As heavy oil begins to overtake conventional oil in western Canada's energy supply, it becomes increasingly urgent to address the greater technical challenges posed by enhanced heavy oil recovery. This study investigates the technical feasibility of using CO2and enriched flue gas in an immiscible water-alternating-gas (WAG) injection process in those heavy oil reservoirs for which thermal recovery methods are likely to be uneconomic. In addition to phase behaviour and fluid property measurements of CO2, N2, and an enriched flue gas mixed with a heavy crude oil (12.4 ° API), this study focused on coreflooding tests of immiscible WAG injection at reservoir conditions.Additional tertiary recoveries of around 6% initial oil in place were obtained. The results indicate that N2 in the enriched flue gas (i.e., 70% N2 + 30% CO2) did not have a detrimental effect on oil recovery. Addition of a foaming agent with the injected CO2 was also beneficial.
The phase behaviour measurements indicate that the viscosity reduction mechanism of a conventional immiscible injection process cannot alone account for the results obtained in the laboratory corefloods. Additional mechanisms are suggested for oil recovery and water blocking by free gas.The analysis discussed in this paper seeks to establish a better understanding of the possible mechanisms involved in the heavy oil immiscible gas flood process, and thereby improve oil recovery performance.
Heavy oils are playing an increasingly important role in supplying Canada's energy needs, as global energy consumption escalates and conventional oil resources shrink. However, enhanced recovery of the vast heavy oil resource in west-central Saskatchewan faces greater technical challenges than do light oils. Heavy oil in this area is not only very viscous, but is also located in thin and shallow formations. The study discussed here investigated the technical feasibility of using CO2 and enriched flue gas in a water-alternating-gas injection process to enhance recovery from those heavy oil reservoirs for which thermal recovery methods are likely to be uneconomic. Heavy oil reservoirs in west-central Saskatchewan typically have low reservoir pressures; miscibility between the oil and injected solvent gases, such as CO2, cannot be achieved. Immiscible gas injection appears to be a practical enhanced oil recovery (EOR) method for these heavy oil reservoirs. In an mmiscible water-alternating-gas process, gas and water are alternately injected: the water following gas injection drives the reduced-viscosity oil, resulting in displacement with an improved mobility ratio. In addition to reducing viscosity, the dissolved gas also swells the oil so that, for a given fixed residual oil saturation, less oil remains after a waterflood.
These two mechanisms have been demonstrated by numerous laboratory phase behaviour studies, coreflood tests and simulations.1–5 Analysis of results from a tertiary CO2 injection field test revealed that incremental oil production by immiscible CO2 injection has two components. The first is an instantaneous response, probably resulting from gas displacing oil that was not being displaced by water. The second component is the long-term effect caused by viscosity reduction, swelling, and relative permeability alteration.6
