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Shale gas reservoir is characterized by complex pore structure, ultra-low permeability and a large number of natural fractures. Therefore, it is necessary to apply horizontal well drilling with hydraulic fracturing to stimulate the shale gas reservoirs by forming complex fractures network composed of main fractures (i.e., hydraulic fractures) and branch fractures (i.e., activated natural fractures). During shale gas fracturing, hydraulic fractures will initiate simultaneously, deflect under the stress interference with each other, activate adjacent natural fractures and connect with them. These complex behaviors of fractures propagation would greatly complicate the production prediction after shale gas fracturing. Currently, the majority of the production prediction models neglect the complexity of fractures network. Therefore, based on Fick's diffusion law, Langmuir isothermal adsorption equation and dual-medium seepage theory, this paper derived a productivity prediction model by considering complexity of fractures network, stress-sensitive effect and ad-desorption by using point source method, Duhamel principle and Laplace transform, and solved the model with perturbation theory, discrete superposition and Stehfest numerical inversion. Then, the production prediction model was verified by a field example analysis, and the influence of the morphology of main fractures and branch fractures on productivity is explored. It indicates that the main fracture shape has a great influence on the production, and the trapezoidal mode is closer to the production practice. The large deflection of main fractures, the high conductivity and large approaching angle of branch fractures are beneficial to improving the production of fractured shale gas horizontal wells.

During hydraulic fracturing, the filtration of fracturing fluid increases the pore pressure in the vicinity, resulting in pore pressure–induced stress in the reservoir. In order to study th...

Hydraulic fracturing is regarded as one of the essential techniques for developing shale reservoirs at present. During fracturing, propagation of multi-fractures and complex fracture network is developed as result of interactions between preexisting natural fractures and hydraulic fractures, as evidenced by microseismic event patterns. This paper introduces a new mathematic model for analyzing the growth and geometry of fracture network in association with criterions of dilation and propagation based on the theory of fracture mechanics. The solution method concentrates on both extension description and dimensions calculation of every branching fracture through local explicit computation and iteration improvement. Simulation results indicate that the complex fracture network significantly depends on the features of preexisting natural fractures, optimization of fracturing parameters and materials for realizing simultaneous extension at higher net pressure. The areas with less horizontal stress contrast would increase curvature radius of fracture propagation path, which facilitates interconnection with more natural fractures on the lateral plane, and also expands network volume. Propagating angle and pressure at fracture tip for further propagation and dimensions computation are influenced by the properties of natural fractures, such as length and orientation. By using actual treatment parameters, complex fracture model is corrected against microseismic monitoring patterns by matching the distribution and density of interpretation data with geometry and complexity of simulation results; it is also applicable to fracturing design.

Geostress evolution in the process of oil field development can directly influence wellbore stability. Therefore, it is significant to strengthen the research of the evolution rule for well drilling and casing protection. Considering the interaction between reservoir seepage and stress fields, a mathematical model to characterize the stress evolution around wellbore was built. Using the FEM Software ABAQUS, through numerical simulation, the authors studied the evolution features of pore pressure and stress changes with time under different injection-production ratio, which disclosed the dynamic change regulation of pore pressure and stress of surrounding rock nearby the injection and production wells. These results may have implications in the treatment of wellbore stability and optimizing the injection and production processes during oil and gas production.