Phase-Behavior Properties of CO2 - Reservoir Oil Systems

Abstract

February 1978 Original manuscript received in Society of Petroleum Engineers office Jan. 14, 1977. Paper accepted for publication Aug. 15, 1977. Revised manuscript received Sept. 21, 1977. Paper (SPE 6387) was presented at the SPE-AIME Permian Basin Oil and Gas Recovery Conference, held in Midland, Tex., March 10-11, 1977. Abstract This paper presents experimental phase behavior data on two CO2-reservoir oil systems at reservoir pressures and temperatures. pressures and temperatures. The data includepressure-composition diagrams with bubble points, dew points, and critical points;vapor-liquid equilibrium compositions and related K values;vapor and liquid densities compared with values calculated by the Redlich-Kwong equation of state;vapor and liquid viscosities compared with predictions by the Lobrenz-Bray-Clark correlation; andinterfacial tensions for six vapor-liquid mixtures compared with values calculated by the Weinaug-Katz parachor equation. These and other published data contribute to development of the generalized correlations needed by reservoir and production engineers for evaluating, designing, and efficiently operating CO2-injection projects. projects Introduction This paper presents experimental phase behavior data for two CO2-reservoir oil systems. These data are used in predicting the performance of CO2 floods with a compositional simulator. The simulator calculates vapor and liquid compositions, densities, viscosities, and interfacial tensions to describe the phase behavior as the injected CO2 advances through phase behavior as the injected CO2 advances through the reservoir. The simulator predictions are used to evaluate proposed projects and to design and efficiently operate approved ones. The data in this paper consist of pressure-composition diagrams with bubble points, pressure-composition diagrams with bubble points, dew points, and critical points; and compositions, densities, viscosities, and interfacial tensions of vapors and liquids in equilibrium in the two-phase region. These data were obtained by the experimental procedure shown in Fig. 1. procedure shown in Fig. 1. We have compared our measured data with values calculated by existing methods: Redlich-Kwong equation for densities, Lohrenz-Bray-Clark correlation for viscosities, and the Weinaug-Katz parachor equation for interfacial tension. We found parachor equation for interfacial tension. We found that these published methods give acceptable agreement in some areas, but in general, they are not satisfactory for engineering purposes. Therefore, we conclude that improved calculation methods are needed for CO2 systems. For the special case of compositional simulator applications, we devised a technique for obtaining satisfactory calculated density, viscosity, and interfacial tension values. This technique is discussed in the section on "Measurements vs Calculations." We believe that our data, along with previously published information and information yet to come, published information and information yet to come, will advance the development of satisfactory correlations, thus reducing the need for extensive laboratory studies of individual systems. PRESSURE-COMPOSITION DIAGRAMS PRESSURE-COMPOSITION DIAGRAMS OIL A Ten mixtures of CO2 and Reservoir Oil A were prepared. These mixtures contained CO2 concentrations prepared. These mixtures contained CO2 concentrations of 0, 20, 40, 55, 60, 65. 70, 75, 80, and 90 mol percent. At 130 degrees F, pressure traverses were made with each mixture. These traverses started in the single-phase region at a pressure above the bubble (or dew) points and lowered the pressure in discrete steps, passing from the single-phase into the two-phase region. At each step, the vapor and liquid volumes were measured. The results are described in Fig. 2A. At 130 degrees F, the critical point of the CO2-Reservoir Oil A system (where intensive properties of the gas and liquid phases were equal) properties of the gas and liquid phases were equal) is 2,570 psia and 60-mol percent CO2. OIL B Eight mixtures of CO2 and Reservoir Oil B also were prepared and studied in the visual cell at 255 degrees F. CO2 concentrations for these mixtures were 0, 20, 40, 55, 65, 75, 80, and 85 mol percent. The pressure was varied from 800 to 6,100 psia, and the pressure was varied from 800 to 6,100 psia, and the relative vapor and liquid volumes measured. The results are given in Fig. 2B. The critical point of the CO2-Reservoir Oil B system at 255 degrees F is 4,890 psia and 74-mol percent CO2. psia and 74-mol percent CO2. SPEJ P. 20

Experimental and modeling study of the phase behavior of synthetic crude oil+CO2

“…However, for (CO2 + dead oil), the upper and lower bounds were almost indistinguishable and we found the horizontal three-phase line at p = 6.06 MPa, as shown in Figure 7a. The T-p projection of this three-phase line was measured from T = 298.15 K to the upper critical end point, which was found to be at T = 316.3 K, and the data are given in [33], and Simon et al [34]. Although limited to T ≤ 316.3 K in the present work, it is likely that the three phase region can extend into the temperature range of CO2 reservoir-flooding processes because of multiple contacts between CO2 and hydrocarbons during CO2 injection [68].…”

“…Examples of phase equilibria studies on (CO2 + crude oils) can be found in the work of Orr et al [30], Gardner et al. [31], Rathmell et al [32], Turek et al [33], and Simon et al [34].…”

A general regression neural network model offers reliable prediction of CO2 minimum miscibility pressure

“…CO 2 lowers the interfacial tension (IFT) and enhances mobility by reducing oil viscosity and causing oil swelling (Simon et al 1978;Green and Willhite 1998).…”

Evaluation of Asphaltene Stability During CO2 Flooding at Different Miscible Conditions and Presence of Light Components

“…Carbone dioxide flooding in Enhanced Oil Recovery (EOR) processes has been encouraging; however it may result to asphaltene deposition which it turns affect reservoir rock and fluid properties (Moritis, 2006;Hamouda et al, 2008;Idem & Ibrahim, 2002;Simon et al, 1978;De Boer et al, 1995;Burke et al, 1990;Haskett & Tartera, 1965). Haskett and Tartera (1965) reported that crude oils with low asphaltene percentage could experience asphaltene precipitation/deposition due to pressure reduction in early stage recovery, as well as reservoir fluid composition variations during enhanced recovery by gas/chemical injection.…”