scholarly journals Phase behavior and miscible mechanism in the displacement of crude oil with associated sour gas

2019 ◽  
Vol 74 ◽  
pp. 54 ◽  
Author(s):  
Congge He ◽  
Longxin Mu ◽  
Anzhu Xu ◽  
Lun Zhao ◽  
Jun He ◽  
...  
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Drive Mechanism ◽  
Investment Cost ◽  
Compositional Simulator ◽  
Point Pressure ◽  
Gas Drive ◽  
Effective Development ◽  
Sour Gas

The re-injection of associated sour gas, with high H2S and CO2 content, into the reservoir is proposed to be an effective development method due to its low investment cost and high oil recovery. The aim of this work is to present the phase behavior and miscible mechanism of crude oil displaced by associated sour gas. Based on the equation of state and the phase equilibrium theory, the phase behavior of crude oil mixed with various gases (associated sour gas, H2S, CO2 and CH4) have been analyzed. Then, the miscibility of associated sour gas was determined by calculating its Minimum Miscible Pressure (MMP) and the effect of sour component fraction on miscibility was evaluated. Moreover, a series of numerical simulations modeling 1D slim-tube were conducted using a compositional simulator to study the miscible mechanism in the displacement of crude oil with associated sour gas. The results show that the injection of H2S can reduce the bubble point pressure of crude oil and therefore is beneficial to prevent the crude oil degassing; nevertheless, the injection of CO2 has little effect on it. The miscible ability of associated sour gas decreases as its sour component fraction decreases. It is observed that the crude oil displaced by associated sour gas and sweet gas both show a combined condensing/vaporizing mechanism, with miscible zone in the middle of transition zone. However, the vaporizing-gas drive mechanism is slightly stronger than the condensing-gas drive mechanism during the displacement by associated sour gas while is significantly stronger during the displacement by sweet gas.

Surfactant Retention in Berea Sandstone- Effects of Phase Behavior and Temperature

1982 ◽  
Vol 22 (06) ◽  
pp. 962-970 ◽  
Author(s):  
J. Novosad
Keyword(s):  
Porous Media ◽  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Liquid Interface ◽  
Divalent Ions ◽  
Surfactant Precipitation ◽  
Wide Range ◽  
Solid Liquid Interface ◽  
Solid Liquid

Novosad, J., SPE, Petroleum Recovery Inst. Abstract Experimental procedures designed to differentiate between surfactant retained in porous media because of adsorption and surfactant retained because Of unfavorable phase behavior are developed and tested with three types of surfactants. Several series of experiments with systematic changes in one variable such as surfactant/cosurfactant ratio, slug size, or temperature are performed, and overall surfactant retention then is interpreted in terms of adsorption and losses caused by unfavorable phase behavior. Introduction Adsorption of surfactants considered for enhanced oil recovery (EOR) applications has been studied extensively in the last few years since it has been shown that it is possible to develop surfactant systems that displace oil from porous media almost completely when used in large quantities. Effective oil recovery by surfactants is not a question of principle but rather a question of economics. Since surfactants are more expensive than crude oil, development of a practical EOR technology depends on how much surfactant can be sacrificed economically while recovering additional crude oil from a reservoir.It was recognized earlier that adsorption may be only one of a number of factors that contribute to total surfactant retention. Other mechanisms may include surfactant entrapment in an immobile oil phase surfactant precipitation by divalent ions, surfactant precipitation caused by a separation of the cosurfactant from the surfactant, and surfactant precipitation resulting from chromatographic separation of different surfactant specks. The principal objective of this work is to evaluate the experimental techniques that can be used for measuring surfactant adsorption and to study experimentally two mechanisms responsible for surfactant retention. Specifically, we try to differentiate between the adsorption of surfactants at the solid/liquid interface and the retention of the surfactants because of trapping in the immobile hydrocarbon phase that remains within the core following a surfactant flood. Measurement of Adsorption at the Solid/Liquid Interface Previous adsorption measurements of surfactants considered for EOR produced adsorption isotherms of unusual shapes and unexpected features. Primarily, an adsorption maximum was observed when total surfactant retention was plotted against the concentration of injected surfactant. Numerous explanations have been offered for these peaks, such as a formation of mixed micelles, the effects of structure-forming and structurebreaking cations, and the precipitation and consequent redissolution of divalent ions. It is difficult to assess which of these effects is responsible for the peaks in a particular situation and their relative importance. However, in view of the number of physicochemical processes taking place simultaneously and the large number of components present in most systems, it seems that we should not expect smooth monotonically increasing isotherms patterned after adsorption isothemes obtained with one pure component and a solvent. Also, it should be realized that most experimental procedures do not yield an amount of surfactant adsorbed but rather a measure of the surface excess.An adsorption isotherm, expressed in terms of the surface excess as a function of an equilibrium surfactant concentration, by definition must contain a maximum if the data are measured over a sufficiently wide range of concentrations. SPEJ P. 962^

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

Phase Boundaries of Microemulsion Systems as a Way of Characterizing Hydrocarbon Mixtures

1981 ◽  
Vol 21 (06) ◽  
pp. 763-770 ◽  
Author(s):  
Kishor D. Shah ◽  
Don W. Green ◽  
Michael J. Michnick ◽  
G. Paul Willhite ◽  
Ronald E. Terry
Keyword(s):  
Crude Oil ◽  
Phase Boundary ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Single Phase ◽  
Carbon Number ◽  
Phase Boundaries ◽  
Titration Method ◽  
Lower Phase ◽  
Surfactant System

Abstract Phase behavior of microemulsions composed of TRS 10-80, brine (10.6 mg/g NaCl), isopropyl alcohol, and mixtures of pure hydrocarbons was studied to determine the location of phase boundaries of the single-phase microemulsion region. Studies were conducted on pseudoternary phase diagrams where the pseudocomponents were isopropanol, brine, and a constant ratio of surfactant to hydrocarbon (S/H). Phase boundaries were determined be the titration method developed by Bowcott and Schulman, which was extended to systems of interest for oil recovery by Dominguez et al.The titration method involves the addition of brine to a single-phase microemulsion until phase separation occurs. Then the system is titrated to transparency by addition of isopropanol. Dominguez et al. demonstrated the applicability of the titration method for systems containing pure alkanes. They found upper and lower phase boundaries (high and low alcohol concentrations) for the microemulsion regions on S/H pseudoternary diagrams that were represented by linear relationships between the volume of alcohol and the volume of brine required to attain a single-phase microemulsion. This region, termed Region 4, bounded by linear phase boundaries, extends over a wide range of brine concentrations including regions of interest to enhanced oil-recovery processes. The research reported in this paper extends the work of Dominguez et al. to mixtures of pure hydrocarbons. The locations of the lower phase boundaries for Region 4 were determined for four types of mixtures prepared with pure hydrocarbons ranging from C6 to C18.In all phase behavior experiments, the lower phase boundary of Region 4 was a straight line when volume of alcohol was plotted against volume of brine. Furthermore, the slope of this phase boundary was found to be a linear function of alkane carbon number (ACN) for pure hydrocarbons and equivalent alkane carbon number (EACN) for mixtures of pure hydrocarbons.The correlation of a property of the phase diagram (the slope of the lower phase boundary) with EACN suggests a new approach to characterization of hydrocarbon/surfactant systems. In our experience, the EACN determined from phase behavior studies is more reproducible than the EACN determined from methods involving measurements of interfacial tensions. This method has potential for characterization of surfactant/hydrocarbon systems for complex mixtures of hydrocarbons, including crude oils. Introduction The design of a surfactant system for an enhanced oil-recovery application typically requires much effort, expense, and time. The surfactant system, usually consisting of a petroleum sulfonate and an alcohol dissolved in a brine solution, must be tailormade for a given crude oil/reservoir brine system where it will be applied. The process in finding the optimal system involves varying the components in the surfactant system in compatibility tests, phase behavior studies, physical property measurements, and displacement tests in both Berea and actual reservoir rock.One of the most important considerations in this screening procedure is matching the sulfonate to the crude oil of interest. This can be difficult since both the sulfonate and the crude oil are complex mixtures of pure components. It would be advantageous if each could be characterized by some physical property. SPEJ P. 763^

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

Thermodynamic Modeling of Phase and Tension Behavior of CO2/Hydrocarbon Systems

1985 ◽  
Vol 25 (02) ◽  
pp. 235-254 ◽  
Author(s):  
Muhammad Sahimi ◽  
H. Ted Davis ◽  
L.E. Scriven
Keyword(s):  
Phase Equilibria ◽  
Crude Oil ◽  
Phase Behavior ◽  
Gradient Theory ◽  
Homogeneous Fluid ◽  
Liquid Liquid Extraction ◽  
Interfacial Composition ◽  
Composition Profiles ◽  
Gas Drive ◽  
Liquid Vapor

Abstract The gradient theory of in homogeneous fluid is used to predict phase splits and compositions, interfacial composition profiles, and interfacial tension (IFT) of liquid-liquid, liquid-vapor, and liquid-liquid-vapor equilibria in binary and ternary mixtures of CO2 with propane and decane. The theory's input are the equation of state (EOS) of homogeneous fluid and the influence parameters of inhomogeneous fluid. An efficient computational algorithm is presented for simultaneously generating phase behavior, critical points, interfacial composition profiles, and tension between the phases. Most calculations are made with the Peng-Robinson EOS and the geometric mixing rule for the influence parameters. Use of other EOS and alternative schemes for choosing the influence parameters is explored. Introduction CO2 is a promising agent for enhancing petroleum recovery. Laboratory and field studies have established that CO2 can be an efficient oil-displacing agent. The various mechanisms by which it can act includesolution gas drive,immiscible CO2 drive,hydrocarbon/CO2 miscible drive,hydrocarbon vaporization,direct miscible CO2 drive, andmulticontact dynamic miscible drive. Phase-equilibria a data for CO2-reservoir oils have been reported. The data suggest that two distinct types of equilibria are possible. In one, there are only two phases, liquid and vapor. In the other, there is a region of liquid-vapor equilibrium, but in the phase diagram it exists in conjunction with both liquid-liquid and liquid-liquid-vapor regions. Hutchinson and Braun have shown how a lean gas can develop miscibility with a relatively rich oil. Miscibility is achieved when the lean gas strips intermediates from the liquid until the gas composition is rich enough to be miscible with the original oil. This process is called the high-pressure or vaporizing gas drive. In CO2/crude-oil systems of only one liquid phase and one vapor phase, the miscibility development mechanism can be regarded as vaporization. If the temperature is relatively low, the mechanism is described more accurately as condensation (absorption) of CO2 into the oil phase. In CO2/crude-oil systems that display more than one liquid phase in conjunction with a vapor phase, the mechanism is one of condensation and can account for a phenomenon reported by Shelton and Yarborough, namely that two liquid phases card form either with or without vapor being present. The displacement then has the appearance of a liquid-liquid extraction process. In any case, the miscibility development mechanism is related directly to the phase equilibria of the CO2/reservoir-fluid system. All these mechanisms are characterized by high recoveries in the laboratory. Simon et al. suggested that IFT effects are responsible for high recoveries in a vaporizing situation and might be equally effective in a liquid-liquid extraction situation; consequently, it is desirable to study tension behavior along with the phase behavior of CO2/hydrocarbon systems, as we do here. We make use of a molecular theory, the gradient theory of inhomogeneous fluid, which unifies phase and tension behavior in a practicable way. Such an approach has not been followed before. The CO2/propane (C3) / decane (C1O) system was selected for this study because CO2-C3 and CO2-C1O binary phase equilibria data for wide ranges of temperature and pressure are available. Propane represents the light ends and decane the heavier components. Of course, CO2 and reservoir oils do not have exactly the same phase (and therefore tension) behavior as the simple binary and ternary systems discussed here, but as Hutchinson and Braun demonstrated, these systems can give at least a qualitative description of the phase behavior of CO2/crude-oil systems, although Rathmell et al. indicated that when large amounts of CO2 and methane (C1) are both present, a quaternary diagram is needed to account for the observed behavior. Phase Behavior Calculations The design of a CO2 flooding process requires accurate phase behavior predictions of the equilibrium between the oil in place and the injected CO2. In one approach, the experimental data and extrapolations or interpolations are used in the process simulator. This approach can be quite inaccurate unless a great deal of data are available. Alternatively, an EOS can be postulated and its adjustable parameters fit to a limited amount of data. This is clearly the best approach when a good EOS can be found. As shown in the next section, it is the only feasible approach when IFT are to be predicted along with phase behavior. SPEJ P. 235^

scholarly journals A Study of Asphaltene Precipitation Problem in some wells in Kurdistan Region

2020 ◽  
Vol 4 (6) ◽  
pp. 27-36
Author(s):  
akram Humoodi ◽  
Baroz Aziz ◽  
Dana Khidhir
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil And Gas ◽  
Surface Condition ◽  
Oil And Gas Industry ◽  
Kurdistan Region ◽  
Asphaltene Precipitation ◽  
Oil Composition ◽  
Reservoir Conditions ◽  
Point Pressure

Throughout the production and reservoir lifecycle, the asphaltene precipitation is an ever existing problem through changing the porosity, permeability and wettability leading to decline in production. The conditions that govern Asphaltene precipitation varies from well to well and from reservoir conditions of high pressure and temperature to surface conditions and need to be studied case by case. The modeling and predicting the phase behavior and precipitation of Asphaltene is paramount for wells in Kurdistan region as it is developing its oil and gas industry. Crude oil samples from three wells in Kurdistan Region-Iraq were selected for this study. Experimental data such as crude oil composition using Gas Chromatography, PVT analysis and reservoir pressure and temperature were used as input data into Computer Modeling Group CMG simulator and a model of Asphaltene phase behavior was suggested. The model suggests that the maximum precipitation occurs near the bubble point pressure at reservoir conditions. This is validated and compared with results in literature indicating similar behavior of crude oil. To predict the Asphaltene precipitation at surface condition a modified Colloidal Instability Index CII were used and the results were validated by De Bore plot

Experimental Analysis of Alkali-Brine-Alcohol Phase Behavior with High Acid Number Crude Oil

2021 ◽  
pp. 1-19
Author(s):  
D. Magzymov ◽  
T. Clemens ◽  
B. Schumi ◽  
R. T. Johns
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Complex Mixture ◽  
Acid Number ◽  
Field Application ◽  
Water Interface ◽  
Total Acid ◽  
Oil Water

Summary A potential enhanced oil recovery technique is to inject alkali into a reservoir with a high-total acid number (TAN) crude to generate soap in situ and reduce interfacial tension (IFT) without the need to inject surfactant. The method may be cost-effective if the IFT can be lowered enough to cause significant mobilization of trapped oil while also avoiding formation of gels and viscous phases. This paper investigates the potential field application of injecting alkali to generate in-situ soap and favorable phase behavior for a high-TAN oil. Oil analyses show that the acids in the crude are a complex mixture of various polar acids and not mainly carboxylic acids. The results from phase behavior experiments do not undergo typical Winsor microemulsion behavior transition and subsequent ultralow IFTs below 1×10−3 mN/m that are conventionally observed. Instead, mixing of alkali and crude/brine generate water-in-oil macroemulsions that can be highly viscous. For a specific range of alkali concentrations, however, phases are not too viscous, and IFTs are reduced by several orders of magnitude. Incremental coreflood recoveries in this alkali range are excellent, even though not all trapped oil is mobilized. The viscous phase behavior at high alkali concentrations is explained by the formation of salt-crude complexes, created by acids from the crude oil under the alkali environment. These hydrophobic molecules tend to agglomerate at the oil-water interface. Together with polar components from the crude oil, they can organize into a highly viscous network and stabilize water droplets in the oleic phase. Oil-soluble alcohol was added to counter those two phenomena at large concentrations, but typical Winsor phase behavior was still not observed. A physicochemical model is proposed to explain the salt-crude complex formation at the oil-water interface that inhibits classical Winsor behavior.

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.

Phase Behavior and Properties of a Petroleum Sulfonate Blend

1981 ◽  
Vol 21 (05) ◽  
pp. 573-580 ◽  
Author(s):  
J.H. Bae ◽  
C.B. Petrick
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Surfactant Solution ◽  
Phase Region ◽  
Salinity Range ◽  
Equal Weight ◽  
Optimal Salinity ◽  
Petroleum Sulfonate

Abstract A sulfonate system composed of Stepan Petrostep TM 465, Petrostep 420, and 1-pentanol was investigated. The system was found to give ultralow interfacial tension against crude oil in a reasonable range of salinity and sulfonate concentrations. It also was found that sulfonate partitioned predominantly into the microemulsion phase. However, a significant amount also partitioned into water and, at high salinity, into the oil phase. On the other hand, the oil-soluble 1-pentanol partitioned mostly into oil and microemulsion phases.The interfacial tension between excess oil and water phases was ultralow, in the range of 10-3 mN/m. The tensions were close to and paralleled those between the middle and water phases. The trend remained the same even when the alcohol content changed. This means that in the salinity range that produces a three-phase region, below the optimal salinity, the water phase effectively displaces both oil and middle phases, even though the oil may not be displaced effectively by the middle phase. The implication is that, from an interfacial tension point of view, the oil recovery would be more favorable in the salinity range below the optimal salinity with the mixed petroleum sulfonate system used here. This was confirmed by oil recovery tests in Berea cores. It also was concluded that the change in viscosity upon microemulsion formation might have a significant influence on the surfactant flood performance. Introduction During a surfactant flood, the injected slug of surfactant solution undergoes complex changes as it traverses the reservoir. The surfactant solution is diluted by mixing with reservoir oil and brine and by depletion of surfactant due to retention. Also, the reservoir salinity rarely is the same as that of the injected solution. Moreover, there is chromatographic separation of sulfonate and cosurfactant.When phase equilibrium between oil, brine, and injected surfactant is reached in the front portion of the slug, a microemulsion phase is formed. This phase behavior and its importance in oil recovery have been the subject of numerous papers in recent years. The microemulsion phase formed in the reservoir contacts fresh reservoir brine and oil and undergoes further changes. All these changes are accompanied by property changes of the phases that affect oil recovery.The objective of this paper is to investigate the properties of a blend of commercial petroleum sulfonates and its behavior in different environments. The phase volume behavior and changes in the properties of different phases and their effects on oil recovery were studied. This work was done as part of the design of a surfactant process for a field application. Therefore, a crude oil was used as the hydrocarbon phase. Experimental Procedures A blend of Petrostep 465 and 420 from Stepan Chemical Co. was used as the surfactant. An equal weight of each sulfonate on a 100% active basis was mixed. 1-pentanol from Union Carbide Corp. was used as a cosurfactant. Unless otherwise stated, a 50g/kg sulfonate concentration was used in the solution. We used symbols to denote the formulation. The first number in the symbol indicates the 1-pentanol concentration; the last number indicates the NaCl concentration. Thus, 15 P 10 means that the solution consists of 50 g/kg sulfonate, 15 g/kg 1-pentanol, and 10 g/kg NaCl. The sulfonate blend first was mixed with alcohol, and then the required amount of NaCl brine was added to make the solution. SPEJ P. 573^

Advantages of an APS/AES Seawater-Based Surfactant Polymer Formulation

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3494-3506
Author(s):  
Jeffrey G. Southwick ◽  
Carl van Rijn ◽  
Esther van den Pol ◽  
Diederik van Batenburg ◽  
Arif Azhan ◽  
...  
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Salinity Gradient ◽  
Low Complexity ◽  
Fine Tuning ◽  
Reservoir Rock ◽  
Similar Amount ◽  
Type I ◽  
Chemical Flooding

Summary A low-complexity chemical flooding formulation has been developed for application in offshore environments. The formulation uses seawater with no additional water treatment beyond that which is normally performed for waterflooding (filtration, deoxygenation, etc.). The formulation is a mixture of an alkyl propoxy sulfate (APS) and an alkyl ethoxy sulfate (AES) with no cosolvent. With seawater only (no salinity gradient), the blend of APS and AES gives substantially higher oil recovery than a blend of APS and internal olefin sulfonate (IOS) in outcrop sandstone. This formulation also reduces complexity, increases robustness, and potentially improves project economics for onshore projects as well. It is shown that the highest oil recovery is obtained with surfactant blends that produce formulations that are underoptimum (Winsor Type I phase behavior) with reservoir crude oil. Also, these underoptimum formulations avoid the high-injection pressures that are seen with optimum formulations in low-permeability outcrop rock. The formulation recovers a similar amount of oil in reservoir rock in the swept zone. Overall recovery in reservoir rock is lower than outcrop sandstone due to greater heterogeneity, which causes bypassing of crude oil. A successful formulation was developed by first screening surfactants for phase behavior then fine tuning the formulation based on insights developed with corefloods in consistent outcrop rocks. The consistency of the outcrop is essential to understand cause and effect. Then, final floods were performed in reservoir rock to confirm that low interfacial tension (IFT) is propagated through the core.

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