Oil Carbon Dioxide Research Articles

Effect of Nitrogen On the Solubility And Diffusivity of Carbon Dioxide Into Oil And Oil Recovery By the Immiscible WAG Process

Abstract In the immiscible displacement of oil by carbon dioxide gas, the solubility and diffusivity of carbon dioxide are important factors that determine the efficiency of the process, because an increase in the carbon dioxide solubility and diffusivity into oil leads to an increase in oil recovery. It is shown by experimental studies that the solubility and diffusivity of carbon dioxide into oil are governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. The solubility and diffusivity of carbon dioxide into Aberfeldy heavy oil were measured, using impure carbon dioxide gas containing nitrogen as the main contaminant gas. It was noted that increasing the concentration of nitrogen in the carbon dioxide stream decreased the solubility and diffusivity of carbon dioxide in oil, consequently leading to a reduction in the swelling of the oil by carbon dioxide. Displacement experiments were also conducted to observe the effect of using impure carbon dioxide in place of pure carbon dioxide in the immiscible displacement WAG process. It was noted that the presence of nitrogen in carbon dioxide adversely affected oil recovery by the process and that increasing the nitrogen concentration up to 30 mole% could result in 10% loss in oil recovery. Introduction The solubility of carbon dioxide is the most important effect in the immiscible displacement of oil by carbon dioxide gas since it was found by Rojas(1) that among other mechanisms, an increase in the carbon dioxide solubility in oil leads to an increase in oil recovery. This is true because the solubility of carbon dioxide greatly reduces the viscosity of the oil and promotes the swelling of the oil. Viscosity reduction and swelling of the oil lower the water-oil mobility ratio, consequently leading to an increased oil recovery. Early work in 1926 by Beecher and Parkhurst(2) showed that carbon dioxide was more soluble on a molar basis in a 30.2 °API oil than air and natural gas. Svreck and Mehrota's data(3) for carbon dioxide, methane and nitrogen showed that and Mehrotra's data(3), carbon dioxide is the most soluble and nitrogen the least soluble in bitumen. The solubility of carbon dioxide in oil is governed by the saturation pressure, reservoir temperature, composition of the oil and purity of the gas. Miller and Jones(4) and Chung, Jones, and Nguyen(5) measured the solubility of carbon dioxide in Canyon and Wilmington heavy oils and found that the solubility of carbon dioxide in heavy crude oils increased with pressure but decreased with temperature and reduced API gravity. Briggs and Puttagunta(6) reported sets of data for carbon dioxide solubility in Aberfeldy oil and swelling of oil at 20.6 °C. Their data showed that both carbon dioxide solubility and oil swelling increased when pressure increased. Later, Sayegh and Sarbar(7) established that carbon dioxide is more soluble in oil at lower temperatures than at higher ones.

HIGH PRESSURE PHASE EQUILIBRIUM: PREDICTION OF ESSENTIAL OIL SOLUBILITY

This work describes a method to predict the solubility of essential oils in supercritical carbon dioxide. The method is based on the formulation proposed in 1979 by Asselineau, Bogdanic and Vidal. The Peng-Robinson and Soave-Redlich-Kwong cubic equations of state were used with the van der Waals mixing rules with two interaction parameters. Method validation was accomplished calculating orange essential oil solubility in pressurized carbon dioxide. The solubility of orange essential oil in carbon dioxide calculated at 308.15 K for pressures of 50 to 70 bar varied from 1.7<FONT FACE="Symbol">±</font> 0.1 to 3.6<FONT FACE="Symbol">±</font> 0.1 mg/g. For same the range of conditions, experimental solubility varied from 1.7<FONT FACE="Symbol">±</font> 0.1 to 3.6<FONT FACE="Symbol">±</font> 0.1 mg/g. Predicted values were not very sensitive to initial oil composition.

Extraction of Squalene from Shark Liver Oil in a Packed Column Using Supercritical Carbon Dioxide

Continuous extraction of squalene from shark liver oil using supercritical carbon dioxide was carried out in both laboratory and pilot scale plant. The shark liver oil contained around 50% by weight squalene, which was recovered as the main extract stream. The other major components in the oil were triglycerides, which were recovered as raffinate, and pristane, which was recovered as a second extract stream. Separation performance was determined as a function of temperature; pressure; oil to carbon dioxide flow rate ratio, packed height and type of packing; and reflux ratio. The pressure, temperature, and feed oil concentration of squalene determined the maximum loading of oil in carbon dioxide. The oil to carbon dioxide ratio determined the squalene concentration in both the product stream and raffinate stream. The ratio of oil flow rate to the flow rate of squalene required to just saturate carbon dioxide was found to be a useful correlating parameter for the oil loadings and product compositions. Of the three packings investigated, wire wool gave the best separation efficiency and Raschig rings the worst efficiency. Mass transfer correlations from the literature were used to estimate the number of transfer units NTU from experimental data and literature correlations. NTU's from the experimental data were comparable to predictions at a pilot scale but were underpredicted at the laboratory scale. The use of reflux at the pilot scale enabled the concentration of squalene in the product stream to be increased from 92% by mass to a maximum of 99% by mass at fractionation conditions of 250 bar and 333 K.

Phase equilibrium study for the separation and fractionation of fatty oil components using supercritical carbon dioxide

Bharath, R., Inomata, H., Adschiri, T. and Arai, K., 1992. Phase equilibrium study for the separation and fractionation of fatty oil components using supercritical carbon dioxide. Fluid Phase Equilibria, 81: 307-320. Vapor-liquid equilibria were measured for the binary systems oleic acid-carbon dioxide and triolein-carbon dioxide and for the ternary system oleic acid-triolein-carbon dioxide with the aim of separating the fatty acids and triglycerides. Experimental results showed that oleic acid can be selectively extracted using supercritical carbon dioxide as a solvent. Supercritical carbon dioxide was also considered for the fractionation of mixtures of triglycerides. High pressure vapor-liquid equilibria were measured for the systems palm kernel oil-carbon dioxide and sesame oil-carbon dioxide. Supercritical carbon dioxide was found to fractionate these triglyceride mixtures on the basis of the total carbon number of the constituent fatty acids of the triglyceride.

Eagle Lake Viking Miscible Displacement Laboratory Studies

Abstract A series of displacement tests was conducted on preserved reservoir core plugs to assist in estimating waterflood and miscible flood performance potential for the Eagle Lake Viking Reservoir in Saskatchewan. The reservoir rock is a heterogeneous sandstone, comprising thin interbeds of sand and shale with the sand lenses containing widely different amounts of smectite clays. To assess miscible recovery efficiencies in this complex sand, displacement tests were conducted with first-contact miscible propane and carbon dioxide solvents. Using standard waterflood relative permeabilities and a dual permeability model, all miscible displacements were matched by simulation with a Todd-Longstaff-type miscible mixing model. Introduction The Eagle Lake Viking Reservoir is located in southwest Saskatchewan as shown in Figure 1. It is a sandstone formation of Mississippian age. Discovered in 1957, one half of this 12.7 million m3 field was put on waterflood ten years later in 1967. Unfortunately, because of its low permeability, it has been possible to only inject 0.14 pore volumes of water in the subsequent 2O-year period. As a result, in the thirty years since discovery, only 15% of original oil- in-place has been produced. The cause of poor performance appears to be due to the abundant shales and days. Thin section analyses, however, show that bands of higher permeability are also found throughout the pay zone and often exist as thin to very thin sand stringers which are relatively free of days. In 1985, operations engineers decided that the half of the field which was still under primary depletion should be placed under some form of secondary recovery. Because the waterflood had been less than satisfactory, it was decided to examine miscible flooding as a potential alternative. Hence, a core flooding study using carbon dioxide as a flooding agent was designed with the following objectives;quantify carbon dioxide oil displacement efficiency;compare carbon dioxide with waterflood oil recovery; andcompare the potentially complex carbon dioxide miscible oil displacement process with a more conventional hydrocarbon solvent process using propane. To extend the initial objectives for reservoir design purposes, a fourth objective was to:obtain waterflood and miscible displacement parameters for use in numerical simulation of field applications, Reservoir Fluid and CO2 Miscibility Pressure The live oil used in this study was obtained by recombining separator gas and liquid to a bubble point pressure of 6509 kPa at 22 °C. Fluid densities were measured as a function of pressure at the reservoir temperatures of 22 °C and were matched with the Peng-Robinson(l) equation-of-state. The reference 2 characterization procedure was used and viscosity predictions were made with the Jossi, Stiel and Thodos correlation. Table 1 illustrates the accuracy or this prediction which involved proprietary correlations for heavy end parameters. This set of density and viscosity data was used in the simulation study. The oil composition is also shown in Table 1. To determine the first-contact miscibility pressure for CO2, oil and CO2 were blended in a visual cell at 22 °C. These results and the Peng-Robinson equation-of-state matches are presented in Table 2.

Phase equilibria in mixtures of glycerides and carbon dioxide and application of continuous thermodynamics to mixtures of rapeseed oil and carbon dioxide

A lattice model equation of state recently developed by Kumar et al. is used to model phase equilibria in binary and quaternary mixtures of trilaurin, trimyristin, tripalmitin and carbon dioxide. In order to obtain an accurate description of the thermodynamic properties of the supercritical fluid, we introduce the Bender equation of state into the lattice model. As expected, the Kumar-Bender equation of state leads to an improved representation of the triglyceride solubilities. Considering rapeseed oil to be a mixture of triglycerides, the Kumar-Bender model is applied to the rapeseed oil-carbon dioxide system. The efficiency of continuous thermodynamics is compared with a conventional pseudocomponent technique. These investigations indicate that for mixtures of vegetable oils and carbon dioxide, the capability of an equation of state to model phase equilibria of asymmetric mixtures accurately is more important than the exact knowledge of the composition of the complex mixture.

Measurement and model prediction of vapor-liquid equilibria of mixtures of rapeseed oil and supercritical carbon dioxide

Isothermal-vapor-liquid equilibrium data of the rapeseed oil-carbon dioxide system were measured with a vapor-recirculation apparatus at 313.15, 333.15, 353.15, and 373.15 K at pressures between 10 and 85 MPa. The solubilities of rapeseed oil in carbon dioxide were compared with solubility data of other vegetable oils from the literature. A lattice model equation of state (EOS) is used to describe the rapeseed oil-carbon dioxide system. The lattice EOS was improved by introducing a more accurate EOS for carbon dioxide (Bender EOS) into the model. With the Kumar-Bender model and a tree-binary-parameter, composition- and density-dependent combining rule proposed by Wilczek-Vera and Vera, a quantitative description of phase equilibrium is obtained. The temperature dependence of the binary parameters has been evaluated for interpolation or extrapolation purposes.

A Laboratory Study Of Heavy Oil Recovery With Carbon Dioxide

Abstract Heavy oil reservoirs of Saskatchewan are characterized by thin pay, shaley sand, heterogeneity, low productivity and bottom water. Thermal recovery processes are not expected to be economically feasible for reservoirs containing approximately eighty per cent of the heavy oil in the province. The carbon dioxide immiscible flooding process is considered to be the most promising among the non-thermal recovery methods for these reservoirs. This paper presents a survey of the recent laboratory and field studies a/the heavy oil-carbon dioxide immiscible process and the results obtained from phase behaviour and core displacement experiments. Viscosity, density bubble point pressure, gas-oil ratio (GOR) and swelling factor far the reconstituted reservoir fluids and CO2 saturated wellhead oil and reservoir fluid were measured at 28 °C and pressures lip to 8.27 MPa. A forty-five-fold reduction in viscosity and a 16% increase in the swelling factor were observed in the heavy oil CO2 system. Carbon dioxide once dissolved in the heavy oil at a high pressure remains in solution even when the pressure is reduced. Waterflooding of the oil-saturated core produced 31.5% to 46.2% initial oil-in-place (IOIP). The incremental recovery from the CO2 injection into the waterflooded core was between 12.7% and 38,6% residual oil-in-place (ROIP) in the water-alternating gas (WAG) mode and between 23.1% and 33.2% ROIP for the slug process. The total recovery appeared to level off at 60% IOIP. The CO2 injection into the core at the initial oil saturation recovered 29.9%. IOIP in the WAG mode and 41.6% IOIP for a slug process where CO2 was allowed to soak for 69 h. There appears to be considerable merit in soaking with CO2 prior to water injection. Introduction Saskatchewan has an extensive resource of heavy oil. The proven resource is 1.0 × 109m3 and the probable oil-in-place 3.4 × 109m3 (l). The heavy oil reservoirs of Saskatchewan are characterized by thin pay, shaley sand, heterogeneity, low productivity and bottom water. Fifty-five per cent of the initial heavy oil-in-place is contained in reservoirs less than 3 m thick and ninety-five per cent in less than 7 m thick(2). Primary and secondary methods together recover less than ten per cent of the initial oil-in-place. The development of appropriate recovery techniques specific to Saskatchewan reservoirs is necessary if the full potential of this resource is to be realized. Saskatchewan's heavy oil enhanced recovery projects have centred around steam injection and in-situ combustion. While steam injection has been very successful, it is not expected to be economically feasible for those reservoirs which contain approximately eighty per cent of the heavy oil(3,4). Insitu combustion, although applicable to thin reservoirs, has been only marginally successful thus far. Recovery of heavy oil using carbon dioxide immiscible flooding is considered to be the most promising among the non-thermal EOR processes, particularly for those reservoirs having such undesirable geology as found in Saskatchewan(4–6). Since 1982 the number of carbon dioxide immiscible projects in the United States has grown from zero to eighteen(3).

Pyrolysis of nuclear reactor circulator oil in carbon dioxide: II. Long term degradation studies

The thermal degradation of Advanced Gas cooled nuclear Reactor (AGR) circulator oil in carbon dioxide has been studied using degradation temperatures up to 650°C and for degradation periods up to 4 h. The degradation products were measured and identified using gas chromatography (GC) and GC combined with mass spectrometry. The following conclusions were drawn: 1. The production of lower molecular weight hydrocarbons at temperatures below 525°C results from primary decomposition reactions. At higher temperatures the net rate of formation falls as they are converted to other species. The production of higher hydrocarbons is complex. 2. The relative proportions of the different species vary with temperature, e.g. propene forms 19% of the total at 540°C, but only 2% at 400°C and 650°C. 3. The proportion of alkenes falls and the proportion of aromatics rises with both increasing temperature and increasing time. 4. A lower proportion of aromatic species results from degradation in helium compared with degradation in carbon dioxide. 5. The reactions are too complex to allow the data to be fitted to a rate equation.

Pyrolysis of nuclear reactor circulator oil in carbon dioxide

The ingress of circulator oil into the carbon dioxide coolant of a nuclear reactor can cause problems such as the deposition of carbon on the fuel elements. This paper describes the first stage of degradation when oil is pyrolysed, in carbon dioxide at temperatures between 600 and 900°C, and in helium at 900°C, for 20s. The degradation products were determined using gas chromatography with either a selective carbon monoxide monitor or a flame ionization detector. The chromatograph was combined with a mass spectrometer for the identification of the degradation produces. Hydrogen, carbon monoxide and a wide range of hydrocarbons are the initial degradation products. The amounts of individual reaction product, and the total amount formed ( P) increased with pyrolysis temperature, T, according and the total amount = 1/ T. The sensitivity to temperature of product formation varied from one product to another. Formation of carbon monoxide was least sensitive to temperature. It is clear that a chemical reaction takes place between the oil and carbon dioxide since the total amounl of product produced is much greater in carbon dioxide than in helium and the relative amounts of product produced in carbon dioxide differ considerably from those produced by pyrolysis in helium: for example, no carbon monoxide is detected when the oil is pyrolysed in helium.

A Study of the Vaporization of Crude Oil by Carbon Dioxide Repressuring

Abstract The object of this study was to determine if crude oil could be produced successfully by a process of crude oil vaporization using carbon dioxide repressuring. This process appears to have application to highly fractured formations where the major oil content of the reservoir is contained in the non-fractured porosity with little associated permeability. Crude oil was introduced into the windowed cell and carbon dioxide was charged to the cell at the desired pressure. A vapor space was formed above the oil, and the crude oil-carbon dioxide mixture was allowed to come to equilibrium. The vapor phase was removed and the vaporized oil collected as condensate. Samples of all produced and unproduced fluids were analyzed. Tests were also performed to evaluate the amount of vaporized oil that can be produced by rocking from a high to a lower pressure. The carbon dioxide repressuring process was applied to a sand-filled cell to investigate the performance in a porous medium. A test was performed to evaluate how the condensate recovery changes as the size of the gas cap in contact with the oil changes. Introduction This study has been directed toward a relatively new process of vaporization of crude oil designed to increase ultimate production of hydrocarbons through the application of carbon dioxide to an oil reservoir. Suggested advantages of carbon dioxide repressuring of a petroleum reservoir are: - reduction in viscosity of liquid hydrocarbons due to the solubility of carbon dioxide in crude oil, - swelling of the reservoir oil into a larger liquid-oil volume with a resulting increase in production and decrease in residual oil saturation due to an increase in the relative permeability to oil, - displacement of more stock-tank oil from the reservoir since the residual liquid is a swelled crude oil, and - gasification of some of the hydrocarbons into a carbon dioxide-hydrocarbon vapor mixture. Balanced against these advantages are several detrimental factors which must be evaluated; i.e., high compression costs and corrosion of well equipment and flow lines. Some of the more outstanding contributions to the study of carbon dioxide injection have been reviewed in order to furnish a basis for a continuation of research pertaining to this method. The literature reviewed has been limited to that dealing with carbon dioxide repressuring processes or with carbon dioxide-crude oil-natural gas phase behavior. Articles relating to carbonated water injection and literature published on the use of low pressure carbon dioxide gas injection in water flooding have not been included in this study. In 1941 Pirson suggested the high pressure injection of carbon dioxide into a partially depleted reservoir for the purpose of causing the reservoir oil to vaporize and thus produce the oil as a vapor along with the carbon dioxide gas. By reducing the pressure on this produced mixture of hydrocarbons and carbon dioxide at the surface, it was proposed to separate the hydrocarbons from the carrier gas. He theorized that essentially all the oil in a reservoir could be produced by simply injecting enough carbon dioxide to vaporize the residual oil. This present investigation deals with the vaporization of a crude oil by carbon dioxide, the molecular weight and gravity of the vaporized oil product and the characteristics of the residual oil after several repressuring cycles with carbon dioxide. An attempt is made to evaluate the merits of a vaporization process for the crude oil rather than a flow process where the oil recovery is determined by relative permeability considerations. Such a vaporize of crude oil by carbon dioxide repressuring appears to have possible use in a highly fractured formation where the major oil content of the reservoir is contained in the non-fractured porosity with little permeability. The carbon dioxide flows into the fractures, contacts the crude oil in the matrix and vaporizes part of the crude oil; this vaporized oil is produced and recovered and the carbon dioxide is reinjected again. The specific problem of this study is to attempt to answer this question; Can crude oil be produced successfully (technically, but without economic considerations) from a petroleum reservoir by a process of vaporization of the crude oil by carbon dioxide repressuring?