Use of CP3D Simulations for Evaluation of ECDA Indications on Pipeline Conditions

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Use of CP3D Simulations for Evaluation of ECDA Indications on Pipeline Conditions
Chu, Chia
Orazem, Mark ( Mentor )
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Gainesville, Fla.
University of Florida
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Use of CP3D Simulations for Evaluation of ECDA Indications on

Pipeline Conditions

Chia H. Chu and Mark E. Orazem


The cost of corrosion on buried pipeline can be reduced substantially by applying coatings and cathodic

protection. Although these methods can considerably increase the useful lifetime of an underground pipeline, they

do not guarantee total suppression of corrosion. A number of techniques use above ground measurements

to determine pipeline conditions. Currently, engineers in the field who are experienced with external

corrosion interpret these indications on a subjective basis due to lack of a numerical guideline. By using

the comprehensive cathodic protection model CP3D, developed by the University of Florida, a guideline can

be developed to assist engineers in prioritizing field works. The software is able to generate data such as on- and

off-soil surface potentials under specific environmental conditions applied to the program. The data generated

can then be processed to simulate common field techniques. Under various environmental conditions, the

sensitivities of these field techniques are compared. It is expected that these comparisons will lead to

the development of a general guideline.


An extensive underground network of pipelines is used to transport liquid petroleum products and natural gas.

In 1999, the American Gas Association reported that approximately 1.3 million miles of buried steel pipe was used

for the transport of natural gas alone in the United States1. Buried steel structures are subject to corrosion. In

severe cases, perforation of the pipeline can occur. Severe corrosion can lead to consequences including loss

of product, property damage, and even loss of life. The purpose of corrosion prevention is therefore not only an

issue of protecting valuable assets, but also of minimizing the social and economic cost. Modern pipelines

are generally protected by coatings and by cathodic protection.2

A serious need exists for methods to assess conditions where the corrosion mitigation strategies have failed.

A number of External Corrosion Direct Assessment (ECDA) techniques are based on measuring current and

potential distributions.3 Engineers need criteria to select and prioritize ECDA indications. Presently,

engineers experienced with external corrosion choose indications on a subjective basis.

The University of Florida has developed a comprehensive cathodic protection model named CP3D.4,5 This

software can be used to prioritize various ECDA indications under a certain pipeline conditions. The objective of

this work was to use CP3D to develop guidelines that will assist engineers in the field in making decisions

on implementations of ECDA.


Corrosion occurs when a material deteriorates due to its reaction with the environment. Specifically, for primary

focus of this research, a buried steel pipeline reacts with dissolved oxygen that is present in the soil environment.

In the electrochemical aspect, metallic corrosion is a redox reaction in which the metal is oxidized while oxygen

is reduced.2 The anodic (oxidation) reaction results in the dissolution of the metal, in this case, iron, as

Fe -> Fe2+ + 2e- (1)

Oxygen can be reduced differently at low and high pH. A cathodically protected steel pipeline in soil forms an

alkaline environment, and, thus, the cathodic reaction is oxygen reduction at high pH.2

02 + 2H20 + 4e- -> 40H- (2)

Both the oxidation reaction and the reduction reaction must occur at the same rate on the pipeline surface.

The overall reaction can be obtained by adding the oxidation and reduction reactions (1) and (2):

2Fe + 2H20 + 02 -> 2Fe2+ + 40H- (3)

The products of the overall reaction form ferrous hydroxides, which are further oxidized to form ferric

hydroxides.2 Ferric hydroxides are more commonly known as rust.


Cathodic protection is commonly used to prevent corrosion. The basic idea is to supply electrons to the

metal structure to suppress metal dissolution. Two forms of cathodic protection are used: one that uses

sacrificial anodes and another that applies impressed currents.2 In the first scenario, the buried steel pipeline to

be protected is connected to a less noble metal such as zinc or magnesium. Once connected, they form a

galvanic couple. The sacrificial anode will corrode at a faster rate than it would have by itself; while, the steel

pipeline becomes the cathode and corrodes at a slower rate than it would by itself. Sacrificial anodes are so

termed because the material is consumed in order to protect the steel pipeline. Eventually the anode will

require replacement. A schematic representation of a pipe protected by a sacrificial anode is presented in Figure 1

Figure 1. Sacrificial anode forms a galvanic couple with the steel pipe.

Alternatively, a buried steel pipeline can also be protected by an external power supply. The negative terminal of

a rectifier is connected to the pipeline while the positive terminal to an inert material. This way current is

impressed between the pipeline and the anode and corrosion is suppressed. A schematic representation of a

pipe protected by a rectifier is given in Figure 2.

Figure 2. Pipeline is protected by impressed current.

To reduce the current requirement for cathodic protection, pipelines are usually coated with materials such as coal

tar enamel. 6 However, localized corrosion can be accelerated if a defect is present in the pipe coating. Such

localized corrosion can be mitigated by increasing the level of cathodic protection, but an excessive level of

cathodic protection can cause hydrogen embrittlement.2


A comprehensive cathodic protection model was developed at the University of Florida to address areas

where standard analytic design equations are not applicable. This is true for situations where pipeline

coatings contain holidays so severe that bare steel is exposed and where geometry of pipelines are complex.4 The

CP simulation represents the solution to assist engineers in evaluating the cathodic protection system in place

and also answering the key question: how to prioritize other field works when an anomaly is encountered? Figure

3 provides the entry screen seen when CP3D is launched.

1.ji* ----

Figure 3. A view of CP3D when the program is initially launched.

During the process of creating a pipe in the program, a holiday was specified in a rectangular shape and placed

along the pipeline facing down. Figure 4 is a view from within the pipe. The defect can be seen at the bottom in

red. The density of nodes increases near the coating holiday. Figure 5 is a view of a groundbed attached to the

steel pipe. A sacrificial anode would appear identical to an impressed current anode. Physical properties are

specified to distinguish between the two. The next step was then to place soil surfaces over the pipeline

where coating holidays were present. A soil surface was also placed above the segment where the groundbed

is attached to the pipeline in order to study the behaviors of soil surface potentials above an anode. Figure 6 is a

view of a soil surface over the anode after the calculations were finished. The legend on the screen indicates

the range of on- or off-potentials to corresponding colors.

. . . .
I .-._ . ......

Figure 4. Viewing the holiday from inside the pipeline. The nodes become denser toward the pipe

where defect (red spot on the bottom) is present.




Figure 5. A magnesium anode is attached to the steel pipeline. An impressed current anode would

appear the same way.

Figure 6. Surface potentials over the groundbed observed at the end of calculations.


A description of ECDA techniques is provided as a NACE Standard Practice.7 Prior to conducting pipeline

integrity surveys, pipeline location as well as depth of cover must be determined. The centerline of a pipeline can

be located using an inductive pipe-locating device. The technician places survey flags every 100 feet over

the pipeline.8 At each flag location, the same pipe-locating device can determine depth of cover.

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Direction Current Voltage Gradients

Direction Current Voltage Gradients (DCVG) surveys are used to evaluate pipeline coating integrity and are the

only method capable of approximating a holiday size. During a DCVG survey, the pipeline's CP current is

interrupted to create the DC signal and then the surveyor measures above ground voltage gradients along

the pipeline.8 The surveyor walks along the pipeline with two probes. One is always kept above the pipe

centerline where the other approximately five feet away perpendicular from the pipe centerline.8 The voltmeter

is observed when both probes are in contact with the ground. As a coating holiday is approached, a signal

deflection can be observed on the voltmeter. The DCVG indication is calculated according to

DCVG = ((V -Vq) -(V -V ) .))

where the y-direction is the direction perpendicular to the pipe. The maximum deflection should be observed at

a location where a coating holiday is present. To determine the size of the coating holiday further

measurements must be made. The measurements are performed perpendicular to the pipeline toward remote

earth. Remote earth is reached when the difference between adjacent IR drops observed on the voltmeter is 1 mV

or less. IR drop is defined as the difference between on-potential and off-potential. The "%IR", assumed to

represent the size of coating holiday is found from

= (Vo -V Xl-(Vo-Vq,)

where point 1 represents the centerline of the pipe and point 0o represents remote earth.

A summary of DCVG %IR indications is provided in Table 1.8

Table 1

Summary of DCVG %IR indications.8

Category %IR Range Indications

Coating holidays are negligible if a proper CP system is in
1 1%-15%
place. Note: A CP system can be evaluated by CIS.

Coating holidays are recommended for repair. A proper CP

2 16%-35% system can still adequately protect the area. It requires

additional monitoring.

3 36%-60% Coating holidays are required to be repaired.

Coating holidays are a serious problem to the pipeline
4 61%-100%
integrity. It requires immediately attention.

Alternating Current Voltage Gradient

Alternating Current Voltage Gradient surveys (ACVG) are similar to the previously described DCVG technique,

except that in an ACVG survey, a low frequency transmitter is connected to the pipeline to create the AC signal.8

Close-Interval Surveys

Close-Interval Surveys (CIS) are used to evaluate the performance of cathodic protection systems and to

detect coating holidays. They do so by measuring the potential difference between the pipeline and the soil as the

CP current sources are switched on and off.8 A pipeline that is under cathodic protection is equipped with test

stations where electronic leads are physically attached to the pipeline to measure pipe-to-soil potentials.

However, these test stations do not cover the entire length of the pipeline. The goal of CIS then is to determine

the quality of CP performance over the entire pipeline. Normally the range between -850mV and -1,200mV is

desired for a well-protected system.3

In a CIS survey, the technician is physically connected to the test station by a trailing wire and measures the

pipe potential above ground with a pair of reference electrodes spaced approximately five feet from each other.3

The accuracy of this survey relies on the current interrupters at each CP current source. All the interrupters must

be synchronized to make sure that CP current flow through soil is minimized during potential readings.

Additionally, the ratio between on and off cycles must be long enough so that a reading can be taken, yet

significant depolarization may result if the on-to-off ratio is too large. The general rule of thumb is three seconds

on and one second off.7 This way pipeline polarization can be maintained while accurate measurements can

be obtained. While the previously mentioned techniques may be better at detecting coating holidays, CIS is

also useful in identifying interference, contact with other metallic structures, and so on.8


Many factors affect ECDA indications such as soil resistivity, polarization parameters, and pipe diameter.

We performed a set of CP3D simulations that varied the coating holiday size while keeping the rest of the

factors constant. The set of simulations were repeated at different soil resistivity levels. Summaries of

specifications for the simulations are presented in Tables 2 and 3.

Table 2

Summary of simulation specifications

Item Specifications

Pipe Dimensions:

Anode Dimensions


Pipe to Anode Length:

12" Diameter

2/8" Wall Thickness

10 Mile Length

30" Diameter

200 ft Length


1000 ft

Table 3

Summary of coating specifications- Bare Steel 10mA represents coating holidays

that exposes bare steel

Property Name

Coated Pipe

Bare Steel (10mA)

Coating Resistivity 5*109 ohm-cm ---

Coating Thickness 20 mils ---

Oxygen Bocking 99.9% ---

Apore/A 0.10% ---

Iron Oxidation

E Fe (-) 522 mV CSE (-) 622 mV CSE

Tafel Slope 62.6 mV/decade 59 mV/decade

Oxygen Reduction

Limiting current density for
0.975 mA/ft2 10 mA/ft2
Oxygen Reduction

E 02 (-) 172 mV CSE (-) 172 mV CSE

Tafel Slope 66.5 mV/decade 61 mV/decade

Hydrogen Evolution

E H2 (-) 942 mV CSE (-) 942 mV CSE

Tafel Slope 132.1 mV/decade 132.1 mV/decade

Corrosion Potential (-) 654.3 mV CSE (-) 561.1 mV CSE

The coating holiday sizes chosen were 1, 16, 36, 64, 100 square inches and the soil resistivity levels chosen were

500 ohm-cm, 3,000 ohm-cm, and 10,000 ohm-cm. At the end of each simulation, soil surface on- and off-

potentials were extracted from the program and processed to simulate the DCVG and %IR techniques. Since the

soil surface potentials should be symmetrical with respect to pipe centerline, the soil surface will be reduced in

half for time efficiency.

Prior to running the matrix of simulations, it was necessary to determine the distance from the pipe centerline to

the remote earth. This was done through a trial and error process. A pipeline with a coating holiday was

simulated and a soil surface section was placed over the pipe segment where coating holiday was found. The

initial trial was to have the soil surface extending ten nodes from the centerline to remote earth with each node

was spaced in increments of 5.1 feet perpendicular to the pipe. Then IR drop was calculated at each node.

Remote earth was designated as the node yielding difference between adjacent IR drop of 1 mV or less.7


The number of nodes was determined by a trial-and-error process. Figure 7 shows that changes in IR drops

become steady and with values of less than 1 mV beyond the third node.


0 2 4 6 8 10 12

Figure 7. Change in IR drop across nodes that extended perpendicularly from the pipe centerline.

The result was obtained for soil resistivity of 10,000 ohm-cm.

In order to ensure that remote earth is reached, the soil surface calculation section was extended to the eighth node.

The DCVG indications were obtained by recording the maximum voltage gradient observed when one moves

along the pipeline near the coating holiday. When DCVG indications were plotted against coating holiday sizes

at different soil resistivity levels, as shown in Figure 8, DCVG indications were found to be more sensitive at lower

soil resistivities. Highest DCVG indications were obtained at soil resistivity of 500 ohm-cm.

S-e- 500 Ohm-cm
S/ -A--3,000 Ohm-cm
P. a 10,000 Ohm-cm

0 50 100 150 200
DCVG Indications (mV)

Figure 8. DCVG indications compared at different soil resistivity levels.

The %IR indication was obtained by recording the maximum value observed. Figure 9 indicates that at higher

soil resistivity levels the %IR is more sensitive to coating holidays.

0 50 100 150

Figure 9. %IR is plotted against coating holidays at different soil resistivity levels.


Prevention of social and economic costs due to corrosion on buried pipes requires a proper pipe coating and a

well-maintained cathodic protection system. Several survey techniques are recommended by NACE International

to monitor the pipeline integrity. The usefulness of these recommended practices depend on environmental

conditions encountered. Developing a numerical guideline for the effect of environmental conditions was the

major objective of this work. Several parameters, including soil resistivity, pipe diameter, holiday size,

and groundbed specifications, were recognized as factors affecting the sensitivities of ECDA indications.

The approach taken was to isolate one parameter at a time and to determine general trends of ECDA indications as

a function of the chosen parameter. Soil resistivity was chosen as the first parameter and a matrix of

defective pipelines were simulated at various soil resistivity levels ranging from 500 ohm-cm to 10,000 ohm-cm.

The level of defect was adjusted by changing the size of coating holiday. Data were processed to simulate DCVG

and %IR indications. Results show that DCVG indications were highest at a low soil resistivity while %IR

indications were highest at a high soil resistivity. Therefore, in a scenario where a weak DCVG indication at a high

soil resistivity is observed, an operator can perform a %IR survey to confirm a defective site.

This work represents an important starting point for the development of a general guideline for choosing

ECDA indications. Several other parameters, including pipe diameter and groundbed specification, will be tested in

a similar fashion.


The technical assistance of Dr. Oliver Moghissi, Vice President of CC Technologies, and Patrick McKinney, UF

graduate student, is gratefully acknowledged.References


1. Technical report, American Gas Association (1999). Http://

2. Fontana, Mars G., Corrosion Engineering, McGraw Hill, New York, 1986.

3. GTI Pipeline Integrity Management, "ECDA Implementation Protocol," GTI, Des Plaines Illinois, 2003.

4. Riemer, D. P. and Orazem, M. E., "Application of Boundary Element Models to Predict Effectiveness of Coupons

for Assessing Cathodic Protection of Buried Structures," Corrosion, 56 (2000), 794-800.

5. Riemer, D. P. and Orazem, M. E., "Modeling Coating Flaws with Non-Linear Polarization Curves for Long Pipelines,"

in Corrosion and Boundary Element Methods, R. A. Adey, editor, WIT Press, Southampton, UK, 2005, in press.

6. Peabody, A. W., Control of Pipeline Corrosion, NACE International, Houston, Texas, 1978.

7. NACE Standard RP0502-2002, "Pipeline External Corrosion Direct Assessment Methodology," NACE

International, Houston, Texas, 2002.

8. Moghissi, 0., CC Technologies, personal communication, 2005.


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