Polymer flooding has been implemented in Western Canada, specifically in Saskatchewan and Alberta since 2000s. Flooding with polymer has been more effective than with water in heavy oil reservoirs due to a more favorable mobility ratio, resulting in more a stable front and less fingering. Optimization of polymer flood strategies is essential for successful implementation of field-scale operations. Core and sand-pack flood testing have been a reliable method for laboratory evaluation of different injection methods and chemicals as the cores are representative of the reservoir geometries and rock chemistries. However, few drawbacks exist such as long turnaround time when multiple strategies need to be compared and inconsistency in pore geometry. Most importantly, this approach cannot resolve the pore scale displacement mechanisms, falling short to compare injection cases in which the recovery factors are similar, but pore-scale dynamics are different. In this study, a microfluidic-based platform was developed to visually evaluate the performance of different polymer flood cases in heavy oil recovery. Two secondary injection tests were performed with water and polymer. A tertiary polymer injection test was also performed with the waterflood followed by the polymer flood. Recovery factors and pore-scale flow behaviour and dynamics of the displacement processes were quantified. The results reported here demonstrate that the microfluidic system is a unique screening tool that can be potentially implemented in conjunction to the traditional core-flooding method to provide more efficient and reliable information to optimize the polymer flooding parameters and inform the operators.

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