Massive hydraulic fracturing requires an enormous consumption of water and introduces many potential environmental issues. In addition, water-based fluid tends to be trapped in formations, reducing oil/gas-phase relative permeability, and causes clay-mineral swelling, which lowers absolute permeability. Carbon dioxide (CO₂) is seen as a promising alternative working fluid that poses no formation-damage risk, and it can stimulate more-complex and extensive fracture networks. However, very little, if any, extant research has quantitatively analyzed the effectiveness of CO₂ fracturing, except for some qualitative fracturing experiments that are based on acoustic emissions. In this study, we systematically examine water and CO₂ fracturing, and compare their performance on the basis of a rigorously coupled geomechanics and a fluid-heat-flow model. Parameters investigated include fluid viscosity, compressibility, in-situ stress, and rock permeability, illustrating how they affect breakdown pressure (BP) and leakoff, as well as fracturing effectiveness. It is found that (1) CO₂ has the potential to lower BP, benefiting the propagation of fractures; (2) water fracturing tends to create wider and longer tensile fractures compared with CO₂ fracturing, thereby facilitating proppant transport and placement; (3) CO₂ fracturing could dramatically enhance the complexity of artificial fracture networks even under high-stress-anisotropy conditions; (4) thickened CO₂ tends to generate simpler fracture networks than does supercritical CO₂ (SC-CO₂), but still more-complex fracture networks than fresh water; and (5) the alternative fracturing scheme (i.e., SC-CO₂ fracturing followed by thickened-CO₂ fracturing) can readily create complex fracture networks and carry proppant to keep hydraulic fractures open. This study reveals that, for intact reservoirs, water-based fracturing can achieve better fracturing performance than CO₂ fracturing; however, for naturally fractured reservoirs, CO₂ fracturing can constitute an effective way to stimulate tight/shale oil/gas reservoirs, thereby improving oil/gas production.

Summary: A fully coupled thermal/hydromechanical (THM) model for hydraulic-fracturing treatments is developed in this study. In this model, the mixed finite-volume/finite-element method is used to solve the coupled system, in which the multipoint flux approximation L-method is used to calculate interelement fluid and heat flux. The Gu et al. (2011) crossing criterion is extended to a 3D scenario to delineate the crossing behaviors as hydraulic fractures meet inclined natural fractures. Moreover, the modified Barton et al. (1985) model proposed by Asadollahi et al. (2010) is used to estimate the fracture aperture and model the shear-dilation effect. After being (partially) verified by means of comparison with results from the literature, the developed model is used to investigate complex-fracture-network propagation in naturally fractured reservoirs. Numerical experiments show that the key factors controlling the complexity of the induced-fracture networks include stress anisotropy, injection rate, natural-fracture distribution (fracture-dip angle, strike angle, spacing, density, and length), fracture-filling properties (the degree of cementation and permeability), fracture-surface properties (cohesion and friction angle), and tensile strength of intact rock. It is found that the smaller the stress anisotropy and/or the lower the injection rate, the more complex the fracture network; a high rock tensile strength could increase the possibility of the occurrence of shear fractures; and under conditions of large permeability of fracture filling combined with small cohesive strength and friction coefficient, shear slip could become the dominant mechanism for generating complex-fracture networks. The model developed and the results presented can be used to understand the propagation of complex-fracture networks and aid in the design and optimization of hydraulic-fracturing treatments.