Numerical simulation of hydraulic fracture propagation in shale gas reservoir

Abstract

On the basis of damage mechanics, a 2D fracture propagation model for seepage-stress-damage coupling in multi-fracture shales was established. Numerical simulations of hydraulic fracture propagation in the presence of natural fractures were carried out, with the use of mechanical parameters of shale reservoirs. The results showed that when hydraulic fractures encountered natural fractures in a shale reservoir, the morphology of fracture propagation was jointly affected by the properties of natural fractures (permeability and mechanical properties of rocks), approaching angle, horizontal stress difference, and flow rate of fracturing fluids. At a small horizontal stress difference, or low approaching angle, or small friction coefficient, natural fractures had increased potential to be damaged due to shear and tension. In such cases, the hydraulic fractures tended to propagate along the natural fractures. As the flow rate of fracturing fluid increased and the width of hydraulic fractures expanded, branch fractures formed easily when the net pressure exceeded the sum of horizontal stress difference and tensile strength of the rocks in which natural fractures with approaching angle smaller than 60° existed. It is seen, a high flow rate will increase the complexity of fracture network. However, when a large number of natural fractures with approaching angles greater than 60° existed, a large flow rate generally led to propagation of hydraulic fractures beyond natural fractures, which was not favored. Hence, an appropriate flow rate should be selected based on the orientations of natural fractures and hydraulic fractures. At the early stage of hydraulic fracturing, a low flow rate was favorable for the initiation of natural fractures and the growth of complexity of regional fractures near the well. Later, a higher flow rate facilitated a further propagation of hydraulic fractures into the depth of reservoir, thus forming a network of fractures. The underlying control mechanism of flow rate and net pressure on the formation of fracture network still requires clarification. The bending degree of the fracture propagation path depended on the ratio of net pressure to stress difference at a distant point as well as on the spacing between fractures. When the horizontal stress difference (<9 MPa) or coefficient of horizontal stress difference (<0.25) was low, the ratio of net pressure to stress difference was high. In this case, the fracture-induced stress obtained an enhanced significance, while the interactions of hydraulic fractures intensified, leading to a non-planar propagation of fractures. In addition, a smaller spacing between fractures caused intensified interactions of hydraulic fractures, so the propagation path altered more easily. This work contributes to the prediction of morphology of fracture propagation in unconventional oil and gas reservoirs.