The Alberta Oil Sands of the Western Canadian Sedimentary Basin (WCSB) are the world’s largest conventional oil accumulation. The ‘oil sands’ consist of Cretaceous Mannville Group sandstone in three areas – Athabasca (930 Bbbl), Cold Lake (220 Bbbl), and Peace River (140 Bbbl), as well as undeveloped Devonian carbonate subcrop (380 Bbbl), totaling 1.7 Tbbl BIIP (bitumen initially in- place). Currently, oil sands produce 3.5+ MMbbl/d, and comprise the majority of Canadian output.
Oil sands are hosted by poorly-consolidated, fluvio-estuarine deposits of the Blue sky (Peace River), McMurray (Athabasca) and Clearwater (Cold Lake) Formations. These sands were deposited during a marine transgression of the Cretaceous Western Interior Seaway, which ultimately extended the length of the North American Continent, parallel to the present-day Rocky Mountains. Primary source rocks were the Mesozoic Exshaw and Nordegg Formations. Hydrocarbon migrated hundreds of km up dip to the northeast, along a regional sub-Cretaceous unconformity. In the Athabasca region, oil accumulated in a subtle anticline above a zone of evaporite dissolution. Fresh water incursion subsequently biodegraded oil to bitumen (API <= 10°). Thickest sands average 40 m, with 90+% net-to-gross, 30+% porosity, multi-Darcy permeability, and 80+% oil saturation. In the Athabasca region, oil sands range from0-400 m depth. Bitumen-impregnated sandstone outcrops occur along the Athabasca, Steep bank and Christina Rivers. In the Peace River and Cold Lake areas, reservoirs range from 400-600 m depth with no surface exposure. Bitumen deposits were well-known to Canadian First Nations, who described them to European fur trappers in the early 18th century.
Initially, high bitumen viscosities of 100,000+ cP precluded commercial development; early operations were limited to surface strip mining and separation of bitumen from sand. Great Canadian Oil Sands opened the first mine near Fort McMurray Alberta, in 1967. Currently, three operators (Suncor, Canadian Natural Resources, Imperial) produce 1.5 MMbbl/d from 9 mines. However, only 10% of BIIP can be mined commercially, in areas where overburden does not exceed 50 m. In the early 1980s, the Alberta government created an Underground Testing Facility (UTF) to pilot thermal Enhanced Oil Recovery (tEOR, aka ‘steam flood) applications for in-situ projects.
The first full-field steam flood project in the oil sands was Imperial Cold Lake, starting in 1975. Cold Lake is a phased development implementing Cyclic Steam Stimulation(CSS) – an alternating ‘huff-and-puff’ tEOR application that does not rely on inter-well communication. The more common tEOR configuration is Steam-Assisted Gravity Drainage (SAG-D), conceived at the UTF. SAG-D involves 1000 m horizontal producer/injector well pairs spaced at ~100 m intervals. Injectors are positioned parallel to and 5 m above producers. Artificial lift, infill drilling and extensive monitoring of steam conformance have enabled recovery factor of 60+% in many SAG-D projects. Operators Cenovus, Canadian Natural Resources, Suncor, Imperial, MEG Energy and others currently produce 1.6 MMbbl/d from tEOR projects (85% from SAG-D, and 15% from CSS). A key metric for tEOR performance is Steam-to-Oil Ratio; values below 3 are industry-standard. The largest SAG-D projects produce 200+ kbopd; SAG-D is best suited for amalgamated sands with high vertical permeability.
Where reservoir thickness is too thin for steam flood implementation, operators utilize heavy primary production with long lateral sand progressing cavity pumps. Canadian Natural Resources implement chemical EOR (polymer flood, for enhanced mobility ratio) at Pelican Lake.
Heavy oil is consumed domestically and exported to US markets by pipeline, as Western Canadian Select blend. Oil sands operators struggle with the perception of high carbon intensity. Shell Canada’s Quest project sequesters CO2 emitted from an upgrader near Edmonton.
U3 Explore Venezuela project team of local and international experts has collaborated on this and two other related studies published by U3 Explore. You can read more at:
- Comparison of the methods of the Enhanced Recovery of a heavy oil between the Huyapari block in Ayacucho area in Venezuela and Quifa-Rubiales field in Colombia
- Comparison of Venezuela’s Faja Petrolífera del Orinoco and the Alberta Oil Sands challenges in EOR method selection
U3 Explore geologic-engineering team is available for consulting or expert boards sessions using the results of this and other two studies in applying the best fitted EOR method in the producing fields of northern South America.
