Summary The use of crosslinking agents to improve viscosity in polysaccharide polymer fluids is a widespread practice in hydraulic fracturing. The viscosity obtained from the use of a particular crosslinking agent depends entirely on the parameters of the in-situ chemical reaction to be performed at the wellsite. The major parameters encountered, such as concentration of polymer and crosslinking agent, pH, temperature, and shear regimen, will dictate the apparent viscosity of the product generated by the reaction. A mechanistic model for this crosslinking reaction is presented along with a description of the general effects of concentration, pH, temperature, and shear levels. Macroscopic observation of an ideal "complexed" gel is discussed using the most significant reaction parameters. Data show that the rheological properties of a crosslinked fracturing fluid are time-dependent and vary widely, depending on the reaction parameters to be encountered at the wellsite during a fracture treatment. Introduction Since their introduction as stimulation fluids to the industry in 1968, the use of crosslinked fracturing fluids has grown steadily. Today, they account for approximately 35% of the total volume of aqueous gels used in stimulation treatments. These fluids provide several advantages over non-crosslinked gels:greater viscosity per pound of polymer,friction reduction,wider fractures,better sand transport,more viscosity in high-temperature applications, andversatility and adaptability to a wide variety of treatment conditions. Before a comparison between various crosslinked fluids can be made, it should be recognized that the rheological data are highly dependent on the experimental conditions under which they were obtained. One of our primary objectives is to emphasize the importance of some of the experimental conditions. There are many water-soluble polymers that can be crosslinked with a variety of crosslinking agents to form fracturing fluids. However, only a rather limited number of polysaccharide gelling agents have found extensive commercial application in fracturing fluids. Table 1 shows the many chemical elements that have been used successfully to crosslink polysaccharides materials. Each element has its own unique pH. oxidation state, and concentration range for optimal crosslink formation. Although many metals require specific salt and/or chelated derivatives as the delivery form, the resulting crosslinked gels exhibit many common properties. This paper is restricted to the natural polysaccharides (cellulose and guar gum) and their nonionic derivatives (Fig. 1). We use examples of crosslinking agents from Table 1 to illustrate the effect of shear, pH. temperature, and type of coordination on the general properties exhibited by crosslinked fluids. Experimental Procedure Viscosity measurements were made on a Model 50 or Model 39 Fann viscometer using a variety of bob and sleeve combinations as described in Ref. 10. The crosslinking reactions were performed by first prehydrating a 0.48 to 0.72 wt% solution of the base polymer (40 to 60 lbm/1,000 gal) in a blender for 30 minutes in the presence of an adequate buffer concentration to control pH. The ph-control agents used as buffers include fumaric acid, hydrochloric acid, acetic acid, formic acid, sodium bicarbonate, sodium carbonate, and sodium hydroxide. JPT P. 315^

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Differential scanning calorimetry is used to obtain specific heats of the α, β′2, β′1 and β phases of trimargarin and tristearin in the temperature range from 190–350 K. Unequal specific heats are observed for β′ phases of the 2 lipids in contrast to nearly coincident values for their respective α and β phases. These results are discussed on the basis of odd vs even chain length triglycerides.

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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 (>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. P. 217