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Multi-stage hydraulic fracturing is a commonly used method to maximize production from shale gas reservoirs. However, the recovery of flowback water after hydraulic fracturing is relatively low, which gives rise to technical and environmental concerns. Although it is widely accepted that the water uptake is due to physicochemical fluid–shale interactions caused by the capillary forces, much of the studies up to now are just descriptive in nature and little attention has been paid to quantitatively characterize the fluid–shale interactions and, thus, surface forces from a geochemical perspective. In this study, we performed geochemical modeling to explain the results of spontaneous imbibition experiments by published work. We calculated the surface potential of organic matter, quartz, and calcite in the presence of 0.1–20 wt % NaCl. Moreover, we predicted the local pH using PHREEQC with consideration of ion exchange and mineral dissolution. We also computed the disjoining pressure under constant charge conditions. Results show that a low salinity drives the surface potential of organic matter and inorganic minerals to strongly negative at in situ pH. The disjoining pressure isotherm shows that air–brine–organic matter and air–brine–calcite systems give positive disjoining pressure regardless of salinity, implying a water-wet system. Moreover, a low salinity shifts the disjoining pressure to be more positive for organic matter, suggesting a wettability alteration process. However, the change of disjoining pressure on the calcite surface is negligible as a function of salinity. Our results confirm that capillary forces at least partially contribute to the water uptake, and the presence of organic matter likely further facilitates the water uptake as a result of wettability alteration. This explains in part why a low salinity causes shale expansion and microfracture generation in organic-rich reservoirs.

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