 psi = 0.00689 MPa Internal Pressure (psi)

Figure 5.1 1d Fragility Curves for a 16 in. (40.6 cm) Standard Wall SA-106 Carbon

a Function of Internal Pressure With Varying Levels of Wall Loss

Steel Pipe as

90

"I
1.OE+00

1 .OE-01

t.OE-02

a,

.R 1.OE-03

Zs 1.OE-04

-DC

.0

2 1.OE-05 aL

I -. I

I ... I ,

7,

/

L F

t

I I

1I I /

I 1.OE-06

1.OE-07

1.OE-08

I /- /

/I . . . . . . -_ . . . . . . I'

0

1 psi = 0.00689 MPa

500 1000 1500 2000 2500

,, Intemal Pressure (psi)

Figure 5.l1 e Fragility Curves for a 24 in. (61.0 cm) Standard Wall SA-106 Carbon Steel Pipe as

a Function of Internal Pressure With Varying Levels of Wall Loss

1 .OE+00

1.OE-02 -

.2 1.OE-03

rL

Z. 1.OE-04

2 1.OE-05

t1.OE-06

1 .OE.07

1.OE-08

M% whil 1IMA

I 50% Iall ds&/

I I 25% wall loss!/

f I I

,i 7 J 7

U /

/

L 7-T7

0

1 psi = 0.00689 MPa

500 - 1000

I Intemal Pressure (psi)

1500 2000

Figure 5.1 1 f Fragility Curves for a 42 in. (107 cm) Diameter x .562 in. (1.43 cm) Wall SA-1 06

Carbon Steel Pipe asa Function of Internal Pressure With Varying Levels of Wall Loss

91
0

IL

Z.

.0

0P

1.OE+00

1.0E-02

1.OE-04

1.OE-06

1.0E-08

1.OE-10

1.OE.12

1.OE*14

1 .OE*16

0 10 20 30 40 50 60 70 s0 90 100

Wall Loss (%)

Figure 5.12a Probability of Failure for a 2 in. (5.08 cm) Standard Wall SA-106 Carbon Steel

Pipe Under Design Pressure vs. Wall Loss

VOGE-04

. 1.OE-06 -

.0

>s .OE-08 ^m;ri --

I I.E1 I F e-II ItIIIT T I FIIl i

1.OE-16

0 10 20 30 40 50 60 70 80 90 100

Wall Loss (%)

Figure 5.12b Probability of Failure for a 4 in. (10.2 cm) Standard Wall SA-106 Carbon Steel

Pipe Under Design Pressure vs. Wall Loss

92

I
~2 1.OE-106

_1.__ L , E- : ---t-1- --

¶ .OE-12

1.oE-u4

D.QE-16 _

0 10 20 30 40 50 60 70 80 90 100

Wall Loss(%

Figure 5.12c Probability of Failure for an i in. (20.3 cm) Standard Wall SA-106 Carbon Steel

Pipe Under Design Pressure vs. Wall Loss

1.OE-14 - -- 3

LI.OE0

. i.OE-06 m - - -

.0

1.0E-16 _ T TI

1.OE.16

0 10 20 30 40 50C 60 70 80 90 100

, Wall Loss (%)

Figure 5.12d Probability of.Failure for an 1 in. (40.6 cm) Standard Wall SA-106 Carbon Steel

Pipe Under Design Pressure vs. Wall Loss

93'
0

A

L

-D

a.

1.OE+OO

t.OE-02

I .OE-04

1.OE-06

I.OE-08

1.02-10

1.OE-12

1.0E-14

I Af~tR .uc- lo

0 10 20 30 40 50 60 70 80 90 100

Wall Loss (%)

Figure 5.1 2e Probability of Failure for a 24 in. (61.0 cm) Standard Wall SA-1 06 Carbon Steel

Pipe Under Design Pressure vs. Wall Loss

1.012+00

1.OE-042

0

a.

1.OE-.1 -

1 .OE-16 -

0 10 20 30 40 50 60 70 80 90 100

Wall Loss (%/)

Figure 5.1 2f Probability of Failure for a 42 in. (1 07 cm) Diameter x .562 in. (1.43 cm) Wall SA106 Carbon Steel Pipe Under Design Pressure vs. Wall Loss

94

II
a)

LL

0

2:

co

2

1 .OE+00

1 .OE-02

1 .OE-04

1 .OE-06

1 .OE-08

1 .OE-10

1.OE-1 2

1 .OE-14

1.OE-16

AE

I I1 I I I

N11 I .p.

I

. .1- . .

z

A4

2 in

-- -4 in

8in

-16 in

- - -24 in

- - -- 30 in

-42 in I I I I I. ,

_ _ _ __ _ _ __ _ _I

0

Figure 5.13

I

10 20 30 40 50 60 70 80 90

Wall Loss (%)

Probability of Failure for SA-106 Carbon Steel Pipe Under Design Pressure vs. Wall Loss - All Sizes

95

100
6 RISK EVALUATION OF DEGRADED BURIED PIPING SYSTEMS

Buried piping systems at a nuclear power plant (NPP) can degrade, as described in the

previous sections. Such deterioration potentially could impair the operation of the system that

contains the buried piping, and thus impact the overall risk of an NPP.

Currently, buried piping is not systematically inspected. Accordingly,' a failure of a buried pipe is

"discovered" because the failure is self-revealing1, or a failure or degradation of a buried pipe is

"discovered" because of another event, such as excavation that is performed for unrelated

items. If the "discovery" indicates that thde pipe has failed, then a repair2 has to be completed to

return it to normal condition. If the "discovdry' indicates that the pipe has not failed, but it has

degraded, the regulatory question that arises is:'"does the pipe have to be repaired immediately,

or is it acceptable for the plant to continu6'6perating?3" In essence, the methods and criteria

described in this report provide guidance'to the NRC staff to assist them in answering this'

question.

These methods assess the increase in projected risk as a function of time from the time of

inspection to answer the question in the previous'paragraph. In this way, they estimate the

number of years' befo're the plant risk becomes unacceptable. The expression "projected risk"

means that the risk is evaluated at some time after the time of inspection.

The increase in projected risk is assessed from the time of inspection because it is known that

the pipe has not failed at this time, and'th6'objective of the evaluation is to assess whether

continued operation of the'pipe (plant) from this time leads to "unacceptable" risk. Figure 6.1

depicts relevant events as a function of timrre frorn'the start of life of a buried pipe.-

To estimate the effect of buried piping degradation on plant risk, five nuclear plant sites having

buried piping systems were selected. Section 6.1 describes the process used to select the five

nuclear plant sites with buried piping systems. Each'site may have one or more NPPs; to

simplify the discussion, this report refers t6one site simply as an NPP or a plant.

To develop degradation acceptance criteria, which is one of the stated goals of this research, a

quantitative measure of "acceptable risk" is'n'eeded. Section 6.2 defines what is considered to

be acceptable risk, the conditions for which it is applicable in this study,' and the quantitative'risk

acceptance criteria.

The evaluation of the risk associated with deg'rading buried piping depends on the type of

system that contains'this Oipinig. Section 6.3 discusses some top-level considerations for

developing methods for estimating this risk, including a classification of the plant's systems for

the purpose of assessing this risk. Section' 6.3 concludes that all the systems with'buried piping

of the five nuclear plants selected fall into two categories:

1 A failure of a buried pipe is self-revealing, for example, when a system that is normally operating fails in

such a way that the failure becomes visible to plant personnel.

2 In this section the term orepair" is used in a very broad sense, including replacement. In other words,

when a "repair" is carried out, it is considered that the pipe is returned to a condition that meets the plant's

current licensing basis.,

3 If the buried pipe is degraded but not failed,-the licensee is still expected to evaluate the degraded

condition to determine if any corrective action needs to be taken depending on the evaluation findings and the level of degradation. Although future inspections are an option, there is no requirement to do so.

'97
1) A system is normally operating and its failure causes an initiating event (IE), and

2) A system is not subjected to internal pressure at all times and its failure does not

cause an IE.

The methods for estimating the risk associated with degrading buried piping presented in

Sections 6.5 and 6.6 use the conditional probability that the pipe will fail by M years after the

time of inspection, given that it has not failed at the time of inspection. Section 6.4 presents a

derivation of this probability.

Sections 6.5 and 6.6 derive the methods for estimating the risk associated with degrading

buried piping for a system that is normally operating and its failure causes an Initiating Event,

and for a system that is normally in standby and its failure does not cause an Initiating Event,

respectively. These methods are applied to the selected plants to obtain results that will be used

in Section 7 to calculate degradation acceptance criteria.

6.1 Selection of Plants

To evaluate the risk of degraded buried piping, five NPPs were selected for analysis from

among twelve License Renewal Applications (LRAs) submitted to the NRC. The choice was

made from these twelve plants because their LRAs were the only reliable sources of information

that specifically listed what buried piping systems exist at their plant.

Table 2.2 lists the buried piping systems for each of the twelve LRA plants; these data are

summarized in Table 2.3. Table 6.1 reformats this information in terms of the number of buried

piping systems for each plant. This table also provides plant information consisting of the

reactor type, NSSS supplier, type of containment, architect/engineer, and location in the United

States. All of these data were used to select the five plants for the risk evaluation.

The first criterion was to choose plants with the greatest number of buried piping systems to get

the most information about such systems. These plants were Surry, North Anna, and Hatch, all

having seven or more buried piping systems. Then, for the remaining plants having five buried

piping systems, it was desirable to select two more plants that would offer the best variation on

the remaining parameters shown in Table 6.1. Peach Bottom was dropped because it is a GE

BWR, Steel Mark I containment, designed by Bechtel, which is the same plant information for

the Hatch plant (already selected). McGuire and Catawba have the same plant parameters and

so only one of them was needed; the former was selected. Oconee was included because it has

a Babcock & Wilcox designed PWR, a prestressed concrete containment, and it was

constructed by Duke and Bechtel; all of these parameters differ from the other plants.

Accordingly, the risk evaluation encompassed the following five plants:

* Surry

* Hatch

* North Anna

* McGuire

* Oconee.

The information given in Table 2.3 shows that these five plants are a good selection because

they cover practically all systems having buried piping, as reported in the LRAs. In addition, they

contain both "frontline" and usupporf' systems having buried piping.

98

I"
6.2 Defining Acceptable Risk

Current trends in the regulatory environment and industry are to incorporate risk-informed

decisionmaking in order to make more productive uses of available resources by applying them

to those activities that can have the greatest improvement on safety of NPPs while maintaining

costs at reasonable levels. To assist the industry in using information from risk assessments,

the NRC has issued Regulatory Guide 1.174, Revision 1, entitled "An Approach For Using

Probabilistic Risk Assessment In Risk-lnformed Decisions On Plant-Specific Changes To The

Licensing Basis."

Regulatory Guide 1.174, Revision 1 (RG-1.174), provides recommendations developed by the

staff for using risk information in support of licensee-initiated licensing basis (LB) changes that

require review and approval by the NRC. The document describes an approach that is

acceptable to the NRC for analyzing proposed changes to the LB of a plant and for assessing

the impact that such changes may have on the risk associated with the plant.

Another document that relates to probabilistic risk assessments is the NRC Standard Review

Plan NUREG-0800, Chapter 19 Rev. 1 (2002), which is entitled, "use of Probabilistic Risk

Assessment in Plant-Specific, Risk-Informed Decisionmaking: General Guidance." The standard

review plan was issued to provide guidance to the NRC staff for performing evaluations of

licensees' requests for changes to the LB that utilize risk insights.

The RG 1.174 and the Standard Review Plan both indicate that the licensees' submittals are

expected to use an integrated process that combines risk insights from a PRA, together with

insights from traditional engineering analyses, supported by performance monitoring and

feedback. The quality of the PRA needed to support this process'should be commensurate with

the roles the risk insights play in the final decisionmaking.

. r

The research described in this report is intended to be used as a guideline for determining the

potential risk significance of a specific degraded condition. Therefore, RG 1.174'is being used to

provide a quantitative measure of what can be considered as "significant risk" and is not being

used to justify a change in the licensing basis at the plant where the degradation has occurred.

In developing the approach described in RG 1.174, the NRC has decided that only small

increases in risk would be permitted, and thenionnly when it is reasonably assured,' among other

things, that sufficient defense in depth and sufficient safety margins are maintained. This.

approach is followed because of the inherent uncertainties and the need to account for safety

issues that may arise related to 'design, construction, and operation of NPPs.' -

As described above, a quantitative measure of acceptable risk was needed for this study in

order to develop quantitative acceptance criteria for degraded buried piping. The quantitative

guidelines of acceptable risk contained in.RG .1i 74 were adapted to develop these criteria.

Subsection 6.2.1 discusses the quantitative guidelines of acceptable risk in RG 1.174, and

Subsection 6.2.2 develops the quantitative risk acceptance citeria for'degraded buried piping.

6.2.1 Quantitative guidelines of acceptable risk in RG 1.174

Subsection 2.2.4 of RG 1;174 presents quantitative measures of risk. Acceptance guidelines for

changes in Core Damage Frequency (CD) are presented in Figure 3 of the Guide. The

guidelines in Figure 3 are broken down into thiee regions: I,' I, and IlIl. Once the baseline CDF

.99
of a particular plant is developed (or already known from past assessments), the ACDF resulting

from the proposed change in the LB is used to determine the acceptance region. A change that

falls in Region I is a significant change for which the Guide states "no changes allowed." Region

11 is considered a "small change" which requires the licensee to "track cumulative impacts."

Region IlIl corresponds to "very small changes" which permit "more' flexibility with respect to

baseline CDF" and also requires the licensee to "track cumulative impacts."

The acceptance guidelines described in RG 1.174 were used to define acceptable risk for

evaluating degraded buried piping in order to determine the level of degradation that should be

considered to potentially have a significant effect on plant risk. To be conservative and to

account for some of the uncertainties described elsewhere in the report, the definition of

acceptable risk will be if the ACDF due to degradation falls in Region IlIl as described earlier.

From Figure 3 of RG 1.174, the upper boundary of Region IlIl has a ACDF of 10i per year and

the maximum baseline CDF for this Region ends at somewhat less than 103 per year. Since the

maximum baseline CDF shown for Region IlIl is not represented with a well-defined boundary, a

value of 5 x 104 per year was selected as an upper bound value for the baseline CDF. Based

on these observations, the acceptable ACDF selected for this study is 1 x 106 per year and the

maximum baseline CDF selected is 5 x 10 4 per year. These criteria were selected as a

definition of acceptable risk and were applied to all plants for this study.

The acceptance guidelines of RG 1.174 also specify that these guidelines are intended for

comparison with a full-scope (including internal events, external events, full power, and

shutdown) assessment of the change in risk metric. As described later in Sections 6.5 and 6.6

of this report, the methods for assessing the risk associated with buried piping used parameters

obtained from evaluating the SPAR version 3 models that are full-power level-I probabilistic risk

assessment (PRA) models for internal events. The evaluation of level-1 PRAs of internal events

during full power operation is considered acceptable because RG 1.174 states that it is

recognized that many PRAs are not full scope and PRA information of less than full scope may

be acceptable. The approach described in this report utilizes the latest available PRA models

that are currently accessible for use in this research study. Also, the soil above buried piping

would protect the pipe from external events of high winds, flooding, fire, lightning, snow and ice,

and a light aircraft crash (the external event of earthquakes is addressed separately in Section

5.1 of this report). In addition, the conservatisms included in the fragility analysis approach

provide added margins to account for the uncertainties and assumptions made.

It is acknowledged that RG 1.174 indicates' that in addition to the acceptance guideline for CDF

(Figure 3 of RG 1.174), the acceptance guideline for Large Early Release Frequency (LERF)

(Figure 4 of RG 1.174) should also be used. This however was not possible for this study

because only level 1 PRA models were available for performing the risk assessments. In

addition, RG 1.174 is really intended to be used by licensees to evaluate proposed changes to a

plant's licensing basis. The results presented in this report are intended to be used as a

guideline for determining the potential risk significance of a specific degraded condition. RG

1.174 in the context of this study is being used to provide a quantitative rmeasure of what can be

considered as "significant risk" and is not being used to justify a change in the licensing basis at

the plant where the degradation has occurred. To address the concern regarding the need to

consider the acceptance guideline for LERF, those buried piping systems whose main function

is to mitigate events other than level 1 internal events (e.g., LERF and fire) have been identified

and excluded from the degradation acceptance criteria. These buried piping systems should be

considered on a case-by-case basis. From the list of buried piping systems shown in Table 2.3,

100
three systems that should be considered on a case-by-case basis are the standby gas

treatment, containment spray, and recirculation spray systems.

On the other hand, the methods presented in this section can be applied to assess the risk

related to CDF and LERF provided that models for evaluating these parameters are available. In

particular, one possibility for obtaining a simplified evaluation of LERF (or of Large Early

Release Probability (LERP)) is to use the approach of NUREG/CR-6595, Rev. 1 (Pratt et at.,

2004). An evaluation of LERP using this approach can be combined with the methods described

in this section for evaluating the contribution to risk related to LERF.

6.2.2 Quantitative risk acceptance criteria for degraded buried piping

If a buried pipe is subjected to some type of degradation mechanism(s), it will degrade as a

function of time. As discussed earlier, the objective of the risk evaluation is to assess whether

continued operation of the pipe (plant) from the time of inspection leads to unacceptable risk.

The increase in projected risk is assessed from the time of inspection because it is known that

the pipe has not failed at this time. Accordingly, the risk is evaluated M years after this time; see

Figure 6.1. In this study, the measure of risk due to the pipe's degradation is the increase in the

core damage probability (ACDP) over these M years.

First, an acceptable ACDP over M years of operation after the time of an inspection can be

expressed as

ACDPACceptabfe = ACCDFAmeptable X M (6.1)

where ACDPAcceptabie is the acceptable increase in the core damage probability over M years

from the time of inspection, and

ACDFAceptbie is an acceptable increase in core damage frequency.

As discussed in Subsection 6.2.1, according to the guidelines in RG 1.174, an acceptable ACDF

is 1E-6/year, so (6.1) becomes -.

ACDPAceptable = (1 E-6/year) x M (6.2)

where M is in units of years.

Accordingly, from a plant risk point of view, a system with buried piping that is degrading could

be allowed to continue operating after the time of an inspection as long as

ACDP <ACDPAcceptabe (6.3)

where ACDPAceptabte is calculated using equation (6.2).

ACDP is the increase in the core damage probability over M years after the time of inspection

due to degradation of the buried piping.

Substituting equation (6.2) into equation (6.3), -

ACDP < (1 E-6/year) x M (6.4)

>101 .1 . .
Equation (6.4) and the condition that the maximum baseline CDF of a plant is 5 x 104 per year

or less, discussed in Subsection 6.2.1, are the quantitative risk acceptance criteria. These

criteria are used in this study to assess the acceptability of the degradation of the buried piping

over M years of operation after the time of an inspection. Calculating the ACDP to be used in

equation (6.4) depends on the type of system being evaluated. Sections 6.5 and 6.6 derive the

methods for estimating the risk associated with degrading buried piping for a system that is

normally operating and its failure causes an Initiating Event, and for a system that is normally in

standby and its failure does not cause an Initiating Event, respectively.

In this report, a statement such as plant risk falls below the risk acceptance criteria means that

the ACDP associated with a degrading buried pipe is less than 1 E-6/year * M, as shown by

equation (6.4).

Section 6.3 discusses some top-level considerations for developing methods for estimating the

risk associated with degrading buried piping, including a classification of the plant's systems for

the purpose of assessing this risk.

6.3 Considerations for Developing Methods for Estimating the Risk of Buried Piping

Buried piping subjected to degradation mechanisms will eventually fail if no repair or other

actions are taken. The time elapsed from the time the piping is installed to the time it fails

depends on the rate of its degradation. If this rate is slow, it would take a long time for buried

piping to fail; on the other hand, if this rate is fast, then the piping will fail sooner.

One of the main objectives of this research program is to develop risk-informed acceptance

criteria corresponding to different levels of observed degradation of buried piping. For example,

assume that an inspection of buried piping after 5 years of operation reveals that it has not

failed, but has a 20% wall loss. Then, is it acceptable that this piping remains in operation given

this level of degradation, or does it have to be replaced? To respond, the rate of degradation of

this piping must be considered. As discussed above, if this rate is slow, then the impact of

degraded piping on the plant risk would likely fall below the risk acceptance criteria derived in

Subsection 6.2.2 by the end of M years, after the time of inspection. Even if the impact of the

degraded condition on plant risk falls below the risk acceptance criteria, the licensee is still

expected to evaluate the degraded condition to determine what, if any, corrective action needs

to be taken. However, if the pipe is degrading rapidly, then its impact on the plant risk would

likely exceed the risk acceptance criteria by the end of these M years, and accordingly, the

piping has to be repaired as soon as possible. The terms such as 'slow' or 'rapid" are used to

illustrate the impact of the rate of degradation on the plant risk, and are not defined specifically.

The results presented in Table 7.3 were carried out for a range of rates of degradation, and

these results demonstrate this impact. Rates of degradation for buried piping are discussed in

Sections 3.4, 7.2.1, and 7.3.1.

Therefore, to develop risk-informed acceptance criteria corresponding to different levels of

observed degradation of the buried piping, the impact of this degradation on plant risk as a

function of time must be calculated. Sections 6.4 through 6.6 derive the methods for estimating

this risk.

To develop the methods for assessing the impact of degrading buried piping on plant risk, the

following considerations were made:

102

H
1. At the top level, there are two technical aspects for evaluating the contribution of degraded

buried piping to ACDP. One is determining this contribution to ACDP as a function of time,

and the other is assessing it as a function of space. The first is the subject of this section. In

simple terms, the second one is assessing a degradation rate (and a ACDP) as a function of

the pipe's length because different segments of the pipe may degrade at different rates.

Since spatial dependency is not considered, it is assumed that the rate of degradation is

constant throughout the pipe. This is considered acceptable if the maximum degradation

rate along the pipe is used for the assessment.

2. The approach described in this report applies to steady-state stresses, and not to transient

ones. Generally, buried piping is not subjected to transient loads, and if it is, then the piping

would need to be evaluated on a case-by-case basis.

3. As mentioned at the beginning of this section, if an inspection reveals that a buried pipe has

not failed, but it has degraded, the regulatory question that arises is: bdoes the pipe have to

be 'repaired immediately, or is it acceptable for the plant to continue operation?" To answer

this question it is' noted that since at the time of the inspection the pipe has not failed, the

probability of failure of the pipe at any time before and at the time of inspection is zero.

Accordingly, the risk associated with the degrading pipe for any time before the time of

inspection evaluated at the time of inspection is zero. Thus; the risk should be controlled

' from the time of inspection, and the approach to control the risk is that the estimated

increase in projected risk from this time over a period of M years is acceptably small.

Therefore, evaluating the increase in projected risk associated with the degrading pipe from

the time of inspection is the relevant measure of risk to assess the acceptability of continued

operation of the buried pipe. The methods developed in this section account for the fact that

the buried pipe is degraded at the time of inspection, even though the pipe may still meet

the conditions of the current licensing basis. If the pipe does not meet the current licensing

basis, the licensee is required to take appropriate action (e.g., repair or replacement) to

bring the pipe back into compliance.

4. The methods developed in this section use the level-1 probabilistic risk assessment (PRA)

of internal events during full-power operation of each selected plant. Accordingly, the

increase in core damage probability (ACDP) is the resulting measure of risk. Therefore, for

this study, the measure of the impact of degraded buried piping on the risk of an NPP is the

ACDP due to internal events during full-power operation. Accordingly, the evaluations in this

section do not include the impact of degraded buried piping for other modes of operation,

other levels of PRA, and other challenges (such as external events). The impact on plant

risk of degrading buried piping systems that fall into these categories should be reviewed in

light of the discussion presented in Section 6.2.1.

The contribution of degraded buried piping to the risk of an NPP typically is not quantified in

conventional Probabilistic Risk Assessments (PRAs).- Hence, this contribution is not included in

the risk due to internal events quantified in a conventional PRA, or in Individual Plant

Examination (IPE) submittals.

For the purpose of evaluating the contribution to ACDP of the failure of a system with buried

piping, the systems in'an NPP can be classified into one of two main categories:

1. the system's'failure causes an initiating event, or I .,. . ;

103
2. the system's failure does not cause an initiating event, but is required to mitigate an

initiating event.

An initiating event (IE) is an occurrence that causes a reactor trip. The second category can be

subdivided into the following subcategories:

2.1 The buried pipe is subjected to internal pressure at all times. After the pipe fails, it

may be replaced (or repaired) subsequent to the shutdown of the plant or while the

plant is operating. Thus, two cases are identified as follows:

2.1.a Replacement (or repair) is done when the plant is shut down immediately

after the pipe breaks.

2.1.b Replacement (or repair) is done while the plant is operating.

2.2 The buried pipe is not subjected to internal pressure at all times. The pipe will not

fail when not subjected to internal pressure. However, the pipe may fail after a true

demand (initiating event) or after a test demand (demand while the system is being

tested), since the pipe is under pressure in these circumstances.

The contribution from potential failures after test demands to the ACDP comes from

the pipe failing on a test demand, the plant continuing to operate while the pipe is

being repaired, and a true demand occurring while the pipe is being repaired. It is

considered that this contribution is negligible because the likelihood of the plant

continuing to operate, and a true demand occurring before the repair of the pipe is

completed, is expected to be small.

The contributions to the ACDP from potential failures after true and test demands

should in principle be added. However, since the contribution from potential failures

after test demands is considered negligible, only the contribution to the ACDP from

true demands is considered in this study. Accordingly, one case is identified as

follows:

2.2.a The pipe is not subjected to internal pressure at all times and its failure does

not cause an IE. Only the contribution to the ACDP from potential failures

after true demands is considered.

Hence, the first step in evaluating the contribution to ACDP from a system with buried piping is

to define the category that the system falls into. Figure 6.2 presents a roadmap that can be used

to select the method to be used for each category. The discussion in the rest of this section

provides the basis and details for using each method.

The buried piping systems of the five nuclear plants selected were reviewed to identify the

category that each of their systems falls into. The review indicated that all the systems of these

five plants fall into two categories:

Category 1: The system to which the buried pipe belongs is normally operating, and its

failure causes an IE. An example for McGuire 1 and 2 is the Service Water (SW) system.

Category 2.2.a: The system to which the buried pipe belongs is not subjected to internal

pressure at all times, and its failure does not cause an IE. An example for North Anna 1 and

2 is the Residual Heat Removal (RHR) system.

104

l1
Therefore, for the five plants, methods were developed to assess the contribution to ACDP from

a system belonging to each of these two categories; they are described in Sections 6.5 and 6.6.

Since systems (with buried piping) belonging to other plants may fall into one of the other

categories (other than Category 1 and Category 2.2.a), these other categories are discussed

next.

Category 2.1.a. The piping system is normally operating, so it is subjected to internal pressure

at all times. The plant is shut down immediately when the pipe breaks and replacement (or

repair) is done while the plant is shut down. For this case, the risk during power operation, is

negligible, since the likelihood of an initiating'event occurring during the process of shutting

down is very small. One might have to consider that the shutdown process could, for example,

cause a loss of offsite power event, but the likelihood that a controlled shutdown would

challenge the grid stability is small. Thus, the risk due to pipe degradation for this case is

neglected. -

Category 2.1.b. The piping system is normally operating, so it is subjected to internal pressure

at all times. After the pipe fails, it may be replaced (or repaired) while the plant is operating. The

contribution to the ACDP comes from the possibility of an initiating event occurring during the

time the pipe is being repaired and is unavailable. This contribution to the ACDP would have to

be evaluated on a case-by-case basis.

The methods for estimating the risk associated with degrading buried piping presented in

Sections 6.5 and 6.6 use the conditional probability that the pipe will fail by M years after the

time of inspection, given that the pipe has not failed at the time of inspection. Section 6.4

presents a derivation of this probability, and an approach to evaluate it.

6.4 Derivation of the Conditional Probability of Failure of a Buried Pipe

If a buried pipe is subjected to some type'of degradation mechanism(s), it will degrade as a

function of time. Since it is known that the pipe has not failed at the time of inspection, it is

necessary to estimate the (conditional) probability that the pipe will fail by M years after the time

of inspection, given that it has not failed at the time of inspection.

Starting with the general expression from probability theory for the conditional probability of two

events A and B:

P(NB) P(BIA)P(A) ' (6.5) P(B);

where P(A i B) is the probability of A giv'en'B has already occurred.

Let

A =pipe failed by time t ;,.

B = pipe not failed by time to-

'105
to is the time of inspection (after the start of life of the buried pipe). The time t is any time after

the time of inspection, so t > to. To simplify the discussion that follows, the time of inspection, to,

is set to zero. Accordingly, t > 0; see figure 6.1.

Then, if F(t) is the cumulative failure distribution of the time-to-failure of the pipe,

P(A) = P(pipe failed by time t) = F(t) (6.6)

P(B) = P(pipe not failed by time = 0) = 1 - F(0) (6.7)

To derive P(B / A) = P(pipe not failed by time = 0/ pipe failed by time t), it is noted that

P(pipe failed by time = 0/ pipe failed by time t) = F(0) I F(t) (6.8)

P(pipe not failed by time = 0 / pipe failed by time t) = 1 - [F(0) / F(t)] (6.9)

Hence,

P(B / A) = P(pipe not failed by time = 0/ pipe failed by time t) = 1 - [F(0) / F(t)] (6.10)

Inserting (6.6), (6.7), and (6.10) into (6.5):

CP(t) = F(t) -F(() (6.11)

where CP(t) is the conditional probability that the pipe failed by time t, given it has not failed at

time =0.

For a plant that has operated M years after the time of inspection, the conditional probability that

the pipe failed by the end of the Mth year, given it has not failed at the time of inspection (t = 0)

is then given by:

CP(M) = F(M) - F(0) (6.12)

1 - F(0)

A derivation of the cumulative failure distribution of the time-to-failure of a buried pipe, F(t), and

an approach to estimate the terms F(0) and F(M) in equation (6.12) are presented next.

The cumulative failure distribution of the time-to-failure of a buried pipe, F(t), is defined in terms

of the fragility curves presented in Section 5. A fragility curve is the cumulative distribution

function of the probability of failure for a given value of input load, given by

F(t) = P(strength s load) (6.13)

For this study, it was assumed that failure occurs when the hoop stress in the pipe is greater or

equal to the tensile strength of the pipe material. Accordingly,

F(t) = P[pipe's tensile strength s PD(t)/2w(t)] (6.14)

where

106

n
P = pipe's internal pressure

D(t) = time-dependent pipe's average diameter

w(t) = time-dependent pipe's wall thickness

Section 5 calculates the time-dependent average pipe diameter, D(t), assuming that the inside

diameter of the undegraded pipe is constant and the outside diameter of the pipe is reduced

due to the degradation. Section 5 indicates that the assumption of whether the reduction in wall

thickness occurs on the inside or outside of the pipe has a negligible effect on the final results.

Section 5 also assumes that the pipe's internal pressure equals the maximum design pressure.

Accordingly, for a given pipe size, the maximum design pressure is a constant. In addition, the

time-dependent pipe's average diameter, D(t), is a function of the time-dependent pipe's wall

thickness, w(t). Therefore, equation (6.14) shows that a fragility curve (the cumulative

distribution function of the probability of failure) is a function of w(t), which can be written as

F(w(t)). For this reason, the fragility curves can be derived and presented as a function of the

pipe's wall thickness; this is the approach used in Section 5. Figure 5.13 presents these fragility

curves for several pipe sizes'.

The terms F(O) and F(M) in equation (6.12) are obtained as follows. F(O) is the value of a

fragility curve at the wall thickness equal to the observed wall thickness at the time of

inspection, w(O). In other words, F(O) is given by the fragility curves presented in Section 5 as

F(w(0)). F(O) represents the probability of failure of the pipe given knowledge of the wall

thickness at the time of inspection, but, of course, not given the knowledge that the pipe is not in

a failed condition at the time of inspection.

F(M) is the value of a fragility curve at the wall thickness equal to the estimated wall thickness

when the plant has operated for M years after the time of inspection, w(M). Hence, to obtain

F(w(M)), it is necessary to estimate the wall thickness by this time, w(M). This thickness can be

assessed using the thickness observed at the time of inspection (t =0) and the rate of

degradation for the piping. This rate may be considered to be constant, r, or a function of time,

r(t). In the general case in which the rate of degradation is a function of time, the pipe's wall

thickness after M years of operation from the time of inspection is given by

M .

w(M)=w(O)-Zr(i) (6.15)

i11

where r(i) is the rate of degradation (per year) during year i, and the summation is carried out in

intervals of one year.

The wall's thickness by the end of the Mth year can then be calculated using w(M) from

equation (6.15), and the probability that the buried pipe failed by this time, F(w(M)), can' be

obtained from the corresponding fragility curve.'

Sections 6.5 and 6.6 describe methods to assess the contribution to ACDP from a system

having buried piping and belonging to Category 1 (normally operating, and its failure causes an

1 The fragility curves in Figure 5.13 are actually presented as a function of the percentage of wall loss.

This percentage obviously can be derived from the pipe's original wall thickness and the remaining wall

thickness, w(t).

107
IE) and to Category 2.2.a (normally in standby, its failure does not cause an IE, and the system

fails after a true demand), respectively. The methods estimate the contribution to ACDP due to

degrading buried piping, and are applicable to those cases where an inspection shows that a

pipe has not failed, but has degraded.

6.5 A System is Normally Operating and its Failure Causes an Initiating Event

Since the system is normally operating, the piping is subjected to internal pressure. The failure

of the system causes an initiating event. A typical example of this kind of system in a

pressurized water reactor (PWR) is the component cooling water (CCW) that supplies cooling,

directly or indirectly, to the motor and seals of the reactor coolant pumps. Accordingly, if the

CCW is lost (failed), the initiating event 'loss of CCW" occurs, and the mitigating systems that it

supports also would be unavailable, unless the CCW is recovered or another recovery action is

completed.

A method was developed to estimate the contribution to ACDP due to degraded buried piping

for a system in Category 1. In other words, the system is normally operating, the piping is

subjected to internal pressure, and the failure of the system causes an initiating event. If the

pipe was inspected at time t = 0 and has not failed at this time, but is considered to be subjected

to degradation mechanisms, then it can be expected to continue degrading over the following

years.

The increase in core damage probability (ACDP) over M years of operation after the time of the

inspection due to the degradation of the buried piping can be expressed as:

ACDP = CP(M) x CCDP (6.16)

where

CP(M) = conditional probability of failure of the system (piping) between the time of an

inspection (t = 0) and the end of year M, given that the system has not failed at the time

of the inspection. It is given by equation (6.12).

CCDP is the conditional CDP given the loss of the system has occurred. In the example

of the CCW, this is the probability that core damage will occur given the loss of the

CCW.

Equation (6.16) can be solved for different values of M, the number of years from the time of

inspection to some future time, to obtain the ACDP over this interval.

Assessing the contribution to ACDP for those systems in Category 1 (Section 6.5) and Category

2.2.a (Section 6.6) requires calculating the following parameters: the conditional CDP given the

loss of the system (CCDP), the CDF given that a buried pipe fails, and the CDF given that a

buried pipe does not fail. The following considerations apply to these evaluations:

1. They were made using the Standardized Plant Analysis Risk (SPAR) models version 3.xx

that were available atithe beginning of March 2004 for the selected NPPs. Version 3.xx

corresponds to SPAR model versions 3.01 and 3.02 depending upon the particular plant

being evaluated. These models are full-power, level-1 PRA models for internal events. They

have some basic capabilities that previous versions did not have, such as more support

systems and an expanded number of event trees.

108
- s

., te, "-., '" '

2. The calculations using the SPAR models were carried out with the SAPHIRE computer code

version 7. The cutoff value for all evaluations was 8.8E-1 2/year (1 .OE-1 5/hour). It was used

in documenting the SPAR models and is considered adequate for the evaluations.

3. Since detailed information about the layout of a buried piping system was unavailable, it was

assumed that when the piping failed the complete system was unavailable.

4. The following systems were not evaluated because they were not included in the SPAR 3.xx

model of their corresponding plant: Fire Protection of McGuire 1 and 2, Fire Protection of

North Anna 1 and 2, Fire Protection and Containment Spray of Surry 1 & 2, and Standby

Gas Treatment of Hatch 1 & 2. It appears that the reason that these systems are not

included in the SPAR 3.xx models of these plants is that they are mainly used for events

other than level-1 internal events, such as fire events or level-2 events.

5. It is not known whether the Service Water and the Turbine Generator Cooling Water of the

Keowee's hydro units of the Oconee nuclear plant are normally operating (with internal

pressure), or if they are kept in standby. On the other hand, these systems are unique to

Oconee's hydro units, so the findings are not expected to be applicable to'any other nuclear

plant. For this reason, they were not evaluated at this time.

The CCDPs for the systems in Category 1 were evaluated using the SPAR 3.xx model of the

selected NPPs. Table 6.2 presents the results of these evaluations.

Equation (6.16) shows that the larger the CCDP, the larger is the contribution to ACDP. Hence,

for the five plants selected in this study, using the system with the largest CCDP value leads'to

a maximum ACDP. From Table 6.2, the largest value of the CCDP is 3.4E-2, which corresponds

to the Service Water System of McGuire.- A generic evaluation of the contribution to ACDP over

M years of operation after the time of inspection can be obtained by substituting this value for

CCDP in equation (6.16), which leads to:

ACDP = (3.4E-2) x CP(M) (6.17)

Therefore, a generic calculation of the ACDP over M years of operation after the time of

inspection, for Category 1 type systems belonging to the five plants, can be carried out using

equations (6.17)'and (6.12).

Equations (6.4), (6.17), and (6.12) can be solved in an incremental way for different values of M

until the risk acceptance criterion, i.e., equation (6.4), is satisfied. Subsection 7.1.1 describes

this process for the systems in Category 1. In this way, these equations are used to assess

whether it is acceptable for a plant to operate for M years after the time of inspection. The

results presented in Section 7 for the systems in this Category were obtained by solving these

equations.

Equation (6.12) is solved by using a degradation rate appropriate to this Category of system

where the pipe is subjected to internal pressure.

Equation (6.17) was developed to carry out a generic evaluation because it uses the largest

CCDP of all Category 1 piping systems from the 5 plants selected in this study.

-109
6.6 A System is Normally in Standby and its Failure Does Not Cause an Initiating Event

This section describes a method to estimate the contribution to ACDP due to degrading buried

piping for a system in Category 2.2.a. In other words, the system is normally in standby, and the

failure of the system does not cause an initiating event during power operation. A typical

example is the Residual Heat Removal (RHR) system.

If a buried pipe was inspected at time t = 0 and has not failed at this time, but is considered to

be subjected to degradation mechanisms, then it can be expected to continue to degrade over

the following years. If the plant is operated M years after the time of inspection, then the method

developed below determines the increase in projected risk over this period by calculating the

ACDP that results from operating this plant during the M years.

The piping is not subjected to internal pressure during power operation, but only on a system

demand, which may be either a test demand or a true system demand. If the pipe fails on a test

demand, then the contribution to ACDP comes from the possibility of an initiating event requiring

the system's operation while the pipe is being repaired, provided the plant is not shut down to

repair the system. The contribution to ACDP of the pipe failures discovered during true system

demands depends on the frequency of both true system demands and test demands. This is

because if the pipe fails on a true demand, the system fails, and if the pipe fails on a test

demand, the system will be unavailable while the pipe is being repaired, as long as the plant

keeps operating during this repair.

A review of the specific systems to be evaluated (for the five NPPs selected) indicated that if

any of them fails during operation after a test, then the plant will not continue to operate, i.e., it

will be shut down. Hence, the ACDP for these systems is due to failures after "true" demands.

To derive an expression for calculating the change in CDP (ACDP), let A, be the initiating event

frequency for initiating events of type i. For the pipe to fail on a true system demand of type i, in

the interval (t, t+dt), a true system demand of type i must occur (with probability A, dt); the pipe

must not have failed before t (represented by the reliability of the pipe, R(t)), and the pipe must

fail on the true system demand at time t (probability CP(t)). Then, the probability that the pipe

fails in the interval (t, t+dt) given initiating event i is given by A, CP(t) R(t) dt.

To obtain the contribution of pipe failures on true system demands to the core damage

probability (ACOP), this expression (Al CP(t) R(t) dt) is multiplied by [P(CD / I E and pipe fails) -

P(CD / IE1 and pipe does not fail)], summed over all initiating events, and then integrated from

the time of the inspection (time = 0) to the end of M years (time = M), as follows:

t-M

ACDP = |EA,[P(CD/lEiand pipe fails) - P(CD/IE1 andpipe does not fail)]CP(t) R(t)dt (6.18)

t=o i

where P(CD / IE, and pipe fails) is the probability of core damage given that the initiating event i

occurred, and the pipe failed. P(CD / IE1 and pipe does not fail) is defined similarly.

The contribution of pipe failures on true system demands to the core damage probability

(ACDP) is obtained by summing all initiating events in equation (6.18):

110
t=M

ACDP = {CP(t)R(t)[CDF(givenpipefails) - CDF(givenpipe does not fail)]dt tw , !..... . .

(6.19)

To calculate the probability the pipe has not failed before time t (the reliability R(t) in'equation

(6.19)), it is noted that the pipe can fail from either true system demands or test demands.

Denote the frequency of total demands by AtOtal,

Atoal 1 =Ai + Atest I ,. . . . (6.20)

where kt,,t is the test frequency. The reliability decreases in time because of pipe failures that

occur according to: -

dR(t) =7-A,,aCP(t)R(t) dt

The solution of differential equation (6.21) is:

R(t) = exp [- At,,, JCP(t)dt

t=O

(6.21)

; (6.22)

The degradation acceptance criteria presented in Section 7 indicates that a buried pipe should

not be allowed to continue operating H the degradation at the time of inspection is more than

approximately 45% of the original nominal pipe wall thickness. The fragility curves in Figure 5.13

show that a buried pipe of any size with' a 45% wall loss has a probability of failure of less than

1 E-10, and a pipe with a percentage wall loss less than 45% has a smaller probability' of failure.

The range of wall loss of 45% or less is named in this study the range of wall loss of interests

because a buried pipe with a degradation of about 45% or more of wall loss would not be

allowed to continue operating.

CP(t) in equation (6.22) is given by equation (6.1 1). CP(t) is about 1 E-10 'or less for the range of

wall loss of interest.'Since CP(t) is very small fdrthe range of wall loss of interest, equation

(6.22) shows that R(t) is very close to 1 1 1naddition,'the terms CDF(given pipe fails) and

CDF(given pipe does not fail) in equation (6.19) are considered constant over time. According to

these considerations, equation (6.19) becomes

ACDP = [CDF(given pipefails) - CDF(given pipe does not fail)] JCP(t)dt (6.23) -;* * . tsO

The solution of equation (6.23) can be approximated by numerically solving the integral in

increments of 1 year, as follows:

;. D I fd . [Iginpe .

i\CDP =[CDF(givenpipefails) -CDF(givenpipe doesnot fail)] :CP(i)

s11

(6.24)

where CP(i) is the conditional probability of pipe failure between the time of inspection and the

end of year i. CP(i) is given by equation (6.11).

.111
Since R(t) was approximated to 1, the effect of test demands on reducing the contribution of

pipe failures to the core damage probability has conservatively been omitted. This conservatism

is considered negligible.

Equation (6.24) can then be solved for different values of M, the number of years from the time

of inspection to some future time, to obtain the ACDP over this interval.

Equation (6.24) shows that the larger the difference in the expression

[CDF(given pipe fails) - CDF(given pipe does not fail)],

the larger the contribution to ACDP. A generic evaluation of the ACDP after M years of

operation can be obtained by using the largest difference [CDF(given pipe fails) - CDF(given

pipe does not fail)] from the systems of this type belonging to the five plants. Values for the

CDF(given pipe fails) and CDF(given pipe does not fail) were evaluated using the SPAR 3.xx

model of the selected NPPs, according to the considerations described in Section 6.5. Table 6.3

provides the results of these evaluations. From this table, the largest difference [CDF(given pipe

fails) - CDF(given pipe does not fail)] is 8.5E-3 I year, corresponding to Surry's Emergency

Feedwater. A generic evaluation of the contribution to ACDP can be obtained using this value in

* equation (6.24) as follows:

ACDP = (8.5E-3/ year)y CP(i) (6.25)

1=

Therefore, a generic calculation of the ACDP over M years of operation after the time of

inspection, for the systems of this type belonging to the five plants, can be carried out using

equations (6.25) and (6.11).

Equations (6.4), (6.25), and (6.11) can be solved in an incremental way for different values of M

until the risk acceptance criterion, i.e., equation (6.4), is satisfied. Subsection 7.1.2 describes

this process for the systems in Category 2.2.a. In this way, these equations are used to assess

whether it is acceptable for a plant to operate for M years after the time of inspection. The

results presented in Section 7 for the systems in this Category were obtained by solving these

equations.

Equation (6.11) is solved by using a degradation rate appropriate to this type of system where

the pipe may not be under pressure, and there is no flow in the pipe.

Equation (6.25) yields a generic evaluation because it uses the largest difference of the

expression

[CDF(given pipe fails) - CDF(given pipe does not fail)]

among all of the systems of this type from the five plants selected in this study.

112
I - -I - I

I K- M years

. .. .Time

Start of life of

the buried pipe

Time of

inspection, to = 0

Time after

inspection, t

Figure 6.1 Relevant Events From the Start of Life of a Buried Pipe . . '"

: ':I 

Nois\

/ the pipe - Yes normally

pressurized

nt is >-"

t Is

fg? E

-Yes ,

* Category 2.1.b:

Replacement (or repair) Is done while

plant Is operating.

The ACDP would be

evaluated on a caseby-case basis.

No

NoCategory 2.1.a:

Replacement (or

repair) Is done when

the plant is shut down.

Risk is considered

negligible.

Figure 6.2 Roadmap For Selection of the Method to be Used For Each Type of System

113
Table 6.1 Buried Piping Systems and Descriptions of Twelve NPPs That Submitted Their License Renewal Application

Plant Number of Reactor NSSS Containment Architect/ Location

Buried Type Engineer Piping

Systems

Surry 1 & 2 8 PWR W Reinf. Conc. S&W Virginia

Edwin I. Hatch 1& 2 7 BWR GE Steel MK I Bechtel Georgia

North Anna 1 & 2 7 PWR W Reinf. Conc. S&W Virginia

Peach Bottom 2 & 3 5 BWR GE Steel MK I Bechtel Pennsylvania

McGuire 1 & 2 5 PWR W Steel (Ice Cond.) Duke N. Carolina

Catawba 1 & 2 5 PWR W Steel (Ice Cond.) Duke S. Carolina

Oconee 1, 2, & 3 5 PWR B&W Prestr. Conc. D&B S. Carolina

St. Lucie 1 & 2 4 PWR CE Steel Ebasco Florida

V. C. Summer 4 PWR W Prestr. Conc. Gilbert S. Carolina

Calvert Cliffs 1 & 2 3 PWR CE Prestr. Conc. Bechtel Maryland

Turkey Point 3 & 4 3 PWR W Prestr. Conc. Bechtel Florida

Arkansas Nuclear One 1 2 PWR B&W Prestr. Conc. Bechtel Arkansas

GE = General Electric; W = Westinghouse; B&W = Babcock &

S&W = Stone & Webster; D&B = Duke & Bechtel

Wilcox; CE = Combustion Engineering

114
. i

Table 6.2 Conditional Core Damage Probabilities

Used in the Methodology for Category 1 Buried Piping Systems

Plant System CCDP

McGuire 1 and2 2

| Service Water (SW) | 3.4E-2

Condenser Circulating Water(2 6.4E-6

North Anna 1 and 2

Service Water - 1.6E-2

Oconee 1, 2, and 3

| Condenser Circulating Water(3) | 2.7E-3

High Pressure Service Water"' 6.1 E-4

Surry 1 & 2

Service Water A"3.3E-3

Condensate"' 3.2E-6

Hatch 1 & 2

-Service Water (SW) - | 7.9E-3

Notes:

1. According to Surry's Individual Plant Examination (IPE), Service Water provides

cooling to the control room and relay room air conditioning unit chiller condensers. The

emergency switchgear room cooling is dependent upon these chillers. Hence, loss of

Service Water causes a loss of chilled water. This loss is not modeled in the SPAR

3.xx model, so the notebook for the Significance Determination Process (SDP) of

Surry (Azarm, 2003) was used to estimate this CCDP. This is a unique utilization of an

SDP notebook.

2. Loss of this system was considered to cause a transient with loss of main feedwater.

3. "Loss of Condenser Circulating Water" and Loss of High Pressure Service Water" are

not included as initiating events in Oconee's SPAR 3.xx model or in Oconee's SDP

notebook. It was assumed that either of these losses causes a tLoss of Low Pressure

Service Water."

!115
A

Table 6.3 Conditional Core Damage Frequencies

Used in the Methodology for Category 2.2.a Buried Piping Systems

Plant System CDF CDF

[given pipe fails] [given pipe

does not fail]

(per year) (per year)

McGuire 1 and 2

_ Diesel Fuel Oil(' ) 9.2E-4 1 1.1 E-5

North Anna 1 and 2 _ _ _

Diesel Fuel Oil) 6.4E-3 2.2E-5

Safety Injectione2 4) 1.6E-3

Recirculation Spraye2) 1.2E-4

RHR 2z 2.9E-5

Containment Spray 2) _ 2.7E-5

Oconee 1, 2, and 3

|SSF DG Fuel OilV3) | 1.4E-5 1.2E-5

Surry 1 & 2

Emergency Feedwater 8.5E-3 f 1.4E-5

Diesel Fuel Oil(') 4.4E-3

Safety Injection(4) 1.3E-3 |

Hatch 1 & 2

|_Diesel Fuel Oil(') 2.9E-3 4.3E-5

HPCIo)8 -1.3E-4

RCIC__) 9.OE-5

Fire Protectionp5' 4.3E-5

Notes:

1. Failure of Diesel Fuel Oil was assumed to cause the unrecoverable loss of all emergency

diesel generators (EDGs).

2. After the failure of the Containment Spray, Recirculation Spray, RHR, and Safety Injection

systems, their pumps were considered to be unavailable.

3. The failure of the Standby Shutdown Facility's (SSF's) Diesel Generator Fuel Oil was

considered to cause the unavailability of the SSF Diesel Generator.

4. For the failure of Safety Injection, all high- and low-head safety injection (HHSI and LHSI)

pumps were considered to be lost.

5. For failure of Fire Protection at Hatch, the firewater injection was considered not available.

6. The failure of the High-Pressure Coolant Injection (HPCI) was modeled as the loss of the

HPCI pump.

7. The failure of the Reactor Core Isolation Cooling (RCIC) was modeled as the loss of the

RCIC pump.

116
7 DEGRADATION ACCEPTANCE CRITERIA

The risk-informed degradation acceptance criteria (DAC) were developed by identifying the level

of degradation of a buried pipe that would potentially have a significant effect on plant risk. The

approach used to develop the DAC is based on the fragility curves calculated in Section 5.3,

definition of acceptable risk presented in Section 6.2,'and the methodology for' estimating the

risk associated with degrading buried pipe described in Sections 6.3 through 6.6. The DAC

developed below consider the effects of degradation after the time of inspection and the impact

that corrosion allowance, if provided for in the original design, may have on the final results.'

7.1 Calculation of Acceptable Wall Loss''

Sections 7.1.1 and 7.1.2 describe the methodology used to develop the acceptable wall loss for

generalized 'pipe wall degradation which may occur on the outside or inside surface of a buried

pipe. The applicability of these results to localized loss of material/pitting is discussed separately

in Section 7.1.3.'

For any pipe size and thickness, fragility curves can be developed as described in Section 5.3.

The fragility curves for nominal pipe sizes 2 through 42 in. (5.08 through 107 cm) were

calculated and presented in Figure 5.13. The fragility curves provide the probability of failure

versus percentage wall loss for SA-1066caibon steel pipe under design pressure loading.

Standard schedule pipe was utilized for all pipe sizes except 107 cm (42 in.) pipe, which used a

pipe thickness of 1.43 cm (0.562 in.) as explained in Section 5.3.

As described in Section 6.3, each buried piping system in the five selected plants used in this

study can be categorized as either a system that is normally operating and whose failure causes

an initiating event (Category 1), or a system that is normally in standby and whose failure does

not cause an initiating event (Category 2.2.a).'The DAC were developed separately for

Category 1 and Category 2.2.a buried piping systems as described below in Sections 7.1.1 and

7.1.2. The evaluation approach for buried piping of systems that might fall into other categories

are discussed in Section 6.3.

7.1.1 Category 1 Buried Piping System -

For a buried piping system that is normally operating and whose failure causes an initiating

event, the methodology described in' Section 6.5 was utilized to'determine the maximum

permissible wall loss. As shown in Section 6.5,' the following equation can be used to calculate

the increase in core damage probability (ACDP) for a Category 1 buried piping system:

ACDP = (3.4E-2) x CP(M) (7.1)

As discussed in Section 6.5, the 'value of 3.4E-2 corresponds to the envelope of the conditional

core damage probability (CCDP) for all buried piping systems from the five plants. CP(M) is the

conditional probability of failure of the'pipirng by'year M after the time of inspection and is given

by:

Nominal pipe size corresponds to a standardized outside diameter (O.D.) as defined in ASME B36.1 OM2004. For nominal pipe sizes 14 inches and above, the actual O.D. is equal to the nominal pipe size. For

nominal pipe sizes 12 in. and smaller, the actual O.D. is greater than the nominal pipe size, (e.g., 2 inch

nominal pipe actually corresponds to 2.375 In. O.D.).

117
CP(M) = F(M) - F(0) (7.2) 1 - F(O)

M is the number of years after the time of inspection and F(M) is the cumulative failure

distribution of the time-to-failure of the pipe at time M (i.e., fragility value from the fragility

curves). In this equation, F(0) represents the fragility of the pipe at time = 0 (time of inspection).

A spreadsheet calculation was performed using these equations to create a table which solves

for ACDP progressively year by year, for a given degradation rate and for various observed wall

loss percentages at the time of inspection. Table 7.1 presents a sample table created for a 40.6

cm (16 in.) diameter pipe which is degrading at a rate of 0.254 mm/year (0.01 in./year). These

tables were also calculated at other degradation rates of 0.0254 and 2.54 mm/year (0.001 and

0.100 inJyear) to cover the maximum expected range of degradation rates (see Section 3.4).

Table 7.1 shows the calculation of the various parameters needed to solve equations (7.1) and

(7.2). The parameters used in Table 7.1 are explained in the footnotes to the table.

For a given degradation rate, the ACDP can be solved for increasing values of time (the number

of years of operation after the time of inspection). As described in Section 6.2.2, the criterion for

assessing the acceptability of risk significance is that the ACDP of the system is less than or

equal to the acceptable increase in core damage probability identified as ACDPAcceptabj9

(hereinafter, referred to as ACDPA). At each year, the plant's calculated ACDP can be

compared to the ACDPA. When the plant's calculated ACDP reaches ACDPA, that defines the

number of years required for the buried pipe to reach a degradation level that would potentially

have a significant effect on plant risk. This becomes the degradation acceptance criterion in

terms of risk.

Using Table 7.1 as an example, for an observed wall loss at the time of inspection equal to

60%, the ACDP reaches ACDPA (see shaded boxes) between years 4 and 5. This corresponds

to an estimated percentage wall loss (EPWL) equal to 71.5%. The EPWL entries in the table

were calculated using the observed wall loss at the time of inspection and adding the additional

increment of wall loss (each year) caused by the degradation rate. Considering the range of

percent wall losses after the time of inspection of 10% through 70% (Table 7.1 shows a partial

tabulation of 10, 20, 50, & 60%), the acceptable EPWL varies between 71.5% and 73.5%. The

evaluation considered EPWL up to 70% because at 70% or higher, the number of years to

reach risk significance is less than one, which means that the buried pipe needs to be repaired

immediately. Since the variation in EPWL from 71.5% to 73.5% is relatively small, the minimum

acceptable EPWL value within each pipe size (71.5% in this case) was utilized to obtain the

acceptable percentage wall loss. Additional calculations were also performed at degradation

rates of 0.0254 and 2.54 mm/year (0.001 and 0.100 inches/year). For this example, the 2.54

mm/year (0.100 in./year) degradation rate resulted in a slightly lower value of 69.2% (compared

to the 71.5%). Since the differences in the acceptable percentage wall loss corresponding to

varying degradation rates were small, the minimum values for acceptable percentage wall

losses were utilized for the degradation acceptance criteria. The resulting acceptable

percentage wall loss as a function of pipe size (enveloped across varying observed wall loss

percentages and across varying degradation rates), is tabulated below. Using the minimum

value of percentage wall loss in the enveloping process provides some additional level of

conservatism.

118
_ !

Acceptable Percentage Wall Loss

For Category 1 Buried Piping Systems

(Considering Pressure Loading)

Nominal Acceptable

cm / in. % Wall Loss

5.08 /2 70.3

10.2/4 70.4

20.3 / 8 69.6

40.6 /16 69.2

61.0/24 68.7

76.2/30 68.1

107 /42 69.2

Since the acceptable percentage wall loss was initially determined based on pressure loads

alone, an adjustment was made to account for other loads such as soil surcharge load,

groundwater, and surface live loads. For each pipe size, the acceptable percentage wall loss

listed above was reduced by an amount needed to accommodate these other loads. To do this,

an "acceptable risk-based stress level' in the pipe corresponding to the acceptable percentage

wall loss was developed. The acceptable risk-based stress level in the pipe (Caywept'able risk) is

given by: -

PDacceptabie .:. .- i,-

Gacoeptabl risk = 2 (7.3) ta5pble H

where

P = design pressure

tamceptabie = thickness at the acceptable % wall loss based on pressure alone (obtained

from the above table

Dacceptable = average diameter at the acceptable % wall loss based on pressure alone

(calculated using txptabIe)

The contribution to pipe stress from all applicable loads (pressure and other loads) must not

exceed caaeptable risk, which can be expressed as follows:

0 pressure + otherbads < (arceptablerik (7.4)

Cyofrloads is the stress level corresponding to other loads as described above. For this study, a

reasonable value for expected pipe circurfme'eintial stress due to other loads (surcharge,

groundwater, and live load) is 50% of the pipe material yield strength. American Lifelines

Alliance Report (2001) recommends this criterion be used for through-wall bending stress from

earth loads (static, live, surface impact). Following this approach, 50% of the yield strength

results in 121 MPa (17,500 psi). The calculations described in Section 5.1 for the other loads

.119
satisfy this recommendation since they used 103 MPa (15,000 psi) as an upper limit. Using 121

MPa (17,500 psi) for CroherIoads is slightly more conservative. Therefore,

aother loads =121 MPa (17,500 psi) (7.5)

apressure is the stress corresponding to the pressure loading when other loads are present and is

given by:

PDave usingtmin (7.6)

pressure -

2 tmin

Substituting equations (7.3), (7.5), and (7.6) into equation (7.4), the variable tirni can be solved.

The variable tmi, represents the minimum required pipe wall thickness needed to accommodate

both pressure and other loads. The solution of these equations is demonstrated with an

example which follows.

Example

This example will consider a 40.6 cm (16 in. pipe), standard schedule (t = 0.953 cm (0.375 in.)),

and design pressure equal to 4.34 MPa (630 psi). The acceptable degradation is based on

69.2% wall reduction obtained from the previous table for pressure loading alone. Degradation

is assumed to occur at the outside pipe surface. The pipe stress corresponding to an acceptable

level of risk is calculated using equation (7.3) as follows (in terms of psi):

aaceptable risk = (630)(16-(2x.375)+.375(1-.692)) =41,906 psi (289 MPa) 2(0.375 x(1 -.692))

Substituting this value and the other terms into equation (7.4) results in the following (in terms of

psi):

PDaveusingtmin +17,500 •41,906

2t rn

Assuming corrosion occurs on the outside surface, this leads to the following expression (in

terms of psi):

P(Dinner + tmin) + 17,500 < 41,906

2tmin

This equation is solved for the required tmmn, which is calculated to be 0.1994 in. (0.506 cm).

Therefore, the acceptable percent reduction of the original nominal wall thickness is reduced

from 69.2% (if pressure acts alone) to:

0.375-0.1994 x 100 = 46.83% when considering pressure and other loads.

0.375

120

I
This'calculation was repeated for pipe sizes ranging from 5.08 cm to 107 cm (2 in. to 42 in.),

assuming standard schedule pipe (except for the 107 cm (42 in. pipe) which requires a

thickness of 1.43 cm (0.562 in.) to satisfy the D/t requirement of 80). The results of the

calculation for the various pipe sizes are shown below. The percentage wall losses fall into a

relatively narrow range between 45.0% and 48.6%.

Acceptable Percentage Wall Loss

For Category I Buried Piping Systems

(Considering Pressure and Other Loads)

Nominal Acceptable

Pipe Size % Wall Loss

cm / in. X'_!_WllLos_

5.08 /.2 47.5

10.2 / 4 48.6

20.3/8 47.0

40.6/16 -46.8

61.0/24 45.9

76.2130 45.0

107/ 42 47.7

7.1.2 Category 2.2.a Buried Piping System

For a buried pipirig system that is normally in standby,'and whose failure does not cause an

initiating event, the methodology described in Section 6.6 was utilized to determine the

maximum permissible wall loss. As shown in Section 6.6, the following equation can be used to

calculate the increase in core damage probability (ACDP) for a Category 2.2.a buried piping

system:

ACDP = (8.5E-3 / year)ECP(i) (7.7)

1=1

As discussed in Section 6.6, the value of 8.5E-3 i year corresponds to the envelope of the

expression [CDF(given pipe fails) - CDF(givefi pipe does not fail)] for all buried piping systems

from the five plants. As described in Section 6.4, CP(i) is the conditional probability of failure of

the piping at year i and is given by:

F(i) -F(O). CP(i)= (7.8) 1 - F(0) .

M is the number of years after the time of inspection and F(i) is the cumulative failure

distribution of the time-to-failure of the pipe at the i th year (i.e., fragility value from the fragility

curves).

A spreadsheet caldulation was performed using these equations by creating a table which

solves for ACDP progressively year by'year,'for a given degradation rate and for various

observed wall loss percentages at the-time of inspection. Table 7.2 presents a sample table

created for a 40.6 cm (16 in.) diameter pipe which is degrading at a rate of 0.254 mm/year (0.01

:. 121
in./year). The table shows the calculation of the various parameters needed to solve equations

(7.7) and (7.8). The parameters used in Table 7.1 are explained in the footnotes to the table.

The approach for the Category 2.2a buried piping is very similar to the Category 1 buried piping.

For a given degradation rate, the ACDP can be solved for increasing values of time, the number

of years of operation after the time of inspection. At each year, the plant's calculated ACDP can

be compared to the ACDPA (acceptable CDP based on the change in core damage frequency

(ACDF) criterion of 1 E-6 /year). When the plant's calculated ACDP reaches ACDPA, that defines

the number of years required for the buried pipe to reach a degradation level that would

potentially have a significant effect on plant risk. This becomes the degradation acceptance

criterion in risk terms.

Using Table 7.2 as an example, for an observed wall loss of 60% at the time of inspection, the

ACDP reaches ACDPA (see shaded boxes) between 4 and 5 years. This corresponds to an

estimated percentage wall loss (EPWL) equal to 73.2%. Considering the range of percent wall

losses of 10% through 70% (Table 7.2 shows a partial tabulation of 10, 50, & 60%), the

acceptable EPWL varies between 72.2% and 75.3%. Since this is a relatively small variation,

the minimum acceptable EPWL value within each pipe size (72.2% in this case) was utilized to

obtain the acceptable percentage wall loss. Additional calculations were also performed at other

degradation rates 0.0254 and 2.54 mm/year (0.001 and 0.100 inlyear). For this example, the

0.254 mm/year (0.010 in./year) degradation rate resulted in a slightly lower value of acceptable

percentage wall loss. Since the differences in the acceptable percentage wall loss

corresponding to varying degradation rates were small, the minimum values for acceptable

percentage wall losses were utilized for the degradation acceptance criteria. The resulting

acceptable percentage wall loss as a function of pipe size (enveloped across varying observed

wall loss percentages at the time of inspection and across varying degradation rates), is

tabulated below. Using the minimum value of percentage wall loss in the enveloping process

provides some additional level of conservatism.

Acceptable Percentage Wall Loss

For Category 2.2.a Buried Piping Systems

(Considering Pressure Loading)

Nominal Acceptable

Pipe Size % Wall Loss

cm / in.

5.08/2 74.2

10.2/4 73.2

20.3/ 8 72.7

40.6 /16 72.2

61.0/24 71.8

76.2/30 71.6

107 /42 72.1

As in the case of Category 1 buried piping systems, the acceptable percentage wall loss for

Category 2.2.a piping systems was initially determined based on pressure loads alone.

Therefore, an adjustment was made to account for other loads such as soil surcharge load,

groundwater, and surface live loads. For each pipe size, the acceptable percentage wall loss

122

r
listed above was reduced by an amount needed to-accommodate these other loads. The'same

method described for Category 1 buried piping systems was utilized to account for other loads

for Category 2.2.a buried piping systems. The results of the calculations for the various pipe

sizes are shown below. The percentage wall losses fall into a' range between 54.5% and 58.6%.

Acceptable 'Percentage Wall Loss

For Catego'ry 2.2a'BOried Piping Systems

(Considering Pressure and Other Loads)

-Nominal Acceptable

cm / in. % Wall Loss

5.08/2 58.6

; 10.2/4 56.6

, 20.3/8 55.8

40.6 /16 55.2

; 61.0/24 54.5

76.2/30.1 54.6

107 !/42 55.5

7.1.3 DAC for Localized Loss of Material/Pitting

Section 5.3 evaluated the fragility for localized loss of materialpitting. This evaluation was

based on tests on degraded buried piping which were reported in ASME B31 G-1 991. The test

data and results presented in ASME B31G-1991,'d6 not distinguish between general wall

thinning or pits. Based on the description6presented in the ASME B31 G-1 991, the data are

considered to be applicable to loss of mrterial including localized loss of material/pitting.

The analyses performed in Section 5.2.3 developed distributions of failure stress (% minimum

yield) for degraded pipe in terms of the mean and standard deviation for three ranges of

corrosion depths (40% to 60%, 60% td 80%,'ard 80% to 100%). The results demonstrated that

the mean values for all three ranges of degradation were higher than those obtained from the

fragility analyses for general wall thinning. Fragility curves were also developed in terms of

probability of failure versus internal pipe pressure for the three ranges of degradation. These

fragility curves also demonstrated that the results obtained from the fragility analyses for general wall thinning are conservative forocalizdd loss of materialpitting.

It should be noted that due to the small size of the test sample (47 tests), the fragility curves

developed from the test data were not directly relied upon to develop the DAC. Instead, the

results obtained from test data were compared to the results from the general wall thinning

analysis. The comparison of these two sets of results demonstrated with reasonable confidence

that the fragility curves developed byaanalysis for the general wall thinning case bound the test

data for localized/pitting corrosion. Therefore, for purposes of developing the DAC for localized

loss of materialpitting, the same acceptance limits developed for the general wall thinning case

are recommended. ' -' ' ' -

... . ...

-123
i

7.2 Development of Degradation Acceptance Criteria

This section of the report describes how the acceptable percentage wall loss values presented

in Sections 7.1.1 and 7.1.2 were used to develop the degradation acceptance criteria in a form

that is simple to use and considers degradation over time. Section 7.2.1 develops the

degradation acceptance criteria without considering whether corrosion allowance was included

in the original design of the buried piping system. Section 7.2.2 develops an approach which

considers corrosion allowance, if it can be confirmed that it was included in the original design of

the piping system.

7.2.1 Degradation Acceptance Criteria Without Consideration of Corrosion Allowance

The degradation acceptance criteria developed below is expected to be utilized for most cases

because it does not require the user of the criteria to determine whether corrosion allowance

was utilized in the original design of the buried piping system. Without this knowledge, however,

the DAC may be somewhat conservative since it does not take advantage of the possibility that

some of the observed wall loss in a degraded pipe may be within the corrosion allowance.

If it turns out that the DAC cannot be satisfied, then it is suggested that the design basis of the

buried piping system be reviewed to determine whether corrosion allowance was provided and

the magnitude of the corrosion allowance. This additional information can then be used to check

the degraded condition at the time of inspection against the DAC developed in Section 7.2.2,

which considers corrosion allowance that may have been incorporated in the original design of

the piping system.

To simplify the development and application of the DAC for buried piping systems, without

consideration for corrosion allowance, the envelope of the acceptable percentage wall loss from

Category 1 and Category 2.2.a piping systems was utilized. This was achieved by noting that

the percentage wall loss for Category 1 piping is less than Category 2.2.a for all pipe sizes.

Therefore, the acceptable percentage wall loss for Category 1 buried piping was utilized to

represent both categories of piping. Using the Category 1 values for both categories introduces

some additional level of conservatism for the Category 2.2.a piping. The advantage of this

approach is that it eliminates the need by the user of the DAC to utilize multiple tables.

Therefore, the following (enveloped) acceptable percentage wall loss will be utilized for both

types of buried piping systems when corrosion allowance is not being considered:

Acceptable Percentage Wall Loss

Without Consideration of Corrosion Allowance

Nominal Acceptable

Pipe Size % Wall Loss

cm /in. _ _ _ _ _

5.08/2 47.5

10.2/4 48.6

20.3/8 47.0

40.6 / 16 46.8

61.0/ 24 45.9

76.2 /30 45.0

107 /42 47.7

124

I'
For a given pipe size having a standard schedule or thicker pipe (the case of the 107 cm (42 in.)

pipe requires a thickness of 1.43 cm (0.562 in.) or more), these values represent the maximum

acceptable wall loss which would lead to a potentially significant effect on plant risk. If the

degradation of a particular buried pipe is observed to be close to these limits, then immediate

attention is required to correct this problem. However, if the observed wall loss at the time of

inspection is well below these limits', then the question that arises is how much longer can the

system continue to operate before the degradation reaches a level which would potentially have

a significant effect on plant risk? One should never plan to reach this level of degradation;

however, it does provide a measure of time which may permit various steps to mitigate, monitor,

and/or correct the degraded condition depending on the severity of the pipe degradation.

To predict the effects of degradation over time,'it is required to estimate the degradation rate for

the particular buried piping system. As discussed in Section 3.4 this is a function of

environmental, metallurgical, and hydrodynamic variables. These variables include items such

as pipe material; soil conditions; adequacy of coatings; fluid parameters such as temperature,

pressure, velocity, and water quality; and type'of corrosion/degradation. Since these parameters

vary' depending on the piping system and nuclear plant, it is beyond the scope of this report to

define an appropriate'degradation rate. Instead'a description of the important parameters that

should be reviewed to select an appropriate degradation rate are discussed and presented (see

Section 3.4). In addition, information is provided in Section 3.4 which indicates' some typical

degradation rates that have been identified in the nuclear power industry. These include

degradation rates for service water buried piping systems and degradation rates for specific

degradation occurrences that have been reported in NRC Information Notices. Based on the

EPRI Report TR-103403 (1993), general corrosion rates vary from 1 to >10 mils/year (1 mil per

year = 0.0254 mm/year (0.001 in. per year)) for carbon steel and low alloy steels in fresh water

at temperatures of 1.670C to 40.60C (350F to 1050F). Based on Information Notices discussed in

Section 3.4, degradation rates for above ground piping for severe cases of degradation were

found to be higher, as much as 60 to 90 mils per year. Therefore, the DAC developed within this

research program considered degradation rates ranging from 1 to 100 mils per year (0.0254 to

2.54 mm per year (0.001 to 0.100 iniyear)).

To simplify the DAC, the degradation rates considered were assumed to remain constant over

time. While degradation rates over long'periods of time may increase, consideration of constant

degradation rates is a'good start, especially'for shorter periods of time which is the primary

concern. If results for increasing degradation'rates are needed, then the same methodology

described in this section can be applied to develop DAC for any definition 6f increasing

degradation rates by assuming a linear, polynomial, exponential, or any other relationship

between degradation rate and time.'

By assuming a constant'degradation rate,'the equation shown below can be used to predict the

number of years (N) 'required for the buried pipe to reach a degradation ,corresponding to the

acceptable wall loss percentage calculated previously.

NxDR OL+ xl=x100=AL- (7.9)

tnom

where

OL = Observed wall loss at the time of inspection as a percentage of original nominal

wall thickness

N = Number of years

125
DR = Degradation rate

tnam = Nominal wall thickness

AL = Acceptable wall loss percentage

This equation was solved for the number of years (N) and then applied to varying degradation

rates, varying observed wall losses at the time of inspection, and the full range of pipe sizes.

The results of these calculations are presented in Table 7.3. Calculated values for the number

of years were rounded down to the lower whole number since the results are not expected to be

accurate to fractions of a year and rounding down eliminates any unconservatism that would

arise if some of the results are rounded up. This table provides the DAC for degraded buried

piping which can be used to determine how quickly a degraded pipe might reach a condition

which would potentially have a significant effect on plant risk.

Separate DAC tabulations are presented in Table 7.3 for each pipe size. For a given pipe size,

and knowing two variables consisting of observed wall loss at the time of inspection and

degradation rate, the number of years to reach risk significance is found by reading the entry

that intersects these two parameters. The DAC have been prepared for degradation rates

varying from 0.0254 to 2.54 mm per year (0.001 to 0.100 in./year) as explained earlier. When

the estimated degradation rate for a particular case falls between the tabulated values, the next

higher degradation rate shown in the table should be used or equation (7.9) can be utilized. The

percent wall loss values range from 0% to 50% since at a value of 50%, the maximum number

of years is zero, for all pipe sizes. A value of zero for the number of years in Table 7.3 means

that the degradation level has reached risk significance, and therefore, needs to be repaired

immediately. For observed wall loss percentages at the time of inspection, that fall between

tabulated values, the next higher observed wall loss should be used or equation (7.9) can be

utilized.

7.2.2 Degradation Acceptance Criteria With Consideration of Corrosion Allowance

The DAC presented in Table 7.3 should be used to determine the number of years required for

the buried pipe to reach a degradation level that would potentially have a significant effect on

plant risk. If this determination results in an unacceptable situation for the pipe, then the

approach described in this section can be used to take advantage of any corrosion allowance

that may have been included in the original design of the buried piping system. However, the

amount of corrosion allowance that was originally provided for in the design for the particular

buried piping system will need to be identified.

Rather than developing another set of tabulations for the consideration of corrosion allowance,

an approach was developed which enables the use of the existing Table 7.3 (developed without

the consideration of corrosion allowance). This approach eliminates the need for numerous

tables which would be required for varying levels of corrosion allowance that might have been

included in the original design of the buried piping systems. The approach that was developed

evaluates two possibilities for an observed degraded condition. Either the observed loss at the

time of inspection is less than or equal to the corrosion allowance, or it is greater than the

corrosion allowance.

Case A: Observed Loss is Less Than or Equal to the Corrosion Allowance

As shown below, the observed loss (OL) is still within the corrosion allowance (CA). Since OL <

CA, this condition is the same as using the existing DAC in Table 7.3 corresponding to a pipe

with a thickness of t, (equals t,, m - CA) and 0% wall loss at the time of inspection. Therefore, the

126
recommended approach for Case A, when OL < CA, is to use the existing Table 7.3 for DAC

and reading off the acceptable number of years at the row corresponding to 0% observed wall

loss at the time of inspection. It should be noted that the figure presented below shows

degradation occurring from the inside of the pipe; however, the approach is valid regardless

whether the corrosion occurs from the inside surface, outside surface or a combination of both.

Observed

Loss (OL)Ag

Corrosion

Allowance (CA)

Required thickness - - - pipe

for pressure and Nominal pipe

other loads -_ - size (t,,Or)

Case A: OL:5 CA

. OL B:, . G Ta t CorrosIoAwn

Case B: Observed Loss is Greater Than the Corrosion Allowance

As shown'below, the observed loss (OL) is greater than the 'corrosion allowance (CA) and has

reduced some of the wall thickness required for pressure and other loads.' For this case, where

OL > CA, a term identified as the equivalent degradation percentage (ED) can be defined as:

ED=OL CA x100

tr

.. ' ... 

. . . .. (7.10)

Observed

Loss (OL)

Corrosion

-Allowance (CA)

Required thickness

for pressure and -other loads

.(Q, = t,,,,, - CA -

I . .

Nominal pipe

size (tro,) -

, r - .

Case B: OL> CA

127
The ED provides the amount, in percentage terms, that was lost from the required wall

thickness for pressure and other loads. Now the existing DAC table corresponding to a pipe with

a thickness equal to (tr) and percent wall loss equal to ED can be used to determine the number

of years to reach a level of degradation that would potentially have a significant effect on plant

risk. Therefore, the recommended approach for Case B, when OL > CA, is to use the existing

Table 7.3 for DAC and reading off the number of years at the row corresponding to the

equivalent observed wall loss percentage (ED) as defined above. An example of how to apply

this approach to a pipe that is degraded beyond the corrosion allowance is provided in Section

7.3.

7.3 Guidance on the Use of Degradation Acceptance Criteria

If buried pipe degradation is identified at an NPP, it may not be evident whether the pipe still

complies with the plant licensing commitments or whether the degradation potentially has an

immediate significant effect on plant risk. Normally, the licensee performs an evaluation of the

degraded condition which may include further inspections, testing, calculation/design review,

and other actions to determine the severity of the condition, risk implications, and whether an

immediate repair is needed. Since these steps may take time, often beyond a week, the

methodology and DAC developed in this report provides guidance to the NRC staff for making

an assessment in a timely manner whether the degraded condition potentially has an immediate

significant effect on plant risk. This knowledge is important in order to provide input that can

help determine whether immediate repairs are warranted, or whether the appropriate

investigation, inspection, aging management, or other actions can be determined in the normal

course of evaluating the condition. The methodology and DAC can not be used by the industry

to justify existing degraded conditions; licensees are still required to meet their commitments

regarding the plant's current licensing basis.

This section provides the guidelines for using the DAC. It describes what the DAC are, how to

use them, the acceptable range of conditions permitting their use, and recommendations if the

DAC cannot be satisfied. More specifically, the DAC provides the number of years required for

the buried pipe to reach a degradation level that would potentially have a significant effect on

plant risk. To utilize the DAC, developed in Section 7.2, there were a number of variables and

parameters that were used in the various stages of the research study. Therefore, a number of

conditions must be satisfied to permit the use of the DAC. These conditions are described in this

section of the report.

It should be noted that the analyses were performed for SA-1 06 Grade B carbon steel pipe. The

results are considered applicable to stainless steel pipe as well because, most stainless steel

buried piping systems use 304 and 316 type stainless steel material which have higher ultimate

strength values and are more ductile than SA-106 Grade B carbon steel pipe.

The research described in this report developed DAC for general wall thinning and localized

loss of material/pitting in buried piping. The types of buried piping systems, configurations,

materials, and other conditions that must be satisfied to use the DAC have also been developed

and presented below.

The results obtained are based on the service conditions that buried piping is designed for (e.g.,

pressure induced stresses less than % of the minimum ultimate strength of the material and

relatively low temperatures) and recognizing that seismic induced stresses in buried piping are

self-limiting since deformations or strains are limited by seismic motions of the surrounding

media. In addition, the DAC presented below arose from a probabilistic risk assessment which

128
accounted for the contribution to risk of the postulated degradation of buried piping systems at

NPPs. The measure of risk was based on the change in core damage frequency due to internal

events during full power operation. It should be noted that even if the DAC show that there are

still many years of acceptable operation left, it is expected that the licensee'will evaluate the'

conditions that led to the degradation and may need to monitor, maintain, and/or repair the

degraded pipe based on the evaluation findings, the level of degradation, and the plant's

licensing commitments.

The DAC can not be used by the industry asla design tool to justify existing degraded

conditions. Licensees are still required to meet their commitments regarding their current

licensing basis. The DAC are intended to provide guidance to the NRC staff for making an

assessment in a timely manner whether degraded conditions, identified at a plant site,

potentially have an immediate significant effect on plant risk.

The DAC are applicable to the specific buried piping systems listed in Table 7.4 and can only be

used if the conditions described in Section 7.3 and Table 7.5 are satisfied. The conditions were

developed based on the limitations and requirements utilized in the various analyses described

in Sections 5, 6,' and 7. The buried piping systems listed in Table 7.4 were selected based on'

surveys and the LRAs which were described in Section 2. These piping systems should account

for most buried piping systems found at NPPs. If a particular degraded buried pipe does not

match one of the piping systems listed in Table 7.4, then it may still be possible to utilize the

DAC. However, the buried piping system would have to first be categorized in accordance with

Section 6.3. This would indicate which method should be followed for each category of buried -

piping system. In'addition, care should be exercised to ensure that the buried piping system. -'

satisfies the conditions given in Section 7.3 and Table 7.5, and is bounded by the parameters

used in the analyses described in Sections 5 through 7.

The DAC apply to piping directly buried in the ground (i.e., do not apply to piping installed within

another larger diameter pipe or tunnel). In addition, the DAC are applicable to a single buried

piping system and not a multiple set of buried piping systems. If degradation is identified in more

than one buried piping system then this should be reviewed on a case-by-case basis.

The DAC are applicable to welded steel pipes consisting of straight sections of buried pipe and

pipe components such as elbows, tees, branches, and reducers. Degradation of mechanical

connections such as flanges, Dresser couplings, bell'& spigot, and welds and adjacent heat

affected zones should be considered on a-case-by-case basis.

The DAC are not applicable to any degradation that includes pipe cracks; sharp discontinuities

regardless of the size, width, or length of the crack/discontinuity; defects caused by mechanical

damage, such as gouges and grooves; or defects introduced during manufacture. These

conditions need to be evaluated immediately. '

Degradation of coatings and/or linings is' not considered to directly and immediately affect the

safety of buried piping unless it has led to a loss of material of the base metal. Degradation of

coatings and/or lining, however, is an indication that other locations along the pipe should be

inspected because degradation at those locations might be more severe than at the observed

locations. In addition, if the degradation to the pipe interior coating and/or lining is significant, it

may cause fouling of the line and equipment (e.g '; heat exchangers) which can affect the

performance of the system. Another concern is that depending on the rate of coating or lining

degradation, this loss of protection may lead to degradation of the steel pipe before the end of

'129
the design life of the piping. Therefore, even though coating degradation is not within the scope

of the DAC, it needs to be inspected, monitored, and repaired when appropriate.

7.3.1 Degradation Acceptance Criteria (DAC)

In order to utilize the DAC, the conditions described above (within Section 7.3) and presented in

Table 7.5 must first be satisfied.

To apply the DAC, two quantities must be known: the observed wall loss at the time of

inspection and a degradation rate. The observed wall loss is to be calculated as a percentage of

the nominal undegraded pipe wall thickness (or as specified in Section 7.2.2 when corrosion

allowance is considered in the assessment). The degradation rate can be defined in terms of

mm per year (in. per year). It is most accurate to base the degradation rate on measured values

over time for the subject buried piping system at the plant, and therefore, this is the preferred

method to obtain the degradation rate. Although a degradation rate equal to the loss of material

divided by the total number of years that the plant has been operating provides one estimate, it

may not be sufficiently accurate. Additional information on degradation rates for piping systems

is provided in Section 7.2.1 and Section 3.4. This information is only provided as guidance on

typical degradation rate values that have been reported in the nuclear industry. The selection of

an appropriate degradation rate is the responsibility of the individual using these criteria, based

on the conditions that exist at the plant for a particular buried piping system. The degradation

rate selected for this assessment shall be the maximum rate throughout the particular piping

system being evaluated. If there is some uncertainty whether the maximum degradation rate

has been identified, then additional observations/measurements should be taken to ensure that

the maximum (or at least a conservative) degradation rate is being utilized.

To simplify the process, the observed level of degradation without consideration of corrosion

allowance can be used with the DAC. If this shows unacceptable results, then the approach that

considers corrosion allowance should be used.

A. Without Consideration of Corrosion Allowance

It is acceptable and conservative to check the observed degradation against the DAC without

consideration of corrosion allowance. The DAC for general wall thinning and localized loss of

material/pitting are provided in Table 7.3. This table provides the number of years required for

the buried pipe to reach a degradation level that would potentially have a significant effect on

plant risk.

Example:

A 76.2 cm (30 in.), standard schedule (0.953 cm (0.375 in.)) buried pipe has an observed wall

loss at the time of inspection equal to 0.381 cm (0.15 in.). This represents a wall loss of 40

percent ([0.381/0.953] X 100). For an estimated degradation rate for this system equal to 0.254

mm/year (0.01 in./year), the number of years from the time of inspection for this system to reach

risk significance can be found using Table 7.3. The number of years is read at the intersection

of the 40% wall loss row and the 0.254 mm/year (0.01 inlyear) degradation rate column. This

results in 1 year left from the time of inspection to reach a level of degradation that would

potentially have a significant effect on plant risk. Since the number of years to reach risk

significance is only one year, further immediate evaluation or action is needed.

130
B. Considering Corrosion Allowance

If it turns out that the 'number of years is short (e.g., before the remaining life of the plant or

before the next scheduled outage when the pipe will be repaired), then it is suggested that the

design of the'buried piping system be reviewed to determine whether corrosion allowance was

provided in the original desigri of the piping system and the magnitude of the corrosion

allowance.

If the observed wall loss is less than or equal to the corrosion allowance, then the approach

described in Section 7.2.2 (Case A) should be followed. If the observed wall loss is greater than

the corrosion allowance, then the approach described in Section 7.2.2 (Case B) should be

followed.

Example:

Use the same example as'above, except that the corrosion allowance included in the original

design of the buried piping system was identified to be 0.159 cm (1/16 in.). Since the observed

wall loss 0.381 cm (0.15 in.) is greater than the'corrosion allowance of 0.159 cm (1/16 in.), the

approach in Section 7.2.2 (Case B) will be followed.

From equation (7.10), the equivalent degradation percentage (ED) is calculated to be:

ED= OL-CA x100= 0 38 1 -0 .

15 9 x100=28%

tr 0.953-0.159

This means that the existing DAC in Table 7.3 with an observed wall loss of 28% and

degradation rate of 0.254 mm/year (0.01 inWyear) can be used to obtain the number of years.

Rounding the observed wall loss up to 30% (which is conservative) leads to the number of years

equal to 5. This is higher than the 1 year calculated in the previous example where corrosion

allowance was not considered. It should be noted that even though 5 years is longer than 1

year, this indicates that some corrective action needs to be taken soon unless the remaining life

of the plant is expected to be well below the 5 years found in this example.

7.3.2 If Conditions Cannot Be Satisfied or Unacceptable Results are Obtained

Step 1:

If the requirements and conditions described above and listed in Table 7.5 cannot be satisfied,

then a detailed review can be performed to determine whether the DAC can still be utilized. This

may very well be possible because to keep the DAC simple to use, the analytical methodology

utilized some conservative assumptions in arriving at the acceptance limits. In addition,

bounding values were sometimes used to cover various ranges of parameters. This avoided

having an extensive set of criteria to account for every permutation of parameters.

As an example, if the depth of soil cover for a particular pipe D/t ratio exceeds the limits

presented in the conditions described above, then a hand calculation of pipe stresses as

described in Section 5.1 could be performed based on actual conditions at the site now or

expected in the future. The stresses would have to meet the limits recommended in Section 5.1.

; 131
If unacceptable results are obtained advantage may be taken for a system that can be classified

as Category 2.2.a (normally in standby, and whose failure does not cause an initiating event)

since the Category 2.2.a criteria would be less restrictive than the Category 1 system (used to

develop the DAC). The acceptable percentage wall loss table developed in Section 7.1.2 for a

Category 2.2.a system can be used to obtain the number of years to reach risk significance,

following the same approach described in Section 7.2. This would result in a somewhat longer

time period to reach risk significance for all pipe diameters included in this study.

Step 2:

If the conditions still cannot be satisfied, then the DAC cannot be used and the degraded buried

pipe must be reviewed on a case-by-case basis. If instead, the conditions can be met however

the results are unacceptable, i.e., number of years to reach risk significance is short (e.g.,

before the next scheduled outage when the pipe will be repaired), then this indicates that a

condition exists which potentially has a significant effect on plant risk. Therefore, additional

detailed evaluation, and/or repair should be performed as soon as possible. Continued

monitoring for this level of degradation to see if the condition worsens or removal of the cause of

degradation to prevent further degradation would not be sufficient.

132
Table 7.1 Sample Calculation of Percentage Wall Loss Criteria

For Design Pressure Loading of Category 1 Buried Piping Systems

16 inch Nominal Pipe Size, Standard Schedule Pipe, 0.01 inches/year Constant Degradation Rate

No. of

Wal F0 2 Para- Years 3

WLaO F(O) Meters2 (M) 1 2 3 4 4.32* 5 6 7 8 8.36* 9

10 1.67E-15 EPWL 12.67 15.33 18.00 20.67 21.52 23.33 26.00 28.67 31.33 32.29 34.00

F(M) 2.78E-15 4.55E-15 7.66E-15 1.34E-14 1.62E-14 2.44E-14 4.57E-14 8.92E-14 1.82E-13 2.38E-13 3.88E-13

CP(M) 1.11E-15 2.89E-15 6.OOE-15 1.18E-14 1.45E-14 2.28E-14 4.41E-14 8.75E-14 1.80E-13 2.36E-13 3.87E-13

ACDP 3.77E-17 9.81E-17 2.04E-16 4.00E-16 4.94E-16 7.74E-16 1.50E-15 2.97E-15 6.12E-15 8.02E-15 1.31E-14

ACDPA 1.00E-06 2.OOE-06 3.0OE-06 4.OOE*06 4.32E.06 5.00E-06 6.OOE-06 7.OOE-06 8.OOE-06 8.36E.06 9.OOE.06

20 1.17E-14- 'EPWL ' 22.67 25.33 28.00 30.67 31.52 33.33 36.00 38.67 41.33 42.29 44.00

F(M) 2.10E-14 3.90E-14 7.52E-14 1.52E-13 1.91E-13 3.20E-13 7.1OE-13 1.67E-12 4.17E-12 5.89E-12 1.11E-11

CP(M)' 9.33E-15 2.73E-14-6.35E-14' .4OE-13' 1.80E-13'3.08E-13 '6.98E-13 1.66E-12 4.15E-12 5.88E-i2-~1.iiEl1

.ACDP_,, 3.17E-16 9.29E-16 2.16E-15 4.76E-15 6.11E-15 1.05E-14 2.37E-14 5.63E-14 1.41E-13 2.OOE-13 3.78E-13

ACDPA 1.OOE-06 2.OOE.06 3.00E-06 4.OOE-06 4.32E.06 5.00E-06 6.OOE-06 7.00E06 8.00E-06 8.36E-06 9.OOE-06

50 1.36E-10 EPWL 52.67 55.33 58.00 60.67 61.52 63.33 66.00 68.67 71.33 | ,72.29 | 74.00

F(M) 4.79E-10 1.88E-09 8.24E 09 4.12E-08 7.09E-08 2.36E-07 1.57E-06 1.21E.05 1.07E.04 2.43E-04 1.06E.03

CP(M) 3.43E-10 1.74E-09 8.ilE-09 4.1OE-08 7.07E208 2.36E-07 1.57E.06 1.21 E05 1.07E-04 2.43E-04 1.06E-03

ACDP 1.17E-11 5.91E-11 2.76E-10 1.40E-09 2.41E-09 8.022-09 5.33E.08 4.11E.07 3.65E-06 8.25E-06 3.60E-05

ACDPA 1.00E-06 2.00E-06 3.OOE.06. 4.00E-06 4.32E-06 '5.00.E06 6.OOE-06 '7.OOE-06 8.00E-06 J68.36E-06 9.OOE-06

60 2.72E-08 EPWL 62.67 65.33, 68.00 70.67 ['.:71.52 73.33 76.00 78.67 81.33 82.29 84.00

F(M) 1.51E-07 9.63E-07 7.16E-06 6.15E.05 1.26E-04 5.94E.04 6.04E.03 5.33E-02 3.37E-01 .5.36E-01 8.75E-01

CP(M) 1.23E-07 9.36E-07 7.13E-06 6.14E-05 1.26E-04 5.94E-04 6.04E-03 5.53E-02 3.37E-01 5.36E-01 8.75E-01

ACDP 4.19E.09 3.18E-08 2.42E-07 2.09E-06 4.27E 2.02E-05 2.05E-04 1.88E-03 1.15E-02 1.82E-02 2.97E-02

ACDPA 1.OOE-06 2.OOE-06 3.00E-06 4.OOE.06 14.32E061 5.OOE-06 6.OOE-06 7.OOE.06 8.00E.06 8.36E-06 9.OOE-06

1 In. equals 2.54 cm

133
Footnotes:

1. % wall loss corresponds to the observed pipe wall loss at the time of inspection.

2. The definition of each parameter is given below, with a detailed description presented in Section 6.2 to 6.5.

F(O) = Unconditional probability of failure at the time of inspection (M=O), which can be obtained from the fragility curve at

the % wall loss at the time of inspection

EPWL = Estimated percentage wall loss at year M (calculated from the % wall loss at the time of inspection and the

degradation rate)

F(M) = Estimated unconditional probability of failure at year M corresponding to the EPWL, which can be obtained from the

fragility curve

CP(M) = F(M)-F(O)

1 -F(O)

ACDP = 3.4E-2 CP(M)

ACDPA = Acceptable increase in core damage probability over M years after the time of inspection = 1 .OE-6/year x M years

3. No. of Years (M) corresponds to the number of years after the time of inspection.

* In order to obtain a more accurate EPWL, at the point in time when risk significance is reached, interpolation was performed

between the adjacent two years so that ACDP is as close as possible to ACDPA.

134
Table 7.2 Sample Calculation of Percentage Wall Loss Criteria

For Design Pressure Loading of Category 2.2a Buried Piping Systems

16 Inch Nominal Pipe Size, Standard Schedule Pipe, 0.01 inches/year Constant Degradation Rate

Pam- No.of

Wall F(0) 2 Meaters 2 Y(eM)s 1 2 3 4 4.95* 5 6 7 8 8.96* 9

Loss'M

10 1.67E-15 EPWL 12.67 15.33 18.00 20.67 23.20 23.33 26.00 28.67- 31.33 33.89 34.00

F(M) 2.78E-15 4.55E-15 7.66E-15 1.34E-14 2.36E-14 2.44E-14 4.57E-14 8.92E-14 1.82E-13 3.76E-13 3.88E-13

CP(M) 1.11E-15 2.89E-15 6.OOE-15, 1.18E-14 2.20E-14 2.28E-14 4.41E-14 8.75E-14 1.80E-13 3.75E-13 3.87E-13

CumCP(M) 1.11E-15 4.OOE-15 9.99E-15 2.18E-14 4.26E-14 4.38E-14 8.79E-14 1.75E-13 3.55E-13 7.15E-13 7.31E-13

ACDP -'' 9.44E-18 3.40E-17 8.49E-17 1.85E-16 3.62E-16 3.72E-16 7.47E-16 1.49E-15. 3.02E-15 6.08E-15 6.21E-15

, ACDPA 1.00E-06 2.00E-06 3.00E-06 4.OOE-06 4.95E-06 5.00E-06 6.00E-06 7.002-06 8.OOE-06 8.96E-06 9.00E-06

50 1.36E-10 EPWL ' 52.67 55.33 58.00 60.67 63.20 63.33 66.00 68.67 71.33 [.73.89 74.00

F(M) 4.79E-10 1.88E.09 8.24E-09 4.12E-08 2.16E-07 2.36E-07 1.57E-06 1.21E-05 1.07E-04 9.66E-04 1.06E-03

CP(M) 3.43E-10 1.74E-09 8.11E-09 4.1OE-08 2.15E-07 2.36E-07 1.57E-06 1.21E-05 1.07E-04 9.66E-04 1.06E-03

Cum CP(M) 3.43E-10 2.08E-09 1.02E-08 5.12E-08 2.56E-07 2.68E-07 1.84E-06 1.39E-05 1.21E-04 1.05E-03 1.09E-03

ACDP 2.92E-12 1.77E-11 8.66E-11 4.35E-10 2.18E-09 2.28E-09 1.56E-08 1.18E-07 1.03E:06 8.9'E-06| 9.28E-06

-- ACDP , 1.OOE.06 2.002-06 3.00E-06 4.00E-06 4.95E-06 5.002-06 6.OOE-06 7.00-E06 8.00E-06 8.96E-O6 9.OOE-06

60 2.72E-08 EPWL 62.67 65.33 68.00 70.67 [ 73.20 73.33 76.00 78.67 81.33 83.89 84.00

F(M) 1.512-07 9.63E-07 7.162-06 6.152-05 5.29E-04 5.942-04 6.042-03 5.532-02 3.372-01 8.592-01 8.752-01

CP(M) 1.23E-07 9.36E-07 7.13E-06 6.14E-05 5.29E-04 5.94E-04 6.04E-03 5.53E-02 3.37E-01 8.59E-01 8.75E-01

Cum CP(M) -,. 1.23E-07 1.06E-06 8.19E-06 6.96E-05 5.73E-04 6.02E-04 6.64E-03 6.20E-02 3.99E-01 1.22200 1.26E00

ACDP 1.05E-09 9.002-09 6.96E-08 5.92E-07 |.87E-OB|5.12E-06 5.64E-05 5.27E-04 3.39E-03 1.04E-02 1.07E-02

ACDPA 1.00-E06 2.00-E06 3.00E-06 4.00E-06 |4.95E-06 5.00E-06 6.002-06 7.00E-06 8.00E-06 8.96E206 9.002-06

I In. equals 2.54 cm

135
Footnotes:

1. % wall loss corresponds to the observed pipe wall loss at the time of inspection.

2. The definition of each parameter is given below, with a detailed description presented in Section 6.2 to 6.6.

F(O) = Unconditional probability of failure at the time of inspection (M=O), which can be obtained from the fragility curve at

the % wall loss at the time of inspection

EPWL = Estimated percentage wall loss at year M (calculated from the % wall loss at the time of inspection and the

degradation rate)

F(M) = Estimated unconditional probability of failure at year M corresponding to the EPWL, which can be obtained from the

fragility curve

Cp(M) = F(M)-F(O) CP(M) - -F(O)

M

Cumulative CP(M) = ZCP(i)

-i1

ACDP = 8.5E-3 / year x Cumulative CP(M)

ACDPA = Acceptable increase in core damage probability over M years after the time of inspection = 1 .OE-6/year x M years

3. No. of Years (M) corresponds to the number of years after the time of inspection.

* In order to obtain a more accurate EPWL, at the point in time when risk significance is reached, interpolation was performed

between the adjacent two years so that ACDP is as close as possible to ACDPA.

136
Table 7.3 Degradation Acceptance Criteria Providing The Number Of Years That Would Potentially Have a

Significant Effect On Plant Risk*

2 Inch Nominal Pipe, Nominal Wall Thickness Equal to or Greater Than 0.154 Inches

% Wall Loss Number Of Years After the Time of Inspection That Would Potentially Have a Significant Effect

at the Time On Plant Risk For Degradation Rates (inches/year) Equal To:

of Inspection 0.001 0.002 0.004 0.006 0.008 0.010 0.020 0.040 0.060 0.080 0.100

0. 73 36 18 12 9 7 3 1 1 0 0

5' 65 32 16 10 8 6 3 1 1

10 57 28 14 9 7 5 2 1 0

15 50 25 12 8 6 5 2 1

20 42 21 10 7 5 4 2 1

25 34 17 8 5 4 3 1 0

-30' 26 13' 6 4 3 2 1

35' 19 9. 4 .3 2 1 0

11 5 2 ' -1 '--'

5-. .... ,,,, ,, , OO " ;

50 , 0 0 - .

4 Inch Nominal Pipe, Nominal Wall Thickness Equal to or Greater Than 0.237 Inches

% Wall Loss Number Of Years After the Time of Inspection That Would Potentially Have a Significant Effect

at the Time On Plant Risk For Degradation Rates (inches/year) Equal To:

of Inspection 0.001 0.002 0.004 0.006 0.008 0.010 0.020 0.040 0.060 0.080 0.100

0' 115 57 28 19 14 11 5 2 1 1 1

5 103 51 25 17 12 10 5 2 1 1 1

10 91 45 22 15 11 9 4 2 1 1 0

15 79 39 19 13 9 7 3 1 1 0

20 67 33 16 11 8 6 3 1 1

25 55 27 13 .9 6 5 2 1 0

-30 44 22 11 7 5 . 4 2 1

35 32' 16 8 5 4' 3 1 0

40 20 10 5 3 *2 2' 1

45 8 4 2 1 1 0 0

50 0 0 , 0 0 0

137
8 Inch Nominal Pipe, Nominal Wall Thickness Equal to or Greater Than 0.322 Inches

% Wall Loss Number Of Years After the Time of Inspection That Would Potentially Have a Significant Effect

at the Time On Plant Risk For Degradation Rates (inches/year) Equal To:

of Inspection 0.001 0.002 0.004 0.006 0.008 0.010 0.020 0.040 0.060 0.080 0.100

0 151 75 37 25 18 15 7 3 2 1 1

5 135 67 33 22 16 13 6 3 2 1 1

10 119 59 29 19 14 11 5 2 1 1 1

15 103 51 25 17 12 10 5 2 1 1 1

20 87 43 21 14 10 8 4 2 1 1 0

25 70 35 17 11 8 7 3 1 1 0

30 54 27 13 9 6 5 2 1 0

35 38 19 9 6 4 3 1 0

40 22 11 5 3 2 2 1

45 6 3 1 1 0 0 0

50 0 0 0 0

16 Inch Nominal Pipe, Nominal Wall Thickness Equal to or Greater Than 0.375 Inches

% Wall Loss Number Of Years After the Time of Inspection That Would Potentially Have a Significant Effect

at the Time On Plant Risk For Degradation Rates (inches/year) Equal To:

of Inspection 0.001 0.002 0.004 0.006 0.008 0.010 0.020 0.040 0.060 0.080 0.100

0 175 87 43 29 21 17 8 4 2 2 1

5 156 78 39 26 19 15 7 3 2 1 1

10 138 69 34 23 17 13 6 3 2 1 1

15 119 59 29 19 14 11 5 2 1 1 1

20 100 50 25 16 12 10 5 2 1 1 1

25 81 40 20 13 10 8 4 2 1 1 0

30 63 31 15 10 7 6 3 1 1 0

35 44 22 11 7 5 4 2 1 0

40 25 12 6 4 3 2 1 0

45 6 3 1 1 0 0 0

50 0 0 0 0

138
24 Inch Nominal Pipe, Nominal Wail Thickness Equal to or Greater Than 0.375 Inches

°% Wall Loss Number Of Years After the Time of Inspection That Would Potentially Have a Significant Effect

at the Time On Plant Risk For Degradation Rates (inches/year) Equal To:

of Inspection 0.001 0.002 0.004 0.006 0.008 0.010: 0.020 0.040 0.060 0.080 0.100

0 .172

5 153

10: 134

15 115

* 20 97

25 78

-30 59

.35 401

40 . 22

45 : :-

... 0.-.. 0

86

76

.67 -

57

48

39

29

20

11

. . ... I- -0

.-. ' . .- 0 ! .-,..-.

43

38

33

28

24

19

14

10

5

0.- .-

28

25

22

19

16

13

9

6

3

-. l .- I!, . X

21

19

16

14

12

9

7

5

2

0- - ; 

17

15

13

-11

9.

i'

8

7

.6

5

.4

3

4

3

3

2

2

1

2

2

2

1

1

2

1

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I

1

1

1

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0

1 0

5 2 1 0

4 2

2 1

0 . , 0 . . I 

1

0

30 Inch Nominal Pipe, Nominal Wall Thickness Equal to or Greater Than 0.375 Inches

% Wali Loss Number Of Years After the Time of Inspection That Would Potentially Have a Significant Effect - at the Time On Plant Risk For Degradation Rates (inches/year) Equal To:

of Inspection 0.001 0.002 0.004 0.006 0.008 0.010 0.020 0.040 0.060 0.080 0.100

0 168 84 42 28 21 16 8 4 2 2 1

5 149 74 37 24 18 14 7 3 2 1 1

10 131 65 32 21 16 13 6 3 2 1 1

15 112 56 28 18 14 11 5 2 1 1 1

20 93 46 23 15 11 9 4 2 1 1 0

25 74 37 18 12 9 7 3 1 1 0

30 56 28 14 9 7 5 2 1 0

35 - 37 18 9. 6 4 3 1 0

40 9 418 3 2: 1 0

45 : 0 0 0 0 0 0

50

139
42 Inch Nominal Pipe, Nominal Wall Thickness Equal to or Greater Than 0.562 Inches

% Wall Loss Number Of Years After the Time of Inspection That Would Potentially Have a Significant Effect

at the Time On Plant Risk For Degradation Rates (inches/year) Equal To:

of Inspection 0.001 0.002 0.004 0.006 0.008 0.010 0.020 0.040 0.060 0.080 0.100

0 268 134 67 44 33 26 13 6 4 3 2

5 239 119 59 39 29 23 11 5 3 2 2

10 211 105 52 35 26 21 10 5 3 2 2

15 183 91 45 30 22 18 9 4 3 2 1

20 155 77 38 25 19 15 7 3 2 1 1

25 127 63 31 21 15 12 6 3 2 1 1

30 99 49 24 16 12 9 4 2 1 1 0

35 71 35 17 11 8 7 3 1 1 0

40 43 21 10 7 5 4 2 1 0

45 15 7 3 2 1 1 0 0

50 0 0 0 0 0 0

1 in. equals 2.54 cm.

This table is applicable to pipe wall loss degradation from the inside surface, outside surface, or a combination of both.

Nominal pipe size corresponds to a standardized outside diameter (O.D.) as defined in ASME B36.10M-2004. For nominal pipe sizes 14

inches and above, the actual O.D. is equal to the nominal pipe size. For nominal pipe sizes 12 in. and smaller, the actual O.D. is greater than

the nominal pipe size, (e.g., 2 inch nominal pipe actually corresponds to 2.375 in. O.D.).

Nominal pipe wall thickness is the thickness of the pipe wall specified by ASME B36.10M-2004 without consideration for manufacturing tolerance.

Degradation rates are assumed to be constant. For a discussion on increasing degradation rates, see Section 7.2.1.

% Wall Loss at the time of inspection is calculated as a percentage of the pipe nominal wall thickness as shown at the heading of each

tabulation (or as specified in Section 7.2.2 when corrosion allowance is considered in the assessment).

Interpolation between degradation rate values should not be used. Instead, the next higher degradation rate shown in the table should be used

or equation (7.9) can be utilized.

Interpolation between observed percent wall loss values at the time of inspection should not be used. Instead, the next higher observed wall

loss shown in the table should be used or equation (7.9) can be utilized.

A value of zero for the number of years means that the threshold limit has already been reached.

For other explanations and conditions that must be satisfied, see Table 7.5 and Section 7.3.

140
Table 7.4 Applicable Buried Piping'Systems for use of Degradation Acceptance Criteria'

Service Water2

Diesel Fuel Oil3

Emergency Feedwater 4

Condenser Circulating Water 5

Condensate

Safety Injection

High Pressure'Coolant Injection

Reactor Core Isolation Cooling

Residual Heat Removal

Notes:

1. For other buried piping systems not listed see discussion in Section 7.3.

2. Includes Service Water, Emergency Service Water, Auxiliary Salt Water, Saltwater, Nuclear

Service Water, Residual Heat Removal Service Water, Plant Service Water, High Pressure

Service Water, Intake Cooling Water.-

3. Includes Diesel Fuel Oil, Emergenicy Diesel Fuel Oil, Diesel Fuel Oil Storage, Fuel Oil, Diesel

Generator Fuel Oil, Standby Shutdown Diesel, Diesel Fuel Oil Supply, Emergency Diesel

Generator, Diesel Generator Services, Standby Shutdown Facility Diesel Fuel Oil.

4. Includes Emergency Feedwater, Auxiliary Feedwater, Feedwater, Standby Steam Generator

Feedwater.

5. Includes Condenser Circulating Water and Condenser Cooling Water. .. .. . .

I *, :; . - - !

141
Table 7.5 Risk-informed Degradation Acceptance Criteria Summary

For Buried Piping Systems At NPPs

Dearadation Accettance Criteria (DADA

Without Consideration Use Table 7.3

of Corrosion Allowance

Observed Wall Loss at the Time Follow approach in

of Inspection is Less Than or Section 7.2.2 Case A

Considering Corrosion Equal to Corrosion Allowance . C

Allowance Observed Wall Loss at the Time Follow approach in

of Inspection is Greater Than Section 7.2.2 Case B

Corrosion Allowance

NOTE:

Additional information, guidance, and examples are provided in Sections 7.2 and 7.3.

In order to utilize the above DAC, the conditions listed below, in addition to those presented in

Section 7.3, must be satisfied.

Conditions for use of DAC

CONDITION REQUIREMENT

Aging effects Loss of material: general wall thinning and localized

Aging __effectsloss of material/pitting'

Pipe material type Ductile steel pipe (carbon steel, stainless steel)

Piping design ASME B31.1 or ASME Section 1II, NC/ND-3600

Pipe nominal diameter 2 in. to 42 in

Minimum pipe schedule (thickness) Standard2

Maximum diameter/thickness (D/t) 80

Max operating temperature 1500 F

Max ground surface live load3 AASHTO H20 truck load = 32,000 lb axle load

Minimum soil cover depth4 3 ft

Diameter to 203I0506 08

Max soil cover depth as a function thickness ratio (D/t)20 30 40 50 60 70 80

of D/t ratio4 Max soil cover (ft) 63 30 19 14 12 10 10

Soil material (min. requirements)5 Well-graded and moderate compaction

142
CONDITION REQUIREMENT

No current indication or past history of soil settlement

Soil conditions or building structure settlement at the site; no concern

with buoyancy (large diameter pipe close to surface)

e LPipe is not subject to significant fluid transient loads,

Other Loadings significant cyclic loads, or surface impact loads

a) Plant baseline total CDF less than 5 x 10o /year

(this is expected to be satisfied for most NPPs)

Risk parameters for the plant and b) For a Category 1 buried piping system:

system being evaluated CD F 3.4 x 102 p

(See Sections 6.3 through 6.6 for

an explanation of the terms used) c) For a Category 2.2.a buried piping system: [CDF (given pipe fails) - CDF (given pipe does not

fail)l 5 8.5 x 1 03/ year

1 in. = 2.54 cm; 1 ft = 30.48 cm; 1 lb = 4.45 N; 0C = (OF - 32)/1.8

Footnotes:

1. The other major aging effect which is reduction in flow due to fouling/biofouling can be

addressed by monitoring system performance parameters such as system flow and

pressure, periodic examination of equipment fed by piping system, and other means (see

Section 3.2, Operating Experience).

2. Applicable for all pipe sizes except 42 in. (107 cm) pipe diameter, which requires a minimum

wall thickness of 0.562 in. (1.43 cm).

3. This also requires no surface loads such as railway, building structure, fill material, or other

surcharge loads over the buried piping, unless the effects of the surface load are shown to

be less than the effects due to the H20 truck load.

4. Soil cover is the distance between the top of the buried pipe and the ground surface

5. If desired, quantitative information for this requirement (i.e., modulus of soil reaction (E') of

1,000 psi [6.89 MPa]) is available in Table 3.4 of Moser (2001).

143
8 CONCLUSIONS AND RECOMMENDATIONS

If buried pipe degradation is identified at an NPP, it may not be evident whether the pipe still

complies with the plant licensing commitments or whether the degradation potentially has an

immediate significant effect on plant risk. Normally, the licensee performs an evaluation of the

degraded condition which may include further inspections, testing, calculation/design review,

and other actions to determine the severity of the condition, risk implications, and whether an

immediate'repair is needed. Since these steps may take time, often beyond a week, the

methodology and degradation acceptance criteria (DAC) developed in this report provide

guidance to the'NRC staff for making an assessment in a timely manner whether the degraded

condition potentially has an immediate significant effect on plant risk. This knowledge is

important in order to provide input that can help determine whether immediate repairs are.

warranted, or whether the appropriate investigation, inspection, aging management, or other

actions can be determined in the normal course of evaluating the condition. The methodology

and DAC can not be used by the industry to justify existing degraded conditions; licensees are

still required to meet their commitments regarding the plant's current licensing basis.

To achieve the objectives of this study,:fragility modeling procedures for degraded buried piping

have been developed and the effect of degradation on fragility and plant risk has been -

determined. The effects of degradation over time were also included in the methodology. The

analytical approach provides the technical basis for evaluating degraded buried piping at NPPs

and provides guidelines for assessing the effects of degraded conditions on plant risk. The

guidelines, which are identified as degradation acceptance criteria (DAC), are presented in

tabular form for ease of use.

The effects of degradation over time were considered in developing the DAC in a manner that

provides the number of years required for the buried pipe to reach a degradation level that

would potentially have a significant effect on plant risk. If the degraded condition exceeds the

criteria, then immediate repair would be required unless otherwise justified. If the degradation

level is less than the criteria, then it is 'expected that the licensee will still evaluate the conditions

that led to the degradation and may need to repair the degraded pipe based on the evaluation

findings, the level of degradation, and theplant's current licensing basis.

8.1 Conclusions

8.1.1 Understanding of the Degradation of Buried Piping

The types of buried piping systems, material and design parameters, and analysis and design

methods that can be used for buried piping at NPPs have been collected and evaluated. Based

on a survey and review of license renewal applications, there are many different buried piping

systems used at NPPs; however, the most predominant types are the service water, diesel fuel,

fire protection, and emergency feedwater systems. The materials used for buried piping are,

primarily carbon steel and to a lesser extent stainless steel. Other materials which are not as

cormmon are low-alloy'steel,'galvanized steel,'cast iron,-fiberglass, copper nickel, ductile iron,

and Yoloy. Methods for the 'structural analysis and design of buried piping are available in the.

general literature and in various industry codes, standards, and guides. z e- .. a, ::1 , ,

The predominant aging 'effects and associated aging mechanisms for buried piping have been

identified and summarized in this' report. The predominant aging effects are loss of material and

fouling/biofouling. Most occurrences of loss of material are manifested as either general wall

thinning or localized loss of material/pitting.'A number of occurrences of degraded buried piping

vi 145
at NPPs have been reported in NRC generic correspondences, license renewal applications

submitted to the NRC, industry reports, and research reports. For this study the aging effect of

loss of material was selected because there are programs that have already been developed to

address fouling/biofouling in buried piping.

8.1.2 Detection of Age-Related Degradation and Condition Assessment

Inspection methods for the degradation of buried piping can be based on visual, nondestructive, or destructive methods. Since degradation mechanisms can cause aging effects on

the interior and/or exterior of buried piping systems, information about the condition of the inside

and outside surface of buried piping is important. Large diameter lines such as portions of the

service water system usually can be examined by personnel by close visual examination

provided there is access to the line. Smaller diameter lines however, are not easily accessible

and require other techniques which have been improved significantly over recent years. The use

of a particular method depends on the size of the line, access to the interior or exterior surface,

pipe material, aging effect of interest, and cost.

The inspection methods available for examining buried piping include visual inspection,

cameras, ultrasonic test (UT), electromagnetic test, and pipeline pigs. Indirect indications of

degradation can also be identified by monitoring the performance of the cathodic protection

system, if such a system was installed at the plant. Other methods that have been developed

using different technologies or variations of the technologies described previously include

remote field eddy current, magnetic flux leakage, and infrared thermography.

8.1.3 Regulatory and Industry Guidance

There are several regulatory requirements and technical guidance documents that relate to

degradation of buried piping. These include 10 CFR 50.65 - Maintenance Rule, 10 CFR Part 54

- License Renewal Rule, Generic Aging Lessons Learned (GALL), NRC Standard Review Plan

for Review of License Renewal Applications for Nuclear Power Plants, NRC generic

correspondences, and NRC Inspection Procedures. The industry has also developed some

guidance documents which support licensees in implementing the Maintenance Rule and the

License Renewal Rule. Although these documents describe the buried piping materials, aging

effects and mechanisms, environment, and acceptable aging management programs, they do

not provide specific quantitative acceptance criteria for judging the adequacy of a degraded

buried pipe. This is left to the licensee to define on a plant-specific basis. As a result, this study

is particularly useful for the NRC staff to support their licensing review activities related to

current operating plants.

8.1.4 Fragility Evaluation of Degraded Buried Piping

A review of the design loads on buried piping systems was conducted to identify the critical

loads which may lead to pipe rupture failure as a direct result of loss of material in the pipe wall

caused by age-related degradation. The design loads considered were internal pressure, soil

surcharge (dead weight), groundwater, surface loads, seismic, and thermal expansion. Within

the expected range of parameters for NPP buried piping applications, it was shown that soil

surcharge, groundwater and surface loads produce low stresses which are not significantly

affected by wall thinning. Thermal and seismic loads in buried piping systems produce selflimiting secondary stresses which are also not significantly affected by reductions in wall

thickness. On the other hand, stresses due to internal pressure are primary stresses which are

directly affected by loss of material due to age-related degradation of the pipe wall. As a pipe

146
- -

wall becomes thinner, the pressure induced stress increases, thereby increasing the probability

of a pipe rupture failure. ,

Using the properties of buried carbon steel pipe, a methodology for developing buried piping

fragility curves to predict probability of failure versus internal pressure was developed. Based on

allowable variations in material and dimensional properties, it was shown that the tensile

strength was the most significant random variable affecting the probability of failure. By using

the minimum strength properties allowed by the material specification and by making

reasonable assumptions on mean and upper limit strength values, a normal distribution of

material strength was developed. Using this material strength distribution, pipe stress equations,

and the assumption of uniform wall thinning; a series of fragility curves were analytically

developed for undegraded pipes and for degraded pipes with different levels of percentage wall

loss. In addition, a statistical evaluation of available test data on pressure tests of degraded

pipes removed from service was performed to confirm the conservatism of these fragility curves

and to demonstrate that the curves are applicable to piping with localized or pitting corrosion as

well as uniform wall thinning.

Using the same methodology,' a series of fragility curves were developed for carbon steel pipe

ranging in size from 5.08 to 107 cm (2 in. to 42 in.) in diameter. These curves were developed

for both undegraded and degraded pipes.; Finally, by assuming that the internal pipe pressure is

equal to the design pressure allowed by Code rules, plots of probability of failure versus percent

wall loss were generated. These curves were combined on a single graph and showed that

under design pressure, the variability of the probability of failure of degraded pipe at different

percentage wall losses is within a factor of about 5.

8.1.5 Risk Evaluation of Degraded Buried Piping Systems

Buried piping systems at an NPP can degrade, as described in the previous sections of this

report. Such deterioration potentially could impair the operation of the system that contains the

buried piping, and thus impact the overall risk of an NPP. To develop a methodology that can

estimate the effect of degraded buried piping on plant risk, a definition of the criterion to be used

as a measure of significant risk was needed. For this study, the measure of significant plant risk

was based on a change in core damage frequency (ACDF) of 1 .0x104 per year. This was

selected based on the guidelines provided in NRC RG 1.174,-Rev. 1.

To determine the effects of buried piping degradation on plant risk, five NPP (sites) were

selected for evaluation. The plants selected consist of McGuire 1 and 2; North Anna 1 and 2;

Oconee 1, 2, and 3; Surry 1 & 2; and Hatch 1 .& 2. These plants were selected because they

contain many different buried piping systems and they have different attributes consisting of:, -

reactor types, NSSS suppliers, containment types, architectengineers, and locations in the

United States. In addition, they contain both "frontline" and "support" systems with buried piping.

; ' e, '.}f - I (; -+

For the purpose of evaluating the contribution of the degradation of a buried piping system to

plant risk, the systems in any NPP can be classified into several categories depending on

whether the system's failure causes an initiating event, whether the system is normallyoperating,'and otheir criteria. A review of ,the buried piping systems at these five plants

determined that they fell into two categories. Analytical time-dependent methods were

developed for these two categories to estimate the increase in plant risk due to degraded buried

piping. Some parameters required by these methods were obtained by using the Standardized

Plant Analysis Risk (SPAR) version 3 models of the five selected plants. A SPAR model is a

level-1 probabilistic risk assessment (PRA) model of internal events during full-power operation.

'-.147
I

Bounding values for these risk parameters were utilized to cover the five plants. Enveloping the

results for the five plants and the other conservatisms identified within this report, help

generalize the results to most other NPPs in the US.

The risk evaluations and formulations that were developed provide a methodology which can be

used to determine analytically how degraded buried piping affects plant risk. The formulations

permit the solution of how many years are required for the buried pipe to reach a degradation

level that would equal the defined measure of risk significance.

8.1.6 Degradation Acceptance Criteria

The Degradation Acceptance Criteria (DAC) are risk-informed acceptance limits that can be

used to provide information for determining whether a degraded buried piping condition would

potentially have an immediate significant effect on plant risk. The effects of degradation over

time were included in developing the DAC and the DAC is applicable to most steel buried piping

systems found at NPPs.

This study developed DAC for general wall thinning and localized loss of material/pitting in

buried piping. The types of buried piping systems, configurations, materials, and other

conditions that must be satisfied to use the DAC have also been developed and presented in

Section 7.3 and Table 7.5. The results obtained are based on the service conditions that buried

piping is designed for (e.g., pressure induced stresses less than /4 of the minimum ultimate

strength of the material and relatively low temperatures) and recognizing that seismic induced

stresses in buried piping are self-limiting since deformations or strains are limited by seismic

motion of the surrounding media. In addition, the DAC presented in Section 7.3 arose from a

probabilistic risk assessment which accounted for the contribution to risk of the postulated

degradation of buried piping systems at NPPs. It should be noted that even if a degraded buried

pipe meets the DAC, it is expected that the licensee will still evaluate the conditions that led to

the degradation and may need to repair the degraded pipe based on the evaluation findings, the

level of degradation, and the plant's current licensing basis.

The DAC are applicable to the specific buried piping systems listed in Table 7.4 and can only be

used if the conditions described in Section 7.3 and Table 7.5 are satisfied. The conditions were

developed based on the limitations and requirements utilized in the various analyses described

in Sections 5, 6, and 7. The buried piping systems listed in Table 7.4 were selected based on

surveys and the LRAs which were described in Section 2. These piping systems should account

for most buried piping systems found at NPPs. If a particular degraded buried pipe does not

match one of the piping systems listed in Table 7.4, then it may still be possible to utilize the

DAC. However, the buried piping system would have to first be categorized in accordance with

Section 6.3. This would indicate which method should be followed for each category of buried

piping system. In addition, care should be exercised to ensure that the buried piping system

satisfies the conditions given in Section 7.3 and Table 7.5, and is bounded by the parameters

used in the analyses described in Sections 5 through 7.

The DAC are applicable to welded steel pipes consisting of straight sections of buried pipe and

pipe components such as elbows, tees, branches, and reducers. Degradation of mechanical

connections (e.g., flanges, Dresser couplings, bell & spigot, and welds and adjacent heat

affected zones) should be considered on a case-by-case basis.

148
The DAC are not applicable to any degradations that include pipe cracks; sharp discontinuities

regardless of the size, width, or length of the crack/discontinuity; defects caused by mechanical

damage, such as gouges and grooves; or defects introduced during manufacture.

Conclusions for Degradation Acceptance Criteria (DAC)

The results of this study demonstrate that for a buried pipe meeting the conditions of the DAC, a

pipe thickness loss less than approximately.45% of the original nominal pipe wall thickness,

identified at the time of inspection, is not expected to have an immediate significant effect on

plant risk. Risk-informed degradation acceptance criteria (DAC) were developed and presented

in Table 7.3 for each pipe diameter in the range of 5.08 to 107 cm (2 to 42 in.). Based on the

observed percentage wall loss at the time of inspection and the applicable degradation rate for

the pipe, the number of years required for the buried pipe to reach a degradation level that

would potentially have a significant effect on plant risk can be found. Additional information,

guidance, and examples are provided in Section 7. In order to utilize the DAC, the conditions

described earlier within Section 7.3 and presented in Table 7.5 must be satisfied.

As a first step, corrosion allowance that may have been provided in the original design of a

buried piping systerri may be neglected and the criteria in Table 7.3 may be used. If the DAC

cannot be satisfied, then an approach described in Section 7.2.2 can be followed to take

advantage of any corrosion allowance that may have been included in the design of the piping

system.

For all pipe sizes, the results in Table 7.3 demonstrate that as the observed percentage wall

loss increases, the number of years required for the buried pipe to reach risk significance

reduce. Table 7.3 also indicates that for small degradation rates and percentage wall losses of

about 20% or less, the number of years required to reach risk significance is quite large. As an

example, for all pipe diameters 5.08 to 107 cm (2 to 42 in.), degradation rate of 0.0254 mm/year

(0.001 in./year), and observed percentage wall loss of 20% or less, the results in the table -;

indicate that it would take 42 years or more for the buried pipe to reach a level of degradation

that would potentially have a significant effect on plant risk. However, for higher degradation

rates, the results indicate that the number of years can drop substantially depending on the

degradation rate being used.

If Conditions are Not Satisfied

If the requirements and conditions described above cannot be satisfied, then a detailed review

can be performed to determine whether the DAC can still be utilized. This may very well be

possible because to keep the DAC simple to use, the analytical methodology utilized

conservative assumptions in arriving at the acceptance limits. In addition, bounding values were

often used to cover various ranges of parameters. This avoided having an extensive set of

criteria (tables) to account for every permutation of parameters. Further guidance on how to

treat degraded buried piping systems if the conditions of the DAC cannot be satisfied is

provided in Section 7.3. : -

8.2 Recommendations -

In light of the insights gained during this research,- there are some recommendations for

additional studies that could be implemented to remove some of the conservatisms, incorporate

updated plant information, and extend the applicability of the degradation acceptance criteria

(DAC) to other buried piping designs. These improvements would be applicable to a number of

149
the analyses performed in this study which encompass the various loadings, fragility analyses,

and risk evaluations.

8.2.1 Conservatisms

In order to develop a relatively simple set of DAC which could be used by various individuals

with different levels of knowledge or expertise, it was necessary to select bounding values for a

number of design and analysis parameters. These bounding values in effect introduce

conservatisms which could be identified and relaxed where appropriate. The benefit would be

somewhat more lenient degradation acceptance criteria.

This task could be performed by identifying, for each design and analysis parameter, whether

there is sufficient benefit for developing a separate set of DAC for the range of the parameter

being studied. This could lead to more relaxed acceptance limits and/or developing additional

tables within the DAC that would provide improved limits corresponding to the range of the

selected parameters.

Some examples of variables that could be evaluated for reduction in conservatism rather than

using bounding values are different values for pipe schedules, soil properties, surface load

types and magnitudes, and temperatures.

The analytical development of fragility curves was based on a conservative assumption that the

wall thinning is uniformly distributed around the circumference and length of the pipe. In reality,

however, the effects of pipe corrosion are more likely to be localized. A review of limited

pressure test data of corroded pipes removed from service demonstrated the conservatism of

the analytical assumption. If additional test results were available, it is expected that a case

could be made for the generation of less conservative fragility curves based on test results.

The development of the normal distribution of material tensile strength was based on the

assumption that the minimum value defined in the material specification is the 5 t percentile

lower bound value, the mean is 20 percent higher, and the 95h percentile upper bound value is

40 percent higher. A sensitivity analysis indicated that these assumptions were conservative. If

additional material test results were available (manufacturer data or open literature), the use of

less conservative values could be justified.

In developing the plots of probability of failure versus wall loss, it was assumed that the pipe is

subjected to the maximum pressure equal to the code based design pressure. For small

standard weight pipes, the design pressure may be over 6.89 MPa (1000 psi). However, the

WRC Bulletin 446 survey did not identify pressures in buried piping higher than 150 psi (see

Table 2.1). The use of actual plant operating pressures would reduce the probabilities of failure

for most pipes.

As described in Section 6, to cover all five selected plants included in this study and to

generalize the results for most NPPs, plant specific risk parameters such as the conditional core

damage probability (CCDP) were conservatively enveloped across all buried piping systems

within a given plant and across the five plants. A specific piping system at a plant may have

lower parameters than the enveloped values, and therefore, a plant specific evaluation may

result in a relaxation of the conservatism inherent in the DAC.

Since detailed information about the buried piping systems (e.g., the layout of each piping

system and associated components - valves, pumps, etc.) was unavailable for the risk

150
evaluations, a conservativea'ssumption was made that if degradation caused the failure of any

section of a buried pipe, the entire system is unavailable. This assumption may have led to

conservative risk evaluations in some cases. Therefore, we recommend obtaining detailed

information for some of the plants having buried piping using their specific layout. This would

enable an assessment that is as realistic as possible and will provide an indication of the extent

of conservatism inherent within the current analysis approach.

8.2.2 Consideration of Updated Information

It is advisable to consider updated information that was not available during the early phases of

this study, in order to verify and enhance the methods and results presented in this report.

Several examples of areas that would be very beneficial are described below.

Because of the difficulties in obtaining some input information regarding buried piping at NPPs,

some of the input parameters (e.g., types of systems, pipe materials, operating experience)

were based on the 12 license renewal applications (LRAs) that were available at the early

phase of this research study. Based on some recent submittals to the NRC, there are more

LRAs that are available that were not included in this study. Additional submittals of LRAs by

licensees are also expected in the near future.

The risk evaluations could be expanded to more plants to confirm the risk parameters used in

developing the formulations presented in Section 6 of the report. The study described in this

report considered five plants for performing the risk evaluations. This could be expanded to

consider additional plants and to different types of plants to enhance the applicability of the

DAC.

The risk evaluation considered a level-1 PRA of internal events during full-power operation.

Hence, the assessments did not include the impact of degraded buried piping for other modes

of operation, other levels of PRA, and other challenges (such as external events). Those buried

piping systems that are mainly used to prevent or mitigate those challenges (e.g., fire protection

system and containment spray system), which were removed from consideration for the

degradation acceptance criteria, currently need to be considered on a case-by-case basis.

Therefore, further research is recommended for those buried piping systems that were not

included in the scope of this study.

8.2.3 Extend Applicability of Degradation Acceptance Criteria

This study focused on the most prevalent types of buried piping found at NPPs which are ductile

steel pipe made of carbon steel and stainless steel material. It would be beneficial to perform

-similar analyses to expand the DAC for other types of metallic pipe material which are less

frentit u fr tls * ,ie!r4 hi it feor WAhih rdn rnrIntinn a r-nfntn en rr;tn r;n *c In r.e;nr
complicated, analytical methods could be developed to consider the degradation effects caused

by multiple (different) buried piping systems occurring at the same time.

152
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157
NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

(9-2004) (AssIgned by NRC, Add Vol., Supp., Rev..

NRCMD 3.7 and Addendum Numbers, If anry.)

BIBLIOGRAPHIC DATA SHEET

(See kbstruct~onsn fe revrse) NUREG/CR-6876

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Risk-informed Assessment of Degraded Buried Piping Systems in Nuclear Power Plants MONTH YEAR

June 2005

4. FIN OR GRANT NUMBER

____________________________________________________________W-6684

5. AUTHOR(S) 6. TYPE OF REPORT

J.1. Braverman, G. DeGrassi, G. Martinez-Guridi, R.J. Morante, C. H. Hofmayer, Brookhaven Final

National Laboratory

7. PERIOD COVERED (Inclusive Dates)

2003-2005

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (NfNRCaprovke Dh~son.OfieorfetionU.S. Nucdear Re~ultoiCommissionmand iailag ddress;kconfractor;

provide namne and nmhv~ address)

Brookhaven National Laboratory

Upton, NY 11973-5000

9. SPONSORING ORGANIZATION -NAME AND ADDRESS (NfNRC, "e'Same as above'. f co~ntra ctot, provide NRC Vrvison. Offve orflegion. U.S. Nudlear RegtdtonjCommirssion,

and maliV address.)

Division of Engineering Technology

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

10. SUPPLEMENTARY NOTES

TV Crhrnn NIRC Prnionrt Manarnpr

11. ABSTRACT (200 words or less)

This report documents results of a research sponsored by the U.S. Nuclear Regulatory Commission (NRC) and performed by the Brookhaven National Laboratory. The objective of this research was to assess the effects of age-related degradation of

buried piping at nuclear power plants. Analytical methods and degradation acceptance criteria (DAC) that can be used to

assess the condition of degraded buried piping were developed. The research was focused on a risk-informed approach to

evaluate the most common aging effects in buried piping consisting of general wall thinning and localized loss of

material/pitting. The effects of degradation over time were Included in the methodology developed to assess buried piping. To

achieve the goals of this research effort, fragility modeling procedures for degraded buried piping have been developed and the

effect of degradation on fragility and plant risk has been determined. The measure used for plant risk was based on the

change In core damage frequency (delta CDF) due to internal events during full power operation. The analytical approach provides the technical basis for evaluating the structural adequacy of degraded buried piping and for developing guidelines for

assessing the effect of degraded conditions on plant risk.. When a degraded condition is Identified In a given pipe, it is often not

immediately known whether that pipe complies with the licensing basis or whether It has a significant effect on plant risk, and it

may take time for the licensee to evaluate the cfegraded condition. In such Instances, the methodologies presented in this

report provide tools to help the NRC staff make a quick, Independent assessment to determine whether the Identified

degradation has the potential for an Immediate, significant effect on plant risk. Nonetheless, licensees cannot and shall not use

the methodologies discussed in this report to justify exemptions to current regulations or to request changes to a plant's licensing basis.

12. KEY WORDSIDESCRIPTORS (List words orpllrases that wif assist resea~rchers b2 Jocatklgme report.) 13. AVAILABIIrTY STATEMENT

Age-related degradation, aging effects, nuclear power plants, buried piping, general wall thinning andunite

localized loss of material/pitting, risk-informed assessment, fragility modeling, fragility of buried piping, 14. SECURITYCLASSIFICATION

change in plant core damage frequency, Internal events, full power operation of nuclear power plants, (This Page.)

licensing basis, effect on plant risk, analytical methods, dograain acceptance criteria (DAC). unclassified

(This Report)

unclassified

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