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- Sprache: Englisch
DEFECT ASSESSMENT FOR INTEGRITY MANAGEMENT OF PIPELINES Make energy pipelines safer by improved defect assessment for integrity management Pipelines provide an effective and efficient mode for transportation of energies, including both conventional fossil fuels and renewable energies and fuels such as hydrogen, biofuels and carbon dioxide, over wide ranges and long distances, meeting economic development and civilian needs. While the integrity and safety of in-service pipelines is paramount to pipeline operators, there are many factors which can adversely affect the pipeline integrity and potentially result in pipeline failures and, sometimes, serious consequences. Defect Assessment for Integrity Management of Pipelines provides a thorough and detailed overview of various techniques that can be used to assess corrosion defects, the most common defects on pipelines, and other mechanical defects such as dents, buckles and winkles, all of which constitute essential threats to pipeline integrity. In addition to widely used standards and codes for defect assessment, readers can obtain the latest progress in development of advanced techniques for improved accuracy in defect assessment. From early-stage Level I methods to the newest Level III method integrating with the mechano-electrochemical interaction, Defect Assessment for Integrity Management of Pipelines has everything you need to improve safety of your pipelines. Defect Assessment for Integrity Management of Pipelines readers will also find: * Evolution of defect assessment techniques and limitations to be overcome with improved techniques * Detailed analysis of defect assessment for determination of fitness-for-service of the pipelines, and prediction of their failure pressures * Both theoretical and practical aspects of the defect assessment methods applied on pipelines Defect Assessment for Integrity Management of Pipelines is ideal for pipeline professionals, researchers and graduate students to improve personal knowledge, research expertise, and technical skills.
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Table of Contents
Cover
Table of Contents
Title Page
Copyright Page
Dedication Page
Preface
List of Abbreviations and Symbols
1 Pipeline Integrity Management
1.1 Introduction
1.2 Overview of Threats to Pipeline Integrity
1.3 Elements of Pipeline Integrity Management
1.4 Plan‐Do‐Check‐Act Integrity Management Cycle
References
2 Levels I and II Assessment of Corrosion Anomalies on Pipelines
2.1 Defect Assessment for Pipeline FFS Determination
2.2 Evolution of Defect Assessment Techniques
2.3 Level I Defect Assessment on Pipelines
2.4 Level II Defect Assessment on Pipelines
References
3 Level III Assessment of Corrosion Anomalies on Pipelines
3.1 Introduction
3.2 Principle and Methods
3.3 Applications for FFS Determination and Failure Pressure Prediction of Pipelines
3.4 Commentary Remarks
References
4 Mechano‐electrochemical Interaction for Level III Assessment of Corrosion Anomalies on Pipelines – A Single Corrosion Defect
4.1 Fundamentals of Mechano‐electrochemical Interaction for Pipeline Corrosion
4.2 Multi‐Physics Field Coupling at a Corrosion Defect on Pipelines
4.3 The M–E Interaction at a Single Corrosion Defect on Pipelines
References
5 Mechano‐electrochemical Interaction for Level III Assessment of Corrosion Anomalies on Pipelines – Multiple Corrosion Defects
5.1 Introduction
5.2 Assessment of Multiple Corrosion Defects on Pipelines and Development of Interaction Rules
5.3 Interactions of Multiple Corrosion Defects with Irregular Orientations
References
6 Assessment of Dents on Pipelines
6.1 Introduction
6.2 Standards and Methods for Dent Assessment
6.3 Assessment of Dent‐Defect Combinations on Pipelines
6.4 Fatigue Failure of Pipelines Containing Dents
6.5 Failure Criteria of Pipelines Containing Dents
6.6 Finite Element Modeling for Dent Assessment on Pipelines
References
7 Assessment of Buckles on Pipelines and Buckling Failure Analysis
7.1 Introduction
7.2 Buckling Failure Analysis of an X80 Steel Pipe Containing a Dent Under Bending Moment
7.3 Buckling Failure Analysis of a Corroded Pipe Under Axial Compressive Loading
7.4 Buckling Resistance of Corroded Pipelines under Bending Moment
7.5 Prediction of Burst Capacity of Corroded Pipelines under a Combined Bending Moment and Axial Compressive Load
References
Index
End User License Agreement
List of Tables
Chapter 1
Table 1.1 Some main manufacturing defects at pipeline welds and the illustra...
Chapter 2
Table 2.1 Level I defect assessment models for prediction of failure pressur...
Table 2.2 Applicability of the Level I defect assessment methods in terms of...
Table 2.3 Some main Level IIa models and codes for assessment of a complex‐s...
Table 2.4 Various interaction rules developed for defining mutual interactio...
Chapter 3
Table 3.1 Some typical examples of the application of Level III assessment f...
Table 3.2 Typical examples of the applications of FE‐based Level III assessm...
Table 3.3 Failure pressure of a pipe (19 mm in wall thickness) made of X65, ...
Table 3.4 Failure pressures determined by the FE model for an X80 steel pipe...
Table 3.5 Failure pressures of X46, X60, and X80 steel pipes containing two ...
Table 3.6 Failure pressure of X80 steel pipe containing a corrosion defect u...
Table 3.7 Maximum von Mises stress (
σ
max
) at defect for different defec...
Chapter 4
Table 4.1 Failure pressures of X100 steel pipe containing a corrosion defect...
Table 4.2 Failure pressure of the suspended X100 steel pipe containing a cor...
Table 4.3 Failure pressure of the suspended X100 steel pipe containing a cor...
Chapter 6
Table 6.1 Standards and methods used for assessment of plain dents and a den...
Table 6.2 Typical burst and fatigue modeling by FE analysis on dented pipeli...
Table 6.3 Effect of the spacing between a dent and a corrosion defect on fai...
List of Illustrations
Chapter 1
Figure 1.1 Causes of rights‐of‐way incidents 2016–2020 occurring on CEPA mem...
Figure 1.2 Statistical analysis of total number of accidents and their cause...
Figure 1.3 Statistical analysis of total number of accidents and their cause...
Figure 1.4 Scenarios identified on pipelines where the CP current is shielde...
Figure 1.5 Surface morphology of hydrogen blisters on an X100 pipeline steel...
Figure 1.6 Optical view of a hydrogen‐induced crack in X100 pipeline steel u...
Figure 1.7 A crack initiated at combined inclusions of aluminum oxide and ti...
Figure 1.8 Framework of a pipeline integrity management program.
Figure 1.9 Flow chart of the FFS assessment process.
Figure 1.10 Main contents of a PDCA cycle.
Chapter 2
Figure 2.1 Example of the FFS determination process for various types of dam...
Figure 2.2 Illustration of the methods used in various Level I defect assess...
Figure 2.3 Comparison of the burst pressures of X52 steel pipe containing a ...
Figure 2.4 Illustration of the length and depth profiles of a corrosion defe...
Figure 2.5 “Envelope rectangle” concept used for defect assessment of multip...
Figure 2.6
“
Envelope rectangle” concept used for defect assessment of m...
Chapter 3
Figure 3.1 Schematic diagram of a buried pipeline under (a) an axial compres...
Figure 3.2 von Mises stresses of the inner and outer surfaces of X80 steel p...
Figure 3.3 Effective plastic strain of the inner and outer surfaces of the X...
Figure 3.4 Distribution of plastic deformation of the X80 steel pipe contain...
Figure 3.5 The 3D model for a steel pipe containing corrosion defects (a) a ...
Figure 3.6 Effect of (a) the longitudinal spacing and (b) circumferential sp...
Figure 3.7 Distributions of von Mises stress on an X46 steel pipe containing...
Figure 3.8 The failure pressure ratio, i.e.,
P
overlapped
/
P
single
, of an X46 ...
Figure 3.9 Schematic illustration of the geometry of a corrosion defect on t...
Figure 3.10 A 3D model illustrating a steel pipe containing an internal corr...
Figure 3.11 The maximum von Mises stress at the corrosion defect on X60 and ...
Figure 3.12 Distribution of von Mise stress (MPa) at the corrosion defect un...
Figure 3.13 The maximum von Mises stress at the corrosion defect on X60 and ...
Figure 3.14 Distribution of von Mise stress (MPa) at the corrosion defect un...
Figure 3.15 (a) A 3D FE model illustrating the dimensional parameters of a c...
Figure 3.16 Distribution of von Mises stress at the X80 steel pipe elbow at ...
Figure 3.17 Effect of corrosion depth on burst pressure of X80 steel pipe el...
Figure 3.18 Effect of corrosion length on burst pressure of the X80 steel pi...
Figure 3.19 Effect of corrosion width on burst pressure of the X80 steel pip...
Figure 3.20 Comparison of the burst pressures predicted from the developed m...
Figure 3.21 Schematic diagram of a 3D FE model for an X52 steel pipe segment...
Figure 3.22 Three types of distributions between internal and external defec...
Figure 3.23 Stress distribution of the pipe segment containing corrosion def...
Figure 3.24 Failure pressure of the pipe containing different defect distrib...
Chapter 4
Figure 4.1 Time dependence of stress and corrosion potential of a pipeline s...
Figure 4.2 EIS plots measured on a pipeline steel under various elastic tens...
Figure 4.3 EIS plots measured on a pipeline steel under various plastic stra...
Figure 4.4 Distributions of von Mises stress, corrosion potential, and anodi...
Figure 4.5 Distributions of von Mises stress, corrosion potential, and anodi...
Figure 4.6 (a) Schematic diagram of a 3D FE model for an X100 steel pipe seg...
Figure 4.7 Distribution of von Mises stress at the corrosion defect with var...
Figure 4.8 Distribution of corrosion potential at the defect with varied inc...
Figure 4.9 Distributions of (a) anodic and (b) cathodic current densities al...
Figure 4.10 Burst pressure of the pipe elbow containing a corrosion defect (...
Figure 4.11 The relationship between the maximum anodic current density (i.e...
Figure 4.12 Schematic diagram of the approximation for a corrosion defect on...
Figure 4.13 Schematic diagram of a 3D FE‐based model for an X100 steel pipe ...
Figure 4.14 (a) Distribution of von Mises stress of a corrosion defect at
θ
...
Figure 4.15 Distribution of anodic current density (i.e., corrosion rate) al...
Figure 4.16 (a) Distribution of von Mises stress of a corrosion defect at
θ
...
Figure 4.17 Distribution of anodic current density (i.e., corrosion rate) al...
Figure 4.18 Schematic diagrams of (a) a physical model showing a corrosion d...
Figure 4.19 Flowchart for modeling of corrosion defect growth on an X100 ste...
Figure 4.20 Time dependence of the (a) length, (b) maximum depth, and (c) wi...
Figure 4.21 Distributions of (a) von Mises stress (MPa) and (b) anodic curre...
Figure 4.22 Schematic diagram showing (a) the physical model, (b) the mechan...
Figure 4.23 Distributions of (a) displacement of a suspended X100 steel pipe...
Figure 4.24 Distributions of (a) von Mises stress (MPa) and (b) anodic curre...
Figure 4.25 Maximum von Mises stress and maximum anodic current density at a...
Chapter 5
Figure 5.1 Schematic diagram of a steel pipe containing two longitudinally o...
Figure 5.2 Distributions of von Mises stress at two adjacent corrosion defec...
Figure 5.3 Linear distribution of von Mises stress along the steel/solution ...
Figure 5.4 Linear distribution of anodic current density along the steel/sol...
Figure 5.5 Distribution of von Mises stress of the steel pipe containing two...
Figure 5.6 Distributions of anodic current density, i.e., corrosion rate, al...
Figure 5.7 The maximum longitudinal spacing between adjacent corrosion defec...
Figure 5.8 A 3D model showing half of an X46 steel pipe containing two circu...
Figure 5.9 Distributions of von Mises stress at corrosion defects with vario...
Figure 5.10 Distributions of anodic current density at the corrosion defects...
Figure 5.11 Distributions of von Mises stress at the circumferentially align...
Figure 5.12 Distribution of anodic current density of two adjacent corrosion...
Figure 5.13 The ratio of the anodic current density at the defect adjacency ...
Figure 5.14 A 3D model showing a half of steel pipe containing two overlappe...
Figure 5.15 The von Mises stress distribution at the overlapped corrosion de...
Figure 5.16 Distribution of anodic current density at the overlapped corrosi...
Figure 5.17 Distributions of von Mises stress at the overlapped corrosion de...
Figure 5.18 Distributions of anodic current density at the overlapped corros...
Figure 5.19 3D FE model for corrosion defects with different orientations on...
Figure 5.20 Effect of the longitudinal spacing between corrosion defects, wh...
Figure 5.21 Distributions of (a) von Mises stress and (b) anodic current den...
Figure 5.22 Effect of the circumferential spacing between corrosion defects,...
Figure 5.23 Distributions of (a) von Mises stress and (b) anodic current den...
Figure 5.24 Parameter sensitivity on the M–E interaction between corrosion d...
Chapter 6
Figure 6.1 Schematic diagram illustrating different types of dent‐defect com...
Figure 6.2 A typical FAD recommended by API 579 for crack assessment.
Figure 6.3 Schematic diagram showing the steps for modeling and analysis of ...
Figure 6.4 Distributions of hoop and axial strains at the dent during indent...
Figure 6.5 Circumferential and axial strains as a function of circumferentia...
Figure 6.6 (a) Relationship between the dent depth after spring‐back and the...
Figure 6.7 Relationship between the equivalent strain at the dent apex and t...
Figure 6.8 A model for (a) a pipe segment, (b) an indenter, and (c) the elec...
Figure 6.9 Modeling results of von Mises stress (MPa), anodic current densit...
Figure 6.10 Relationship between failure pressure and service time for a cor...
Figure 6.11 Schematic diagrams showing (a) a 3D model for a steel pipe and a...
Figure 6.12 Von Mises stress contour of the pipe containing a dent adjacent ...
Chapter 7
Figure 7.1 The developed FE model for a steel pipe containing a dent created...
Figure 7.2 Schematic diagram illustrating the nodes that participate in curv...
Figure 7.3 The buckling modes of the pipe under various internal pressures a...
Figure 7.4 Relationship between bending moment and curvature of the pipe und...
Figure 7.5 Influence of internal pressure on the critical buckling moment un...
Figure 7.6 Effect of the pipe wall thickness on critical buckling bending mo...
Figure 7.7 Effect of the pipe outer diameter on critical buckling bending mo...
Figure 7.8 Effect of the strain hardening exponent on critical buckling mome...
Figure 7.9 Effect of stress hardening exponent on critical buckling moment o...
Figure 7.10 A FE model for an X80 steel pipe containing a corrosion defect f...
Figure 7.11 The dimension of the corrosion defect on the steel pipe.
Figure 7.12 Relationship between the critical buckling load and
d
/
t
ratio wi...
Figure 7.13 Buckling modes of the pipe containing a corrosion defect with va...
Figure 7.14 Critical buckling load of the corroded pipe as a function of the...
Figure 7.15 Effect of the corrosion defect width on critical buckling load...
Figure 7.16 Relationship between the critical buckling load and the pipe out...
Figure 7.17 Critical buckling load of the steel pipe as a function of the pi...
Figure 7.18 Relationship between the critical buckling load and the dimensio...
Figure 7.19 Schematic diagram of the four‐point bending test on a steel pipe...
Figure 7.20 The FE model developed to study the buckling behavior of a steel...
Figure 7.21 Three typical types of corrosion features present on pipelines f...
Figure 7.22 Critical buckling moment, i.e.,
M
c
/
M
o
, of a pipe containing a co...
Figure 7.23 Critical buckling moment, i.e.,
M
c
/
M
o
, of a pipe containing a co...
Figure 7.24 Relationship between the critical buckling moment and the pipe o...
Figure 7.25 Critical buckling moment of the X80 steel pipe with various wall...
Figure 7.26 Relationship between the critical buckling moment,
M
c
/
M
0
, and no...
Figure 7.27 Critical buckling moment as a function of internal pressure when...
Figure 7.28 Effects of axial tensile and compressive loads on burst failure ...
Figure 7.29 Effects of closing and opening bending moments on the maximum vo...
Figure 7.30 Relationship between the burst pressure and the bending moment,
Figure 7.31 Relationship between burst pressure of the corroded X52 steel pi...
Figure 7.32 Effects of (a) corrosion depth, (b) length and (c) width on burs...
Figure 7.33 Comparison of burst pressures obtained from the developed model ...
Figure 7.34 Performance comparison of failure pressure prediction models for...
Guide
Cover Page
Table of Contents
Title Page
Copyright Page
Dedication Page
Preface
List of Abbreviations and Symbols
Begin Reading
Index
WILEY END USER LICENSE AGREEMENT
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Defect Assessment for Integrity Management of Pipelines
Y. Frank Cheng
University of CalgaryCalgary, Canada
Copyright © 2024 by John Wiley & Sons, Inc. All rights reserved.
Published by John Wiley & Sons, Inc., Hoboken, New Jersey.Published simultaneously in Canada.
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Library of Congress Cataloging‐in‐Publication Data applied for:
Hardback ISBN: 9781119815396
Cover Design: WileyCover Image: © Frank Cheng
To Jianshu and Winston
Preface
Defect assessment is an essential component which is integral to the integrity management program of pipelines. By processing and analyzing the data collected by in‐line inspection (ILI) tools and from other sources such as historical records, operating control and monitoring system, and offline/aboveground inspections with various models, formulas and numerical algorisms, the defect assessment provides information about performance condition of the pipelines, including prediction of failure pressure, determination of fitness‐for‐service (FFS), and further, estimation of the remaining service life. The defect assessment also contributes to failure risk and reliability evaluation, and recommendations of proper measures and actions for pipeline failure mitigation and control.
The pipeline defect assessment technique has evolved in the past several decades, experiencing development of three levels of technical progress, i.e., Levels I, II, and III methods. Targeting determination of the stress and strain distributions at the defects and evaluation of pipeline FFS and failure pressure, the three levels of methods distinguish themselves mainly by improved accuracy of the defect sizing, inclusion of the interaction of multiple defects, and solving highly nonlinear problems in defect assessment on pipelines, respectively. Nowadays, Levels I and II methods have been extensively used in industry for improved integrity management, while the Level III method, which relies on finite element (FE) modeling and analysis for solving nonlinearity at pipeline defects, has found its applications mainly in engineering research community due to background knowledge requirement and computational complexity.
In the last decade, my research group has been focusing on Level III defect assessment on pipelines, developing various FE‐based models and methods to determine the stress and strain distributions at corrosion defects based on accurate definition of the defect dimension under pipeline operating conditions, evaluating their effect on FFS of the pipelines and predicting the failure pressure. Moreover, the assessment targets not only a single corrosion defect on pipelines, but also multiple defects between which a mutual interaction may exist to further degrade the pipeline integrity. For various orientations the corrosion defects are aligned with each other, critical spacings between them are defined to determine if an interaction exists so that they should be assessed either together or separately.
The major contribution of my group to development of the Level III defect assessment technique is, based on the mechano‐electrochemical interaction theoretical concept I proposed in 2013, to integrate the mechanical force with electrochemical force, developing a multi‐physics field coupling model for defect assessment while considering the dynamic nature of corrosion defects in actual service environments. Prior to that, the corrosion defects have been usually treated as metal‐loss features, while ignoring the dynamic process of defect growth due to corrosion reactions. This is regarded as “revolutionary” to pipeline defect assessment techniques. The novel Level III defect assessment method, at the first time of its kind, enables prediction of the rate of corrosion defect growth on pipelines under the synergism of mechanical and electrochemical forces, reproducing the reality and thus providing more accurate and reliable results.
In addition to corrosion defects, the mechano‐electrochemical interaction integrated Level III assessment method has also expanded its use to other types of surface anomalies such as dents, buckles and wrinkles, as well as combinations of different types of defects. Moreover, the defect assessment applies on both straight pipes and pipeline elbows where the defects experience different mechanical and corrosion conditions. Criteria and methods are developed to evaluate the pipeline performance and predict burst failure.
The book starts with an overview of pipeline integrity management program in Chapter 1, where the basic principle, main components and methods, and design pathway of integrity management of pipelines are introduced. Various threats to degrade the pipeline integrity in the field are reviewed, and common ILI tools for detecting surface defects are summarized. Chapter 2 introduces the historical development of defect assessment techniques, while focusing on the principles, criteria, and applications of Levels I and II methods. Commentary remarks are given to analyze the limitations of the two levels of assessment method. In Chapter 3, the FE‐based Level III defect assessment method is detailed in terms of the principles, criteria, and applications for pipeline FFS determination and failure pressure prediction. The assessment applies for both single and multiple corrosion defects, straight pipes and pipeline elbows, internal and external defects, and the defects on pipelines under vibration induced by running of ILI tools. Chapters 4 and 5 contain the important innovation of Level III defect assessment method by integrating mechanical and electrochemical forces at corrosion defects, considering the synergism of stress/strain and electrochemical corrosion and its effect on pipeline performance and failure during service. The fundamentals of mechano‐electrochemical interaction for pipeline corrosion are imparted in Chapter 4, followed by development of a multi‐physics field coupling model for defect assessment. The defects are either regularly shaped or with complex shapes encountered in the field, where a definitive method is proposed to accurately size the defects. Particularly, when a corrosion defect is present on a pipe in suspension under soil‐erosive conditions, additional mechanical factors such as surface loading and a non‐uniform stress distribution in the suspended pipe segment are considered and modeled. Moreover, the defect growth rate on pipelines is modeled and predicted under both mechanical stress and electrochemical corrosion effects, and the results help estimate the remaining life of corroded pipelines in the field. In addition to single corrosion defect, multiple corrosion defects where a mutual interaction exists are modeled with the novel Level III assessment method. The adjacent corrosion defects are oriented either longitudinally, circumferentially, or overlapped with each other. Critical spacings between them are defined to determine if an interaction exists to degrade the pipeline integrity. Furthermore, a new criterion based on anodic current density, i.e., corrosion rate, at the adjacent area between the corrosion defects is proposed and validated to evaluate the defect interaction. In Chapter 6, dent assessment on pipelines is included, where the dent assessment principle, uniqueness, challenge, and failure criteria are reviewed. A new method to define the critical strain at a dent is introduced. In addition to dent assessment, the combinations between a dent and a gouge, corrosion, and a crack are modeled and assessed on pipelines. Finally, assessment of buckles on pipelines and buckling failure analysis by FE‐based models are included in Chapter 7. Buckling failure of pipelines usually occurs under pipe–soil interactions, where an axial compressive load or bending moment is generated on the pipelines. The critical compressive force or the critical bending moment is defined for pipelines containing a dent or corrosion defect where buckling failure potentially occurs, while considering the parametric effects such as pipe dimension, defect size, internal pressure, and steel properties. A new method for prediction of burst capacity of corroded pipelines under a combined bending moment and axial compressive load is proposed.
I acknowledge numerous fruitful discussions I have had with many industry partners and academic colleagues. I am indebted to the dedicated and unfailing assistance and contributions provided by the students and postdoctoral fellows that I have the pleasure to supervise to study defect assessment on pipelines in my research group. They are Drs. Luyao Xu, Jialin Sun, Jian Zhao, Zhuwu Zhang, Yi Shuai, and Guojin Qin. Thank you very much for your hard work and research accomplishments!
Research grants from the Canada Research Chairs Program, Natural Science and Engineering Research Council of Canada (NSERC), Mitacs, and many industrial organizations have created the favorable conditions that helped to support an active research environment that has both contributed to and enabled the writing of this book. I am grateful and indebted to the assistance provided by these programs, agencies, and organizations, as well as the University of Calgary’s Schulich School of Engineering and the Department of Mechanical & Manufacturing Engineering.
Finally, I thank my wife, Jianshu, and my son, Winston, who have provided encouragements and have supported the creation of this book.
Y. Frank Cheng
Calgary, Alberta, Canada
List of Abbreviations and Symbols
2D
2‐dimensional
3D
3‐dimensional
AC
Alternating current
ACVG
Alternating current voltage gradient
API
American Petroleum Institute
ASME
American Society of Mechanical Engineering
BS
British Standard
BS&W
Basic sediments and water
CEPA
Canadian Energy Pipeline Association
CFR
Code of federal regulations
CIS
Close interval survey
CO
2
Carbon dioxide
CP
Cathodic protection
CSA
Canadian Standardization Association
CSE
Copper sulfate electrode
CTOD
Crack tip opening displacement
DC
Direct current
DCVG
Direct current voltage gradient
DFDI
Ductile fracture damage index
DNV
Det Norske Veritas
DSAW
Double submerged arc‐welded
EAC
Environmentally assisted cracking
ECA
Engineering critical assessment
ECDA
External corrosion direct assessment
EIS
Electrochemical impedance spectroscopy
EMAT
Electromagnetic acoustic transducer
EPRG
European Pipeline Research Group
ERW
Electric resistance‐welded
FAD
Failure assessment diagram
FE
Finite element
FERC
Federal Energy Regulatory Commission
FFS
Fitness‐for‐service
H
Hydrogen atom
H
2
Hydrogen molecule
H
2
S
Hydrogen sulfide
HAZ
Heat‐affected zone
HE
Hydrogen embrittlement
HEDE
Hydrogen‐enhanced decohesion
HELP
Hydrogen‐enhanced local plasticity
HIB
Hydrogen‐induced blistering
HIC
Hydrogen‐induced cracking
HVAC
High voltage alternating current
HVDC
High voltage direct current
ICCP
Impressed current cathodic protection
ICDA
Internal corrosion direct assessment
ILI
In‐line inspection
LOF
Lack of fusion
LOP
Lack of penetration
MAOP
Maximum allowable operating pressure
M‐C
Mechanical–chemical
M‐E
Mechano‐electrochemical
MFL
Magnetic flux leakage
MIC
Microbiologically influenced corrosion
MnS
Manganese sulfide
NACE
National Association of Corrosion Engineers
NDT
Non‐destructive testing
NEB
National Energy Board
NSC
Net Section Collapse
PDCA
Plan‐Do‐Check‐Act
PE
Polyethylene
PHMSA
Pipeline and Hazardous Materials Safety Administration
ROW
Right‐of‐way
RP
Recommended practice
RPA
Rectangular parabola area
R‐O
Ramberg‐Osgood
ROW
Right‐of‐way
SBD
Strain‐based design
SCADA
Supervisory control and data acquisition
SCC
Stress corrosion cracking
SCCDA
SCC direct assessment
SCE
Saturated calomel electrode
SCF
Stress concentration factor
SF
Safety factor
SHE
Standard hydrogen electrode
SL
Suspension length
SLD
Strain limit damage
SME
Subject matter expert
SMYS
Specified minimum yield strength
S‐N
Stress–Number of cycles
SP
Shape parameter of a dent
SRB
Sulfate‐reducing bacteria
SSC
Sulfide stress cracking
UKOPA
UK Onshore Pipeline Association
UT
Ultrasonic tool
XFEM
Extended finite element method
a
Activity
ã
M‐C activity
ā
Electrochemical activity
ǟ
M‐E activity
2a
Length of the secondary axis of a semi‐ellipsoidal corrosion defect
b
a
Anodic Tafel slope
b
c
Cathodic Tafel slope
c
1
Length of the primary semi‐axis of the bigger semi‐ellipsoidal corrosion defect
c
2
Length of the primary semi‐axis of the smaller semi‐ellipsoidal corrosion defect
2
c
Length of the primary axis of a semi‐ellipsoidal corrosion defect
C
1
A constant obtained through burst test on a non‐indented pipe
C
2
Elongation rate of pipe steel measured in uniaxial tensile testing
A
0
Cross‐sectional area of a pipe before corrosion occurs
A
Area
A
eff
Effective area
A
P
A coefficient depending on dent geometry
B
P
A coefficient depending on pipe dimension
c
Curvature coefficient of a pipe elbow
C
P
A coefficient depending on steel properties
d
Depth
d
1
Depth of the top defect for two overlapped corrosion defects
d
2
Depth of the bottom defect for two overlapped corrosion defects
d
ave
Average defect depth
d
clus
Depth of the defect cluster
d
e
Equivalent depth of multiple defects
d
g
Maximum depth of a gouge
d
i
Maximum depth of the composite defect
d
max
Maximum depth of an irregularly shaped corrosion defect
D
Pipe outer diameter
D
e0
Simplified DFDI value before spring‐back
D
eform
Damage resulted from deforming
D
e,k
Damage during the
k
th load increment
D
em
Maximum DFDI at a dent
D
et
An indicator of the limit state for a pipeline to carry no further load
D
max
Maximum pipe outer diameter
D
min
Minimum pipe outer diameter
E
Young’s modulus
F
Faraday’s constant
F
c
Critical buckling load
F
comp
Compressive force
F
ref
Reference buckling load
f
Frequency
f
1
A factor representing the difference of strains after and before spring‐back of an unconstrained dent
h
Final depth of the dent after removal of the indenter
h
o
Initial displacement of the indenter applied on a pipe
i
a
Anodic reaction current density
i
0, a
Anodic exchange current density
i
a
e
Anodic current density of an elastically stressed steel in a corrosive environment
i
a
f
Anodic current density of a plastically stressed steel in a corrosive environment
Anodic current density of the steel pipe far away from the corrosion defects
Anodic current density at the middle of two adjacent corrosion defects
i
c
Cathodic reaction current density
i
0,
c
Cathodic exchange current density
I
An integral value used as the damage indicator
k
An index for either liquid or solid
K
R‐O material parameter, a constant
K
1
,
K
2
, …
Curvature of each node in a pipe during buckling modeling
K
Buckling
Pipe curvature at a local buckling position
K
d
Stress concentration factor at a dent
K
F
Fatigue stress concentration factor
K
r
Toughness ratio
L
Length
L
1
A half of the length of the top defect for two overlapped defects
L
clus
Length of the defect cluster
L
e
Equivalent length of multiple defects
L
eff
Effective length
L
g
Length of a gouge
L
i
Total length of the composite defect
L
p
Length of a pipe segment
L
r
p
Load ratio
M
Folias factor
M
c
Critical buckling moment
M
o
Critical elastic buckling moment
n
R‐O material parameter, a constant
N
Fatigue life in cycles
N
0
Initial density of dislocations prior to plastic deformation
N
1
,
N
2
, …
Nodes in modeling of curvature of a pipe during buckling
P
Internal pressure
P
1
Pressure at initial stage
P
2
Pressure at end stage
P
0
Tresca strength solution
P
(0)
Initial pressure capacity
P
b
Burst pressure
P
e
Minimum external hydrostatic pressure
P
F
Failure pressure
P
F,add
Failure pressure of a pipe when additional internal defects are included
P
FE
Burst pressures of a defect‐containing elbow predicted by FE model
P
GM
Burst pressure of a defect‐free elbow
P
i
Maximum design internal pressure
P
max
Upper limit burst pressure
P
min
Lower limit burst pressure
P
multiple
Failure pressure of a pipeline containing multiple corrosion defects
P
overlapped
Failure pressure of a pipeline containing overlapped corrosion defects
P
single
Failure pressure of a pipeline containing a single corrosion defect
P
y
Critical internal pressure when pipe steel yields
Q
Length correction factor
Q
k
A general source term
r
cc
Ratio of the lengths of primary axis of the smaller semi‐ellipsoidal defect to that of the bigger semi‐ellipsoidal corrosion defect in a double ellipsoidal defect
R
Ideal gas constant
R
0
Initial pipe surface radius
R
1
External surface radius of curvature in the transverse plane through a dent
R
2
External surface radius of curvature in the longitudinal plane through a dent
R
b
Bending radius of elbow
R
c
Stress ratio during cyclic loading
R
d
Surface radius of the curvature at a dent
R
p
Pipe outer radius
R
r
Outer radius of sealing cup of the ILI tool
S
C
Circumferential spacing between two adjacent corrosion defects
Limiting circumferential spacing between two adjacent corrosion defects
S
L
Longitudinal spacing between two adjacent corrosion defects
Limiting longitudinal spacing between two adjacent corrosion defects
Limiting longitudinal spacing between external defects
Limiting longitudinal spacing in the presence of both external and internal defects
S
Li
Longitudinal spacing between adjacent defect projections
t
Pipe wall thickness
T
Temperature
u
Profile functions in the longitudinal direction of a pipe
v
Profile functions in the circumferential direction of a pipe
V
Volume
V
o
Initial volume
V
m
Molar volume
w
Pipe wall deflection in the radial direction of a pipe
W
Width
W
clus
Width of the defect cluster
z
Chemical valence or charge number
α
A coefficient
β
Width angle of a defect
β
e
Equivalent width angle of multiple defects
σ
Stress
σ
1
,
σ
2
,
σ
3
Principal stresses of a pipeline
σ
a
Alternating stress
σ
e
Effective stress
σ
eq
Equivalent stress
σ
exp
Experimental stress function
σ
F
Failure stress
σ
FS
Fatigue strength
σ
flow
Flow stress
σ
k
Conductivity
σ
m
Mean stress
σ
max
Maximum stress
σ
min
Minimum stress
σ
Mises
von Mises stress
σ
Tresca
Tresca yield stress
σ
u
Ultimate tensile strength
σ
y
Yield strength
σ
yhard
Stress enhancement hardening factor during plastic deformation
σ
θ
Hoop stress
σ
z
Axial stress
ε
Strain
ε
as
Strain at the dent apex after spring‐back
ε
ini
Strain at the dent apex before spring‐back
ε
0
True strain to failure
ε
1
Bending strain in the circumferential direction
ε
2
Bending strain in the longitudinal direction
ε
3
Membrane strain in the longitudinal direction
ε
apex
Equivalent strain at the dent apex
ε
crit
Critical strain to initiate cracks
ε
i
Equivalent strain on the inside surface of a pipe
ε
o
Equivalent strain on the outside surface of a pipe
ε
eff
Effective strain
ε
eq
Equivalent strain
ε
lim
Strain limit
ε
max
Maximum equivalent strain
ε
p
Plastic strain
ε
x
Strain in the axial direction of a pipe
ε
y
Strain in the circumferential direction of a pipe
ε
z
Strain in the radial direction of a pipe
ε
b
Bending strain
ε
m
Membrane strain
γ
xy
Shear strain
Δ
Pipe ovality
Δ
ε
Cyclic strain range
θ
Angular position of a corrosion defect on pipe elbow
θ
b
Orientation of bending load
θ
incl
Inclination angle of corrosion defect relative to the axial direction of a pipeline
φ
Electrical potential
φ
eq
Equilibrium electrode potential
φ
a
,
eq
Equilibrium potential of anodic reaction
Standard equilibrium potential of anodic reaction
φ
c
,
eq
Equilibrium potential of cathodic reaction
Standard equilibrium potential of cathodic reaction
Φ
Axial routing angle of the pipe
μ
Chemical potential
μ
0
Chemical potential of solid in a standard state
μ
0
′
Standard chemical potential of solid considering the M‐C interaction
Δ
μ
Chemical potential difference
Δ
P
Pressure difference
Δ
Change of electrochemical anodic equilibrium potential under an elastic stress
Δ
Change of electrochemical anodic equilibrium potential under a plastic stress
χ
Compressibility coefficient of solid
υ
An orientation‐dependent factor
η
a
Anodic activation overpotential
η
c
Cathodic activation overpotential
v
Poisson’s ratio
1Pipeline Integrity Management
1.1 Introduction
Pipelines provide an effective and efficient means to transport oil, natural gas, and petrochemical products across provinces, countries, and even continents, meeting continuously increasing energy demands. The oil and gas transmission pipelines around the world are up to 3,500,000 km, with about 32,000 km of new pipelines constructed each year [Hopkins, 2007]. The total length can be multiplied many times if gathering and distribution pipelines are included. The world’s energy consumption is predicted to increase by 71% from 2003 to 2030, with fossil fuels continuing to supply much of the energy used worldwide [Department of Energy, 2006]. It is thus expected that pipeline construction and operation activities will continue growing. In recent years, with great efforts made to combat climate change and achieve the net‐zero emission target globally, pipelines have been used for safe, economical, and highly efficient transportation of “green” energies and fuels such as hydrogen gas, hydrogen/natural gas blends, biofuels, and supercritical carbon dioxide (CO2) [Ogden et al., 2018; Reuß et al., 2019; Cerniauskas et al., 2020]. The new energy pipelines are expected to experience rapid development in the next decade.
Energy transportation by pipelines is safe. Statistics showed that, in the United States, 1.7 fatalities to operators, personnel, and the public per year were caused by oil and gas pipeline accidents. As a comparison, transportation of oil and gas by rail and truck resulted in 2.4 and 10.2 fatalities per year, respectively [Hansen and Dursteler, 2017]. Pipeline transportation of hydrocarbon products was 4.5 times safer than rail on a like‐for‐like basis from analysis of the North American data [Green and Jackson, 2015].
The integrity of pipelines can be adversely affected by many factors in the field, such as corrosion, stress corrosion cracking (SCC), fatigue, mechanical damage, stray current, materials and manufacturing faults, equipment and component failures, geotechnical factors, incorrect operation, and external interference such as excavation [Godin, 2014; Canadian Energy Pipeline Association, 2015]. Although occurring occasionally, pipeline failures can result in energy loss, environmental and ecological impact, and, sometimes, death [Cheng, 2016]. Thus, pipeline incidents usually attract wide attention from news media and the public. One of the most widely reported pipeline incidents is the rupture and release of Enbridge’s oil pipeline in Marshall, Michigan, on July 25, 2010, which resulted in the largest inland oil spill and one of the costliest spills in US history [National Transportation Safety Board, 2012]. Following the spill, the volatile hydrocarbon diluents evaporated, leaving the heavier bitumen to sink in the water column. Thirty‐five miles of the Kalamazoo River were closed for clean‐up until June 2012.
Safety is the top priority for pipeline operators. The concept of Integrity First has been accepted by pipeline companies and become integral to corporation culture [Canadian Energy Pipeline Association, 2013]. In today’s pipeline industry, an integrity management program has been developed and implemented to ensure the safety, reliability, and longevity of the pipeline system by mitigating and preventing pipeline failure, achieving the goal of zero pipeline incidents. Particularly, defect assessment is a critical component of a well‐developed pipeline integrity management program. Development of models and methods for accurate and reliable assessment of various defects, such as corrosion, cracks, dents, and other anomalies, detected on pipelines is critical to determination of the pipeline fitness‐for‐service (FFS), prediction of failure pressure and estimation of the remaining service life of the pipelines [Qin and Cheng, 2021].
1.2 Overview of Threats to Pipeline Integrity
During long‐term service of pipelines in the field, the integrity of the pipeline system can be compromised by multiple types of threats or their combinations. According to Canadian Energy Pipeline Association (CEPA), metal loss including corrosion, cracking, and external inference remains the leading cause of incidents occurring on CEPA member operators’ oil/gas transmission pipelines [Canadian Energy Pipeline Association, 2021]. Collectively, these accounted for 82% of the total incidents over the period from 2016 to 2020, as seen in Figure 1.1. Other factors affecting the pipeline integrity included geohazards, external interference, and some unidentified reasons.
Figure 1.1 Causes of rights‐of‐way incidents 2016–2020 occurring on CEPA member operators’ pipelines.
Source: From Canadian Energy Pipeline Association [2021].
In the United States, the leading cause of accidents impacting people or the environment on liquid pipeline systems is corrosion according to the statistics of the Pipeline and Hazardous Materials Safety Administration (PHMSA). The second and third leading causes are equipment failure and material failure of pipe or weld, respectively. These three leading causes accounted for 65% of accidents since 2010 [Pipeline and Hazardous Materials Safety Administration, 2020]. Other factors included excavation damage, incorrect operation, natural force, and others. Similarly, the main causes resulting in onshore gas pipeline failures in the period of 2005–2020 included corrosion, equipment failure, material failure of pipe or weld, excavation damage, natural force, and others [Pipeline and Hazardous Materials Safety Administration, 2021]. Figures 1.2 and 1.3 show the statistical analysis of total number of accidents and their causes for PHMSA‐regulated liquid and gas pipelines, respectively, in the United States [Pipeline and Hazardous Materials Safety Administration, 2020; 2021].
1.2.1 Corrosion
Corrosion has been recognized as one of the primary mechanisms causing pipeline failures in North America. As stated, corrosion, as the most important reason causing failures of transmission pipelines in Canada, was responsible for 46% of all reported failure incidents from 2015 to 2019 [Canadian Energy Pipeline Association, 2021]. In a comparative analysis of pipeline performance issued by the National Energy Board (NEB) in Canada, the primary cause of ruptures on NEB‐regulated pipelines between 1991 and 2009 was corrosion‐related cracking (38%) and metal loss (27%) [National Energy Board, 2011], where the cracking included hydrogen‐induced cracking (HIC) and mechanical damage delayed cracking, SCC, and corrosion fatigue, and the metal loss included both internal and external corrosion, as well as scratches. For both liquid and gas pipelines operated in the United States, data from PHMSA showed that corrosion was the first leading cause of reported accidents, representing 30.5% (2010–2019) and 22.5% (2005–2020), respectively, of cases [Pipeline and Hazardous Materials Safety Administration, 2020; 2021].
Figure 1.2 Statistical analysis of total number of accidents and their causes for PHMSA‐regulated liquid pipelines in the United States from 2010 to 2019.
Source: From Pipeline and Hazardous Materials Safety Administration [2020].
Figure 1.3 Statistical analysis of total number of accidents and their causes for PHMSA‐regulated gas pipelines in the United States from 2005 to 2020.
Source: From Pipeline and Hazardous Materials Safety Administration [2021].
For underground pipelines, corrosion can occur both externally and internally. The strategy for external corrosion control is application of high‐performance coatings combined with cathodic protection (CP), an electrochemical technique mitigating and even stopping steel corrosion by cathodically polarizing the steel structure from its corrosion potential in the corrosive environment to a more negative potential. In an impressed current CP (ICCP) system, the cathodic polarization of the steel structure is realized by provision of electrons from an external power supply, i.e., a rectifier, to the structure. Generally, the coatings provide the first line of defense to protect the pipelines from environmental attack such as corrosion. When the coatings degrade or fail, the CP can provide further protection at the coating failures. The demand for CP current, i.e., electrons flowing from the rectifier to the steel structure, depends on coating performance. When the coatings are intact and provide excellent protection to the substrate steel, the CP current demand is zero. As the coatings degrade, the CP current demand increases. After the coatings completely lose the protective ability, e.g., the coatings are missed over an extensive area from the pipeline, the CP demand reaches a maximum level, and the pipeline corrosion is controlled by CP only [Cheng and Norsworthy, 2017].
The combination of coatings and CP technique does not always work properly for corrosion control on pipelines. The CP current can become shielding from reaching pipe steel in corrosive environments and lose the protective ability when the coatings fail. Three typical scenarios have been identified where the CP current is shielded while the coatings degrade and fail, as shown in Figure 1.4 [Cheng and Norsworthy, 2017]. First, a coating, primarily a polymeric coating such as epoxy or a polyethylene (PE)‐based product, contains pinholes, defects, or breakages, which are usually introduced during coating manufacturing and pipeline construction, while the coating adhesion to the steel substrate is still maintained. These local features can be penetrated by water, chemical species, and gases during service in the underground environment. As a result, a corrosive environment is generated at the bottom of the features to cause corrosion of the pipe steel. Owing to geometric limitation (i.e., a small aspect ratio of the width to the depth of the features) or deposit of corrosion products inside the features, the CP current is shielded from reaching the bottom of the features for corrosion protection, as shown schematically in Figure 1.4a [Xu and Cheng, 2014]. Second, the coating is disbonded from the pipe steel at a holiday (or a defect). Although CP is applied, the disbonding crevice under the coating is shielded from the CP current owing to geometric limitation, i.e., a long, narrow disbonding crevice. Separated anode and cathode are generated where anodic dissolution (i.e., corrosion of the steel) occurs under the disbondment, especially at the disbonding bottom, and cathodic reaction (e.g., electrochemical reduction of dissolved oxygen or water) occurs at the holiday, which is under CP, as seen in Figure 1.4b [Kuang and Cheng, 2015a; 2015b]. Finally, the CP current is shielded from a defect‐free coating membrane, which is usually composed of PE components, such as PE tape, when the coating is disbonded from the pipe steel due to a poor surface treatment of the steel or improper coating application (Figure 1.4c). Generally, the PE is highly resistant to permeation of water, chemicals, and gases under pipeline operating conditions. The intrinsic properties make the coating impermeable to the CP current [Fu and Cheng, 2011].
Figure 1.4 Scenarios identified on pipelines where the CP current is shielded from reaching pipe steel while the coatings degrade and fail (a) A pinhole (d: depth, w: width) contained in the coating while the adhesion to the steel substrate is still maintained. (b) A coating disbonded at a holiday. (c) A defect‐free, impermeable coating membrane, disbonded from the pipe steel.
Source: (a) From Xu and Cheng [2014] / with permission of Elsevier; (b) from Kuang and Cheng [2015b].
In addition to the factors related to coating properties and performance as mentioned above, dry soil environments with an extremely high resistivity can break the current flow circuit of the CP system, making the CP nonfunctional [Cheng and Norsworthy, 2017]. When water is trapped under disbonded coating, corrosion would occur in the absence of CP. Furthermore, microbiologically influenced corrosion (MIC) can happen on pipelines externally. In soil environments, many types of microorganisms that cause (usually accelerate) corrosion of metals, such as the anerobic sulfate‐reducing bacteria (SRB), exist. It was found that, compared to the corrosion rate of 0.0473 mm/y in abiotic soils, the corrosion rate of pipeline steels could be up to 0.282 mm/y when SRB were contained in the soil [Liu and Cheng, 2017a]. An increased moisture content in the soils favored the growth of SRB, accelerating the steel MIC. In addition, the CP could facilitate bacterial attachment to pipe steels. When a layer of the so‐called “biofilm” is formed on the steel surface, the effectiveness of CP for corrosion protection decreases [Liu and Cheng, 2017b]. The CP potential of −0.85 V (copper sulfate electrode, CSE) is not sufficient to fully protect the steels from MIC induced by SRB. While a negative shift of the CP potential to −1 V (CSE) can prevent uniform MIC, pitting corrosion still occurs under the biofilm. The external corrosion of pipelines can also be accelerated by alternating current (AC) or direct current (DC) interference, where the interference sources such as high voltage AC (HVAC) or high voltage DC (HVDC) power lines and AC‐powered rail transit systems are collocated with buried pipelines [Cheng, 2021]. The AC and DC inferences can accelerate steel corrosion and, sometimes, initiate pitting corrosion. Moreover, the coating properties and performance become degraded in the presence of AC interference. The applied CP potential can be shifted from the design value toward either positive or negative direction, reducing corrosion protectiveness of the CP. With growing numbers of HVAC transmission lines collocated with the pipelines, nowadays, AC corrosion has been recognized as a serious threat to the integrity of pipelines [Canadian Energy Pipeline Association, 2014].
For long‐distance transmission pipelines, internal corrosion is not regarded as a big threat to pipeline integrity although pipeline failure incidents attributable to internal corrosion have been reported. The quality of the fluids (i.e., oil and natural gas) carried in the transmission pipelines has been ensured through processing before they are transported by the pipelines. For example, according to US Federal Energy Regulatory Commission (FERC) regulations, the transported oils are subject to a limitation on basic sediments & water (BS&W) of less than 0.5 vol% [Federal Energy Regulatory Commission, 2011]. Corrosion of steels does not happen in oil unless water and wetted sands entrained in the oils are separated from the oily phase and settle down on the pipe floor, making the steel water wetted over an extended period [National Academy of Sciences, 2013]. Moreover, trace amounts of salts dissolving in water can increase its conductivity. A more aggressive environment is that a biofilm forms on the pipe wall surface, separating the underneath environment from the carried fluid. A microbiological community develops under the biofilm, which are usually composed of petroleum sludge, solid sands, water, chemicals, corrosion products, and microorganisms, to cause internal MIC [Lenhart et al., 2014; Liu and Cheng, 2018]. It is not uncommon that pipelines leak due to MIC‐induced perforation [Cole and Marney, 2012]. Generally, pipeline operators conduct periodic pigging to clean out various deposits including biofilms. The pigging removes the environment that might otherwise cause corrosion. In‐line inspection (ILI) tools allow the operators to collect information about the geometry and location of pipeline flaws and, further, to analyze the FFS of the corroded pipelines [Canadian Energy Pipeline Association, 2015]. The industry also depends on appropriate chemical treatment programs to add inhibitors and biocides to mitigate and control internal corrosion and MIC [Banff Pipeline Workshop, 2015]. Owing to both the strictly enforced BS&W limit in the pipelined fluids and periodic pigging, along with the appropriate chemical treatment program, internal corrosion does not occur as frequently as external corrosion on transmission pipelines, although there have been reports of pipeline‐leaking incidents resulting from internal corrosion.
1.2.2 Environmentally Assisted Cracking
Environmentally assisted cracking (EAC) is a general term for fracture that occurs when a susceptible metal is under tensile stress in a corrosive environment. The EAC is different from a mechanical fracture in that corrosion reaction participates in (usually accelerates) the fracture process. In other words, the EAC occurs due to both mechanical stress and corrosion reaction that act simultaneously and usually synergistically. Generally, the EAC is categorized into three types of fracture, i.e., SCC, corrosion fatigue, and HIC.
1.2.2.1 Stress Corrosion Cracking
The SCC is defined as a cracking process of metals due to the combined and synergistic interaction of mechanical tensile stress and corrosion reactions [Jones, 1992]. Pipeline SCC occurs under a combination of factors from environmental (e.g., coatings and coating failure modes, CP shielding effect, soil chemistry and resistivity, temperature, and aeration), stress (i.e., internal pressure and its fluctuations, ground movement, hoop and longitudinal stresses, and bending stress), and materials (e.g., steel grade, mechanical properties, chemical composition, microstructure, metallurgical defects, and welding metallurgy) aspects [Cheng, 2013]. SCC used to be a major threat to integrity and safety of pipelines. According to NEB of Canada, approximately 38% of the primary causes for pipeline failures were due to cracking from 1991 to 2009 [National Energy Board, 2011]. Particularly, the SCC caused pipeline failures by 10–13%. Pipeline SCC has been categorized into two types, i.e., high‐pH SCC and near neutral‐pH SCC, based on the pH of electrolytes contacting the pipe steel. Thus, the pH refers to the pH value of the aqueous environment at the crack location rather than the soil pH [Cheng, 2013].
The environments to cause high pH SCC on pipelines are aerobic, concentrated carbonate–bicarbonate electrolytes with a pH range of 8–10 [National Energy Board, 1996]. The environments result from CP current penetrating the so‐called permeable coatings, such as asphalt, to reach the pipe steel surface, cathodically polarizing the steels. Hydroxyl ions are produced by cathodic reduction of dissolved oxygen to elevate solution pH. The CO2, which is from the soils by decay of organic matter, is dissolved in the electrolytes. When non‐dissolvable deposits such as Mg(OH)2 and Ca(OH)2 are formed in the alkaline electrolytes and present on the coating, the CP current flow is blocked. As a result, the cathodic polarization applied on the pipe steels is stopped. During relaxation of the steel potential from the initial CP value, the steel may pass a potential window which is susceptible to SCC. It has been accepted that the high pH SCC of pipelines follows a dissolution‐based mechanism, where corrosion at the crack tip dominates the crack propagation process [Parkins, 2000]. Stress corrosion cracks tend to propagate along grain boundaries due to preferential dissolution occurring locally, which is attributed to an enhanced electrochemical corrosion activity at the grain boundaries by factors such as impurity accumulation, dislocation pinning and lattice distortion [Cheng, 2013]. Thus, the high pH SCC follows an intergranular growth mode, often with small branches [National Energy Board, 1996]. The fracture surface normally exhibits a dark, discolored layer of oxides, primarily magnetite. The last portion of the pipe wall to fracture (i.e., the rapidly fractured region) remains a shiny silver color. The high pH SCC of pipelines is temperature sensitive.
The environments to cause near‐neutral pH SCC on pipelines are anerobic, diluted bicarbonate electrolytes with a pH range of 5.5–7 [National Energy Board, 1996]. The environments are generated under disbonded, impermeable coatings, such as PE tape, which can shield CP current from reaching pipe steel. Thus, the steel is at its corrosion potential in the trapped electrolyte, where CO2 coming from the soils is dissolved. It has been accepted that hydrogen (H) atoms participate in the near‐neutral pH SCC process on pipelines, accompanying anodic dissolution of the steel inside the crack [Parkins, 2000]. Stress corrosion cracks are usually wide due to corrosion, and corrosion products accumulate inside the crack. Due to the hydrogen effect on the crack propagation process, the crack growth rate is usually hundreds of times greater than the cracking process dominated by corrosion reaction only. The near‐neutral pH SCC follows a transgranular growth mode [National Energy Board, 1996]. The near‐neutral pH SCC of pipelines is independent of temperature under pipeline operating conditions.
Both high pH and near‐neutral pH SCC of pipelines occur as colonies of multiple parallel cracks that are generally perpendicular to the direction of the highest stress, i.e., primarily hoop stress resulting from the internal pressure, on the pipelines. These cracks can vary in depth and length and grow in two directions, i.e., the axial and transverse directions. They tend to coalesce or link together to form longer cracks. At some point, these cracks may reach a critical depth and length combination that can result in rupture. A leak will occur if a crack grows through the pipe wall thickness before it reaches a critical length for rupture.
