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In the two-dimensional simulated reservoir volume (SRV) model, the position of natural fractures is determined only by the approaching angle, and it is only required to consider the influence of horizontal principal stress in its failure criterion. In the three-dimensional shale reservoir, the position of natural fracture needs to be determined by the dip angle and approaching angle while considering the influence of vertical and horizontal principal stress in its failure criterion. In addition, the simultaneous opening of several hydraulic cracks will lead to the change of geostress, thus causing the change of the conditions of the natural fracture and shear failure by the induced tress. In order to analyze the generation of three-dimensional fracture network, this paper establishes a mathematical model based on elastic mechanics, three-dimensional rock failure criterion, full permeability tensor, and material conservation equation. Firstly, the finite element method model of geological stress caused by fracturing is established based on the crack propagation model, and the finite difference method module based on three-dimensional fluid diffusion control equation and full permeability tensor is used to solve the reservoir pressure distribution. Then, the three-dimensional rock tensile and shear failure criteria are used to determine whether any grid units are destroyed. Once a grid has occurred in any form of rock failure criterion, the permeability of the corresponding grid unit will also change due to the change of natural fracture opening. Finally, the stimulated reservoir volume is represented by the region of increased permeability. This paper presents the sensitivity analysis of the multi-factor after using the micro-seismic data to validate the numerical model, including the influence of injected fluid volume, natural fracture approaching Angle, dip Angle and horizontal principal stress difference on the size of SRV (shape, size, border width, length, etc.). Results show that, compared to without the induced stress, the tensile failure volume decreases and the shear failure volume increases, while the total SRV increases due to the induced stress. When the vertical principal stress in the three-principal stress is maximum, the length of the SRV increases with the increase of natural fracture approaching angle, dip angle and horizontal principal stress difference, but its width decreases. Its width and length increase at the same time only with the increase volume of injected fluid; the size of SRV increases with the increase of the injection fluid volume and the natural fracture dip, but decreases with the increase of the natural fracture approaching angle and horizontal principal stress difference. [ABSTRACT FROM AUTHOR]

Multistage hydraulic fracturing to create a complex fracture network has become a key technology for the economic and effective development of shale gas reservoirs. How to design hydraulic fracture parameters is very important for the hydraulic fracturing treatment. Production evaluation is a useful method to optimize the hydraulic fracture parameters. In this paper, a dual porosity/dual permeability continuum model was proposed to evaluate shale gas production performance with consideration of the geo-mechanical effect and multi-transport mechanisms, including adsorption and desorption, Knudsen diffusion, surface diffusion, and viscous flow. The induced fracture network in a stimulated area is considered to be a continuum, and both the stimulated and unstimulated domains are characterized as a dual-porosity continuum. The hydraulic fracture and stimulated area are represented by modifying grid block permeability after discretizing the natural fracture continuity equation. The numerical models were derived by using the Galerkin finite element method. Finally, the shale gas production and pressure distribution of the simulation element with a single planar fracture was compared with the shale gas production and pressure distribution of the fracture network, and a sensitivity analysis was performed to observe the impact of different hydraulic fracture parameter values, incorporating the stimulated reservoir volume (SRV), SRV width, SRV length, ratio of the fracture network length and width, primary fracture conductivity, secondary fracture conductivity and cluster spacing for shale gas cumulative production and the gas flow rate. The results indicate that cumulative gas production increases linearly with the increase in the hydraulic fracture network parameter value until cumulative gas production reaches a critical value. Smaller cluster spacing does not necessarily improve shale gas production because of the stress shadow effect. The optimal hydraulic fracture parameter values are obtained based on this production simulation study. This work offers important theoretical and practical significance for evaluating shale gas production and hydraulic fracturing treatment parameter design. [ABSTRACT FROM AUTHOR]