This paper presents correlations for predicting the solubility, swelling and viscosity behavior of CO2-crude oil systems. The correlations were developed from experimental data obtained by the authors. These data are also presented. The data were determined by measuring the properties of mixtures of CO2 and nine different oils. Experimental conditions covered a range of 100 to 250 degrees F and pressures up to 2,300 psia. Properties predicted by the correlations have average deviations, expressed as per cent of experimental value, of 2 per cent for solubility, 0.5 per cent for swelling and 12 per cent for viscosity. Introduction Interest in CO2 injection as an oil recovery process has led to the development of performance prediction methods which can be applied to specific reservoirs. To use these performance prediction methods, it is necessary to know the solubility, swelling, and viscosity properties of CO2-crude oil mixtures at reservoir conditions. Some information on these properties has appeared in the literature; however, this information did not cover the range of different oils and conditions needed to prepare generalized correlations for reservoir engineering purposes. Consequently, an experimental program was undertaken to collect the data needed. The data obtained and the correlations developed from the data are described in the following sections of this paper. SOLUBILITY OF CO2 IN CRUDE OILS CO2 solubility data in the literature come from six principal sources. The solubility prediction method of Welker and Dunlop is limited to 80F.The information in Ref. 4 is of two types: the first includes binary and ternary mixtures of CO2 and light hydrocarbons (C1 to C6), and the second gives data for CO2 and heavy hydrocarbons for a temperature range of 40 to 90F.Ref. 5 contains a KCO2 chart for systems whose convergence pressure is 4,000 psia. The KCO2's are based mainly on CO2-natural gas mixtures. Poettmann's work covered CO2 solubility in one condensate and one crude oil. Jacoby and Rzasa measured CO2 solubilities as a function of pressure and temperature for two natural gas-absorber oil mixtures and two natural gas-crude oil mixtures. CO2 concentration in these four systems was fixed at 5 mol per cent. The work reported in this paper extends CO2 solubility data to a variety of different crude oil types in a temperature range from 110 to 250F and pressures up to 2,300 psia. The experimental procedure used by the authors to obtain the solubility data consisted of combining known amounts of pure CO2 and crude oil in a visual cell at a fixed temperature and measuring the bubble point of the mixture. Measurements were made for a total of 40 different CO2-oil mixtures and the results are shown in Table 2. The mixtures included nine different oils (seven crude oils and two refined oils) whose properties are listed in Table 1. All nine oils had vapor pressures less than 1 atm at the experimental temperatures. Consequently, analysis of the bubble-point vapor showed a CO2 concentration over 99 mol per cent. At no time during these experiments was a second, more dense, liquid phase observed. The solubility correlation which was developed from the data in Table 2 is presented in Figs. 1, 2 and 3. In these figures, solubility is expressed as xCO2, the mol fraction of CO2 in the CO2-Oil mixture. Fig. 1 shows solubility as a function of CO2 fugacity and temperature. Fig. 2 shows the same solubility data expressed as a function of saturation pressure and temperature. The solubility shown in Figs. 1 and 2 is for an oil whose UOP characterization factor is 11.7. UOP characterization factors of crude oils can be determined from Ref. 10 if the viscosity and API gravity of the oil are known. Fig. 3 gives the solubility correction factor for oils whose UOP characterization factors differ from 11.7. JPT P. 102ˆ

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

The down-hole emulsification process has been developed to improve productivity and operating efficiency of oil wells that produce viscous crudes. The process involves using surface active chemicals in the wellbore to convert high viscosity oil or water-in-oil (W/O) emulsions to low viscosity oil-in-water (O/W) emulsions. Improved pump efficiency, faster rod drop rate, and lower flow-line pressure-drop result. pressure-drop result. Benefits obtainable from down-hole emulsification have been demonstrated in a series of field tests. The principal test, of 6 months duration, involved three wells, and showed that surfactant injection increased oil production 34 percent for a surfactant cost of $0.08/bbl of incremental oil produced. Introduction The economics of producing viscous crudes from pumped wells are affected by pumping unit limitations. pumped wells are affected by pumping unit limitations. The high viscosity of the crudes or the water-in-oil (W/O; water droplets surrounded by oil as the continuous phase) emulsions produced with the crudes causes low pump volumetric efficiency, slow rod drop rate, and high flowline pressure drop. Various methods, such as the use of bottom-hole heaters and light oil diluents, and water injection, have been used in the past to overcome these limitations. The purpose of this paper is to describe a new and improved method the down-hole emulsification processfor improving the economics of viscous crude production. Down-hole emulsification involves the use of surface active chemicals to convert high viscosity fluids in a wellbore into low viscosity oil-in-water (O/W; oil droplets surrounded by water as the continuous phase) emulsions. These emulsions result in improved pump performance and economical increases in productivity and operating efficiency. Process Description Process DescriptionThe down-hole emulsification process, illustrated in Fig. 1, consists of three primary steps: preparation, production and separation. Preparation of low viscosity O/W emulsions from viscous crude oils and the W/O emulsions produced with the oils is accomplished simply by mixing these fluids with the proper surfactants. The surfactants can be dissolved in water and injected, either continuously or in batches, into the tubing-casing annulus. The O/W emulsion is formed by the mixing action that occurs as the surfactant falls through the oil and water. This mixing may be aided by turbulence caused by gas liberation or the intermingling of the fluids entering the pump and flowing up the tubing. The oil is broken into droplets and the water forms a continuous phase surrounding the droplets. It is the continuous water phase that imparts low viscosity to the O/W emulsions. The surfactants concentrate at the oil-water interface, retarding oil droplet coalescence. At least 10 percent water cut is needed in the wellbore to make the surfactant effective. Details of emulsion preparation and viscosity data are in the Appendix. Production of the O/W emulsions formed in the wellbore is accomplished in the usual manner by pumping up the tubing and through the surface gathering lines. Because the emulsion has a lower viscosity than the crude oil, it is possible to obtain increased pump efficiency and rod drop possible to obtain increased pump efficiency and rod drop rate, and decreased rod loading and gathering-line pressure drop. pressure drop. Successful application of down-hole emulsification requires preparation of O/W emulsions that are stable when flowing; this avoids premature separation or inversion to a high viscosity W/O emulsion. (Conditions required to maintain stability are discussed in the Appendix.) Conversely, in surface equipment, O/W emulsions must separate readily into dry oil and disposable water. Emulsions prepared with nonionic surfactants meet these requirements prepared with nonionic surfactants meet these requirements more easily than those prepared with anionic surfactants. Separation of a variety of crude-oil-in-water emulsions has been accomplished by processing them in conventional horizontal separators (having hold-up times ranging from 1 to 4 hours) at elevated temperatures. Increasing temperature reduces solubility of nonionic surfactants in water, but increases their solubility in oil, thus reducing the coalescence barrier at the oil-water interface. pH control may be desirable in some applications. Data on O/W emulsion separation are in Fig. 6. Field Applications Down-hole emulsification has been successfully field tested in eight oil fields. The results of two tests are reported here. JPT P. 1349

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