Wettability alteration induced water uptake in shale oil reservoirs: A geochemical interpretation for oil-brine-OM interaction during hydraulic fracturing

Abstract

Multi-stage hydraulic fracturing is an indispensable approach to enable shale oil available and affordable. However, a low flowback water recovery (usually <30%) after fracking has been widely observed, triggering both technical and environmental concerns. While it has been confirmed that water uptake is a complex function of physicochemical processes in particular capillary forces, there have been few direct investigations on the characterization of the wettability of oil-brine-shale from the geochemical perspective, especially organic matter (OM), which impedes to better manage and predict flowback water recovery. To gain a deeper understanding of the system wettability, we hypothesized the hydraulic fracturing fluid (usually slick water with low salinity <5000 ppm) increases the hydrophilicity of oil-brine-OM system thereby contributing water uptake in shale. To be more specific, lowering salinity particularly in Ca2+ and Mg2+ increases oil and organic matter surface potentials and facilitates electrical double layer expansion, and thus triggers the hydrophilicity. To test our hypothesis, we conducted a geochemical simulation using literature data to account for the incremental oil recovery from shale oil rocks in low salinity brines. We computed surface species and surface potential of oil and organic matters as a function of pH for different brine salinity (280,000, 140,000 and 28,000 ppm of formation brine and 20,000 ppm of KCl) at different temperature (25 °C, 60 °C and 100 °C). We also examined the disjoining pressure between the interfaces of brine-oil and brine-OM.Surface complexation modelling results show that the oil-brine-OM system wettability is primarily controlled by in-situ salinity and secondarily affected by pH and temperature. At a given pH, decreasing salinity triggers a greater positive surface potential for both oil and OM surfaces, implying a greater electrical double layer expansion thus hydrophilicity. Moreover, the surface potential for oil and OM decreases with increasing pH, which even would be shifted from positive to negative in the presence of low salinity water. Furthermore, the surface potential of both oil and OM decreases with increasing temperature at in-situ pH (from 3.5 to 7). The disjoining pressure results show that saturating sample from high salinity formation brine into the low salinity KCl solution will shift the disjoining pressure from negative values (attraction) to positive values (repulsion). Our results support the hypothesis that lowering salinity increases hydrophilicity of oil-brine-OM, which likely contributes to water uptake by shale. We also argue that geochemical modelling would be an effective tool to characterize the interaction of oil-brine-OM, providing insights into water uptake and enhanced oil recovery in shales.