Enhanced Oil Recovery In Canada: Success In Progress

Abstract

Abstract The oil industry in Canada has been in the forefront applying enhanced oil recovery technology. Fifty-one commercial projects were operating in 1987 in reservoirs producing light and medium** crude oil in Alberta. Several pilot projects are operating in Alberta. Saskatchewan and Ontario. This paper discusses enhanced oil recovery (EOR) in general and reviews the history of EOR application in Canadian reservoirs. The performance of several projects and the economic factors affecting EOR implementation are reviewed. Introduction Primary and secondary methods leave a substantial portion of oil unrecovered in the reservoir. Tertiary recovery, more often called enhanced oil recovery (EOR), can recover some of the oil left behind by secondary recovery methods. Field application of enhanced recovery in Canada dates from the North Pembina Cardium Unit hydrocarbon miscible pilot project in 1957–58. Fifty-one commercial projects are now operating, all of them hydrocarbon miscible floods in the Province of Alberta. Other EOR techniques are being or have been used in pilot tests, so far with limited or uncertain results. Is EOR successful? The performance and proliferation of projects affirms that additional oil is being recovered and that this additional oil recovery is economic. Oil Recovery Factors Affecting Oil Recovery Large volumes of oil will remain unrecovered after primary recovery, which uses the natural energy of the reservoir, fluid and rock expansion and water influx, to produce the oil. Recovery factors for primary recovery range from 0% to 50% of the oil originally in-place in the reservoir, averaging about 19%(1) for Alberta reservoirs. In some reservoirs, a portion of the oil not recoverable using primary recovery can be produced with secondary recovery methods, which involve adding energy to the reservoir to maintain the pressure by injecting a fluid, usually water or gas. Water injection is the most common secondary recovery method used to enhance oil recovery. Waterflood recovery factors range from 25% to 45% of the original oil-in-place (OOIP). For the waterfloods in Alberta, the average ultimate recovery factor is 32%(1). Approximately 20% of the total Alberta light and medium reserves will be recovered because of waterflooding. Water injection leaves oil in the reservoir as a residual saturation, trapped by capillary forces where the water has swept the reservoir, and at higher saturations where the injected water did not contact the oil. Waterflood displacement efficiency, or the portion of the original oil saturation that can be recovered from rock that is flooded by injected water, ranges from 40% to 70%. However, not all of the reservoir will be contacted by injected water. The water may be more mobile (less viscous) than the displaced oil, causing early water breakthrough and poor areal sweep. The water may be more dense than the oil and may tend to move to the bottom of the reservoir, reducing the vertical sweep. The combination of areal and vertical sweep efficiency is the volumetric sweep efficiency, which is the portion of the total reservoir volume that is contacted by injected water and which ranges from 20% to 90%.