Hydraulic fracturing with low and high viscous injection mediums to investigate net fracture pressure and fracture network in shale of different brittleness index

Abstract

The stimulation of shale reservoirs by hydraulic fracturing is required to recover trapped hydrocarbons. For effective stimulation, it is essential to study the mechanism of hydraulic fracturing in terms of fracture initiation and propagation in shale reservoirs. In this study, hydraulic fracturing experiments are carried out on three shale formations (Eagle Ford, Marcellus, and Mancos) to investigate the fracture initiation pressure and resultant fracture networks in different rock fabrics. Several parameters were evaluated in this respect, including rock heterogeneities in lamination and mineralogy, rock brittleness, the type of fracturing fluids, and various confinement conditions. The results show that rock heterogeneities profoundly affect the resultant fracture network in shale. Furthermore, the aperture, permeability, and complexity of the fracture network mainly depend on the structure and thickness of the laminate sets and the direction of the lateral well-bore concerning these discontinuities. The fracturing fluid substantially impacts the fracture initiation pressure and resultant fracture network in shale. Under constant fluid injection rates and confining conditions, the fracture initiation pressure with water resulted in higher net fracture pressure than higher viscous fluid (oil). However, the aperture and length of the fracture are significantly more significant in the latter case. The net pressure required to initiate fracture propagation is inversely related to the rock’s confinement pressure and brittleness index. A sharp decrease in net breakdown pressure is observed with both parameters. During hydraulic fracturing with water and oil, a consistent rise in the injection pressure is recorded. In contrast, sudden fluctuations are recorded with supercritical carbon dioxide (SC CO2) and SC CO2 foam injection. SC CO2 foam fracturing increased fracture initiation pressure compared to water and oil as injection mediums. An appreciable difference in fracture initiation pressure with SC CO2, SC CO2 foam, and water are 5023 psi, 6456 psi, and 4000 psi, respectively, at high conferment pressure (3500 psi). A comparison of Eagle Ford and Mancos shale hydraulic fracturing with different injection mediums shows that water produced complex fractures but unstable fractures in a Mancos shale due to water imbibition near fracture surfaces. In contrast, SC CO2 foam has produced open, complex, and stable fracture networks. Such open and stable fractures are mainly needed, so that embedment is avoided after achieving the required fracture network to maintain optimum fracture conductivity for the high production of hydrocarbons.