Unconventional shale reservoirs require massive and multistage hydraulically fractured horizontal wells in order to produce economically. Induced hydraulic fractures interacting with in-situ natural fractures results in complex or discrete fracture networks (DFN). Even though well testing characteristics in fractured reservoirs with vertical wells have been investigated extensively, there is indeed a lack of good understanding of well testing behaviors for hydraulically fractured horizontal wells in complex fracture networks.

First, three practical approaches are presented regarding how to generate complex fracture networks in the context of developing unconventional shale reservoirs with hydraulically fractured horizontal wells. Complex fracture networks can be generated 1) from stochastic algorithms that input fracture density, length and strike distributions, or 2) from the flowing-producing DFN (FP-DFN) area that is constrained by microseismic information, or 3) from digitization of realistic outcrop maps. Then, new unstructured fracture gridding and discretization techniques specially tailored for complex fracture networks are developed to handle nonuniform fracture apertures, extensively fracture clustering and nonorthogonal fracture intersections. Finally, numerical simulations of pressure build-up are performed in complex fracture networks that are generated from three proposed approaches using both synthetic and field examples. Flow regimes are identified and discussed based on pressure derivative plots.

Complex fracture networks show that the most representative characteristics are formation-fracture bilinear flow and formation linear flow regimes. The appearance of the bilinear flow regime during early period might be not clear due to the impact of wellbore storage effect for the fractal fracture generation approach. In addition, the microseismic-based approach reduces uncertainties of fracture characterization by using percentiles of FP-DFN areas. The pressure build-up responses clearly indicate that the higher the percentiles of FP-DFN areas, the lower the pressure difference and derivative curves. The fracture mineralization affects pressure build-up responses significantly. The decrease in nonuniform fracture apertures cause pressure diagnostic plots shift upward. The effect of boundary in the outcrop-based complex fracture network shows an early deviation from the formation linear flow regime. No classic dual porosity behavior is observed in all cases to quantify related parameters.

Three practical techniques are proposed to generate complex fracture networks. Pressure transient characteristics are identified and summarized. The open research areas are discussed and highlighted. This work helps us better understand pressure transient behavior of complex fracture networks and after-closure analysis of fracturing calibration test.

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