The pressure drop due to flow within a propped fracture results from three mechanisms: viscous drag of the fluid, inertial effects associated with the movement of fluid around the proppant grains, and multiphase effects associated with the interaction of the different fluid phases.

Most existing fracture models and production simulators analyze the effects of viscous drag only, often underestimating the total pressure drop in the fracture by one or two orders of magnitude. These models rely solely on the reference permeability of the proppant, which is measured in the laboratory with extremely low flow rates of 2 to 10 cc/min. This paper reviews the design changes necessary to accommodate the incremental pressure losses resulting from multiphase and non-Darcy flow, and shows application of the theory to two operators' stimulation programs.

Production rate projections and economic analyses are provided for fracture treatments conducted in two field programs (both gas reservoirs): Total-Fina-Elf's development in the Frio and Vicksburg reservoirs of South Texas and Chevron USA's Birch Creek Unit in the Green River Basin of Wyoming.

Fracture treatments in existing wells had been designed with traditional Darcy flow models. New stimulation treatments were redesigned to include multiphase and non-Darcy flow effects. This paper provides details of the two different stimulation treatment designs in each of the development programs and the production results – average productivity increases of 20 to 30% for the new wells compared to offset wells treated with stimulations based on Darcy flow design models.

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