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Hydraulic fracturing operations have been widely used to enhance reservoir permeability during the extraction of oil, shale gas and tight sandstone gas. Recently, non-aqueous fracturing fluids, such as supercritical carbon dioxide and nitrogen, have been proposed as the potential fracturing fluid candidates due to their advantages of decreasing formation damage, conserving water resources and avoiding injection-induced seismicity. However, the breakdown process of the non-aqueous fracturing process and the breakdown mechanism remain mysteries. In this research, we report a series of hydraulic fracturing experiments with low-permeable shale samples and high-permeable sandstone samples by water, supercritical carbon dioxide, and nitrogen gas under different injection rates. Moreover, we use a coupled fluid-rock interaction model to visualize the distribution of fluid pressure near the injection borehole during hydraulic fracturing before the sample breakdown. The results indicate that the fluid infiltration decreases the breakdown pressure by increasing the pore pressure and decreasing the effective stress, especially for high-permeable sandstone rock and low-viscosity fracturing fluid. Also, breakdown pressure increases with increasing fluid injection rate, and the conventional Hubbert-Willis and Haimson-Fairhust equations can still effectively determine the upper and lower limits in predicting the breakdown pressure. Our results suggest that lower viscosity fluid with a lower injection rate leads to a lower breakdown pressure, which is suitable to be implemented for the reservoirs with high intrinsic permeability.

A model accommodating multi-scale pores containing kerogen within an inorganic matrix is used to explore the complex multi-mechanistic transport mechanisms of shale gas reservoirs. These include the complex evolution of pressure, diffusion and flow within both kerogen and inorganic components and their interaction with effective stresses. A general poromechanical model is proposed considering desorption and molecular diffusion in the kerogen, viscous flow in the inorganic matrix and fracture system, and composite deformation of the triple porosity assemblage. The model is verified by history matching against field data for gas production rate. The simulation results indicate that the pattern of gas flow is sequential during gas depletion – pressure first declines in the fracture, followed by the inorganic phase and then in the kerogen. The evolution of permeability is pressure dependent and the evolution of pressure is closely related to the intrinsic gas diffusion coefficient in the kerogen, inorganic matrix intrinsic permeability and fracture intrinsic permeability. A series of sensitivity analyses are completed to define key parameters affecting gas production. The study shows that dominant influence of the fracture network in acting as the main permeable conduit. The intrinsic permeability and porosity of the fracture have a positive correlation with gas production, while fracture spacing has a negative correlation to gas production. Kerogen also plays a critical role in gas production for shale reservoirs with higher total organic carbon. The enhancement of inorganic matrix permeability and gas diffusion coefficient in kerogen could efficiently guarantee a long-term gas production with a higher rate.

Gases show promise as an alternative to water-based fracturing fluids because they are non-damaging to water-sensitive formations, show some potential to create complex fracture networks, flow back to the well rapidly after treatment, and deliver some environmental benefits. However, the ability of gases to transport proppant has been questioned due to their relatively low viscosity and density. The fracturing then proppant-carrying capacity of various gases is investigated to determine the form and function of the emplaced proppant pack. First, fracture propagation and proppant transport driven by several commonly-used pure gases (CO2, liquified petroleum gas, ethane, and N2) is simulated and compared against slickwater fracturing – generally identifying inferior reach and functionality. Several methods are then investigated to improve the proppant-carrying capacity of the pure gases. Results show that, compared with slickwater, gases create shorter and narrower fractures and carry proppant shorter distances due to their lower viscosity and faster leak-off. Among the gases examined in this study, liquified petroleum gas and CO2 return the deepest proppant penetration along the fracture, followed by ethane, and with N2 unable to carry proppant into the fracture due to the resulting narrow fracture. However, elevating injection rate of gases could improve their fracture-inducing potential and proppant-transport capability to a level competitive with that of slickwater. A near-uniform proppant distribution may be achieved by using a gelled gas, with an approximately two order-of-magnitude enhancement in viscosity, or a foam-based fluid with a high quality. The fracture length may also be extended by limiting leak-off due to the increased viscosity. Moreover, ultra-light-weight proppants (ULWPs) perform better with gases than commonly-used sands in terms of uniformity of distribution, due to decelerated proppant settling. Well performance is improved significantly by fracturing with gelled gases or foams instead of pure gases or by pumping ULWPs instead of normal sands.