With the development of unconventional shale and tight reservoirs, stimulation treatments that place multiple transverse fractures have received a greater attention in recent years. The post-frac productivity of such low-permeability reservoirs is largely determined by the matrix-fracture contact area with appropriate fracture conductivity. Although it is often anticipated that the fractures are infinitely conductive, the general belief is that the production increases with the proppant amount injected.

This paper presents an approach to assess the optimum proppant amount injected by determining the post-frac conductivity. First, using three-dimensional finite difference reservoir simulations in a naturally fractured reservoir, which has both the hydraulic fracture and natural fractures modeled explicitly as discrete grid blocks, we find cumulative production as a function of fracture conductivity. For a fixed propped length and production time, we observe a critical conductivity beyond which the production is insensitive to the conductivity. The critical conductivity is then obtained as a function of the propped length and production time. The numerical results show that the critical conductivity increases with propped length and decreases with production time. The effect of stimulated natural fracture properties (intensity and permeability) on the critical conductivity is then investigated. For reservoirs with matrix permeability in the range 20-1000 nD, natural fractures increase the short-term critical conductivity but decrease the medium to long-term ones. The paper also evaluates the influence of water production, cluster spacing, and BHP flowing pressure on the critical conductivity.

This study demonstrates that Agarwal type curves based on linear flow are not appropriate for naturally fractured reservoirs and lead to errors in estimation of critical conductivity. The results of this study can be useful for selecting the type and amount of proppant for stimulation of unconventional reservoirs.

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