Summary Hydraulic-fracturing treatments have become an indispensable part of well completion in shale gasfield development. Shale formations often contain natural fractures, and complex hydraulic-fracture networks may form during a treatment. The complex fracture network is strongly influenced by the interaction between the hydraulic fracture and the pre-existing natural fractures. A criterion has been developed to determine whether a fracture crosses a frictional interface (pre-existing fracture) at nonorthogonal angles. This criterion is an extension of the one for orthogonal crossing originally developed by Renshaw and Pollard (1995). The dependence of crossing on the intersection angle is shown quantitatively using the extended criterion. The fracture is more likely to turn and propagate along the interface than to cross it when the angle is less than 90°. The validation of the criterion using laboratory experiments for various angles is described and discussed. When applied to laboratory experiments, good agreement between the criterion and experiments is observed for a wide range of angles. The criterion can be used to determine whether hydraulic fractures cross natural fractures under particular field conditions, and it has been incorporated in a hydraulic-fracture model that simulates hydraulic-fracture propagation in a naturally fractured formation.

Hydraulic fracturing treatments have become an indispensable part of well completion in shale gas field development. Shale formations often contain natural fractures and complex hydraulic fracture networks may form during a treatment. The complex fracture network is strongly influenced by the interaction between the hydraulic fracture and the pre-existing natural fractures. A criterion has been developed to determine whether a fracture crosses a frictional interface (pre-existing fracture) at non-orthogonal angles. This criterion is an extension of the one for orthogonal crossing originally developed by Renshaw and Pollard (1995). The dependence of crossing on the intersection angle is shown quantitatively using the extended criterion. The fracture is more likely to turn and propagate along the interface than to cross it when the angle is less than 90°. The validation of the criterion using laboratory experiments for various angles is described and discussed. When applied to laboratory experiments, good agreement between the criterion and experiments is observed for a wide range of angles. The criterion can be used to determine whether hydraulic fractures cross natural fractures under particular field conditions, and it has been incorporated in a hydraulic fracture model that simulates hydraulic fracture propagation in a natural fractured formation.

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.

A hybrid discrete-continuum numerical scheme is developed to study the behavior of a hydraulic fracture crossing natural fractures. The fully coupled hybrid scheme utilizes a discrete element model for an inner domain, within which the hydraulic fracture propagates and interacts with natural fractures. The inner domain is embedded in an outer continuum domain that is implemented to extend the length of the hydraulic fracture and to better approximate the boundary effects. The fracture is identified to propagate initially in the viscosity-dominated regime, and the numerical scheme is calibrated by using the theoretical plane strain hydraulic fracture solution. The simulation results for orthogonal crossing indicate three fundamental crossing scenarios, which occur for various stress ratios and friction coefficients of the natural fracture: (i) no crossing, that is, the hydraulic fracture is arrested by the natural fracture and makes a T-shape intersection; (ii) offset crossing, that is, the hydraulic fracture crosses the natural fracture with an offset; and (iii) direct crossing, that is, the hydraulic fracture directly crosses the natural fracture without diversion. Each crossing scenario is associated with a distinct net pressure history. Additionally, the effects of strength contrast and stiffness contrast of rock materials and intersection angle between the hydraulic fracture and the natural fracture are also investigated. The simulations also illustrate that the level of fracturing complexity increases as the number and extent of the natural fractures increase. As a result, we can conclude that complex hydraulic fracture propagation patterns occur because of complicated crossing behavior during the stimulation of naturally fractured reservoirs.

In conventional fracturing fluids, proppant transport is governed by settling, described by Stokes Law. In thin fluids, saltation and reptation (creep) may dominate proppant transport. Past slot tests have shown that a proppant bank forms in the fracture and that proppant pumped later may overshoot previously-pumped proppant. If this occurred in full-scale hydraulic fractures, it could negate the benefits of pumping tail-in stages of more conductive proppant.Proppant banks can also migrate in a manner similar to wind-blown sand dunes. Although some qualitative results have been derived from past slot tests, there is very limited quantitative data on proppant transport via saltation and reptation. This paper outlines the theory behind these two transport mechanisms and identifies the key parameters governing them. The relative importance of a high coefficient of restitution and low friction coefficient are demonstrated.The methodology and results of experiments to measure the material properties governing saltation and reptation are presented for both conventional and advanced ceramic proppants and compared with those for sand. Advanced ceramic proppant has both a high coefficient of restitution and a low friction coefficient. Although sand has a higher coefficient of restitution than conventional ceramic proppant, it transports poorly due to the high friction associated with a rough, irregular surface.Both qualitative and quantitative testing has been performed in two large-scale slots. Qualitative testing has shown the development of dunes and demonstrated the impact of friction on dune shape. Results of tests pumping larger (30/40) proppant after smaller (50/60) show that larger proppant can fill the entrance (near-wellbore) area as opposed to passing over the smaller proppant, and flow through a slot representing a complex network has shown how proppant can "turn the corner" from a primary fracture to build a dune in a secondary fracture. Finally, quantitative testing has validated the theory and experimental measurements related to the initiation of proppant transport from a static bank.Some criteria to select the optimum proppant for slickwater fracturing are provided.