Many-heavy oil reservoirs in Alberta are currently produced by primary production (cold production) or by thermal processes (SAGD or cyclic steam). Not all reservoirs are suitable for these techniques due to bottom water zones or unfavourable mineralo-economically purpose of this work was to develop and evaluate an and technically feasible non-thermal process for those reservoirs which are not suitable for primary production or thermal simulation, and as a post-primary process. The focus was on developing processes using solvent mixtures tuned to the specific reservoirs, which would result in good sweep efficiency, reduced solvent costs, and commercially viable production rates. Several partially-scaled physical models were used to model the tuned solvent process being evaluated. Since gravity drainage is the primary process believed to occur in a heavy oil reservoir produced by a top-down displacement, the models represented a two-dimensional slice of the reservoir which intersected a pair of horizontal injection/production wells. The models operated at ambient reservoir conditions, representative of the Burnt Lake field or the Lloydminster region. The solvents used were gaseous or two-phase (vapour-liquid) mixtures of CH4, C2H6, C3H8, and CO2. The oil recovery ranged from 12% IOIP (initial oil in place) to 73% IOIP at 15 years field time. A series of experiments was performed to evaluate the potential economic non-thermal recovery of heavy oil from a Burnt Lake reservoir, based on solvent assisted gravity drainage to horizontal wells. The experiments performed used carbon dioxide, a single phase hydrocarbon solvent, and two two-phase hydrocarbon solvents. Results of the experiments were extrapolated to the field scale (500 m horizontal well), and economic analyses were performed. Additional field scenarios were developed and their economics were analysed. The results of the economic analyses were used to evaluate the commercial potential of the processes proposed. Oil supply costs ranged from $384/m(3) (lean mix experiment) to $41/m(3) (the best single well scenario). The experimental results were analysed with a spreadsheet economic model in order to determine the economic potential of a 1,500 m(3)d field project. Oil supply costs ranged from $384 Cdn/m(3) (pre tax) for the lean mix process to $60.67/m(3) Cdn for the rich mix+ process to $44/m(3) for the thick Lloydminster process. Additional scenarios were investigated by extrapolating oil production and costs to cover possibilities such as wider well spacing, thicker pay zone, lower solvent cost, and a single well process. The additional scenarios were analysed using our economic model, The economic analysis suggested that a properly selected solvent would allow production of heavy oil from a single well cyclic process in a Burnt Lake reservoir at potentially economic rates. A dual-well gravity drainage process was potentially economic for a thick Lloydminster (> 15 m) reservoir, but not in a thin (< 8 m) Lloydminster reservoir. The most critical factor for economic success was to obtain high rates of bitumen production soon after the startup of the process, in order to rapidly recover the capital cost of the wells. Also critical was the minimizing of the solvent inventory and cost while maintaining solvent effectiveness. Two-well primary processes were not considered to be economic the current Burnt Lake conditions. A single-well process may be considered economic for Burnt Lake reservoir conditions.