Energized Fracturing With 50% CO2 for Improved Hydrocarbon Recovery
Authors: Black Harold N. , Langsford Robert W. 
Published: December 2007

For several years, carbon dioxide (CO2) has been added to fracturing fluids at concentrations of 100 to 500 cu ft/bbl (18 to 90 m3/m3) to assist in post-treatment cleanup. In some instances, this has eliminated swabbing after treatment. A recent technique increases the concentration of liquid CO2 to 50% of the total injected volume, approximately 3,000 cu ft/bbl (540 m3/m3). Distinguishing features of this technique are improved fluid-loss control, higher injection rates, increased proppant concentrations, faster fluid recovery, and improved production.

Introduction

Since the early 1960's, liquefied CO2 has been used widely as an additive to hydraulic fracturing and acid treatments to improve recovery of treating fluid. CO2 may exist as liquid, gas, or solid (Fig. 1). It has a critical temperature of 87.8 degrees F (31 degrees C) and a critical pressure of 1,071 psia (7.4 MPa). During a fracturing treatment, the liquefied CO2 nominally is injected below critical temperature and remains liquid until heated. After CO2 enters the perforations, it may expand into a gaseous state, which provides improved fluid-loss control. The injected liquid CO2 flows back as gas after treatment, along with some fracturing and formation fluids.

Mechanism of Fracturing With High CO2 Concentrations

When the liquid CO2 is commingled with gelled water, the mixture remains liquid until heated to the critical temperature of 87.8 degrees F, when CO2 begins to vaporize. Even at high temperatures, the solubility of CO2 in water remains high (Fig. 2). 1 This property is a big advantage in recovering the fracturing fluid. It provides a long-sustained solution-gas drive.

Fig. 3 shows the high solubility of CO2 in crude oil. The CO2 that goes into solution in a crude oil also imparts a solution-gas drive to the affected fluids when pressure is reduced. Fig. 4 shows that CO2 reduces the viscosity of formation crude oils. Although the amount of CO2 that enters the formation during the fracturing treatment is probably insufficient to reduce oil viscosity deep in the reservoir, the injected CO2 may contact the formation oil near the created fracture. This can reduce oil viscosity in this vicinity and, thereby, improve cleanup after treatment.

Fluid retention in a formation is related to interfacial tension of fluids in the reservoir and capillary effects. Fig. 5 shows a significant reduction in interfacial tension when water is saturated with CO2 under pressure. Simon et al. reported interfacial tensions of CO2 with crude oils above saturation of less than 2 dyne/cm (2 mN/m) at 3,000 psi (20.8 MPa). A decrease of 30 to 40% in interfacial tension in laboratory experiments was reported when water was saturated with CO2. Reductions in interfacial tension aid capillary flow of fluids in the minute pores in the formation and help prevent water blocks.

The use of high CO2 concentrations reduces the amount of water injected and, consequently, the amount retained in the formation. This significantly decreases water volume injected, water/clay contact time, and cleanup time after treatment.

Comparison of CO2 With Other Energized Fracturing Fluids

Other energized fluids such as nitrogen, liquefied petroleum gas mixed with CO2, and stable (50 to 80% nitrogen) foams have been used successfully as fracturing fluids. Liquefied petroleum gas has been eliminated as a viable fracturing energy gas because of its flammability.

JPT

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