evaluation of above-ground potential measurements for assessing pipeline integrity

8/12/2019 Evaluation of Above-ground Potential Measurements for Assessing Pipeline Integrity

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EVALUATION OF ABOVE-GROUND POTENTIALMEASUREMENTS FOR ASSESSING PIPELINE INTEGRITY

By

JAMES PATRICK MCKINNEY

A THESIS PRESENTED TO THE GRADUATE SCHOOLOF THE UNIVERSITY OF FLORIDA IN PARTIAL FULFILLMENT

OF THE REQUIREMENTS FOR THE DEGREE OFMASTER OF SCIENCE

UNIVERSITY OF FLORIDA

2006



ACKNOWLEDGMENTSI would like to thank my advisor, Dr. Mark Orazem, for his support, guidance,

and his belief in me. He has shown me not only how to improve my abilities in

research, but also how to improve my abilities as a person. I would like to thank

Dr. Oliver Moghissi of CC Technologies and Daphne D’Zurko of Northeast Gas

Association for sponsoring this project. I appreciate Dr. Moghissi’s willingness to

work closely with me on this project. He beneted not only the project, but also

my abilities and understanding regarding both the fundamentals of the project

and corrosion engineering in general. I would like to thank Dr. Douglas Riemer

for offering technical support needed for running CP3D simulations. I would also

like to thank everyone in my research group for their daily and continuous support.

This includes Nelliann Perez-Garcia, Mei-Wen Huang, Michael Matlock, Sunil Roy,

and Chia Chu, who has worked closely with me on this project.

Finally, I would like to thank my parents, my sister, and my brother for their

love and support throughout my life. I appreciate them instilling the value of

education in me at an early age.

ii



TABLE OF CONTENTS page

ACKNOWLEDGMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

LIST OF TABLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

LIST OF FIGURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi

ABSTRACT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix

CHAPTER

1 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 LITERATURE REVIEW . . . . . . . . . . . . . . . . . . . . . . . . . . 3

2.1 External Corrosion Direct Assessment (ECDA) . . . . . . . . . . . 32.2 Corrosion Background . . . . . . . . . . . . . . . . . . . . . . . . 52.3 Cathodic Protection . . . . . . . . . . . . . . . . . . . . . . . . . . 9

2.3.1 Background . . . . . . . . . . . . . . . . . . . . . . . . . . 92.3.2 Principles of CP . . . . . . . . . . . . . . . . . . . . . . . . 11

2.4 Internal Inspection Techniques . . . . . . . . . . . . . . . . . . . . 152.5 Above-Ground Measurement (Indirect) Techniques . . . . . . . . . 17

2.5.1 Close Interval Survey (CIS) . . . . . . . . . . . . . . . . . . 172.5.2 Direct Current Voltage Gradient (DCVG) . . . . . . . . . . 202.5.3 Alternating Current Voltage Gradient (ACVG) . . . . . . . 232.5.4 Current Attenuation . . . . . . . . . . . . . . . . . . . . . . 24

3 CP3D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

3.1 Description of CP3D . . . . . . . . . . . . . . . . . . . . . . . . . 263.2 Mathematical Development . . . . . . . . . . . . . . . . . . . . . . 27

3.2.1 Bare Steel . . . . . . . . . . . . . . . . . . . . . . . . . . . 303.2.2 Coated Steel . . . . . . . . . . . . . . . . . . . . . . . . . . 313.2.3 Sacricial and Impressed Current Anodes . . . . . . . . . . 32

3.3 Replication of Techniques . . . . . . . . . . . . . . . . . . . . . . . 333.3.1 CIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333.3.2 DCVG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 343.3.3 ACVG . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 393.3.4 Current Attenuation . . . . . . . . . . . . . . . . . . . . . . 39

3.4 CP3D settings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 403.4.1 Matrix of Simulations . . . . . . . . . . . . . . . . . . . . . 40

iii



4 RESULTS AND TRENDS . . . . . . . . . . . . . . . . . . . . . . . . . . 42

4.1 Current and Potential Distributions in the Pipeline . . . . . . . . 424.2 Trends from Simulation Results . . . . . . . . . . . . . . . . . . . 484.3 Flaw Size Predictors . . . . . . . . . . . . . . . . . . . . . . . . . 57

4.3.1 CIS Predictor . . . . . . . . . . . . . . . . . . . . . . . . . 574.3.2 DCVG Predictor . . . . . . . . . . . . . . . . . . . . . . . . 63

5 CONCLUSIONS AND FUTURE WORK . . . . . . . . . . . . . . . . . . 65

5.1 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 655.2 Future Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

BIOGRAPHICAL SKETCH . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

iv



LIST OF TABLESTable page

3–1 The matrix of model runs showing the ranges of different parametersthat were varied. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

4–1 Three simulations different only in CP level. Parameters are 12in Dp,4ft DOC, and 0.5 kohm-cm (soil resistivity) . . . . . . . . . . . . . . 58

v



LIST OF FIGURESFigure page

2–1 A CP system with a sacricial anode. . . . . . . . . . . . . . . . . . . 12

2–2 A CP system with impressed current. . . . . . . . . . . . . . . . . . . 14

2–3 A representation of on- and off-potential proles which show how CISdips are categorized. Each data point represents a measurement atthe soil surface directly over the pipeline. . . . . . . . . . . . . . . . 19

2–4 The percent-IR calculation is shown using the lateral voltage gradi-

ents with the interpolated value of IR drop over the coating aw. . 222–5 A diagram showing how an IR measurement is interpolated at the

ground surface above the coating aw. . . . . . . . . . . . . . . . . 23

3–1 An image from CP3D showing the physical orientation of the soil sur-face with respect to the pipeline. The darker area on the pipelinerepresents the coating aw or holiday. . . . . . . . . . . . . . . . . 27

3–2 A prole of on- and off-potentials from CP3D simulation data wherethe dip indicates the location of the coating aw. Each data pointrepresents a measurement at the soil surface directly over the pipeline. 34

3–3 A schematic of how CIS indication is calculated using the nodes of the soil surface. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3–4 A schematic of how DCVG measurements are made using CP3D. . . 35

3–5 A prole of DCVG measurements above the pipeline. The peak valuerepresents the overall DCVG indication. . . . . . . . . . . . . . . . 36

3–6 A schematic of how percent-IR is measured and calculated. . . . . . . 38

3–7 A prole of IR drops in the perpendicular direction to the pipeline.

The IR drops are all at the same lengthwise position as the coatingaw in respect to the pipeline. . . . . . . . . . . . . . . . . . . . . . 38

4–1 A plot of current density as it changes along the length of the pipeline.Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp 43

4–2 An angular plot of current density at the location of the coating aw.Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp 44

vi



4–3 A plot of soil surface on-potentials as they change along the length of the pipeline. Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ftDOC, 12in Dp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

4–4 A plot of steel voltage as it changes along the length of the pipeline.

Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp 464–5 Current distribution along the pipeline is shown for changing soil re-

sistivities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

4–6 DCVG indication in mV is plotted versus aw size as soil resistivity(ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC:4ft, anode voltage: 5V . . . . . . . . . . . . . . . . . . . . . . . . . 49

4–7 DCVG indication in percent-IR is plotted versus aw size as soil re-sistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in,DOC: 4ft, anode voltage: 5V . . . . . . . . . . . . . . . . . . . . . 50

4–8 DCVG indication in mV is plotted versus aw size as CP level is var-ied. Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, DOC:4ft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

4–9 DCVG indication in percent-IR is plotted versus aw size as CP levelis varied. Simulation parameters are Rs: 500 ohm-cm, Dp: 12in,DOC: 4ft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

4–10 DCVG indication in mV is plotted versus aw size as DOC is varied.Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, CP level: high 52

4–11 DCVG indication in mV is plotted versus aw size as Dp is varied.Simulation parameters are Rs: 500 ohm-cm, DOC: 4in, CP level:high . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

4–12 CIS on-potential dip indication is plotted versus aw size as soil re-sistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in,DOC: 4ft, CP level: high . . . . . . . . . . . . . . . . . . . . . . . . 54

4–13 DCVG indication in mV is plotted versus aw size as soil resistivity(ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC:4ft, CP level: high . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

4–14 CIS off-potential dip indication is plotted versus aw size as soil re-sistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in,DOC: 4ft, CP level: high . . . . . . . . . . . . . . . . . . . . . . . . 56

4–15 A prole of soil surface on- and off-potentials from a simulated CISsurvey. Simulation parameters are aw size: 36 in 2 , Rs: 500ohm-cm, Dp: 12in, DOC: 4ft, CP level: high . . . . . . . . . . . . . . . 56

vii



4–16 A representation of soil surface on-potential proles taken along thelength of the pipeline. The anode voltage is held constant for eachsimulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

4–17 Current attenuation in mA is plotted against aw size as soil resistiv-

ity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC:4ft, CP level: high . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

4–18 Current attenuation in percent is plotted against aw size as soil re-sistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in,DOC: 4ft, CP level: high . . . . . . . . . . . . . . . . . . . . . . . . 59

4–19 A plot of CIS indications versus aw size from simulation data. CISindication is the difference in the on-potential dip and the off-potentialdip. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

4–20 A prole of general behavior of on- and off-potentials along the cen-

terline at the soil surface. . . . . . . . . . . . . . . . . . . . . . . . 604–21 A plot of CIS indication divided by IR total versus the square root of

the aw size. The denition of IR total is illustrated in Figure (4-20). 61

4–22 An exponential plot of slope versus soil resistivity. Data was at a depthof cover of 4ft and a pipe diameter of 6 inches. . . . . . . . . . . . . 62

4–23 A plot of pre-exponential factors versus the corresponding depth of cover. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

4–24 Actual aw size is plotted versus predicted aw size for each simula-tion using the derived expression for m. . . . . . . . . . . . . . . . 63

4–25 Actual aw size is plotted versus predicted aw size for each simula-tion using DCVG indications. . . . . . . . . . . . . . . . . . . . . . 64

viii



Abstract of Thesis Presented to the Graduate Schoolof the University of Florida in Partial Fulllment of theRequirements for the Degree of Master of Science

EVALUATION OF ABOVE-GROUND POTENTIALMEASUREMENTS FOR ASSESSING PIPELINE INTEGRITY

By

James Patrick McKinney

May 2006

Chair: Mark E. OrazemMajor Department: Chemical Engineering

Indirect techniques based on currents and potentials measured at the soil

surface can be used to evaluate the condition of buried pipelines. These techniques

are the foundation of External Corrosion Direct Assessment (ECDA) protocols. A

quantitative relationship between ECDA signals and the presence of coating defects

or aws has not previously been established. Such a relationship is anticipated

to be dependent on parameters such as soil resistivity and the condition of the

defect-free coating.

The objective of this work was to simulate the sensitivity to the pipe coating

condition of above-ground ECDA techniques. This project made use of a mathe-

matical model CP3D which was developed at the University of Florida to simulate

the operation of a cathodic protection system for mitigating corrosion of buried

pipelines. This program allows for the creation of a visualized three-dimensional

environment. It was developed as a tool to help improve the ability to assess the

condition of underground pipelines. It takes into account a wide variety of different

parameters such as pipeline diameter, depth of cover, soil resistivity, coating aw

(holiday) size, coating condition, level of cathodic protection, and polarization

ix



resistance. A matrix of simulation runs has been completed within which each of

these parameters was varied.

Above-ground ECDA procedures were simulated using results from the model.

The model generates results that include current and voltage distributions alongthe pipeline as well as the on- and off-potentials calculated at locations on the

ground surface above the pipeline. The ECDA techniques or tools that are per-

formed include Close Interval Survey (CIS), Direct Current Voltage Gradient

(DCVG), Alternating Current Voltage Gradient (ACVG), and Current Attenu-

ation. Results from these techniques show that soil and coating parameters are

signicant. Currently engineers use subjective judgment based on ECDA indication

results measured. However, these results can be signicantly skewed based on

changes in these parameters which can affect the interpretation of results.

x



CHAPTER 1INTRODUCTION

External Corrosion Direct Assessment (ECDA) is a method to prioritize

susceptibility to corrosion along a pipeline segment. If the most susceptible

locations are excavated and directly examined and then found to be in good

mechanical condition, the remaining locations are also considered to be in good

condition. On this basis, an overall pipeline integrity assessment is achieved.

This work shows that the results of measurement techniques are sensitive to

various pipeline parameters and soil conditions such as soil resistivity, coating aw

size, depth of cover, pipe diameter, and cathodic protection (CP) level through

use of the simulation software program called CP3D. From an entire spreadsheet

of simulation results, a design equation was developed to predict coating aw size

based on these parameters and the indication results from simulated measurement

techniques.

The above-ground measurement techniques are one way to assess the condition

of pipelines since they can measure current and potential distributions. ECDA is

a recently developed process that has been implemented to improve the utilization

of these techniques. However, this process relies heavily on the subjective decisions

of engineers. The objective of this work is to show that increased knowledge of the

parameters of pipelines and their surrounding environment improves the ability to

interpret results from the different above-ground measurement techniques. Cur-

rently, not enough information about pipelines and their environments are included

in assessments and these factors can lead to misinterpretation of indications.

This document is divided into ve chapters. Chapter 2 discusses the history

and basic principles of corrosion and how cathodic protection systems work. Also

1



2

included is explanation of how the different above-ground measurement techniques

are used to assess pipeline integrity and how they are utilized by ECDA.

In Chapter 3, CP3D is introduced as the simulation software program used

to replicate the techniques. It explains how CP3D works and what it offers.Discussion of the governing equations used for the mathematical model is also

included. Explanation is then given of how each technique is replicated within

CP3D.

Chapter 4 gives results from each of the different techniques used in CP3D

based on changes in the make-up of the pipeline and its environment. These results

are used to explain which techniques are more sensitive under different conditions.

A quantitative relationship is also derived which predicts coating aw size based on

simulation parameters and calculated indications.

Chapter 5 involves the conclusions made regarding this project based on

simulation results and interpretations. Also included in this chapter is discussion of

future work which involves possible projects that are related to this work but would

take a new and somewhat different direction.



CHAPTER 2LITERATURE REVIEW

2.1 External Corrosion Direct Assessment (ECDA)

External Corrosion Direct Assessment (ECDA) was rst introduced as an

alternative method to assess pipeline integrity. 1, 2 It is intended to be a way to

improve safety by decreasing external corrosion. 3, 4 ECDA was initially considered

to be an option for pipelines that were not ”piggable” or were difficult for pressure

testing or in-line inspection. 1, 2 It is characterized as a continuous process for

maintaining the integrity of pipelines. 1–3,5 This is because each time the ECDA

process is completed for a given pipeline, it must be scheduled to be completed

again. This ensures that the pipeline will always be monitored and maintained.

ECDA utilizes traditional methods to evaluate the level of external corrosion,

the condition of coating, and the level of cathodic protection. 2 Some of these

traditional methods include indirect inspection techniques such as DCVG, CIS,

PCM, and ACVG. ECDA does not introduce any new techniques, but it does allow

for new techniques that can be included into its application. 2

ECDA is a four step process aimed at determining the integrity of a given

pipeline. 4, 5 These steps are Preassessment, Indirect Inspection, Direct Examina-

tion, and Post-Assessment. 4, 5

Preassessment is the rst step of ECDA. It involves a background study of

the pipeline and its surrounding environment. This includes information such as

pipeline structure, soil condition, operating history, and previous survey results. 2

By collecting this information and evaluating the accessibility of the ground above

the buried pipeline, preassessment also includes determining if ECDA can be

properly used. 2, 3 For example, sometimes pipelines are buried underneath rivers,

3



4

lakes, roads, rocky terrain, or commercial and residential areas. 3 This causes many

difficulties for using indirect inspection techniques. Approval of access must be

given by landowners or managers if the pipeline exists in commercial or residential

areas.3

For issues of water, roads, or rocky terrain a measurement technique calledGuided Wave Ultrasonics has been used in the past. 3 This technique is able to

gauge metal loss without making electrical contact with the land. 3 The selection

of which above-ground techniques are to be used is decided in the preassessment

step. 6, 7

The second step of ECDA, indirect inspection, involves use of the above-

ground measurement techniques. 5 The indirect inspections are aimed to locate

coating holidays as well as areas that either lack the proper amount of cathodic

protection or those that have corrosion. 1,2,5 At least two measurement techniques

must be used to follow Direct Assessment protocols. 2 They are both to be per-

formed over the same sections of pipeline that are determined from Preassessment

and they should be done consecutively without much time in between. 2 Most

indirect inspections only include CIS and DCVG as the two techniques needed for

assessment since ECDA requires them both. 2, 3 However, PCM and ACVG are both

considered advantageous to use for indirect inspection. Some sources recommend

that at least three techniques should be used. 3 One advantage of using three is that

DCVG is considered to be a slow survey. 3 Therefore, if PCM and CIS were rst

completed, then it would minimize the length needed for a DCVG survey based on

the results already found. 3

The third step of ECDA, Direct Examination, involves excavations so that thepipeline can be inspected rst-hand. 5 Before excavations are started, this step rst

involves evaluating the measurements from the indirect inspections. 2 Based on the

data collected, a determination is made for which areas need excavation. The exca-

vations are done at areas where the data from above-ground measurements suggest



5

that corrosion is worst. 2 These excavations are called “bell-hole” excavations. 3, 8

They allow for reparations to be made and they give the opportunity to determine

if indirect indications were accurate. 8 In order to completely test whether indica-

tions are valid, random excavations are done at areas where there is no indicationof defect.3, 8 Further testing done during excavations involve determining the soil

resistivity, metal loss, and corrosion rates. 3

Once repairs are made and excavations are completed, the last step of ECDA

called Post-assessment begins. It is primarily used to evaluate the effectiveness of

ECDA’s rst three steps and to determine when ECDA will be completed again

for the same pipeline. 1,4,5 This is called a reassessment interval which is calculated

to ensure that ECDA will be completed again before corrosion can reach advanced

levels that would be detrimental to the future of the pipeline’s operation and to the

health of the environment. 2 Once this is determined, step four is completed.

Another aspect that can be included in ECDA is Structure Reliability Analysis

(SRA). While it is not always used, it can be benecial in providing numbers for

the probability of nding defects based on ECDA as well as the probability that

the pipeline will fail. SRA is considered a probabilistic technique that can be used

in combination with ECDA. 3

2.2 Corrosion Background

Corrosion has been a concern for centuries and even millennia. The growth of

corrosion has coincided over history with the increased use of metals. It has also

been suggested that a larger industrial atmosphere and other pollutants have also

caused corrosion problems to increase. The Romans were one of the rst knownto use methods to ght corrosion. Around 100 B.C., they were recorded to have

used methods as simple as applying tar and pitch to the exterior of metals to aid

in protection. 9 However, in much more recent times scientic approaches have been

developed to ght corrosion such as cathodic protection.



6

Corrosion is an issue that has become increasingly important due to its

economic impact. There have been many reports that have estimated annual

monetary losses due to corrosion. For example, textbooks on corrosion published

in the mid 1980s to the mid 1990s have reported losses between 8 and 126 billiondollars a year in the United States of America alone. 10,11 Other sources during

this time estimated a tighter range of annual losses between 30 and 70 billion

dollars a year. 12,13 By the year 1998, however, another source estimated that 276

billion dollars a year was lost due to corrosion. 14 120 million of that 276 billion

represented efforts to prevent corrosion. 14 Although these are large numbers,

they still do not include the indirect costs of corrosion. 11 While a direct cost

could normally be associated with replacing corroded and ineffective equipment,

the indirect cost would be due to shutdown of a production line while corroded

equipment is being replaced. 15 Another example of an indirect cost is the product

lost from leaks in pipelines. 15 While the cost of xing the leak is reported due to

corrosion, the cost of product lost is not included. Over design of equipment is also

another indirect effect of corrosion. 15 This can be attributed to the inaccuracy or

lack of available corrosion information.

In order to apply corrosion preventative methods properly, a basic level of

knowledge of corrosion is rst needed. Corrosion is dened as the deterioration

of a metal due to its chemical interaction with its environment. This chemical

interaction involves anodic reactions which are characterized as the dissolution

of the metal. The anodic or oxidation reactions must be balanced by cathodic

reactions which reduce oxygen or acids at the metal surface. The rate at which theanodic and cathodic reactions proceed must be equal. As the anodic reactions are

completed, the oxidized ferrous ions begin reacting with reduced hydroxide ions

forming rust. The presence of rust represents the deterioration of the metal.



7

The likelihood of a given metal corroding is partially due to the type of metal

being used since some metals are more likely to corrode than other metals. The

metals that are more likely to corrode are called active metals and the metals

that do not corrode easily are called noble metals. Examples of noble metals aregold, platinum, and silver. As noble metals they do not give up their electrons

very easily. The limitation of these metals is that they are rare and costly. Due

to the large demand for metals, more abundant metals are needed for large scale

operations. Iron is the most abundant metal on earth and it is sturdy and strong.

However, as a more abundant metal, it is much more active. As an active metal it

is more capable of losing its electrons and oxidizing under normal conditions.

To be used, metals must be extracted from their ores or the minerals that they

are contained in. The science involving the use of procedures to extract metals

from their ores is called metallurgy. It takes energy to extract metals from their

ores. The energy needed is the same amount of energy that is released when the

reactions producing corrosion are occurring. 11 Therefore, sometimes corrosion is

referred to as extractive metallurgy in reverse because corrosion transforms the

metal back into its original state. 10,11,13 An ore or a corroded metal no longer

maintains its metallic properties. Some of the most natural ores are oxides and

suldes.9

There are many different conditions that favor corrosion. High temperatures

around 500 degrees Fahrenheit and high pressures can both be very hostile towards

metals. 10 The presence of a gas such as hydrogen sulde is also very corrosive. 10

These conditions are becoming more likely in industrial chemical processes asthey are needed to produce higher yields in product. 10 However, some processes

have always caused an increase in corrosivity. One example is the conversion

of coal to both oil and gas as it causes high temperatures and emits corrosive

gases.10 These conditions formed from the conversion of coal can be termed as dry



8

corrosion.10 Dry corrosion occurs from vapors or gases. The conditions are above

the environment’s dew point when dry corrosion occurs. 10 Corrosion can also be

described as wet corrosion. Wet corrosion is more common than dry corrosion. 10

It usually occurs when there are aqueous solutions or electrolytes present.10

Some chemicals are more corrosive depending on whether they are present as

a gas or a liquid. For example, dry chlorine is very corrosive, but not when it

is dissolved in water. 10 For acid solutions, corrosivity is increased if dissolved

oxygen is present. This is because oxygen will also reduce at the metal surface

to form water which causes the rate of metal dissolution to increase. 10 There

is also a difference in corrosivity depending on whether the materials used are

organic or inorganic. Inorganic materials are considered less corrosive than organic

materials. 10 Examples of inorganic materials are those without carbon compounds

such as sulfur, sodium chloride, and hydrochloric acid. 10 Examples of organic

materials are naphtha and oil. 10

Although corrosion was not as rampant in earlier times as it is today, it still

has been a problem for centuries. Records indicate that the Romans used methods

to ght corrosion around 100 B.C. 9 They used oil and tar to protect bronze and

they used pitch and gypsum to protect iron. 9 There is no known evidence of a

scientic approach used to combat corrosion until the 19th century. 9 There are

several reasons why corrosion was not as large of an issue in earlier times than it

is today. One reason is because the metals they used were those that were most

easily extracted from their ores. 9 This meant that they did not revert back to their

original state easily. Other reasons corrosion is a larger issue today are due to theincreasing use of metals and the ever growing industrial atmosphere. 9

Today there are lots of ways that corrosion is fought. Some are simple and

some are much more complex and scientic. Simple methods involve protecting



9

metals with paints, caulking materials, polymers, metallic coatings, or organic coat-

ings. Some examples of organic coatings are coal and asphalt enamels, polyethylene

tapes, and fusion bonded epoxy. 14 These organic coatings are preferred for the use

of pipelines.14

There are also corrosion inhibitors which can be sprayed onto themetal’s surface forming a non-conducting lm. These corrosion inhibitors can be

included with organic coatings to provide additional protection. 16,17 An alternative

to applying external protection to metals is to use high performance steels that

include chromium or nickel which have a high resistance to corrosion. As for more

scientic approaches, cathodic and anodic protections are the most common used

to ght corrosion. Although there are principle differences between the two, they

both involve maintaining metals such as tanks and pipelines at certain potentials in

order to make the dissolution of metal atoms unfavorable.

2.3 Cathodic Protection

2.3.1 Background

The rst person to describe the use of cathodic protection was Sir Humphrey

Davy in 1824.9,10 Through experimentation he showed that by connecting two

metals electrically and submerging them both in water that one metal would

remain in good condition while the other metal would deteriorate at an increased

rate. 9 He was soon asked to apply this method to help protect the British Naval

ships.9,10 He was called upon because in his work he had suggested that the

bottoms of ships could be protected by attaching zinc and iron plates. 9 He ended

up using cast iron because he found that it remained electrically active longer than

either zinc or iron.9

A century later, cathodic protection was also used to protect underground

pipelines. Pipelines were rst installed underground in the United States in the

1920s.9 They quickly became a large concern due to their susceptibility to corrosion

since they were primarily made of iron or steel and the surrounding soil contained



11

properties that coatings should exhibit in order to work well for pipelines. 23 For

example, pipeline coatings should have strong adhesion to the pipeline and offer

exibility at high temperatures. 23 These coatings should also have resistance to soil

stress and cathodic disbonding.23

2.3.2 Principles of CP

Cathodic protection is a scientic approach used to protect a metal structure

from degradation. It involves electrically connecting two metals in an electrolyte.

For underground pipelines, the soil can be considered to be the electrolyte. There

are two different types of cathodic protection. One is through use of a sacricial

anode and the other is by impressed current. CP with the use of a sacricial anode

involves galvanically coupling the pipeline with a metal more active than the metal

of the pipeline. The metal that is considered to be more active is the metal that

has a more negative standard equilibrium potential. Once they are connected a

potential difference develops between the two metals. The more active metal acts

as the anode and the more noble pipeline metal acts as a cathode. As the more

active metal, the anode will give up its electrons much easier than the noble metal.

There are two reactions that can occur normally at the pipeline’s surface. One of

these reactions is the oxidation of iron

Fe → Fe2+ + 2e − (2.1)

The other reaction is the reduction of oxygen

O2 + 2H 2O + 4e − → 4OH− (2.2)

These two reactions must be electrically balanced so that they proceed at the same

rate. Since the integrity of the pipeline can be compromised by the iron dissolution

reaction, the rate of this reaction must be reduced. This is done by providing the

excess of electrons from the anode. The metal dissolution reaction of the anode is



13

which can convert alternating current from an external power source to direct

current. This creates a voltage drop between the anode and the pipeline which

drives electrons from the anode to the metal through the low resistance wire.

By an excess of electrons at the pipeline’s surface, the potential of the metal ispolarized to a more negative potential. The rate of oxygen reduction reaction ( 2.2)

is increased and the anodic or oxidation reaction ( 2.1) which normally occurs at the

pipeline’s surface becomes unfavorable. If the potential of the pipeline becomes too

polarized the hydrogen evolution reaction

H2O + 2e − → H2 + 2OH − (2.4)

can occur. The evolution of hydrogen can result in hydrogen embrittlement of the

pipeline, so it is necessary to ensure that polarization does not cause the pipeline’s

potential to become too negative.

Figure 2–2 gives a representation of how the arrangement is different for a CP

system with impressed current. The current is supplied to the pipeline from the

anode through the soil. When the current reaches the pipeline it travels toward

the low-resistance wire. This low-resistance wire allows for the return of current

to the anode from the pipeline. The anode in this system is made up of an inert

material so that it will not chemically react with the environment and degrade as a

sacricial anode would. Sometimes the anode can be more noble than the pipeline.

In this case, the rectier must overcome both the resistance of the circuit and the

back potential created from the more noble anode in order to ow current in the

proper direction.20

In order to balance the reduction reactions occurring at thepipeline’s surface, there must be oxidation reactions occurring at the surface of the

impressed current anode. The main reaction occurring is the oxidation of water or

the evolution of oxygen given as

2H2O → O2 + 4H + + 4e − (2.5)



14

Figure 2–2: A CP system with impressed current.

At more extreme positive potentials the evolution of chlorine can also occur as

2Cl− → Cl2 + 2e − (2.6)

There are advantages and disadvantages associated with both sacricial

anodes and impressed current anodes. Some of the advantages of a sacricial anode

are that it does not require an external energy source and that is self sustained.

Therefore, a sacricial anode can be preferred in areas where an external energy

source is unavailable. On the other hand, CP systems with impressed current

anodes do consume external energy. Some of its advantages involve that it can

supply a larger magnitude of protection and will also last longer. For example,

eventually a sacricial anode will be consumed by the environment and must be

replaced. By supplying more protection, impressed current anodes can be used to

protect larger sections of pipeline and handle more resistive soil environments. One

of the few disadvantages of impressed current CP systems can be due to the risk



15

of supplying too much current causing damaging hydrogen evolution. However,

this should be able to be prevented by properly controlling the rectier and having

knowledge of the pipeline and its environment.

2.4 Internal Inspection TechniquesThere are two types of Internal Inspection techniques discussed in this section.

One is called pressure testing or hydrostatic testing. The other is called in-line

inspections (ILIs) or pigging. ILI involves measuring the conditions of the pipeline

through ultrasonic testing (UT) or magnetic ux leakage (MFL) sensors. The

inspections are referred to as “in-line” because they involve measurements inside of

the pipeline. Pipeline inspections using ILI tools began being utilized between the

mid 1960s and mid 1970s.24,25 Pressure testing has been used for much longer.

Pressure testing involves hydrostatic pressure which is applied to the internal

walls of pipelines. It tests the ability of a pipeline to maintain pressure and resist

bursting. Pressure testing is also capable of locating areas where internal corrosion

damage to an extent leading to pipe wall failure is present. It is able to do so

by determining the sturdiness of the walls of the pipeline. Usually pressures are

tested around 1.5 times the normal operating pressure expected to be placed on

the interior of the pipeline. Pipelines are taken off line during pressure testing and

the uid being transported must be displaced so that it can be re-lled with water

through the use of pumps. This can cause some environmental issues involving

the disposal of the uids that are normally transported in pipelines as well as the

disposal of the used and contaminated hydrostatic test water. 1 Pressure testing

is often done upon the completion of the building of a pipeline so that it can betested at certain pressure levels beyond those required during operation. 24 This can

also determine if construction defects are present.

ILIs involve the use of pigs. A pig is a device that moves through the pipeline

for either inspection or cleaning. Sometimes pigging is used before pressure testing



16

so that the pipeline is initially clean. If a pipeline is not pigged its throughput

capacity may decrease over time. There are different designs used to insert and

retrieve pigs from the pipeline. Some pipelines have built in systems where an

additional line will join the pipeline from above the ground so that a pig can belaunched into the pipeline. Similarly, in order to retrieve a pig there is a stray line

which forks off of the main pipeline to a location above-ground so that it can be

recovered.

There are several different types of pigs used due to their different functions.

Some are called “smart pigs” because of their ability to detect corrosion, gouges,

or dents. Usually the rst type of pig used is a scout pig which will detect whether

the pipeline is clean or if there are any obstructions in the interior of the pipeline.

Then cleaning pigs can be used in order to remove or displace debris or wax

buildup on the interior walls. This is done by brushers or scrapers which are

attached to the pig. Another type of pig involves magnetic ux leakage (MFL).

It can detect both internal and external corrosion defects. MFL is used for gas

pipelines while ultrasonic testing (UT) is used for liquid pipelines. A document was

prepared for the U.S. Department of Energy regarding a new method using MFL. 26

This document outlines methods for determining axially oriented defects which

stretch along the length of the pipeline. According to normal MFL measurements

the original orientation of the magnetic eld created did not detect these anomalies.

However, by orienting the magnetic eld around the circumference of the pipeline

these axial defects were detected.

One of the problems with pigging or pressure testing in terms of detectionof corrosion is that they are detecting problems with the pipeline after they have

occurred. However, early detection can be the key since problem areas can then

be corrected before they become potential failures. Another limitation can be due

to the lack of physical accessibility of some areas of the pipeline. The land above



17

buried pipelines sometimes involves rocky terrain or developed areas where access

to a given pipeline may be unavailable. It is preferred that pig launch and retrieval

systems are built upon installation of a given pipeline. Then pigs can be used to

help prepare the pipeline before it goes online by cleaning it. Another concern forusing pigs is that pipelines do not turn at sharp angles or have any dents which

might cause a pig to get stuck. A pipeline may not be a good candidate for pigging

due to inadequate pressure, ow, costs of modications, and customer issues. 25 The

systems involving launching pigs and retrieving pigs as well as the pigs themselves

are all very expensive equipment. Natural gas pipelines are often not amenable

to pigging or pressure testing. 2 These types of pipelines are not designed for pig

insertion and also they can not be taken off-line for pressure testing due to service

demands. Direct Assessment is a method that is considered as an alternative to

inspect pipelines if pressure testing or pigging are unavailable. 1

2.5 Above-Ground Measurement (Indirect) Techniques

The following measurement techniques are used to determine pipeline integrity

through indirect inspections. These techniques are termed as indirect because they

do not involve physically inspecting the pipeline rst hand. These techniques rely

on voltage and potential distributions that arise in the soil or electrolyte due to the

CP system that is in place to protect the pipeline.

2.5.1 Close Interval Survey (CIS)

The Close Interval Survey (CIS) technique has historically been used to

characterize how well the CP system is working. 3,6,27 It gives both on-potential

and off-potential proles along the length of the pipeline at the ground surface.These potentials are measured at the soil surface with respect to the potential of

the pipeline. Test stations are placed at intervals usually between one and two

kilometers along the pipeline. Each test station allows for a direct connection to

be made to the pipeline. Between test stations, surveyors use a trailing wire to



18

remain connected to the previous test station. The measurements are made at

the ground surface by use of a walking stick probe with a Cu / CuSO4 reference

electrode placed at the bottom so it is touching the ground. It is used to measure

the potential at the soil surface directly above the pipeline with respect to thedirect connection with the pipeline. A pipe locator is used to ensure the proper

location of measurements at the ground surface. Measurements are taken every

ve feet along the pipeline. The on-potentials and off-potentials are measured at

each location by interrupting the CP current. When the CP current is turned on,

the on-potential reading is measured. When it is interrupted or disconnected, the

off-potential reading is found. Acceptable potentials are expected to be in the range

between -850mV and -1200mV. 28

One concern during the CIS survey is that depolarization may occur when the

CP current is interrupted. It is suggested that the length of the CP interruption

cycle is limited in order to maintain proper polarization levels. Through interrup-

tion, the CP current is turned on and off continuously. It is suggested that these

on and off intervals are maintained at three seconds for the CP current on and one

second for the CP current off. This represents a four-second interruption cycle.

The one- second interval has been found to be long enough to allow for correct

measurement of the off-potential.

CIS indications are often analyzed by placing results in three different cat-

egories.7,8,28,29 The rst category is labeled as a Type I indication. This level of

indication is characterized as minor since both the on-potential and off-potential

values for the peaks of the dips remain more negative than -850mV. In Figure2–3, a representation of a Type I indication is shown along with Type II and

Type III indications. Type II is considered as a moderate indication. It has an

on-potential dip in which the peak value remains more negative than -850mV

while the off-potential’s dip does not. The Type II indication is considered to be



19

-960

-940

-920-900

-880

-860

-840

-820

-800

0 50 100 150 200length along pipe (feet)

p o

t e n

t i a l ( m V )

-850 mVon

off

Type I

Type II Type III

Figure 2–3: A representation of on- and off-potential proles which show how CISdips are categorized. Each data point represents a measurement at the soil surfacedirectly over the pipeline.

properly protected by the CP system. Type III indications are termed as severe.

These types of dips have peak values for on- and off-potentials which extend into

the range more positive than -850mV. The presence of a defect is considered likely

under this indication and the ability of the CP system to protect it is considered to

be unlikely.

There are some limitations of CIS. Indications are expected to only indicate

whether corrosion is taking place at the time of the measurement. It is not ex-

pected that a CIS survey will indicate areas where corrosion may have occurred

previously.8,28

While CIS is able to detect the possibility of holidays, it is not thepreferred method to discover such locations. The primary function of CIS is to de-

termine how well the CP system is working for a given pipeline. As mentioned, this

can be done by nding dips in the on- and off-potential proles and determining

whether the CP current should properly protect these locations.



20

2.5.2 Direct Current Voltage Gradient (DCVG)

The Direct Current Voltage Gradient (DCVG) survey is used to determine the

location of a coating aw or holiday and to categorize its relative severity once it

is found. This is done by using two different calculations. The rst of these twocalculations is in units of mV and it is used to determine the coating aw’s location

as measurements are made along the length of the pipeline. The second calculation

is termed as a percent-IR calculation and it involves measurements moving away

from the pipeline. The measurements of DCVG in mV are completed by detecting

a voltage gradient at the surface of the ground above the pipeline. This voltage

gradient is detected by the use of two Cu / CuSO4 electrodes. These electrodes are

placed at the bottom of walking stick probes as those used in the CIS survey. One

electrode is placed at the ground surface directly above the pipeline and the other

is placed at a location approximately ve feet away from the pipeline, but also at

the ground surface. There is no direct connection made to the pipeline as in the

CIS survey. This measurement takes into account only the voltage gradient found

between the two electrodes which is the result of current entering the pipeline at

a coating aw. CP rectiers are interrupted at a regular cycle which creates a DC

signal detected by the potential difference between the electrodes. The electrodes

are electrically connected to a voltmeter which displays the voltage gradient

detected in mV.

Measurements along the pipeline are typically made at ve feet intervals.

When the survey begins, the eld engineer nulls the voltmeter so that the rst

value or reading is at zero. This means that as the CP current is interrupted,the voltmeter remains at zero even when the CP current is switched back and

forth between on and off. As a coating aw is approached, the voltmeter will

begin swinging in either the positive direction or the negative direction from zero

depending on the direction of current detected in the soil or electrolyte. When



21

the CP current is switched off, the voltmeter goes back to zero. However, as the

coating aw approaches, the voltmeter continues to give either the positive or

negative reading when the CP current is switched on that is consistent with the

previous measurements. The magnitude of this value increases as the coating awapproaches. The magnitude of the voltage reading will reach its maximum when

the surveyor’s measurement is made directly above the aw. This is evidenced

by the voltmeter’s sudden swing from positive to negative or vice versa when

the aw is passed. For example, if the voltmeter has shown increasing positive

values up to 75 mV, then once the aw is passed the voltmeter will swing to -75

mV. Then all of the measurements will continue to be negative as the surveyor

moves on along the pipeline in the same direction. However, the absolute value

of the reading will decrease back towards zero as movement is made further away

from the coating aw. This behavior found by use of the voltmeter is due to the

detection of a direction change in the ow of current in the electrolyte. The current

in the electrolyte or soil is always moving toward the coating aw, therefore when

the aw is passed there is a change in direction of the current.

Once a coating aw or defect is found and located, its size and severity must

be determined. This further characterization of the coating aw is done through

the calculation of DCVG in percent-IR. There are two steps that the eld surveyor

follows in determining the percent-IR value for a given coating aw. The rst is

by taking lateral voltage gradients moving away from the pipeline. These lateral

measurements are shown in Figure 2–4 where point A represents the location of

the aw. Successive lateral measurements are made in the direction away fromthe pipeline and the coating aw until the voltage gradient reaches a value of less

than or equal to one mV. The location where the lateral voltage gradients are not

greater than one mV is termed either as remote earth or IR innity. Again these

voltage gradients are measured by the ve foot spacing of Cu / CuSO4 electrodes.



22

Figure 2–4: The percent-IR calculation is shown using the lateral voltage gradientswith the interpolated value of IR drop over the coating aw.

The voltage gradients are then added up and divided by the IR drop at the soil

surface directly above the coating aw. However, the IR drop over the soil surface

is not measured directly since a direct connection to the pipeline is not made.

Therefore, this value must be interpolated by using the known values of potentials

that are directly connected to the pipeline. This is shown in Figure 2–5 as the

closest test posts are used since they are directly connected to the pipeline. At the

location of each test post the IR drop can be measured.

Once a percentage is calculated for a given coating aw, it is categorized based

on what range of values it lies in. There are four categories that are generally used

to differentiate the severity or size of holidays. The rst category is for IR drops

between zero and 15 percent. If a coating aw has a percent-IR in this range it is

considered to be safe and not severe. This is because the CP system is expected to

provide adequate protection for a coating aw with such a low percent-IR value.

Therefore, no action is needed. If the percent-IR is between 15 and 35 percent, its



23

Figure 2–5: A diagram showing how an IR measurement is interpolated at theground surface above the coating aw.

severity is also considered to be minimal. However, the survey must be performed

again in the near future to further monitor it. The third category is between 35

and 70 percent. A sufficient amount of coating damage is expected to be present

for a percent-IR value in this range. However, a eld engineer is allowed to make

the decision to either take immediate action and excavate or to schedule another

survey in the near future for further monitoring. For a percent-IR value above 70

percent, immediate action is necessary. Digging at the site of the coating aw is

needed so that the pipeline can be physically repaired. Upon completion of the

percent-IR calculation and its assessment, the DCVG survey is considered to be

completed.2.5.3 Alternating Current Voltage Gradient (ACVG)

The Alternating Current Voltage Gradient (ACVG) technique is similar to

the DCVG technique. They are similar in that ACVG is also used to determine

the location of holidays in order to evaluate the coating condition of the pipeline.



24

However, instead of a DC signal being created, an AC signal is initiated from a

frequency transmitter. This can be done by either a high frequency transmitter

or a low frequency transmitter. This signal is detected by the voltage gradient

measured between two electrodes at the surface of the ground. However, theseelectrodes are placed at the bottom of a structure which is called an “A-Frame”

because of its shape. The A-Frame is planted into the ground in order to measure

the voltage gradient. The width of the A-Frame causes another difference between

ACVG and DCVG due to a discrepancy in distance between the electrodes. The

width of the A-Frame is 31.5 inches which is roughly half the distance of the

spacing of the electrodes when making DCVG measurements.

2.5.4 Current Attenuation

The purpose of this technique is to determine the overall coating condition

of the pipeline. It relates current change along the length of the pipeline to the

area of the exposed metal known as the coating aw. This technique is sometimes

referred to as the Pipeline Current Mapper (PCM) technique. This survey involves

both the use of a transmitter and a receiver. The transmitter is able to simulate

the low frequency DC signal similar to that of the CP system. However it can also

simulate the AC signal at either low frequency (4Hz) or high frequency (937.5Hz).

The receiver is responsible for making all of the necessary measurements and

calculations. Its primary output is the ability to plot current versus distance along

the pipeline. The portable receiver is able to plot points as it moves along the

pipeline further increasing its distance from the transmitter. The magnitude of

current slowly decreases as distance from the transmitter increases. However, thereis sharp drop in the magnitude of current when a coating aw is present. The

magnitude of current drops because the pipeline consumes a large portion of the

current at the location of the coating aw. Once the current reaches the pipeline

it travels back down the pipeline in the direction of the transmitter. The relative



25

size of holidays can be determined by noting the size of the drop in the plot of

current versus distance. If there are multiple holidays found, then the relative sizes

of the step changes in current can be compared to determine which ones are most

severe. The larger the drop of in current is the larger the size of the coating aw isexpected to be. One of the advantages of this type of survey is that it helps show

how CP current can be lost along the pipeline. If certain locations of the pipeline

are large consumers of CP current, it can cause a lack of current to be able to reach

other portions of the pipeline which need protection.



CHAPTER 3CP3D

3.1 Description of CP3D

CP3D is a mathematical model in the form of a computer software program.

It has been developed by Dr. Mark Orazem’s electrochemical engineering research

group at the University of Florida as a comprehensive model for cathodic protec-

tion. It allows for the creation of a visualized three-dimensional cathodic protection

system of buried structures. This program was developed as a tool to help improve

the ability to assess pipeline conditions. There are several parameters that can

be used and varied in the calculations performed by the mathematical model.

Some of these include coating aw or coating holiday size, soil resistivity, cathodic

protection level, coating condition, depth of cover, and pipe thickness. In order to

perform the different above-ground techniques in CP3D, a soil surface is created

and utilized within the program. The soil surface is made up of nodes where on-

and off-potentials are calculated by the model at each node’s exact location. In

order to study the details of interest, soil surfaces are placed over the anode and

the coating aw location of the pipe. The soil surface areas above the anode and

above the aw represent areas where a useful distribution of on- and off-potentials

are found. Figure 3–1 is an image of the three dimensional environment of CP3D

showing the arrangement of the soil surface with the pipeline and the coating aw.

The soil surface must be limited in size to avoid putting a strain on the resources

of the program. However, in a real-life eld survey, measurements must eventually

cover the entire pipeline in order to properly inspect its complete condition. Since

the area of interest is specied within CP3D, a soil surface that covers the entire

pipeline is not necessary.

26



27

Figure 3–1: An image from CP3D showing the physical orientation of the soil sur-face with respect to the pipeline. The darker area on the pipeline represents thecoating aw or holiday.

3.2 Mathematical Development

There are a set of governing equations for the CP3D model that work as a

basis for all calculations made by the program. For protection of underground

pipelines, this model accounts for the current ow through the soil, the pipeline,

and through the circuitry back to the anode. There are two different domains

which are governed separately in the model. One domain is called the outer domain

which is represented by the soil. The other is called the inner domain which

represents the pipeline, the anode, and the electrical wiring that connects them.

The rst of the governing equations for the outer domain is the material

balance of a solute species∂ci

∂t = − (∇ · N i ) + R i (3.1)

where ci is the concentration of a species i , N i is the net ux vector for species i ,

and R i represents the rate of generation of species i due to homogeneous reactions.



28

Homogeneous reactions are dened as the reactions which occur in the electrolyte

and not at the electrode surfaces, which in this system are either the anode or the

pipeline. Equation ( 3.1) must be coupled with the equation of electroneutrality in

order to properly account for the concentrations and potentials that are present inthe soil. The equation for electroneutrality is given as

i

z i ci = 0 (3.2)

where z i represents the charge associated with species i . For a dilute electrolyte,

the ux of a given species can be given based on its contributions from convection,

diffusion, and migration as

N i = vc − D i∇ ci − z i ui Fc i∇ Φ (3.3)

where v is the uid velocity, D i is the diffusion coefficient for species i, ui is the

mobility, F is Faraday’s constant and Φ represents the distribution of potential

in the domain. The diffusion coefficient is related to the mobility by the Nernst-

Einstein equation as

D i = RT u i (3.4)

where R is the gas constant and T is the temperature. The equation for current

density is based on the contribution of the movement of each ionic species and is

given as

i = F i

z i N i (3.5)

If the concentration of ions in the electrolyte are uniform and steady state is

assumed the equation for current density can be written as Ohm’s law. Therefore,

i = − κ∇ Φ (3.6)



29

where κ represents the conductivity of the electrolyte. The conductivity is given by

κ = F 2i

z 2i ui ci (3.7)

and it is uniform because the concentration is uniform. Due to uniform concentra-tion, the potential is governed by Laplace’s equation which is given as

∇2Φ = 0 (3.8)

Laplace’s equation can be derived by rst multiplying equation ( 3.1) by z i F and

summing over the species which gives

∂ ∂t F i

z i ci = −∇ · F i

z i N i + F i

z i R i (3.9)

From electroneutrality and from the assumption that R i is zero because it repre-

sents reactions in the bulk, equation ( 3.9) reduces to

∇ · i = 0 (3.10)

By substituting Ohm’s law into equation ( 3.10) and by the assumption of constant

conductivity, Laplace’s equation is obtained.

Since it is assumed that there are no concentration gradients in the soil or

electrolyte, the concentration gradients due to reactions at the surface of the anode

and pipeline are treated so that they lie in a thin layer adjacent to these surfaces. 21

The concentration gradients in this thin layer are incorporated into the boundary

condition which is based on electrochemical reactions.

For the inner domain, there are also some assumptions that must be made.For example, this model treats the potential through the pipeline as non-uniform.

Previously, pipelines of shorter lengths have neglected the potential drop along the

pipeline steel. 30 However, it has been proven that for long pipelines this potential

drop can not be neglected. 9,20,31



30

Laplace’s equation also governs the ow of current through the pipe steel,

anode, and the connecting wires. It is given as

∇ · (κ∇ V ) = 0 (3.11)

where κ is the conductivity of either the pipeline steel, the anode, or the electrical

wires and V is the drop in potential of the metal from a uniform value. The

conductivity of the inner domain is not constant because it is not the same for

the anode, pipeline, or the copper connecting wires. Laplace’s equation can be

simplied as

∆ V = IR = IρL

A (3.12)

which accounts for the potential drop along the copper connecting wires. For

this equation, R represents the resistance of the wire, ρ represents the electrical

resistivity of the wire, L is the length, and A is the cross-sectional area of the

connecting wire.

The two domains are coupled through boundary conditions. The boundary

conditions develop a relationship between the local values of potential and the

current density on the metal surface. 21 This relationship varies depending on

whether the type of surface is the bare metal pipeline, the coated pipeline, a

sacricial anode, or an impressed current anode.

3.2.1 Bare Steel

For a non-coated pipeline, bare steel is exposed to the soil. Bare steel can also

be exposed in places where a coated pipeline has scratches or aws on it. There

are three different electrochemical reactions that can take place at the surface of

the bare steel. These reactions include the oxidation of iron, reduction of oxygen,

and hydrogen evolution. Hydrogen evolution can occur if the metal is polarized

to very negative potentials. The current contribution of each of these reactions

can be included in the relationship between local current density i, the potential



31

of the steel V , and the potential of the soil next to the steel Φ. The following

equation 32,33 represents the boundary condition of the bare metal pipeline and the

adjacent soil and is given as

i = 10( V − Φ− E F e )

β F e − ( 1ilim,O 2

− 10( V − Φ − E O 2 )

β O 2 )− 1 − 10− ( V − Φ − E H 2 )

β H 2 (3.13)

The term E F e represents the equilibrium potential for the oxidation of iron and

this term is written similarly for the reactions of oxygen reduction and hydrogen

evolution. The β term is given for each reaction and it represents the tafel slope of

the corresponding reaction. The ilim,O 2 term represents the mass transfer limiting

current density of oxygen reduction at the metal surface. Therefore, the current

contribution of oxygen reduction can not be larger than the value of i lim,O 2 .

3.2.2 Coated Steel

For coated pipelines, treatment of the reactions at the pipeline-soil interface

must be different than that of bare steel. The purpose of the coating is to provide

resistance for the transport of reducing species to the metal surface. It also reduces

the amount of CP current that is needed to protect a given pipeline. There are

two main types of coating behavior and these are both modeled differently. One

model of coating behavior is where the transport of species is uniform through

the coating. The electrochemical reactions take place once the transported species

reaches the coating-metal interface. These reactions are driven by the difference in

potential V of the metal and the potential Φ in just underneath the coating but still

above the metal or steel.

The other type of model involves the presence of pores which allow for thetransport of solute species to take place. It has been shown that the pore structure

will expand after it has been contacted with water and that the conductivity of

the coating increases with time after its exposure to water. 34 The resistivity of

the coating with pores is a function of the number of pores per unit area. The



32

electrochemical reactions also take place at the coating-metal interface for this

model and these reactions are also driven by the potential difference between V and

Φin .

It has been shown that the non-porous coated steel forms a diffusion barrierwhen put in aqueous environments. As the water is adsorbed by the coating, the

steel can be polarized slightly even if the coating is disbonded. 35–38 Equation ( 3.13)

can be modied based on either model of transport through the coating. 39,40 The

current density can be written as a function of the potential drop through the

coating as

i = Φ − Φin

ρδ (3.14)

where Φ is the potential of the soil adjacent to the coating, ρ is the resistivity of

the coating, and δ is the thickness of the coating. By writing the current density in

terms of electrochemical reactions it is also given as

i = A pore

A [10

( V − Φ in − E F e )β F e − (

1(1 − α blk )i lim,O 2

− 10( V − Φ in − E O 2 )

β O 2 )− 1 − 10− ( V − Φ in − E H 2 )

β O 2 ]

(3.15)

where Apore

A is the effective surface area available for reactions to occur and α block isthe reduction of the transport of oxygen through the diffusion barrier. In order to

determine the values for the current density ( i) and Φin , both equation ( 3.14) and

equation ( 3.15) are solved simultaneously by the Newton-Ralphson method.

3.2.3 Sacricial and Impressed Current Anodes

The reactions at the surface of a sacricial anode involve normally oxygen

reduction and the corrosion reaction of the anode. The current density expression

is treated similarly as that of the bare steel except that the hydrogen evolution

reaction is neglected. The expression is given as

i = ilim,O 2 (10V − Φ− E corr

β anode − 1) (3.16)



33

where E corr is the corrosion potential at the anode and β anode is the corresponding

Tafel slope for the anodic corrosion reaction.

The current density model equation for impressed current anodes is similar to

that of the galvanic or sacricial anode. The only difference is the inclusion of therectier potential setting. This equation is given as

i = ilim,O 2 (10V − Φ− ∆ V rect − E corr

β anode − 1) (3.17)

This equation must be modied if there are chloride ions present in the soil.

3.3 Replication of Techniques

The above-ground measurement techniques that are used in eld surveys

to assess pipeline integrity can be reproduced within the CP3D program. These

techniques are replicated by using the on and off potentials calculated by the

mathematical model of CP3D at each node’s surface location. Then the additional

calculations are done which are specic to each technique.

3.3.1 CIS

When using CP3D to explore the CIS technique, the potential measured with

a reference electrode at grade is simulated. A prole of on-potentials and off-

potentials along the surface directly above the pipeline can be plotted for a given

simulation as shown in Figure 3–2. The on-potential prole is more negative than

the off-potential prole representing an increased level of protection when the CP is

turned on. Under most conditions proles for both on- and off-potentials as shown

in Figure 3–2 will have a dip located at the coating aw or holiday. The potentials

are most positive at the dip representing the coating aw location. Conversely, themost negative potentials occur far away from the coating aw.

The calculation of the CIS dip indication is explained in Figure 3–3. Figure

3–3 shows that the CIS dip indication is calculated by taking the IR drop over

the coating aw and subtracting it by the IR drop that is both above the pipeline



34

-0.98

-0.96

-0.94-0.92

-0.9

-0.88

-0.860 20 40 60 80

position on soil surface (ft)

p o

t e n

t i a l ( V )

On PotentialOff Potential

Figure 3–2: A prole of on- and off-potentials from CP3D simulation data wherethe dip indicates the location of the coating aw. Each data point represents ameasurement at the soil surface directly over the pipeline.

and far away from the coating aw. This calculation is done separately for both

on-potential and off-potential giving two different dip indications. By calculating

the dip for both on- and off-potential, a conclusion can be drawn about the current

demand to the coating aw.

3.3.2 DCVG

The DCVG survey is simulated using potentials calculated by the model of

CP3D as shown in Figure 3–4. The nodes are spaced equally to stay consistent

with the spacing between two electrodes. Figure 3–4 shows that there are nodes

located both directly over the pipeline and on an imaginary line parallel to the

pipeline. At each position along the length of the pipeline, the difference between

the IR drop over the pipeline and the IR drop over the imaginary line is calculated.

This gives a DCVG indication value at each 5.2 foot interval along the pipeline.

This distance represents the approximate separation length between electrodes

that are planted by a surveyor when taking a measurement. The DCVG indication

is the voltage gradient that is calculated directly over the coating aw. Figure



35

Figure 3–3: A schematic of how CIS indication is calculated using the nodes of thesoil surface.

Figure 3–4: A schematic of how DCVG measurements are made using CP3D.



36

00.5

11.5

2

2.53

3.5

4

0 10 20 30 40 50 60 70 80 90

position on soil surface (ft)

p o

t e n

t i a l ( m V )

Figure 3–5: A prole of DCVG measurements above the pipeline. The peak valuerepresents the overall DCVG indication.

3–4 explains that DCVG is calculated by taking the difference in adjacent IR

drops. The difference in adjacent IR drops approach a constant value when moving

away from a coating aw. Therefore, these values increase as the coating aw is

approached and then decrease once it is passed. Figure 3–5 shows a representation

of this behavior. In Figure 3–4, the peak value would be the difference in IR drops

between nodes A and B, assuming that the coating aw is located at node A.

For all simulations with coating aws, the shape of the curve in Figure 3–5 is

similar where the DCVG calculation is largest at the coating aw. Each data point

represents the DCVG calculation in mV that is represented along the soil surface inthe lengthwise direction of the pipeline. It is clear where the location of the coating

aw is due to the peak value shown in Figure 3–5.

A different section of nodes is needed from the soil surface to calculate DCVG

in percent-IR. Figure 3–6 shows the relationship between the nodes that are used



37

in percent-IR calculations. Only those nodes running perpendicular to the pipeline

at the location of the coating aw are used. The spacing of the nodes remains

consistent at approximately 5.2 feet. In order to use the correct number of nodes to

determine percent-IR, the differences for all adjacent IR drops are calculated. Thisdifference decreases as the distance of the nodes from the pipeline increase towards

remote earth. As similar to a the real eld survey, once the difference between

adjacent nodes reaches one mV or less, no more nodes further from the pipeline

are needed in determining percent-IR. An example of data from a simulation which

gives the prole of all perpendicular IR drops is shown in Figure 3–7. This gure

shows the general behavior of data from simulations in that as distance from the

pipe increases, the IR drops approach a constant value. Therefore, in Figure 3–6,

the equation shown to calculate percent-IR is only correct if node D is at remote

earth. This means that if node E was included in Figure 3–6, that its IR drop

would be no more than one mV different from that of node D. The IR drop at

remote earth can also be termed as IR innity.

The calculation of percent-IR is illustrated in Figure 3–6. It explains that

percent-IR is found by taking the difference in IR drop between the node over the

coating aw and the node at remote earth and dividing that quantity by the IR

drop of the node over the coating aw. This calculation is complete once the value

is multiplied by 100 in order to make the quantity a percentage. There are also

other denitions of percent-IR that can be used in terms of its calculation. For

example, percent-IR can be dened to be calculated differently by dividing by the

IR drop at remote earth (node D) instead of the IR drop over the coating aw.Another type of denition would scale or divide by the IR drop over the pipeline

but far from the aw. These calculations can be used to further verify trends in the

data.



38

Figure 3–6: A schematic of how percent-IR is measured and calculated.

-60-59-58-57-56-55-54-53-52-51-50

-49

0 5 10 15 20position on soil surface (ft)

p o

t e n

t i a l ( m V )

Figure 3–7: A prole of IR drops in the perpendicular direction to the pipeline.The IR drops are all at the same lengthwise position as the coating aw in respectto the pipeline.



40

3.4 CP3D settings

For these simulations the CP3D system was only run under impressed current

mode and not under sacricial anode. One reason for this is because cathodic

protection of large scale pipelines normally use impressed current anodes. Also,in real eld survey’s CP current usually must be interrupted in order to get the

difference between on- and off-potentials. A CP system with a sacricial anode can

not be controlled in this way.

The pipeline’s length was 10 miles for all simulations with a connection to a

single anode. The anode was placed at 10,000 feet from one end of the pipeline

in the direction towards the other end so that it was almost directly under the

pipeline. The anode was placed 1,000 feet deep with a vertical orientation. This

depth was specied at such a large depth in order to supply a more uniform

distribution of current to the pipeline. The size of the anode was 2.5 feet wide

and 200 feet long. The coating aw was placed almost exactly in the middle of the

pipeline. The coating parameters that were used were for an excellent coating. The

thickness of the coating was 20 mils. The coating resistivity was 10 9 ohm-cm. The

oxygen blocking was at 95 percent and the oxygen limiting current for reduction

was set at 10 mA per square feet.

3.4.1 Matrix of Simulations

Table 3–1 is included to show which parameters were varied in the simulation

runs. The column for CP level is based on soil surface off-potential values that are

far away from the pipeline and the coating aw. For example, for low CP level, a

soil surface off-potential was desired to reach between -700 mV and -799 mV. Inorder to achieve such an off-potential, the anode voltage would have to be adjusted.

The medium CP level was for values between -900mV and -999mV and the high

CP level was for values between -1100mV and -1199mV.



41

Table 3–1: The matrix of model runs showing the ranges of different parametersthat were varied.

aw size (in 2) Rs (kΩ-cm) DOC (ft) D p (in) CP level (mV)1 0.5 4 6 -70016 3 8 12 -90036 10 16 48 -110064 50100 100

1000



CHAPTER 4RESULTS AND TRENDS

4.1 Current and Potential Distributions in the Pipeline

The current from an impressed current CP system travels from the anode to

the pipeline through the soil. Once it reaches the pipeline it returns to the anode

through the low resistance wire. Then it returns to the anode and repeats the

cycle. The following gures and discussion involve using multiple graphs to explain

and reiterate that the behavior of the current in the pipeline is largely based on its

tendency to return to the anode.

Much information can be learned about some of the basics of a cathodic

protection system by studying the current and potential distributions along the

pipeline. If eld surveyors understand more about the behavior of the pipeline

current then they will be able to maintain a better balance between excessive CP

and inadequate CP. Excessive CP can cause the potential along the pipeline to

become too negative. When the potential becomes too polarized or too negative,

the hydrogen evolution reaction plays a larger role. Once excessive current is

supplied to the pipeline, the hydrogen ions present in the soil will begin to reduce

to form hydrogen. However, too much of the evolved hydrogen will damage the

pipeline through embrittlement. Conversely, too little CP can cause the pipe to be

left unprotected. These distributions of the current and potential can help explain

the behavior of the current in the pipeline and whether the CP is working properly.

The effectiveness of the CP current can be rst evaluated by Figure 4–1 as it

represents the cathodic current density distribution along the length of the pipeline.

The values are negative because the current is cathodic. Therefore, the values

with the largest magnitude of current are the ones that are most negative. It is of

42



43

-0.01 92

-0.0172

-0.0152

-0.0132

-0.0112

-0.0092

0.0E+00 1 .0E+04 2.0E+04 3.0E+04 4.0E+04 5.0E+04distance along pipeline (ft)

c u r r e n

t d e n s i t y

( m A / s q

f t )

Figure 4–1: A plot of current density as it changes along the length of the pipeline.Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp

interest in Figure 4–1 that the largest magnitude of current according to the graph

is located at the negative dip around 10,000 feet. This is due to the location of the

anode and the fact that the current is travelling along the pipeline in the directionof the bond between the pipeline and anode. The rectier applies a voltage drop

which is the driving force for the current to return from the pipe to the anode. The

magnitude of current also shows an increase near the pipe ends which is due to the

geometry of the rounded edges. The last feature to mention about Figure 4–1 is

the behavior of the current at the coating aw. The aw is located in the middle of

the pipeline which means that it is placed halfway along the length of the pipeline.

Therefore, this feature of the graph due to the coating aw is shown in the very

center of the x-axis. This peak at the middle of the x-axis of Figure 4–1 represents

the location of the coating aw. The values of the current density are much lower

here than all of the other locations along the pipeline. This can be misleading



44

-200

-160

-120

-80

-40

0

0 60 120 180 240 300 360

degrees from top of pipe

c u r r e n

t d e n s

i t y ( m A

/ s q

f t )

Figure 4–2: An angular plot of current density at the location of the coating aw.Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp

because the magnitude of cathodic current is actually greatest at the coating aw.

Values over the aw are actually as large as 120 mA/sq ft for this given simulation.

However, the values that are plotted on this graph are actually for the coated

area near the pipe. These values are very small because they are very close to the

coating aw, which is consuming almost all of the local cathodic current. This is

called a draw down in current near the coating aw. By creating an axial plot such

as Figure 4–1, the values of current density over the coating aw are not included.

In order to include these points, an angular plot must be generated. In Figure 4–2,

the locations of 0 degrees and 360 degrees represent the top of the pipeline where

the coating aw is located. Notice that the coating aw is now included by the

large magnitude of current that is present making all other points negligible on this

plot. These negligible points represent where the coating is present.

Notice that there are a lot of points in the axial plot around the location of the

coating aw. This is also true for the locations at the ends of the pipe and at the



45

-2.2E+03

-2.0E+03

-1.8E+03

-1.6E+03

0.0E+00 1.0E+04 2.0E+04 3.0E+04 4.0E+04 5.0E+04distance along pipeline (ft)

p o

t e n

t i a l ( m V )

Figure 4–3: A plot of soil surface on-potentials as they change along the length of the pipeline. Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp

connection to the anode. These extra points are included automatically by CP3D

because they are located where conditions change. For example, at the coating aw

the condition is changing from a coated pipe to an bare pipe. Therefore, in order toget an accurate picture of current and voltage distributions, more nodes or points

are used at these locations where changes in the pipeline are present.

The ow of current along the pipeline can also be illustrated by the magnitude

of current values given in Figure 4–1. It is known that as the current enters the

pipeline at a given location that it will begin to ow towards the connection with

the anode. This can be proven by noticing that the magnitude of current is larger

at locations closer to the anode. Note that in this graph by looking from right to

left that the shape slopes downward. This downward slope represents an increase in

the magnitude of current towards the pipeline’s connection with the anode.



46

-10

30

70

110

150

0.0E+00 1.0E+04 2.0E+04 3.0E+04 4.0E+04 5.0E+04distance along pipeline (ft)

p o

t e n

t i a l ( m V )

Figure 4–4: A plot of steel voltage as it changes along the length of the pipeline.Parameters: 36 sq in aw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp

The distribution of potential is very similar to that of the current in terms of

its shape as shown in Figure 4–3. More protected regions are shown as those which

display a more negative potential. The potentials near the bond to the anode arethe most negative which makes since because Figure 4–1 showed that this location

had the greatest magnitude of current. The behavior of current is also consistent as

current should ow from positive potentials to negative potentials. This is found to

be true as the values of potentials become more negative as they reach the bond of

the pipeline with the anode.

Another plot shown in Figure 4–4 gives a representation of steel voltage along

the length of the pipeline. This value of potential is based on the potential at a

given location along the pipeline referenced to the potential at one of the ends of

the pipeline. By looking at this pipe the behavior of the current also is represented

as owing towards the bond with the anode. The location of the coating aw can



47

-0.07

-0.06

-0.05

-0.04

-0.03

-0.02

-0.01

0.00

0.E+00 1.E+04 2.E+04 3.E+04 4.E+04 5.E+04 6.E+04

location along pipe (feet)

i ( m A / f t 2 )

30 k Ω cm

10 k Ω cm

3 k Ω cm

0.5 k Ω cm

50 k Ω cm

Figure 4–5: Current distribution along the pipeline is shown for changing soil resis-tivities.

be identied as the location in the middle of the plot where a high concentration of

data points are included. The graph shows a linear behavior at this location.

An additional set of simulations were run in order to help further understand

the behavior of current if the soil resistivity was increased. The coating defect

was taken off the pipeline in order to simplify this behavior. These simulations

were done separately from the previous data showing current and potential

distributions along the pipeline. For this set of simulations, the anode was placed

in the middle of a ten mile pipeline with no defect present. The anode voltage

was set a constant value of 5 Volts. The anode was moved to the middle of thepipeline so that it could be ensured that the distribution was symmetric. Again,

the magnitude of current is largest at the location of the bond to the anode as

shown in Figure 4–5. Figure 4–5 also shows that the magnitude of the current

also increases towards the ends of the pipeline as shown in previous distributions.



48

Different soil resistivities were used to help understand the effect of soil resistivity

on CP current. This graph shows the basic trend that as soil resistivity increases

the magnitude of current decreases. This is due to the fact that the current has an

increased difficulty of reaching the pipeline if the soil resistivity is high. Increasedsoil resistivity means that the conductivity of the soil is decreased. Therefore, if

the soil resistivity is high, the pipeline will receive less current and this could cause

the pipeline to be under protected. This allows the argument to be made that

soil resistivity is very important. The soil resistivity should be known in order to

make a decision on the level of CP to be used. This is because a normal CP level

that may be high for a low soil resistivity will probably insufficient for a high soil

resistivity.

4.2 Trends from Simulation Results

The effect of soil resistivity and coating aw (holiday) size on the value of

calculated indications was rst explored using CP3D simulation results. Figure 4–6

was developed to show the correlation between DCVG indication in mV versus aw

size based on changing soil resistivities. There are two main trends that are found

from Figure 4–6. One trend is that DCVG indications in mV will increase with

increasing aw size, which is consistent with conventional knowledge. The other

trend found is that as soil resistivity increases the DCVG indication decreases. This

trend is a result that was not initially expected. Since these are competing trends it

is of interest to determine which trend has a more dominating effect on indications.

By taking a closer look at Figure 4–6, it appears that the soil resistivity plays are a

larger role than aw size in determining DCVG indication in mV. This is supportedby the behavior at high soil resistivities where the DCVG indications show almost

no dependence on aw size. Conversely, there is a wide distribution of DCVG

indications at low soil resistivities. This result shows that prioritization of DCVG

indications in mV can be much improved by taking soil resistivity into account.



49

0

20

40

60

80

100

0 10 20 30 40 50

voltag e gradient (mV)

f l a w

s i z e

( i n 2 )

0.5K3K10K50K100K

Figure 4–6: DCVG indication in mV is plotted versus aw size as soil resistivity(ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, anode voltage:5V

DCVG indications were converted to percent-IR as shown in Figure 4–

7. This plot also shows the effect of soil resistivity and aw size on indication

except that it is for DCVG indications in percent-IR. In this case, the percent-IR calculations were made by scaling by the IR drop over the coating aw. The

results show that percent-IR indication increases both with increasing coating

aw size and increasing soil resistivity. This plot also shows that soil resistivity

can have a greater effect on percent-IR values than aw size. For example, for

each soil resistivity, the relative change of indications stays the same. This means

that as aw size changes, the percent-IR indication changes by the exact same

incremental value regardless of of what soil resistivity that the system is at. This

result shows that percent-IR indications can also be better prioritized by taking soil

resistivity into account. In other words, the percent-IR indications obtained could

be misinterpreted causing an inaccurate prediction of the coating aw size if the



51

0

20

40

60

80

100

0 20 40 60voltage gradient (mV)

f l a w

s i z e

( s q

i n )

high CP

med CP

low CP

Figure 4–8: DCVG indication in mV is plotted versus aw size as CP level is var-ied. Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, DOC: 4ft

be undetected. Therefore, the severity of a aw could be misinterpreted if CP level

is not taken into account. A sufficient amount of CP current is needed in order to

yield a measurable voltage gradient. DCVG in percent-IR was also plotted exactly

as done in Figure 4–8. This is shown in Figure 4–9. The obvious result shown here

is that the percent-IR values do not change with increased CP level. This result

could be helpful in predicting aw size based on DCVG indications in percent-IR.

Sensitivity of indications of DCVG in mV are also evaluated based on changing

depth of cover as shown in Figure 4–10. From this plot it is shown that DCVG

indications are more sensitive to a pipeline that is buried at four feet than at eightfeet. Although not shown here, previous simulations have further supported this

trend where indications at larger depths of cover are practically negligible. This

trend indicates that depth of cover should be used in prioritizing indications. For

the similar conditions in Figure 4–10, a plot of DCVG indication in mV is given



52

0

20

40

60

80

100

0 5 10 15 20 25percent-IR

f l a w

s i z e

( s q

i n )

high CP

med CP

low CP

Figure 4–9: DCVG indication in percent-IR is plotted versus aw size as CP levelis varied. Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, DOC: 4ft

0

20

40

60

80

100


f l a w

s i z e

( s q

i n )

4ft DOC

8ft DOC

Figure 4–10: DCVG indication in mV is plotted versus aw size as DOC is varied.Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, CP level: high



53

0

20

40

60

80

100


f l a w

s i z e

( s q

i n )

12in OD

48in OD

6in OD

Figure 4–11: DCVG indication in mV is plotted versus aw size as Dp is varied.Simulation parameters are Rs: 500 ohm-cm, DOC: 4in, CP level: high

versus changing pipe diameter. There is no clear trend found from this result as

shown in Figure 4–11. However, this result is taken with great caution since there

is no justiable evidence to prove that pipe diameter does not have an effect on

DCVG indication in mV.

CIS on-potential dip (on-dip) indications are plotted against aw size based

on changing soil resistivity in Figure 4–12. One basic trend shows that CIS on-dip

indication increases with increasing aw (holiday) size. Another trend shown is

that the CIS on-dips increase as soil resistivity increases. However, this result

should be considered with caution due to the changing of the anode voltage. The

anode voltage was changed for each simulation to maintain a certain level (high)

of CP. The anode voltage was increased as soil resistivity increased to maintain a

certain range (-1150mV) of soil surface off potentials far away from the aw. This

same result is also shown for DCVG indications given in Figure 4–13. Note that

the DCVG trend in mV for Figure 4–13 is different than it was in Figure 4–6. This



54

0

20

40

60

80

100

0 50 100 150 200 250potential (mV)

f l a w

s i z e

( s q

i n )

3K10K50K100K

Figure 4–12: CIS on-potential dip indication is plotted versus aw size as soil resis-tivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level:high

is because in Figure 4–6, the anode voltage was held constant for all runs. This

indicates that increased CP level increases the DCVG indication found even if soilresistivity is also increased.

Figure 4–14 is based on data from the same simulations run in Figure 4–12.

However, it shows a different result for some soil resistivities. The negative CIS off-

dips initially represented an area of concern. The on- and off-potential proles are

given for a simulation that gives a negative CIS off-dip in Figure 4–15. A general

potential prole represents current direction by moving from positive to negative

potentials. In Figure 4–15, the on-potential prole shows that current is entering

the pipeline at the coating aw and then it travels away from the aw based on the

prole of on-potentials moving from positive to negative. This is normally expected

to be found for CIS off dips as well. However, the negative CIS off-dip indicates



55

0

20

40

60

80

100

0 20 40 60 80voltage gradient (mV)

f l a w

s i z e

( s q i n

)

3K10K50K100K

Figure 4–13: DCVG indication in mV is plotted versus aw size as soil resistivity(ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level: high

that when the CP current is turned off that the potential ows back towards the

aw. This can be attributed to the pipeline being substantially over protected

underneath the coating than it is at the aw. This is justied to occur at low soilresistivities because the coating resistance is so much higher than the resistance of

the soil when the soil resistivities are low.

Another way to prioritize CIS indications is to calculate the dips in potential

to determine the relative size of the coating. From simulation data it can be shown

that the size of the dip has a direct correlation with the size of the aw. This result

is shown in Figure 4–16. This trend shows that the magnitude of the dip increases

with increasing size of the coating aw.

Current attenuation plots are also included in both mA and percent. Figure

4–17 shows that as soil resistivity increases that the Current attenuation decreases.

This makes sense because less current is able to get to the aw at higher soil



56

0

20

40

60

80

100

-20 0 20 40 60 80 100

potential (mV)

f l a w

s i z e

( s q

i n )

3K10K50K100K

Figure 4–14: CIS off-potential dip indication is plotted versus aw size as soil resis-tivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level:high

-2

-1.8

-1.6

-1.4

-1.2

-1

7910 7920 7930 7940position along soil surface (m)

p o

t e n

t i a l ( V )

On PotentialOff Potential

Figure 4–15: A prole of soil surface on- and off-potentials from a simulated CISsurvey. Simulation parameters are aw size: 36 in 2 , Rs: 500ohm-cm, Dp: 12in,DOC: 4ft, CP level: high



57

-1.62

-1.6

-1.58

-1.56

-1.54

-1.52

7910 7915 7920 7925 7930 7935 7940position along soil surface (m)

p o

t e n

t i a l ( V )

1 sq in36 sq in100 sq in

Figure 4–16: A representation of soil surface on-potential proles taken along thelength of the pipeline. The anode voltage is held constant for each simulation.

resistivities. However, even with the anode voltage being adjusted for each of these

data points, the soil resistivity dominates. A similar trend is shown for current

attenuation in percent. Note that the percentages are all very low. This can be

attributed to the ratio of the area of aw size to the area of the pipeline.

4.3 Flaw Size Predictors

4.3.1 CIS Predictor

All simulation data results were used to predict aw size based on CIS

indications. The simulation data used involve variations in CP level, pipe diameter,

depth of cover, and soil resistivity. The objective was to develop a formula that

predicts aw size through use of the CIS dip indications given as:

aw size = m(CIS on − dip − CISoff − dip ) (4.1)



59

0

20

40

60

80

100

0.00 0.50 1.00 1.50 2.00Indication (%)

f l a w

s i z e

( s q i n

)

3K10K50K100K1000K

Figure 4–18: Current attenuation in percent is plotted against aw size as soil resis-tivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level:high

neglect CP level from the expression for m. In Table ( 4–1), data for three different

simulations are shown whose only difference is in CP level. Notice that there is a

different CIS indication for each simulation in Table ( 4–1). However, by dividing

by IR total (which is illustrated in Figure ( 4–20)), an identical value is obtained for

each simulation. Therefore, the total number of simulations used in the calculation

for the aw size predictor can be divided by three. The last column in Table ( 4–1)

is now multiplied by 100 to make it a percentage and then plotted against the

square root of the aw size. The square root of aw size was used in order to get a

value that exhibits the same qualities of a characteristic radius. This plot is given if

Figure ( 4–21).

A plot similar to Figure ( 4–21) was created for each different combination of

soil resistivity, depth of cover, and pipe diameter. However, in contrast to Figure

(4–21), a near perfect linear t was found for each of these combinations. The



60

0

20

40

60

80

100

120

140

0 20 40 60 80 100 120

flaw size (sq in)

C I S I n d i c a

t i o n

( m V )

Figure 4–19: A plot of CIS indications versus aw size from simulation data. CISindication is the difference in the on-potential dip and the off-potential dip.

Figure 4–20: A prole of general behavior of on- and off-potentials along the cen-terline at the soil surface.



61

0.0

5.0

10.0

15.0

20.0

0.0 2.0 4.0 6.0 8.0 10.0 12.0flaw size 1/2 (in1/2 )

C I S I n d i c a

t i o n

/ I R

t o

t a l

Figure 4–21: A plot of CIS indication divided by IR total versus the square root of the aw size. The denition of IR total is illustrated in Figure (4-20).

different slopes found (one for each combination) were then plotted against soil

resistivity for each combination of pipe diameter and depth of cover. A near perfect

exponential t was found for each. An example of this is shown in Figure ( 4–22).

For each of these plots a pre-exponential factor was calculated and an exponential

term was calculated. The different pre-exponential factors were then plotted versus

depth of cover and pipe diameter separately. No relationship was found between

the pre-exponential factor and the pipe diameter. However, a linear t was found

between the pre-exponential factor and depth of cover as shown in Figure ( 4–23).

Now, an expression for m can be used to predict aw size as

m = A exp(− aR s ) (4.2)

where A is the function found from Figure ( 4–23), a is the average of all of the

exponential terms from the different plots similar to Figure ( 4–22), and Rs is soil



64

0

20

40

60

80

100

120

140

160

0 20 40 60 80 100 120 140 160

Actual flaw size (sq in)

P r e

d i c t e d f l a w

s i z e ( s q

i n )

Figure 4–25: Actual aw size is plotted versus predicted aw size for each simula-tion using DCVG indications.

along the pipeline, the DCVG predictor used IR drops far away from the coating

aw but in the direction away from the pipeline towards remote earth. In order for

the predictor to be used the soil resistivity, depth of cover, and pipe diameter mustbe known. Figure ( 3–6) shows the percent-IR calculation which is similar to the

information needed for the DCVG predictor to work. Assuming that point D is at

remote earth in Figure ( 3–6), the voltage gradient between point A and D must be

found. This same voltage gradient must also be used but at a location further down

the pipeline so that it is not near the coating aw. Also the IR drop at remote

earth (point D) must be used to complete the information needed to calculate aw

size. In Figure (4–25), a condence interval is given as represented by the dashed

lines. This is used to show that the DCVG predictor is not predicting an exact

coating aw size but instead a range in which the coating aw size should be in.

The same was done for the CIS predictor in Figure ( 4–24).



CHAPTER 5CONCLUSIONS AND FUTURE WORK

5.1 Conclusions

Several trends were found addressing the sensitivity of the different above-

ground techniques under variation of many parameters. DCVG in mV was the

rst measurement technique explored in this work. As expected, it was found that

DCVG indications increase with increasing coating aw size. However, a more

interesting result showed that increased soil resistivity caused DCVG indications

in mV to decrease. In fact, it was found that soil resistivity has an even larger

effect on DCVG indications than the size of the coating aw. Also found was that

increased anode voltage causes DCVG indications to increase. This is explained by

a larger amount of current entering the pipeline at the coating defect. The effect

of parameters such as depth of cover and pipe diameter on DCVG indications were

also explored. It was found that DCVG indications decrease as depth of cover

increases. There was no relationship established regarding the sensitivity of DCVG

in mV with pipe diameter.

Trends and relationships were also found for DCVG indications converted to

percent-IR. Percent-IR values increased with both increasing coating aw size and

soil resistivity. From these results it was found that the evaluation of percent-IR

values should not exclude consideration of soil resistivity. For example, a high

soil resistivity could cause a small defect to yield a large percent-IR value leading

to unnecessary excavation. Also, most of the large coating aws (100 sq in) had

low percent-IR values that under normal evaluations would be as minimal threat

to potential corrosion failure. This further proves that percent-IR values are not

65



66

enough to make a decision on whether a defect is severe or not. The level of soil

resistivity among other factors must also be incorporated into this assessment.

The Close Interval Survey (CIS) showed similar results to DCVG in mV

in that larger prole dips were found with increased coating aw size. After allof the required simulations were completed, CIS results were able to be used to

predict a given aw size based on indications and known pipeline parameters. This

development proved that CIS indications as well as DCVG indications do not give

enough information alone to make assessments about aw size. This is shown in

Figure ( 4–19), where there is a substantial amount of scatter in the data between

CIS indications and aw size. No conclusion or assessment about the size of the

aw can be made using the CIS indications calculated. However, this development

showed that by knowing more about other parameters of the system (such as soil

resistivity, depth of cover, and pipe diameter), a quantitative relationship can be

made between CIS indications and coating aw size. Overall, the predictor for

CIS showed very good agreement between actual aw size and predicted aw size.

A similar method was used to predict aw size using DCVG indications, but the

condence interval was much larger than that of the CIS predictor.

5.2 Future Work

Most importantly, the quantitative results of this work need to be tested.

Now that coating aw size predictors have been developed using the CP3D

simulation model, they need to be tested in eld surveys. A condence interval

has already been established from the results. However, it is expected that the

design equations used to predict aw size may need to be adjusted slightly bysome factor after initial results. As for ways to improve the current work, a model

predictor needs to be obtained involving Current Attenuation surveys similar to

that of the CIS and DCVG aw size predictors. In some cases it may be easier to

run a survey involving current attenuation instead of CIS or DCVG. Therefore, a



67

design equation needs to be developed that can predict aw size based on current

attenuation indications.

While this work has incorporated variances in many different parameters of

the pipeline and its environment, more simulations need to be run to improvethe understanding of the behavior of a pipeline with a bad coating. This work up

until now involves assessments using coatings in excellent condition. Therefore, an

extension of this work would be to cover areas that we have not explored yet such

as coatings in medium or bad condition. Bad coatings can cause issues for above-

ground measurement techniques due to the possibility that corroded areas of the

pipeline may be undetected. This can occur because the CP current is so widely

distributed that there is not enough localized current entering the pipeline at a

corroded or bare location. This causes indications from measurement techniques

to not be large enough to detect bare spots on the coating. For example, voltage

gradients in the ground will not arise if there is not a large enough ow of localized

current entering the pipeline at a given location. Characterization of this behavior

needs further development using CP3D simulations.

Another issue to be explored is of CP systems involving multiple pipelines

and/or multiple anodes. Underground spacing between pipelines continues to

decrease everyday as more pipelines are installed. This can cause some pipelines to

interfere with the CP current intended for nearby pipelines. This can also lead to

insufficient protection of some pipelines causing a legitimate concern. CP3D has

the ability to create an environment with multiple pipelines and multiple anodes

which could lead to a better understanding of how CP current systems should beimplemented in close proximity. This type of study could also incorporate the use

of using both impressed current anodes as well as sacricial anodes. Contributions

of the different anodes could be differentiated to understand at what locations and

settings they will work best.



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evaluation of above-ground potential measurements for assessing pipeline integrity

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