Rock-Fluid Interactions in the Duvernay Formation: Measurement of Wettability and Imbibition Oil Recovery

Abstract

Abstract In this study, we evaluate the wettability of shale samples drilled in the Duvernay Formation, which is a source-rock reservoir located in the Western Canadian Sedimentary Basin (WCSB). We use reservoir oil and brine to conduct air-liquid contact angle and air-liquid spontaneous imbibition tests for wettability measurements. We characterize the shale samples by measuring pressure-decay permeability, effective porosity, initial oil and water saturations, mineralogy, total organic carbon (TOC) content, and conducting rock-eval pyrolysis tests. We also conduct Scanning Electron Microscope (SEM) and energy-dispersive x-ray spectroscopy (EDS) analyses on the shale samples to characterize the location and size of pores. After evaluation of wettability, we conduct soaking experiments. First, we measure liquid-liquid contact angles for the droplets of the soaking fluids and reservoir oil equilibrated on surface of the rock samples. Then, we immerse the oil-saturated samples in the soaking fluids with different compositions and physical properties. The we record the oil volume produced due to spontaneous imbibition of the soaking fluids. The soaking fluids are characterized by measuring surface tension, interfacial tension (IFT), viscosity, and pH. We analyze the results of soaking tests and investigate the controlling parameters affecting oil recover factor (RF). The results of wettability measurements demonstrate that the shale samples have stronger wetting affinity to oil compared with brine. The positive correlations of TOC content with effective porosity and pressure-decay permeability suggest that the majority of connected pores are present within the organic matter. Organic porosity may explain the strong oil-wetness of the shale samples. The SEM/EDS analyses also show the abundance of organic nanopores within organic matter. The results of liquid-liquid contact angle tests show that a reduction in IFT of the soaking fluid leads to an increase in wetting affinity of rock to soaking fluid. The results also show that oil RF is higher for soaking fluids with lower IFT, which can be explained by wettability alteration. The shale samples have higher wetting affinity to soaking fluids with lower IFT, leading to an increase in the driving capillary pressure and, consequently to higher oil recovery by spontaneous imbibition. In addition, comparing the results of air-brine imbibition with soaking tests suggests that adding surfactant to the soaking fluid may alter the wettability of organic pores towards more water-wetness, leading to the displacement of oil from hydrophobic organic pores.