When most people think about oil sands development, images of vast open-pit mining operations and huge tailings ponds come to mind. However, only 18% of Alberta's oil sands deposits are shallow enough to mine from the surface. Of the 91 active oil sands projects in Alberta, five are mining projects and 86 are in situ projects.[i] The large majority of oil sands in Alberta must be developed in place via extraction wells, and this is referred to as "in situ" (meaning "in place") oil sands development. Water in in situ operations is converted to steam to heat and help "liquefy" deep bitumen bound in porous sedimentary deposits, so it can be pumped to the surface. Once it is at the surface, water is again used, as in surface mining, to process or upgrade bitumen into synthetic crude oil (SCO), which can be pumped via pipeline to distant plants for further processing into a variety of fuels and other petroleum products. As in situ operations roll out over approximately 140,000 square kilometers that contain oil sands deposits in northern and central Alberta, water use will continue to increase dramatically bitumen extraction.

The two most common in situ extraction processes are cyclic steam simulation (CSS) and steam-assisted gravity drainage (SAG-D). Both involve a high-density scattering of wells over an area the size of one or more townships and a network of underground pipes for steam injection and bitumen recovery. CSS requires a dense caprock that is able to withstand the high pressures created by steam injection and has been used in the Cold Lake and Peace River areas for more than 20 years.[ii] High-pressure steam is injected from the surface into the bitumen formations using a network of vertical and horizontal wells, and once it is warmed, the bitumen flows to and is pumped up through the same well bores. This cycle is continued until bitumen recovery is no longer economic.[iii] SAG-D is used where bitumen is too deep to mine and either too shallow for high-pressure CSS. Steam is continually injected into the ground via a network of wells and pipes, and as the bitumen is heated, it flows downward to a second network of collection pipes that are used to pump it to the surface. In both CSS and SAG-D, condensed steam that is recovered with the pumped out bitumen is recovered, treated, and reused, and this recycled water is referred to as "process water."

The average amount of water required for in situ oil sands extraction is 2.4:1 (water:bitumen recovered) for SAG-D and 3.6:1 for CSS (see Table 1). Because of recycling of process water by oil sands companies, the average amount of new water used per barrel of bitumen produced is lower: 0.39 barrels for SAG-D and 0.52 barrels for CSS. This amount of groundwater or surface water consumed to produce a barrel of bitumen has declined substantially over the last 25 years and is much lower than to produce a barrel of bitumen from surface mining operations (2.5 barrels of water). However, because the space that is filled by bitumen in underground rock formations must be filled by water as the bitumen is removed, the final ratio of water used to oil produced for in situ operations is 1:1.[iv] In addition to water demands for in situ extraction, upgrading of bitumen to usable petroleum products requires approximately 0.4-0.5 barrels of fresh water per barrel of SCO produced, for steam generation, cooling, and as a hydrogen source for sulfur removal.[v] Therefore, total water use for production of SCO from in situ operations likely averages 1.4-1.5 barrels per barrel of oil, although where bitumen is exported as is, it will be approximately 1 barrel per barrel of bitumen.

According to a recent draft directive of the Energy Resources Conservation Board (ERCB), in situ operators will have to minimize their use of fresh water and evaluate alternative sources "where possible," and large operators are directed to recycle their water used so that a maximum of 10% of annual water used can be freshwater. However, during the first 12 months of steam injection, fresh water use limits will not be enforced and an extension of this period may be granted.[vi]  Ideally, in situ oil sands operations would use saline or brackish groundwater, as opposed to surface freshwaters from nearby lakes or rivers or groundwater from freshwater aquifers. This also appears to be the purpose and priority of the ERCB draft directive for in situ water use. However, while industry and government appear to promote a general concern for the environment and a commitment to reduce freshwater use in oil sands operations, a recent application by an in situ oil sands operator to change its source of water from the originally proposed saline groundwater to freshwater from the Clearwater River — a National Heritage River - was based simply on costs and waste management concerns. [See our previous article for more detail.]

In 2009, annual in situ freshwater consumption was 16 million m³. While it can be expected that in situ oil sands operations will become even more efficient, it is still projected that total freshwater use may almost triple to 45 million m³ by 2020, when in situ operations are projected to produce up to 40% of Canada's crude oil.[vii] While in situ oil sands operations are more efficient in terms of water use than mining operations, without a clear understanding of groundwater and surface water dynamics, Alberta will continue to basically operate in the dark in terms of the effects of oil sands development and upgrading on surface- and groundwaters. For this reason, Alberta must develop land-use management plans and water management frameworks for all of the basins in which in situ development is anticipated before issuing development approvals. Otherwise, we will be forced to continue to play "catch-up" with problems of over-allocation of waters, pollution controls and effects, and negative publicity both here and abroad.

Sources

[i] AMEC Earth & Environmental, Water for Life: Current and Future Water Use in Alberta, (Edmonton, AB: AMEC Earth & Environment, prepared for Alberta Environment, 2007) p. 594; Government of Alberta, Alberta's Oil Sands.

[ii] Griffiths, M., A. Taylor, and D. Woynillowicz. 2006. Troubled Waters, Troubling Trends: Technology and Policy Options to Reduce Water Use in Oil and Oil Sands Development in Alberta. (Pembina Institute for Appropriate Development), p. 36.

[iii] Ultimate expected recovery of bitumen from CSS operations is 20-35% of total bitumen, and for SAG-D operations it is 40-70%; Alberta Chamber of Resources, Oil Sands Technology Roadmap: Unlocking the Potential (2004), http://www.acr-alberta.com/Portals/0/projects/OSTR_report.pdf.

[iv] Griffiths, supra note ii, Table 3-1.

[v]  Griffiths, supra note ii at p. 40.

[vi] ERCB. 2009. Requirements for Water Measurement, Reporting, and Use for Thermal In Situ Oil Sands Schemes Draft Directive. CAPP, ibid.

[vii] Canadian Association of Petroleum Producers. 2009. Water Use in Canada's Oil Sands. Document 2009-0022.