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Alberta’s crude oil reserves

Recovery factors achieved by improved recovery techniques indicate that crude oil reserves in Alberta’s bitumen sands are the largest on earth

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Article Summary
The Western Canada Sedimentary Basin (WCSB, see Figure 1) extends from the Williston Basin, which straddles the Canada-US border, north to the Mackenzie Basins, west to the Rocky Mountains and east to the edge of the Precambrian Shield.

The WCSB has long been considered gas-prone and large volumes of conventional gas have been shipped, mainly to eastern Canada and the western 
US, for more than 50 
years. Very recently1, the 
Alberta Energy Resources Conservation Board (ERCB), now the Alberta Energy Regulator (AER), along with the Alberta Geological Survey (AGS) estimated 3424 tcf (trillion cubic feet) of original gas in place and 59 billion barrels (bbl) of original natural gas liquids (NGLs) in place in just six of 15 Alberta tight shale and siltstone formations that were evaluated and are just starting to be developed.

Significant production of conventional oil, defined as crude light enough to be pipelined, lighter than ~20° API, started in the WCSB with the discovery of oil at Turner Valley in the 1930s, expanded greatly with discovery of the Leduc reef trend by Imperial Oil in 1947, and peaked at 1.4 million bbl/d in 1973.

Over 200 years ago, the first Europeans noted bitumen seeps along the banks of the Athabasca River in northern Alberta. The local people had long been using bitumen to waterproof canoes. Bitumen is crude with a specific gravity greater than fresh water (less than 10° API) and is a thick, semi-solid fluid at room temperature that does not flow at commercial rates to a wellbore under normal reservoir conditions.

Karl Clark, a scientist with the Alberta Research Council in the 1920s, pioneered experiments with a hot water flotation process. He mixed bitumen sand with hot water and aerated the resultant slurry which would then separate into a floating froth of bitumen and a clean layer of sand that settled to the bottom of the tank. The hot water flotation process was used to produce bitumen for roofing and road surfacing at a plant north of Fort McMurray. In 1936, Abasand Oils’ plant west of Fort McMurray produced diesel oil from the bitumen sands until it burned down in the 1940s. In 1962, the Government of Alberta announced a policy to provide for the orderly development of the bitumen sands and Suncor’s Great Canadian Oil Sands project came on stream in 1967 to become the world’s first large scale bitumen sands project.

Alberta’s bitumen sands
Shallow, bitumen saturated, unconsolidated sand and hard-rock carbonate reservoirs are now known to underlie 54 132 square miles of land in northern Alberta in the Alberta Basin portion of the WCSB (see Figure 2).

Depending on depth beneath the surface, raw bitumen is produced either by surface strip mining or by various in situ techniques using wells.

In the surface mineable area (see Figure 3), estimated at 1854 square miles, bitumen sands reservoirs are generally thick and high quality and lie less than about 250ft below the surface, allowing bitumen to be extracted economically by strip mining with recovery factors often exceeding 90%. In this method, vegetation is stripped, overburden is removed, bitumen sands are mined by excavation, and raw bitumen is separated from mined material using the hot water process. In the surrounding Shallow Thermal Area there is increased risk of high pressure steam and heated bitumen breakthrough to surface for in situ projects.

The raw bitumen is then either diluted with condensate to allow pipelining as dilbit (~20° API) or upgraded to synthetic crude oil (SCO or syncrude, ~30° API and higher) which can then either be pipelined or refined. Upgrading means removing carbon by decoking or adding hydrogen to carbon to produce a lighter product requiring some additional processing to produce a sweet syncrude that is more valuable and desirable as refinery feedstock.

The eight surface strip mining projects currently operating and under active development are CNRL Horizon, Suncor Fort Hills, Imperial/ExxonMobil Kearl, Shell Muskeg River, Shell Jackpine, Suncor, Syncrude, and Total Joslyn North. The just commissioned Kearl project and the in development Fort Hills project are the first surface strip mines without upgraders. Kearl is also the first to use a solvent process to separate bitumen from sand.

At greater depths, in situ recovery of bitumen is done using enhanced thermal recovery techniques of cyclic steam stimulation (CSS) or steam assisted gravity drainage (SAGD).

In CSS, the first in situ enhanced recovery method developed, high pressure steam is injected into a well for a period of months and then produced back from the same well for another period of months. The cycle is then repeated.

In SAGD, pairs of parallel horizontal wells, one about 15ft or 20ft above the other, are drilled from a pad. High pressure steam is continuously injected into the upper well to heat the reservoir and reduce the viscosity of the bitumen, allowing it to continuously drain into the lower horizontal wellbore for production. SAGD is currently the technique of choice for almost every in situ project under development. There are literally dozens of operational, under development, in approval, or planned in situ SAGD projects.

The Alberta Energy Resources Conservation Board (ERCB) forecasted2 bitumen production doubling to 3.8 million b/d from 2012 to 2022 with an ever increasing percentage of in situ production (see Figure 4).

A June 2013 forecast3 by the Canadian Association of Petroleum Producers (CAPP) forecasted 
the same increase by 2022 (see 
Figure 5).

Recovery factors
The first commercial SAGD project was initiated in 1996 at Foster Creek and achieved commercial production only in 2001. In situ thermal enhanced recovery technology for bitumen production is still at an early development stage — improvements in efficiency as measured by recovery factor will most assuredly continue to occur. Recovery factors measure how efficiently original oil in place (OOIP) is recovered by production technology.

In a 2006 presentation,4 Eddie Lui of Imperial Oil said that in the portion of the reservoir (net pay) being targeted by CSS, typical recovery rates are about 35-45%. This translates to a recovery rate 
of 25-30% of the entire bitumen bearing zone (gross pay). Net 
pay is reservoir thickness deemed to contribute to production of 
technically recoverable reserves. Gross pay measures the total 
thickness of reservoir containing any measurable quantities of 

Improvements in technology such as co-injection with air and chemical additives, use of solvents, inclined and horizontal drilling, and fracturing of the formation have been highly successful, improving CSS recovery factors to 40% of gross pay.5

Recovery factors for SAGD typically exceeding 50%6 and sometimes reaching 70-80%7 are well documented but are not yet adequately recognised by the ERCB.2

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