Multiphase fluid flow in porous media is found in various applications such as oil and gas recovery, hydrology, geological CO2 sequestration, and soil remediation. The formation of preferential flow regimes by invading fluid is a critical constraint in above processes. A three-dimensional pore network model is extracted from micro-CT images of a sand sample to explore the effect of pore scale characteristics such as pore size distribution and coordination number (connectivity) on the displacement behavior of multiphase fluid flow among a wide range of capillary numbers and viscosity ratios. Results reveal that widening the pore size distribution increases the saturation of invading fluid in stable displacement and viscous fingering domains, but decreases the saturation in capillary fingering zone. Accordingly, within the phase diagram, the boundaries between the stable displacement and capillary fingering shrinks as the uniformity of pore size distribution increases. Increasing the connectivity numbers escalates the saturation in stable displacement and capillary fingering zone. However, varying the coordination number doesn’t affect the saturation in viscous fingering domain. The invading fluid velocity fields show that the pore network wider pore size distribution results in wider fluid velocity distribution in which the mean fluid velocity increases in stable displacement and viscous fingering domains, and decreases in capillary fingering zone. |
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