With multi-fractured horizontal wellbores being the primary means to economically access hydrocarbon resources in low- and ultra-low permeability reservoirs, a multitude of completion and stimulation practices can be employed along the lateral section of the wellbore. Completion (staging method, perforations, cluster spacing, etc.) and stimulation (fluid type, proppant type, proppant concentrations, etc.) design parameters are typically adjusted in order to accelerate hydrocarbon recovery and improve ultimate recovery.

One practice that has been gaining popularity as a method of maximizing contact area and accelerating hydrocarbon recoveries in many shale plays is the combination of thin water-based fracturing fluids, small-mesh proppants (mostly 100 mesh sand with some 40/70 mesh sand), and a high intensity of injection points in each fracture stimulation stage. The theory behind this practice is that thinner fluids and smaller mesh proppants can generate more fracture complexity in shale formations, thereby increasing contact area which is of high importance in very low permeability reservoirs, and smaller mesh proppants can be transported at larger distances than larger proppants such as 20/40 and 30/50 mesh.

Historic hydraulic fracturing practice prior to the shale boom had previously utilized small quantities of small mesh proppants such as 100 mesh sand to assist with hydraulic fracture generation and placement. However, many publications often cautioned against the use of significant quantities of these small proppants, due to the adverse impact it would have on fracture conductivity in tight gas reservoirs with permeabilities on the order of 0.01 to 1 millidarcy or greater. However, many shale plays currently in development, such as the Bakken, Eagle Ford, and Haynesville formations, have significantly lower permeabilities than tight gas plays, on the order of 1 to 1,000 nanodarcy (Walls and Sinclair, 2011), potentially elevating 100 mesh sand to "proppant" status.

This paper will critically evaluate the historic and contemporary uses of 100 mesh sand both as a placement aid as well as a proppant in very low permeability reservoirs. The effects of fracture conductivity in naturally-fractured reservoir will be explored in order to determine how much conductivity is sufficient to adequately drain the reservoir, and if using 100 mesh sand as a proppant is appropriate for this purpose. An evaluation of large datasets from publically-derived completion and production data to statistically evaluate the successes of different completion practices and a couple of specific case studies will be presented to illustrate some ways where operators can exceed the statistical mean well performance in their particular area, without needing to resort to using large fluid volume waterfrac treatments with small mesh proppants.

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