Simulation of complex fracture networks influenced by natural fractures in shale gas reservoir

• Published in: Natural Gas Industry B Vol. 1; no. 1; pp. 89 - 95
• Main Authors: Jinzhou, Zhao, Yongming, Li, Song, Wang, Youshi, Jiang, Liehui, Zhang
• Format: Journal Article
• Language: English
• Published: KeAi Communications Co., Ltd 01.10.2014
• Subjects: Complex fracture model; Fracture network; Hydraulic fracturing; Initiation and propagation criterion; Propagating angle; Propagating pressure; Shale gas
• ISSN: 2352-8540
• DOI: 10.1016/j.ngib.2014.10.012

When hydraulic fractures intersect with natural fractures, the geometry and complexity of a fracture network are determined by the initiation and propagation pattern which is affected by a number of factors. Based on the fracture mechanics, the criterion for initiation and propagation of a fracture was introduced to analyze the tendency of a propagating angle and factors affecting propagating pressure. On this basis, a mathematic model with a complex fracture network was established to investigate how the fracture network form changes with different parameters, including rock mechanics, in-situ stress distribution, fracture properties, and frac treatment parameters. The solving process of this model was accelerated by classifying the calculation nodes on the extending direction of the fracture by equal pressure gradients, and solving the geometrical parameters prior to the iteration fitting flow distribution. With the initiation and propagation criterion as the bases for the propagation of branch fractures, this method decreased the iteration times through eliminating the fitting of the fracture length in conventional 3D fracture simulation. The simulation results indicated that the formation with abundant natural fractures and smaller in-situ stress difference is sufficient conditions for fracture network development. If the pressure in the hydraulic fractures can be kept at a high level by temporary sealing or diversion, the branch fractures will propagate further with minor curvature radius, thus enlarging the reservoir stimulation area. The simulated shape of fracture network can be well matched with the field microseismic mapping in data point range and distribution density, validating the accuracy of this model.