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The residual opening of fluid-driven fractures is conditioned by proppant distribution and has a significant impact on fracture conductivity - a key parameter to determine fluid production rate and well performance. A 2D model follows the evolution of the residual aperture profile and conductivity of fractures partially/fully filled with proppant packs. The model accommodates the mechanical response of proppant packs in response to closure of arbitrarily rough fractures and the evolution of proppant embedment. The numerical model is validated against existing models and an analytic solution. Proppant may accumulate in a bank at the fracture base during slick water fracturing, and as hydraulic pressure is released, an arched zone forms at the top of the proppant bank as a result of partial closure of the overlaying unpropped fracture. The width and height of the arched zone decreases as the fluid pressure declines, and is further reduced where low concentrations of proppant fill the fracture or where the formation is highly compressible. This high-conductivity arch represents a preferential flow channel and significantly influences the distribution of fluid transport and overall fracture transmissivity. However, elevated compacting stresses and evolving proppant embedment at the top of the settled proppant bed reduce the aperture and diminish the effectiveness of this highly-conductive zone, with time. Two-dimensional analyses are performed on the fractures created by channel fracturing, showing that the open channels formed between proppant pillars dramatically improve fracture transmissivity if they are maintained throughout the lifetime of the fracture. However, for a fixed proppant pillar height, a large proppant pillar spacing results in the premature closure of the flow channels, while a small spacing narrows the existing channels. Such a model provides a rational means to design optimal distribution of the proppant pillars using deformation moduli of the host to control pillar deformation and flexural spans of the fracture wall.

Relative to water-based fluids, non-aqueous fracturing fluids have the potential to increase production, reduce water requirements, and to minimize environmental impacts. Since the viscosity of supercritical CO2 is one-tenth that of water, its density is close to that of water, and is capable of promoting sorptive rejection of methane, it is an attractive substitute for water in the extraction of shale gas and coalbed methane. The following defines a geomechanical model accommodating the interaction of fluid flow, adsorption-induced swelling stress, solid deformation and damage to quantify rock-gas interactions during supercritical CO2 fracturing for shale gas production. The architecture of the shale is accommodated that includes both pore- and micro-crack-based porosity. According to the microcrack model representing shales with low porosity, both analytical and numerical results show that the effective stress coefficient is much smaller than unity. We analyze the potential advantages of fracturing using supercritical CO2 including enhanced fracturing and fracture propagation, increased desorption of methane adsorbed in organic-rich portions of the shale and the potential for partial carbon sequestration. Rock-gas interactions include both the linear poroelastic response and the chemo-mechanical interaction due to sorption. Simulation results demonstrate that supercritical CO2 fracturing indeed has a lower fracture initiation pressure and a significantly lower breakdown pressure, as observed in experiments, and that fractures with greater complexity than those developed with liquid CO2 and water fracturing result. With increasing dynamic viscosity of the fracturing fluids, the predicted breakdown pressure also increases, consistent with experimental observations.

Restimulation of previously hydraulically-fractured wells can restore productivity to near original levels. Understanding the stress state resulting from the original hydraulic fracturing and subsequent depletion is vital for a successful refracuring treatment. The stress obliquity in the vicinity of the wellbore, due to production from a previously introduced hydraulic fracture, promotes a new concept – that of altered-stress refracuring which allows fractures to propagate into previously unstimulated or understimulated areas and therefore enhancing recovery. In this study, a coupled poromechanical model is used to define stress redistribution and to define optimal refrac timing as defined by maximizing the size of the stress reversal region. Key factors include the time dependency of the stress reorientation, the threshold stress ratio σ h max / σ h min and the influences of permeability anisotropy/heterogeneity, pressure drawdown and rock-fluid properties. The results show that stress reorientation develops immediately as the reservoir begins to produce. This stress reversal region extends to a maximum extent before retreating as the direction of the maximum principal stress gradually returns to the initial state. The optimal refrac timing and the size of the stress reversal region are positively correlated with pressure drawdown and Biot coefficient, negatively correlated with stress ratio σ h max / σ h min ratio and Poisson’s ratio and ambiguously correlated with permeability anisotropy. Permeability magnitude and porosity have no influence on the size of the resulting zone but are negatively and positively correlated to the timing, respectively. Permeability heterogeneity has no influence on the size nor the timing. Coupled fluid flow and damage-mechanics simulations follow fracture propagation under the effect of stress redistribution during refracturing treatments. These results define the evolving path of secondary refracture as it extends perpendicular to the initial hydrofracture and ultimately turns parallel to the hydrofracture as it extends beyond the stress-reversal region. This discrete model confirms the broader findings of the continuum model.