Abstract
Proppants are essential to the success of most hydraulic fractures and often account for the overwhelming cost of the treatment. Both the mass of proppant and the selection of the right type of proppant are essential elements in gaining the highest Net Present Value (NPV).
It has been generally believed that in the lower closure stress environment (below 6,000 psi, i.e., shallow reservoirs), natural sands such as Brady and Ottawa are appropriate as proppants and, for the same mesh size, they provide essentially the same permeability. Commonly accepted notion is that manmade proppants (such as ceramics) should be applied at higher closure stress environment, invariably, deeper reservoirs.
Three types of proppants are studied for a gas reservoir of Eagle Ford basin: Brady sand, Ottawa sand and ceramic. A fracture optimization p-3D model is used to maximize well performance by optimizing fracture geometry, including fracture half length, width and height. Reduced proppant pack permeability is compensated by larger width. Non-Darcy effects in the fracture are also considered. Post-treatment well performance is then estimated, using the optimized well geometry, leading to cumulative production over the well life. Finally, NPV analysis is employed as the criterion to select the best proppant for the job.
In this project, we show there is an optimum Proppant Number corresponding to maximum NPV in various reservoir permeability. Based on that, we propose a systematic way of choosing proppant type and mass to maximize NPV in oil reservoirs. For tight gas reservoirs, we correct the prejudice that natural sand proppants cannot be applied to deeper reservoirs by showing NPV study results that are superior to those of manmade proppants. Keeping stimulation costs down, natural sands proppants have a much larger range of applicability than previously thought.
