EVALUATION OF ABOVE-GROUND POTENTIAL MEASUREMENTS FOR ASSESSING PIPELINE INTEGRITY

Transcription

1 EVALUATION OF ABOVE-GROUND POTENTIAL MEASUREMENTS FOR ASSESSING PIPELINE INTEGRITY By JAMES PATRICK MCKINNEY A THESIS PRESENTED TO THE GRADUATE SCHOOL OF THE UNIVERSITY OF FLORIDA IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE UNIVERSITY OF FLORIDA 2006

2 ACKNOWLEDGMENTS I 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 benefited 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

3 TABLE OF CONTENTS page ACKNOWLEDGMENTS ii LIST OF TABLES v LIST OF FIGURES vi ABSTRACT ix CHAPTER 1 INTRODUCTION LITERATURE REVIEW External Corrosion Direct Assessment (ECDA) Corrosion Background Cathodic Protection Background Principles of CP Internal Inspection Techniques Above-Ground Measurement (Indirect) Techniques Close Interval Survey (CIS) Direct Current Voltage Gradient (DCVG) Alternating Current Voltage Gradient (ACVG) Current Attenuation CP3D Description of CP3D Mathematical Development Bare Steel Coated Steel Sacrificial and Impressed Current Anodes Replication of Techniques CIS DCVG ACVG Current Attenuation CP3D settings Matrix of Simulations iii

4 4 RESULTS AND TRENDS Current and Potential Distributions in the Pipeline Trends from Simulation Results Flaw Size Predictors CIS Predictor DCVG Predictor CONCLUSIONS AND FUTURE WORK Conclusions Future Work REFERENCES BIOGRAPHICAL SKETCH iv

5 Table LIST OF TABLES page 3 1 The matrix of model runs showing the ranges of different parameters that were varied Three simulations different only in CP level. Parameters are 12in Dp, 4ft DOC, and 0.5 kohm-cm (soil resistivity) v

6 Figure LIST OF FIGURES page 2 1 A CP system with a sacrificial anode A CP system with impressed current A representation of on- and off-potential profiles which show how CIS dips are categorized. Each data point represents a measurement at the soil surface directly over the pipeline The percent-ir calculation is shown using the lateral voltage gradients with the interpolated value of IR drop over the coating flaw A diagram showing how an IR measurement is interpolated at the ground surface above the coating flaw An image from CP3D showing the physical orientation of the soil surface with respect to the pipeline. The darker area on the pipeline represents the coating flaw or holiday A profile of on- and off-potentials from CP3D simulation data where the dip indicates the location of the coating flaw. Each data point represents a measurement at the soil surface directly over the pipeline A schematic of how CIS indication is calculated using the nodes of the soil surface A schematic of how DCVG measurements are made using CP3D A profile of DCVG measurements above the pipeline. The peak value represents the overall DCVG indication A schematic of how percent-ir is measured and calculated A profile of IR drops in the perpendicular direction to the pipeline. The IR drops are all at the same lengthwise position as the coating flaw in respect to the pipeline A plot of current density as it changes along the length of the pipeline. Parameters: 36 sq in flaw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp An angular plot of current density at the location of the coating flaw. Parameters: 36 sq in flaw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp 44 vi

7 4 3 A plot of soil surface on-potentials as they change along the length of the pipeline. Parameters: 36 sq in flaw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp A plot of steel voltage as it changes along the length of the pipeline. Parameters: 36 sq in flaw, 35Kohm-cm, High CP, 4ft DOC, 12in Dp Current distribution along the pipeline is shown for changing soil resistivities DCVG indication in mv is plotted versus flaw size as soil resistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, anode voltage: 5V DCVG indication in percent-ir is plotted versus flaw size as soil resistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, anode voltage: 5V DCVG indication in mv is plotted versus flaw size as CP level is varied. Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, DOC: 4ft DCVG indication in percent-ir is plotted versus flaw size as CP level is varied. Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, DOC: 4ft DCVG indication in mv is plotted versus flaw size as DOC is varied. Simulation parameters are Rs: 500 ohm-cm, Dp: 12in, CP level: high DCVG indication in mv is plotted versus flaw size as Dp is varied. Simulation parameters are Rs: 500 ohm-cm, DOC: 4in, CP level: high CIS on-potential dip indication is plotted versus flaw size as soil resistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level: high DCVG indication in mv is plotted versus flaw size as soil resistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level: high CIS off-potential dip indication is plotted versus flaw size as soil resistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level: high A profile of soil surface on- and off-potentials from a simulated CIS survey. Simulation parameters are flaw size: 36 in 2, Rs: 500ohmcm, Dp: 12in, DOC: 4ft, CP level: high vii

8 4 16 A representation of soil surface on-potential profiles taken along the length of the pipeline. The anode voltage is held constant for each simulation Current attenuation in ma is plotted against flaw size as soil resistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level: high Current attenuation in percent is plotted against flaw size as soil resistivity (ohm-cm) is varied. Simulation parameters are Dp: 12in, DOC: 4ft, CP level: high A plot of CIS indications versus flaw size from simulation data. CIS indication is the difference in the on-potential dip and the off-potential dip A profile of general behavior of on- and off-potentials along the centerline at the soil surface A plot of CIS indication divided by IR total versus the square root of the flaw size. The definition of IR total is illustrated in Figure (4-20) An exponential plot of slope versus soil resistivity. Data was at a depth of cover of 4ft and a pipe diameter of 6 inches A plot of pre-exponential factors versus the corresponding depth of cover Actual flaw size is plotted versus predicted flaw size for each simulation using the derived expression for m Actual flaw size is plotted versus predicted flaw size for each simulation using DCVG indications viii

9 Abstract of Thesis Presented to the Graduate School of the University of Florida in Partial Fulfillment of the Requirements for the Degree of Master of Science EVALUATION OF ABOVE-GROUND POTENTIAL MEASUREMENTS FOR ASSESSING PIPELINE INTEGRITY By James Patrick McKinney May 2006 Chair: Mark E. Orazem Major 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 flaws 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 mathematical 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 flaw (holiday) size, coating condition, level of cathodic protection, and polarization ix

10 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 along the 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 performed include Close Interval Survey (CIS), Direct Current Voltage Gradient (DCVG), Alternating Current Voltage Gradient (ACVG), and Current Attenuation. Results from these techniques show that soil and coating parameters are significant. Currently engineers use subjective judgment based on ECDA indication results measured. However, these results can be significantly skewed based on changes in these parameters which can affect the interpretation of results. x

11 CHAPTER 1 INTRODUCTION 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 flaw 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 flaw 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. Currently, 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 five chapters. Chapter 2 discusses the history and basic principles of corrosion and how cathodic protection systems work. Also 1

12 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 flaw 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.

13 CHAPTER 2 LITERATURE REVIEW 2.1 External Corrosion Direct Assessment (ECDA) External Corrosion Direct Assessment (ECDA) was first 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 Examination, and Post-Assessment. 4, 5 Preassessment is the first 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

14 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 called Guided 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 aboveground 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 performed 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 first 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 the pipeline can be inspected first-hand. 5 Before excavations are started, this step first involves evaluating the measurements from the indirect inspections. 2 Based on the data collected, a determination is made for which areas need excavation. The excavations are done at areas where the data from above-ground measurements suggest

15 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 indications are valid, random excavations are done at areas where there is no indication of 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 first 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 beneficial in providing numbers for the probability of finding 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 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 first known to use methods to fight 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 scientific approaches have been developed to fight corrosion such as cathodic protection.

16 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 billion dollars 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 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 fixing 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 first needed. Corrosion is defined 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 the anodic 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.

17 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 are gold, 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 sulfides. 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 sulfide is also very corrosive. 10 These conditions are becoming more likely in industrial chemical processes as they 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

18 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 fight 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 scientific 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 the increasing 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 scientific. Simple methods involve protecting

19 9 metals with paints, caulking materials, polymers, metallic coatings, or organic coatings. 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 the metal s surface forming a non-conducting film. 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 scientific approaches, cathodic and anodic protections are the most common used to fight 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 Background The first person to describe the use of cathodic protection was Sir Humphrey Davy in , 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 first 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

20 10 appreciable levels of oxygen, water, and salts. Pipelines became susceptible to leaks as corrosion would accelerate eventually degrading areas of the metal completely. This became of major consequence as problems occurred such as fire, contamination of the environment, lost product, service interruptions, and declining relations with the public. 9 Since many underground pipelines carry oil and natural gas over hundreds of miles, it is quite a task to ensure that an entire pipeline is protected. Today, over 1.3 million miles of underground pipeline are used to carry natural gas and another 170,000 miles is used to transport oil or other petroleum products. 18, 19 By the 1930s pipeline owners began fighting corrosion by applying external coatings and implementing cathodic protection. 9 The corrosivity of the ground was measured in order to focus on areas which needed protection the most and efforts made were considered to be successful. 9 After coatings were applied on pipelines, accelerated corrosion was found at certain areas and it became evident that CP must accompany the coating. 20 During installation or excavation of pipelines with coatings it is likely that the coating will be scraped or damaged in some places leaving bare spots. These areas are called coating flaws or coating holidays. One study found that a coating flaw causes a much greater risk to the pipeline than there would be if the coating was completely absent as the potential for localized failure of the pipeline is greatly increased. 21 This is because the unprotected metal forms a galvanic couple with the adjacent protected metal underneath the coating. 22 In the galvanic couple the bare metal becomes the anode and the neighboring metal covered by the coating becomes the cathode as if it were an electrochemical cell. This further protects the metal underneath the coating and accelerates the deterioration of the unprotected metal. The use of coatings also help CP systems because they reduce the current requirement needed for protection. 21 Therefore, the amount of current needed to polarize the pipe steel by 100mV is also decreased. 22 There are also some

21 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 flexibility at high temperatures. 23 These coatings should also have resistance to soil stress and cathodic disbonding Principles of CP Cathodic protection is a scientific 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 sacrificial anode and the other is by impressed current. CP with the use of a sacrificial 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 Fe e (2.1) The other reaction is the reduction of oxygen O 2 + 2H 2 O + 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

22 12 Figure 2 1: A CP system with a sacrificial anode. given as M M n+ + ne (2.3) where M represents the sacrificial anode metal being oxidized. By degradation of the anode metal, electrons are supplied to the pipeline so that the oxygen reduction reaction can occur which reduces the rate of the iron oxidation reaction. The electrons are delivered to the pipeline through a low resistance wire as shown in Figure 2 1. Therefore, through galvanic coupling the more active anode begins to degrade which further protects the more noble pipeline metal. Figure 2 1 gives a visualization of a cathodic protection system with a sacrificial anode and its placement in respect to the buried pipeline. Most sacrificial anodes are made of either magnesium or zinc since they are both more active as compared to iron pipelines. CP systems with impressed current involve supplying current from an external source in order to protect pipelines. This is done by a rectifier or DC generator

23 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 is polarized 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 H 2 O + 2e H 2 + 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 sacrificial anode would. Sometimes the anode can be more noble than the pipeline. In this case, the rectifier must overcome both the resistance of the circuit and the back potential created from the more noble anode in order to flow current in the proper direction. 20 In order to balance the reduction reactions occurring at the pipeline 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 2H 2 O O 2 + 4H + + 4e (2.5)

24 14 Figure 2 2: A CP system with impressed current. At more extreme positive potentials the evolution of chlorine can also occur as 2Cl Cl 2 + 2e (2.6) There are advantages and disadvantages associated with both sacrificial anodes and impressed current anodes. Some of the advantages of a sacrificial anode are that it does not require an external energy source and that is self sustained. Therefore, a sacrificial 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 sacrificial 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

25 15 of supplying too much current causing damaging hydrogen evolution. However, this should be able to be prevented by properly controlling the rectifier and having knowledge of the pipeline and its environment. 2.4 Internal Inspection Techniques There 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 flux 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 fluid being transported must be displaced so that it can be re-filled with water through the use of pumps. This can cause some environmental issues involving the disposal of the fluids 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 be tested 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

26 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 be launched 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 first 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 flux 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 field created did not detect these anomalies. However, by orienting the magnetic field around the circumference of the pipeline these axial defects were detected. One of the problems with pigging or pressure testing in terms of detection of 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

27 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 for using 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, flow, costs of modifications, 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 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 first 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 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 profiles 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

28 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/CuSO 4 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 the direct connection with the pipeline. A pipe locator is used to ensure the proper location of measurements at the ground surface. Measurements are taken every five 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 interruption, 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 categories. 7, 8, 28, 29 The first 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 Figure 2 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

29 potential (mv) Type I -850 mv on off Type II Type III length along pipe (feet) Figure 2 3: A representation of on- and off-potential profiles which show how CIS dips are categorized. Each data point represents a measurement at the soil surface directly 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 expected 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 the preferred method to discover such locations. The primary function of CIS is to determine how well the CP system is working for a given pipeline. As mentioned, this can be done by finding dips in the on- and off-potential profiles and determining whether the CP current should properly protect these locations.

30 Direct Current Voltage Gradient (DCVG) The Direct Current Voltage Gradient (DCVG) survey is used to determine the location of a coating flaw or holiday and to categorize its relative severity once it is found. This is done by using two different calculations. The first of these two calculations is in units of mv and it is used to determine the coating flaw 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/CuSO 4 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 five 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 flaw. CP rectifiers 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 five feet intervals. When the survey begins, the field engineer nulls the voltmeter so that the first 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 flaw 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

31 21 the CP current is switched off, the voltmeter goes back to zero. However, as the coating flaw 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 flaw approaches. The magnitude of the voltage reading will reach its maximum when the surveyor s measurement is made directly above the flaw. This is evidenced by the voltmeter s sudden swing from positive to negative or vice versa when the flaw is passed. For example, if the voltmeter has shown increasing positive values up to 75 mv, then once the flaw 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 flaw. This behavior found by use of the voltmeter is due to the detection of a direction change in the flow of current in the electrolyte. The current in the electrolyte or soil is always moving toward the coating flaw, therefore when the flaw is passed there is a change in direction of the current. Once a coating flaw or defect is found and located, its size and severity must be determined. This further characterization of the coating flaw is done through the calculation of DCVG in percent-ir. There are two steps that the field surveyor follows in determining the percent-ir value for a given coating flaw. The first 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 flaw. Successive lateral measurements are made in the direction away from the pipeline and the coating flaw 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 infinity. Again these voltage gradients are measured by the five foot spacing of Cu/CuSO 4 electrodes.

32 22 Figure 2 4: The percent-ir calculation is shown using the lateral voltage gradients with the interpolated value of IR drop over the coating flaw. The voltage gradients are then added up and divided by the IR drop at the soil surface directly above the coating flaw. 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 flaw, 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 first category is for IR drops between zero and 15 percent. If a coating flaw 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 flaw with such a low percent-ir value. Therefore, no action is needed. If the percent-ir is between 15 and 35 percent, its

33 23 Figure 2 5: A diagram showing how an IR measurement is interpolated at the ground surface above the coating flaw. 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 field 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 flaw 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 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.

34 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, these electrodes 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 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 flaw. 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, there is sharp drop in the magnitude of current when a coating flaw is present. The magnitude of current drops because the pipeline consumes a large portion of the current at the location of the coating flaw. Once the current reaches the pipeline it travels back down the pipeline in the direction of the transmitter. The relative

35 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 flaw is expected 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.

36 CHAPTER 3 CP3D 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 protection. 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 flaw 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 onand 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 flaw location of the pipe. The soil surface areas above the anode and above the flaw 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 flaw. The soil surface must be limited in size to avoid putting a strain on the resources of the program. However, in a real-life field survey, measurements must eventually cover the entire pipeline in order to properly inspect its complete condition. Since the area of interest is specified within CP3D, a soil surface that covers the entire pipeline is not necessary. 26

37 27 Figure 3 1: An image from CP3D showing the physical orientation of the soil surface with respect to the pipeline. The darker area on the pipeline represents the coating flaw 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 flow 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 first of the governing equations for the outer domain is the material balance of a solute species c i t = ( N i) + R i (3.1) where c i is the concentration of a species i, N i is the net flux vector for species i, and R i represents the rate of generation of species i due to homogeneous reactions.