Survey of Energy Resources 2007
Transportation and Upgrading
The transportation of the extra-heavy oil and bitumen outside the concession or lease requires that the oil be heated, or alternatively blended with diluents (naphtha, gas condensates, or light oils), to reduce viscosity, or the oil be upgraded on-site. The degree of upgrading depends on the quality of the extracted oil and the desired standard of the SCO, that is, the target API gravity and sulphur content. In many cases the specifications for the SCO will depend on the availability of merchant refinery capacity capable of accepting and profitably refining it, or specifications may depend on the requirements of a captive refinery. A captive refinery is one that is obligated because of ownership or contract to refine a particular producer's crude oil.
For light oil refinery feedstock, simple atmospheric/vacuum distillation processes might yield an acceptable slate of primary products that included high-value transportation fuels: gasoline, jet fuel, and diesel fuels. With simple distillation, the heavier the refinery feedstock oil, the lower the yield of high-value transportation fuels and the higher the percentage residuum yield. Refineries steeply discount the price they are willing to pay for the heavy oil feedstocks that have low yields of the high-value products.
The upgrading process of heavy oil and natural bitumen starts with atmospheric and vacuum distillation processes that recover the diluents for recycling to the field, and which also produce gas oil and residue. The gas oil can be treated with hydrogen to reduce sulphur and nitrogen (producing hydrogen sulphide and ammonia). The two options are hydrotreating (a catalytic reaction) and hydrocracking the gas oil (carried out under mild conditions). The typical options for treating the residue (often called resid conversion) are (1) solvent deasphalting applied as pretreatment of the residue for removal of asphaltic materials (Speight, 1991), (2) visbreaking, which is a mild thermal cracking operation used to reduce the viscosity of the residue, producing a low-grade gasoline, heavy gas oil distillates, and a residual tar, (3) coking, which is used to break the heaviest fractions of the residue into elemental carbon (coke) and lighter fractions, and (4) hydrocracking, which adds hydrogen as the residue is heated under high temperature and high pressures (high conversion), so that liquid yields are maximised under high conversion (Vartivarian and Andrawis, 2006). Hydrogen for hydrotreating and hydrocracking is either purchased or generated by passing natural gas over steam (steam-methane reforming process). Because the residue hydrocracking occurs under extremely high temperatures and pressures, investment costs for process equipment are much higher than for the other resid conversion processes (Speight, 1991).
Bitumen upgrading: Canada
The yield of upgraded oil (SCO) from natural bitumen, based on data from Alberta, varies with the technology employed, the consumption of the product for fuel in the upgrader, the extent of natural gas liquids recovery, and the degree of residue upgrading. The Suncor, Syncrude, and Albian Sands projects mine natural bitumen and extract the oil from the mined sand. The Suncor project uses delayed coking for a yield of 0.81 barrels of oil per barrel of natural bitumen input. The Syncrude project, which uses fluid coking combined with hydrocracking the gas oil fraction, has a yield of 0.85 barrels of oil per barrel of bitumen (Speight, 1990). The yield for the Albian Sands upgrading plant at Scotford, which applies hydrocracking to both the distillation gas oil and residue, is 0.9 (NEB, 2004).
As of 2005, about 60% of the crude bitumen produced in Alberta was converted into various grades of SCO. The remaining 40% was blended with diluents (light oils, gas condensates or natural gas liquids) and shipped to refiners having the capability to accept the heavy oil blend. The diluents account for 33% of the blend (NEB, 2006). New and expansion projects could increase bitumen production to 3 mb/d by 2015 (Alberta EUB, 2006). If such an expansion is realised, on-site upgrading could be attractive to both mining and in-situ projects, by eliminating the need for diluents for transportation. Their elimination would reduce the volume of diluents the industry needs and increase the effective capacity of product pipelines to refineries. The by-product coke from upgrading plants could provide a substitute for the natural gas used for steam generation for in-situ projects (Luhning, et al., 2002). The principal challenges are the additional capital cost required and the scale of the bitumen production project needed to take advantage of economies of scale at the upgrading facility.
Extra-heavy oil upgrading: Orinoco Oil Belt
Fig. 4-6 shows the upgrade plant capacities and product specifications for the four commercially-operating Orinoco extra-heavy oil production projects. Upgrading occurs before export because of the limited availability of light Venezuelan crude oils for blending and the location of the upgrading plants on the northeast coast of Venezuela. All of the plants recover and recycle diluents to their fields. Each also uses delayed coking to upgrade residue and hydrotreat the coking process by-product naphtha for removal of sulphur and nitrogen. The Sincor project produces a low-sulphur light SCO by hydrocracking the heavy gas oil generated from gasifying part of the coke from the coking process. The conversion efficiency of extra-heavy oil into synthetic crude varies from 87-95%. Although the light and low-sulphur synthetic oils are generally the easiest to market to refiners and command the highest prices, most of the lower-quality synthetic crude oil produced by the Petrozuata and Cerro Negro projects are transported to captive refineries in the US and Caribbean (Chang, 1998). The extracted extra-heavy oil and bitumen-diluent blends require similar upgrading processes, suggesting that upgrading costs will be comparable.