Chemical Evolution of a High-Temperature Fracturing Fluid

Abstract

Abstract Reservoirs with bottomhole temperatures (BHT's) in excess of 250°F [121 °C] and permeabilities of less than 1.0 md are commonly encountered in drilling and completing geothermal and deep gas wells. Successful stimulation of these wells often requires the use of massive hydraulic fracturing (MHF) treatments. Fracturing fluids chosen for these large treatments must possess shear and thermal stability at high BHT's. The use of conventional fracturing fluids has been limited traditionally to wells with BHT's of 250°F [121 °C] or less. Above 250°F [121 °C], high polymer concentrations and/or large fluid volumes are required to maintain effective fluid viscosities in the fracture. However, high polymer concentrations lead to high friction pressures, high costs, and high gel residue levels. The large fluid volumes also increase significantly the cost of the treatment. Greater understanding of fracturing fluid properties has led to the development of a crosslinked fracturing fluid designed specifically for wells with BHT's above 250°F [121 °C]. The specialized chemistry of this fluid combines a high-pH hydroxypropyl guar gum (HPG) solution with a high-temperature gel stabilizer and a proprietary crosslinker. The 6fluid remains stable at 250 to 350°F [121 to 177°C] for extended periods of time under shear. This paper describes the rheological evaluations used in the systematic development of this fracturing fluid. In field applications, this fracturing fluid has been used to stimulate successfully wells with BHT's ranging from 250 to 540°F [121 to 282°C]. Case histories that include pretreatment and posttreatment production data are presented.