With a global paradigm shift towards exploring shale reservoirs, the industry focus has moved towards optimizing hydraulic fracturing in these reservoir types. Low-viscosity slickwater fracture treatments are commonly used as a completion technique in these ultra-low permeability reservoirs. Each shale reservoir is different due to the presence of in situ natural fractures and other geologic complexities, and thus the resultant hydraulic fracture network is distinct and the proppant transport in these "created" complex fracture networks is not clearly understood. Much speculation exists in the industry as to how efficiently the proppant is transported from the primary fracture into subsidiary fractures, if it is at all. A better awareness of proppant movement in complex fracture networks can possibly help with better hydraulic fracture treatment designs by focusing on parameters that enhance transport in the subsidiary fractures and understanding what impacts this transport may have on the resulting production. This paper discusses a series of tests carried out in a low-pressure laboratory setting to evaluate proppant transport in complex fracture networks. Different slickwater treatment scenarios were simulated by pumping sand slurry through a series of complex slot configurations while varying the slot complexity, pump rate, proppant concentration, and proppant size. Results from twenty-seven tests carried out provide some interesting insights into the nature of proppant transport and settling in complex fracture networks. In the case of a primary slot system, the proppant transport was observed to occur via traction carpet after the creation of a proppant dune. However, in the case of secondary slots, the proppant transport was found to be dependent on the dune buildup in the primary slot. Two mechanisms were observed to be transporting the proppant into the secondary slots: 1) proppant flowing around the corner at pump rates higher than the threshold pump rate (related to the threshold velocity in the primary slot), and 2) proppant falling from the primary slot due to the effects of gravity, regardless of the pump rate.

The most common completion methodology the industry uses to help maximize productivity and fluid recovery in unconventional reservoirs consists of placing multiple, optimally spaced transverse fractures in horizontal wells, navigating along the direction of minimum principle horizontal stress. In this type of completion, well productivity and fluid recovery can be maximized when the following conditions are met: Horizontal wellbore navigates optimally in the reservoir. Generated fracture connects the entire productive pay zone. Transverse fractures are optimally spaced. Proppant is well-distributed throughout the created fracture. With respect to the actual completion strategy, the first two conditions are met using proper geological interpretation and measurements of fracture height growth (e.g., microseismic); the third condition depends on economics and cluster efficiency. However, the distribution of proppant within the hydraulic fractures is usually ignored, particularly for cases in which low-viscosity fracturing fluids are used for stimulation. By performing extensive simulations for gas-producing reservoirs with a wide range of unconventional reservoir permeabilities, this paper quantifies the impact of proppant distribution on well productivity and the recovery factor (RF). For cases in which proppant distribution is not optimized, previously published extensive simulations demonstrate that the RF and productivity are significantly affected.