Higher prices for crude oil and refined petroleum products are opening the door for nonconventional liquids to displace petroleum in the traditional fuel supply mix. Growing world demand for diesel fuel is helping to jump-start the trend toward increasing production of nonconventional liquids, and technological advances are making the nonconventional alternatives more viable commercially. Those trends are reflected in the AEO2006 projections. 

In the reference case, based on projections for the United States and project announcements covering other world regions through 2030, the supply of syncrude, synthetic fuels, and liquids produced from renewable fuels approaches 10 million barrels per day worldwide in 2030. In the high price case, nonconventional liquids represent 16 percent of total world oil supply in 2030, at more than 16.4 million barrels per day. The U.S. share of world nonconventional liquids production in 2030 is 15 percent in the reference case and nearly 20 percent in the high price case (Table 14). 

The term “nonconventional liquids” applies to three different product types: syncrude derived from the bitumen in oil sands, from extra-heavy oil, or from oil shales; synthetic fuels created from coal, natural gas, or biomass feedstocks; and renewable fuels—primarily, ethanol and biodiesel—produced from a variety of renewable feedstocks. Generally, these resources are economically competitive only when oil prices reach relatively high levels. 

Synthetic Crude Oils 

At present, two nonconventional oil resources—bitumens (oil sands) and extra-heavy crude oils—are actively being developed and produced. With technology innovations ongoing and production costs declining steadily, their production increases in the AEO2006 projections, provided that the world oil price remains above $30 per barrel. Development of a third nonconventional resource, shale oil, is more speculative. The greatest risks facing syncrude production are higher production costs and lower crude oil prices. In AEO2006, production of syncrude worldwide increases to 5.3 million barrels per day in the reference case and 8.5 million barrels per day in the high price case in 2030. 

Oil sands. Bitumen, the “oil” in oil sands, is composed of carbon-rich, hydrogen-poor long-chain molecules. Its API gravity is less than 10, and its viscosity is so high that it does not flow in a reservoir. It can contain undesirable quantities of nitrogen, sulfur, and heavy metals. 

The percentage of bitumen in oil sands deposits ranges from 1 to 20 percent [49]. After the bitumen is extracted from the sand matrix, various processes, including coking, distillation, catalytic conversion, and hydrotreating, must be applied to create syncrude. On average, about 1.16 barrels of bitumen is required to produce 1 barrel of syncrude. Canada’s resource of 2.5 trillion barrels of in-place bitumen is estimated to be 81 percent of the world total [50]. Economically recoverable deposits in Canada amount to about 315 billion barrels of bitumen under current economic and technological conditions [51], and in 2004 Canada shipped more than 87 million barrels of light, sweet syncrude [52]. If fully developed, the bitumen resources in Canada could supply more than 40 years of U.S. oil consumption at current demand levels. 

Currently, there are two methods for extracting bitumen from oil sands: open-pit mining and in situ recovery. For deposits near the surface, open-pit mining is used to extract the bitumen by physically separating it from the sand and clay matrix, at recovery rates approaching 95 percent. For deposits deeper than 225 feet, the in situ process is used. Two wells are drilled, one of which is used to inject steam into the deposit to heat the sand and lower the viscosity of the bitumen and the other to collect the flowing bitumen and bring it to the surface. Addition of gas condensate, light crude, or natural gas can also reduce viscosity and allow the bitumen to flow. Much of today’s production comes from open-pit mining operations; however, 80 percent of the Canadian oil sands reserves are too deep for open-pit mining. 

According to most analysts, oil sands syncrude production is economically viable, covering fixed and variable costs, only when syncrude prices exceed $30 per barrel. The variable costs of producing syncrude have declined to around $5 per barrel today, from estimates of $10 per barrel in the late 1990s and $22 per barrel in the 1980s. 

Syncrude tends to yield poor quality distillate and gas-oil products owing to its low hydrogen content. Refineries processing oil sands syncrude need more sophisticated conversion capacity including catalytic cracking, hydrocracking, and coking to create higher quality fuels suitable for transportation markets. 

Extra-heavy oil. Extra-heavy oil is crude oil with API gravity less than 10 and viscosity greater than 10,000 centipoise. Unlike bitumen, extra-heavy oil will flow in reservoirs, albeit much more slowly than ordinary crude oils. Extra-heavy oil deposits are located in at least 30 countries. One singularly large deposit, representing the majority of the known extra-heavy oil resource is located in the Orinoco oil belt of eastern Venezuela. Petroleos de Venezuela SA (PDVSA) estimates that 1.36 trillion barrels of extra-heavy oil are in place in the Orinoco belt, with an estimated 270 billion barrels of currently recoverable reserves. 

There are three main recovery methods: cyclic steam injection/steam flood; diluents and gas lift; and steam-assisted gravity drainage (SAGD) using stacked horizontal wells. Other methods substitute CO₂ for natural gas injection or solvents for steam injection. The Orinoco projects currently use a two-step upgrading process, partially upgrading the bitumen in the field, followed by deep conversion refining in the importing country. 

Extra-heavy oil recovery rates currently range from 5 to 10 percent of oil in place, although R&D efforts are steadily and significantly improving the performance. Lifting and processing costs range from $8 to $11 per barrel (2004 dollars) [53]. According to the latest PDVSA filings with the U.S. Securities and Exchange Commission, production of extra-heavy crude oil from the Orinoco area totaled 430,000 barrels per day in 2003 [54]. 

It is not clear that PDVSA can continue to provide the massive capital investment necessary to sustain the growth of its extra-heavy oil production in the future. Relationships with possible foreign investors have been strained due to actions by the Venezuelan government to renegotiate existing contracts and to structure new ones so as to sharply reduce potential returns to investors. In addition, the recent deterioration of political relations between Venezuela and the United States could limit the market for Orinoco-produced extra-heavy crude oils. 

Shale oil. The term “oil shale” is something of a misnomer. First, the rock involved is not a shale; it is a calcareous mudstone known as marlstone. Second, the marlstone does not contain crude oil but instead contains an organic material, kerogen, that is a primitive precursor of crude oil. When oil shale is heated at moderate to high temperatures for a sufficient period of time, kerogen can be cracked to smaller organic molecules like those typically found in crude oils and then converted to a vapor phase that can be separated by boiling point and processed into a variety of liquid fuels in a distillation process. The synthetic liquid distilled from oil shale is commonly known as shale oil. Oil shale has also been burned directly as a solid fuel, like coal, for electricity generation. 

The global resource of oil shale base is huge—estimated at a minimum of 2.9 trillion barrels of recoverable oil [55], including 750 billion barrels in the United States, mostly in Utah, Wyoming, and Colorado [56]. Deposits that yield greater than 25 gallons per ton are the most likely to be economically viable [57]. Based on an estimated yield of 25 gallons of syncrude from 1 ton of oil shale, the U.S. resource, if fully developed, could supply more than 100 years of U.S. oil consumption at current demand levels. 

There are two principal methods for oil shale extraction: underground mining and in situ recovery. Underground mining, followed by surface retorting, is the primary approach used by petroleum companies in demonstration plants built in the mid to late 1970s. In this approach, oil shale is mined from the ground and then transferred to a processing facility, where the kerogen is heated in a retort (a large, cylindrical furnace) to around 900 degrees Fahrenheit and enriched with hydrogen to release hydrocarbon vapors that are then condensed to a liquid. There is some risk that, despite its apparent promise, the underground mining/surface retorting technology ultimately will not be viable, because of its potentially adverse environmental impacts associated with waste rock disposal and the large volumes of water required for remediation of waste disposal piles. 

A comprehensive in situ process is currently under experimental development by Shell Oil [58]. Shale rock is heated to 650-750 degrees Fahrenheit, causing water in the shale to turn into steam that “microfractures” the formation. The in situ process generates a greater yield from a smaller land surface area at a lower cost than open-pit mining. The technology also avoids several adverse issues connected to mining and waste rock remediation, minimizes water usage, and has the potential to recover at least 10 times more oil per acre than the conventional surface mining and retorting process; however, it could take as long as 15 years to demonstrate the commercial viability of the Shell in situ process. 

For a conventional mining and retorting process, $55 to $70 per barrel (2004 dollars) is the estimated breakeven price. That estimate is based in part on technical literature from the late 1970s and early 1980s, however, and thus may no longer be relevant today. The older estimates are likely to understate the cost of waste rock remediation. Advances in equipment technology over the years could increase operating efficiencies and reduce costs. A 1 million barrel per day shale oil industry based on underground mining/surface retorting would require mining and remediation of more than 500 million tons of oil shale rock per year—about one-half of the annual tonnage of domestic coal production. The process would also consume approximately 3 million barrels of water per day [59]. 

A 2005 industry study prepared for the National Energy Technology Laboratory estimates that crude oil prices (WTI basis) would need to be in the range of $70 to $95 per barrel for a first-of-kind shale oil operation to be profitable [60] but could drop to between $35 and $48 per barrel within a dozen years as a result of experience-based learning (“learning-by-doing”). In the AEO2006 high price case, assuming the use of underground mining with surface retorting, U.S. oil shale production begins in 2019 and grows to 410,000 barrels per day in 2030. 

Synthetic Fuels 

Synfuels can be produced from coal, natural gas, or biomass feedstocks through chemical conversion into syncrude and/or synthetic liquid products. Huge industrial facilities gasify the feedstocks to produce synthesis gas (carbon monoxide and hydrogen) as an initial step. Synfuel plants commonly employ the Fischer-Tropsch process, with front-end processing facilities that vary, depending on the feedstock. The manufacturing process for the synthetic fuels typically bypasses the traditional oil refining system, creating fuels that can go directly to final markets. A simplified flow diagram of the synthetic fuels process is shown in Figure 19. 

In the basic Fischer-Tropsch reaction, syngas is fed to a reactor where it is converted to a paraffin wax, which in turn is hydrocracked to produce hydrocarbons of various chain lengths. End products are determined by catalyst selectivity and reaction conditions, and product yields are adjustable within ranges, depending on reaction severity and catalyst selection. Potential products include naphtha, kerosene, diesel, methanol, dimethyl ether, alcohols, wax, and lube oil stock. A product workup section separates the liquids and completes the transformation into final products. The diesel fuel produced (“Fischer-Tropsch diesel”) is limited by a lack of natural lubricity, which can be remedied by additives [61]. Water and CO₂ are typically produced as byproducts of the process. 

Coal-to-Liquids. A CTL plant transforms coal into liquid fuels. CTL is economically competitive at an oil price in the low to mid-$40 per barrel range and a coal cost in the range of $1 to $2 per million Btu, depending on coal quality and location. 

A CTL plant requires several decades of coal reserves to justify construction. Given the economies of scale required, 30,000 barrels per day is regarded as a minimum plant size. Coal reserves of approximately 2 to 4 billion tons are required to support a commercial CTL plant with a capacity of 70,000 to 80,000 barrels per day over its useful life [62]. Capital expenses are estimated to be in the range of $50,000 to $70,000 (2004 dollars) per barrel of daily capacity. The front-end (coal handling) portion of a CTL plant accounts for about one-half of the capital cost [63]. 

There are two leading technologies for converting coal into transportation fuels and liquids. The original process, indirect coal liquefaction (ICL), gasifies coal to produce a syngas and rebuilds small molecules in the Fischer-Tropsch process to produce the desired fuels. Direct coal liquefaction (DCL) breaks the coal down to maximize the proportion of compounds with the correct molecular size for liquid products. The process reacts coal molecules with hydrogen under high temperatures and pressures to produce a syncrude that can be refined into products. The conversion efficiency of DCL is greater than that of ICL and requires higher quality coal; however, DCL currently exists only in the laboratory and at pilot plant scale. China’s first two CTL plants, which will use the DCL process, are slated to be operational after 2008 [64]. 

When combined with related processes such as CHP or IGCC, CTL can be considered a byproduct, with Fischer-Tropsch added as a part of a poly-generation configuration (steam, electricity, chemicals, and fuels). Revenues from the sale of electricity and/or steam can significantly offset CTL production costs [65]. Prospects for CTL production could be constrained, however, by plant siting issues that include waste disposal, water supply, and wastewater treatment and disposal. Water-cooling limitations can be overcome through the use of air-cooling, although it adds to the cost of production. CTL requires water for the front-end steps of coal preparation, and processing of coal with excessive moisture content can also produce contaminated water that requires disposal. These issues are similar to those associated with typical coal-fired power plants. 

AEO2006 projects 800,000 barrels per day of domestic CTL production in the reference case and 1.7 million barrels per day in the high price case in 2030. Most of this activity initially occurs in coal-producing regions of the Midwest. Worldwide CTL production in 2030 totals 1.8 million barrels per day in the reference case and 2.3 million barrels per day in the high price case. 

Gas-to-Liquids. GTL is the chemical conversion of natural gas into a slate of petroleum fuels. The process begins with the reaction of natural gas with air (or oxygen) in a reformer to produce syngas, which is fed into the Fischer-Tropsch reactor in the presence of a catalyst, producing a paraffin wax that is hydrocracked to products. A product workup section then separates out the individual products. Distillate is the primary product, ranging from 50 percent to 70 percent of the total yield. 

Given the significant capital costs of a GTL plant, natural gas reserves of 4 to 5 trillion cubic feet are required to provide a feedstock supply of 500 to 600 million cubic feet per day over 25 years to support a plant with nominal capacity of 75,000 barrels per day. GTL competes with LNG for reserves of inexpensive, stranded natural gas located in scattered world regions. Stranded natural gas lies far from markets and would otherwise require major pipeline investments to commercialize. One processing advantage for GTL plants is that they can use natural gas with high CO₂ content as a feedstock and can target smaller fields than are required for LNG production. Competition between GTL and LNG plants for the world’s stranded natural gas supplies is not a limiting issue, however. All the GTL and LNG plants envisioned between now and 2030 would tap less than 15 percent of the total world supply of stranded natural gas. 

Capital costs for GTL plants range from $25,000 to $45,000 (2004 dollars) per barrel of daily capacity, depending on production scale and site selection. Those costs have dropped significantly, however, from more than $100,000 per barrel of total installed capacity for the earliest plants. Opportunities to further lower the capital costs include reducing the size of air separation units, syngas reformers, and Fischer-Tropsch reactors. Another opportunity lies in reducing cobalt and precious metals content in catalysts. An industry goal is to reduce GTL capital costs below $20,000 per barrel, but recent increases in steel prices and process equipment are making the goal more elusive. By comparison, the cost of a conventional petroleum refinery is around $15,000 per barrel per day. In terms of engineering and construction metrics, a GTL facility with a capacity of 34,000 barrels per day is roughly equivalent to a grassroots refinery with a capacity of 100,000 barrels per day [66]. 

GTL is profitable when crude oil prices exceed $25 per barrel and natural gas prices are in the range of $0.50 to $1.00 per million Btu. The economics of GTL are extremely sensitive to the cost of natural gas feedstocks. As in the case of LNG, the presence of natural gas liquids (NGL) in the feedstock stream can augment total producer revenues, reducing the effective cost of the natural gas input. In addition, the GTL process is exothermic, generating excess heat that can be used to produce electricity, steam, or desalinated water and further enhance revenue streams. 

The technologies used for GTL are similar to those that have been employed for decades in methanol and ammonia plants, and most are relatively mature; however, the suite of integrated GTL technologies has not been used on a commercial scale. One looming uncertainty with regard to GTL is whether a proven pilot plant can be scaled up to the size of a commercial plant while reducing capital and operating costs. A key engineering goal is to improve the thermal efficiency of the GTL process, which is more complex than either LNG liquefaction or petroleum refining. 

The leading GTL processes include those developed by Shell, Sasol, Exxon, Rentech, and Syntroleum. At this time, there is no indication as to which technology will prevail. Currently, the proponents of these various processes have nearly 800,000 barrels per day of first generation capacity under development in Qatar. 

AEO2006 projects domestic GTL production originating in Alaska, reflecting a longstanding proposal to monetize stranded natural gas on the North Slope. GTL liquids would be transported to the lower 48 refining system. In 2030, domestic GTL production totals 200,000 barrels per day in the high price case, even though it competes directly with the Alaska natural gas pipeline project. In AEO2006, both investments are feasible simultaneously. What will actually occur depends on how and where Alaska natural gas stakeholders ultimately decide to make their investments. GTL production worldwide exceeds 1.1 million barrels per day in the reference case and 2.6 million barrels per day in the high price case in 2030. 

Biomass-to-Liquids. BTL encompasses the production of fuels from waste wood and other non-food plant sources, in contrast to conventional biodiesel production, which is based primarily on food-related crops. Because BTL does not ordinarily use food-related crops, it does not conflict with increasing food demands, although crops grown for BTL feedstocks would compete with food crops for land. 

BTL gasification technology is based on the CTL process. The resulting syngas is similar, but the distribution of the hydrocarbon components differs. BTL uses lower temperatures and pressures than CTL. Like GTL, the BTL reaction is exothermic and requires a catalyst [67]. There are at least 13 known processes covering directly and indirectly heated gasifiers for this step. 

BTL originates from renewable sources, including wood waste, straw, grain waste, crop waste, garbage, and sewage/sludge. According to a leading process developer, 5 tons of biomass yields 1 ton of BTL [68]. One hectare (2.471 acres) of land generates 4 tons of BTL. A modestly sized BTL plant under sustained operation would require the biomass of slightly more than 12,000 acres [69]. Unlike biodiesel or ethanol, BTL uses the entire plant and, thereby, requires less land use. 

BTL fuels are several times more expensive to produce than gasoline or diesel. Without taxes and distribution expenses, a leading European developer estimates BTL production costs approaching $3.35 per gallon by 2007 and falling to $2.43 per gallon by 2020 [70]. This equates to a crude oil equivalent price in the high $80 per barrel range at current capital cost levels. 

BTL technology is at the pilot-plant stage of development. The capital cost of a commercial-scale BTL plant could approach $140,000 (2004 dollars) per barrel of capacity, according to a study conducted for DOE by Bechtel in 1998 [71]. The estimated initial investment level is comparable with those for early CTL and GTL plants, which have since declined by 50 percent or more. Technological innovations over time and economies of scale could further reduce BTL costs. The first commercial-scale BTL plant, with a capacity just over 4,000 barrels per day. is planned to begin operation in Germany after 2008, followed by four additional facilities. About two-thirds of a BTL plant’s capital cost is related to biomass handling and gasification. BTL front-end technology is new and evolving and has parallels with cellulose ethanol technology. 

Large BTL plants require huge catchment (staging) areas and incur high transportation costs to move feedstocks to a central plant. From a process standpoint, the main challenge for BTL is the high cost of removing oxygen. It is unclear whether gasification and other processing steps can achieve the cost reductions necessary to make it more competitive. Catalyst costs are high, as they are for other Fischer-Tropsch processes. Without additional technological advances to lower costs, BTL could be limited to the production of fuel extenders rather than primary fuels. 

Renewable Biofuels 

Not to be confused with BTLs are the renewable biofuels, ethanol and biodiesel. These fuels can be blended with conventional fuels, which enhances their commercial attractiveness. Biofuels have high production costs and are about 2 to 3 times more expensive than conventional fuels. Renewable biofuel technology is relatively mature for corn-based ethanol production, and future innovations are not expected to bring its costs down substantially. Future cost reductions are likely to be achieved by increasing production scale and implementing incremental process optimizations. Energy is a significant component of operating costs, followed by catalysts, chemicals, and labor. Production costs are highly localized. 

The greatest challenge facing biofuels production is to secure sufficient raw material feedstock for conversion into finished fuels. Production of biofuels requires significant land use dedicated to the growth of feedstock crops, and land prices could represent a significant constraint. 

Ethanol. Ethanol, the most widely used renewable biofuel, can be produced from any feedstock that contains plentiful natural sugars. Popular feedstocks include sugar beets (Europe), sugar cane (Brazil), and corn (United States). Ethanol is produced by fermenting sugars with yeast enzymes that convert glucose to ethanol. Crops are processed to remove sugar (by crushing, soaking, and/or chemical treatment), the sugar is fermented to alcohol using yeasts and microbes, and the resulting mix is distilled to obtain anhydrous ethanol. 

There are two ethanol production technologies: sugar fermentation and cellulose conversion. Sugar fermentation is a mature technology, whereas cellulose conversion is new and still under development. Cellulose-to-biofuel (bioethanol) can use a variety of feedstocks, such as forest waste, grasses, and solid municipal waste, to produce synthetic fuel. 

Capital costs for a corn-based ethanol plant can range from $21,000 to $33,000 (2004 dollars) per barrel of capacity, depending on size [72]. Manufacturing costs can be as low as $0.75 per gallon, as demonstrated by the low-cost production in Brazil, where climate conditions are favorable and labor costs are low. One industry risk is drought, which can limit the availability of feedstocks. Another issue is competition with the food supply. Based on current land use, industry trade sources estimate that annual corn ethanol production in the United States is limited to approximately 12 billion gallons to avoid disrupting food markets. 

AEO2006 projects 700,000 barrels per day of ethanol production in 2030 in the reference case, representing about 47 percent of world production. The high price case projects production of 900,000 barrels per day in 2030, representing 30 percent of the world total. Worldwide, ethanol production (including biodiesel) in 2030 totals nearly 1.7 million barrels per day in the reference case and 3 million barrels per day in the high price case. 

Biodiesel. Biodiesel is produced from a variety of feedstocks, including soybean oil (United States), palm oil (Malaysia), and rapeseed and sunflower oil (Europe). The technology is mature and proven. In general, the feedstock for biodiesel undergoes an esterification process, which removes glycerin and allows the oil to perform like traditional diesel. Although biodiesel has been produced and used in stationary applications (heat and power generation) for nearly a century, its use as a transportation fuel is recent. Today it is used primarily as an additive to “stretch” conventional diesel supplies, rather than as a standalone primary fuel. One technical limitation of biodiesel is its blend instability and tendency to form insoluble matter. In the United States, those limitations are further aggravated by the introduction of new ULSD into the national fuel supply [73]. 

Capital costs for biodiesel production facilities are similar to those for ethanol facilities, ranging from $9,800 to $29,000 (2004 dollars) per daily barrel of capacity, depending on size [74, 75]. Feedstocks for biodiesel, which can be expensive, include inedible tallow ($41 per barrel), jatropha oil ($43 per barrel), palm oil ($46 per barrel), soybean oil ($73 per barrel), and rapeseed oil ($78 per barrel) [76]. On a gasoline-equivalent basis, production costs in the United States range from 80 cents per gallon for biodiesel from waste grease to $1.14 per gallon for biodiesel from soybeans oil. U.S. biodiesel production totals 20,000 barrels per day in 2030 in the AEO2006 reference case and 30,000 barrels per day in the high price case.

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Notes and Sources

Contact: Philip Budzik
Phone: 202-586-2847
E-mail: philip.budzik@eia.doe.gov