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5 Assessing the Effects of Diluted Bitumen on Pipelines T his chapter examines the main causes of pipeline failure and the phys- ical and chemical properties of the transported crude oils that can affect each. The relevant properties of diluted bitumen and other crude oil shipments are compared to make judgments about whether trans- porting diluted bitumen increases the likelihood that a pipeline will fail. Consideration is then given to whether pipeline operators, in transport- ing diluted bitumen, alter their operating and maintenance procedures in ways that can inadvertently make pipelines more prone to failure. The following sections examine the potential sources of failure in pipelines from (a) internal degradation, (b) external degradation, and (c) mechanical forces. Because it is exposed to the shipped liquid, the inside of the pipe is the most obvious location to look for possible sources of damage from shipments. Corrosion is the main cause of internal deg- radation in crude oil transmission pipelines, followed to a lesser extent by erosion. Although the outside of the pipeline is not in contact with the shipped liquid, pipeline operating conditions associated with the shipment can affect the exterior of a transmission pipeline. Corrosion and cracking are the main sources of external degradation that can be affected by these conditions. Mechanical damage to the pipeline from overpressurization and outside forces also can be affected indirectly by the liquid in the pipeline. SOURCES OF INTERNAL DEGRADATION Pipelines sustain internal damage primarily as a result of progressive deterioration caused by corrosion and erosion of the mild steel used to manufacture line pipe. Internal corrosion is an electrochemical process 67

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68 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines that typically causes damage to the bottom of the pipe when water is present. Erosion is a mechanical process that causes metal loss along the interior wall of the pipe because of the repeated impact of solid particles, particularly at bends and other areas of flow disturbance. Both forms of attack reduce pipe wall thickness and can penetrate the wall fully to cause leaks or decrease the strength of the metal remaining in the wall to produce a rupture. Internal corrosion is more prevalent than erosion in crude oil transmission pipelines. Both sources of internal pipeline dam- age are reviewed next, and the potential for diluted bitumen to affect their occurrence in crude oil transmission pipelines is assessed. Internal Corrosion The electrochemical process that causes iron in steel to corrode involves anodic and cathodic reactions. The main anodic reaction is the oxidative dissolution of iron. The main cathodic reaction is reductive evolution of hydrogen. The main species that contribute to a higher rate of corrosion are dissolved acid gases such as carbon dioxide (CO2) and hydrogen sul- fide (H2S) as well as organic acids. For the electrochemical reactions to occur, an ionizing solvent must be present, which in the pipeline envi- ronment is usually water. Salts, acids, and bases dissolved in the water create the necessary electrolyte. To prevent external corrosion, pipes are coated on the outside sur- face and cathodic protection is applied. In the case of internal corrosion, protecting the steel through the use of a coating or cathodic protection is impractical for various reasons. To prevent internal corrosion, there- fore, pipeline operators try to keep water and other contaminants out of the crude oil stream and to design their systems so as to reduce places where any residual quantities can accumulate on the pipe bottom. They also use operational means to limit deposition, including maintenance of turbulent flow; periodic cleaning with pigs; and the injection of chemi- cals, called corrosion inhibitors, that disperse and suspend water in the crude oil and form a protective barrier on the pipe surface. When crude oil is pumped from the ground, it is accompanied by some water and varying amounts of CO2 and H2S as well as certain organic acids. Crude oil producers try to minimize these impurities in delivering a stabilized product to the transmission pipeline, but eliminating them

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Assessing the Effects of Diluted Bitumen on Pipelines 69 is prohibitively expensive. Transmission pipelines carrying crude oil therefore typically have some small amount of water and sediment (usu- ally less than 1 percent by volume), and dissolved CO2 and H2S will exist in even smaller quantities. Of interest to this study is whether diluted bitumen contains any more of these corrosive contaminants than do other crude oils or whether these contaminants are more likely to settle and accumulate on the bottom surface of pipelines transporting diluted bitumen. The various means by which water, sediment, dissolved gases, and other materials can cause internal corrosion of crude oil transmission pipelines are reviewed next. Water Deposition and Wetting Oil by itself is not corrosive to mild steel pipe in the temperature range in which transmission pipelines operate, which is typically well below 100°C. Water contact with the inside pipe wall is an essential precondi- tion for internal corrosion. Pure water is not a significant source of cor- rosion when it acts alone. As discussed in more detail below, however, water in the presence of certain dissolved contaminants, such as CO2, H2S, and oxygen (O2), will cause corrosion if the water is allowed to con- tact and wet the steel surface of the pipe. In theory, a pipeline carrying oil and a small amount of water will not experience internal corrosion if the water is dispersed and suspended in the oil rather than flowing as a sepa- rate phase in contact with the bottom of the pipe. The following factors can affect whether water falls out of the oil flow to cause water wetting of the steel surface: • Flow rate: When oil and water move through a horizontal pipeline at low flow rates, gravitational force will dominate turbulent forces and cause the water to flow as a separate layer. As the rate of flow increases, the turbulence energy of the flow will increase, causing the water to become gradually more dispersed and entrained in the oil. The turbu- lence will cause water to break up into smaller droplets, and it will keep these finer droplets suspended. • Water content: The more water present in the flow, the harder it becomes for the flowing oil to suspend all water droplets. Thus, water settles more readily when there is more of it in the pipeline stream.

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70 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines • Pipe diameter and inclination: Water is more difficult to keep entrained as the diameter of the pipeline increases as long as other parameters remain the same, including the flow rate and physical prop- erties of the crude oil. Pipe inclination has a comparatively small effect on the ability of oil to entrain water if the inclination is less than 45 degrees. • Physical properties of the oil and water: The density and viscosity of water and oil play an important role in water entrainment and settling. In general, oils that have high density and viscosity are better able to entrain water than are lighter oils, in part because the density of a heavy oil will be close to that of water. Another important physical property is the oil and water interfacial tension, or tendency of the water and oil to mix or separate. Interfacial tension is affected by the presence of surface- active substances naturally found in the crude oil as well as by surfactant chemicals that may be injected into the flow by the pipeline operator. • Chemical additives: Chemicals injected into the flow stream can sig- nificantly influence water entrainment, primarily by affecting interfacial tension. As explained in Chapter 2, pipeline operators add corrosion- inhibiting chemicals to the oil stream to adsorb onto the steel surface and provide a protective layer against corrosion and water wetting. Another benefit of these additives is that they usually contain surface-active com- pounds that decrease oil and water interfacial tension so as to make it more difficult for water to separate from the oil flow. Conversely, chemi- cal demulsifiers that are added to oil to remove water during processing before delivery to the pipeline can have the undesired effect of increasing the interfacial tension and thus causing easier separation of oil and water in the pipeline flow. Finally, the drag-reducing agents that are sometimes added by pipeline operators to enhance throughput can lower the ability of flowing oil to entrain water by dampening turbulence. Solids Deposition Solids in the crude oil stream settle to the pipe bottom for the same hydrodynamic reasons described above for water dropout. Typically the settled solids consist of a mix of inorganic and organic components. Sand, clay, detached scale, and corrosion products (such as carbonates and sulfides) are usually the main inorganic components of settled sol- ids. Organic components commonly consist of asphaltenic and paraffinic compounds as well as other organic material formed by the action of

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Assessing the Effects of Diluted Bitumen on Pipelines 71 microorganisms (Mosher et al. 2012; Friesen et al. 2012). The corrosive effect of microorganisms in pipeline deposits is discussed in more detail later in the section. When the flow rate and associated turbulence are low, solids can settle and accumulate, particularly at the bottom of horizontal lines. When no water is present, the deposition of solids can impede flow to create a flow assurance problem. When the solids settle with water, the mix is often referred to as sludge. A porous layer of settled solids can retard corrosion by water containing aggressive species, because the solids will cover part of the steel surface and make it harder for those species to reach the sur- face. However, a porous layer of solids can also impede access to the steel surface by corrosion-inhibiting chemicals. In this case, the internal sur- face of the pipe that is covered by a layer of solids may corrode faster than the rest of the surface not covered by solids but protected by the chemical inhibitors. This adverse effect can be compounded by an unfavorable gal- vanic coupling between the unprotected area covered by the solids and the surrounding areas that are chemically inhibited. The basic sediment and water (BS&W) content of a crude oil ship- ment, as described in the previous chapters, is a common measure of the amount of solids and water carried and can be used to predict the likelihood of deposit formation. Even when BS&W is very low (less than 0.5 percent by volume) and the fluid velocity is relatively high (>1 meter per second or >2 miles per hour), some accumulated solids and water may be found in low spots in the pipeline and in dead legs, where the flow rate is low or stagnant. Sludge deposits holding water containing the dis- solved gases, acids, and microorganisms discussed next are the source of a common form of localized internal corrosion commonly referred to as underdeposit corrosion. Corrosive Effect of CO2 CO2 dissolved in water can have a particularly corrosive effect in pipe- lines, as evidenced by the series of reactions that ensue (DeWaard and Milliams 1975). Water containing dissolved CO2 that forms carbonic acid (H2CO3) and wets the pipe surface leads to the dissolution of iron (Fe) from the pipe steel and the evolution of hydrogen (H2) from the water. This weak acid partially dissociates in water to produce the bicarbonate ion (HCO3-) and protons (H); in water the protons are present as hydro-

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72 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines nium ions (H3O+). Bicarbonate ions dissociate further to produce more hydronium ions and carbonate ions (CO32-). The hydronium ion is highly reactive as it seeks to obtain a missing electron from nearby species. In giving up electrons to hydronium ions, the iron atoms on the pipe sur- face are destabilized, and they dissolve in the water to form iron ions (Fe2+). By obtaining the resulting electrons, the hydronium ions are con- verted to dissolved hydrogen gas (H2). The corrosion by-product is iron carbonate (FeCO3), which may deposit on the steel surface and be pro- tective in some cases. Keeping CO2 out of the crude oil stream is particularly important because the ensuing corrosion process can occur rapidly. The reason is that as the hydronium ions are consumed by the corrosion reaction, the carbonic acid dissociates further to replenish the reactive ions, which allows the corrosion process to continue at a fast rate. As long as there is sufficient CO2 to produce the carbonic acid, the iron in pipe steel that is water wet will continue to corrode. The full series of chemical reac- tions involved in CO2 corrosion is detailed in Box 5-1. Corrosive Effect of H2S H2S is another gas that may be present in the crude oil stream to create corrosive conditions inside pipelines when it is dissolved in water. Crude oil is often extracted with some amount of H2S. The concentrations in crude oil can be small [less than 100 parts per million (ppm) in the gas phase] or substantially larger. Other sulfur compounds in crude oil are less common, and they are typically soluble in oil rather than water, requiring high temperatures (>300°C) to become reactive (Nesic et al. 2012). Thus, their concentrations do not present a corrosion problem in transmission pipelines. The reactions that cause H2S to corrode pipe steel are generally simi- lar to those described for CO2. Like CO2, H2S gas is soluble in water. As a weak acid, the dissolved H2S behaves in a manner similar to carbonic acid (H2CO3) by providing a reservoir of reactive hydronium ions. An impor- tant difference is that the layer of protective iron sulfide (FeS) always forms on the steel surface as a result of the reactions involving H2S. Experimental evidence indicates that H2S corrosion initially proceeds by adsorption of the H2S to the steel surface. This adsorption is followed by a fast surface reaction at the steel and water interface to form a thin (about

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Assessing the Effects of Diluted Bitumen on Pipelines 73 box 5-1 CO2 Corrosion of Mild Pipe Steel CO2 gas dissolved in water forms a weak carbonic acid (H2CO3): CO2 + H2O ⇔ H2CO3 Carbonic acid partially dissociates in water to produce acidity [i.e., hydro- nium ions (H+); water is omitted for simplicity]: H2CO3 ⇔ H+ + HCO3 - Further dissociation occurs in the bicarbonate ion (HCO3) to produce - more H+ and form carbonate ions (CO3 ): 2- HCO3 - ⇔ H+ + CO32- The surface atoms of iron (Fe) in the steel will readily give up electrons to hydronium ions and dissolve into the water in the form of iron ions (Fe2+): Fe → Fe2+ + 2e- In obtaining the additional electron, the hydronium ion will form hydro- gen gas (H2), and the reaction is complete. 2H+ + 2e- → H2 When the concentrations of the corrosion products in water (Fe2+ and CO32- ions) exceed the solubility limit (typically at neutral and alkaline pH), they form solid iron carbonate on the surface of the steel: Fe2+ + CO32- ⇔ FeCO3 (s) The layer of iron carbonate can become fairly protective and reduce the rate of underlying steel corrosion by blocking the surface and preventing the corrosive species from reaching it. 1 micron) film of the iron sulfide mackinawite (Wikjord et al. 1980). The formation of mackinawite is an important factor governing the corrosion rate because the surface film can create a barrier that impedes the ability of other species to reach the steel. Accordingly, corrosion due to other contaminants such as CO2 can be reduced when small amounts of H2S (in the low ppm range in the gas phase) are present in crude oil.

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74 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines The rapid kinetics of mackinawite formation favor it as the initial product of H2S reactions. However, with time, and as H2S concentra- tions increase, mackinawite is less prevalent, and other forms of iron sulfide are seen, such as pyrrhotite. At high H2S concentrations, pyrite and elemental sulfur are formed. While layers of any iron sulfide will offer some corrosion protection, there is no well-defined relationship between the type of iron sulfide layer and the ensuing rate of corrosion. It is well understood that high H2S levels accompanied by elemental sulfur can lead to high rates of localized corrosion. However, elemental sulfur is usually associated with the production of natural gas with a high H2S content. For a crude oil to have similarly high H2S and elemental sulfur content would be unusual. Corrosive Effect of Oxygen Oxygen dissolved in water is undesirable in pipelines because it is highly reactive with iron. Corrosion generally becomes a problem when levels of dissolved oxygen reach those found in aerated surface water (typically about 8 ppm). Smaller amounts of oxygen (below 1 ppm) can become a problem when the oxygen reacts and impairs protective iron carbonate and iron sulfide layers. In general, the water associated with oil produc- tion does not contain oxygen, and therefore such high concentrations are seldom observed in shipments of stabilized crude oil transported in pressurized pipelines with controlled air entry points. Oxygen may become elevated when air is introduced into the pipeline inadvertently. Air may be introduced during shutdowns for inspections and repairs. Chronic sources of air ingress, such as during injection of chemicals and in storage tanks holding liquids at atmospheric pressure, are potentially more problematic. Nevertheless, how and why these air entry points would differ from one crude oil shipment to the next in the same pipeline facility are not evident. Corrosive Effect of Organic Acids Organic acids with low molecular weights are water soluble and thus present a significant corrosion threat when they are found in settled water that wets the steel surface of crude oil pipelines. A common rep- resentative of the family of water-soluble organic acids is acetic acid

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Assessing the Effects of Diluted Bitumen on Pipelines 75 (CH3COOH).1 Other low-molecular-weight organic acids that can lead to corrosion of mild steel include propionic and formic acids. These weak acids create a corrosion scenario similar to the one described for CO2 attack, with the organic acid taking the place of carbonic acid. Much like carbonic acid, organic acids provide a reservoir of hydronium ions. Their corrosive effect is particularly pronounced at low pH and higher temper- atures, when their abundance can increase corrosion rates dramatically. At a higher pH (>6), the corrosive effect of organic acids on mild steel is negligible, regardless of concentrations. Other organic acids found in crude oil—and notably in bitumen—are compounds with high molecular weight, which are often referred to as naphthenic acids. While these organic acids can be a significant corro- sion threat at the high temperatures (>300°C) reached in refineries, they are not a threat to pipe steel because they are not soluble in water but are rather dissolved in the oil phase (Nesic et al. 2012). Accordingly, high- molecular-weight organic acids do not pose a corrosion threat to steel at pipeline temperatures. In some crude oils these acids may even have moderately inhibitive properties (Nesic et al. 2012). Effect of Microbiologically Influenced Corrosion The term microbiologically influenced corrosion (MIC) is used to des- ignate the localized corrosion affected by the presence and actions of microorganisms (Little and Lee 2007). The types of damage that can be caused by these microorganisms are not unique, which means that MIC cannot be identified by visual inspection of the damage. Although MIC is discussed here with respect to internal corrosion, it can also contribute to corrosion on the outside of the pipe, as noted later. Microorganisms that cause MIC are bacteria, archaea, and fungi. Some occur naturally in crude oils, while others may be introduced as contaminants from air, sediment, and water. The temperature range in which these organisms can grow is that in which liquid water can exist, approximately 0°C to 100°C (32°F to 212°F) (Little and Lee 2007). How- ever, individual groups of microorganisms have temperature optima, including sometimes narrow ranges, for growth. The temperature range 1  A household name for acetic acid is vinegar, which consists of 2 to 3 percent acetic acid dissolved in water.

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76 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines over which transmission pipelines operate will therefore select for spe- cific microorganisms, but it will not prevent microbial growth. For microorganisms to grow and proliferate, they require not only liquid water but also nutrients and electron acceptors for respiration. Accordingly, how microorganisms use water, nutrients, and electron acceptors to grow and how they influence corrosion is explained, and consideration is then given to whether levels of any of these essentials are likely to be affected by diluted bitumen. water availability Microbial growth is limited by the availability of liquid water. Growth is therefore concentrated at oil–water interfaces and in the aqueous phase, including the water in deposits of sludge in pipelines. The volume of water required for microbial growth in hydro- carbon liquids is extremely small (Little and Lee 2007). Because water is a product of the microbial mineralization of organic substrates, micro- bial mineralization of hydrocarbon can generate the additional water needed for proliferation. nutrient availability Microorganisms need suitable forms of car- bon, nitrogen, phosphorus, and sulfur as nutrients (Little and Lee 2007).2 In oil pipelines, hydrocarbons can be degraded by aerobic or anaerobic processes to yield assimilable carbon. Aerobic degradation of hydro­ carbons is faster than anaerobic degradation, with the rate depending on the specific electron acceptors used in the process. In general, the susceptibility of hydrocarbon compounds to degradation can be ranked as follows: linear alkanes, branched alkanes, small aromatics, and cyclic alkanes (Atlas 1981; Das and Chandran 2011; Perry 1984). As the chain length of alkanes increases, bacteria show decreasing ability to degrade these compounds (Walker and Colwell 1975). Some high-molecular- weight polycyclic aromatics may not be degraded at all (Atlas 1981). As a practical matter, however, carbon availability is often not the main con- straint for crude oil biodegradation. Both nitrogen and phosphorus are required for microbial growth. Low concentrations of assimilable forms of these elements can limit biodegradation.3 2  A representation of the major elements required for a typical microorganism composition is C169(H280O80)N30P2S. 3  Atlas (1981) reported that when a major oil spill occurred in marine and freshwater environments, the supply of carbon was significantly increased and the availability of nitrogen and phosphorus generally became the limiting factor for oil degradation.

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Assessing the Effects of Diluted Bitumen on Pipelines 77 electron acceptors Microorganisms can use a variety of electron acceptors for respiration. In aerobic respiration, energy is derived when electrons are transferred to oxygen, which is the terminal electron accep- tor. In anaerobic respiration, a variety of organic and inorganic com- pounds may be used as the terminal electron acceptor, including sulfate, nitrate, nitrite, iron (III), manganese (IV), and chromium (VI) (Little and Lee 2007). Anaerobic bacteria can therefore be grouped on the basis of the terminal electron acceptor, such as sulfate-, nitrate-, and metal- reducing bacteria.4 In petroleum environments, the bacteria most often associated with MIC are sulfate reducers. In anaerobic environments, sulfate reducers produce H2S when they use the sulfate as an electron acceptor.5 In addition, many archaea can produce sulfides, and there- fore the inclusive term for this group of anaerobes is sulfide-producing prokaryotes (SPP). SPP-related corrosion of metals used in oil exploration and production has been reported around the world (Mora-Mendoza et al. 2001; Ciaraldi et al. 1999; El-Raghy et al. 1998; Jenneman et al. 1998). A main concern is that these microorganisms produce H2S. As discussed earlier, H2S reacts with the iron ions to form a thin layer of the iron sulfide mackinawite that adheres to the steel surface. In the absence of oxygen, and if the concen- tration of iron ions in the solution is low, this mineral layer will protect the iron in the steel pipe surface from dissolution (Wikjord et al. 1980). However, if oxygen is introduced, the iron sulfide can be converted to an iron oxide and elemental sulfur, which will cause the rate of corrosion to increase substantially for reasons already given.6 Pipelines operators, therefore, seek to prevent the formation of colonies of SPP and other 4  There is specificity among anaerobes for particular electron acceptors. Facultative anaerobic bacteria can use oxygen or other electron acceptors. Obligate anaerobic microorganisms cannot tolerate oxygen for growth and survival. Obligate anaerobic bacteria are, however, routinely isolated from oxygenated environments associated with particles and crevices and, most important, are in association with other bacteria that effectively remove oxygen from the immediate vicinity of the anaerobe. 5  Some anaerobes can also reduce nitrate, sulfite, thiosulfate, or fumarate (Little and Lee 2007). 6  The impact of oxygen on corrosion from anaerobic SPP was examined by Hardy and Bown (1984) by using mild steel and weight loss measurements. Successive aeration-deaeration shifts caused variations in the corrosion rate. The highest corrosion rates were observed during periods of aeration. Hamilton (2003) concluded that oxygen was the terminal electron acceptor in all MIC reactions. In laboratory seawater and fuel incubations, Aktas et al. (2013) demonstrated that there was no biodegradation of hydrocarbon fuels, little sulfate reduction, and no corrosion of carbon steel in the absence of oxygen.

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88 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines microstructure, thereby reducing interatomic bond strength and provid- ing nucleation sites for cracks. Hydrogen-assisted cracking can occur on the inside or outside of the pipe, depending on the source of the hydrogen and its ability to reach the pipe surface. Assessment of Effects of Diluted Bitumen on Sources of External Degradation Because diluted bitumen only contacts the inside of a pipeline, it can contribute to external degradation only indirectly. In the case of external corrosion and EAC, one concern is that elevated operating temperatures can adversely affect the performance of the coating as a barrier to corro- sion. The relevant question with respect to both external corrosion and EAC is whether diluted bitumen creates operating temperatures and pressures that are sufficiently different from those of other crude oils to increase coating disbondment. As has been reported, diluted bitumen and other heavy crude oils have similar densities and viscosities and flow through pipelines at the same rate and within comparable pressure and temperature ranges (see Chapter 3, Tables 3-4 and 3-7). For this reason, the likelihood of coating degradation and any associated external dam- age resulting from the operating parameters of diluted bitumen should be equivalent to that of other crude oils with comparable density and viscosity. Pipelines transporting diluted bitumen and other heavy crude oils should not differ in the stress loadings generated by their transporta- tion because operating pressures are comparable. Other sources of static stress, such as residual stresses from pipe fabrication and installation, would not be affected by the product in the pipeline. Transmission pipelines, therefore, should not experience more stress cracking from transporting diluted bitumen than from transporting other crude oils of similar density and viscosity. Finally, if the exterior coating of the pipe disbonds, hydrogen may dif- fuse into the surface metal with a rate of uptake and subsequent potential for embrittlement that will depend on a number of factors, including pH and temperature. However, the operating parameters of diluted bitumen should not increase the potential for coating disbondment. With respect to the interior of the pipeline, the availability of H2S and free sulfur to

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Assessing the Effects of Diluted Bitumen on Pipelines 89 form hydrogen in diluted bitumen is relatively low. Thus, transporting diluted bitumen is not likely to increase the potential for hydrogen- assisted cracking. SOURCES OF MECHANICAL DAMAGE Mechanical damage to the pipeline and its components can occur as a result of overpressurization or outside forces. Mechanical forces can cause an immediate, and sometimes catastrophic, breach and release or make the pipeline more susceptible to releases by destabilizing support structures and damaging other components such as valves, joints, and other fittings. Damage from mechanical forces can also weaken the resis- tance of the pipeline to other failure mechanisms. Sites on the pipeline that sustain even light damage, such as scrapes, are vulnerable to corro- sion attacks and stress-related cracking. Accordingly, consideration of whether the transportation of diluted bitumen creates an elevated poten- tial for phenomena that can lead to mechanical damage is warranted. Overpressurization Various events can generate excessive pressure in a pipeline, including surges, thermal overpressure, column collapse, and human error. If the pipe is already weakened by corrosion, cracking, or deformities from earlier mechanical damage, overpressure events can increase the poten- tial for damage and failure. Pipeline operators prevent overpressure events through personnel training; standardized procedures; system design; and safety systems such as pressure relief valves, pressure switches, surge tanks, and bypass systems. Nevertheless, excessive pressure in a pipeline can occur as a result of operator error, thermal overpressure, and column separation. A transported fluid that increases the likelihood of any of these outcomes could increase the potential for mechanical damage. Surge Any action in a pipeline system that causes a rapid reduction in the velocity of the transported fluid could cause a pressure surge. Transient, high-amplitude pressure waves, or surges, are not normal and can cause

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90 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines mechanical damage to pipes, components (e.g., valves, seals, joints), instrumentation (e.g., meters and gauges), and support structures. Because all crude oils have relatively high bulk modulus (incompress- ibility), they have a comparable propensity for energy to be transferred in high-pressure waves when events trigger abrupt reductions in flow velocity. Operator Error Overpressurization can be caused by direct human error. Unintentional pumping of fluids against a closed valve with coincidental failure of pres- sure switches, pressure relief valves, and other protective devices is an example of a rare-event overpressurization scenario. Most pipelines are equipped with safeguards such as pressure switches and relief devices to avoid damage from these scenarios. If a transported liquid adds com- plexity to operational requirements, operator errors could increase. Column Collapse Pressure surges can arise from pressure differentials, or slack conditions, in the pipeline. A slack line can occur when the liquid being transported develops a vapor void at a point in the pipeline where line pressure drops below the vapor pressure of the liquid. The void will temporarily restrict the flow of liquid. When the void collapses, a pressure wave comparable with that of a rapid valve closure can be produced. The transformation of the liquid into a vapor phase is known as column separation. To pre- vent the occurrence of column separation, pipeline operators strive to maintain line pressure above the vapor pressure of the liquid. Loca- tions vulnerable to pressure differentials are elevation peaks and the downstream side of slopes. A liquid that has certain properties, such as a relatively high fraction of hydrocarbons with high vapor pressure, can theoretically increase the potential for column separation. Thermal Overpressure A pipe segment that is full of liquid will experience a rapid pressure increase when it is exposed to a heat source and when volume expan- sion is restricted. Special procedures and thermal relief valves are used to prevent this occurrence in aboveground pipe segments where the flow may be impeded or blocked and the segment may be subsequently

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Assessing the Effects of Diluted Bitumen on Pipelines 91 exposed to a heat source such as sunlight or fire. Because the chemistry of the trapped fluid determines the amount of pressure increase corre- sponding to an incremental increase in temperature, some transported liquids could have greater potential for thermal overpressure. Outside Force Damage Pipelines can sustain external mechanical damage from both natural forces and human activity. Natural forces include seismic movements and other ground shifts, such as those from landslides and subsidence. Examples of damage from human activity include accidental strikes from vehicles, earth moving activity, and surface loading by farm equip- ment. Intentional damage to a pipeline, or sabotage, is a potential source of mechanical damage, although it is rare. There are ways in which the contents of a pipeline can affect or interact with an outside force failure mechanism. One possibility is that a denser, heavier fluid adds weight to a pipe that is free-spanning (i.e., unsupported) or traverses a terrain susceptible to inadequate sup- port. Another possibility is that the heat flux from a fluid transported at an elevated operating temperature reduces the stability of a pipeline in a frost zone. Similar interactions with the outside environment related to pipe vibrations, expansion, and contraction may be postulated as poten- tial sources of mechanical damage. Assessment of Effects of Diluted Bitumen on Sources of Mechanical Damage Mechanical damage to the pipeline and its components can occur as a result of outside forces and overpressurization events. Several causes of outside force damage that could be affected to some degree by the prop- erties of the transported liquid have been postulated. The most relevant properties of the transported liquid are density, viscosity, and operat- ing temperatures. However, because these properties are the same for diluted bitumen as many other crude oils, there is no reason to believe their interactions with outside forces will differ. The same conclusion can be reached concerning the potential for mechanical damage due to chemical or physical properties that can affect the propensity for

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92 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines surge, column separation, or thermal expansion. The potential for these sources of mechanical damage should be indistinguishable from that of other crude oils. Diluted bitumen is blended like many other crude oils to remain fully mixed in the pipeline environment and it does not con- tain a high percentage of light (high vapor pressure) hydrocarbons. EFFECTS ON OPERATIONS AND MAINTENANCE PROCEDURES The preceding analysis has consistently found that the properties of diluted bitumen are within the range of other crude oils. These findings do not indicate a need for operations and maintenance (O&M) proce- dures that are customized to diluted bitumen, nor do they suggest that pipeline operators apply O&M procedures in transporting diluted bitu- men that are different from those applied in transporting other crude oils with similar properties. Of course, if operators who traditionally carry only light crude oils do not make appropriate adjustments to line pressure and flow rates when they transport diluted bitumen or any other similarly dense and viscous crude oil, a greater potential for some of the failure mechanisms examined above could result. Because most pipeline operators transport many varieties of crude oil, they routinely make adjustments to operational parameters to accommodate different crude oil grades. There is no reason to believe that operators fail to make these adjustments when they transport heavy crude oils generally or, more specifically, when they transport diluted bitumen. Nevertheless, to be comprehensive, a search was undertaken for evidence of O&M practices being altered in inadvertent ways that could be detrimental to pipeline integrity. Operational Procedures As discussed in Chapter 2, the operation of most pipelines is monitored and controlled by a combination of local and remote systems by using a centralized supervisory control and data acquisition system. Instrumen- tation at pump stations, tank farms, and other facilities includes sensors, programmable logic controllers, switches, and alarms. Remote systems allow for monitoring and coordination at centralized locations distant from the pipeline facilities. Together, these local and remote capabili-

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Assessing the Effects of Diluted Bitumen on Pipelines 93 ties provide protection against abnormal operations—for example, by allowing for the orderly shutdown of pumps and cessation of flow if an alarm condition occurs or if certain operating parameters are violated. Maintaining the integrity of control systems is essential in ensuring safe pipeline operations. Therefore, whether there are any characteristics of diluted bitumen that could introduce more complexity into or otherwise compromise the satisfactory functioning of pipeline control systems and their compo- nents is worth investigating. As previously noted, none of the chemical and physical properties of diluted bitumen suggests that such an effect could be expected, because the properties fall within the range of other crude oils commonly transported by pipeline. Nevertheless, the commit- tee undertook a search of any instances in which operators modified or were advised to modify their standard control and monitoring activities in transporting diluted bitumen. A search of published documents did not reveal any noteworthy reports, special standards, or guidance docu- mentation. In consulting Canadian pipeline operators (see Appendix A), the committee asked whether the transportation of diluted bitumen required changes to set points for safety and control instrumentation. The response was as follows: “There are no differences. Standards and procedures are in place for control that are generic for all crude oil commodities shipped. The standards and procedures are structured to ensure safe operation regardless of the commodity.” Likewise, all pipe- line operators interviewed in public meetings convened by the commit- tee stated that transporting diluted bitumen did not require different control or monitoring procedures.12  Representatives from Enbridge, Inc., and TransCanada Pipeline Company were invited to make 12 presentations to the committee during its first meeting on July 23, 2012. During the public meet­ ing, the representatives were asked to identify any special operational or maintenance demands associated with transporting diluted bitumen. None was identified. On October 9–10, 2012, committee members convened a public meeting in Edmonton, Alberta, in which representatives of several pipeline companies that transport diluted bitumen were interviewed. In conjunction with the meeting, committee members also visited a transmission pipeline terminal in Fort McMurray, Alberta, where representatives from the pipeline company explained operational and control procedures associated with diluted bitumen transportation. They also responded to questions from committee members. None of the interviews and information obtained from the site visit suggested that operators use different procedures for system control and monitoring when they transport diluted bitumen.

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94 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines In its investigation of the July 25, 2010, EAC-related rupture near Marshall, Michigan, the National Transportation Safety Board found that the control center made repeated errors by increasing the delivery rate of the pipeline under the impression that low-pressure readings caused by the undetected rupture were indicative of slack line conditions caused by column separation (NTSB 2012). The product released in the incident, discussed in Chapter 4, was diluted bitumen. The phenomenon of column separation has already been reviewed, and no evidence that diluted bitumen has properties associated with it was found. Further- more, the National Transportation Safety Board did not indicate that the shipment of diluted bitumen that was being delivered through the ruptured pipeline had actually experienced column separation or that any of the properties of the shipment had any other specific effect on the actions of the control center. Maintenance Procedures As described in Chapter 2, pipeline operators use various methods for preventing, detecting, and mitigating damage in pipelines. Methods for preventing external cracking and corrosion include use of coatings and cathodic protection. Methods for preventing internal corrosion include chemical treatments, flow maintenance, and in-line cleaning. Opera- tors also monitor pipeline conditions by using various inspection tools, probes, and surveys. If transporting diluted bitumen compromises the ability of operators to carry out any of these activities, more adverse conditions could arise and persist and thereby increase the potential for failures. As with other potential issues, the absence of significant differences in the chemical and physical properties of diluted bitumen compared with other heavy crude oils suggests that no changes are required in pipe- line maintenance and inspection regimes. Nevertheless, the committee searched for reports of operators experiencing difficulties in carrying out standard maintenance, mitigation, and inspection activities while trans- porting diluted bitumen. The committee also searched for standards and other guidance documentation alerting operators to issues associ- ated with maintenance and inspection, such as advisories on the use of in-line inspection tools, chemical inhibitors, and coupons and probes for

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Assessing the Effects of Diluted Bitumen on Pipelines 95 corrosion monitoring. The search did not uncover any issues or added complexities. In addition, in its questionnaire to Canadian pipeline operators (see Appendix A), the committee asked whether the transportation of diluted bitumen required changes in pipeline cleaning intervals or predictive and preventive maintenance programs. No differences in cleaning inter- vals or predictive and preventive maintenance programs were reported. Pipeline operators who met with the committee during public meetings (as noted above) were asked similar questions, and all stated that no special maintenance and inspection issues arose in transporting diluted bitumen. They did not report any adverse affects on their ability to carry out their normal maintenance and inspection activities. Assessment of Effects of Diluted Bitumen on O&M Procedures As common carriers, operators of transmission pipelines generally have the ability to transport the wide range of crude oil varieties that are in the commercial stream. Accordingly, operations and maintenance proce- dures are designed to be robust, capable of ensuring operational reliabil- ity and safety without the need for significant procedural modifications from one crude oil shipment to the next. The chemical and physical prop- erties of diluted bitumen do not suggest that transporting this product by pipeline requires O&M procedures that differ from those of other crude oils having similar properties. Likewise, inquiries with operators and searches of industry guidelines and advisories did not indicate any spe- cific issues associated with transporting diluted bitumen that would neg- atively affect operators as they carry out their standard O&M programs, including their corrosion detection and control capabilities. SUMMARY The chemical and physical properties of diluted bitumen shipments have been examined to determine whether there are any differences from those of other crude oil shipments that increase the likelihood of pipeline failures from internal degradation, external degradation, or mechanical damage. Any differences that could affect either the frequency or the severity of a failure mechanism or the ability to mitigate it would suggest

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96 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines a difference in failure likelihood. The chemical and physical properties of diluted bitumen shipments were not found to differ in ways that would be expected to create a likelihood of release that is higher for a transmis- sion pipeline transporting diluted bitumen than one transporting other crude oils. An assessment was also made with regard to whether pipeline operators transporting diluted bitumen alter their O&M procedures in ways that can inadvertently make pipelines more prone to the sources of failure. No differences were found in these procedures. The assessment results are summarized in the next chapter. REFERENCES Abbreviations CEPA Canadian Energy Pipeline Association NTSB National Transportation Safety Board Aktas, D. F., J. S. Lee, B. J. Little, K. E. Duncan, B. M. Perez-Ibarra, and J. M. Suflita. 2013. Effects of Oxygen on Biodegradation of Fuels in a Corroding Environment. International Biodeterioration and Biodegradation, Vol. 81, July, pp. 114–126. Atlas, R. M. 1981. Microbial Degradation of Petroleum Hydrocarbons: An Environ- mental Perspective. Microbiological Reviews, Vol. 45, No. 1, pp. 180–209. Beavers, J. A., and N. G. Thompson. 2006. External Corrosion of Oil and Natural Gas Pipelines. ASM Handbook, Vol. 13C, Corrosion: Environments and Industries, pp. 1015–1025. http://www.asminternational.org/content/ASM/StoreFiles/ ACFAB96.pdf. CEPA. 2007. Stress Corrosion Cracking: Recommended Practices, 2nd ed. Calgary, Alberta, Canada. Ciaraldi, S. W., H. H. Ghazal, T. A. Shadey, H. A. El-Leil, and S. El-Raghy. 1999. Prog- ress in Combating Microbiologically Induced Corrosion in Oil Production. Paper 181. Presented at Corrosion 99, National Association of Corrosion Engi- neers International, Houston, Tex. Das, N., and P. Chandran. 2011. Microbial Degradation of Petroleum Hydrocarbon Contaminants: An Overview. SAGE-Hindawi Access to Research, Biotechnology Research International, Vol. 2011, Article ID 941810. DeWaard, C., and D. E. Milliams. 1975. Carbonic Acid Corrosion of Steel. Corrosion, Vol. 31, No. 5, pp. 171–181. El-Raghy, S. M., B. Wood, H. Abuleil, R. Weare, and M. Saleh. 1998. Microbiologically Influenced Corrosion in Mature Oil Fields—A Case Study of El-Morgan Field in

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Assessing the Effects of Diluted Bitumen on Pipelines 97 the Gulf of Suez. Paper 279. Presented at Corrosion 98, National Association of Corrosion Engineers International, Houston, Tex. Escalante, E. 1989. Concepts of Underground Corrosion. In STP 1013: Effects of Soil and Characteristics on Corrosion (V. Chaker and J. D. Plamer, eds.), American Society for Testing and Materials International, Philadelphia, Pa., pp. 81–94. Friesen, W. I., S. Perovici, J. C. Donini, and R. W. Revie. 2012. Relative Corrosivi- ties of Crude Oils from Oil Transmission Pipelines. Paper 2012-08. Proc., 2012 Northern Area Eastern Conference: Corrosivity of Crude Oil Under Pipeline Oper- ating Conditions, National Association of Corrosion Engineers International, Houston, Tex. Hamilton, W. A. 2003. Microbiologically Influenced Corrosion as a Model System for the Study of Metal Microbe Interactions: A Unifying Electron Transfer Hypothesis. Biofouling, Vol. 19, No. 1, pp. 65–76. Hardy, J. A., and J. L. Bown. 1984. Corrosion of Mild Steel by Biogenic Sulfide Films Exposed to Air. Corrosion, Vol. 40, pp. 650–654. Jenneman, G. E., P. Wittenbach, J. Thaker, and Y. Wu. 1998. MIC in a Pipe Used for Disposal of Produced Water from a Coal Seam Gas Field. Paper 281. Presented at Corrosion 98, National Association of Corrosion Engineers International, Houston, Tex. Koch, G. H., M. P. H. Brongers, N. G. Thompson, Y. P. Virmani, and J. H. Payer. 2002. Corrosion Cost and Prevention Strategies in the United States. FHWA-RD-01-156. Office of Infrastructure Research and Development, Federal Highway Adminis- tration, March. Little, B. J., and J. S. Lee. 2007. Microbiologically Influenced Corrosion. John Wiley & Sons, Hoboken, N.J. Mora-Mendoza, J. L., R. Garcia-Esquivel, A. A. Padilla-Viveros, L. Martinez, O. F. Cedillo, C. A. Chavez, and M. M. Bautista. 2001. Study of Internal MIC in Pipe- lines of Sour Gas, Mixed with Formation Waters. Paper 01246. Presented at Corrosion 2001, National Association of Corrosion Engineers International, Houston, Tex. Mosher, M., B. Crozier, W. Mosher, J. Been, H. Tsaprailis, T. Place, and M. Holm. 2012. Development of Laboratory and Pilot Scale Facilities for the Evaluation of Sludge Corrosivity in Crude Oil Pipelines. Paper 2012-07. Proc., 2012 Northern Area Eastern Conference: Corrosivity of Crude Oil Under Pipeline Operating Conditions, National Association of Corrosion Engineers International, Houston, Tex. Nesic, S., S. Richter, W. Robbins, F. Ayello, P. Ajmera, and S. Yang. 2012. Crude Oil Chemistry on Inhibition of Corrosion and Phase Wetting. Paper 2012-16(c). Proc., 2012 Northern Area Eastern Conference: Corrosivity of Crude Oil Under Pipeline Operating Conditions, National Association of Corrosion Engineers International, Houston, Tex.

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