Effect of injection rate on hydraulic fracturing in naturally fractured shale formations: a numerical study

This paper studies the effect of fluid injection rate on hydraulic fracturing in pre-existing discrete fracture network (DFN) formations. A flow–stress–damage coupling approach has been used in an initial attempt toward how reservoir responses to injection rate under different DFN connected configuration states. The simulation results show that injection rate has an significant influence on the hydraulic fractures (HF) and DFN interaction and hydraulic fracturing effectiveness, which can be characterized by the total interaction area, stimulated DFN length, stimulated HF length and leak-off ratio. For the sparse DFN model, stimulated HF length increases with increasing injection rate and the stimulated DFN length decreases with the increasing injection rate. For the medium DFN model, stimulated HF and DFN length both increase with increasing of injection rate. For the dense DFN model, length of stimulated HF deceases with increasing injection rate; however, the stimulated DFN length increases with the increasing injection rate. The effect of injection rate on hydraulic fracturing is closely related to formation characteristics, which are strongly affected by the DFN connected configuration. For the studied fracture network, the sparse DFN model gets the optimal hydraulic fracturing effectiveness with lower injection rate; however, the dense DFN model has the best hydraulic fracturing effectiveness with higher injection rate. This work strongly links the production technology and hydraulic fracturing effectiveness evaluation and aids in the understanding and optimization of hydraulic fracturing simulations in naturally fractured reservoirs.