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Full text of "CONTROL OF PIPELINE CORROSION"

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PEABODY'S 

CONTROL OF PIPELINE CORROSION 

SECOND EDITION 



A.W. PEABODY 

Edited by 

RONALD L. BIANCHETTI 



NACE International 
The Corrosion Society 

1440 South Creek Drive 
Houston, Texas 77084 



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NACE International 
The Corrosion Society 

© 1967, 2001 by NACE International 

Second Edition 2001. All rights reserved. 

Library of Congress Catalog Number 99-80032 

ISBN 1-57590-092-0 



Printed in the United States of America. All rights reserved. This book, or parts thereof, 
may not be reproduced in any form without permission of the copyright owners. 

Neither NACE International, its officers, directors, or members thereof accept any re- 
sponsibility for the use of the methods and materials discussed herein. The information 
is advisory only and the use of the materials and methods is solely at the risk of the user. 



Cover illustration by Mark Lewis, courtesy of the East Bay Municipal Utility District. 

NACE Press: 

Director of Publications: Jeff Littleton 

Manager of NACE Press: Neil Vaughan 




NACE International 

1440 South Creek Drive 

Houston, Texas 77084 

http : // w w w.nace . org 



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Table of Contents 



Preface v 

About the Author vii 

Contributors ix 

Chapter 1 Introduction to Corrosion 

John A. Beavers 1 

Chapter 2 Pipeline Coatings 

Richard N. Sloan 7 

Chapter 3 Cathodic Protection — How It Works 

John A. Beavers 21 

Chapter 4 Criteria for Cathodic Protection 

John A. Beavers and Kevin C. Garrity 49 

Chapter 5 Survey Methods and Evaluation Techniques 

Ronald L. Bianchetti 65 

Chapter 6 Instrumentation 

Mark Lewis 101 

Chapter 7 Ground Bed Design 

Ronald L. Bianchetti 131 

Chapter 8 Impressed Current Cathodic Protection 

Ronald L. Bianchetti 157 



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Table of Contents 



Chapter 9 Cathodic Protection with Galvanic Anodes 

Ronald L. Bianchetti 

Chapter 10 Cathodic Protection with Other Power Sources 

John A. Beavers 

Chapter 11 Stray Current Corrosion 

Michael J. Szeliga 

Chapter 12 Construction Practices 

Ronald L. Bianchetti 

Chapter 13 Maintenance Procedures 

Ronald L. Bianchetti 

Chapter 14 Microbiologically Influenced Corrosion 

Brenda J. Little and Patricia Wagner 

Chapter 15 Economics 

Ronald L. Bianchetti 

Chapter 16 Fundamentals of Corrosion 

John A. Beavers 

Appendix A NACE Glossary of Corrosion-Related Terms 

Appendix B Additional Important Information on Underground Corrosion Control 

Index 



177 
201 
211 

237 
261 

273 

285 

297 
319 
339 
341 



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Preface 



This book was originally published in 1967 by Sam Peabody and is the most quoted and 
used document in the corrosion industry for pipeline corrosion control and testing. When 
the original book was published, specific criteria for cathodic protection for underground 
pipelines were still under evaluation and consideration. Not until 1969 was the first 
documented standard approved by NACE International on criteria RP0169. The depth 
and vision that Peabody incorporated in the first version of the book has stood the test 
of time. 

This revised version of the 1967 book is not an attempt to make radical changes to the 
original document. Much of the original text and concepts remain intact. We attempted, 
however, to incorporate original traditional elements of the book with updates and 
expanded discussions on equipment, testing techniques and criteria, coatings, survey 
methods, and data analysis. 

An integral part of this revision is a CD-ROM that contains formulas of key design 
calculations, case examples of corrosion control designs which provide a set-by-step 
overview of how to design various components of cathodic protection systems, and an 
electronic copy of the revised book edition. 

As described in the Preface of the original 1967 edition, every attempt has been made 
to check the accuracy of all statements and other data. However, it is unreasonable 
to assume that everything in this book is accurate and exact. Any suggestions will be 
considered when future editions of this book are prepared. 



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About the Author 




1915-1998 



This updated version of NACE International's book titled Control of Pipeline Corrosion is 
dedicated to the memory of its original author, A. W. (Sam) Peabody. Since its publication 
in 1967, the book has been translated into at least seven different languages and is 
considered by most as the definitive work on pipeline corrosion. 

Sam received his bachelor's degree from the University of Maine and pursued grad- 
uate studies at the Brooklyn Polytechnic Institute in New York. He worked for Ebasco 
Services Inc. (no longer in existence) for over 40 years until his retirement in 1980 as 
Director of Corrosion Engineering. He was an active member of NACE since 1947. His 
accomplishments, awards, and recognitions are too many to list here. His biggest legacy, 
especially to those of us who had the privilege of working for and with him, is that he 
was the perfect example of "a gentleman and a scholar." He was an excellent teacher 
who always emphasized professional integrity, a quality he instilled in so many. 



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Contributors 



John A. Beavers 

John A. Beavers is Vice President of Research at CC Technologies, a corrosion engineering 
and research company. He received B.S. and Ph.D. degrees in metallurgical engineering from 
the University of Illinois at Urb ana-Champaign in 1973 and 1977, respectively. Dr. Beavers 
has directed and contributed to numerous research programs on corrosion performance of 
structural materials. These programs included failure analyses, critical literature reviews, and 
laboratory and field evaluations of metallic and non-metallic material. Dr. Beavers has utilized 
state-of-the-art electrochemical, surface analytical, and mechanical techniques for the evalua- 
tion of materials performance. A major emphasis of his research has been the mechanistic and 
practical aspects of corrosion and stress corrosion cracking (SCC) on underground pipelines. 
Dr. Beavers worked at Battelle Memorial Institute from 1977 to 1987, where he was a Senior 
Research Leader in the Corrosion Section. He joined CC Technologies in 1987. 

Dr. Beavers has authored over 80 papers in the field of corrosion and has received two 
U.S. Patents. An active member of NACE, he was Chairman of the Research in Progress 
Symposium in 1994 and of the Publications Committee in 1991 and 1992. 

Editor's Note: Sincere appreciation to John Beavers for investing a lot of time on a detailed and 
productive review of the final draft on the eve before printing. 

Ronald L. Bianchetti 

Ronald L. Bianchetti is currently a Senior Engineer at East Bay Municipal Utility District 
(EBMUD) in Oakland, California. He received a B.S. in engineering in 1975 from the 
University of California, Davis and an MBA in 1981 from St. Mary's College of California. 
He is a Registered Professional Engineer and has over 25 years of experience. Prior to holding 
his current position, Mr. Bianchetti worked in the private sector as a consultant in the cor- 
rosion industry from 1975 to 1992. His work includes planning, designing, testing, and the 
construction management of cathodic protection systems for underground pipelines, tanks, 
refineries, power plants, and marine structures. He has served in NACE International as Past 



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Contributors 



Chairman of the Publications Committee, ad-hoc member to the Board of Directors, Past 
Western Region Chairman and Past Section Chair of the San Francisco Section. 

Mr. Bianchetti has published over 30 papers in the field of corrosion and has given hun- 
dreds of presentations on corrosion and corrosion control. 

Kevin C. Garrity, RE. 

Kevin C. Garrity, P.E., is currently Vice President of Engineering at CC Technologies, a cor- 
rosion engineering and research company. He received a B.S. in electrical engineering in 
1974 from the Polytechnic Institute of Brooklyn. He is a NACE Certified Cathodic Protection 
Specialist and a Registered Professional Engineer in seven states. Mr. Garrity has 26 years 
of experience in the design, installation, monitoring, and assessment of cathodic protection 
systems for buried pipelines, underground storage tanks, concrete structures, and marine 
structures. Mr. Garrity worked at Ebasco Services from 1974 to 1982, where he was a Senior 
Corrosion Engineer, and at Harco Corporation from 1982 to 1989, where he was Vice President 
of Engineering. He joined CC Technologies in 1989. 

In 1996, Mr. Garrity received the Colonel George W. Cox Award for outstanding contribu- 
tions to the field of underground corrosion control. He has published more than 20 papers in 
the field of corrosion control. Mr. Garrity delivered the plenary lecture at Corrosion'98. 

Mark Lewis 

Mark Lewis is Assistant Corrosion Engineer at the East Bay Municipal Utility District 
(EBMUD) in Oakland, California. He is a graduate of Kent State University and attended 
Bethany College in West Virginia. He has worked in the cathodic protection and corrosion 
engineering field since 1980, both within the United States and internationally. He is a Past 
Chairman of the San Francisco Bay Area Section of NACE International. 

He is the author of several technical and historical articles on cathodic protection and has 
made numerous presentations on the subject. Mr. Lewis has a patent pending for a distribution 
system rectifier design. 

Brenda J. Little 

Brenda J. Little, Senior Scientist for Marine Molecular Processes at the Naval Research Labora- 
tory, has a Ph.D. in chemistry from Tulane University and a B.S. in biology and chemistry from 
Baylor University. She is a member of the American Chemical Society and the National As- 
sociation of Corrosion Engineers (NACE International). She is a NACE International Fellow 
and the recipient of a 1999 NACE International Technical Achievement Award. 

Dr. Little serves on the editorial board for Biofouling and is the author of one book, 20 
book chapters, and over 80 peer-reviewed journal articles. 



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Contributors 



Steve McKim 



Since 1989, Steve McKim has been Vice President of American Construction & Supply, Inc. 
Based in Mill Valley, California, his company specializes in cathodic protection construction 
services. Mr. McKim previously worked with Harco Corporation and Chevron USA. He has 
been in the corrosion industry since he graduated from the University of Illinois with a B.S. in 
mechanical engineering in 1983. He is a Past Chairman of the NACE San Francisco Bay Area 
Section. 



Richard N. Sloan 



The late Richard Sloan, was an authority in the field of pipeline coatings. He worked for over 
45 years with a company that was first known as HC Price. (The company changed its name 
several times: HC Price, Ameron Price, Bredero Price, and Energy Coatings.) He attended 
Drexel University and graduated with a bachelor's degree in Industrial Administration. 

During his professional career, Richard Sloan taught various short courses in pipeline 
coatings, and was a speaker at numerous seminars on the subject. The late Mr. Sloan was an 
active and long-standing member of NACE, AWWA, and Western Pipeliners. 



Michael J. Szeliga 



Michael J. Szeliga, P.E., is the Chief Engineer for Russell Corrosion Consultants, Inc. He has 
more than 23 years of experience in corrosion control engineering. Much of his work has 
involved the analysis and control of stray current from DC-powered transit systems and 
from impressed current cathodic protection systems. A Licensed Professional Engineer in 
several states and certified by NACE International as a Corrosion Specialist and a Cathodic 
Protection Specialist, Mr. Szeliga has been and is the principal corrosion consultant for the 
design, construction, and maintenance of many light and heavy rail transit systems. He is 
presently chairman of the NACE (05)024X Committee on Interference Problems Associated 
with Rail Transit. Mr. Szeliga is also chairman of the ASTM subcommittee on stray current. 

He has edited a book for NACE International titled Stray Current Corrosion and has pub- 
lished several articles on the subject. 



Patricia Wagner 



Patricia Wagner retired from the Naval Research Laboratory in 1998 after 14 years of extensive 
experience in microbiologically influenced corrosion. She is the coauthor of one book and the 
author of numerous articles on corrosion. 



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Chapter 



Introduction to Corrosion 



John A. Beavers 



WHAT IS CORROSION? 



One general definition of corrosion is the degradation of a material through environ- 
mental interaction. This definition encompasses all materials, both naturally occurring 
and man-made and includes plastics, ceramics, and metals. This book focuses on the 
corrosion of metals, with emphasis on corrosion of carbon and low-alloy steels used 
in underground pipelines. This definition of corrosion begs the question; why do met- 
als corrode? The answer lies in the field of thermodynamics, which tells whether a 
process such as corrosion will occur. A second logical question is what is the rate 
of corrosion or how long will a pipeline last? Corrosion kinetics can help provide an 
answer to this question. Both topics are discussed in greater detail in Chapter 16. Chap- 
ter 1 contains an introduction to the subject of underground corrosion. A glossary of 
terms is included in Appendix A of this book to help with the sometimes confusing 
terminology. 

A significant amount of energy is put into a metal when it is extracted from its 
ores, placing it in a high-energy state. These ores are typically oxides of the metal such 
as hematite (Fe203) for steel or bauxite (AI2O3H2O) for aluminum. One principle of 
thermodynamics is that a material always seeks the lowest energy state. In other words, 
most metals are thermodynamically unstable and will tend to seek a lower energy state, 
which is an oxide or some other compound. The process by which metals convert to the 
lower-energy oxides is called corrosion. 

Corrosion of most common engineering materials at near-ambient temperatures oc- 
curs in aqueous (water-containing) environments and is electrochemical in nature. The 
aqueous environment is also referred to as the electrolyte and, in the case of under- 
ground corrosion, is moist soil. The corrosion process involves the removal of elec- 
trons (oxidation) of the metal [Equation (1)] and the consumption of those electrons by 
some other reduction reaction, such as oxygen or water reduction [Equations (2) and (3), 



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Introduction to Corrosion 



respectively]: 

Fe -> Fe ++ + 2e~ 

2 + 2H 2 + 4e~ -> 40H" 

2H 2 + 2e~ -> H 2 + 20H~ 



(1) 
(2) 
(3) 



The oxidation reaction is commonly called the anodic reaction and the reduction 
reaction is called the cathodic reaction. Both electrochemical reactions are necessary for 
corrosion to occur. The oxidation reaction causes the actual metal loss but the reduction 
reaction must be present to consume the electrons liberated by the oxidation reaction, 
maintaining charge neutrality. Otherwise, a large negative charge would rapidly develop 
between the metal and the electrolyte and the corrosion process would cease. 

The oxidation and reduction reactions are sometimes referred to as half-cell reactions 
and can occur locally (at the same site on the metal) or can be physically separated. 
When the electrochemical reactions are physically separated, the process is referred to 
as a differential corrosion cell. A schematic of a differential corrosion cell is given in 
Figure 1.1. The site where the metal is being oxidized is referred to as the anode or 
anodic site. At this site, direct electric current (defined as a positive flow of charge) flows 
from the metal surface into the electrolyte as the metal ions leave the surface. This current 
flows in the electrolyte to the site where oxygen, water, or some other species is being 
reduced. This site is referred to as the cathode or cathodic site. There are four necessary 
components of a differential corrosion cell. 

1 . There must be an anode 

2. There must be a cathode 




Anode 



Metal 



Cathode 



Current 



Figure 1.1 Schematic showing a differential corrosion cell. 



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How Do We Detect Corrosion? 



3. There must be a metallic path electrically connecting the anode and cathode. (Nor- 
mally, this will be the pipeline itself.) 

4. The anode and cathode must be immersed in an electrically conductive electrolyte 
(normally, moist soil). 

Underground corrosion of pipelines and other structures is often the result of differ- 
ential corrosion cells of which a variety of different types exist. These include differential 
aeration cells, where different parts of a pipe are exposed to different oxygen concen- 
trations in the soil, and cells created by differences in the nature of the pipe surface or 
the soil chemistry. Galvanic corrosion is a form of differential cell corrosion in which 
two different metals are electrically coupled and exposed in a corrosive environment. 
Further discussion of these differential corrosion cells is given below and in Chapter 16. 



HOW DO WE DETECT CORROSION? 

The electrochemical nature of the corrosion process provides opportunities to detect 
and mitigate corrosion of underground structures. We can monitor the voltages and the 
currents associated with the corrosion process. 

When a piece of metal is placed in an electrolyte, such as soil, a voltage will develop 
across the metal-electrolyte interface because of the electrochemical nature of the cor- 
rosion process. We cannot measure this voltage directly but, using a voltmeter, we can 
measure a voltage between two different metals that are placed in the soil. We also can 
measure the voltage difference between a metal and a reference electrode, commonly 
called a half-cell electrode. This voltage is referred to as a corrosion potential, an open 
circuit potential, or a native potential for that metal in the environment in which the mea- 
surement is being obtained. For soil environments, the most common reference electrode 
used is the copper-copper sulfate reference electrode (CSE). 

Potential measurements can be used to estimate the relative resistance of different 
metals to corrosion in a given environment. Noble metals, such as gold and platinum, 
have more positive potentials and are more resistant to corrosion than are the more 
common engineering metals such as steel and aluminum. A galvanic series is a list of 
metals and alloys arranged according to their relative corrosion potentials in a given 
environment. Table 1.1 shows a galvanic series for metals and other materials in neutral 
soils and water, indicating that carbon has the most positive potential of the materials 
listed and magnesium has the most negative potential. The potentials measured for the 
different metals in a galvanic series vary somewhat, depending on the nature of the 
environment, but the relative position of the metals is similar for natural environments 
such as soil and seawater. 

Another use for corrosion potential measurements is to establish whether galvanic 
corrosion is likely to occur. When two metals are electrically coupled in an environ- 
ment, the more negative (active) member of the couple will become the anode in the 



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Introduction to Corrosion 



Table 1 .1 Practical Galvanic Series for Materials in Neutral Soils 
and Water 

Material Potential Volts (CSE) a 

Carbon, Graphite, Coke +0.3 

Platinum to -0.1 

Mill Scale on Steel -0.2 

High Silicon Cast Iron —0.2 

Copper, Brass, Bronze -0.2 

Mild Steel in Concrete -0.2 

Lead -0.5 

Cast Iron (Not Graphitized) -0.5 

Mild Steel (Rusted) -0.2 to -0.5 

Mild Steel (Clean and Shiny) -0.5 to -0.8 

Commercially Pure Aluminum —0.8 

Aluminum Alloy (5% Zinc) - 1 .05 

Zinc -1.1 

Magnesium Alloy (6% Al, 3% Zn, 0.15% Mn) -1.6 

Commercially Pure Magnesium —1.75 

a Typical potential normally observed in neutral soils and water, mea- 
sured with respect to copper sulfate reference electrode. 



differential corrosion cell, and the more positive (noble) member of the couple will be- 
come the cathode in the cell. In general, the severity of the galvanic couple increases as 
the difference in potential between the two members of the couple increases, although 
this is not always the case. The galvanic series shown in Table 1.1 indicates that, where 
copper is electrically coupled to mild steel in soil, the copper will become the cathode and 
the steel will become the anode, accelerating corrosion of the steel. A further discussion 
of galvanic corrosion is given in Chapter 16. 

Table 1.1 also shows that the potential of mild steel can differ depending on whether 
the surface is clean or covered with mill scale. The potential of steel also is a function of 
soil properties, including pH, ion concentration, oxygen, and moisture content. The po- 
tential differences that develop on underground pipelines and other structures as a result 
of these factors can result in severe corrosion. Further discussions of these differential 
corrosion cells are given in Chapter 16. 

Potential measurements are commonly used on underground pipelines to detect the 
presence of these types of differential corrosion cells. An electrical connection is made to 
the pipe, and the potential of the pipe is measured with respect to a reference electrode 
placed over the pipe. This process is shown schematically in Figure 1.2. Normally, the 
reference electrode is connected to the negative lead of a digital voltmeter to obtain a 
negative reading. As shown in Table 1.1, most potentials in soils are negative. With this 
type of measurement, the most negative regions of the structure are the anodes and are 
undergoing accelerated corrosion due to the differential corrosion cells. 



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How Do We Mitigate Corrosion? 



Copper 
Sulphate 
Reference 
Electrode 




Figure 1.2 Schematic showing a pipe- 
to-soil potential measurement. 

Current measurements also can be used to detect differential corrosion cells if the 
anodes and cathodes are large. These large cells create long-line currents that can be 
detected by measurements made over the pipe or other underground structure. Through 
Ohm's law (V = IR, where V is the voltage, I is the current, and R is the resistance) 
we know that current flow in the soil will create a voltage gradient. This gradient can 
be detected by placing identical reference electrodes over the pipe and measuring the 
voltage difference. The voltage measurements can be used to indicate the direction of 
the differential cell current. The anodic and cathodic sites on the pipeline can be located 
by performing a series of cell-to-cell potential measurements taken along the pipeline. 
Another possible source of current flow in the ground is stray currents. These issues are 
discussed further in Chapter 5. 



HOW DO WE MITIGATE CORROSION? 



The principal methods for mitigating corrosion on underground pipelines are coatings 
and cathodic protection (CP). Although each will be treated in greater detail in the 
following chapters, these two methods are briefly described here. 



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Introduction to Corrosion 



Coatings normally are intended to form a continuous film of an electrically insulating 
material over the metallic surface to be protected. The function of such a coating is to 
isolate the metal from direct contact with the surrounding electrolyte (preventing the 
electrolyte from contacting the metal) and to interpose such a high electrical resistance 
that the electrochemical reactions cannot readily occur. In reality, all coatings, regardless 
of overall quality, contain holes, referred to as holidays, that are formed during appli- 
cation, or during transport or installation of mill-coated pipe. Holidays in coatings also 
develop in service as a result of degradation of the coating, soil stresses, or movement of 
the pipe in the ground. Degradation of the coating in service also can lead to disbonding 
from the pipe surface, further exposing metal to the underground environment. A high 
corrosion rate at a holiday or within a disbonded region can result in a leak or rupture, 
even where the coating effectively protects a high percentage of the pipe surface. Thus, 
coatings are rarely used on underground pipelines in the absence of CP. The primary 
function of a coating on a cathodically protected pipe is to reduce the surface area of 
exposed metal on the pipeline, thereby reducing the current necessary to cathodically 
protect the metal. Further discussion of coatings is given in Chapter 2. 

One definition of CP is a technique to reduce the corrosion rate of a metal surface 
by making it the cathode of an electrochemical cell. This is accomplished by shifting the 
potential of the metal in the negative direction by the use of an external power source 
(referred to as impressed current CP) or by utilizing a sacrificial anode. In the case of an 
impressed current system, a current is impressed on the structure by means of a power 
supply, referred to as a rectifier, and an anode buried in the ground. In the case of a 
sacrificial anode system, the galvanic relationship between a sacrificial anode material, 
such as zinc or magnesium, and the pipe steel is used to supply the required CP current. 
Further discussions of CP are given in Chapters 3 and 16. 



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Chapter 



Pipeline Coatings 



Richard N. Sloan 



When the first edition of Control of Pipeline Corrosion by A.W. Peabody was published in 
1967, there were few governmental regulations to contend with. Today the Department of 
Transportation-Office of Pipeline Safety (DOT/OPS), Occupational Safety and Health 
Administration (OSHA), and the Department of Environmental Resources (DER) are 
among the many regulatory agencies influencing or controlling the pipeline industry 
Governmental regulations, along with the development, introduction, and acceptance of 
new pipeline coatings, have made major changes and will continue to affect the selection 
and use of pipeline coatings in the future. 

Economics, while still a factor, is being replaced by safety and environmental con- 
cerns to obtain the best available pipe-coating systems. This trend was first apparent in 
Europe where permanence, instead of cost, led to the use of multi-layer systems that 
have proven to be most effective and more economical over the life of the pipeline. In 
today's regulated environment, all new hazardous pipelines (carrying oil, gas, or other 
potentially dangerous substances) are required by federal regulation to use an effective 
coating and cathodic protection (CP). 



EFFECTIVENESS OF COATINGS AS A MEANS OF CORROSION CONTROL 

First attempts to control pipeline corrosion relied on the use of coating materials and the 
reasoning that if the pipeline metal could be isolated from contact with the surrounding 
earth, no corrosion could occur. This concept is entirely reasonable and logical. Further- 
more, a coating would be completely effective as a means of stopping corrosion if the 
coating material: 

• Is an effective electrical insulator, 



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Pipeline Coatings 



• Can be applied with no breaks whatsoever and will remain so during the backfilling 
process, and 

• Constitutes an initially perfect film that will remain so with time. 

While this is possible with some of the advanced multi-layer systems, it may not be 
practical from an initial cost analysis. 

Although coatings by themselves may not be the one perfect answer to corrosion 
control, they are extremely effective when properly used. Most operators plan coatings 
and cathodic protection (CP) for all their pipelines as a matter of course. A properly 
selected and applied coating will provide all the protection necessary on most of the 
pipeline surface to which it is applied. On a typical well-coated pipeline this should be 
better than 99% and, along with the CP, should give total protection. 

It is not the intent of the chapter to make specific recommendations for coating ma- 
terials to be used. However, the capabilities and limitations of various pipeline coating 
materials will be discussed as well as desirable characteristics and how to get the most 
of any material used. Types of coatings now used on pipeline systems will be described 
briefly. 

NACE Standard RPO 169-96 Section 5: Coatings, is a comprehensive guide to pipe 
coatings, and is required reading for a better understanding of their importance. This 
Standard lists the following desirable characteristics of coatings: 

1 . Effective electrical insulator. Because soil corrosion is an electrochemical process, 
a pipe coating has to stop the current flow by isolating the pipe from its installed 
environment /electrolyte. To assure a high electrical resistance, the coating should 
have a high dielectric strength. 

2. Effective moisture barrier. Contrary to the theory that water absorption is good 
because it increases the effectiveness of CP, water transfer through the coating may 
cause blistering and will contribute to corrosion by prohibiting isolation. 

3. Applicability. Application of the coating to the pipe must be possible by a method 
that will not adversely affect the properties of the pipe and with a minimum of 
defects. 

4. Ability to resist development of holidays with time. After the coating is buried, two 
areas that may destroy or degrade coatings are soil stress and soil contaminants. Soil 
stress, brought about in certain soils that are alternately wet and dry, creates forces 
that may split or cause thin areas. To minimize this problem, one must evaluate the 
coating's abrasion resistance, tensile strength, adhesion, and cohesion. The coating's 
resistance to chemicals, hydrocarbons, and acidic or alkaline conditions should be 
known for evaluating their performance in contaminated soils. 

5. Good adhesion to pipe surface. The pipe coating requires sufficient adhesion to 
prevent water ingress or migration between the coating and the pipe, along with 
cohesion to resist handling and soil stress. Soil stress is the main cause of pipe coat- 
ing failure. "Soil stress effects can be seen on flexible PE coatings with elastomeric 
adhesives as a characteristic wrinkling. However, other types of coatings can fail 
by blistering fusion-bonded epoxy (FBE) or fatigue cracking coal tar enamel (CTE) 



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Effectiveness of Coatings as a Means of Corrosion Control 



that are exacerbated by soil movement resistance to shear must be combined 

with a measurement of the resistance of the backing material (or outer jacket) to 
deformation and tensile force. The two properties combine to determine the ability 
of a pipeline coating to resist damage to soil movement/' Soil stress resistance is 
measured by shear resistance, not by peel strength. 

6. Ability to withstand normal handling, storage (UV degradation), and installation. 
The ability of a coating to withstand damage is a function of its impact, abrasion, 
and flexibility properties. Pipe coatings are subject to numerous handlings between 
application and backfill. Their ability to resist these forces vary considerably, so those 
factors need to be evaluated to know if any special precautionary measure should be 
used. Ultraviolet rays can be very destructive to pipe coatings. Storage life may vary 
from 6 months to 5 years so resistance to ultraviolet is a very important consideration. 

7. Ability to maintain substantially constant electrical resistivity with time. The ef- 
fective electrical resistance of a coating per average square foot depends on the 
following. 

• Resistivity of the coating material 

• Coating thickness 

• Resistance to moisture absorption 

• Resistance to water vapor transfer 

• Frequency and size of holidays 

• Resistivity of the electrolyte 

• Bond or adhesion of coating 

If the effective resistance is unstable, the CP required may double every few years. It 
is easy to obtain misleading higher resistance measurements if the soil has not settled 
around the pipeline and if the moisture has permeated to any holidays in the coating. 
Experience is necessary to evaluate the validity of these resistance measurements and 
to use them for designing the CP system. 

8. Resistance to disbonding. Because most pipelines are cathodically protected, the 
coating must be compatible with CP. The amount of CP required is directly propor- 
tional to the quality and integrity of the coating. The negative aspects of CP are that it 
may drive water through the coating and that the interface bond surrounding a hol- 
iday may have a tendency to disbond. No coating is completely resistant to damage 
by CP. When large amounts of current are required, stray current and interference 
problems may arise. This emphasizes the importance of proper coating selection, 
application, and installation. 

9. Ease of repair. Because the perfect pipe coating does not exist, we can expect to make 
some field repairs as well as field-coating of the weld area. Check for compatibility 
and follow the manufacturer's recommendations. A field repair is never as good as 
the original coating. Tight inspection should be maintained. 

1 0. Nontoxic interaction with the environment. Some coating materials have been mod- 
ified, restricted, or banned because of environmental and health standards. Asbestos 
felts and primers with certain solvents have required substitution of glass rein- 
forcements and modification of solvents; changes in fusion-bonded epoxy powders 



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10 



Pipeline Coatings 



to eliminate carcinogenic agents have also been necessitated by health and envi- 
ronmental concerns. This has been a major influence of change on today's pipe 
coatings. 

In addition to the above characteristics, the following typical factors should be con- 
sidered when selecting a pipe coating. 

Type of environment 
Accessibility of pipeline 
Operating temperature of pipeline 

Ambient temperatures during application, storage, shipping, construction, and in- 
stallation 

Geographical and physical location 
Type of coating on existing pipeline 
Handling and storage 
Installation methods 
Costs 
Pipe surface preparation requirements 

Good practice in modern pipeline corrosion control work comprises the use of good 
coatings in combination with CP as the main lines of defense. Supplementary tactics, 
such as the use of insulated couplings and local environmental control may be used to 
reinforce these basic control methods. 

In selecting a coating system for a given pipeline project, one of the most important 
characteristics to design for is stability. By this we mean a coating combination that will 
have a high electrical resistance after the pipeline has been installed and the backfill 
stabilized and will lose the least electrical resistance over time. 

Those characteristics are important in any event but particularly so where CP is used 
to supplement the coating. When used with an unstable coating, a CP system that is fully 
adequate during the early life of a pipeline may no longer provide full protection as the 
coating deteriorates (as indicated by a reduction in the effective electrical resistance of the 
coating), which will require additional current. This means that continued expenditures 
will be necessary for additional CP installations. The overall economics of the coating- 
plus-CP concept are adversely affected by poor coating performance. 

In a review of 50 years of literature on pipeline coatings, the following concepts 
emerged: 

• Selection of the best coating and proper application are very important. 

• CP must supplement the coating for 100% protection. 

• In-the-ground tests are more reliable than laboratory tests. 

• Results of adhesion tests do not correlate with those of cathodic disbondment tests. 

• Cathodic disbondment tests are the best tests to measure coating performance. 

• The current required for CP is the best measure of coating performance. 



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Specifications 11 



• Optimum coating thickness is important. 

• Soil stress is one of the main problems. 

• Resistance to cathodic disbondment and soil stress are very important requirements 
of a pipe coating. For a pipe coating to be effective, it should meet these criteria: 
adhesion, adequate thickness, low moisture absorption /transfer, chemical resistance 
(especially alkalis from CP), and flexibility. 

• Selection of the best appropriate system is important, but proper application is the 
most important consideration. 

A major cause of pipeline coating failure is improper application. A quality material 
poorly applied is of little value, and the quality of a pipe coating is only as good as the 
quality of application. To assist in the evaluation of an applicator, the following points 
should be considered. 

1 . Experience. Research and trial and error have gone into the development of every 
coating, with close cooperation between applicator, coating manufacturer, equipment 
manufacturer, and customer. The transition from laboratory to production line is usu- 
ally a costly experience, which should not be ignored. 

2. Reputation. This is an asset earned by consistent performance. Not only good quality 
work but also solving problems and correcting mistakes help to develop a reputation. 

3. Reliability. Many variables affect the application of coatings. A reliable work force, 
well-maintained equipment, and consistent quality performance are prerequisites for 
an applicator. 

4. Conformance to the coating manufacturer's specifications. The manufacturer's es- 
tablished minimum specifications for application of materials should be met. 

5. Modern automated equipment. Capital expenditure on automated application equip- 
ment is an important part of the success of plastic coatings. Elimination of human er- 
rors through automation and controls continues to be an important factor in improved 
pipe coatings. 

6. Quality control. Conformance to specifications has to be checked regularly. Knowl- 
edge of the applicator's quality control procedures on materials, application, and 
finished product is essential in the selection of an applicator. 



SPECIFICATIONS 



Pipeline coating should not be attempted without rigid specifications that precisely spell 
out every step of the coating procedure to be used. Such specifications are necessary to 
ensure that the materials being used are applied in a manner that will permit develop- 
ment of the best coating of which those materials are capable. 

Because many materials may be used, no specific example of coating specifica- 
tions will be attempted here. Specifications can be prepared in accordance with the 



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12 Pipeline Coatings 



manufacturer's recommendations with such modifications as may be dictated by con- 
ditions applicable to the particular project and requirements of the pipeline system in 
which the coated pipe is to be used. 

Areas to be covered by specifications should include the following. 

• Cleaning the pipe surface 

• Priming, if required 

• The coating materials to be used and (if more than one material) the order in which 
they are to be applied 

• Total thickness with permissible tolerances 

• Specifications applicable to the particular materials to be used, such as application 
temperature and thickness, tension (for tapes or wrappers), and other items of a similar 
nature 

• Handling requirements for coating materials, such as storage provisions and mainte- 
nance of dry and clean conditions 

• Inspection requirements 

• Procedure for repair of coating defects 

• Basis for rejection of unacceptable coating 

• Requirements for handling and transporting the coated pipe 

• Details of coating field joints when factory coated pipe is used 

• Backfilling requirements 



INSPECTION PROCEDURES 



Once the coating system and applicator are selected, an important part of a quality 
installation is good inspection. Inspection should begin with the stockpile of bare pipe 
through coating operations, load out, coated pipe stockpile, field inspection, joint coating 
procedure, and backfill of coated pipe. Knowledge of the coating system, plant facilities, 
quality control methods, shipping requirements, handling, joint coating, field conditions, 
field holiday detection, and repair are requirements for proper installation. Experience 
and common sense in interpretation of specifications and analysis of test results will 
contribute to obtaining the best possible coating results. 

As a final backup to application supervision exercised by the coating inspector, usual 
pipelining practice includes a final test with a holiday detector (or "jeep"). This device 
impresses an electrical voltage across the coating. An electrode is passed over the entire 
coating surface and, as it passes over a coating defect, there is an electrical discharge 
between electrode and pipe. This discharge, or spark, actuates a signaling device, which 
warns the operator that a holiday has been detected. The operator marks the defect for 
the repair crew and continues. 

Refer to the proper NACE specification when examining for holidays: RP02-74 (latest 
revision) for the thicker coatings, or RP04-95 (latest revision) for the thinner coating 
systems. 



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Inspection Procedures 13 



Plant Holiday Inspection 



Pipe coated at a coating plant normally is passed through a holiday detector before 
shipment. Both mill-coated pipe and that coated over the ditch should be subjected to a 
final holiday test before being placed in the ditch. 

The fewer the defects in a coating which is to be repaired, the better the quality of the 
completed coating. Nevertheless, if all holidays are picked up by a detector in proper 
operating conditions, and if they are repaired to conform to an effective procedure, then 
the quality of the coating as it enters the ditch will at least approach an optimum. 



Field Holiday Inspection 



Several types of holiday detectors are suitable for field use at the pipeline construction 
site. The most common ones are usually battery operated and equipped with some type 
of pipe-encircling electrode. The electrode is arranged so that the ring may be pushed or 
rolled along the pipe by the operator, allowing the electrode to sweep all portions of the 
coating surface. 

The holiday detector should be operated in strict accordance with the manufacturer's 
instructions. The coating inspector should be sure the operator has been trained properly 
and is using the equipment correctly. Some practical operating procedures that apply to 
any type of holiday locator include the following. 

1 . Use only adequately charged batteries in battery-operated models. 

2. Use detectors that are set to operate at a voltage suitable for the coating being applied. 
Thick coatings require a high voltage to spark through at defects. On the other hand, 
too high a voltage may break down thin film coatings such as tapes or other thin 
plastic coatings. 

3. Verify periodically that the detector is operating properly. This may be done by 
purposely making a coating defect (such as a pinhole made with a knife) and pass- 
ing the detector over the hole. Failure to detect the hole properly indicates the need 
for prompt corrective adjustment. During production work, verification should be 
made at least twice a day and at such other times as the inspector may suspect poor 
performance. 

4. Keep the contact electrodes clean. A buildup of coating material on electrodes may 
interfere with efficient detection or even prevent it entirely. This possibility is greater 
with some materials than others. Where found to be a factor, keeping the electrodes 
clean of the insulating coating material must be insisted on. 

5. Maintain a good ground. To be complete, the detector circuit must contact the earth, 
with a trailing ground wire for example. This trailing wire should be checked for 
damage daily (or whenever faulty detector operation is suspected) and replaced or 
repaired if faulty. When working on long sections of line, there usually will be sufficient 



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Pipeline Coatings 



conductance between line and earth to permit adequate detector operation. On the 
other hand, a short length of well-coated pipe on dry skids may have to be grounded 
to the pipe to establish an adequate circuit. 



TYPES OF PIPELINE COATINGS 



The types of pipeline coatings and their characteristics are summarized in Table 2.1. 



Table 2.1 Types of Pipeline Coatings 



Pipe coating 



Desirable characteristics 



Limitations 



Coal tar enamels 



Mill-applied tape 
systems 



Crosshead-extruded 
polyolefin with 
asphalt/butyl 
adhesive 



Dual-side-extruded 
polyolefin with 
butyl adhesive 



Fusion-bonded 



Multi-layer epoxy/ 
extruded polyolefin 
systems 



80+ years of use 

Minimum holiday susceptibility 

Low current requirements 

Good resistance to cathodic disbondment 

Good adhesion to steel 

30+ years of use 

Minimum holiday susceptibility 

Ease of application 

Good adhesion to steel 

Low energy required for application 

40+ years of use 

Minimum holiday susceptibility 

Low current requirements 

Ease of application 

Nonpolluting 

Low energy required for application 

25 years of use 

Minimum holiday susceptibility 

Low current requirements 

Excellent resistance to cathodic disbondment 

Good adhesion to steel 

Ease of application 

Nonpolluting 

Low energy required for application 

35+ years of use 

Low current requirements 

Excellent resistance to cathodic disbondment 

Excellent adhesion to steel 

Excellent resistance to hydrocarbons 

Lowest current requirements 

Highest resistance to cathodic disbondment 

Excellent adhesion to steel 

Excellent resistance to hydrocarbons 

High impact and abrasion resistance 



Limited manufacturers 

Limited applicators 

Health and air quality concerns 

Change in allowable reinforcements 

Handling restrictions — shipping and installation 
UV and thermal blistering — storage potential 
Shielding CP from soil 
Stress disbondment 

Minimum adhesion to steel 

Limited storage (except with carbon black) 

Tendency for tear to propagate along pipe length 



Difficult to remove coating 
Limited applicators 



Exacting application parameters 

High application temperature 

Subject to steel pipe surface imperfections 

Lower impact and abrasion resistance 

High moisture absorption 

Limited applicators 

Exacting application parameters 

Higher initial cost 

Possible shielding of CP current 



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Enamels 



Types of Pipeline Coatings 15 



Bituminous enamels today are formulated from coal tar with a low carbon content, 
plasticized by the digestion of coal and heavy aromatic coal tar distillates followed by 
the addition of an inert mineral filler. Petroleum asphalts with select air-blown asphalts 
are still used internationally as a pipe coating but their use today in North America is 
almost nonexistent. 

The early coal tar enamel (CTE) coatings usually had an outerwrap of rag felt to 
provide a backfill shield. However, the rag felt did not prevent the tendency of the CTE 
to creep and cold-flow under soil stresses at the higher operating temperature range of the 
pipeline. The use of asbestos felt minimized this problem but the manufacture of asbestos 
wraps has been discontinued; resin-bonded glass fiber mats are being used at present. 
CTE systems have been used over 80 years, and a recently introduced two-component 
epoxy primer when used with special hot service enamel has increased the exposure 
temperature of a CTE coating system to 230 °F. Today an inner and outer glass fiber mat 
are incorporated into the CTE coating system simultaneously with the application of the 
hot CTE. The inner glass mat is pulled into the center of the coating. The outer glass 
mat is usually presaturated with coal tar to assist wetting and is pulled into the outer 
surface of the CTE. Extra-heavy-duty outer reinforcement wraps have been developed 
with woven glass filaments and resin-bonded glass mats to further guard against the 
effects of soil stresses. 

The use of CTE is not expected to increase in the future because of the increased 
acceptance of fusion-bonded epoxy (FBE), extruded polyolefin, and the FBE-polyolefin 
combination coatings; decreasing numbers of suppliers; and restrictive regulations. 

Extruded Asphalt Mastic 

Introduced over 75 years ago, this thick (1/2 to 5/8 in [1.2 to 1.6 cm]), dense mixture of 
select graded sand, crushed limestone, and glass fiber bound with an air-blown asphalt 
proved to be a prominent pipe coating. Its weight, cost, and limited availability, however, 
led to its manufacture being discontinued. 

Mill-Applied Tape Coating Systems 

Fabric-reinforced petrolatum-coated tapes were first used over 65 years ago. Polye- 
thylene tapes for pipeline coatings were introduced 46 years ago, and mill-applied 
tape systems were introduced 20 years ago. The mill-applied tape systems consist of 
a primer, a corrosion-preventative inner layer of tape, and one or two outer layers for 
mechanical protection. Concern regarding shielding of CP on a disbonded coating has 
led to development of fused multi-layer tape systems and also of a backing that will 
not shield CP. Environmental restrictions on solvent-based primers is being resolved by 



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16 



Pipeline Coatings 




Quench 



Electrical 



Inspection 



Stockpile 



Figure 2.1 Crosshead extruded polyolefin over asphaltic mastic application schematic. 



introducing environmentally acceptable primers. In spite of these limitations, the ready 
availability, ease of application, and cost mean the use of mill-applied tape systems 
will continue. 



Extruded Polyolefin Systems 



The first extruded polyolefin system was introduced in 1956 as a crosshead-extruded 
polyethylene over an asphalt mastic adhesive. Originally introduced for small-diameter 
pipe (up to 4 1/2 in [11.4 cm]), the material is now available for pipe up to 24 in (61 cm) in 
diameter; the most popular size is 16 in (40.6 cm). Recent improvements in the adhesive 
yield better adhesion, and selection of polyethylenes has increased stress crack resistance. 
Available with polypropylene for use at higher temperatures (up to 190°F [88°C]), these 
systems have been used in Europe since the mid-1960s, along with the side extrusion 
method for larger diameters through 60 in (152.4 cm). A copolymer adhesive is applied 
to eliminate cold flow and minimize shrink-back of the coating. This is followed by the 
application of an epoxy primer. In late 1972, the side-extrusion method was introduced 
in the United States. This is a dual-side extrusion, where the butyl rubber adhesive is 
extruded onto the pipe, followed by the polyethylene extrusion. Side extrusion can coat 
pipes as great as 145 in (368 cm) in diameter, the only restriction being cleaning and 
pipe-handling capacity. The extrusion process is a dependable production method with 
exacting controls. The extruder heats, melts, mixes, and extrudes the materials onto the 
steel pipe at the desired temperature and pressure. One may select the best polyolefin 
to meet the end-use requirements, and the process consistently produces holiday-free 



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Types of Pipeline Coatings 



17 




Figure 



Quench Electrical s^^ Inspection Stockpile 

2.2 Side extruded polyolefin over side extruded butyl adhesive application schematic. 



coatings. Extrusion systems are nontoxic and do not degrade air quality. Use of these 
systems will continue to grow because of handleability, moisture resistance, and overall 
consistent reproducibility. 



Fusion-Bonded Epoxy 



Fusion-bonded epoxy (FBE) coatings were first commercially available in late 1961. For 
many years they were available only on 3/4 to 8 5/8 in (1.9 to 21.9 cm) pipe but now 
are available in North America for pipe up to 48 in (122 cm) in diameter. For many 
years FBE was applied at 8-10 mil (203.2-254.0 /xm) to be more competitive with other 
coatings. At present, it is applied at 12 mil minimum up to 25 mil (304.8-635 /urn). Over 
the past 35 years, the resins have evolved through those requiring a primer and some 
requiring post application heat. None of the present epoxy pipe coatings require a primer, 
and most plant applications do not require post application heat. Most of the FBE pipe- 
coating powders have remained the same for the last 18 years. Newer dual-FBE systems 
were introduced in the early 1990s, to improve resistance to moisture absorption and 
abrasion. 

FBE coatings require great care to apply them properly. In addition to the NACE 
No. 2 near- white metal finish, a phosphate wash and demineralized water rinse have 
proven essential to remove potential chloride contamination and improve performance 
properties. Among the advantages of FBE is that it does not cover up any steel defects 
present, thus permitting inspection of the pipe after the FBE has been applied. Resistance 



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18 



Pipeline Coatings 




Cure Time 



Quench 
Figure 2.3 Fusion-bonded epoxy powder application schematic. 



Electrical Separators 

Inspection 



Stockpile 



to soil stress and cathodic disbondment has made FBE the most specified pipe coating 
in the United States. The trend is to thicker applications with 16 mil (406.4 ^m) being 
the norm. FBE will continue its prominence in the near future but will gradually share 
this position with improved extruded polyolefin coating systems and the multi-layer 
(FBE-extruded polyolefin) coating systems. 



Liquid Coating Systems 



Epoxy coal tars and urethanes are currently the most used liquid pipe-coating systems. 
They are applied in custom coating or modified plant systems, usually on larger-diameter 
pipes or ductile iron pipes that may not be compatible with existing pipe-coating plants. 
Specific manufacturers' specifications must be strictly followed with emphasis on surface 
cleaning, preparation, and times for cure and overcoat. 

These systems are constantly evolving. The largest growth has been in the use of 
urethane systems. 



Multi-Layer Epoxy/Extruded Polyolefin Systems 

First introduced in Europe in the mid-1960s as a hard adhesive under polyethylene, fol- 
lowed by the addition of an epoxy primer (FBE or liquid), multi-layer epoxy /polyolefin 



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Conclusion 



19 



d 




Preheat 




Blast Ctean Grind Surface 

Defects 



Surface 
Inspection 



— a~ r — g*^***.* 



■ 


■ 


I I 


■ ■ 


I J 


■ ■ 


i i 


■ ■ 


- - I 


m m 


I J 


■ ■ 


\ I 



Pofyolefin 
Copolymer 




FBE Application induction 
Heat 



Final Surface 
Treatment 



SESESL 



3* 



^ 



Quench 



Electrical 



P Inspection 



Stockpile 



Figure 2.4 3-Layer copolymer coating application schematic. 



systems are the most-used pipe-coating systems in Europe. These systems are now avail- 
able throughout the world. 



CONCLUSION 



In summarizing this chapter on coatings, pipeline corrosion engineers should stress two 
areas of knowledge: 

• Full information on all details of characteristics, performance, and limitations of the 
coatings considered for various pipeline projects. 

• As complete a summary as practical of the conditions existing along the route of 
proposed pipeline projects together with information on the manner in which the 
pipeline will be operated. 



When well informed in these matters, corrosion engineers will be able to advise 
management effectively in the selection of suitable protective coating systems. They also 
will be able to prepare application specifications and plan inspection programs that will, 
if effectively implemented, ensure getting the best possible coating job. 



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20 Pipeline Coatings 



BIBLIOGRAPHY 



J.D. Kellner, "Shear Strength Testing of Pipeline Coatings and Soil Stress/' Corrosion '96, paper 

no. 199 (Houston, TX: NACE, 1996). 

NACE Standard RP0169-92, Section 5, "Coatings" (Houston, TX: NACE, 1967). 

A.W. Peabody, Control of Pipeline Corrosion (Houston, TX: NACE, 1967). 

W. Roder, Personal correspondence to R.N. Sloan, Oct 3, 1997. 

R.N. Sloan, "50 Years of Pipe Coatings — We've Come a Long Way," Corrosion '93, paper no. 17 

(Houston, TX: NACE, 1993). 

R.N. Sloan and A.W. Peabody, Steel Structures Painting Council, Steel Structures Painting Manual, 

Vol. 1 (Pittsburgh, PA), 1982. 



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Chapter 



Cathodic Protection 
How It Works 



John A. Beavers 



Over the years, cathodic protection (CP) has continued to be treated as a somewhat 
mysterious term by those not fully conversant with this most useful means of corrosion 
control. Apparently, many feel that CP is a complicated procedure. In actuality, the basic 
idea of CP is very simple. Any complications arise during the application of this basic 
idea. Trained pipeline corrosion engineers, however, are equipped with the knowledge 
needed to apply the basic concept of CP to pipeline systems and to attain a very high 
level of effective corrosion control. 

In this chapter, a simple theory of CP is described. Factors involved in application 
as well as limitations that must be kept in mind also are outlined. A more detailed 
description of the theory of CP is provided in Chapter 16. 



BASIC THEORY OF CATHODIC PROTECTION 

As defined in Chapter 1, CP is a technique to reduce the corrosion rate of a metal surface 
by making it the cathode of an electrochemical cell. This definition is explained in greater 
detail here. 

Various conditions that cause pipeline corrosion are described in Chapter 1, and in 
greater detail in Chapter 16. In each case, anodic areas and cathodic areas are present 
on the pipe surface. At the anodic areas, current flows from the pipeline steel into the 
surrounding electrolyte (soil or water) and the pipeline corrodes. At the cathodic areas, 
current flows from the electrolyte onto the pipe surface and the rate of corrosion is 
reduced. 

In light of the above, it becomes obvious that the rate of corrosion could be reduced if 
every bit of exposed metal on the surface of a pipeline could be made to collect current. 

21 



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Cathodic Protection — How It Works 



BURIED 

EARTH CONNECTION 

(GROUND BED) 




INTERCONNECTING 
PIPELINE, CURRENT 
SOURCE, AND 
GROUND BED 



SOURCE OF DIRECT 
CURRENT ELECTRICITY 



SHADED AREA ON PIPELINE 
DENOTES ANODIC AREAS 
EXISTING PRIOR TO APPLICATION 
OF CATHODIC PROTECTION. 

Figure 3.1 Basic CP installation. 



DOTTED LINES REPRESENT 
CURRENT DISCHARGE 
FROM ANODIC AREAS 
WHICH HAS BEEN 
ELIMINATED BY 
CATHODIC PROTECTION. 



This is exactly what CP does. Direct current is forced onto all surfaces of the pipeline. 
This direct current shifts the potential of the pipeline in the active (negative) direction, 
resulting in a reduction in the corrosion rate of the metal. When the amount of current 
flowing is adjusted properly, it will overpower the corrosion current discharging from 
the anodic areas on the pipeline, and there will be a net current flow onto the pipe surface 
at these points. The entire surface then will be a cathode and the corrosion rate will be 
reduced. This concept is illustrated in Figure 3.1. A major activity of a CP engineer is to 
determine the actual level of CP required to reduce the corrosion rate to an acceptable 
level. Monitoring, in conjunction with the application of CP criteria, are used for this 
determination. Details of these activities are given in Chapters 4 and 5 of this book. 

If, as shown by Figure 3.1, current is forced to flow onto the pipe at areas that were 
previously discharging current, the driving voltage of the CP system must be greater 
than the driving voltage of the corrosion cells that are being overcome. The original 
cathodic areas on the pipe collect current from the anodic areas. Under CP, these same 
cathodic areas (which were corroding at a negligible rate in the first place) collect more 
current from the CP system. 



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Practical Application of Cathodic Protection 23 



For the CP system to work, current must be discharged from an earth connection 
(ground bed). The sole purpose of this ground bed is to discharge current. In the process 
of discharging current, the anodes in the ground bed are consumed by corrosion. It is 
desirable to use materials for the ground bed that are consumed at a much lower rate 
(pounds/per ampere/per year) than are the usual pipeline metals. This will ensure a 
reasonably long life for the anodes. Further discussion of ground-bed design is covered 
in Chapter 7. 



PRACTICAL APPLICATION OF CATHODIC PROTECTION 

With the simple theory of CP in mind, a preliminary discussion of the techniques of 
putting CP into actual use is given below. Details of each of these techniques are covered 
in later chapters. 

Cathodic Protection with Galvanic Anodes 

The corrosion cell resulting from contact of dissimilar metals is discussed in Chapters 1. 
In such a cell, one metal is active (negative) with respect to the other and corrodes. In 
CP with galvanic anodes, this effect is taken advantage of by purposely establishing a 
dissimilar metal cell strong enough to counteract corrosion cells normally existing on 
pipelines. This is accomplished by connecting a very active metal to the pipeline. This 
metal will corrode and, in so doing, will discharge current to the pipeline as shown in 
Figure 3.2. In the case of CP with galvanic anodes, CP does not eliminate corrosion; 
rather, it displaces corrosion from the structure being protected to the galvanic anodes. 
Under normal circumstances, the current available from galvanic anodes is limited. 
For this reason, CP by galvanic anodes normally is used where the current required 
for protection is small. Similarly, the driving voltage existing between pipe steel and 
galvanic anode metals is limited. Therefore, the contact resistance between the anodes 
and the earth must be low for the anodes to discharge a useful amount of current. This 
means that, for normal installations, galvanic anodes are used in low-resistivity soils. 
A normal installation, as considered here, is one in which the current from a galvanic 
anode installation is expected to protect a substantial length of pipeline. There are also 
instances where galvanic anodes are placed at specific points on a pipeline (often termed 
hot spots) and may be expected to protect only a few feet of pipe, especially where the line 
is bare. This is an application of the close anode concept, as discussed later in the chapter. 
Details of the design of galvanic anode installations are discussed further in Chapter 9. 

Cathodic Protection with Impressed Current 

To be free of the limited driving voltage associated with galvanic anodes, current from 
some outside power source may be impressed on the pipeline by using a ground bed and 



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24 



Cathodic Protection — How It Works 



WORKING GALVANIC 
ANODE OF ZINC OR 
MAGNESIUM BURIED IN 
EARTH AND CONNECTED 
TO PIPELINE WITH WIRE 
WILL DISCHARGE CURRENT 
AND PROTECT PIPELINE 
AS SHOWN. 



DRIVING VOLTAGE CAN BE 
DEMONSTRATED BY CONNECTING 
ANODE AND UNPROTECTED 
PIPELINE TO VOLTMETER AS 
SHOWN. TYPICALLY, PIPELINE 
COULD BE APPROXIMATELY 
1.0 VOLT POSITIVE TO 
MAGNESIUM ANODE AND 
0.5 VOLT POSITIVE TO 
ZINC ANODE. 




^ PROTECTED 
PIPELINE. 



UNPROTECTED 
PIPELINE. 



Figure 3.2 Cathodic protection with galvanic anodes. 



a power source. Figure 3.1 illustrates this situation. The most common power source is 
the rectifier. This device converts alternating current (AC) electric power to low-voltage 
direct current (DC) power. Rectifiers usually are provided with the means for varying 
the DC output voltage, in small increments, over a reasonably wide range. Although 
the maximum output voltage may be less than 10 V or close to 100 V, most pipeline 
rectifiers operate in the range between 10 and 50 V and can be obtained with maximum 
current outputs ranging from less than 10 A to several hundred amperes. This serves 
to illustrate the flexibility in choice of power source capacity available to the corrosion 
engineer when planning an impressed current CP system. 

Any other reliable source of DC electric power can be used for impressed current 
CP systems. Some of these are discussed in Chapter 10. Details of the design of rectifier 
installations are treated in Chapter 8. 



Criteria for Cathodic Protection 



Although the basic theory of CP is simple (impressing DC on a structure to reduce the 
corrosion rate), the obvious question that arises is: How do we know when we have 
attained adequate protection on a buried structure? The answer to this question is that 
various criteria have been developed over the years that permit a determination of 
whether adequate protection is being achieved. Those criteria in more common usage 
involve measuring the potential between the pipeline and earth. The measurement per- 
mits a rapid and reliable determination of the degree of protection attained. Basically, 



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Practical Application of Cathodic Protection 25 



potential criteria are used to evaluate the changes in structure potential with respect to the 
environment that are caused by CP current flowing to the structure from the surrounding 
soil or water. The potential measurement criteria, as well as other criteria, are discussed 
in detail in Chapter 4. 

The potential of a pipeline at a given location is commonly referred to as the pipe- 
to-soil potential. The pipe-to-soil potential can be measured by measuring the voltage 
between the pipeline and a reference electrode placed in the soil directly over the pipeline. 
The most common reference electrode used for this purpose is a copper-copper sulfate 
reference electrode, which is commonly given the acronym CSE. The potential is referred 
to as an on potential if the measurement is made with the CP system energized. The off 
or instant ojff potential estimates the polarized potential when the measurement is made 
within one second after simultaneously interrupting the current output from all CP 
current sources and any other current sources affecting that portion of the pipeline. See 
Chapters 4 and 5 for further details on potential measurements. 

Selection of Type, Size, and Spacing of a Cathodic Protection System 

Some of the questions to be resolved when planning a pipeline CP system include the 
following: 

1. Shall galvanic anodes be used or would an impressed current system be a better 
choice? 

2. How much total current will be required to attain adequate CP? 

3. What should be the spacing between installations, and what will be the current output 
required from each installation? 

4. What provisions should be made to permit testing the completed installation? 

5. Are there special conditions at certain locations that will require modifications in the 
general plan for CP? 

These questions cannot be answered using only material covered up to this point. 
The needed information that will influence the decision includes such items as: 

• The corrosivity of the environment; 

• The soil structure and resistivity; 

• Whether the pipeline is bare or coated; 

• If coated, the quality and electrical strength of the coating and the presence of envi- 
ronmental conditions that may cause the coating to deteriorate; 

• The metal or alloy used in the pipeline; 

• The size of the pipeline and its ability to conduct CP current; 

• The presence of metallic structures from other resources (usually termed foreign struc- 
tures) crossing or close to the pipeline to be protected; 

• The presence of stray current from man-made or natural sources. 



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26 



Cathodic Protection — How It Works 



As this list makes apparent, an appreciable quantity of information and data must 
be accumulated with respect to the pipeline for which CP is planned. Once reliable 
information is obtained in sufficient detail, answers to the questions posed earlier in this 
section can be developed and a sound engineering design can be prepared. Chapters 5 
through 12 are concerned with getting the needed data and using it in the CP design. 



Effect of the Coating on Cathodic Protection 

In the discussion of coatings in Chapter 2, it was stated that better than 99% of the 
surface of a well-coated pipe would be completely free of corrosion. Also, it was stated 
that CP would be relatively easy to apply because only minute areas of exposed steel 
would require protection. Let us look at these statements again and get an idea of their 
significance in terms of the amount of current that must be supplied for CP. 

Figure 3.1 illustrates the pattern of current flow that is expected for protection of 
a section of bare pipeline. The picture is quite different with a high-resistance barrier 
coating between the pipeline and the environment, as illustrated by Figure 3.3. 

In Figure 3.3, current from the CP ground bed is shown flowing to all areas where pipe 
metal is exposed. In so doing, the original corrosive current discharge from defects in 
anodic areas is reduced. In addition to the current shown flowing to defects, current also 
flows through the coating material itself. No coating material is a perfect insulator (even 
when absolutely free of any defects whatsoever) and will conduct some current. The 
amount will depend on the electrical resistivity of the material (expressed in ohm-cm) 
and its thickness. When a high-resistivity coating is used, the current passing directly 



GROUND BED 








Figure 3.3 Cathodic protection of a coated pipeline. 



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Practical Application of Cathodic Protection 27 



Table 3.1 Range of Current Required for Protection of 10 Miles 
of 36-in Diameter Pipe (under conditions stated in text) 

Effective coating resistance in ohms 

for one average square foot Current required in amperes 

Bare Pipe 3 500 

10,000 14.91 

25,000 5.964 

50,000 2.982 
100,000 1.491 

500,000 0.2982 

1,000,000 0.1491 

5,000,000 0.0298 

Perfect coating 0.000058 

a Bare pipe assumed to require a minimum of 1 mA/ft 2 . 

through the coating will be negligible compared with that flowing to coating defects 
unless the number and size of the defects are unusually small. 

Table 3.1 gives some idea of the CP current range that may be encountered. The 
current required to protect a 10-mile section of 36-in diameter pipeline is compared for 
a wide range of coating resistances, from bare pipe to a holiday-free coating 3/32 in 
thick with a resistivity of 1 x 10 13 ohm-cm. The pipeline section is assumed to be in soil 
having an average resistivity of 1 x 10 3 ohm-cm. The current required is that needed to 
cause a 0.3 V drop across the effective resistance between the pipeline and remote earth 
(polarization effects are neglected). 

The effective coating resistances given in Table 3.1 all could be obtained with the same 
coating for which the perfect coating current figure is given but with varying numbers 
of coating defects. For the examples used in the table, effective resistances of 1 x 10 4 to 
2.5 x 10 4 ohms for one square foot of coating reflect either poor handling and installation 
of the coated pipe or degradation of the coating after installation. For pipelines in 1 x 10 3 
ohm-cm soil, average resistances of 1 x 10 5 to 5 x 10 6 ohms for one square foot of coating 
indicate good to superior construction work and little or no degradation of the coating 
with time. 

The table shows that a bare pipeline can accept thousands of times more current 
than the same line with a superior coating. An ordinary two-cell flashlight bulb draw- 
ing ~0.5 A can take nearly 17 times as much current as that required to cathodically 
protect 10 miles of 36-in diameter pipe with a superior coating (5 x 10 6 ohms for one 
square foot). In contrast, the current required to protect a line with a poorly applied 
coating (2.5 x 10 4 ohms for one square foot) could be at least 200 times more than the 
current required if the same coating were applied and handled in a superior manner. 
The examples given are meant to stress a most important point. Because of the wide 
variation possible, the pipeline corrosion engineer must know the present condition of 
the coating on the pipeline before determining how much current will be needed from a 



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28 Cathodic Protection — How It Works 



proposed CP system. The engineer also must be able to estimate the rate of degradation 
of the coating so that the CP system can be designed to protect the pipeline as the coating 
degrades. 

Very long lengths of pipeline can be protected with a single CP system. For example, 
it is frequently possible to protect over 50 miles of cross-country pipeline from one 
location, if the pipeline has a large-diameter and is well coated. Oddly enough, it is 
easier to protect long lengths of large-diameter pipe than of small-diameter pipe from 
a single CP installation. In a CP installation such as that shown in Figure 3.1, current 
flow at any location on the pipe is inversely proportionally to the total resistance of the 
system at that location, based on Ohm's law. Once the current enters the mass of the 
earth from a ground bed, it is in a very low resistance conductor and theoretically will 
travel great distances if there is a suitable return conductor. In pipeline work, the pipe 
itself is the return conductor. For a given wall thickness, large-diameter pipe has a lower 
resistance than small-diameter pipe because the former has a larger cross-sectional area 
and the resistance of a conductor is inversely proportional to the cross-sectional area. 
Therefore, a larger-diameter pipe will permit extension of effective CP for substantially 
greater distances. It also follows, then, that better coatings cause less rapid buildup of 
current in the pipe and extend the distance of effective protection from a single CP 
installation. 



Over-Protection of Coated Lines 



Under some conditions, excessive amounts of CP current to a coated pipeline may dam- 
age the coating. This process is called cathodic disbondment. The current flow promotes 
water and ion migration through the coating and an increase in the electrolyte pH at the 
pipe surface. If the polarized potential is sufficiently negative, hydrogen can also evolve 
in the form of gas bubbles on the pipe surface. All of these processes are detrimental to 
coatings and promote degradation and disbondment. 

The polarized potential at which significant damage to a coating occurs is a function 
of many factors, including the inherent resistance of the coating to degradation, the 
quality of the coating application, the soil conditions, and the pipeline temperature. 
As a rule of thumb, off -potentials that are more negative than —1.1 V (CSE) should 
be avoided to minimize coating degradation. In this connection, it should be noted that 
damaging conditions can be created readily by an improperly adjusted impressed current 
CP system, and can sometimes result when using high-potential galvanic anodes such as 
magnesium, but seldom if ever will develop when using low-potential galvanic anodes 
such as zinc. 



Remote vs Close Ground Beds 



Flow of current from an external source to a pipeline (as is true when the pipeline is 
cathodically protected) will be accompanied by a potential difference between the earth 



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Practical Application of Cathodic Protection 29 



and the pipeline, the earth being positive (+) and the pipeline negative (— ). The potential 
difference is used in certain criteria for determining the degree of CP, as will be covered 
in Chapter 4. Developing the desired potential difference can be accomplished in either 
of two ways: 

• By making the pipeline negative with respect to remote earth, or 

• By making the earth positive with respect to the pipe in local areas. 

The first method uses remote ground beds, from which substantial lengths of pipeline 
can be protected. The second method uses close ground beds or anodes, which afford 
protection only in their immediate vicinity. 



Remote Ground Beds 



The sketch in Figure 3.1 may be used yet again to illustrate the remote ground bed type 
of installation. Current discharge, from an anode or group of anodes forming the ground 
bed, will cause voltage drops in the earth between points along lines radiating from the 
ground bed. Close to the ground bed, the voltage drop per unit of distance is relatively 
high. As one moves away from the ground bed, this voltage drop per unit of distance 
becomes less and less until a point is reached beyond which no further significant voltage 
drop can be observed. This point may be considered as remote earth and establishes the 
radius of what is termed the area of influence surrounding the ground bed. 

Exactly as described above, current flowing to the protected pipeline also will cause 
a voltage drop in the soil adjacent to the line, and there will be an area of influence 
surrounding the pipeline. The ground bed shown in Figure 3.1 may be said to be remote 
from the pipeline if it is far enough away such that there is no significant overlap between 
the area of influence surrounding the ground bed and the area of influence surrounding 
the pipeline. Under such conditions, current flows from the ground bed into the general 
mass of the earth, which may be considered a resistance-less, or infinite, conductor. Cur- 
rent will then flow from this infinite conductor to the pipeline to be protected and cause 
a voltage drop across the resistance between the pipeline and this infinite conductor. 
The simple equivalent circuit shown in Figure 3.4 illustrates this concept. Under these 
conditions, the pipeline will be made negative with respect to remote earth and, if made 
sufficiently negative, effective CP will result. 

With current flowing in an infinite conductor as illustrated, the resistance of the 
pipeline itself may limit the length of pipeline that can be protected from one ground bed. 
As described above, pipelines having lower incremental longitudinal resistances (large 
diameter lines) can have longer sections protected from one ground bed, other conditions 
being equal. A limitation at the most remote point from the ground bed is the minimum 
potential required for adequate CP. A limitation near the ground bed is the need to 
maintain the pipe-to-soil polarized potential at values that are less negative than about 
1.1 V (CSE) to avoid coating damage and hydrogen effects in susceptible steels. 



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30 



Cathodic Protection — How It Works 



GROUND BED 

(+ WITH RESPECT 
TO REMOTE EARTH). 




■PIPELINE 
INCREMENTAL 
PIPELINE 
RESISTANCE 



RESISTANCE, GROUND 
BED TO REMOTE 
EARTH. 

INFINITE (RESISTANCE- 
LESS) CONDUCTOR 
REPRESENTING REMOTE 
EARTH. 




+ 

POWER 
SOURCE 



■ INCREMENTAL 
RESISTANCE, 
PIPELINE TO 
REMOTE EARTH. 



Figure 3.4 Simple equivalent circuit of a pipeline with a re- 
mote ground bed. 



Close Ground Beds 



The use of close anodes, or a series of anodes, is quite different from the remote type 
of installation just described. Their successful use depends on the area of influence sur- 
rounding each ground bed anode as has been discussed in general terms. For a better 
understanding of how close anodes are used, the conductive path between a ground bed 
anode and remote earth is examined in greater detail. 

The current per unit of cross-sectional area of earth (current density) flowing away 
from a ground bed anode is highest close to the anode and decreases with distance. 
Where the current density is highest, the greatest point-to-point potential drops can be 
observed in the earth. The net result of this effect is that most of the potential drop to 
remote earth of a single anode normally is encountered within the first few feet. This is 
illustrated by Figure 3.5, which shows the percentage of the total resistance or potential 
drop (with respect to remote earth) as a function of distance from an anode that is 
discharging current. 

The curves in Figure 3.5 are based on a 3-in diameter x 60-in long anode discharging 
2 A of current in 1 x 10 3 ohm-cm resistivity soil. Other anode sizes will result in somewhat 
different shaped curves, but the one illustrated is typical. Non-uniform soil conditions 
also will change the shape of the curve. The curve is based on the following formula 
from Rudenberg (1945): 



V x 



o.038ip 1 (y + Vy 2 + x 2 ) 

ny ° Sl ° x 



(1) 



where: 



V x = Potential at x (see Figure 3.5) in volts caused by ground anode current 
I = Ground anode current in amperes 



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Practical Application of Cathodic Protection 



31 



100 



LU 
Q 

o 



j< DC 

cn \- 

LU LU 
DTLU 

DC . 

o >< 

LU . 

CD 5 

§1 

3 IE 

LL DC 

o < 



o o 

DC ^ 

LU LU 

D_ DC 



O 
DC 




2 3 

20 30 40 50 

DISTANCE "X" IN FEET 



Figure 3.5 Gradients at a ground bed anode. 



p = Earth resistivity in ohm-centimeters 
y = Length of anode in earth in feet 
x = Distance from anode in feet 



If x is greater than lOy, then 



Vr = 



0.0052Ip 



(2) 



Note that the same curve may be used to indicate the percentage of total voltage drop 
as well as resistance. This is because both properties are directly related through Ohm's 
law, which says that the voltage drop across a resistance is equal to the value of the 
resistance multiplied by the current flowing through it (volts = amps x ohms; V = IR). 
Therefore, if current flows from a ground anode to a point that is far enough away to 
include 50% of the total resistance of the anode to remote earth, then the voltage drop 
between the anode and that point will be 50% of the total voltage drop between the 
anode and remote earth. Further, it is important to note that the earth within the area 



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32 



Cathodic Protection — How It Works 



CIRCLES REPRESENT 
PERCENTAGE OF TOTAL 
ANODE POTENTIAL 
BETWEEN THAT POINT 
AND REMOTE EARTH. THESE 
ARE BASED ON CURVES 
FROM FIGURE 3.5. / 

' ANODE 



\ 



X 



POWER SOURCE. 
5 VOLTS IMPRESSED 
ON ANODE. 



\ SJ 



Ca 



X 



\ 



30 20 
/ / 

/ 



10 



I 

5% 

I 



\ 
EARTH POTENTIAL N 

CHANGE ADDED TO 
POTENTIAL TO EARTH 
OF PIPELINE BEFORE 
ANODE IS ENERGIZED. - 



\ 



/ 



LU 
I Q 

|f 
! a 
• erf 



_1 LJJ 03 

LU _l , 
\~ =) 

O co 

D_ 

DC 
LJJ LU 
0- D_ 

o 



1.5 



1.0 



0.5 



AREA OF 
— FULL — 



PIPELINE. POTENTIAL TO 
EARTH ASSUMED TO BE 
-0.5 VOLT BEFORE 
ENERGIZING ANODE. 



PROTECTION 




POTENTIAL AT 
WHICH PIPELINE 
WILL BE PROTECTED, 
-0.85 VOLT BETWEEN 
PIPE AND COPPER 
SULPHATE ELECTRODE 
DIRECTLY OVER LINE 
(SEE CHAPTER 4). 



DISTANCE ALONG PIPELINE-FEET 



Figure 3.6 

anode. 



Protective potentials impressed on a pipeline by a close ground bed 



of influence surrounding a current-discharging anode will be positive with respect to 
remote earth and the most-positive earth will be closest to the anode. Let's see how this 
positive potential gradient can be used to advantage. 

In the upper portion of Figure 3.6, it can be seem that a pipeline will pass through the 
area of influence surrounding a ground bed anode located close to the pipe. This means 
it will pass through earth that is at a positive potential with respect to remote earth. As 
shown in the potential plot in the lower half of Figure 3.6, there will be a limited area 
along the pipeline opposite the anode in which the net potential difference between the 
pipe and adjacent soil will, because of this effect, be sufficient to attain CP. This is in 
accord with the criterion for protection of steel (pipe-to-soil potential of at least —0.85 V 
[CSE]). For the analysis shown in Figure 3.6, it is assumed that the IR voltage drop error 
in the pipe-to-soil potential measurement is negligible. Where this assumption does not 
hold, the area of full protection will be smaller. A further discussion of criteria and their 
application is given in Chapter 4. 



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Practical Application of Cathodic Protection 33 



Figure 3.6 indicates that approximately 35 ft of the pipeline would be protected under 
the conditions given when 5 V are impressed on the anode. A galvanic anode will operate 
similarly, but because its voltage output is less (see Chapter 9), the length of pipeline 
protected likewise would be less. Typically, with anodes spaced 1 foot from the pipe, 
protection could be expected for 4 to 5 ft if using zinc anodes and 8 to 10 ft if using 
magnesium anodes. 

When only a few anodes are close to a large pipeline (particularly if uncoated), not 
enough current will be discharged from them to change the potential of the pipeline to 
remote earth to any appreciable degree. If, however, many such close anodes are used, 
enough current may be flowing to all portions of the line to make the line more negative 
with respect to remote earth. This would approach the results discussed previously for 
remote ground beds. 

The region of a pipe protected by a single anode is analogous to a flashlight beam 
that is shined on a wall. As the flashlight is moved closer to the wall, the area illuminated 
decreases but the light intensity increases (the light gets brighter). In this analogy, the 
brightness of the light is equivalent to the current flow to the pipe. The objective of 
optimizing a CP design is to select the type and location of the anode ground beds to 
deliver the optimum level of protection that covers the largest area of the structure. 

Electrical Shielding and Cathodic Protection 

An electrical shield can be defined as any barrier that will prevent or divert from a 
pipeline, for which protection is intended, the flow of CP current from soil or water. This 
electrical shielding can be of two types. One may result from a nonmetallic insulating 
barrier that prevents current flow. The other involves diversion of current to other metal- 
lic structures surrounding and in electrical contact with a pipeline to be protected. Each 
type will be discussed. 

Shielding by an Insulating Barrier 

Figure 3.7 illustrates a condition in which part of a coated pipeline is surrounded by a 
loose insulating barrier. The space between this barrier and the pipeline may be filled 
with earth or water. In the absence of CP, the exposed steel will be subject to corrosion if 
there are defects in the pipeline coating. If the pipeline is under CP, the protective current 
may not reach the exposed steel at coating defects under this barrier. 

One may argue that CP current could flow to the shielded coating defects through the 
soil or water between the insulating barrier and the pipeline. In fact, it can, but often not in 
sufficient amounts for protection. The amount of current reaching bare metal at a coating 
defect will be a function of the longitudinal resistance of the layer of soil or water between 
the shield and the pipe through which the current must flow. The closer the spacing 
between the shield and the pipeline, the higher the per-unit longitudinal resistance of 
the electrolyte (soil or water) because of a reduced cross-sectional area carrying the 



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34 



Cathodic Protection — How It Works 



SOIL, WATER, OR MIXTURE 
OF THE TWO, BETWEEN 
COATED PIPELINE AND 
INSULATING BARRIER 



INSULATING 
BARRIER 
'SURROUNDING 
PIPELINE. 




• COATING DEFECTS OUTSIDE 
INSULATING BARRIER — 
COLLECT CATHODIC 
PROTECTION CURRENT 
FREELY. 



COATING DEFECTS UNDER 
INSULATING BARRIER - 
REACHED BY LITTLE 
OR NO CATHODIC 
PROTECTION CURRENT. 



Figure 3.7 Electrical shielding by an insulating barrier. 



protective current. This means that the ability of electrical current to penetrate such 
spaces is not great. As a practical matter, one normally should not expect to force current 
into the space a distance greater than about 3 to 10 times the thickness of the layer 
between the shield and the pipeline. This figure is not rigorous but serves as a guide to 
the approximate relationships involved. 

The foregoing discussion applies to a completely insulating barrier. It need not com- 
pletely encircle the pipe, as is shown in Figure 3.7, but may partially shield an area, the 
way a large rock might. If the barrier is an insulating material but is sufficiently porous 
to absorb moisture and become conductive, enough current may pass to partially or 
completely protect the pipe at coating defects. Such a barrier would not, then, act as a 
complete shield. 



Shielding by Shorted Cased Crossing 

Figure 3.8 illustrates a common situation involving a metallic shield that diverts CP 
current from its intended path. This condition occurs at cased pipeline crossings where 
the casing is in metallic contact with the pipeline. In the example, water has accumulated 
between the casing and the pipeline but the metallic contact prevents CP of the pipe 
within the casing. 

With the short circuit in place, CP current collects on the outside of the casing and 
flows along the casing to the point of contact between the pipe and the casing. At the 
point of contact, the CP current flows to the carrier pipe through the metallic contact and 
then along the carrier pipe back to the CP installation. Under these conditions, essentially 
no CP current will flow through the casing wall to the pipe surface, leaving pipe inside 
the casing free to corrode even though the rest of the line is fully protected. 



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Practical Application of Cathodic Protection 



35 




CONNECTION REPRESENTING SHORT 
CIRCUIT (CONTACT) BETWEEN CASING AND 
PIPE, WHICH PREVENTS CATHODIC 
PROTECTION OF PIPELINE INSIDE CASING. 

CURRENT INTERCEPTED BY THE 
CASING FLOWS TO CARRIER PIPE THROUGH 
THE CONTACT AND RETURNS TO THE 
POWER SOURCE VIA THE CARRIER. 




INSULATING SPACER 



■n 



>o >o >o 



//////////////////////////////////////////////////////////////////////// T 



ssssssssss 

■///// /TTT 



/74?f£ 



CARRIER 
PIPE 



■ I / \ / / / ^X / \ / 




CURRENT FLOW 
FROM CATHODIC 
PROTECTION 
INSTALLATION 





SECTIONAL VIEW 



WATER 
ACCUMULATION 
BETWEEN PIPELINE 
AND CASING 



Figure 3.8 Electrical shielding by a shorted pipeline casing. 

If the casing pipe is free of a metallic contact with the carrier pipe (i.e., properly 
insulated), the metallic casing material simply serves as part of the conducting environ- 
ment. Cathodic protection current then is able to flow straight through the casing walls 
to those portions of pipeline in contact with any electrolyte inside the casing. It should 
be recognized that current discharging from the inner surface of the casing wall would 
corrode the inside of the casing. Furthermore, the level of protection of a cased carrier 
pipe will be less than that afforded an uncased carrier pipe, even in the absence of a 
short, because of the voltage drops across the metal-electrolyte interfaces on the ID and 
OD surface of the casing. For these reasons, it is important to keep the number and size 
of coating defects to a minimum on the carrier pipe within a casing. 

Figure 3.8 shows a pipeline in half-section as well as a casing installed with end seals 
and insulating spacers. The spacers and seals are intended to keep the casing completely 
free from metallic contact with the pipeline. This is not always accomplished. Contacts 
may develop from such conditions as the following: 



Improperly installed end seals 
Insufficient number of, or failed, spacers 
Crooked or out-of-round casing 
Curved carrier pipe 
Welding icicles inside the casing 



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36 Cathodic Protection — How It Works 



• Test point wiring (see Chapter 12) contacting the end of a casing or vent pipe 

• Metallic objects or scrap inadvertently left in the casing during construction 

Whatever the cause, the condition may be represented by a connection bond as shown 
in Figure 3.8. 

If the pipe inside the casing is coated perfectly or if the space between the pipe and 
casing is dry, there would be no corrosion problem other than atmospheric corrosion 
of exposed steel. These conditions are not likely to be present. Pipeline coatings are 
likely to be damaged when coated pipe is being pushed into a casing, and the longer the 
casing, the greater the probability of damage. Water sometimes enters the casing through 
defective end seals, or it can condense from air entering through the vents. Figure 3.8 
shows water in the space between the pipe and casing, as is found in a surprisingly large 
percentage of cased crossings. If the oxygen supply to the water accumulated inside a 
casing is restricted sufficiently, this will tend to slow the rate of corrosion. But failures 
do occur and when they do, repair is much more involved and expensive than at places 
where pipe is buried directly in earth along the right-of-way. The critical nature of cased 
crossings from the standpoint of safety hazards and repair difficulty justifies taking pains 
to ensure that pipe inside casings is protected properly. 

For new construction, cased crossings should be avoided whenever structural analy- 
ses indicate they are not needed and codes/regulations permit uncased crossings. Where 
the use of casings cannot be avoided, care must be exercised in selecting the proper ma- 
terials and design for casing spacers and end seals. 

Recent practices have incorporated pumping mortar /concrete into the annular space 
between the carrier pipe and the casing. This is a questionable practice because stresses 
may result in cracking of the concrete, potentially causing coating damage. At road 
crossings, chlorides from deicing salts may migrate to the areas of coating damage, and 
cause corrosion damage to the carrier pipe. 

On some pipeline systems, bare or poorly coated casing pipe is used on well-coated 
pipelines. If such casings are shorted to the line, there is a disadvantage in addition to 
the loss of protection on the pipe inside the casing. This is because a single bare cased 
crossing in contact with the coated pipe can absorb as much CP current as several miles of 
pipeline. Therefore, shorted casings impose an unnecessary load on the CP installations. 

Chapter 13 includes suggested procedures for clearing short circuits at cased cross- 
ings. Also, if the short circuit cannot be cleared because of inaccessibility, suggestions 
are given for corrosion-proofing the pipe inside the casing by methods other than CP. 

Shielding by Reinforcing Wire in Weight Coating 

A shielding action, similar to that encountered at a shorted cased crossing, can occur if 
reinforcing wire in concrete weight coating is accidentally in electrical contact with the 
pipe. The condition is illustrated in Figure 3.9. Although the reinforcing wire mesh or 
spiral wound wire does not form a solid shield as with a shorted cased crossing, the 
closely spaced wires can intercept most of the CP current if the wires are in electrical 



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Practical Application of Cathodic Protection 



37 



.JOINTS OF WEIGHT- - 
COATED PIPE FREE 
OF CONTACTS BE- 
TWEEN REINFORCING 
WIRE AND PIPE. 
CURRENT FLOWS 
THROUGH WEIGHT- 
COATING TO PIPE 
STEEL AND PIPE 

, IS PROTECTED. 



, JOINT OF WEIGHT-COATED PIPE 
WITH ACCIDENTAL CONTACT BE- 
TWEEN PIPE AND REINFORCING 
WIRE. WIRE INTERCEPTS AND 
COLLECTS CATHODIC PROTECTION 
CURRENT. PIPE IN ENTIRE JOINT I 
SHIELDED FROM EFFECTIVE / 

r CATHODIC PROTECTION. / 



r WEIGHT-COAT 



PROTECTIVE 
COATING - 




CATHODIC PROTECTION 
INSTALLATION 



Figure 3.9 Electrical shielding by shorted reinforcing wire in weight coating. 



contact with the pipe. Just one point of contact in a length of weight-coated pipe can 
shield the entire length. 

Wire reinforcement applied at a coating mill should not contact pipe steel. Further- 
more, particular care must be taken at field joints if reinforcing wire is applied to them 
after welding and coating. Careful inspection is necessary to ensure that wire is applied in 
such a manner that contact does not occur. This is very important because such contacts 
will reduce or completely nullify the beneficial effects of CP in their vicinity. 

Furthermore, in underwater installations, the weight-coated pipe will, for all practical 
purposes, be inaccessible for elimination of the contacts. To ensure that contacts do not 
exist, it is good practice to make resistance measurements between the pipe steel and 
wire mesh. Instrumentation and techniques for such measurements are discussed in 
Chapter 6. This problem can be completely avoided by using nonmetallic reinforcing 
wires in concrete weight coating. 



Shielding in Congested Areas 



Piping in congested areas, such as pumping stations and tank farms, may encounter 
a form of shielding that is the result of the close proximity of the underground metal 
structures. In Figure 3.10, a condition is represented wherein a network of piping in a 
restricted area is protected by a remote-type ground bed. The remote ground bed and 
suitably sized rectifier may change the potential of the entire structure sufficiently to 



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38 



Cathodic Protection — How It Works 



' GROUND 
BED 



REPRESENTATION 

OF CLOSELY 

SPACED PIPING 
NETWORK. 



D-C 
POWER 
SOURCE 



f± 



-1.5 



REFERENCE 

ELECTRODE 

CONTACTING 

SOIL AT 

ELECTRICALLY 

REMOTE 

EARTH. 




REFERENCE^ 

ELECTRODE 

CONTACTING 

SOIL IN 

CENTER OF 

CONGESTED 

AREA. 



Figure 3.1 Electrical shielding in congested areas. 



give an indication of full protection when measured with respect to a remote reference 
electrode, such as the —1.5 V indicated in Figure 3.10. But, if a measurement is made 
between remote earth and earth in the midst of the congested area, the potential of the 
whole earth mass in the area may have been changed as indicated by the —0.8 V reading. 
When this occurs, there may be relatively low potentials between the pipe and adjacent 
earth. This is indicated by the —0.7 V reading in Figure 3.10, which is less than full 
protection using the —0.85 V (CSE) criterion (see Chapter 4). The shielding effect will 
tend to be greatest near the center of the congested area. 

Conditions at each such congested area will determine whether or not the effect 
described in the preceding paragraph will be serious. The effect may not be important 
if all piping is well coated and if there are no other underground metallic structures 
(particularly uncoated ones) in electrical contact with the piping to be protected. In this 
situation, the protected pipe can polarize readily and the amount of current flowing in the 
earth within the congested area may not be sufficient to change the potential of the earth 
mass itself to any substantial degree. In an area such as a pumping station, however, 
there may be contacts with such things as the station grounding system, reinforced 
concrete foundations, the electrical system, tanks, and water piping. Total current flow 
to the area then may be enough to cause potential gradients in the earth, which will 
create the shielding effect described. If all bare piping (rather than coated piping) were 
used, the effect could be very severe. 

Where congested area shielding is a problem, it may not be practical to rely on a 
remote type of CP system. Cathodic protection still can be attained by the use of the 
close anodes discussed earlier in this chapter. Such anodes (either galvanic or impressed 
current) must then be distributed throughout the congested area in such a way that the 
areas of influence surrounding the anodes overlap sufficiently to permit development 



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Effectiveness of Cathodic Protection 



39 



of protective potentials on the entire interconnected structure. See Chapter 7 for further 
discussion. Chapter 9 also mentions the use of galvanic anodes for electrical grounding 
to help relieve the congested area shielding effects at pumping stations and similar 
areas. 



EFFECTIVENESS OF CATHODIC PROTECTION 
Stopping the Development of Pipeline Leaks 

That CP, properly designed and maintained, can control pipeline corrosion effectively 
on steel systems has been demonstrated in countless instances. Chapter 4 describes 
criteria for determining whether adequate corrosion control has been achieved. Chapter 5 
describes field-monitoring techniques required for the assessment of these criteria. 

The proof of the effectiveness of CP is most apparent where protection has been 
applied to old piping systems that had been developing leaks at a rapidly increasing 
rate. Suitable protection systems can stop the development of further leaks in dramatic 
fashion. Woody (Collection of papers on underground pipeline corrosion, Vol. IX) pro- 
vides an example of such results on a section of natural gas mains in Houston, Texas, 
which had been under protection for over 20 years. Reduction in the number of leaks 
was impressive, as shown in Figure 3.11. The curve shows that further leak development 
was stopped once CP was applied to the pipeline. This study was made on mains in cor- 
rosive soil, where leaks were becoming so numerous that abandonment was seriously 
considered prior to the decision to apply CP. Stetler (1980) reported a similar impressive 
reduction in the frequency of leaks on a cast iron water main after application of CP. 



150 

140 

130 

120 
£ 110 
< 100 
- 1 90 
S 80 H 
!< 70 
^ 60 
^ 50 
O 40 " 
30 
20 - 
10 




CATHODIC PROTECTION 
COMPLETED 



1930 1935 1940 1945 1950 1955 1960 1965 

YEARS 

Figure 3.1 1 Effectiveness of CP in stopping the development of leaks. 



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40 Cathodic Protection — How It Works 



Presence of Stray Current 



Where stray current corrosion is a factor, CP alone may not be the best method of con- 
trolling corrosion. The stray currents can be man-made or natural direct currents from 
sources other than galvanic corrosion cells on the pipeline itself. The applicability of CP 
depends to a great extent on the severity and degree of variation of the stray currents 
picked up and discharged by the pipeline. Low-level steady-state (static) currents or 
currents that vary within reasonable narrow limits may be controlled with CP systems. 
Larger stray currents, particularly those showing wide variation and reversals in di- 
rection of flow (dynamic stray currents), usually require special analysis and corrective 
measures, as discussed in Chapter 11. 



Aluminum Pipe 



Cathodic protection of aluminum pipe is a special problem, in that aluminum is sensitive 
to alkali (high-pH environments). As previously discussed, the cathodic reactions in a CP 
circuit generate alkali at the cathode surface. If too much CP is applied, the alkalinity at 
the surface of an aluminum pipe may become sufficient to break down the passive films 
on aluminum, resulting in significant rates of attack, even in the presence of CP. This 
process, sometimes termed cathodic corrosion, does not occur on iron or steel pipelines. 
The danger is that a buried aluminum pipeline under strong CP actually may corrode 
faster than it would if it had not been cathodically protected at all. 

Precise limitations for CP of aluminum pipe have not been established. Experience 
indicates that low-level CP can be beneficial. As a guide, the protective potentials on 
aluminum pipe should be maintained at a less negative value than about —1.00 to —1.10 V 
(CSE). Because of this limitation, the CP design for an aluminum pipeline generally 
requires greater care and precision than one for a steel pipeline. Criteria for effective CP 
of aluminum piping are discussed in greater detail in Chapter 4. 



EFFECT OF CATHODIC PROTECTION ON OTHER STRUCTURES 

It is quite possible to design a CP system for a pipeline that will protect the line, but, 
through stray current effects, may promote corrosion of neighboring underground metal- 
lic structures. It is important that the corrosion engineer be fully informed about con- 
ditions that can result in such adverse effects to these foreign structures. The designs 
can then minimize this possibility, and the engineer will know where to look for other 
structures that may be subject to damage. 

Corrosion damage to an underground structure caused by a CP system on another 
structure is commonly called interference. This is actually the result of a form of stray 
current corrosion. Corrective measures for such problems are treated in Chapter 11. This 



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Effect of Cathodic Protection on Other Structures 41 



form of stray current damage is most commonly associated with impressed current CP 
systems. Galvanic anode systems, because of their low voltage, are not as likely to cause 
trouble, but they are not completely free of the possibility 

One way to think of interference effects is to consider the earth between a ground bed 
and a pipeline under CP as one resistance path for the current flow. A foreign pipeline 
or other metallic structure forms a second resistance path, where the current can jump 
onto and off of the structure to complete the circuit. According to Ohm's law, the relative 
amount of current in the two paths is inversely proportional to the relative resistances 
of those paths. 

Another way to consider the problem of interference effects is to consider the voltage 
gradients associated with the flow of current in the earth. As previously described in 
this chapter, the resistance and voltage drops are directly related. A further discussion 
of the problem, with this in mind, follows. 

Foreign Pipelines Close to Cathodic Protection Ground Beds 

A CP ground bed installed too close to a foreign pipeline can be harmful. Two general 
conditions will be discussed. 



Case 1 



In Figure 3.12, a foreign pipeline is shown passing through the zone of positive earth 
potentials (area of influence) surrounding an impressed current ground bed and then 
crossing the protected pipeline at a more remote location. The positive earth potentials 
will force the foreign pipeline to pick up current at points within the area of influence. 
This current must then complete the electrical circuit and return to the negative terminal 
of the rectifier power source. Figure 3.12 illustrates this by showing most of the picked- 
up current flowing along the foreign line toward the point where the two lines cross and 
then leaving the foreign line in the vicinity of the crossing. This current is then picked 
up by the protected pipeline and returned to the rectifier. Where the current leaves the 
foreign line in the vicinity of the crossing, accelerated corrosion of the foreign pipeline 
occurs. 

Usually, a small amount of current will flow along the foreign pipeline in the opposite 
direction from the ground bed area. This is indicated as endwise current in the figure. This 
current will leave the foreign pipeline at remote locations, usually in areas of relatively 
low soil resistivity. The severity of the effect is largely a function of the impressed voltage 
on the ground bed and the proximity of the foreign pipeline to the ground bed. Where 
the impressed voltage is high and the foreign pipeline is close to it, current forced onto 
the foreign pipeline tends to be high and can cause damage. In such instances, the foreign 
pipeline can fail within a short time if corrective action is not taken. Aluminum and lead 
structures can suffer corrosion damage at both the pick-up and discharge points because 
of the mechanism described in the section on aluminum piping. 



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42 



Cathodic Protection — How It Works 




AREA OF INFLUENCE SURROUNDING 
GROUND BED. WITHIN THIS AREA 
SOIL POTENTIALS ARE POSITIVE 
(+) WITH RESPECT TO REMOTE 
EARTH. 



CURRENT FLOW 
FROM FOREIGN 
STRUCTURE TO 
PROTECTED LINE 
IN CROSSING 
AREA^ 



Figure 3.12 Foreign pipeline damaged by CP installa- 
tion — Case 1. 



In cases where the current pickup by the foreign pipeline is not too great, a metallic 
bond can be installed between the two lines as discussed in Chapter 11. However, severe 
cases may necessitate abandonment of the ground bed when an adequate bond between 
the two systems circulates so much of the rectifier current through the foreign pipeline 
that little is left for CP of the pipeline for which the CP system was installed. This 
emphasizes the need for care in selecting CP installation sites so that conditions such as 
these can be avoided. 



Case 2 



Figure 3.13 illustrates a condition where a foreign pipeline (or other buried metallic 
structure) closely approaches a CP ground bed but does not cross the protected pipeline. 
In this case, as in the preceding case, the foreign pipeline is forced to pick up current 
in the area of positive earth potentials surrounding the ground bed. Current will flow 
endwise along the foreign pipeline in both directions from the ground bed. This stray 
current must then leave the foreign pipeline in more remote areas (such as at areas of low 
soil resistivity) to flow to the protected pipeline and then back to the rectifier to complete 
the circuit. This means there may be many areas of current discharge and damage to the 
foreign pipeline rather than a single discharge area as in the preceding case. 

Corrective actions may include the use of bond cables from the foreign pipeline to the 
negative terminal of the rectifier or the installation of CP systems on the foreign pipeline 
to reverse the flow of endwise current, all of which are discussed further in Chapter 11. 
As in the preceding case, current pickup by the foreign pipeline may be so intense that 



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Effect of Cathodic Protection on Other Structures 43 



AREA OF INFLUENCE 
PROTECTED LINE. _ 



FOREIGN PIPELINE SURROUNDING THE 

NOT CROSSING S GROUND BED. 



X __ \ ENDWISE 
/ / Z^N \ C CURRENT FLOW. 
/ / X ^. \ , f > 







W 




CURRENT 
GROUND / DISCHARGE 
_BED / ^FROM FOREIGN 
y A PIPELINE IN 

REMOTE 

AREAS 



\ 

~\ RECTIFIER 



p \ \ 



^ PROTECTED PIPELINE 

Figure 3.1 3 Foreign pipeline damage caused by CP installa- 
tion — Case 2. 



correction of the condition may not be practical if the ground bed is too close to the 
foreign pipeline. The ground bed then may have to be abandoned. 

In selecting ground bed sites for impressed current systems, the presence of foreign 
pipelines, which could be adversely affected, must be carefully explored. In areas of high 
soil resistivity, where relatively high voltage rectifiers may be used, the area of influence 
surrounding a ground bed may extend for several hundred feet. Small units in low- 
resistivity soil will not create as extensive a problem. In any event, tests must be made 
by the corrosion engineer to assure that neighboring pipelines will not be damaged or, 
if there is some influence, that the possibility of damage can be corrected economically. 

In many major metropolitan areas, corrosion control coordinating committees reg- 
ularly meet to manage interfering systems. The corrosion engineer has an ethical re- 
sponsibility to inform and cooperate with representatives of neighboring facilities when 
designing and installing a potentially interfering source of stray current. Coordinating 
committees are discussed further at the end of this chapter. 

In the preceding sections, impressed current CP systems were used to illustrate stray 
current corrosion on foreign pipelines because these systems are most likely to promote 
this form of corrosion. The same conditions can be established with galvanic anodes but 
the anodes would have to be very close to the foreign pipeline for the line to pick up 
any appreciable portion of their output. This is because the area of influence surround- 
ing galvanic anodes is relatively small. Nevertheless, the corrosion engineer must make 
certain not to establish conditions that will lead to stray current corrosion, regardless 
of the type of CP system used. As with impressed current systems, care must be used 
in selecting galvanic anode installation sites; however, much closer spacing to foreign 
pipelines is permissible in most cases. Usually, a spacing of 15 ft would be ample, al- 
though the corrosion engineer should check for current pickup on foreign structures this 
close. Even closer spacing might be tolerated in instances where tests show that the area 
of influence surrounding the galvanic anodes is sufficiently limited. 



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44 



Cathodic Protection — How It Works 



Foreign Pipelines Crossing Bare Cathodically Protected Lines 

Earlier in the chapter, a potential gradient in the earth surrounding a cathodically pro- 
tected pipeline was mentioned. This gradient is caused by current flowing onto the 
pipeline from remote earth and is the reverse of the potential gradient or area of influ- 
ence surrounding a ground bed that is discharging current. As a result of this gradient, 
the earth in the immediate vicinity of the pipeline is negative with respect to remote 
earth. This is illustrated by Figure 3.14. 

The size of the area (zone) of influence around a protected pipeline is a function of the 
amount of current flowing to the line per unit area of pipe surface (current density). The 
greater the current density, the greater the zone of influence. For well-coated pipelines, 
the current is so small that potential gradients in the earth around the line are negligible. 
A cathodically protected bare line, however (or large holidays on coated lines), can collect 
so much current that substantial voltage drops can be measured in the earth around the 
line. A foreign pipeline or other buried metallic structure crossing the protected bare 
line will pass through the potential gradient region and be subject to possible corrosion 
damage. This is illustrated by Figure 3.15. 

Within the potential gradient region, the foreign pipeline tends to become positive 
with respect to adjacent soil. This is most pronounced at the point of crossing. The voltage 
difference between pipe and earth can force the foreign pipeline to pick up CP current in 
electrically remote sections and discharge it to the protected line in the crossing area. The 
foreign pipeline will be damaged by such discharge to earth, with the point of greatest 
probable damage being directly at the point of crossing with the protected bare line. 




Figure 3.1 4 Potential gradients in earth around cathod- 
ically protected pipeline. 



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Effect of Cathodic Protection on Other Structures 



45 



FOREIGN LINE TENDS 

TO BECOME POSITIVE 

TO SOIL WITHIN AREA 

OF INFLUENCE AND 

IS FORCED TO DISCHARGE 

CURRENT 



■ MOST INTENSE CURRENT 
DISCHARGE AND GREATEST 
CORROSION DAMAGE TO 
FOREIGN LINE IS NORMALLY 
AT POINT OF CROSSING. 




FOREIGN 
^ PIPELINE 



/T?^S^T 



CURRENT [ 

PICKED UP , "l I \ v 



BY FOREIGN 
PIPELINE \ \ 



OUTSIDE AREA\ \ 
OF INFLUENCE ^ \ 




^ AREA OF 
\* INFLUENCE 

SURROUNDING 

PROTECTED 

PIPELINE. 



Figure 3.15 Effect on foreign pipeline passing through earth 
potential gradients around cathodically protected bare line. 



A foreign pipeline can develop leaks in a short time in extreme instances. If the 
foreign pipeline happens also to be too close to an impressed current ground bed on 
the protected line, as previously discussed, the two effects are additive and the rate of 
corrosion at the point of crossing with the protected line will increase. Damage to the 
foreign pipeline can occur even if it has a CP system of its own. This takes place if the 
potential gradients surrounding the cathodically protected bare line are strong enough 
to offset the protective potential on the foreign pipeline and force it to discharge current 
(and accelerate corrosion) at the point of crossing. 

If the foreign pipeline had a perfect coating, there could be no current discharge and 
no corrosion despite the existence of potential gradients where it passed through the 
zone of influence around the cathodically protected bare line. This, however, is unlikely 
for typical pipeline coatings and field conditions. Even a single coating defect within the 
gradient can cause a leak. The rate of penetration would tend to increase with increasing 
coating quality because the current discharge would be concentrated at smaller breaks 
in the coating. 

The existence of a possibly damaging effect on a foreign pipeline at a point of crossing 
can be ascertained readily. This is accomplished by measuring potentials between the 
foreign pipe and a close electrode located directly over the foreign line. The measure- 
ments are obtained at close intervals because the rate of potential change, point-to-point, 
can be quite rapid. Thus, these measurements simply comprise a close interval survey 
of the foreign line in the area near the crossing of the two pipelines. Typically, the plot- 
ted result will look like Figure 3.16. This figure illustrates the effect on a cathodically 
protected foreign pipeline and shows a severe potential dip at the point of crossing. 



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46 



Cathodic Protection — How It Works 





(-) 


> 

Q 
LU 


< 






V 


CTr> 








._ + -.!.!. i \. .!. 


LU 




Q 

o o 

P DC 


1 A 


FOREIGN-^ PROTECTED -*0 


LU 

h- w 

2^ 

LU ^ 
^3 
- 1 CO 
LU 

D- DC 

Q_ LU 

D_ 

CD O 
Dj ° 

DC ljj 
O CO 




O 

LU 

h- 

n 




LINE BARE LINE 
AREA OF 




CC 
Q_ 




POSSIBLE DAMAGE 










- 


Q 
LU 

h- 

o 

LU 

h- 

o 

DC 
D_ 


"\: 


-0.85 VOLT ^\ /S 

^ POINT OF CROSSING 




(+) 


3 




WITH PROTECTED 




U- O 




i 


p 


BARE LINE. 




O 













DISTANCE IN FEET ALONG FOREIGN LINE 

Figure 3.1 6 Pipe-to-soil potentials on foreign pipeline pass- 
ing through area of influence around cathodically protected 
bare line. 



Damage to the foreign pipeline would be expected unless its coating is perfect. Such 
a plot clearly identifies the length of foreign pipeline affected. The length of foreign 
pipeline subject to depressed potentials can vary from just a few feet in mild cases to 
hundreds of feet when the potential gradients are severe and the angle between the 
two crossing lines is small. Other factors being equal, the amount of foreign pipeline 
subjected to depressed potentials is least for a right-angle crossing. 

If there is any question that the potential dip is caused by the CP system on the bare 
pipeline, the CP current sources can be turned off and the potential measurements along 
the foreign pipeline repeated. If the dip disappears, or nearly so, this is adequate proof 
that the CP system on the bare line is the cause of the trouble. 

Corrective measures are discussed in Chapter 11. Metallic bonds are suitable in some 
instances. In other cases, the bare, cathodically protected pipeline may be coated in the 
vicinity of the crossing to reduce the intensity of potential gradients by locally reducing 
the amount of current flow to the pipeline per unit area. Galvanic anodes can be used to 
advantage where conditions are favorable, as described in Chapter 11 in the subsection 
on use of galvanic anodes. 



Sources of Information on Interference 



It is desirable, and usually saves considerable time, to seek the help of a corrosion coor- 
dinating committee when a pipeline is being installed in an area in which a committee 
exists. Corrosion coordinating committees are made up of representatives from many of 



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References 47 



the principal owners of underground metallic structures in an area (usually a metropoli- 
tan district where many pipelines cross) that work cooperatively to solve their corrosion 
problems. Many of these committees have been in existence for decades and have accu- 
mulated useful data, maps, and other information that will help avoid the destructive 
effects associated with interfering CP systems. These committees can assist in locating 
underground structures in the area, ascertaining the extent and nature of existing CP 
systems, and making cooperative surveys or cooperative contracts for protection. 



REFERENCES 



R. Rudenberg, Grounding Principles and Practices, I — Fundamental Considerations on Ground 
Currents, Electrical Engineering, January 1945. 

F.E. Stetler, Accelerating Leak Rate in Ductile Cast Iron Water Mains Yields to CP, Materials Perfor- 
mance, Vol. 19, No. 10, October 1980. 

C.L. Woody, Is 0.85 Volts to Cu/CuS0 4 the Only Criteria for Protection? Collection of papers on 
Underground Pipeline Corrosion, Vol. IX, Library of Congress Catalog Number: 59-54031. 



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Chapter 



Criteria for Cathodic 
Protection 

John A. Beavers and Kevin C. Garrity 



In Chapter 3, the theory and principles of how cathodic protection (CP) works were 
presented and discussed. To assure that CP is applied in accordance with these principles, 
criteria and methods of assessment are required. This chapter describes the industry- 
accepted criteria, and Chapter 5 describes the survey methods and techniques used to 
assess whether the criteria are met. The discussion below is a review of the NACE criteria 
presented in NACE Standard RP-01-69 (1996 Revision) Control of External Corrosion of 
Underground or Submerged Metallic Piping Systems. This document lists criteria and other 
considerations for CP that will indicate, when used either separately or in combination, 
whether adequate CP of a metallic piping system has been achieved. The document states 
that the corrosion control programs are not limited to the primary criteria listed: "Criteria 
that have been successfully applied on existing piping systems can continue to be used 
on those systems. Any other criteria used must achieve corrosion control comparable to 
that attained with the criteria herein," referring to the three primary criteria described 
below. Other criteria that have been used for underground piping include the 300 mV 
shift criterion, the E-log I criterion, and the net current flow criterion. 

CRITERIA FOR STEEL AND CAST IRON PIPING 

Three primary criteria for CP of underground or submerged steel or cast iron piping are 
listed in Section 6 of NACE Standard RP-01-69 (1996 Revision): 

1 . -850 mV (CSE) a with the CP applied, 

2. A polarized potential of -850 mV (CSE) 

3. 100 mV of polarization. 

Saturated copper-copper sulfate reference electrode. 

49 



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50 Criteria for Cathodic Protection 



A fourth criterion, the net protective current criterion, is also listed in Section 6 under 
a special conditions section, for bare or poorly coated pipelines where long-line corrosion 
activity is the primary concern. The application and limitations of each are given below. 



-850 mV with Cathodic Protection Applied Criterion 

The full criterion states that adequate protection is achieved with: 

a negative (cathodic) potential of at least 850 mV with the CP applied. This 
potential is measured with respect to a saturated copper/ copper sulfate 
reference electrode contacting the electrolyte. Voltage drops other than 
those across the structure-to-electrolyte boundary must be considered for 
valid interpretation of this voltage measurement. Consideration is under- 
stood to mean application of sound engineering practice in determining 
the significance of voltage drops by methods such as: 

• measuring or calculating the voltage drop(s), 

• reviewing the historical performance of the CP system, 

• evaluating the physical and electrical characteristics of the pipe and its 
environment 

• determining whether or not there is physical evidence of corrosion. 



Applications 



Of the three primary criteria listed above, the first, —850 mV criterion with CP applied, 
is probably the most widely used for determining if a buried or submerged steel or cast 
iron structure has attained an acceptable level of CP. In the case of a buried steel or 
cast iron structure, an acceptable level of protection is achieved, based on this criterion, 
if the potential difference between the structure and a CSE contacting the soil directly 
above and as close as possible to the structure is equal to or more negative than (larger 
in absolute value) —850 mV. As described above, voltage drops other than those across 
the structure-to-electrolyte boundary must be considered for valid interpretation of this 
voltage measurement. These voltage drops are a result of current flow in the electrolyte 
(soil) and are generally referred to as ohmic or IR voltage drops. IR voltage drops are 
more prevalent in the vicinity of an anode bed or in areas where stray currents are present 
and generally increase with increasing soil resistivity. 

For bare or very poorly coated structures, IR voltage drops can be reduced by placing 
the reference electrode as close as possible to the structure. For the majority of coated 
structures, most of the IR voltage drop is across the coating, and the measurement is less 
affected by reference electrode placement. The IR voltage drop can also be minimized 
or eliminated by interrupting all of the direct current sources of the CP system and 
measuring the instantaneous off-potential. Details on this measurement technique are 
given in Chapter 5. The off -potential will be free of the IR voltage drop errors if all of the 



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Criteria for Steel and Cast Iron Piping 51 



current sources, including sources of stray currents, have been properly interrupted and 
if long-line currents are negligible. Long-line currents occur on a structure as a result of 
the presence of macro-cells, as described in Chapter 1 and Chapter 16. The difference 
between the on- and the off-potential indicates the magnitude of the IR voltage drop 
error when the measurement is made with the protective current applied. 

This criterion was originally adopted based on the observation that the most negative 
native potential observed for coated underground steel structures was about —800 mV 
(CSE). The assumption was made that macro-cell corrosion would be mitigated if suffi- 
cient CP current were applied to raise (in the negative direction) the potential of the entire 
structure to a value that is more negative than the native potential of the local anodic 
sites. A potential of —850 mV was adopted to provide a 50 mV margin of protection. The 
effectiveness of the criterion has been demonstrated over many years of application. 



Limitations 



This criterion has a number of limitations. The potential reading should be taken with 
the reference electrode contacting the electrolyte directly over the structure, to minimize 
ohmic voltage drop errors in the measurement and to minimize the extent of averaging 
over large areas of the structure. Alternative criteria may be required where the refer- 
ence electrode cannot be properly placed, such as at river crossings or road crossings. 
The criterion also is most commonly used for well-coated structures, where it can be 
economically met. For poorly coated or bare structures, the high CP currents required to 
meet this criterion can be prohibitive, such that alternative criteria are typically used. 

Potentials can vary significantly from one area of an underground structure to another 
as a result of variations in soil conditions, coating damage, interference effects, etc. This 
creates the possibility that potentials less negative than —850 mV (CSE) exist between 
the measurement points. This problem can be addressed for pipelines by means of close- 
interval surveys, as described in Chapter 5. If the close-interval survey establishes that 
this problem exists, one should maintain more-negative potentials at the test stations to 
ensure that adequate protection is achieved on the entire structure. However, the more 
negative potentials required will result in increased power consumption. 

Potentials more negative than —850 mV (CSE) also are required in the presence of 
bacteria or with a hot pipeline. In the latter case, the current required for CP can increase 
by a factor of two for every 10°C (18°F) increase in temperature of the pipe. The potential 
criterion is adjusted to compensate for the increased anodic current kinetics. Typically, a 
potential of —950 mV (CSE) is used for hot pipelines. In the case of microbes, the kinetics 
of the corrosion reaction and the environment at the pipe surface are altered such that a 
more-negative potential is typically required to mitigate corrosion. Where the presence 
of microbes is confirmed or suspected, a minimum potential criterion of —950 mV (CSE) 
is typically used. A more detailed discussion of microbially influenced corrosion (MIC) 
and CP is given in Chapter 14. 

Care should be exercised to avoid overprotection, which can result in coating dam- 
age and may promote hydrogen damage of susceptible steels. The potential above which 



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52 Criteria for Cathodic Protection 



coating damage can occur is a function of many variables, including the soil composi- 
tion and moisture content, the temperature, the coating type, the quality of the coating 
application, and the presence of microbes. The general consensus in the industry is to 
avoid polarized (instant off) potentials more negative than —1.05 to —1.1 V (CSE). 

The older steels generally contain higher levels of impurities, such as sulfur and 
phosphorus, and exhibit greater susceptibility to hydrogen damage than do the newer, 
cleaner steels. In the older steels, the microstructures associated with hard spots and 
welds typically are more susceptible to hydrogen damage than is the microstructure 
of the wrought base metal. Again, the general consensus in the industry is to avoid 
polarized (instant off) potentials more negative than —1.05 to —1.1 V (CSE) to minimize 
hydrogen damage in these steels. 

Potentials also can vary seasonally as a result of variation in the soil moisture content. 
Thus, some pipeline companies perform annual surveys at the same time each year, so 
that trends in the behavior of a pipeline can be properly interpreted. This approach does 
not, however, preclude the possibility that the criterion is not being met on some parts 
of the structure during portions of the year. 

Limitations also exist in the ability to accurately measure the potential of the struc- 
ture in the presence of telluric currents or where shielding by disbonded coatings, rocks, 
thermal insulation, etc., has occurred. Similarly, the accuracy of the potential measure- 
ment is compromised by stray currents that cannot be interrupted or by the presence of 
multiple pipelines in a right-of-way where the pipelines have varied coating conditions. 

Dynamic stray currents, from sources such as DC transit systems and mining activi- 
ties, pose a significant challenge in applying this criterion. Where dynamic stray currents 
are suspected, it is generally necessary to obtain potential values over the duration of 
the stray current activity, typically for twenty-four hours or longer. For example, for DC 
transit systems, it is often possible to obtain fairly stable on-potentials of the structure in 
the early morning hours when the transit system is not operating. These potentials can 
provide baseline data for use in evaluating other measurements. Of course, appropri- 
ate interpretation of such data is required. DC stray currents not only affect the ability 
to obtain accurate off -potentials, but also influence the polarized potential of the pipe. 
Nevertheless, the —850 mV criterion with CP applied is the criterion most commonly 
used in areas of significant dynamic stray current activity. It is generally accepted that 
the structure is protected at a test location if the potential of the structure remains more 
negative than —850 mV (CSE) at all times, even with significant fluctuations associated 
with the dynamic stray currents. It may be necessary to increase the number of test points 
and the frequency of surveys in areas of dynamic stray DC currents. 

Polarized Potential of —850 mV Criterion 

This criterion states that adequate protection is achieved with "a negative polarized 
potential of at least 850 mV relative to a saturated copper/copper sulfate reference 
electrode." The polarized potential is defined as the "potential across the struc- 
ture/electrolyte interface that is the sum of the corrosion potential and the cathodic 



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Criteria for Steel and Cast Iron Piping 



53 



-1200 



-ST -1100 

(0 

3 
(J) 



<D - 
Q. 
Q. 
O 
O 
i_ 
<D 
Q. 
Q. 
O 

o 

> 
E 



-1000 



-900 



-800 






Z -700 

D. 



-600 



-• — On Potential, mV 
-■- Off Potential, mV 
-♦ — Native Potential, mV 
-x- -850 mV Criterion 








50 



100 



250 



300 



150 200 

Distance, Meters 
Figure 4.1 Close interval survey data showing on, off, and native potentials. 



350 



polarization." The polarized potential is measured directly after the interruption of all 
current sources and is often referred to as the off- or instant off-potential. The difference 
in potential between the native potential and the off or polarized potential is the amount 
of polarization that has occurred as a result of the application of the CP. As previously 
stated, the difference in potential between the on-potential and the off-potential is the 
error in the on-potential introduced as a result of voltage drops in the electrolyte (soil) 
and the metallic return path in the measuring circuit. Typical close interval survey data 
showing these potentials are given in Figure 4.1. 



Applications 



This second criterion is more direct than the —850 mV criterion with CP applied by clearly 
defining the method by which voltage drops errors in the on-potential are considered. 
In the second criterion, these errors are minimized or eliminated. The voltage drop 
errors, which are often referred to as ohmic potential drop or IR drop errors, occur as a 
result of the flow of CP or stray current in the electrolyte (soil) or in the structure. They 
are measurement errors because the cathodic polarization at the structure-to-electrolyte 
interface is the only part of the on-potential measurement that contributes to a reduction 
in the rate of corrosion of the structure. As described above, polarization is defined as the 
difference in potential between the native potential and the off- or polarized potential; 
it is referred to as cathodic polarization if the potential shift is in the negative direction. 



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54 Criteria for Cathodic Protection 



This criterion is most commonly applied to coated structures where the sources of DC 
current can be readily interrupted. An example would be an FBE-coated gas transmission 
pipeline in a rural area with an impressed current CP system. 



Limitations 

An important limitation of this criterion is the requirement that all sources of DC current 
be interrupted. For standard survey techniques, the interruption must be performed 
simultaneously on all current sources. On gas transmission pipelines, interrupting all 
current sources may require the use of a large number of synchronous interrupters for 
all rectifiers, sacrificial anodes, and bonds affecting the section of pipeline that is being 
evaluated. In some cases, the number of rectifiers affecting a test section is not known 
without experimental verification. On gas distribution systems, sacrificial anodes are 
more commonly used for CP and the electrical leads for the anodes are usually bonded 
directly to the pipe with no means available to interrupt the current. For those situations, 
this criterion cannot be used. Achieving the criterion also may require the application 
of high CP currents, resulting in overprotection of some portions of the structure and 
related problems such as cathodic disbondment of coatings and hydrogen embrittlement 
of susceptible steels. As described above, a potential more negative than —850 mV (CSE) 
may be required to mitigate corrosion on hot pipelines or in the presence of MIC, further 
increasing the likelihood of overprotection. 

Many of the difficulties of accurately measuring pipe-to-soil potentials that were de- 
scribed under limitations to the —850 mV criterion with CP applied apply to the polarized 
potential of —850 mV criterion as well. These include access to the structure, seasonal 
fluctuations in the potential between testing times, spatial fluctuations in potential be- 
tween test stations, the presence of multiple pipelines with different levels of coating 
quality in a right-of-way, telluric current effects, and shielding of the structure surface 
by disbonded coatings, rocks, and thermal insulation. 

100 mV of Polarization Criterion 

This criterion states that adequate protection is achieved with "a minimum of 100 mV 
of cathodic polarization between the structure surface and a stable reference electrode 
contacting the electrolyte. The formation or decay of polarization can be measured to 
satisfy this criterion/' Of the three criteria, this criterion has the most sound fundamental 
basis. As described in Chapters 3 and 16, the corrosion rate decreases and the rate of 
the reduction reaction on the metal surface increases as the underground structure is 
polarized in the negative direction from the native potential. The difference between the 
corrosion rate (expressed as a current) and the rate of the reduction reaction is equal 
to the applied CP current. These processes can be shown graphically in a diagram of E 
versus log I, referred to as an Evans diagram (see Chapter 16). The slope of the anodic 



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Criteria for Steel and Cast Iron Piping 55 



(corrosion) reaction is referred to as the anodic Tafel slope and typically has a value of 
~100 mV per decade of current. With this Tafel slope, the corrosion rate of a structure 
decreases by a factor of 10 (an order of magnitude) for every 100 mV cathodic shift 
in the polarized potential. An order of magnitude decrease in the corrosion rate of an 
underground structure typically is more than adequate to effectively mitigate corrosion. 

The cathodic polarization also promotes beneficial changes in the environment at the 
pipe surface, such as reducing oxygen, increasing the pH, and moving halides such as 
chlorides away from the metal surface, which further decreases the corrosion rate. These 
beneficial changes in the environment at the metal surface are referred to as environmen- 
tal polarization, in that the environmental changes typically result in a shift in the free 
corrosion potential of the pipe in the negative direction. Thus, the total potential shift 
from the native potential (excluding IR voltage drops in the soil) includes components 
attributable to environmental polarization and cathodic polarization. 

As described in the criterion, the magnitude of the polarization shift can be deter- 
mined by measuring its formation or decay. To determine the magnitude of the shift as 
a result of the formation of polarization, one must first determine the native potential 
of the underground structure at test locations before applying CP. The potential is then 
re-measured after the CP system is energized and the structure has had sufficient time 
to polarize. Typically, the on-potential is continuously monitored at one test location 
directly after energization the CP system, and an off-potential reading is made when 
there is no measurable shift in the on-potential reading for several minutes. The off- 
potential is then compared with the native potential; if the difference exceeds 100 mV, 
then the 100 mV criterion has been satisfied at that location. These measurements are 
shown graphically in Figure 4.2. Off-potential readings are then obtained at the other test 
locations to determine whether the criterion is met at these locations. The time required 
for sufficient polarization to develop is highly dependent on the nature of the structure 
(coating condition, underground environment, types and number of bonds, and so forth) 
and the design of the CP system. From a practical standpoint, it is wise to reexamine 
the overall structure and the CP system if a reasonable amount of polarization does not 
develop within a few hours of energizing the CP system. 

An alternative method of assessing the formation of cathodic polarization is to mea- 
sure the on-potential immediately after energizing the CP system and then re-measure 
the on-potential after a few hours to days of operation. If the on-potential shifts in the 
cathodic (negative) direction by >100 mV, then one can conservatively assume that the 
criterion has been met. Because the applied CP current generally decreases with time, 
the magnitude of the IR voltage drop also decreases. Thus, the total shift in the on- 
potential must be a result of the sum of the additional cathodic polarization and the 
environmental polarization of the pipeline, both of which reduce the corrosion rate of 
the structure and are included in the 100 mV of polarization in the criterion. If this 
method is used, the engineer should confirm that the applied CP current decreased with 
time. 

Measuring the positive potential shift associated with polarization decay that occurs 
after de-energizing the CP system is the most common method to determine the amount 



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56 



Criteria for Cathodic Protection 




CP System 
Turned On 



CP System 
Turned Off 



Figure 4.2 Pipe-to-soil potential as a function of time following energizing 
CP system. 



of polarization. Figure 4.3 is a schematic that shows the pipe-to-soil potential follow- 
ing de-energizing of a CP system. When a CP system is de-energized, the pipe-to-soil 
potential undergoes an instantaneous positive shift as a result of elimination of the IR 
voltage drop in the soil. The potential measured at this time is referred to as the off- 
potential, as previously described, and is used as the starting point for assessing the 
polarization shift. There may be a spike in the potential reading immediately after inter- 
ruption of the CP system, a result of inductive effects of the pipeline and the CP system. 
Because this spike may last a few hundred milliseconds, the off-potential is typically 
measured 200 to 500 ms after the interruption. 

The potential will then exhibit an exponential decay with time in the positive direction 
as the capacitor across the structure-to-electrolyte boundary discharges. This component 
of the potential shift is the cathodic polarization of the structure as a result of the applied 
cathodic current. A gradual linear decay in the potential will then occur over minutes 
to weeks as a result of a return of the environment at the pipe surface to its native 
condition. This component of the potential shift is the environmental polarization. To 
obtain the total polarization shift, the final potential after polarization decay is measured 



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Criteria for Steel and Cast Iron Piping 



57 




Environmental 
Depolarization 



2 4 6 8 10 

Time, Seconds 

Figure 4.3 Pipe-to-soil potential as a function of time following de-energizing 
CP system. 



and subtracted from the off -potential. If this difference is >100 mV, then the criterion has 
been satisfied. 



Applications 



The 100 mV polarization criterion is most commonly used on poorly coated or bare 
structures where it is difficult or costly to achieve either of the —850 mV criteria. In many 
cases, 100 mV of polarization can be achieved where the off-potential is less negative than 
—850 mV (CSE). The application of the 100 mV polarization criterion has the advantage of 
minimizing coating degradation and hydrogen embrittlement, both of which can occur 
as a result of overprotection. In piping networks, the 100 mV polarization criterion can 
be used for the older, poorly coated pipes; whereas, a —850 mV (CSE) polarized potential 
criterion can be used for the newer piping in the network. Because of its fundamental 
underpinnings, the 100 mV polarization criterion also can be used on metals other than 
steel, for which no specific potential required for protection has yet been established. 



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58 Criteria for Cathodic Protection 



Limitations 



This criterion has several limitations. The time required for full depolarization of a poorly 
coated or bare structure can be several days to several weeks, making the method very 
time-consuming and leaving the structure unprotected for an extended period of time. 
Fortunately, much of the depolarization occurs within a few hours and waiting for the 
full decay frequently is not necessary, except where the total polarization is very close 
to 100 mV. Once the criterion has been met, it is not necessary to continue waiting for 
further depolarization. At the other extreme, if a depolarization of <50 mV is measured 
within a few hours, it is questionable whether the 100 mV polarization criterion can 
be achieved. At this point, it may be prudent to assess whether a longer wait for total 
depolarization is justified. 

The 100 mV polarization criterion is frequently used to minimize the costs for up- 
grading CP systems, and the associated increase in power costs, in areas with degrading 
coatings. Because of the complicated nature of the measurements, the cost of conducting 
surveys for the assessment of the 100 mV polarization criterion is considerably higher 
than for the —850 mV criteria. Thus, an economical analysis may be required to determine 
whether an actual cost savings is associated with application of the 100 mV polarization 
criterion. 

The 100 mV polarization criterion should not be used in areas subject to stray currents 
because 100 mV of polarization may not be sufficient to mitigate corrosion in these areas. 
It is generally not possible to interrupt the source of the stray currents to accurately 
measure the depolarization. To apply this criterion, all DC current sources affecting the 
structure, including rectifiers, sacrificial anodes, and bonds must be interrupted. In many 
instances, this is not possible, especially on the older structures for which the criterion 
is most likely to be used. 

The 100 mV polarization criterion should not be used on structures that contain 
dissimilar metal couples because 100 mV of polarization may not be adequate to protect 
the active metal in the couple. This criterion also should not be used in areas where 
the intergranular form of external stress corrosion cracking (SCC), also referred to as 
high-pH or classical SCC, is suspected. The potential range for cracking lies between the 
native potential and —850 mV (CSE) such that application of the 100 mV polarization 
criterion may place the potential of the structure in the range for cracking. 



Net Protective Current Criterion 



RP0169-96 (latest revision) states under paragraph 6.2.2.2 (Special Conditions): "On bare 
or ineffectively coated pipelines where long-line corrosion activity is of primary concern, 
the measurement of a net protective current at predetermined current discharge points 
from the electrolyte to the pipe surface, as measured by an earth current technique, may 
be sufficient" for CP to be achieved. 

This statement establishes the fourth criterion for CP of underground piping, referred 
to as the net protective current criterion. This criterion was originally based on the 



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Criteria for Steel and Cast Iron Piping 59 



concept that if the net current at any point on a structure is flowing from the electrolyte 
to the structure, there cannot be any corrosion current discharging from that point on 
the structure. The theory of electrochemical kinetics, described in Chapter 16, shows that 
corrosion can occur at a point on a structure that is collecting net cathodic current from 
the electrolyte, as long as the polarized potential is more positive than the equilibrium 
potential. Nevertheless, the criterion can be effective, from a practical standpoint, because 
the collection of net cathodic current at any point along the structure produces beneficial 
cathodic polarization and also promotes beneficial changes in the environment at the 
structure surface, as described above. 

Typically, the criterion is applied by first performing, with the CP system de- 
energized, a close-interval pipe-to-soil potential survey, or a cell-to-cell potential survey 
to locate the anodic discharge points along the pipeline. Further details on these survey 
methods are given in Chapter 5. For the surveys to be effective, the CP systems must 
be de-energized long enough for all polarization to decay. The CP system is then ener- 
gized and the structure is allowed to polarize. A side drain method is then used at the 
anodic discharge points to determine whether the structure is receiving cathodic current 
at these locations. With the side drain method, the potential difference between an elec- 
trode placed directly over the structure and one placed on either side of the structure 
is measured. If the electrode located over the pipe is negative with respect to the other 
two electrodes, then current is collecting on the pipe at the location and the criterion is 
satisfied. 



Applications 



The net protective current criterion is normally used on poorly coated or uncoated 
pipelines, where the primary concern is long-line corrosion activity. The technique also 
is normally only used in situations where other criteria cannot be easily or economically 
met. With these exceptions, this criterion is not a standard criterion for establishing the 
effectiveness of a CP system. 



Limitations 



There are a number of limitations to this criterion. First and foremost is the fact that 
the criterion essentially states that any magnitude of net current flow to the structure 
(and therefore, any amount of cathodic polarization of the structure) is adequate to 
mitigate corrosion. In general, that is not the case and therefore, the criterion should be 
considered for use only as a last resort. Application of the criterion should be avoided in 
areas of stray current activity or in common pipeline corridors because of the possibility 
of misinterpretation of the potential readings. The criterion also may not be effective 
in areas with high-resistivity soils, for deeply buried pipelines, or where the separation 
distance of the corrosion cells is small. Finally, the side drain measurements at a given 
location are indicative of the direction of current flow at that location only and are not 
necessarily representative of behavior elsewhere on the pipeline. Thus, for the application 



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60 Criteria for Cathodic Protection 



of this criterion, it is generally necessary to perform side drain measurements at close 
intervals (2 to 20 ft) along the pipeline. 

Other Criteria for Steel and Cast Iron 

The four criteria listed for steel and cast iron piping are the only acceptable criteria listed 
in RP-0 1-69-96 for underground or submerged metallic piping. However, other criteria 
can be used on a piping system for which they have been used in the past and it can 
be demonstrated that their use has resulted in effective CP. Other criteria are also useful 
for underground structures such as reinforced concrete pipe and piling. The two most 
common other criteria that have been used in the past for underground structures are 
the 300 mV potential shift criterion and the E-log I curve criterion. 

300 mV Potential Shift Criterion 

The 300 mV potential shift criterion was contained in the original version of RP 01-69 
and stated that adequate protection is achieved with "a negative (cathodic) voltage shift 
of at least 300 mV as measured between the structure surface and a saturated copper- 
copper sulfate half cell contacting the electrolyte. Determination of this voltage shift is 
to be made with the protective current applied/' This criterion is similar to the 100 mV 
polarization criterion, which is assessed on the basis of the formation of polarization on 
a structure. With both criteria, it is first necessary to determine the native potential of 
the underground structure at test locations before CP is applied. The potential is then 
re-measured after the CP system is energized and the structure has had sufficient time to 
polarize. The difference between the two criteria is that, in the case of the 300 mV potential 
shift criterion, the on-potential is used for assessment of the criterion; whereas, in the case 
of the 100 mV polarization criterion, the off-potential is used for assessment. Regarding 
the 300 mV potential shift criterion, the standard states "The Corrosion Engineer shall 
consider voltage (IR) drops other than those across the structure-electrolyte boundary 
for valid interpretation of the voltage measurements." Thus the relationship between the 
300 mV potential shift criterion and the 100 mV polarization criterion is analogous to the 
relationship between the —850 mV (CSE) with CP applied criterion and the polarized 
potential of —850 mV (CSE) criterion. 

The 300 mV potential shift criterion has mainly been used for mitigation of moderate 
rates of uniform corrosion of bare steel pipelines. It has been applied for protection of 
entire pipelines and also for hot-spot protection. On these pipelines, native potentials of 
—200 to —500 mV (CSE) are common and a 300 mV shift has been found to be adequate 
to mitigate corrosion in some instances. Thus, the development of the criterion was 
empirically based. The 300 mV potential shift criterion is more applicable to impressed 
current CP systems than to galvanic anode systems because galvanic anodes may not 
have sufficient driving voltage to meet the criterion when negative native potentials are 
encountered. 



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Criteria for Steel and Cast Iron Piping 61 



Probably the most successful application of this criterion has been on steel reinforced 
concrete structures. These structures typically have native potentials in the range of —200 
to —400 mV (CSE) and passive steel surfaces, with the exception of hot spots, such that 
a potential shift of 300 mV can be readily achieved. Application of this criterion avoids 
problems associated with overprotection. 

Many of the limitations associated with the 100 mV polarization criterion are appli- 
cable to the 300 mV potential shift criterion as well. These include the time required for 
polarization, the possibility of moving the potential into the cracking range for SCC, 
and difficulties in areas containing stray currents or galvanic couples. In general, the 
300 mV potential shift criterion should not be used where high-pH SCC is confirmed or 
suspected, or where stray currents or galvanic couples are present. The original version 
of RP 01-69 states, "This criterion of voltage shifts applies to structures not in contact 
with dissimilar metals/' 

Probably the single greatest limitation of the 300 mV potential shift criterion is that 
situations will exist in the field where the criterion will appear to be applicable yet 
corrosion may not be mitigated. In some situations, the majority of the potential shift 
will be the result of IR voltage drops in the soil or across the coating, and very little 
polarization of the structure will occur. For this reason, the criterion was removed from 
the primary list of criteria in the 1992 and 1996 revisions of RP-01-69. 



E-Log I Curve Criterion 



The E-log I curve criterion also is found in the original version of RP-01-69, which states 
that adequate protection is achieved with "a voltage at least as negative (cathodic) as 
that originally established at the beginning of the Tafel segment of the E-log I curve. This 
voltage shall be measured between the structure surface and a saturated copper-copper 
sulfate half cell contacting the electrolyte." The criterion was originally developed based 
on an incorrect interpretation of a plot of potential versus the log of the current (E-log I 
curve). The cathodic E-log I curve, which is generated as a structure is polarized from the 
native potential, was thought to exhibit a break that had some fundamental significance. 
This break was thought to occur at the beginning of the Tafel region. A review of the 
theory of CP, given in Chapter 16, indicates that the net cathodic current measured at any 
applied cathodic potential is equal to the difference between the rate of the reduction 
reaction and the rate of the oxidation reaction. An E-log I curve shows a smooth transition 
from zero current, at the native potential, to the linear Tafel region. The Tafel region starts 
when the rate of the oxidation (corrosion) reaction is negligibly small in comparison with 
the rate of the reduction reaction. Depending on the Tafel slopes for the oxidation and 
reduction reactions, the beginning of the Tafel region can vary between 50 and 100 mV 
cathodically from the native potential. 

At present, the E-log I curve criterion is rarely used for evaluating existing CP sys- 
tems. However, the measurement technique, originally developed for applying the E-log 
I curve criterion, is now most commonly used to determine the minimum current re- 
quired for protection. The pipe-to-soil potential, determined by using a remote reference 



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62 Criteria for Cathodic Protection 



electrode, is plotted as a function of the current output of a CP system. Typically, it is 
necessary to use an interruption technique and off-potentials for constructing the E-log I 
plot in order to accurately establish the curve. The potential required to achieve a desired 
minimum current value is identified on the curve. This value should be at least as nega- 
tive as the value at the beginning of the Tafel region of the E-log I curve. Once the potential 
and current values have been established, future surveys consist of checking the current 
output of the CP system and the potential of the structure with respect to the remote 
reference electrode, placed in the same location as was used in the original E-log I tests. 
Because of the elaborate nature of the technique, its use is generally limited to struc- 
tures where conventional means of assessment are difficult. Examples include river 
crossings for pipelines, well casings, and piping networks in concentrated areas such 
as industrial parks. The technique can give erroneous results in areas of stray currents. 
The reference electrode must be placed in the same location each time the potential is 
measured. Furthermore, there is no guarantee that a repeat E-log I curve will yield the 
same results as the original curve. 



CRITERION FOR ALUMINUM PIPING 

RP01 69-96, lists a single criterion for aluminum piping, identical to the 100 mV polariza- 
tion criterion used for cast iron and steel. According to paragraph 6.2.3.1, "The following 
criterion shall apply; a minimum of 100 mV of cathodic polarization between the struc- 
ture and a stable reference electrode contacting the electrolyte. The formation or decay 
of this polarization can be used in this criterion." 

Two precautionary notes included in Section 6.2.3.2 are unique to aluminum piping: 
one dealing with excessive voltages (paragraph 6.2.3.2.1) and one dealing with alkaline 
conditions (paragraph 6.2.3.2.2). 

Paragraph 6.2.3.2.1, states that: 

Notwithstanding, the minimum criterion in Section 6.2.3.1, if aluminum 
is cathodically protected at voltages more negative than -1200 mV mea- 
sured between the pipe surface and a saturated copper/ copper sulfate 
reference electrode contacting the electrolyte and compensation is made 
for the voltage drops other than those across the pipe-electrolyte bound- 
ary, it may suffer corrosion as a result of the buildup of alkali on the metal 
surface. A polarized potential more negative than —1200 mV should not 
be used unless previous test results indicate that no appreciable corrosion 
will occur in the particular environment. 

Paragraph 6.2.3.2.2 states that: 

Aluminum may suffer from corrosion under high-pH conditions and ap- 
plication of CP tends to increase the pH at the metal surface. Therefore, 



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Criterion for Copper Piping 63 



careful investigation or testing should be made before applying CP to stop 
pitting attack on aluminum in environments with a natural pH in excess 
of 8.0. 

The basis for these cautionary notes is the incompatibility of aluminum in high-pH 
environments. The protective passive films on aluminum break down in high-pH elec- 
trolytes, leading to significant increases in the corrosion rate, even at relatively negative 
potentials. In addition to these precautionary notes, several of the limitations for the 
100 mV polarization criterion for steel and cast iron also apply to aluminum. These 
include the time-consuming nature of the measurement technique, difficulties associ- 
ated with interrupting all current sources, and limitations in applying the criterion to 
structures with dissimilar metals and in the presence of stray currents. Because no other 
criterion is applicable to aluminum, good engineering practice must be used to address 
these limitations. For example, sources of stray current should be identified and elim- 
inated, if possible. Aluminum piping should be isolated from other metals before CP 
is applied (isolation of aluminum is required for the CP criterion of dissimilar metals 
under Section 6.2.5 of RP0169; see below). 



CRITERION FOR COPPER PIPING 

RP0169-96 has a single criterion for copper piping. According to paragraph 6.2.4.1, "The 
following criterion shall apply; a minimum of 100 mV of cathodic polarization between 
the structure and a stable reference electrode contacting the electrolyte. The formation 
or decay of this polarization can be used in this criterion/' 

This criterion is identical to the 100 mV polarization criterion used for cast iron, 
steel, and aluminum. There are no precautionary notes with this criterion, but several of 
the limitations with the 100 mV polarization criterion for steel and cast iron also apply 
to copper. These include the time-consuming nature of the measurement technique, 
difficulties associated with interrupting all current sources, and limitations in applying 
the criterion on structures with dissimilar metals and in the presence of stray currents. 
Sources of stray current should be identified and eliminated, if possible. Because copper is 
a noble metal, steel, cast iron, or other metals usually will undergo preferential galvanic 
attack when coupled to copper. Therefore, it is desirable to eliminate such dissimilar 
metal couples before applying CP. 

Criterion For Dissimilar Metal Piping 

RP01 69-96 contains a single criterion for dissimilar metal piping. Under paragraph 
6.2.5.1, the following criterion is listed: "A negative voltage between all pipe surfaces 
and a stable reference electrode contacting the electrolyte equal to that required for the 
protection of the most anodic metal should be maintained. " 



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64 Criteria for Cathodic Protection 



There is one precautionary note, under Paragraph 6.2.5.2: "Amphoteric materials that 
could be damaged by high alkalinity created by CP should be electrically isolated and 
separately protected/' Amphoteric metals include aluminum, titanium, and zirconium. 

In practice, this criterion applies only where carbon steel or cast iron is coupled to a 
more noble metal such as copper. In this situation, either of the 850 mV criterion would 
apply: —850 mV (CSE) with the CP applied or a polarized potential of —850 mV (CSE). 
Other criteria, such as the 100 mV of polarization criterion would not be applicable. 



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Chapter 



Survey Methods and 
Evaluation Techniques 



Ronald L. Bianchetti 



Various testing methods and techniques may be used on underground pipelines during 
the course of field surveys. 



DATA ASSEMBLED BEFORE STARTING A FIELD SURVEY 

Before any field survey, the corrosion engineer should gather as much information as 
possible about the pipeline to be studied. This may provide valuable data on corrosion 
conditions to be expected and should be helpful in planning a survey program that will 
yield useful data for design purposes. 

The following items of information are typical of those which should be accumulated 
before planning and starting the field survey. 

• Pipe material: Steel (including grade of steel), cast iron, wrought iron, or other material 
of known electrical resistance. 

• Is the line bare or coated? If coated, what is the coating material and what coating 
specifications were used? 

• If it is an existing line, is there a leak record? If so, information on the location and 
date of occurrence of each leak will positively indicate the more serious problem 
areas. 

• Pipe diameter, wall thickness, and weight per foot; data on any changes in these items 
along the route of the line. 

• Size or sizes of casing pipe used, with wall thickness or weight per foot; grade of 
steel used; data on insulators used between pipe and casing and on casing end 



65 



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66 Survey Methods and Evaluation Techniques 



seals; if coated casing was or is to be used, type of coating and application specifica- 
tions. 

Location and construction details of all corrosion test points that have been installed 
along the line. If no test points have been installed for corrosion test purposes, deter- 
mine locations where contact can be made with the pipeline for test purposes (other 
than by driving contact bars down to the pipe). 

Is the line of all-welded construction, or are mechanical couplers used? 
Location of branch taps. 

Location of insulated flanges or couplers, if any, purposely used to sectionalize the 
line or to isolate it electrically from other portions of the system or from piping of 
other ownership. 

Route maps and detail maps giving as much data as is available. 
Location of underground structures of foreign ownership that cross the pipeline to be 
surveyed; if any of these structures are cathodically protected, determine the location 
of cathode protection (CP) current sources (particularly rectifiers) that may be close 
to the line being surveyed. 

Location of possible sources of man-made stray current (such as DC electric transit 
systems or mining operations) that could affect the line under study. 
Do any sections of the pipeline closely parallel (within 200 ft or so) high voltage 
electric transmission lines? If so, what is the length of such exposure, how close is 
the pipeline to the towers, at what voltage does the electric line operate, and what 
method is used for grounding the towers? (This information is significant because 
rectifier installations and insulated joints in well-coated pipes closely parallel to high 
voltage electric lines may be damaged by induced AC voltage surges under electric 
system fault conditions if preventive measures are not taken.) 

Is the line now operated at elevated temperature or will it be so operated in the 
foreseeable future. (High temperature could cause deterioration of coatings used.) 



SURVEY METHODS AVAILABLE 

The actual field survey should be organized to use several or all of the following pro- 
cedures. The actual selection and the relative importance of data obtained from each 
method selected will depend on the particular situation. Survey methods for different 
situations are listed below to guide the corrosion engineer. These tests should supple- 
ment information gathered under Data Assembled Before Starting a Field Survey. 

Survey of Pipeline Routes before Construction 

• Measurement of the electrical resistivity of the soil environment around the pipeline 

• Determination of conditions suitable for anaerobic bacterial corrosion 



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Measurement Procedures and Survey Methods 67 



• Determination of various chemical constituents in the soil environment (chlorides, 
sulfate, sulfides, bicarbonates) 

Survey of Pipeline Not under Cathodic Protection 

• Measurement of the electrical resistivity of the soil environment around the pipeline 

• Determination of conditions suitable for anaerobic bacterial corrosion 

• Determination of various chemical constituents in the soil environment (chlorides, 
sulfate, sulfides, bicarbonates) 

• Potential surveys: measurements of potentials between pipeline and environment 

• Line current survey: measurement of electrical current flowing on the pipeline 

• Measurement of the effective electrical resistance of any coating on the pipeline being 
studied 

• Bellhole examinations for evidence of corrosion activity 

• Use of recording instruments for the study of unstable (stray current) conditions 

• If cathodic protection (CP) is deemed necessary: evaluation of electric current require- 
ments for CP. 

Survey of Pipeline under Cathodic Protection 

• Potential surveys: measurements of potentials between pipeline and environment 

• Line current survey: measurement of electrical current flowing on the pipeline 

• Measurement of the effective electrical resistance of any coating on the pipeline being 
studied 

• Bellhole examinations for evidence of corrosion activity 

• Use of recording instruments for the study of unstable (stray current) conditions 

From the listings above, a corrosion survey might seem to be a rather involved process. 
It is the responsibility of the corrosion engineer to select the proper survey "tools" that 
will be best suited for a specific situation and provide adequate design information at 
the least expense. It is easily possible to // overengineer ,/ corrosion surveys and to put 
the greatest emphasis on what may turn out to be relatively unimportant data. This is 
where knowledge and — particularly — experience are important. 



MEASUREMENT PROCEDURES AND SURVEY METHODS 

In this section, we will discuss some of the more important field test measurement proce- 
dures for typical test equipment described in Chapter 6. These measurements procedures 
will be incorporated into survey methods commonly utilized for assessing pipelines both 
with and without CP. 



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68 



Survey Methods and Evaluation Techniques 



Potential Measurements 



Measurement of potential between a pipeline and a copper sulfate reference electrode 
(CSE) is the most frequent test performed in the corrosion industry. All discussions in 
this book that deal with potential measurements will be referenced to the CSE. 

Pipe-to-earth potential measurements are performed by placing the electrode over the 
pipeline for "close" readings or at remote earth for "remote" readings. The porous plug, 
with cap removed, should be in firm contact with moist earth. This may require "digging 
in" at places where the earth's surface is dry. In extremely dry areas, it maybe necessary 
to moisten the earth around the electrode with fresh water to obtain good contact. Do not 
permit grass or weeds (particularly when wet) to contact exposed electrode terminals 
because that may affect the observed potential. 

For the purposes of standardized convention in this book the reference electrode will be con- 
nected to the negative terminal of a high-impedance voltmeter and the positive terminal to 
the pipeline (via test point terminal, probe rod, or direct contact with pipeline), as shown in 
Figure 5.1. 



Pipelines Not under Cathodic Protection 

Potentials reveal several things about the pipeline being evaluated. These include a 
general idea of the extent to which corrosion has progressed, the location of hot spots 
where corrosion is most severe, and the location of areas that are subject to stray current 
electrolysis. 



Digital 
Voltmeter 


© 
© 


850 

X 

VOLTg, 
*'co'M < f 










i _ 


Reference 
^^ Electrode 


Pipe Test Lead — 


1 


Electrode potential 
does not vary 

Pipe potential 








'v i * 


v is the variable 




Figure 5.1 Pipe-to-earth potential measurement. 



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Measurement Procedures and Survey Methods 69 



A general idea of corrosion extent can obtained from the average pipeline potential. 
When potentials are measured with respect to a reference electrode every mile or so along 
a pipeline or at test stations and the readings are then plotted (excluding those subject 
to stray current or other external influences), the newer and less corroded pipelines will 
typically have more negative potential values. Newly laid, coated steel pipelines may 
have an average potential in the range of —0.5 to —0.7 V, whereas old, bare steel lines 
may have an average potential more in the range of —0.1 to —0.3 V (CSE). 

Location of "hot spots" (corroding areas) can be determined by making what is known 
as an over-the-line potential survey. This technique is particularly useful on both bare 
and coated pipelines. In an over-the-line survey, measurements are taken at fairly close 
intervals (about 3 ft apart) between the pipeline and copper sulfate electrode directly 
over the line. 



Pipelines under Cathodic Protection 

Protection criteria based on potential measurements are a logical development of under- 
standing how CP works. As demonstrated in Chapter 3, a flow of current to a cathodically 
protected pipeline from its environment causes a change in potential, a combination of 
the voltage drop across the resistance between pipeline and environment and the po- 
larization potential developed at the pipe surface. The resistance between pipeline and 
environment includes the resistance of the pipeline coating, if any. The net result is that 
the pipeline will become more negative with respect to its environment. This is illustrated 
by Figure 5.2. 

As discussed in Chapter 4, if cathodic areas on a corroding pipeline are polarized to 
the open circuit potential of the anodic areas, corrosion will be mitigated. Ideally, based 
on this concept, potentials should be measured directly across the interface between 
the pipeline and its environment. This location is represented by the terminals marked 
"polarization potential" on the equivalent circuits shown in Figure 5.2. However, this is 
difficult when working with buried pipelines. In common practice, the usual approach is 
to measure the potential between the pipeline and the earth at the surface directly above 
the pipeline. As shown by the equivalent circuits, the observed potential thus includes 
the polarization potential plus a potential created by current flowing through a portion 
of the resistance (IR drop) between pipeline and earth. 

Under some conditions, it is not necessarily desirable to approach the ideal measure- 
ment of polarization potential indicated previously. A measurement of potential between 
pipeline and remote earth then may be in order. This alternative location is indicated 
in Figure 5.2. Reasons for using a remote earth location are discussed in the section on 
Remote vs Close Potential Measurements. 

Assuming that potential measurement is a reasonable approach to a workable crite- 
rion, the next question is how much potential should be present to indicate protection 
and how is it measured. The actual potential measured varies with the method used to 
contact the pipeline environment. The contact must be made by means of a reliable and 
stable reference that will permit reproducible results. 



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70 



Survey Methods and Evaluation Techniques 



POINT "C". CONTACT WITH ■ 
"REMOTE" EARTH TO (-) 
TERMINAL OF VOLTMETER. 



CATHODIC PROTECTION 
POWER SOURCE 



WHEN CONNECTED AS 
SHOWN, DIGITAL VOLTMETER 
WILL SHOW MORE NEGATIVE 
VALUES WHEN CATHODE 
PROTECTION SYSTEM IS 
ENERGIZED AND FORCES 
CURRENT TO FLOW TO THE 
PIPE SURFACE 




COMBINATION OF ANODE-TO-EARTH 
RESISTANCE AND PIPE-TO-EARTH 
RESISTANCE WHICH IS LESS THAN 
THE SUM OF PIPE AND ANODE 
RESISTANCES TO REMOTE EARTH. 

EQUIVALENT CIRCUIT 1 

PIPELINE WITHIN "AREA OF 
INFLUENCE" OF GROUND BED 



RESISTANCE 
OF GROUND 
BED ANODES 
TO REMOTE 
EARTH 



RESISTANCE - 
BETWEEN 
PIPELINE 
AND REMOTE 
EARTH 



i- POINT 

^POLARIZATION 
POTENTIAL 



POINT "A" 
ON EARTH 
ABOVE PIPE 



EQUIVALENT CIRCUIT 2 

GROUND BED ELECTRICALLY 
REMOTE FROM PIPELINE 



Figure 5.2 Pipe-to-environment potential change with flow of cathodic protection current. 



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Measurement Procedures and Survey Methods 71 



With the background developed above, a discussion of actual potentials can be un- 
dertaken. In Chapter 4, we discussed the concept that if cathodic areas on the pipeline 
are polarized to the open circuit potential of the anodic areas, macrocell corrosion will 
cease. As established by various investigators, the most highly anodic areas to be ex- 
pected on a steel pipeline in most soils and waters will have a potential of around —0.8 V 
as measured with respect to a CSE contacting the environment immediately adjacent to 
the anodic area. For usual potential measurements, it is not practical to excavate so that 
the electrode can be placed at pipe depth. The most common approach is to place the 
CSE at the ground surface directly above the pipeline. To allow for a drop in potential in 
the soil between this point and the pipe, and to allow for some latitude in the potential 
of the most highly anodic areas, the practical value of —0.85 V (CSE) has been adopted 
as an indication of satisfactory protection. This criterion along with its applications and 
limitations is discussed in detail in Chapter 4. 

Remote vs Close Potential Measurements 

Pipeline potential readings usually are referred to either "close" or "remote" electrodes. 
If neither is designated, "close" electrode will be meant in most cases. 

Close Earth 

A reading to close electrode usually means an observation made with the reference placed 
on the ground (or water) surface directly above the pipeline being studied. A reading to 
remote electrode means the reference is placed in earth that is electrically remote from the 
pipeline. Often, to permit reproducing similar conditions, the distance and direction will 
be indicated, as "potential to remote CSE, 100 east" or similar notations. Applications of 
both types of reading are covered below. 

Remote Earth 

Under certain testing conditions, it may be desirable to know how far one has to go 
from a structure before the potential represents an electrically remote distance from 
the structure being evaluated. Examples are the area of influence around an impressed 
current ground bed and the area affected by potential gradients around a cathodically 
protected pipeline. This distance may be determined by a series of readings between 
the structure being evaluated and a CSE moved away from the structure at specified 
intervals. When the data are plotted for a cathodically protected pipeline, it might appear 
as illustrated by Figure 5.3. 

The plot taken at an impressed current ground bed would look similar except that 
potentials would increase in the positive direction instead of negative and the distance 
to remote earth could be greater. 



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72 



Survey Methods and Evaluation Techniques 





-1 n 






LU 




(f) 




O 






-0 9 


2« 

■- o 




0) £= 




Q_ O 
-— <D 


-0.8 


0- r^ 




M- U- 1 




O Q) 








CO ,£ 


-()./ 






C =5 




CD C/} 








££ 


-0.6 


Q. 




O 




O 




o 


-0.5 



o a o o 



50 



100 



Distance (feet) Between Pipeline and Copper Sulfate Electrode 
Figure 5.3 Determination of remote earth. 



It should be pointed out that the distance to remote earth will not necessarily be the 
same at all points along a protected line nor will the distance to remote earth necessarily 
be the same for all similarly sized impressed current ground beds at different locations. 
Both soil resistivity and soil structure have an effect. In high-resistivity soil areas, the 
distance to remote tends to be greater. Probably the greatest effect causing extension of 
the distance to remote earth is observed at areas where pipelines or ground beds are 
in relatively shallow surface layers of earth overlying material of much higher resis- 
tivity (such as rock). In these instances, the current to the pipeline or from the ground 
bed tends to concentrate in the surface layer rather than come from or flow to the gen- 
eral earth mass. This substantially extends the distance from the structure to electrically 
remote earth. Awareness of this effect, when working in such areas, is important in 
considering the possible interference effect of potential gradient fields on other struc- 
tures. 



Over-The-Line Potential Surveys (Close Interval Surveys) 

So why are different readings obtained when the reference is placed directly over the 
line? The readings are affected by corrosion current flowing to or from the pipe. Such 
currents cause voltage drops in the soil in the immediate vicinity of the pipeline, which are 
reflected in the readings to a close electrode. Which readings then indicate unfavorable 
conditions? 

In general, when interpreting over-the-line potential survey readings, for pipelines 
without CP the worst corrosion will be where the potential readings are the most nega- 
tive, and there will be little or no corrosion at the points of least negative readings. 

To illustrate results that can be obtained with an over-the-line potential survey on 
a well-coated pipeline without CP, Figure 5.4 represents plotted data taken from an 



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Measurement Procedures and Survey Methods 



73 





-1.0 




-0.9 


III 




CO 


-OH 


o 




CO 


-0.7 


h 




o 


-0.6 


> 




_l 

< 


-0.5 


h- 
7 


-0.4 


LU 




s 


-0.3 


Q_ 




C/) 


-0.2 






Q_ 


-0.1 








CLOSE 

ELECTRODE 

READINGS 




I I I I 

1000 2000 3000 4000 

PIPELINE LENGTH-FEET 
Figure 5.4 Close interval potential survey (w/o CP applied). 



actual field survey. The plotted data do not form a smooth curve. Peaks in the plot 
indicate locations to be suspected as corroding areas. Major peaks mark those areas that 
require closest attention and coordination with other survey data to be discussed later. 

If areas are encountered where stray current electrolysis is a problem, this will be 
apparent from the potential measurements. Potentials attributable to soil conditions 
only show little or no variation during measurements made with indicating voltmeters, 
whereas the effects of a DC transit system, for example, can cause observation of erratic 
and extreme variations in potential values. In severe cases, the variation can be from 
several volts positive to several volts negative with respect to the copper sulfate electrode. 
When such conditions are encountered, electrolysis preventive measures may be needed 
as discussed in Chapter 11. 

To illustrate information that can be obtained with an over-the-line potential survey 
on a well-coated pipeline with CP, Figure 5.5 represents plotted data taken from an 
actual field survey. The plotted data again do not form a smooth curve even when taken 
on a cathodically protected pipeline. Depressions in the plot (least negative potential) 
indicate locations where CP may not be adequate because of underground contacts to 
other pipelines or structures or areas of possible coating damage. These areas of potential 
depressions may require close attention and coordination with other survey data to be 
discussed later. 

Over-the-line potential surveys provide measurement of potentials to a reference 
electrode directly above the pipe and at frequent intervals along the pipe; survey results 
can be used to locate the more actively corroding areas (hot spots) on a pipeline not 
under CP or areas of depressed potentials on cathodically protected pipelines. A detailed 
discussion can be found in Chapter 16. Three methods that may be used for taking these 
closely spaced readings are as follows: 



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74 



Survey Methods and Evaluation Techniques 



-2500 



-2000 



> 

E 



O -1500 



-1000 
-850 



-500 



-000 





















,„....„...,,:::::;::::::,.„..: 




— "On" pote 


ntial 












— "Off" potential 












*x 




....,,/""* 














" yK \kl" 






J \r- 



















Distance 



Figure 5.5 Over-the-line survey (with cathodic protection). 



Method 1 

The principle involved in the over-the-line survey is illustrated in Figure 5.6 which shows 
readings taken on a continuous basis at 3- to 5-ft intervals along the pipeline. For an all- 
welded steel pipeline, there would be negligible voltage drop through the pipe between 
any two points tested (at the usual soil corrosion currents flowing in the pipe). Typically, 



VOLTMETER 
/^" LOCATION 




REFERENCE 
ELECTRODES 
OVER PIPELINE 



< 3 - 5FEET > l 
SPACING 



PIPELINE 



Figure 5.6 Over-the-line potential surveys (Method 1). 



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Measurement Procedures and Survey Methods 



75 



a measuring device, with light wire for continuous contact to the pipeline, is used with 
a data logger to capture data as the survey is being performed. The location of each 
electrode position is recorded with the observed potential. Different types of over-the- 
line survey equipment are discussed in Chapter 6. 

In areas where traffic conditions, terrain features, or other obstructions do not in- 
terfere, long distances can be surveyed on either side of each pipeline connection. The 
distance is limited only by the length of test conductor available. The resistance of the 
light-wire test lead should not be sufficient to cause noticeable error in potential measure- 
ments made with a suitable high-resistance voltmeter. This is true if spools of light wire 
conductors 3 to 5 miles long are maintained properly and have no high-resistance connec- 
tions. For example, 15,000 ft (3 miles) of no. 34 gage light wire would have a resistance of 
approximately 2,800 ohms. A high-impedence voltmeter or datalogger with a minimum 
input impedence of 20 x 10 6 ohms typically reduces any errors from the wire resistance. 

Method 2 

Another measurement technique involves the use of a pair of CSE in leapfrog fashion, 
as illustrated in Figure 5.7. 



ELECTRODES ARE 
PLACED ON SURFACE 
DIRECTLY ABOVE PIPE. 



HIGH RESISTANCE 
VOLTMETER 



.REAR ELECTRODE "LEAP-FROGGED" 
TO FORWARD POSITION FOR EACH 
SUBSEQUENT READING. 



FIRST READING 




SECOND READING 
— mm&wm^ 




CUS0 4 

ELECTRODE "A" 
POSITION 1 



CUSO4 

ELECTRODE "B" 
POSITION 2 

:— KNOWN SPACING- 



CUSO4 ' 
ELECTRODE "A" 
POSITION 3 



PIPELINE 



TEST POINT WIRE OR OTHER 
METALLIC CONTACT WITH 
PIPELINE. 



Figure 5.7 Over-the-line potential surveys using two copper sulfate electrodes (Method 2). 



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76 Survey Methods and Evaluation Techniques 



Table 5.1 Data Record for Leap Frog Potential Surveys 



Position (or 


Potential Drop 


From 


Polarity of 


Pipe to CuS0 4 


Pipe-line Station) 


CuS0 4 


at Last Position 


Forward CuS0 4 


Potential 


1 


— 






— 


-.625volt (1) 


2 


.08 






+ 


-.705 


3 


.04 






+ 


-.745 


4 


.075 






- 


-.670 


5 


.10 






- 


-.570 



(1) Initial value measured via direct pipeline contact at Position 1. 



When using this technique, the survey may be started with a measurement to 
the pipeline at a connection point (ETS) in the usual manner, as shown at Position 
1 in the figure. The value observed and the electrode position are recorded. Leaving 
this electrode (A) at that location, a second electrode (B) is placed at the next location 
along the pipeline (Position 2 in the figure), and this potential difference is observed 
and recorded, together with the polarity of the forward electrode. Electrode A at Po- 
sition 1 is leapfrogged to Position 3 and the potential between the electrodes is mea- 
sured as above. The procedure is continued in the same manner along the length of the 
pipeline. 

The actual pipe-to-electrode potential at Position 2 is the observed potential at Po- 
sition 1 with the potential between Positions 1 and 2 being numerically added to the 
Position 1 value if the polarity of the forward electrode is (+) or subtracted if it is (— ). 
This is continued for each subsequent reading. The data may be recorded as shown in 
Table 5.1. 

The two-electrode technique avoids the need to string out long leads but does in- 
volve greater probability of error, particularly in areas having variable DC stray current. 
Leapfrogging the electrodes avoids any cumulative error caused by potential difference 
between electrodes. Potential drops between electrodes must be measured accurately 
and using a high-impedance voltmeter will typically eliminate that error. An error in ob- 
serving and recording the data at any one position will be reflected in all the subsequent 
calculated pipe-to-electrode potentials. 

Where this method is used, good practice calls for checking the cumulative pipe-to- 
electrode potential by direct measurement to a pipeline contact every thousand feet or 
so and adjusting accordingly. This will guard against unnoticed errors in the data. With 
careful work, however, this method is quite reliable. 



Method 3 

This method, often called the side drain technique, measures the potential drops between 
two copper sulfate electrodes, as shown in Figure 5.8. Electrodes used should be matched 



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Measurement Procedures and Survey Methods 



11 




Copper copper sulfate half cell 
High Impedence Voltmeter 

s :::: i 

Position 1 Position 2 Position 3 

Figure 5.8 Over-the line (Method 3). 



distance (5-10 feet) 



Pipeline 



(not more than 5 mV difference in electrode potential). Measurements are made on 
each side of a unprotected pipeline, typically in areas in question, to identify areas of 
current flow onto and off the pipeline. In Fig 5.8 positive voltage reading would indicate 
current flow to the pipe. A negative voltage reading would indicate current flow off the 
pipeline. 

This technique is not widely used because it is time-consuming. Direct contact poten- 
tial measurements as described in Method 1 are easier than the other methods described. 
Methods 2 and 3 are typically used to qualify specific areas of concern identified using 
Method 1 survey techniques. 



Line Current Measurements 



Measurement of pipeline current by the resistance drop method is useful in pipeline 
survey work. It is also useful in determining the distribution of current along a cathodi- 
cally protected pipeline and for other applications such as stray current. The procedures 
outlined typically use permanent test points to contact the pipe. 



Permanent Two-Wire Test Points 



Where the two-wire test points spanning a known length of pipe are available, cur- 
rents may be measured by determining the potential drop across the span, selecting the 
pipe resistance from tables, and calculating the current using Ohm's law. The general 
arrangement is shown in Figure 5.9. 

The procedure may be performed as follows: 

1 . Measure the circuit resistance of the test leads and pipe span by passing known battery 
current through the circuit and measuring the resulting voltage drop across the test 
point terminals. Calculate resistance in ohms by Ohm's law: R (resistance) = V (volts) 
divided by I (amperes). If the resistance obtained is higher than reasonable for the 
size and length of test wires, defective leads may be suspected. 



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Survey Methods and Evaluation Techniques 



CLOSE SWITCH FOR 
STEP 1 ONLY 



FOR STEP 1 
ONLY > 



PIPE SIZE AND WALL 
THICKNESS OR WEIGHT 
PER FOOT MUST BE 
KNOWN v 



— I |l|l|- 

BATTERY 

TEST POINT 
TERMINALS 



■ AMMETER 



MV 

O Q 



WIRES MUST BE- 
COLOR CODED 



■ VOLTMETER 



PIPELINE 



PIPE SPAN IN FEET - 



Figure 5.9 Current measurement, 2-wire test point. 



2. Measure the voltage drop across the test point terminals caused by the normal current 
flowing in the pipeline. Usually this will be millivolts or microvolts. Instrument resis- 
tance must be known and correction made for the external circuit (measured in Step 1). 
Note the polarity of the meter connection to the test point terminals and indicate the 
direction of current flow (+ to — ) along the pipeline. 

3. Using pipeline resistance tables, determine the resistance of the pipeline span. 

4. Calculate the pipeline current flow by Ohm's law. Current in milliamperes = corrected 
millivolt drop (from Step 2) divided by pipe span resistance in ohms. 

Table 5.2 may be used as a general guide to pipeline resistance. Resistivity values for 
steel typically range between 15 and 23 /i^-cm, depending on the composition of the 
steel. The average value is ~18 imQ-cm. 

Sample determination of current flow on a 200-ft span of 30-in-diameter pipe weigh- 
ing 118.7 lb /ft (pipeline runs east and west) requires the following measurements and 
calculations: 



Step 1. (Battery current = 1.2 A; voltage drop = 0.108 V; circuit resistance = 0.108/1.2 = 
0.09 ohm. 

Step 2. Potential drop at test point terminals = 0.16 mV; the west terminal is (+). 

Step 3. Resistance of pipeline span (from Table 5.2) = 2.44 x 10" 6 x 200 = 0.49 milliohm. 

Step 4. Current = 0.17 mV/0.49 milliohm = 346 mA; flow is from west to east. 



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79 



Table 5.2 Steel Pipe Resistance 1 



Pipe Size, 
Inches 



Outside 
Diameter, Inches 



Wall Thickness, 
Inches 



Weight Per 
Foot, Pounds 



Resistance of One Foot 2 in 
Ohmsx 10" 6 (Millionths of an Ohm) 



2 


2.375 


0.154 


3.65 79.2 


4 


4.5 


0.237 


10.8 26.8 


6 


6.625 


0.280 


19.0 15.2 


8 


8.625 


0.322 


28.6 10.1 


10 


10.75 


0.365 


40.5 7.13 


12 


12.75 


0.375 


49.6 5.82 


14 


14.00 


0.375 


54.6 5.29 


16 


16.00 


0.375 


62.6 4.61 


18 


18.00 


0.375 


70.6 4.09 


20 


20.00 


0.375 


78.6 3.68 


22 


22.00 


0.375 


86.6 3.34 


24 


24.00 


0.375 


94.6 3.06 


26 


26.00 


0.375 


102.6 2.82 


28 


28.00 


0.375 


110.6 2.62 


30 


30.00 


0.375 


118.7 2.44 


32 


32.00 


0.375 


126.6 2.28 


34 


34.00 


0.375 


134.6 2.15 


36 


36.00 


0.375 


142.6 2.03 


1 Based on 


steel density of 489 


pounds per cubic 


foot and steel resistivity of 18 mi( 


2 p _ 16 - 061 


x Resistivity in Microhm-cm 
Weight per foot 


= resistance of one foot of pipe in microhms. 



Permanent Four-Wire Test Points 



Pipelines having four- wire test points with two color-coded wires at each end of a current- 
measuring span are best equipped for accurate measurements of pipeline current because 
each such span can be calibrated accurately. This avoids errors in length of pipe span 
and pipe resistance that may occur when the two-wire test point is used. The general 
arrangement for a pipeline current measurement is shown in Figure 5.10. 
The test procedure is as follows: 

1 . Measure the circuit resistance in the current measuring span (between terminals 2 and 
3) by using Step 1 for the two-wire test point procedure. 

2. Calibrate the span by passing a known amount of battery current between the outside 
leads (terminals 1 and 4) and measure the change in potential drop across the cur- 
rent measuring span (terminals 2 and 3). Divide the current flow in amperes by the 
potential drop in millivolts to express the calibration factor in amperes per millivolt. 
Normally, when the pipeline operating temperature is stable, the calibration factor 
remains constant and does not need to be recalibrated. However, on pipelines where 
the temperature of the pipe changes considerably (with accompanying changes in 
resistance), more frequent calibration may be necessary 



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Survey Methods and Evaluation Techniques 



CLOSE SWITCH FOR 
STEPS 1 AND 2 ONLY 



BATTERY 




< AMMETER 



STEP1 ONLY- 



STEP2 ONLY- 



TEST POINT 
TERMINALS " 



MV 

Q O 



1 2 



COLOR CODED _ 
TEST POINT LEADS 



VOLTMETER 



PIPELINE 



■ CURRENT MEASURING SPAN ■ 



■ FIVE PIPE DIAMETERS SUGGESTED ■ 



Figure 5.1 Current measurement, 4-wire test point. 



3. Measure the potential drop in millivolts across the current-measuring span (termi- 
nals 2 and 3) caused by the normal pipeline current. Calculate the current flow by 
multiplying the measured potential drop by the calibration factor determined in Step 
2. Note the direction of current flow. 

Sample determination of current flow in the same pipeline section used for the exam- 
ple on two-wire test point current determination requires the following measurements 
and calculations: 



Step 1. Circuit resistance between terminals 2 and 3 measured as 0.09 ohm. 

Step 2. Ten amperes of battery current passed between terminals 1 and 4. Corrected 
potential drop, current on = 5.08 mV. Corrected potential drop, current off = 0.17 
mV. Change in potential drop (AV) = 4.91 mV. Calibration factor = 10 A/4.91 
mV = 2.04 A/mV. 



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81 



AMMETER 



ADJUSTABLE 
BATTERY 



VOLTAGE SUPPLY 




i- VOLTMETER 



(-) 



MV 



H 



(+) 



'(+) 

FOUR-WIRE TEST _ 
POINT TERMINALS 

COLOR CODED LEADS ■ 



m'&m&i& j E 7 R7mm>M$ 



LL 



PIPELINE 



DIRECTION OF CURRENT FLOW 
TO BE MEASURED 



Figure 5.1 1 Null ammeter circuit. 



Step 3. Potential drop across current-measuring span (terminals 2 and 3) = 0.17 mV (cor- 
rected) with west end terminal (+). Pipeline current = 0.17 mV x 2.04 A/mV = 
0.346 A (346 mA); flow is from west to east. 

An alternative method for measuring line current is to use a null ampere test cir- 
cuit arrangement based on procedures described by Werner. 6 The circuit, illustrated by 
Figure 5.11, is used with four-wire test points. With a high-impedance voltmeter con- 
nected between the inner pair of wires, current from the battery flows between the outer 
pair of wires in opposition to the measured current flowing in the pipe. As the opposition 
current is increased, the voltage measured will move towards zero. When the voltage 
reading is at or very near zero, the subsequent opposition current measured on the am- 
meter represents the magnitude of current flow in the pipeline span under consideration. 
Remember the measured opposition current is flowing in the opposite direction of the 
actual current flow on the pipeline, so be sure to document the actual direction of pipeline 
current flow (the opposite of that of the opposition current). 



Probe Rods 



Where necessary, pipeline current may be measured by obtaining the potential drop 
across a pipe span of measured length. The pipe may be contacted at each end of the span 
by using pipe-contacting probe rods as described earlier. Otherwise, the test arrangement 



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82 Survey Methods and Evaluation Techniques 



is generally similar to that illustrated in Figure 5.9. There are, however, several additional 
steps (to ensure accuracy) to those outlined for the two-wire test point procedure. 
The set-up and test procedure may be performed as follows: 

Step 1. Locate the pipeline with a pipe locator so that probe rods may be worked into 
the ground squarely above the pipe. 

Step 2. Measure and mark off the current measuring span (such as 100 ft) to an accuracy 
of ±1 in. 

Step 3. Insert the probe rods, working them down to a solid contact with the pipe steel. 
The rods must be kept vertical so that the span length will not deviate from the 
measured value. 

Step 4. The two leads used to connect the measuring instrument to the probe rods should 
be connected together first, so the series resistance of the two leads can be mea- 
sured and the value noted. 

Step 5. Connect the two leads to the probe rods and measure the circuit resistance, which 
includes the test lead resistance and that of the pipe span. This value should 
be the same, for all practical purposes, as the resistance of the test leads only 
(measured in Step 4). This is because the resistance of an electrically continuous 
pipe span is so low compared with that of the test wires that the difference will 
not be detectable by the usual test procedures (except for long spans of very 
small pipe). If the resistance is measurably higher, it would be assumed that 
good contact between probe rods and pipe has not been attained. Work the rods 
against the pipe until the circuit remains stable. (If the circuit resistance does 
not drop to the desired value with solid contacts between rods and pipe, it is an 
indication of a possible extraneous resistance in the pipe span, such as a pipe 
fitting or mechanical coupling. In this event, current flow cannot be measured 
accurately and it will be necessary to move the probe rods to another point where 
they will span solid pipe.) 

Step 6. Measure the millivolt drop between the two probe rods and correct the reading 
for the effect of the external circuit resistance. Note the polarity to determine 
direction of current flow. 

Step 7. Repeat the circuit resistance measurement of Step 5 to be sure that the circuit has 
remained stable while the test was being made. If not, repeat the procedure. 

Step 8. Determine pipe span resistance from Table 5.2 and calculate the current flow 
by Ohm's law, following the procedure established for two-wire permanent test 
points. 

Line Current Survey Evaluation Methods 

If corrosion is taking place on a pipeline, there will be current flow to the line at some 
points and current flow away from the line at others. For small local cells, often termed 



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Measurement Procedures and Survey Methods 83 



"long line/' the current may follow the pipe for hundreds or thousands of feet. It is these 
long-line currents that can be detected in a line current survey. 

Because the pipe itself has some resistance to the flow of electric current, there will be 
a voltage drop in the pipe if current is flowing through this pipe resistance. The voltage 
drops are usually very small but can be determined by using suitable instrumentation 
(discussed in Chapter 6). The resistance per foot of steel pipe is not great and becomes 
progressively smaller as the pipe size and weight per foot increases. Many pipeline 
companies install permanent test point installations with wires of a known span length, 
for example, 100 ft. To see how sensitive such a span would be to small values of pipeline 
current, consider two examples: 

1 . If the pipeline is an 8-in-diameter line with 0.322-in- thick wall weighs 28.6 lb /ft and 
is made of 5LX32 steel, the resistance across a 100-ft span would be 9.75 xlO -4 ohms. 
If the available test instrument is sensitive to a potential as small as 0.02 mV, a current 
of only 20.5 mA flowing through the span resistance would cause this minimum 
deflection. 

2. A 30-in-diameter line with 0.375-in-thick walls weighs 118.7 lb/ft (also of 5LX32 steel) 
will have a 100-ft span resistance of ~2.36 x 10 -4 ohms. With this lower resistance 
span, a current flow of 84.7 mA through the pipeline will be required to give the 
assumed minimum deflection of 0.02 mV. Obviously, a given test span length is much 
less sensitive on large-diameter pipe than on small lines. Using longer span lengths on 
large pipes (that is increasing the span resistance) will result in increased sensitivity. 

On lines without permanently installed test spans, contact bars may be used to es- 
tablish a span for test purposes. This must be done carefully to avoid error as discussed 
earlier. This procedure would be necessary, however, to make closely spaced line current 
measurements (at 500- or 1000-ft intervals, for example) during a line current survey on 
a bare line. 

At each point of measurement in a line current survey, the voltage drop is observed 
and recorded, together with the polarity of instrument connections to indicate the di- 
rection of current flow (plus to minus). Knowing the span resistance of the pipe being 
surveyed, one may convert the voltage drops to equivalent current flow by application 
of Ohm's law (voltage drop in millivolts/ span resistance in ohms = current flow in mil- 
liamperes). The values of current together with the direction of flow then may be plotted 
vs line length. The results might be generally similar to the plot shown by Figure 5.12. 

As illustrated, at one area the current flows from both directions toward a particular 
point on the line. This must be a point of current discharge and, unless the current is 
being drained off by a metal contact such as through another structure, corrosion may 
be expected in that area. 

Line current surveys in most cases will be more meaningful for bare lines than for 
well-coated lines. On coated pipe, current can enter or leave the pipe only through breaks 
or pinholes in the coating. With current concentrated at these coating defects, current 
density in terms of milliamperes per square foot of exposed steel usually is greater than 
on bare pipe. This means that the degree of attack will be greater at coating defects in 
anodic areas on coated pipe with a greater rate of penetration than would be the case 



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Survey Methods and Evaluation Techniques 



400 
co 350 

Q_ 

| 300 H 

_l 

^ 250 



LU 

cr 200 

DC 

=) 

o 



150 - 



LU 



100 



q_ 



50 




















1000 



2000 
PIPELINE LENGTH-FEET 



3000 



4000 



Figure 5.1 2 Line current survey. 



with bare pipe under similar soil conditions. Nevertheless, the total long-line current 
flow on the coated pipe between anodic and cathodic areas would be much less than on 
bare pipe (again, under similar soil conditions) because, with reasonably good coating, 
all but a very small percentage of the pipeline steel is insulated from the surrounding soil. 

There are several possibilities of error in making line current surveys. Care must be 
taken when using probe bars to contact the pipe as mentioned earlier. Unless actual 
resistance is measured for each test span, changes in pipe size or wall thickness (that 
is, differences from what may be normal for the line being surveyed) can result in the 
actual span resistance being substantially different from that calculated from the normal 
pipe dimensions. Likewise, unless the span resistance is measured, the presence of an 
unknown mechanical pipe coupling in the test span could introduce enough resistance 
to make results completely erroneous. Permanently installed test spans are usually put 
in at the time of pipeline construction, using span length and color-coded wiring in 
accordance with an established specification. Errors in color coding may result in the 
current flow being indicated in the wrong direction. 

When planning test point installations for new pipeline systems (or when installing 
them on an existing system), it is good practice to provide current-measuring test spans 
with two separate wires connected to the pipeline at each end of the span. This permits 
measuring the actual span resistance, as described earlier. 



Soil Resistivity Survey 



This indication of a tendency for current to flow becomes more important if something 
is known about the soil resistivity. High-resistivity soils may offer so much resistance 



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85 



100,000 



10,000 

b lu 

> tH 8,000 

Ml 

S g 6,000 -\ 
S g 4,000 



2,000 




| | | | 

1000 2000 3000 4000 



PIPELINE LENGTH-FEET 



Figure 5.1 3 Soil resistivity survey. 



to current flow that conditions are not as severe as the plotted potential data might 
lead one to believe. Conversely, severe potential peaks coupled with a relatively low 
resistivity environment may mean a truly serious condition. Frequent soil resistivity 
determinations are important when making a detailed survey on a pipe line. In addition 
to being a valuable aid when interpreting the severity of corrosive areas, a soil resistivity 
profile is extremely helpful in the later selection of sites for CP installations. Figure 5.13 
is a plot of the soil resistivity measurements taken along the same section of pipeline 
used as a basis for the plots shown in Figures 5.4 and 5.12. 

Data plotted in the figure represent average soil resistivity to approximate pipe depth. 
In this example, a very wide range of soil resistivity is represented. Other cases would not 
necessarily have such a large difference between maximum and minimum resistivities 
along a similar length of line. 

Along well-coated pipelines, measurements of soil resistivity can be of great assis- 
tance in the later selection of CP installations. This may be particularly true to identify 
areas where soils of suitable low resistivity for such installations. 

Instruments used for measuring soil resistivity by the four-pin method are described 
in Chapter 6. Certain precautions to be observed in using the method are given below, 
together with suggestions for planning soil resistivity measurements. 

In the example shown, resistivity of the soil was measured at ~100-ft intervals along 
the proposed alignment. Soil resistivity measurements were conducted by the Wenner 
four-pin method, utilizing a soil resistance meter (see Chapter 6). The Wenner method 
requires the use of four metal probes or electrodes, driven into the ground along a straight 
line, equidistant from each other, as shown in Figure 5.14. An alternating current from 
the soil resistance meter causes current to flow through the soil, between pins CI and 
C2. The voltage or potential is then measured between pins PI and P2. The meter then 



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Survey Methods and Evaluation Techniques 



PIN 
C1 



PIN 
P1 



PIN 
P2 



■ho 

pi 



■e 

C1 




P2 



C2 



PIN 
C2 



\— Soil Resistance Meter 
Figure 5.1 4 Soil resistivity test set-up (Wenner four pin method). 

registers a resistance reading. Resistivity of the soil is then computed from the instrument 
reading, according to the following formula: 

p = IttAR 
where p = soil resistivity (ohm-centimeters) 

A = distance between probes (centimeters) 

R = soil resistance (ohms) {instrument reading} 

n = 3.1416 



The resistivity values obtained represent the average resistivity of the soil to a depth 
equal to the pin spacing. Resistance measurements are typically performed to a depth 
equal to that of the pipeline being evaluated. Typical probe spacings are in increments 
of 2.5 ft (76.2 cm). 

If the line of soil pins used when making four-pin resistivity measurements is closely 
parallel to a bare underground pipeline or other metallic structure, the presence of the 
bare metal may cause the indicated soil resistivity values to be lower than it actually 
is. Because a portion of the test current will flow along the metallic structure rather 
than through the soil, measurements along a line closely parallel to pipelines should be 
avoided. When making soil resistivity measurements along a pipeline, it is good practice 
to place the line of the pins perpendicular to the pipeline with the nearest pin at least 
15 ft from the pipe — further, if space permits. 



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Measurement Procedures and Survey Methods 87 



Table 5.3 Format for Recording Soil Resistivity Measurements 





Nominal Pin 






Resistivity in 


Test Location 


Spacing, Feet 


Ohms 


Factor 


Ohm-cm 


No. 1 










Pipeline Station 


2.5 


4.40 


500 


2200 


1000 + 00. Nearest 


5 


2.05 


1,000 


2050 


pin 100 ft west of pipe. 


7.5 


1.26 


1,500 


1890 


Line of tests perpendicular 


10 


0.96 


2,000 


1920 


to pipe. Clay Moist 


12.5 


0.78 


2,500 


1950 




15 


0.62 


3,000 


1860 




50 


0.17 


10,000 


1700 


No. 2 










Station 1001 + 00. 


2.5 


1.30 


500 


650 


Nearest pin 200 ft 


5 


0.60 


1,000 


600 


east of pipe. Line of 


7.5 


0.45 


1,500 


675 


tests parallel to pipe. 


10 


0.36 


2,000 


720 


Edge of swamp. Wet 


12.5 


0.34 


2,500 


850 




15 


0.33 


3,000 


990 




25 


0.34 


5,000 


1700 



Soil resistivity data taken by the four-pin method should be recorded in tabular form 
for convenience in calculating resistivities and evaluating results obtained. The tabular 
arrangement may be as shown in Table 5.3. Where many soil resistivity measurements 
are to be made, field time will be saved by using printed forms arranged for entering the 
necessary data. 

With experience, much can be learned about the soil structure by inspecting series 
of readings to increasing depths. The recorded values from four-pin resistivity measure- 
ments can be misleading unless it is remembered that the soil resistivity encountered 
with each additional depth increment is averaged, in the test, with that of all the soil in 
the layers above. The indicated resistivity to a depth equal to any given pipe spacing is 
a weighted average of the soils from the surface to that depth. Trends can be illustrated 
best by inspecting the sets of soil resistivity readings in Table 5.4. 

Soil resistivity is an electrical characteristic of the soil /groundwater which affects 
the ability of corrosion currents to flow through the electrolyte (soil /groundwater). 
Resistivity is a function of soil moisture and the concentrations of ionic soluble salts 
and is considered to be most comprehensive indicator of a soil's corrosivity Typically, 
the lower the resistivity, the higher will be the corrosivity 

Table 5.5 correlates resistivity values with degree of corrosivity The interpretation 
of soil resistivity varies among corrosion engineers. However, this table is a generally 
accepted guide. 

The first set of data in Table 5.4, Set A, represents a uniform soil conditions. The 
average of the readings shown (~960 ohm-cm) represents the effective resistivity 



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88 Survey Methods and Evaluation Techniques 



Table 5.4 Typical Soil Resistivity Readings Using 
4 Pin Method 



Pin Spacing 




Soil Resistivity (ohm- 


cm) 


(Feet) 


Set A 


Set B 


SetC 


SetD 


2.5 


960 


1100 


3300 


760 


5 


965 


1000 


2200 


810 


7.5 


950 


1250 


1150 


1,900 


10 


955 


1500 


980 


3,800 


12.5 


960 


1610 


840 


6,900 


15 


955 


1710 


780 


12,500 



that may be used for design purposes for impressed current ground beds or galvanic 
anodes. 

Data Set B represents low-resistivity soils in the first few feet. There may be a layer 
of somewhat less than 1000 ohm-cm around the 5-ft depth level. Below 5-ft, however, 
higher-resistivity soils are encountered. Because of the averaging effect mentioned ear- 
lier, the actual resistivity at 7.5-ft deep would be higher than the indicated 1250 ohm-cm 
and might be in the order of 2500 ohm-cm or more. Even if anodes are placed in the 
lower-resistivity soils, there will be resistance to the flow of current downward into the 
mass of the earth. If designs are based on the resistivity of the soil in which the anodes 
are placed, the resistance of the completed installation will be higher than expected. The 
anodes will perform best if placed in the lower resistance soil. The effective resistivity 
used for design purposes should reflect the higher resistivity of the underlying areas. In 
this instance, where increase is gradual, using horizontal anodes in the low-resistivity 
area and a figure of effective resistivity of ~2500 ohm-cm should result in a conservative 
design. 

Data Set C represents an excellent location for anode location even though the surface 
soils have relatively high resistivity. It would appear from this set of data that anodes 



Table 5.5 Soil Resistivity vs. Degree of 
Corrosivity 



Soil resistivity 

(ohm-cm) Degree of corrosivity 

0-500 Very corrosive 

500-1,000 Corrosive 

1,000-2,000 Moderately corrosive 

2,000-10,000 Mildly corrosive 

Above 10,000 Negligible 

Reference: NACE Corrosion Basics. 



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89 



located >5-ft deep, would be in low-resistivity soil of ~800 ohm-cm, such a figure being 
conservative for design purposes. A lowering resistivity trend with depth, as illustrated 
by this set of data, can be relied upon to give excellent ground bed performance. 

Data Set D is the least favorable of these sample sets of data. Low-resistivity soil is 
present at the surface but the upward trend of resistivity with depth is immediate and 
rapid. At the 7.5-ft depth, for example, the resistivity could be tens of thousands of ohm- 
centimeters. One such situation could occur where a shallow swampy area overlies solid 
rock. Current discharged from anodes installed at such a location will be forced to flow for 
relatively long distances close to the surface before electrically remote earth is reached. As 
a result, potential gradients forming the area of influence around an impressed current 
ground bed can extend much farther than those surrounding a similarly sized ground 
bed operating at the same voltage in more favorable locations such as those represented 
by data Sets A and C. 

One mathematical procedure, known as the Barnes method, is based on calculating 
the resistivity of the soil in each incremental layer of soil. This is done by using the 
data from the four-pin soil resistivity test but extending the calculations by determining 
the conductivity of each incremental layer and converting this conductivity to resistivity. 
Applying the procedure to the Set B soil resistivities (Table 5.6) provides a demonstration 
of the method. 

The Barnes method of analysis is not infallible because its accuracy requires soil 
layers to be of uniform thickness and parallel to the surface. In cases, where this is true, 
each added layer of earth must increase the total conductivity from the surface to the 
bottom of the added layer, no matter what the resistivity of the added layer may be. If, as 



Table 5.6 Calculation of Soil Resistivity by Layers 





4-PIN DATA, SET B 1 






BARNES PROCEDURE 






Ri 




Resistivity 


Mhos 2 


Mhos 3 


R 2 Ohms 




Layer Resistivity 


Spacing 




and Layer 


Feet 


Ohms 


Factor 


Ohm-Cm 


l/Ri 


Al/Ri 


1/A 1/R: 


Factor 4 


Ohm-cm 


Depth, Feet 


2.5 


2.2 


500 


1100 


0.455 


— 


— 


— 


1100 


0-2.5 


5.0 


1.0 


1000 


1000 


1.0 


.545 


1.84 


500 


920 


2.5-5.0 


75 


0.833 


1500 


1250 


1.2 


.20 


5.0 


500 


2500 


5.0-7.5 


10.0 


0.75 


2000 


1500 


1.33 


.13 


7.7 


500 


3850 


7.5-10 


12.5 


0.645 


2500 


1610 


1.55 


.22 


4.55 


500 


2275 


10-12.5 


15.0 


0.57 


3000 


1710 


1.75 


.20 


5.0 


500 


2500 


12.5-15 



^rom Table 5.4 

2 This is the conductivity in mhos (reciprocal of resistance) to the indicated depth. 

3 This is the increase in conductivity caused by the added layer of earth. 

4 The factor used here is for nominal 2.5 foot layer increments. If other layer thickness are used, the factor must 



be changed accordingly (191.5 x layer thickness in feet). 



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90 Survey Methods and Evaluation Techniques 



in the sample calculations above, the conductivity (the column headed 1/Ri) continues 
to increase with depth, conditions appear to approach the ideal closely enough to make 
the method usable. Decreases in the conductivity at any point in a series are an indication 
that soil layers are too distorted to permit use of the method for analysis of data at that 
depth. For example, if the Barnes method procedure is applied to soil data Set D, results 
cannot be calculated by this method below the 5-ft level. One inference from this type 
of data is that the low resistivities observed near the surface indicate the presence of 
a limited pocket of favorable soil in an area of soil having predominantly very high 
resistivity. 

In some areas, experience will show that soil resistivities may change markedly within 
short distances. A sufficient number of four-pin tests should be made in a ground bed 
construction area, for example, to be sure that the best soil conditions have been located. 
For ground beds of considerable length (as may be the case with impressed current 
beds), four-pin tests should be taken at intervals along the route of the proposed line 
of ground bed anodes. If driven rod tests or borings are made to assist in arriving at 
an effective soil resistivity for design purposes, such tests should be made in enough 
locations to ascertain the variation in effective soil resistivity along the proposed line of 
anodes. 



Soil Chemical Analysis 



If soil samples are not measured "on location" but are collected for later measurement, 
they should be kept in air-tight containers to preserve the normal moisture content. In 
some instances, abnormally dry surface soils may be moistened with distilled water to 
obtain their resistivity under wet conditions. 

A wide variety of soluble salts are typically found in soils. Two soils having the 
same resistivity may have significantly different corrosion characteristics, depending 
on the specific ions available. The major constituents that accelerate corrosion are chlo- 
rides, sulfates, and the acidity (pH) of the soil. Calcium and magnesium tend to form 
insoluble oxide and bicarbonate precipitates in basic environments, which can create a 
protective layer over the metal surface and reduce the corrosion. In contrast, the chloride 
ion tends to break down otherwise protective surface deposits and can result in corro- 
sion and corrosion pitting of buried metallic structures. Bicarbonates are not typically 
detrimental to buried metallic. However, high concentrations of bicarbonates found in 
soils /groundwater tend to lower the resistivity without the resulting increase in corro- 
sion activity. 

Soil samples should be taken at the depth of the pipeline in areas where soil resistivity 
data may indicate corrosive conditions. Samples should be sent to a qualified laboratory 
to perform the analysis in accordance with standard practices. 

Table 5.7 correlates the effect of chlorides, sulfates, and pH on the corrosion of buried 
steel or concrete structures. Acidity, as indicated by the pH value, is another aggressive 
factor of soil /groundwater. The lower the pH (the more acidic the environment), the 
greater the corrosivity with respect to buried metallic structures. As pH increases to >7 



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Measurement Procedures and Survey Methods 91 



Table 5.7 Effect of Chlorides, Sulfates, and pH 
on Corrosion of Buried Steel Pipelines 



Concentration (ppm) 


Degree of corrositivity 


Chloride 1 




> 5,000 


Severe 


1,500-5,000 


Considerable 


500-1,500 


Corrosive 


<500 


Threshold 


Sulfate 1 




> 10,000 


Severe 


1,500-10,000 


Considerable 


150-1,500 


Positive 


0-150 


Negligible 


pH 2 




<5.5 


Severe 


5.5-6.5 


Moderate 


6.5-7.5 


Neutral 


>7.5 


None (alkaline) 



Reference: ACI-318, Building Code Requirements for 

Reinforced Concrete (American Concrete Institute, 

1999). 

2 Reference: M. Romanoff, Underground Corrosion, 

1957. 



(the neutral value), conditions become increasingly more alkaline and less corrosive to 
buried steel structures. 

In many areas, soils encountered along a pipeline route will be approximately neutral 
(pH 7). There may, however, be locations where unusual environmental conditions exist, 
either alkaline (pH values >7) or acid (pH values <7). 

Alkaline conditions do not pose any serious difficulty to steel pipelines because such 
an environment is not aggressive toward steel. Strongly alkaline conditions can be detri- 
mental to aluminum piping, however. Under some conditions, use of CP may not be 
able to prevent alkaline attack on aluminum. 

Acid conditions around the pipe have the general effect of making it much more 
difficult to polarize the line to protective potentials (the acid acts as a depolarizing agent) 
when CP is applied. This increases the current requirements in the area. 

Clearly, during a corrosion survey, it would be of value to check the soil pH in 
areas where there is a possibility of unusual chemical conditions. The results could 
have considerable effect on the locations selected for CP rectifiers or galvanic anodes. 
A particularly acid soil condition, for example, would indicate the need for a relatively 
high current density to maintain CP. This could in turn make it desirable to locate CP 
installations at or near the area of high current requirement. 



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92 



Survey Methods and Evaluation Techniques 



CURRENT REQUIREMENT TESTING FOR CATHODIC PROTECTION 
Bare Lines 

Current Applied Method 

The most widely used method for current requirement testing of a pipeline is represented 
below in Figure 5.15. Basically, direct current is forced to flow from a temporary ground 
connection to the pipeline section being studied, and determining how much current 
will be needed to protect that section. 

The output of the current source shown in the figure may be adjusted until protective 
potentials are attained at the ends of the section to be protected. When working with 
bare line, the current should be allowed to flow steadily, which will permit the line to 
polarize to some degree, depending on the duration of the test. Full polarization on a bare 
line may take weeks to achieve; if, however, during the test, the increase in protective 
potential is plotted versus time at a fixed current output, the curve can be extended 
to give a rough approximation of the potentials that would be obtained with complete 
polarization. Current flowing into the protected section from the pipeline on either side 
may be measured by the voltage drop across a known pipe span as described previously. 
These two values may then be subtracted from the total current to obtain the net flow 
into the protected section. Getting the net current in this manner is significant if, when 
making permanent CP installations, there will be CP units in adjacent areas that would 



TEMPORARY 
GROUND CONNECTION 



1.7 A (CALCULATED) 



MV 



m 



BARE 
PIPELINE 



SOURCE 
OF D-C 



1.2 A (CALCULATED) 



IZ. 



AMMETER 
59.0 AMPS 



MV 



t£ 





























































V 






V 






V 






V 






V 






























































+ 
-0.85 V 






+ ■ 
-1.02 V 






+ ■ 
-3.20 V 






+ ■ 
-1.10V 






+ 
-0.85 





VOLTMETER 



Figure 5.1 5 Current requirements for CP. 



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Current Requirement Testing for Cathodic Protection 93 



reduce or eliminate the current flow from remote areas into the area being tested as 
described. 

Current requirement tests of the type described do not give more than a reasonable 
close approximation of current needs. Variations will be caused by such things as ground 
bed resistance and location with respect to the pipeline, polarization effects (as mentioned 
above), the amount of line that is protected by each installation, and whether or not 
adjacent installations will affect the amount of current flowing to the pipeline beyond 
the area to be protected. Such variables can cause appreciable differences between survey 
results and the ultimate performance of permanent installations. Interpretation of survey 
test results on bare lines is seldom simple. Experience is most valuable when developing 
a final design from field survey data of the nature discussed. 

Because bare line current requirements usually are high, substantial currents will be 
flowing along the pipeline. These, in turn, will cause significant voltage drops in the 
line, which will limit the length of pipe that may be protected from one point without 
producing excessive potentials at the point of current drainage. Unless circumstances 
are unusual, only a few hundred up to a thousand feet or so of bare pipe should be 
tested at one time. As a general rule, longer pipe lengths can be tested when working 
with larger-diameter lines because their longitudinal resistance is less. When planning a 
current requirement test on bare line, the current source needed should have sufficient 
capacity to supply, as a guide, at least 1-3 mA per square foot of pipe surface plus 25% 
more. The voltage of the power source must be sufficient to force the needed current 
through the temporary ground connection used. Storage batteries may be adequate for 
testing short lengths of small-diameter pipe, whereas a source such as a DC welding 
generator may be needed for longer lengths of larger-diameter pipe. See Chapter 7 for 
information on the resistance of ground beds. 



Coated Pipelines 



When surveying a coated pipeline system, data on the electrical strength of the coating 
and on current requirements for CP can be taken concurrently. If the coating is in rea- 
sonably good condition, current requirements are much smaller than on bare lines. This 
makes it possible to test many miles of pipeline with one test set-up and a modest power 
supply. Batteries are usually sufficient. 

Although the same coating specification may be used throughout the length of 
a given pipeline, the effective electrical strength of that coating (in terms of its ability 
to resist the flow of current) may vary considerably along the route. Variations may 
be due to the type of terrain, construction difficulties (rocky pipe-laying conditions 
may result in many more accidentally damaged areas), changes in average soil resisti- 
vity, and different degrees of quality of pipeline construction work and inspection. In 
any event, knowledge of areas where abnormally low coating resistances are preva- 
lent on a given line will assist the corrosion engineer in planning the corrosion control 
system. 



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94 



Survey Methods and Evaluation Techniques 



n 



. TEMPORARY 
GROUND BED 



D.C. POWER 
SOURCE ^L 



POTENTIAL 



TEST POINT 
NO. 1 

«_ REMOTE 
ELECTRODE 

CURRENT 



^-7 

INTERRUPTER 



POTENTIAL 



TEST POINT 
NO. 2 

-| ^_ REMOTE 
^ ELECTRODE 



CURRENT 



MV 



CURRENT 
FLOW 



MV, 



PIPELINE 
(COATED) 



■3 TO 5 MILES TYPICAL - 
COATING RESISTANCE - 
DETERMINED FOR THIS 
SECTION OF PIPELINE 



Figure 5.1 6 Coating resistance and CP current requirement tests. 



When making the combined survey on a coated line, a test arrangement may be used 
as illustrated by Figure 5.16. At the test battery location, a current interrupter (see Chapter 
6) is used to automatically switch the current source on and off at a convenient time inter- 
val (such as 10 s on and 5 s off). This way the data needed for coating resistance calcula- 
tions are obtained. At the same time this procedure assures the test engineer at remote lo- 
cations that the battery installation is still operating properly as long as the potential and 
line current measurements continue to change in accord with the established on-off cycle. 

On a reasonably well-coated pipeline, test data taken at intervals of, typically, 3 to 
5 miles will give satisfactory information on the average coating resistance within each 
section tested. Testing section by section can be continued in each direction from the 
temporary CP location until the changes in the observed currents and potentials (as the 
current interrupter switches on and off) are no longer large enough to result in accurate 
data. The limits of the area that can be maintained above the protected ctiterion of —0.85 V 
or better will be established at this same time. 

Coated pipelines polarize very rapidly. The better the coating, the faster the polariza- 
tion. This means that conditions stabilize within the first few minutes (and sometimes 
in a matter of seconds) after the test current is applied. 

On coated pipeline systems provided with test points for potential and line current 
measurement, a survey will proceed rapidly. Data may be taken with reasonable accu- 
racy by a single test engineer. For maximum accuracy, however, two engineers in radio 
communication can observe data simultaneously at each end of each section tested. This 
becomes essential if the pipeline under test is affected by stray current. Strays may make 
it necessary to take a series of simultaneous readings and average them to obtain usable 
data. 



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Current Requirement Testing for Cathodic Protection 95 



To obtain data for calculations of coating resistance, readings are taken along the 
pipeline to a copper sulfate electrode with the interrupter on and off, and pipeline cur- 
rent is measured with the interrupter on and off at each end of each line section. From 
these readings one can determine the change in pipe potential (A V) and the change in 
line current (A J) at each end of the test section. The difference of the two A I values 
will be equal to the test battery current collected by the line section when the current 
interrupter is switched on. The average of the two A V values will be the average change 
in pipeline potential within the test section caused by the battery current collected. The 
average A V in millivolts, divided by the current collected in milliamperes, will give the 
resistance to earth, in ohms, of the pipeline section tested. From the length and diame- 
ter of pipe in the section tested, its total surface area in square feet may be calculated. 
Multiplying the pipe-section-to-earth resistance by the area in square feet will result in 
a value of ohms per average square foot, the effective coating resistance for the section 
tested. Some workers express coating condition in terms of conductivity (in mhos or 
micromhos). This is simply a matter of conversion. The reciprocal of the resistance per 
average square foot is the conductivity in mhos. The reciprocal of the resistance per aver- 
age square foot is the conductivity in mhos. The reciprocal times 10 6 is the conductivity in 
micromhos. 

Here is an example of data and its treatment as described in preceding paragraph. 
Referring to Figure 5.16, assume that the section between test points 1 and 2 is under test 
and that this section consists of 15,000 ft of coated pipeline having a total external pipe 
surface area of 50,070 ft 2 . Test data taken at test point 1 are as follows: 

PipetoCuS0 4 = -1.75 volts, ON and -0.89 volts, OFF 
AV = -0.86 volt 
Pipe span potential drop = +0.98 MV, ON and +0.04 MV, OFF 
With span calibrated at 2.30 amps per mV (discussed earlier in this chapter.), 
Pipeline current = +2.25 amps, ON and +0.09 amps, OFF 
AI = 2.16 amps 

Test data taken at test point 2 are 

Pipe to CuS0 4 = -1.70 volts, ON and -0.88 volts, OFF 
AV = -0.82 volt 
Pipe span potential drop = +0.84 MV, ON and -0.02 MV, OFF 
With span calibrated at 2.41 amps per MV, 

Pipeline current = +2.03 amps, ON and —0.05 amps, OFF 
(negative off currents indicate current flow in opposite direction) 
AI = 2.08 amps 



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96 Survey Methods and Evaluation Techniques 



Calculation of coating resistance is therefore: 

Average AV = (-0.86 + -0.82) -r- 2 = -0.84 volt 
Current collected = 2.16 - 2.08 = 0.08 amp 
Pipe to earth resistance = 0.84 V -r 0.08 A = 10.5 ohms 
Effective coating resistance = 10.5 ohms x 50, 070 

= 526,000 ohms for an average square foot (approx.) 
(ohms-ft 2 ) 

Note that the average soil resistivity has an effect on the effective coating resistance 
measurement. In part this is because the apparent pipeline resistance to remote earth 
measure in the procedure described is a combination of the coating resistance and the 
resistance to remote earth of the pipeline itself. In the example given, if we assume that 
the test section was in 1000 ohm-cm soil, the resistance to earth of the 15,000 ft of 12-in- 
diameter line, if bare, would be in the order of 0.0062 ohm. If the average soil resistivity 
were 100,000 ohm-cm, this resistance would be 0.62 ohm. If the difference, ~0.6 ohm, is 
added to the 10.5 ohms of pipe-to-earth resistance calculated in the example, the new 
total of 11.1 ohms, multiplied by the 50,070 ft 2 surface area, would give an indicated 
effective coating resistance of 606,000 ohms per average square foot. 

Actually, however, the resistance to earth of exposed steel at coating defects may 
have a much greater effect on the apparent coating resistance with variation in soil 
resistivity Using the example again, if the coating were perfect (10 13 ohm-cm resistivity), 
the resistance of the pipeline section to remote earth would be in the order of 50,000 
ohms — whereas the measured value was only 10.5 ohms. Now if we assume that the 10.5 
ohms (in 1000 ohm-cm soil) is primarily the resistance to earth at pinholes distributed 
along the 15,000 ft section, this resistance will vary in approximate proportion to the 
soil resistivity The resistance in 100,000 ohm-cm soil, then, would be in the order of 
(100,000/1,000) x 10.5 or 1050 ohms x 50,070 ft 2 , or 52.5 x 10 6 ohms for an average 
square foot (ohms-ft 2 ). This relationship is not rigorous and depends on the relative 
size and spacing of coating defects as well as the ratio between the section resistance 
with perfect coating and that as actually measured (when the ratio is high, as in this 
case, pinhole resistance prevails). This does, however, demonstrate the effect that soil 
resistivity can have on apparent coating resistance. In particular, it shows that something 
must be known about the soil resistivity when evaluating a section of pipeline coating. 

The method described for obtaining an approximation of effective coating resistance 
depends, for accuracy, on the precision with which field data are taken. The potential mea- 
surements pose no particular problem (unless erratic stray current effects are present), 
but the line current measurements are another matter. Unless current-measuring test 
points of a type that can be calibrated are permanently installed, errors in span length or 
variations in pipe span resistance may make calculated currents erroneous. Also, as was 
demonstrated earlier, it may not be possible to detect small currents or current differ- 
ences that are below the sensitivity range of the millivoltmeter being used. Nevertheless, 
as long as these limitation are recognized, the procedure is fully practical in establishing 
relative coating quality from section to section. 



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Additional Considerations 97 



An initial coating resistance profile along a new pipeline will serve as a reference 
to which similar data taken in later years may be compared. Such comparisons reveal 
information on the long-term performance of the coating. For example, detrimental 
effects caused by such things as high pipeline operating temperature, areas of abnormal 
soil stress, areas subject to a high degree of bacterial activity, or any other condition that 
may affect the coating. 



ADDITIONAL CONSIDERATIONS 
Microbiologically Influenced Corrosion 

Microbiologically influenced corrosion (MIC) is one manifestation of the effect on corro- 
sion by soil bacteria. MIC is discussed in detail in Chapter 14. Certain bacteria, which can 
exist under anaerobic conditions (absence of oxygen) at the pipeline surface, have the 
ability to reduce any sulfates present and consume hydrogen in the process. Consump- 
tion of hydrogen at the pipe surface acts to depolarize the steel at cathodic areas and 
permits more rapid consumption of the metal by galvanic corrosion cells. The bacteria, 
then, do not directly attack the pipe but provide conditions conducive to a more rapid at- 
tack by existing corrosion cells, which are normally partially stifled by the development 
of an insulating polarization film of hydrogen. 

The practical effect of anaerobic bacteria activity on the application of CP is an in- 
crease in the amount of current required to maintain CP. Some workers have reported 
that higher-than-normal protective potentials should be used in areas where anaerobic 
bacteria are active because the open circuit potentials of anodic areas are more negative. 
An additional 100 mV of protective potential has been suggested (—0.95 V to copper 
sulfate electrode instead of the usual —0.85 V). 



Bellhole Examinations 

Sometimes there is nothing that will satisfy the corrosion engineer more than having 
an actual look at the pipe that has been surveyed by electrical methods. Actually, this 
is an acceptable and desirable procedure for use in evaluating the relative severity of 
corrosive areas detected during a survey. 

Typical hot-spot corrosive areas found during a corrosion survey on an older bare 
line may be uncovered and inspected. This will give the corrosion engineer a guide for 
evaluating other corrosive areas on the line. 

Areas where anaerobic corrosion is suspected may be exposed for examination. If 
anaerobic bacteria are present and active, a layer of black iron sulfide will coat the pipe 
surface. The deposit would be expected only at coating defects on pipelines having a 
bonded coating. If this black material is iron sulfide, treating it with a dilute solution of 



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98 Survey Methods and Evaluation Techniques 



hydrochloric acid will release hydrogen sulfide gas, which is recognized by its charac- 
teristic rotten egg odor. 

If areas have been found where pipe coatings have unusually low resistance values, 
bellhole inspections may be in order to trace the causes of coating damage. This may be 
particularly valuable in connection with older pipeline coatings to determine the nature 
of deterioration over time as a guide to selection of materials for future coating projects. 



EXAMPLES OF CORROSION SURVEYS 
Corrosion Survey on a Typical Coated Line 

To conduct a corrosion survey on a 100-mi-long, 30-in-diameter pipeline having an very 
good dielectric coating, what should one know? In the first place, particularly if the 
line was recently laid, the usual intent is to cathodically protect the line. Accordingly, 
information to be obtained during the survey will be based on this objective. With this 
in mind, the following types of data may be procured for such a line: 

1 . Soil resistivity information at intervals along the line, including locations suitable for 
CP installations. If at sites where electric power is available, note details of power 
supply line: company, voltage, pole number, single or three-phase, and so forth. 

2. Effective electrical resistance of the coating. 

3. Current requirements for CP. 

4. Location of unusual environmental conditions along the pipeline route such as acidic 
areas, sections where severe bacterial attack may be suspected, or any other condition 
that might tend to result in increased corrosion rates or rapid coating deterioration. 

5. Effect of stray current, if any. 

6. Tests at crossings with structures of other ownership to see if mutual interference 
effects may be a problem. 

7. Condition of cased crossings at roads and railroads. 

All the above types of information can have a direct bearing on the type and design 
details of the CP system to be developed for the pipeline being surveyed. Only when such 
information is complete can a protection system be designed for optimum performance 
from the standpoint of protection coverage, reliability, and economy. Survey methods 
used to obtain most of the above-listed types of information have been described earlier 
in this chapter. 

At crossings with underground structures of other ownership, tests will be made 
to make sure that the two systems are electrically insulated from one another. If the 
foreign system is cathodically protected, the possibility of adverse effect on the line being 
surveyed is investigated. Likewise, it may be necessary to determine if a CP system on 
the line being surveyed will affect the foreign structure to a degree requiring corrective 



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Examples of Corrosion Surveys 99 



action. These effects are a form of stray current and are discussed in greater detail in 
Chapter 11. 



Corrosion Survey on a Typical Bare Line 

Bare line surveys are time-consuming and expensive when compared with corrosion 
surveys on coated pipelines of the same length. Because of this, careful planning is 
necessary to be sure that all needed information is obtained without extending the scope 
of the survey beyond the requirements of the pipeline situation involved. 



Example No. 1 



Assume that a bare line to be surveyed is old and has an extensive leak record. Also, 
although the line is planned to be in use for only another 10 years, the cost of repairing 
leaks is becoming prohibitive. In this instance, the line operators might elect to adopt 
stop-gap measures by applying CP at the worst spots. A field corrosion survey, then, 
would be confined to those trouble areas where leakage is a problem, as defined by the 
leak records. 

One approach to surveying this pipeline would be to make soil resistivity measure- 
ments for the selection of rectifier-powered CP units at each trouble area and to make 
current-requirement tests to assist in the design of the final installations. This approach 
would be adopted logically if the leakage areas were relatively few and well defined but 
large enough to justify the installation of one or more rectifier units in each area. 

Another survey approach might be adopted if the leakage areas were frequent and 
small such that the use of rectifiers might not seem justified. Galvanic anodes might 
be the better choice. In this event, the corrosion survey would consist of soil resistivity 
measurements to assist in the selection of size and type of anodes to be used. 

Either approach described should be supplemented by sufficient pipeline potential 
readings to establish whether or not stray current damage is a possibility if there is any 
reason to suspect an effect from such sources. Locating foreign pipeline rectifiers is also 
necessary where they are close enough to the line being surveyed to be a possible source 
of damaging interference. The location of all foreign underground structures should be 
known in areas where CP installations are to be made, particularly if rectifier units are 
contemplated. 



Example No. 2 



Assume that the bare line to be surveyed is relatively new but corrosion has started to 
become apparent through leak development. Assume further that the line is of a critical 
nature, requiring corrosion control throughout its length, and that its life is to be extended 
indefinitely. This could be a line, for example, that was expected to have a short economic 



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100 Survey Methods and Evaluation Techniques 



life when installed originally (hence laid bare) but was found later to be needed for as 
long as possible. 

For such a line, a complete corrosion survey would be indicated. As a minimum, the 
survey techniques should include an over-the-line potential survey and a soil resistivity 
survey, both described earlier in the chapter. 

Field survey data accumulated as above will serve as an adequate basis for the design 
of CP installations. 



RECORDING SURVEY DATA 



No corrosion survey will be of value unless data are recorded in such form that they 
can be analyzed properly during and after the survey. This requires planning before 
the survey starts. When a considerable amount of any one type of data is expected to be 
taken, time will be saved in the field by having data forms on which to enter the readings. 
In addition to reducing paper work in the field, such forms will serve as a reminder of 
readings that should be taken. 

An area of particular importance in recording field data is designating where the 
readings are taken. Location may be identified by pipeline station numbers when maps 
showing this information are available. If there is no station numbering system, distances 
from the closest positively identifiable landmark should be recorded. For example, if 
corrosive areas are found during potential surveys on bare lines, the information will be 
of value only if the precise location can be found again later when corrective CP is to be 
installed. 



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Chapter 



Instrumentation 



Mark Lewis 



The corrosion engineer must have a sound basic knowledge of the variety of test instru- 
ments used in corrosion work and he or she must know how to use them effectively in 
the field. Only with such knowledge can engineers obtain reliable and meaningful data. 
The corrosion engineer will routinely employ not only common electronic multimeters 
but also very specialized instrumentation. 

Section 1 of this chapter includes a discussion of typical equipment used for the vari- 
ous field tests. Section 2 covers the variety of accessories and supplementary equipment 
that may be needed along with the basic test instruments. Section 3 addresses the care 
and maintenance of corrosion instrumentation. 



EQUIPMENT 



This section will examine the operating characteristics and capabilities of instrumenta- 
tion suitable for corrosion testing. Although typical instrumentation will be illustrated, 
all available devices cannot be covered. For more thorough coverage of these instru- 
ments, as well as others not described, consult the manufacturer's operating instruc- 
tions, or an instrumentation supplier. Equipment vendors can also offer operating 
advice, as well as firsthand instruction on the operation of the more specialized in- 
struments. 



Voltmeters 



Measurement of voltage, such as that between a pipeline and a reference electrode, is 
probably the most frequently made determination in corrosion testing work. If suitable 



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voltage measuring equipment is not used (or if the right equipment is not used properly), 
the values obtained may be misleading or completely meaningless. 



Voltmeters and Resistance 



Because of improvements in measurement technology, electronic voltmeters are manu- 
factured with an enormous variety of capabilities. Many commonly available voltmeters 
are referred to as multimeters because they have the ability to measure multiple electrical 
values in addition to voltage. The features offered on a given instrument may be tailored 
to the needs of a particular industry or discipline, or the device may offer a combination 
of test capabilities common to many applications. 

It is important to understand the versatility of these devices as well as their limitations. 
Certain multimeter functions and features are valuable for corrosion engineering work, 
while others can be insufficient or unnecessary. 

When measuring, for example, the voltage difference between a pipeline and a ref- 
erence electrode, two important resistance values must be kept in mind. To determine 
a pipe-to-soil potential value, a voltmeter must measure across an external circuit re- 
sistance, which may vary widely from one environment to another. For instance, the 
resistance of a reference electrode in contact with moist or wet soil will be considerably 
less than one in contact with dry sand or frozen or oily soil. Therefore, the reference 
electrode's contact resistance represents a large portion of the overall resistance of the 
circuit across which a voltage is to be measured. 

To compensate for these variations in the measuring circuit, voltmeters must be 
equipped with a high impedance, or input resistance. A high external resistance re- 
quires a high input resistance to maintain accuracy during measurements. Most conven- 
tional multimeters currently produced have an internal impedance of 10 million ohms 
(10 7 ohms, or 10 megohms), or more. However, some inexpensive voltmeters are avail- 
able that are not intended for use in the measurement of high resistance circuits, such as 
those encountered in corrosion testing. The use of a meter with, for example, an internal 
resistance of only 2 x 10 3 ohms per volt can cause significant error when used to measure 
pipe-to-soil potentials. 

Measurement of other voltage values, such as rectifier output voltage or voltage drop 
across a current measuring shunt does not require such a high impedance voltmeter. 
However, it is prudent to select a voltmeter suitable for every anticipated field test. 
To determine the input impedance of a particular voltmeter, consult the instrument's 
technical specifications. 



Voltmeter Selection 



In addition to high input impedance, it is important to select a voltmeter with the appro- 
priate range, resolution and accuracy. Many standard voltmeters are available off-the-shelf 
that are suitable for measuring corrosion-related voltages. Figure 6.1 shows a typical 



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*■■■ 



Figure 6.1 Battery powered multimeter. (Photo 
courtesy of Farwest Corrosion Control and John 
Fluke Mfg. Co. Used with permission.) 



hand-held battery-powered multimeter. The meter illustrated can measure a maximum 
of 1,000 volts (both AC and DC) in any of five different ranges and features a ba- 
sic accuracy of 0.1%. The device has a 10 megohm input resistance, which is suitable 
for all but the highest resistivity environments. This instrument also has the capabil- 
ity to measure resistance, capacitance, frequency, and both DC and AC current. Dig- 
ital multimeters such as that illustrated are widely available and produced by many 
manufacturers. 



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Figure 6.2 Specialized voltmeter with variable input resistance. (Photo 
courtesy of M. C. Miller Co.) 



Figure 6.2 shows a specialized voltmeter which has a selectable input resistance. This 
meter can be used where very high input resistance is required, such as in extremely 
high resistivity soils. It is also useful in the verification of structure-to-soil potential 
data. Changing the resistance-selector switch can validate a particular pipe-to-soil poten- 
tial measurement. No change in potential while switching between resistance ranges 
indicates a valid reading. This instrument also incorporates the ability to measure up to 
600 volts AC, and resistance values as high as 200 ohms. 

When selecting a voltmeter it is important to consider the meter's measuring range 
and resolution. To measure small voltage increments, such as the voltage across a shunt, 
a meter should offer an appropriate combination of range and resolution. For instance, 
when using a 0.001 ohm shunt to measure current to within 0.1 ampere accuracy, a 
voltmeter with a 0.1 millivolt resolution is necessary. Conversely, if a meter's resolution 
is 0.1 millivolt, that same shunt will yield an accuracy of +/— 0.1 amp. 

The importance of a meter's resolution becomes apparent when measuring the cur- 
rent output of a galvanic anode using an external shunt. To measure, for instance, 54 
millamps flowing through a standard 0.01 ohm shunt, a meter must have a resolution 
of 0.01 millivolts. If the meter has only 0.1 millivolt resolution, as in the above example, 
the current will be measured as 50 mA, not 54 mA. The meter shown in Figure 6.2 has a 
lower range of 0-20 millivolts DC, and a resolution of 0.01 millivolts. This combination 
is ideal for measurement of direct current through external shunts. 



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With regard to meter accuracy, many meters offer a 3% or 4 1 /, digit resolution. This 
refers to the number of significant digits that will be used to display an accurate voltage 
value. For cathodic protection measurements, where a voltage of, for instance, minus 
0.972 volts is being measured, a more accurate measurement of minus 0.9721 may not 
be relevant to a field determination of protection. The significance of extreme precision 
must be viewed in conjunction with the necessity of such accuracy. 

The selection of voltmeters should also include an evaluation of cost versus practi- 
cality. Many commercially available meters are hand-held, battery-powered, and well 
suited for field applications, while others are primarily suitable for bench tests or labo- 
ratory work. Voltmeters can be purchased with an array of features such as large data 
storage capacity, oscilloscope display, recording capability and computer interface con- 
nections. A voltmeter should be chosen for its applicability to the work at hand, with 
the proper balance of cost, durability, and accuracy. 



Resistivity Test Instruments 



The corrosion engineer has many occasions to measure soil resistivity during corrosion 
surveys, selecting locations for cathodic protection groundbeds and other similar work. 
These tests may be made with a battery and an individual DC ammeter and voltmeter. 
For greater speed and convenience in making field determinations, however, there are 
specialized instruments available that can be read directly. 

Soil resistivity field measurements are often made using ASTM 1 G57 or IEEE 2 Stan- 
dard 81, more commonly known within the corrosion industry as the "Wenner 4-Pin 
Method". This procedure involves driving four steel pins into the earth in a straight 
line, equally spaced, with the pin spacing equal to the depth to which knowledge of the 
average soil resistivity is desired. Soil resistivity is a simple function of the voltage drop 
between the center pair of pins, with current flowing between the two outside pins. 

Meters such as that shown in Figure 6.3 can provide the necessary current supplied 
to the outer pins, while simultaneously measuring the voltage drop between the center 
pair of pins. The resistance, in ohms, is then the reading on the dial multiplied by the 
range switch position. The instrument can measure resistance values between 0.01 ohm 
and 11 x 10 5 ohms depending on which multiplier (scale) is selected. The meter also 
uses alternating current, which overcomes the problem of polarization of the pins, an 
inherent problem with direct current tests. 

The meter shown is Figure 6.3 is also useful for other measurements, such as during 
anode installation or for measuring the resistance of anode beds and grounding systems. 
The resistance-to-earth of ground rods can be measured when used in the 3-pin config- 
uration. It is important to remember not to measure across energized circuits to avoid 
damaging the meter. In addition, the resistance of the test leads might be included in the 
measurement, depending on the test lead configuration. 



1 American Society for Testing and Materials, West Conshohocken, PA. 

2 Institute of Electrical and Electronics Engineers. 



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Figure 6.3 Soil resistivity meter. (Photo courtesy of Nilsson Electrical Laboratory.) 



Recording Instruments 



Some cathodic protection measurements are best made in relation to specific periods of 
time, or distance, to quantify values that change or fluctuate. A number of recording 
voltmeters are available which can measure and record readings while left unattended, 
such as during interference testing. The chart recorder shown in Figure 6.4 records volt- 
age values on a continuous basis and prints a graphical copy of the data. Other recording 
devices, such as that shown in Figure 6.5, operate on an electronic basis and can interface 
with computers to facilitate data plotting and presentation. The electronic chart recorder 
shown in Figure 6.5 is very small and compact, allowing it to be inconspicuously lo- 
cated during testing. Such recording devices can measure and plot several parameters 
simultaneously to enhance data collection and interpretation. 

Other recording instruments are used to measure and store pipe-to-soil potentials 
while traversing a pipeline during an over-the-line type survey. Figure 6.6 shows a data 
recorder that can store many thousands of data entries, including text comments. When 



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Figure 6.4 Strip-chart recorder. (Photo courtesy of M. C. Miller Co.) 




Figure 6.5 Electronic dual-channel recorder. 
(Photo courtesy of Corrpro Companies, Inc.) 



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Figure 6.6 Electronic data recorder. 
(Photo courtesy of Corrpro Compa- 
nies, Inc.) 



used with a distance measuring "chainer," data can be gathered and plotted showing 
voltage versus distance. Several of the accessories used in the over-the-line survey are 
illustrated in Section 2 of this chapter. 



Wall Thickness and Pit Gages 



While the corrosion engineer is primarily concerned with the elimination or reduction of 
corrosion, sometimes it is necessary to quantify the remaining wall thickness of a pipeline. 



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PIPE PIT GAGE 

IP AT t,97« H ftl2) 



USEFUL FORMULAS 
AREA s 0.7B54 X D 2 
CIRCUM = 3.1416X0 
SURFACE = 3.1416 X OXL 
PRESSURE s-^f^- 

S = FIBER STRESS 
T = WALL THICKNESS 
D ^ PIPE DIAMETER 
P. PRESSURE 
L = LENGTH 



1 US. GAL ^231CUIMS. 
1 U.S, GAL. = 8.33 LBS, - WATER 
1 U,S. GAL. = 83 IMPERIAL GAL. 
7.48 U.S. GAL* = 1 CUBIC FOOT 
42U.S,GAL. = 1 BAHREL ^^ 

&P 



1 CU. FT AIR 
s 0,0009 LBS 







Figure 6.7 Pipe pit gage. (Photo courtesy of KTA Tator and W. R. Thorpe Co.) 



The traditional pit gage, as shown in Figure 6.7, is a very handy tool for the measurement 
of pit depth. These gages are small, reasonably accurate and can be carried easily in a 
toolbox or briefcase. Care must be taken to use them properly, and to understand their 
limitations. 

For instance, on all but the largest diameter pipes, this instrument must be aligned 
lengthwise with a pipeline, and must rest on an even surface. On severely pitted or 
partially coated structures, such a gage may offer only a rough estimation of pit depth, 
if it cannot be properly aligned. A more accurate pit gage is shown in Figure 6.8. It does 
not require such a large, flat surface for accurate positioning. However, it is more fragile 
as well as somewhat more expensive. 

Another non-destructive device for gathering corrosion data is the ultrasonic wall 
thickness gage, such as shown in Figure 6.9. This device, and those similar to it, can ac- 
curately measure wall thickness using ultrasonic (sound) waves. They operate by com- 
puting the elapsed time between echoes produced when an ultrasonic pulse is passed 
through a material. By knowing the velocity of sound in that particular material, the 
thickness is calculated. Other more sophisticated versions offer features such as data 
storage and data printing capabilities, and display-screens showing the actual wave- 
form and soundpath echo. These devices can detect and characterize flaws within the 
steel plate itself, and some can measure wall thickness through various coatings. All 
ultrasonic measuring devices must be periodically calibrated and have certain impor- 
tant limitations to their use. Worn or improperly used transducers, for instance, can give 
erroneous readings, sometimes twice or three times the actual value. Knowledge of the 
material being tested is also important, because the speed of sound varies from material to 
material, and can be altered by temperature, heat treatment, and other material qualities. 



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Figure 6.8 Dial type pit gage. (Photo courtesy of KTA Tator 
and the L. S. Starrett Co.) 



Current Interrupters 



The ability to interrupt cathodic protection current is an important and frequently used 
technique in cathodic protection testing. A variety of current interrupters are available, 
most of which offer the benefits of precision timing and the ability to synchronize multiple 
interrupters. The device shown in Figure 6.10 relies on a quartz crystal for accurate 
timing and can serve as a master unit to synchronize similar interrupters. Other devices 
are manufactured with sophisticated timing clocks, which can be programmed to run 
pre-set timing cycles during the day (when surveys take place), and return to a closed 
circuit at night (Figure 6.11). This feature saves time because the survey crew does not 
need to return to the unit each morning for re-installation. It also minimizes structure 
depolarization because of unnecessary off-cycling. 



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Figure 6.9 Ultrasonic wall thickness gage. (Photo courtesy of Panametrics.) 



When using any interrupter it is important to follow the manufacturer's recommen- 
dations on the maximum allowable current (either AC or DC) that the instrument can 
safely handle. It is also important to recognize the amount of drift in the timing of multiple 
current interrupters. The industry is beginning to overcome this limitation by using the 
clock transmission from satellites for interrupter timing (Figure 6.12). To incorporate this 
feature into corrosion testing requires that the interrupter's receiving antenna gathers 



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Figure 6.1 Quartz crystal controlled current in- 
terrupter. (Photo courtesy of Nilsson Electrical 
Laboratory Inc.) 

frequent and accurate satellite communication data. If battery operated, these instru- 
ments will require monitoring to replace batteries regularly during extended surveys. 



Pulse Generators and Analyzers 



The pulse generator is gaining acceptance as an alternative to traditional current inter- 
ruption. The pulse generator is installed in the cathodic protection power supply and 
momentarily interrupts the output in a precisely timed pattern. The interruptions are ex- 
tremely brief and occur in a repetitive cycle. Pulse generators can be installed in multiple 
rectifiers (or other CP power sources, including galvanic systems) and an "on/ off" sur- 
vey conducted with a portable analyzer. 



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Figure 6.1 1 Programmable current interrupter. (Photo courtesy of 
M. C. Miller Co.) 




Figure 6.12 Satellite controlled current interrup- 
ter. (Photo courtesy of Corrpro Companies, Inc.) 



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The analyzer recognizes these multiple momentary current interruptions and, using 
an algorithmic analysis, calculates the overall "off " potential of the protected structure. 
It is critical to ensure that all pulse generators are operating, and that they are each set 
to a timing cycle that exactly corresponds to the algorithm analyzer. These analyzers 
also have a finite limit to the number of pulse generators that they can recognize, so 
this must also be taken into consideration when surveying or interpreting survey data. 
When used correctly they offer the advantage of measuring "off" potentials at every test 
site, without the installation of numerous specialized test stations. A disadvantage to 
permanent pulse generator installation is that the pulsing signal may be confusing to 
the operators of neighboring utilities who happen to see this pattern during surveys of 
their own structures. To avoid this, permanently installed generators can each be set to 
steady-state operation. 



Pipe and Cable Locators 



During the course of corrosion testing, it is sometimes necessary to determine the location 
of buried items such as the pipeline being worked on, the location of foreign utilities, 
groundbed cables and other concealed metallic structures. The pipe and cable locator 
can be a great time-saver in such a case. Pipe and cable locators impress an electrical 
signal onto the target line, and this permits a hand-held receiver to detect their location. 
Electrical contact with the metallic structure being located need not be made, although 
conductive locating is generally much more accurate than inductive. Figure 6.13 (a) and 
(b) show two commercially available instruments. 

The type of signal that is transmitted to the pipe (or cable) can vary from manufac- 
turer to manufacturer, and can even be variable within a single locator. Alteration of 
the signal frequency allows the operator to select the most appropriate signal for the 
application. For example, poorly coated pipes, well coated pipes, shorted pipelines, and 
insulated cables, might each be best located using different frequencies. It is imperative 
to remember to set both the transmitter and the receiver to matching frequencies. 

Other locator features can be useful in cathodic protection work. Some transmitters 
have a clamp accessory that can be clipped around a conductor to induce the signal, 
such as when tracing a live electrical cable. This technique saves time as well as enhances 
safety. The clamp can be placed around an electrical conduit leading to a rectifier, for 
instance, so that unlocking and opening the rectifier enclosure becomes unnecessary. Of 
course, if the conduit contains multiple conductors, verification of a correct tracing may 
be necessary. 

Advances in locator technology have also enabled a variety of attributes to be incorpo- 
rated into pipe and cable locators. Depth measurement capability has greatly improved 
and allows the operator to measure, with increasing confidence, the depth of the target. 
Other pipe locators have the ability to measure and trace the amount of signal current be- 
ing conducted by the pipeline or cable (Figure 6.14). These locators can trace the pipeline 
as well as improve the operator's ability to analyze and evaluate the pipe's current- 
carrying characteristics. Tools such as these are becoming accepted in locating electrical 
shorts to distribution networks. By tracing current flow and magnitude, unintended 



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Figure 6.1 3(a) Pipe and cable locator. (Photo courtesy of Radiodetection.) 



shorts can be rapidly found. Operator experience with pipe locators is valuable in utility 
operations in general, and particularly effective in cathodic protection administration. 



Ammeter Clamps 



The measurement of AC or DC current flowing through a pipeline or cable is obviously 
a useful kind of measurement in cathodic protection work. However, shunts or "current 
spans" may not exist at a location where a measurement is necessary. If the pipe or 
cable is made accessible, a portable non-contact ammeter clamp can measure the current 
magnitude and direction of flow. These devices rely on the relationship between current 



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Figure 6.13(b) Pipe and cable locator. (Photo cour- 
tesy of Fisher.) 

flow in a conductor and the electro-magnetic field that it generates. They use amplifying 
coils positioned around the pipe or cable such as shown in Figure 6.15. These clamps 
are quite specialized in that they must fit around the pipe being tested. They are also 
a tool for which there is no substitution in certain applications. They can be used in 
interference testing, short locating, fault detection, and to identify bad insulating joints. 
The proper use of ammeter clamps requires careful attention to coil orientation, magnetic 
interference, nearby current flow, and polarity interpretation. 



Insulator Checkers 



Portable, battery-operated instruments that check the integrity of insulators find a very 
valuable place in cathodic protection and corrosion control. 

Devices such as that shown in Figure 6.16 can not only identify shorted flanges, 
but when tested individually, can detect shorted bolt-sleeve-washer assemblies. They 
can also test other insulating assemblies, such as dielectric insulating unions. These 



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Figure 6.14 Pipe and current tracing transmitter. (Photo courtesy of Radio- 
detection.) 



instruments are affordable and can rapidly test critical insulating devices before they are 
backfilled. 



Test Rectifiers 



Current requirement tests, groundbed testing and CP design work require portable 
power supplies. A common automobile battery may suffice for some of these tests, but 
an adjustable power supply is more appropriate and more versatile (Figure 6.17). Most 
rectifier manufacturers offer portable, adjustable power supplies that can be carried into 



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Figure 6.1 5 Non-contact ammeter clamp. (Photo courtesy of William H. Swain Co.) 



the field and used as convenient and temporary rectifiers. Optional features, such as 
built-in current interrupters or unusual input/ output options can be ordered with such 
equipment. 

Portable rectifiers, of course, require an AC power source. Low-current power sup- 
plies that are battery powered are also available. They are adjustable, and within the 
limits of their battery source, are very useful in short-term tests, such as current require- 
ment testing, short-locating, and tests of steel casing-to-pipeline continuity. Figure 6.18 
shows one such compact power supply. 



Holiday Detectors 



Many corrosion engineers might never use a holiday detector because the pipelines they 
protect have been buried and, perhaps, well protected for many years. However, in 
new construction and during rehabilitation projects, these instruments are important to 
corrosion control. 



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Figure 6.1 6 Insulator checker. (Photo courtesy of Tinker and Rasor.) 



For bonded dielectric coatings, one must ensure that a pipeline, for instance, is in- 
stalled with a coating of the highest integrity. Scrapes and tears are readily discernible by 
visual inspection; however, pinholes and small holidays are not. A holiday detector will 
help to find them by impressing an electrical voltage across the coating. An electrode 
then passes over the entire coating surface and as it crosses a coating defect, it gives 



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Figure 6.1 7 Portable test rectifier. (Photo courtesy of Corrpro Companies, Inc.) 

off an electrical discharge, or spark, which signals the operator that a holiday has been 
detected. The operator can then mark the holiday for subsequent repair prior to company 
acceptance. Holiday detectors must be selected for the thickness and type of coating be- 
ing tested. Excessive voltage can stress or damage thin coatings if the detector has been 
set too high. Adherence to the manufacturer's instructions is recommended, including 
both the manufacturer of the coating and the manufacturer of the holiday detector. NACE 
International also publishes a recommended practice (RP0274) for high voltage holiday 
detection. 



ACCESSORIES 



Reference Electrodes and Coupons 



Cathodic protection testing depends largely on the proper use and interpretation of pipe- 
to-electrolyte measurements. These determinations, in turn, rely on reference electrodes. 



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Figure 6.18 Portable battery operated D.C. power supply. (Photo cour- 
tesy of Tinker and Rasor.) 



Similarly, the use of buried test coupons is another tool in the evaluation of CP's effec- 
tiveness. 

The type of reference electrode the corrosion technician uses is dictated by the 
environment in which the electrode is used. Predominantly, copper-copper sulfate 



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Figure 6.1 9 Portable copper-copper sulfate reference electrodes. (Photo 
courtesy of M. C. Miller Co.) 



(CSE) electrodes are used, but other types are common and often necessary. Silver-silver 
chloride and zinc-zinc sulfate are also used in corrosion measurement applications, par- 
ticularly in high chloride environments such as seawater. All reference electrodes are 
available in transportable models as well as models manufactured for permanent burial 
or immersion. 

Portable reference electrodes have a variety of configurations as seen in Figure 6.19. 
Note that some have a large sensing area for use where maximum soil contact is desirable. 
Other slim models can be used where only a narrow soil access is available, such as in 
small test holes drilled through pavement. These can also be easily transported in a shirt 
pocket or briefcase. 

The antimony electrode (Figure 6.20) is an accessory that can measure the pH (acidity) 
of soil or water. It does not measure a cathodic protection potential, but can help conduct 
soil evaluations, and is helpful during forensic work. 

Reference cells are also used in permanent installations. These are buried or sub- 
merged adjacent to a structure with test leads routed to an accessible test station. Other 
reference electrode configurations (Figure 6.21) incorporate a test coupon built into the 
electrode assembly. These devices represent a discreet sample of the subject steel, usu- 
ally connected within the test station. The coupon simulates a bare portion of, or coating 
holiday in, the steel. This device enables the corrosion engineer to determine the amount 
of protection being afforded the structure. The devices can also be disconnected (or 
interrupted) from the CP system to evaluate the polarization level. 



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Figure 6.20 The antimony electrode for measurement of 
pH. (Photo courtesy of Agra.) 




Figure 6.2 1 Reference cell equipped with a test coupon. 
(Photo courtesy of Borin Manufacturing.) 



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When using test coupons, it is important to use an alloy identical to that of the 
protected structure. Following coupon installation, it will take some time to stabilize the 
coupon at a level representative of the true corrosion activity. 

Reference electrodes should always be selected for compatibility with the environ- 
ment in which they will be used. Copper sulfate electrodes are easily contaminated by 
saline or brackish environments that have high levels of ionic chlorides. If a portable 
reference electrode is suspected of contamination, it should be cleaned and re-filled with 
fresh solution. Reliance on a single electrode for field work is never advisable, for it pre- 
cludes both cell-to-cell comparison, and the redundancy of having a spare cell on hand. 
Reference electrodes require maintenance to ensure accuracy, and must be periodically 
"re-charged". They should also be periodically checked against a standard to determine 
if further maintenance is required. 

Reference electrodes also can be equipped with accessories to make them more ver- 
satile. Waterproof adapters can be fitted onto the cell, which attaches it to a long, well- 
insulated and waterproof wire and makes the electrode submersible. Electrode exten- 
sions can also be fabricated or purchased for over-the-line walking type surveys on land. 



Meter Accessories 



Meter manufacturers as well as corrosion specialty suppliers offer many accessories to 
be used with corrosion test equipment. Wire reels, for instance, are indispensable for 
many test applications. They can be configured in many ways, dependent upon wire 
gage and length of cable. Figure 6.22 shows several of those available. The integrity of 
the insulation must be maintained for accuracy, as 'skinned' insulation can compromise 
many measurements if the copper wire becomes shorted to other structures, or to earth. 

Meter manufacturers also offer a variety of test leads, carrying cases, and complemen- 
tary accessories, such as temperature probes. These usually plug directly into the meter 
and will accommodate the variety of conditions encountered by a corrosion technician. 
Insulated leads and test clips are always recommended, especially if higher current or 
voltage applications are encountered. Custom-made leads and connectors can also be 
fabricated to suit a particular situation. 

Portable shunts are available, some, such as in Figure 6.23, can plug directly into the 
voltmeter and allow current measurement to be made at any cable connection point. 
As with any permanently installed shunt, portable shunts must be used with careful 
observation of rating and capacity. 



Resistance Accessories 



Several complementary accessories are available for use with a resistivity meter. Soil 
pins can be purchased, and should be selected for the degree of service to which they 
will be subjected. A corrosion engineer with only an occasional need to measure soil re- 
sistivity might suffice with the use of large screwdrivers, or other improvised temporary 



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Figure 6.22 Wire reels. (Photo courtesy of M. C. Miller Co.) 




Figure 6.23 Portable shunt. (Photo courtesy of Agra.) 



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Instrumentation 




Figure 6.24 Soil resistivity pins. (Photo courtesy of M. C. Miller Co.) 



electrodes. Alternatively, a substantial amount of survey work, or work in highly com- 
pacted soil, might justify the purchase of more durable electrodes. Long stainless steel 
pins equipped with handles suitable for repeated hammering are available if needed 
(Figure 6.24). 

If multiple soil-depth resistivity measurements are to be taken, a convenient selector 
box can be used. It enables the technician to install a long series of properly spaced 
pins into the ground, and then gather data for many soil depths without returning to 
reposition the pins. This is done by switching the selector box to connect the correct 4-pin 
array to the resistance meter. 

The soil box is a valuable accessory used in conjunction with a standard resistivity me- 
ter. Soil boxes are designed for connection to the potential and current terminals of these 
meters, usually with only a multiplication factor to remember (Figure 6.25). However, 
the soil box can permit the disadvantages of improper sample handling, compaction, and 
moisture preservation. Nevertheless, the soil box offers substantial information about 
the corrosivity of a particular soil, and can be valuable when combined with laboratory 
soil work. 



Close Interval Survey Accessories 

A number of accessories have been developed to gather multiple pipe-to-soil potentials 
in relation to distance. These include wire carrying and measuring backpacks, refer- 
ence electrode extensions, and numerous other devices to make the long pipeline survey 



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Accessories 



127 




Figure 6.25 Soil resistivity box. (Photo courtesy of M. C. Miller Co. 



accurate and efficient (Figure 6.26). Many of these systems are designed to work in 
conjunction with proprietary software and plotting programs. Close interval survey 
equipment may also include related current interruption equipment that can be inte- 
grated into the survey to gather "on" and "off" data. 




Figure 6.26 

nies, Inc.) 



Close interval survey equipment. (Photo courtesy of Corrpro Compa- 



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128 Instrumentation 



CARE AND MAINTENANCE 



Correct handling and maintenance of corrosion test equipment used in the field will pay 
dividends in ensuring the reliability of the instruments and the procurement of accurate 
test data. The following suggestions are given as a guide. 

Probably the greatest cause of damage to sensitive test equipment is inadequate 
protection during transportation. When carrying equipment in cars or trucks, sensitive 
instrumentation should be protected from road shock and should be secured so that 
the various items of equipment will not slide about and knock against each other. In 
addition, electronic instrumentation should be protected from moisture and road dust. 
The corrosion engineer must also decide which instruments are needed on a routine basis, 
and which are better left in storage and carried into the field as necessary. Deploying 
every imaginable instrument into the field may be impressive; however, it brings a greater 
obligation to proper equipment care and maintenance. 

Long-term reliability of corrosion test equipment also involves documentation and 
record keeping. 

Meter serial numbers, warranties, instruction manuals, and purchase records should 
be kept in an orderly fashion so that repair or replacement can be done as necessary with 
minimal interruption to productivity. 

Calibration records should also be kept, particularly when survey work involves legal 
or regulatory issues. Oftentimes calibration must be traceable to the National Institute 
of Standards and Technology (NIST 3 ), and such documentation should be maintained. 
Evidence of traceability for a particular instrument is available from the instrument 
manufacturer, although certain limitations and fees are usually involved. 

Portable instruments rely on batteries that are inexpensive and easily replaced, but 
easily overlooked. The corrosion technician should carry spares for each type of battery 
used. Consideration should be given to the use of rechargeable batteries for instruments 
using larger, frequently drained batteries (Figure 6.27). Meters used infrequently should 
have the batteries removed to prevent leakage and subsequent damage to the instrument 
components. 

Copper sulfate reference electrodes should be kept clean and uncontaminated. The 
copper sulfate solution must be a saturated solution; that is, crystals are visible in the solu- 
tion at ambient temperature after sufficient time is allowed to reach solution equilibrium. 
The copper rod may be cleaned when it becomes encrusted or if it is suspected that the 
copper sulfate solution is contaminated. The rod can be sanded with fine, nonmetallic 
sandpaper. The use of metal-containing sandpaper will embed foreign metallic particles 
in the copper rod and can compromise accuracy. Disposal of used copper sulfate solution 
is also now regulated in some areas because of its potential for environmental impact. 
Consult with local regulations before disposing copper sulfate solution. 

Reference cells stored in or subject to freezing conditions can be filled with anti-freeze 
solution. These must be periodically refreshed, just as with ordinary electrodes. Electrode 
tips may occasionally require replacement, particularly if they are routinely used in close 
interval survey work. 

3 National Institute of Standards and Technology, Gaithersburg, Maryland. 



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Care and Maintenance 



129 




Figure 6.27 Rechargeable battery. (Photo courtesy of Nilsson Electrical Laboratory.) 



Always remember that test equipment should be handled and maintained in top 
working condition. This is essential for optimum results when conducting field tests and 
surveys. Even the most sophisticated instrumentation is of no value if used incorrectly 
or improperly maintained. 



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Chapter 



Ground Bed Design 



Ronald L. Bianchetti and Steve McKim 



This chapter will provide a guideline for design of anode ground beds and serve 
as a nucleus for the development of design procedures for the pipeline corrosion 
engineer. 



LOCATING GROUND BED SITES 

Previous chapters (3, 4 and 5) have provided basic considerations involved in deciding 
approximately where cathodic protection (CP) current will be needed and how much 
will be required. Once these decisions have been made, specific installation sites for 
ground beds may be selected and proper designs prepared. 

In selecting ground bed sites, the most important consideration from a design stand- 
point is determination of effective soil resistivity. The discussion on measurement and 
analysis of soil resistivity in Chapter 5 serves as a guide. Other considerations that must 
be taken into account when selecting a site include the following: 

• Are other underground metallic structures within the area of influence surrounding 
the ground bed? If so, they may pick up current from the ground bed and create a 
stray current interference problem that will require corrective measures if the site is 
used. This is important when planning impressed current ground beds. 

• Is the proposed site on or off the pipeline right-of-way? If off (as is apt to be the case 
with impressed current ground beds), can right-of-way be procured? Check with the 
pipeline right-of-way department on this. 

• If a rectifier-powered impressed current system is to be installed, is there a power line 
present? If not, is a power line extension from the nearest source practicable? 

• Is the site reasonably accessible for construction and maintenance purposes? 

• Are there plans for building construction (new pipelines, highway development, or 
other similar work) that will make the site untenable in the near future? 

131 



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132 Ground Bed Design 



In most cases, locations for galvanic anode installations are easier to select than those 
for impressed current ground beds because they usually can be placed within the pipeline 
right-of-way, are independent of power sources, and are relatively free of interference 
with foreign underground structures. Impressed current ground beds may be located at 
certain sites by compromise rather than other sites with more favorable soil resistivity 



DESIGNING THE GROUND BED 

Once ground bed locations have been selected for either impressed current or galvanic 
anode systems and the effective soil resistivities for design purposes have been deter- 
mined, the design process can proceed. Designs are reasonably simple when design 
charts are available, and many companies utilize such charts. These charts are typically 
based on the type of anode and construction to be employed. Determining effective soil 
resistivity is prerequisite to all decisions before designing the system. Because of all of 
the variables involved, it should be recognized that the design calculations for completed 
ground bed resistance may not be highly precise. The design engineer can consider the 
design successful if the final completed ground bed resistance is consistently within 10% 
of design calculations. 



Impressed Current Ground Beds 



Design charts for impressed current ground beds should be based on the types of an- 
ode construction adopted by the corrosion engineer for his pipeline system. Typical 
construction sketches will be shown to illustrate principles involved, but others may be 
used if found more suitable for specific pipeline conditions. 

Figure 7.1 illustrates one form of vertical anode installation. The figure includes the 
essential features only. The carbonaceous backfill surrounding the anode, when well 
tamped, serves two functions: 

• Being of a very low resistivity, it has the effect of increasing the anode size with 
resulting reduction in resistance to earth, and 

• Most of the current is transmitted to the backfill from the anode by direct contact so 
that the greater part of material consumption should take place at the outer edges of 
the backfill column. 

Since a positive potential (voltage) is impressed on the entire ground bed assembly, 
it is absolutely essential that all header cable insulation, anode pigtail wire insulation, 
the connection between anode and pigtail (a manufacturer's function) and insulation of 
connections between pigtails and a header cable or cable runs to a test or junction be 
completely intact and moistureproof . If this is not maintained, current will be discharged 
through insulation imperfections, causing wires to corrode and sever in a relatively short 
period of time, thus losing connections to all or part of the ground bed. Connections 
between header cable and anode pigtail must be of permanent low resistance. This may 



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Designing the Ground Bed 



133 




INSULATED HEADER CABLE TO 
POWER SOURCE AND TO OTHER 
ANODES IN GROUND BED 



mrm.&&&wn&% 



FILL CABLE TRENCH 
AND TOP OF ANODE 
AUGER HOLE WITH 
TAMPED EARTH AFTER 
COMPLETING 
CONNECTIONS 




INSULATED CONNECTION 
BETWEEN HEADER CABLE 
AND ANODE PIGTAIL WIRE 



INSULATED CONNECTION WIRE 
FURNISHED WITH ANODE 



ANODE-HIGH SILICON 
CAST IRON OR GRAPHITE 



CARBONACEOUS BACKFILL 
MATERIAL, WELL TAMPED 



AUGERED HOLE FOR 
< ANODE AND BACKFILL 



LENGTH OF SPECIFIED ANODE 
L + 5FEET(MIN) 



Figure 7.1 Typical vertical anode installation. 



be accomplished by methods such as thermite welding, soldering, or high compression 
crimp-type connections. 

The number of vertical anodes required to attain a required ground bed resistance 
can be determined by using the typical chart in Figure 7.2. The figure is based on 
all anodes being along a straight line, the most favorable ground bed configuration in 
most instances. This chart is for use with the type of anode installation illustrated by 
Figure 7.1. Similar graphs can be prepared for anode-backfill combinations of other 
dimensions. Curves on these graphs were developed using the following formulas and 
procedures. 

Total resistance of each anode to earth consists of the resistance of the anode to the 
carbonaceous backfill plus the resistance to earth of the backfill column itself. Resistance 
of the anode to backfill is obtained by using the following equation. 



0.00521p / 01 
R v = ^(2.3 log 



8L 



-1 



(1) 



where: 



R v = resistance of vertical anode to earth in (ohms) 
p = resistivity of backfill material (or earth) in (ohm-cm) 
L = length of anode in (feet) 
d = diameter of anode in (feet) 



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134 



Ground Bed Design 







on- X 




O 1 








^ X 


O IS 




i \ 


5 i n V 




: 


° °- 7 JllllllEi||l|llllllllllllllllM°- F00T ANODE SPACING HHHl 






O ========== = = =========== = = Ui^^=~~?as^= = ========= ===== 


Z ""^^ "*s»,^ '-•«..*„,_ 






1— no ^»,^^^ — »>^ — — *>«.« 














■*- 




_i - I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I 



10 15 20 

NUMBER OF ANODES 



25 



30 



Figure 7.2 Typical vertical anode design chart. 



Using a value of 50 ohm-cm for the resistivity of the carbonaceous backfill material, 
resistances are calculated for the backfill column and the anode (7 ft x 8 in and 5 ft x 2 in 
respectively in this case). The difference between the two figures is the resistance from 
the anode to the outer edges of the backfill column. For the anode construction shown 
in Figure 7.1, this was calculated to be 0.106 ohm. 

Resistance of several anodes in parallel can be calculated by the following equation: 



K „ = ^( 2 . 31 „ g ^- 1 + ! ( 2.31o g 0.6 5 6N>) 



(2) 



where: 



R v = resistance of vertical anode to earth in (ohms) 

p = resistivity of backfill material (or earth) in (ohm-cm) 

L = length of anode in (feet) 

d = diameter of anode in (feet) 

N = number of anodes in parallel 

S = anode spacing in (feet) 

The dimensions of the backfill column (7 ft x 8 in in this case) are used in applying the 
formula. Curves for 10, 15, 20 and 25-ft anode spacing are included in the Figure 7.2. The 



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Designing the Ground Bed 135 



curves do not include the anode internal resistance (anode to backfill). The resistance 
for any number of anodes in parallel from the curves must be added to the internal 
resistance of one anode divided by the number of anodes in parallel. The effect of this 
internal resistance becomes less as the number of anodes is increased. 

Curves of Figure 7.2 are for anodes in 1000-ohm-cm soil. The resistance for the 
selected number of anodes from the curves varies directly with the resistivity. For ex- 
ample, if a combination of anodes has a resistance of 0.40 ohm in 1000-ohm-cm soil 
(as indicated by the curves) but the soil resistivity for design purposes at the installa- 
tion site selected is 2400 ohm-cm, the ground bed resistance for the same number of 
anodes is 0.40 x 2400/1000 = 0.96 ohms, plus the internal resistance. For a second ex- 
ample, assume the soil resistivity for design purposes was 750 ohm-cm, the resistance 
of the same anode combination would be 0.40 x 750/1000 = 0.30 ohm plus the internal 
resistance. 

Extending this analysis, assume that a ground bed installation site has been se- 
lected where the effective soil resistivity for design purposes has been determined to 
be 2800 ohm-cm. Assume that the nearest ground bed anode will be 300 ft from the 
pipeline and that No. 4 copper connecting cable will be used. Also assume that the 
ground bed is to discharge 20 A at 24 V applied from a rectifier. 

Before using the chart, the maximum permissible resistance of the anodes must be 
determined. This is necessary because, in addition to resistance to earth of the anodes, 
other considerations must be analyzed to determine the total circuit resistance. These 
include the following: 

• Back voltage between ground bed and pipeline, 

• Resistance to earth of the pipeline at the ground bed location, and 

• Resistance of cable from the pipeline to power source and from the power source to 
and along the anodes comprising the ground bed. 

The back voltage is that which exists between the anodes and pipeline in opposition 
to the applied voltage. For ground bed anodes with carbonaceous backfill, this will 
be, usually, in the order of 2 V. Some areas of unusual soil composition may result 
in higher back voltages but the 2-V figure is used commonly for design purposes un- 
less experience in a specific area dictates otherwise. In practice, the back voltage at a 
working ground bed is determined by measuring the voltage between ground bed and 
pipeline (across the positive and negative rectifier terminals) immediately after switching 
the rectifier power OFF. The ground bed will always be positive to the pipeline. If the 
back voltage is 2 V, it means it will require 2 V of the rectifier source voltage to overcome 
the back voltage before current can flow through the ground bed. 

Resistance to earth of the pipeline depends on the quality of the pipeline coating. 
The better the coating, the higher the effective resistances at the ground bed location. In 
the example being used, if current requirement tests made at (or in the vicinity of) the 
selected ground bed location had indicated that 20 A of applied current would cause a 
change in pipeline voltage (AV) of —1.5 V to a remote copper sulfate electrode (CSE), 
the effective pipeline resistance would be 1.5/20 or 0.075 ohm. 



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136 Ground Bed Design 



Cable resistance is the additive resistance of the cable from the pipeline via the power 
source to the first anode of the ground bed (assuming that the line of ground bed anodes 
is perpendicular to the pipeline), plus effective resistance of the header cable along the 
line of anodes or individual anode cables. This effective header cable resistance is less 
than that of the full length of the ground bed because all current does not flow the full 
length of the ground bed but is diminished as each anode connected drains off its share 
of current. Although subject to variations with differences in individual anode resistance 
and possibly other factors, it is practical to use the resistance of one half of the ground 
bed header cable resistance as the effective header cable resistance. Table 7.1 includes 
data on resistance of copper conductors in the sizes commonly used in pipeline corrosion 
engineering work. 

With the above discussion in mind, the design of the vertical anode ground bed for 
the example proposed can be estimated as follows: 

• Maximum power source voltage will be 24 minus 2 V back voltage or 22 V. 

• For 20 A current output, circuit resistance can not exceed 1.10 ohm. This is determined 
by using Ohm's law (Voltage (V) divided by Current (I) = Resistance (R ), 22 V divided 
by 20 A or 1.10 ohm.) 

• Deductions from the circuit resistance must be made for the pipe-to-earth resistance 
(0.075 ohm in this example), and the resistance of the cable from the rectifier to the 
first anode. In this example use the resistance of 330 ft of No. 4 cable (300 ft distance 
given, plus 10% slack) that equals 0.082 ohms. The total resistance is determined 
by adding the resistance to earth of the anodes plus the effective resistance of the 
ground bed header cable, a variable, (0.075 + 0.082 = 0.157 ohms). These resistances 
are deducted from the total circuit resistance allowance (1.10 ohm — 0.157 ohm = 
0.94 ohm). 

• Make an assumption of the allowance to be made for the header cable resistance. As 
a first try, assume that the anode resistance alone should be 0.90 ohm. 

• Convert the 0.90-ohm anode resistance to a 1000 ohm-cm base to permit using the 
design chart. Because effective soil resistivity for design purposes for the example is 
2800 ohm-cm, the converted resistance is 0.90 x (1000/2800) = 0.321 ohm. 

• Using the chart of Figure 8.2, the indicated number of anodes at 20-ft spacing would 
be at slightly over 11. For design purposes use 12 anodes. (The number of anodes at 
other spacing would be determined in similar fashion.) 

• Header cable length for 12 anodes would be 11 spaces at 20 ft or 220 ft. Effective 
resistance would be approximately 110 ft of No. 4 cable or 0.0285 ohm. For design 
use 0.029 ohm. 

• Total anode plus header cable resistance for 12 anodes would then be ((0.308 ohm 
(from the chart) x (2800/1000)) + internal resistance (0.106/12 = .009) + 0.029 = 0.90 
ohm which is within the desired value of 0.94 ohm. 

• Following the same procedure for 11 anodes, total resistance would be approximately 
0.96 ohm, which is higher than the desired value, indicating that 12 anodes would be 
the minimum number to be used at the 20-ft spacing. 



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Designing the Ground Bed 



137 



Table 7.1 Resistance of Copper Conductors 

Resistance of Stranded Copper 
Conductors in Ohms per Foot 
Times 10" 3 at 25°C 1 



General 




Conductor 




Use 




Size (Awg) 








4/0 


0.0509 






3/0 


0.0642 


Impressed 




2/0 


0.0811 


Current 




1/0 


0.102 


Ground 




1 


0.129 


Beds 




2 


0.162 






4 


0.259 






6 


0.410 


Galvanic Anode 


8 


0.654 


Installations 


1 


10 


1.04 


Pipeline 


| 


12 


1.65 


Test Points 


i 


14 


2.62 






16 


4.18 


Instrument 




18 


6.66 


Test Leads 




20 


10.6 






22 


17.0 




Correction Factors for Other 




Temp 


erature Follow: 










Multiply 


Temperature 




Resistance at 


C = F 






25°C by: 


-10 14 






0.862 


-5 23 






0.882 


32 






0.901 


5 41 






0.921 


10 50 






0.941 


15 59 






0.961 


20 68 






0.980 


30 86 






1.020 


35 95 






1.040 


40 104 






1.059 



^C = 77°F 



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138 



Ground Bed Design 



INSULATED HEADER CABLE 
TO POWER SOURCE AND 
OTHER ANODES IN 
GROUND BED 



INSULATED CONNECTION 
BETWEEN CABLE AND 
ANODE PIGTAIL WIRE 



INSULATED 
PIGTAIL WIRE 
FURNISHED WITH 
ANODE 



ANODE CENTERED IN '1 x 1 
CROSS SECTIONAL FILL OF 
TAMPED CARBONACEOUS 
BACKFILL 



TAMPED EARTH 
FILL 




ANODE; HIGH SILICON CAST 
IRON OR GRAPHITE 



L = LENGTH OF SPECIFIED ANODE 
Figure 7.3 Typical horizontal anode installation. 



Another important consideration in selecting the number of anodes is desired anode 
life. This is discussed in detail in the Chapters 8 and 9 on ground bed materials. If the 
minimum number of anodes that will give a satisfactory low ground bed resistance will 
not result in adequate life, the number of anodes would have to be increased accordingly. 
Although, as a general principle, vertical ground bed anodes are preferable to horizontal 
anodes, it may be necessary to use horizontal construction because of unfavorable soil 
conditions at depths reached by vertical anodes. A typical method of installing horizontal 
anodes is shown in Figure 7.3. 

Figure 7.4 includes design charts that may be used for determining the resistance of 
horizontal anodes in parallel. These charts are based on the type of construction shown 
in Figure 7.3 with all anodes placed along a straight line. 

The same general procedure is followed in determining the resistance from the anode 
to the outer edges of the backfill as was used in Figure 7.2 except that the applicable 
formula (also derived from H. B. Dwight equations) is the following: 



Rh 



0.00521p / , 4L 2 + 4L{S 2 + L 1 } 1 ' 1 S {S 2 + L 1 } 1 ' 1 \ 
^^ 2 ' 31 ° g TS + L L 'J 



(3) 



where 



R h = resistance of horizontal anode to earth in (ohms) 
p = resistivity of backfill material (or earth) in (ohm-cm) 
L = length of anode in (feet) 
d = diameter of anode in (feet) 
S = twice depth of anode in (feet) 



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Designing the Ground Bed 



139 



o.u ■ 


o 


w 20 ■ ] 






S ■ 










m Y 


° 1 n - I 




O 08 _= ==^=%F = = = = = = = = = = = = = = = = = = E = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = 


^ 07 .-===^s^=b=^==^=========-=========^===-==== 


z 06 -=======ii|=============^- 15-FOOT ANODE SPACING :== 

rn n ' EEEEEEEEE%f^EEUElE^~^ 20-FOOT SPACING iEE 
w 0.5 -========= = 5^ 5 ===== ?= =^=, 25-FOOT SPACING EE 

S o.4 -========= = ===S|Jg=H== (CENTERLINE TO CENTERLINE):=z 

- 0.3 niinniniiiMi=hip|HiH=iiiMMiiMiiMiiiMiMin=i=i 

LU EEEEEEEEEEEEEEEEEEEEE__i|5E,EE__is=EEEEEEEEEEEEEEEEEEEEEEEEEE 
O EEEEEEEEEEEEEEEEEEEEEEEEE^|s==EE=^=E=EEEEEEEEEEEEEEEEEEE 

j< ::~::::::::~::::::::::::::::: 5 S^^- ( _i::- a ^^;___::~:: 


CO *=^^_^= *«.___ -="5=-.-.^- 








"*-••«. 


01 .:::::::::::::::::::::::::::::::::::::::::±::::::::::::::::: 







25 



5 10 15 20 

NUMBER OF ANODES 
Figure 7.4 Typical horizontal anode bed design chart. 



30 



Using this procedure, the resistance in 1000 ohm-cm soil of one horizontal anode installed 
per Figure 7.3 is approximately 2.22 ohms (including 0.136 ohm internal resistance). 
No specific formula applicable to horizontal anodes in parallel is known. The curves 
of Figure 7.4 were obtained by dividing the resistance of 1 anode (excluding internal 
resistance) by the number of anodes in parallel and applying paralleling factors obtained 
from the curves of Figure 7.2. To the values obtained from the curves must be added an 
amount equal to the internal resistance of 1 anode divided by the number of anodes in 
parallel. To allow for the reduced distance between nearest portions of horizontal anodes 
at a given spacing compared to that for vertical anodes at the same spacing, paralleling 
factors for 15 ft horizontal anode spacing were taken from the curve for 10 ft vertical 
anode spacing, and so forth. This is not at all rigorous but will serve as a reasonable 
guide. 

As an example, the paralleling factor for 20 vertical anodes at 15-ft spacing (from 
Figure 7.2) is 0.218 ohm. The resistance of one anode calculated from Eq 3 is 2.56 ohm. 
Paralleling factor = 0.218/(2.56/20) = 1.70. Using this factor for 20 horizontal anodes 
at 20 ft spacing, the parallel resistance would be 2.08 ohm (resistance of one horizontal 
anode excluding internal resistance) divided by 20 and multiplied by the factor. 

(2.08/20) x 1.70 = 0.177 ohm (see Figure 7.4). 



Another approach to horizontal ground bed construction involves the use of a con- 
tinuous strip of carbonaceous backfill with anodes located at intervals within the strip. 
Construction would be similar to that shown in Figure 7.3 except that the carbonaceous 



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140 



Ground Bed Design 



============================================================== 
























^ 




10- 




0-7 -iiE3r==^===========iiIIIIllllIIiIIiiI=ii===iiiiiiii=llIlIIIIII 

0.6 -ll|i*p = = = = = = ==lllll^^ 

0.4 -fEEE_EEE=|EEEEEEEEEEEEEE_EEEEE_EEE_EEEEE_EEEE_EEEE_EEEEE EEE=== 










U.O " <E 
















^^ 


2 -s 




, , , .. <^j .. . . , ^S^ 










-4 k S »»^ 


1 r ^s, 












0>1 - 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 ni^-L-U 







100 



500 



200 300 400 

GROUND BED LENGTH IN FEET 
Figure 7.5 Typical design for continuous horizontal anode. 



600 



backfill layer is continuous throughout the length of the ground bed. Figure 7.5 is a 
design curve for determining the resistance of a continuous horizontal ground bed with 
anodes on 15-ft centers with the carbonaceous backfill strip starting 5 ft before the end 
of the first anode and ending 5 ft after the end of the last anode. 

The curve in Figure 7.5 is based on the formula for a horizontal anode given earlier 
plus an allowance for longitudinal resistance of the carbonaceous backfill. This curve 
is based on carbonaceous backfill having 50-ohm-cm resistivity, a conservative value 
because a good quality backfill, well tamped, should have less than this amount. In 
using this curve, as with the other design charts, effective soil resistivity must be known 
with reasonable accuracy. 



Galvanic Anode Ground Beds 



The design of galvanic anode ground beds involves procedures similar to those used for 
impressed current ground beds. Design charts, however, differ somewhat with anode 



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Designing the Ground Bed 



141 




17-POUND PACKAGED 
MAGNESIUM OR ZINC ANODE 



AUGER HOLE 



L = LENGTH OF SPECIFIED ANODE 
Figure 7.6 Typical galvanic anode installation. 



dimensions and backfill used with them. Galvanic anodes (see Chapter 9) use special 
backfill having resistivities in the order of 50 ohm-cm. Calculations for design charts in 
this chapter, however, are based on a conservative figure of 300 ohm-cm. Using proce- 
dures described previously earlier in this chapter under Impressed Current Ground Beds, 
similar charts may be developed based on lower resistivity backfill mixtures. Figure 7.6 
illustrates two typical types of galvanic anode installation. 

The following is a calculation procedure similar to those used for impressed current 
anodes. The resistance to earth of a 17-lb packaged anode (at the left of Figure 7.6) is 
approximately 7.17 ohms in 1000-ohm-cm soil. Resistance to earth of the longer anodes 
(at the right of the figure) will range from 3.48 ohms for a 1.4-in x 1.4-in cross section 
anode to 3.38 ohms for a 2-in x 2-in cross-section anode in 1000-ohm-cm soil. As stated 
above, these figures are based on 300 ohm-cm chemical backfill resistivity. Comparable 
figures using 50-ohm-cm backfill (which reduces the internal resistance between anode 
and outer edge of backfill column) would be 6.36, 2.94 and 2.92 ohms respectively. 

For vertical galvanic anodes in parallel, design curves are provided in Figure 7.7. The 
curves shown are for 17-lb magnesium anodes at 15-ft spacing and for 5-ft long zinc or 
magnesium anodes at 15-ft spacing. Similar curves for other spacing may be calculated 
by procedures described earlier. 

Seventeen-pound anodes, being short, need not be installed horizontally except in 
specific circumstances. Longer anodes may require horizontal installation at locations 
where soil conditions are not favorable for the more usual vertical configuration. Figure 
7.8 includes a design curve that may be used as a guide in determining the parallel 
resistance of 5-ft horizontal anodes centered in a 6-ft. length of 8-in x 8-in cross section 
clay-gypsum backfill in a 4-ft deep trench with 15-ft spacing, center to center, between 
anodes. 



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142 



Ground Bed Design 



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Designing the Ground Bed 



143 







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0.06 

0.05 

0.04 



0.01 



50 100 150 200 250 

GROUND BED LENGTH IN FEET 



300 



0.03 E 

LU 



0.02 



Figure 

anode. 



7.9 Typical design chart for horizontal continuous galvanic 



Typically little can be gained by installing individual galvanic anodes in a continuous 
horizontal layer of backfill as described for impressed current ground bed installations. 
Longitudinal resistance of the higher resistivity backfill tends to prevent good current 
distribution along such a bed. If, however, continuous strip anodes are used (available 
in both zinc and magnesium), this type of backfill construction becomes practical. The 
design curve in Figure 7.9 may be used as a guide for continuous anode strips centered 
in a continuous horizontal layer of clay-gypsum backfill, 8-in x 8-in cross section, in a 
4-ft deep trench. 

As an example of galvanic anode ground bed design, assume a requirement involving 
the installation of vertical 2 x 2 x 60-in magnesium anodes (see Figure 7.6) in 800-ohm-cm 
soil to furnish 0.5 A of protective current with the pipeline polarized to —1.0 V to CSE. 
Assume that anodes will be installed on 15-ft centers, that the nearest anode will be 20 ft 
from the pipeline, and that No. 8 copper wire will be used for the header cable. Assume 
that effective resistance between pipeline and earth at the installation site is 0.4 ohm. 

The driving voltage available to force current from the magnesium anodes through 
the circuit resistance will be the polarized open circuit potential of the magnesium used 
less the polarized pipeline potential. Assume magnesium open circuit potential of stan- 
dard magnesium (Chapter 9) at —1.55 V to copper sulfate. The driving potential in this 
case, then, will be 1.55 — 1.00 — 0.10 (anode polarization) = 0.45 V. Maximum permissible 
current resistance to provide 0.5 A output will be 0.45 V/0.5 A = 0.90 ohm. 



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144 Ground Bed Design 



From the 0.90 ohm circuit resistance, subtract the effective pipe-to-earth resistance 
(0.4 ohm in this case) and the resistance of No. 8 wire from pipe to first anode (0.02 ohm 
used in this case to allow for 35 ft which will permit slack and test point connections). 
The total circuit resistance is 0.90 — (0.4 + 0.02) = 0.48 ohm for anode-to-earth resistance 
plus effective header cable resistance. Using the design curve of (Figure 7.7), convert the 
0.48 ohm to a 1000 ohm-cm soil resistivity base. 

0.48 x (1000/800) = 0.60 ohm. 

Using the curve for 60 in anodes at 15-ft spacing from Figure 7.7, seven anodes in 
parallel would be selected for the first attempt. Assuming 7 anodes, the resistance would 
be 0.55 ohm (from the curve) x (800/1000) (to convert to the 800 ohm-cm soil resistivity at 
the installation site) + (0.60/7) (the internal anode resistance) + 0.030 ohm (the resistance 
of 45 ft of No. 8 wire, half the header cable length). This equals 0.556 ohm, which is too 
high. By increasing the number of anodes by trial and error, it is found that 9 anodes will 
be the minimum number that will meet the requirements of the example. The resistance, 
by the above procedure, will be (0.45 x (800/1000)) + (0.60/9) + 0.039 = 0.466 ohm which 
is within the 0.48 ohm requirement. The above calculations were made using the higher 
resistivity chemical backfill. Using the lower resistivity (50 ohm-cm) backfill, the internal 
anode resistance would be lower and the anode bed resistance lower. 

A similar approach to that detailed above would be used for design problems in 
which other galvanic anode design charts included herein are employed to arrive at a 
desired value of anode bed resistance. The useful life to be expected must be considered 
also. See Chapter 9 for data on selection of galvanic anode materials, sizes, and life 
calculations. 



DISTRIBUTED ANODE SYSTEMS 

Distributed anodes, either impressed current or galvanic, should be considered when it 
is necessary to protect a limited area of pipeline. Typically, such systems are used on 
sections of bare pipeline or coated pipeline in congested areas where electrical shielding 
precludes effective protection with remote ground bed installations. 

The principle of protection received from distributed anode or close anode systems 
is that the length of pipeline protected by a single close anode depends on changing 
the potential of the earth around the pipeline rather than changing the potential of the 
pipeline with respect to earth. The amount of earth potential change (and hence the 
length of pipe that can be protected from a single anode) is a function of voltage impressed 
on the anode rather than the amount of current discharged by the anode. 

Distributed Impressed Current Anodes 

When designing distributed anode systems using an impressed current anode system, 
effective soil resistivity along the section of pipeline to be protected should be known. 



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Design and Installation of Deep Anode Cathodic Protection Systems 145 



(See Chapter 5.) With this information, resistance of individual anodes can be calculated 
using procedures described earlier in this chapter. The voltage to be impressed is selected 
and anode spacing is calculated using the following principles. Existing potentials to 
earth must be known along the section to be protected, so the earth potential change 
needed to attain a minimum potential of —0.85 V (pipe-to-close CSE) can be determined 
at the midpoint between anodes. The parallel resistance of all anodes is calculated. With 
allowances for header cable resistance and back voltage between pipeline and anodes, 
voltage and current requirements of the power source may be calculated. 

It should be noted if relatively long distances are covered by distributed anodes fed 
from one power source, voltage attenuation resulting from potential drop in the header 
cable (current flowing through the cable resistance) will result in reduced voltage to 
the more remote anodes than that impressed on those close to the power source. This 
should be checked during the design phase. If the difference is significant, closer spacing 
between the more remote anodes may be required to attain the same level of protection 
between anodes along the distributed anode system. 

An important consideration in determining spacing between distributed anodes is 
the additive effect of earth potential changes at midpoints between adjacent anodes. If, 
for example, the earth potential change at the midpoint between two anodes is 0.1 V 
from one anode with design voltage impressed on it and is 0.1 V from the second anode, 
the total earth potential change will be 0.2 V at the midpoint. This should be considered 
when planning spacing between anodes. 



Distributed Galvanic Anodes 



When protecting a section of line with distributed galvanic anodes by the earth potential 
change method, anodes must be close together. Wide spacing is not effective, contrary 
to what is true with impressed current anodes, because anode voltage is a function of 
the anode material (i.e. magnesium or zinc). Placing galvanic anodes at individual hot 
spots (using procedures described in Chapter 5) is a form of distributed anode system 
used effectively on bare lines or pipelines that experience random leaks over time. 



DESIGN AND INSTALLATION OF DEEP ANODE CATHODIC 
PROTECTION SYSTEMS 

Steve McKim 

In the past quarter century, deep anode cathodic protection (CP) systems have become 
an industry standard. While such installations can be very useful under most conditions, 
they are not applicable to all situations. This section discusses design considerations 
that may be used as a guide during planning and construction. Local restrictions may 
influence installation of certain deep anode configurations, and communications with 
the local authorities for further information is always advisable. 



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146 Ground Bed Design 



DEFINITION 



A deep anode system is an impressed current CP arrangement in which the anodes are 
located in wholly, or partially, electrically remote earth extending down vertically from 
the surface in a hole drilled for the purpose, or an existing hole. This achieves the same 
result obtained by locating anodes electrically remote laterally from the structure, and 
near the surface as described earlier in this chapter. 



USES AND BENEFITS 



Deep anodes provide effective CP to facilities as diverse as underground pipelines, 
storage tanks, refineries, power plants, treatment plants, pile structures, and well casings 
in areas where surface soil resistivities are either very high or, if reasonably low, are 
shallow and overlie high resistivity material. These conditions require large surface 
anodes too far from the structure to obtain reasonably low resistance electrically remote 
from the structure. 

Deep earth formations must, however, have low enough resistivity to permit con- 
struction of a deep anode that radiates the volume of current at a reasonable necessary 
impressed voltage. In deep formations with low resistivity compared to surface soils, 
excellent current distribution along the structure is expected. Even where surface soils 
are entirely satisfactory for surface anode design, deep anodes can be useful in congested 
areas where surface anodes are difficult to locate so that they will be remote electrically 
from foreign structures as well as from the structure being protected. 

Because remote earth is obtained vertically, the deep anode can be placed within the 
structure right-of-way, which is difficult with conventional surface-type remote anodes. 
As discussed earlier in this chapter, these remote earth properties provide optimum cur- 
rent distribution along the protected structure and minimize voltage gradient variation. 
These benefits allow installation of high output systems near foreign utilities and struc- 
tures with fewer negative side effects associated with surface anode systems, such as 
interference with foreign structures, hydrogen embrittlement of susceptible steels, and 
cathodic coating degradation. 

Installing systems at greater intervals reduces the overall cost of CP. The compact 
installation means less foreign utility damage during installation and less chance of sub- 
sequent system damage from other construction activities. Fewer systems mean fewer 
locations to coordinate rectifier power and negotiate easement rights, fewer rectifiers to 
maintain and less interference to investigate, correct, and monitor. 

Installing multiple anodes in one carbon column achieves maximum anode current 
discharge balance. The high level of carbon compaction in deep anodes provides maxi- 
mum electronic current discharge, thereby increasing anode life. The high probability for 
ground water provides the lowest possible circuit resistance. Properly installed venting 
systems minimize the risk of gas blockage and allow for anode irrigation with potable 



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Design Considerations 



147 



water. Inherently low circuit resistance of these anode systems minimizes the costs of 
AC power consumption. Note that many of the benefits of deep anodes are reduced 
substantially if the designer attempts to install too few systems at too great intervals. In 
areas with foreign underground structures, the maximum recommended current output 
is 30 A. 



DESIGN CONSIDERATIONS 



Figure 7.10, represents a typical deep anode installation. 

Standard features include nonmetallic vent pipe, active column consisting of multiple 
anodes placed between 5 and 20 ft apart and backfilled with coke breeze (carbon), and 
an inactive column consisting of nonconductive backfill and sanitary well seal. 

Other early deep anode configurations proved successful, although their use has 
diminished in recent years. These configurations included carbon steel pipe or heavy 
steel rails in place of fabricated anodes. Another less common deep anode configuration 
utilizes multiple anodes attached to a single header cable instead of individual cables 
from each anode. Looping the anode header cable back to the rectifier from each end 
will increase design reliability. 



2" min. annular 
cement well seal 
around vent pipe 




2" min.sch.40 

PVC vent pipe with 

perforations in 

anode interval 



Impressed current 
anode (number 
and size varies) 



Entire 10" well 

bore cemented 

through surface 

formations 



Coke breeze anode 

backfill (fluid or 

granular) 



Figure 7.1 Typical deep anode ground bed in normal soil strata. 



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148 Ground Bed Design 



Soil Resistivity 



Resistivity of deep formations may be determined by several techniques. Information 
gained from existing nearby deep anodes is most valuable. Histories of current output 
readings from individual anodes can indicate relative resistivity of downhole formations. 
Histories of rectifier outputs can indicate total anode bed resistance values. Existing soil 
logs may be available from nearby water wells or monitoring wells. This information 
can provide clues to the relative resistivity of downhole formations. 

The four-pin method of measuring soil resistivity may be used in some instances. 
Techniques described in Chapter 5 are applicable. After determining surface soil re- 
sistivities in the usual manner, deep formation resistivities may be measured with, 
first, pin spacing of 50 ft and then with spacing increased progressively by 50-ft in- 
crements until it is felt that the location has been explored satisfactorily. Relatively thin 
strata of either high or low resistivity may be missed, but average conditions will be 
determined. Measurements may be made to depths of several hundred feet but resis- 
tance values obtained will be so low that the DC method will have to be used in most 
cases. The measured change in voltage between potential pins will be small, requir- 
ing high impedance electronic circuitry. Data analysis can be achieved as outlined in 
Chapter 5. 

Obviously, when using the four-pin test to measure at greater depths, the soil pins 
will be spread over a wide area (1500 ft, for example, from first to last pin for a reading 
to a depth of 500 ft). This requires a large clear area. For accurate results, the pins must 
remain clear of all underground structures (pipelines, cables, pole line grounds, etc.) 
that could pick up or discharge a portion of the test current and upset the geometry of 
the test. Due to the free space requirements, four-pin measurements to sufficient depth 
are usually impractical in urban areas. 

If existing wells can be found in the area being investigated and if the length of 
casing and/ or tubing is known, resistance of such structures may be measured to remote 
earth. From this, the effective soil resistivity may be estimated to a depth equal to the 
length of casing and /or tubing. This is done by application of the D wight formula for 
a single vertical anode and solving for soil resistivity. Other methods of measuring 
deep soil resistivity, such as electromagnetic conductivity, are cited by Morgan in CP, 
second edition, NACE, 1993. Opportunities for application of these methods may be 
infrequent. 

Probably the most effective method of proving a location is to drill a small pilot hole to 
a depth of the proposed deep well. If natural water is not encountered, the hole must be 
filled with potable water to measure the downhole resistance. A single anode is lowered 
down the hole with a long attached wire connected to the structure in series with a battery 
(or other DC power source) and an ammeter (shunt). By measuring the current output of 
power source voltage at intervals as the test anode is lowered, a profile of current output 
with depth can be developed. This profile will reveal the best permanent anode locations 
opposite the more highly conductive earth layers, as indicated by the highest current 
outputs from the test anode. If the pilot hole proves satisfactory, it may be drilled out 



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Vent Pipes 149 



to full size for a permanent deep anode installation. Applying test anode resistance and 
dimensions to the Dwight formula at favorable anode locations may determine effective 
soil resistivity Averaging the values obtained through that part of the hole where anodes 
could be installed would give a figure that may be used for designing the permanent 
installation. 

Upon developing a figure for effective soil resistivity, the resistance for a permanent 
system may be based on the resistance of a single vertical anode, using the Dwight 
formula. As a last resort in areas of varying soil resistivities, it may be advantageous 
to install the deep anode before sizing the rectifier. This will allow actual resistance 
measurement and accurate rectifier ratings. 



Well Dimensions 



Common deep anode depths range from 50 ft to 500 ft. Prominant geologic formations 
near the proposed location may control final depth. Deeper installations may provide 
more remote earth and allow larger coverage, they also allow for more anodes, which will 
increase system life. Local regulatory authorities may constrain the design philosophy, 
so early contact is recommended. 

Most anodes have a nominal diameter of 10 in, which is achieved with a standard 
9^ in rotary drill bit. This diameter provides the most cost-effective combination of 
system life, installation cost, and operation expense. Other common drill bit diameters 
used for deep anodes are 6 in, 7^ in, 8| in, 10 g in and 12^ in. Smaller diameters reduce 
initial installation cost; however, they also shorten system life by reducing the bulk 
mass of carbon available for consumption. Smaller diameters also raise overall circuit 
resistance, which increases rectifier power consumption costs. Larger diameter wells 
reverse these effects, but cost of construction increases exponentially. Diameters larger 
than 9 1 in become quite costly in hard formations. Applications of Dwight equations 
indicate a more efficient reduction in anode resistance by increasing the length of active 
anode column rather than by increasing the diameter of active column. 



VENT PIPES 



All deep anode installations should include a method of venting produced gases to 
the atmosphere. Lack of ventilation can lead to gas blockage of anodes and eventual 
system failure. Ventilation is normally accomplished by installing nonmetallic pipe with a 
diameter between 1 in and 2 in. The vent pipe is perforated throughout the active column 
and solid through the inactive column. Standard perforations range from 0.006 in wide 
slots to \ in diameter holes and are commonly placed every 6 in of pipe length. To 
prevent plugging with inactive column backfill, perforations should end even with top 
anode. 



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150 Ground Bed Design 



Schedule 40 PVC is the most common material used for vent pipe. Schedule 80 is only 
required when head pressure from deep cement well seals could cause pipe collapse. 
Upper end of vent pipe should be terminated so produced gases are allowed to dissipate 
naturally to the atmosphere. Termination should be above any flood plain elevation. 
Vent pipe installation should be designed to allow for eventual well destruction. De- 
struction procedure could be regulated by local regulatory authorities and may include 
filling vent pipe with nonporous materials. 



Anode Suspension Systems 



The standard method of installation is to lower each anode by its attached wire, suspend 
it at the desired depth, and tie it off at the surface. This technique allows adjustment of 
anode position to low resistance soil formations and also provides a ready method to 
test for proper carbon backfill settlement by pulling on suspended anode wires. 

Some installations have separate suspension systems to hold anodes and eliminate 
stress on the attached wires using ropes, steel pipe, or the vent pipe. Anode suspension 
systems are usually not required when following proper loading procedures. Use of 
1^-in diameter steel pipe is the most common suspension system. However, it requires 
dielectric unions between anodes to allow resistance logging during backfill. Another 
disadvantage of using a metallic support material is its eventual corrosion due to contact 
with the anode circuit. This may complicate eventual well destruction. 

Use of PVC vent pipe for suspension eliminates need for dielectric unions but is 
extremely dangerous during installation. PVC vent pipe suspension is not recommended 
because of the dangers associated with vent pipe joint separation during loading. Sepa- 
ration will lead to downhole free-fall of anodes, which could result in injury to the 
installation crew. 



Anode Centering Devices 



Anode centralizers may be installed to ensure that carbon backfill surrounds each anode. 
Centralizers should be designed to prevent damage to anode wires during installation 
and allow anode movement in the well without snagging on downhole formations or 
other anode assemblies. 



Carbon Backfill 



High quality calcined petroleum coke is recommended for all deep anode installations. 
Granular carbon sinks readily in fresh water and is normally poured directly from the 
bag into the well. Fluid coke is comprised of fine carbon particles that compact tightly 
around anodes. Because of small particle size, fluid coke should be pumped from the 



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Vent Pipes 



151 




Figure 7.1 1 Typical deep anode ground bed without surface seal. 



bottom up using a pipe installed for this purpose. Fluid coke should normally be allowed 
to settle overnight and sounded prior to installation of inactive column. 



Inactive Column and Well Seals 



To eliminate anode current leakage up the inactive column, the upper section of deep an- 
odes should be backfilled with nonconductive materials. Materials include PVC casing, 
sand, gravel, and cement. Sand bridges easily during installation and is not recom- 
mended. Depth of inactive column will depend on current distribution requirements. 
Pea gravel backfill above the active column will increase the probability for ground water 
recharge. However, long columns of porous backfill can lead to commingling of aquifers 
with differing water qualities. 

All deep anodes should include a nonporous sanitary well seal in upper section of 
inactive column. Depth of seal should be 50 ft minimum and could be in excess of 100 ft. 
Seal materials include cement, concrete, and specially formulated bentonite. Depth may 
be dictated by local regulatory agency. 

Conductor casings may be required to prevent caving of surface formations during 
installation. Steel casing should be removed from inactive column within 50 ft of active 
column. PVC casings can be left in inactive column, but should be cemented into place 
to provide sanitary well seal. Top of casings must be sealed to prevent surface runoff that 
could lead to contamination of downhole aquifers. Size well diameter to provide 2-in 
minimum annular space around outside diameter of casing for proper seal placement. 



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152 



Ground Bed Design 



To 

Rectifier or 

J-box 



100' 
min. 



2" min. annular 

cement well seal 

around casing 




2" min.sch.40 

PVC vent pipe with 

perforations in 

anode interval 



Impressed current 
anode (number 
and size varies) 



10" PVC casing 

cemented through 

potential 

contamination 



Coke breeze anode 

backfill (fluid or 

granular) 



10" 



Figure 7.1 2 Typical deep anode ground bed in contaminated soil strata. 



In potentially contaminated formations, surface casing should be cemented into place 
before drilling active column. This should eliminate cross contamination during instal- 
lation and operation of anode system. 



INSTALLATION CONSIDERATIONS 

Deep anodes are normally drilled with truck-mounted rotary drilling equipment. Typical 
equipment circulates water-based drilling mud to maintain well integrity and remove 
downhole cuttings. Compressed air circulation systems may be advantageous in lim- 
ited situations where downhole formations allow their use. Installation procedures are 
critical, so use only fully qualified drillers. 



Loading Procedures 



As previously mentioned, deep anodes are ordinarily drilled with direct mud rotary 
equipment. After reaching desired depth, downhole mud slurry must be thinned to 
nearly the viscosity of fresh water to allow proper carbon settlement around anodes. 
Thinning is performed by pumping potable water from the bottom up through mud 
circulation system until it returns to surface in well bore. Accurate well thinning is 
critical to system installation. 



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Installation Considerations 



153 



Drillers familiar with proper thinning procedures are essential. Higher downhole 
fluid viscosities provide more resistance to caving of formations, but slow carbon settle- 
ment. Lower viscosities speed carbon settlement, but can lead to caving of downhole 
formations. Caving formations can bridge in well bore or settle around anodes. These 
conditions prevent carbon settlement around anodes, which will significantly decrease 
system performance and life. 

After thinning, drill pipe is removed from well to allow system loading. Vent pipe is 
usually lowered first and tied into position. Anodes are lowered by their attached wire 
to the desired elevation and tied off at the surface. After anodes are placed at desired 
elevations, carbon backfill is poured or pumped downhole. Anode resistance logging 
before, during, and after carbon backfill provides proof of proper carbon settlement. 
Settlement of top-loaded granular carbons normally occurs within 1 hr. Settlement of 
pumped fluid carbons normally takes 6 to 12 hr. Total settlement should occur before 
backfill of inactive column. 



Site Layout 



Deep anode installation equipment usually includes portable rotary drill rig, mud circu- 
lation system, water truck, drill mud and cuttings containment system, material trailer, 
and support equipment. 

Drill rig masts are normally between 20 ft and 40 ft high. Safe and legal clearance 
from overhead power lines and other obstructions is mandatory. 



Mud circulation system 

Power system 




Figure 7.1 3 Typical portable rotary mud drill rig. 



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154 



Ground Bed Design 




Figure 7.1 4 Minimum drill rig clearance dimensions. 



Drill rigs are also between 20 ft and 40 ft long. Anode location must provide enough 
space to safely place required equipment. 

Rig must be near level during drilling. Slope of anode location cannot exceed limits 
of drill rig leveling equipment. 

Containment of drill cuttings and circulation fluid must also be considered when 
choosing anode locations. 




Figure 7.1 5 Minimum drill rig clearance dimensions. 



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References 



155 




Figure 7.1 6 Maximum drill rig site slope dimensions. 



REFERENCES 



Derived from equations in "Calculation of Resistance to Ground", by H.B. Dwight. Electrical 
Engineering, p. 1319 (1936) December. 

Derived from equations in the book by Erling D. Sunde. "Earth Conduction Effects in Transmission 
Systems." D. Van Nostrand Co., Inc. (1949). 



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Chapter 



Impressed Current 
Cathodic Protection 



Ronald L. Bianchetti 



Rectifiers are used more than any other source of impressed current power. Areas dis- 
cussed include rectifier types, rectifier selection, specification requirements, and typical 
installation details. Various types of impressed current anodes and components that 
make up an impressed current system are also presented. 



RECTIFIER TYPES 



Cathodic protection (CP) rectifiers have the following major components. These typ- 
ically include a transformer to step down AC line voltage to low voltage AC on the 
secondary with a tap arrangement to permit selecting a range of voltage, a rectifying 
element (usually full wave silicon diodes for rectification), and a housing for outdoor 
mounting. These components are supplemented by an AC circuit breaker and DC output 
meters. Both single-phase and three-phase units are in common use. Figure 8.1, illustrates 
diagrammatically single-phase and three-phase units of the full-wave bridge-connected 
type. 

Where electrical storm activity is prevalent, it is advisable to provide protection 
against lightning damage. 

• Lightning surges may occur from the electric distribution line (the more probable) 
and /or 

• Surges coming from the pipeline (both from lightning and AC ground fault) 



157 



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158 



Impressed Current Cathodic Protection 




AC 
1 PHASE 
SUPPLY 



STEP-DOWN 
TRANSFORMERS WITH 
VOLTAGE ADJUSTING 
TAPS ON SECONDARY 
WINDINGS 



BRIDGE-CONNECTED 
RECTIFIER STACKS. 



■QmQmQ.Q.Q.Q.0. 



TO PIPELINE 

3-PHASE UNIT 



TO GROUND BED 



— e — 




GROUNDED SHIELD 
BETWEEN 
PRIMARY AND 
SECONDARY 
WINDINGS 



ARROW HEAD 
INDICATES 
DIRECTION OF 
CURRENT FLOW 
THRU ELEMENT 



GROUND 
CONNECTION 
FOR RECTIFIER 
CABINET 



1 



TO PIPELINE 

1 -PHASE UNIT 



TO GROUND 
BED 



Figure 8.1 Rectifier schematic diagrams. 



Specifying rectifiers having transformers with an electrical shield between primary and 
secondary transformer windings may provide some protection from lightning surges. 
Such a shield (shown in the figure), when grounded properly, intercepts the high voltage 
peak surge of a lightning pulse and carries it to ground. Otherwise, it can break down 
a rectifying element and may burn out the element. Low voltage lightning arrestors 
can also be placed across rectifier terminals and may provide protection from lightning 
surges from the pipeline. Neither type of protection, however, is effective against a direct 
strike to the rectifier itself. 

Rectifier manufacturers produce units for CP applications with a wide range of out- 
puts. Data are available in the supply catalogs of CP equipment. Three general housing 
types are available. Ventilated housings that provide for convection air cooling are used 
for most pipeline applications. Where highly corrosive atmospheres exist (marine or 
industrial, for example), the equipment may be oil-immersed in a tank-type housing. 
For locations subject to hazards and explosives an explosion proof housing is available 
for oil-immersed units. Figure 8.2 illustrates the appearance of typical air-cooled and 
oil-immersed units. 



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Rectifier Types 



159 




Figure 8.2 Typical rectifiers: (left) air cooled unit; (right) oil immersed unit. (Courtesy of Universal 
Rectifier, Inc.) 



Rectifying elements typically used in units today are silicon diodes. A silicon diode 
has high resistance to current flow in one direction and low resistance in the other. This 
characteristic makes rectification possible. The diagrams of Figure 8.1 show that for a 
given direction of current flow in the transformer secondary winding, the current can 
flow on only one route through the rectifying element (in the direction of the arrow 
heads). This flow is out the positive terminal to the ground bed and back from the 
pipeline connection to the negative terminal. When the direction of current flow in the 
transformer secondary reverses (this occurs 120 times at normal 60-cycle AC power 
frequency), the current will take a different route through the rectifying element but will 
still flow out at the positive terminal and back at the negative terminal. The result is 
direct current (DC). 

A rectifying diode is rated by the manufacturer for specific maximum current flow at 
a given ambient temperature and for maximum inverse voltage (the voltage impressed 
across the element in the high resistance direction). Diodes are assembled into stacks 
or assemblies with series-parallel combinations to attain the over-all DC voltage and 
current rating needed for the rectifier produced. In older rectifiers, the rectifying elements 
were selenium stacks or discs, but modern rectifiers use mainly diodes as rectifying ele- 
ments. Rectifying elements have been continuously improved over the years in operating 
characteristics and efficiency. The rectifier user is advised to review developments in this 
field and replace older rectifying elements with improved stacks when justified by the 
improved characteristics and efficiency of newer ones. 

Cathodic protection rectifiers may be equipped with filters in the DC output which 
smooth out the ripple in the rectified DC and permit higher over-all efficiency. These 
filters are practical where savings in power cost justify the additional investment. 



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160 Impressed Current Cathodic Protection 



Under certain circumstances, "constant potential" rectifiers are useful on pipeline 
systems. Such rectifiers are designed to maintain a constant protective potential on the 
pipeline at the rectifier location, which changes to match pipeline current requirements. 
Applications include areas subject to stray current from transit systems or in mining 
operations where potential variations are not beyond the corrective capacity of this type 
of unit. Use with ground beds subject to wide seasonal variations in resistance (wet to 
dry) is also included. 

Constant potential rectifiers (see Figure 8.3) differ from more conventional rectifiers 
(which require manual adjustment of transformer taps to change output) in that a sensing 
circuit that maintains continual checks on the pipe-to-soil potential changes the output 
current automatically. Typically, this can be accomplished by burying a permanent ref- 
erence electrode at the point where constant pipe-to-soil potential is to be maintained. 

Once the rectifier is adjusted for the desired pipe-to-soil potential, any increase in 
absolute value of this potential serves (through the electronic controller) to increase the 
reactor reactance. This cuts the output current back until a balance at the preset potential 
is regained. Likewise, any decrease in absolute value of this potential between pipeline 
and reference electrode will cause the rectifier output current to increase automatically 
until balance is regained. 



SELECTION OF RECTIFIER SIZE 



Rectifier size (output rating) will depend primarily on the current requirement at the 
installation site and the output voltage required to force the current through the pipeline 
to ground bed circuit resistance. Current requirement tests, or other design procedures, 
determine the amperage. Circuit resistance is determined by the ground bed design as 
discussed in Chapter 7. 

The output voltage rating should be sized 15 to 25% over the design-calculated value 
to allow for any change in ground bed resistance. This permits maintaining full rated 
output when ground bed resistance goes up as the anodes deteriorate with age. Final 
output ratings for current and voltage can then be coordinated with standard output 
ratings defined on the rectifier name plate or manufacturer's catalogue data. 

Initial rectifier current ratings can give some understanding of future system require- 
ments as outlined in the following examples. For example, the current needed to protect 
a section of bare line is not likely to increase with time, the rectifier may be sized to 
meet the existing design current requirements. On the other hand, a newly laid well- 
coated pipeline may initially require only a small amount of current, but as the coating 
stabilizes with time (or deteriorates from soil stress, temperature effect, etc), it may re- 
quire several times the initial current. In these cases, it is practical to install rectifiers hav- 
ing maximum current capacity several times greater than the initial requirement. Coated 
lines that have been in the ground for a long enough time to become well stabilized do 
not tend to require as much reserve capacity. No firm rules can be established, however, 



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Selection of Rectifier Size 



161 



AC SUPPLY 



SATURABLE 
CORE 
REACTOR 
(SCR) 




ELECTRONIC 
CONTROLLER " 



CIRCUIT BREAKER 




ULQJLQJUUU 



Twnnnnnnnr 



PIPE 





(y) 



SHUNT 



TRANSFORMER 



TO GROUND BED 



RECTIFIER STACK 



REFERENCE ELECTRODE 



Figure 8.3 Typical constant potential rectifier diagram. 



because variables such as length of pipe section protected, coating used, changes in soil 
conditions, probable temperature effects, and other conditions will apply in each case. 
Experience with conditions on the pipeline corrosion engineer's own system will help 
to make proper current rating determination. 

When time permits, some pipeline corrosion engineers design and install impressed 
current ground beds before deciding on the rectifier rating. Following this procedure, it 
is possible to measure the installed circuit resistance and make new current requirement 
tests using the completed ground bed. Rectifier voltage and current ratings may be 
selected with full assurance that the installation will work as planned. Although results 



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162 Impressed Current Cathodic Protection 



are positive, this procedure does require more time and involves additional expense for 
repeat visits by the construction crews to make rectifier installations. However, when 
ground bed designs can be prepared with reasonable accuracy, this procedure is not 
necessary 

In determining power costs, the corrosion engineer should recognize that the smaller 
rectifiers along the pipeline (well coated pipelines particularly) may draw so little power 
that the costs do not exceed the power company's minimum billing (where applicable). 
In such instances, relative efficiency of the rectifier may have little bearing on economic 
choice. 

Although rectifiers operating on three-phase power are more efficient than single- 
phase units, three-phase power may be available at relatively few locations along a 
pipeline. Where it is available, the choice between single-phase and three-phase units 
should be based on a relative cost study. Results of this study can be expected to favor 
three-phase units for large installations. 

The use of filters for improvement in efficiency should be considered only when they 
will reduce the net annual cost of the complete installation. The savings will be a result 
of a reduction in power cost. Applicable power rates must be determined when making 
cost comparisons. Rectifier manufacturers who furnish filters for their equipment should 
provide data on efficiency improvement. 



RECTIFIER SPECIFICATIONS 



After deciding on the size and type of rectifier to be used, ordering specifications must 
include at least the following information in order to ensure obtaining the correct unit 
when purchasing from the standard lines of rectifier manufacturers. 

1. AC input: Voltage, single or three phase and frequency. For example: 120/240 V, 
single phase, 60 cycles. (The expression 120/240 means that the unit may be field 
connected for operation on either 120 or 240 V AC). 

2. Maximum DC output in amperes and volts. 

3. Air-cooled, oil-immersed, or oil-immersed and explosion-proof. 

4. Pole mounting, wall mounting, or floor (pad) mounting. 

5. Silicon type rectifying element and either full wave bridge or full wave center tap. 

6. Maximum ambient operating temperature. 

7. Protective equipment: Circuit breaker in AC input. Shielded transformer winding. 
Lightning arrestors, etc. 

8. Instruments: Voltmeter and ammeter with accuracy (such as 2 percent of full scale). 

9. Provisions for external current shunt terminals and potential terminals for periodic 
check of rectifier instruments should be specified. 

10. Case construction such as anodized aluminum, galvanized, coated steel or small 
arms proof. 



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Rectifier Efficiency 163 



When standard units do not meet needed requirements, it is necessary to specify 
additional provisions. These may include an output filter for efficiency improvement, 
additional positive terminals (for leads from individual deep-well ground bed anodes 
for example), additional negative terminals where current is to be drained from more 
than one pipeline, additional current measuring shunts, lightning arrester or other special 
protective equipment, special housing finish and /or design, and other special features as 
required. Special provisions such as those above may be supported by an accompanying 
drawing where necessary to clarify requirements. 

Some users of large numbers of CP rectifiers prepare standard detail specifications, 
which include minimum requirements for all components of rectifier assemblies. These 
are used to make equipment uniform instead of ordering units from a manufacturer's 
standard line. Unless the number of units ordered is substantial, this can involve extra 
cost because manufacturers may have to modify their standard production techniques 
to meet the specifications. 



RECTIFIER EFFICIENCY 



In addition to the type of rectifying elements used and whether or not an output filter is 
used, rectifier efficiency is affected by the percentage of current or voltage loading. The 
effect is illustrated by Figure 8.4, which shows typical efficiency curves for units operated 
(1) at full current but reduced voltage and (2) at full voltage but reduced current. 

Curves shown are for illustration only and should not be used for calculations. If 
calculations are required, use the curves applying to the equipment being considered. 
The curves in the figure show that efficiency suffers most when units are operated at a 
small percentage of the rated voltage. 

The actual overall efficiency of an operating rectifier unit may be determined as 
follows: 

rr . . . DC power output 

Efficiency in percent = r- 1 — x 100 

AC power input 

The DC power output is the output current multiplied by the output voltage. The AC 
power input may be measured by a wattmeter. If the rectifier has a kilowatt-hour meter 
(provided by the power company) measuring the power taken by one rectifier only, use 
it to measure the power input. If the meter is marked with a meter constant, measure the 
number of seconds for the meter disc to make one revolution. The power consumption 
is then (3600 s/h/s for one disc revolution) x meter constant = watts input. The meter 
constant is usually shown on the face of the kilowatt-hour meter. 

Simply measuring the AC input voltage and current and multiplying them to get 
the AC power input neglects power factor and will not be accurate. If, however, it is 
impossible to measure the true power input, using the input current and voltage will 
yield a reasonable approximation. If this is done, subsequent efficiency measurements 



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164 



Impressed Current Cathodic Protection 



ou 









































































































































.'* 


































„,*>' 




































^% - 




































^7 v- 


































60 - 


-£ X- 




































^ * 


































- 




































1 






















































1 










EFFICIENCY VS. PERCENT OF 
;. RATED CURRENT AT FULL RATEC 
- VOLTAGE. 






I 






























































































tk 




































-i \ - 




































t \ 




































J N 




































1 


.s 






I EFFICIENCY VS. PERCENT OF 








7 


V 












r 










RATED VOLTAGE AT FULL RATED 






















: 1 


































^U -; I 








































































i 




































17 




































1/ 




































fit 




































DT 




































it 




































it 




































o+LU 





































10 20 30 40 50 60 70 80 90 
PERCENT OF RATED VOLTAGE OR CURRENT 



100 



ou -■ 
































































































































































































































































































































































































5 




























































bU ~" 




«^ 
































































































































,'\ 
































































J 5 
































































t 


\ 






EFFICIENCY VS. PERCENT OF 
RATED CURRENT AT FULL RATED 
VOLTAGE. 






















I / 






s 
























?t -t 






x 
























#t t 






























-t j- 




























40 -- 


t /A 






























t * 
































































±j 


\ 






























































±7 


\ 






























































±f 


































































V, 








EFFICIENCY VS. PERCENT OF 
RATED VOLTAGE AT FULL RATED 
CURRENT. 










































































































































































































































































































' 


































































































































































































b 






























































u 
































































1 
































































1 
































































o 4 

































































10 20 30 40 50 60 70 80 90 100 
PERCENT OF RATED VOLTAGE OR CURRENT 

Figure 8.4 Rectifier efficiencies. Top: Selenium - Typ- 
ical overall efficiency curves for custom line air cooled 
selenium bridge connected rectified unit rated at 60 V, 
60 amp full load DC output. 230- V, single phase, AC in- 
put. Bottom: Silicon - Typical overall efficiency curves 
for custom line air-cooled silicon bridge connected rec- 
tifier unit rated at 40 V, 34 amp full load DC output. 
230 V, single phase AC input. (Courtesy of Universal 
Rectifier, Inc.) 



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Rectifier Installation Details 



165 



should be made in the same manner in order to detect any deterioration of efficiency 
ones a period of time. 



RECTIFIER INSTALLATION DETAILS 

Various standards for rectifier installation are used by operating pipeline companies. 
Installation practices differ depending on local conditions and individual preferences. 
There is no universal standard in effect. Rectifier installation sketches are shown below, 
which may be adapted as necessary to meet the user's requirements. 

Figure 8.5 illustrates a method for installing a pole-mounted CP rectifier. Most in- 
stances of air-cooled rectifiers are pole mounted, as shown in the figure. 



POLE 



WEATHERHEAD 




LEADS FOR 
CONNECTION 
BY LOCAL 
UTILITY 
COMPANY 



CONDUIT STRAPPED TO POLE 



RECTIFIER. RATING AS 
REQUIRED FOR THE 
PARTICULAR 
INSTALLATION. 



NOTE: 

DETAILS OF INSTALLATION 
SUBJECT TO VARIATION 
TO SUIT USER'S SPECIFIC 
PRACTICES AND TO 
CONFORM TO LOCAL 
CODES AND STANDARDS. 




KWH METER 



RAINTIGHT 
ENTRANCE SWITCH 




GROUNDING WIRE 
FROM LUG IN 
ENTRANCE SWITCH 
OR ON RECTIFIER 
CABINET. 



DC CONDUITS 
STRAPPED TO POLE 
ONE CONDUIT MAY 
BE USED FOR BOTH 
DC LEADS. 



CABLES TO 
PIPELINE AND 
TO GROUND BED 



REAR VIEW 
Figure 8.5 Pole mounted rectifier. 



SIDE VIEW 



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166 



Impressed Current Cathodic Protection 




POWER SUPPLY LINE 

COVER MUST BE 
REMOVED TO 
CHANGE TAPS -^ 



POWER SWITCH ■ 



7 



-Ez- 



ra 

GROUND- 
BED 



OIL-IMMERSED 
RECTIFIER 



J- 



JUNCTION 
BOX. OUTPUT 
VOLTMETER 
AND AMMETER 



£ CONCRETE 
MOUNTING PAD 



rz 



GROUND ROD 



PIPELINE 



Figure 8.6 Pad mounted rectifier. 



Figure 8.6 shows the use of a concrete pad for mounting air-cooled (pedestal type), 
oil-filled and explosion-proof rectifiers. Neither of these figures represents an attempt 
to standardize rectifier installation practices. They are included only to serve as a guide 
to those who may be preparing installation standards that apply to their own specific 
system requirements. 



GROUND BED MATERIALS FOR IMPRESSED CURRENT SYSTEMS 

This section includes guidance on the selection of materials for use with impressed 
current ground beds. 



Anode Types 



Materials currently popular for use as anode material include graphite, high silicon cast 
iron, mixed metal oxide, platinum, and steel. 

Graphite anodes may be obtained in various sizes (Figure 8.7), although 3-in. diam- 
eters by 60-in. rods are most commonly used for pipeline ground beds. These anodes 
are typically supplied by the manufacturers with insulated copper leads usually high 
molecular weight polyethylene (HMW/PE). Standard lead length and size usually is 



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Ground Bed Materials for Impressed Current Systems 



167 



Graphite 

Solid Rod Anodes 




POLYETHYLENE PLUG 
WASHER 



CABLE 

SEALING COMPOUND 

INSULATION REMOVED 
AND WIRE TINNED 
EXPANDED CAULKING 
(LEAD FREE) 



lg 



V— ~ o 



CENTER CONNECT 



v^ 



END CONNECT 



Standard Dimensions and Shipping Wts 



ANODE TYPE DIMENSIONS in, 

L 



(mm) 



BAREWT 
lbs (kg) 



(76.2) 



3C 



(76.2) 



13 



(5.9) 



(101.6) 



40 (1,016) 



35 



(15.9) 



(76.2) 



60 (1,524) 



27 



(12.3) 



(101.6) 



80 (2,032) 



70 (31.8) 



CHEMICAL COMPOSITION 


Element 


Content % 


Carbon 


99.80 


Ash 


0.20 



Figure 8.7 Graphite anodes typical sizes and chemi- 
cal composition. (Corrpro Companies Inc.) 



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168 Impressed Current Cathodic Protection 



20 ft of No. 8 HMW/PE insulated wire. Leads of any length may be special ordered. 
Larger wire sizes are available within limits established by the manufacturer. Cata- 
logs for CP material give full details on available sizes and ordering information. The 
" specially treated" graphite anodes (NA treated) are impregnated with linseed oil to pre- 
vent interparticle attack and sloughing off of active material under adverse conditions. 
The additional cost for treated anodes is justified. 

Graphite is brittle so anodes of this material should be handled accordingly. The con- 
nection between insulated anode lead and the anode proper is mechanical, and insulating 
material protects it from moisture penetration. Anode caps are designed to safeguard 
against early deterioration of the connection end. Caps may be cast in place or may be 
in the form of a prefabricated heat shrink cap. 

When anodes are backfilled with carbonaceous backfill material, they are usually 
rated at a current output up to one ampere per square foot (1 A/ft 2 ). A 3-in. by 60-in. 
anode would have a maximum output of approximately four amperes. This must be 
taken into account when designing ground beds, as outlined in Chapter 7. 

Graphite anodes are consumed at no more than two pounds per ampere per year 
when discharging current into an electrolyte. When used with carbonaceous backfill by 
direct electrical contact, most of the material consumed is backfill material rather than 
the anode itself. 

High silicon cast iron anodes normally contain between 14 and 15% silicon plus lesser 
quantities of other alloying elements. Chemical composition and other information is 
shown in Table 8.1. 

Silicon alloy behaves differently from ordinary cast iron when discharging current. 
Ordinary cast iron loses approximately 20 lbs of its iron content per ampere per year. 
High silicon cast iron, on the other hand, loses material at a much lower rate. Typical 
reported rates are as shown in Table 8.1 for ground bed applications in soil. 

High silicon cast iron anodes also have insulated leads as does graphite. The material 
is somewhat brittle and must be handled with care. They are available in various sizes 
and available from suppliers of CP material. A common size used in impressed current 
ground beds is 2-in. diameter by 60-in. length. They are used commonly with carbona- 
ceous backfill, which absorbs most of the consumption resulting from current discharge. 
Tables 8.2 and 8.3 show sizes and output of rated operating current of high silicon iron 
anodes. 

Mixed-metal oxide anodes are available in a variety of sizes and shapes. Mixed metal 
oxide coated titanium anodes are based on electrode technology developed in the early 
1960s for production of chlorine and caustic soda. Usually the mixed metal oxide films 
are thermally applied to precious metal such as titanium or niobium cores. These oxide 
coatings have excellent conductivity, are resistant to acidic environments, are chemically 
stable, and have relatively low consumption rates. Table 8.4, shows sizes and rated 
operating current outputs of solid rod anodes in mixed metal for ground bed installations. 
Table 8.5, shows sizes and rated operating current outputs of tubular mixed metal anodes 
for ground bed installations. Ground bed installation in soils usually specifies that the 
anode be prepackaged in a canister with carbonaceous backfill material. Standard lead 
wire is 10-ft of No. 8 HMW/PE; however, any length and type of cable including Kynar™, 



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Ground Bed Materials for Impressed Current Systems 



169 



Table 8.1 High Silicon Cast Iron Typical Types and Chemical Composition. (Corrpro 
Companies Inc.) 




Durichlor 51 Tubular 

Cast Iron Anodes 



CHEMICAL COMPOSITON 



HIGH SILICON CAST IRON 
STANDARD ANODES 
DURICHLOR 51 ANODE 



Element 


Content % 


C 


0.70-1.10 


Mr 


1 .50 Max 


Si 


14.20- 14.75 


Cr 


3.25 - 5.00 


MO 


0.20 Max 


Cu 


0.50 Max 


Iron 


Remainder 




ANODE 


TYPICAL ANODE 


NOMINAL 


MATERIAL 


CURRENT DENSITY 


CONSUMPTION RATE 




(AMPS/FT 2 ) 


(PER AMP.YR) 




IN SOIL OR 






FRESHWATER 




DURICHLOR 51 






No Backfill 


0.25 ■ 0.5 


0.25 LB 


Coke Backfill 


0.5 -1.0 


0.1 -0.25 LB 



Halar™, and PVC can be specified. Mixed metal oxide anodes can also be configured 
for use in deep well anode beds. 

Platinum and platinized-niobium anodes are available in a variety of sizes and 
shapes. Platinum anodes are available in wire and rod configurations and in different 



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Table 8.2 Standard High Silicon Cast Iron Anodes. (Corrpro Companies Inc.) 

D-51 STANDARD ANODES 
(Continued) 



Two Polyethylene 
Compression Washers 



Cast Epoxy 

Encapsulation 
(Optional) 




Heat Shrinkable 
Teflon (FEP) Etched 
Tubing (Optional) 



Cast Epoxy No. 8—7 Strand 
Cap Cable 



TYPE M : 2%"x60"— Both ends enlarged with cored openings. 
TYPE M1 : 2y4"x60"— One end only enlarged. 



Heat Shrinkable Teflon (FEP) Etched 
Tubing (Optional) 

FriSpL ,J/ Strand Cable 




Epoxy Encapsulation 
(Optional) 



Caulked Lead-^ Tinned Sealin 9 , 
Wires Compound^ 



TYPE E: As shown. 



Polyethylene 
Washers 



Heat Shrinkable 
Teflon (FEP) Etched 
Tubing (Optional) 



>— ~s 



4 1 /2" 



/ Tinned 
/ Wires 
Caulked Lead 
Sealing Compound- 1 
-60" 




Epoxy 

Encapsulation 

(Optional) 

-Polyethylene 
Washers 



TYPE SM: As shown. 



Typical Sizes and Configurations 



Sealing Two Polyethylene 
Compound Compression Washers 
Caulked Lead " 



O 



ZJ 




Tinned \_ 1* ^2" ■ 

Wires 



No. 8 
7 Strand Cable 



TYPE B : 1 "x60" — Both ends enlarged with cored openings. 

TYPE CD : 1 1 /2"x60"— One end only enlarged. 

TYPE CDD: 1 V2"x60"— Both ends enlarged with cored openings. 



One Polyethylene 
Compression Washer „ .1 .. 
v \ 7 Strand Cable 

Caulked Lead Sealing \ Groove & 

^ .Compound \ Epoxy 




Epoxy Cap 
(Optional) 



TYPE D: 2 "x60"— Uniform diameter. 



Full Encapsulation (Optional) Epoxy & Heat Shrink 

Cap (Optional) 





TYPE C: 1 1 /2"x60"— Uniform diameter. 



TYPE 


SIZE 
In (mm) 


APPROXIMATE 

WEIGHT EACH 

lbs (kg) 


AREA 
ft 2 (m 2 ) 


GENERAL APPLICATION 


SPECIAL FEATURES 


B 


1 x 60 (25x1 524) 


12(5.4) 


1.4 (.13) 


Fresh water tanks. 


Each end enlarged to 1 1 / 2 in. (38 mm) 
dia. with cored opening for joining. 


C 


1V 2 x 60 (38x1 524) 


25(11.4) 


2.0 (.19) 


Open box coolers requiring 
lengths greater than 5 feet. 


Uniform 1 1 / 2 in. (38 mm) dia. with 
cored opening both ends for joining. 


CD 


1 1 / 2 x 60 (38x1524) 


26(11.8) 


2.0 (.19) 


Ground bed with backfill. 


One end only enlarged to 2 in. (51 
mm) dia. with cored opening for 
cable connection. 


CDD 


1 1 / 2 x 60 (38x1524) 


26(11.8) 


2.0 (.19) 


Ground bed with backfill permits 
joining in series. 


Each end enlarged to 2 in. (51 mm) 
dia. with cored opening for cable 
connection. 


D 


2x60(51 x1524) 


44 (20.0) 


2.6 (.24) 


Ground bed without backfill. 


Uniform 2 in. (51 mm) dia. with cable 
connections on one end only. 


M 


2 1 / 4 x 60 (57x1 524) 


63 (28.6) 


2.9 (.28) 


Mild saline or deep well without 
backfill. 


Each end enlarged to 3 in. (76 mm) 
with cored opening for joining. 


M1 


2V 4 x 60 (57x1 524) 


65 (29.5) 


2.9 (.27) 


Mild saline or deep well 
without backfill. 


Same as type M but cored opening 
on one end only for cable 
connection. 


E 


3x60(76x1524) 


110(49.9) 


4.0 (.37) 


Severe ground, deep well or sea 
water without backfill. 


One end only enlarged to 4 in. (102 
mm) dia. with cored opening for 
cable connection. 


EWO 


3x60(76x1524) 


110(49.9) 


4.0 (.37) 


Severe ground, deep well or sea 
water without backfill. 


One end only enlarged to 4 in. (102 
mm) dia. with cored opening for 
cable connection. 


SM 


4 1 / 2 x60 (114x1524) 


220 (99.9) 


5.5 (.51) 


Sea water with high current 
discharge per anode. 


Uniform 4 1 / 2 in. (114 mm) dia. with 
cored opening each end. Permits two 
cable connections, if required. 





170 



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171 



Table 8.3 Tubular High Silicon Cast Iron Anodes. (Corrpro Companies Inc.) 
DURICHLOR 51 TYPE TA TUBULAR ANODES 



MASTIC SEAL 




EPOXY SEAL CABLE 
LEAD CONNECTOR 



CABLE 

GUIDE 



ANODE 
TYPE 


NOMINAL 

SIZE 

In (mm) 


LENGTH 
In (mm) 


WEIGHT 
Lbs (kg) 


AREA- 

SQ. FEET 

(m 2 ) 


NOMINAL 
DISCHARGE- 
AMPS 


GENERAL APPLICATIONS 


SPECIAL FEATURES 


TA1 


2 21 / 32 x42 
(67x1067) 


42 
(1067) 


31 
(14.1) 


2.4 
(.22) 


1.5-2.0 


Fresh water tanks, deep ground 
beds, or standard ground beds. 


Center connection, in series on 
continuous cable or one lead only. 


TA2 


2 3 /i 6 x84 
(56x2133) 


84 
(2133) 


46 
(20.9) 


4.0 
(.37) 


3.0-4.0 


Fresh water tanks, deep ground 
beds, or standard ground beds. 


Center connection, in series on 
continuous cable or one lead only. 


TA3 


2 21 / 32 x84 
(67x2133) 


84 
(2133) 


63 
(28.6) 


4.9 
(.46) 


3.5-5.0 


Deep ground beds or standard 
ground beds. 


Center connection, in series on 
continuous cable or one lead only. 


TA4 


3 3 /, x 84 
(95x2133) 


84 
(2133) 


85 
(38.6) 


6.9 
(.64) 


6.0-7.0 


Severe ground, deep well 
without backfill or sea water. 


Center connection and tubular 
design gives greater surface area. 


TA5 


4 3 / 4 x 84 
(121 x2133) 


84 
(2133) 


110 
(49.9) 


8.7 
(.81) 


6-8.5 


Severe ground, deep well 
without backfill or sea water. 


Center connection eliminates loss 
due to "end effect." 


TA6 


6% x78 
(170x1981) 


78 
(1981) 


260 
(118) 


11.4 
(1.06) 


11-15 


Seawaterwith high current discharge 
per anode or severe ground bed. 


Center connection and tubular 
design gives longer life. 


TA2A 


2 3 / 16 x42 
(56x1067) 


42 
(1067) 


23 

(10.4) 


2.0 
(.19) 


1.5-2.0 


Fresh water tanks, deep ground 
beds, or standard ground beds. 


Center connection, in series on 
continuous cable or one lead only. 


TA5A 


4 3 / 4 x 84 
(121 X2133) 


84 
(2133) 


175 
(79.4) 


8.7 
(.81) 


9-10 


Seawaterwith high current discharge 
per anode or severe ground bed. 


Center connection and tubular 
design gives longer life. 


TAB 


2 3 / e x 24 
(56 x 609) 


24 
(609) 


13 
(5.9) 


1.1 
(.10) 


0.5-1.0 


Fresh water tanks, distributed 
systems in ground trenches. 


Lightweight flexible assembly with 
continuous cable. 


TABB 
TACD 


2 21 / 32 x24 
(67 x 609) 
2 3 / 16 x60 
(56x1524) 


24 
(609) 

60 
(1524) 


18 
(8.2) 

32 
(14.5) 


1.4 
(.13) 

2.8 
(.26) 


0.5-1.0 
2.5-3.0 


Fresh water tanks, distributed 
systems in ground trenches. 
Fresh water tanks, deep ground 
beds, or standard ground beds. 


Lightweight flexible assembly with 
continuous cable. 
Center connection, in series on 
continuous cable or one lead only. 


TAD 


2 21 / 32 x60 
(67x1524) 


60 
(1524) 


45 
(20.4) 


3.5 
(.32) 


2.5-3.5 


Fresh water tanks, deep ground 
beds, or standard ground beds. 


Center connection, in series on 
continuous cable or one lead only. 


TAE 


4 3 / 4 x 60 
(121 X1524) 


60 
(1524) 


125 
(56.7) 


6.2 
(.58) 


6-8 


Severe ground, deep well 
without backfill or sea water. 


Center connection eliminates loss 
due to "end effect." 


TAJA 
TAJ 


4 3 / 4 x 24 
(121 x609) 

4 3 / 4 x 60 
(121 X1524) 


24 
(609) 

60 
(1524) 


31 
(14.1) 

78 
(35.4) 


2.5 
(.23) 
6.2 
(.58) 


1.5-2.0 
5.0-6.0 


Fresh water tanks, deep ground 
beds, or standard ground beds. 
Severe ground.deep well 
without backfill or sea water. 


Center connection, in series on 
continuous cable or one lead only. 
Center connection and tubular 
design gives greater surface area. 


TAM 


3 3 / 4 x 60 
(95x1524) 


60 
(1524) 


60 
(27.2) 


4.9 
(.46) 


3.5-5.0 


Deep ground beds or standard 
ground beds. 


Center connection, in series on 
continuous cable or one lead only. 


TAG 


2% x8 
(67x203) 


8 

(203) 


6 

(2.7) 


0.47 
(.05) 


0.55 


Elevated fresh water tank. 
Underground cables in ducts. 


Center connection, in series on 
continuous cable or one lead only. 


TAFW 


2 3 /i 6 x8 
(56 x 203) 


8 

(203) 


4.3 
(1.9) 


0.38 
(.04) 


0.40 


Elevated fresh water tank. 


Lightweight flexible assembly with 
continuous cable. 


TAFWA 


23 / 6 x12 
(56 x 304) 


12 
(304) 


6.5 
(2.9) 


0.57 
(.06) 


0.60 


Elevated fresh water tank. 
Underground cables in ducts. 


Center connection, in series on 
continuous cable or one lead only. 



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172 



Impressed Current Cathodic Protection 



Table 8.4 Typical Sizes and Rated Operating Current Data. Solid 
Mixed Metal Oxide Anodes. (Corrpro Companies Inc.) 



Mixed Metal Oxide 
Solid Rod Anode 


^\ 


SHRINK SLEEVE — i 


MASTIC TAPE 
r^ SECOND LAYER 

/ MASTIC TAPE 
/ /~ FIRST LAYER 

J!//— CONNECTOR 




^^ 






^^^) M k { 


LEAD WIRE ^ 




T 


J MIXED METAL 
/ OXIDE ANODE 

L PRIMER 


J 


Standard Dimensions and Shipping Weights 


ANODE 
TYPE 


NOMINAL DIMENSIONS 

in. (mm) ft (mm) 


NOMINAL WEIGHT 
BARE WT PKG WT 


CURRENT 
RATING* 





L 


oz/ft (g/M) 


lbs (kg) 


amps 


M84 


0.125 (3.175) 


4 


(101.6) 


0.38 (35.6) 


22 (10) 


7.0 


M88 


0.125 (3.175) 


8 


(203.2) 


0.38 (35.6) 


44 (20) 


14 


M44 


0.25 (6.350) 


4 


(101.6) 


1.5 (43.4) 


22 (10) 


15 


M48 


0.25 (6.350) 


8 


(203.2) 


1.5 (43.4) 


44 (20) 


30 


M24 


0.50 (12.7) 


4 


(101.6) 


6.1 (173.8) 


23 (10.5) 


29 


M28 


0.50 (12.7) 


8 


(203.2) 


6.1 (173.8) 


46 (21) 


58 


*Based on 


15 year design life ar 


ldXEc 


mating in sa 


itwater 



platinum coating thickness. Table 8.6 shows typical chemical composition of platinum 
anodes. 

Typically the anode is composed of a copper core surrounded by a niobium substrate 
with the platinum metallurgically bonded to the niobium substrate. The consumption of 
the platinum coating is extremely low (40 to 80 mg/ A-year). To achieve the desired design 
life of the anode the platinum coating thickness can be varied. Typical platinum coating 
thicknesses are 25, 50 and 100 micro-in. Typical practice for ground bed installation in 
soils is to specify the anode in a prepackage canister with carbonaceous backfill material. 
Standard lead wire is 10-ft of No. 8 HMW/PE, however any length and type of cable 
including Kynar, Halar and PVC can be specified. Platinum anodes can also be configured 
for use in deep well anode beds. 



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173 



Table 8.5 Sizes and Rated Operating Current Data Tubular. 
Mixed Metal Oxide Anodes. (Corrpro Companies Inc.) 

Mixed Metal Oxide 
Tubular Anodes 



"FOLLOWER" HALF - 
OF CONNECTOR 



"SOLDERING" HALF 
OF CONNECTOR 




CONNECTOR ASSEMBLY 

ADJUSTMENT SCREW 



MIXED METAL OXIDE ANODE 




LEADWIRE- 



L— SLOT FOR WIRE 
ATTACHMENT 



CONNECTOR INSTALLATION 



Standard Dimensions and Shipping Weights 



ANODE 
TYPE 



NOMINAL DIMENSIONS 
LENGTH 



in. (mm) ft 



NOMINAL WEIGHT 
BARE PKGD. 



CURRENT 
RATING' 



oz/ft (g/M) 



lbs (kg) 



amps 



M752 



0.75 (19.1) 



2.0 (610) 



3.4 (314) 



23 (10.5) 



23 



0.75 (19.1) 



4.0 (1,219) 



3.4 (314) 



25 (11.4) 



1.0 (25.4) 



3.3 (1,006) 



3.8 (351) 



25 (11.4) 



1.25 (31.8) 



4.0 (1,219) 



5.8 (538) 



27 (12.3) 



73 



* Based on 15 year design life in saltwater 



Table 8.6 Chemical Composition of Platinum Anodes 



Element 



Content % of Diameter 



Copper 

Niobium 

Platinum 



79.5 
19.5 
Less than 1% 



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174 Impressed Current Cathodic Protection 



Table 8.7 Chemical Composition of Petroleum and 
Metallurgical Coke Backfill 



Element 


Content % 


Petroleum Coke Backfill 




Fixed Carbon 


99.77 


Ash 


0.1 


Moisture 


0.0 


Volatile Matter 


0.0 


Metallurgical Grade 




Fixed Carbon 


85.89 


Ash 


8-10 


Moisture 


6-9 


Sulfur 


0.8 


Volatile Matter 


0.5 



Backfill Materials 



The term "carbonaceous backfill" used earlier describes the backfill surrounding ground 
bed anodes. There are three common materials that fit this description: Coal coke breeze, 
calcined petroleum coke breeze, and natural or man-made graphite particles. Chemical 
composition for petroleum coke backfill and metallurgical grade coke backfill are listed 
in Table 8.7. 

All are basically carbon in a low resistivity form. "Breeze" is a loose term indicating 
a finely divided material. Originally it referred to the fine screenings left over after coal 
coke was graded for sale as fuel. For backfill purposes, however, specific particle sizes 
may be obtained. 

Carbonaceous backfill serves two purposes when surrounding impressed current 
anodes: 

• To increase the size of the anode to obtain lower resistance to earth and 

• To bear the consumption resulting from current discharge. 

The latter function requires good electrical contact between the anode and back- 
fill particles. To accomplish this, the backfill must be tamped solidly around the core. 
Occasionally, subsurface soil conditions may not allow adequate contact pressure, or 
may relax with time, so that much of the current will discharge directly from anode to 
electrolyte. This tends to reduce anode life. 

Consumption rate of the backfill should not exceed two pounds per ampere per year. 
In the absence of specific information on the unit weight of the material used, weights 
may be estimated by using the tabulation in Table 8.8. The suppliers can provide specific 
information on coke breeze material. 

Coke breeze should be procured by specification. Size and resistivity are important. 
Some users specify, as an example, that maximum particle size shall not exceed 3/8 in., 



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Ground Bed Materials for Impressed Current Systems 175 



Table 8.8 Weights of Carbonaceous Backfill 

Material Lb/Ft 3 

Coal coke breeze 40 to 50 

Calcined petroleum coke breeze. . . 45 to 70 

Natural graphite particles 70 to 80 

Crushed man-made graphite 70 



that not more than 10% dust shall be included and that resistivity shall not exceed 
50 ohm-cm. Petroleum coke must be calcined (heat treated) to remove all other petroleum 
products; otherwise its resistivity will be too high. 

Natural or manufactured graphite both have low resistivity. Although natural 
graphite is available in flake form, flakes are not desirable for ground bed used where gas 
must be vented, because the interleaving flakes may block discharge. This applies par- 
ticularly to deep-well ground beds. Natural graphite may be obtained in granular form 
(less expensive than flake graphite) and would involve less possibility of gas blocking 
difficulties. 

Deep-well anode ground beds have reported good results when a calcined petroleum 
coke in the form of rounded granules or beads is used. With material of this type, there 
will be little interlocking of particles to block passage of gas. 



Cable Types 



All underground cable, which is a part of an impressed current ground bed, is at a positive 
potential with respect to ground. If not perfectly insulated, the cable will discharge 
current and corrode in two, thus cutting off the current from all or part of the ground 
bed. Thus first quality insulation must be used on all anode leads and ground bed header 
cables. 

Insulation should have at least a 600-V rating and be suitable for direct burial. Wire 
with a high molecular weight polyethylene (HMW/PE) insulation is widely used for 
ground bed construction. This has been effective in most cases. Polyethylene may be 
used with or without a protective jacket. Where chlorine gas may be generated due to 
ground bed operation or severe chemical environments may be encountered, a protective 
jacket of KYNAR™ or HALAR™ may be necessary. 

Cable should be inspected carefully during installation to be absolutely sure that 
there are no scars or cuts which may present problems later. Any scars or cuts in the 
insulation must be encapsulated with a heat shrink sleeve. Select only backfill free of 
sharp stones or other harmful materials to contact the ground bed cable. 

Catalog information on cable suited for ground bed construction is available through 
manufacturers and through suppliers of CP material. 

Selecting cable size has both a practical and an economic aspect. From the practi- 
cal standpoint, the cable should be large enough to carry the intended current (see the 



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176 Impressed Current Cathodic Protection 



National Electric Code for tables of current rating) and to withstand mechanical stresses 
encountered during ground bed construction. Cable smaller than No. 8, for impressed 
current anode cable is not adequate. Anodes should never be installed by the cable. Sim- 
ilarly, cable that is unusually large may cause handling and connection problems during 
construction. From the economic standpoint, select a cable size based on a comparison of 
cable cost with current carrying ability and the cost of power loss from cable resistance 
when current flows through it. 



Connections 



Electrical connections between anode leads and header cable are a critical part of im- 
pressed current ground bed construction. Anode leads must be connected to the header 
cable by a method that will have permanently low resistance. The connection, once 
made, must be insulated so that it will be waterproof to present current leakage and 
cable corrosion. 

Acceptable connection methods for copper wire include soft soldering, powder weld- 
ing (thermite), hard (silver) soldering, phos-copper brazing, compression (crimp type) 
couplings, and split-bolt couplings. The first four methods result in complete joining 
of the metals and have permanent low resistance. Mechanical methods, if used prop- 
erly, also will give low resistance connections, which will remain low if subsequent joint 
insulation excludes moisture and air completely so that no corrosion films may form 
within the joint to introduce resistance. When using joining methods involving the use 
of a torch, cable insulation adjacent to the connection should be protected against heat 
damage. Any heat damage should be removed prior to insulating the connection. 

Joints should be insulated with materials and methods that will equal, at least, the 
electrical strength of original cable insulation. The work must be done carefully so that 
insulation covers all exposed metal and overlaps cable insulation by at least 1 in. Where 
jacketed cable is used, the jacket should be removed from about the first \ in. to expose 
the basic cable insulation, and then the applied joint insulation will adhere to both cable 
insulation and jacket material. 

Acceptable joint insulation includes cast epoxy resin insulation and various tapes. 
There are several manufacturers of cast joint for CP uses. These materials use a contain- 
ment mold designed to surround the joint to be coated. Then the mold is filled with a 
catalyzed resin which sets quickly to form a solid cast around the joint and overlapping 
wire insulation. Properly made, the poured material fills all crevices of the joint to exclude 
moisture and air. Such connections are recommended particularly for mechanical joints 
but are used also with other types. Satisfactory taped joint insulation can be achieved 
with top quality high voltage rubber splicing compound covering the joint metal and 
overlapping the wire insulation. This is followed by two half-lapped layers of rubber 
tape followed by two half-lapped layers of plastic tape. Sharp points or corners should 
be removed from joints to be taped. If they cannot be rounded sufficiently to prevent 
tape rupture or puncture, they may be padded with electrical putty. Details of joining 
and insulating materials may be obtained from the catalogs of CP material suppliers. 
The splice connections are usually the weakest link in a ground bed installation. 



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Chapter 



Cathodic Protection 
with Galvanic Anodes 



Ronald L. Bianchetti 



Discussion of the common types of galvanic (sacrificial) anode materials including 
performance characteristics, typical applications, and installation details are outlined 
below. 



TYPES OF GALVANIC ANODES FOR PIPELINE USE 

The two galvanic anode metals commonly used for buried pipelines are magnesium 
and zinc. Appearance of typical anodes is shown in Figures 9.1 and 9.2. Aluminum has 
a theoretical energy content (in terms of ampere-hours per pound) which exceeds that 
of magnesium and zinc but so far, aluminum has not proved practical for earth-buried 
installations because of problems associated with keeping it electrically active with good 
efficiency characteristics. Aluminum anodes are primarily used for marine applications 
but this specialized application will not be considered here. 



HOW GALVANIC ANODES WORK 

The use of galvanic anodes for cathodic protection (CP) is a simple application of the 
dissimilar metal corrosion cell discussed in Chapter 1. Where a steel pipeline is elec- 
trically connected to a metal higher in the electromotive force series and both are in a 
common conductive electrolyte such as the earth, the more active metal is corroded and 
discharges current in the process. Magnesium and zinc are such metals. If the amount 



177 



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178 



Cathodic Protection with Galvanic Anodes 



Soil and Ribbon 

Cast and Extruded Zinc Anodes 




Figure 9.1 Typical zinc anodes. (Corrpro Companies Inc.) 



of current needed for a given CP application is known, anode systems can be designed 
using sufficient anode material to produce the desired current output continuously over 
a desired number of years. 

The corrosive nature of the underground environment may cause self-corrosion of 
the anode material. Electrical currents produced by this self-corrosion do not result in 
producing CP current. The ratio of metal expended in producing useful CP current to 
total metal expended is termed 'anode efficiency'. This is an important characteristic, 
which will be discussed in more detail in the following sections. 



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Galvanic Anode Applications 



179 



Cast Magnesium Anodes 




Figure 9.2 Typical magnesium anodes. (Corrpro Com- 
panies Inc.) 



GALVANIC ANODE APPLICATIONS 



For pipeline CP applications, galvanic anodes are generally used in cases where relatively 
small amounts of current are required (typically less than 1 A) and areas where soil 
resistivity is low enough (typically less than 10,000 ohm-cm) to permit obtaining the 
desired current with a reasonable number of anodes. If large amounts of current are 
needed (typically greater than 1 A) impressed current systems tend to be more economi- 
cal. If there is a question as to which current source to use, an economic analysis should 
be undertaken, unless local conditions dictate otherwise. Chapter 15 provides the basis 
for performing economic analyses. 



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180 Cathodic Protection with Galvanic Anodes 



Short increments of well-coated pipe will have moderate current requirements for 
protection. These current requirements can be met with galvanic anodes where soil resis- 
tivity conditions are suitable. 

Some operators follow a practice of installing galvanic anodes at each location where 
a leak is repaired (hot spot protection) rather than installing a complete CP system. Such 
practices may be encountered on bare or very poorly coated systems where complete 
CP may not be feasible from an economic standpoint. 

On well-coated pipelines with impressed current CP systems, there may be isolated 
points where additional current may be needed in relatively small amounts. These re- 
quirements can be met with galvanic anodes. Typical applications include poorly or 
incompletely coated buried valve installations, shorted casings which cannot be cleared, 
isolated sections where pipeline coating has been badly damaged and areas where electri- 
cal shielding may impair effective current distribution from remotely located impressed 
current systems. 

Galvanic anodes may be used in some instances to correct stray current interference 
conditions at pipeline crossings where the interference arises from impressed current CP 
systems. This application is discussed further in Chapter 11. 

Galvanic anodes (usually zinc) may also be used for electrical grounding applica- 
tions at pipeline pumping stations and across insulating joints. Zinc anodes as ground 
rods serve as effective electrical grounds and at the same time provide a measure 
ofCP 

Pipelines may pass through areas where there are many other underground metallic 
structures under conditions that make it difficult to install impressed current systems 
without creating stray current interference problems (see Chapter 11). Galvanic anodes 
may be an economical choice for a CP current source under such conditions. 



CHARACTERISTICS OF MAGNESIUM AND ZINC ANODES 

Magnesium is the most widely used material for galvanic anodes. Typical characteristics 
are given in Table 9.1. Magnesium anodes are available in various shapes and weights 
from the manufacturers. Some of the sizes available, suitable for use in soil, are listed in 
Table 9.2. 

Zinc anodes are available in a number of sizes for use in earth anode beds. Typical 
characteristics of zinc used as an anode material are given in Table 9.3. These are long 
slender shapes to achieve low resistances to earth and practical current output at the 
usual low driving voltage between anode and protected structure. Some sizes available 
as standard commercial items are shown in Table 9.4. Nonstandard sizes may be obtained 
on special order. 

Packaged magnesium and zinc anodes (anode and backfill furnished as a complete 
unit ready for installation) are standard with most suppliers. 



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Characteristics of Magnesium and Zinc Anodes 



181 



Table 9.1 Characteristics of Magnesium Anodes 



Specific Gravity 1 .94 

Pounds per Cubic Foot 121 

Theoretical Amp Hours per Pound 1000 

Theoretical Pounds per Amp per Year 8.7 

Current Efficiency - Percent 50 (2) 

Actual Amp Hours per Pound 500 (2) 

Actual Pounds per Amp perYear 17.4 (2) 

Solution Potential - Volts to CSE 

Standard H-1 Alloy -1 .50 to -1 .55 (3) 

High Potential Alloy -1 .75 to -1 .77 (4) 

Driving Potential to Pipeline 
Polarized to -0.90 Volt to CuS0 4 

Standard Alloy - Volts 0.55 (5) 

High Potential Alloy - Volts 0.80 (5) 

1) Anodes installed in suitable chemical backfill. 

2) Current efficiency varies with current density. Efficiency given (which results 
in actual amp hr per pound and actual pounds per amp per year shown) is at 
approximately 30 milliamps per sq ft of anode surface. Efficiencies are higher 
at higher current densities, lower at lower current densities. 

3) Alloy with nominal composition % 6 Al, 3 Zn, 0.2 Mn and balance Mg. 

4) Proprietary alloy-manganese principal alloying element. 

5) Driving potentials allow for anode polarization in service of approximately 
0.10 volt which reduces the solution potential by this amount. Driving 
potential in volts for pipeline polarized to any specific potential (P) in 
volts = solution potential of magnesium type used minus 0.10 volts minus P. 



STANDARD H-1 ALLOY 
CHEMICAL COMPOSITION 



Weight Content % 


Element 


Grade A 


Grade B 


Grade C 


Al 


5.3-6.7 


5.3-6.7 


5.0 - 7.0 


Mn 


0.15 min 


0.15 min 


0.15 min 


Zn 


2.5-3.5 


2.5-3.5 


2.0 -4.0 


Si 


0.10 max 


0.30 max 


0.30 max 


Cu 


0.02 max 


0.05 max 


0.10 max 


Ni 


0.002 max 


0.003 max 


0.003 max 


Fe 


0.003 max 


0.003 max 


0.003 max 


Other 


0.30 max 


0.30 max 


0.30 max 


Magnesium 


Remainder 


Remainder 


Remainder 



HIGH POTENTIAL ALLOY 
CHEMICAL COMPOSITION 



Element 


Weight Content % 


Al 


0.010 


Mn 


0.50 to 1 .30 


Cu 


0.02 Max 


Ni 


0.001 Max 


Fe 


0.03 Max 


Other 


0.05 each or 0.3 Max Total 


Magnesium 


Remainder 



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182 



Cathodic Protection with Galvanic Anodes 



Table 9.2 Magnesium Anode Types (Corrpro Companies Inc.) 



High Potential 

Cast Magnesium Anodes 




• BACKFILL 



LEAD WIRE 



PACKAGED ANODE 



20 GAUGE GALV. 
STEEL CORE 




BARE ANODE 



Standard Dimensions and Shipping Weights 



ANODE 
TYPE 



"A" 



NOMINAL DIMENSIONS 
in (mm) 

"B" "C" "D" 



"E" 



NOMINAL WT. 

lbs (kg) 



BARE 



PKGD. 



3 lb 



3(76) 3(76) 4.5(114) 6.5(165) 6(152) 



3(1.4) 



9(4.1) 



5 lb 



3(76) 3(76) 7.5(191) 13.5(343) 6(152) 



5 (2.3) 



14(6.4) 



9 lb 



2 (51 ) 2 (51 ) 27 (686) 31 (787) 5 (1 27) 



9(4.1) 



36(16.3) 



9 lb 



3(76) 3(76) 13.5(343) 17(432) 6(152) 



9(4.1) 



24(10.9) 



17 1b 



2 (51 ) 2 (51 ) 51 (1 295) 55 (1 397) 5 (1 27) 



17(7.7) 



61 (27.7) 



171b 



3(76) 3(76) 25.5(648) 30(762) 6(152) 



17(7.7) 



42(19.1) 



20 lb 



2(51) 2(51) 60(1524) 62.5(1588) 5(127) 



20(9.1) 



70(31.8) 



32 lb 



3(76) 3(76) 45(1143) 61(1549) 6(152) 



32(14.5) 



90 (40.8) 



32 lb 



5(127)5(127) 21(533) 30(762) 8(203) 



32(14.5) 



70(31.8) 



40 lb 



3(76) 3(76) 60(1524) 64(1626) 6(152) 



40(18.1) 



105(47.6) 



48 lb 



5(127)5(127) 31(787) 34(864) 8(203) 



48(21.8) 



96 (43.6) 



60 lb 



4(102) 4(102) 60(1524) 64(1626) 6.75(171) 



60 (27.2) 



130(59.0) 



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Characteristics of Magnesium and Zinc Anodes 



183 



Table 9.2 (Continued) 



H-1 Alloy 

Cast Magnesium Anodes 




• BACKFILL 



LEAD WIRE 



PACKAGED ANODE 



■ 20 GAUGE GALV. 
STEEL CORE 




BARE ANODE 



Standard Dimensions and Shipping Weights 



ANODE 
TYPE 



NOMINAL DIMENSIONS 

in (mm) 

"A" "B" "C" "D" "E" 



NOMINAL WT. 

lbs (kg) 



BARE 



PKGD. 



1 lb 



2.9 (74) 



3(76) 6(152) 6(152) 



1 (0.45) 



3.5(1.6) 



3 lb 



3(76) 3(76) 4.5(114) 6.5(165) 6(152) 



3(1.4) 



9(4.1) 



5 lb 



3(76) 3(76) 7.5(191) 13.5(343) 6(152) 



5 (2.3) 



14(6.4) 



9 lb 



3(76) 3(76) 13.5(343) 17(432) 6(152) 



9(4.1) 



24(10.9 



171b 



4(102) 4(102) 17(432) 19(483) 6.5(165) 



17(7.7) 



42(19.1) 



32 lb 



5(127) 5(127) 21(533) 30(762) 8(203) 



32(14.5) 



70(31.8) 



50 lb 



I (203) 



15(381) 18(457) 10(254) 



50 (22.7) 



110(49.5 



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184 



Cathodic Protection with Galvanic Anodes 



Table 9.3 Characteristics of Zinc Anodes 

Specific Gravity 7 

Pounds per Cubic Foot 440 

Theoretical Amp Hours per Pound 372 (2) 

Theoretical Pounds per Amp per Year 23.5 

Current Efficiency - Percent 90 (3) 

Actual Amp Hours per Pound 335 

Actual Pounds per Amp per Year 26 

Solution Potential - Volts to CSE -1.1 

Driving Potential to Pipeline 
Polarized to -0.90 Volt to CuS0 4 0.2 (4) 

(1) Anodes installed in suitable chemical backfill. 

(2) Zinc used for soil anodes should be high purity zinc such as "Special High 
Grade" classification which is at least 99.99 percent pure zinc. 

(3) Current efficiency of zinc is reasonably constant from low to very high current 
outputs in terms of milliamperes per sq ft of anode surface. This applies when 
the high purity anode grade zinc is used. The 90 percent efficiency is 
conservative. 

(4) Zinc not subject to significant anodic polarization when used in suitable 
backfill. Driving potential is zinc solution potential minus polarized potential of 
protected structure. 

CHEMICAL COMPOSITION 



Element 


Weight Content % 


MIL-A-18001 
(ASTMB-418Typel) 


ASTM B-418 
Type II 


Al 


0.1 -0.5 


0.005 max 


Cd 


0.02 -0.07 


0.003 max 


Fe 


0.005 max 


0.0014 max 


Pb 


0.006 max 


0.003 max 


Cu 


0.005 max 


0.002 max 


Zinc 


Remainder 


Remainder 



ANODE BACKFILL 



For reliable operation in earth installations, both zinc and magnesium anodes are used 
with a chemical backfill to surround the anode completely. There are several reasons for 
using chemical backfill. Typical data on chemical backfill are shown in Table 9.5. 

With the anode surrounded with a uniform material of known composition, anode 
current is more efficient. If the soil contacts the anode directly, variations in soil compo- 
sition can set up local corrosion on the anode resulting in nonuniform consumption of 
the anode. 

By isolating the anode material from the native soil, the backfill material greatly 
reduces the possibility of adverse effect on anode performance. In the presence of 



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Table 9.4 Zinc Anode Types 



Soil and Ribbon 

Cast and Extruded Zinc Anodes 



-20 GAUGE GALV. 
STEEL CORE 




PACKAGED ANODE 



Standard Dimensions and Shipping Weights 



ANODE 
TYPE 



NOMINAL DIMENSIONS 

in (mm) 



NOMINAL WT. 

lbs (kgs) 



PKGD. 



SOIL PACKAGED ANODES 



5 1b 1.4(35.5) 1.4(35.5) 9(228.6) 15(381) 5(127) 5(2.3) 24(10.8) 



12 lb 



18 1b 



30 1b 



30 1b 



45 1b 



1.4 (35.5) 



1.4(35.5) 



1.4(35.5) 



2 (50.8) 



2 {50.1 



ANODE 
TYPE 



1.4 (35.5) 



1.4(35.5) 



1.4(35.5) 



2 (50.£ 



2 (50.8) 



24 (609.6) 



36(914.4) 



60(1524) 



30 (762) 



45(1143) 



60 lb 2(50.8) 2(50.8) 60(1524) 66(1676.4) 5(127) 



30 (762) 



42(1066.8) 



66(1676.4) 



36(914.4) 



51 (1295.4) 



5 (127) 



5(127) 



5(127) 



5(127) 



5(127) 



NOMINAL DIMENSIONS 



"A" 

in (mm) 



"B" 

in (mm) 



ft/RO (M/RO) 



12 (5.4) 



18(8.1) 



30(13.6) 



30(13.6) 



45 (20.4) 



60 (27.2) 



48(21.7) 



70(31.7) 



95 (43.0) 



70(31.7) 



110(49.9) 



130(58.9) 



BAREWT. 

lbs/lineal ft 
(kg/lineal M) 



RIBBON EXTRUDED ANODES 



Super 



Plus 



Standard 



Small 



1 (25.4) 



5/8(15.8) 



1/2(12.7) 



11/32(8.7) 



1-1/4(31.7) 



7/8 (22.2) 



9/16(14.2) 



100(30.4) 



200 (60.9) 



500(152.4) 



15/32(11.9) 1,000(304.7) 



2.4 

(1.09) 



1.2 
(0.54) 



0.6 

(0.27) 



0.25 
(0-11) 



: The Standard anode model is also available in 1000 and 3600 foot rolls. 



185 



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186 Cathodic Protection with Galvanic Anodes 



Table 9.5 Backfill data for Magnesium and Zinc Anodes 





Gypsum 


(CaS0 4 )% 


Bentonite 
Clay % 


Sodium 
Sulfate % 






Hydrated 


Molding Plaster 
(Plaster of Paris) 


Approx Resistivity 
in ohm-cm 


(A) 
(B) 


50 

75 


- 


50 
20 


5 


250 
50 



1. Backfill mix (A) commonly used with zinc anodes. 

2. Backfill mix (B), with low resistivity, is useful in high soil resistivity areas to reduce the anode resistance 
to earth. 



phosphates, carbonates and bicarbonates, zinc anodes can develop passive films and 
cease to produce useful amounts of current. Carbonates and bicarbonates will influence 
magnesium the same way. Chlorides tend to increase self-corrosion of magnesium and 
reduce its current efficiency. 

Chemical backfills can be helpful in absorbing soil moisture to keep the environment 
immediately surrounding the anode continuously moist. Anode backfill is of low resis- 
tivity and when anodes are installed in soils having a resistivity higher than that of the 
backfill, the backfill column has the effect of increasing the anode size. This results in a 
lower resistance to remote earth than would be the case if the bare anode were buried 
directly in the soil. This effect is discussed in Chapter 7. 



CALCULATING ANODE LIFE 



If current output of a galvanic anode of any given weight is known, its approximate 
useful life can be calculated. This calculation is based on the theoretical ampere-hour 
per pound of the anode material, its current efficiency, and a utilization factor. The 
utilization factor may be taken as 85% — meaning that when the anode is 85% consumed, 
it will require replacement because there is insufficient anode material remaining to 
maintain a reasonable percentage of its original current output. 

For magnesium, anode life may be determined by the following expression (efficiency 
and utilization factor expressed as decimals). 

Magnesium Anode 

0.116 x Anode Weight (pounds) x Efficiency x Utilization Factor 



Life (years) = 



Design Current (amperes) 



For zinc anodes, anode life may be determined in similar manner by the following 
expression: 



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Calculating Anode Life 



187 



Zinc Anode 



Life (years) = 



0.0424 x Anode Weight (pounds) x Efficiency x Utilization Factor 
Design Current (amperes) 



As an example, assume that a 32-lb magnesium anode is producing 0.1 A at 50% efficiency 
and that a 30-lb zinc anode is producing 0.1 A at 90% efficiency. Compare the expected 
operating lives at the 0.1 A output. 



a . T -r / x 0.116x32x0.50x0.85 iro 
Magnesium Anode Life (years) = = 15.8 yr, 



Zinc Anode Life (years) 



0.1 

0.0424 x 30 x 0.90 x 0.85 
0.1 



9.7 yr. 



These calculations reflect the difference in theoretical ampere hours per pound charac- 
teristic of the two materials. Although anode costs may fluctuate with the metal market, 
zinc is typically less expensive than magnesium. Graphical design information has been 
developed for typical anode types. An example is shown in Figure 9.3. 



Current Output of GALVOMAG® 
and High Purity H-1 Anodes. 



10000 




20 30 40 



70 100 



200 300 400 



700 1000 



Anode Current (milliamperes) 



Figure 9.3 Magnesium anode design curves. (Corrpro 
Companies Inc.) 



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188 Cathodic Protection with Galvanic Anodes 



DESIGN CONSIDERATIONS 



To provide a better understanding of the differences in performance between zinc and 
magnesium installations it may be helpful to first identify typical types of installa- 
tion practices. A general rule-of- thumb says that zinc anodes are better used in the 
lower soil resistivity (below 1500 ohm-cm) and magnesium anodes are better in the 
higher resistivity soils (between 1500 and 10,000 ohm-cm). This rule is not universal 
and will depend on the application. This will be illustrated by the examples presented 
below. 

Well-coated pipeline sections typically have low current requirements and will po- 
larize easily to a volt or more. Either zinc or magnesium anodes may provide sufficient 
current for full protection, but zinc anodes may provide full protection with much less 
current being wasted. This is illustrated in the following example. 

Assume a well-coated section of pipeline having a native or static potential to a copper 
sulfate reference electrode (CSE) of —0.7 V, an effective resistance-to-earth of 2 ohm at 
the anode installation site and that 75 mA is necessary to shift the pipeline potential to 
—0.85 V. Also assume that the soil resistivity at the anode installation site is 1500 ohm-cm. 

The installation circuit resistance needed to raise the potential to —0.85 V using zinc 
anodes is calculated by determining the driving voltage (1.1 V — 0.85 V) or 0.25 V and 
dividing it by the current requirement. This calculation is performed using Ohm's Law, 
0.25 V/0.0 75 A = 3.3 ohms. The calculated 3.3 ohms minus the effective resistance of 
the pipeline, estimated at 2 ohms, leaves 1.3 ohms for the resistance of anodes and lead 
wires. Following the procedures outlined in Chapter 7, it can be calculated that five 
1.4 x 1.4 x 60-in zinc anodes (30 lb) surrounded with 50-50 gypsum-bentonite backfill 
in 8-in diameter holes at 15-ft spacing will have a resistance of 1.21 ohms in the 1500 
ohm-cm soil. With 0.03 ohms allowed for lead wire resistance, total resistance is 1.24 
ohms which is within the 1.3-ohm design allowance. 

The same procedure can be derived for magnesium anodes. The magnesium in- 
stallation circuit resistance needed to provide the initial 75 mA requirement will be the 
driving potential (1.55 — 0.85 = 0.70 V) divided by the estimated current requirement of 
75 mA, equals 9.33 ohms. Subtracting the 2-ohm pipeline resistance leaves 7.33 ohms for 
anode-to-earth resistance and lead wire resistance. Using Chapter 7 anode bed resistance 
procedures, one 2 x 2 x 60-in magnesium anode (20 lb each) with 75% gypsum, 20% 
bentonite, 5% sodium sulfate backfill in 8-in diameter hole will give 4.80 ohms anode-to- 
earth resistance in the 1500 ohm-cm soil with 0.01 ohm allowed for lead wire resistance. 
This totals 4.81 ohms, which is within the 7.33-ohm requirement. 

As shown in the previous example, the zinc anode installation number of anodes is 
much larger. This is not, however, the complete analysis. In most cases, a well-coated 
pipeline will continue to polarize after initial requirements are met. The pipeline in the 
zinc anode example may polarize to a potential approaching the —1.1 V open circuit 
potential of zinc. This will result in the reduced current demand. 

Assume a polarized potential of —1.05 volt. The zinc anodes will now have a driving 
potential of only 0.05 V (1.1 - 1.05 V) and the current output will be 0.05-V/3.24-ohms 



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Design Considerations 189 



circuit resistance = 0.0154 A. The magnesium anodes will have a driving potential 
of 0.35 V (1.55 - 1.2 V) and the current output will be 0.35 V/6.81-ohms circuit 
resistance = 0.0513 A. These final or stabilized currents can be used to determine the 
useful lives of the two installations. 

The five, 30-lb zinc anodes will have calculated life as follows. 

0.0424 x 5(30) x 0.90 x 0.85 
Zinc Anode Life (years) = = 315 yr. 

The single 20-lb magnesium anode will have a calculated life as follows: 

A , r , x 0.116x20x0.50x0.85 _ 
Magnesium Anode Life (years) = nTuTTo = Y r ' 

The new calculated design life for each anode is at the efficiencies shown in the for- 
mula (90% for zinc, 50% for magnesium). At very low current densities, efficiencies will 
decrease and actual lives would be less than indicated. This is particularly true for 
magnesium anodes. 

To evaluate these two installations in terms of cost per year of estimated life, the 
installed cost must be known. Zinc is less expensive than magnesium. Assuming a con- 
servatively high material and installation cost per anode, the five zinc anodes could 
cost $250 per anode to install or $1,250. The one magnesium anode with installation 
on the same basis could cost $350. The indicated cost per year for the zinc installation 
would be $1,250/315 years = $3.96 per year. Similarly, the indicated cost per year for 
the magnesium installation would be $350/19.2 years = $18.22 per year. 

It may appear that the indicated life of 315 years for the zinc installation is beyond 
reasonable expectations when the usual design life of a pipeline is 20-50 yr. If the cost 
per year is based on a 20-yr pipeline life, the zinc anode installation cost per year would 
be $62.50 (although not consumed at the end of this period) while the magnesium cost 
per year remains at approximately $18. This analysis favors magnesium if the estimated 
protection current requirements do not change. 

If current requirements increase (see the following discussion on regulation), the orig- 
inal zinc installation can continue to provide adequate protection, whereas replacement 
of the magnesium anode would be required in less than 20 yr. The magnesium anode 
replacement would require more anodes than were used originally in order to maintain 
adequate protection. This will bring the cost per year to roughly equivalent figures for 
zinc and magnesium for the example used in the 1500 ohm-cm soil. Chapter 15 provides 
more detailed analysis of life cycle cost. 

The previous illustration indicates that on a long-term basis, zinc anode installations 
can be less expensive than magnesium when calculated on a simple cost per year basis. 
In the example, it was shown that one magnesium anode discharged more than twice 
as much current as the five zinc anodes. This offers no advantage because zinc fully 
protects the line while excess current from magnesium is wasted. 



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190 Cathodic Protection with Galvanic Anodes 



Inserting resistance in series in the circuit can control the wasted current from mag- 
nesium. In the previous example, current wastage can be eliminated if sufficient resis- 
tance could be inserted in series with the magnesium anode to reduce its output to the 
point that the pipeline would remain protected. That current level would be the same 
as that obtained from the zinc anode (0.030 A). The driving potential would now be 
1.55 - 1.05 = 0.4 V. Circuit resistance would be 0.4 V/0.030 A = 13 ohms. This value of 
13 ohms minus the circuit resistance of the magnesium anode alone, 6.81 ohms (from the 
example above), leaves 6.52 ohms resistance to be inserted in the circuit. By reducing 
the current, the magnesium anode indicated life is increased to 33 yr, reducing the cost 
per year of life to $10.60, which is more in line with the zinc installation. This is further 
discussed below. 



ANODE PERFORMANCE 
System Regulation 



Regulation as applied to galvanic anode installations is a measure of an installations' 
ability to adjust output automatically to compensate for changes in the current require- 
ments of the pipeline to which it is attached. In the previous example which compares 
zinc and magnesium, the assumed pipeline section had an excellent coating, so very 
little current was required to maintain protection. However, current requirements may 
increase with time due to coating deterioration, addition of more pipe, or development 
of a short circuit to another foreign pipeline. 

Assuming that this has occurred, the effective resistance of the pipeline to earth at 
the anode installation site drops from the original 2 ohms to 0.5 ohms. Also assume the 
minimum current required to maintain a polarized potential of —0.85 V has increased to 
130 mA from the original 75 mA. Using figures from the preceding example: 

Zinc installation 

• Driving potential = 1.1 - .85 = 0.25 V 

• New circuit resistance = 1.74 

• Current = 0.25/1.74 = 0.144 A (144 mA) 

• Indicated life at 144 mA output = 33.6 yr 

Magnesium installation without current reducing resistor 

• Driving potential = 1.55 - .85 = 0.70 V 

• New circuit resistance = 5.31 ohm 

• Current = 0.7/5.31 = 0.188 A (188 mA) 

• Indicated life at 188 mA output = 8.4 yr 



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Anode Performance 191 



Magnesium installation with current reducing resistor 

• Driving potential = 0.70 V 

• New circuit resistance = 24.5 ohms 

• Current = 0.7/24.5 = 0.0285 A (28.5 mA) 

• Indicated life at 28.5 mA output = 55 yr 

In this example, the zinc installation has a greater capability of providing current than 
the minimum required, indicating that the line will polarize to some value above the 
—0.85 V minimum protection value and that consequently there will be a better distri- 
bution of full protective potentials along the line. The magnesium installation without 
resistor (which originally discharged more than twice as much current as the zinc and 
was wasting current) now does not discharge quite enough current to maintain the min- 
imum —0.85 V. The line will assume a potential of something less than —0.85 V. The 
magnesium installation with a current controlling resistor obviously does not discharge 
enough current. The size of the resistor would need to be reduced below the calculated 
6.5 ohms value from above or the resistor would have to be removed to achieve any sub- 
stantial degree of protection. This would then reduce the design life of the magnesium 
anode. 

Variations in Soil Resistivity 

The relative effect of soil resistivity on anode performance is discussed below. Calcula- 
tions for zinc and magnesium anodes in soils ranging from low to high resistivity are 
summarized in Table 9.6. The conditions applicable to Table 9.6 are the same as for 
the preceding example based on an installation in 1500 ohm-cm soil (the 1500 ohm-cm 
figures summarize those developed in the example). Specifically, assumptions are the 
following. 

1 . That the pipeline section being protected is well coated and that it has an effective 
resistance to earth of 2 ohms. 

2. That 75 mA are required initially to polarize the pipeline to —0.85 V to copper sulfate. 

3. That once CP current is applied, the line will continue to polarize to —1.05 V CSE 
when protected with zinc and to —1.2 V when protected with magnesium. 

Anodes of similar sizes were used for both magnesium and zinc for purposes of this com- 
parison. If more than one anode was required, the anode bed resistance was calculated 
on the basis of 15-ft spacing between anodes. 

Although the use of different anode sizes would alter the current output and indicated 
life, the table does illustrate certain tendencies. These are the following. 

1 . That zinc anode installations of the smallest size that will meet design current require- 
ments have a substantially longer life than their magnesium anode counterparts. 



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192 



Cathodic Protection with Galvanic Anodes 



Table 9.6 Comparison of Zinc and Magnesium Anodes in Varying Resistivities 













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3x3x60 
40-Pound 


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1.3 


1.4x1.4x60 
30-Pound 


0.76 


2.76 


18.1 


107 


198 


11.0 


9.8 












One 


















Mag 


0.6 


8.0 


6.0 


3x3x60 
40-Pound 


2.0 


4.0 


62.5 


31.5 


240 


3.85 


8.2 


500 










Two 


















Zinc 


0.25 


3.3 


1.3 


1.4x1.4x60 
30-Pound 


1.07 


3.07 


16.2 


120 


159.5 


9.85 


12.2 












One 


















Mag 


0.6 


8.0 


6.0 


2x2x60 
20-Pound 


4.81 


6.81 


36.6 


26.9 


113 


3.08 


8.7 


1500 










Five 


















Zinc 


0.25 


3.3 


1.3 


1.4x1.4x60 
30-Pound 


1.24 


3.24 


15.4 


315 


144 


9.35 


33.6 












Two 


















Mag 


0.6 


8.0 


6.0 


2x2x60 
20-Pound 


4.86 


6.86 


36.4 


55.2 


112 


3.08 


17.6 


3000 










Eleven 


















Zinc 


0.25 


3.3 


1.3 


1.4x1.4x60 
30-Pound 


1.3 


3.3 


15.2 


745 


139 


9.15 


83 



2. That as soil resistivity increases, the ratio of number of zinc anodes to the number 
of magnesium anodes increases. This increases installation costs for zinc at a greater 
rate than for magnesium. 

3. That magnesium anode current outputs are consistently higher than the output of 
the zinc anodes under design conditions. This represents wasted current from the 
magnesium anodes because fully adequate protection is obtained from zinc at its 
lower current output. 



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4. That if the current demands of the pipeline increase, the magnesium anodes in low 
resistivity soil will continue to deliver higher currents than zinc anodes. Under lower 
soil resistivity conditions, more magnesium anode material (using anodes of the 
size shown) would be needed to obtain equivalent life than would be needed using 
zinc. 

5. That if the current demands of the pipeline increase, zinc anode installations in the 
higher resistivity soils have a higher current delivery capability than the magnesium 
installations. 

6. That the gains by regulation of zinc installations are consistently better than those 
from magnesium and that the ratio of the two increases as soil resistivity increases. 
This characteristic is related closely to observations 4 and 5. 

The conclusions that can be reached from the foregoing examples and comparisons 
include the following. 

1 . That installations may be designed using either zinc or magnesium over a wide range 
of soil resistivities. 

2. That from an economic standpoint, zinc is most attractive in lower resistivity soils. 
Using it in soils below 1500 ohm-cm resistivity is a reasonable guide in this respect. 

3. That zinc anodes in soils of any resistivity offer the best self-regulating characteristics 
in terms of continuing to provide sufficient current for adequate protection without 
excessive current wastage. 



GALVANIC ANODE INSTALLATION DETAILS 

Galvanic anode installations are simple compared to the usual impressed current instal- 
lation. The simplest installation is that involving the burying of a single packaged anode 
at a leak repair location or for distributed anode installations along a pipeline. This is 
shown by Figure 9.4. 

The popular 17-lb, 20-lb, or 32-lb packaged magnesium anodes are used most com- 
monly for this type of application, although packaged zinc anodes may be used in low 
resistivity soils and heavier packaged magnesium anodes may be used, where conditions 
warrant, for longer life. 

Where several magnesium or zinc anodes are to be installed at a single location, 
usually on a coated pipeline, the anodes may be connected to a header wire. The header 
wire should be brought to a test point to permit monitoring, and periodic measurement 
of output current, for calculation of anode life. This is illustrated by Figure 9.5. 

Anodes in a multiple anode bed should be placed in straight line configuration for 
lowest resistance to earth. The line of anodes may be perpendicular to the pipeline, as 
shown in the figure, or may be along a line parallel to the pipe. The latter arrangement 
makes it possible, in many cases, to install a large galvanic anode bed without having to 
go beyond the limits of the pipeline right-of-way. A parallel line of magnesium anodes 



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Cathodic Protection with Galvanic Anodes 




HOLE DUG FOR 
LEAK REPAIR OR 
DISTRIBUTED ANODES 



PACKAGED ANODE 
WITH ATTACHED 
INSULATED LEAD 



5' MINIMUM 



Figure 9.4 Single package anode installation. 



should be at least 15 ft away from the pipeline. With zinc, this distance may be reduced 
to 5 ft or even closer, if little space is available, without affecting significantly the current 
distribution characteristics of the bed used with coated pipe. Where space is available, 
however, it is best to allow at least 10 ft between the pipeline and the line of zinc anodes 
for optimum performance. 




TEST STATION 



TEST POINT 



AUGER HOLE DEPTH 
TO MATCH ANODE SIZE 
AND LOCATION OF 
FAVORABLE SOIL 
RESISTIVITY ■ 



INSULATED 
HEADER WIRI 



EXOTHERMIC 
WELD CONNEC- 
TION, (COATED) 



DESIGN DISTANCE 
10' MINIMUM 
(SUGGESTED) 




A.£ 



INSULATED SPLICE 
CONNECTION 




PACKAGED ANODE 



Figure 9.5 Multiple galvanic anode installation. 



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195 



EXOTHERMIC WELD 
. CONNECTION 
TO PIPE , 



SINGLE ANODES: 
(3' MIN) 

MULTIPLE ANODES 
(5' MIN) 




WHERE NECESSARY, 
HOLE MAY BE ANGLED 
SLIGHTLY TO PLACE 
ANODE DIRECTLY 
UNDER PIPE 



PACKAGED ANODE 



Figure 9.6 Galvanic anode below pipe installation. 



Where soil resistivities and augering conditions permit and where space limitations 
are extremely critical, as may be true in distribution systems, anodes may be placed in 
auger holes alongside the pipe with the hole being deep enough that reasonable spacing 
between pipe and anode is obtained. This is illustrated by Figure 9.6. 

In this type of installation, very deep auger holes would be required to place multiple 
anodes as far below the pipe as given above for anodes at lateral distances parallel to 
the pipe. The recommended depth is shown in the figure. These are justified by the 
fact that with the anodes deeper in the mass of the earth (and where soil resistivities 
are favorable) potential gradient effects at the pipeline may be less severe than with 
anodes closer to the surface and at comparable lateral distances from the pipe. Further 
advantages of this type of installation are that the anodes, being placed deep, are less 
subject to seasonal current output variation associated with soil moisture content and 
there is less connecting wire located where it may be damaged by excavations made for 
other purposes. 

The preceding three illustrations concerned the use of packaged anodes where each 
anode and its associated backfill material are installed as a single unit. Either zinc or 
magnesium anodes are available unpackaged. They should, nevertheless, be used with 
prepared backfill in the usual buried installation. Anodes and backfill may be installed 
in auger holes as shown in Figure 9.7. 



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Cathodic Protection with Galvanic Anodes 



SOIL BACKFILL 




SPECIAL BACKFILL ■ 
MIXTURE 

PLACE AND TAMP 6" LAYER 

IN HOLE BOTTOM. 

PLACE AND CENTER ANODE 

IN HOLE. 

FILL HOLE WITH TAMPED 

BACKFILL TO POINT 6" 

ABOVE TOP OF ANODE 

8" DIAMETER AUGER HOLE - 
(OR LARGER IF NECESSARY 
TO PERMIT 2" THICK LAYER 
OF BACKFILL AROUND 
ANODE) 



INSULATED SPLICE CONNECTION 



HEADER CABLE 
(INSULATED) 



TOTAL HOLE DEPTH 
DICTATED BY SOIL 
RESISTIVITY 
CONDITIONS 



AS 



Figure 9.7 Unpackaged galvanic anode installation. 



Anodes and backfill installed separately are used more often for multiple anode 
installations than for single anode installations. The advantage of this type of installation 
is that the backfill, being installed separately and tamped in place, fills completely all the 
voids in the auger hole. This minimizes the possibility of the backfill settling away from 
the anodes and reducing the anodes long-term effectiveness. This possibility is greater 
when packaged anodes are used because when the backfill container deteriorates, the 
backfill will settle into voids that may unknowingly have been left around or below the 
package. 

When calculating backfill material requirements, a figure of 70 lbs of backfill material 
may be used for each cubic foot of space to be filled. This is done by calculating the 
total volume of the auger hole to be filled with backfill, and then subtracting the volume 
of the anode. Magnesium anode volume is the anode weight divided by 121 while zinc 
anode volume is the anode weight divided by 440. A word of caution in calculating 
hole volume — for example, an 8-in auger, hole will be actually somewhat oversize when 
completed. An additional 0.5 or 1 in diameter can result in a substantial increase in 
backfill volume. 

As was the case with anodes for impressed current anode beds, galvanic anodes may 
be installed horizontally where soil resistivity requires it for most effective performance. 
Either packaged anodes or separate anodes and backfill may be so installed. When 
placing horizontal packaged anodes in a trench, care must be taken when backfilling to 
be sure that the earth surrounds the package completely so that no voids exist. Native 



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197 





FENCE LINE OR OTHER 
CONVENIENT TEST 
POINT LOCATION 

POST-MOUNTED TEST STATION 
CROSS CONNECTION MAY BE 
UNDERGROUND IF SUITABLE 
LOCATION FOR TEST POINT 
DOES NOT EXIST 



CONNECTION 
TO PIPE ■ 




■ STRIP ANODE OF MAGNESIUM 
OR ZINC SURROUNDED SPLICE 

WITH SPECIAL BACKFILL SEE DETAIL - 



DP 



-■L± 



-1000' MAX- 



EXOTHERMIC WELD OR 

CRIMP-TYPE 

CONNECTION 

INSULATED WIRE 
TO TEST POINT 




SEE DETAIL OF 
CONNECTION TO ■ 
STRIP ANODE 



Detail of connection to strip anode 



Detail of strip 
anode splice 



EXPOSE APPROXIMATELY 
3" OF CORE WIRE BY 
MELTING AWAY ZINC 
WITH TORCH. 



2 HALF-LAPPED 
LAYERS OF RUBBER 
TAPE AND 2 HALF- 
LAPPED LAYERS OF 
PVC SELF-ADHESIVE 
TAPE 




■ EXPOSE 2" OF CORE WIRE 
ON EACH END AND JOIN 
WITH EXOTHERMIC WELD OR 
CRIMPED CONNECTION 



Note: Magnesium anode should never be melted with torch. Expose steel wire core by carefully 
cutting magnesium with knife or sharp object. 

Figure 9.8 Continuous galvanic anode installation. 



earth then may be used to complete the trench backfill (after making all anode lead 
connections and insulating them). 

In some applications, long strip (ribbon) anodes of either magnesium or zinc may 
be plowed in parallel to the pipeline along sections of bare or poorly coated line where 
continuous local protection is required. General features of a strip anode installation are 
shown by Figure 9.8. 

The steel wire core of strip anodes provides continuous longitudinal electrical con- 
ductivity even after the anode material is consumed completely in some areas (it will be 
used up first, in the lower soil resistivity sections). Connections between the pipeline 
and anode core wire should be made at intervals to complete the protection circuit. If 



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198 Cathodic Protection with Galvanic Anodes 



these cross connections can be made at test points located at fence lines or other con- 
venient location, it will be possible to measure current flow periodically and estimate 
the rate of anode material consumption. Intervals between cross connections should 
not be too great because there will be some voltage drop in the strip anode, with this 
voltage drop increasing with time as the strip cross-sectional area is reduced as active 
material is consumed. Although this effect will vary depending on the soil resistivity 
and total current being carried by the strip anode, it is suggested that the interval not 
exceed 1000 ft. 

Spacing between the strip anode and pipeline is not critical. To remain clear of the 
pipe during plowing-in operations, a spacing of at least 5 ft from the near edge of the 
pipe may be used. The anode strip should be deep enough to be used in continuously 
moist soil. No less than 2 ft is suggested and greater depths will be necessary in areas 
where soils are subject to deep drying out during dry periods. 

Strip anodes of magnesium or zinc are furnished bare. Using such anodes in earth 
without a special backfill involves risk of anode passivation and inadequate amounts 
of current. For most reliable results, the strip anode should be plowed in with suitable 
special backfill. An adequate allowance, assuming satisfactory dispersion around the 
anode, is 70 lbs of backfill per 100 ft of strip. 

Strip anodes may be used favorably in areas where soil conditions permit the use 
of tractor-drawn plows fitted to carry trail reels of anode strip and a backfill supply. 
Rocky or very rough terrain may preclude the use of this type of anode as opening 
a continuous ditch in the conventional manner would, in most instances, be too 
costly. 

Test points for multiple anode locations may be installed as shown in Figure 9.9. 

The shunt in the test point terminal box makes it possible to measure the current 
from the anodes (using a millivoltmeter as shown) without disturbing the circuit. The 
common 0.01 ohm shunt does not have enough resistance to have a substantial effect 
on the anode current output in most cases. If a solid link is used instead of the shunt, 
however, good practice is to use an ammeter circuit for measuring the anode current or 
a clamp-on ammeter as discussed in Chapter 6. The separate test wire from the pipeline, 
as shown in the figure, makes it possible to measure accurately the pipeline potential to a 
copper sulfate reference electrode. Pipe and anode leads for multiple anode installations 
may, typically, be No. 8 AWG copper wire with insulation suitable for direct burial insu- 
lation. The separate potential test wire should not be smaller than No. 12 AWG insulated 
wire. 

With galvanic anode installations, all wire connected to the anode tends to be 
protected. This means that if any copper is exposed, it will not tend to corrode and 
cause severing of the wire as will happen if there is any break in the insulation in wires 
connected to the positive terminal of the DC power source in an impressed current CP 
system. Because of this, insulation of underground connections on galvanic anode instal- 
lation is not as critical but should nevertheless be well done to prevent current loss. Also, 
if anything other than brazed, soldered or welded connections are used (such as crimp 
or compression connections), the connection should be waterproofed completely to pre- 
vent possible development of resistance within the joint. Probably the most important 



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199 




TEST POINT SUPPORT 

4" x 4" x 6' TREATED WOOD POST 

OR 2" TO 4" x 6' STEEL PIPE 



-TEST STATION 



PVCOR 
GALVANIZED 
STEEL CONDUIT 
3/4" OR 1 
CONDUIT 
STRAP 



yp^ 7 ^ 



^^^w^ 



CONDUIT 
BUSHING 




0.01 OHM WIRE 

SHUNT 

0.1 AMP PER 

MILLIVOLT DROP 



INSULATED WIRE 
TO ANODES 



INSULATED CURRENT- 
CARRYING AND TEST 
WIRES TO PIPELINE 



Figure 9.9 Galvanic anode test station installation. 



connection in a galvanic anode system from an insulation standpoint is the connection 
between the pipeline and the copper anode lead. The strong dissimilar metal corrosion 
cell between steel and copper needs to be thoroughly and permanently waterproofed to 
prevent any possibility of pipe corrosion immediately adjacent to the connection where 
the corrosion cell may not be overcome completely by the applied CP. This can occur 
particularly when bare copper wire lies closely parallel to bare steel such that the wire 
acts as an electrical shield and prevents protective current from reaching the steel. 

When galvanic anode installations are first set up, they may not attain maximum 
current output for some time. This is because the dry backfill mixture may take up 
moisture slowly from the surrounding soil. Unless the surrounding soil is very wet, it 
may be several days or even weeks before maximum output is attained. If dry soil 
conditions prevail, wetting the soil above the anode after installation will help. The 
obvious solution of mixing the backfill with water before installation is not necessarily 
a good one because shrinkage may result, with possible development of voids when 
excess water leaves the backfill. On the other hand, well-tamped dry backfill tends to 
expand upon taking up moisture from the surrounding soil, thus ensuring intimate 
contact throughout the backfill column. 



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Chapter 



Cathodic Protection with 
Other Power Sources 



John A. Beavers 



Although most impressed current cathodic protection (CP) systems use AC power sup- 
plied by utilities in conjunction with rectifiers as a source of DC current, there are several 
other power sources that may be used if AC power lines are not available. Some of these 
have been in use for some time; others are relatively new; and still others are in the 
development stage. Many of these alternative power sources are expensive; therefore, 
the corrosion engineer must make certain that the same degree of protection cannot be 
obtained at less cost by other means such as by galvanic anodes. 



ENGINE-GENERATORS 



Engine-generator sets may be used to provide the electrical energy for CP rectifiers if a 
large power source is needed and AC power lines are not available. Gas from the pipeline 
may be used to power the engine for a CP system on a natural gas pipeline. If the line 
carries a petroleum product suitable for engine fuel, this may be taken directly from the 
line as well. Otherwise, fuel must be brought to the generator station periodically. 

Present practice is to use an engine coupled with an AC generator (alternator). The 
power from the alternator is fed to a conventional rectifier that supplies the direct current 
energy required for the CP installation, as shown in Figure 10.1. The DC power output 
from the rectifier is used in the conventional manner to supply current to ground beds 
(surface or deep well) as discussed in Chapter 7. 

The reasons for using an alternator and conventional rectifier rather than generating 
direct current are the following: 

1 . The alternator requires less maintenance on its slip rings than a DC generator requires 
with its commutator, and 

201 



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202 



Cathodic Protection with Other Power Sources 



TANK FOR LUBRICATING OIL 



A-C SUPPLY LINE 
TO RECTIFIER 



ALTERNATOR 
CONTROL CENTER 




EXHAUST STACK 



CONVENTIONAL A-C 
TO D-C IMPRESSED 
CURRENT CATHODIC 
PROTECTION RECTIFIER 



FUEL GAS 
SUPPLY LINE 
TO ENGINE 






PROTECTED 
NATURAL GAS 
PIPELINE 



NEGATIVE LEAD 
TO PIPELINE 



V CONVENTIONAL 
GROUND BED 



GAS-POWERED - 
ENGINE 



Figure 1 0.1 Engine-generator CP installation. 



2. Control of DC output voltage over a wide range is accomplished more readily with 
rectifiers than by controlling the output of a DC generator. 

Engine-generator installations must be designed with reliable equipment that will 
operate unattended for several weeks. The cost of operating such an installation will be 
relatively high, particularly if engine fuel must be brought in. The installations should 
be inspected frequently, preferably at least every two weeks. Periodic overhauling of the 
rotating equipment (particularly the engine) should be planned to assure continued ef- 
fective operation. Intervals between overhauls will depend on the engine manufacturer's 
recommendations and operating experience with the equipment. 



TURBOGENERATORS 



Closed cycle vapor turbogenerators (CCVTs) are commercially available as power 
sources for remote CP systems. The available CCVT systems can supply up to 5000 W 
and 100 V. The system consists of a Rankine cycle turbine and an alternator. A schematic 
is shown in Figure 10.2 and an actual installation is shown in Figure 10.3. A burner heats 
an organic liquid that vaporizes and expands. The vapor is directed through the rotating 
turbine wheel, providing power to the alternator. The vapor is passed into a condenser 
where it is cooled and returns to the liquid state. The liquid is then pumped back into 
the vapor generator. The common shaft connecting the turbine wheel, generator, and 



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Turbogenerators 



203 



CPVCM and 
Electrical cabinet 
including rectifier 



Electrical output 
filtered DC 



Vapor generator 
Burner 



Chimney 



i,^/" Condenser 



Condensate 
outlet 



Turbine 
wheel 



Alternator 

Canister 
Feed pump 




Condensate 
feed pipe 



Organic fluid 

Control cables 
to fuel panel 

Thermostat 



Fuel inlet 



r— Fuel 
control 
panel 



Figure 10.2 Schematic of a closed cycle vapor turbogenerator. (Courtesy of 
Ormat.) 



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204 



Cathodic Protection with Other Power Sources 




Figure 1 0.3 Installation of a closed cycle vapor turbogenerator on a gas 
pipeline in the western United States. (Courtesy of Ormat.) 



pump is the only moving part in the system. This shaft is supported by working fluid 
film bearings, minimizing wear and associated maintenance. 

CCVT systems can operate on a variety of fuels, including natural gas, liquified 
petroleum gas, kerosene, jet fuel, and diesel fuel. With natural gas, the burner should be 
inspected and cleaned, if necessary, annually. More frequent cleaning may be required 
if less clean fuels are used. 



THERMOELECTRIC GENERATORS 



It has long been known that heating a junction of certain dissimilar metals could generate 
electricity. These junctions (thermocouples) are used widely as a means of measuring 
temperature — the voltage output of the heated junction being fed to a voltmeter cali- 
brated in degrees. In the earliest attempts to use this principle as a CP power source, 
large numbers of low-capacity metallic junctions were connected in series-parallel com- 
binations and heated with a gas flame to attain the necessary DC output capacity. These 
designs were not particularly successful because of failure of the junctions used. 

In recent years, there has been rapid development of higher capacity semiconducting 
thermoelectric materials designed specifically for power-generation use. Figure 10.4 is a 



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Thermoelectric Generators 



205 



COOLING FINS 



HEAT PIPES 

COLD ELECTRODES 

ELEMENTS 

HOT ELECTRODES 



BURNER 




HEAT PIPE FLUID 



THERMAL INSULATION 
INSIDE HERMETICALLY 
SEALED POWER UNIT 



- ELECTRICAL INSULATOR 
Figure 10.4 Schematic of a thermoelectric generator. (Courtesy of 
Global Thermoelectric, Inc.) 



schematic showing the operation of a thermoelectric generator and Figure 10.5 shows an 
actual installation. A thermocouple is formed by a P type and an N type thermoelectric 
leg joined together electrically by a hot junction electrode. Adjacent thermocouples are 
joined together by cold junction electrodes with each pair producing about 90 mV. Sev- 
eral hundred thermocouple pairs are connected in series to provide the desired output 
voltage. The hot junction is maintained at a high temperature (about 1000°F) using nat- 
ural gas or propane while the cold junction is cooled with heat pipes to maintain a lower 
temperature (about 325°F). The heat pipe is hermetically sealed and contains a special 
fluid in equilibrium with its vapor. As heat is applied to the fluid, it boils, carrying heat 
with it. The vapor rises to the finned portion of the pipe and condenses because of the 
cooling effect of the fins. 

Standard thermoelectric generator units are available at power outputs up to 600 W 
and voltages up to 48 V. Higher power outputs can be achieved by adding parallel units. 
If higher voltages are required for a CP installation, it is also possible to convert the 
low DC voltage from the generator to a higher DC voltage. The converters, although 
of high efficiency, do cause some power loss. For this reason, maximum efficiency will 



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206 



Cathodic Protection with Other Power Sources 




Figure 10.5 Installation of a thermoelectric generator. (Courtesy of Global Thermo- 
electric, Inc.) 



result if ground beds can be built to directly use the output of the thermoelectric gen- 
erator. Designing ground beds without carbonaceous backfill will reduce the applied 
voltage requirement by reducing the groundbed back voltage substantially. When plan- 
ning an installation where a thermoelectric generator may be applicable, check with the 
equipment manufacturers for the latest equipment specifications. Since thermoelectric 
generators contain no moving parts, maintenance is minimal. Annually, it is necessary 
to replace the fuel filter and clean the fuel orifice. 



SOLAR ELECTRIC POWER SYSTEMS 



In areas where sunlight can be expected for relatively large percentages of the time, a 
combination of solar cells and storage batteries can be used to provide a continuous flow 
of current to a CP installation. A typical installation is shown in Figure 10.6. Solar cells 
rely on the photoelectric effect: a process in which a material liberates an electric charge 
when electromagnetic radiation (sunlight) is incident on the material surface. Solar cells 
are typically P-N junction semiconductors fabricated of crystalline silicon and doped to 
provide the desired photovoltaic properties. 



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Batteries 



207 




Figure 10.6 Typical solar electric CP installation. 
(Courtesy of Kyocera Solar, Inc.) 

The initial cost of the solar electric powered CP systems has dropped dramatically 
over the past 20 years as the technology has advanced. This advancement has occurred, 
in part, as a result of rapid development in the semiconductor industry in general. Solar 
electric power systems also are used for other applications such as satellite communica- 
tions and cellular telephony. Systems are now available that operate at power outputs 
up to 1000 W, voltages up to 20 V, and currents up to 50 A. Battery storage capacities up 
to 3200 A-h (at 12 V) are available. Such a battery backup could supply a 10 A rectifier 
for almost two weeks with no recharging. 



BATTERIES 



The cost of electrical energy from batteries is high. Occasionally, however, they have been 
used to supply CP current to isolated sections of well-coated pipe where power lines are 
not available and where galvanic anodes will not supply the necessary protective current 
at less cost. Figure 10.7 illustrates the use of batteries on a well-coated river crossing. 

Note that the ground bed shown in the figure is scrap steel. High silicon cast iron 
anodes without carbonaceous backfill may be used also. Graphite anodes or other anodes 
backfilled with carbonaceous material are not favored because of the characteristic back 
voltage (usually around 2 V) which would have to be overcome with extra battery 
capacity. 



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Cathodic Protection with Other Power Sources 



RIVER 



INSULATED 
FLANGES 



PIPELINE 



BATTERY IN 
WEATHERPROOF 
POLE-MOUNTED „ 
HOUSING. 



SCRAP STEEL 
GROUND BED 



I I I r 



INSULATED 
FLANGES 



)M 



Figure 1 0.7 Battery-powered CP installation. 



WIND-POWERED GENERATORS 



Wind-powered generators may be used as a source of power in areas where prevailing 
winds are of sufficient intensity and duration. Such units were used fairly extensively 
in the early days of pipeline CP. However, they are expensive and require quite a lot of 
maintenance. Their use for this application has declined with the development of more 
cost-effective, reliable power sources, such as solar cells, CCVTs, and thermoelectric 
generators. Nevertheless, wind-powered generators may be considered as one method 
of providing power for CP systems in remote areas. Because the power output from a 
wind-powered generator will be neither steady nor continuous, some means must be 
used to assure a steady supply of current to the CP ground bed. This can be done by 
using storage batteries. 

When designing a wind-powered installation, wind conditions must be evaluated 
thoroughly so that both the generator and storage battery can be sized properly. The 
storage batteries used must have sufficient capacity to supply the required CP current 
throughout the duration of the longest probable windless period. Likewise, the generator 
must have sufficient capacity to both supply the CP current and recharge the batteries 
during periods of sufficient wind. 

Wind-powered generator installations require significant maintenance. Lubrication 
of the generator bearings and mounting swivel (unless they are the lubricated-for-life 
type) must be scheduled on a regular basis. Generator commutator and brushes as well as 



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Gas Turbines 



209 



slip rings and brushes at the mounting swivel must be checked periodically, cleaned, and 
dressed when worn. Storage batteries require close attention to maintain the electrolyte 
at the proper level. 



GAS TURBINES 



Gas turbines can be used to drive DC generators on natural gas pipelines if there is an 
adequate pressure drop available. The installation of such a device across a delivery 
station is illustrated in Figure 10.8. The gas is diverted to the turbine through a bypass 
line and returned to the system without loss. Similar systems can be established at other 
locations on gas systems where reasonably constant pressure drops are available, such as 
in producing gas fields, at well heads, and on gas transmission pipelines. The principal 
disadvantage of gas turbine power sources is the restricted number of locations where 
they can be used. For this reason, they are not widely installed. 



TRANSMISSION 
PIPELINE 



INSULATED 
FLANGES 



PRESSURE 
REDUCTION 
EQUIPMENT 
AT DELIVERY 
STATION 



DISTRIBUTION 
SYSTEM MAIN 



REGULATOR 
(WHERE NECESSARY) 



«c 



■<A> 



X 



CATHODIC 

PROTECTION 

GROUNDBED 



D-C GENERATOR 
'GAS TURBINE 



Figure 1 0.8 Gas turbine CP installation. 



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210 Cathodic Protection with Other Power Sources 



FUEL CELLS 



The fuel cell is still another source of DC energy that is subject to intensive development 
as a result of space exploration and military applications and, most recently, automotive 
applications. In its simplest form, the basic fuel cell can be visualized as a sandwich of 
two porous electrically conducting plates (or electrodes) with an electrolyte filling the 
space between the plates. A gaseous fuel such as hydrogen is forced through one plate 
into the cell, and an oxidizing agent such as oxygen gas is forced through the other plate. 
Within the porous electrodes, the fuel and oxidant react electrochemically with the 
electrolyte to produce electricity and water. Leads from the two porous electrodes serve 
to remove the electricity generated. Cell developments are in the areas of porous elec- 
trode formulation, electrolytes, and catalysts that will permit long-term cell performance 
at optimum output. Development is active also in the technology of fuel cells that use 
fuels other than hydrogen and oxygen. The pipeline corrosion engineer will have an- 
other useful DC power source for impressed current CP installations when fuel cells are 
developed commercially at practical cost that can use natural gas or propane as fuels. 



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Chapter 



Stray Current Corrosion 



Michael J. Szeliga 



The major emphasis of the preceding chapters has been on corrosion and the use of 
corrosion control methods to combat it successfully. The stray currents associated with 
pipeline corrosion problems are, as the designation implies, direct currents flowing in 
the earth from a source other than that associated with the affected pipeline. To cause 
corrosion on a pipeline, stray direct current (DC) must flow from an outside source 
onto the pipeline in one area and then flow along the line to some other area or areas 
where they leave the pipe to reenter the earth (with resulting corrosion) and complete 
the circuit by returning to the original DC power source. Stray currents are either static 
(nonvarying) or dynamic (varying). Stray current sources include the following: im- 
pressed current cathodic protection (CP) systems on other pipelines, DC transit systems, 
DC mining operations, DC welding operations, high voltage DC transmission systems 
and disturbances of the earth's magnetic field. On occasion, AC current flow to ground 
on electrical distribution systems may be rectified if environmental conditions are such 
that rectifying junctions can be formed such as certain copper oxide films on copper or 
copper jacketed ground rods. The resulting direct current could create a stray current 
problem (usually minor) that can be mitigated by the procedures described below for 
the more usual sources of stray DC currents. 

The purpose of this chapter is to outline the fundamentals involved in recognizing, 
testing for and correcting stray current corrosion conditions. The ability to deal with such 
situations is important to the pipeline corrosion engineer. This is because the magnitude 
of stray current discharge from a pipeline at a given point may be far greater than that 
of galvanic corrosion currents experienced elsewhere on the line. Failure to correct stray 
current discharge, can lead to early pipeline leaks. 

STRAY CURRENT FROM CATHODIC PROTECTION INSTALLATIONS 

Impressed current CP systems can cause stray current interference on adjacent pipelines 
depending on the location of the ground beds, the exact location of the pipeline and the 

211 



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Stray Current Corrosion 



( '\ 

'ooopoo 



\ 



I— ^REMOTE 
GROUND BED 



AREA OF INFLUENCE SURROUNDING 
GROUND BED. WITHIN THIS AREA 
SOIL POTENTIALS ARE POSITIVE 
(+) WITH RESPECT TO REMOTE 
EARTH. 




RECTIFIER 



FOREIGN 
PIPELINE. 
OR OTHER 
METALLIC 
STRUCTURE 



CURRENT FLOW 
FROM FOREIGN 
STRUCTURE TO 
PROTECTED LINE 
IN CROSSING 
AREA> 




. PROTECTED 
PIPELINE 



Figure 11.1 Foreign pipeline damage by cathodic 
protection installation — case 1. 

operating characteristics of the CP system. Figures 11.1 to 11.4 illustrate the conditions 
that can result in this type of stray current interference. 



Testing for Interference 



Testing for static stray DC current interference caused by CP systems is reasonably 
straightforward in areas where there are no complications caused by the presence of 



FOREIGN PIPELINE 
NOT CROSSING 
PROTECTED LINE. ^ _ 



N 

N \ 
\ N i 



AREA OF INFLUENCE 
■ SURROUNDING THE 
GROUND BED. 

ENDWISE 
C CURRENT FLOW. 
j > 



ffM^Fn 




GROUND ' 
BED / 

— RECTIFIER 




CURRENT 
DISCHARGE 
FROM FOREIGN 
PIPELINE IN 
REMOTE 
AREAS. 



P \ \ 



3 



■ PROTECTED PIPELINE 



Figure 1 1 .2 Foreign pipeline damage by cathodic protection 
installation — case 2. 



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Stray Current from Cathodic Protection Installations 



213 



nV'/ •&>/ ^"/ ^'i, N Vi, 




Figure 11.3 Potential gradients in earth around 
cathodically protected pipeline. 



superimposed dynamic (variable) stray currents from sources such as DC powered tran- 
sit systems. Figure 11.5 illustrates an example where an impressed current CP system 
(incorporating a rectifier as a DC power source) has been applied to a section of coated 
pipeline that has several foreign pipelines crossing it. Assume that at each foreign line 
crossing, a test station has been installed, as shown in the detail on the figure, with two 



FOREIGN LINE TENDS 
TO BECOME POSITIVE 
TO SOIL WITHIN AREA 
OF INFLUENCE AND IS 
FORCED TO DISCHARGE 
CURRENT. 



■ MOST INTENSE CURRENT 
DISCHARGE AND GREATEST 
CORROSION DAMAGE TO 
FOREIGN LINE IS NORMALLY 
AT POINT OF CROSSING. 



:& 



nV'/ 



*", 



^'1/ 




X 



X 



*'>/ $1/ ^'1/ ^ sJ l, 

FOREIGN 
^ PIPELINE 



'7~ T^pp^f " 

n\ IDDCMT I / / / , U Vk i * . i t 



CURRENT 

PICKED UP 

BY FOREIGN • • \ 

PIPELINE \ \ 

OUTSIDE AREA\ 

OF INFLUENCE 




/ 
PROTECTED 
PIPELINE. 



S~ AREA OF 
\* INFLUENCE 
/ SURROUNDING 

PROTECTED 

PIPELINE. 



Figure 11.4 Effect on foreign pipeline passing through earth 
potential gradients around cathodically protected bare line. 



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Stray Current Corrosion 




FOREIGN FOREIGN 
LINE C LINE D 



RECTIFIER 
GROUND BED 
INSTALLATION 



PROTECTED LINE 
^ UNDER TEST 



=ff 



£= 



CURRENT 
INTERRUPTER 
INSERTED FOR 
TESTS. 



"O 



RECTIFIER AND GROUND 
BED ON FOREIGN LINE 



STATION 
1765 + 00 



=ff 



STATION 
1815 + 00 



^H PIPELINE E 

P (OWN PIPELINE) 




2 WHITE LEADS 



PROTECTED 
LINE 



Figure 11.5 Testing foreign pipeline crossings for stray current interference from CP 
installations. 



color-coded leads brought to the test station terminal board from each pipe. An automatic 
current interrupter (a device for automatically opening and closing an electrical circuit 
at preset time periods) may then be installed in the output of the rectifier as shown. 
The interrupter may be set to operate at a cycle such as 20 seconds, current ON, and 
10 seconds current OFF, so that the effect of the CP current on the foreign pipelines can be 
clearly distinguished. With the current interrupter operating, each foreign line crossing 
is visited and the potential of each line is measured under both current ON and current 
OFF conditions. For these tests, the copper sulfate electrode (CSE) is placed directly over 
the point of crossing. If there is any question as to the crossing location, a pipe locator 



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Stray Current from Cathodic Protection Installations 215 



Table 11.1 Survey Notes on Stray Current Investigation 





Foreign Line 
Lgnation & Location 






Potential Vs Close (CSE) 






Des 


(E) Own Pipel 


ine, V 


Foreig 


n Pipeline 


,V 




Pipeline 


With Current 




With Current 




Name Station 


ON 


OFF 


AV 


ON 


OFF 


AV 


A 


10 + 00 


-0.88 


-0.85 


-0.03 


-0.87 


-0.89 


+0.02 


B 


900 + 00 


-1.98 


-1.02 


-0.96 


-0.32 


-0.68 


+0.36 


C 


1765 + 00 


-0.68 


-0.64 


-0.04 


-0.78 


-0.78 





D 


1815 + 00 


-0.95 


-0.91 


-0.04 


-0.68 


-0.68 






should be used to determine exactly where it is. See Chapters 5 and 6 on instrumentation 
and techniques for information on equipment and test procedures. 

Data taken at the several pipeline crossings of Figure 11.5 may be recorded as shown in 
Table 11.1. The data shown in the table illustrate various types of stray current interference 
effects that may be encountered. In addition to the data shown for this illustration, field 
data sheets should include full information on the line protected, date, current output of 
the interrupted rectifier and other pertinent facts. Following are some conclusions that 
can be reached from the data as well as notes on supplementary tests that can be made 
where appropriate. 



Crossing A 



Pipeline E (own pipeline) is fully protected, but may have a substantial coating holiday 
in the vicinity of the crossing because the potential of the foreign line decreases when the 
interrupted rectifier switches from OFF to ON. This indicates that there is appreciable 
current flowing to the line under test, creating more negative soil locally around the 
foreign line. 

The foreign line in this instance appears to be cathodically protected as indicated 
because its potential at the crossing, with the line E rectifier turned OFF, is —0.89 V. The 
potential of pipeline A becomes less negative (— 0.87 V) when the line E rectifier is ON. 
This indicates that the line E rectifier is reducing the protective potential on pipeline A. 
However, the reduction is probably not sufficient to suggest a loss of protection. To verify 
full protection on line A, additional testing should be performed with the CP system for 
the foreign line interrupted while the rectifier for pipeline E is turned ON. The data 
indicate that no corrective measures would probably be required for pipeline A. 



Crossing B 



Pipeline E is fully protected. Pipeline B is not cathodically protected (at least not fully) 
because its potential is well below —0.85 V to CSE with the line E rectifier OFF. With 



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216 Stray Current Corrosion 



the line E rectifier ON, the potential on line B is shifted severely in the less negative 
direction, indicating the probability of severe stray current corrosion damage to the 
foreign line. Corrective measures will be required to protect line B from stray current 
corrosion damage. 

From the location of line B, crossing only 1,500 ft from the line E rectifier and its 
route carrying into the vicinity of the line E ground bed, the interference can be expected 
to result from current pickup by line B where it passes through the area of influence 
surrounding the line E ground bed. Two verification tests can be made. First, if the 
potential of Line E is the same, or nearly so, with reference to a remote electrode as it 
is to the electrode directly over the point of crossing, coating damage on line E is not 
probable as was the case at the crossing with line A. Second, if the potential of line B to 
an electrode placed directly over it in areas where it approaches the ground bed swings 
in the negative direction when the rectifier is switched ON, current pickup by line B is 
indicated. 

Finally, where interference is found (as in this case) it is necessary to determine if 
the actual point of crossing is the point of maximum exposure. This is done by mov- 
ing the electrode a few feet at a time, five ft to start, first in one direction and then in 
the other away from the point of crossing and directly over line B to see if there is an 
area in which the positive delta voltage swing is greater than at the point of crossing. 
If such an area is found, the electrode may be moved by smaller distance increments 
within this area until the point of maximum exposure is found. Identify the location 
and record the ON, OFF and delta voltages at this point. Rarely will it be necessary 
to go more than 100 ft in either direction from the point of crossing. The maximum 
exposure point may be other than at the point of crossing if soil resistivity varies ap- 
preciably in the crossing area or if the coating (if any) on the foreign line varies in 
quality. 



Crossing C 



Line E, at the crossing with line C, is receiving inadequate protection, apparently because 
of interference from the CP system for Line C. If the potential of line E is measured to a 
CSE that is remote from both pipelines, and this potential is found to be representative 
of normal protective potentials (above —0.90 V in this case), the low potential at the 
crossing is a localized condition that is probably caused by the CP system on line C. 
Corrective measures will be required. The length of the line under test that is below 
—0.85 V can be determined by taking readings to an electrode placed directly above line 
E in each direction from the point of the crossing with line C. If the data, when plotted, 
give a curve similar to that in Figure 11.6, interference from the protection system on 
line C is confirmed. Pipeline C, in this case, is not affected adversely by the CP system 
for line E. There was no change in the line C potential with the line E rectifier ON 
and OFF. 



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Stray Current from Cathodic Protection Installations 



217 



SET UP FOR OVER-THE-LINE 
POTENTIAL SURVEY FOREIGN LINE 

■ SUBJECT TO 
INTERFERENCE 




LINE CURRENT 

MEASUREMENT 

(EAST SIDE) 



CURRENT 
INTERRUPTER 



PROTECTED 
PIPELINE 



s~ 



^ 




PLOT OF OVER-THE-LINE 
POTENTIAL SURVEY ON 
PARALLEL FOREIGN LINE 



CURRENT 

DISCHARGE 

AREA 



DISTANCE IN FEET 
Figure 1 1 .6 Testing noncrossing foreign pipelines for stray current interference 
from installations. 



Crossing D 



Pipeline E is protected adequately. Pipeline D does not have full protection but is not 
affected by the CP system on the line under test. No corrective action is required. 

Another possible situation involving interference can exist with a foreign pipeline that 
passes through the area of influence of a rectifier ground bed, but never actually crosses 
the protected pipeline. Testing for interference on such a line is illustrated by Figure 11.6. 
As shown in the figure, the foreign line can be tested by making an over-the-line potential 
profile in the ground bed area. This can be supplemented, if the profile indicates a current 



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Stray Current Corrosion 



Table 11.2 Survey Notes on Investigation of Interference from Ground Bed 



Electrode 
Location 






Over-the-Line Potentials— 
on Foreign Pipeline 


-Volts 






with Respect to 




Rectifier 


Rectifier 








Starting Point-Ft 




ON 




OFF 




ACSE (1) 




Remarks 







-0.48 




-0.52 




+0.04 




Exposure 


100 




-0.58 




-0.58 











200 




-0.64 




-0.63 




-0.01 






300 




-0.69 




-0.64 




-0.05 






400 




-1.01 




-0.69 




-0.32 






500 




-1.20 




-0.77 




-0.43 






600 




-1.37 




-0.81 




-0.56 




Opposite 


700 




-1.18 




-0.78 




-0.40 




Ground Bed 


800 




-0.99 




-0.71 




-0.28 






900 




-0.66 




-0.65 




-0.01 






1000 




-0.64 




-0.64 











1100 




-0.57 




-0.59 




+0.02 




Exposure 


1200 




-0.48 




-0.53 




+0.05 




Exposure 


(1) Values to be plotted 


Foreign Pipeline 
Line Current 


Potential Drop 
Rectifier ON 


Potential Drop 
Rectifier OFF 


Change in Cal 
Potential Drop Interfere 

AmV Flow Amp/mV 


zulated 
nee Current 


Measurement 


mV^ 


Flow 


mV^ 


Flow 


Amps Flow 


West Side 


0.62 


West 


0.08 


East 


0.70 


West 3.8 (2) 




2.66 West 


East Side 


0.53 


East 


0.02 


East 


0.51 


East 4.1 




2.09 East 



^ mV readings corrected for lead resistance. 

(2) Amp/mV factors for the specific voltage drop span. 



pickup area, by pipeline current measurements to determine the magnitude of current 
pickup. With an interrupter operating at the rectifier on the protected line, the data might 
appear as shown in Table 11.2. 

The first set of data in Table 11.2, with highly negative values of delta voltage oppo- 
site the ground bed, indicate definite current pickup. The positive delta voltage values 
indicate the beginning of a current discharge area. The portion of the foreign pipeline 
that is picking up current starts at the 100 ft point and continues to the 1,000 ft location 
for a total distance of 900 ft. 

The foreign pipeline current flow measurements (second set of data in Table 11.2) in- 
dicate definite stray current flow along the pipeline with the rectifier ON. The magnitude 
of the current flow indicated is high for this type of interference condition. Serious dam- 
age to the foreign line could be expected at an early date if the condition were allowed 
to exist without correction. 



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How to Reduce Stray Current Interference 21 9 



HOW TO REDUCE STRAY CURRENT INTERFERENCE 

Some of the methods used to reduce or eliminate stray current interference from CP in- 
stallations include bonds between the offending and affected pipelines, use of galvanic 
anodes at the point of crossing, use of coatings, and use of electrical shields. In some 
instances, the corrective measures required may be so complicated or expensive that 
relocating the offending rectifier installation may be the more economical solution. To 
illustrate how the various corrective procedures may be used, the examples of inter- 
ference described above in "Testing for Interference" will be used to demonstrate the 
specific corrective procedures. 



Drainage Bonds 

Table 11.1 shows that foreign pipeline B is subject to stray current damage from the 
impressed current CP system on pipeline E, see Figure 11.5. A commonly used method 
to correct this condition involves connecting a resistance bond between the two pipelines 
with the amount of resistance in the bond adjusted to drain just enough current from 
the affected line to eliminate the damaging condition. Normally, this is done during 
cooperative tests with the corrosion engineer representing the foreign pipeline owner 
unless the owner has given specific permission to make the bond installation without 
representation on his part. Permission should be in writing. 

The accurate determination of when the stray current interference effect has been 
eliminated is critical. To determine this, the bond is adjusted with the current interrupter 
operating at the rectifier on the pipeline causing the interference (as in Figure 11.5) 
and with a voltmeter set up to measure the potential of the foreign line to CSE at the 
point of crossing (or at the point of maximum exposure if other than at the actual point 
of crossing). The bond resistance is made such that the foreign line potential with the 
affecting rectifier ON is the same as was observed and recorded for it with the rectifier 
OFF prior to the installation of the bond. In other words, the foreign pipeline potential 
is restored to its original value. A typical foreign line test point with a bond in place is 
illustrated by Figure 11.7, together with the instrument connections for measuring the 
pipe-to-soil potentials on affected pipeline. 

Assuming that the point of crossing is also the point of maximum exposure in this in- 
stance (crossing B, Figure 11.5), the original readings for the foreign line are —0.32 V, ON, 
and —0.68 V, OFF. With the resistance bond adjusted properly, the foreign line potential 
with the rectifier ON should be -0.68 V. 

A method of adjusting bonds frequently used, calls for adjusting the bond resistance 
until there is no swing (delta voltage) on the foreign pipeline at the point of maximum 
exposure as the affecting rectifier is switched ON and OFF. This no potential shift pro- 
cedure has been shown over the years 1 to be ultra conservative in that more current is 
drained by the bond than is necessary to clear the interference. Although this does no 
harm to the foreign line, the cathodically protected line may be unnecessarily penalized. 



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Stray Current Corrosion 



BOND TYPICALLY 
AN ADJUSTABLE 
SLIDE RESISTER 
CONNECTED 
BETWEEN THE 
HEAVY LEAD 
TERMINALS FOR 
WIRES FROM 
FOREIGN AND 
PROTECTED 
LINES 



TYPICAL FOREIGN LINE CROSSING 
TEST POINT INSTALLATION. 
• TERMINAL BOX MAY BE BURIED, 
IF NECESSARY, RATHER THAN 
POST-MOUNTED 



HIGH RESISTANCE 
TEST VOLTMETER 



COPPER SULPHATE 
ELECTRODE DIRECTLY 
OVER FOREIGN LINE 
AT POINT OF MAXIMUM 
EXPOSURE 



(TYPICAL) 
NO 8 & NO 12 
BLACK INSU- 
LATED WIRES 
FROM FOREIGN 
LINE 



NO 8 & NO 12 WHITE 
INSULATED WIRES 
FROM PROTECTED 
LINE 




FOREIGN LINE 
BEING AFFECTED 
BY STRAY CURRENT 
INTERFERENCE 



PROTECTED PIPELINE WITH RECTIFIER 
■ (INTERRUPTED) CAUSING INTERFERENCE 
ON FOREIGN PIPELINE 



Figure 11.7 Bond at foreign pipeline crossing. 



Had the foreign pipeline in this example been cathodically protected such that full 
protective potentials were lost with the affecting rectifier ON, full return to the origi- 
nal potential might not be necessary. Assume that, when the crossing was tested, the 
readings were the following: -0.55 V, ON; -0.91V, OFF; +0.36 V, delta voltage. By ad- 
justing the bond with the rectifier ON until the foreign line reads —0.85 V at point of 
maximum exposure, corrosion would be prevented with no need to return the foreign 
pipeline potential to the full —0.91 V. The stray current drainage bond would require 



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How to Reduce Stray Current Interference 221 



bi-monthly inspections by qualified personnel to verify that it was in place and operat- 
ing properly. 

Situation Involving Poorly-Coated Line 

Table 11.1 shows that the crossing of pipeline E with foreign line C on Figure 11.5 involves 
interference conditions which may not be solved with a bond. Test data taken on this for- 
eign line suggest that the foreign line causing interference is bare or very poorly coated 
at the crossing. Assume, as suggested in proceeding discussion, that the potential of the 
line under test is measured to a remote CSE and found to be —0.93 V with its rectifier ON, 
even though a value far below this is measured to an electrode placed at the crossing as 
a result of the interference. With the rectifier on the foreign pipeline interrupted, the po- 
tential of the line under test to the electrode at the point of crossing could have, typically, 
values as follows: -0.68 V, ON; -0.91V, OFF; +0.23 V, delta voltage. The ON reading 
needs to be corrected to at least —0.85 V to eliminate interference, meaning that if a bond 
is used, it will have to drain current from the line under test. If, however, the potential of 
the foreign line is measured to the remote reference electrode and found to be, for exam- 
ple, only —0.83 V with its rectifier ON, it becomes apparent that a bond between the two 
lines will not drain current from the pipeline, as would be necessary to correct the inter- 
ference. A bond, under these conditions, would not correct the interference, but would 
impose needless additional burden on the CP system for the coated pipeline under test. 
Knowing that a relatively high current density that is flowing through the soil onto 
the bare foreign line results in a localized reduction in the protective potential on the line 
under test, one solution is to reduce the density of current flow to the foreign line in the 
crossing area. This may be done with coatings as illustrated by Figure 11.8. By applying 
a quality coating to the foreign pipeline causing the interference in the crossing area, 
current flow through the soil to the foreign line is reduced greatly. This means that the 
voltage drops in the earth (cathodic field) around the foreign line become negligible and 
no longer cause a severe local depression of protective potentials on the line under test. 
The length of foreign line to be coated can be based on the over-the-line potential profile 
on the line under test, as shown in Figure 11.9, which identifies the length of line subject 
to interference. Coated lengths of foreign line are equated with the interference profile 
length as shown in Figure 11.8. 

Use of Galvanic Anodes 

Another means of correcting the interference involves the use of galvanic anodes attached 
to the line under test through the area subject to interference from the foreign line as 
illustrated by Figure 11.10. Basically, this approach involves using the anodic potential 
gradient fields surrounding galvanic anodes to offset the cathodic potential gradient 
field surrounding the pipeline. For most applications of this type, a single line of anodes 
between the affected pipeline and the one causing the interference will be sufficient to 



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222 



Stray Current Corrosion 



DISTANCE A AND B ARE AREAS 

OF DEPRESSED POTENTIALS ON 

PIPELINE UNDER TEST PRIOR 

TO CORRECTIVE MEASURES 




FOREIGN LINE 
CAUSING INTER- 
FERENCE. 

LIMIT OF 
POTENTIAL 
DEPRESSION 
AREA 

PROTECTED 

PIPELINE 

UNDER 

TEST 



A' AND B\ EQUAL TO DISTANCES 

A AND B RESPECTIVELY, REPRESENT 

THE LENGTH OF FOREIGN LINE 

TO BE COATED. 



Figure 1 1 .8 Use of coating to correct interference at foreign pipeline crossing. 



o o 

I- DC 






D_ DC 

q_ UJ 

D_ 

CD O 

m ° 

DC ljj 

O CO 

^ o 



(-) 



(+) 



rm^T^W^^^rE^^ 



■r-r-r-nETC. 



S 



FOREIGN 
LINE 

AREA OF 
POSSIBLE DAMAGE 

k > 



PROTECTED -+ J 
BARE LINE 




POINT OF CROSSING 
WITH PROTECTED 
BARE LINE. 



DISTANCE IN FEET ALONG FOREIGN LINE 
Figure 11.9 Pipe-to-earth potentials on foreign pipeline 
passing through area of influence around cathodically pro- 
tected bare line. 



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How to Reduce Stray Current Interference 



223 



TEST POINT : 

ONE PIPE LEAD AND 

LEAD FROM ANODE 

BED JOINED BY LINK OR 

CURRENT MEASURING 

SHUNT OTHER LEADS 

FOR POTENTIAL TESTS 



PERMANENT 
REFERENCE 
ELECTRODE 
(CSE) 




COATED CATHODICALLY 
PROTECTED PIPELINE 
AFFECTED BY STRAY 
CURRENT INTERFERENCE 
FROM BARE PROTECTED 
LINE 



(AREA OF DEPRESSED 
POTENTIALS AS A 
RESULT OF INTERFERENCE 



12"± 




FIVE FOOT LONG MAGNESIUM 
OR ZINC ANODES, PACKAGED 
OR BACKFILLED WITH SPECIAL 
FILL 




X 



k k- 2' ETC. TO 5' MAX 

CATHODICALLY PROTECTED 
BARE OR VERY POORLY 
COATED LINE 



HEAVIEST ANODE AT 
POINT OF MAXIMUM 
EXPOSURE 



Figure 1 1 .1 Use of galvanic anodes to correct interference at foreign pipeline 
crossing. 



mitigate the harmful effects of the interference. There still will be current discharge but 
the discharge will be from the anodes rather than the previously affected pipeline. Where 
potential differences are very great as occurs occasionally with stray current from DC 
transit systems or mining substations, several strings of anodes may be required forming 
a cage around the affected line. In such a case, however, anode life may be short unless 
soil resistivity is high. 

As shown in the figure, the heaviest anodes would be used at the point of cross- 
ing where the exposure is most intense while lighter anodes may be used elsewhere. 
Magnesium anodes are used successfully because they have higher anodic potential 
gradient fields than do zinc anodes. The length of the anode string is determined by the 
length of the depressed potential area on the affected pipeline. A test point is desirable to 
permit measuring anode output periodically and to facilitate potential measurements. In 
addition to the normal surface potential measurements, a permanent reference electrode 
placed as shown in the figure will permit checking the underside of the affected line 
at the point of maximum exposure. A prepackaged, permanent, CSE placed below the 
pipeline makes an excellent installation. 

Information in proceeding chapters is applicable when working out the design for in- 
stallations of this type. Factors to be considered include soil resistivity, voltage difference 
between the lines, length of exposure area, and desired life. 



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224 



Stray Current Corrosion 



Use of Electrical Shield 



Where a pipeline passes through the area of influence surrounding a ground bed, it is 
possible to reduce the amount of stray current the line will pick up by using electrical 
shields. Situations where this may be a solution include examples such as represented by 
foreign line B in Figure 11.5 and that illustrated by Figure 11.6. The Figure 11.6 condition 
is used to illustrate the application of electrical shields as shown by Figure 11.11. 

The reason electrical shields of bare pipe may be useful is that they permit utilization 
of the cathodic potential gradient fields surrounding the bare pipe connected to the 
rectifier negative terminal. With the foreign line lying between the two shields as shown, 



FOREIGN LINE 
SUBJECT TO 
INTERFERENCE 



STRAY CURRENT 
PICKUP AREA 



\ 




i .... i 



1 o-A— o 



MV + 



LiHU 



GROUND BED 
AREA OF 
INFLUENCE 



PIPELINE CURRENT FLOW 
STILL AWAY FROM PICKUP 
AREA BUT REDUCED IN 
MAGNITUDE WITH SHIELDS 
CONNECTED IN CIRCUIT 
CURRENT FLOW CAN BE 
REVERSED (DESIRABLE) 
WITH GALVANIC ANODES 
OR BONDS AS SHOWN. 




ELECTRICAL SHIELDS- 
BARE PIPE PARALLEL 
TO AFFECTED LINE 
IN PICKUP AREA 

► 



\ o— o— o 



JJtl 



:H 



MV 



LM 



LINE CURRENT 
MEASUREMENT 



GALVANIC ANODES (EACH 
SIDE) TO REMOVE RESID- 
UAL STRAY CURRENT 
RESISTANCE BONDS BACK 
TO RECTIFIER NEGATIVE 
COULD BE USED ALSO. 

RECTIFIER AND 
GROUND BED 



-PROTECTED PIPELINE 



Figure 11.11 Use of electrical shields to reduce stray current interference. 



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How to Reduce Stray Current Interference 225 



it is completely within the gradient field. This cathodic field is in opposition to the 
positive ground bed field. The net result is a reduction in the amount of stray current 
picked up by the foreign line. The effect is quite similar to that which has been described 
for a coated and cathodically protected pipeline crossing a cathodically protected bare 
line, with local loss of protection on the coated line because of a reduction in current 
pickup from the soil caused by the cathodic potential gradient field. 

The shields shown in the figure will reduce the stray current pickup on the foreign 
line, but will seldom eliminate it. Interference current still can be expected to flow away 
from the pickup area to remote discharge points at which the pipe will be corroded. This 
current flow needs to be reversed. This may be done with galvanic anodes or bonds, as 
suggested on the figure, if the shields have reduced stray current pickup to a reasonably 
small magnitude. 

Using shields as described has many disadvantages. The bare pipe shields connected 
to the rectifier negative may consume a large portion of the rectifier current output and 
thus possibly reduce protection of the line to which the rectifier is connected. The bare 
pipe used as shields may be kept small (3/4-in diameter pipe should be satisfactory in 
most cases) to keep the current demands within reason. A shield installation as described 
can be expensive to install and expensive to maintain because, probably, a substantial 
percentage of the rectifier operating costs will be due to the shields. Because of these 
considerations, the pipeline corrosion engineer should consider other alternatives care- 
fully before using shields to be sure that it would not be less expensive, in the long run, 
to relocate the rectifier and ground bed. 



Notification Procedures 



An essential part of the pipeline corrosion engineer's job involves cooperating with 
owners of other pipelines or buried metallic structures. This is necessary in order that 
all parties may plan and operate their corrosion control systems with the least practical 
effect on structures belonging to others. Corrosion engineers should, when cathodically 
protecting a pipeline, notify all owners of underground structures crossing their pipeline 
that a CP system is planned. This should be done before the CP system installations 
are made. These foreign structure owners should be given the location, type, and size 
of protection installations to be installed in the vicinity of their crossing or crossings. 
They should be told when the system is to be energized and they should be invited to 
participate in cooperative tests at points of crossing. They may be promised copies of 
data taken at their crossings if they do not elect to send a representative for cooperative 
tests. They should be asked if they have additional crossings not known to the engineer 
issuing the notifications. For clarification, the written notice may be accompanied by a 
strip map of the pipeline (or pertinent portions thereof) marked to show the foreign line 
crossings of the company being notified and the proposed CP installations in the vicinity 
of those crossings. 

Some geographical areas, typically large urban areas, have organized corrosion coor- 
dinating committees that have established procedures for disseminating information to 



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226 



Stray Current Corrosion 



companies within their area. The corrosion coordinating committee will typically have 
specific notification procedures and possibly specific forms to be filled out and sub- 
mitted to impacted utility companies and the committee recording secretary In areas 
which are not served by corrosion coordinating committees, the pipeline corrosion engi- 
neer will have to determine the appropriate offices of foreign structure owners to which 
notifications will be sent. 



STRAY CURRENT FROM TRANSIT OR MINING SYSTEMS 

Stray current problems on pipelines arising from direct current transit systems and min- 
ing operations can be very severe. Solving such problems is more complicated than 
treating those discussed in the preceding sections. This is because of the continuously 
varying nature of the exposure as the load on the DC power sources varies. This type of 
problem is affecting an ever growing portion of the utility operators in North America 
because of the widespread construction of new DC powered rail transit systems in urban 
areas throughout the continent and the expansion of existing transit systems. The two 
types of DC powered rail transit systems that are becoming more common are heavy 
rail (the typical subway system) and light rail (the typical street railway). The terms 
heavy rail and light rail do not refer to the weight of the transit vehicles. The terms relate 
to the general operating characteristics of the rail vehicles. Typically heavy rail transit 
systems will operate with greater accelerations, higher speeds, longer trains, and higher 
current demands than will light rail transit systems. No such generalities may be made 
as to which type of system creates the highest overall levels of stray current activity. 
The amount of stray current generated by a specific transit system will depend upon the 
resistance-to-earth of the running rails and the level of voltage on the running rails. A 
simplified version of the problem is illustrated by Figure 11.12. 



TRACKS- 
NEGATIVE 

LOAD CURRENT REQUIRED OVERHEAD POSITIVE RETURN 

TO OPERATE TRAIN /- FEEDER 




D-C 
SUB- 
STATION 




mrwmwmwi&wnmwnm 



£3 




MOVING CURRENT 
PICKUP AREA 



c 



-^or 



CURRENT FLOWING AROUND 
HIGH RESISTANCE OR 
INSULATING JOINT 



DISCHARGE AREA SUBJECT 
TO CORROSION 



Figure 11.12 Stray current corrosion caused by DC transit systems. 



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Stray Current from Transit or Mining Systems 227 



DC light rail transit systems, as shown in Figure 11.12, are operated normally with 
the overhead insulated feeder connected to the positive bus of the DC traction power 
substation. The load current which is typically measured in thousands of amperes is 
supposed to return to the substation via the tracks (the running rails) which are connected 
to the negative bus at the substation. A common operating potential for transit systems 
is 750 volts. Because running rails are laid at ground level and are not fully insulated 
from earth, some part of the load current will enter the ground where the running rails 
are most positive (at the load) and take an earth path back to the substation. The current 
which flows through the ground is called stray current. Pipelines in the area constitute 
a good return path for a portion of the total stray current. Such a pipeline will carry 
the current to a location in the vicinity of the DC substation where it will flow from the 
pipeline to earth and return to the negative bus of the substation. Severe pipe corrosion 
will result if corrective measures are not used. Where the pipeline is picking up current 
near the train, it is receiving CP. In severe cases, the pipe may be many volts negative 
to adjacent earth in this area and, at the same time, many volts positive to earth in the 
exposure area near the DC substation. If there are high resistance joints in the pipeline, as 
shown in Figure 11.12, there may be enough driving voltage to force current to bypass the 
joint and corrode the pipe on the side where the current leaves the pipe. It is important to 
note that the location where the stray current returns to the negative return system is not 
always going to occur in the vicinity of the traction power substations. The stray current 
may return at any location on the transit system where the track-to-earth resistance is 
low. This means that any evaluation of stray current activity on a pipeline must first 
determine the locations of stray current discharge from the pipeline before any possible 
stray current control measures may be considered. 

As mentioned earlier, the illustration of the Figure 11.12 is a simple condition in- 
volving one load (train) and one substation. In actuality, operating systems will have a 
number of trains in operation at any one time depending on the traffic load. This means 
that the severity of exposure conditions is subject to constant variations that makes the 
evaluation of the stray current activity very complex. Ideally, if the transit system run- 
ning rails were perfectly isolated from earth, they would return all of the DC current to 
the substations and there would be no stray current to affect pipelines in the area. How 
closely any given transit system will approach this condition depends on several factors 
including the type of negative return system, the type of track construction, the level of 
track maintenance, and the overall dryness of the trackwork. 

Most new transit systems are designed with ungrounded negative return systems. 
The ungrounded negative return system is intended to electrically isolate the return sys- 
tem from earth and provides the highest level of stray current control. The ungrounded 
transit systems are also typically designed with multiple traction power substations that 
are intended to maintain running rail voltages at safe levels. This also helps to reduce 
stray current activity by keeping running rail voltages relatively low. 

Diode grounded transit systems may have electrically isolated running rails for stray 
current control, but the negative return system is deliberately grounded through diodes 
at the traction power substations. This allows a relatively high level of stray current 
activity. Some transit systems will use diode grounding for running rail voltage control. 



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228 Stray Current Corrosion 



The running rails and substations are normally isolated from earth. Sensing circuits 
monitor the running rail voltages and when preset limits (unsafe voltages) are reached, 
switches close that temporarily ground the negative return system though diodes. The 
period of time when the return system is grounded will produce relatively high overall 
stray current levels. 

Grounded transit systems operate with the negative return system permanently con- 
nected to earth at the substations. No special measures are typically implemented to 
electrically isolate the running rails from earth. High stray current activity is caused by 
these grounded transit systems. Typically, it is only the very old, existing transit systems 
that are operated with their negative return system deliberately connected to ground. 
Old, existing transit systems also have an additional problem that new transit systems do 
not have. New transit systems are constructed with welded running rails and insulating 
rail joints are installed only at specific locations, such as at crossovers, where they are 
required for automatic train control operations. These insulating rail joints are bonded 
across with impedance bonds that allow the return of DC current through them while 
blocking the AC current of the train control system. Old, existing transit systems were not 
constructed with welded running rails. Therefore, each rail joint has bond cables welded 
across it to assure proper return of the negative current. If these rail bonds are broken, as 
may occur during normal rail operations, then the return current cannot flow through the 
bond cables and all of the return current passes through earth. Extremely high stray cur- 
rent activity will occur under these circumstances. Old, existing transit systems should 
have a program in place to periodically inspect and repair these critical rail bonds. 

Underground mining operations that are DC powered have negative return systems 
that operate in much the same manner as has been described for transit systems. Because 
most of these systems are underground, pipelines will seldom be as close to the running 
rails as is the case with surface transit systems. Stray current effects on pipelines can still 
be severe in some situations. DC substations may be located underground rather than at 
the surface. This can result in problems in applying corrective measures as will be seen 
in later sections of this chapter. 



Testing for Exposure Areas 



Suitable time based recording instruments are critical when locating exposure areas. 
The instruments may include paper strip chart recorders or electronic data loggers. Both 
types of equipment have advantages and disadvantages for field evaluations. The most 
appropriate type of equipment for your particular application should be determined. 
Locations where tests may be made are selected from a knowledge of all pipeline routes in 
the area as well as those of the transit or mining system. The location of all DC substations 
and their operating schedules must be known. Testing should always be performed in the 
vicinity of DC traction power substations as these are likely locations for the pipeline to 
be in exposure, especially if the substation is grounded. Testing should never be limited 
solely to the vicinity of traction power substations as the pipeline may be in exposure in 
other locations due to low track-to-earth resistance values on the transit system. 



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Stray Current from Transit or Mining Systems 



229 



Exposure can be experienced on pipelines which do not come close to a DC substation. 
If, for example, a pipeline crosses a DC traction system, stray current may be picked up 
at the point of crossing as trains pass. This stray current may flow in both directions from 
the crossing and discharge at remote locations. If a pipeline parallels a transit line for a 
distance, but does not approach a DC substation closely, current will be picked up by the 
pipeline as trains pass the parallel section. This current will be discharged from the ends 
of the parallel section. In finding its way back to the DC substation, stray current may 
jump from pipeline to pipeline at crossings in order to follow the most direct or lowest 
resistance path. Therefore, a pipeline that is not in close proximity to a transit system may 
cross a pipeline that is. The pipeline that is close in proximity to the transit system may 
carry the stray currents to the pipeline that is not in close proximity. Corrosion damage 
at these pipeline crossings that are remote from a transit system can be severe. Tests for 
exposure should be made at such possible points of current interchange. This emphasizes 
the need to know the routes of all foreign lines in an area where conducting tests. 

Recording voltmeters are used to measure and record pipe-to-earth potentials at 
locations selected for test. The potential will be measured to adjacent earth in most 
instances. Changes in the pipe-to-earth potentials are greater per unit of current discharge 
on coated lines than on bare lines. Where the pipeline potential becomes more positive 
during periods of stray current activity, current discharge is indicated. Experience with 
this type of testing is most helpful in planning the recording instrument test program 
and when interpreting the data taken. 

Figure 11.13 is a representation of the results that may be obtained at a stray current 
discharge area on a pipeline adjacent to a transit system. The chart shows that the pipeline 
is affected by stray current activity when the transit system is in operation, but that the 
pipeline only goes into exposure during the morning and afternoon rush hour periods. 




MIDNIGHT 



6 AM 



6 PM 



MIDNIGHT 



TIME-HOURS 

NOON 

Figure 11.13 Pipe-to-earth potential at traction system stray current discharge 



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230 Stray Current Corrosion 



It becomes apparent from a study of the chart that observation of an indicating meter 
for any reasonable period of time is not apt to give a true picture of the full range 
of potential variations. The evaluation of the stray current activity indicated on the 
chart in Figure 11.13 must focus on the time periods when the pipeline is in exposure. 
The duration of the individual exposures must be determined as well as the expected 
impact on the pipeline itself. If the pipeline goes into exposure for only very limited 
time periods, then the pipeline may not be experiencing corrosion damage and no stray 
current mitigation measures may be necessary. 

Recording millivolt meters may be used to measure pipeline current on calibrated 
pipe spans. Where sufficient test spans exist or can be installed, two or more such record- 
ing millivolt meters may be used to record the current flow at adjacent test points in 
areas where exposure is suspected. By comparing the charts taken at any two adjacent 
test points, current loss in the section may be detected. Current loss between test points 
may be determined with indicating millivolt meters also. This necessitates having an 
observer at each test point. A series of simultaneous readings are made and compared 
to ascertain whether or not current loss is occurring. Although a synchronized timing 
schedule, typically using computer data loggers, may be used to obtain simultaneous 
readings, direct communication (as by cellular phone) is more reliable and should be 
used to verify that the test equipment is actually synchronized. 

When working with bare pipe, carefully conducted current loss surveys will indicate 
the point of maximum voltage exposure (by showing where current loss is greatest) 
unless there is wide variation in soil resistivity. On coated lines, however, the point of 
maximum current discharge can be some distance from the point of maximum voltage 
exposure. This can happen when the coating at the point of maximum exposure, for 
example, is in substantially better condition than at other locations in the area. 

Once the general location of the point of maximum exposure has been determined, 
it may be pinpointed more precisely by the use of X/Y plotters or two indicating volt- 
meters (two identical voltmeters are required to assure consistency of data). This is done 
by correlating the pipe-to-earth potential at the test point with the potential between 
the pipeline and the transit system negative return. Correlations are made at a series 
of locations through the exposure area. At each location, a number of simultaneous 
readings are taken at various degrees of intensity of the stray current effect. Carefully 
recorded data, when plotted, will fall along a generally straight line. The slope of the 
line is a measure of exposure: the greater the slope, the greater the exposure. The calcu- 
lated slope at each test point may be referred to as the Beta for that point. The diagram 
obtained by plotting the slope, or Beta, against the test point locations may be referred 
to as a Beta Profile or an Exposure Profile. The general procedure is summarized by 
Figure 11.14. 

Because of the possibly very marked and quick stray current variations, it is essential 
that indicating instruments of identical characteristics be used in obtaining simultaneous 
readings. Rapid response is necessary. If characteristics are not identical, particularly with 
regard to response speed, good correlation of simultaneous readings cannot be obtained. 
It is obvious that a lot of work is involved in taking and plotting data and obtaining 
slopes at each test point to produce an exposure profile. X/Y plotters are available which 
will record both values simultaneously and show the line of slope. Where much of this 



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Corrective Measures 



231 



D-C 
SUB- 
STATION 



OVERHEAD FEEDER 



SAME INSTRUMENT 
SET UP FOR EACH 
TEST POINT 




E, -VOLTS 



TYPICAL PLOT OF 
SIMULTANEOUS 
READINGS AT A 
TEST LOCATION 



TEST POINTS 

TYPICAL PLOT OF SLOPES THROUGH 

SUSPECTED EXPOSURE AREA 



Figure 11.14 Locating point of maximum stray current exposure. 

type of work is to be done, such instruments will save a great deal of time. High input 
impedance and rapid response are essential characteristics to be looked for in selecting 
such a recorder. 



CORRECTIVE MEASURES 
Transit System Action 



One approach to stray current mitigation involves the elimination of excessive stray 
current activity at its source. This involves the assistance of the transit system operator 



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232 Stray Current Corrosion 



and is often only feasible with the newer, nongrounded transit systems. Most transit 
systems have a corrosion engineer on staff or a corrosion engineering consultant available 
to deal with these types of stray current interference problems. The utility operator 
should request a meeting with the transit system corrosion engineer to review the field 
data and discuss what action is available to the transit system. Typically, the transit 
system engineer will perform track-to-earth resistance and track-to-earth voltage testing 
in the vicinity of the pipeline to determine if a problem exists on the transit system. If a 
problem is found to exist, the transit system will usually make the necessary repairs and 
the excessive stray current activity may be eliminated. The typical repairs will include 
cleaning of wet and dirty trackwork, replacement of damaged track fasteners, removal of 
inadvertent contacts between the negative return system and ground, and /or correction 
of improper positive system operation. Retesting of the pipeline, after the repair of the 
transit system, will have to be performed to verify that the excessive stray current activity 
has been mitigated and that any remaining stray current activity is at tolerable levels. 



Pipeline Modifications 



Another approach to stray current mitigation involves making modifications to the 
pipeline to reduce its susceptibility to stray currents and to provide a safe means of 
stray current discharge. The modification of the pipeline to reduce stray current activity 
maintains all control for the stray current measures directly in the hands of the pipeline 
operator. 

The first consideration for pipeline modification involves the installation of insulating 
joints. The proper placement of insulating joints in a pipeline can dramatically reduce 
the overall stray current activity on the pipeline by making the pipeline less susceptible 
to stray current pickup and discharge. By installing insulators, the pipeline operator is 
increasing the overall resistance of the pipe to earth, thereby reducing its tendency to 
pick up stray currents. This approach may require modifications to the CP system for the 
pipeline to assure that full protection is maintained on the pipeline after the insulating 
joints are installed. 

Another possible pipeline modification involves the installation of magnesium an- 
odes on the pipeline at the locations where the pipeline is going into stray current dis- 
charge. The magnesium anodes can provide a low resistance discharge point for the 
stray currents so that no stray current actually discharges directly from the pipeline. The 
stray current activity must be carefully re-evaluated after the magnesium anodes are 
installed to verify that the stray current is discharging fully from the anodes. If magne- 
sium anodes are installed where the pipeline both picks up and discharges stray current, 
then the installation of diodes with the magnesium anodes may be necessary to assure 
that the anodes discharge stray current, but do not collect stray current. The installation 
of magnesium anodes may be required at insulating joints where stray current may be 
discharging around the joints. 

Another possible pipeline modification involves the installation of a potentially con- 
trolled rectifier and impressed current ground bed where the pipeline is going into stray 



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Corrective Measures 



233 





PIPELINE 
{EA \ 




3.C. RAILROAD 

IS EXPOSURE AF 

1 




EXPOSURE AF 




(EA 


/ . 






\ 




/ . 








\ 


^i 1 — 




\ 1 . 


^>H 






\ 


v y t^ 






X f^ 


X 


REFERENCE 






POINT OF 
MAXIMUM 




REFERENCE 








ELECTRODE _ 




ELECTRODE 














POINT OF 


A.C. 
SUPPLY 




■ A.C. 
SUPPLY 


MAXIMUM 




EXPOSURE 

\ 

POTENTIAL 
CONTROLLED 
AUTOMATIC 
RECTIFIER 

GROUND 
BED 




EXPOSURE 




+ 


) 








+ 

) 
) 
) 


POTENTIAL 








CONTROLLED 
AUTOMATIC 






RECTIFIER 






GROUND 
BED 






( 


5 


( 




c 




c 





Figure 1 1 .1 5 Use of potential controlled automatic rectifiers for stray current control. 



current discharge. The output of the rectifier would automatically adjust itself to supply 
additional CP current to the pipeline when stray current was being discharged. This 
would maintain acceptable CP levels on the pipeline at all times. This approach is only 
effective and feasible if the pipeline has a very limited number of areas where the stray 
current is discharging from the pipeline. Figure 11.15 shows a potentially controlled 
rectifier installation. 

The pipeline should be evaluated to determine if its CP system is operating prop- 
erly. It is possible that the existing CP system would be sufficient to overcome the stray 
current activity if it were operating properly. The repair of defective rectifiers, damaged 
external coatings, defective insulating joints and the removal of any inadvertent con- 
tacts to grounded structures may sometimes greatly reduce stray current effects and 
eliminate possible stray current damage. Always make sure that everything on the 
pipeline is operating as intended and that the CP system is functional before perform- 
ing any evaluations to determine what additional stray current mitigation measures are 
required. 



Stray Current Drainage Bonds 



The measure of last resort that may be implemented for stray current mitigation is the 
installation of a drainage bond between the pipeline and the transit system negative 
return system. Figure 11.16 shows a drainage bond installation. The installation of a 



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234 



Stray Current Corrosion 



RUNNING RAILS 
NEGATIVE RETURN 



LOAD CURRENT REQUIRED 
TO OPERATE TRAIN 



OVERHEAD POSITIVE 
FEEDER 



D-C 
SUB- 
STATION 




MOVING CURRENT 
PICKUP AREA 



• BOND ACROSS HIGH 
RESISTANCE JOINTS 



POINT OF MAXIMUM 
EXPOSURE 



Figure 11.16 Bond between pipeline and DC substation. 



drainage bond should only be considered if all other stray current control (on the transit 
system) and stray current mitigation measures (on the pipeline) prove ineffective. The 
installation of a stray current drainage bond requires a direct connection between the 
pipeline and the negative return of the transit system. The connection to the negative 
return is made at a traction power substation if at all possible to avoid interfering with 
any automatic train control equipment on the running rails. The installation of a drainage 
bond should safely drain the stray current from the pipeline. However, it will also result 
in a decrease in the transit system's overall negative return resistance-to-earth. This will 
result in a significant increase in total stray current activity associated with the transit 
system and will probably result in excessive stray current interference on pipelines that 
were previously being subjected to only minor stray current effects. This is likely to lead 
to the need for additional stray current drainage bonds and the distribution of the stray 
current over an ever increasing larger area with an increase in the number of utilities 
being adversely impacted by the stray current activity. 

The bond must have adequate conductivity to remove all stray current and clear the 
exposure condition. In designing a bond, it should have, ideally, just enough conductivity 
to clear the exposure. If the conductivity is higher than necessary, more current will be 
drained. This may not be harmful to the pipeline to which the bond is connected but 
will cause it to become more highly negative to earth than necessary. This may in turn 
increase the likelihood of exposure at crossings with other pipelines. If the pipeline being 
bonded to the substation is coated, potentials should not be allowed to become more 
negative to earth than necessary so that, insofar as possible, coating damage may be 
avoided. 

Although a bond resistance value may be obtained by installing a temporary cable 
and determining the degree of clearance per ampere drained, the resistance may be 
calculated using the following expression: 



Bond resistance in ohms = (Rp-G /Slope) — Rp- 



a) 



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Corrective Measures 235 



where: 

Rp-g is the resistance in ohms between pipeline and ground at point of 
maximum exposure. 

Slope is the slope (expressed as a decimal) previously determined at 
the point of maximum exposure. 

Rp-n is the resistance in ohms between pipeline and substation 
negative bus. 

Resistance values are determined by the ammeter-voltmeter method using an inter- 
rupted source of DC current connected between the pipeline and substation negative 
bus. The DC current source used must be of sufficient capacity to override the potential 
swings caused by the stray current activity. The average of a number of readings will be 
required to obtain reliable data. Taking such readings at a time when the load on the sub- 
station is at a minimum will facilitate good data. Once the bond cable size is determined, 
a trial installation is recommended to determine the impacts on other adjacent utilities 
from the installation of a bond. This will allow testing to be performed to determine if 
other utilities will require a bond to the pipeline or to the transit system. This testing 
may determine that a different size bond cable than that originally calculated will be 
required. The bond cable that is installed must have sufficient current carrying capacity 
to handle the maximum current drained without burning out. 

A simple bond to a DC substation as discussed is ample where that substation is 
the only one supplying current to the traction or mining system. If, however, there are 
several substations on the system and the one to which the bond is connected is lightly 
loaded or out of use during part of each 24 hour period, having the bond permanently 
connected becomes a disadvantage. This is because the direction of current flow in the 
bond can reverse and feed stray current to the pipeline. This reverse current flow will 
increase exposure conditions at other points on the pipeline. 

To prevent this reverse current flow, various types of reverse current switches may 
be used in the bond cable installed between pipeline and negative bus. These may take 
the form of relay-actuated switches which open automatically when the current tends 
to reverse. Diodes may also be used to block any reverse current flows. A stray current 
drainage bond should always have some kind of device to block the flow of reverse 
current. In the event of a change in the transit system operations, the bond should 
not be allowed to carry current directly to the pipeline. If this happens, stray current 
will be discharged from the pipeline at a location remote from the drainage bond. This 
could result in serious corrosion damage on the pipeline. When reverse current blocking 
devices of either type are used, allowances must be made in the bond resistance design 
for any voltage drop (effective resistance) interposed by the blocking device. 

The installation of bond cables between a pipeline and a DC substation is seldom 
easy, particularly in urban locations where a practical route for heavy drainage cable 
must be selected. A special problem is associated with underground substations on 
mining systems. If a bond is unavoidable, it may be necessary to drill a bore hole from 
the surface to the mine gallery where the substation is located. This requires careful 
selection of the hole location in cooperation with the mine surveyor, and the drilling of 



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236 Stray Current Corrosion 



a straight hole. Before undertaking such action, however, it is wise to find out how long 
the underground substation will remain in its present location. This is because mining 
substations are apt to be moved as mining progresses. If it is found that the substation 
is to be moved in the near future, the bore hole installation would not be economical. 

Underground Corrosion Coordinating Committees 

As was discussed under Notification Procedures in the section covering stray current 
from CP installations, the pipeline corrosion engineer should utilize the services of the 
underground corrosion coordinating committees. By attending committee meetings reg- 
ularly, the engineer will have advance information pertaining to any changes in stray 
current sources or corrective action by others which may have an effect on the engineer's 
own system. 

Stray Current from Magnetic Disturbances 

Occasionally, varying pipe-to-soil potentials and /or pipeline currents will be encoun- 
tered in areas where there is no known source of man-made stray direct current. These 
pipe-to-soil variations usually are associated with disturbances in the earth's magnetic 
field. Such disturbances have been found most active during periods of severe sun spot 
activity. Stray current from this source is termed telluric. The reason for the effect on 
pipelines may be associated with the buildup and collapse of the earth's magnetic field 
in the area of the pipeline. In an electric generator, voltage is produced by passing an 
insulated conductor through a magnetic field in such a manner that the conductor cuts 
the magnetic lines of force. Likewise, a voltage is generated on a pipeline due to the 
variations in the earth's magnetic field along the pipeline route. 

Telluric effects may be identified with recording instruments. A 24-hour record of 
pipeline current or pipe-to-soil potential, if the effect is telluric, will not show any iden- 
tifiable pattern as is the case when the stray current is of man-made origin. Fortunately, 
although occasionally intense, telluric current effects on pipelines are seldom of long 
duration and may not even be localized at specific pickup or discharge areas for any 
length of time. For this reason, corrective measures are not often required. Should areas 
be found, however, where the condition occurs frequently enough and is of serious inten- 
sity, corrective measures discussed earlier in the chapter may be adapted to counteract 
the telluric effect. 



REFERENCES 



R. L. Seifert, Practical Interference Current Testing on Underground Metallic Structures, Materials 
Protection and Performance, Vol. 11, 41 October 1972. 

M. J. Szeliga, ed., Stray Current Corrosion: The Past, Present and Future of Rail Transit Systems, 
NACE International, Houston, TX, 1994. 



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Chapter 



j 



Construction Practices 



Ronald L. Bianchetti 



Areas covered in this section that apply to the overall corrosion control program include 
pipeline coatings, test points, cased crossings, insulated joints, galvanic and impressed 
current cathodic protection (CP) installations, and inspection requirements. 



PIPELINE COATINGS 



Pipeline coatings were detailed in Chapter 2. Although precautions to be observed were 
discussed in that chapter, additional points applicable specifically to construction are 
described below. 



Handling Mill Coated Pipe 



If mill coated pipe is used, start at the mill to verify that all coating steps are strictly 
in accordance with the specifications established. This includes surface preparation, 
priming, application of specified coating materials, holiday tests and holiday repairs, 
and yard racking of the coated pipe. Check also to see that the pipe is handled carefully 
during loading out for truck or rail delivery so that coating damage will be at a minimum. 
Also see that coated pipe lengths are padded adequately and secured solidly on rail cars 
or trucks so that damage cannot develop under normal shipping conditions. Shipping 
requirements should be covered by careful specifications designed to accomplish the 
desired result. 

If shipping is by rail, the coated pipe either will be transferred from the rail cars 
directly to trucks or will be placed first in field storage and then loaded onto the trucks. 
Again make sure that the coated pipe is handled and protected with care and arrange 
for specifications that will cover every phase of this work. 

When trucks arrive at the job site, facilities must be available for placing the coated 
pipe on the ground — not dumping it directly from the truck. Coated pipe should not be 

237 



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238 Construction Practices 



placed directly on the ground unless the ground is free of material that could damage 
the coating. Preferably it should be placed with skids or supports under the bare pipe 
ends where the coating has been cut back; this is seldom possible, however, because 
of pipe length variation. The best alternative is the use of supports padded properly 
to prevent damage to the coating. Check with the coating manufacturer for padding 
recommendations as well as the number of layers permissible in the pipe pile. 

Lengths of mill coated pipe should be handled with belt slings or end hooks. Chains 
or cables around the coated pipe must not be permitted. Belt slings must be wide enough 
so that they will bear the full pipe weight without distorting the coating. End hooks (one 
to engage each end of the pipe using a cable sling and spreader) must be designed so 
that the pipe ends will not be distorted by their use. If a length of coated pipe is handled 
with a single belt sling, its swing should be restricted with ropes or other suitable means 
to prevent accidental swinging into equipment with attendant coating damage. 

When coated pipe is taken from the ground after stringing for lining up and welding 
into the pipeline, it usually will be laid up on skids under coated portions to free the 
ends for welding. Suitable padding must be used between the coating and timber skids 
to avoid damage. 



Pipe Coating over the Ditch 



In addition to making sure that the coated pipe is handled as carefully as described for 
mill coated pipe, the corrosion engineer must verify that the coating application is in 
strict accordance with tight specifications as was discussed in Chapter 2. 

This applies to every phase of pipe cleaning, priming and application of coating 
materials such as cold applied tapes, wax coatings, heat-shrink sleeves, and wraps. Be 
sure materials are handled carefully in the field. They must be kept free of dirt and other 
foreign matter. Wrapping material must be kept dry. 

The manufacturer of coating materials should have a technical advisor on a pipeline 
project. If problems develop under unusual application conditions, the advisor should 
be consulted at once. Advisors are interested in how their material performs and will be 
able to recommend application or material modifications to meet the special situation 
encountered. 



Holiday Detection and Repair 



Refer to Chapter 2 for further information on the use of holiday detectors. This is an im- 
portant part of the over-all coating procedure. The corrosion engineer should be assured 
that detector operators are trained properly in the use of the equipment and that they 
are using appropriate procedures to verify adequate detector performance at all times. 
Because the holiday detector test usually is the last opportunity to verify coating 
integrity before it is backfilled, this test must be thorough with all holidays well marked 
for repair. If the coated pipe is laid up on skids prior to lowering into the ditch, be sure 
that the pipe is checked after lifting from each skid. 



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Test Point Installations 239 



The holiday repair crew is as important as the holiday detection crew. Those making 
such repairs must be trained to repair coating defects properly and apply the repair 
materials in such fashion that the repaired holiday will be as strong, electrically and 
mechanically, as the original coating. Preparation includes removing broken and dis- 
bonded material and, for best performance when working with enamel or other thick 
coatings, feathering the edges of the break with a draw knife or equivalent tool. This 
assures a better bond between the repair materials and the original coating. If there is an 
outer wrap, it must be removed from around the break to obtain good bonding of repair 
materials at the overlap. The repair materials themselves must be handled carefully and 
in accordance with good coating practice. 



Good Practices Save Money 



Good coating construction practices produce results. Insistence on good coating pro- 
cedures from the beginning of construction should be the function of the responsible 
corrosion engineer. 



TEST POINT INSTALLATIONS 



Test points are the best means of electrically examining a buried pipeline to determine 
whether or not it is cathodically protected as well as making other tests associated with 
corrosion control work. Types of test points needed have been mentioned in preceding 
chapters. To serve their purpose over the years, these test points must be convenient to 
use and must be so constructed to minimize future damage to the test station. 



Types of Test Points 



Test point types by function are illustrated in Figure 12.1. The types shown are not neces- 
sarily representative of any particular standard but are intended to represent the variety 
that may be encountered. A color code is shown to illustrate a system whereby leads 
may be identified. Whatever color code is adopted should be made standard throughout 
your pipeline system. 

The two-wire potential test point is the one used most frequently. Two wires make it 
possible to check pipe-to-earth potential with one while test current is being applied to 
the line (if desired) using the other. 

The four-wire insulated joint test point permits measuring pipe-to-earth potentials 
on each side of an insulated joint. The second pair of heavier gauge wires are available 
for inserting a resistance or solid bond across the insulated joint if necessary. 

The four-wire calibrated line current test point permits accurate measurement of 
pipeline current flow as discussed in Chapter 5. 

The six-wire combination insulated joint and line current test point is useful, particu- 
larly at terminal insulated flanges, because it permits positive measurement of current 



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Construction Practices 




WHITE 




INNER WIRES HEAVIER 
GAUGE THAN 
OUTER WIRES 



rP^ 



YELLOW ? 
BLACK -f> 



il&>&/&>£'/W$'W>£V& / 4->Z&g r K7W 



BLUE OR 
GREEN 



CR 



HlK 3'-H h 



— WHITE 



FLOW- 



TO 



MEASURED SPAN 



K-3' 



POTENTIAL 
TEST POINT 



INSULATED JOINT 
TEST POINT 



4-WIRE CALIBRATED 
LINE CURRENT TEST POINT 



YELLOW 

BLACK 

WHITE 



WIRES CLOSEST 
TO JOINT TO BE 
HEAVIER GAUGE 




-H MEASURED SPAN K NJJ 



COMBINATION INSULATED JOINT 
AND LINE CURRENT TEST POINT 



WHITE 7 



MOMENTARY 
, CONTACT 
SWITCH 

* RED 



_s 



A PACKAGED COPPER COPPER 
C~^ SULFATE (CSE) REFERENCE 
ELECTRODE 

INDICATING VOLTMETER 
TEST POINT 



BLACK 
HEAVIER WIRE 




BLACK 



^ 



.^1— SHUNT 



WHITE 



rm&Tmgwg 



A 



■RED 



WMWl8 f &J&S 




ANODES 



V\ 



FOREIGN LINE CROSSING 
TEST POINT 

Figure 1 2.1 Typical types of test station. 



GALVANIC ANODE 
TEST POINT 



flow through an insulated flange should the flange become totally or partially shorted 
for any reason. Likewise, it will measure the current flowing through a solid or resistance 
bond should such measurement be necessary. One heavier gauge wire is provided on 
each side of the insulated joint for bonding purposes (if required). 

An indicating voltmeter test point is installed at key points on some systems. These 
meters may be read by operating personnel on a routine basis and the indicated values 
recorded and reported to the corrosion engineer. As shown in Figure 12.1, a voltmeter 
may be connected between the pipe and a reference electrode suitable for underground 
service. 



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241 



The foreign line crossing test point provides two wires to each line. One wire is 
used for potential measurements or other tests as required while the other (the heavier 
gauge wire) is available for installing a bond when needed. It should be noted that 
test wires should never be attached to another company's pipeline unless the pipeline 
owner authorizes it. Further, many companies will allow such attachments only if made 
by their own personnel or if their own representatives are present while the attachments 
are being made. 

The galvanic anode test point is typically used primarily in connection with anodes 
at one location. Such a test point is shown in greater detail in Chapter 9 (Figure 9.9). 



Test Point Construction 



Test points should be located where they will be as convenient as practical for the corro- 
sion engineer. While some type of post mounting is preferable, in some areas test points 
may have to be in grade level boxes or even buried. 

Typical methods of mounting above-ground test points are illustrated by Figure 12.2. 
Terminal boxes used should be of heavy cast metal construction to resist gunfire — 
test points in rural areas become convenient targets. Many terminal boxes and match- 
ing terminal blocks are available commercially. Terminal blocks obtained to fit the 
box selected should have heavy studs (at least 0.25 in) of solid brass (may be nickel or 




TERMINAL BOX 
(COVER REMOVED) 



REDUCING 
FITTINGS IF 
NECESSARY 

2" GALVANIZED 
STEEL CONDUIT 



4"x4"x6" TREATED 
WOOD POST 



r\ 



18x18x6 
CONCRETE 
SLAB CAST 
AROUND PIPE 
AT GRADE 
LEVEL 




TERMINAL BOX 



SELF-SUPPORTED 
CONSTRUCTION 




TACK WELD 
STRAP TO 
VENT OR 
TACK WELD 
CONDUIT TO 
VENT 

3/4" OR 

LARGER 

GALVANIZED 

STEEL 

CONDUIT 



CONDUIT 
BUSHING 



VENT PIPE 



POST-SUPPORTED 
CONSTRUCTION 



VENT-PIPE-SUPPORTED 
CONSTRUCTION 



Figure 1 2.2 Typical types of above grade test stations. 



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Construction Practices 



REMOVABLE COVER 




-2 • <3 ■ 



TERMINAL — 
BLOCK 

LEAD 

BLOCK 

HOUSING - 



STREET PAVING 
■ OR 18"x18"x6" 
CONCRETE BLOCK 



TO PIPELINE 



Figure 1 2.3 Typical at-grade types of test stations. 



cadmium plated), with hex nuts and washers. If a rigid steel conduit is used it should be 
reamed carefully after cutting to length to remove all sharp edges and a conduit bushing 
should be installed at the lower end as shown. Each wire terminated in the box should 
have at least 12 in of slack coiled as shown. The last two requirements are necessary to 
prevent the insulation from being cut through or having them pulled off the terminals in 
case the wires are subjected to tension by backfill settlement. Where a test point conduit 
is tack welded to vent pipes or other steel structure, all welding should be done before 
wires are pulled in so that there will be no heat damage to insulation. 

Test points installed at grade level may use an arrangement such as that illustrated 
by Figure 12.3. In its simplest form, the grade-level test point uses a common street valve 
box with a cover that has test wires coiled and left in the box with their ends taped to 
avoid contacts. Terminal boards may be made to fit such boxes. Test point boxes are 
available, however, which are manufactured specifically for this purpose and include 
covers identifying them as such. Some designs are completely watertight. 

When installing grade level test points, ample wire slack (typically 18 in) should 
be left in the housing below the terminal panel to allow for backfill settlement and for 
withdrawing the terminal panel should it be necessary during test work. Each grade level 
terminal box should be located precisely with respect to permanent reference points and 
entered on pipeline maps or other permanent records. This is necessary to avoid time 
loss in searching for the boxes when they are covered with grass, weeds, dirt or snow, 
or pavement renewals. 

Buried test points may be installed as shown in Figure 12.4. A water tight box as 
illustrated is preferred. A protective plank should be placed directly above the box 
and wires as seen in the figure to prevent damage to the wires when excavating the 
box for test. 



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Test Point Installations 



243 



WATER TIGHT 
STUFFING BOX 



TEST WIRES WITH 
SUFFICIENT SLACK 
TO PERMIT BRINGING 
TEST BOX TO SURFACE 
FOR TESTS 



> BELOW FLOW DEPTH 

TREATED WOOD PLANK 
ABOVE BOX AND WIRES 



WATER TIGHT BOX WITH 
TERMINAL BOARD 




PIPELINE 



Figure 1 2.4 Typical buried type of test stations. 



Because of the time required for excavating buried test points, they should be used 
only when there is no alternative. Where possible, it may be preferable to extend leads 
several hundred feet to a point where an above-ground test point can be installed. This 
test site must be located precisely with respect to permanent landmarks and the location 
information recorded where it will be available when tests are made. 



Test Wires and Pipeline Connections 

Test wires for potential measurements are sized for mechanical strength rather than elec- 
trical requirements. As a guide, No. 12 American Wire Gauge (AWG) single conductor 
stranded wire with 600 V insulation suitable for this service under normal conditions 
should be used. Such wire may be procured in the various colors needed for test point 
color coding. For heavier gauge wire shown in some of the sketches in Figure 12.1, No. 6 
or No. 4 AWG wire is satisfactory unless the test points are in severe transit or areas of 
stray current where the wires may carry very large currents. Wire sizing in these cases 
will depend on experience in similar situations. 

If it should be necessary to splice test wires during installation, twisted or bolted 
splices should not be permitted because they may develop high resistance in time. 
A soldered splice is preferable, using a good grade of 60-40 lead-tin solder with a 



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Construction Practices 



GRAPHITE MOLD. 
SEE MANUFACTURERS 
DATA FOR SIZE AND STYLE 



FLINT GUN FOR 
IGNITING POWDER 



BARED END OF TEST 
WIRE INSERTED IN 
MOLD. MAY REQUIRE 
REINFORCING SLEEVE. 
SEE MANUFACTURERS 
INSTRUCTIONS. 




REMOVE EXCESS 
SLAG AND TEST 
WELD WITH HAMMER 
FOR GOOD BOND. 
REMAKE IF FOUND 
DEFECTIVE. 



COATING MUST COMPLETELY 
SURROUND ALL EXPOSED 
COPPER NO VOIDS ARE 
PERMITTED. N 



■ REMOVE COATING AND CLEAN 
PIPE TO BRIGHT STEEL WITH FILE 
WHERE CONNECTION IS TO BE MADE 

Figure 1 2.5 Wire connections to pipe. 




COATING PATCH OVERLAPPING 
k EXISTING COATING AND 
INSULATION ON WIRE. 



noncorrosive flux. The splice should be insulated by rubber and plastic tape with the 
wrapping overlapping the wire insulation sufficiently to render it water-tight. 

Test point wires should be so placed that they will not be subjected to excessive 
strain and damage during backfill operations. Care taken in installation will avoid wire 
breakage requiring expensive re-excavation for repair. Damage of this nature is most 
likely to occur where wires are extended along the pipe (as are remote wires for a 4-wire 
calibrated test point) to reach the test point terminal box. In such instances, the wires 
may be placed under the pipe as far as they will go before backfilling or they may be run 
along the top of the pipe and adhered to the pipe with a continuous strip of self-adhesive 
tape that will also serve to give the wires added mechanical protection. 

Permanent low resistance connections are required between test wires and pipeline. 
Usually these are made using an exothermic welding processes. Currently, practice favors 
limiting the size of the powder charges to 15-gram when working on high pressure steel 
lines to minimize localized stresses in the pipe steel caused by the welding heat. The 
15-gram charge is adequate for smaller wire sizes. For sizes larger than No. 4, it may be 
necessary to separate the wire stranding into two or more bundles and powder weld 
each bundle to the pipe separately. Coating repair is important after wire connections are 
made. Manufacture literature should be referenced to determine proper powder charge 
for type and size of pipeline. The essential features of exothermic weld connections and 
coating repair are shown in Figure 12.5. 



Planning a Test Point Location 



Prior to construction, the corrosion engineer should study the proposed route and de- 
termine the number and types of test points needed. The location and type designation 



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Installing and Testing Cased Crossings 



245 



of each test point should be included on pipeline construction drawings so that they will 
be installed as part of the pipeline construction. 

On well coated-pipelines, it is good practice to have four-wire calibrated test points 
at 3 to 5-mile intervals for measurement of line current and pipe-to-soil potential. In- 
termediate two- wire test stations should be placed at a minimum of 1/2-mile intervals 
to a maximum of 1-mile intervals along the pipeline route. Additionally, test points are 
needed at foreign line crossings, buried insulated joints, and at cased crossings. Test 
stations should be placed where they will be readily accessible during routine tests. 



INSTALLING AND TESTING CASED CROSSINGS 

As discussed in Chapter 5 it may be necessary that casing pipe used at road and rail- 
road crossings be electrically insulated from the carrier pipe for adequate CP. Materials 
are available from a number of manufacturers that make it possible to accomplish this 
effectively. 



Materials 



The basic insulating material requirements are shown in Figure 12.6. Insulating spacers, 
as illustrated in the figure, consist of some type of insulating skid which are strapped 



^ 



__^l. 



^ 



VENT PIPE 



ROADWAY 



Zx 



?W 



INSULATING SPACER SEPARATING PIPE 
FROM CASING. NUMBER TO BE USED 
DEPENDS ON CASING LENGTH. 




JUL 



HL. 



WW7&W' 

INSULATING END 
SEAL SECURED TO 
PIPE AND CASING. 



Figure 1 2.6 Casing installation requirements. 



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246 Construction Practices 



around the pipe through the casing at specific intervals. The various commercially avail- 
able types of casing insulators range from all-plastic types to models having insulated 
blocks secured to steel bands (which may be rubber or plastic lined). Skids should be 
evenly spaced (typically 10 ft max), so that when the carrier pipeline is pulled into the 
casing, the end insulating spacers will be close to the casing end as shown in the Figure 
12.6. Follow manufacturer's recommendations for the number and size of insulating 
spacers. Top quality materials and careful attention to installation are essential, since 
stresses on the insulator during installation can be very large. This is particularly true 
when working with the larger pipe sizes at long-cased crossings. If, during the pulling-in 
operation, a casing insulator is by accident snagged badly on the casing end, it should 
be replaced before continuing the installation. After pulling the pipe into final position, 
if the end insulators are not close to the casing end (such as within 3 ft) additional 
spacers should be slid into position at the casing ends to maintain positive electrical 
separation. 

End seals shown in the Figure 12.6 are commercially available in various designs. 
Most designs are arranged to provide a tight, yet flexible, seal between pipe and casing, 
and most seals are watertight. The style illustrated is typical of synthetic rubber sleeves 
sized to fit the pipe and casing and strapped to them. 

The casing must be prepared properly before the carrier pipe is pulled into it. Welds 
should be smooth on the inside to prevent damage to insulating spacers. The casing 
needs to be straight and in round so the carrier pipe, with spacers affixed, can be pulled 
in without binding. All debris must be removed. If vent pipes are set after the carrier 
pipe is pulled, burning a hole in the casing may damage the carrier pipe coating, and 
if the coupon resulting from cutting the hole is allowed to fall into the casing, a short 
circuit from pipe to casing could result. All welding and hole burning should be done 
before pulling the carrier pipe. 



Test Method for Cased Crossings 



After a cased crossing has been completed, it should be checked for adequate insulation 
before backfilling. Defects can be repaired at that time at a lesser cost than following the 
completed pipeline installation. 

A method of testing cased crossings on completed pipelines is to compare the pipeline 
potential to soil with the casing potential to soil (electrode at the same location for both 
tests). A difference in the readings is a qualitative indication of satisfactory insulation 
between the two pipes. Details of this testing procedure are found in Chapter 5. 

Do not use a welding generator to test casing insulation during construction by con- 
necting it between the pipe and casing. If the casing is insulated properly, the generator 
will not pass current and no harm will be done. If, however, there should be a short, suf- 
ficient current may flow to cause a burning effect on the pipe, which could be dangerous 
in the case of high pressure lines. 



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247 



WHITE 



TEST POINT 

- TERMINAL - 

BLOCKS 




O O O Uo 

WHITE 



m^FT^^^j^^j^^^^f^^j^m^^: 




o o 

GREEN 



^ G 



TWO-VENT CASINGS 
(1) 



ONE-VENT CASINGS 
(2) 



NO-VENT CASINGS 
(3) 



Figure 1 2.7 Casing test point installations. 



Cased Crossing Test Points 



The ease with which cased crossings may be tested depends on the type of test point 
installed. Some suggestions on casing test points are included in Figure 12.7. Although 
vent pipes may be used in Cases (1) and (2) to indicate whether or not the casing is shorted 
by using the potential method described above, resistance measurements cannot be made 
for quantitative results and, if a contact exists, little can be done to locate the fault. To test 
the nonvented casing (Case 3), test wires are required for routine tests to avoid having 
to use probe rods to contact the casing. 

The four-wire test points (vent pipe serves as one wire in Cases 1 and 2) permit 
accurate resistance measurements. The additional wire, vent pipe, or probe rod contact 
at the opposite end of the casing makes it possible to locate the position of a short circuit, 
should one develop, as discussed in the next section. 



Locating Short Circuits in Casings 

If a cased crossing becomes shorted in service, being able to identify by testing where 
the short circuit is located, will save much time and money. This testing can be done 
as illustrated in Figure 12.8. As shown in the figure, battery current measured with 
an ammeter is passed between the pipe and casing. This current will flow along the 



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Construction Practices 



TEST BATTERY 
AND AMMETER 



VENT PIPE, TEST 
WIRE, OR PROBE 




Figure 1 2.8 Casing short location. 



casing to the point of short circuit where it will transfer to the pipe and return to the 
battery. A millivoltmeter connected between the two ends of the casing will indicate a 
value dictated by the measured current flowing through the casing resistance within the 
casing length, which the current actually flows through. The casing size and thickness, 
or weight per foot, must be known so that its resistance can be estimated using Table 5.3 
in Chapter 5. 

As an example, assume that the casing in Figure 12.8 is 26-inch pipe, 0.375-in wall 
thickness and that the span bridged by the millivoltmeter connection is 80 ft. The resis- 
tance per foot is 2.82 x 10~ 6 ohms per foot. The resistance of the 80 ft span would be 
225.6 x 10 -6 ohms. If the battery current flowing is 10 A and the millivoltmeter reading 
(corrected for lead resistance) is 1.6 mV, the distance traversed by the current would be 
the following: 



Length = 



1.6 x 10- 3 V 



10 A x (2.82 x 10- 6 ) ohms/ft 



= 57 ft 



The short circuit is 57 ft to the right of the voltmeter connection from the left hand end 
of the casing. 

If a short circuit is found more than a few feet in from the ends of the casing (as in 
the example), it may be very difficult or impractical to clear. Fortunately, many shorts 
are found at the casing ends where they may be cleared without too much trouble. 

In some instances if care is not exercised in placing test leads, an apparent defective 
casing is actually a short circuit between one of the pipeline test leads and either the 
casing or vent pipe. Test lead shorts can result if the test wires are wrapped around the 
vent pipe and subsequently subjected to enough strains to cut through the insulation on 
the wire. 



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Insulated Joints 249 



INSULATED JOINTS 



Insulated joints are almost always required in cathodically protected piping systems. 
On transmission lines, for example, they are used to separate the pipeline electrically 
from terminal facilities and pumping systems. They may be used also to divide the 
line into sections so that failure of CP systems or development of contacts with other 
structures or sections of the pipeline will reduce the loss of protection to an adjacent 
section. These sections may be reasonably long under normal conditions with distances 
of 25 to 50 mi being satisfactory. If, however, there are areas where stray currents from 
mining, traction, or other systems are a problem, closely spaced insulating joints may be 
helpful in controlling stray current pickup and discharge. 

The corrosion engineer should examine proposed construction plans to be sure that 
adequate provision has been made for placement of insulating joints. The location of 
insulated joints in such areas will depend on the engineer's knowledge or investigation 
of areas where stray current influence may be expected. 

In planning points of insulation, care must be taken that all possible current paths 
are insulated. For example, 30 in main line with an insulated flange at a line terminus, 
can be rendered ineffective by an noninsulated quarter inch instrument line bypassing 
the flange. Either insulated flanges, or reassembled insulating assemblies, can be used 
for high pressure line work. 

In distribution system piping work, insulated joints maybe used to separate the sys- 
tem into smaller areas for CP purposes. The size of the areas planned will depend on the 
amount of underground congestion with other pipeline facilities. In downtown sections 
where underground facilities are dense, individual insulated areas may be limited to 
a few square blocks. In outlying areas where underground congestion is not great, the 
insulated areas may be much larger. Separation of areas facilitates maintenance trouble 
shooting in the event of contact development. 

Field assembled or preassembled insulated flanges, or insulated mechanical joints 
may be used on distribution mains and large service lines. Residential size service lines 
may be insulated at the meter with various commercially available devices such as 
insulating bushings, unions, meter bars, meters with insulating swivels, and so forth. 
Service insulation at the main (if necessary) may be by insulating main tapping fittings, 
bushings, mechanical couplings, and other kinds of insulation. 



Insulated Flanges 



The general features of the usual insulated flange assembly are illustrated by Figure 12.9. 
Flange insulating kits are available from corrosion control supply companies to fit all 
standard sized flanges. Standard flange bolt holes are 0.125 in larger than standard bolts. 
Full length insulating sleeves, as shown in the figure, will fit satisfactorily if flanges are 
aligned properly. 

If it is necessary to insulate an existing flange without taking the line out of service, this 
may be done if the existing gasket is a reasonably good insulating material. Metallized or 



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250 



Construction Practices 



INSULATING GASKET 
INSULATING WASHERS 



NOTE: ALL STUDS 
INSULATED SIMILARLY 
TO THAT SHOWN 



INSULATING SLEEVE ON STUD 
EXTENDS INTO, BUT NOT ALL 
THE WAY THROUGH, EACH 
INSULATING WASHERS 




NUT STEEL 
\ V~ WASHER 



INSULATING 
WASHER-^ r 



I i I i I i I i I i I i I i I i I i I i I i I 



INSULATING 
WASHER 



2^ 



r 



STUD 



T 



INSULATING 
SLEEVE 



L 



STEEL 
WASHER 



Figure 1 2.9 Insulated flange assembly. 



graphite-impregnated gasket materials normally will make it impossible to insulate the 
flange without taking it out of service. Assuming that the existing gasket is satisfactory, 
one bolt may be removed at a time, insulated, and replaced until all bolts have been 
so treated. Existing flanges, however, are not likely to be sufficiently aligned to permit 
installing full length insulating sleeves on standard bolts. In this event, insulating and 
steel washers, and a half-length insulating sleeve may be used on one flange only. The 
half length sleeve will extend from partway through the insulating washer through the 
flange being insulated but short of the companion flange. An alternate procedure is to 
use smaller bolts of higher strength steel such that these smaller bolts with full length 
insulating sleeves will pass through the misaligned flanges permitting full bolt insulation 
as illustrated in Figure 12.9. 

For new construction, the best practice is to assemble and test the insulated flange 
before welding it into the line. Shop fabrication and testing allows for perfect flange 
alignment to be maintained so that undue stresses on insulating materials (particularly 
the insulating sleeve) will be minimized. Shop fabricated insulated flanges can be tested 
using a simple ohmmeter. Resistance values in the megohm range should be measured 
between flanges to indicate proper insulation. The full bolt insulation procedure shown 
in Figure 12.10 can also be used. 



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Insulated Joints 



251 



STORAGE BATTERY 




Figure 12.10 Shop testing of Insulating Flanges. 



Testing Insulated Joints 



When an insulated joint is placed in a pipeline with a substantial amount of pipe on 
either side of the joint, a simple resistance measurement across the joint may read just 
a few ohms (or even a fraction of 1 ohm), even though the joint resistance was several 
million ohms just prior to installation. This method should not be used. The resistance 
measured with the joint in place consists of two parallel resistances: (1) the joint resistance 
and (2) the resistance to earth of the pipeline on one side of the joint plus the resistance 
to earth of the pipeline on the other side of the joint. The resistance measured across a 
joint, then, (even with perfect joint insulation) will be governed predominantly by the 
amount of pipe on either side of the joint, the quality of coating (if any), and the average 
soil resistivity along the pipelines. 

More indicative testing of insulated joint effectiveness involves interrupting the 
CP current source (or test current applied from a temporary d.c. source) on one side 
of the insulated joint and measuring the potential to a remote copper sulfate elec- 
trode. If the joint is effective, the potential on the side with the CP source will change 
with a positive shift as the current source is interrupted. The unprotected side will 
remain constant or move in the negative direction. If the measurements are made to 
a close electrode over or alongside the insulated joint additional information may be 
gained. For example, if the pipe on the unprotected side swings in the positive direction 
when the interrupter turns the current source ON (even though there may have been 
little or no change with respect to the remote electrode), it is an indication that current is 
flowing through the earth around the insulated flange. This may be a result of defective 



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252 Construction Practices 



coating or excessive voltage drop across the flange. Another test is to utilize an insulator 
tester, which is commonly available. These instruments allow direct measurement of the 
insulating flange integrity. 

If an insulated flange is found defective, it may be possible to repair it without taking 
the line out of service. This depends on whether the insulating gasket is shorted across or 
whether it is an insulated bolt sleeve that is broken down. If it is the latter, the shorted bolt 
may be removed and the insulation replaced. Determining where the trouble is can be ac- 
complished by checking each bolt electrically. If flange bolts are fully insulated per Figure 
12.9, an insulator tester should be used to check resistance between pipeline and each bolt. 
Bolts that are shorted will have zero or low resistance to the pipe. If all bolts have a high 
resistance to the pipe, a shorted gasket is probably the problem. This assumes that any 
possible bypassing piping on each side of the flange has been identified and insulated. 

In the case of a shorted insulated flange having bolts insulated on one side only, the 
ohmmeter test will not be acceptable because all bolts will have low resistance to the 
pipe. Use an insulator checker to identify whether the bolts are shorted or the flanges 
are shorted. 



Grounding Cells for Insulated Joints 

Protective devices may be required where insulated joints are subject to damage from 
lightning-initiated high potential surges. This may be more probable where pipelines 
closely parallel high voltage electric transmission lines as when a pipeline is installed in 
the same right-of-way. In such instances, a lightning-initiated fault may cause very high 
voltages to be induced in the pipeline. If these high voltages are developed across an 
insulated joint they may cause the joint to arc the current from the lightning flow for a 
short time. Typically insufficient energy (except in rare cases) is expended to cause the 
joint to weld across the flange. 

Standard lightning arresters may be used effectively. A voltage rating should be 
selected that will provide adequate protection for the insulation level in the insulating 
joint being used. Arresters having too high a voltage rating might not divert the high 
potential appearing across the joint before the insulation fails. 

Another protective measure is the grounding cell which combines voltage surge pro- 
tection with a degree of CP on the unprotected side of the insulating joint. A grounding 
cell may be constructed as shown, in principle, in Figure 12.11. 

Constructed with zinc anodes as illustrated in Figure 12.11, a grounding cell will 
have a value of resistance between the two closely-spaced anodes depending on the 
resistivity of the chemical backfill being used. For a properly installed grounding cell, 
this resistance should be in the range of 0.2 to 0.5 ohms (depending on the backfill used). 
In the event of a high potential surge, the cell will conduct and the voltage drop across 
the insulated joint will be limited to 200 to 500 V per thousand amperes of fault current 
flow. Where very heavy fault currents are anticipated, four anode cells (cross-connected 
as shown in the detail of Figure 12.11) may be used. These have a lower cell resistance, 
which limits further the voltage build-up across the insulated flange. 



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Insulated Joints 



253 



COMBINATION INSULATED 
JOINT AND LINE CURRENT 
TEST POINT 



UNPROTECTED SIDE 




DETAILS OF FOUR ANODE 
CROSS CONNECTED CELL 
WHERE REQUIRED. 



TWO-2" x 2" x 60" ZINC 
ANODES SEPARATED 
BY, TYPICALLY, 1 " 
INSULATING BLOCKS 
AND STRAPPED 
TOGETHER WITH 
INSULATING MATERIAL 



NOTE: THE ANODES WITH 
BACKFILL MAY BE 
OBTAINED AS A 
PACKAGED UNIT 
ENTIRE ASSEMBLY 
INSTALLED IN AUGERED 
HOLE. 



Figure 12.11 Grounding cell installation. 



With the grounding cell connected across an insulated joint separating cathodically 
protected pipe from unprotected pipe, loss of protection current through the cell is limited 
by cell polarization in addition to the cell resistance. It works in this fashion. The zinc 
anode connected to the unprotected pipe tends to discharge current to the zinc anode 
connected to the protected pipe. The anode receiving current, however, will polarize in 
the negative direction up to approximately —1.5 V with respect to the copper sulfate 
electrode. The anode discharging current remains at approximately —1.1 V. The cell, 
then, develops a back voltage up to the difference between the above two figures or 
0.4 V. Up to a voltage difference between the two pipelines of this amount, the current 
flow through the cell will be only that required to maintain polarization. Current flow 
due to any excess above 0.4 V will be limited by the cell resistance. 

In addition to the performance characteristic described above, the zinc anode con- 
nected to the unprotected pipeline provides a degree of CP to the unprotected pipe in 
the flange area. This reduces the possibility of current leaving the pipe in this area to 
bypass the insulated joint with resulting corrosion of the unprotected pipe. 



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254 Construction Practices 



Where higher cell back voltage is desired, other materials may be used. High silicon 
cast iron, for example, polarizes in both the negative and positive direction and can 
develop cell potentials in the order of 2 V or more. If used at an insulated joint separating 
protected and unprotected pipe, however, the high silicon cast iron anode connected to 
the unprotected pipe is polarized in the positive direction and will tend to draw current 
from the unprotected pipe (and corrode) rather than provide a measure of CP as is the 
case when zinc is used. This can be overcome by using a high resistance container for the 
cell package (with, however, provision for entry of soil moisture to keep the chemical 
backfill wet) plus the installation of a local galvanic anode on the unprotected pipe at 
the insulated joint. 



ISP/Polarization Cells 



Isolation surge protectors (ISP) and polarization cells are devices that provide excellent 
grounding and protection for insulating joints. ISP are electronic mechanisms that when 
placed across an insulating flange block DC current flow and allow AC current to flow. 
Due to the devices' ability to pass AC current during normal operational, ground fault 
conditions or lightning strikes, the insulating joint is protected and more importantly the 
safety of personnel is assured. Since ISP are electronic devices they can automatically reset 
following a fault condition. Although these devices are more expensive than grounding 
cells, they provide superior protection. A variety of companies manufacture them and 
can provide technical support for your particular needs. 



GALVANIC ANODE INSTALLATIONS 

Although typical galvanic anode installations have been described in Chapter 9, the 
following pertains to construction practices. 

Wire and Connections 

All buried wire interconnecting galvanic anodes with the pipeline are cathodically pro- 
tected. For this reason, insulation level on wire is not critical, but the insulation should 
be a material which can be expected to resist deterioration under service conditions. 
Connections between individual anode leads and header wire should be insulated by 
taping with at least one half-lapped layer of rubber tape and one half-lapped layer of 
self-adhesive plastic tape (or equivalent insulation) with the joint insulation overlapping 
the wire insulation. The copper wire connection to the steel main is the most critical inso- 
far as insulation is concerned. At this point, all copper at the connection must be coated 
completely to avoid the possibility of a shielded copper-steel corrosion cell. All connec- 
tions must be permanently low resistance. Any gradual development of joint resistance 
will reduce anode output. Permanent connection such as soldered joints (lead-tin solder 
or silver solder) or exothermic-welded connections are reliable. 



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Cathodic Protection System Installations 255 



Anode Backfill 



The chemical backfill in packaged galvanic anodes will take up moisture slowly even 
if saturated with water after placing in the auger hole and before completing the earth 
fill. For this reason, the anode will not attain full output immediately. Depending on the 
amount of moisture in the earth, it may be a matter of days or even weeks before full 
output is attained. 



CATHODIC PROTECTION SYSTEM INSTALLATIONS 

The basic information on ground bed design is contained in Chapter 7 and information 
on impressed current CP systems is contained in Chapter 8. The following construction 
notes supplement the information included in those two chapters. 

Anodes 

Anodes used for ground bed construction, should be transported and handled with care 
to avoid damage. The insulated leads furnished with the anodes by the manufacturer 
should be protected from damage to both the wire insulation and the connection be- 
tween wire and anode. Although these connections are well made, the full anode weight 
should not be supported by the lead wire alone; although the connection may not fail 
mechanically, the strain may be sufficient to damage insulating material at the connec- 
tion. The use of the lead wire to lower anodes into an installation should be prohibited. 
This may permit current leakage that would cause corrosion failure of the connection. 
Insulating compounds, taping or specially molded insulating caps of various types are 
available for reinforcing the insulation provided by anode manufacturers. 

Cable and Connections 

All underground cable connected to the positive terminal of the rectifier is subject to 
corrosion at any insulation breaks in the main cable insulation or in field-applied insula- 
tion on connections. If a ground bed is to meet its design life expectation without major 
repairs, all underground cable insulation must be perfect, because the slightest current 
leakage will result in cable severing. 

In selecting insulated cable for ground bed use, follow the cable manufacturer's 
recommendations for the expected service conditions. Such conditions might include 
unusually acid or alkaline soils, presence of sea water or brine rather than the usual soil 
moisture, pressure or abrasive action (cable on ocean or river bottom), solvent action 
(such as from petroleum product spillage), and other hazards. In recent years, high 
molecular weight polyethylene insulation has been popular. 



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256 Construction Practices 



Field applied insulation over connections between anode leads and header cable is 
particularly critical. These connections must be made absolutely waterproof. This can 
be accomplished by taping after applying insulating putty to break sharp corners at the 
connection. Four half-lapped layers of top grade rubber splicing compound (overlapping 
the cable insulation) followed by four half-lapped layers of self-adhesive plastic tape are 
effective when applied with care. Chemically setting plastic resins poured into molds 
surrounding connections are also excellent. When the resin and its hardening agent are 
mixed properly and poured into a correctly applied mold, excellent void-free insulation 
results. 

The more popular methods of making connections between anode leads and header 
cables are by powder welding or compression connectors using hand or hydraulic com- 
pression tools. 



Backfill in Cable Trench 



Because of the danger of cable insulation breaks, care must be taken to be sure that 
there are no sharp rocks or other objects in the cable trench bottom that could damage 
insulation. Should such material be present, the ditch may be deepened and padded 
with clean earth. The first layer of backfill directly above the cable should likewise be 
free of cable damaging material. This layer must be of sufficient thickness to prevent 
penetration by cable-damaging objects in the subsequent fill. Horizontal cable runs are 
buried, usually, at a minimum depth of 24 in. 



Installing Ground Bed Anodes 



When installing ground bed anodes according to designs shown in Chapter 8, one of the 
more critical operations is the installation of coke breeze (or other carbonaceous backfill) 
around the anode. The fill must be tamped solidly for maximum coupling between anode 
and earth. 

When placing backfill around anodes in vertical holes, continuous tamping is advis- 
able as the backfill is placed layer by layer. This minimizes the possibility of bridging 
across the hole with void spaces below the bridge. Such voids may increase resistance 
values and may operate to reduce anode life. When tamping with power tampers (pre- 
ferred) or by hand, particular care must be exercised to prevent damage to the anode or 
anode lead wire. 

In horizontal installations, ditch width at anode depth should be that of the design 
width of the carbonaceous backfill layer. Where this is not possible because of trenching 
conditions, form boards may be used to restrict the backfill. After the carbonaceous 
backfill and anodes have been placed inside the form boards and the tamped earth 
outside, the form boards must be withdrawn. The coke breeze should be retamped to 
fill the space occupied by the form boards. 



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Inspection 257 



Rectifier Placement 



If possible, rectifiers should be placed where they may be reached for periodic inspection 
and maintenance with reasonable ease. This may at times necessitate additional cable 
from the rectifier to the ground bed or pipeline or both. If the amount of additional cable 
is appreciable, however, the value of having the more convenient rectifier location must 
be weighed against the increased installed cost of cable and increased power losses in 
the cable resistance (where significant). 

If the proposed rectifier site is in an area where flooding may be a problem, the 
maximum high water level should be ascertained and the rectifier mounted so that it 
will be above this level. In the usual instance, however, the rectifier case (if pole mounted) 
should be placed at a convenient working height. 

Before installing a rectifier, the details of the National Electrical Code (NEC) and 
local electrical codes should be checked. In many areas, rectifier installations must be 
inspected and passed by an electrical inspector before power service can be obtained. By 
making the installation conform to the code requirements initially, time will be saved in 
getting the inspector's certification. 

Where power is to be supplied from a local power company by a separate metered 
service, usually a kilowatt-hour meter base may be obtained from the company. When 
the installation is completed and inspected (if necessary), the power company can make 
the necessary connections to the pole top (or other delivery point) and install the kwh 
meter in the base supplied. 

Rectifier cabinets should be grounded separately for safety. Likewise, the power 
company usually will have pole grounds and a ground rod at the transformer pole 
serving the rectifier installation. If any of these ground rods are close enough to the 
ground bed within its area of influence, they will tend to collect current and create 
a stray current situation on the power system if power distribution is by a grounded 
neutral system. Locating ground bed anodes too close to ground rods has caused severe 
instances of stray current damage to power system ground rods and anchors. When 
there is any question of possible interference from this source, tests should be made and 
corrective bonds established between the rectifier negative and power system neutral if 
necessary. In severe instances it could be necessary to install galvanic anodes on ground 
rods and anchors in current discharge areas to correct the condition, as discussed in 
Chapter 11. 



INSPECTION 



Adequate inspection during the construction of corrosion control facilities on pipelines 
can make the difference between first class performance and a system that may per- 
form poorly and require relatively high maintenance expenditures if ineffective or not 
inspected. 



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258 Construction Practices 



Test Points, Cased Crossings, and Insulating Joints 

Test points must be inspected to assure that installation complies with construction 
plans. The inspection should make sure that connections to the pipeline are sound and 
well insulated, that color coding is observed, that wires are so placed in the ditch that 
backfill will not break them, and that the specified terminal panel and housing is installed 
properly. 

Cased crossings should be inspected as soon as they are installed. This is necessary 
to ascertain that the casing is electrically insulated from the carrier pipe and to permit 
correction of defects before backfilling. 

Insulating joints installed as complete preassembled, pretested units should be in- 
spected for proper installation at the location indicated on the plans, so that the joint 
is not subject to undue mechanical strains that could cause early failure of insulating 
material and that the joint is in fact performing satisfactorily once welded into the line. 

The inspectors charged with inspecting the above features must be thoroughly famil- 
iar with the use of test points, cased crossings, and insulating joints. They must have the 
necessary instrumentation to verify the satisfactory performance of the various items 
prior to acceptance. They should also have the authority to see that corrections are made 
should defects be found. 



Cathodic Protection Installations 

Inspectors responsible for CP installations must be fully familiar with all details of good 
CP construction practice as well as with the specific provisions of the installations being 
made. 

In some instances field modifications may be necessary. This may occur, for example, 
if vertical anode installations were specified but rock is closer to the surface than expected. 
A field decision is then necessary to determine whether the type of anode installation 
may be changed from vertical to horizontal or if best results will be obtained by boring 
the rock. Occasionally what appears to be solid rock is actually a relatively thin layer 
with good soil underneath. The inspector must be qualified to evaluate all such situations 
when encountered. If major modifications are advisable, the inspector should check with 
the designer of the installation to be sure that the system performance will not be affected 
adversely. 

At galvanic anode installations, one of the more particular points to be watched is the 
anode backfilling operation to be sure that there are no voids in the fill around the anodes. 
This can be a problem with packaged galvanic anodes placed vertically in augured holes. 
If the hole is small, it may be difficult to work earth backfill all around the anode package 
so that no voids will exist. If voids are present, the chemical backfill material can settle 
away from the anode, once the container has deteriorated, with probable reduction in 
anode effectiveness. If anodes and chemical backfill are installed separately, the inspector 
must verify that the anode is centered in the hole or trench as specified and that the fill 
is so placed and compacted that no voids can exist. All other details of galvanic anode 



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Inspection 259 



installations must be verified by the inspector as being in accordance with good practice 
for such construction. 

When inspecting impressed current ground beds, anode placement and backfilling 
operations must be given careful attention to ensure installation at the design location 
and to avoid voids in special carbonaceous backfill which would tend to increase anode 
resistance and shorten life. Adequate compacting of carbonaceous backfill materials is 
important and the inspector must verify that this is done effectively but in a way that 
will not damage the anode proper or its connecting cable. 

Probably the most important single feature of impressed current ground beds to be 
verified by the inspector is the insulation on all positive header cable, anode connecting 
cable, and connections between the two. The inspector must be sure that no damaged 
cable insulation is buried without being repaired and that the insulation of all splices 
and tap connections are such that they will be permanently watertight so no current 
leakage can occur. Likewise, the inspector must be sure that the cable trench bottom that 
can damage the cable insulation and that the backfill in contact with the cable is free of 
insulation-damaging material. 

When rectifier installations are involved, the inspector verifies that the rectifier unit 
has been placed at the specified location and in the specified manner, that all wiring is 
correct and that requirements of the power company and of NEC and local jurisdictional 
codes have been satisfied. If power supplies other than rectifiers are used, the inspector 
must be familiar with the details of the power source specified so that he may verify that 
the installation is being made properly. 



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Chapter 



) 



Maintenance Procedures 



Ronald L. Bianchetti 



Pipeline corrosion control measures as described in the preceding chapters can be highly 
effective if properly designed and installed, but only if they are maintained adequately 
Without a suitable maintenance program, money spent for designing and installing cor- 
rosion control can be wasted. There have been many instances, for example, of the system 
owner paying for the installation of cathodic protection (CP) on sections of their system 
without establishing any means for ongoing maintenance. Although they may feel that 
their troubles are over, this false sense of security can be short-lived if corrosion failures 
continue to occur. The tendency is to blame the design, but from experience the fault in 
most cases is simply failure to keep the system operating continuously and effectively. 
The purpose of this chapter is to present suggestions for maintenance programs that will 
help to keep corrosion control measures operating at maximum effectiveness. 



REQUIREMENTS FOR A MAINTENANCE PROGRAM 

The following items should be included, as applicable, in a maintenance program for a 
pipeline corrosion control system: 

• Periodic surveys to determine the status of CP and related items 

• Coating maintenance procedures 

• Maintenance procedures for current sources and ground beds in impressed current 
CP installations 

• Maintenance procedures for galvanic anode CP installations 

• Maintenance procedures for test points 

• Maintenance procedures for cased crossings 

• Maintenance procedures at foreign line crossings. 

Each of the above will be discussed in detail in the following sections. 

261 



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262 Maintenance Procedures 



PERIODIC SURVEYS 



On cathodically protected pipelines, the following data should be taken as outlined in 
NACE INTERNATIONAL RP0169 (latest revision) and code of Federal Regulations- 
Transportation Section 49, Part 192: 

• A potential survey along the protected pipeline. This should include, on a coated 
pipeline, potentials to close copper sulfate electrode (CSE) at all test points along the 
line 

• On coated pipelines, data for calculation of effective coating resistance 

• At each rectifier installation, DC current and voltage, the efficiency of the rectifier and 
the kilowatt hour meter reading 

• At other DC power sources, the DC current and voltage as well as pertinent supple- 
mentary information which may apply to the particular power source 

• The resistance of each impressed current ground bed 

• The current output and resistance of each galvanic anode installation 

• Potentials of the line surveyed and of the foreign line at foreign line crossings. Where 
intersystem bonds exist, measure the bond current and direction of flow 

• At cased crossings, the resistance between carrier pipe and casing plus the potential 
to reference electrode of both pipeline and casing 

• In variable stray current areas, verification that bonds, electrolysis switches or other 
corrective measures are operating properly and are providing the required degree of 
protection 

• Verification that insulated joints are effective and that any protective lightning ar- 
resters, spark gaps, grounding cells, and polarization cells are performing their func- 
tion effectively 

• Notes on maintenance requirements on any of the physical features associated with 
the corrosion control system. 

In addition to the required surveys, a more frequent check of protective potentials 
should be made in areas where there is pipeline congestion with many foreign line 
crossings, where variable stray current interference is a problem, or where particularly 
critical or hazardous environmental conditions exist. In this category may be included 
interference correction bonds between pipelines where the bond carries more than some 
established value (5 A for example) as well as bonds, electrolysis switches, or other 
facilities for stray current electrolysis correction in DC transit system, mining, or other 
similar problem areas. 

Standard printed forms should be used to record the field data. These may be planned 
by the pipeline corrosion engineer to suit particular requirements. Such forms serve two 
important functions. First, they save field time by minimizing the amount of writing 
necessary on the part of field test personnel. Second, they establish a uniform manner 
for recording data which is important if a number of different people are participating 
in the surveys throughout the pipeline system. A form that may be used for recording 
the protective potential data is shown by Figure 13.1. 



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Periodic Surveys 



263 



XYZ PIPE LINE COMPANY 

CORROSION CONTROL DEPARTMENT 

POTENTIAL SURVEY TEST DATA 



Date 7-8-68 j es t Engineer(s) 



Pipeline . 



Omega 30" Main Line No. 1 



John Doe Sheet No. 2 f _J_ 

Mileposts 9 to 23 



.and. 



Between Compressor Stations ^ 

Test Meter: MCM B-3 Meter No. 123 Scale 1 -Volt and 2- Volt 




NOTES: 



Figure 1 3.1 Form for potential test data. 



Other forms may be used for line current data and calculations, for coating resistance 
test data and calculations, for galvanic anode or impressed current source tests, for cased 
crossing rests, for stray current tests, and for other special tests that may be made as a 
matter of routine during periodic survey work. 

Although areas requiring additional protection may be determined by inspection of 
the data sheets, the best understanding of the results may be achieved by plotting the 
protective potentials versus line length. Master sheets may be prepared for each line with 
all test points, impressed current or galvanic anode installations, insulating joints, taps, 
and other pertinent information shown in their correct position above the area in which 
the data are plotted. Results of each survey may be plotted on a print of the master sheet 
together with a plot of the last survey made. This permits readily determining areas 
where there may have been reduction or loss of protection since the last survey was 
made. This will show graphically where improvements in the protection system may be 
required. A portion of such a data plot is illustrated by Figure 13.2. 



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264 



Maintenance Procedures 



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Figure 1 3.2 Protective potential profile. 



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20 



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22 



23 



As shown in the figure, there is an area near the center where there has been a loss of 
protective potential throughout a substantial area. From the line plot above the graph, it 
can be seen that there is an insulated main line tap, a cased crossing, a bond to a foreign 
structure, and a magnesium anode installation within this area. Difficulty with any one 
or several of these items could have contributed to the loss of protection. Comparison of 
the most recent survey data at each of these sites with similar data taken during the last 
preceding survey should give a quick indication of the probable source of the trouble — 
shorted insulation in the lateral tap, shorted cased crossing, changed conditions at the 
foreign line crossing, or magnesium anode installation starting to fail. 

Note also from Figure 13.2 that items such as test points and CP current sources are 
given identifying numbers (arbitrary in this case). For a pipeline network covering an 
extensive area, it is helpful to establish some system of designations that will identify the 
location within the network. In the illustration, for example, CD-TP6-F could indicate the 
section between compressor stations C and D with TP6 indicating test point No. 6 and F 
indicating a foreign line test point. Similarly, CD-Mg3 could indicate magnesium anode 
installation No. 3 in the same section. In setting up a system, the overall requirements 
of the pipeline network should be analyzed and a uniform designation code established 
that will satisfy fully the requirements of that particular network. 

Original survey data and completed survey plots should be bound in suitable ledgers 
or otherwise stored in such fashion that they may be reviewed conveniently. Such data 



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Coating Maintenance 265 



may become of great importance in the event of litigation involving the need to demon- 
strate that a section of line has been placed under CP and maintained adequately. 

As soon as a periodic survey is completed it should be analyzed promptly In areas 
where required, corrective action should be taken immediately The corrosion engineer 
should recommend, obtain approval for, and organize standard procedures for having 
required maintenance work done through established channels consistent with company 
policy This will make it a routine matter for requesting maintenance work when and as 
needed to keep the corrosion control system operating at optimum effectiveness. 



COMPUTER PROGRAMS 



Computers today provide the capability for the pipeline company to manage and analyze 
large amounts of data in a relatively short time. Experience shows that the development 
and use of computer programs to save, sort, and analyze data provides the corrosion en- 
gineer an invaluable tool for operation and maintenance of the corrosion control system. 
Programs can be written to automatically flag such things as protective potentials below 
predetermined levels, rectifier efficiencies that have dropped to an uneconomic level re- 
quiring stack replacement, anode installations that have dropped below a predetermined 
output level, and other items of a similar nature as required. The time spent in getting 
such a program organized and established will be repaid in the speed of analyzing data 
upon conclusion of periodic surveys. 



COATING MAINTENANCE 



Although coated pipelines are buried and inaccessible under normal conditions, there 
are things that can be done to maintain coating systems. During normal operations on 
most pipeline systems the line will be frequently uncovered for other maintenance work. 
This work may involve damage to the coating or removal of portions of it. Coating repair 
or replacement should be of a quality at least as good as the original coating. Maintenance 
crews should be trained in good coating application procedures, care of materials, and 
compliance with specifications so that acceptable coating work will result. 

Maintaining a performance record of pipeline coatings on the system will help the 
corrosion engineer to prepare and present recommendations for material to be used on 
new construction. The general electrical condition in terms of effective resistance can 
be obtained from the periodic corrosion surveys. In some cases, specific information 
can be obtained by training all line maintenance crews to report on the coating condition 
whenever pipe is uncovered. Information desirable in such a report includes date, specific 
location, coating type and description, manufacturer and grade of material (if known) 
or other identifying information as available or applicable, temperature at the coating 
surface in place, general condition of the coating, bond quality, evidence of cold flow, 
evidence of moisture under the coating, evidence of soil stress effects, presence of pitting 



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266 Maintenance Procedures 



at holidays (with data on number of pits, depth range, and range of pit diameters), 
and data on environmental conditions surrounding the pipe that could have an adverse 
effect on coating. Accumulation of information by this method allows for a continuous 
reporting procedure to compare historic data, thereby providing the corrosion engineer 
with knowledge of how the pipeline's coatings are performing. 

Where anomalies are found as part of the ongoing surveys, special dig-ups may 
be required. These may be caused by conditions where potentials are declining along 
a specific section of pipeline with no apparent cause. Actual points to be excavated 
are typically selected on the basis of areas of low potentials, sections with higher than 
normal current demands, and areas having the more severe holiday indications following 
holiday detection. 

Although uncovering a pipeline and replacing a coating is expensive, it may be 
necessary in some instances. This is typically true where coating deterioration is found 
to be severe over a short length of pipeline because of unusual environmental conditions. 
This circumstance may result in loss of protective levels of CP over an area of the pipeline. 
Recoating the section usually restores CP to proper levels over the entire line with no 
significant changes in the CP system current outputs. If a section is recoated, the chances 
are that the original coating was not a suitable selection for conditions in that area. The 
material used for recoating should be selected specifically for its ability to stand up under 
the particular environmental conditions encountered. Another means of reestablishing 
proper levels of CP in the deficient area(s) is to provide supplemental localized CP. 
Economic justification for recoating versus simply adding local CP in the affected area 
should be evaluated for each case. 



RECTIFIER MAINTENANCE 



Rectifiers or other impressed current power sources should be inspected on a routine 
basis. Preferably this should be combined with other pipeline operations to eliminate 
the need for a separate maintenance trip. The routine established would depend on the 
procedures followed in a system. Seldom would inspection more than once per week 
be required, and every two weeks is satisfactory. The interval normally should not exceed 
a month. 

Where longer periods between inspections are unavoidable, units on lines which are 
air patrolled can be fitted with devices which will give a visual indication of loss of 
power. The air patrol report will provide prompt notice of unit failure. Monthly power 
bills on rectifiers equipped with individual kilowatt hour meters will serve also as an 
indication of whether or not the power is functioning and power consumption is normal. 
Newer technology which may include remote monitoring systems may be considered 
for areas where normal inspection intervals cannot be maintained. 

Routine inspection of rectifiers consists normally of reading the DC output voltmeter 
and ammeter as well as reading the AC kilowatt hour meter (if one exists). This lat- 
ter reading makes it possible, if the unit is found to be out of service, to estimate the 



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Rectifier Maintenance 267 



approximate time the unit has been off. Readings should be recorded on a form and 
forwarded to a designated office where they may be posted and compared with prior 
readings to observe unusual variations. At some locations where seasonal variations 
cause substantial changes in rectifier current output, rectifier taps may require adjust- 
ment during routine inspection to maintain adequate protection. 

If a rectifier is found to be off, the inspector should check to see if the trouble is caused 
by a blown fuse or tripped circuit breaker. If this is found to be the case because of a 
temporary electric system disturbance (such as may occur during an electrical storm), 
restoring the circuit may be all that is necessary. If, however, the rectifier cannot be 
returned to service easily, the responsible corrosion engineer should be notified as soon 
as is practical so he may investigate the trouble and implement corrective action. 

Older rectifiers may be expected to become less efficient as the rectifier stacks age. 
For small units operating on a minimum power bill basis, this is not significant unless 
the inefficiency becomes so great that the minimum bill is exceeded. Efficiency is most 
important, however, on large units. Rectifier stacks on large units should be replaced 
when they become so inefficient that the increased annual cost of power exceeds the 
annual cost of the investment required to make the replacement. 

In making stack replacements in rectifier units, the use of an element identical to the 
one being replaced may not be always the right thing to do. The technology of manufac- 
turing rectifying elements has advanced markedly over the years and a stack that may 
have been the best available when a rectifier was built originally may be outmoded by 
the time a replacement is needed. For this reason, particularly when replacing stacks in 
older rectifiers, the new rectifying elements should be specified to match the DC output 
nameplate rating on the rectifier (plus whether single or three phase, full wave bridge 
or center tap, and type (silicon, or other) rather than specifying an exact replacement 
of original equipment. By so doing, gains in efficiency, improvements in aging char- 
acteristics, and increases in voltage blocking capacity can be beneficial. Such upgrades 
provide improved efficiency, reduce operating expense while higher inverse voltages 
give greater protection and operating flexibility to the rectifier. 

At least once per year (usually at the time of the complete annual survey), rectifier 
components should be systematically inspected and checked as follows: 

• Clean and tighten all bolted current-carrying connections. 

• Clean all ventilating screens in air cooled units so that air flow will be completely 
unobstructed. 

• Check indicating meters for accuracy. 

• Replace insulated wires on which insulation has cracked or been damaged. 

• Oil immersed units, check for proper oil level and cleanliness. The oil should be 
clear and nearly colorless. A failing oil is usually characterized by a murky or cloudy 
appearance with loss of transparency and should be replaced with a good grade of 
standard electrical transformer oil unless facilities are available for testing the oil and 
salvaging by filtration where practicable. 

• Check all protective devices (fuses, circuit breakers, or lightning arresters) to be sure 
that they are undamaged and in satisfactory operating condition. 



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268 Maintenance Procedures 



Other types of direct current sources for impressed current systems, will require 
routine maintenance to at least an extent equal to rectifiers. Although not detailed here, 
maintenance programs should be prepared for such power supplies. Programs should 
have as their prime objective the prevention of unit failures before they occur plus prompt 
repair should outages develop. 



GROUND BED MAINTENANCE 
Surface Anodes 



Ground bed maintenance will consist of periodic checks to ensure that there has been 
no disturbance of the earth above the header cable and line of anodes in a conventional 
(surface) type bed. If any part of the ground bed is subject to washing (by storm water) 
with exposure of cable, the cable should be covered again for protection. This should be 
done only after determining that there has been no insulation damage. Washes should 
be diverted to prevent reexposure of the cable. 

If construction activity is noted in the vicinity of the ground bed, the location of the 
ground bed route should be staked or marked with paint so that inadvertent damage 
may be avoided. If new construction involves installation of underground structures, 
tests may be necessary to determine whether or not they will be within the potential 
gradient field surrounding the ground bed and subject to possible stray current damage. 

During routine testing, any significant increases in ground bed resistance (or an open 
circuit), will prompt additional testing. Measurement techniques will be required to 
locate cable breaks or anodes that have failed. When an increase in resistance is found, a 
pipe-cable locator can be used to find the problem. If the locator indicates a continuous 
cable throughout the ground bed length, one or more anodes may have failed. If there 
is a header cable break along the line of anodes, the signal will drop to essentially zero 
in the vicinity of the break. 

Where failed anodes are indicated, they may be located by an over-the-line potential 
profile (made along the line of anodes with the rectifier energized) with the measured 
potentials being taken between a remote reference electrode and the over-the-line CSE 
which is moved by two or three foot increments along the line. The potential profile 
will show positive potential peaks at each working anode. Any areas where peaks in 
potential are not found represent anodes that are no longer working and require repair 
or replacement. The number and spacing of anodes installed originally should be known. 



Deep Well Anodes 



Deep well ground beds require preventive maintenance that includes ensuring that 
cables are well protected between the rectifier cabinet and the well head. Additionally 
the well head cover or cap should be adequately secured to prevent unauthorized entry 



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Test Point Maintenance 269 



and be vented sufficiently to permit escape of any anode-generated gases. If deep well 
ground anode(s) fail, little can be done if the anode string cannot be withdrawn from 
the well. If the failure is a result of cable damage at the well top, typically repairs can be 
made and the functionality of the anode well reestablished. 

Increased resistance of a deep well caused by gas blocking can be remedied in some 
cases by air or water injection through the vent pipe if one exists. If injection of a low 
resistivity chemical solution is considered, the possible effect on anode material and 
cable insulation must be studied as well as the possibility of contaminating potable 
water supplies via underground water seams. 



GALVANIC ANODE MAINTENANCE 

Maintenance of galvanic anode installations is typically performed to determine that an- 
ode leads or header cables have not been exposed or damaged by accident, right-of -way 
washing or construction work. Where such exposure or damage is found, repairs should 
be scheduled promptly. At installations having test points, maintaining the connection 
between the lead from the anodes and that from pipeline is critical. Due to the low driv- 
ing potential available from galvanic anodes, resistance in the connection can cause a 
marked decrease in current output. Annually, such connections should be cleaned. 

As galvanic anodes approach the end of their useful life, current output will diminish. 
Replacement of individual anodes or the entire anode ground bed will be required 
when insufficient current output(s) to maintain protective potentials on the pipeline are 
identified. Current output can be measured during annual surveys at those installations 
having test points installed for the purpose. Approximate determination of the useful life 
of such installations may be predicted from a comparison of the average current output 
(since installation) with the amount of anode material. See the calculation of anode life 
in Chapter 9. 

If there is a marked decrease in the output of a galvanic anode installation and there 
is no reason to believe that it is reaching the end of its life, a broken header wire or anode 
lead may be the cause. If an over-the-line potential profile is made to locate disconnected 
anodes, the peaks at working anodes will be usually of much less magnitude than those 
found for impressed current anodes. 



TEST POINT MAINTENANCE 

Test points are the principal means in evaluating the level of CP on most pipeline systems. 
Post mounted test stations, from time to time, require replacement of box covers or cover 
retention screws, cover gaskets or terminal nuts or screws within the test box. Occasion- 
ally a test station may be broken or missing as the result of accident or vandalism. Pipeline 
corrosion personnel, when making routine surveys, should carry a complete stock of 
spare parts and test boxes so that minor maintenance can be implemented at that time. 



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270 Maintenance Procedures 



Broken wires at test points can be hard to repair if the break is not near the surface. 
Where test stations are attached to a cased crossing vent pipe, earth settlement at a 
deeply buried crossing can create enough tension on the wires to break them. While it is 
good practice to leave slacked wire in the test box to relieve tension, this is not always 
sufficient. 

Occasionally it is found that test wires were tied around the vent pipe to hold it in 
place while the crossing excavation was being filled and that this tie-off was not loosened 
when the test point was set. Soil settlement can pull the wires taut at and below the point 
where they are tied and either snap them or cut through the wire insulation to short 
circuit the wires to each other or to the vent pipe. In the case of long buried underground 
conductors along the current measurement spans, backfill settlement around the pipe 
may be sufficient to snap the wires if they were not placed properly at the time of 
installation. 

Occasionally, a defective exothermic weld connection between test lead and pipe may 
separate from the pipe and give an open circuit indication. At locations where the test 
point is located close to the pipe connections, the excavation required to locate and repair 
the trouble (unless the line is very deep) is rather simple. If the break is in a long wire 
span, where to excavate becomes important and requires the use of pipe-cable locator 
tests to determine the break location. 



CASED CROSSING MAINTENANCE 

Maintaining insulation between carrier pipe and casing is the most important objective at 
cased crossings. If it is not possible to isolate the casing and the carrier pipe, steps should 
be taken to eliminate (by methods other than CP) conditions conducive to corrosion on 
the carrier pipe within the casing. See Chapter 5 on the effect of shorted casings on CP. 

The status of isolation at cased crossings should be measured at each annual survey. 
If a shorted condition is found, immediate repair should be scheduled. Before sending 
a crew to the site, as much information as possible on the probable location of the short 
circuit should be determined by electrical measurements. 

The first thing to check is the test point at the cased crossing. It is not unusual to 
find that the short circuit is not in the casing itself, but may result from contacts between 
the test point wires and the casing vent (or the end of the casing) or between the test 
wires and test point conduit mounted on the casing vent. Locating and clearing such 
short circuits is discussed in the preceding section. If the short circuit is between the pipe 
and casing, it should be determined (if casing and test point construction so permit) 
whether the short is at one of the two ends or is well inside the casing. This is discussed 
in Chapter 5. With a contact at one of the two ends, that end may be uncovered, the end 
seal removed and the short circuit cleared. This may require jacking the pipe and casing 
apart and inserting additional insulating spacers. Usually, when the contact is at one 
end, its location and cause are obvious once uncovered and the end seal is removed. The 
casing end seal should be replaced after the short circuit is cleared and before backfilling. 



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Foreign Line Crossings 271 



If tests indicate that the point of contact is well back from the end of the casing, the 
chances are that it cannot be cleared with any reasonable effort and expense by working 
from the casing ends. To safeguard the carrier pipe inside such nonclearable casings, 
the favored procedure is to fill the entire annular space between pipe and casing with a 
material that will stifle any corrosion tendency Proprietary casing compounds (greases 
containing chemical inhibitors) may be used. Companies routinely provide both casing 
filler compounds and installation of these products. 



FOREIGN LINE CROSSINGS 



Resistance bonds installed between pipelines for intersystem interference correction re- 
quire periodic checking (the ones carrying larger amounts of current should be checked 
frequently). Resistance bonds may be subject to occasional burn-out in the event of high 
current surges. Prompt replacement is required. 

Probably the most important item of preventive maintenance is the timely exchange 
of operational information resulting from changes in corrosion control systems on exist- 
ing foreign lines and for new foreign pipeline construction where foreign lines may cross 
or closely approach the corrosion engineer's system. This information may be obtained 
by direct contact with the foreign line companies involved and /or through electrolysis 
committees active in the area. Early information exchange allows planning for coop- 
erative interference tests, design of corrective bonds, or other necessary measures to 
mitigate interference damage caused to either party. 

The matter of information exchange is equally important in stray current electroly- 
sis areas. Advance information on changes in operating schedules, discontinuation, or 
moving of DC substations are most important. This information will make it possible to 
coordinate testing and install any required modifications in the corrosion control system 
to mitigate stray current problems. 



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Chapter 



Microbiologically Influenced 
Corrosion 



Brenda J. Little and Patricia Wagner 



INTRODUCTION 



Microbiologically influenced corrosion (MIC) is corrosion resulting from the presence 
and activities of microorganisms, including bacteria and fungi. Jack et al. (1996) reported 
that MIC was responsible for 27% of the corrosion deposits on the exterior of line pipe 
in one survey of Nova Gas Transmission Ltd. (Calgary, Alberta) lines. Pope and Morris 
(1995) reported that almost all cases of MIC on external surfaces of pipes were asso- 
ciated with disbonded coatings (Figure 14.1). The following general statements about 
microorganisms are taken directly from Pope (1986): 

1 . Individual microorganisms are small (from less than 0.2 to several hundred micro- 
meters (^m) in length by up to 2 or 3 /urn in width) a quality which allows them to 
penetrate crevices and other areas easily. Bacterial and fungal colonies can grow to 
macroscopic proportions. 

2. Bacteria may be motile, capable of migrating to more favorable conditions or away 
from less favorable conditions, that is, toward food sources or away from toxic 
materials. 

3. Bacteria have specific receptors for certain chemicals which allow them to seek out 
higher concentrations of those substances that may represent food sources. Nutri- 
ents, especially organic nutrients, are generally in short supply in most aquatic en- 
vironments; but surfaces, including metals, adsorb these materials, creating areas of 
relative plenty. Organisms able to find and establish themselves at these sites will 
have a distinct advantage in such environments. 

4. Microorganisms can withstand a wide range of temperatures (at least —10 to 99 °C), 
pH (about 0-10.5) and oxygen concentrations (0 to almost 100% atmospheres). 



273 



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274 



Microbiologically Influenced Corrosion 




Figure 14.1 Disbonded pipeline coating associated with external localized MIC. (Courtesy 
Dan Pope, Bioindustrial Technologies, Inc.). 



5. They grow in colonies which help to cross-feed individuals and make survival more 
likely under adverse conditions. 

6. They reproduce very quickly (generation times of 18 min have been reported). 

7. Individual cells can be widely and quickly dispersed by wind and water, animals, 
aircraft, and other means, and thus the potential for some of the cells in the population 
to reach more favorable environments is good. 

8. Many can quickly adapt to use a wide variety of different nutrient sources. For 
example, Pseudomonasfluorescens can use more than 100 different compounds as sole 
sources of carbon and energy including sugars, lipids, alcohols, phenols, organic 
acids, and other compounds. 

9. Many form extracellular polysaccharide materials (capsules or slime layers). The 
resulting slimes are sticky and trap organisms and debris (food), resist the penetration 
of some toxicants (e.g., biocides) or other materials (corrosion inhibitors) and hold 
the cells between the source of the nutrients (the bulk fluid) and the surface toward 
which these materials are diffusing. 

1 0. Many bacteria and fungi produce spores which are very resistant to temperature 
(some even resist boiling for more than 1 h), acids, alcohols, disinfectants, drying, 
freezing, and many other adverse conditions. Spores may remain viable for hundreds 



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Mechanisms for MIC 275 



of years and germinate on finding favorable conditions. In the natural environment, 
there is a difference between survival and growth. Microorganisms can withstand 
long periods of starvation and desiccation. If conditions are alternating between 
wet and dry, microbes may survive dry periods but will grow only during the wet 
periods. 
11. Microorganisms are resistant to many chemicals (antibiotics, disinfectants, etc.) by 
virtue of their ability to degrade these chemicals or by being impenetrable to them 
because of slime, cell wall, or cell membrane characteristics. Resistance may be easily 
acquired by mutation or acquisition of a plasmid (essentially by naturally occurring 
genetic exchange between cells, i.e., genetic engineering in the wild). 



MECHANISMS FOR MIC 



It is established that the most aggressive MIC takes place in the presence of microbial con- 
sortia in which many physiological types of bacteria, including metal-oxidizing bacteria, 
sulfa te-reducing bacteria (SRB), acid-producing bacteria (APB), and metal-reducing bac- 
teria (MRB) interact in complex ways within the structure of biofilms (Figure 14.2) (Little 
et al. 1991). MIC does not produce a unique form of localized corrosion. Instead, MIC 
can result in pitting, crevice corrosion, underdeposit corrosion and selective dealloying, 
in addition to enhanced galvanic and erosion corrosion. The principal effect of bacte- 
ria under aerobic conditions is to increase the probability that localized corrosion will 
be initiated. Bacteria can set up the proper conditions for pitting or crevice corrosion. 
Once localized corrosion has been initiated, microbial reactions can maintain proper 
conditions (e.g., low oxygen) for continued pit/crevice growth. The rate at which pits 
propagate can be governed by organic acid production by fungi in aerobic environ- 
ments and by certain bacteria in anaerobic environments. Under anaerobic reducing 
conditions, aggressive MIC is observed when there is some mechanism for the removal 
or transformation of corrosion products (i.e., there are switches from stagnation to flow 
or from anaerobic to aerobic conditions). The following discussion about individual MIC 
mechanisms will be related directly to carbon steel. 



Sulfate Reduction 



SRB are a diverse group of anaerobic bacteria that can be isolated from a variety of sub- 
surface environments. If the aerobic respiration rate within a biofilm is greater than the 
oxygen diffusion rate during biofilm formation, the metal /biofilm interface can become 
anaerobic and provide a niche for sulfide production by SRB (Figure 14.3). The critical 
thickness of the biofilm required to produce anaerobic conditions depends on the avail- 
ability of oxygen and the rate of respiration. SRB concentrations are always correlated 
with groundwater sulfate concentration. The distribution of favorable pH ranges from 
6 to 12, although they can mutate to accommodate pH conditions. SRB grow in soil, 



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Microbiologically Influenced Corrosion 



Bulk Water 



(CH 2 0) n 




(CH 2 0) n 



-^►C0 9 + H,0 



(CH 2 0) n 



^alcohols 
organic acids 



( CH 2°)n 




(Clostridia, propionibacterium) 
> CH 4 organic acids > butanol 



-►S" 



► CO ? + H. + RCOOH 

fermenters d L 



acetone 
ethanol 
isopropanol 
propionic acid 
acetic acid 
CO, 



sulfate-reducing 
bacteria 



Fe" 



iron-reducing 
bacteria 



Figure 1 4.2 Strata within a typical biofilm and possible reactions within the strata. 



fresh water, or salt water under anaerobic conditions. Many species of SRB have been 
identified, differing in morphology and in organic substances that they can metabolize. 
They have in common the ability to oxidize certain organic substances to organic acids 
or carbon dioxide by reduction of inorganic sulfate to sulfide. In the absence of oxygen, 
the metabolic activity of SRB causes accumulation of sulfide near metal surfaces. This is 
particularly evident when metal surfaces are covered with biofilms. The concentration of 
sulfide is highest near the metal surface. Iron sulfide forms quickly on carbon steels and 
covers the surface if both ferrous and sulfide ions are available. Formation of iron sulfide 
minerals stimulate the cathodic reaction. Once electrical contact is established, a galvanic 
couple develops with the mild steel surface as an anode, and electron transfer occurs 
through the iron sulfide. At low ferrous ion concentrations adherent and temporarily 
protective films of iron sulfides are formed on the steel surface, with a consequent re- 
duction in corrosion rate. Aggressive SRB corrosion requires exposure to oxygen. Hardy 
and Bown (1984) demonstrated that corrosion rates of mild steel in anaerobic cultures 
of SRB were low (1.45 mg/dm 2 /day). Subsequent exposure to air caused high corrosion 



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Mechanisms for MIC 



277 



3500 



3000 



2500 



£ 2000 

E 
o 

■| 1500 

LU 

O 

i 1000 
P= 

en 

Q 

500 



-500 



Dissolved oxygen 
. Sulfide 
pH 




12 3 4 

Dissolved oxygen concentration (mg/L) 



-7 -6 -5 -4 

Log of total sulfide concentration (mol/L) 



Figure 1 4.3 Concentration profiles of sulfide, oxygen, and pH in a biofilm on carbon steel. 
(From Biofouling, 1993. Reprinted with permission from Overseas Publishers Association 
(OPA) and Gordon and Breach Publishers.) 



rates (129 mg/dm 2 /day). Accordingly, structures that are exposed under fully deaer- 
ated conditions generally experience low corrosion rates despite the presence of high 
concentrations of SRB. 



Acid Production 



Organic acids can be produced by both bacteria and fungi. Most of the final products of 
MIC community metabolism are short-chained fatty acids like acetic acid that are very 
aggressive in the attack of carbon steel, and become especially aggressive when concen- 
trated under a colony or other deposit. This type of attack is accelerated by the addition 
of chloride. The resulting chloride-rich corrosion products have a greater volume and are 
less stable, often flaking from the surface. Other bacterial species can produce aggressive 
inorganic acids, such as H2SO4. Microorganisms in the soil may generate high concen- 
trations of carbon dioxide. The carbon dioxide dissolves in the groundwater, producing 
carbonic acid. Carbonic acid solution is very corrosive to pipeline steels and can lead to 
general attack, pitting attack, and stress corrosion cracking. 



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Microbiologically Influenced Corrosion 



Metal Deposition 



Microorganisms can also affect corrosion by creating differential aeration cells on the 
surface of the metal and fixing the location of anodic sites beneath colonies of microor- 
ganisms. The organisms most often cited as causing differential aeration cells are those 
organisms capable of depositing iron and manganese oxides. 

Manganese oxidation and deposition is coupled to cell growth and metabolism of or- 
ganic carbon. The reduced form of manganese (Mn +2 ) is soluble and the oxidized forms 
(Mn203, MnOOH, MnsC^, Mn02) are insoluble. As a result of microbial action, man- 
ganese oxide deposits are formed on buried or submerged materials including metal, 
stone, glass, and plastic, and can occur in natural waters that have manganese con- 
centrations as low as 10 to 20 ppb (Figure 14.4). For mild steel corrosion under anodic 
control, manganese oxides can elevate corrosion current. The current may be signifi- 
cant for biomineralized oxides that provide large mineral surface areas. Given sufficient 




Figure 14.4 Black manganese dioxide deposits on 
carbon steel caused by metal-depositing bacteria. 



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Mechanisms for MIC 



279 




J.J^ 'Mi) h ••" , 



Figure 1 4.5 Tubercules on carbon steel. 



conductivity, manganese oxide may serve as a cathode to support corrosion at an oxygen- 
depleted anode within the deposit. 

Iron-oxidizing bacteria produce orange-red tubercles of iron oxides and hydroxides 
by oxidizing ferrous ions from the bulk medium or the substratum (Figure 14.5). Iron- 
depositing bacteria are microaerophilic and may require synergistic associations with 
other bacteria to maintain low oxygen conditions in their immediate environment. De- 
posits of cells and metal ions create oxygen concentration cells that effectively exclude 
oxygen from the area immediately under the deposit and initiate a series of events that 
individually or collectively are very corrosive. In an oxygenated environment, the area 
immediately under individual deposits becomes deprived of oxygen (Figure 14.6). That 
area becomes a relatively small anode compared to the large, surrounding oxygenated 
cathode. Cathodic reduction of oxygen may result in an increase in pH of the solution in 
the vicinity of the metal. The metal will form metal cations at anodic sites. If the metal 
hydroxide is the thermodynamically stable phase in the solution, the metal ions will be 
hydrolyzed by water, forming H + ions. If cathodic and anodic sites are separated from 
one another, the pH at the anode will decrease and that at the cathode will increase. The 
pH at the anode depends on specific hydrolysis reactions. In addition, Cl~ ions from the 
electrolyte will migrate to the anode to neutralize any buildup of charge, forming heavy 
metal chlorides that are extremely corrosive. Under these circumstances, pitting involves 



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280 



Microbiologically Influenced Corrosion 




Figure 1 4.6 Possible reactions under tubercles created by metal-deposit- 
ing bacteria. 



the conventional features of differential aeration, a large cathode-to-anode surface area, 
and the development of acidity and metallic chlorides. Pit initiation depends on mineral 
deposition by bacteria. Pit propagation is dependent not on activities of the organisms, 
but on metallurgy. 



Metal Reduction 



Dissimilatory iron and /or manganese reduction occurs in several microorganisms, in- 
cluding anaerobic and facultative aerobic bacteria. Inhibitor and competition experi- 
ments suggest that Fe +3 and Mn +4 are efficient electron acceptors that are similar to 
nitrate in redox ability and are capable of out-competing electron acceptors of lower 
potential, such as sulfate or carbon dioxide (Meyers 1988). MRB in direct contact with 
solid iron (Fe +3 ) and manganese (Mn +4 ) oxides produce soluble ions (Fe +2 and Mn +2 ). 
The result is dissolution of surface oxides and localized corrosion that was described by 
Obuekwe et al. (1981) as anodic depolarization. 



MIC ON PIPELINES 
Environment 



The potential for MIC on buried pipelines is controlled by availability of nutrients, water, 
and electron acceptors. Peabody (1967) reported data from Harris (1960) indicating that 



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MIC on Pipelines 



281 



soil moisture content and bacterial cell counts were greater in backfill material than in 
undisturbed earth adjacent to a pipeline. Trench backfill is not as consolidated and al- 
lows greater penetration of moisture and increased oxygen diffusion. Anaerobic bacteria 
thrive in waterlogged, dense soil. Alternating moisture and oxygen concentrations will 
influence the growth of bacterial populations. Despite the numerous mechanisms that 
one would predict for MIC of buried pipelines, most failures have been attributed to 
the presence and activities of SRB and APB. In general, sandy soils favor APB; high clay 
soils support populations of both kinds of organisms. To protect against all forms of 
external corrosion and cracking, several coating materials are used including asphalts, 
poly olefin tapes, and fusion-bonded epoxies (FBE). Line pipe is further protected by 
an impressed current or cathodic protection (CP). MIC can occur in the presence of these 
preventative measures. 



Coatings 



Because of differing environmental conditions (e.g., soil moisture, microflora, nutrients) 
in both field surveys and laboratory experiments, it is extremely difficult to interpret 
comparisons of coating performance. Soil stress or tenting along irregularities on the 
pipe surface, especially at long seam or girth welds, can create gaps between the tape 
and the pipe surface that fill with ground water and introduce microorganisms that create 
corrosion cells under the disbonded coating. Tenting is most prevalent in wet high clay 
soils, on unstable, geologically active slopes and downstream compressor stations. High 
service temperatures also promote disbonding. Not all coating materials are affected by 
soil bacteria under all conditions. Coatings derived from both coal (tars) and petroleum 
(asphalts) pass some exposure tests and fail others. Materials which by themselves show 
resistance to attack by microorganisms fail when combined or reinforced with other 
materials. 

Peabody (1967) reported that coal tars, coal tar epoxies, and coal tar enamels were 
immune to disbonding because of activities of microorganisms. Early coatings based on 
asphalt were subject to oxidation and loss of low-molecular weight components through 
biodegradation and biodeterioration, resulting in a permeable, embrittled coatings (Jack 
et al. 1996). Pendrys (1989) demonstrated that with time asphalt could be degraded 
by microorganisms selected from soil. Harris (1960) demonstrated that bacteria found 
commonly in pipeline soils can degrade asphalt, tape adhesives, kraft paper (expendable 
once line is in place), and binders and fillers used in felt pipeline wrappers. The next 
generation coatings were based on polyolefin tapes made of polyvinyl chloride (PVC) 
or polyethylene (PE). The PVC tape was unstable in service. Plasticizers constitute up 
to 50% of a PVC product and can be effectively lost through biodeterioration and water 
dissolution. Tape coatings rely on adhesives to attach the polyolefin layer to the primed 
steel surface. 

Jack et al. (1996) demonstrated that certain coatings disbonded more readily after 
being exposed to soils containing SRB and APB. PE coating damage proceeded lin- 
early with time. PE tape coatings supported higher bacterial counts than extruded PE 



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282 Microbiologically Influenced Corrosion 



or fusion-bonded epoxy (FBE), presumably because of the presence of biodegradable 
adhesive /primer components in the paint system. Susceptibility to disbonding increased 
in the order: FBE, extruded PE, and PE tape. Two types of coating damage were reported: 
damage due to water leaching and permeation, which affect intact coatings and coating 
around holidays. FBE coatings were damaged with increased susceptibility to cathodic 
disbondment at existing holidays. 

The most prevalent mechanism for the observed corrosion in a study reported by 
Jack et al. (1996) was formation of a galvanic couple between microbiologically produced 
iron sulfides and steel. The couple is normally short-lived because the iron sulfide matrix 
becomes saturated with electrons derived from the corrosion process. In the presence of 
SRB, however, the corrosion process is perpetuated because SRB can remove electrons in 
the corrosion process from the iron sulfide surface. This process may involve formation 
of cathodic hydrogen on the iron sulfide or direct transfer of electrons from the iron 
sulfide matrix to redox proteins in the bacterial cell wall. Corrosion rates associated with 
this mechanism were proportional to the amount of iron sulfide in the corrosion cell. 



Cathodic Protection 



Detection 



Cathodically polarized surfaces attract microorganisms, including SRB, so that, if the 
CP is interrupted MIC can occur at a higher rate than if CP were not previously present 
(Sanders and Maxwell 1983). MIC has at least three effects on CP of pipelines. First, where 
MIC activity is present, the potential level required to mitigate corrosion is moved to more 
negative values. Pope and Morris (Pope 1995) found that pipeline failures were often in 
contact with wet clays with little scaling potential, creating the situation in which the 
demand for CP continued at a high level over long periods of time and in which CP may 
not be distributed equally over the surface of holidays and surrounding disbondments. 
Microorganisms colonize and initiate corrosion at such sites. Research by Barlo and 
Berry (1984) showed that a potential of at least —950 mV (copper/copper sulfate) is 
required to mitigate MIC, as opposed to the standard NACE International criterion of 
—850 mV. Second, MIC can increase the kinetics of the corrosion reactions, increasing the 
CP current necessary to achieve a given level of polarization. Third, microorganisms can 
attack pipeline coatings, increasing exposed metal surface area and further increasing 
the CP current required to achieve a given level of polarization. Water intrusion at breaks 
in the coating may block CP. 



Because microorganisms are ubiquitous, the presence of bacteria or other microorgan- 
isms does not necessarily indicate a causal relationship with the corrosion. Microorgan- 
isms can always be cultured from natural environments but are not always the cause 
for corrosion found in their presence. Other factors must be considered in determining 
a cause and effect relationship. Areas of high SRB activity are generally very negative 



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References 283 



in potential and can be located by means of a native potential survey if the following 
conditions are met: (1) area of MIC activity must be large, (2) CP system must be off, 
and (3) coating cannot shield the metal surface. Once a suspected area of MIC has been 
located, the presence of bacteria can be confirmed by means of bell hole inspections in 
conjunction with the application of the analytical techniques described in NACE TPC 
Publication 3 in (NACE 1990), including culture methods and antibody analyses. A drop 
of dilute hydrochloric acid placed on corrosion product deposits will produce the odor of 
rotten eggs when sulfides are present. Detection of SRB or other bacteria in deposits as- 
sociated with accelerated corrosion does not conclusively establish a casual relationship 
between the bacteria and the observed corrosion (Little 1996). 



SUMMARY 



Backfill around pipelines provides an environment that supports microbial growth more 
than what is expected for undisturbed soil. Nutrients associated with coatings and 
cathodic polarization encourage microbial settlement on pipeline surfaces. Extensive 
analyses of field samples indicate that MIC of external surfaces of buried pipeline and 
other underground structures is most often associated with SRB and APB and disbonded 
coatings. 



ACKNOWLEDGMENTS 



Work was performed by the Office of Naval Research, Program Element 0601153N 
and Defense Research Sciences Program, NRL Contribution Number NRL/BA/7333- 
97-0056. 



REFERENCES 



T.J. Barlo, W.E. Berry. Materials Performance 23, 9, 1984, p. 9. 

J.A. Hardy, J.L. Bown. Corrosion 40, 1984, p. 650. 

J.O. Harris. Corrosion 16, 1960, p. 441. 

T.R. Jack, G. Van Boven, M. Wilmott, R. Worthingham. Materials Performance 35, 3, 1996, p. 39. 

T.R. Jack, M.J. Wilmott, R.L. Sutherby, R.G. Worthingham. Materials Performance 35, 3, 1996, p. 18. 

W. Lee, Z. Lewandowski, M. Morrison, WG. Characklis, R. Avci, P. Nielsen. Biofouling 7, 1993, 

p. 217. 

B.J. Little, R. Ray, P. Wagner, Z. Lewandowski, W.C. Lee, W.C. Characklis. Biofouling 3, 1991, p. 43. 

B.J. Little, PA. Wagner, K.R. Hart, R.I. Ray. Spatial Relationships Between Bacteria and Localized 

Corrosion. Corrosion/96, paper no. 278, Houston, TX: NACE International, 1996. 



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284 Microbiologically Influenced Corrosion 



Microbiologically Influenced Corrosion and Biofouling in Oilfield Equipment. TPC Publication 3, 
NACE International, Revised September 1990. 

C. Myers, K.H. Nealson, Science 240, 1988, p. 1319. 

CO. Obuekwe, D.W.S. Westlake, J.A. Plambeck, ED. Cook. Corrosion 37, 8, 1981, p. 461. 
A.W. Peabody. Control of Pipeline Corrosion, Houston, TX: NACE International, 1967, p. 173. 
J.P. Pendrys. Appl. Environ. Microbiol. 55, 6, 1989, p. 1357. 

D. Pope. A Study of Microbiologically Influenced Corrosion in Nuclear Power Plants and a Practical 
Guide for Countermeasures. Electric Power Research Institute Report NP-4582, May 1986. Palo 
Alto, CA. 

D.H. Pope, E.A. Morris III. Materials Performance 34, 5, 1995, p. 23. 

P.F. Sanders, S. Maxwell. Microfouling, Macrofouling, and Corrosion of Metal Test Specimens in 

Seawater. In: Microbial Corrosion, Teddington, UK: Metals Society, 1983, p. 74. 



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Chapter 



; 



Economics 



Ronald L. Bianchetti 



Good economics principles should be used in all pipeline corrosion work. To assure 
successful implementation of a corrosion control program, the corrosion engineer must 
be able to express the benefits in terms that management can understand, and that is 
through economic analysis. 

Over the years the cost of implementing a corrosion control system has proven to be 
extremely beneficial in the reduction of leaks and extension of the useful life of pipelines. 
Whether by using coating alone or coating with cathodic protection (CP), pipeline owners 
have obtained very good results when sound corrosion engineering is implemented. 
The additive cost for corrosion control typically represents a very small percentage of 
initial pipeline construction costs. With this in mind corrosion control systems should 
be implemented as a standard operating procedure for all buried pipeline systems to 
enhance the life of the asset. Some examples of economic considerations are discussed 
below. 



ECONOMIC COMPARISONS 



The prime objective in pipeline corrosion control work is to maintain a corrosion-free sys- 
tem at the lowest annual cost. The total annual cost is frequently used as a simple means 
of comparing the relative cost of alternate means of applying protection to sections of a 
pipeline system. This cost figure includes the annual cost of the capital invested plus the 
annual cost of operating and maintaining the system. To make annual cost comparisons 
that are valid, the pipeline corrosion engineer must know the various component cost 
items with reasonable accuracy. 



Existing Pipelines 



When CP is planned for existing pipelines that have an established leak history, it is 
possible to forecast the number and cost of probable leaks that may occur if CP were not 



285 



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286 Economics 



applied to the total cost of CP. These costs are evaluated for a period of time, typically 
20 to 50 yr. 



New Pipelines 



Where CP is installed at the time a pipeline is built, there will be no leak history on 
which to base the type of comparison previously mentioned. However, established leak 
histories of other pipelines in the same area can be a valuable guide to indicate the 
probable savings to be gained by installing CP 

Comparisons can be made for planned pipelines where the choice is between in- 
stalling CP initially, or installing the pipeline without CP but providing a corrosion 
allowance such as an extra ^-inch pipe-wall thickness beyond that needed for design 
operating conditions. The comparison may be based on the annual cost of the CP on 
the thinner wall pipe versus the annual cost of the investment for the additional steel in 
the pipe having the corrosion allowance. The probability should be recognized that the 
pipe having the extra wall thickness ultimately would reach the point where it, too, will 
require CP. 



Cost of Money 



The cost of money invested for CP installations or other corrosion control measures 
is usually developed by the company financial specialists. The money used for such 
investments can cost more than the simple interest rate. Included also in the cost are 
such items as taxes and depreciation that increase the real cost to the company of the 
money invested. 

There can be a difference between the cost of money used for installations made under 
capital expenditure funding versus those made using maintenance funds. The corro- 
sion engineer should determine the difference, because corrosion control installations 
may be capitalized in some instances (for new pipeline construction) and considered as 
maintenance costs in others. 



Establishing Initial Cathodic Protection System Cost Estimates 

When evaluating economic comparisons, estimates of the total installed cost of alternate 
systems (galvanic anodes versus impressed current) should be considered. Validity of 
the economic comparisons will depend largely on the accuracy of the cost figures used 
in compiling the estimates. 

An estimate for the installed cost of a CP system includes such items as the following: 

• Engineering time and associated expenses for field-testing, design, and preparation of 
plans and specifications. 



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Economic Comparisons 287 



• Cost of materials plus the overhead expense to cover purchasing and storage costs. The 
overhead factor or other means of determining these costs should be decided for the 
particular company. 

• Cost of right-of-way acquisition, if involved. This includes cost of right-of-way ease- 
ments, time and expenses for right-of-way procurement personnel, and crop damage 
where applicable. 

• Unit construction costs for the various components of the systems to be installed. The 
corrosion engineer will need to establish a working file on costs. If installations are to 
be made by company crews, review the proposed work with appropriate company 
personnel for their estimates of all charges that would be made against a work order 
for the installation. If possible, the estimate should be broken down into unit costs 
(such as trenching cost per foot, cost per anode for installation, etc.). 

If installations are to be made by a CP construction contractor, that person may be 
willing to provide scoping estimates. The new corrosion engineer may be able to obtain 
estimating figures from experienced corrosion engineers with neighboring pipeline sys- 
tems who have direct knowledge of applicable contract construction costs in the same 
general area. Where corrosion-engineering consultants are used, they can assist the new 
corrosion engineer by providing established reliable figures for cost estimating purposes. 

• Inspection time and associated expenses on the part of the corrosion engineer during 
the actual construction phase. 

• Completed system check out and associated expenses of the corrosion engineer to verify 
adequate protection is being achieved. Performing CP current output adjustments as 
necessary and conducting cooperative interference tests as may be necessary. 

Establishing On-Going Operating Cost Estimates 

Estimates for the annual operating costs for a pipeline CP installation should include 
such items as the following: 

• Power costs where rectifiers are to be used as a current source. Applicable power com- 
pany rates for the appropriate class of service should be known. If minimum monthly 
rates apply, they should be taken into account. This usually applies to small rectifier 
installations. In some instances, however, if the electric company has to build a long 
power line extension to serve the rectifier, it may establish a fairly substantial mini- 
mum monthly billing over a period of years to recover the cost of the line extension. 
Where other current sources using an outside source of energy are used (thermo- 
electric generators for example), the cost of fuel required to operate the device must 
be determined. 

• Maintenance and system checkout costs include time and associated expenses for rou- 
tine operational checks (particularly applicable for systems using rectifiers or other 
DC power sources subject to relatively frequent inspection); time and expense for 



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288 Economics 



periodic corrosion surveys along that section of the system protected by the proposed 
installation; and an estimate for time, expenses, and materials for corrective repair 
work. 



COST COMPARISON EXAMPLES 

To illustrate cost comparisons of different CP systems the following examples are pre- 
sented to assist the corrosion engineer. 



Comparing Alternative Cathodic Protection Systems 

Assume a new 50-mile well-coated pipeline to be cathodically protected. Initial corro- 
sion survey tests show that protection can be obtained with 2 A from a single rectifier 
installation near the center of the line or with 1.5 A from three magnesium anode in- 
stallations distributed along the line. Less current is required for the magnesium anode 
system because of reduced attenuation resulting from distributed installations. 



Impressed Current System 

On the basis of the corrosion survey, it has been determined that the rectifier can be in- 
stalled at a location where soil conditions are such that a ground bed with three vertical 
anodes at 20-ft spacing can be placed 300 ft from the pipeline. This system will provide 
the required 2 A at 5 V. Electric service is available at the installation site and the appli- 
cable power rate is 3.5 cents per kwh for the first 250 kwh per month with a minimum 
monthly bill of $2.50. (Power costs vary from area to area. Actual local rates should be 
determined.) Right-of-way acquisition will be necessary. 



Galvanic Anode System 

At the three magnesium anode installations, assume that the initial corrosion survey data 
have shown that installation sites are available. Soil conditions at the three installations 
will produce 0.5 A of protection current (with the pipe at protected potentials) using five 
20-lb packaged magnesium anodes at 15-ft spacing along the edge of the right-of-way 
15 ft from the pipe. No right-of-way costs will be incurred. 

To determine which type of installation will be the more economical, the pertinent 
costs can be compared as shown in Table 15.1. It is assumed that the necessary steps 
have been taken to obtain reliable estimating figures and that this final comparison 
summarizes and compares the cost data obtained. 



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Cost Comparison Examples 289 



$2400 


$1950 


$1000 


- 


$4700 


$4500 


$1500 


$1500 


$2500 


$1500 


$13,165 


$10,418 


$1184 


$937 



Table 15.1 Economic Comparision Between Alternative CP Systems 

Total for 
Rectifier 3 Magnesium 

Description Installation Anode Installations 

A-INSTALLATION COSTS 

1. Time (1) and expense for field 

tests, design, plans and 

specifications $1065 

2. Cost of materials including 

10 percent for overhead 

3. Right-of-way acquisition costs 

4. Contract installation cost 

5. Time and expense for construction 

inspection 

6. Time and expense for system 

check-out (2) 

TOTAL INSTALLATION COST 

ANNUAL COST OF MONEY 
(Based on an assumed 4 percent 
for 15 year system life) 

B-OPERATING COSTS 

1. Power cost (3) 

2. Routine operational checks (4) 

3. Periodic corrosion survey 

4. Time, expenses and materials for 

corrective repairs (5) 

TOTAL ANNUAL OPERATING COST 

C-ECONOMIC COMPARISON 

ANNUAL COST OF MONEY (A) 
TOTAL ANNUAL OPERATING COST (B) 

TOTAL ANNUAL COST 

(1) Engineering time charges for operating company personnel include, normally, an overhead 
charge. This can be determined for the particular company involved. 

(2) Additional check-out time for rectifier installations to allow for additional interference checks. 
( 3 ) Power consumption is less than minimum billing which applies in this instance. 

( 4 ) Based on rect. readings every month. 
(5) Estimated annual repair cost. 



$100 


- 


$100 


- 


$700 


$500 


$50 


$50 


$950 


$550 


$1184 


$937 


$950 


$550 


$2134 


$1487 



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290 



Economics 



This comparison indicates that the three magnesium anode installations will have a 
lower annual cost than the single rectifier and would, therefore, be more economical. 
Although this is usually the case for lower current outputs (typically less than 2A) used 
in this example, a similar comparison should be made using the specific factors that 
apply to the pipeline corrosion engineer's own system. 

On the other hand if the amount of current required was higher, an impressed cur- 
rent system tends to become more economical than galvanic anode installations. This 
is because the additional investment for added rectifier output (in terms of dollars per 
ampere of capacity) does not increase as rapidly as that for galvanic anode installations. 



Comparing Leak Cost and Cathodic Protection Cost 

When a section of pipeline system starts to develop leaks, experience has shown that 
further leaks will develop at a continuously increasing rate. If the accumulated number 
of leaks repaired is plotted on semilog paper against pipeline age in years, a straight 
line is the usual result where accurate leak records are available (Figure 15.1). In this 



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YEARS AFTER PIPELINE INSTALLATION 
Figure 15.1 Cumulative number of leaks without CR 



24 



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Cost Comparison Examples 291 



instance, the first leak did not develop until the line was 4-yr old and a total of only seven 
leaks had developed by the time the pipeline was 12-yr old. A definite trend has been 
established, which shows that in the next 10-yr there will be approximately 70 new leaks, 
if corrosion is not controlled. The figure also shows that the number of leaks developing 
each year is increasing at such a rate that the pipeline may become inoperable if the trend 
is not stopped. 

The application of CP as shown in Figure 15.1 can mitigate development of new leaks. 
The cost of operating a CP system(s) versus the cost of leaks over a period of time can 
then be economically evaluated. In the case illustrated (Figure 15.1), application of CP 
at the end of the 12 th year would eliminate approximately 70 new leaks over the next 
10-yr period. Thus a dollar figure can be developed to represent the cost savings for the 
anticipated leaks. 

To determine the cost of leaks several items should be considered. 

• The average cost of a leak repair on the pipeline under study. This should include 
labor, overhead, materials, transportation costs, and other attendant expenses. 

• An average cost for property damages associated with a simple corrosion leak repair. 
This can vary with the fluid in the pipeline. Such damages tend to be substantially 
higher, if a pipeline is carrying petroleum or petroleum products versus natural gas. 

• The value of product lost from an average corrosion leak. This will depend on the 
product, the pipeline pressure, the average size of the leak, and the average length of 
time that/product escapes before the leak repair is accomplished. 

• Miscellaneous factors, such as insurance, good will, and other costs. 

The total average cost of each leak, will be the sum of the above items plus any associated 
costs that may be involved for the particular pipeline system under consideration. 

Now assume that a coated pipeline having the leak record represented by Figure 15.1 
is surveyed during its 12 th yr and that design calculations indicate that CP can be applied 
using a rectifier system. Further assume that the annual cost of the investment for CP 
plus annual operating costs will be $6,000 per year and it has been established that the 
average total cost of each leak repaired is $1500. Using these figures, if CP is applied at 
the end of the 12 th yr, comparative costs for the following 10-yr period are as follows: 

• Cathodic protection costs: 10 x $6000 = $60,000 

• Savings in leak repair costs: 70 x $1500 = $105,000 

This example indicates that, over the 10-yr period, there will be a net savings of $45,000 
with CP installed, if all leaks are avoided. 

Greater savings can be shown by projecting the comparison over a longer period 
because although CP annual costs remain reasonably uniform, the number of projected 
leaks over that longer period increases very rapidly. (Note, from Figure 15.1, that there 
would be approximately 20 new leaks in the 23 rd yr alone.) 



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292 Economics 



Now look at the comparison that would apply for the same pipeline if CP had been 
installed when the line was initially constructed. First, the annual cost of CP would be 
less because the new coating would be better initially Second, the coating should be 
substantially better after 12-yr. Third, the full 22-yr of pipeline life is considered in the 
annual cost analysis, so the annual cost allocation for CP would be $4,000. The total 
number of leak repairs saved, per Figure 15.1, would be 80 over the 22-yr period. The 
comparison now is as follows: 

• Cathodic protection costs: 22 x $4,000 = $88,000 

• Savings in leak repair costs: 80 x $1500 = $120,000 

Assuming that annual costs for CP have been estimated accurately, there is still a signifi- 
cant saving of $32,000 with CP. 

The previous comparison may be used as an argument in favor of deferring the 
application of CP until leaks have started to develop. This would only be valid if there 
was a guarantee that all leaks would be simple leaks, as assumed in the cost comparisons, 
with no risk of exceptional hazard. For pipelines carrying a hazardous product (such as 
natural gas or petroleum products), there is always the possibility of fire, explosion or 
loss of life if the leak should develop in the wrong place. Since these are possibilities only 
(although very real possibilities), a dollar figure cannot be attached readily to the direct 
cost that might be involved nor to intangible factors such as impaired public good will. 
Just one serious incident, if it should occur, can more than offset any apparent saving 
which could be gained by deferring application of CP until leaks start to develop. 

Comparing Cathodic Protection with Pipe Corrosion Allowance 

A corrosion allowance for example, an additional ^ of an inch of pipe wall thickness 
(above that needed for pipeline operating considerations) may be considered in lieu of 
applying CP. This practice is not recommended for underground pipelines, because it 
does not provide a permanent means of corrosion control but only defers the time when 
a leak will occur. 

Ground Bed Cable Sizing and Anode Spacing 

Economic considerations apply to various phases of CP system design. Sizing ground 
bed cables and determining the economic spacing for impressed current or galvanic 
anodes are particularly important instances. 

Ground Bed Cable Size 

Basically, ground bed cable can be increased in size as long as each incremental increase 
will show a dollar savings in terms of reduced annual power losses in the cable resistance 



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Cost Comparison Examples 293 



compared with the annual cost of the additional investment for the larger cable size. For 
rectifier installations, AC power losses (which determine the cost) are the DC power 
losses in the cable divided by the rectifier efficiency expressed as a decimal. 

As was discussed in Chapter 7, the effective resistance of the ground bed cable may 
be taken as that of the full length of cable between pipeline and first anode plus that of 
one-half the length of cable along the line of anodes. Power costs at rectifier installations 
are determined from the power company rate schedule. For small rectifier installations, 
which do not use enough power to exceed the minimum monthly billing, nothing is 
gained by using a larger cable size than is necessary for adequate mechanical strength. 
No. 8 AWG header cable (the same size as the usual anode pigtail cable) may be con- 
sidered the smallest practical size, although some operators may elect to use no smaller 
than No. 4 AWG cable for header cable construction. 

Power costs at galvanic anode installations vary with the size and type of installa- 
tion but can be reduced to a cost per kilowatt-hour (kWh). This is performed by first 
determining the kWh lifetime output of the installation by the expression. 

kWh = driving voltage x amps output x 8.76 x installation life in years. 

The cost per kWh is then the installation cost in dollars divided by the expected total 
lifetime power output in kWh. 

Although the cost per kWh for a galvanic anode installation usually will be several 
dollars compared with only a few cents at a rectifier installation (where the monthly 
minimum bill is exceeded), there may be no economic advantage in using cable larger 
than needed for strength. This is because the square of the current output of a small 
galvanic anode installation may be very small compared with that of a rectifier instal- 
lation (and in addition there is much less cable in the usual galvanic anode installation 
than in the typical rectifier ground bed). 



Anode Spacing 



Based on the information on ground bed design discussed in Chapter 7, it is recognized 
that for soil of uniform resistivity, two boundary conditions for anode spacing exist. 
These are the following: 

• The parallel resistance of two vertical ground bed anodes placed side by side will be 
only slightly less than the resistance of one anode alone. 

• The parallel resistance of two vertical ground bed anodes placed electrically far apart 
will be approximately one-half the resistance of one anode alone. 

Both of these boundary conditions are not economical. The most economical anode 
spacing is somewhere between these two conditions. 

Using proper materials, right-of-way procurement, installation, and power costs, 
the pipeline corrosion engineer can make an economic analysis to determine the most 



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294 



Economics 



co^ 

if 

— CO 



CO : 

o ; 

O 



:1 

_J CD 

Sen 
z O 




10 15 20 

ANODE SPACING IN FEET 



Figure 1 5.2 Typical plot for economical anode spacing. 



favorable spacing for installations. This may be done by calculating, for a typical ground 
bed resistance in typical soil resistivity, the annual cost of the total investment required 
for constructing a ground bed at several different anode spacing points. The annual cost 
of power losses in the cable should be added to the annual cost of the investment. By 
plotting a total annual cost versus the cost of anode spacing, a curve will be obtained 
which may appear somewhat as indicated in Figure 15.2. Although the results may vary 
with costs applicable to a particular system, economical anode spacing of 20 to 25 ft is 
typical for rectifier ground bed construction. 



ECONOMICS OF GOOD MAINTENANCE 



The most obvious economic contributor is good maintenance. This means maintaining 
all CP installations and other corrosion control facilities in optimum operating condition 
and making sure that full protection is being given the system for the maximum practica- 
ble percentage of the time. This is a necessity for proper system performance. Without 
proper maintenance and system performance the initial investment is not optimized, 
and the cost of the corrosion control investment represents a wasted expenditure. This 
is not an acceptable practice and is highly discouraged. 

Maintenance economics applies to equipment use in CP installations. At rectifier 
installations particularly, as discussed in Chapter 8, economies can be gained by replacing 
rectifying elements (stacks) in older units with new more efficient elements when the 
annual saving in power cost is greater than the annual cost of the investment for the 



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Coating Economics 295 



new stacks. In extreme cases involving large single-phase rectifiers, changing the single- 
phase unit for a more efficient three-phase rectifier may prove economical on the annual 
cost basis if three-phase power is available. 



COATING ECONOMICS 



Chapter 2 emphasized that the most favorable coating system for any given pipeline 
is the most stable of those available — that is, the coating system with electrical and 
mechanical characteristics that will deteriorate at the slowest rate with time under the 
specific installation conditions. Such a coating used with a CP system will be the most 
economical combination. 

Even the most stable pipeline coating system selected will suffer some deteriora- 
tion with time. Designing and constructing the initial CP system with sufficient reserve 
capacity to allow for the expected increased current requirements from anticipated coat- 
ing degradation will result in overall cost savings. This saving tends to be greater in 
the case of rectifier installations where the cost of providing additional current output 
capacity can be substantially less than in the case of galvanic anode installations. 

The direct cost of the installations will be a function of the electrical resistivity of the 
coating used. An excellent stable coating properly applied should have a high electrical 
resistance. Current requirements should be so low that the cost of providing additional 
capacity will be minimal. On the other hand, a coating initially having a substantially 
lower electrical resistivity will require correspondingly greater investments for CP and 
the additional cost for reserve capacity becomes much more significant. 



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Chapter 



Fundamentals of Corrosion 



John A. Beavers 



INTRODUCTION 



The fundamentals of corrosion can be divided into the disciplines of thermodynamics 
and kinetics. Thermodynamics is used to indicate whether a specific corrosion process 
is possible and kinetics is used to understand and predict actual rates of corrosion. Both 
topics are discussed in greater detail in this chapter. 



THERMODYNAMICS 
Gibbs Free Energy 



As described in Chapter 1, a significant amount of energy is put into a metal when it is 
extracted from its ores, placing it in a high-energy state. These ores are typically oxides 
of the metal such as hematite (Fe203), for steel or bauxite (AI2O3 • H20), for aluminum. 
One principle of thermodynamics is that a material always seeks the lowest energy state. 
In other words, most metals are thermodynamically unstable and will tend to react with 
something in their environment (e.g., oxygen or water) in order to reach a lower, more 
stable energy state such as an oxide. As an analogy, consider a baseball. As you raise 
the baseball in your hand, you are increasing the energy level of the ball. In the case of 
gravitational energy, the energy U = mgh in which m is the mass of the ball, g is the 
gravitational constant, and h is the height of the ball. If you let the ball go at a height h\, 
it will fall to the floor, which is the lowest possible energy state. The change in energy 

ALT = ITfinai - LZinitiai = mg(0) - mghi = -mgh x (1) 

In other words, the change in energy is negative. A more general term for the energy 
of a system is the Gibbs Free Energy which uses the symbol G. For a process such 

297 



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298 Fundamentals of Corrosion 



as corrosion to be spontaneous, AG must be negative. Unfortunately, for most common 
metals in natural environments, AG < and the corrosion process is thermodynamically 
favored. 



Electrode Potentials 



The corrosion of most common engineering materials at temperatures near ambient 
usually involves water and is electrochemical in nature, as described in Chapter 1. The 
corrosion process occurs with the removal of electrons (oxidation) of the metal and 
the consumption of those electrons by some other reduction reaction, such as oxygen 
reduction 

Fe^Fe 2+ + 2e- (2) 

2 + 2H 2 + Ae~ -> 40H- (3) 

Note that arrows have been used in the oxidation and reduction reactions listed above 
indicating that we know the direction of the reactions. Since the oxidation and reduction 
reactions are different, the corrosion process is not reversible and is not at equilibrium. A 
system has attained a state of equilibrium when it shows no further tendency to change its 
properties with time. A corroding metal changes its state with time and is, by definition, 
not at equilibrium. 

The individual oxidation and reduction reactions are referred to as half-cell reactions 
and can occur locally at the same site on the metal or can be spatially separated. The free 
energy of each pair of half-cell reactions is related to a reversible electromotive force (E ) 
through the equation 

AG = -\z\FE (4) 

in which z is the valence change associated with the reaction and F is Faraday's constant. 
In other words, E is directly related to the driving force (the change in the Gibbs Free 
Energy) for the reaction. A positive value of E indicates that the change in Gibbs Free 
Energy is less than zero, and that the reaction is thermodynamically favored. 



CAUTION: This statement refers to an electromotive force between equilibrium re- 
actions and cannot be directly related to a pipe-to-soil (P/S) potential measurement. 
P/S potentials are generally negative under corrosive conditions when measured 
with a copper sulfate reference electrode. 



The electromotive force (EMF) is a potential and can be calculated for any set of two half- 
cell reactions using Equation (4) and standard thermodynamic data for the reactions 



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Thermodynamics 299 



involved. The hydrogen reduction reaction 

2H + + 2e- =H 2 (5) 

has been arbitrarily set at 0.00 V for the series, allowing for the calculation of the EMF of 
individual half-cell reactions. 

A compilation of these EMFs and half-cell reactions, calculated for the reactants at 
unit activity, is referred to as the electrochemical or EMF series. The activity of a species 
is a measure of its effective concentration in solution and the activity is equal to the 
concentration for an ideal solution. When the reactions are written as reduction reactions, 
the most positive members of the series are the noble metals such as gold and platinum, 
and the most negative members of the series are the active metals such as sodium and 
magnesium (see Table 16.1). Note that, in addition to metal reactions, the series also 
contains reactions for common oxidants found in corrosion such as oxygen. 

The potential of any two half-cell reactions can be calculated as shown in the following 
equation, where the EMF series is written as reduction reactions 

^ = ^(reduction) ~~ ^(oxidation) W 



Table 1 6.1 Standard Electrochemical Series for Some Common 
Metals and Reactions 







Standard Reduction 




Reaction 


Potential V (SHE) 


t 


Au 3+ + 3e~ = Au 


+1.498 


Noble 


Pt 2+ + 2e~ = Pt 


+1.200 




Pd 2+ + 2e~ = Pd 


+0.987 




Ag+ + e~ = Ag 


+0.799 




Hg 2+ + 2e~ = 2Hg 


+0.788 




2 + 2H 2 + 4e-=40H- 


+0.401 




Cu 2+ + 2e~ = Cu 


+0.337 




2H+ + 2e~ = H 2 


0.000 




Pb 2+ + 2e~ = Pb 


-0.126 




Sn 2+ + 2e~ = Sn 


-0.136 




Ni 2+ + 2e~ = Ni 


-0.250 




Co 2+ + 2e~ = Co 


-0.277 




Cd 2+ + 2e~ = Cd 


-0.403 




Fe 2+ + 2e~ = Fe 


-0.440 




Cr 3+ + 3e~ = Cr 


-0.744 




Zn 2+ + 2e~ = Zn 


-0.763 




Al 3+ + 3e~ = Al 


-1.662 




Mg 2+ + 2e~ = Mg 


-2.363 


Active 


Na+ + e~ = Na 


-2.714 


1 


K+ + e~ = K 


-2.925 



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300 Fundamentals of Corrosion 



For example, for the reactions; Au 3+ + 3e = Au and Al = Al 3+ + 3e , the potential is 

E° = 1.498 - (-1.662) = 3.160 V (7) 

Since the EMF is positive, AG < 0, and the reactions will proceed as written. Had the 
direction of the reactions been reversed, the calculated EMF would have been negative, 
indicating that the reactions would not proceed as written. Therefore, with this informa- 
tion, one can use the series to determine whether a set of reactions is possible. Corrosion 
of a metal in the presence of a possible oxidant will occur if the reduction potential of the 
metal is less positive than the reduction potential of the oxidant. For example, oxygen 
reduction cannot support corrosion of gold but can promote corrosion of the common 
materials of construction such as iron. 

The EMF series is calculated for the reactants at unit activity. These potentials shift 
as a function of concentration according to the Nernst equation. For any electrochemical 
reaction 

aA+bB =cC+dD (8) 

\z\F (a A ) a (a B y 

in which E is the cell potential, E ° is the standard cell potential, R is the gas constant, 
T is the absolute temperature, \z\ is the number of electrons transferred, F is Faraday's 
constant, and (acf is the activity of species C raised to the c power. 

As described in the preceding section, the EMF series can be generated from standard 
thermodynamic data. In theory, the EMF series also could be generated experimentally 
by measuring the potential difference between each of the metals at equilibrium in so- 
lutions of unit activity and the hydrogen electrode, as shown in Figure 16.1. When a 
potential is measured in this fashion, it is referred to as an electrostatic potential or 
a standard electrode potential, rather than an EMF. The hydrogen electrode consists 
of an inert platinum wire immersed in an acidic solution of H + ions at unit activity 
with H2 gas bubbled through it at 1 atm. A shorthand description of the cell is often 
written 

Pt|H 2 /H + (fl = l)\\M n+ (a = 1)|M (10) 

and the potential of the cell is E° = F M/M n+ — Eh 2 /h+ = Em/m m+ - The solid vertical line 
represents a phase change (for example, between the metal M and the solution). The || 
indicates the presence of a porous barrier that allows electrical communication between 
the two half cells but minimizes mixing of the electrolytes. The superscript "°" on the E 
indicates that the potential is a standard electrode potential at unit activity (a =1). 

For the measurement to be accurate, the reactions must be at equilibrium, which 
implies that no net current can flow in the measurement circuit. This can be accom- 
plished by using a high input impedance voltmeter for the measurement. The hydrogen 



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Thermodynamics 



301 



Copper Wire Leads 
To High Impedance 
Voltmeter 




HCI Solution 



Silver Foil Covered 
With AgCI 



Figure 16.1 Hydrogen electrode (left side) and silver 
metal electrode in cell for standard EMF determination. 



electrode used as shown in Figure 16.1 is referred to as a reference electrode. In practice, 
a hydrogen reference electrode is rarely used because of the difficulty in constructing 
and maintaining the electrode. Other types of reference electrodes are described in the 
following section. 

In practice, standard electrode potentials cannot be measured for many metals be- 
cause they react with water; water is reduced and the metal is oxidized. Therefore, the 
metal cannot be present at equilibrium in aqueous solutions. These metals include iron 
and common anode metals such as aluminum, zinc, and magnesium. For these metals, 
the standard half-cell potentials are generated from thermodynamic data. 



Reference Electrodes 



One definition of a reference electrode is "a reversible electrode used for measuring 
the potentials of other electrodes". As described in the previous section, a reversible 
electrode must be at equilibrium, which means that there is no net change in the electrode 
over time. Desirable properties of a good reference electrode include the following: 

• Easy to use and maintain 

• Stable potential over time 

• Potential varies little with current flow (does not polarize readily) 

• Not easily contaminated 

• Does not contaminate what is being measured. 



The hydrogen electrode can be used as a reference electrode but it is cumber- 
some, even in the laboratory. Other common reference electrodes include silver-silver 



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302 Fundamentals of Corrosion 



Table 1 6.2 Potentials of Common Reference 
Electrodes 





Potential (V) 


Electrode 


@25°C 


Cu 2+ /CuS0 4 (Saturated) [CSE] 


+0.300 


Calomel (Saturated KC1) [SCE] 


+0.241 


Ag+/AgCl (Saturated KC1) 


+0.196 


Ag+/AgCl (0.6 M CI") [seawater] 


+0.250 


Standard Hydrogen Electrode [SHE] 


0.000 


Zinc (Seawater) 


-0.800 



chloride, calomel, and copper-copper sulfate. Their potentials are given in Table 16.2. 
Each reference electrode potential is based on the equilibrium reaction for the respective 
metal 

Ag + + e~ = Ag (silver-silver chloride) (11) 

Hg2+ + 2e~ = 2Hg (calomel) (12) 

Cu 2+ + 2e~ = Cu (copper-copper sulfate) (13) 

The potential of the reference electrode is dependent on the aqueous environment used. 
For example, silver-silver chloride reference electrodes are normally filled with potas- 
sium chloride (KC1) solution and can be purchased with KC1 concentrations ranging 
from 0.1 M up to saturated KC1, with a corresponding range of potentials. Since silver 
chloride (AgCl) has very limited solubility in KC1, the silver wire in the reference elec- 
trode is normally coated with AgCl to establish the equilibrium reaction and associated 
potential. 

The copper-copper sulfate reference electrode (CSE) is the most common reference 
electrode used for underground corrosion. It is frequently referred to as a half-cell based 
on the copper half-cell reaction. A schematic of the CSE is given in Figure 16.2. As shown 
in the figure, a heavy gauge copper wire is used for the electrode and the cell is filled 
with a saturated solution of copper sulfate. Saturated solutions are commonly used in 
reference electrodes since salt crystals can be added to the cell to ensure that saturation 
is maintained. It is very important to maintain the desired concentration of the solution 
in the reference electrode to ensure that it has a stable potential over time. 

The standard procedure for performing potential measurements (such as a pipe- 
to-soil potential measurement) is to connect the positive terminal of the voltmeter to 
the reference electrode and the negative terminal to the structure. When recording the 
reading, the sign of the reading must be reversed. The measurement has historically 
been performed in this manner to produce a positive deflection on an analog meter 
(pipe-to-soil potentials are usually negative values). 



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Thermodynamics 



303 



Container Of Insulating 
Material. Often Transparent Or 
Translucent 



Porous Plug (Usually 
Wood Or Ceramic) 





Pure Copper Rod 
(Electrolytic Copper) 

Insulating Seal 



Saturated Solution 
Of Copper Sulfate 



Surplus Crystals of 
'Copper Sulfate 



Figure 1 6.2 Schematic of copper-copper sulfate reference electrode. 



Galvanic Series 



As described in the section on electrode potentials, the electrochemical series is derived 
from thermodynamic data and represents equilibrium conditions. One rarely encounters 
such conditions in the real world except for the case of reference electrodes. A galvanic 
series is similar in appearance to an electrochemical series but represents actual poten- 
tial measurements made on common engineering materials in everyday environments. 
Table 16.3 shows a galvanic series produced on a number of metals in soil. The series was 
generated by measuring the stable potential between the metal and a CSE in a neutral 
soil. This potential is referred to as a corrosion potential, an open circuit potential, or a 
native potential. Note that the potentials measured may vary considerably, depending 
on the temperature, the type of soil, the moisture content of the soil, and the amount 
of time the metal is in contact with the soil before the measurement. Nevertheless, the 
galvanic series provides an indication of the relative reactivity of the different metals. 

A corrosion potential is not an equilibrium potential. The metal never reaches a state 
of equilibrium in corrosive environments. There is net oxidation of the metal to produce 
metal ions and corrosion products, and net reduction (and consumption) of some other 
species, such as oxygen, hydrogen, or water. These reactions are not reversible. If it were 
possible to measure the equilibrium potential for the metal in soil, it would be found 
to lie at a more negative value than the corrosion potential. Similarly, the equilibrium 
potential for the reduced species (oxygen, for example) is a more positive potential. 
Thus, the corrosion potential is somewhere between the equilibrium potentials of the two 



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304 Fundamentals of Corrosion 



Table 1 6.3 Practical Galvanic Series for Metals in Neutral Soils 
and Water 





Potential 


Metal 


V (CSE) 1 


Carbon, Graphite, Coke 


+0.3 


Platinum 


to -0.1 


Mill Scale On Steel 


-0.2 


High Silicon Cast Iron 


-0.2 


Copper, Brass, Bronze 


-0.2 


Mild Steel In Concrete 


-0.2 


Lead 


-0.5 


Cast Iron (Not Graphitized) 


-0.5 


Mild Steel (Rusted) 


-0.2 to -0.5 


Mild Steel (Clean and Shiny) 


-0.5 to -0.8 


Commercially Pure Aluminum 


-0.8 


Aluminum Alloy (5% Zinc) 


-1.05 


Zinc 


-1.1 


Magnesium Alloy (6% Al, 3% Zn, 0.15% Mn) 


-1.6 


Commercially Pure Magnesium 


-1.75 



typical potentials normally observed in neutral soils and water, 
measured in relation to copper sulfate reference electrode. 



reactions. Both reactions are polarized from their equilibrium values. The metal oxidation 
reaction is anodicaliy polarized and the reduction reaction is cathodically polarized. 
These reactions are commonly called the anodic and cathodic reactions, respectively 

Potential measurements are powerful tools for studying electrochemical processes 
such as corrosion. However, potential measurements do not directly provide information 
on the corrosion rate of a material. The rate must be inferred through knowledge of the 
relationship of the potential and the electrode kinetics. 



KINETICS 



As described in the previous section, the oxidation and reduction reactions on a corroding 
metal are polarized from their equilibrium values. A definition of polarization is "the 
deviation (change) in potential of an electrode as a result of the passage of current/' The 
potential deviation (polarization) can be measured from the equilibrium potential or from 
the corrosion potential. The amount of polarization is referred to as the overvoltage or 
overpotential and is assigned the term eta (rj). 

One type of polarization commonly observed in corroding metal systems is activation 
polarization. In the case of activation polarization, the rate of the corrosion reaction is 



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Kinetics 



305 



limited by the electron transfer reaction at the metal surface. This electron transfer process 
has an associated activation energy and the rate of this process is exponentially related to 
the free energy change. Since the free energy is directly related to the potential, and the 
rate is directly related to the electrical current, the relationship becomes the following 



AI oc e 11 '^ 



(14) 



in which I is the corrosion current, R is the gas constant, and T is the absolute temper- 
ature. Upon taking the log of both sides of the equation, the relationship becomes the 
following 



Log(AI) oc 



RT 



(15) 



Rather than using equations, a better way of visualizing the relationship between 
potential and current is by means of Evans diagrams (E-log i plots), where potential is 
plotted on the vertical (Y) axis and log current or log current density is plotted on the 
horizontal (X) axis (see Figure 16.3). In this example, the equilibrium potentials for the 
reduction reaction, hydrogen reduction, and the metal oxidation reactions are indicated 
as £h+/h 2 an d Em 2 +/M/ respectively. Note that at the equilibrium potential of each reaction, 



c 

CD 
CL 



i (H7H 2 ) e S 

1 ^X 

1 >c^/ 


T y< 




E„(H7H 2 ) X^ 




— 




~* 1 


-E ->^ 
io(M 2 7M) yf^ 

V Y! 1 1 



Log Current Density 

Figure 16.3 Evans diagram (potential versus logarithm of 
current density) for metal M in deaerated acid solution. 



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306 



Fundamentals of Corrosion 



there is an associated current. This current is referred to as an exchange current z'o- At 
equilibrium, the exchange current for the oxidation and reduction reactions are equal 
and the net rate is zero. The exchange current of a reaction is different depending on 
the type and nature of the surface on which it is occurring. For example, the exchange 
current for the hydrogen reaction is higher on a clean metal surface such as platinum 
than on a metal surface with an oxide film present. 

The corrosion potential for a metal in an environment is established at a potential 
where the net sum of the reduction reactions is equal to the net sum of the oxidation 
reactions. This is because there can be no net accumulation of charge; all of the electrons 
liberated by the oxidation of the metal must be consumed by the reduction reactions. 
The value of the corrosion potential, £ C orr/ is indicated in Figure 16.3. Note in the exam- 
ple in Figure 16.3 that the oxidation reaction for hydrogen and the reduction reaction 
for the metal are ignored in the summation process. This is because the current scale 
is logarithmic and the rates for these reactions are negligible near the free corrosion 
potential. 

The curves in Figure 16.3 show the current-potential relationships of the individ- 
ual oxidation and reduction reactions. The net current (difference between oxidation 
and reduction currents), plotted as a function of potential, has the form shown in 
Figure 16.4. The net current is zero at the free corrosion potential and only approaches 
the curves shown in Figure 16.3 at overpotentials greater than about 75 mV from E CO rr- 
At overpotentials less than this value, the net current is affected by both the anodic and 



c 

I 

CL 




Log Current Density 

Figure 16.4 Evans diagram for metal M in deaerated acid solu- 
tion, showing net anodic and cathodic currents. 



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Kinetics 307 



cathodic reactions. The equation describing the net current has a form similar to the 
classical Butler- Volmer equation 

ine t = ico4e 23 " /h -e- 23 " /fic ] (16) 

in which fi a and /3 C are the slopes of the anodic and cathodic components of the corrosion 
reactions, in millivolts per decade of current. These slopes are referred to as Tafel Slopes. 
In general, the anodic and cathodic Tafel slopes are different. 

The anodic (corrosion) current at the corrosion potential is I C orr which is the corrosion 
rate. When written as a large I, the units are generally in amperes (A). This current can 
be converted into a corrosion rate if one knows the surface area over which the current 
occurs. When this is known, the current is written as a current density (/) with units of 
A /cm 2 or A /ft 2 . This current can be converted to an actual corrosion rate using Faraday's 
Law 

mJM 

at nF v } 

in which m is the mass loss of the metal in grams, t is the time in seconds, a is the 
exposed surface area of the metal in cm 2 , i is the current density in A /cm 2 , M is the 
atomic weight of the metal in grams, n is the number of electrons transferred, and F is 
Faradays Constant (96,500 Coulombs/mole of e~). The left-hand side of the equation 
can be converted to a corrosion rate by dividing by the density (p), in grams /cm 3 and 
converting the units to the desired values. 

corrosion rate (cm/s) = (18) 

at 

For example, as written, the units are in cm /sec, which are not commonly used. This can 
be converted to thousandths of an inch per year (mils per year or mpy) by multiplying 
the number by 1.242 x 10 10 . 

corrosion rate (mils per year) = Corrosion Rate(cm/s) x (1.242 x 10 10 ) (19) 

A good number to remember is that 1 mpy for iron is equal to a current density of 
2.17 x 10" 6 A/cm 2 , which is equivalent to 2.02 mA/ft 2 . 

Another type of polarization commonly observed is concentration polarization. A 
definition of concentration polarization is "The portion of the polarization of a cell pro- 
duced by concentration changes resulting from passage of current through the elec- 
trolyte/' Concentration polarization is most commonly associated with the reduction 
reaction and is shown graphically in Figure 16.5. In this example, the diffusion of 
oxygen to the metal surface limits the rate of corrosion. Note that the rate of the re- 
duction reaction is independent of potential when concentration polarization occurs. 



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308 



Fundamentals of Corrosion 



£ 
o 

CL 



— 






E™ 1 


Activation 
Polarization 

/ Concentration 


— 


i i i \ 


V Polarization 

'corr 



Log Current Density 

Figure 1 6.5 Evans diagram for metal M where the concentration of oxy- 
gen is limiting rate of corrosion. 



Differential Aeration Cells 



In the corrosion cells described above, the oxidation and reduction reactions occur phys- 
ically at or very near the same location on a metal. At any given moment, one atom 
is being oxidized while the reduction reaction is occurring at an adjacent atomic site. 
Corrosion of a metal in an acid solution is a common example of this type of behav- 
ior. It is also possible for the oxidation and reduction reactions to be separated on a 
metal surface, where the metal oxidation occurs predominantly at one site while the 
reduction reaction occurs predominantly at another site. This is referred to as a differ- 
ential corrosion cell. One common differential corrosion cell is a differential aeration 
cell, shown in Figure 16.6. In this example, the paved road lowers the oxygen concen- 
tration in the soil around the pipeline. This region of the pipeline becomes the anode in 
the differential corrosion cell. Current leaves the metal surface in this region, increas- 
ing the corrosion rate, and flows to the cathodic areas where the oxygen concentration 
is higher. 

The Evans diagram for a differential aeration cell is shown in Figure 16.7. Note that 
each of the two sites has its own free corrosion potential. At the cathodic site, the primary 
reduction reaction is oxygen reduction while water reduction is indicated as the primary 
reduction reaction at the anodic site. The oxidation reactions at the two sites are the 



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Kinetics 



309 



Soil On Each Side Of Road 
Permitting Relatively Free 
Migration Of Oxygen To Pipe 
Surface 




Paved Road Preventing Free 
Access Of OxygenTo Pipeline 



mmmm^mmmmmm ^^^^^^^^^S mmmmmmmm^^m 



Soil 



^\ ^ 



^ ^X 



Anode Area 



(Corroding) 

Figure 16.6 Schematic showing differential aeration cell developed 
on a pipeline beneath a paved road. Arrows indicate direction of cur- 
rent flow. 



c 
o 
o 



(Aerated Steel) 



(Deaerated Steel) 




(Deaerated Steel) 



(Aerated Steel) 
Log Current Density 

Figure 1 6.7 Evans diagram for differential aeration cell. 



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31 Fundamentals of Corrosion 



same: oxidation of iron in this case. However, the Tafel slopes for the oxidation reactions 
are different because oxygen promotes the formation of protective oxide films. Figure 
16.7 shows that the cathodic site, where net reduction occurs, is polarized cathodically 
(in the negative direction) from its free corrosion potential. The anodic site, where net 
oxidation occurs, is polarized anodically (in the positive direction) from its free corrosion 
potential. After polarization, the two sites are not usually at the same potential because 
of an ohmic potential drop in the electrolyte, which is also indicated in the figure. 

The differential aeration cell is probably the most common corrosion cell found on 
pipelines or other underground structures. The upper parts of the structure are exposed 
to higher concentrations of oxygen and become the cathodes in the cell while the lower 
parts of the structure are oxygen deficient and become the anodes. Books on CP com- 
monly state that the following four conditions are required for a corrosion cell to function: 

1 . There must be an anode. 

2. There must be a cathode. 

3. There must be a metallic path electrically connecting the anode and cathode. (Nor- 
mally, this will be the pipeline itself.) 

4. The anode and cathode must be immersed in an electrically conductive electrolyte 
(normally, moist soil). 

The earlier edition of this book also stated that there must be an electrical potential 
between the anode and cathode. However, the principles of electrode kinetics show that 
a potential difference between the anode and cathode is not required for all types of 
corrosion. For example, an electrical potential between the anode and cathode is not 
necessary for uniform corrosion to occur. In the case of uniform corrosion, the anode 
and the cathode can be adjacent atoms on a metal at the same potential. The anodic 
and cathodic reactions must be polarized from their equilibrium values for corrosion to 
occur: the cathodic reaction is cathodically polarized and the anodic reaction is anodically 
polarized. The polarization of these reactions generates net oxidation and reduction 
currents that produce corrosion. Nevertheless, the vast majority of cases of corrosion on 
underground structures occur as a result of differential cells where the four conditions 
are present and a potential difference between the anode and cathode is present. 



Other Differential Corrosion Cells 

Galvanic Corrosion 

The differential aeration cell is one example of a differential corrosion cell. Galvanic 
corrosion is another example. In the case of galvanic corrosion, the potential difference 
is created by the presence of different metals. Referring to the galvanic series described 
in the thermodynamics section, each material has a different corrosion potential in a 
given environment. When these metals are electrically coupled, the metal with the most 



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Kinetics 



311 



positive corrosion potential is cathodically polarized, reducing its corrosion rate, while 
the more negative member of the couple is anodically polarized, increasing its corrosion 
rate. Galvanic corrosion can be very detrimental to an underground structure. Examples 
include the corrosion of iron in contact with copper or stainless steel fittings. However, 
galvanic corrosion can be used as an effective means of CP, as described in the section 
onCP. 



Mill Scale Corrosion 



Although not a metal, mill scale on hot rolled steel acts like a dissimilar metal in contact 
with the pipe steel. As shown by the practical galvanic series of Table 16.3, pipe steel 
will be anodic to mill scale. This can result in severe corrosion in low resistivity soils. 



New and Old Pipe 



A condition closely related to dissimilar metal corrosion occurs when new steel pipe, 
as shown in Figure 16.8, is intermixed with old steel pipe. This has often been found 
in older distribution piping systems where a section of pipe has been replaced because 
of corrosion damage. The new piece of pipe, exposed to the same corrosion conditions, 
logically would be expected to last as long as the original section. However, the new 
section will usually fail sooner than expected unless it is electrically insulated from the 
remainder of the system. This is simply an application of the practical galvanic series 
of Table 16.3, which shows that the potential of bright new steel is markedly different 



-0.40V 



-0.65V 



V 



V 



-0.35V 



Soil 



V 



Old Pipe 



New Pipe 



Old Pipe 



\- 



Anodic Area 



(Corroding) 

Figure 16.8 Schematic showing a differential corrosion 
cell created by replacement of a section of pipe. 



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Fundamentals of Corrosion 



from that of old rusted steel. The new steel is anodic and corrodes more rapidly than the 
old rusted steel. A similar corrosive condition can occur if, during work on an existing 
piping system, tools cut or scrape the pipe and expose areas of bright steel. These bright 
spots will be anodic and can result in accelerated corrosion in low resistivity soils. 



Dissimilar Soils 



A steel pipeline passing through dissimilar soils can establish corrosion cells in much 
the same manner that corrosion cells can be established with dissimilar metals. This 
is illustrated by Figure 16.9, which shows a pipeline passing through two dissimilar 
soils. The potential of the pipeline in soil A is slightly different from the potential in 
soil B. As indicated in the section of the book on the galvanic series, the corrosion, or 
native potential of a metal can vary with differences in the environment. This causes 
the potential difference illustrated and satisfies the conditions necessary to establish 
a differential corrosion cell. In the figure, the pipe in soil A is anodic to that in soil 
B and is corroding as indicated by the current discharge. This behavior is sometimes 
made strikingly apparent when excavating an old bare pipeline in which some areas 



Voltmeter 



-0.4V 



Copper 
Sulfate 
Reference 
Electrode 




Arrows 
Indicate 
Direction 
Of Current 
Flow 

Figure 16.9 Schematic showing differential corrosion cell created by dis- 
similar soils. 



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Kinetics 



313 



Ground Surface 




Arrows Indicate 
Direction Of Current Flow 



Anodic And Cathodic Areas On Pipe 
Indicated By "A" And "C M Respectivly 



Figure 1 6.1 Schematic showing numerous small differential corrosion 
cells created by different soils. 



(cathodic) are in excellent condition but other areas (anodic) only a few feet away are 
severely corroded. The middle voltmeter illustrates that the potential difference between 
soil types can be measured. This type of measurement is used during pipeline surveys 
as outlined in Chapter 5. 

Figure 16.10 illustrates the effect of adjacent soil types of different character on differ- 
ential cell corrosion. In some instances, different soil types are layered so that the backfill 
contacting the pipe will be a mixture of soil types when a pipeline trench is excavated 
and the pipe is laid and backfilled. This produces many small corrosion cells at the pipe 
surface that are not necessarily detectable by potential measurements taken at the surface 
of the ground. 

A specialized differential corrosion cell involves steel in concrete versus steel in soil. 
Figure 16.11 indicates that the portion of a steel pipe which is embedded in concrete 
will be more noble (positive) than adjacent pipe sections buried in soil. The electrolytic 
environment of moist concrete, being entirely different from the surrounding soil, re- 
sults in substantial differences in the steel-to-environment potential as illustrated in 
Table 16.3. Practically, this will always make the steel in soil more negative (active) than 
the steel embedded in concrete. This is an important source of corrosion activity in some 
instances. 



Relative Size of Anodic and Cathodic Areas 



Up to this point, various conditions have been discussed that can cause corrosion current 
to flow in a differential corrosion cell. The relative size of anodic and cathodic areas has 
not been mentioned. An understanding of the effect of differences in area relationships 



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Fundamentals of Corrosion 



Voltmeter 



Copper 
Sulfate 
Reference 
Electrode 




- Concrete 
Encasement 



Pipe In Soil 
Corrodes 



Figure 16.11 Schematic showing differential corrosion cell created by 
concrete encasement of pipe. Note that the indicated polarities of the po- 
tentials are reversed. 



is important for an appreciation of why, for example, a dissimilar metal combination can 
cause very rapid corrosion under certain area relationships and relatively little in others. 
Figure 16.12 demonstrates the effect of anode to cathode area ratio on galvanic corrosion. 
The left-hand sketch in Figure 16.12 shows a small anode (a galvanized cap on a service 
stub on a bare steel pipeline) in contact with a large cathode (the bare steel line). Under 
such a condition, the small anode will be subject to a high density of current discharge 
per unit area, with the total amount of current flowing governed by the kinetics of the 
oxidation and reduction reactions and the soil resistivity. The current collected per unit 
area on the cathode is relatively low and may not be sufficient to result in any degree 
of polarization which would tend to limit corrosion current flow as discussed earlier. 
Under these conditions, in a low resistivity environment, corrosion can be serious and 
rapid. 

By contrast, the right-hand sketch in Figure 16.12 shows a large anode (the steel 
pipeline) and a small cathode (the brass valve in the steel system). With such a com- 
bination, a high current density may be collected per unit area at the cathode, but the 
total cathodic current will be relatively small because of the small area of the cathode 
(total current = current density x area). The corrosion current density discharged from 
the steel will be even smaller because the small current is distributed over a large sur- 
face area. From this discussion, we may conclude that no matter what condition has 



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Cathodic Protection 



315 



Small Cathode 
(Brass Service Cock) 



Small Anode 
(Galvanize Pipe Cap) 




Small Anode - Large Cathode. 
(Corrosion At Anode Severe). 

(a) 



Small Cathode - Large 
Anode. (Relatively Mild 
Corrosion At Anode). 

(b) 



Figure 16.12 Schematic showing the effect of anode to cathode area 
ratio on galvanic corrosion. 



initiated the differential corrosion cell, if the anodic area is relatively small in relation to 
the cathodic area, corrosion will be severe. If, on the other hand, the anodic area is large 
as compared to the cathodic area, corrosion will be relatively mild. 



CATHODIC PROTECTION 



The principal methods for mitigating corrosion on underground pipelines are coatings 
and CP. A primary function of a coating on a cathodically protected structure is to reduce 
the surface area of exposed metal on the pipeline, thereby reducing the current necessary 
to cathodically protect the metal. CP is defined as "a reduction of the corrosion rate by 
shifting the potential of the structure toward a less oxidizing potential by applying an 
external current." This can be shown graphically on an Evans diagram as indicated in 
Figure 16.13. In the illustration, the potential of the metal is shifted from the free corrosion 
potential, £ corr to the value Ecp by the application of the CP current, /applied- As the 
potential becomes more negative, the corrosion rate decreases, as defined by the anodic 
kinetics, while the rate of the cathodic current increases. This difference between the 
anodic and cathodic kinetics is the amount of current required to maintain the indicated 
potential and is equivalent to the CP current applied to a structure. 

It is important to note that complete protection is not achieved until the potential of the 
metal is shifted to the equilibrium potential, E e quil- At this potential, the net corrosion rate 
is zero. Usually, it is not practicable to achieve complete protection because of the high 
current required; the applied current increases exponentially with decreasing potential. 
Since anodic Tafel slopes are typically around 100 mV, a 100 mV negative shift in the 



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Fundamentals of Corrosion 



+ 


0.0 




0.1 




0.2 




0.3 




0.4 


ClT 

C/) 


0.5 



o 



0.6 



TB 0.7 



c 



o 


0.8 




0.9 




1.0 




1.1 




1.2 


1 


1.3 




1.4 

0.001 0.01 0. 1 1 10 1 00 1 000 1 0,000 

Log Current Density, l-t A/cm 

Figure 1 6.1 3 Evans diagram demonstrating mechanism of CP. 

potential will decrease the corrosion rate by a factor of 10. This magnitude of decrease 
is typically considered to be adequate to protect most structures. 

The required shift in potential can be achieved by means of an external power source 
(referred to as impressed current CP) or by utilizing a sacrificial anode. The impressed 
current system uses a power supply, referred to as a rectifier, and an anode buried in 
the ground to impress a current on the structure. The sacrificial anode system uses the 
galvanic relationship between a sacrificial anode material, such as zinc or magnesium, 
and the pipe steel to supply the required CP current. 



ENVIRONMENTAL POLARIZATION 

The concepts presented for CP are fundamentally correct at the instant that CP is applied 
but are too simplistic to consider the time-dependant behavior of a cathodically protected 



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Environmental Polarization 317 



underground structure. At the surface of a structure under CP, a number of changes in the 
environment occur that are beneficial in mitigating corrosion. They have been referred 
to as environmental polarization. As shown in Figure 16.13, the rate of the reduction 
reaction is increased when the CP is applied. The reduction reactions generate OH - or 
consume H + 

2 + 2H 2 + 4e~ -> 40H- (3) 

2H + + 2e~ -^H 2 (5) 

2H 2 + 2e~ -> 20H~ + H 2 (20) 

Thus, an increase in the rate of these reactions causes a pH increase to occur at the 
metal surface, creating a less acidic (more basic) environment. This pH increase is bene- 
ficial because the corrosion rate of steel decreases with increasing pH, even under freely 
corroding conditions. The decrease in corrosion rate is the result of the formation of a 
protective oxide film on the metal surface in the elevated pH environment, a process 
referred to as passivation. On an Evans diagram, this process corresponds to an increase 
in the anodic Tafel slope and a resulting shift in the oxidation kinetics to the left. The 
flow of electrical current also causes damaging negatively charged ions (anions), such 
as chloride, to migrate from the metal surface. 



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Appendix 



NACE Glossary of 
Corrosion-Related Terms 

Courtesy of Technical Coordination Committee and Reference Publications Committee. 



Abrasive Small particles of material 
that are propelled at high velocity to 
impact a surface during abrasive blast 
cleaning. 

Abrasive Blast Cleaning Cleaning and 
roughening of a surface produced by the 
high-velocity impact of an abrasive that is 
propelled by the discharge of pressurized 
fluid from a blast nozzle or by a mechan- 
ical device such as a centrifugal blast- 
ing wheel. (Also referred to as Abrasive 
Blasting.) 

Accelerator A chemical substance that 
increases the rate at which a chemical 
reaction (e.g., curing) would otherwise 
occur. 

Acrylic Type of resin polymerized from 
acrylic acid, methacrylic acid, esters of 
these acids, or acrylonitrile. 



Activator A chemical substance that 
initiates and accelerates a chemical reac- 
tion (e.g., curing). Heat and radiation may 
also serve as activators for some chemical 
reactions. 

Active (1) The negative direction of 
electrode potential. (2) A state of a metal 
that is corroding without significant in- 
fluence of reaction product. 

Aeration Cell [See Differential Aeration 
Cell] 

Air Drying Process by which an ap- 
plied wet coat converts to a dry coating 
film by evaporation of solvent or reaction 
with oxygen as a result of simple expo- 
sure to air without intentional addition 
of heat or a curing agent. 

Airless Spraying Process of spraying 
coating liquids using hydraulic pressure, 
not air pressure, to atomize. 

Alkyd Type of resin formed by the reac- 
tion of polyhydric alcohols and polybasic 



319 



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acids, part of which is derived from satu- 
rated or unsaturated oils or fats. 

Alligatoring Pronounced wide crack- 
ing over the surface of a coating, which 
has the appearance of alligator hide. 

Amphoteric Metal A metal that is sus- 
ceptible to corrosion in both acid and 
alkaline environments. 

Anaerobic Free of air or uncombined 
oxygen. 

Anion A negatively charged ion that 
migrates through the electrolyte toward 
the anode under the influence of a poten- 
tial gradient. 

Anode The electrode of an electrochem- 
ical cell at which oxidation occurs. Elec- 
trons flow away from the anode in the 
external circuit. Corrosion usually occurs 
and metal ions enter the solution at the 
anode. 

Anode Cap An electrical insulating ma- 
terial placed over the end of the anode at 
the lead wire connection. 

Anode Corrosion Efficiency The ratio 
of the actual corrosion (mass loss) of an 
anode to the theoretical corrosion (mass 
loss) calculated from the quantity of elec- 
tricity that has passed between the anode 
and cathode using Faraday's law. 

Anodic Inhibitor A chemical substance 
that prevents or reduces the rate of the 
anodic or oxidation reaction. 

Anodic Polarization The change of the 
electrode potential in the noble (positive) 
direction caused by current across the 
electrode /electrolyte interface. [See Po- 
larization.] 

Anodic Protection Polarization to a 
more oxidizing potential to achieve a 



reduced corrosion rate by the promotion 
of passivity. 

Anodizing Oxide coating formed on a 
metal surface (generally aluminum) by an 
electrolytic process. 

Anolyte The electrolyte adjacent to the 
anode of an electrochemical cell. 

Antifouling Preventing fouling. [See 
Fouling.] 

Attenuation Electrical losses in a con- 
ductor caused by current flow in the 
conductor. 

Auger Electron Spectroscopy Analyt- 
ical technique in which the sample 
surface is irradiated with low-energy 
electrons and the energy spectrum of 
electrons emitted from the surface is 
measured. 

Austenitic Steel A steel whose mi- 
crostructure at room temperature consists 
predominantly of austenite. 

Auxiliary Electrode An electrode, usu- 
ally made from a noncorroding material, 
which is commonly used in polarization 
studies to pass current to or from a test 
electrode. 



B 



Backfill Material placed in a hole to fill 
the space around the anodes, vent pipe, 
and buried components of a cathodic 
protection system. 

Barrier Coating (1) A coating that has a 
high resistance to permeation of liquids 
and/ or gases. (2) A coating that is ap- 
plied over a previously coated surface to 



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321 



prevent damage to the underlying coat- 
ing during subsequent handling. 

Beach Marks The characteristic mark- 
ings on the fracture surfaces produced 
by fatigue crack propagation (also known 
as clamshell marks, conchoidal marks, and 
arrest marks). 

Binder The nonvolatile portion of the 
vehicle of a formulated coating material. 

Bituminous Coating An asphalt or 
coal-tar compound used to provide a pro- 
tective coating for a surface. 

Blast Angle (1) The angle of the blast 
nozzle with reference to the surface dur- 
ing abrasive blast cleaning. (2) The angle 
of the abrasive particles propelled from 
a centrifugal blasting wheel with refer- 
ence to the surface being abrasive blast 
cleaned. 

Blowdown (1) Injection of air or water 
under high pressure through a tube to 
the anode area for the purpose of purging 
the annular space and possibly correcting 
high resistance caused by gas blockage. 
(2) In conjunction with boilers or cooling 
towers, the process of discharging a sig- 
nificant portion of the aqueous solution 
in order to remove accumulated salts, de- 
posits, and other impurities. 

Blushing Whitening and loss of gloss 
of a coating, usually organic, caused by 
moisture (also known as blooming). 

Brittle Fracture Fracture with little or 
no plastic deformation. 

Brush-Off Blast Cleaned Surface A 

brush-off blast cleaned surface, when 
viewed without magnification, shall be 
free of all visible oil, grease, dirt, dust, 
loose mill scale, loose rust, and loose 
coating. Tightly adherent mill scale, rust, 



and coating may remain on the surface. 
Mill scale, rust, and coating are consid- 
ered tightly adherent if they cannot be re- 
moved by lifting with a dull putty knife. 
[See NACE No. 4/SSPC-SP 7.] 



Calcareous Coating A layer consisting 
of calcium carbonate and other salts de- 
posited on the surface. When the surface 
is cathodically polarized as in cathodic 
protection, this layer is the result of the 
increased pH adjacent to the protected 
surface. 

Calcareous Deposit [See Calcareous 
Coating.] 

Case Hardening Hardening a ferrous 
alloy so that the outer portion, or case, is 
made substantially harder than the inner 
portion, or core. Typical processes are car- 
burizing, cyaniding, carbo-nitriding, ni- 
triding, induction hardening, and flame 
hardening. 

Casein Paint Water-thinned paint with 
vehicle derived from milk. 

Catalyst A chemical substance, usually 
present in small amounts relative to the 
reactants, that increases the rate at which 
a chemical reaction (e.g., curing) would 
otherwise occur, but is not consumed in 
the reaction. 

Cathode The electrode of an electro- 
chemical cell at which reduction is the 
principal reaction. Electrons flow toward 
the cathode in the external circuit. 

Cathodic Corrosion Corrosion result- 
ing from a cathodic condition of a struc- 
ture, usually caused by the reaction of an 



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amphoteric metal with the alkaline prod- 
ucts of electrolysis. 

Cathodic Disbondment The destruc- 
tion of adhesion between a coating and 
the coated surface caused by products of 
a cathodic reaction. 

Cathodic Inhibitor A chemical sub- 
stance that prevents or reduces the rate 
of the cathodic or reduction reaction. 

Cathodic Polarization The change of 
the electrode potential in the active (neg- 
ative) direction caused by current across 
the electrode /electrolyte interface. [See 
Polarization.] 

Cathodic Protection A technique to re- 
duce the corrosion of a metal surface by 
making that surface the cathode of an 
electrochemical cell. 

Catholyte The electrolyte adjacent to 
the cathode of an electrochemical cell. 

Cation A positively charged ion that 
migrates through the electrolyte toward 
the cathode under the influence of a po- 
tential gradient. 

Cavitation The formation and rapid 
collapse of cavities or bubbles within a 
liquid which often results in damage to a 
material at the solid /liquid interface un- 
der conditions of severe turbulent flow. 

Cell [See Electrochemical Cell] 

Cementation The introduction of one 
or more elements into the surface layer 
of a metal by diffusion at high temper- 
ature. (Examples of cementation include 
carburizing [introduction of carbon], ni- 
triding [introduction of nitrogen], and 
chromizing [introduction of chromium].) 

Chalking The development of loose, re- 
movable powder (pigment) at the surface 



of an organic coating, usually caused by 
weathering. 

Checking The development of slight 
breaks in a coating which do not pene- 
trate to the underlying surface. 

Chemical Conversion Coating An ad- 
herent reaction product layer on a metal 
surface formed by reaction with a suit- 
able chemical to provide greater corro- 
sion resistance to the metal and increase 
adhesion of coatings applied to the metal. 
(Example is an iron phosphate coating on 
steel, developed by reaction with phos- 
phoric acid.) 

Chevron Pattern A V-shaped pattern 
on a fatigue or brittle-fracture surface. 
The pattern can also be one of straight 
radial lines on cylindrical specimens. 

Chloride Stress Corrosion Cracking 

Cracking of a metal under the combined 
action of tensile stress and corrosion in the 
presence of chlorides and an electrolyte 
(usually water). 

Coat One layer of a coating applied to a 
surface in a single continuous application 
to form a uniform film when dry. 

Coating A liquid, liquefiable, or mas- 
tic composition that, after application to 
a surface, is converted into a solid pro- 
tective, decorative, or functional adherent 
film. 

Coating System The complete number 
and types of coats applied to a substrate 
in a predetermined order. (When used in 
a broader sense, surface preparation, pre- 
treatments, dry film thickness, and man- 
ner of application are included.) 

Cold Shut Horizontal surface disconti- 
nuity caused by solidification of a portion 
of a meniscus during the progressive 



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323 



filling of a mold, which is later covered 
with more solidifying metal as the molten 
metal level rises. Cold shuts generally oc- 
cur at corners remote from the point of 
pour. 

Commercial Blast Cleaned Surface A 

commercial blast cleaned surface, when 
viewed without magnification, shall be 
free of all visible oil, grease, dust, dirt, 
mill scale, rust, coating, oxides, corrosion 
products, and other foreign matter. Ran- 
dom staining shall be limited to no more 
than 33 percent of each unit area (ap- 
proximately 58 cm 2 [9.0 in. 2 ]) of surface 
and may consist of light shadows, slight 
streaks, or minor discolorations caused 
by stains of rust, stains of mill scale, or 
stains of previously applied coating. [See 
NACE No. 3/SSPC-SP 6.] 

Concentration Cell An electrochemical 
cell, the electromotive force of which is 
caused by a difference in concentration of 
some component in the electrolyte. (This 
difference leads to the formation of dis- 
crete cathodic and anodic regions.) 

Concentration Polarization That por- 
tion of polarization of a cell produced 
by concentration changes resulting from 
passage of current though the electrolyte. 

Conductive Coating (1) A coating that 
conducts electricity. (2) An electrically 
conductive, mastic-like material used as 
an impressed current anode on reinforced 
concrete surfaces. 

Contact Corrosion [See Galvanic Corro- 
sion.] 

Continuity Bond A connection, usually 
metallic, that provides electrical continu- 
ity between structures that can conduct 
electricity. 



Continuous Anode A single anode 
with no electrical discontinuities. 



Conversion Coating 

version Coating.] 



[See Chemical Con- 



Corrosion The deterioration of a mate- 
rial, usually a metal, that results from a 
reaction with its environment. 

Corrosion Fatigue Fatigue-type crack- 
ing of metal caused by repeated or fluctu- 
ating stresses in a corrosive environment 
characterized by shorter life than would 
be encountered as a result of either the 
repeated or fluctuating stress alone or the 
corrosive environment alone. 

Corrosion Inhibitor A chemical sub- 
stance or combination of substances that, 
when present in the environment, pre- 
vents or reduces corrosion. 

Corrosion Potential (E cor r) The poten- 
tial of a corroding surface in an electrolyte 
relative to a reference electrode under 
open-circuit conditions (also known as 
rest potential, open-circuit potential, or freely 
corroding potential). 

Corrosion Rate The rate at which cor- 
rosion proceeds. 

Corrosion Resistance Ability of a ma- 
terial, usually a metal, to withstand cor- 
rosion in a given system. 

Corrosiveness The tendency of an en- 
vironment to cause corrosion. 



Counter Electrode 

trode.] 



[See Auxiliary Elec- 



Counterpoise A conductor or system 
of conductors arranged beneath a power 
line, located on, above, or most fre- 
quently, below the surface of the earth 
and connected to the footings of the tow- 
ers or poles supporting the power line. 



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Couple [See Galvanic Couple.] 

Cracking (of Coating) Breaks in a coat- 
ing that extend through to the substrate. 

Crazing A network of checks or cracks 
appearing on the surface of a coating. 

Creep Time-dependent strain occur- 
ring under stress. 

Crevice Corrosion Localized corrosion 
of a metal surface at, or immediately ad- 
jacent to, an area that is shielded from full 
exposure to the environment because of 
close proximity of the metal to the surface 
of another material. 

Critical Humidity The relative humid- 
ity above which the atmospheric corro- 
sion rate of some metals increases sharply. 

Critical Pitting Potential (E p , E pp ) The 
lowest value of oxidizing potential (volt- 
age) at which pits nucleate and grow. The 
value depends on the test method used. 

Curing Chemical process of developing 
the intended properties of a coating or 
other material (e.g., resin) over a period 
of time. 

Curing Agent A chemical substance 
used for curing a coating or other material 
(e.g., resin). [Also referred to as Hardener.] 

Current Density The current to or from 
a unit area of an electrode surface. 

Current Efficiency The ratio of the elec- 
trochemical equivalent current density 
for a specific reaction to the total applied 
current density. 



D 



of alternating current (AC) in both direc- 
tions and stops or substantially reduces 
the flow of direct current (DC). 

Dealloying The selective corrosion of 
one or more components of a solid solu- 
tion alloy (also known as parting or selec- 
tive dissolution). 

Decomposition Potential The poten- 
tial (voltage) on a metal surface necessary 
to decompose the electrolyte of an electro- 
chemical cell or a component thereof. 



Decomposition Voltage 

sition Potential] 



[See Decompo- 



se Decoupling Device A device used 
in electrical circuits that allows the flow 



Deep Groundbed One or more anodes 
installed vertically at a nominal depth of 
15 m (50 ft) or more below the earth's sur- 
face in a drilled hole for the purpose of 
supplying cathodic protection. 

Depolarization The removal of factors 
resisting the current in an electrochemical 
cell. 

Deposit Attack Corrosion occurring 
under or around a discontinuous deposit 
on a metallic surface (also known as poul- 
tice corrosion). 

Dezincification A corrosion phenome- 
non resulting in the selective removal of 
zinc from copper-zinc alloys. (This phe- 
nomenon is one of the more common 
forms of dealloying.) 

Dielectric Coating A coating that does 
not conduct electricity. 

Dielectric Shield An electrically non- 
conductive material, such as a coating, 
sheet or pipe, that is placed between 
an anode and an adjacent cathode, usu- 
ally on the cathode, to improve cur- 
rent distribution in a cathodic protection 
system. 



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Differential Aeration Cell An electro- 
chemical cell, the electromotive force of 
which is due to a difference in air (oxygen) 
concentration at one electrode as com- 
pared with that at another electrode of the 
same material. 

Diffusion-Limited Current Density 

The current density that corresponds 
to the maximum transfer rate that a 
particular species can sustain because of 
the limitation of diffusion (often referred 
to as limiting current density). 

Disbondment The loss of adhesion be- 
tween a coating and the substrate. 

Double Layer The interface between an 
electrode or a suspended particle and 
an electrolyte created by charge-charge 
interaction leading to an alignment of 
oppositely charged ions at the surface 
of the electrode or particle. The simplest 
model is represented by a parallel plate 
condenser. 

Drainage Conduction of electric cur- 
rent from an underground or submerged 
metallic structure by means of a metallic 
conductor. 

Driving Potential Difference in poten- 
tial between the anode and the steel struc- 
ture. 

Drying Oil An oil capable of conver- 
sion from a liquid to a solid by slow reac- 
tion with oxygen in the air. 



Elastic Deformation Changes of di- 
mensions of a material upon the appli- 
cation of a stress within the elastic range. 
Following the release of an elastic stress, 



the material returns to its original dimen- 
sions without any permanent deforma- 
tion. 

Elastic Limit The maximum stress to 
which a material may be subjected with- 
out retention of any permanent deforma- 
tion after the stress is removed. 

Elasticity The property of a material 
that allows it to recover its original di- 
mensions following deformation by a 
stress below its elastic limit. 

Electrical Isolation The condition of 
being electrically separated from other 
metallic structures or the environment. 

Electrochemical Cell A system consist- 
ing of an anode and a cathode immersed 
in an electrolyte so as to create an electri- 
cal circuit. The anode and cathode may 
be different metals or dissimilar areas on 
the same metal surface. 

Electrochemical Equivalent The mass 
of an element or group of elements oxi- 
dized or reduced at 100% efficiency by the 
passage of a unit quantity of electricity. 

Electrochemical Potential The partial 
derivative of the total electrochemical free 
energy of a constituent with respect to 
the number of moles of this constituent 
where all other factors are kept constant. 
It is analogous to the chemical potential 
of a constituent except that it includes 
the electrical as well as chemical contri- 
butions to the free energy. 

Electrode A conductor used to establish 
contact with an electrolyte and through 
which current is transferred to or from an 
electrolyte. 

Electrode Potential The potential of 
an electrode in an electrolyte as mea- 
sured against a reference electrode. (The 



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electrode potential does not include any 
resistance losses in potential in either the 
electrolyte or the external circuit. It repre- 
sents the reversible work to move a unit of 
charge from the electrode surface through 
the electrolyte to the reference electrode.) 

Electrokinetic Potential A potential 
difference in a solution caused by resid- 
ual, unbalanced charge distribution in the 
adjoining solution, producing a double 
layer. The electrokinetic potential is dif- 
ferent from the electrode potential in that 
it occurs exclusively in the solution phase. 
This potential represents the reversible 
work necessary to bring a unit charge 
from infinity in the solution up to the in- 
terface in question but not through the 
interface (also known as zeta potential). 

Electrolyte A chemical substance con- 
taining ions that migrate in an electric 
field. 

Electrolytic Cleaning A process for re- 
moving soil, scale, or corrosion products 
from a metal surface by subjecting the 
metal as an electrode to an electric cur- 
rent in an electrolytic bath. 

Electromotive Force Series A list of el- 
ements arranged according to their stan- 
dard electrode potentials, the sign being 
positive for elements whose potentials 
are cathodic to hydrogen and negative for 
those anodic to hydrogen. 

Ellipsometry An optical analytical 
technique employing plane-polarized 
light to study films. 

Embrittlement Loss of ductility of a 
material resulting from a chemical or 
physical change. 

EMF Series See Electromotive Force Series. 

Enamel (1) A paint that dries to a 
hard, glossy surface. (2) A coating that is 



characterized by an ability to form a 
smooth, durable film. 

End Effect The more rapid loss of anode 
material at the end of an anode, compared 
with other surfaces of the anode, resulting 
from higher current density. 

Endurance Limit The maximum stress 
that a material can withstand for an in- 
finitely large number of fatigue cycles. 

Environment The surroundings or con- 
ditions (physical, chemical, mechanical) 
in which a material exists. 

Environmental Cracking Brittle frac- 
ture of a normally ductile material in 
which the corrosive effect of the environ- 
ment is a causative factor. 

Environmental cracking is a general 
term that includes all of the terms listed 
below. The definitions of these terms are 
listed elsewhere in the Glossary: 

Corrosion fatigue 
Hydrogen embrittlement 
Hydrogen-induced cracking — (stepwise 

cracking) 
Hydrogen stress cracking 
Liquid metal cracking 
Stress corrosion cracking 
Sulfide stress cracking 

The following terms have been used in 
the past in connection with environmen- 
tal cracking but are now obsolete and 
should not be used: 

Caustic embrittlement 

Delayed cracking 

Liquid metal embrittlement 

Season cracking 

Static fatigue 

Sulfide corrosion cracking 

Sulfide stress corrosion cracking 

Epoxy Type of resin formed by the re- 
action of aliphatic or aromatic polyols 



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(like bisphenol) with epichlorohydrin 
and characterized by the presence of re- 
active oxirane end groups. 

Equilibrium Potential The potential of 
an electrode in an electrolyte at which the 
forward rate of a given reaction is exactly 
equal to the reverse rate; the electrode 
potential with reference to a standard 
equilibrium, as defined by the Nernst 
equation. 

Erosion The progressive loss of mate- 
rial from a solid surface due to mechan- 
ical interaction between that surface and 
a fluid, a multicomponent fluid, or solid 
particles carried with the fluid. 

Erosion-Corrosion A conjoint action 
involving corrosion and erosion in the 
presence of a moving corrosive fluid or a 
material moving through the fluid, lead- 
ing to accelerated loss of material. 

Exchange Current The rate at which ei- 
ther positive or negative charges are en- 
tering or leaving the surface when an elec- 
trode reaches dynamic equilibrium in an 
electrolyte. 

Exfoliation Corrosion Localized sub- 
surface corrosion in zones parallel to the 
surface that result in thin layers of un- 
corroded metal resembling the pages of a 
book. 

External Circuit The wires, connectors, 
measuring devices, current sources, etc., 
that are used to bring about or measure 
the desired electrical conditions within an 
electrochemical cell. It is this portion of 
the cell through which electrons travel. 



Fatigue The phenomenon leading to 
fracture of a material under repeated or 



fluctuating stresses having a maximum 
value less than the tensile strength of the 
material. 

Fatigue Strength The maximum stress 
that can be sustained for a specified num- 
ber of cycles without failure. 

Fault Current A current that flows from 
one conductor to ground or to another 
conductor due to an abnormal connec- 
tion (including an arc) between the two. 
A fault current flowing to ground may be 
called a ground fault current. 

Ferrite The body-centered cubic crys- 
talline phase of iron-based alloys. 

Ferritic Steel A steel whose microstruc- 
ture at room temperature consists pre- 
dominantly of ferrite. 

Filiform Corrosion Corrosion that oc- 
curs under a coating in the form of ran- 
domly distributed thread-like filaments. 

Film A thin, not necessarily visible 
layer of material. 

Finish Coat [See Topcoat.] 

Forced Drainage Drainage applied to 
underground or submerged metallic 
structures by means of an applied elec- 
tromotive force or sacrificial anode. 

Foreign Structure Any metallic struc- 
ture that is not intended as a part of a 
system under cathodic protection. 

Fouling An accumulation of deposits. 
This includes accumulation and growth 
of marine organisms on a submerged 
metal surface and the accumulation of 
deposits (usually inorganic) on heat ex- 
changer tubing. 

Fractography Descriptive treatment of 
fracture, especially in metals, with spe- 
cific reference to photographs of the frac- 
ture surface. 



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Fracture Mechanics A quantitative 
analysis for evaluating structural relia- 
bility in terms of applied stress, crack 
length, and specimen geometry 

Free Machining The machining charac- 
teristics of an alloy to which an ingre- 
dient has been introduced to give small 
broken chips, lower power consump- 
tion, better surface finish, and longer tool 
life. 

Fretting Corrosion Deterioration at the 
interface of two contacting surfaces under 
load which is accelerated by their relative 
motion. 

Furan Type of resin formed by the poly- 
merization or polycondensation of fur- 
furyl, furfuryl alcohol, or other com- 
pounds containing a furan ring. 



Galvanic Anode A metal that provides 
sacrificial protection to another metal that 
is more noble when electrically coupled 
in an electrolyte. This type of anode is 
the electron source in one type of cathodic 
protection. 

Galvanic Corrosion Accelerated corro- 
sion of a metal because of an electrical 
contact with a more noble metal or non- 
metallic conductor in a corrosive elec- 
trolyte. 

Galvanic Couple A pair of dissimilar 
conductors, commonly metals, in electri- 
cal contact in an electrolyte. 

Galvanic Current The electric current 
between metals or conductive nonmetals 
in a galvanic couple. 



Galvanic Series A list of metals and 
alloys arranged according to their corro- 
sion potentials in a given environment. 

Galvanostatic Refers to an experimen- 
tal technique whereby an electrode is 
maintained at a constant current in an 
electrolyte. 

General Corrosion Corrosion that is 
distributed more or less uniformly over 
the surface of a material. 

Graphitic Corrosion Deterioration of 
gray cast iron in which the metallic con- 
stituents are selectively leached or con- 
verted to corrosion products, leaving the 
graphite intact. 

Graphitization The formation of gra- 
phite in iron or steel, usually from decom- 
position of iron carbide at elevated tem- 
peratures. [Should not be used as a term 
to describe graphitic corrosion.] 

Grit Small particles of hard material 
(e.g., iron, steel, or mineral) with irregu- 
lar shapes that are commonly used as an 
abrasive in abrasive blast cleaning. 

Grit Blasting Abrasive blast cleaning 
using grit as the abrasive. 

Groundbed One or more anodes insta- 
lled below the earth's surface for the pur- 
pose of supplying cathodic protection. 



H 



Half-Cell A pure metal in contact with 
a solution of known concentration of its 
own ion, at a specific temperature, de- 
velops a potential that is characteristic 
and reproducible; when coupled with 
another half-cell, an overall potential 



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that is the sum of both half-cells de- 
velops. 

Hand Tool Cleaning Removal of loose 
rust, loose mill scale, and loose paint 
to degree specified, by hand chipping, 
scraping, sanding, and wire brushing. 
[See SSPC-SP 2.] 

Hardener [See Curing Agent.] 

Heat-Affected Zone That portion of the 
base metal that is not melted during braz- 
ing, cutting, or welding, but whose mi- 
crostructure and properties are altered by 
the heat of these processes. 

Heat Treatment Heating and cooling a 
solid metal or alloy in such a way as to 
obtain desired properties. Heating for the 
sole purpose of hot working is not consid- 
ered heat treatment. 

High-Pressure Water Cleaning Water 
cleaning performed at pressures from 34 
to 70 MPa (5,000 to 10,000 psig). 

High-Pressure Water Jetting Water jet- 
ting performed at pressures from 70 to 170 
MPa (10,000 to 25,000 psig). 

High-Temperature Hydrogen Attack 

A loss of strength and ductility of steel 
by high-temperature reaction of absorbed 
hydrogen with carbides in the steel, re- 
sulting in decarburization and internal 
fissuring. 

Holiday A discontinuity in a protective 
coating that exposes unprotected surface 
to the environment. 

Hydrogen Blistering The formation of 
subsurface planar cavities, called hydro- 
gen blisters, in a metal resulting from 
excessive internal hydrogen pressure. 
Growth of near-surface blisters in low- 
strength metals usually results in surface 
bulges. 



Hydrogen Embrittlement A loss of 
ductility of a metal resulting from absorp- 
tion of hydrogen. 

Hydrogen-Induced Cracking Stepwise 
internal cracks that connect adjacent hy- 
drogen blisters on different planes in the 
metal, or to the metal surface (also known 
as stepwise cracking). 

Hydrogen Overvoltage Overvoltage 
associated with the liberation of hydro- 
gen gas. 

Hydrogen Stress Cracking Cracking 
that results from the presence of hydro- 
gen in a metal in combination with ten- 
sile stress. It occurs most frequently with 
high-strength alloys. 



Impingement Corrosion A form of 
erosion-corrosion generally associated 
with the local impingement of a high- 
velocity, flowing fluid against a solid 
surface. 

Impressed Current An electric current 
supplied by a device employing a power 
source that is external to the electrode 
system. (An example is direct current for 
cathodic protection.) 

Inclusion A nonmetallic phase such as 
an oxide, sulfide, or silicate particle in a 
metal. 

Inorganic Zinc-Rich Coating Coating 
containing a metallic zinc pigment (typi- 
cally 75 wt% zinc or more in the dry film) 
in an inorganic vehicle. 



Intercrystalline Corrosion 

granular Corrosion.] 



[See Inter- 



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Interdendritic Corrosion Corrosive at- 
tack of cast metals that progresses prefer- 
entially along paths between dendrites. 

Intergranular Corrosion Preferential 
corrosion at or along the grain boundaries 
of a metal (also known as intercrystalline 
corrosion). 

Intergranular Stress Corrosion Cracking 

Stress corrosion cracking in which the 
cracking occurs along grain boundaries. 

Internal Oxidation The formation of 
isolated particles of oxidation products 
beneath the metal surface. 

Intumescence The swelling or bub- 
bling of a coating usually caused by 
heating. [The term is commonly used 
in aerospace and fire-protection applica- 
tions.] 

Ion An electrically charged atom or 
group of atoms. 

Iron Rot Deterioration of wood in con- 
tact with iron-based alloys. 



K 



Knife-Line Attack Intergranular corro- 
sion of an alloy along a line adjoining or 
in contact with a weld after heating into 
the sensitization temperature range. 



useful in predicting scaling behavior of 
natural water. 

Line Currrent The direct current flow- 
ing on a pipeline. 

Lining A coating or layer of sheet mate- 
rial adhered to or in intimate contact with 
the interior surface of a container used to 
protect the container against corrosion by 
its contents and /or to protect the contents 
of the container from contamination by 
the container material. 

Liquid Metal Cracking Cracking of a 
metal caused by contact with a liquid 
metal. 

Long-Line Current Current though the 
earth between an anodic and a cathodic 
area that returns along an underground 
metallic structure. 

Low-Carbon Steel Steel having less 
than 0.30% carbon and no intentional al- 
loying additions. 

Low-Pressure Water Cleaning Water 
cleaning performed at pressures less than 
34 MPa (5,000 psig). 

Luggin Probe A small tube or capillary 
filled with electrolyte, terminating close 
to the metal surface of an electrode under 
study, which is used to provide an ion- 
conducting path without diffusion be- 
tween the electrode under study and a 
reference electrode. 



Lamellar Corrosion [See Exfoliation 
Corrosion.] 

Langelier Index A calculated satura- 
tion index for calcium carbonate that is 



M 



Martensite A hard supersaturated 
solid solution of carbon in iron char- 
acterized by an acicular (needle-like) 
microstructure. 



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Metal Dusting The catastrophic deteri- 
oration of a metal exposed to a carbona- 
ceous gas at elevated temperature. 

Metallizing The coating of a surface 
with a thin metal layer by spraying, hot 
dipping, or vacuum deposition. 

Mill Scale The oxide layer formed dur- 
ing hot fabrication or heat treatment of 
metals. 

Mixed Potential A potential resulting 
from two or more electrochemical reac- 
tions occurring simultaneously on one 
metal surface. 

Modulus Of Elasticity A measure of 
the stiffness or rigidity of a material. It is 
actually the ratio of stress to strain in the 
elastic region of a material. If determined 
by a tension or compression test, it is also 
called Young's Modulus or the coefficient 
of elasticity. 



N 



Natural Drainage Drainage from an 
underground or submerged metallic 
structure to a more negative (more an- 
odic) structure, such as the negative bus 
of a trolley substation. 

Near-White Blast Cleaned Surface A 

near-white blast cleaned surface, when 
viewed without magnification, shall be 
free of all visible oil, grease, dust, dirt, 
mill scale, rust, coating, oxides, corrosion 
products, and other foreign matter. Ran- 
dom staining shall be limited to not more 
than 5% of each unit area of surface (ap- 
proximately 58 cm 2 [9.0 in. 2 ]), and may 
consist of light shadows, slight streaks, or 
minor discolorations caused by stains of 



rust, stains of mill scale, or stains of pre- 
viously applied coating. [See NACE No. 
2/SSPC-SP 10.] 

Negative Return A point of connection 
between the cathodic protection negative 
cable and the protected structure. 

Nernst Equation An equation that ex- 
presses the exact electromotive force of an 
electrochemical cell in terms of the activ- 
ities of products and reactants of the cell. 

Nernst Layer The diffusion layer at the 
surface of an electrode in which the con- 
centration of a chemical species is as- 
sumed to vary linearly from the value in 
the bulk solution to the value at the elec- 
trode surface. 

Noble The positive direction of elec- 
trode potential, thus resembling noble 
metals such as gold and platinum. 

Noble Metal (1) A metal that occurs 
commonly in nature in the free state. 
(2) A metal or alloy whose corrosion 
products are formed with a small nega- 
tive or a positive free-energy change. 

Noble Potential A potential more ca- 
thodic (positive) than the standard hydro- 
gen potential. 

Normalizing Heating a ferrous alloy to 
a suitable temperature above the trans- 
formation range (austenitizing), holding 
at temperature for a suitable time, and 
then cooling in still air to a tempera- 
ture substantially below the transforma- 
tion range. 



o 



Open-Circuit Potential The potential 
of an electrode measured with respect to 



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a reference electrode or another electrode 
in the absence of current. 

Organic Zinc-Rich Coating Coating 
containing a metallic zinc pigment (typi- 
cally 75 wt% zinc or more in the dry film) 
in an organic resin. 

Overvoltage The change in potential of 
an electrode from its equilibrium or 
steady-state value when current is ap- 
plied. 

Oxidation (1) Loss of electrons by a con- 
stituent of a chemical reaction. (2) Corro- 
sion of a metal that is exposed to an oxi- 
dizing gas at elevated temperatures. 

Oxidation-Reduction Potential The 

potential of a reversible oxidation- 
reduction electrode measured with 
respect to a reference electrode, corrected 
to the hydrogen electrode, in a given 
electrolyte. 

Oxygen Concentration Cell [See Differ- 
ential Aeration Cell] 



Paint A pigmented liquid or resin ap- 
plied to a substrate as a thin layer that 
is converted to an opaque solid film af- 
ter application. It is commonly used as a 
decorative or protective coating. 

Paint System [See Coating System.] 

Parting [See Dealloying.] 

Passivation A reduction of the anodic 
reaction rate of an electrode involved in 
corrosion. 



Passivation Potential 

sive Potential] 



[See Primary Pas- 



Passive (1) The positive direction of 
electrode potential. (2) A state of a 
metal in which a surface reaction product 
causes a marked decrease in the corrosion 
rate relative to that in the absence of the 
product. 

Passive-Active Cell An electrochemi- 
cal cell, the electromotive force of which 
is caused by the potential difference be- 
tween a metal in an active state and the 
same metal in a passive state. 

Passivity The state of being passive. 

Patina A thin layer of corrosion prod- 
uct, usually green, that forms on the sur- 
face of metals such as copper and copper- 
based alloys exposed to the atmosphere. 

pH The negative logarithm of the hy- 
drogen ion activity written as: 

pH = -log 10 (a+) 

where a^ = hydrogen ion activity = 
the molar concentration of hydrogen 
ions multiplied by the mean ion-activity 
coefficient. 

Pickling (1) Treating a metal in a chem- 
ical bath to remove scale and oxides 
(e.g., rust) from the surface. (2) Complete 
removal of rust and mill scale by acid 
pickling, duplex pickling, or electrolytic 
pickling. [See SSPC-SP 8.] 

Pickling Solution A chemical bath, 
usually an acid solution, used for pick- 
ling. 

Pigment A solid substance, generally in 
fine powder form, that is insoluble in the 
vehicle of a formulated coating material. 
It is used to impart color or other spe- 
cific physical or chemical properties to the 
coating. 

Pipe-To-Electrolyte Potential The po- 
tential difference between the pipe 



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metallic surface and electrolyte that is 
measured with reference to an electrode 
in contact with the electrolyte. 

Pitting Localized corrosion of a metal 
surface that is confined to a small area 
and takes the form of cavities called pits. 

Pitting Factor The ratio of the depth of 
the deepest pit resulting from corrosion 
divided by the average penetration as 
calculated from mass loss. 

Plastic Deformation Permanent defor- 
mation caused by stressing beyond the 
elastic limit. 

Plasticity The ability of a material to de- 
form permanently (nonelastically) with- 
out fracturing. 

Polarization The change from the open- 
circuit potential as a result of current 
across the electrode /electrolyte interface. 

Polarization Admittance The recipro- 
cal of polarization resistance. 

Polarization Cell A DC decoupling de- 
vice consisting of two or more pairs 
of inert metallic plates immersed in an 
aqueous electrolyte. The electrical char- 
acteristics of the polarization cell are 
high resistance to DC potentials and low 
impedance of AC. 

Polarization Curve A plot of current 
density versus electrode potential for 
a specific electrode /electrolyte combina- 
tion. 

Polarization Decay The decrease in 
electrode potential with time resulting 
from the interruption of applied current. 

Polarization Resistance The slope 
(dE/di) at the corrosion potential of a 
potential (E)-current density (i) curve. 
(The measured slope is usually in good 



agreement with the true value of the 
polarization resistance when the scan 
rate is low and any uncompensated resis- 
tance is small relative to the polarization 
resistance.) 

Polarized Potential The potential 
across the structure /electrolyte interface 
that is the sum of the corrosion potential 
and the cathodic polarization. 

Polyester Type of resin formed by the 
condensation of polybasic and monoba- 
sic acids with polyhydric alcohols. 

Postweld Heat Treatment Heating and 
cooling a weldment in such a way as to 
obtain desired properties. 

Potential-pH Diagram A graphical 
method of representing the regions of 
thermodynamic stability of species for 
metal /electrolyte systems (also known 
as Pourbaix diagram). 

Potentiodynamic Refers to a technique 
wherein the potential of an electrode with 
respect to a reference electrode is varied at 
a selected rate by application of a current 
through the electrolyte. 

Potentiokinetic [See Potentiodynamic] 

Potentiostat An instrument for auto- 
matically maintaining a constant elec- 
trode potential. 

Potentiostatic Refers to a technique for 
maintaining a constant electrode poten- 
tial. 

Pot Life The elapsed time within which 
a coating can be effectively applied after 
all components of the coating have been 
thoroughly mixed. 

Poultice Corrosion [See Deposit Attack.] 

Pourbaix Diagram [See Potential-pH 
Diagram.] 



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Power Tool Cleaning Removal of loose 
rust, loose mill scale, and loose paint to 
degree specified by power tool chipping, 
descaling, sanding, wire brushing, and 
grinding. [See SSPC-SP 3.] 

Precipitation Hardening Hardening 
caused by the precipitation of a con- 
stituent from a supersaturated solid 
solution. 

Primary Passive Potential The poten- 
tial corresponding to the maximum ac- 
tive current density (critical anodic cur- 
rent density) of an electrode that exhibits 
active-passive corrosion behavior. 

Prime Coat [See Primer.] 

Primer A coating material intended to 
be applied as the first coat on an uncoated 
surface. The coating is specifically formu- 
lated to adhere to and protect the surface 
as well as to produce a suitable surface 
for subsequent coats. [Also referred to as 
Prime Coat.] 

Profile Anchor pattern on a surface pro- 
duced by abrasive blasting or acid treat- 
ment. 

Protective Coating A coating applied 
to a surface to protect the substrate from 
corrosion. 



Relative Humidity The ratio, ex- 
pressed as a percentage, of the amount of 
water vapor present in a given volume 
of air at a given temperature to the 
amount required to saturate the air at 
that temperature. 

Remote Earth A location on the earth 
far enough from the affected structure 
that the soil potential gradients associ- 
ated with currents entering the earth from 
the affected structure are insignificant. 

Rest Potential [See Corrosion Potential] 



Reversible Potential 

Potential] 



[See Equilibrium 



Rimmed Steel An incompletely deoxi- 
dized steel. [Also called Rimming Steel] 

Riser (1) That section of pipeline ex- 
tending from the ocean floor up to an off- 
shore platform. (2) The vertical tube in a 
steam generator convection bank that cir- 
culates water and steam upward. 

Rust Corrosion product consisting of 
various iron oxides and hydrated iron 
oxides. (This term properly applies only 
to iron and ferrous alloys.) 

Rust Bloom Discoloration indicating 
the beginning of rusting. 



R 



Reduction Gain of electrons by a con- 
stituent of a chemical reaction. 

Reference Electrode An electrode 
whose open-circuit potential is constant 
under similar conditions of measure- 
ment, which is used for measuring the 
relative potentials of other electrodes. 

Reference Half-Cell [See Reference Elec- 
trode.] 



Sacking Scrubbing a mixture of a ce- 
ment mortar over the concrete surface us- 
ing a cement sack, gunny sack, or sponge 
rubber float. 

Sacrificial Protection Reduction of cor- 
rosion of a metal in an electrolyte by gal- 
vanically coupling it to a more anodic 
metal (a form of cathodic protection). 



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335 



Scaling (1) The formation at high tem- 
peratures of thick corrosion-product lay- 
ers on a metal surface. (2) The deposition 
of water-insoluble constituents on a metal 
surface. 

Scanning Electron Microscope An 

electron optical device that images topo- 
graphical details with maximum contrast 
and depth of field by the detection, 
amplification, and display of secondary 
electrons. 

Sensitizing Heat Treatment A heat 
treatment, whether accidental, inten- 
tional, or incidental (as during welding), 
that causes precipitation of constituents 
(usually carbides) at grain boundaries, of- 
ten causing the alloy to become suscep- 
tible to intergranular corrosion or inter- 
granular stress corrosion cracking. 

Shallow Groundbed One or more an- 
odes installed either vertically or horizon- 
tally at a nominal depth of less than 15 m 
(50 ft) for the purpose of supplying ca- 
thodic protection. 

Shop Coat One or more coats applied in 
a shop or plant prior to shipment to the 
site of erection or fabrication. 

Shot Blasting Abrasive blast cleaning 
using metallic (usually steel) shot as the 
abrasive. 

Shot Peening Inducing compressive 
stresses in the surface layer of a material 
by bombarding it with a selected medium 
(usually steel shot) under controlled 
conditions. 

Sigma Phase An extremely brittle Fe-Cr 
phase that can form at elevated tempera- 
tures in Fe-Cr-Ni and Ni-Cr-Fe alloys. 

Slip A deformation process involving 
shear motion of a specific set of crystal- 
lographic planes. 



Slow Strain Rate Technique An ex- 
perimental technique for evaluating sus- 
ceptibility to environmental cracking. It 
involves pulling the specimen to fail- 
ure in uniaxial tension at a controlled 
slow strain rate while the specimen is in 
the test environment and examining the 
specimen for evidence of environmental 
cracking. 

Slushing Compound Oil or grease 
coatings used to provide temporary pro- 
tection against atmospheric corrosion. 



Heat Treatment Heating a 
a suitable temperature and 



Solution 

metal to 

holding at that temperature long enough 

for one or more constituents to enter 

into solid solution, then cooling rapidly 

enough to retain the constituents in 

solution. 

Solvent Cleaning Removal of oil, 
grease, dirt, soil, salts, and contaminants 
by cleaning with solvent, vapor, alkali, 
emulsion, or steam. [See SSPC-SP 1.] 

Spalling The spontaneous chipping, 
fragmentation, or separation of a surface 
or surface coating. 

Standard Electrode Potential The re- 
versible potential for an electrode process 
when all products and reactions are at 
unit activity on a scale in which the poten- 
tial for the standard hydrogen reference 
electrode is zero. 

Standard Jetting Water Water of suffi- 
cient purity and quality that it does not 
impose additional contaminants on the 
surface being cleaned and does not con- 
tain sediments or other impurities that are 
destructive to the proper functioning of 
water jetting equipment. 

Steel Shot Small particles of steel with 
spherical shape that are commonly used 



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NACE Glossary of Corrosion-Related Terms 



as an abrasive in abrasive blast cleaning 
or as a selected medium for shot peening. 

Stepwise Cracking [See Hydrogen- 
Induced Cracking.] 

Stray Current Current through paths 
other than the intended circuit. 

Stray-Current Corrosion Corrosion re- 
sulting from current through paths other 
than the intended circuit, e.g., by any ex- 
traneous current in the earth. 

Stress Corrosion Cracking Cracking of 
a material produced by the combined ac- 
tion of corrosion and tensile stress (resid- 
ual or applied). 

Stress Relieving (Thermal) Heating a 
metal to a suitable temperature, holding 
at that temperature long enough to re- 
duce residual stresses, and then cooling 
slowly enough to minimize the develop- 
ment of new residual stresses. 

Subsurface Corrosion [See Internal 
Oxidation.] 

Sulfidation The reaction of a metal or 
alloy with a sulfur-containing species to 
produce a sulfur compound that forms 
on or beneath the surface of the metal or 
alloy. 

Sulfide Stress Cracking Cracking of a 
metal under the combined action of ten- 
sile stress and corrosion in the presence 
of water and hydrogen sulfide (a form of 
hydrogen stress cracking). 



Tack Coat A thin wet coat applied to the 
surface that is allowed to dry just until it 
is tacky before application of a thicker wet 



coat. (Use of a tack coat allows application 
of thicker coats without sagging or runs.) 

Taf el Plot A plot of the relationship be- 
tween the change in potential (E) and the 
logarithm of the current density (log i) of 
an electrode when it is polarized in both 
the anodic and cathodic directions from 
its open-circuit potential. 

Tafel Slope The slope of the straight- 
line portion of the E log i curve on a Tafel 
plot. (The straight-line portion usually oc- 
curs at more than 50 mV from the open- 
circuit potential.) 

Tarnish Surface discoloration of a 
metal resulting from formation of a film 
of corrosion product. 

Thermal Spraying A group of pro- 
cesses by which finely divided metallic 
or nonmetallic materials are deposited in 
a molten or semimolten condition to form 
a coating. 

Thermogalvanic Corrosion Corrosion 
resulting from an electrochemical cell 
caused by a thermal gradient. 

Throwing Power The relationship be- 
tween the current density at a point on 
a surface and its distance from the coun- 
terelectrode. The greater the ratio of the 
surface resistivity shown by the electrode 
reaction to the volume resistivity of the 
electrolyte, the better is the throwing 
power of the process. 

Topcoat The final coat of a coating sys- 
tem. [Also referred to as Finish Coat.] 

Transpassive The noble region of po- 
tential where an electrode exhibits a 
higher-than-passive current density. 

Tuberculation The formation of local- 
ized corrosion products scattered over the 



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337 



surface in the form of knob-like mounds 
called tubercles. 



u-v-w 



Ultimate Strength The maximum 
stress that a material can sustain. 

Ultrahigh-Pressure Water Jetting Wa- 
ter jetting performed at pressures above 
170 MPa (25,000 psig.) 

Underfilm Corrosion [See Filiform- 
Corrosion.] 

Vehicle The liquid portion of a formu- 
lated coating material. 

Void (1) A holiday, hole, or skip in a 
coating. (2) A hole in a casting or weld 
deposit usually resulting from shrinkage 
during cooling. 

Wash Primer A thin, inhibiting primer, 
usually chromate pigmented, with a 
polyvinyl butyral binder. 

Water Cleaning Use of pressurized wa- 
ter discharged from a nozzle to remove 
unwanted matter (e.g., dirt, scale, rust, 
coatings) from a surface. 

Water Jetting Use of standard jetting 
water discharged from a nozzle at pres- 
sures of 70 MPa (10,000 psig) or greater 
to prepare a surface for coating or inspec- 
tion. 

Weight Coating An external coating 
applied to a pipeline to counteract buoy- 
ancy. 

White Metal Blast Cleaned Surface A 

white metal blast cleaned surface, when 



viewed without magnification, shall be 
free of all visible oil, grease, dust, dirt, 
mill scale, rust, coating, oxides, corrosion 
products, and other foreign matter. [See 
NACENo. 1/SSPC-SP5.] 

Weld Decay Intergranular corrosion, 
usually of stainless steel or certain nickel- 
base alloys, that occurs as the result of 
sensitization in the heat-affected zone 
during the welding operation. [This is not 
a preferred term.] 

Wet Film Gauge Device for measuring 
wet film thickness of a coating. 

Working Electrode The test or speci- 
men electrode in an electrochemical cell. 

Wrought Metal in the solid condition 
that is formed to a desired shape by work- 
ing (rolling, extruding, forging, etc.), usu- 
ally at an elevated temperature. 



X-Y-Z 



Yield Point The stress on a material 
at which the first significant permanent 
or plastic deformation occurs without 
an increase in stress. In some materials, 
particularly annealed low-carbon steels, 
there is a well-defined yield point from 
the straight line defining the modulus of 
elasticity. 

Yield Strength The stress at which a 
material exhibits a specified deviation 
from the proportionality of stress to 
strain. The deviation is expressed in terms 
of strain by either the offset method (usu- 
ally at a strain of 0.2%) or the total- 
extension-under-load method (usually at 
a strain of 0.5%.) 



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Appendix 



Additional Important Information 
on Underground Corrosion Control 



Copies of federal regulations concerning the installation and operation of underground 
pipelines are available as follows: 

Transportation of Natural and Other Gas by Pipeline: Minimum Safety Standards. Fed- 
eral Register, Vol. 35, Number 161, Part II, August 19, 1970. Title 49. Parts 190, 192. 

Transportation of Liquids by Pipeline. Federal Register, Vol. 35, No. 218, November 7, 
1970. Title 49. Parts 180, 195. 

Available from Department of Transportation, Office of Pipeline Safety, Washington, 
D.C. 20590. 



NACE REFERENCED STANDARDS 



Standard 
Coatings 

MR0274-95 

RP0185-96 
RP0190-95 
RP0399-99 
RP0394-94 
RP0375-99 



Standard Title 



Material Requirements for Polyolefin Cold-Applied Tapes for Underground Sub- 
merged Pipeline Coatings-Item No. 21301 

Extruded Polyolefin Resin Coating Systems with Soft Adhesives for Underground 
or Submerged Pipe-Item No. 21029 

External Protective Coatings for Joints, Fittings, and Valves on Metallic Under- 
ground or Submerged Pipelines and Piping Systems-Item No. 21042 
Plant-Applied, External Coal Tar Enamel Pipe Coating System: Application, 
Performance, and Quality Control-Item No. 21089 

Application, Performance, and Quality Control of Plant- Applied, Fusion-Bonded 
Epoxy External Pipe Coating-Item No. 21064 
Wax Coating Systems for Underground Piping Systems-Item No. 21013 



339 



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340 Additional Important Information on Underground Corrosion Control 



Surface 
Preparation 

NACE No. 

1 /SSPC-SP 5 White Metal Blast Cleaning (RP0494-2000)-Item No. 21065 

NACE No. 

2/SSPC-SP 10 Near-White Metal Blast Cleaning (RP0594-2000)-Item No. 21066 

NACE No. 

3/SSPC-SP 6 Commercial Blast Cleaning (RP0694-2000)-Item No. 21067 

NACE No. 

4/SSPC-SP 7 Brush-Off Blast Cleaning (RP0794-2000)-Item No. 21068 

NACE No. 

5 /SSPC-SP 12 Surface Preparation and Cleaning of Steel and Other Hard Materials by High- 

and Ultrahigh-Pressure Water Jetting Prior to Recoating (RP0595-95)-Item No. 

21076 
NACE No. 
8/SSPC-SP 14 Industrial Blast Cleaning (RP0299-99)-Item No. 21088 

Holiday 
Testing 

RP0274-98 High- Voltage Electrical Inspection of Pipeline Coatings Prior to Installation-Item 

No. 21010 
RP0188-99 Discontinuity (Holiday) Testing of Protective Coatings-Item No. 21038 

RP0490-95 Holiday Detection of Fusion-Bonded Epoxy External Pipeline Coatings of 250 to 

760 micrometers (10 to 30 mils)-Item No. 21045 

Cathodic 
Protection 

RP0169-96 Control of External Corrosion on Underground or Submerged Metallic Piping 

Systems-Item No. 21001 
RP0 177-95 Mitigation of Alternating Current and Lightning Effects on Metallic Structures 

and Corrosion Control Systems-Item No. 21021 
RP0200-2000 Steel-Cased Pipeline Practices-Item No. 21091 

RP0286-97 Electrical Isolation of Cathodically Protected Pipelines-Item No. 21032 

RP0572-95 Design, Installation, Operation, and Maintenance of Impressed Current Deep 

Groundbeds-Item No. 21007 

Referenced Standards can be ordered from NACE International Item no. shown is the NACE 
catalogue order number. 

Purchase Information 

The Standards listed above may be purchased from NACE International, 1440 South Creek Drive, 
Houston, Texas 77084. Write or call for prices. Phone: (281) 228-6223. 

Note 

The above information is revised periodically. Please check current NACE Products Guide or 
www.nace.org for updates and revisions. 



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Index 



A 

Acidity 

bacteria and, 277-279 

pH values, 4, 90-91, 279 

soil and, 90-91, 317 
Activation polarization, 304 
Adhesion tests, 10 
Aeration cell, 308-309 
Alkaline conditions, 11, 62, 64, 91 
Alternative power sources, 201-210 
Aluminum anodes, 177, 301 
Aluminum piping, 40, 62-63 
Ammeter clamps, 115-116 
Amphoteric materials, 64 
Anaerobic conditions, 66, 97, 280 
Anode systems 

backfill and, 134-135, 184, 255 

cathodes and, 23, 277-299, 313-314 

connections and, 176 

deep anodes, 145-155, 268-269 

distributed, 144-145 

efficiency of, 177-178, 186 

galvanic, 23, 140-144, 177-199, 221-222 

ground beds, 140-144, 255-256 

high-potential, 28 

horizontal, 138-139 

impressed current, 144-145 

installation of, 193-199 

interference and, 221-222 

life of, 186-187, 269 

maintenance, 261-271 



multiple anode bed, 193 
performance, 190-193 
resistance equation, 134 
size of, 313-314 
spacing of, 292-294 
suspension systems, 150 
types of, 166-169 
vertical, 132-133 
See also specific types 
Anodic reaction, 2 
Antimony electrode, 122 
Area relationships, 313-314 



B 

Back voltage, 135 
Backfills, 132-133, 134 

anodes and, 184, 255 

cable trench, 256 

carbon, 150-151 

carbonaceous, 132, 139-140, 174, 256 

chemical, 184, 186, 255 

materials, 174-175, 196 

See also specific types 
Bacteria, 273-284 
Bare lines, 92-93, 99 
Barnes method, 89, 90 
Bellhole surveys, 67, 97-98 
Beta profile, 230 
Biocides, 274 
Biofilms, 275, 276 



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Index 



Blistering, 8 

Bolt insulation, 250 

Bond, drainage, 219-221, 233-236 

Butler- Volmer equation, 307 



C 

Cables 

backfill and, 256 

ground bed, 255 

locators, 114 

resistance, 136 

trench for, 256 

types of, 175-176 
Calibration records, 128 
Carbon backfill, 150-151 
Carbonaceous backfill, 132, 174, 256 
Carbonic acid solution, 277 
Cased crossings, 245-248 

avoidance of, 36 

casing compounds, 271 

inspection of, 258 

maintenance of, 270-271 

short circuits, 247-248 

survey of, 262 

test methods, 245-248 
Cast iron anodes, 168, 254 
Cast iron pipes, 49-62 
Casing end seals, 246 
Casing insulators, 246 
Cathodic protection (CP), 5, 21-48 

alternative power sources, 201-210 

application of, 23-28 

bacteria and, 282 

bare lines, 44 

basic theory, 21-23 

coating and, 26-28 

cost of, 146, 285-292 

criteria for, 24-25, 49-64 

de-energizing, 56-57 

deep anodes, 145-155, 268-269 

definition of, 6 

disbondment, 28 

E-log I criteria, 62-63 

effectiveness of, 39-47 

foreign pipelines and, 41-43 

galvanic anodes, 23-24, 177-199, 
221-222 



ground beds and, 41-43 

impressed current, 23-24, 43, 157-176 

installation of, 255-259 

instrumentation, 101-129 

interference, 212-223 

maintenance procedures, 261-271 

mV criteria, 50-58, 60 

net protective criteria, 58-60 

overprotection, 56-57 

polarization and, 52-58 

potential shift, 50-58, 60 

power sources, 201-210 

rectifiers, 157-176 

shielding, 33 

stray current from, 211-236 

testing for, 92-100 

underground piping, 50-58 

See also specific problems, types 
CCVTs. See Closed cycle vapor 

turbogenerators 
Centralizers, 150 
Close ground beds, 30-32 
Close interval surveys, 71-73, 126-127 
Closed cycle vapor turbogenerators (CCVTs), 

202-204 
Coal tar enamel (CTE), 8, 15 
Coatings, 7-20, 93-99 

adhesion of, 8 

applicability, 8 

bacteria and, 281-282 

degradation of, 6 

dielectric, 8, 119 

disbonding, 281-282 

effectiveness of, 7-11 

function of, 6 

improper application, 11 

inspection of, 12-14 

maintenance, 265-266 

multi-layer systems, 8 

nontoxic, 9 

overprotection, 28 

pinholes, 119 

poorly-coated lines, 221 

recoating, 266 

repair of, 9, 12 

resistivity, 26 

soil stress and, 8-11, 265, 281 

specifications for, 10-12 



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343 



surveys of, 93-97, 265-266 

See also Holidays; specific problems, types 
Coke breeze, 174, 256 
Compression couplings, 133, 176 
Computer surveys, 265 
Concentration polarization, 307 
Congested areas, 37-39 
Connection methods, 176 
Construction practices, 237-259, 287 
Coordinating committees, 236 
Copper-copper sulfate electrode, 25, 121-122 
Copper piping, 63-64 
Copper sulfate electrodes (CSE), 68, 124-128, 

214, 302 
Cost estimates, 285-292 
Coupons, 120-124 
CR See Cathodic protection 
Cracking, 307 

Crimp-type connections, 133, 176 
Crossings, foreign-line, 41-44, 213-215, 222, 

262, 271 
CSE. See Copper sulfate electrode 
CTE. See Coal tar enamel 
Current interrupters, 110-111, 113 



E-log I curve criterion, 61-63 
Economic factors, 285-295 
Efficiency, of anodes, 177-178, 186 
Electric shielding, 33-39, 224-225 
Electrolysis switches, 262 
Electromagnetic conductivity method, 

148 
Electromotive force (EMF), 298-299 
Embrittlement, 54 
EMF. See Electromotive force 
Enamels, 8, 15 

Engine-generator systems, 201-202 
Environmental effects, 9 
Environmental polarization, 316-317 
Epoxies, 8, 17-18, 281-282 
Equilibrium potential, 303, 315 
Equipment vendors, 101 
Equivalent circuit, 30 
Evaluation techniques, 65-100 
Evans diagrams, 54, 305, 308, 315, 

317 
Extrusion systems, 15-17 



D 

Deep anode systems, 145-155, 268-269 

Deep well beds, 268-269 

Delta voltage, 219 

Department of Environmental Resources 

(DER), 7 
Department of Transportation-Office of 

Pipeline Safety (DOT/OPS), 7 
Depolarization, 280 
DER. See Department of Environmental 

Resources 
Dielectric coatings, 8, 119 
Differential aeration cells, 308-310 
Differential corrosion cells, 2-5, 310-313 
Disbonding, 9, 11, 28 
Dissimilar metal piping, 63-64 
Distributed anodes, 144-145 
DOT/OPS. See Department of 

Transportation-Office of Pipeline 

Safety 
Drainage bonds, 219-221, 233-236 
Dwight equations, 149 



Faraday constant, 298, 300 

Faraday's law, 307 

Fatigue cracking, 8 

FBE. See Fusion-bonded epoxies 

Ferrous ion concentrations, 276 

Flanges, 249-250 

Flooding, 257 

Foreign line crossings, 41-44, 213-215, 

222, 262, 271 
Four-pin method, 85-87, 105, 148 
Four-wire test points, 79-81, 239, 247 
Fuel cells, 210 
Fungi, 273-284 
Fusion-bonded epoxies (FBE), 8, 17-18, 

281-282 



Galvanic anode systems, 23, 140-144, 

177-199, 221-222, 288 
Galvanic corrosion, 310-312 
Galvanic series, 303-304 
Gas blocking, 269 



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Index 



Gas turbines, 209 
Generators, 201-202 
Genetic engineering, 275 
Gibbs free energy, 297-298 
Graphite anodes, 166-167, 174-175 
Ground bed systems, 28-33 

cables and, 255, 256 

cathodic protection, 41-43 

close, 30-32 

designing, 131-156 

galvanic anodes, 140-144 

impressed current systems, 132-140, 
166-176 

installing, 256 

locating, 131-132 

maintenance of, 268-269 

stray current, 224-225 

vertical anodes, 133 
Grounding cells, 252-254, 262 
Gypsum-bentonite backfill, 188 



Half-cell electrodes, 2-3, 298 
Header wire, 193 
High-potential anodes, 28 
High-resistivity coating, 26 
Holidays, 5, 8 

coatings and, 6, 266 

detection, 12, 118-120, 238-239 

foreign lines and, 215 

inspection and, 13-14 
Horizontal anodes, 138 
Hotspot protection, 69, 180 
Hydrogen, 51, 97-98 



Impedance, 102 

Impressed current systems, 288 

cathodic protection and, 23-24, 157-176 

deep anodes and, 145-146 

ground beds, 132-140, 166-176 

insulation, 259 

interference, 180 

survey and, 262 
Inspections, 12-14, 257 
Installation procedures, 193-199, 219 



Instrumentation, 101-129 

Insulation 
barrier, 33-34 
buried wire and, 254 
couplings and, 10 
grounding cells, 252-254 
inspection, 116, 246, 258 
joints and, 176, 249-254, 258 
shielding and, 33-34 
zinc anode, 252-253 

Interference, 40-41 

cathodic protection and, 212-223 
impressed current and, 180 
information on, 46-47 
stray current and, 219-224 

Interrupters, 110-111, 113, 214 

Investment costs, 286 

Ion concentrations, 4, 276 

IR voltage drops, 50, 69 

Iron-oxidizing bacteria, 279 

Iron pipes, 49-62 

Iron sulfide, 276, 282 

Isolation surge protectors (ISP), 254 

ISP. See Isolation surge protectors 



) 

Jeeping of coatings, 12 

Joint insulation, 176, 249-254, 258 



Kinetics, 304-308 



Leaks, pipeline, 39, 291 
Leapfrog technique, 75-76 
Lightning, 157-158, 252-254, 262 
Line current measurements, 77-84 
Liquid coating systems, 18 
Locators, for cables, 114 
Long-line current flow, 51, 83 

M 

Magnesium anodes, 180-184, 188, 190-193, 

223, 232, 301 
Magnetic disturbances, 236 



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Index 



345 



Maintenance procedures, 261-271, 287, 

294-295 
Metal deposition, 278-279 
Metal-reducing bacteria (MRB), 275 
Metal reduction, 275, 280 
Meter accessories, 124 
MIC. See Microbiologically influenced 

corrosion 
Microbiologically influenced corrosion 

(MIC), 97, 273-284 
Mill coated pipe, 15, 237-238 
Mill scale corrosion, 311 
Mixed-metal oxide anodes, 168 
Moisture content, of soil, 4 
Mortar/concrete systems, 36 
MRB. See Metal-reducing bacteria 
Multi-layer systems, 8, 18-19 
Multimeters, 102 
Multiple anode bed, 193 
mV shift criteria, 50-61 



N 

National Electrical Code (NEC), 257 

National Insitute of Standards and 

Technology (NIST), 128 
Natural gas systems, 204, 209 
NEC. See National Electrical Code 
Nernst equation, 300 
Net protective criterion, 49, 58-60 
Niobium, 172 
NIST. See National Institute of Standards and 

Technology 
Noble metals, 3 
Null ampere test, 81 

O 

Occupational Safety and Health 

Administration (OSHA), 7 
Off-potentials, 28 
Ohmic voltage drops, 50 
Ohm's law, 77-78 
OPS. See Department of 

Transportation-Office of Pipeline 

Safety 
OSHA. See Occupational Safety and Health 

Administration 



Over-the-line potential survey, 

69-73 
Overprotection, 28, 51, 56-57 
Overvoltage, 304 
Oxidation, 1-2 
Oxide film, 317 
Oxygen, 1-2, 4, 279 



PE. See Polyethylene 

Peel strength, 9 

pH values, 4, 90-91, 277-279, 317 

Pipe-to-soil potential, 29, 56, 68, 71, 95, 

102, 222, 302 
Pit gages, 108-109 
Pitting, 265, 280 
Plasmids, 275 
Plastic resins, 256 
Platinum anodes, 169-172 
Polarization, 55 

cells, 262 

concentration, 307 

CP system, 52-58 

decay, 55 

definition of, 53, 304 

environmental, 316-317 

hydrogen, 97 

off -potential values, 55 
Polyethylene (PE), 255, 281 
Polyolefin, 16-19, 281 
Polysaccharide materials, 274 
Polyvinyl chloride (PVC), 281 
Portable instruments, 122 
Potential shift criterion, 60-61 
Potential values, 3-4, 25, 71 
Power costs, 287 
Power sources, 201-210 
Priming, 12, 237 
Probe rods, 81-82, 247 
Pulse generators, 112-114 
PVC. See Polyvinyl chloride 

R 

Rail transit systems, 226-230 
Rankine cycle turbine, 202 
Recording instruments, 106-108 



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Index 



Rectifiers 

constant potential, 160 

efficiency of, 163-165 

installation details, 165 

maintenance, 266-268 

placement of, 257 

power costs, 287 

selection of, 157 

size of, 160-161 

specifications, 162-163 

transformers, 158 
Reduction reaction, 1-2 
Reference electrodes, 3, 120-124, 301-302 
Reinforcing wire, 36-37 
Remote earth, 71-72, 146 
Remote ground beds, 28-33 
Resistance drop method, 77 
Resistivity testing, 105, 124-125 

accessories, 124-125 

coatings and, 9 

drop method, 77 

resistance to earth, 135 

soil and, 84-90, 105-106, 148-149, 
191-193 

voltmeters and, 102-103 

See also specific methods 
Reverse current flow, 235 
Ribbon anodes, 197 
Rubber splicing compound, 256 
Rudenberg formula, 30 



Salts, in soils, 90 
Saturated solution, 128 
Sea water, 255 
Seals, 35, 151-152 
Selenium stacks, 159 
Shielding, 33-39, 219, 224-225 
Short circuits, 34-36, 247-248 
Side drain technique, 76-77 
Silicon diodes, 157, 159 
Six-wire test point, 239-240 
Soils 

chemical analysis, 90-91 
deep formations, 148-149 
dissimilar, 312-313 
moisture content, 195 



resistivities, 84-90, 105-106, 
148-149, 191-193 

salts, 90 

sandy, 281 

stress, 8-11, 265, 281 

types, 313 
Solar power systems, 206-207 
Solvent action, 255 
Spacing, of anodes, 292-294 
Spark gaps, 262 
Spin-bolt couplings, 176 
Spores, 274-275 
Steel piping, 49-62 
Storage batteries, 208 
Stray current, 40, 211-236 
Strip anodes, 197, 198 
Sulfate reduction, 275-277 
Sulfides, 276 
Surface anodes, 268 
Surface preparation, 237 
Surges, 157, 252-254 
Survey methods, 65-100, 262-266 
Suspension systems, 150 



Tafel slopes, 55, 61, 307, 315, 317 
Tape systems, 14-15, 256 
Telluric effects, 236 
Test coupons, 124 
Test points, 239-245, 258, 269-270 
Test rectifiers, 117-118 
Test wires, 243-244 
Thermite welding, 133 
Thermodynamics, 1, 297-317 
Thermoelectric generators, 204-206 
Transformers, 158 
Transit systems, 226-232 
Trench, cable, 256 
Turbines, 209 
Turbogenerators, 202-204 
Two-wire test points, 77, 239 



U 

Ultrasonic gage, 109 
Urethanes, 18 
Utilization factor, 186 



PI: FCE 
CE003-ID 



CE003-Peabody November 3, 2000 12:50 Char Count= 18171 



Index 



347 



Vendors, of equipment, 101 
Vent pipes, 149-150, 246, 247 
Vertical anodes, 132-133 
Voltmeters, 101-103, 229, 239-240 

W 

Wall thickness, 108-109 
Weight coating, 36-37 
Welding, 35, 246, 270 



Well design, 149-152 
Wenner method, 85-86, 105 
Werner procedure, 81 
Wind-powered generators, 208- 

209 
Wires, reinforcing, 36-37 



Zinc anodes, 178-193, 223, 
252-253, 301