For several years carbon dioxide (CO2) has been added to fracturing fluids at concentrations of 100 to 500 cubic feet per barrel (18 to 90 m3/m3), to assist in post-treatment clean-up. In some instances, this has eliminated swabbing after treatment. A new technique increases the concentration of liquid CO2 to 50% of the total injected volume, approximately 3000 cubic feet per barrel (540 m3/m3). Distinguishing features of this technique are improved fluid loss efficiency, higher injection rates, and possible increased proppant concentrations.

Effects of the carbon dioxide on the fracturing fluid, reservoir fluids, formation clays, fluid recovery and production results are important considerations. The benefits of using 50% CO2 in hydraulic fracturing operations are discussed.

This highly energized fracturing fluid generally contains 50% gelled potassium chloride water and 50% liquid CO2 using total treatment volumes of 20,000 to 60,000 gallons (76 to 227 m3) and up to 6 pounds of proppant per gallon (720 kg/m3) of fluid at the proportioner. This system is compatible with additives which may be required to control problems related to clay swelling and fines migration, and paraffin and/or scale deposition.

This hydraulic fracturing technique has resulted in improved oil and gas production in the Permain Basin including the Seven Rivers, Yates, Queens, Grayburg, San Andres, Penrose, Tubbs and Cisco formations. Comparison of treating results to more conventional treatments in the same formations are presented.


Since the early 1960's liquefied carbon dioxide has been widely used as an additive to hydraulic fracturing and acid treatments to improve recovery to treating fluid. Carbon dioxide may exist as a liquid, a gas, or a solid, as shown in Figure 1.1 It has a critical temperature of 87.7 ° F (31 ° C) and a critical pressure of 1071 psia (7.4 MPa). During a fracturing treatment, normally the liquefied CO2 is injected below the critical temperature and remains a liquid until it is heated. After the CO2 enters the perforations, it expands into a gaseous state which will provide improved fluid loss efficiency. The injected liquid CO2 flows back as a gas after treatment.

When the liquid CO2 is co-mingled with gelled water, the mixture will remain liquid until it is heated to the critical temperature of 87.8 ° F, when the CO2 begins to vaporize. Even at high temperatures the solubility of the CO2 in water remains high, as shown in Figure 2 1. This property is a big advantage in recovering the fracturing fluid. It will provide a long sustained solution-gas drive.

Figure 3 shows the high solubility of CO2 in crude oi1.2, 3 The CO2 which goes into solution in a crude oil also imparts a solution-gas drive to affected fluids when pressure Ls reduced. Figure 4 shows that CO2 reduces the viscosity of formation crude oi1s.4 This reduction in viscosity can significantly increase oil recovery.

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