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.
Highlights
In the field of hydrocarbon resources development, various forms of pore network models have been widely used in the simulation and prediction of single or multiphase flow parameters in porous rock media, such as capillary force [22], relative permeability [23], residual oil saturation [24], reservoir recovery [25], etc
Based on the pore network model established above, we evaluated the flow characteristics of the digital cores extracted from the Qingshankou formation, which mainly include absolute permeability and relative permeability
We analyzed the pore characteristics of the Qingshankou formation shale by scanning electron microscope
Summary
Publisher’s Note: MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations. In the field of hydrocarbon resources development, various forms of pore network models have been widely used in the simulation and prediction of single or multiphase flow parameters in porous rock media, such as capillary force [22], relative permeability [23], residual oil saturation [24], reservoir recovery [25], etc. PNM is a simulation tool based on the actual physical existence of multiphase flow in porous media [26] It can complete the simulation of flow in the media with a low computational cost and thereby obtain the relevant attribute parameters, such as relative permeability, capillary force and oil saturation [27]. To the best of our knowledge, this is the first work that evaluates the shale oil mobility by real pore network modelling of the Qingshankou formation, Songliao Basin.
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