Hydraulic fracturing is today the completion of choice in most of tight gas producing fields all over the world. Ultimate performance of fractured wells is severely diminished by the effects of non-Darcy flow inside the fracture. A design methodology based on the effective Proppant Number is presented in this paper.
Non-Darcy flow is described by the β factor method. Evaluation and selection of appropriate β factor correlation is a key step in this approach. Effective fracture permeability and corresponding optimum geometry is calculated through an iterative process.
The proposed methodology was implemented in the design of 11 fractures treatments of 3 tight gas wells in South Texas. Results show that optimal fracture design might increase expected production by 9.64 MMscf/day with respect to design that assumes Darcy flow through the propped pack. The basic finding is that for a given amount of proppant shorter and wider fractures compensate for a significant part of the non-Darcy effect. Optimum fracture geometry varies with the applied pressure drawdown (in contrast to the Darcy flow case, where it does not.)
Optimum fracture design is sensitive to the particular β factor correlation selected. It is recommended to use the equation developed specifically for the given type of proppant and mesh size, if available. Otherwise, the Pursell et al. or the Martins et al. equations are recommended as across the board reliable correlations for predicting non-Darcy flow effects in the propped pack.