Effects of Salinity and Confining Pressure on Hydration-Induced Fracture Propagation and Permeability of Mancos Shale

Low-salinity water imbibition was considered an enhanced recovery method in shale oil/gas reservoirs due to the resulting hydration-induced fractures, as observed at ambient conditions. To study the effect of confining pressure and salinity on hydration-induced fractures, time-elapsed computerized tomography (CT) was used to obtain cross-sectional images of shale cores. Based on the CT data of these cross-sectional images, cut faces parallel to the core axial in the middle of the core and 3D fracture images were also reconstructed. To study the effects of confining pressure and salinity on shale pore fluid flowing, shale permeability was measured with Nitrogen (N₂), distilled water, 4% KCl solution, and 8% KCl solution. With confining pressures increased to 2 MPa or more, either in distilled water or in KCl solutions of different salinities, fractures were observed to close instead to propagate at the end of the tests. The intrinsic permeabilities of #1 and #2 Mancos shale cores were 60.0 and 7000 nD, respectively. When tested with distilled water, the permeability of #1 shale sample with 20.0 MPa confining pressure loaded, and #2 shale sample with 2.5 MPa confining pressure loaded, decreased to 0.45 and 15 nD, respectively. Using KCl can partly mitigate shale permeability degradation. Compared to 4% KCl, 8% KCl can decrease more permeability damage. From this point of view, high salinity KCl solution should be required for the water-based fracturing fluid.