Relative permeability estimation of oil−water two-phase flow in shale reservoir

• Published in: Petroleum science 2022-06, Vol.19 (3), p.1153-1164
• Main Authors: Su, Yu-Liang, Xu, Ji-Long, Wang, Wen-Dong, Wang, Han, Zhan, Shi-Yuan
• Format: Article
• Language: English
• Subjects: Analytical model; Relative permeability; Shale; TOC; Two-phase flow
• ISSN: 1995-8226; 1995-8226
• DOI: 10.1016/j.petsci.2021.12.024

Oil−water two-phase flow is ubiquitous in shale strata due to the existence of connate water and the injection of fracturing fluid. In this work, we propose a relative permeability model based on a modified Hagen−Poiseuille (HP) equation and shale reconstruction algorithm. The proposed model can consider the nanoconfined effects (slip length and spatially varying viscosity), oil−water distribution, pore size distribution (PSD), total organic matter content (TOC), and micro-fracture. The results show that the increasing contact angles of organic matters (OM) and inorganic minerals (iOM) increase the relative permeability of both oil and water. As the viscosity ratio increases, the relative permeability of oil phase increases while that of water phase decreases, due to the different water−oil distribution. The effective permeability of both oil and water decreases with the increasing TOC. However, the relative permeability of water phase increases while that of oil phase decreases. The increasing number and decreasing deviation angle of micro-fracture increase the effective permeability of oil and water. However, micro-fracture has a minor effect on relative permeability. Our model can help understand oil−water two-phase flow in shale reservoirs and provide parameter characterization for reservoir numerical simulation.