Many well stimulation designs in the Bakken Petroleum system of the Williston Basin include hybrid treatments in which multiple fluid types and proppant types are incorporated into the pumping schedule. The industry at the present time is generally focused on cost competitiveness and efficiency. Given the changing trend, a convergence of well stimulation techniques might be expected, however stimulation design and strategies among operators have diverged (figure 1) relative to fluid choices, proppant, and pump rates [Robart et al 2013].
This paper presents an investigation that was conducted to ascertain the potential effect of the mixed proppant sizes relative to fracture conductivity. It is common in hybrid completion designs to mix various sizes of proppant based on stimulation design assumptions and criteria. It is expected that a high concentration of the least conductive proppant is likely to dominate the overall fracture conductivity, but to what degree and to what extent was the question. Also, proppant size distribution is likely to vary throughout the fracture. Depending on the treatment fluids, viscosity, and expected settling rates, proppant may be segregated by tail-in, evenly blended, or blended with dominant concentrations of one particular size.
These potential scenarios were simulated in conductivity cell experiments to gain an understanding from laboratory results. The results include a number of interesting conclusions regarding the selection of tail-in proppants and the performance relative to smaller sizes of sand and light weight ceramic.