Many heavy oil reservoirs in Alberta and Saskatchewan are unsuitable for thermal recovery methods. The present research was directed towards the development of non-thermal methods for such reservoirs.

The main focus of this research was on the assessment of the recovery mechanisms for the low pressure immiscible carbon dioxide water-alternating- gas (WAG) flooding process, employing a linear and a two-dimensional scaled model.

Runs carried out to simulate the Aberfeldy field in a linear model were repeated in a two-dimensional model for the same pressures and WAG ratios, 50 that the results could be compared. The linear model essentially eliminated sweep effects, so that displacement and mobilization efficiencies could be studied more closely.

The oil recovery in the linear model experiments for operations at 2.5 MPa was approximately 50%. The base recovery by a waterflood was about 40%, hence the incremental recovery due to the WAG process was approximately 10%. The recovery in the two-dimensional model experiments ranged from 40 to 50%.

Recovery mechanisms were analyzed by evaluating the relative contributions of WAG, the driving water flood and the blowdown phases of the process. The effect of gas in solution in oil in the carbon dioxide WAG process was also examined.


The immiscible carbon dioxide flooding process holds promise for thin, moderately viscous, heavy oil formations, which are inherently unsuitable for thermal methods, such as steam injection and in-situ combustion. This is especially true for some of the heavy oil reservoirs in Alberta, Saskatchewan, and other regions, because the formations are thin (< 5 m), the reservoir depths are large (> 500 m), oil saturation is often low and other geological conditions such as contiguous water zones, are present. Approximately 85% of Saskatchewan's heavy oil formations are less than 5 meters thick. Carbon dioxide flooding may provide an alternative to thermal methods for these thin heavy oil reservoirs (1).

The process consists of injecting small volumes of carbon dioxide, alternating with slugs of water. After the total volume of carbon dioxide is injected, water injection is continued until an arbitrary water-oil ratio of 20 sm3/sm3 is achieved. At this point, the blowdown phase is started by lowering the pressure to atmospheric pressure. For a given oil and porous medium, the important variables for this process are: the total volume of carbon dioxide injected, the WAG ratio, the number of slugs into which water and carbon dioxide are divided, the operating pressure and the injection rate.

Studies conducted by Klins and Farouq Ali (2) and Rojas and Farouq Ali (3,4), employing numerical simulation and scaled models, showed that this process can recover 10–30% incremental oil more than a waterflood. The numerical model was used as an effective reservoir engineering tool and to study process alternatives.

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