Microseismic fracture mapping has provided significant insights into the nature of fracture growth in unconventional gas reservoirs (primarily shale) and allowed detailed characterization of the created network size and to a lesser extent the internal network structure (i.e., fracture spacings, azimuths, and degree of complexity). Fracture mapping has shown that large volume slickwater stimulations can access millions of square feet of reservoir area. In most unconventional gas reservoirs, well performance is directly related to the size and complexity of the fracture network; however, well performance is also affected by un-propped and propped fracture conductivity and proppant distribution within the fracture network. This paper examines the relationship between network size, proppant distribution, and well performance.

A series of reservoir simulations were used to quantify the effect of network fracture conductivity and proppant distribution on well performance. The simulations evaluate a range of reservoir permeability from 0.0001 to 0.01 mD and utilize a network size and fracture spacing that is consistent with microseismic mapping measurements. Proppant transport cannot be reliably modeled in complex fracture networks, but it is likely that much of the fracture network is un-propped (Cipolla et al.2008). Un-propped fracture conductivities of 0.5 to 5 mD-ft were evaluated in this study. This work investigates the effect of proppant transport from a primary fracture into a fracture network and proppant banking in the primary fracture on well productivity. The results of the reservoir simulations illustrate the likely impact of stimulation designs on well performance. The results from this work provide a better understanding of fracture conductivity requirements in unconventional gas reservoirs that can be used to improve stimulation designs through improved proppant selection and scheduling.

The results of the reservoir modeling show that proppant transport, even short distances, into the fracture network can have a significant affect on well productivity in cases where un-propped fracture conductivity is not adequate to fully exploit fracture complexity. In addition, proppant banking is likely with the low viscosity fluids used in many fracture treatments in unconventional gas reservoirs, which will result in the formation of a high conductivity arch at the top of the proppant bank. The impact of this high conductivity arch can be significant and affect treatment designs, many times reducing proppant volumes and conductivity requirements.

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