Organic shale wettability and its relationship to other petrophysical properties: A Duvernay case study

Abstract

In this study, we conduct spontaneous imbibition tests and measure air-oil and air-brine contact angles of nine twin core plugs from five wells drilled in the Duvernay Formation, which is a source rock located in the Western Canadian Sedimentary Basin (WCSB). We investigate wettability of the shale samples with a wide range of TOC (2.2–6.6wt%), effective porosity (2.0–6.2% BV), and kerogen maturity (wet-gas, dry-gas, and over-mature). We characterize the samples by measuring the effective porosity, pressure-decay permeability, oil saturation, bulk density, matrix density, mineralogy, total organic carbon (TOC) content, and conducting rock-eval pyrolysis tests. To investigate the effects of pore connectivity, we also measure spontaneous imbibition and contact angles of oil and water on crushed shale packs and compare the results with those of similar tests on the core plugs. We also investigate the crossplots of effective porosity, pressure-decay permeability, bulk density, matrix density, oil saturation, and TOC content, by using 130 data points from samples of the five wells.Analysis of the data reveals a positive correlation of TOC content with effective porosity, pressure-decay permeability, and oil saturation of the samples. Bulk density and matrix density of the core samples decrease with increasing the TOC content. The crossplots indicate that the majority of pores exist in the organic matter of the samples and these organic pores have high affinity towards oil. Scanning Electron Microscope (SEM) and energy-dispersive X-ray spectroscopy (EDS) analyses also demonstrate an abundant number of small nanopores within the organic matter. These hydrophobic small nanopores with diameters <100nm may explain high imbibed volume of oil compared with that of brine, and also late equilibrium of oil imbibition. SEM and EDS analysis also show large micropores bordered by inorganic minerals. According to Handy's model, these hydrophilic micropores with diameters >1000nm may explain early equilibrium of brine in spontaneous imbibition experiments. We define pore wettability index of oil (PWIo) and brine (PWIw) based on the imbibition rate of oil and brine, respectively. PWIo is greater than PWIw in all spontaneous imbibition tests. Higher PWIo compared with PWIw indicates that oil preferentially flows through smaller pores while brine prefers to flow through larger pores. We also define oil wettability index (WIo) based on the equilibrium imbibed volume of oil and brine. The results of spontaneous imbibition experiments show that the samples with higher TOC content and effective porosity have higher WIo. Positive correlations of WIo with TOC content and effective porosity suggest that the majority of hydrophobic connected pores exist in the organic part of the rock. In addition, we observe negative correlation of WIo with oxygen index (OI). This observation can be explained by 1) higher number of organic nanopores, and 2) stronger oil-wetness of kerogen in samples with higher kerogen maturity (lower OI).