Shale oil production has become well established operationally, having benefited from improvements in multistage hydraulic fracturing, horizontal multilateral wells, and advanced artificial lift technologies. Oil is produced via fractures created or activated by hydraulic fracturing. However, the release and transport of oil from the nanopores of the shale matrix to fractures is complex and not well understood.
This study uses digital rock technology that incorporates the density functional hydrodynamic (DFH) method and a pore-scale simulator to enable the modeling of multiphase processes that are relevant to nanoscale phenomena in 3D digital rock models. Hydrocarbon release is dynamically modeled, starting at reservoir conditions. The thermodynamic equilibrium of the oil contained in the nanopores is disturbed by pressure depletion. This creates favorable conditions for release of a subset of hydrocarbon components stored in the matrix. Within the organic nanopores, the simulator models an expulsion gas-drive process of oil release that involves a phase transition from single-phase oil to a two-phase oil and gas system. The phase change starts when pressure decreases below the bubble point.
This technology enables investigation of methods, such as gas-injection, for improving production in unconventional reservoirs. Field trials are relatively new and few. Digital rock technology complements the physical production data and derives causality from correlation. The 3D digital rock models are constructed using focused ion beam scanning electron microscopy (FIB-SEM) imaging, followed by digital segmentation. Digital fluids used in the models are created from laboratory fluid analysis data of downhole oil samples and injection gas samples.
The digital rock simulations provide assessment of recovery potential for primary hydrocarbon release to the target pressure conditions. We compare the base case with the behavior of the saturated pore system that is contacted with various injection gases. These gases mix with the oil and gas remaining in pores after the period of primary release. This mixing takes place at pressure conditions higher than the original reservoir pressure. The boundary conditions are subsequently set to production mode to quantify the secondary release and the potential improvement in comparison to the base case. The variables studied in this investigation are the chemical composition of the initial reservoir oil and injection gas and the mixing conditions.
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