The Use of CO2-Based Fracturing Fluids in the Red Fork Formation in the Anadarko Basin, Oklahoma
- P.C. Harris (Halliburton Services) | R.J. Haynes (Halliburton Services) | J.P. Egger (Tenneco Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1984
- Document Type
- Journal Paper
- 1,003 - 1,008
- 1984. Society of Petroleum Engineers
- 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.6 Natural Gas, 3.3.1 Production Logging, 5.2 Reservoir Fluid Dynamics, 2.2.2 Perforating, 2.5.1 Fracture design and containment, 4.1.5 Processing Equipment, 4.2 Pipelines, Flowlines and Risers, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.2.3 Rock properties, 4.2.3 Materials and Corrosion, 4.1.2 Separation and Treating, 5.6.4 Drillstem/Well Testing, 2.4.3 Sand/Solids Control
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The Red Fork formation in Roger Mills County of western Oklahoma recently has been stimulated successfully with CO2-based fracturing fluids. Because of the very volatile nature of CO2-based fluids, the wells appear to clean up better than wells in the same field fractured with aqueous crosslinked-gel-type fluids. Production results ar-e given comparing the CO2-based fluids with gelled water fracturing fluids. The stimulation of a well with CO2 involves special engineering considerations. A plan is detailed for the successful placement of proppant in a deep formation with CO2-based fluid.
CO2 has been used as a chemical agent to assist oil recovery since the early 1950's. Since the early 1960's CO2 has been used as an additive in hydraulic fracturing fluids to aid the recovery of stimulation fluids. Secondary oil recovery using CO2 flooding began in 1967 and had grown to at least 28 projects by 1983. Recently two-phase fluids containing 70% CO2 have been used successfully in hydraulic fracturing of the Red Fork formation of the Anadarko Basin. Application of such CO2 foams in stimulation has spread rapidly. Field experience in the Arkansas-Louisiana-Texas region has demonstrated that the CO2-foam system can be used successfully in low-permeability oil and gas sands and carbonates, at depths ranging from 2,900 to 14,000 ft [884 to 4267 m], reservoir temperatures of 120 to 370 degrees F [48 to 188 degrees C], and reservoir pressures of 1,000 to 13,200 psi [7 to 91 MPa]. CO2 foam has also been used successfully in western Colorado and western Canada. The primary chemical advantage of adding CO2 to a treating fluid comes from its solubility in both aqueous fluids and oil. During injection, liquid CO2 is mixed with an aqueous treating fluid and pumped into the well under high pressure. In this high-pressure state, CO2 is partially soluble in the treating fluid as well as in formation fluids. Following the injection, the wellhead pressure is lowered, and the CO2 begins to come out of solution, forming a solution-gas drive for recovery of the treating fluid and formation fluids. There are several secondary benefits of CO2 that derive from its solubility. The interfacial tension (IFT) of CO2-saturated aqueous fluids is lowered to a level similar to that achieved with many surfactants. 7 The lowering of IFT is important in reducing the capillary forces that can impede the production of treatment fluids imbibed by the pores in the formation. Water saturated with CO2 forms carbonic acid. The low pH of approximately 3.5 is in the best range for the protection of clay-rich formations. Yet the pH is not so low that dissolution of iron from iron-containing minerals, and subsequent precipitation, becomes a problem. There is potential benefit in increasing the percentage of CO2 in the stimulation fluid. However, liquid CO2 has a lower viscosity than water. A fracturing fluid must have enough viscosity to transport and place proppant. The use of a two-phase structured fluid with a high internal phase ratio, such as in a 70 quality foam, provides an excellent way of using high percentages Of CO2. By making a foam with CO2), the typical foam properties of good proppant transport and low fluid loss should become inherent within the fluid.
To illustrate the viscosity of fracturing fluids containing CO2, a series of measurements were made with a high-pressure recirculating-loop pipeline viscometer. An aqueous gel containing 0.48% hydroxypropyl guar (HPG) and a surfactant were introduced into the viscometer at 75 degrees F [24 degrees C] and 1,000 psig [6.996 MPa]. CO2 was added to the viscometer at constant backpressure. The fluid was sheared at 500 seconds for 10 minutes, and then a rheogram was obtained. The viscosity of the fluid is shown as a function of CO2 concentration in Fig. 1. These data indicate an increase in viscosity due to two-phase structuring with high concentrations of CO2. Such viscosities are considered quite adequate for fracturing stimulation. Another important property of fluids energized with CO2 is the high density of the fluids. For most fracturing treatments, the CO2-foam density ranges between 7 and 9 lbm/gal [839 and 1078 kg/m3], as shown in Fig. 2. This high fluid density gives a hydrostatic head approximately the same as water itself and allows CO2-foam fluids to be pumped into deep wells without excessive wellhead pressures. The CO2 is injected as a liquid at the surface but converts to a high density gas when heated by the formation.
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