Temporal Evolution of the In-Situ Contact Angle in Tight Sandstone During Fracturing Fluid Exposure

While mature conventional reservoirs are in decline, unconventional tight sandstones and other plays are increasing in significance, but their properties such as low porosity and permeability make them economic only if stimulation techniques such as hydraulic fracturing are applied. Wettability, one of the variables controlling fluid flow and recovery in such schemes, can be altered in this process as injected fluids react chemically with the rock. Here, we investigate the modification of the wettability in a Berea sandstone core that was initially oil wet, as a reservoir analogue to tight sandstones, all of this by sequential injecting with brine, crude oil, and broken hydraulic fracturing fluid (bHFF). The same sample was imaged several times at four critical points by high-resolution X-ray micro-computed tomography (μCT), exposing pore-scale fluid configurations, contact angle distribution, and oil cluster connectivity in conditions that are representative of a shut-in process. Measurements indicate that while the mean contact angle increased from ~42° for the native oil-wet state to ~88° after exposure to bHFF, consistent with the marked trend towards mixed- or water-wet behavior, there was still significant local heterogeneity. Individual oil clusters were still trapped, demonstrating that even large-scale wettability alteration is unable to eliminate residual oil entrapment, and that pore geometry and fluid flow pathways are crucial to such entrapment. Through imaging the transitions during different stages in real-time, this research demonstrates how dynamic fluid redistribution and wettability can be determined with reproducible μCT scans providing additional insight beyond conventional wettability measurements and facilitating the design of better fracturing fluids and shut-in periods for unconventional reservoirs.