Summary Hydraulic fracturing in shale-gas reservoirs has often resulted in complex-fracture-network growth, as evidenced by microseismic monitoring. The nature and degree of fracture complexity must be understood clearly to optimize stimulation design and completion strategy. Unfortunately, the existing single-planar-fracture models used in the industry today are not able to simulate complex fracture networks. A new hydraulic-fracture model is developed to simulate complex-fracture-network propagation in a formation with pre-existing natural fractures. The model solves a system of equations governing fracture deformation, height growth, fluid flow, and proppant transport in a complex fracture network with multiple propagating fracture tips. The interaction between a hydraulic fracture and pre-existing natural fractures is taken into account by using an analytical crossing model and is validated against experimental data. The model is able to predict whether a hydraulic-fracture front crosses or is arrested by a natural fracture it encounters, which leads to complexity. It also considers the mechanical interaction among the adjacent fractures (i.e., the "stress shadow" effect). An efficient numerical scheme is used in the model so it can simulate the complex problem in a relatively short computation time to allow for day-to-day engineering design use. Simulation results from the new complex-fracture model show that stress anisotropy, natural fractures, and interfacial friction play critical roles in creating fracture-network complexity. Decreasing stress anisotropy or interfacial friction can change the induced-fracture geometry from a biwing fracture to a complex fracture network for the same initial natural fractures. The results presented illustrate the importance of rock fabrics and stresses on fracture complexity in unconventional reservoirs. These results have major implications for matching microseismic observations and improving fracture stimulation design.
In this paper, we study a highly idealized model of a moving lattice defect allowing for an explicit, "rst principles" computation of a functional relation between the macroscopic cong-urational force and the velocity of the defect. The discrete model is purely conservative and contains information only about elasticities of the constitutive elements. The apparent dissipation is due to the presence of microinstabilities and the nonlinearity-induced tunneling of the energy from long to short wavelengths. This type of "radiative damping" is believed to be generic and accounting for a considerable fraction of inelastic irreversibility associated with fracture, plasticity and phase transitions. The paper contains direct comparison of the exact lattice solution with various continuum and quasicontinuum approximations. Despite its simplicity, the model can be used directly for the description of dynamic phase transitions in thin lms.
Hydraulic fracturing in shale gas reservoirs has often resulted in complex fracture network growth, as evidenced by microseismic monitoring. The nature and degree of fracture complexity must be clearly understood to optimize stimulation design and completion strategy. Unfortunately, the existing single planar fracture models used in the industry today are not able to simulate complex fracture networks. A new hydraulic fracture model is developed to simulate complex fracture network propagation in a formation with preexisting natural fractures. The model solves a system of equations governing fracture deformation, height growth, fluid flow, and proppant transport in a complex fracture network with multiple propagating fracture tips. The interaction between a hydraulic fracture and pre-existing natural fractures is taken into account by using an analytical crossing model and is validated against experimental data. The model is able to predict whether a hydraulic fracture front crosses or is arrested by a natural fracture it encounters, which leads to complexity. It also considers the mechanical interaction among the adjacent fractures (i.e., the "stress shadow" effect). An efficient numerical scheme is used in the model so it can simulate the complex problem in a relatively short computation time to allow for day-to-day engineering design use. Simulation results from the new complex fracture model show that stress anisotropy, natural fractures, and interfacial friction play critical roles in creating fracture network complexity. Decreasing stress anisotropy or interfacial friction can change the induced fracture geometry from a bi-wing fracture to a complex fracture network for the same initial natural fractures. The results presented illustrate the importance of rock fabrics and stresses on fracture complexity in unconventional reservoirs. They have major implications on matching microseismic observations and improving fracture stimulation design.
Microseismic mapping (MSM) has shown that the occurrence of complex fracture growth is much more common than initially anticipated and is becoming more prevalent with the increased development of unconventional reservoirs (shale-gas). The nature and degree of fracture complexity must be clearly understood to select the best stimulation design and completion strategy. Although MSM has provided significant insights into hydraulic fracture complexity, in many cases the interpretation of fracture growth has been limited due to the absence of evaluative and predictive hydraulic fracture models. Recent developments in the area of complex hydraulic fracture propagation models now provide a means to better characterize fracture complexity. This paper illustrates the application of two complex fracture modeling techniques in conjunction with microseismic mapping to characterize fracture complexity and evaluate completion performance. The first complex fracture modeling technique is a simple, yet powerful, semi-analytical model that allows very efficient estimates of fracture complexity and distance between orthogonal fractures. The second technique is a gridded numerical model that allows complex geologic descriptions and more rigorous evaluation of complex fracture propagation. With recent advances in complex fracture modeling, we can now evaluate how fracture complexity is impacted by changes in fracture treatment design in each geologic environment. However, quantifying the impact of changes in fracture design using complex fracture models alone is difficult due to the inherent uncertainties in both the Earth Model and "real" fracture growth. The integration of MS mapping and complex fracture modeling enhances the interpretation of the MS measurements, while also calibrating the complex fracture model. Examples are presented that show that the degree of fracture complexity can vary significantly depending on geologic conditions.
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