During a water-alternating-gas (WAG) flooding process for heavy oil reservoirs, the adverse mobility ratio leads to a considerable amount of injection gas fingering through the oil zone. To improve the recovery efficiency of the WAG process for Saskatchewan (Canada) heavy oil reservoirs, a laboratory feasibility study was conducted to evaluate an improved WAG process that augments the injection water with chemicals (alkali/surfactant/polymer). The resulting process is referred to as the CAG process, i.e., chemical-alternating-gas. An integrated approach, which comprised interfacial tension (IFT) and rheology measurements, phase behavior studies, and coreflood tests, was adopted to evaluate the effectiveness of the CAG process. The results showed that addition of ASP to the injection water could significantly lower oil/brine IFT (to 10(-2) mN/m) and improve mobility. The phase behavior studies indicated that CO2 could be dissolved readily into the reservoir heavy oil at moderate pressures (3.4-6.4 MPa), resulting in considerable oil swelling (1.2-8.1%) and viscosity reduction by 45-88%. Flue gas (70 mol% N-2 + 30 mol% CO2), however, resulted in much lower gas solubility compared to CO2, causing negligible oil swelling and viscosity reduction at the reservoir pressure. The coreflood results showed that a conventional CO2-WAG process recovered more incremental oil during the EOR and extended waterflood stages (9.43% versus 3.58% OOIP) than a flue gas-WAG process. Even better recovery results were obtained during these stages in corefloods using CO2-CAG and flue gas-CAG processes: they recovered, respectively, 27.43% and 22.07% of the original oil in place. This comprehensive feasibility study suggests that the CO2-CAG process holds great promise for recovering Saskatchewan's tremendous heavy oil resources. (C) 2012 Elsevier Ltd. All rights reserved.