It has been generally accepted that creating complex fracture networks by hydraulic fracturing is one of the most efficient ways to produce gas from shale gas reservoirs. Although several factors affect development of complex fracture networks, the in-situ stress anisotropy (i.e. maximum in-situ horizontal stress - minimum in-situ horizontal stress) is the most significant factor. Low in-situ stress anisotropy increases the chance of creating complex fracture networks by hydraulic fracturing while high in-situ stress anisotropy reduces the likelihood of complex fracturing. In order to compensate for high in-situ stress anisotropy without drilling additional wellbores, M.Y. Soliman suggested using a fracturing method referred to as the Texas Two Step Method (TTSM). The method rearranges the sequence of fracturing stages to make use of the induced stress contrast caused by the net fracturing pressure. In this paper, the author has reviewed previously published assumptions with regard to the above method, and has concluded that certain assumptions may not be realistic, e.g., the interaction among propagating fractures were not thoroughly considered. To analyze the effectiveness of TTSM, this research has developed numerical codes using the Discontinuous Displacement Method (DDM). Through this research, certain critical characteristics related to fracture geometries are shown to be affected through interaction among multiple hydraulic fractures. The effect of these critical characteristics on the TTSM predictions for optimal fracture spacing of multistage fracturing operations is presented. From the results, it is concluded that curved fractures can increase or reduce the stress contrast induced by the net fracturing pressure, depending on the shape of the curved fractures. This paper further introduces a simple and general formula to calculate the optimal fracture spacing for TTSM.


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