Microscale Evaluation of Tight Oil Mobility: Insights from Pore Network Simulation

Abstract

Pore network modeling based on digital rock is employed to evaluate the mobility of shale oil in Qingshankou Formation, Songliao Basin, China. Computerized tomography technology is adopted in this work to reconstruct the digital rock of shale core. The pore network model is generated based on the computerized tomography data. We simulate the dynamics of fluid flow in a pore network model to evaluate the mobility of fluid in shale formation. The results show that the relative permeability of oil phase increases slowly in the initial stage of the displacement process, which is mainly caused by the poor continuity of the oil phase. In the later stages, with the increase in the oil phase continuity, the range of relative permeability increases. With the increase of organic matter content, the permeability of the water phase remains unchanged at low water saturation, but gradually increases at high water saturation. At the same time, it can be seen that, with the increase in organic matter content, the isosmotic point of the oil–water phase permeability shifts to the left, indicating that the wettability to water phase gradually weakens.