Hydraulic fracture performance in the Moxa Arch Frontier formation

A comparison of hydraulic fracture performance during the initial development of the Moxa Arch Frontier sandstone in southwestern Wyoming (1975 to 1985) through infill development in 1989 to 1991 (320-acre spacing) and 1992 (160-acre spacing) is presented. The evaluation includes 3D hydraulic fracture modeling of reflected bottomhole pressures measured on 36 wells completed in 1992. In addition, in-situ stress test results from two wells are integrated with 3D fracture modeling and reservoir simulation of postfracture well performance to evaluate the evolution of fracture treatments over 17 years of development. The results from over 200 fracturing treatments were used to quantify the effect of treating fluid and proppant type on well performance. Detailed 3D fracture modeling illustrates the effects of in-situ stress and leakoff properties on fracture geometry. The results from 3D fracture modeling of 33 mini-fracs indicates vastly different fluid-loss behavior from well to well and a variation of in-situ stress within the Moxa Arch. The performance of 1992 infill wells stimulated with guar-based gels (borate and zirconium crosslinked) and sand is similar to initial development wells stimulated using guar-based crosslinked polymers and sand. However, 1989 to 1991 infill wells stimulated using CO2 foam and intermediate-strength ceramic proppants (ISP) did not perform as well as the water-based fluids and sand treatments. Fracturing net pressure data are presented that illustrate excess pressures owing to ''proppant effects'' and breakdown of stress barriers during fracturing that occurs in many treatments.