Abstract
Historically, 20-40 mesh frac sand has been used in fracture stimulation treatments in the low permeability Devonian Sands of the Appalachian Basin. Carrier fluids have ranged from straight water to gelled water to water-based foams to crosslinked gelled water and even to crosslinked foams.
Recent work in the very low permeability (<0.1 md) Cotton Valley formation in East Texas has shown that the conventional wisdom of 20-40 mesh sand and high gel loading crosslinked fluids may not necessarily be the most effective treatment. 40-70 mesh frac sand and low gel loadings have proven beneficial. Although the Devonian Sands are not an exact match to the Cotton Valley, the very low permeability and low reservoir pressure make these sandstones a candidate for this type of treatment.
Using an industry accepted well productivity calculator and the parameters of a Devonian reservoir, the well production characteristics of various sand mesh sizes is investigated. This is only a small piece of the puzzle. Where proppant is placed in relationship to the productive interval(s) and effective fracture length are critical factors in the productivity of this type of reservoir.
A 3-dimensional fracture simulator is employed to demonstrate the improved efficiency attained in the placement of small mesh sand (40-70). Various carrier fluids are employed to place the sand. These results are then run through the well productivity calculator demonstrating the importance of proppant placement.
Although pound for pound a large mesh proppant will have improved conductivity, the deeper placement attained with smaller mesh proppants improves well potential. This paper presents this data and develops a case justifying a change in conventional Devonian Sand fracture stimulation philosophy.
