TRB Special Report 311: Effects of Diluted Bitumen on Crude Oil Transmission Pipelines (2013)

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3 Bitumen Properties, Production, and Transportation by Pipeline T his chapter describes the chemical composition and physical proper- ties of bitumen, the methods used to produce it, and the properties of the bitumen shipments that are diluted for pipeline transportation to the United States. BITUMEN COMPOSITION AND PROPERTIES Like all forms of petroleum, bitumen is a by-product of decomposed organic materials rich in hydrocarbons. According to the World Energy Council, bitumen deposits exist in about 20 countries, but the largest are in Canada, Kazakhstan, and Russia (WEC 2010, 123–150). Because only the Canadian bitumen is diluted for transportation by pipeline to the United States, it is the subject of the description in this chapter.1 Canadian bitumen deposits are concentrated in the Western Cana- dian Sedimentary Basin (WCSB), and particularly in the province of Alberta. Three regions in the WCSB have large reserves: the Athabasca, Peace River, and Cold Lake regions (Strausz and Lown 2003, 21). Accord- ing to the government of Alberta, about two-thirds of the world reserves of recoverable bitumen are contained in the three regions, which total some 140,000 square kilometers (55,000 square miles) (ERCB 2012a). In some locations in Alberta, surface deposits are easy to spot, since the black bitumen is impregnated in sandstone along the sides of lakes and 1  Canada contains the vast majority of the natural bitumen in North America. According to the U.S. Geological Survey, bitumen deposits exist in the United States in several states, mainly in Utah, California, and Alabama. While commercial mining operations are being planned in Utah, many technical and economic challenges remain to exploit this resource (USGS 2006). 22 

Bitumen Properties, Production, and Transportation by Pipeline 23 Water Fines envelope (clay-minerals) 5% 15% Bitumen Sand film particles 10% 70% FIGURE 3-1 Composition of oil sands. rivers. Most of the bitumen is not visible because it is deposited below the surface. The bitumen-impregnated sands in the WCSB are referred to as bituminous sands, oil sands, and tar sands (Strausz and Lown 2003, 29). Canadians use the term oil sands, which is also used in this report. The typical composition of the WCSB oil sands is 85 percent sand and clay fines,2 10 percent bitumen, and 5 percent water by weight.3 Oil sands also contain salts, trace gases, and small amounts of nonpetroleum organic matter.4 These components exist together in a specific microstructure with a film of water that surrounds each sand and clay particle, and the bitumen surrounds the film, as shown in Figure 3-1. When freed from this microstructure, bitumen has a typical elemental composition of 81 to 84 percent carbon; 9 to 11 percent hydrogen; 1 to 2 percent oxygen, nitro- gen, and other elements; and 4 to 6 percent sulfur, most of which is bound in the bitumen in stable (e.g., heterocyclic rings) hydrocarbon structures 2  The solid particles consist of sand grain minerals, mostly of quartz but also feldspar, mica, and chert. The solid particles also consist of clay minerals, mostly kaolinite and illites (Strausz and Lown 2003, 31–32). 3  Up to 18 percent of the ore can be made up of bitumen (Strausz and Lown 2003, 62). 4  The organic matter consists of humin, humic acids, fulvic acids, and chemiabsorbed aliphatic carboxylic acids (Strausz and Lown 2003, 29–32). 

24 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines (Dettman 2012; Strausz et al. 2011; Gogoi and Bezbaruah 2002; Strausz and Lown 2003). Hydrocarbon molecules account for 92 to 95 percent of the weight of bitumen.5 These molecules range from light alkanes, such as ethane, to long-chain compounds with relatively high molecular weights and boiling points. The latter molecules are more common in bitumen than in the lighter, more paraffinic crude oils that have undergone less microbial degradation. 6 Bitumen contains relatively high con- centrations of asphaltenes, which account for 14 to 17 percent of the total weight of the material (Strausz and Lown 2003, 95; Rahimi and Gentzis 2006, 151). Trace elements, such as vanadium and nickel, usu- ally reside in the asphaltenes along with sulfur, nitrogen, and oxygen (Strausz and Lown 2003, 93–99, 495–498). The nitrogen in the bitumen is bonded with carbon in pyridinic structures, including quinolines and acridines (Rahimi and Gentzis 2006). The asphaltenes, as well as other nonparaffinic compounds such as naphthenes, give bitumen its high density and high viscosity (Strausz and Lown 2003, 99). Bitumen is usually distinguished from other forms of petroleum on the basis of physical properties that derive in part from its rela- tively high asphaltene content. The U.S. Geological Survey (USGS) has used the following definition to distinguish bitumen from other heavy crude oils: Natural bitumen is defined as petroleum with a gas-free viscosity greater than 10,000 centipoises (cp) at original reservoir temperature. Petroleum with a gas-free viscosity between 10,000 and 100 cp is generally termed heavy crude oil. In the absence of viscosity data, oil with API gravity less than 10 degrees is generally considered natural bitumen, whereas oil with API gravity ranging from 10 degrees API to about 20 degrees API is considered heavy crude oil. The term extra-heavy crude oil is used for oil with a viscosity less than 10,000 cp but with API gravity less than 10 degrees. (USGS 2006) 5  The ratio of hydrogen to carbon atoms is about 1.5 in bitumen, compared with 2.0 for very light oils (Strausz and Lown 2003, 95–96). 6  Bitumen has undergone more biodegradation than have other petroleum oils. Because straight- chain paraffinic hydrocarbons are more readily metabolized by microorganisms, these hydrocarbons are depleted in bitumen (Strausz and Lown 2003, 90). 

Bitumen Properties, Production, and Transportation by Pipeline 25 Viscosity (centipoise) 106 105 104 Athabasca 103 Cold Lake 102 Heavy oil (Lloydminster) 10 Light crude oil 1 100 200 300 Temperature (°F) FIGURE 3-2 Response of crude oil viscosity to changes in temperature. Source: Raicar and Procter 1984; WEC 2010, 126. The American Petroleum Institute (API) gravity scale referenced by USGS is an inverse measure of the density of a liquid relative to that of water at room temperature. A liquid with API gravity greater than 10 degrees will float on water; if the API gravity is lower than 10 degrees, it will sink.7 Canadian bitumen (undiluted) typically has an API gravity between 7 and 13 degrees, whereas most heavy crude oils have values that are 5 to 15 degrees higher (Strausz and Lown 2003, 100). The viscosity of bitumen is also high compared with that of other crude oils across a range of temperatures. Figure 3-2 compares the effects of temperature on viscosity [in centipoise units (cp)] for bitumen derived from two WCSB reservoirs (Cold Lake and Athabasca), a Canadian heavy crude 7  API gravity values are referred to as “degrees.” Most crude oils have API gravities in the range of 20 to 40 degrees, but some range 10 degrees higher or lower. 

26 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines (Lloydminster), and typical light crude oils.8 At most pipeline operating temperatures [0°C to 40°C (32°F to 100°F)], the lighter crude oils will behave as liquids, while the bitumen will remain in a semisolid state, having viscosities comparable with that of peanut butter. Although they are less viscous than bitumen, the heaviest conventionally drilled Canadian crude oils have relatively high viscosities as well.9 Several Canadian crude oils, including the Lloydminster crude oils shown in Figure 3-2, are routinely diluted with lighter oils to improve their flow in transmission pipelines.10 BITUMEN PRODUCTION The WCSB has long been a major oil-producing region of North America. Oil exploration commenced in the early 20th century, and by the 1960s hundreds of millions of barrels of Western Canadian crude oil were being exported each year through pipelines to the United States. Nearly all of this oil was produced with conventional drilling and well technology. By the 1990s, Western Canadian exports of conventionally produced oil were declining just as new technologies were being introduced to recover the vast deposits of bitumen contained in oil sands. While natural bitumen had long been used as sealing material, Cana- dian entrepreneurs started mining deposits for refinery feed during the early 20th century. However, separating the bitumen from the mined ore required significant amounts of heated water, which made recovery expensive compared with the lighter crude oils that were less costly to drill elsewhere in Canada and the United States. Commercial ventures to mine bitumen began in the 1920s, but it took another 40 years of declin- ing North American crude oil reserves, increasing consumer demand for gasoline and other refined petroleum, and advances in extraction and 8  Centipoise is a measure of resistance to shear flow, or the dynamic viscosity of a fluid. A more common measure of resistance to flow by crude oils is the centistoke (cSt), which is the ratio of dynamic viscosity to fluid density, also known as kinematic viscosity. At room temperature, the kinematic viscosity of bitumen will exceed 100,000 cSt, compared with about 25 cSt for a medium- density crude oil. Kinematic viscosity is referenced more often in this report. 9  This Canadian heavy crude oil is usually diluted with lighter oils for pipeline transportation. 10  Lloydminster heavy crude oils have API gravities of 12 to 23 degrees (Strausz and Lown 2003, 26). 

Bitumen Properties, Production, and Transportation by Pipeline 27 processing technologies to transform the mined bitumen into a commer- cially viable refinery feedstock.11 During the 1990s, thermally assisted in situ recovery methods were introduced in the WCSB to exploit the large reserves of bitumen located too deep for surface mining. After this development, the quantity of bitu- men produced surpassed the quantity of conventionally produced oil from the basin. Today, bitumen accounts for more than 70 percent of the petroleum produced in Alberta, and in situ recovery methods account for nearly half of this bitumen production (ERCB 2012a). One in situ method in particular—steam-assisted gravity drainage (SAGD)—led to the recent growth in Canadian bitumen production for export to the United States. Indeed, no significant quantities of mined bitumen are diluted for pipeline transportation to the United States, the main market for bitumen recovered by using the SAGD process.12 Bitumen Mining and Upgrading to Synthetic Crude Oil About 20 percent of the bitumen deposits in the WCSB are less than 60 meters (200 feet) deep and can be recovered by surface mining. Min- ing operations use diesel-powered shovels to excavate the ore, which is transported by truck to field facilities containing crushers. The crushed ore is mixed, or washed, with hot water to create a slurry that is piped a short distance, where it is agitated and filtered in separation vessels. The hot water heats and releases the water that surrounds the sand and clay particles. The agitation causes air bubbles to attach to bitumen droplets, which float in a froth to the top of the vessel. The froth is then deaerated with steam and diluted with a hydrocarbon solvent such as naphtha. The solvent coalesces and causes settlement of emulsified water and min- eral solids. The suspended bitumen is then separated with a centrifuge and skimmer. 11  Oil Sands Discovery Centre. Facts About Alberta’s Oil Sands and Its Industry. http://history. alberta.ca/oilsands/docs/facts_sheets09.pdf. 12  The discussion focuses on surface mining and SAGD, which are the most common bitumen recovery methods. Other methods not discussed include cyclic steam stimulation, toe-to-heel air injection, vapor-assisted petroleum extraction, and cold heavy oil production with sand. More information on recovery methods can be found at http://www.oilsands.alberta.ca/. 

28 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines The extraction process for mined bitumen yields a product that typi- cally contains 0.5 percent solids and 1 to 2 percent water by volume. This solid and water content is generally too high to be accepted by trans- mission pipelines. As a consequence, mined bitumen is nearly always upgraded, usually at nearby field plants, into synthetic crude oil. The field plants consist of refinery-type cokers that crack the bitumen into lighter products that are then processed in hydrotreating units to remove sul- fur and nitrogen.13 The processed streams are then mixed to produce a low-viscosity, low-sulfur synthetic crude oil that can be transported by transmission pipeline to refineries in Canada and the United States. The synthetic crude oils are also blended with other heavy Canadian crude oils, including in situ–produced bitumen, for pipeline transportation to the United States. Nearly all of the bitumen mined in the WCSB is upgraded to synthetic crude oil.14 This situation is subject to change as alternative methods are introduced to yield mined bitumen with reduced viscosity and water and sediment content comparable with that of the bitumen produced in situ and transported in diluted form through transmission pipelines. One alternative is to deasphalt the mined bitumen partially to produce synthetic crude oil that retains some of the heavier hydrocarbon frac- tion by substituting a paraffinic solvent for the aromatic-rich naphtha solvent traditionally used during removal of water and solids (Rahimi et al. 1998). Composed largely of pentanes and hexanes, a paraffinic solvent is more effective than naphtha in promoting aggregation and settlement of asphaltenes and suspended water and solids. Removal of asphaltenes through paraffinic treatment yields a processed bitumen that is less viscous and has lower levels of water and solids than mined bitumen that is processed with a traditional naphtha solvent. Mined bitumen processed with paraffinic solvent can be transported by transmission pipeline, usually by retaining some of the solvent as 13  According to the Alberta Energy Ministry, the five upgraders operating in Alberta in 2011 had the capacity to process approximately 1.3 million barrels of bitumen per day (ERCB 2013). 14  According to the Alberta Energy Ministry, in 2011 about 57 percent of oil sands bitumen production was upgraded to synthetic crude oil in Alberta. Most upgraders produce synthetic crude oil, but some also produce refined products such as diesel (ERCB 2013). 

Bitumen Properties, Production, and Transportation by Pipeline 29 diluent.15 Mined bitumen treated in this manner is being piped several hundred miles from oil sands production regions to large, centrally based upgraders elsewhere in Alberta, where it is processed into synthetic crude oil. The mined bitumen, however, is not transported through pipelines to the United States (except when upgraded to synthetic crude oil) because paraffinic solvents are too expensive to use as diluent for long-distance transportation. Instead, the solvent is recovered at the Canadian upgrad- ers and piped back to bitumen production fields for reuse as a solvent. In Situ Recovery Because most Canadian bitumen is located deep underground, it can only be recovered in place. Although reaching the deposits is not difficult,16 the challenge in recovering them is in separating and thinning the bitu- men for pumping to the surface. A recovery method that is now common involves the injection of pressurized steam into the deposit. The steam thins the bitumen and separates it from the sand while the pressure helps to push the bitumen up the well. A number of thermally assisted recovery methods are used in the WCSB. The two main methods are cyclic steam stimulation (CSS) and SAGD. CSS involves injecting steam into the bitumen deposit and let- ting it soak for several weeks. This process causes the bitumen to sepa- rate from the sand and become sufficiently fluid for pumping. Over the past decade, SAGD has surpassed CSS as the preferred thermal recovery method because a higher proportion of the bitumen is recovered. SAGD involves drilling two horizontal wells, one located a few feet above the other as shown in Figure 3-3. Steam is injected into the upper well, which heats the bitumen and causes it and steam condensate to drain into the lower well for pumping to the surface. At the surface, condensed water is separated from the recovered bitumen and recycled to produce steam for subsequent applications. 15  While asphaltene concentrations have significant implications for bitumen viscosity, the removal of all asphaltenes would not reduce viscosity enough for undiluted bitumen to meet pipeline specifications (Rahimi and Gentzis 2006). 16  The exploited deposits are generally less than 750 meters (2,500 feet) underground. 

30 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines FIGURE 3-3 Bitumen recovered by SAGD. Source: ERCB 2012b. The high recovery ratio of SAGD is an important reason for the growth in Canadian bitumen production. SAGD now accounts for about half the bitumen recovered from the WCSB.17 Compared with mining, SAGD has the advantage of eliminating the need to wash the ore with hot water because the bitumen is separated from the sand and clay underground. After further treatment (e.g., standard degassing, dewatering, and desalt- ing), the recovered bitumen contains much lower levels of water and sed- iments (generally less than 0.5 percent by volume) than mined bitumen, and it is sufficiently stable for acceptance by long-distance pipelines. Whereas nearly all mined bitumen is upgraded into synthetic crude oil in Alberta, less than 10 percent of the SAGD-derived bitumen is processed  In 2011, about 1.7 million barrels per day of bitumen were produced, with surface mining accounting 17 for 51 percent and in situ processes accounting for 49 percent of the production (ERCB 2013). 

Bitumen Properties, Production, and Transportation by Pipeline 31 Thousands of Barrels per Day 10,000 Light Sweet (>29°API and 8,000 <1% Sulfur) Other Light Sour import 6,000 (>29°API and regions >1% Sulfur) 4,000 Western Canada Heavy Sour 2,000 Venezuela (<29° API, >1% Sulfur) Mexico 0 2005 2006 2007 2008 2009 2010 2011 2012 Year FIGURE 3-4 Annual U.S. crude oil imports by grade and origin. Source: Chart is derived from January 31, 2012, presentation to the committee by G. Houlton. Source data on crude oil imports were obtained from the Energy Information Administration, U.S. Department of Energy (http://www.eia.gov/countries/cab.cfm?fips=CA). into synthetic crude oil (NEB 2009). Most SAGD-derived bitumen is diluted with lighter oils for transportation by pipeline to U.S. refineries. PIPELINE TRANSPORTATION OF DILUTED BITUMEN According to the U.S. Department of Energy, imports of Canadian diluted bitumen and other crude oils have grown by more than one-third since 2000.18 Partially as a result of Canadian supplies as well as newly exploited domestic oil shale, crude oil imports from other regions of the world are declining. In particular, the Canadian feedstock has supplanted heavy crude oils once imported in large volume from Venezuela and Mexico (Figure 3-4). While more than two-thirds of the Canadian crude oil is refined in the Midwest, refinery demand for this feedstock has been grow- ing in other regions of the country, particularly at Gulf Coast refineries that are equipped to process heavy feed.  http://www.eia.gov/countries/cab.cfm?fips=CA. 18 

32 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines U.S. Pipelines Transporting Diluted Bitumen Figure 3-5 shows U.S. refinery destinations for diluted bitumen and other Canadian crude oils, and Figure 3-6 shows the main pipeline cor- ridors that access these refineries. Major export pipelines from Canada include the Enbridge Lakehead network, which serves several Great Lakes refineries; the TransCanada Keystone pipeline, which accesses the Cushing, Oklahoma, hub and refineries in southern and central Illinois; and the Kinder Morgan Express and Prairie pipelines, which transport Canadian crude oils to refineries in the Rocky Mountains and provide surplus to refineries farther east and south. These trunk lines are connected to pipelines that deliver feed to refineries as far east as Ohio and western Pennsylvania and as far south as the Texas Gulf Coast and New Mexico. Several connecting pipelines have recently undergone flow reversals, such as the 375-mile Occidental Centurion line, which now runs southwest from Cushing in the direction of El Paso, Texas; the 858-mile ExxonMobil Pegasus line, which runs south from Illinois to refineries on the Gulf Coast; and the 670-mile Enbridge Seaway line, which crosses East Texas and is expected to become fully operational during 2013. Properties of Diluted Bitumen Shipped by Pipeline In Canada, the National Energy Board (NEB) administers the tariffs, or terms and conditions, that govern the transportation of crude oil by transmission pipeline. For shipments entering the United States, pipe- line operators must also file tariffs with the Federal Energy Regulatory Commission. As explained in Chapter 2, tariffs contain quality specifi- cations for crude oil shipments that are intended to ensure compliance with the operational requirements of pipelines as well as possession of properties required by refiners. At custody transfer points, pipeline oper- ators sample shipments to confirm compliance with tariff specifications. Density and Viscosity Levels To ensure pipeline transportability, NEB tariffs specify that the den- sity of crude oil shipments not exceed 940 kilograms per cubic meter (kg/m3) (about 20 degrees API gravity) and that viscosity not exceed 

Bitumen Properties, Production, and Transportation by Pipeline 33 Northeast and Other California and 1% Washington Gulf Coast 4% 7% Montana/Utah/ Colorado Oklahoma/Kansas 11% 7% Michigan/Ohio/ Western Minnesota Pennsylvania 16% 12% Illinois/Indiana 42% FIGURE 3-5 U.S. refinery destinations for Canadian heavy crude oil imports in 2011. Source: National Energy Board fact sheet “Disposition of Heavy Crude Oil and Imports” (http://www.neb-one.gc.ca/clf-nsi/rnrgynfmtn/sttstc/crdlndptrlmprdct/dspstnfdmstccrdlndmprts-eng.html#s1). Canadian heavy crude oils and diluted bitumen Refinery Storage hub Transmission pipeline Flow direction FIGURE 3-6 Main pipeline corridors moving Canadian crude oil to U.S. refineries. 

34 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines 350 cSt19 when measured at the posted pipeline operating temperature.20 To meet the specifications, Canadian bitumen is diluted into either “dilbit” or “synbit.” The Canadian Association of Petroleum Producers describes dilbit as a bitumen blend consisting of diluent that has a den- sity of less than 800 kg/m3 (45 degrees API). If it has a density greater than or equal to 800 kg/m3, the diluent is presumed to be synthetic crude oil, and the blend is called synbit (CAPP 2013). In the case of dilbit, the most common diluents are naphtha-based oils, including natural gas condensate.21 The light oils that are used have low densities (<750 kg/m3), high API gravities (>60 degrees), and low viscosities (<1 cSt at room temperature). Compared with condensate, synthetic crude oils have higher densities (825 to 875 kg/m3), lower API gravities (30 to 40 degrees), and higher viscosities (5 to 20 cSt). Some bitumen shipments are diluted with both condensate and synthetic crude oil to produce “dilsynbit.” Dilution and blending activity is common in the petroleum industry, as distillates and light oils are regularly mixed with heavier oils to alter shipment density and viscosity characteristics. The chemical compat- ibility of the oils and distillates must be considered before blending, particularly to avoid precipitation of asphaltenes. Thick deposits of these components can foul pipelines, pumps, and other equipment to create an increased need for pig cleaning to prevent flow assurance prob- lems (Cimino et al. 1995; Saniere et al. 2004; Leontaritis and Mansoori 1988). Dilution with distillates containing high concentrations of light hydrocarbons such as pentanes and hexanes can cause asphaltenes to precipitate from oils if the distillate makes up a majority of the volume of the blend (Maqbool et al. 2009). The acceptable types and ratios of distillates blended with bitumen have therefore been analyzed to ensure chemical compatibility as well as a transportable product that does not deposit asphaltenes during postproduction storage and transportation (Schermer et al. 2004). 19  Kinematic viscosity and the centistoke (cSt) unit of viscosity measurement have been defined earlier in this chapter. 20  For an example, see Article 1, page 3 (Definition for Heavy Crude) of NEB Tariff Number 4, Keystone Pipeline System Petroleum Tariff (http://www.transcanada.com/docs/Key_Projects/ 06_NEB_Tariff_No_4_Rules_and_Regs_CL.pdf ). 21  Condensate liquid is produced from raw natural gas when the temperature is reduced below the boiling temperature of the gas. 

Bitumen Properties, Production, and Transportation by Pipeline 35 As discussed earlier, distillates such as naphtha are usually mixed with bitumen at the production plant to facilitate water and sediment removal. Indeed, all or most of the diluent in diluted bitumen is blended during the processing stage before delivery of shipments for transmis- sion by pipeline. In some cases, more diluent may be added after delivery to the transmission pipeline if further dilution is necessary to meet the density and viscosity levels required for long-distance transportation.22 Like all crude oil blending, the mixing of diluent and bitumen is designed to make the shipped product miscible, or fully mixed in all proportions. As discussed in Chapter 2, once in the pipeline, batch shipments of diluted bitumen and other heavy crude oils are sequenced to avoid contact with lighter crude oil and condensate shipments. Meters along the pipelines track the batched stream to detect any changes in shipment density and viscosity. After blending, diluted bitumen becomes a mixture of hydrocarbons with a range of molecular weights. As in the case of other crude oils, these hydrocarbons are separated by distillation at recipient refiner- ies. Table 3-1 compares the distilled volume of light (low-molecular- weight) hydrocarbons in three diluted bitumen crude oils and five light, medium, and heavy crude oils imported from Canada. The light hydro- carbons in all crude oils are mainly pentanes or heavier, with some measurable butanes and trace amounts of lighter molecules. Because of the diluent, the light fraction of diluted bitumen is comparable with that of medium and heavy crude oils and accounts for 17 to 27 percent of hydrocarbon volume. The specific diluents used in blending are selected on the basis of many factors, including their availability in bitumen production regions. Table 3-2 shows the chemical and physical properties of the common diluent Southern Lights, a condensate produced in the United States and piped to Alberta. Because of its low viscosity, this condensate and others can be mixed with bitumen at a ratio of about 30:70 by volume.23 Table 3-2 also shows the chemical and physical properties of a Suncor synthetic crude oil. Because it has a higher density than condensate, this 22  Information on production processes was obtained from briefings by and interviews with bitumen producers and pipeline operators. 23  These blending ratios are nominal and will vary somewhat depending on seasonal temperatures and the flow regime of individual pipeline operators. 

36 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines table 3-1 Percentage, by Volume, of Low-Molecular-Weight Hydrocarbons in Selected Diluted Bitumen Blends and Other Canadian Crude Oils Light Access Borealis Koch Sour Sour High Smiley– Lloyd Western Wabasca Heavy Alberta Blend Edmonton Coleville Kerrobert Blend Heavy Blend (Light (Light (Medium (Heavy (Heavy (Diluted (Diluted (Diluted Crude Crude Crude Crude Crude Hydrocarbon Bitumen) Bitumen) Bitumen) Oil) Oil) Oil) Oil) Oil) Butanes 0.72 1.93 0.38 4.50 2.43 2.43 0.54 2.04 Pentanes 8.53 1.92 4.01 2.39 3.25 2.56 4.88 6.00 Hexanes 7.06 3.00 5.75 4.54 6.13 4.59 3.95 3.96 Heptanes 4.73 3.47 4.57 5.61 7.44 5.31 2.7 2.12 Octanes 2.74 3.53 5.28 6.09 8.72 5.58 2.12 1.38 Nonanes 1.43 2.64 4.04 4.97 7.18 4.60 2.05 1.36 Decanes 0.70 1.21 1.49 2.49 3.46 2.46 1.10 0.81 Total 25.91 17.7 25.52 30.59 38.61 27.53 17.34 17.67 Mass Recovered Distillation Temperature [°C (°F)] 5% 38 93 64 45 69 64 62 51 (101) (200) (147) (114) (156) (147) (144) (123) 10% 70 152 93 92 87 93 114 136 (158) (307) (200) (198) (188) (200) (237) (276) Source: Data obtained from CrudeMonitor.com by Crude Quality, Inc. (http://www.crudemonitor.ca/condensate.php?acr=SLD; http://www.crudemonitor.ca/crude.php?acr=SYN). Accessed March 1, 2013. and other synthetic crude oils are usually blended in even (50:50) ratios with bitumen. Illustrative blending ratios and resulting density and vis- cosity values for synbit and dilbit are given in Table 3-3. Once they are diluted for transportation, shipments of bitumen have physical properties comparable with those of other heavy crude oil ship- ments, and they can be stored and transported through the same pipeline facilities in a similar manner—that is, without a need to heat the crude oil to increase fluidity. API gravities for dilbit and synbit blends are generally in the low 20 degrees (a density of about 925 kg/m3), and viscosities gen- erally range between 75 and 200 cSt at pipeline operating temperatures. 

Bitumen Properties, Production, and Transportation by Pipeline 37 TABLE 3-2 Selected Properties of Two Common Diluents Southern Lights Suncor Synthetic Property Condensate Diluent Crude Oil Diluent Density (kg/m3) 675 861 API gravity (°) 78 33 Sulfur (weight percent) 0.03 0.17 Viscosity at 20°C (68°F) (cSt) <0.5 6.3 Sediment (ppmw) 16 0 Note: ppmw = parts per million by weight. Source: Data obtained from CrudeMonitor.com by Crude Quality, Inc. (http://www. crudemonitor.ca/condensate.php?acr=SLD; http://www.crudemonitor.ca/ crude.php?acr=SYN) and from Enbridge website (http://www.enbridge.com/ DeliveringEnergy/Shippers/~/media/www/Site%20Documents/Delivering%20 Energy/2012CrudeCharaceristics.ashx). Both accessed March 1, 2013. TABLE 3-3 Example Blending Ratios and Density and Viscosity Levels for Synbit and Dilbit Viscosity Blend Component Volume Percent Density (kg/m3) [cSt at 15°C (59°F)] Synbit Bitumen 51.7 1,010 760,000 Synthetic crude oil 48.3 865 5.9 Total 100 940 128 Dilbit Bitumen 74.6 1,010 760,000 Condensate 25.4 720 0.6 Total 100 936 350 Source: Illustrative blending ratios provided by R. Segato, Suncor Energy, October 23, 2012 (http://onlinepubs.trb.org/onlinepubs/dilbit/Segato102312.pdf). 

38 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines Table 3-4 shows average density, API gravity, and viscosity values for six common diluted bitumen blends. The values are compared with those of six other heavy Canadian crude oils that are commonly piped to the United States. In some cases, these other heavy crude oils are also blended with lighter oils. As would be expected of commercial crude oils, the 12 sampled products have viscosities that conform to requisite pipe- line tariff specifications. TABLE 3-4 Comparison of Density, API Gravity, and Viscosity of Diluted Bitumen and Other Canadian Crude Oils canadian heavy crude oils Western Bow Lloydminster Lloydminster Smiley– Canadian River Fosterton Blend Kerrobert Coleville Blend Density (kg/m3) 914 927 927 930 932 929 API gravity (°) 23 21 21 20 20 21 Viscosity at 20°C 100 96 145 146 144 145 (68°F) (cSt) Viscosity at 40°C 37 36 52 52 51 52 (104°F) (cSt) diluted bitumen Surmount Access Cold Peace River Christina Wabasca Heavy Western Lake Heavy Lake Heavy (Synbit) Density (kg/m3) 926 928 931 923 935 936 API gravity (°) 21 21 20 22 20 19 Viscosity at 20°C 150 153 113 178 134 131 (68°F) (cSt) Viscosity at 40°C 53 54 44 62 49 47 (104°F) (cSt) Source: Data obtained from CrudeMonitor.com by Crude Quality, Inc. (http://www.crudemonitor.ca/tools/comp/ crudecomparisons.php#results) and from Enbridge website (http://www.enbridge.com/DeliveringEnergy/ Shippers/~/media/www/Site%20Documents/Delivering%20Energy/2012CrudeCharaceristics.ashx). Both websites accessed March 1, 2013. 

Bitumen Properties, Production, and Transportation by Pipeline 39 According to API, shipments of diluted bitumen enter transmission pipelines at the same temperatures as other Canadian crude oils, gen- erally in the range of 4°C to 25°C (40°F to 75°F) (API 2013). Tempera- tures will increase as a result of friction as the crude oil flows through the pipeline and because of high ambient temperatures during summer months. Because more pumping energy is needed for viscous crude oils, the temperature will be elevated in pipeline segments downstream from pumps. The temperature gain from pumping, however, will be the same for diluted bitumen as for other crude oils with similar densities and vis- cosities. Increasing pumping energy to boost the flow rate will raise the temperature further, but this effect will remain the same for all crude oils with corresponding levels of density and viscosity. Within the con- straints of the design and safety factors of a pipeline, an operator may elect to increase the flow rate of any crude oil type as a means of adding throughput capacity, but this is strictly an economic decision. Water and Sediment Content Refiners dislike crude oil feed containing excess water and sediment that requires filtration and added treatment for effluent disposal. Further- more, they do not want to pay for the transportation of these impurities in crude oil shipments. Water and sediment are also undesirable from the standpoint of pipeline operators because of the potential for internal corrosion, as discussed in Chapter 5. Canadian pipeline tariffs specify that basic sediment and water (BS&W) in crude oil shipments not exceed 0.5 percent by volume. While U.S. tariffs tend to allow higher BS&W lim- its (1 percent in most cases), the lower Canadian threshold becomes the constraining factor for diluted bitumen and other crude oils piped into the United States from Canada. Data specifically on the water content of pipeline shipments are dif- ficult to obtain (as distinguished from data on combined water and sedi- ment volumes). Nevertheless, because the Canadian tariffs are generally more restrictive than those in the United States, it can be inferred that shipments of Canadian crude oils, including diluted bitumen, do not con- tain more water than other crude oils transported in U.S. transmission pipelines. In the case of sediment, any amounts measured in diluted bitu- men are likely to derive from the bitumen, since the diluents are largely free of sediment (as shown in Table 3-2). Some sediment sampling data 

40 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines Sediment content (ppmw) 350 = Diluted bitumen 300 = Other crude oils 250 200 150 100 50 0 15 20 25 30 35 40 API Gravity FIGURE 3-7 Average sediment content for nine diluted bitumen blends and 10 light, medium, and heavy Canadian crude oils. Source: Data obtained from CrudeMonitor.com by Crude Quality, Inc. (http://www.crudemonitor.ca/condensate. php?acr=SLD; http://www.crudemonitor.ca/crude.php?acr=SYN). Accessed March 1, 2013. are available to compare diluted bitumen with other Canadian crude oils. Figure 3-7 shows the average sediment levels for nine diluted bitumen blends and 10 light, medium, and heavy Canadian crude oils. Average sediment levels range from 18 to 265 ppmw for the diluted bitumen and from 98 to 322 ppmw for the selection of Canadian crude oils.24 Sedi- ment quantities in this general range (<500 ppmw) will constitute less than 0.05 percent of the crude oil stream. The comparisons suggest that shipments of diluted bitumen contain sediment levels that are within the range of other crude oils piped into the United States. Other characteristics of entrained sediments, such as the size, shape, mass, and hardness of solid particles, are seldom measured in pipeline shipments or reported in standard crude oil assays. Particle size is a potentially important factor in the tendency of sediments to clog pumps and other pipeline equipment and settle to the pipe bottom to form 24  Most contaminants are expressed as parts per million (ppm), which is 1 milligram per kilogram for weight (noted as 1 ppmw) or 1 milligram per liter for volume (noted as 1 ppmv). 1,000 ppmw = 0.1 percent of weight. 

Bitumen Properties, Production, and Transportation by Pipeline 41 Volume Percentage 16 14 12 10 8 6 4 2 0 0.01 0.1 1 micron FIGURE 3-8 Particle size distribution of solids in diluted bitumen. Source: McIntyre et al. 2012. sludge. The shape, mass, and hardness of solid particles in sediment can also affect the potential for internal erosion. While data on physical properties are limited, some values for parti- cle size and other properties have been reported in laboratory studies of diluted bitumen and other crude oils. Figure 3-8 shows the particle size distribution of solids in diluted bitumen as measured by McIntyre et al. (2012). Median particle size was 0.1 micron (mm) and rarely exceeded 1 mm. Other data indicate that the distribution of particle size observed by McIntyre et al. (2012) is well within the range of other crude oils shipped by pipeline. The Canadian Crude Quality Technical Association (CCQTA) has spot sampled the desalter effluent from three refineries in Canada and the United States. The effluent was derived from crude oils other than diluted bitumen. The particle size distributions from these samples are shown in Table 3-5. The median particle sizes for the sam- ples ranged from about 0.4 to 1.6 mm, higher than the median particle size reported for the diluted bitumen sampled by McIntyre et al. (2012). CCQTA data on the nature of solids filtered from five diluted bitu- men and two heavy crude oil samples show median particle sizes that are comparable across the samples, ranging from 1.0 to 2.4 microns for four of the five diluted bitumen samples and from 1.9 to 2.3 microns for 

42 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines TABLE 3-5 Size Distribution of Solid Particles Obtained from Refinery Effluent for Crude Oils Other Than Diluted Bitumen particle size (m) refinery refinery a refinery b c Sample Sample Sample Sample Sample Sample Sample Sample Sample 1 2 3 4 5 1 2 3 1 Mean 0.85 1.1 1.13 0.74 1.14 2.67 1.23 0.82 0.98 Mode 0.32 0.31 0.28 0.33 0.39 2.33 0.26 0.53 0.54 Median 0.66 0.86 0.76 0.49 0.81 1.61 0.8 0.43 0.84 Minimum 0.13 0.17 0.13 0.06 0.13 0.06 0.1 0.07 0.15 Maximum 3.38 4.5 9.74 4 6.55 21.59 13.3 17.7 4.64 Standard 0.55 0.76 1.05 0.67 0.9 3.09 1.3 1.36 0.6 deviation Source: Data provided by CCQTA and derived from Oil Sands Bitumen Processability Project. Presented to the committee on October 23, 2012 (http://onlinepubs.trb.org/onlinepubs/dilbit/SegatoLimieux102312.pdf). the two heavy crude oil samples.25 The fifth diluted bitumen sample had a median particle size of 5.6 microns. The maximum particle sizes in the five diluted bitumen samples ranged from 11 to 92 microns, while the maximum value for the two heavy crude oils was 33 microns. Data are more limited for characterizing the shape, mass, and hardness of solids in diluted bitumen and other crude oils. As noted earlier, the sand grains in unprocessed bitumen contain hard silicate minerals such as quartz, feldspar, and mica, in addition to the softer minerals found in clay fines (Strausz and Lown 2003, 31–32). However, the in situ–produced bitu- men that is processed and diluted for pipeline transportation does not contain the same high levels of sand, clay fines, and other sediments found in bitumen in its native state. McIntyre et al. (2012) reported that about 1 percent of the solids in sampled diluted bitumen consisted of 25  Data obtained from the CCQTA Oil Sands Bitumen Processability Project. Presented to the com­ mittee on October 23, 2012 (http://onlinepubs.trb.org/onlinepubs/dilbit/SegatoLimieux102312.pdf ). 

Bitumen Properties, Production, and Transportation by Pipeline 43 quartz, while clay materials (16 percent) and hydrocarbon and coke-like materials (83 percent) accounted for the remainder. X-ray diffraction analysis of the solids in the five diluted bitumen and two heavy oil samples taken by CCQTA indicate that silicate particles are more abundant in the solids of diluted bitumen (accounting for 13 to 45 percent of crystalline solids) than in the solids of other heavy crude oils sampled (accounting for 5 to 8 percent of crystalline solids).26 However, the five diluted bitumen samples did not contain high levels of sediment, with none exceeding 350 ppmw (0.035 percent). Other Properties Pipeline tariffs in Canada and the United States generally do not contain specifications for shipment properties apart from those discussed above, although crude oil producers and refiners may have private agreements that specify qualities such as acidity and sulfur content. Table 3-6 shows the acidity and sulfur content for several sampled Canadian heavy crude oils and diluted bitumen blends. The acidity of crude oil is generally referenced by using total acid number (TAN), a measure of the amount (in milligrams) of potassium hydroxide (KOH) needed to neutralize the acid in a gram of oil. TAN usu- ally increases with the extent of oil biodegradation and generally is in the range of 0.5 to 3.0 for heavy oils (Strausz and Lown 2003, 430). Although it overlaps with the range of TANs found in heavy Canadian crude oils (as shown in Table 3-6), the range of acid content in diluted bitumen blends is generally higher than the range in other crude oils because of the greater biodegradation of the natural bitumen and resulting concen- trations of high-molecular-weight organic acids. The type of acid in diluted bitumen is more important to pipeline operators than total acid content. High-molecular-weight organic acids, such as naphthenic acids, are stable in the pipeline transportation envi- ronment. These acids have boiling points higher than water and do not react at pipeline operating temperatures. Although the organic acids can be corrosive to metals used in refineries processing crude oils at 26  Data obtained from the CCQTA Oil Sands Bitumen Processability Project. Presented to the com­ mittee on October 23, 2012 (http://onlinepubs.trb.org/onlinepubs/dilbit/SegatoLimieux102312. pdf ). According to the CCQTA representative presenting the data, X-ray diffraction analysis does not measure the noncrystalline solids, which can account for 30 percent or more of the solids of sediment. 

44 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines TABLE 3-6 Sulfur and Total Acid Content in Sampled Canadian Heavy Crude Oils and Diluted Bitumen Blends Total Sulfur (percentage by weight) TAN (mg KOH/g oil) Canadian Heavy Crude Oils Fosterton 3.26 0.2 Lloydminster Blend 3.56 0.82 Lloydminster Kerrobert 3.12 0.92 Western Canadian Select 3.51 0.94 Diluted Bitumen Blends Albian Heavy Synthetic 2.5 0.57 Access Western Blend 3.93 1.72 Black Rock Seal Heavy 4.32 1.72 Cold Lake 3.75 0.99 Christina Lake 3.79 1.53 Peace River Heavy 5.02 2.5 Smiley–Coleville Heavy 2.97 0.98 Statoil Cheecham Blend 3.69 1.77 Surmount Heavy Blend Synbit 3.02 1.38 Western Canadian Blend 3.1 0.82 Source: TAN data obtained from CrudeMonitor.com by Crude Quality, Inc. (http:// www.crudemonitor.ca/condensate.php?acr=SLD; http://www.crudemonitor.ca/ crude.php?acr=SYN). Sulfur data obtained from Enbridge (http://www.enbridge.com/ DeliveringEnergy/Shippers/~/media/www/Site%20Documents/Delivering%20Energy/ 2012CrudeCharaceristics.ashx). Accessed March 1, 2013. temperatures above 300°C (570°F), they are not corrosive to steels at pipeline temperatures (Nesic et al. 2012). This distinction is discussed further in Chapter 5. The Canadian heavy crude oils and diluted bitumen contain 2.5 to 5 percent sulfur by weight. Whereas condensate and synthetic crude oils are largely free of sulfur (as shown in Table 3-2), natural bitumen 

Bitumen Properties, Production, and Transportation by Pipeline 45 H2S ppmw 450 400 350 300 250 = Diluted bitumen 200 = Other crude oils 150 100 50 0 650 700 750 800 850 900 950 1000 Density (kg/m3 @ 15°C) FIGURE 3-9 H2S content of diluted bitumen and other crude oils. Note: H2S is measured in liquid phase by using ASTM Test Method 5263. H2S remains in a liquid state in pipelines because the partial pressures of operating pipelines are below the bubble point. Source: Data submitted to the committee on November 13, 2012, by the Pipeline Sour Service Project Group of CCQTA. contains 4 to 6 percent sulfur. As described earlier, most of the sulfur in bitumen is bound in stable hydrocarbon structures. Sulfur levels in the 2.5 to 5 percent range, as found in processed bitumen diluted for transportation, are high for light- and medium-density crude oils but not unusual for heavy crude oils. While high sulfur content in crude oil is generally undesirable for refining, it is problematic for transmission pipelines mainly if it exists in surface-active compounds and hydrogen sulfide (H2S). H2S is a weak acid that is corrosive to pipelines for reasons explained in Chapter 5. Available test data on the H2S content in crude oil indicate lower levels in diluted bitumen (less than 25 ppmw in liquid phase) than in other crude oils of various densities (Figure 3-9). Shipment Properties and Operating Parameters Reported by Operators For additional data on the transport properties of diluted bitumen, the committee prepared a questionnaire for the Canadian Energy Pipeline 

46 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines Association (CEPA). CEPA distributed the questionnaire to member companies that regularly transport diluted bitumen by transmission pipeline. The questionnaire and responses from five Canadian operators are provided in Appendix A. A summary of the operator responses on the properties of diluted bitumen is provided in Table 3-7. All of the reported values for BS&W, H2S, sulfur, density, TAN, and operating temperature are within the ranges provided in the preceding tables and figures. With respect to the pipeline flow regime, the surveyed pipeline opera- tors reported average flow velocities of 0.75 to 2.5 meters per second (2.5 to 6.7 feet per second) in transmission pipelines that mostly range in diameter from 20 to 42 inches but that include some mileage consisting of pipe having smaller (8 inches) and larger (up to 48 inches) diameters. Without knowledge of the pipe diameter associated with each reported flow velocity, the resulting flow cannot be verified as turbulent. In gen- eral, flow velocities ranging between 0.75 and 2.5 meters per second would be expected to maintain turbulent flow in pipelines ranging from 8 to 48 inches in diameter when they transport crude oils with the range TABLE 3-7 Properties and Operating Parameters of Diluted Bitumen Shipments Reported by Five Canadian Pipeline Operators Lowest and Highest Range of Reported Values in Reported Highest Reported Property or Parameter Averages Normal Ranges Extremes BS&W (volume percent) 0.18–0.35 0.05–0.40 0.50 H2S (ppmw) <0.50–6.77 <0.50–11.0 11.0 Sulfur (weight percent) 3.10–4.00 2.45–4.97 5.20 Density (API gravity) 19.8–22.1 19.0–23.3 23.3 TAN (mg KOH/g) 1.00–1.30 0.85–2.49 3.75 Operating temperature [°C (°F)] 10–27 (50–81) 4–43 (39–109) 50 (122) Flow rate (ft/s) 2.5–6.7 0.5–8.2 8.2 Pressure (psi) 430–930 43.5–1,440 1,440 Note: Operators reported that oxygen and carbon dioxide concentrations are not routinely measured in shipments of crude oil. See Appendix A for complete survey results. 

Bitumen Properties, Production, and Transportation by Pipeline 47 of viscosities (113 to 153 cSt at 20°C) reported for the diluted bitumen and other heavy crude oils shown in Table 3-4. The committee asked pipeline operators for information on the con- tent of oxygen and carbon dioxide in shipments because these dissolved gases can be an important factor in the corrosion of pipe steel, for reasons explained in Chapter 5. Pipeline operators do not routinely measure oxy- gen and carbon dioxide concentrations in crude oil shipments because of the difficulty associated with sampling and detecting these gases. Never- theless, the operators reported that because diluted bitumen and other crude oils enter the pipeline system deaerated, there should be no signifi- cant difference in the concentrations of oxygen and carbon dioxide gas in products transported in the same pipelines. Operators also reported that as a general matter they aggressively seek to limit avenues for air entry into the pipeline at all times, including periods of storage and blending and pumping operations. SUMMARY The bitumen imported into the United States is produced from Canadian oil sands. The bitumen is both mined or recovered in situ by using ther- mally assisted techniques. Because a large share of the bitumen deposits is too deep for mining, in situ recovery accounts for an increasing per- centage of production. Because mined bitumen does not generally have qualities suitable for pipeline transportation and refinery feed, it is pro- cessed in Canada into synthetic crude oil. Bitumen recovered through use of thermally assisted methods has water and sediment content that is sufficiently low for long-distance pipeline transportation. The bitu- men imported for refinery feed in the United States is recovered through in situ methods rather than mining. Like all forms of petroleum, Canadian bitumen is a by-product of decomposed organic materials and thus a mixture of many hydro­ carbons. The bitumen contains a large concentration of asphaltenes and other complex hydrocarbons that give bitumen its high density and viscosity. At ambient temperatures, bitumen does not flow and must be diluted for transportation by unheated pipelines. The diluents consist of light oils, including natural gas condensate and light synthetic crude oils. Although the diluents consist of low-molecular-weight hydro­carbons, 

48 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines diluted bitumen does not contain a higher percentage of these light hydrocarbons than do other crude oils. The dilution process yields a stable and fully mixed product for shipping by pipeline with density and viscosity levels in the range of other crude oils transported by pipeline in the United States. Shipments of diluted bitumen are transported at operating tem- peratures, flow rates, and pressure settings typical of crude oils with similar density and viscosity. Water and sediment content conforms to the Canadian tariff limits, which are more restrictive than those in U.S. pipeline tariffs. Solids in the sediment of diluted bitumen are comparable in quantity and size with solids in other crude oils transported by pipe- line. While the sulfur in diluted bitumen is at the high end of the range for crude oils, it is bound in stable hydrocarbon compounds and is not a source of corrosive hydrogen sulfide. Diluted bitumen has higher total acid content than many other crude oils because of relatively high con- centrations of high-molecular-weight organic acids that are not reactive at pipeline temperatures. REFERENCES Abbreviations API American Petroleum Institute CAPP Canadian Association of Petroleum Producers ERCB Energy Resources Conservation Board NEB National Energy Board USGS U.S. Geological Survey WEC World Energy Council API. 2013. Diluted Bitumen. March 20. http://www.api.org/~/media/Files/Oil-and- Natural-Gas/Oil_Sands/Diluted-Bitumen.ashx. CAPP. 2013. Technical Bulletin: Alberta Oil Sands Bitumen Valuation Methodology. Report 2013-9995 (updated monthly). Calgary, Alberta, Canada. http://www. capp.ca.getdoc.aspx?Docid=2213428DT=NTV. Cimino, R., S. Correra, A. del Bianco, and T. P. Lockhart. 1995. Solubility and Phase Behavior of Asphaltenes in Hydrocarbon Media. In Asphaltenes: Fundamentals and Applications (E. Y. Sheu and O. C. Mullins, eds.), Plenum Press, New York, pp. 97–130. 

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50 Effects of Diluted Bitumen on Crude Oil Transmission Pipelines Raicar, J., and R. M. Procter. 1984. Economic Consider­ations and Potential of Heavy Oil Supply from Lloydminster—Alberta, Canada. In Second UNITAR Inter­ national Conference on Heavy Crude and Tar Sands (R. F. Meyer, J. C. Wynn, and J. C. Olson, eds.), McGraw-Hill, New York, pp. 212–219. Saniere, A., I. Hénaut, and J. Argiller. 2004. Pipeline Transportation of Heavy Oils: A Strategic, Economic and Technological Challenge. Oil and Gas Science and Technology—Revue d’IFP Energies nouvelles, Vol. 59, No. 5, pp. 455–466. Schermer, W. E. M., P. M. J. Melein, and F. G. A. van den Berg. 2004. Simple Tech- niques for Evaluation of Crude Oil Compatibility. Petroleum Science and Tech­ nology, Vol. 22, Nos. 7–8, pp. 1045–1054. Strausz, O. P., and E. M. Lown. 2003. The Chemistry of Alberta Oil Sands, Bitumen, and Heavy Oils. Alberta Energy Research Institute, Calgary, Canada. Strausz, O. P., E. M. Lown, A. Morales-Izquierdo, N. Kazmi, D. S. Montgomery, J. D. Payzant, and J. Murgich. 2011. Chemical Composition of Athabasca Bitu- men: The Distillable Aromatic Fraction. Energy and Fuels, Vol. 25, No. 10, pp. 4552–4579. USGS. 2006. National Assessment of Oil and Gas Fact Sheet: Natural Bitumen Resources of the United States. Fact Sheet 2006-3133. U.S. Department of the Interior, Nov. WEC. 2010. 2010 Survey of Energy Resources. London. http://www.worldenergy.org/ documents/ser_2010_report_1.pdf.