The majority of Canadian heavy oil deposits cannot be exploited, after primary production, by thermal recovery as formations are thin or bottom water exists. Thermal processes' applications to these deposits, including the steam assisted gravity drainage process (SAGD), are not promising due to excessive heat losses to the surrounding formations. Solvent vapor extraction process (VAPEX) and other similar processes are faced with major problems, mainly reservoir depletion, existence of channels "wormholes" following primary production and high costs of new horizontal wells, facilities and solvent.

The proposed process is based on pressure cycling of depleted heavy oil reservoirs, It involves injection of natural gas with a specified concentration of vaporized propane into a number of wells for a period of time to pressurize the producing channels connected with injection wells and surrounding reservoir volume. After reaching a pressure target, injection is terminated and the blowdown phase is started. Production is continued until most of the effects of the injection phase are diminished, then the cycle is repeated for a number of times. The composition of the injected enriched gas is selected based on the expected reservoir pressure range during the pressurizing phase to achieve high solubility of propane in oil. The process involves relatively low injection rates and to be operated at low pressures and has the potential for low injectants' losses and effective oil recovery.

This paper reviews the proposed enriched gas pressure cycling process and discusses the various mechanisms controlling it. The process is effective if appropriate reservoir conditions can be achieved. The process appears to be a viable improved recovery method for depleted heavy oil reservoirs on a cost to benefit basis and is predicted to achieve reasonable incremental recovery dependent on the target application, process design and number of cycles. It has many attractive features. It is designed to utilize reservoir conditions created by primary recovery. It requires no new wells, utilizes existing wells, requires reasonable volumes of solvent, requires no water treating or major facilities and the associated risk with its application is minimal.


The observed primary production of many heavy oil reservoirs in Alberta and Saskatchewan such as Lindbergh, Frog Lake and many L10ydminister fields, has been significantly higher than predicted by Darcy fiow models. Many of these reservoirs produced over 10% of the original oil in place (OOIP) during primary and many of them are currently depleted or approaching depletion. However, at the termination of primary, 80 to 90 % of the OOIP remains in the reservoirs. An economic suitable post-primary improved oil recovery process (lOR) would add substantially to heavy oil reserves.

The most efficient method of increasing heavy oil mobility has been reservoir heating by thermal recovery methods which mainly based on steam or air injection. However, the majority of Canadian heavy oil deposits cannot be exploited economically after the primary production phase by thermal recovery as formations are thin or deep or bottomwater exists. Over 80% of Canadian heavy oil deposits are less than 6.0 m thick (1).

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