The Use of Pseudocomponents in the Representation of Phase Behavior of Surfactant Systems

1979 ◽  
Vol 19 (05) ◽  
pp. 289-300 ◽  
Author(s):  
J.E. Vinatieri ◽  
P.D. Fleming

Abstract A new method is developed to represent the phase behavior of multicomponent systems. This method uses fewer pseudocomponents than true components, but unlike conventional methods in which pseudocomponents are often chosen arbitrarily, the pseudocomponents are often chosen arbitrarily, the method uses regression analysis to find a "best" set of pseudocomponents.The method is applied to two surfactant systems of the type used for tertiary oil recovery. One system contains a crude oil (from the North Burbank Unit, Osage County, OK) and the other contains a pure hydrocarbon, 1-phenyltetradecane. For both systems the representation in terms of the pseudocomponents chosen by the regression analysis is significantly more faithful than that obtained by conventional methods.Since the considerations discussed here are general, they should be applicable to a wide range of phase studies in multicomponent systems. For example, they should be illuminating when applied to oil recovery by gas injection (carbon dioxide, natural gas, etc.), and to extraction processes, as well as to surfactant systems. Introduction Systems containing surface active agents have attracted a great deal of attention in connection with tertiary oil recovery. In many of these systems optimum oil recovery has been found to be strongly correlated with the phase behavior of these systems. To understand completely the basis for these correlations, one must be able to represent the phase behavior of systems containing surfactants adequately.Surfactant systems for tertiary oil recovery usually contain at least five components: oil, water, surfactant. cosurfactant, and electrolyte. The isothermal, isobaric phase diagram of these systems can be represented in a phase diagram of these systems can be represented in a four-dimensional space. Because physical representation (in three dimensions) of such a diagram is impossible. various techniques have been developed to attempt to represent the phase behavior in lower dimensional spaces. All these techniques correspond to projections of the original diagram onto lower dimensional spaces. Although almost unlimited methods of projection exist, only a small fraction convey useful information.Two projection schemes having some similarities but different intents and consequences are straight mathematical projection and "pseudocomponent" projection. Straight mathematical projection refers to the process of directly projecting the four-dimensional data for the entire phase diagram along some specified direction onto a three-dimensional space. All information parallel to the direction of the projection is lost. For example, if the rays of projections are parallel to the oil/water edge of the phase diagram, the resulting representation contains no information about the relative amounts of oil and water in the phases. In principle, this problem can be circumvented by generating two representations corresponding to projections of the same data along two different directions. For example. a second representation could be produced corresponding to a projection parallel to the water/alcohol edge of the phase diagram. parallel to the water/alcohol edge of the phase diagram. Although neither representation contains complete information, the pair of representations does contain all information about the system. The problem with this method is that the information is not perceived easily and, since the intent of using phase diagrams is usually to make visible a summary of the phase trends, such mathematical representations are not very useful.The second and generally more useful projection scheme uses pseudocomponents. A pseudocomponent is some mixture of pure components treated as a single component. SPEJ P. 289

1980 ◽  
Vol 20 (05) ◽  
pp. 402-406 ◽  
Author(s):  
James E. Vinatieri

Abstract This paper describes a study of the emulsions which could occur during a pilot surfactant flood, such as that conducted by Phillips Petroleum Co. in the North Burbank Unit, Osage County, OK. The phase behavior of this surfactant system can be characterized by three types of microemulsions, with the transition from one type to another being a function of the salinity. The rate at which emulsions coalesce was seen to correlate directly with the type of microemulsion. Coalescence was slow for macroemulsions at low salinities, rapid at intermediate salinities (where the final state was a three-phase system), and varied from slow to rapid at salinities above the three-phase region. Knowledge of the correlation between phase behavior and emulsion stability can be useful in treating macroemulsions produced during a surfactant flood. Introduction With the increased emphasis currently being placed on the use of surfactants for tertiary oil recovery, a potential problem exists with emulsions which can be produced as a consequence of a surfactant flood. For example, if a channeling problem between an injection well and a production well should occur, it may be possible to produce relatively large amounts of surfactant at moderately high concentrations (0.2 to 2.0070). Under these conditions, emulsions of oil and brine could be stabilized by the presence of the surfactant and could pose a serious problem. Although these emulsions are thermodynamically unstable and ultimately should separate into bulk oil and water phases, the presence of surfactants can increase greatly the time required for such separations. Typical oilfield operations allow, at most, several hours for this separation of phases to occur, but some emulsions containing surfactants may require weeks or even months to separate. Thus, a definite need exists for being able to accelerate this coalescence process. Phillips Petroleum Co. is conducting a pilot surfactant flood in the North Burbank Unit (NBU) in Osage County.1,2 The work reported here was directed at developing a contingency plan for breaking emulsions which may be produced by this surfactant flood. The problem of studying emulsions produced by a surfactant flood has two aspects:the nature of the phases which result when thermodynamic equilibrium finally is attained andthe rate at which this equilibrium state is reached. This is not to imply that any emulsion can be described completely by characterization of these two properties but rather that these are the two properties most important to oilfield operations and, hence, form the basis for the work reported here. The next section discusses the equilibrium properties of surfactant systems and the one following discusses the coalescence of emulsions. The fourth section describes the use of chemical demulsifiers to accelerate coalescence. Equilibrium Phase Behavior The equilibrium phase behavior of systems of oil and water containing appreciable amounts of surfactant (i.e., 0.5%) is characterized by the presence of microemulsions.1,3-5 These microemulsion phases have a high degree of structure and may contain large amounts of both oil and water.


1998 ◽  
Vol 102 (1) ◽  
pp. 200-205 ◽  
Author(s):  
E. S. J. Rudolph ◽  
M. J. Bovendeert ◽  
Th. W. de Loos ◽  
J. de Swaan Arons

Author(s):  
Saba Mahmoudvand ◽  
Behnam Shahsavani ◽  
Rafat Parsaei ◽  
Mohammad Reza Malayeri

The depletion of oil reservoirs and increased global oil demand have given impetus to employ various secondary and tertiary oil recovery methods. Gas injection is widely used in both secondary and tertiary modes, though the major problem associated with this process is the precipitation and deposition of asphaltene, particularly at near-wellbore conditions. In-depth knowledge of asphaltene phase behavior is therefore essential for the prediction of asphaltene precipitation. Previous studies reported the impact of gas injection on asphaltene phase behavior, but the knowledge of precipitation of asphaltene as a function of different mole fractions of injected gas is also imperative. In this study, the thermodynamic model of PC-SAFT EoS is used to discern the phase equilibrium of asphaltene by analyzing the asphaltene drop-out curve during gas injection. Asphaltene drop-out curves of two different live oil samples are analyzed by injecting CO2, CH4, and N2 gases at different mole percentages and temperatures. The results revealed that PC-SAFT EoS can serve as a reliable tool for estimating bubble pressure and asphaltene onset pressure for a wide range of temperatures, pressures, and compositions. The simulation results for the injection of CO2, CH4, and N2 also showed that CO2 gas gives minimum asphaltene precipitation. It reduces the size of the drop-out curve or moves it toward higher pressures. CH4 and N2 expand the drop-out curve by raising the upper onset point. CH4 increases the maximum point of the drop-out curve for two types of oil studied (A and B) at two different temperatures. N2 raises the maximum point of oil type “A” by approximately 57% at 395 K, while it has no effect on the maximum point of oil type “B”. In addition, reducing the temperature resulted in either decrease or increase of asphaltene solubility, demonstrating that the impact of temperature on asphaltene precipitation is closely related to the composition of the crude.


1980 ◽  
Vol 20 (06) ◽  
pp. 508-520 ◽  
Author(s):  
Robert E. Gladfelter ◽  
Surendra P. Gupta

Abstract This paper deals with the oil/water bank propagation in a tertiary oil recovery process. Oil/water bank propagation was studied in a series of laboratory micellar floods and simultaneous oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation. It was observed that a high oil saturation region, or hump, developed at the leading edge of the oil/water bank and grew linearly with distance. A lower steady-state oil saturation region was observed behind the hump. As the hump was produced from the core, high initial oil fractions were observed, as often seen in laboratory micellar floods. This is the result of the observed hysteresis in fractional flow behavior. A graphical method of predicting the occurrence of a hump, its rate of growth, and saturations within an oil/water bank was developed using the observed hysteresis in fractional flow. Using this prediction procedure, it was concluded that in a tertiary oil recovery process, oil breakthrough time or rate of advance of the oil/water bank, oil saturation at the leading edge, and initial produced oil fractions are only functions of the oil-saturation-increasing fractional flow curve and are not necessarily indications of oil recovery efficiency. Introduction During a tertiary oil recovery process, a small slug of displacing fluid (e.g., a micellar fluid) mobilizes residual oil and water and forms an oil/water bank. It is important to understand the propagation behavior of the oil/water bank in a tertiary oil recovery process since it affects the oil breakthrough time and initial oil cuts. This understanding also will aid in the interpretation of oil displacement tests. Moreover, oil breakthrough time and initial oil cuts have been used for judging the efficiency of a tertiary oil recovery process. Oil/water bank propagation was studied in a series of micellar floods and oil/water flow tests using a microwave scanning apparatus for measuring in-situ dynamic oil saturation profiles. Experimental Details The microwave scanning apparatus used is similar to that discussed by Parsons1 and Parsons and Jones.2 Microwaves are transmitted through a core where they are partially absorbed by the water molecules. The measured microwave power attenuation, or degree of absorption of the microwave energy, is a direct measure of the quantity of water and, consequently, of the oil saturation in an oil/water system since the oil does not absorb the microwave energy. The microwave scanning apparatus is capable of measuring the dynamic oil saturation profiles during pressure-monitored laboratory micellar floods and other oil/water flow tests. Fig. 1 is a schematic of the apparatus. Additional experimental details are given in Appendix A. Displacement tests were conducted at room temperature in 120-cm-long rectangular Berea cores (1.91 cm thick×7.62 cm wide). The brine permeability range of these cores was from 418 to 714 md, and pore volumes varied from 377 to 395 cm3. Three tertiary micellar floods were conducted in separate Berea cores with Second Wall Creek crude oil. Table 1 shows the fluid injection sequence and compositions3 for the micellar floods. In addition, simultaneous oil/water injection tests were conducted in separate Berea cores using both Second Wall Creek crude oil and refined oils (see Table 2 for the fluid injection sequence).


2021 ◽  
pp. 1-19
Author(s):  
D. Magzymov ◽  
T. Clemens ◽  
B. Schumi ◽  
R. T. Johns

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.


1984 ◽  
Vol 24 (03) ◽  
pp. 333-341 ◽  
Author(s):  
Zohreh Fathi ◽  
Fred W. Ramirez

Abstract The optimal control theory of distributed-paranieter systems has been applied to the problem of determining the best injection policy of a surfactant slug for a tertiary oil recovery chemical flood. The optimization criterion is to maximize the amount of oil recovered while minimizing the chemical cost. A steepest-descent gradient method was used as the computational approach to the solution of this dynamic optimization problem. The performance of the algorithm was examined for the surfactant injection in a one-dimensional flooding problem. Two types of interfacial tension (IFT) behavior problem. Two types of interfacial tension (IFT) behavior were considered. These are a Type A system where the IFT is a monotonically decreasing function with solute concentration and a Type B system where a minimum IFT occurs at a nominal surfactant concentration. For a Type A system, the shape of the optimal in 'faction strategy was not unique, however, there is a unique optimum for the amount of surfactant needed. For a Type B system, the shape of the optimal injection as well as the amount injected was unique. Introduction Surfactant recovery systems are being investigated by the petroleum industry as a means of increasing the petroleum supply. Commercial application of any petroleum supply. Commercial application of any surfactant flooding process relies upon economic projections that indicate a decent return on investment. projections that indicate a decent return on investment. Previously. surfactant systems for tertiary oil recovery have been optimized by adjusting concentrations of individual components empirically. Salinity has been shown to be an important variable in surfactant system optimization. The particular choice of surfactant and cosurfactant has been studied by Salager et al. Multivariable optimization of surfactant systems based on minimizing the IFT has been studied by Vinatiere et al. As reported, such an optimization may or may not coincide with optimal oil recovery since low IFT is a necessary. but not a sufficient condition for achieving, high displacement efficiency. Chemical supply and cost are important parts of economic projections. Because of the high cost of chemicals, it is essential to optimize surfactant systems to provide the greatest oil recovery at the lowest cost. In this paper, an optimization surfactant is taken as the minimization of the chemical cost and maximization of the recovered oil. The goal is to determine the best way of injecting a surfactant slug into the reservoir formation. Mathematical Formulation of the Performance Index Performance Index We desire to obtain maximum oil recovery with a minimum amount of chemical surfactant injected. These objectives can he expressed in a quantitative form through the formulation of a cost functional. J', which is to be minimized, where J' equals the cost of surfactant injected minus the value of oil recovered. This descriptive statement of the cost functional must be translated into a mathematical form to use quantitative optimization techniques. The oil value can be formulated as (1) where C1 = cost of oil per unit volume ($251.6/m 3[$40/bbl]),= volumetric flow, rate of oil at the coreoutlet L = core length, and a = time. The chemical cost is expressed mathematically as (2) where C2 = chemical cost per unit weight ofsurfactant ($5.45 × 10–3/g [$2.47/lbm]), Cs( ) = surfactant concentration of the injectedfluid in weight fraction, P slug = slug density ( 1 g/cm 3 ). and Qw, ( ) = volumetric flow rate of water at thecore inlet. The objective functional is, therefore, (3) JPT P. 333


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