Development and Evaluation of a More Precise Excess Gibbs Energy Expression for Vapor−Liquid and Liquid−Liquid Phase Behavior

1998 ◽  
Vol 37 (11) ◽  
pp. 4512-4519 ◽  
Author(s):  
Leon Scott ◽  
David Bush ◽  
Noel H. Brantley ◽  
Charles A. Eckert
Keyword(s):  
Liquid Phase ◽  
Gibbs Energy ◽  
Phase Behavior ◽  
Excess Gibbs Energy ◽  
Energy Expression ◽  
Gibbs Energy Expression ◽  
Vapor Liquid

Carbon Dioxide Flooding Evaluation of High Pour-Point, Paraffinic Red Wash Reservoir Oil

1983 ◽  
Vol 23 (04) ◽  
pp. 587-594 ◽  
Author(s):  
James P. Frimodig ◽  
Norman A. Reese ◽  
Craig A. Williams
Keyword(s):  
Liquid Phase ◽  
Phase Behavior ◽  
Pour Point ◽  
Physical Property ◽  
Co2 Flooding ◽  
Constant Composition ◽  
Liquid Equilibrium ◽  
Vapor Liquid Equilibrium ◽  
Co2 Gas ◽  
Vapor Liquid

Abstract Engineering methods are being developed to evaluate reservoir fluid systems for Suitability to CO2 flooding. This paper presents our evaluation procedure as applied to laboratory data for a high-pour-point [95 degrees F (35 degrees C)] oil from the Red Wash field in Utah. The data were obtained from phase behavior and slim tube experiments. The results of this work indicate that high pressures are required for a miscible displacement of the highly paraffinic. high-pour-point Red Wash oil. The minimum miscibility pressure (MMP) was found to be 4,650 psia (32 060 kPa), increasing only 5% to 4,900 psia (33 784 kPa) when the injected CO2 contains a 10 mol% nitrogen contaminant. These pressures are not currently economically obtainable in the Red Wash field. lntroduction The Red Wash field is located in Utah in the northeastern Uinta basin. With a comparatively low ultimate recovery predicted from primary depletion and waterflooding operations, the field is considered an attractive condidate for tertiary recovery methods. The work reported in this paper presents laboratory experiments and calculation techniques used in evaluating reservoir fluids for CO2 flooding. The laboratory work includes constant composition experiments, vapor/liquid equilibrium experiments, liquid-phase viscosity experiments, and slimtube multiple-contact miscibility experiments. Calculation techniques utilized a two-constant equation of state (EOS) to predict phase behavior and fluid properties. One CO2 source available in the area contains approximately 10 mol% nitrogen. To evaluate the effect of nitrogen contamination, experiments were performed with two different gases, one with and one without the nitrogen contaminant. Red Wash Oil/CO, Gas Physical Property Measurements Physical property data for the Red Wash oil/CO2 gas system were obtained from constant composition expansion (CCE), vapor/liquid equilibration (VLE), and liquid-phase viscosity experiments. CCE experiments were conducted to determine the pressure/composition behavior (bubble-point/dew-point envelope) of Red Wash oil and injection gases. VLE experiments measured vapor/liquid equilibrium constants (K values). Liquid-phase viscosities determine to what extent injection gases dissolved in the liquid phase affect the flow behavior of the reservoir oil. All experiments used Red Wash reservoir oil and two different injection gases. The first CO2 gas (Gas 1 ) was approximately 5 mol% methane and 95 mol % CO 2. The second CO2 gas (Gas 2) contained about 10 mol% nitrogen, 5 mol% methane, and 85 mol %, CO2. The exact compositions of Gases 1 and 2 and Red Wash reservoir oil are shown in Table 1. CCE Experiments A high-pressure visual PVT cell was used in the CCE experiments. All experiments were conducted at the reported reservoir temperature of 130 degrees F (54.4 degrees C). During each CCE the visual cell was loaded with measured volumes of Red Wash oil and injection gas. SPEJ P. 587^

Multiple Liquid Phases in a Natural-Gas System

10.2118/33-pa ◽  
1961 ◽  
Vol 1 (03) ◽  
pp. 137-141 ◽  
Author(s):  
Lowell Stroud ◽  
Will E. De Vaney ◽  
John E. Miller
Keyword(s):  
Phase Equilibrium ◽  
Liquid Phase ◽  
Natural Gas ◽  
Phase Equilibria ◽  
Phase Behavior ◽  
Stable Equilibrium ◽  
Analytical Data ◽  
Crude Oils ◽  
Liquid Phases ◽  
Vapor Liquid

Abstract During a recent phase study of a natural gas, two stable equilibrium liquid phases were observed at temperatures below –200F and pressures above 200 psi. This paper reviews the published literature on the occurrence of multiple equilibrium liquid phases and presents analytical data for the vapor and two equilibrium liquid phases of the liquefied natural gas at five experimental conditions. In addition, data for 30 conditions of two-phase equilibria are included. Introduction The low-temperature phase behavior of gases, most of which contained helium, has been investigated in the laboratories of the Helium Activity for many years. Since 1952, experimental studies of these systems have been continuous as part of the research program at Amarillo, Tex. Because of their value to private industries interested in participating in the Helium Conservation Program, several "Open File" reports containing phase equilibria data for helium-bearing natural gases have already been released by the helium Activity. A paper containing information on the general phase behavior, operating criteria and extensive vapor-liquid data for two helium-containing systems was recently published. Additional publications presenting experimental data on the phase relationships of various gas systems are now in process and will be available in the near future. PREVIOUS EXPERIMENTAL WORK Although the formation of multiple liquids has been reported for various systems, to our knowledge this paper is the only substantiated evidence of a vapor-liquid-liquid equilibria in a naturally occurring gas. In 1940, Vink, Ames, and others reported the presence of two liquid phases in a hydrocarbon system consisting of mixtures of crude oils, solvents and natural gas. Eilerts and co-workers published data on the recombined fluids from a gas-condensate well. This condensed gas, containing approximately 76 per cent methane and 24 per cent ethane-plus, exhibited two distinct liquid phases. Weinaug and Bradley observed "unusual" phase behavior in a reservoir mixture. These workers postulated that the anomalous phase behavior was due to the "imminent formation of a second liquid phase". Botkin, Reamer, Sage and Lacey studied two California crude oils that exhibited multiple phases. Kohn and Kurata recently reported two equilibrium liquid phases in the methane-hydrogen sulfide system. Roof and Crawford and Eakin, et al, also have reported experiments with binary systems that formed two stable equilibrium liquid phases. APPARATUS AND PROCEDURE A U. S. Bureau of Mines Phase Equilibrium Apparatus was used in conducting this study. The apparatus and procedures employed in its operation have been previously described and will not be repeated in detail in this report. Briefly, the apparatus consists of a windowed cell which can be maintained within +/−0.5F for temperatures between room temperature and –320F. Pressure within the cell can be maintained within 0.1 per cent of gauge reading up to 800 psig. Equilibrium vapor and liquid samples are obtained in special containers for analysis by a mass spectrometer. Although the accuracy of the analyzer is about +/−0.1 mol per cent, the reproducibility of the phase-equilibrium apparatus is considered relatively Poor. Values reported from methane and nitrogen are considered accurate to +/−1.0 and +/−0.6 mol per cent. Data for ethane-plus in the vapor are accurate within 0.2 mol per cent; liquid-phase data for this aggregate component are accurate within 1.5 mol per cent. For helium in the vapor phase, the analytical data are accurate within 0.2 mol per cent; liquid-phase analyses for this component were obtained by the charcoal adsorption method described by Frost and are accurate within 0.006 mol per cent. All of these references to the accuracy of reported values are conservative estimates based upon a statistical treatment of reproducibility data obtained with the apparatus.

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