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

Use of Perspective Plots To Aid in Determining Factors Affecting Interfacial Tensions Between Surfactant Solutions and Crude Oil

1982 ◽  
Vol 22 (03) ◽  
pp. 350-352
Author(s):  
G.E. Kellerhals
Keyword(s):  
Crude Oil ◽  
Aqueous Phase ◽  
Oil Recovery ◽  
Surfactant Concentration ◽  
Reservoir Rock ◽  
Surfactant Flooding ◽  
Rich Phase ◽  
Interfacial Tensions ◽  
Surfactant Systems ◽  
The Impact

Abstract In surfactant flooding, low interfacial tensions (IFT's) are required for recovery of additional significant quantities of crude oil from a reservoir rock. This paper indicates the usefulness of perspective plots to facilitate comparison of sets of IFT data. Such perspective plots simplify the process of screening various surfactant systems for enhanced oil recovery. Introduction Numerous articles have been written about the effects and/or importance of IFT between oil and aqueous phases in determining ultimate oil recovery during a phases in determining ultimate oil recovery during a secondary (waterflooding) or tertiary oil-recovery process. In the area of micellar/polymer or surfactant process. In the area of micellar/polymer or surfactant flooding, IFT has been studied extensively both by industrial and by academic investigators. A simplistic summary of this work is that low IFT's (generally corresponding to high capillary numbers ( are required for recovery of additional significant quantities of crude oil from a reservoir rock. Method Development Several variables influence between an oil-rich phase and a surfactant-containing aqueous phase. During phase and a surfactant-containing aqueous phase. During a surfactant flood, variations in surfactant concentration and salt concentration will occur as a result of mixing of the chemical slug with the pre flush (or formation brine) and polymer drive (" rear mixing" ). Nelson investigated salt concentrations required during a chemical flood to achieve efficient oil displacement. Since these variables (and others) change during the progress of a flood, it is desirable to determine the impact of these changes on the IFT between the oil- and water-rich phases. To assess the importance of changes in these two key variables (surfactant concentration and salinity) on IFT, an x-y plot may be constructed with values of each variable along the axes. The IFT for a particular surfactant concentration and salinity then is obtained experimentally and the numerical value placed at the corresponding (x, y) point on the plot. The resultant figure/table can be referred to as an IFT map. Points of equal, or about equal, IFT can be connected to produce an IFT contour map. In the investigation of the effect(s) of temperature on a given surfactant system and crude oil, IFT maps might be constructed for each of the pertinent temperatures. IFT's might be determined at six different sodium chloride concentrations (e.g., 1.0, 1.5, 2.0, 3.0, 4.0, and 5.0 wt%) and four surfactant concentrations (e.g., 0.085, 0.064, 0.042, and 0.021 meq/mL), resulting in IFT maps (for each temperature) each consisting of 24 IFT values. A comparison of the values of one map to the values of a second map (measurements made at different temperature) then is required to determine the impact of the temperature change. A single value for IFT for a given salinity and surfactant concentration assumes that the system is two-phase, because two IFT's can be measured for a three-phase system consisting of an oil-rich phase, a water-rich phase, and a microemulsion phase. phase. A method to allow easier comparison for the relatively large number of IFT data points that may be obtained during the study/screening of various surfactant systems at various conditions is described in this paper. The technique consists of interpolating between IFT values and then plotting the data with a perspective plotting routine. The method allows comparisons of IFT values for different crude oils, temperatures, cosolvent types, surfactant types, hardness ion concentrations, etc., through visual scanning of a perspective plot ranter than through trying to judge or compare numerical IFT values of an IFT map. SPEJ p. 350

Favorable Attributes of Alkaline-Surfactant-Polymer Flooding

SPE Journal ◽  
2008 ◽  
Vol 13 (01) ◽  
pp. 5-16 ◽  
Author(s):  
Shunhua Liu ◽  
Danhua Zhang ◽  
Wei Yan ◽  
Maura Puerto ◽  
George J. Hirasaki ◽  
...  
Keyword(s):  
Crude Oil ◽  
Phase Behavior ◽  
Anionic Surfactants ◽  
Naphthenic Acids ◽  
Mobility Control ◽  
Alkaline Solutions ◽  
Synthetic Surfactant ◽  
Optimal Salinity ◽  
Interfacial Tensions ◽  
Alkaline Surfactant Polymer

Summary A laboratory study of the alkaline-surfactant-polymer (ASP) process was conducted. It was found from phase-behavior studies that for a given synthetic surfactant and crude oil containing naphthenic acids, optimal salinity depends only on the ratio of the moles of soap formed from the acids to the moles of synthetic surfactant present. Adsorption of anionic surfactants on carbonate surfaces is reduced substantially by sodium carbonate, but not by sodium hydroxide. The magnitude of the reduction with sodium carbonate decreases with increasing salinity. Particular attention was given to a surfactant blend of a propoxylated sulfate having a slightly branched C16-17 hydrocarbon chain and an internal olefin sulfonate. In contrast to alkyl/aryl sulfonates previously considered for EOR, alkaline solutions of this blend containing neither alcohol nor oil were single-phase micellar solutions at all salinities up to approximately optimal salinity with representative oils. Phase behavior with a west Texas crude oil at ambient temperature in the absence of alcohol was unusual in that colloidal material, perhaps another microemulsion having a higher soap content, was dispersed in the lower-phase microemulsion. Low interfacial tensions existed with the excess oil phase only when this material was present in sufficient amount in the spinning-drop device. Some birefringence was observed near and above optimal conditions. While this phase behavior is somewhat different from the conventional Winsor phase sequence, overall solubilization of oil and brine for this system was high, leading to low interfacial tensions over a wide salinity range and to excellent oil recovery in both dolomite and silica sandpacks. The sandpack experiments were performed with surfactant concentrations as low as 0.2 wt% and at a salinity well below optimal for the injected surfactant. It was necessary that sufficient polymer be present to provide adequate mobility control, and that salinity be below the value at which phase separation occurred in the polymer/surfactant solution. A 1D simulator was developed to model the process. By calculating transport of soap formed from the crude oil and injected surfactant separately, it showed that injection below optimal salinity was successful because a gradient in local soap-to-surfactant ratio developed during the process. This gradient increases robustness of the process in a manner similar to that of a salinity gradient in a conventional surfactant process. Predictions of the simulator were in excellent agreement with the sandpack results. Background Although both injection of surfactants and injection of alkaline solutions to convert naturally occurring naphthenic acids in crude oils to soaps have long been suggested as methods to increase oil recovery, key concepts such as the need to achieve ultralow interfacial tensions and the means for doing so using microemulsions were not clarified until a period of intensive research between approximately 1960 and 1985 (Reed and Healy 1977; Miller and Qutubuddin 1987; Lake 1989). Most of the work during that period was directed toward developing micellar-polymer processes to recover residual oil from sandstone formations using anionic surfactants. However, Nelson et al. (1984) recognized that in most cases the soaps formed by injecting alkali would not be at the "optimal" conditions needed to achieve low tensions. They proposed that a relatively small amount of a suitable surfactant be injected with the alkali so that the surfactant/soap mixture would be optimal at reservoir conditions. With polymer added for mobility control, the process would be an alkaline-surfactant-polymer (ASP) flood. The use of alkali also reduces adsorption of anionic surfactants on sandstones because the high pH reverses the charge of the positively charged clay sites where adsorption occurs. The initial portion of a Shell field test, which did not use polymer, demonstated that residual oil could be displaced by an alkaline-surfactant process (Falls et al. 1994). Several ASP field projects have been conducted with some success in recent years in the US (Vargo et al. 2000; Wyatt et al. 2002). Pilot ASP tests in China have recovered more than 20% OOIP in some cases, but the process has not yet been applied there on a large scale (Chang et al. 2006).

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.

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^

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

Application of the Theory of Multicomponent, Multiphase Displacement to Three-Component, Two-Phase Surfactant Flooding

1981 ◽  
Vol 21 (02) ◽  
pp. 191-204 ◽  
Author(s):  
George J. Hirasaki
Keyword(s):  
Partition Coefficient ◽  
Phase Behavior ◽  
Oil Recovery ◽  
Chromatographic Separation ◽  
Partition Coefficients ◽  
Phase System ◽  
Surfactant Flooding ◽  
Two Phase ◽  
Optimal Salinity ◽  
Interfacial Tensions

Abstract The theory presented in a companion paper is illustrated for the case of three-component, two-phase (i.e., constant-salinity) surfactant flooding. The utility of this method is that, in addition to computation of specific cases, it provides a general qualitative understanding of the displacement behavior for different phase diagrams and different injection compositions. The phase behavior can be classified as to whether the partition coefficient is less than or greater than unity. The injection composition of the slug can be classified as to whether it is aqueous or oleic and whether it is inside or outside the region of tieline extensions.The theory provides an understanding of the displacement mechanisms for the three-component, two-phase system as a function of phase behavior and injection composition. This understanding aids the interpretation of phenomena such as the effects of dispersion, salinity gradient, chromatographic separation, and polymer/surfactant interaction. Introduction The phase behavior of surfactant with oil and brine is the underlying phenomenon of most surfactant-flood design philosophies. The surfactant slugs have been formulated either as (1) surfactant in water, (2) surfactant in oil, or (3) microemulsions containing both water and oil. Recovery of oil is thought to occur by solubilization, oil swelling, miscible displacement, and/or low interfacial tensions. The low interfacial tensions occur in a salinity environment such that three phases can coexist. At higher salinities the surfactant is in the oleic phase, and at lower salinities it is in the aqueous phase.Some recent investigators have preferred designing their process at a constant salinity even though their experiments indicated better oil recovery with a salinity contrast. Glover et al. point out that the optimal salinity is not constant in brines containing divalent ions and that phase trapping can result in large retention of surfactant in a system that was at optimal salinity at injected conditions. Nelson and Pope have demonstrated that good oil recovery is possible in systems containing formation brine with 120,000 ppm TDS and 3,000 ppm divalent cations if the drive salinity is sufficiently low such that the surfactant partitions into the aqueous phase. Moreover, the peak surfactant concentration in the effluent occurred in the three-phase environment where the lowest interfacial tension usually occurs.The purpose of this work is to understand better the mechanism of multiphase, multicomponent displacement so that the phase behavior can be used to advantage. The approach used is to examine in detail the displacement mechanism and behavior of a two-phase, three-component system. This understanding will build a foundation for examining more complex systems.Earlier, Larson and Hirasaki showed effects of oil swelling and the retardation of the surfactant front due to the surfactant partitioning into the oleic phase. Recently, Larson extended the work to finite slugs including oleic slugs. He showed the conditions necessary to have miscible or piston-like displacement. His work showed that systems with large partition coefficients are more tolerant to dispersive mixing. We show in this paper that his observation was probably the consequence of having a phase diagram with a constant partition coefficient. Todd et al. show the effect of the partition coefficients on the chromatographic separation and retention for a two-component surfactant system. Pope et al. evaluated the sensitivity of the performance of a surfactant flood to a number of factors. SPEJ P. 191^

The Effect of Interfacial Tensions on Relative Oil/Water Permeabilities of Consolidated Porous Media

1982 ◽  
Vol 22 (03) ◽  
pp. 371-381 ◽  
Author(s):  
Jude O. Amaefule ◽  
Lyman L. Handy
Keyword(s):  
Porous Media ◽  
Interfacial Tension ◽  
Relative Permeability ◽  
Residual Oil ◽  
Relative Permeabilities ◽  
Interfacial Tensions ◽  
Oil Displacement ◽  
Oil Water ◽  
Relative Permeability Curves ◽  
Low Tension

Abstract Relative permeabilities of systems containing low- tension additives are needed to develop mechanistic insights as to how injected aqueous chemicals affect fluid distribution and flow behavior. This paper presents results of an experimental investigation of the effect of low interfacial tensions (IFT's) on relative oil/water permeabilities of consolidated porous media. The steady- and unsteady-state displacement methods were used to generate relative permeability curves. Aqueous low-concentration surfactant systems were used to vary IFT levels. Empirical correlations were developed that relate the imbibition relative permeabilities, apparent viscosity, residual oil, and water saturations to the interfacial tension through the capillary number (Nc=v mu / sigma). They require two empirical, experimentally generated coefficients. The experimental results show that the relative oil/water permeabilities at any given saturation are affected substantially by IFT values lower than 10-1 mN/m. Relative oil/water permeabilities increased with decreasing IFT (increasing N ). The residual oil and residual water saturations (S, and S) decreased, while the total relative mobilities increased with decreasing IFT. The correlations predict values of relative oil/water permeability ratios, fractional flow, and residual saturations that agree with our experimental data. Apparent mobility design viscosities decreased exponentially with the capillary number. The results of this study can be used with simulators to predict process performance and efficiency for enhanced oil-recovery projects in which chemicals are considered for use either as waterflood or steamflood additives. However, the combined effect of decreased interfacial tension and increased temperature on relative permeabilities has not yet been studied. Introduction Oil displacement with an aqueous low-concentration surfactant solution is primarily dependent on the effectiveness of the solutions in reducing the IFT between the aqueous phase and the reservoir oil. With the attainment of ultralow IFT's (10 mN/m) and with adequate mobility controls, all the oil contacted can conceivably be displaced. When the interfacial tension is reduced to near zero values, the process tends to approach miscible displacement. However, most high-concentration soluble oil systems revert to immiscible displacement processes as the injected chemical traverses the reservoir. This is a result of the continual depletion of the surfactant by adsorption on the rock and by precipitation with divalent cations in the reservoir brine. The mechanism by which residual oil is mobilized by low-tension displacing fluids cannot be explained solely by the application of Darcy's law to both the aqueous and the oleic phases. On the other hand, in those reservoir regions in which water and oil are flowing concurrently as continuous phases, Darcy's law would be expected to apply and the relative permeability concept would be valid. If a low-tension aqueous phase were to invade a region in which the oil had not as yet been reduced to a discontinuous irreducible saturation, one would expect, also, that the relative permeability concept would be applicable. Under circumstances for which these conditions apply, relative permeabilities at low interfacial tensions would be required, The effect of IFT's on relative permeability curves has received limited treatment in the petroleum literature. Leverett reported a small but definite tendency for a water/oil system in unconsolidated rocks to exhibit 20 to 30% higher relative permeabilities if the IFT was decreased from 24 to 5 mN/m. Mungan studied interfacial effects on oil displacement in Teflons cores. The interfacial tension values varied from 5 to 40 mN/m. SPEJ P. 371^

Sign in / Sign up

Export Citation Format

Share Document