The majority of Canadian heavy oil reservoirs cannot be exploited, after primary production, by thermal recovery as formations are thin or bottom water exists. Thermal process applications to these reservoirs are not promising due to excessive heat losses to the surrounding formations. Solvent vapour 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 vapourized 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 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 injectant losses and effective oil recovery.
This paper reviews the proposed enriched gas pressure cycling process and discusses the various mechanisms controlling it. The process appears to be a viable improved recovery method for depleted heavy oil reservoirs if appropriate reservoir conditions can be achieved. Incremental recovery is expected to be dependent on the target application, process design and number of cycles. The process appears to have 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 Lloydminister fields, has been significantly higher than predicted by Darcy flow 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 recovery production, 80 to 90% of the OOIP remains in the reservoirs. An economically viable post-primary improved oil recovery process would add substantially to heavy oil reserves.
The most efficient method of increasing heavy oil mobility has been reservoir heating by thermal recovery methods, based mainly on steam or air injection. However, the majority of Canadian heavy oil reservoirs cannot be exploited economically after the primary production phase by thermal recovery as formations are thin or bottomwater exists. Over 80% of Canadian heavy oil reservoirs are less than 6.0 m thick(1). Applications of steam processes to these reservoirs, including the steam assisted gravity drainage process (SAGD), are not promising due to excessive heat losses to surrounding formations.
