Interpretation of the Change in Optimal Salinity With Overall Surfactant Concentration

1982 ◽  
Vol 22 (06) ◽  
pp. 971-982 ◽  
Author(s):  
George J. Hirasaki
Keyword(s):  
Sodium Chloride ◽  
Phase Behavior ◽  
Surfactant Concentration ◽  
Equilibrium Composition ◽  
Chemical Flooding ◽  
Alkyl Ether ◽  
Divalent Ions ◽  
Optimal Salinity ◽  
Phase Rule ◽  
Compositional Simulator

Abstract Background. For chemical flooding formulations, optimal salinity changes with overall surfactant concentration when the phase behavior is observed in test tubes. Applying these observations to the mathematical simulator is questionable because chromatographic mechanisms during displacement through porous media result in different compositions. Purpose. This work sought the mechanism for the observed change so that calculated optimal salinity can be expressed through the appropriate intensive variable rather than overall surfactant concentration. Method. Association of the alcohol has been described by partition coefficients for distribution of the alcohol among brine, oil, and surfactant. The alcohol was isopropanol (IPA), 1-butanol (NBA), or tertiary amyl alcohol (TAA) in the systems in which they were included and was used to represent a disulfonate in the system with Petrostep petroleum sulfonate. Association of sodium and divalent ions with surfactant has been described by the Donnan equilibrium model, which experimental observations show can be applied to microemulsions as well as to micelles. Conclusions. For the seven systems investigated, the change in optimal salinity is a function of (1) the alcohol associated with the surfactant and (2) the divalent ion fraction of the associated counterions. Introduction Reed and Healy reviewed the concept of optimal salinity for minimum inter-facial tension (IFT) and its relationship to phase behavior. They showed that, as a first approximation, phase behavior can be represented by electrolyte concentration and three pseudocomponents: brine, oil, and surfactant plus cosolvent. If the system actually contains three components plus sodium chloride, optimal salinity should be independent of overall surfactant concentration and WOR. However. in the system Reed and Healy investigated, optimal salinity changed with overall surfactant concentration and WOR, which indicates that the system did not contain just sodium chloride plus three additional components. To handle this problem, Vinatieri and Fleming suggested using regression analysis to determine the best set of pseudocomponents. Then alcohol can be included with the oil and brine as pseudocomponents. Blevins et al. examined the phase behavior of a quaternary system (with brine as a pseudocomponent) by examining pseudoternary planes on a quaternary diagram. Glover et al. showed that the change in optimal salinity of a system containing divalent ions can be modeled by (1) considering the equilibrium composition of the brine, and (2) describing optimal salinity as a linear function of the concentration of divalent ions associated with the sulfonate. They assumed that NEODOL 25-3S did not associate divalent ions. (NEODOL 25-3S is a sodium salt of C12-C15 alkyl ether sulfate, with an average ethylene oxide number of three. Hereafter in this paper it is abbreviated as N253S.) Pope and Nelson showed that phase behavior and IFT's can be modeled in a compositional simulator when optimal salinity and the upper and lower limits of the Type III environment are known. The purpose of this work is to model alcohol or multiple surfactant components and divalent ions so that they can be included in a compositional simulator. Thermodynamic Analysis The Gibbs phase rule is used to show that a four-component system of pure oil, surfactant, water, and NaCl has an optimal salinity that does not depend on overall surfactant concentration. SPEJ P. 971^

Oil emulsion characteristics as significance in efficiency forecast of oil-displacing formulations based on surfactants

2021 ◽  
pp. 91-107
Author(s):  
E. A. Turnaeva ◽  
E. A. Sidorovskaya ◽  
D. S. Adakhovskij ◽  
E. V. Kikireva ◽  
N. Yu. Tret'yakov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Surfactant Concentration ◽  
Chemical Flooding ◽  
Optimal Salinity ◽  
Oil Emulsion ◽  
Oil Displacement ◽  
Laboratory Selection ◽  
Reservoir Conditions ◽  
Selection Of ◽  
Comprehensive Study

Enhanced oil recovery in mature fields can be implemented using chemical flooding with the addition of surfactants using surfactant-polymer (SP) or alkaline-surfactant-polymer (ASP) flooding. Chemical flooding design is implemented taking into account reservoir conditions and composition of reservoir fluids. The surfactant in the oil-displacing formulation allows changing the rock wettability, reducing the interfacial tension, increasing the capillary number, and forming an oil emulsion, which provides a significant increase in the efficiency of oil displacement. The article is devoted with a comprehensive study of the formed emulsion phase as a stage of laboratory selection of surfactant for SP or ASP composition. In this work, the influence of aqueous phase salinity level and the surfactant concentration in the displacing solution on the characteristics of the resulting emulsion was studied. It was shown that, according to the characteristics of the emulsion, it is possible to determine the area of optimal salinity and the range of surfactant concentrations that provide increased oil displacement. The data received show the possibility of predicting the area of effectiveness of ASP and SP formulations based on the characteristics of the resulting emulsion.

Evaluation of the Salinity Gradient Concept in Surfactant Flooding

1983 ◽  
Vol 23 (03) ◽  
pp. 486-500 ◽  
Author(s):  
G.J. Hirasaki ◽  
H.R. van Domselaar ◽  
R.C. Nelson
Keyword(s):  
Active Region ◽  
Phase Behavior ◽  
Aqueous Phase ◽  
Surfactant Concentration ◽  
High Salinity ◽  
Salinity Gradient ◽  
Type Ii ◽  
Middle Phase ◽  
Optimal Salinity ◽  
Type Iii

Abstract Salinity design goals are to keep as much surfactant as possible in the active region and to minimize surfactant possible in the active region and to minimize surfactant retention. Achieving these is complicated becausecompositions change as a result of dispersion, chromatographic separation of components distributed among two or more phases, and retention by adsorption onto rock and/or absorption in a trapped phase-.in the presence of divalent ions, optimal salinity is not constant but a function of surfactant concentration and calcium/sodium ratio: andthe changing composition of a system strongly influences transport of the components. A one-dimensional (ID) six-component finite-difference simulator was used to compare a salinity gradient design with a constant salinity design. Numerical dispersion was used to evaluate the effects of dispersive mixing. These simulations show that, with a salinity gradient, change of phase behavior with salinity can be used to advantage both to keep surfactant in the active region and to minimize retention. By contrast, under some conditions with a constant salinity design. it is possible to have early surfactant breakthrough and/or large surfactant retention. Other experiments conducted showed that high salinity does retard surfactant, and, if the drive has high salinity. a great amount of surfactant retention can result. The design that produced the best recovery had the water flood brine over optimum and the drive under optimum; the peak surfactant concentration occurred in the active region and oil production ceased at the same point. Introduction The phase behavior of surfactant/oil/brine systems for different salinities is shown in Fig. 1. Low salinities. called "underoptimum" or "Type II(−)" phase behavior, are shown at the top of Fig. 1. In this kind of system, surfactant is partitioned predominantly into the aqueous phase. predominantly into the aqueous phase. High salinities, called "overoptimum" or "Type II(+)" phase behavior, are shown at the bottom of Fig. 1. In this kind of system, surfactant is partitioned predominantly into the oleic phase. When the oleic phase predominantly into the oleic phase. When the oleic phase has a low oil concentration, the oil is said to be "swollen" by the surfactant and brine. At moderate salinities, the system can have up to three phases and is called "Type III." This is illustrated in the phases and is called "Type III." This is illustrated in the middle of Fig. 1. The salinity at which the middle phase has a WOR of unity is called "optimal salinity" because the lowest interfacial tensions (IFT's) usually occur near this salinity. As salinity increases, there is a steady progression from Type II(−) to Type III to Type II(+) phase behavior. The middle-phase composition moves from the brine side of the diagram to the oil side. The two-phase regions that correspond to the Type II(−) and Type II( +) systems can be seen above the three-phase region in Fig. 1.

Modeling of Pressure and Solution Gas for Chemical Floods

SPE Journal ◽  
2013 ◽  
Vol 18 (03) ◽  
pp. 428-439 ◽  
Author(s):  
M.. Roshanfekr ◽  
R.T.. T. Johns ◽  
M.. Delshad ◽  
G.A.. A. Pope
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Atmospheric Pressure ◽  
Carbon Number ◽  
Chemical Flooding ◽  
Reservoir Pressure ◽  
Optimal Salinity ◽  
Free Gas ◽  
Cubic Equation ◽  
Solution Gas

Summary The goal of surfactant/polymer (SP) flooding is to reduce interfacial tension (IFT) between oil and water so that residual oil is mobilized and high recovery is achieved. The optimal salinity and optimal solubilization ratios that correspond to ultralow IFT have recently been shown, in some cases, to be a strong function of the methane mole fraction in the oil at reservoir pressure. We incorporate a recently developed methodology to determine the optimal salinity and solubilization ratio at reservoir pressure into a chemical-flooding simulator (UTCHEM). The proposed method determines the optimal conditions on the basis of density estimates by use of a cubic equation of state (EOS) and measured phase-behavior data at atmospheric pressure. The microemulsion phase-behavior (Winsor I, II, and III) are adjusted on the basis of this predicted optimal salinity and solubilization ratio in the simulator. Parameters for the surfactant phase-behavior equation are modified to account for these changes, and the trend in the equivalent alkane carbon number (EACN) is automatically adjusted for pressure and methane content in each simulation gridblock. We use phase-behavior data from several potential SP floods to demonstrate the new implementation. The implementation of the new phase-behavior model into a chemical-flooding simulator allows for a better design of SP floods and more-accurate estimations of oil recovery. The new approach could also be used to handle free gas that may form in the reservoir; however, the SP-flood simulation when free gas is present is not the focus of this paper. We show that not accounting for the phase-behavior changes that occur when methane is present at reservoir pressure can greatly affect the oil recovery of SP floods. Improper design of an SP flood can lead to production of more oil as a microemulsion phase than as an oil bank. This paper describes the procedure to implement the effect of pressure and solution gas on microemulsion phase behavior in a chemical-flooding simulator, which requires the phase-behavior data measured at atmospheric pressure.

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

Surfactant Phase Behavior and Retention in Porous Media

1979 ◽  
Vol 19 (03) ◽  
pp. 183-193 ◽  
Author(s):  
C.J. Glover ◽  
M.C. Puerto ◽  
J.M. Maerker ◽  
E.L. Sandvik
Keyword(s):  
Porous Media ◽  
Phase Behavior ◽  
Surfactant Concentration ◽  
Divalent Cations ◽  
Reservoir Rock ◽  
Residual Oil ◽  
Optimal Salinity ◽  
Interfacial Tensions ◽  
Production Research ◽  
Surfactant Systems

Glover, C.J.,* SPE-AIME, Exxon Production Research Puerto, M.C., SPE-AIME, Puerto, M.C., SPE-AIME, Exxon Production Research Co. Maerker, J.M., SPE-AIME, Exxon Production Research Co. Sandvik, E.L., SPE-AIME, Exxon Production Research Co. Abstract Surfactant retention in reservoir rock is a major factor limiting effectiveness of oil recovery using microemulsion flooding processes. Effects of salinity and surfactant concentration on microemulsion phase behavior have a significant impact on relative phase behavior have a significant impact on relative magnitudes of retention attributed to adsorption vs entrapment of immiscible microemulsion phases.Surfactant retention levels were determined by effluent sample analyses from microemulsion flow tests in Berea cores. Data for single surfactant systems containing NaCl only and multicomponent surfactant systems containing monovalent and divalent cations are included. Retention is shown to increase linearly with salinity at low salt concentrations and depart from linearity with higher retentions above a critical salinity. This departure from linearity is shown to correlate with formation of upper-phase microemulsions. The linear trend, therefore, is attributed to surfactant adsorption, and retention levels in excess of this trend are attributed to phase trapping.Divalent cations are shown to influence microemulsion phase behavior strongly through formation of divalent-cation sulfonate species. A useful method for predicting phase behavior in systems containing divalent cations is described. This method combines equilibrium expressions with a relationship defining the contribution of each surfactant component to optimal salinity. Observed experimental data are compared with predicted data. Introduction Two essential criteria that must be met for successful recovery of residual oil by chemical flooding arevery low interfacial tensions between the chemical bank and residual oil and between the chemical bank and drive fluid andsmall surfactant retention losses to reservoir rock. If retention is excessive, interfacial tensions eventually will become high enough to retrap residual oil in the remainder of the reservoir.Previous studies have described several mechanisms responsible for surfactant retention in porous media. These include adsorption, porous media. These include adsorption, precipitation, partitioning into a residual oil phase, precipitation, partitioning into a residual oil phase, and entrapment of immiscible microemulsion phases. Of particular interest is Trushenski's discussion of microemulsion phase trapping as a consequence of surfactant-polymer interaction, and a supporting statement that similar behavior often was observed when microemulsions were diluted with polymer-free brine. Here, we attempt to provide some understanding of this surfactant dilution phenomenon by examining phase behavior as a function of salinity, divalent-ion content, and surfactant concentration. Experimental Procedures Surfactant Systems Two surfactant systems were used in this study. (Specific microemulsion compositions are discussed later.) One system was the 63:37 volumetric mixture of the monoethanol amine salt of dodecylorthoxylene sulfonic acid and tertiary amyl alcohol (MEAC12OXS/TAA) described by Healy et al. The oil component for these microemulsions was a mixture of 90% Isopar M TM and 10% Heavy Aromatic Naptha.(TM)** The brine contained NaCl only. SPEJ P. 183

The Salinity-Requirement Diagram - A Useful Tool in Chemical Flooding Research and Development

1982 ◽  
Vol 22 (02) ◽  
pp. 259-270 ◽  
Author(s):  
Richard C. Nelson
Keyword(s):  
Phase Equilibrium ◽  
Surfactant Concentration ◽  
Salinity Gradient ◽  
Reservoir Rock ◽  
Chemical Flooding ◽  
Optimal Salinity ◽  
Type Iii ◽  
Oil Displacement ◽  
Small Pore ◽  
Micro Emulsion

Abstract Optimal salinity, the level of brine salinity at which a chemical flooding surfactant displaces oil most efficiently, is related to midpoint salinity and to the range of salinity over which the phase environment is Type III. These three conditions are functions of surfactant concentration-usually decreasing as surfactant concentration decreases, particularly if the brine contains multivalent cations. A salinity-requirement diagram, constructed from phase equilibrium data, expresses quantitatively the dependency of midpoint salinity and the Type III range on surfactant concentration. Because surfactant concentration decreases as a flood with a small-pore-volume chemical slug proceeds, a salinity-requirement diagram can provide insight into the performance of chemical floods. Examples are presented that support the proposal that chemical flooding is most efficient when conducted in a salinity gradient. A phenomenon in which a "wedge" of oil is left on the bottom of the core by a chemical flood is related to the salinity-requirement diagram for the system, and the effect of ion exchange on such diagrams is discussed. Introduction In the nest paper of this series, we concluded that chemical flooding under normal reservoir flow rates can be treated as an equilibrium process. Results of laboratory chemical floods, some of which were reported in that paper, indicate that the phases that form when oil, surfactant, and brine are mixed and allowed to equilibrate in sample tubes also form in the pores of reservoir rock during a chemical flood. Consequently, a reservoir under chemical flood can be visualized as a series of connected mixing cells, with phase equilibrium attained in each cell. Mathematical simulators of the chemical flooding process based on this physical model have been published, and a general theory of multicomponent, multiphase displacement in porous media has been described and illustrated. We defined in that first paper three types of phase environment: Types II(-), II(+), and III. We concluded from our experiments that one objective in designing chemical flooding, systems should be to keep as much of the surfactant as possible in the Type III phase environment, near midpoint salinity, for as long as possible during, the course of the flood. In the second paper of the series, we emphasized that the salinity requirement of a chemical flooding system usually changes during a chemical flood as adsorption and dispersion cause the surfactant concentration to decrease. The salinity requirement is the salinity required for the surfactant/brine/oil system to be at midpoint salinity (i.e., that point in the Type III phase environment where the concentration of oil equals the concentration of brine in the microemulsion, middle phase). Healy and Reed and others have observed that optimal salinity for oil displacement is at or near midpoint salinity. We use midpoint salinity rather than optimal salinity in our work because midpoint salinity is defined precisely. We assume that the sum of the micro emulsion/excess oil and micro emulsion/excess brine interfacial tensions is minimal and oil displacement efficiency is maximal near midpoint salinity. Our experimental results are consistent with this assumption. For most anionic surfactants. midpoint salinity decreases as surfactant concentration decreases, particularly in the presence of multivalent cations. The dependency on surfactant concentration of midpoint salinity and of the range of salinity over which the system is Type III is depicted on a salinity requirement diagram. Such diagrams are similar to those presented by Glover et al. The utility of salinity-requirement diagrams was illustrated in Ref. 9 by considering the results of four laboratory chemical floods that differed only in the salinity of their polymer drives. SPEJ P. 259^

The Effect of Several Polymers on the Phase Behavior of Micellar Fluids

1982 ◽  
Vol 22 (06) ◽  
pp. 816-830 ◽  
Author(s):  
Gary A. Pope ◽  
Kerming Tsaur ◽  
Robert S. Schechter ◽  
Ben Wang
Keyword(s):  
Phase Behavior ◽  
Nonionic Surfactants ◽  
Polymer Concentration ◽  
Salinity Range ◽  
Lower Phase ◽  
Optimal Salinity ◽  
Rich Phase ◽  
Three Phase ◽  
Phase Systems ◽  
Increasing Temperature

Abstract We made static measurements of the phase volumes of mixtures of surfactant, polymer, alcohol, water, oil, sodium chloride, and in some cases polymer additives. We also made a limited number of viscosity, phase concentration, and interfacial tension (IFT) measurements. The purpose was to determine systematically the effect of various polymers on the phase behavior of various surfactant formulations. We made measurements with and without oil (n-octane and n-octane/benzene mixtures) across a range of salinity appropriate to the particular surfactant at temperatures between 24 and 75 degrees C. Introduction The oil-free (i.e., no added oil) solutions showed a characteristic phase separation into an aqueous surfactant-rich phase and an aqueous polymer-rich phase at some sufficiently high salinity (NaCl concentration), which we call the critical electrolyte concentration (CEC). The CEC was found to be a characteristic of a given surfactant/alcohol combination that shifts with the solubility of the surfactant qualitatively the same way as does the optimal salinity: but the CEC was found independent of the polymer type, polymer concentration (between the 100- and 1,000-ppm limits investigated), and surfactant concentration. The CEC increases with increasing temperature for the anionic surfactants and decreases with increasing temperature for the nonionic surfactants. When oil was added to the mixtures, an entirely different pattern of phase behavior was observed. As salinity increases, the particular formulations form the typical sequence of lower-phase microemulsion and excess oil, middle-phase microemulsion. excess oil, and excess brine: and upper-phase microemulsion and excess brine. The sequence with polymer was precisely the same over most of the salinity range but deviated over a limited range of salinity; the three-phase region simply shifted a small distance to the left on the salinity scale. Also, and probably more significantly, some of the aqueous phases in the critical region of the shift (which is also just above oil-free CEC salinity) were found to be gel-like in nature. These apparently occur under conditions such that the polymer concentration in the excess brine of the three-phase systems becomes very high because almost all the polymer is always in the brine phase, even when the brine phase is very small. Thus an overall 1,000 ppm of polymer easily can be concentrated to 10,000 ppm or more. One of the most remarkable aspects of the phase behavior of the surfactant/polymer systems is that the same patterns are observed for all combinations of anionic and nonionic surfactants and polymers. Also, little difference was observed in the IFT values with and without polymer. The three-phase systems still exhibited ultralow IFT values. Obviously, significant differences did occur in the brine viscosities when polymer was added. The polymer-free mixtures were themselves quite viscous, however, and the viscosity of the oil-free surfactant-rich phases (above the CEC) was significantly higher when the phases were in equilibrium with a polymer-rich aqueous phase, even though they apparently contained almost no polymer. We found that the polymer-rich phases had normal viscosities, as judged by the same polymer in the same brine at the expected concentration, assuming all the polymer was in the polymer-rich phase. The effect of polymer on the systems with oil was to increase the viscosity of the water-rich phase only, with little effect on the microemulsion phase unless it was the water-rich phase. SPEJ P. 816^

Development of the Surfactant-Based Chemical EOR Formula for Low Permeability Reservoirs

2021 ◽  
Author(s):  
Nancy Chun Zhou ◽  
Meng Lu ◽  
Fuchen Liu ◽  
Wenhong Li ◽  
Jianshen Li ◽  
...  
Keyword(s):  
Phase Behavior ◽  
Oil Recovery ◽  
Aqueous Solubility ◽  
Low Permeability ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Key Factors ◽  
Low Salinity ◽  
Low Tension ◽  
Low Permeability Reservoirs

Abstract Based on the results of the foam flooding for our low permeability reservoirs, we have explored the possibility of using low interfacial tension (IFT) surfactants to improve oil recovery. The objective of this work is to develop a robust low-tension surfactant formula through lab experiments to investigate several key factors for surfactant-based chemical flooding. Microemulsion phase behavior and aqueous solubility experiments at reservoir temperature were performed to develop the surfactant formula. After reviewing surfactant processes in literature and evaluating over 200 formulas using commercially available surfactants, we found that we may have long ignored the challenges of achieving aqueous stability and optimal microemulsion phase behavior for surfactant formulations in low salinity environments. A surfactant formula with a low IFT does not always result in a good microemulsion phase behavior. Therefore, a novel synergistic blend with two surfactants in the formulation was developed with a cost-effective nonionic surfactant. The formula exhibits an increased aqueous solubility, a lower optimum salinity, and an ultra-low IFT in the range of 10-4 mN/m. There were challenges of using a spinning drop tensiometer to measure the IFT of the black crude oil and the injection water at reservoir conditions. We managed the process and studied the IFTs of formulas with good Winsor type III phase behavior results. Several microemulsion phase behavior test methods were investigated, and a practical and rapid test method is proposed to be used in the field under operational conditions. Reservoir core flooding experiments including SP (surfactant-polymer) and LTG (low-tension-gas) were conducted to evaluate the oil recovery. SP flooding with a selected polymer for mobility control and a co-solvent recovered 76% of the waterflood residual oil. Furthermore, 98% residual crude oil recovery was achieved by LTG flooding through using an additional foaming agent and nitrogen. These results demonstrate a favorable mobilization and displacement of the residual oil for low permeability reservoirs. In summary, microemulsion phase behavior and aqueous solubility tests were used to develop coreflood formulations for low salinity, low temperature conditions. The formulation achieved significant oil recovery for both SP flooding and LTG flooding. Key factors for the low-tension surfactant-based chemical flooding are good microemulsion phase behavior, a reasonably aqueous stability, and a decent low IFT.

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^

Ionization and phase behavior of fatty acids in water: application of the Gibbs phase rule

Biochemistry ◽  
1988 ◽  
Vol 27 (6) ◽  
pp. 1881-1888 ◽  
Author(s):  
David P. Cistola ◽  
James A. Hamilton ◽  
David Jackson ◽  
Donald M. Small
Keyword(s):  
Fatty Acids ◽  
Phase Behavior ◽  
Water Application ◽  
Phase Rule ◽  
Gibbs Phase Rule
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