Parametric study of fracture treatment parameters for ultratight gas reservoirs

Tight gas reservoirs are expected to contribute significantly to the gas and energy supply all over the world. However, the productivity of tight gas wells, especially in the ultra-tight formations, is often lower than expected. One of the needed improvements in reservoir stimulation technology is in the advancement of fracturing fluids and techniques that can help create long and highly conductive fractures and reduce phase trapping at the face of the fracture. Introduction of aqueous based fluids in ultralow permeability sands during hydraulic fracturing decreases the effective gas permeability and ultimate gas recovery. Unfortunately most fracture fluids currently deployed are aqueous based owing to their ease of preparation and low cost. This paper aims to investigate the effect of different fracture fluid systems and fracture treatment parameters and then determine one that achieves a balance of minimal fluid retention, optimal fracture geometry and low cost for ultra-tight gas reservoirs. In this paper, a dataset of reservoir properties, petrophysical properties, and fracture treatment parameters has been developed based on a complete review of published geological and engineering data of ultra-tight gas reservoir. Then based on numerical parametric studies, the effect of pertinent design factors on hydraulic fracture propagation and geometry is quantified with a fracture simulator. The factors investigated include volumetric injection rate, gel loading and proppant size. Parametric variation of seven different injection rates, seven different fracture fluids, and three different proppants was studied. A final fracture treatment that achieves maximum fracture length, fracture width and proppant conductivity is determined to be optimal. Results from simulations show that optimal fracture geometry and fracture conductivity based on pumping limitations is obtained at an injection rate of 100 bpm, a gel loading of 50 pptg of linear gel and a proppant size of 20/40 mesh sand. This paper brings new understanding of fracture behavior in ultra-tight gas reservoirs and serves as a guide for improved hydraulic fracturing practices in ultra-tight gas basins throughout the United States.