A Crosslinkable Synthetic Polymer System for High-Temperature Hydraulic Fracturing Applications
Authors: Holtsclaw Jeremy , Funkhouser Gary P. 
Published: June 2009

Abstract
A new hydraulic fracturing fluid has been developed that is capable of reaching fluid-service temperatures up to 450°F (232°C). This fracturing-fluid technology uses a synthetic polymer that is crosslinkable with metal ions to generate high viscosity. The synthetic polymeric fracturing gel overcomes the thermal limitations of traditional guar and derivatized guar-based fracturing fluids. Several advancements have been made in the development of this technology to maximize the efficiency of crosslinking and to give an effective breaking profile, resulting in excellent gel cleanup in the proppant pack. Research efforts have yielded a fracturing fluid with good fluid stability at high temperatures to create better proppant transport and placement in these most-demanding environments.
An integral part of this fluid is a crosslinking system that can be "tuned" for crosslinking from 100 to 280°F (38 to 138°C). The crosslinking system allows the treatment schedule to be tailored to the targeted well to help minimize friction pressure. An efficient and effective oxidative-breaker package has been developed to give a controlled rheological break for the synthetic fluid, and provides good retained conductivity data. The new, high-temperature fracturing technology provides a new tool to stimulate hotter, deeper hydrocarbon resources to help maximize hydrocarbon recovery. This fracturing-fluid system has been successfully applied in south Texas at temperatures approaching 450°F (232°C).
Rheological data that demonstrates fluid stability, crosslinking performance, and controlled fluid breaks are presented. Dynamic fluid-loss and regained conductivity data are also presented to illustrate fluid cleanup in proppant packs.

Introduction
In the quest to discover more natural gas resources, considerable attention has been devoted to finding and extracting the gas locked within unconventional gas resources. Of the many challenges associated with producing tight-gas reservoirs, high-pressure/high-temperature (HP/HT) reservoirs epitomize the challenges that accompany tight-gas opportunities (MacAndrew 2008; Harms et al. 1984; Hahn et al. 2001; Weijers et al. 2002; Lewis 2004; Jain et al. 2007: Bartko et al. 2009; Tyssee et al. 1982). As current technology is pushed to the cusp of failure, new solutions are being developed to meet the challenges. The traditional chemical technologies that have been routinely used for many years are proving to be inadequate solutions as operators tackle these challenges. One solution to produce these tight-gas reservoirs efficiently is to stimulate the wells with hydraulic fracturing. From a chemical perspective, the need for a thermally stable fracturing fluid that sustains molecular integrity at these temperatures is a step forward to address the HP/HT challenges (Shelley and Harris 2007; LaGrone et al. 1985). These hot reservoirs are often deeply buried and fracturing fluids must transport proppant over longer distances at elevated temperatures. This challenge only becomes more immense when involving horizontal wells.
Traditional hydraulic fracturing technologies use crosslinked polysaccharide gels, such as guar and guar derivatives, to transport proppant from the surface to the desired treatment zone. Typically, the gels are crosslinked with boron-based reagents for low temperatures (Harris 2003; Harris and Heath 1998; Kesavan and Prud'homme 1992), or multivalent titanium or zirconium transition metals (Clark and Barkat 1989; Prud'homme and Uhl 1984; Kramer et al. 1986; Kramer et al. 1987) for higher temperatures. These technologies have been successfully employed for many years in thousands of wells; however, as deeper, hotter reservoirs are fractured, the utility of these gels is being challenged. These gels are being used in temperatures that exceed the practical and realistic limits of polysaccharide gels. Oftentimes, significant volumes of extra fluid are pumped to cool down the formation to make polysaccharide usable in high-temperature wells.