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2 Crude Oil Pipelines in the United States T his chapter provides background on the network of crude oil trans- mission pipelines in the United States; the main components of these systems; and common aspects of their operations, maintenance, and integrity management. The background was derived from several sources: National Petroleum Council 2011, Argonne National Laboratory 2008, Rabinow 2004, and a presentation to the committee by Thomas Miesner.1 NATIONAL PIPELINE NETWORK Crude oil is transported, both onshore and offshore, in gathering systems and transmission pipelines. The gathering systems are made up of low- capacity pipelines—typically less than 8 inches in diameter—that move crude oil from wells to high-capacity transmission pipelines that are usually 8 to 48 inches in diameter. Before the crude oil leaves the produc- tion field, it is processed to remove excess water, gases, and sediments as necessary to meet the quality specifications of transmission pipelines and the refineries they access. Most of the estimated 55,000 miles of crude oil transmission pipeline in the United States are interconnected to form a national network that links oil production regions, storage hubs, and refineries.2 This extensive network accounts for more than 90 percent of the ton-mileage of crude oil transported within the United States.3 1  October 23, 2012 (http://onlinepubs.trb.org/onlinepubs/dilbit/Miesner102312.pdf ). 2  The Pipeline and Hazardous Materials Safety Administration (PHMSA) has estimated that the crude oil transmission pipeline network extended for 55,330 miles as of 2011. 3  “Ton-mile” is a measure of the weight of a substance carried multiplied by the distance over which it is carried. 10

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Crude Oil Pipelines in the United States 11 Transmission pipelines are critical in providing refineries with a steady supply of feedstock consisting of various types of crude oil. About 140 refineries operate nationwide. Some are vast complexes that can process more than 500,000 barrels of crude oil per day, while others serve relatively small and specialized markets and process less than 50,000 barrels per day.4 About 40 percent of U.S. refining capacity is located along the Gulf Coast, and the next largest center is in the Upper Midwest. Originally, the Gulf Coast refineries were supplied by domestic sources, primarily from Texas and Louisiana and from shallow waters in the Gulf of Mexico. As domestic production declined in the 1970s, the Gulf Coast refineries increasingly sourced their crude oil from Mexico, Venezuela, and the Middle East. Because the imports tended to be denser and higher in sul- fur, refiners invested in facilities capable of processing such feedstock. In recent years, increased production from Canada, deep Gulf waters, and domestic shale fields has replaced waterborne imports. These supply shifts have had significant implications for the transmission pipelines that once moved crude oil from Gulf Coast ports to inland refineries as far north as Illinois and Ohio. Many of these systems have had their flow directions reversed and are now being used to transport Canadian crude oil to the Gulf Coast refineries. The transition is under way, with major investments to add more north-to-south capacity by reversing more lines and building new ones. For many decades, U.S. crude oil produced in the northern Rocky Mountains and Dakotas, as well as that produced in the western provinces of Canada, was transported to refining centers in Eastern Canada and the Upper Midwest. In recent years, as output from these oil-producing regions has grown significantly, crude oil supplies have exceeded refin- ing capacity and are being transported south, where they are displacing crude oil traditionally sourced from Mexico, South America, and the Gulf of Mexico. Both the East and West Coasts have remained largely independent markets for crude oil supplies. The eastern states have little oil pro- duction and no significant crude oil transmission pipelines. While the recent development of shale resources in New York and Pennsylvania is  One U.S. barrel of crude oil contains 42 gallons. 4

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12 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines adding production capacity, truck and rail remain the dominant regional modes of crude oil transportation. The main East Coast refining centers in northern New Jersey, Philadelphia, and coastal Virginia receive most of their supplies from tanker vessels. In comparison, California has an extensive network of crude oil transmission pipelines because of sig- nificant in-state oil production. These pipeline systems, some of which consist of heated lines to move the native viscous crude oils, do not con- nect to pipeline systems in other states. Refineries in Washington State receive crude oil by tanker and from Western Canada by pipeline. PIPELINE SYSTEM COMPONENTS The individual pipeline systems that make up the U.S. crude oil trans- mission network vary in specific design features and components. Nevertheless, the systems have many common elements. Line Pipe Pipelines are made of sections of line pipe that are welded together and generally buried 3 or more feet below grade. Virtually all line pipe is made of mild carbon steel that is coated externally but not internally. Pipe sec- tions are typically 40 feet long, manufactured with longitudinally welded seams and joined by circumferential girth welds during installation. Pipe wall thickness depends on many factors, including planned capac- ity and operating pressure. Most line pipe in crude oil transmission sys- tems is operated at pressures between 400 and 1,400 pounds per square inch, is 20 or more inches in diameter, and has a nominal wall thickness ranging from 0.2 to 0.75 inches. Federal regulations in the United States require that pipeline operating pressures and other forces not generate stresses that exceed 72 percent of the specified minimum yield strength (SMYS) of the pipe, and therefore a higher operating pressure requires thicker pipe or pipe with higher yield strength.5 Depending on pipeline design and routing factors, thicker-walled pipe may also be used where 5  Federal regulations concerning SMYS are contained in 49 CFR §195.406. The federal hazardous liquid pipeline safety regulations, as administered by PHMSA, are outlined in Box B-1, Appendix B. Some pipelines operate at 80 percent of SMYS with permission of PHMSA.

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Crude Oil Pipelines in the United States 13 the pipeline crosses a body of water or in areas that are densely popu- lated, environmentally sensitive, or prone to additional external forces such as seismic activity. Inlet Stations and Tank Farms Transmission pipelines originate at one or more inlet stations, or termi- nals, where custody of the shipment is transferred from the owner to the pipeline operator. Accordingly, inlet stations are access points for truck tankers, railroad tank cars, and tanker vessels as well as other pipelines, including gathering lines connecting production areas. Along with pump- ing stations, sampling and metering facilities are located at inlets to ensure that the crude oils injected into the pipeline meet the quality control requirements of the pipeline operator and intended recipients. Metering instruments usually include densitometers and may include viscometers, which are used to measure density and viscosity, respectively. Tanks at inlet stations are used to consolidate shipments into batches sized for main-line movement, blend crude oils to meet quality specifica- tions, and schedule shipments according to the needs of refiners. Tanks can vary in capacity from tens of thousands to hundreds of thousands of barrels.6 All are made of steel and are unpressurized. They are usually designed with floating roofs that rise and fall with the liquid level to limit hydrocarbon loss from vaporization and minimize emissions of volatile organic compounds. Tanks usually have lined floors and are inspected and cleaned periodically to remove any water and sediment settling to the floor. Pump Stations To maintain desired flow rates, booster pumps are positioned at points along the pipeline at intervals of 20 to 100 miles depending on many fac- tors, including topography, line configuration, pipe diameter, operat- ing pressure, and the properties of the fluids being transported. Pump stations are often automated and are equipped with sensors, program- mable logic controllers, switches, alarms, and other instrumentation allowing the continuous monitoring and control of the pipeline as well  Larger underground caverns are used for storage at some pipeline terminals. 6

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14 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines as its orderly shutdown if an alarm condition occurs or if established operating parameters are violated. Valves Shutoff valves are strategically located at pump stations, certain road and water crossings, and other points to facilitate the starting and stop- ping of flow and to minimize the impact of leaks. These valves, many of which can be controlled remotely, ensure that portions of the line can be isolated in the event of a leak or the need for repair or maintenance. In addition, check valves that prevent backflows may be located at eleva- tion changes and other intermediate points. The opening and closing of valves, along with pumping station operations, are sequenced to prevent flow reversals and problems associated with over- and underpressuriza- tion. Bypass lines, safety valves (e.g., pressure and thermal relief ), and surge tanks may be sited at stations to relieve pressure. Intermediate and Terminal Facilities Depending on the scope of operations, a transmission pipeline system may have intermediate points, in addition to terminal facilities, that con- nect to other pipelines, other modes of transport, and refineries. These stations usually contain tanks and crude oil sampling and metering facil- ities. Smaller “breakout” tanks at intermediate points may also be used to support maintenance and emergency activities—for example, to relieve pressure or to allow for temporary draining of a pipeline segment. OPERATIONS AND CONTROL Batch Operations A transmission pipeline will rarely carry a single type of crude oil. At any given time, a large pipeline will usually be transporting dozens of shipments, typically in batches of at least 50,000 barrels and cover- ing a variety of crude oil grades. Sometimes the batches are physically separated by plugs known as pigs, but most of the time they are not. To reduce undesirable mixing at interfaces, the batches are separated and sequenced according to characteristics such as density, viscosity, and

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Crude Oil Pipelines in the United States 15 sulfur content. Accordingly, batches are scheduled to permit the proper lineup of crude oils being moved into and out of storage tanks. Maintain- ing batch separation requires that operators closely monitor the flow characteristics of the pipeline, since reductions in flow velocity and loss of flow turbulence can lead to undesirable intermixing of batches. Flow Regime Most shipments flow through the pipeline at 1.5 to 3 meters per second (3 to 6 miles per hour), which equates to a delivery rate of 500,000 to 1,000,000 barrels of crude oil per day in a 36-inch transmission pipeline.7 Flow conditions in the pipeline will remain turbulent within this range of flow velocities.8 Pipeline operators strive to maintain turbulent flow, characterized by chaotic motion and the formation of eddies, to reduce intermixing of batches and to keep impurities such as water and sedi- ment suspended in the crude oil stream. Choosing a desired flow regime requires the balancing of many technical and economic factors. Increas- ing operating pressure will increase pipeline throughput, which is gener- ally desired by an operator to increase revenue capacity. Higher operating pressures, however, require a larger investment in pipe materials and pumping capacity and will increase energy use and operating costs. The characteristics of the crude oil to be shipped are important consid- erations in establishing the flow regime. More energy is needed to pump dense, viscous crude oils than light crude oils with lower viscosity. Some crude oils are too viscous naturally to be pumped. The normal response when a highly viscous crude oil is transported is to dilute it with lighter oil. When a diluent is too costly or unavailable, an alternative approach is to transport the crude oil in a heated pipeline. However, heating a pipeline 7  http://www.aopl.org/aboutPipelines/?fa=faqs. 8  Whether a flow is turbulent or nonturbulent (i.e., laminar) depends on the diameter of the pipe­ line, the velocity of the flow, and the viscosity of the crude oil. These parameters can be used to calculate the Reynolds number, which defines the flow regime as laminar to turbulent. As described later in Chapter 3, the kinematic viscosity of heavy crude oils can range up to about 250 centistokes (0.00025 square meter per second) at room temperature. These oils will need to be transported at about 2 meters per second (6.5 feet per second or 4.4 miles per hour) in a pipe with a diameter of 20 inches to achieve a Reynolds number higher than 4,000, which is at the transition from laminar to turbulent flow. In a larger pipe, lower velocities are required to maintain turbulence (e.g., 1 meter per second or 2 miles per hour for a 42-inch pipe). Further consideration is given to the beneficial effects of maintaining turbulent flow in Chapter 5.

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16 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines is an expensive option and presents construction and operating chal- lenges that preclude its common use. Where the throughput capacity of a line needs to be increased without adding pumping capacity, an opera- tor may inject drag-reducing agents to enhance flow. These chemicals, which consist of long-chain polymers, dampen turbulence at the inter- face between the crude oil and the pipe wall to reduce friction and enable increased flow velocity. Pipeline flows are usually monitored and controlled by operators from one or more central control centers, where supervisory control and data acquisition systems collect and analyze data signals from sensors and transmitters positioned at pumps, valves, tanks, and other points en route. Parameters other than flow rate, such as line pressure, pump discharge pressures, and temperatures, are also monitored for routine operational and maintenance decisions and for leak detection. Shipment Quality Control In the United States, the Federal Energy Regulatory Commission (FERC) oversees the tariffs that interstate pipeline operators are required to publish as common carriers. For intrastate transmission pipelines, state authorities such as the Texas Railroad Commission and the California Energy Commission function much like FERC in overseeing tariffs for in-state movements. Pipeline tariffs define the terms and conditions for the transporta- tion service, including the quality specifications applicable to all ship- ments in the pipeline. The specifications are driven by both operational and commercial considerations. Measurements to ensure adherence to the specifications are usually taken at custody transfer points. It is com- mon for these specifications to define the maximum allowable sediment and water content, viscosity, density, vapor pressure, and temperature of the shipment. Other shipment qualities, such as levels of sulfur, acid, and trace metals, are seldom delineated in published tariffs but may be specified in private agreements. Quality specifications are designed to protect the integrity of the pipeline and the ancillary facilities, ensure that the shipped crude oil meets the specifications of the refiner, and pre- vent valuable throughput capacity from being consumed by transporting sediment and water.

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Crude Oil Pipelines in the United States 17 MAINTENANCE Each operator tailors pipeline maintenance and integrity manage- ment practices within the parameters allowed by safety regulations and according to the demands of the specific system, including its age, construction materials, location, and stream of products transported. Never­ heless, many practices are standardized. Some of the most com- t mon cleaning, inspection, and mitigation practices are described below. Regulatory requirements that govern integrity management are out- lined in Appendix B. Cleaning Periodic cleaning of crude oil pipelines and equipment is often performed to facilitate inspection as well as to maintain operational performance. Cleaning intervals, typically measured in weeks or months, will vary depending on operating conditions and crude oil properties. A variety of tools are used for cleaning the pipe and monitoring interior condition. Mechanical pigs equipped with scrapers and brushes remove debris from the inner wall. The scraped deposits and scale are transported to clean- out traps. The scrapings may be tested for contaminants and corrosion by-products. Inspection and Monitoring A regular inspection regime that assesses the condition of rights-of-way, pipes, pumps, valves, tanks, and other components is important to main- taining pipeline operational integrity and preventing unplanned shut- downs. Rights-of-way are routinely monitored by aerial patrols looking for threatening activities and encroachments and by field inspectors conducting detailed surveillance of line and equipment conditions. While visual inspection of buried pipe is not possible, pipes exposed for repair are usually inspected for evidence of mechanical damage or signs of deg- radation that may be indicative of problems elsewhere on the line. From time to time, instrumented, or “smart,” pigs are run through the line to detect anomalies. The three primary instruments are geometry, metal loss, and crack tools. Geometry tools are normally equipped with

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18 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines mechanical arms that survey the pipe wall to detect dents and other geom- etry changes. Metal loss tools use either magnetic or ultrasonic technol- ogy. Crack tools are designed to detect cracks in the pipe body, especially those that are longitudinally oriented. The frequency of instrumented pig runs is determined by the risk management program of the operator, as influenced by government regulation. Some pipeline sections, mostly in older systems, are not configured to accept some instrumented pigs. Other techniques for monitoring conditions inside the pipe include the use of corrosion coupons and electrical resistance probes. Coupons are steel samples inserted into the pipeline and periodically removed for examination. Because the coupons are weighed before and after the exposure, the amount of corrosion can be determined by weight loss. Electrical resistance probes inserted into the pipe provide information on the corrosivity of the stream. External corrosion is monitored primar- ily through the use of pipe-to-soil potential surveys, whereby the voltage is measured with respect to a reference electrode to determine whether adequate cathodic protection levels are present along the length of the pipeline. Techniques are also used to measure the voltage gradients in the soil above a protected pipeline to determine the size and location of coating defects. Coupons buried in the soil can supplement this external corrosion monitoring. In addition, coatings are inspected whenever por- tions of the pipeline are uncovered. Corrosion Mitigation Practices It is standard practice for buried transmission pipelines to be coated externally to provide a physical barrier between the steel and the sur- rounding corrosive environment. Desired coating characteristics include low permeability to water and salts, strong adhesion to steel, and good abrasion resistance (Beavers and Thompson 2006). The coating also needs to be durable and resist chemical and thermal degradation at pipe- line operating temperatures. Pipeline coatings have improved over the past several decades. Along with cold and hot applied tapes, field-applied coatings made from coal tar, asphalt, and grease were the dominant systems used through the 1950s (Michael Baker Jr., Inc. 2008; Beavers and Thompson 2006). Because of nonoptimal conditions for field applications, early coatings often had

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Crude Oil Pipelines in the United States 19 poor adhesion characteristics, with pinholes and other imperfections. Some also exhibited degradation of the polymers. After time in service, the coatings tended to become porous or to detach from the pipe surface. During the 1960s and 1970s, fusion bonded epoxy (FBE) coatings were introduced. Unlike other coatings, FBE coatings are formed by heating a powder on the surface of the metal. The components of the powder melt and flow to initiate a cross-linking process. These heat-cured coatings exhibit good mechanical and physical properties, including adhesive strength and resistance to degradation, and they are widely used today. Even a well-coated pipe may have imperfections and develop small holes in the coating that can expose the pipe to corrosion attack. To coun- ter this effect, pipelines are fitted with cathodic protection systems. In some systems, the electrochemical potential of the pipe is reduced by gal- vanically coupling to sacrificial anodes typically made of magnesium, alu- minum, or zinc alloys that will preferentially corrode instead of the pipe. Other systems employ an impressed current applied to the pipeline with the use of a power supply to lower the pipeline potential. The cathodic pro- tection system is designed to supply enough current to a pipe to prevent external corrosion at defects or holes that form in the coating where the external environment can come in contact with the steel surface. Defects in coatings are especially problematic when the disbonded coating shields distribution of the cathodic current to the defect site. This shielding is most often associated with the impermeable tapes and shrink sleeves used on some older pipelines. An advantage of modern FBE systems is that they are permeable to ionic flow and thus do not shield the exposed sites from cathodic protection.9 Preventing the internal corrosion of pipes starts with basic quality control and operational procedures that limit the entry and accumulation of water and other contaminants. As noted above, transmission pipelines are typically constructed of steel with no internal coatings, so the trans- ported product is in contact with the steel. While oil is not corrosive, even small amounts of contaminants such as water and salts in the oil can be 9  Inspections performed on gas gathering lines equipped with an early generation FBE coating (from the mid-1970s) revealed that less than 0.2 percent of pipeline sections exhibited blistering of the coating despite some operating in temperatures as high as 76°C (170°F). Removal of the blistered coating revealed no underlying corrosion because of the permeability of FBE to cathodic fields (Boerschel 2010; Batallas and Singh 2008).

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20 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines corrosive if they are allowed to accumulate on the steel surface. Certain gases dissolved in the product stream, especially oxygen, hydrogen sul- fide, and carbon dioxide, can also increase the rate of corrosion. Actions to mitigate internal corrosion include controlling ingress of air at pumps and other entry points, limiting water and sediment content, and chemi- cal treatment of the crude oil stream. The chemicals injected into the crude oil stream usually consist of a mixture of additives that inhibit corrosion by various means. The most common mixtures contain surfactant chemicals that adsorb onto the steel surface and provide a barrier between the corrosive water and pipe steel. Many surfactants confer additional benefits by reducing the surface ten- sion at the oil–water interface, which keeps the water entrained in the flow rather than depositing on the pipe wall. Chemical additives may also have properties that repel the water from the pipe wall, neutralize acids, and act as biocides to help inhibit microbiologically influenced corrosion. The rates of flow in transmission pipelines are normally sufficient to prevent the deposition of contaminants and to sweep away deposits that settle to the pipe bottom. Areas of low flow, such as steep angles of elevation and sections of isolated piping (called dead legs), are vulner- able to water and sediment accumulation and subsequent internal cor- rosion. Because the hydrodynamic and chemical processes of water and sediment accumulation are well understood, models for analysis are available to guide pipeline construction and operating parameters to decrease the tendency for accumulations and to identify areas of great- est vulnerability to corrosion. Additional details on the mechanisms of pipeline damage and factors that contribute to them are discussed in Chapter 5. SUMMARY The crude oil transmission network in the United States consists of an interconnected set of pipeline systems. Shipments traveling through the network often move from one pipeline system to another, sometimes being stored temporarily in holding tanks at terminals. Most opera- tors of transmission systems are common carriers who do not own the crude oil they transport but provide transportation services for a fee. Few major transmission pipelines are dedicated to transporting specific grades or varieties of crude oil. They usually move multiple batches of

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Crude Oil Pipelines in the United States 21 crude oil, which are often provided by different shippers and include a range of chemical and physical properties. Crude oil shipments are treated to meet the quality requirements of the pipeline operator as well as the content and quality demands of the refinery customer. Pipeline systems traverse different terrains and can vary in specific design features, components, and configurations. These differences require that each operator tailor operating and maintenance strategies to fit the circumstances of its systems in accordance with regulatory requirements. Nevertheless, the systems tend to share many of the same basic components and follow similar operating and maintenance proce- dures. Together, regulatory and industry standards, system connectiv- ity, and economic demands compel both a commonality of practice and a shared capability of handling different crude oils. REFERENCES Argonne National Laboratory. 2008. Overview of the Design, Construction, and Operation of Interstate Liquid Petroleum Pipelines. Report ANL/EVS/TM/08-1. http://www.ipd.anl.gov/anlpubs/2008/01/60928.pdf. Batallas, M., and P. Singh. 2008. Evaluation of Anticorrosion Coatings for High Tem- perature Service. Paper 08039. Presented at 17th International Corrosion Confer- ence, National Association of Corrosion Engineers International, Houston, Tex. 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. Boerschel, V. 2010. New Developments of Mid-TG-FBE Powder Coatings to Meet the Requirements of Pipe Coaters and Pipeline Owners. Paper 10012. Presented at 19th International Corrosion Conference, National Association of Corrosion Engineers International, Houston, Tex. Michael Baker Jr., Inc. 2008. Pipeline Corrosion: Final Report. U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety, Washington, D.C., Nov. http://primis.phmsa.dot.gov/ gasimp/docs/FinalReport_PipelineCorrosion.pdf. National Petroleum Council. 2011. Crude Oil Infrastructure. Paper 1-7. Oil Infra- structure Subgroup of the Resource and Supply Task Group, Sept. 15. http://www. npc.org/Prudent_Development-Topic_Papers/1-7_Crude_Oil_Infrastructure_ Paper.pdf. Rabinow, R. A. 2004. The Liquid Pipeline Industry in the United States: Where It’s Been, Where It’s Going. Association of Oil Pipe Lines, Washington, D.C., April.