Pressure-Transient Characteristics of Fractured Horizontal Wells in Unconventional Shale Reservoirs With Construction of Data-Constrained Discrete-Fracture Network

Unconventional shale reservoirs require massive and multistage hydraulically fractured horizontal wells to produce economically. Induced hydraulic fractures interacting with in-situ natural fractures result in complex or discrete fracture networks (DFNs). Even though well-testing characteristics in fractured reservoirs with vertical wells have been investigated extensively, there is a lack of good understanding of well-testing response 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 enter fracture density, length, and strike distributions, or (2) from the flowing-producing DFN (FP-DEN) 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 aperture, extensive fracture clustering, and nonorthogonal fracture intersections. Finally, the numerical simulation of pressure buildup is performed in complex fracture networks that are generated from three proposed approaches with both synthetic and field examples. Flow regimes are identified and are discussed on the basis of 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 not be clear because of the impact of the wellbore-storage effect as both the wellbore volume and the volume of the larger natural fractures in communication with the wellbore. In addition, the microseismic-based approach reduces the uncertainties of fracture characterization with percentiles of FP-DFN areas. The pressure-buildup response observed clearly indicates that the higher the percentiles of FP-DFN areas (or intense naturally fractured portion of the completion), the lower the pressure difference and derivative curves. Fracture mineralization affects pressure-buildup responses significantly. The decrease in nonuniform fracture apertures causes pressure-diagnostic plots to 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. Further research areas are discussed and highlighted. The combination of techniques such as microseismic, horizontal core, production logging or some method to characterize the fracture network can be used to close the loop between the inferred network and the response that it should exhibit during pressure-transient analysis.