Control Mechanisms of Shale Reservoir Material Composition on Wettability and Two-Phase Flow during Imbibition

Abstract

Shale’s minerals and organic carbon have high wettability differences, and they significantly affect the two-phase flow of gas and water, but the mechanisms are still unclear. In order to reveal the mechanisms, shale samples from the Wufeng–Longmaxi Formation on the southern margin of the Sichuan Basin were selected. The samples were analyzed based on scanning electron microscopy, X-ray diffraction, Raman spectroscopy, and C–S analysis, and the porosity and permeability of the samples were characterized by gas porosity and pressure pulse decay methods. The contact angle measurements, spontaneous imbibition experiments, and two-phase flow simulations were carried out. For shale from the Lower Longmaxi Formation, the results showed that the clay content decreased, and the total organic carbon (TOC) content increased as the burial depths increased. The thermal maturity of organic carbon falls from high-mature to overmature, and its variations are small. The contact angle of water on the shale surface increases with an increase in TOC and increases with a decrease in clay content, resulting in a significant decrease in shale hydrophilia. The spontaneous imbibition experiments and the simulation results show that the increase in TOC caused an increase in nonwetting organic pores, leading to a significant decrease in the maximum water saturation in shale. The maximum capillary pressure becomes smaller as the permeability increases, while a higher TOC slows the decreasing rate of capillary pressure with water saturation, and the power index of the capillary force equation becomes smaller. As the TOC increases, the interval of the relative permeability curve narrows, the maximum relative permeability of water decreases significantly, the rate of water relative permeability with water saturation increases, and the power index in the relative permeability equation becomes larger. Therefore, organic carbon can inhibit the water flow in shale by altering the maximum water saturation, water relative permeability, and capillary force.