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^

Interpretation of Pressure-Composition Phase Diagrams for CO2/Crude-Oil Systems

1984 ◽  
Vol 24 (05) ◽  
pp. 485-497 ◽  
Author(s):  
F.M. Orr ◽  
C.M. Jensen
Keyword(s):  
Low Temperature ◽  
Crude Oil ◽  
Phase Behavior ◽  
Phase Diagrams ◽  
Ternary Systems ◽  
Second Phase ◽  
Stock Tank ◽  
Oil Mixtures ◽  
System Temperature ◽  
Solution Gas

Abstract Results of single-contact phase behavior studies for CO2/crude-oil mixtures often are presented as pressure-composition (P-X) phase diagrams. In such diagrams, regions of pressure and CO2 mole fraction for which more than one phase forms can be identified easily. Phase diagrams for CO2/crude-oil systems can be quite complex, however, since under some conditions such mixtures can form a liquid and a vapor, two liquid phases, or two liquids and a vapor in equilibrium. This paper examines P-X diagrams for two ternary systems, CO2/propane/hexadecane and CO2/methane/hexadecane, and describes transitions from one diagram to another that occur with changes in system temperature or changes in oil composition. Nine experimentally determined P-X diagrams are presented for mixtures of Wasson crude oil with CO2. Three different oils, stock-tank oil, stock-tank oil plus 312 scf/bbl [560 std m3/m3] solution gas, and stock-tank oil plus 602 scf/bbl [ 1084 std m3/m3 ] solution gas, were studied at three temperatures, 90, 105, and 120F [32, 41, and 49C]. Comparison of the resulting phase diagrams with those discussed for the simpler ternary systems indicates that the principal features of the crude oil phase diagrams are qualitatively consistent with those of the ternary systems. The results of the CO2/crude-oil experiments indicate that for low-temperature systems (below about 120F [49C]), the extrapolated vapor pressure (EVP) Of CO2 is a good estimate of the pressure required to produce a dense, relatively incompressible CO2-rich phase that can extract hydrocarbons efficiently from a crude oil. Hence, in the absence of other experimental evidence, the EVP curve can be used as a rough estimate of the minimum miscibility pressure (MMP) for low-temperature reservoirs. Introduction Investigations Of CO2/crude-oil phase behavior commonly include visual observations of the volumetric behavior of binary CO2/crude-oil mixtures. In such studies, metered volumes of CO2 and oil are placed in a windowed cell, and then the volume of the resulting mixture is changed, usually by injecting or removing mercury from the cell. The volume change alters the pressure of the cell contents and also changes the volumes of whatever phases are present as components redistribute between phases. The volumes of the phases are obtained by measuring the positions of interfaces within the cell, and the pressures at which phases appear or disappear are noted. The results of such studies are conveniently plotted on a pressure-composition (P-X) phase diagram (Fig. 1). On such a diagram, saturation pressures and the fraction of the cell volume occupied by one of the phases can be represented. In Fig. 1, bubble-point pressures, at which the visual cell is filled with a single phase, but below which a second phase appears at the top of the cell, are labeled "B." Dewpoint pressures (D) are those at which a second phase appears at the bottom of the cell. The dew- and bubble point curves meet at a critical point (C). Contours of constant volume fraction of one of the phases also meet at the critical point. P-X diagrams have been reported for a number of CO2/crude-oil systems. Those reported for temperatures below about 50C [122F] show liquid/liquid (L1/L2) and liquid/liquid/vapor (L1/L2/V) phase behavior while those at higher temperatures show only liquid/vapor (L/V) phase separations. The phase diagrams reported, however, show distinct differences in the shapes and locations of two- and three-phase regions. In this paper we examine the reasons for those differences and attempt to relate the appearance of a P-X diagram to phase behavior of mixtures that in reality contain many components rather than the two shown on a P-X diagram. To determine what qualitative features should appear on a P-X diagram, we examine the behavior of two ternary CO2/hydrocarbon systems at temperatures above and below the critical temperature of CO2. In addition, we report the results of a series of experiments to determine the effects of changing system temperature and the amount of solution gas on the phase behavior of a CO2/crude-oil system. Finally, we compare the behavior of the CO2/crude-oil systems with that of the simpler hydrocarbon systems. Construction of a P-X Diagram from Binary and Ternary Phase Data A P-X diagram represents only a portion of the phase behavior of a system that contains more than two components. The relationship between the representation of phase behavior on a P-X diagram with the behavior of the more complex system can be seen in Figs. 2 and 3. SPEJ P. 485^

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/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

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^

Solid–liquid phase behavior of ternary mixtures

AIChE Journal ◽  
2008 ◽  
Vol 54 (7) ◽  
pp. 1886-1894 ◽  
Author(s):  
Brian C. Attwood ◽  
Carol K. Hall
Keyword(s):  
Liquid Phase ◽  
Phase Behavior ◽  
Ternary Mixtures ◽  
Solid Liquid

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

scholarly journals Liquid–Liquid Phase Behavior of Diesel/Biofuel Blends: Ternary Mixtures of n-Hexadecane, 2,2,4,4,6,8,8-Heptamethylnonane, and Ethanol and the Binary Subsystems

2021 ◽  
Vol 35 (6) ◽  
pp. 4835-4847
Author(s):  
Anna Ballhause ◽  
Sabine Wagenfeld ◽  
Johannes Kiefer ◽  
Wolffram Schröer ◽  
Bernd Rathke
Keyword(s):  
Liquid Phase ◽  
Phase Behavior ◽  
Ternary Mixtures

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.

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