Due to the low permeability of many shale gas reservoirs, multi-stage horizontal well completions are used to provide sufficient stimulated area to make an economic well. Furthermore, access to, and stimulation of, the natural fracture system is often critical to an economically successful well. During a given hydraulic fracture stimulation, the physical displacement of the fracture alters the stress field around it. Numerous authors have suggested that this altered stress field is beneficial to the stimulation of the natural fracture system; however, other authors have shown the potential to stabilize the natural fracture system - making it less likely to shear - due to the presence of a created hydraulic fracture. In this paper, we present the results of a detailed parametric evaluation of the shear failure (and, by analogy, the microseismicity) due to the creation of a hydraulic fracture as a function of fracture length within two different fracture networks (DFNs) using the 2D Distinct Element Model (DEM), UDEC. Simulations were conducted as a function of: 1) fracture strength; 2) DFN orientation within the stress field; 3) stress ratio (the ratio of the maximum horizontal stress to the minimum); 4) Poisson’s ratio of the shale; and 5) Young’s modulus of the shale. The results show the critical impact that changes in the hydraulic fracture length and the DFN orientation have on the shear of the natural fracture system. In contrast, the simulations suggest that stress ratio, Poisson’s ratio, and Young’s modulus have, at best, a second-order effect on the shearing - and likely the stimulation - of the natural fracture system. The results of the study provide a further, quantitative assessment of the critical parameters affecting shale gas completions and aid in the understanding and optimization of hydraulic fracture stimulations in very low permeability, naturally fractured reservoirs.

There have been extensive industry efforts to understand the geophysical implicationsand limitationsof microseismic analyses; however, a critical issue that is often overlooked is the geomechanics of the rock failure that is represented by microseismicity. Recall that microseismicity is the acoustic representation of rock failure, whether tensile failure or shear failure, which is driven by the coupled hydro-thermo-mechanical effects of injecting cool fluids at high rates into naturally fractured formations. Often overlooked in the analysis of microseismic data is the stress and deformational effects at the tip of a propagating fracture that cause a significant percentage of the total microseismic record. Previous publications, for example, have noted that at the horizontal leading edge of a propagating fracture, the dominant shear is in a horizontal plane. Conversely, at the upper and lower vertical leading edge of the propagating fracture, vertical shear has been reported to dominate. These would be expected to not only cause a different microseismic response, but also, likely, a different stimulation response.In this paper, we present a detailed numerical evaluation of the stresses generated at the tip of a propagating hydraulic fracture under varying field conditions. The simulations were performed with a finite difference continuum code. The results of the simulations show that field conditions and position along the perimeter of the propagating hydraulic fracture can significantly impact local stresses, which will have then have an impact on the generated microseismicity. The results of the work will allow for a better interpretation of field microseismicity for completion optimization.

The success of many shale plays depends on the optimal stimulation of natural fractures, and the characterization of the natural fracture systems is a key issue often leading to the construction of a discrete fracture network (DFN). The DFN chiefly consists of fracture spacing, fracture dip, and dip direction from numerous sources, and, in some cases, is matched to well test data allowing for the determination of hydraulic properties. However, a commonly missing component of natural fracture characterization, and the component most important to evaluating the coupled hydro-mechanical behavior of the fractures during a hydraulic fracture stimulation, is the evaluation of the mechanical behavior of the fractures. The important mechanical parameters of the fractures include: a) elastic properties such as shear and normal stiffness, which relate changes in pore pressure to changes in aperture; b) strength parameters such as cohesion and friction angle, which define when a fracture may shear and open; c) dilational properties, which relate fracture opening to shear slippage; d) fracture toughness, which determines the pressure required to extend a fracture; and e) initial aperture. In this paper, using a new, state-of-the-art, fully-coupled, 3D distinct element hydraulic fracturing simulator, mechanical fracture parameters were evaluated in a parametric study in order to determine their impact on the effectiveness of hydraulic fracture stimulations.

Effective monitoring of hydraulic fracturing stimulations is critical to their optimization, and the evaluation of field microseismic data is now commonly used in many of the active shale plays for this purpose. The concept of Stimulated Reservoir Volume (SRV), for example, is a common technique wherein the extent of the microseismic data is used to represent the size of the fluid drainage area for a fracture or well. A principal challenge with the interpretation of microseismic data - and its use to determine drainage area or some other metric for the success of the stimulation - is the understanding of the actual cause of the microseismicity itself. Basic geomechanics principles show that rock failure - the cause of microseismicity - is a result of changes in the in-situ effective stresses relative to a given rock strength. Effective stress - which is the stress acting on the rock matrix - may change either through a change in pore pressure (leading to ‘wet’ microseismicity) or through a change in the total stress (leading to ‘dry’ microseismicity). Dry microseismicity may occur well beyond the pressure field and be hydraulically disconnected from the wellbore. In this paper, we present the results of a numerical study of hydraulic fracturing-induced microseismicity using a discrete element code, where the mechanical behavior of the natural fractures is modeled explicitly, which allows for the quantitative evaluation of ‘wet’ versus ‘dry’ microseismicity.

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