Developments in Hydrocarbon Fluids for High-Temperature Fracturing
Authors: Burnham J.W. , Harris L.E. , McDaniel B.W. 
Published: December 2007

The original fracturing fluids were refined oils and crude oils because of an initial concern with the possible detrimental aspects of contacting a possible detrimental aspects of contacting a hydrocarbon reservoir with a nonacidizing aqueous fluid. Subsequent experience has shown that with the appropriate additives (clay control materials, surfactants, etc.), most reservoirs can be treated using an aqueous fluid. The applicability of aqueous fluids in the fracture stimulation of a given reservoir is determined best by laboratory tests on formation cores or consistent field results. Use of these evaluation procedures has resulted in some reservoirs being labeled as responding best when a hydrocarbon fluid is used. Presently, fracturing jobs using hydrocarbon fluids represent less than 10% of the total number of fracturing treatments performed.The satisfactory performance of many wells stimulated with aqueous fracturing fluids coupled with the cost, hazard, and limited availability of hydrocarbon fracturing fluids are the major reasons for the preference of aqueous fluids over hydrocarbon fluids. An additional factor has limited the use of hydrocarbon fluids in some instances: heretofore, the viscosity stability of gelled hydrocarbon fluids relative to aqueous fluids has been inferior at elevated temperatures (&gt;225 deg. F or 107 deg. C). This problem is magnified because of the low specific heat of hydrocarbon fluids, which results in more rapid fluid heat-up in the fracture relative to aqueous fluids. Although hydrocarbon-base fracturing treatments have been performed above this temperature in the past, in general they have met with only limited operational success. An improvement in the viscosity stability of hydrocarbon fracturing fluids has been realized through the use of a new process, which is comprised of an initial gel prepared process, which is comprised of an initial gel prepared on the surface and subsequent incorporation of a delayed thickener added during the fracturing operation to provide additional viscosity in the fracture. This allows the preparation of a hydrocarbon gel on the surface that possesses a manageable viscosity but exhibits increased viscosity in the fracture. A similar technique using a delayed thickener for aqueous-base fracturing fluids has been used successfully for several years.

Chemical Theory Early gelled hydrocarbon fracturing fluids were prepared using ingredients such as alkali metal or prepared using ingredients such as alkali metal or aluminum carboxylate. The fluids prepared using these materials performed adequately; however, they were quite limited with respect to gel stability at elevated temperatures. More recently, the use of carboxylate salts has given way to improved fluids using substituted aluminum ortho-phosphates.These aluminum orthophosphate fluids provide enhanced temperature stability and frictional drag reduction. However, the practical temperature limit using these fluids with manageable surface viscosity is approximately 225 deg. F (107 deg. C). At higher temperatures, the gelled hydrocarbons presently used are inferior to aqueous fluids in their ability to place propping agents. This temperature limitation is propping agents. This temperature limitation is mainly due to an inability to incorporate sufficient phosphate thickener in the hydrocarbon fluid phosphate thickener in the hydrocarbon fluid because of excessive surface viscosities. This problem can be overcome by using initial and delayed phosphate thickeners. phosphate thickeners. Baker et al. proposed the formation of association colloids after proper dispersion of alkali metal or aluminum carboxylates in nonpolar media.

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