The oil sands deposits of northern Alberta, Canada are estimated to contain about 142 billion cubic meters (or 890 billion barrels) of bitumen, constituting the largest oil sands deposit in the world. In the Athabasca region of Alberta, oil sands deposits are typically composed of about 12% bitumen (by weight), 82% to 85% mineral matter (solids), and 3% to 6% water. The fraction of solids smaller than 45 micron size (silt and clay) is referred to as fines. The clay fraction of the fines plays an important role in both extraction of bitumen and disposal of oil sands tailings. Since the 1960s, bitumen recovered from northern Alberta oil sands deposits has been upgraded to make synthetic crude oil at production rates as high as one million barrels per day.
Bitumen is commonly recovered from the surface-mined oil sands ore using water-slurry-based extraction processes. Liberated bitumen has to be recovered from the oil sands ore-water slurry by some kind of separation method based on density differences. Bitumen density is very close to the density of water; as a result, bitumen has to become attached to air bubbles to facilitate its recovery from the slurry system by flotation. Clay particles attached to bitumen droplets prevent interaction between bitumen and air bubbles. Attachment of clay particles to bitumen is promoted by the calcium, Ca2+ and magnesium, Mg2+ ions present in the process water. Also, temperature of the oil sands ore-water slurry has to be above a critical temperature, above which bitumen becomes mobile enough (sufficiently low viscosity) to enfold or become attached to air bubbles. This critical temperature for Athabasca bitumen has been reported by several researchers to be at around 32° C. In summary, liberation of bitumen from the oil sands matrix and attachment of air bubbles to bitumen are essential process steps for bitumen recovery in water slurry-based extraction processes.
Asphaltic acids—which are fractions of bitumen asphaltenes present in bitumen and which contain partly aromatic, oxygen-functional groups such as phenolic, carboxylic, and sulfonic types—become water-soluble, especially when the ore-water slurry's pH (i.e., acidity expressed as the minus logarithm of the hydrogen ion concentration: pH=−log [H+]) is over 7, and act as surfactants reducing surface and interfacial tensions. The reduction of surface and interfacial tensions in an oil sands ore-water slurry system causes disintegration of the ore structure and resultant liberation of bitumen from the ore. Therefore, the hydrophilic fractions of bitumen asphaltenes in oil sands play an important role in the recovery of bitumen from mined oil sands ore using slurry-based extraction systems.
The water-soluble fraction of bitumen, which acts as a surfactant, can be increased by increasing the pH of the oil sands ore-water slurry by using caustic soda (NaOH); soda ash (Na2CO3); any salt of weak acid and strong base (hydrolysis of which would be basic); or lime (as CaO or Ca(OH)2), as described in Canadian Patent Application No. 2,581,586 (Ozum) and corresponding U.S. patent application Ser. No. 12/048,430 (which said U.S. application is incorporated herein by reference in its entirety). The water-soluble fraction of bitumen can also be increased by modifying asphaltene molecules contained in bitumen by oxidation, sulfonation, and/or sulfoxidation reactions to water soluble surfactants, which reduce surface and interfacial tensions, as described in International Application No. PCT/CA2005/001875 (Ozum) and corresponding Canadian Patent Application No. 2,629,039 and U.S. patent application Ser. No. 11/720,782 (which said U.S. application is incorporated herein by reference in its entirety).
Recovery of bitumen from deep oil sands formations may be accomplished by well-known thermal methods such as underground bitumen combustion (i.e., in situ combustion, or ISC), or steam injection methods such as steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). In these methods, the thermal energy injected into deep oil sands formations reduces the bitumen's viscosity and increases its mobility within the reservoir. Steam produced as an ISC by-product, or steam injected into a subsurface oil sands seam, condenses due to thermal energy losses and forms bitumen-water emulsions, which may be recovered by means of production wells. Hydrophilic fractions also help to promote the formation of bitumen-water emulsions under in situ recovery conditions, since they act as surfactants reducing surface and interfacial tensions, thereby helping to break down the oil sands ore structure and promoting the release of bitumen from the ore.