Effect of slick-water fracturing fluid on the frictional properties of shale reservoir rock gouges

Abstract

“Slick-water” fluids routinely used in hydraulic fracturing contain friction-reducing agents and clay-stabilizers that may influence on the strength and stability of reservoir rocks and preexisting faults. We performed laboratory measurements on four powered shale reservoir rocks with different carbonate contents recovered from Longmaxi Formation in Sichuan Basin of China, to examine the potential effects of slick-water fracturing fluids on gouge friction. Velocity-stepping experiments were conducted at shear velocities of 0.122 and 1.22 μm/s, a confining pressure of 60 MPa, a pore fluid pressure of 30 MPa and a temperature of 90 °C, typifying the ~ 2.3 km depth of producing reservoirs. Two pore fluids, i.e., DI water and acidic slick-water, were selected to probe the chemical effects of fracturing fluids. Results show that the frictional properties of studied shale gouges are not only controlled by both the phyllosilicate and carbonate contents, but also affected by slick-water. Acidic slick-water dissolves carbonates from the shale gouges and this mineralogic alteration exerts a negligible influence on frictional strength μ but increases the frictional stability (a − b), regardless of the mass of carbonate removed. Clay stabilizers are shown to exert minimal influence on either frictional strength or stability at high confined stresses, possibly due to the unchanged mineral contacts. Our results imply that the acidity of slick-water fluids can impact the frictional responses in carbonate-rich fault gouges through corrosion and dissolution, and have important implications in understanding the chemical effects from the fracturing fluids on subsurface fault stability during shale reservoir stimulation.