Using Phase surfaces to Describe Condensing-Gas-Drive Experiments

1965 ◽  
Vol 5 (03) ◽  
pp. 184-185
Author(s):  
Fred I. Stalkup
Keyword(s):  
Phase Behavior ◽  
Miscible Displacement ◽  
Ternary Diagram ◽  
Dew Point ◽  
Plait Point ◽  
Bubble Point ◽  
Reservoir Fluid ◽  
Point Curve ◽  
The Rich ◽  
Gas Drive

Stalkup, Fred I., Junior Member AIME, The Atlantic Refining Co., Dallas, Tex. Abstract Vapor-liquid phase equilibrium experiments have been conducted in a static equilibrium cell on mixtures of a light, 450 API stock-tank gravity reservoir fluid and a rich hydrocarbon gas containing approximately 55 mole per cent of intermediate hydrocarbons. Both a pressure-vs-composition study of the gas and a simulated reservoir fluid, and a multiple-batch contact simulation of the condensing-gas-drive oil recovery process were performed. In the latter experiments equilibrium gas and liquid compositions were analyzed. Also, conventional, "condensing-gas-drive", long-tube displacement experiments of the reservoir fluid and gases of various richness were performed. The results of these experiments could not be satisfactorily interpreted by the conventional pseudo-ternary-diagram representation of multicomponent phase behavior. The results seem to be explained better by considering a bubble-point surface and a dew-point surface joined in a plait-point locus. Portions of the plait-point locus cannot be "seen" directly by the rich hydrocarbon gas because of curvature of the dew-point surface. In such a system, continuous injection of the rich gas over stationary reservoir fluid might form a zone of contiguously miscible compositions from pure rich gas to pure reservoir fluid by:saturating the reservoir fluid with injected gas to the bubble-point surface;creating by mass transfer with fresh injected gas a path of contiguously miscible compositions along the bubble-point surface to the plait-point locus; andcreating by mass transfer with additional injected gas a path of gas compositions along the dew-point surface up to the point where direct miscibility results between dew-point fluid and the injected rich gas. Introduction The use of the pseudo-ternary-phase diagram to illustrate miscible displacement phase behavior has been discussed by several authors. Such a representation of phase behavior is not rigorous, but the ternary diagram nevertheless gives a qualitative picture of what actually occurs in a miscible displacement process. Fig. 1 is a typical illustration of miscible displacement phase behavior by a ternary diagram. The multicomponent hydrocarbon system is divided into three pseudo-components: a light fraction containing methane and nitrogen, an intermediate fraction containing ethane through hexanes plus carbon dioxide, and a heavy fraction containing heptane and heavier components. A two-phase region is bounded by a dew-point curve and a bubble-point curve, which are joined at the critical point. The concept deduced from such a representation for miscible displacement by a condensing-gas-drive process is as follows: a rich gas G, which lies to the right of the limiting tie line through the critical point C, is injected into the reservoir and contacts reservoir fluid L, saturating the reservoir fluid to give bubble-point fluid L1 and equilibrium dew-point gas G1. Continued injection of rich gas changes the composition of the saturated liquid L1 through a series of liquid compositions lying along the bubble-point curve, until the critical composition C is reached, at which point direct miscibility with the rich gas is achieved. Some equilibrium gas with compositions lying along the dew-point curve from G1 to C is also formed in this process. SPEJ P. 184ˆ

Prediction of the Phase Behavior Generated by the Enriched-Gas-Drive Process

1965 ◽  
Vol 5 (02) ◽  
pp. 160-166 ◽  
Author(s):  
A.M. Rowe ◽  
I.H. Silberberg
Keyword(s):  
Computer Program ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Phase Changes ◽  
Experimental Results ◽  
High Concentration ◽  
Gas Drive ◽  
Non Equilibrium ◽  
Vapor Liquid

Abstract A computer program was written to predict the phase behavior generated by the enriched-gas-drive process. This program is based, in part, on a new concept of convergence pressure, which is then used to select vapor-liquid equilibrium ratios (K-factors) for performing a series of flash calculations. The results of these calculations are the equilibrium vapor and liquid phase compositions which define the phase envelopes. The program was used to predict phase envelopes for 11 different hydrocarbon systems on which published experimental data were available. The predicted and experimental results compare favorably. Introduction The reservoir engineer is frequently faced with the problem of predicting what will happen if gas is injected into a reservoir. One aspect of this general problem is predicting the phase changes that will occur when a non-equilibrium gas displaces a reservoir fluid. In particular, a "dry" gas, upon displacing a volatile oil will pick up intermediate components from the oil. On the other hand, a "wet" gas, containing a high concentration of intermediates, will lose some of these components to a relatively low-gravity, non-equilibrium crude. It is this latter process, occurring in the enriched-gas displacement, which is treated in this paper. In the past, these phase changes have been determined experimentally and the results incorporated into various modifications of the Buckley-Leverett analysis. Such experimental work is time consuming, and the results are sensitive to numerous experimental errors. With the wide availability of high-speed digital computing equipment and numerous correlations pertaining to the vapor-liquid equilibria of hydrocarbon systems, it is now practical to calculate such phase behavior. This paper describes a computer program for performing these calculations. THE ENRICHED GAS DISPLACEMENT PROCESS Experimental results have shown that oil recovery can be significantly increased by enriching the displacing gas with intermediate hydrocarbon components. The essential features of the phase behavior generated by this enriched-gas-drive process are commonly illustrated with ternary diagrams such as Fig. 1. In this figure, Gas D, which contains a high concentration of intermediate hydrocarbons with respect to the undersaturated Crude A, is injected into the reservoir. When D contacts A, gas goes into solution until the oil becomes saturated (Point. B). Further contacting of Gas D and saturated Oil B results in a Mixture C which separates into Vapor Y(c) and Liquid X(c). Liquid X(c) is contacted by additional Gas D, resulting in Mixture E which separates into Vapor Y(e) and Liquid X(e). Repeated contacts of the liquid by the injected gas will eventually result in Liquid X(d) of maximum enrichment existing in equilibrium with Gas Y(d). The equilibrium tie-line X(d) Y(d), when extended, passes through the Point D representing the enriched injection gas. For systems of more than three components, the predicted equilibrium states are dependent upon not only reservoir temperature and pressure, but also the compositions of the crude oil and injected gas. If the gas is sufficiently enriched, a miscible displacement is generated. Line is tangent to the phase envelope at the critical point (Point Z) and represents the limiting slope of the tie-lines as the critical state is approached. Point I therefore represents the minimum enrichment of injection gas required to generate a miscible displacement. Point G represents the minimum enrichment required for initial miscibility of the injection gas with Crude A.Attra has presented a method to be used for prediction of oil recovery by the enriched gas displacement process. To develop the phase behavior data needed, he designed the experimental procedure described in the following quotation from his paper SPEJ P. 160ˆ

Solvent and Driving Gas Compositions for Miscible Slug Displacement

1970 ◽  
Vol 10 (03) ◽  
pp. 298-310 ◽  
Author(s):  
Lyman Yarborough ◽  
L.R. Smith
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Nitrogen Concentration ◽  
Equilibrium Phase ◽  
Miscible Displacement ◽  
Limiting Factor ◽  
Liquefied Petroleum Gas ◽  
Contact Zones ◽  
Wide Range ◽  
Gas Drive

Abstract Experimental data were used for determining miscibility in liquefied petroleum gas (LPG) slug flooding and enriched gas drive of crude oils. The miscibility data for LPG slug flooding includes cases where the driving gas contains large amounts of nitrogen and when low pressure miscible displacement is desired. The results of flow tests for enriched gases miscibly displacing crude oil are given. These data cover a wide range of reservoir oil properties and miscibility pressures. Methods for predicting compositional requirements for both miscible slug displacement processes are recommended and should be useful for preliminary engineering evaluation of miscible slug displacement for a reservoir. Introduction The two most frequently applied hydrocarbon solvent processes for miscible displacement of crude oil are liquefied petroleum gas (LPG) slug flooding and enriched gas drive. A slug of the LPG or enriched gas is injected and followed by dry gas or gas-water displacement. In both cases the injected material forms a miscible slug in the reservoir. Generally, there are two fluid contact zones in which the establishment of miscibility must be considered as related to the fluid compositions and the reservoir temperature and pressure. The first zone is the solvent-reservoir oil pressure. The first zone is the solvent-reservoir oil contact zone; the second zone is where the lean scavenging gas and solvent come together. For successful miscible displacement, there must be single-hydrocarbon-phase condition throughout both contact zones. Aside from possible repressuring procedures which may be undertaken prior to solvent procedures which may be undertaken prior to solvent injection, the primary engineering control for achieving miscibility is the proper specification of the solvent and driving gas compositions. This paper discusses the compositional requirements for paper discusses the compositional requirements for miscibility to be achieved in both contact zones and considers cases where the reservoir pressure is very low or the driving gas contains a large amount of nitrogen. LPG SLUG FLOODING FOR MISCIBLE DISPLACEMENT OF CRUDE OIL In LPG slug flooding there is no problem in achieving miscibility with the crude oil under conditions where the solvent remains liquid. Miscibility between the LPG slug and the driving gas may be the limiting factor. At pressures below 1,100 to 1,200 psia, miscibility often cannot be achieved between the LPG and driving gas, and even higher pressures may be required if the available driving gas contains an appreciable concentration of nitrogen. Another area of increasing interest is LPG slug flooding in reservoirs where the pressure is 1,000 psia or below. At these pressures the methane-LPG transition cannot be pressures the methane-LPG transition cannot be single phase at temperatures below 160 degrees F. The only practicable approach to achieving miscible displacement under these conditions is to inject an ethane-rich buffer slug between the LPG and the driving gas. To determine the allowable nitrogen concentration for gases driving LPG, the phase behavior of nitrogen-methane-propane mixtures was experimentally studied at 105 degrees and 120 degrees F. Similarly, equilibrium-phase behavior data were obtained for the methane-ethane-propane system at 105 degrees F. The latter results allow estimates to be made of the buffer-slug composition necessary for miscible displacement at low pressures. Also, the effects of small amounts of butane and pentane on the phase behavior of the nitrogen-methane-propane and the nitrogen-methane-ethane-propane system were studied. SPEJ p. 278

scholarly journals Measurement and Phase Behavior Modeling (Dew Point+Bubble Point) of Co2 Rich Gas Mixture

2014 ◽  
Vol 14 (10) ◽  
pp. 1061-1066 ◽  
Author(s):  
Qazi Nasir ◽  
K.M. Sabil ◽  
Khashayar Nasrifar
Keyword(s):  
Phase Behavior ◽  
Dew Point ◽  
Behavior Modeling ◽  
Gas Mixture ◽  
Bubble Point

Effect of "Rich" Gas Composition on Multiple-Contact Miscible Displacement A Cell-to-Cell Flash Model Study

1976 ◽  
Vol 16 (06) ◽  
pp. 311-316
Author(s):  
D.D. Fussell ◽  
J.L. Shelton ◽  
J.D. Griffith
Keyword(s):  
Physical Properties ◽  
Transition Zone ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Solvent Concentration ◽  
Miscible Displacements ◽  
Hydrocarbon Fluid ◽  
A Cell ◽  
The Rich ◽  
Gas Drive

Abstract A cell-to-cell flash model was used to simulate the transition, or mixing, zone between a reservoir oil and several "rich" gases for multiple-contact miscible displacements. The transition-zone properties that control The oil recovery efficiency properties that control The oil recovery efficiency were determined and are junctions of the solvent concentration in the rich gas. Results indicate that the optimum use of solvent corresponds to a solvent concentration near the minimum enrichment level. Introduction Many papers have been published on the characteristics and applications of miscible displacement of oil with hydrocarbon fluids. The distinction is clearly made between first-contact miscible displacement, where the injected hydrocarbon fluid is miscible in all proportions with the oil, and multiple-contact miscible displacement, which occurs as a result of component transfer between hydrocarbon phases during flow in the porous media. Two general types of multiple-contact porous media. Two general types of multiple-contact miscible displacements are condensing gas or "rich" gas drive, and vaporizing or high-pressure gas drive. This paper concentrates on the rich gas drive, where the main feature is the transfer of intermediate components or solvent from the injected rich gas to the oil phase. The advantage of condensing gas drive in comparison with first-contact miscible displacement is the reduced concentration of the valuable solvent component in the injected hydrocarbon fluid. The effect of solvent concentration on the displacement process is an important factor in optimizing the use of solvent. Several studies have reported the use of compositional models to investigate the condensing gas drive process. These studies were useful in obtaining a better understanding of the component transfer between the liquid and vapor phases, and its effect on the transition zone existing between the injected hydrocarbon fluid and the reservoir oil. These studies did not define subzones within the transition zone or present methods to evaluate the properties of these subzones. A detailed numerical investigation of the effect of solvent concentration in the injected rich gas upon the behavior of the transition zone has not been reposed previously. The purpose of this work is to obtain this information, which then can be applied to the simulation of reservoir performance and the design of laboratory experiments. performance and the design of laboratory experiments. A cell-to-cell flash model described by Metcalfe et al. was used in this study. OBJECTIVES The principal objective of this study is to present a method that can be used to investigate the physical properties of the transition zone existing between properties of the transition zone existing between the rich gas and the reservoir oil in miscible displacements. Only the effect of rich gas composition on these physical properties will be demonstrated. However, the method allows investigation of the effect of other variables, such as relative-permeability characteristics, pressure, and the composition of the reservoir oil. Knowledge of the physical properties of the transition zone is considered a first step toward proper design of rich gas, multiple-contact oil proper design of rich gas, multiple-contact oil recovery methods. Additional studies are necessary for the design. Though these studies are mentioned within the paper, they are beyond the scope of this work. DESCRIPTION OF STUDY The study involved simulating the displacement of a reservoir oil with five different rich gases. The composition and properties of the fluids are given in Table 1. The reservoir temperature was 231 degrees F and the reservoir pressure was 2,250 psia for all simulations. The cell-to-cell flash model with the "phase mobility option" was used to simulate the oil recovery method. One hundred cells were used. The phase mobility option uses phase mobilities, (kr/) phase, to determine the relative volume of each phase flowing from a particular cell. SPEJ P. 310

Generalized Minimum Miscibility Pressure Correlation (includes associated papers 15845 and 16287 )

1985 ◽  
Vol 25 (06) ◽  
pp. 927-934 ◽  
Author(s):  
O. Glaso
Keyword(s):  
Molecular Weight ◽  
Miscible Displacement ◽  
Ternary Diagram ◽  
Hydrocarbon Gases ◽  
Mole Percent ◽  
Plait Point ◽  
Minimum Miscibility Pressure ◽  
Interpretation Criteria ◽  
Miscible Flooding ◽  
Hydrocarbon Gas

Abstract This paper presents a generalized correlation for predicting the minimum miscibility pressure (MMP) required for predicting the minimum miscibility pressure (MMP) required for multicontact miscible displacement of reservoir fluids by hydrocarbon, CO2, or N2 gas. The equations are derived from graphical correlations given by Benham et al. and give MMP as a function of reservoir temperature, C7+ molecular weight of the oil, mole percent methane in the injection gas, and the molecular weight of the intermediates (C2 through C6) in the gas. CO2 and N2 are represented in the current correlation by "equivalent" methane/propane- and methane/ethane-mixture injection gases, respectively. The study shows that for hydrocarbon systems, paraffinicity has an effect on MMP. In the equations, the C7+ paraffinicity has an effect on MMP. In the equations, the C7+ molecular weight of the oil is corrected to a K factor of 11.95, thereby accounting for varying paraffinicity. An additional temperature effect on N2 MMP is related to the API gravity of the oil. The N2 correlation, however, is not tested against measured MMP data other than those used to develop the equation and should be used with care. A correlation that accounts for the additional effect on CO2 MMP caused by the presence of intermediate components in the reservoir oil is presented. Predicted MMP's from the correlations developed are compared to experimental slim-tube displacement data from the literature and from our displacement tests on North Sea gas/oil systems. These displacement tests have been performed with a packed slim tube, where the effect of viscous fingering is reduced to a minimum. Introduction Multicontact miscibility is represented most easily with a ternary diagram, where the composition of the driving or displaced fluid is altered. This is obtained by vaporization of light hydrocarbon components into a driving gas or by condensation of hydrocarbon components from a driving gas into the reservoir oil. Miscibility between reservoir oils and hydrocarbon gases is achieved either by vaporization or by condensing-gas-drive mechanism, depending on the reservoir oil and injection-gas composition. With N2 and CO2, miscibility is obtained by vaporization, but with CO2, miscibility usually is achieved at lower pressure because CO2 extracts much higher-molecular-weight hydrocarbons from the reservoir oil than N2 gas. The prediction of miscibility conditions from ternary diagrams is based on experimentally determined or calculated gas and liquid compositions of a reservoir-oil/injection-gas mixture. The experimental gas and liquid equilibrium data are not easy to obtain and are often time-consuming to determine, especially near the plait point. The method for calculating gas and liquid data with point. The method for calculating gas and liquid data with equations of state to predict miscibility relies largely on gas and liquid compositions near the plait-point region. It is generally accepted that such data may not be sufficiently accurate. Flow experiments offer the most reliable method to determine the pressure required for miscibility with CO2, N 2, and hydrocarbon gas. The slim-tube method has been most widely used to determine miscibility. Different experimental procedures and interpretation criteria, however, have ted to different definitions of miscibility and have caused considerable confusion. The limitation of the slim-tube test and the problems associated with miscible displacement in porous media have been described by several authors. Phase behavior and mechanisms of miscible flooding with CO2, N2, and hydrocarbon gas have also been described by several authors. Correlations for predicting MMP have been proposed by a number of investigators and are important tools in the selection of potential reservoirs for gas miscible flooding. Therefore, the correlations must be as accurate as possible. Several CO2 MMP correlations have been published, but none of these can be used with enough published, but none of these can be used with enough confidence for final project design. They are useful, however, for screening and preliminary work. Correlations on CO2 miscible flooding have shown temperature to be the most important parameter but they disagree regarding the effect of oil type (e.g., C7+ properties of the oil). Compared with CO2 miscible flooding, very little has been published on high-pressure hydrocarbon gas miscible flooding. A recent publication gives a correlation for predicting MMP with lean hydrocarbon gases and nitrogen. In 1960, Benham et al. presented empirical curves that can estimate miscibility conditions for reservoir oils that are displaced by rich gas within a pressure range of 1,500 to 3,000 psia [10.34 to 20.68 MPa]. They assumed a limiting tie line (at the critical composition on a ternary diagram) parallel to the C1–C7+ axis and estimated mole percent methane in the injection gas from calculated percent methane in the injection gas from calculated critical points with pressure, temperature, molecular weights of C2 through C4 in the gas, and the C5+ molecular weight of the oil as variables. From Benham et al.'s data, the proposed equations have been derived for predicting MMP. SPEJ P. 927

Miscibility Relationships in the Displacement of Oil By Light Hydrocarbons

1962 ◽  
Vol 2 (04) ◽  
pp. 340-346 ◽  
Author(s):  
W.M. Rutherford
Keyword(s):  
High Pressure ◽  
Critical Temperature ◽  
Phase Behavior ◽  
Experimental Methods ◽  
Miscible Displacement ◽  
Hydrocarbon Mixtures ◽  
West Texas ◽  
Displacement Experiments ◽  
The Subject ◽  
Gas Drive

Abstract A knowledge of the limits of miscibility between reservoir oil and possible injection fluids is required for selection of the optimum miscible-injection fluid. Limits of miscibility can be estimated from the results of equilibrium phase-behavior experiments. They can also be determined by means of displacement experiments conducted in a high-pressure sandpack. This paper describes the equipment and procedure which have been developed for determining miscibility conditions by stable displacement. A systematic series of displacements of a West Texas reservoir oil was carried out. The results indicate that, at constant pressure, miscibility is a function only of the pseudo critical temperature of the injection gas. This fact, together with improved experimental methods, makes the displacement technique a rapid, reliable means for determining miscibility conditions. In conjunction with the displacement experiments, phase diagrams were constructed for the oil with dry gas and propane and with dry gas and ethane. Phase behavior of the methane-ethane-propane system was determined at 110 degrees F. The experimental work demonstrates the feasibility of using ethane-rich gases to reduce cost and pressure requirements for miscible displacement. Introduction In recent years, interest in the miscible displacement of oil by light hydrocarbon mixtures has been high. Many pilot and a few field scale projects have been started. These projects have made use of various methods for achieving miscibility:the LPG-slug process,the enriched-gas-drive process andthe high-pressure gas-drive process. Some field projects have been successful; the results of others are debatable. In general, projects which have performed best have involved the injection of an appreciable fraction of a pore volume of miscible material. Economical application of miscible displacement depends strongly on the cost of the miscible-injection fluid. If an appreciable fraction of a pore volume of material is required for successful application of these methods, a precise knowledge of the minimum requirements for miscibility in terms of composition of injection fluid is essential. Therefore, reliable experimental methods for determining miscibility conditions are important, and a procedure for estimating these conditions from the composition of the reservoir fluid is highly desirable. The subject of this paper is the problem of determining conditions which result in miscible displacement of oil by light hydrocarbon mixtures. Miscibility conditions can be estimated by means of equilibrium experiments conducted in a PVT cell, or they can be determined by means of high-pressure displacement experiments. This paper describes the equipment and procedure which have been developed for the determination of miscibility by high-pressure displacement experiments. These methods have been applied to the displacement of a West Texas reservoir oil with mixtures of dry gas, ethane and propane. In conjunction with the displacement experiments, triangular phase diagrams have been constructed for mixtures of the oil with dry gas and propane and with dry gas and ethane. The effect of injection-gas composition on conditions for miscible displacement in high-pressure sandpacks and cores has been the subject of several published papers. The experimental methods used in these investigations were such that displacements were unstable, and the effects of fingering and/or gravity layover are clearly evident in the results. Miscibility conditions were probably correct in spite of the instability phenomena, but the experiments evidently were time-consuming, and limited data were reported. Systematic high-pressure flow studies which would support a correlation of miscibility conditions have not been reported; however, Wilson has proposed the use of pseudo critical temperature of the injection gas as a parameter and Benham, et al, have based a miscibility correlation on observed and calculated equilibrium data. SPEJ P. 340^

Determination of Bubble-Point and Dew-Point Pressure Without a Visual Cell

2014 ◽  
Author(s):  
R.. Hosein ◽  
R.. Mayrhoo ◽  
W. D. McCain
Keyword(s):  
Oil And Gas ◽  
Saturation Pressure ◽  
Volatile Oil ◽  
Phase Region ◽  
Gas Condensate ◽  
Dew Point ◽  
Bubble Point ◽  
Point Pressure ◽  
Dew Point Pressure

Abstract Bubble-point and dew-point pressures of oil and gas condensate reservoir fluids are used for planning the production profile of these reservoirs. Usually the best method for determination of these saturation pressures is by visual observation when a Constant Mass Expansion (CME) test is performed on a sample in a high pressure cell fitted with a glass window. In this test the cell pressure is reduced in steps and the pressure at which the first sign of gas bubbles is observed is recorded as bubble-point pressure for the oil samples and the first sign of liquid droplets is recorded as the dew-point pressure for the gas condensate samples. The experimental determination of saturation pressure especially for volatile oil and gas condensate require many small pressure reduction steps which make the observation method tedious, time consuming and expensive. In this study we have extended the Y-function which is often used to smooth out CME data for black oils below the bubble-point to determine saturation pressure of reservoir fluids. We started from the initial measured pressure and volume and by plotting log of the extended Y function which we call the YEXT function, with the corresponding pressure, two straight lines were obtained; one in the single phase region and the other in the two phase region. The point at which these two lines intersect is the saturation pressure. The differences between the saturation pressures determined by our proposed YEXT function method and the observation method was less than ± 4.0 % for the gas condensate, black oil and volatile oil samples studied. This extension of the Y function to determine dew-point and bubble-point pressures was not found elsewhere in the open literature. With this graphical method the determination of saturation pressures is less tedious and time consuming and expensive windowed cells are not required.

High-Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of Gulf of Mexico Oil Mixed With Nitrogen

2014 ◽  
Vol 17 (03) ◽  
pp. 384-395 ◽  
Author(s):  
Odd Steve Hustad ◽  
Na Jia ◽  
Karen Schou Pedersen ◽  
Afzal Memon ◽  
Sukit Leekumjorn
Keyword(s):  
High Pressure ◽  
Gulf Of Mexico ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Positive Impact ◽  
Viscosity Reduction ◽  
Fluid Composition ◽  
Viscosity Data ◽  
Oil Viscosity ◽  
Reservoir Fluid

Summary This paper presents fluid composition, high-pressure pressure/volume/temperature (PVT) measurements, and equation-of-state (EoS) modeling results for a recombined Tahiti oil, Gulf of Mexico (GoM), and for the oil mixed with nitrogen in various concentrations. The data include: Upper and lower asphaltene onset pressures and bubblepoint pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F), asphaltene precipitation is seen after the addition of 27 mol% of nitrogen. Viscosity data for the swelled fluids showing that the addition of nitrogen significantly reduces the oil viscosity. Slimtube runs indicating that the minimum miscibility pressure (MMP) of the oil with nitrogen is significantly higher than estimated from published correlations. The data were modeled with the volume-corrected Soave-Redlich-Kwong (SRK) EoS and the perturbed-chain statistical association fluid theory (PC-SAFT) EoS. Although both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid-phase compressibility of the reservoir fluid swelled with nitrogen. Nitrogen-gas flooding is expected to have a positive impact on oil recovery because of its favorable oil-viscosity-reduction and phase behavior effects.

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