Quantification of seepage characteristics in shale oil reservoirs: A triple medium model-driven approach

Abstract

Shale oil is an important unconventional oil and gas resource depicting a complex microstructure with various pore types and fluid distribution. In particular, the fluid flow mechanism and the associated percolation characterization theory have recently gained notable interest. Here we establish a mathematical model to describe non-wetting and wetting phase imbibition in shale oil formation. The model is based on the triple continuum medium theory taking into account the wetting characteristics of the shale/oil/brine system, the percolation processes in inorganic and organic pores, and the dynamic process of adsorption and absorption of crude oil in kerogen. The experimental results of oil and water imbibition were fitted thereby obtaining seepage physical parameters and validating the realiability of the proposed model. The impact of physical properties (e.g. inorganic and organic permeability, equivalent cross-flow coefficient, and diffusion coefficient) on the dynamic characteristics of the imbibition process was also evaluated. The results show that the inorganic permeability is between 10−7–10−4μm2 and the organic permeability is between 10−10–10−6μm2. The imbibition rate demonstrates a positive correlation with inorganic and organic permeability, equivalent cross-flow coefficient, and diffusion coefficient. The larger the difference between inorganic and organic permeability, the more pronounced the “bi-horizontal segment” feature of the shale oil imbibition saturation curve. The proposed model effectively calculates the reserves in both organic and inorganic pores, thereby addressing the time-consuming challenges associated with experimentally obtaining seepage parameters. This study thus provides a theoretical basis for precisely evaluating fluid flow in shale oil reservoirs.