Wettability of Shale/Oil/Brine Systems: A New Physicochemical and Imaging Approach

Wetting characteristics of shale/oil/brine systems at reservoir conditions are important for understanding fluid distribution, flow within shale microstructure, and flow back of fracturing fluid. However, shale wettability demonstrates complexity from core to nanoscale due to microstructure heterogeneity. Shale is believed to exbibit mixed wettability such that the organic matter is hydrophobic or oil-wet and the inorganic mineral is hydrophilic or water-wet. Moreover, the application of nanofluids (e.g., silica) as chemical enhanced oil recovery (CEOR) agents has gained growing interest justified by their promising potential. Thus, to elucidate the complex wetting behavior of shale/oil/brine systems before and after exposure to nanofluids, it is essential to consider the influence of broad mineralogy, TOC (Total Organic Carbon), and aging time of shale surfaces in nanofluids. In this paper, a new physicochemical approach coupled with imaging analysis is proposed to emphasize the interactions of shale/decane/brine systems (before and after aging in nanofluids) for precise shale wettability characterization. Here, the wettability of three US shale oil rocks (Eagle Ford, Wolfcamp, and Mancos) was assessed at ambient and HPHT conditions via advancing and receding contact angle measurements followed by wettability assessment post-aging in different nanofluid concentrations (0.1 wt. % to 5 wt. %). Further, the physicochemical features that influence wettability e.g., surface chemistry, mineral composition, TOC, and kerogen maturity have been investigated. These factors have been assessed via sets of physicochemical measurements such as FTIR (Fourier-Transform Infrared Spectroscopy), XRD (X-Ray Diffraction) analysis, SEM (Scanning Electron Microscopy), and AFM (Atomic Force Microscopy) imaging. Furthermore, the varying thermophysical conditions of pressure and temperature are also investigated. The results revealed significant variations in shale initial wettability with Mancos being weakly water-wet while Eagle Ford and Wolfcamp were moderately oil-wet. Moreover, increasing pressure (from 1 MPa to 20 MPa) shifted the wettability of shale rock surfaces towards relatively more oil-wet witnessed by an increase in advancing and receding contact angles. However, no noticeable trend was observed for contact angle variation with temperature. The original wetting behavior of shales is then related to their functional groups and mineralogy. Additionally, shale surfaces witnessed a shift towards a more water-wet state after aging in silica nanofluids at different concentrations. Therefore, this paper provides a new approach for examining the complex shale wettability behavior that relies on a combination of HPHT conditions, physicochemical analysis, and image analysis. Importantly, the results suggest that nanofluid can alter shale wettability towards a more water-wet state - thus showing potential for application as a flowback additive in fracturing or as a CEOR agent in shales.