Equilibrium Phase Compositions of CO2/Crude Oil Mixtures-Part 2: Comparison of Continuous Multiple-Contact and Slim-Tube Displacement Tests

1983 ◽  
Vol 23 (02) ◽  
pp. 281-291 ◽  
Author(s):  
Franklin M. Orr ◽  
Matthew K. Silva ◽  
Cheng-Li Lien
Keyword(s):  
Phase Composition ◽  
New Mexico ◽  
Crude Oil ◽  
Phase Behavior ◽  
Equilibrium Phase ◽  
Saturation Pressure ◽  
Research Center ◽  
Displacement Efficiency ◽  
Ternary Diagrams ◽  
Oil Mixtures

Orr Jr., Franklin M.; SPE; New Mexico Petroleum Recovery Research Center Petroleum Recovery Research Center Silva, Matthew K.; SPE; New Mexico Petroleum Recovery Research Center Petroleum Recovery Research Center Lien, Cheng-Li; SPE; New Mexico Petroleum Recovery Research Center Abstract Results of phase composition and density measurements for CO2/ crude-oil mixtures at 32C and four pressures are reported for a system in which liquid/liquid and liquid/liquid/vapor phase separations occur. The experiments demonstrate that a CO2-rich liquid phase can contain as much as 30 wt% hydrocarbons and show that a CO2-rich vapor phase at the same conditions extracts hydrocarbons less efficiently. Pseudoternary phase diagrams are presented that summarize the results of the detailed phase composition measurements. Results of slim-tube displacements at the same four pressures are also given. They indicate that displacement is efficient when the pressure is high enough that a liquid CO2-rich phase appears. Predictions of the performance of the slim-tube displacements based entirely on the performance of the slim-tube displacements based entirely on the experimental measurements of phase compositions and densities are obtained using a simple one-dimensional (1D) simulator. The simulation results clarify the roles of phase behavior and volume change on mixing in the slim-tube tests. Finally, the advantages and limitations of the slimtube and continuous multiple-contact (CMC) tests are compared. We conclude that the CMC experiment yields more information useful for prediction of the performance of a CO2 flood. Introduction The laboratory experiment most commonly performed in the evaluation Of CO2 flood candidates is the slim-tube displacement. The experiment is an attempt to isolate the effects of phase behavior on displacement efficiency in a flow setting that minimizes the effects of the viscous instability inherent in the displacement of oil by low-viscosity CO2. It provides useful information about the pressure required to produce high displacement efficiency in an ideal porous medium. It is not, however, a direct measurement of the phase behavior Of CO2/crude-oil mixtures. The physical behavior of such mixtures is usually studied by combining known quantities of oil and CO2 in a visual cell and measuring phase volumes at various pressures. The volumetric data obtained, along with saturation pressure pressures. The volumetric data obtained, along with saturation pressure data, do not give any direct evidence concerning displacement efficiency, but they can be used to adjust and tune representations of the phase behavior with an equation of state (EOS). For instance, Sigmund et al., used that procedure to match EOS calculations to PVT data and then simulated slimtube displacement experiments, obtaining good agreement between calculation and experiment. Gardner et al., used a combination of phase composition and volumetric measurements to construct ternary diagrams phase composition and volumetric measurements to construct ternary diagrams for a CO2/crude-oil system and then used the ternary diagrams in 1D simulations of slim-tube displacements. They also obtained good agreement between calculation and experiment. Thus there is at least some experimental confirmation of the relationship between equilibrium phase behavior and flow in an ideal porous medium. The connection between phase behavior and displacement efficiency has, of course, long been recognized. SPEJ p. 281

Phase Behavior of CO2 and Crude Oil in Low-Temperature Reservoirs

1981 ◽  
Vol 21 (04) ◽  
pp. 480-492 ◽  
Author(s):  
F.M. Orr ◽  
A.D. Yu ◽  
C.L. Lien
Keyword(s):  
Critical Temperature ◽  
Liquid Phase ◽  
Low Temperature ◽  
Crude Oil ◽  
Phase Behavior ◽  
Phase Diagrams ◽  
Ternary Mixtures ◽  
Co2 Flooding ◽  
Displacement Efficiency ◽  
Oil Mixtures

Abstract Phase behavior of CO2/Crude-oil mixtures which exhibit liquid/liquid (L/L) and liquid/ liquid/vapor (L/L/V) equilibria is examined. Results of single-contact phase behavior experiments for CO2/separator-oil mixtures are reported. Experimental results are interpreted using pseudoternary phase diagrams based on a review of phase behavior data for binary and ternary mixtures of CO2 with alkanes. Implications for the displacement process of L/L/V phase behavior are examined using a one-dimensional finite difference simulator. Results of the analysis suggest that L/L and L/L/V equilibria will occur for CO2/crude-oil mixtures at temperatures below about 120 degrees F (49 degrees C) and that development of miscibility occurs by extraction of hydrocarbons from the oil into a CO2-rich liquid phase in such systems. Introduction The efficiency of a displacement of oil by CO2 depends on a variety of factors, including phase behavior of CO2/crude-oil mixtures generated during the displacement, densities and viscosities of the phases present, relative permeabilities to individual phases, and a host of additional complications such as dispersion, viscous fingering, reservoir heterogeneities, and layering. It generally is acknowledged that phase behavior and attendant compositional effects on fluid properties strongly influence local displacement efficiency, though it also is clear that on a reservoir scale, poor vertical and areal sweep efficiency (caused by the low viscosity of the displacing CO2) may negate the favorable effects of phase behavior.Interpretation of the effects of phase behavior on displacement efficiency is made difficult by the complexity of the behavior of CO2/crude-oil mixtures. The standard interpretation of CO2 flooding phase behaviour, given first by Rathmell et al. is that CO2 flooding behaves much like a vaporizing gas drive, as described originally by Hutchinson and Braun. During a flood, vaporphase CO2 mixes with oil in place and extracts light and intermediate hydrocarbons. After multiple contacts, the CO2-rich phase vaporizes enough hydrocarbons to develop a composition that can displace oil efficiently, if not miscibly. The picture presented by Rathmell et al. appears to be consistent with phase behavior observed for CO2/ crudeoil mixtures as long as the reservoir temperature is high enough. Table 1 summarizes data reported for CO2/crude-oil mixtures. Of the 10 systems studied, all those at temperatures above 120 degrees F (50 degrees C) show only L/V equilibria while those below 120 degrees F exhibit L/L/V separations (Stalkup also reports two phase diagrams that are qualitatively similar to the other low-temperature diagrams but does not give temperatures). Thus, at temperatures not too far above the critical temperature of CO2 [88 degrees F (31 degrees C)], mixtures of CO2 and crude oil exhibit multiple liquid phases, and at some pressures L/L/V equilibria are observed. It has not been established whether Rathmell et al.'s interpretation of the process mechanism can be extended to cover the more complex phase behavior of low-temperature CO2/crude-oil mixtures. In a recent paper, Metcalfe and Yarborough argued critical temperature CO2 floods behave more like condensing gas drives, whereas Kamath et al. concluded that an increase in the solubility of liquid-phase CO2 in crude oil at temperatures near the critical temperature of CO2 should cause more efficient displacements of oil by CO2. SPEJ P. 480^

Flow Visualization for CO2/Crude-Oil Displacements

1985 ◽  
Vol 25 (05) ◽  
pp. 665-678 ◽  
Author(s):  
Bruce T. Campbell ◽  
Franklin M. Orr
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Water Saturation ◽  
High Water ◽  
Displacement Efficiency ◽  
Refined Oil ◽  
Miscible Displacements ◽  
Viscous Instability ◽  
Oil Mixtures ◽  
First Contact

Abstract Results of visual observations of high-pressure CO2 floods are reported. The displacements were performed in two-dimensional (2D) pore networks etched in glass plates. Results of secondary and tertiary first-contact miscible displacements and secondary and tertiary multiple-contact miscible displacements are compared. Three displacements with no water present were performed in each of three pore networks:displacement of a refined oil by the same oil dyed a different color;displacement of a refined oil by CO2 (first-contact miscible); anddisplacement of a crude oil at a pressure above the minimum miscibility pressure. In addition, three tertiary displacements were performed in the same pore networks;displacement of the refined oil by water, followed by displacement by the same refined oil dyed to distinguish it from the original oil;tertiary displacement of the refined oil by CO2; andtertiary displacement of crude oil by CO2. In addition, recovery of oil from dead-end pores, with and without water barriers shielding the oil, was investigated. Visual observations of pore-level displacement events indicate that CO2 displaced oil much more efficiently in both first-contact and multiple-contact miscible displacements when water was absent. In tertiary displacements of a refined oil, CO2 effectively displaced the oil it contacted, but high water saturations restricted access of CO2 to the oil. The low viscosity of CO2 aggravated effects of high water saturations because the CO2 did not displace water efficiently. CO2 did, however, contact trapped oil by diffusing through water to reach, to swell, and to reconnect isolated droplets. Finally, CO2 displaced crude oil more efficiently than it did the refined oil in tertiary displacements. Differences in wetting behavior between the refined and crude oils appear to account for the different flow behavior. Introduction If high-pressure CO2 displaces oil in a one-dimensional (1D), uniform porous medium (in which the effects of viscous fingering are necessarily absent), the displacement efficiency is controlled by the phase behavior of the CO2/crude-oil mixtures. The conventional description of the effects of phase behavior was given by Hutchinson and Braun1 for vaporizing gas drives and was extended to CO2 systems by Rathmell et al.2 In a rigorous mathematical treatment of the flow of three-component mixtures. Helfferich3 proved that the displacement will develop miscibility if the oil composition lies outside the region of tie-line extensions on a ternary diagram. Helfferich's analysis was for 1D flows in which fluids are mixed well locally, and the effects of dispersion are absent. Sigmund et al.,4 Gardner et al.,5 and Orr et al.6 showed that results of slim-tube displacements, which are nearly 1D and come close to eliminating the effects of viscous instability, can be predicted quantitatively by 1D process simulations based on independent measurements of the phase behavior and fluid properties of the CO2/crude-oil mixtures. Thus there is good experimental confirmation that the simple theory of the effects of phase behavior on displacement performance describes accurately the behavior of flow in an ideal displacement, such as a slim tube. In a CO2 flood in reservoir rock, however, a variety of other factors will influence process performance. Because the viscosity CO2 is much lower than that of most oils, viscous instability will limit the sweep efficiency of the injected CO2. In addition, Gardner and Ypma7 predicted, based on 2D simulations of the growth of a viscous finger, that an interaction between viscous instability and phase behavior would lead to higher residual oil saturation in regions penetrated by a viscous finger. Pore-structure heterogeneity may also influence displacement efficiency. Spence and Watkins8 found that residual oil saturations after CO2 waterfloods increased as the heterogeneity of the core increased. Several investigators have reported that high water saturations can alter mixing between oil and injected solvent. Raimondi and Torcaso9 found, in displacements in Berea sandstone cores, that significant fractions of the oil phase could not be contacted by injected solvent when the water saturation was high. Thomas et al.10 reported that a portion of the nonwetting phase can exist in "dendritic" pores whose shapes were determined by the surrounding wetting phase. They argued that material in the dendritic pores mixed with fluid in the flowing fraction only by diffusion. Stalkup11 and Shelton and Schneider12 also investigated effects of mobile water saturations in miscible displacements. Stalkup found that the flowing fraction decreased as the water saturation increased. Shelton and Schneider reported that the presence of a second mobile phase slowed recovery of either phase, but the nonwetting phase was affected more strongly. In their tests, all of the wetting phase was recovered by a miscible displacement, but significant amounts of nonwetting phase remained unrecovered.

Equilibrium Phase Compositions of CO2/Hydrocarbon Mixtures Part 1: Measurement by a Continuous Multiple-Contact Experiment

1983 ◽  
Vol 23 (02) ◽  
pp. 272-280 ◽  
Author(s):  
Franklin M. Orr ◽  
Matthew K. Silva
Keyword(s):  
Phase Composition ◽  
Crude Oil ◽  
Phase Behavior ◽  
Experimental Technique ◽  
Equilibrium Phase ◽  
Static Equilibrium ◽  
Volumetric Data ◽  
Composition Data ◽  
Fluid Properties ◽  
Rigorous Test

Abstract A new experimental technique that simultaneously measures compositions and densities of two phases in equilibrium is described. Because it operates continuously, the experiment can be performed more rapidly than conventional static-equilibrium measurements. Details of the experimental apparatus are reported, and results of test displacements for two simple CO2/hydrocarbon systems are compared with static-equilibrium phase composition measurements for the same systems. A simple analysis of the operation of the experiment is used to assess the experimental error that results from the continuous nature of the experiment and to suggest ways to reduce that error. Application of the experimental technique to a CO2/crude oil system is reported in a companion paper. Introduction It is by now well documented that phase behavior of CO2/crude oil mixtures has an important impact on CO2-flood-displacement efficiency. As a result, a variety of reservoir simulators applicable to CO2 flooding attempt to calculate compositions and fluid properties of phases that occur during the displacement process. However, the equations of state (EOS) or K-value correlations used to calculate the distribution of components between phases in those simulators often do not yield predictions accurate enough phases in those simulators often do not yield predictions accurate enough to be used without some experimental verification. The correlation parameters that describe the pseudocomponents used to represent the crude parameters that describe the pseudocomponents used to represent the crude oil are rarely known well enough to guarantee accurate a priori predictions. Usually, some sort of adjustment of input parameters is predictions. Usually, some sort of adjustment of input parameters is required to achieve an acceptable match of experimental phase-behavior data. Volumetric data, obtained from observations in a visual cell of binary mixtures of CO2 with crude oil at various pressures, are often used to make that adjustment. A few investigators have also reported measurements of phase compositions, though problems with sampling and analysis of high-pressure mixtures make such experiments difficult to perform. Phase-composition data provide a more rigorous test of the perform. Phase-composition data provide a more rigorous test of the predictions of a phase-behavior calculation than volumetric data and hence predictions of a phase-behavior calculation than volumetric data and hence are desirable. In addition, simultaneous fluid property data would be useful for testing predictions of phase densities and viscosities and for direct application in design of some processes--for instance, those that rely on gravity segregation to reduce the adverse impact of viscous instabilities. Unfortunately, published examples of simultaneous measurements of phase compositions and fluid properties are rare. The time and equipment required to make the mixtures, obtain samples and analyze them, and finally determine their viscosities and densities are sufficient to make such measurements unattractive for routine support of field projects. projects. SPEJ p. 272

Foamlike Dispersions for Mobility Control in CO2 Floods

1985 ◽  
Vol 25 (04) ◽  
pp. 603-613 ◽  
Author(s):  
John P. Heller ◽  
Cheng Li Lien ◽  
Murty S. Kuntamukkula
Keyword(s):  
High Pressure ◽  
Porous Media ◽  
New Mexico ◽  
Crude Oil ◽  
Mobility Control ◽  
Field Conditions ◽  
Reservoir Rock ◽  
Research Center ◽  
Displacement Efficiency ◽  
Foam Flow

Heller, John P., SPE, New Mexico Petroleum Recovery Research Center Petroleum Recovery Research Center Lien, Cheng Li, SPE, New Mexico Petroleum Recovery Research Center, Kuntamukkula, Murty S., SPE, New Mexico Petroleum Recovery Research Center Petroleum Recovery Research Center AUGUST 1985 Abstract At the reservoir temperature and pressure at which CO2 can displace a crude oil with high microscopic-displacement efficiency, its density and compressibility are close to those of the crude oil-and not greatly different from those of water itself. Because of this, the mechanical and chemical characteristics of a high-pressure, CO2-in-water "foam" cannot be assumed to be the same as those of an air/water foam at near-atmospheric pressure. pressure. This paper reports information on the mobility of foamlike dispersions in reservoir rock. The data come both from the recalculation of selected experimental work reported in the literature and from new experiments. An important criterion for these experiments is to eliminate or greatly reduce the influence of fluid compressibility, so as to approximate field conditions in CO2 floods more closely. The core flow experiments performed for this work meet this condition by use of the nonaqueous phase of either liquid CO2 at high pressure, or a light hydrocarbon to simulate dense CO2 in experiments performed at low pressure. We postulate that to be effective in retarding the growth of fingers or other instability patterns in CO2 floods while maintaining a high microscopic displacement efficiency, a foamlike dispersion of dense CO2 in surfactant/water should have the following characteristics. 1. Its aqueous-phase content should be as low as possible, to minimize oil trapping and to permit maximum possible, to minimize oil trapping and to permit maximum contact between CO2 and the crude oil. 2. Its effective mobility in the reservoir rock should be adjustable, by some parameters accessible during its generation, to about that of the oil bank it is expected to form and to displace. Introduction Since the classical flow and model experiments, and calculations of the 1950's and 1960's, it has been well known that adverse mobility ratio prevents the attainment of high areal sweep efficiencies in both miscible and immiscible displacements. The mechanism responsible for this is the formation of "fingers" of an unstable displacement front, which leads to early breakthrough and lowered oil production rates. The only apparent remedy is to thicken or to decrease the mobility of the injected fluids. An early suggestion along this line was to use foams to displace the oil. Several dozen papers over the intervening years have studied this idea further in both laboratory and field, and there is general agreement that the method holds great promise for selected plugging or diversion of flow from high-permeability streaks. Although the literature points out that large pressure drops ate required to move foam through porous media, and although this is very promising for mobility control, serious questions remain unresolved for that application. One such problem is that in most of the reported experiments, considerable expansion in volume occurred over the length of the flow system. Thus, it is difficult to separate the effects of the foam's compressibility from its inherent flow-resisting properties. An even more fundamental question concerns the mechanism of foam flow itself and the task of describing it quantitatively. We reject the idea that a useful description can be given in terms of a "foam viscosity" as measured in any standard viscometer. To explain this view, and to justify a more modest description in terms only of measurable quantities, we present a section on the rheological background of the problem. problem. This work is directed specifically toward the development of foamlike dispersions of dense CO2 in aqueous surfactant solutions for use in the control of mobility ratio in CO2 floods. We have searched the literature for applicable information, and have re-examined several studies of foam flow in porous media. In most cases the given results have been recalculated to cast them all into a common form that, it is hoped, offers a basis for calculation of the pressure gradients associated with foam flow in a reservoir. This paper also contains the results of original, steady-state experiments, performed under approximate field conditions and designed to permit the calculation of the mobility of foam-like dispersions of CO2 in reservoir rock. Finally, some general conclusions are drawn concerning the use of such foams for mobility control. Rheological Background The concept of "viscosity" to represent the resistance offered by a fluid to continuous deformation under the influence of shearing force has been a cornerstone of classical fluid mechanics and is of paramount importance in engineering practice involving fluid flow. The viscosity of a fluid is given by the ratio of shear stress to the rate of shear and is generally a strong function of temperature and weakly dependent on pressure. SPEJ p. 603

A Three-Parameter Representation of Surfactant/Oil/Brine Interaction

1983 ◽  
Vol 23 (04) ◽  
pp. 669-682 ◽  
Author(s):  
Maura C. Puerto ◽  
Ronald L. Reed
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Molar Volume ◽  
Surfactant Concentration ◽  
Low Pressure ◽  
Precise Description ◽  
Optimal Salinity ◽  
Parameter Representation ◽  
Reservoir Conditions ◽  
Oil Mixtures

Abstract When optimal salinity, C, and solubilization parameter Vo/Vs are augmented by Oil molar volume, V mo, the resulting three-parameter representation provides a more precise description of microemulsion phase behavior precise description of microemulsion phase behavior than has previously been available. It then becomes possible to introduce the idea of equivalent oils (Ego's) possible to introduce the idea of equivalent oils (Ego's) as a replacement for the equivalent alkane carbon number (EACN), which is shown to lack some of the properties needed to implement efficient preliminary properties needed to implement efficient preliminary screening of microemulsions for EOR. Broadly speaking, oils are "equivalent" when-they have the same molar volumes, optimal salinities, and solubilization parameters. If, in addition to equivalence, oils are required to have equal viscosities and similar phase behavior as a function of surfactant concentration, phase behavior as a function of surfactant concentration, then it may be possible to replace microemulsion floods of live crude at high pressure with floods of appropriately diluted dead crude at low pressure. This paper places EACN in perspective by means of the three-parameter representation, explores parallel effects of temperature and alcohol cosolvents, and reveals essential nonlinearities in optimal salinity as a function of oil composition (and hence molar volume) for mixtures of various oils. Much of this is subsequently used to develop methods for preparation of Ego's and the more complex but evidently essential equivalent systems (EqS's) needed to model live crudes. Introduction An essential step in design of a microemulsion flood is to test the proposed system and optimize it by using reservoir conditions. fluids, and rock. However, especially when pressure and temperature are high and there is gas in solution, this can be very complex and time consuming, so that it is preferable to minimize this aspect of the total design procedure. Under reservoir conditions, surfactant system phase behavior is also difficult to accomplish and assess in a satisfactory way. In fact, an opaque crude sometimes causes discrimination of the various kinds of phases and emulsions to be problematical. Therefore, it has long been a goal to replace live crude with a pure oil or mixture of pure oils. If this could be accomplished, then phase behavior and the bulk of screening floods could be done at reservoir temperature, but under low pressure, considerably easing the design process. It should be stressed, however, that laboratory tests conducted under the most realistic conditions still are required in final phases of design work. During the attempt to formulate a live-crude replacement algorithm, it became evident that the existing description of surfactant/oil/brine phase behavior was not unique. For example, a single surfactant at fixed temperature can exhibit different interfacial tensions (IFT's) for certain nonhomologous pure oils and yet all tensions can correspond to the same optimal salinity. Or a collection of oils can be found that all furnish the same middle-phase solubilization parameters but have different optimal salinities. Hence, a parameter is needed that characterizes the oil in addition to optimal salinity and solubilization parameters. In this paper, oil molar volume is proposed as one such additional parameter, and the extent to which this improves the characterization of phase behavior is discussed. The resulting three-parameter correlation then is used to replace dead or live crude with pure oil and/or pure-oil/crude-oil mixtures that are equivalent in a pure-oil/crude-oil mixtures that are equivalent in a certain sense related to phase behavior and flooding performance. performance. SPEJ p. 669

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

Research of Phase Behavior in Natural Gas Drive Process and Its Application in T_D Reservoir with HTHP

2021 ◽  
Author(s):  
Tongwen Jiang ◽  
Daiyu ZHOU ◽  
Liming LIAN ◽  
Yiming WU ◽  
Zangyuan WU ◽  
...  
Keyword(s):  
Mass Transfer ◽  
Natural Gas ◽  
Crude Oil ◽  
Phase Behavior ◽  
Viscosity Reduction ◽  
Solid Point ◽  
Displacement Efficiency ◽  
Laser Method ◽  
Gas Drive ◽  
Solid Deposition

Abstract Different from other gas drive processes, phase behavior performs more significant roles in natural gas drive process. The main reason is that more severe mass transfer effect and similar phase solubility effect have been caused by multicomponent interaction. This paper provides a series of methods to study the phase behavior in natural gas drive process, aiming to reveal further mechanism and give technical supports to the on-site practice in T_D Reservoir with HTHP. Four key parameters of natural gas drive have been determined. Firstly, laboratory compounding method has been improved to obtain real components of formation fluids and actual injected gas at formation condition (140°C, 45MPa). Secondly, 19 sets of slim tube test has been carried to determine MMP (minimum miscible pressure) and the injected gas components ensuring miscibility. Thirdly, swelling test and laser method have been used to separately obtain the viscosity reduction degree and solid deposition effects. Finally, multiple contact test has been carried to describe the miscibility behavior. All the above have been applied in T_D Reservoir. Conclusions could be drawn from the results obtained by the methods above. Firstly, swelling capacity of crude oil could be enhanced by natural gas for the formation volume factor of crude oil in T_D Reservoir increased by 57% and the viscosity decreased by 83% after natural gas injection. Secondly, MMP of dry gas and crude oil in T_D Reservoir is 43.5MPa with a miscible displacement efficiency above 90% (>30% compared with immiscible displacement efficiency), and the content of N2+C1 should be controlled over 88%. Thirdly, results of 5 levels contact experiments shows that miscibility behavior of natural gas and oil from T_D Reservoir performs an evaporative-condensate composite miscible process in which the condensate miscible process takes the lead. Finally, obvious solid point has not been observed in natural gas drive process of crude oil from T_D Reservoir at the formation temperature, and the effect of solid deposition on the fluid flow in formation could be ignored because of trace amount of solid solution (<1mg/ml) and minute formation permeability damage (<8%). The achievements above have been applied in T_D Reservoir as one of the important technical means supporting over 350,000 tons increased production by natural gas drive. A systematic methods have been reorganized to research the phase behavior in natural gas drive process and half of these methods mentioned above get partially improvement. These physical simulation experiments have covered most mainly processes and the key parameters in reservoirs with HTHP and natural gas drive, including mass transfer, viscosity, expansion, volume coefficient, MMP, miscibility behavior and solid deposition. Every experiment gives a quantitative analysis which possesses satisfied practicability in field application.

scholarly journals Rheology and Phase Behavior of Carbon Dioxide and Crude Oil Mixtures

2016 ◽  
Vol 31 (6) ◽  
pp. 5776-5784 ◽  
Author(s):  
Ruien Hu ◽  
John P. Crawshaw ◽  
J. P. Martin Trusler ◽  
Edo S. Boek
Keyword(s):  
Carbon Dioxide ◽  
Crude Oil ◽  
Phase Behavior ◽  
Oil Mixtures
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