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Viscosity is a fundamental fluid property affecting the multiphase flow behavior and enhanced oil recovery (EOR) efficiency. A higher invading fluid to defending fluid viscosity ratio is often associated with a more effective invading efficiency in porous media. However, a higher viscosity ratio of displacing fluid in chemical EOR does not necessarily result in higher EOR efficiency due to pore-blocking and reservoir damage. Therefore, the optimal viscosity range varies with the pore structure and permeability. Nevertheless, the relationship between the optimal viscosity range and pore structure remains unclear. This research conducts a case study on surfactant–polymer (SP) solutions, which demonstrated success in a pilot test at Karamay conglomerate reservoirs. Microfluidics is employed to model the pore structure of sandstone and conglomeratic sandstone. Furthermore, an image-based recovery characterization algorithm is implemented to evaluate the mobilization efficiency within multisize pores. The experiments indicate a wider optimal viscosity range for conglomeratic-sandstone-structure chips than for sandstone-structure chips. The observation supports the hypothesis that the best-matched pore proportion determines the recovery factor, even in various pore structure. The optimal viscosity SP solution can maximize the EOR due to matching the highest pore proportion. Furthermore, the viscosity relational diagrams, which enable matching the most pore, are established for multipermeability reservoirs through microfluidic experiments and the developed upscaling model. The findings are significant for viscosity optimization in oil and gas recovery.
Gao et al. (Thu,) studied this question.