Recently, one of the non-thermal oil recovery techniques, polymer flooding, has shown its potential for improving heavy oil recovery. This study investigated the potential of combining solvent-based processes and polymer flooding, called Solvent- Assisted Polymer Flooding, to improve the oil recovery from thin heavy oil reservoirs in Western Canada. This was accomplished through a series of carefully designed laboratory experiments and a lab-scale numerical simulation. This study attempted to validate the feasibility of the solvent-assisted polymer flooding method with respect to enhancing heavy oil recovery and the impact of fluid and operational parameters on the performance of this suggested technique in an alternative schematic. Very little attention to combining these techniques has been considered until now, and there are no comprehensive studies on implementing alternative water/solvent/polymer injection schemes and consequently no significant data is available. Over 12 sets of alternative water/solvent/polymer flooding experiments were performed utilizing solvents of pure carbon dioxide, pure propane, and three different mixtures of C3, C1, and CO2. Prior to the tests, a complete phase behaviour (PVT) analysis of the solvents mixtures was conducted using WinPropTM software from Computer Modeling Group (CMG). All experiments were conducted in sandpacks with similar properties utilizing two heavy oil samples. The first heavy oil sample exhibited a viscosity of 825 mPa.s and the second a viscosity of 5,000 mPa.s at a temperature of 27°C. The production trends and recovery factors for each experiment were determined, and the pressure drop data during the tests were collected. Polymer flooding is sometimes operationally difficult in heavy oil reservoirs due to the high injection pressures that can be encountered. The results obtained from this study were promising. Alternating polymer flooding with a hydrocarbon solvent improved the overall recovery factor. Through the injection of solvent, oil near the watered-out pathways was contacted, and the oil viscosity was lowered in these areas. The lower-viscosity oil then could be displaced by subsequent injection of relatively lower-viscosity polymer than would otherwise be required, leading to improved heavy oil recovery under more feasible operational conditions. This technique can create new, reduced oil viscosity pathways through each subsequent cycle of injection, further improving the oil recovery. The study showed that modifying this technique by injecting different types of solvents before polymer injection can significantly improve the potential of this technology in heavy oil reservoirs and the applicability of polymer flooding is not limited to light oil reservoirs. In addition, it can create an opportunity to not only recover more heavy oil, but also perform the flooding under more favourable conditions. Also, implementing a higher operating pressure improved the incremental recovery of the solvent section, as far as the capacity of this study was able to observe. However, the higher operating pressure did not noticeably change the ultimate oil recovery. Higher operating pressure resulted in more noticeable viscosity reduction. Therefore, a greater decrease in the pressure profile of the polymer flooding was observed. Since pilot and field studies are time consuming and relatively expensive, numerical simulation was initially utilized to history match the results obtained in the laboratory experiments. Based on this fact, CMG-STARSTM was used and the discrepancy between recovery factors obtained from the experiments and those of the numerical simulation model were found to be in the range of 3% to 10%. The lighter oil sample model showed less discrepancy.