Micellar Fluids Research Articles

Micellar Flooding - Compositional Effects on Oil Displacement

Abstract Key variables that govern oil displacement in a micellar flood are capillary number (velocity x viscosity/interfacial tension) and chemical loss. At high capillary numbers, oil displacement is very efficient if various phases propagate at the same velocity. Chemical loss, however, is not always low when oil displacement efficiency is high. Compositions developed in situ often alter the ability of the micellar fluid to displace oil. Oil recovery can be predicted from static equilibrium fluid properties, providing the in situ compositions are known.The displacement of the wetting phase requires a capillary number of 10 times higher than that required to displace the nonwetting phase. This implies less efficient oil displacement in oil-wet systems. The correlation of oil recovery vs capillary number also varies with rock structure and wettability. Hence, for field application, immiscible oil displacement with micellar fluids should be determined in reservoir rocks. The decrease in final oil saturation with increase in capillary number indicates that relative permeability changes with capillary number. A numerically study showed that both the end-points and the shape of the relative permeability curves affect oil recovery at high permeability curves affect oil recovery at high capillary number in a slug process. The shape of the relative-permeability curves also affects the design of micellar slug viscosity. Thus, for field application, it is important to know the shape of relative-permeability curves at anticipated capillary numbers. Introduction In a micellar flood, the injected fluid banks interact with one another and with the reservoir brine, crude oil, and reservoir rock. This places stringent requirements on the design of the micellar flood. Initially, the micellar fluid may be miscible with crude oil and reservoir brine. However, because of dilution and surfactant adsorption, the flood can degenerate to an immiscible displacement. If low interfacial tension (IFT), or more specifically, high capillary number (velocity x viscosity/IFT) is maintained between all the phases, the displacement efficiency is good.There are many phenomena that can decrease oil recovery efficiency. The most important are chemical (surfactant or sulfonate) losses from adsorption by the rock, precipitation by high-salinity and high-hardness brines, interaction with polymer, partitioning into an immobile phase, and trapping of partitioning into an immobile phase, and trapping of the surfactant-rich phase. Recovery efficiency also can be poor when unfavorable in situ compositions develop. This occurs when the micellar fluid is diluted, develops undesirable salinity and hardness environment, experiences selective adsorption of surfactant, or undergoes selective partitioning of components into phases moving at different velocities.A micellar phase (or microemulsion) can exist in equilibrium with excess oil, water, or both. Winsor designated such phase behavior as Type I, II, and III, respectively. More recently, Healy et al. identified this behavior as lower phase (where the micellar phase is in equilibrium with excess oil), upper phase (where the micellar phase is in equilibrium with excess water), and middle phase (where the micellar phase is in equilibrium with excess oil and water). The importance of phase behavior has been the subject of considerable discussion in the literature.Since the function of the micellar fluid is to displace crude oil, not water, it would be desirable if the micellar fluid remained miscible with oil and immiscible with water during the immiscible displacement portion of a flood. This is achieved with upper-phase micellar systems. Since only a small bank of micellar fluid is injected, it must be displaced effectively by the succeeding polymer water bank. However, the upper-phase micellar fluid is not miscible with the polymer water; therefore, some of the micellar phase may be trapped as an immobile saturation (much as residual oil is trapped). SPEJ p. 116

Applications of Scanning Electron Microscopy to Hydrocarbon Exploitation: ABSTRACT

The Scanning Electron Microscope (SEM), which became available commercially in the mid 1960s, has added a new dimension to exploitation during the decade of the 1970s. Of primary importance are studies of pore geometry and diagenetic history, which influence the type, distribution, and flow of fluids in the lithosphere. The SEM provides a means of evaluating the abundance and location of micropores relative to macropores, which influence fluid distribution. If a rock contains a significant percentage of authigenic clay minerals or other fine particles, bound water may be retained in the micropores and cause a high irreducible water saturation. The reservoir may produce water-free hydrocarbons, but wireline-log calculations may indicate water saturations greater than 60%. The SEM is useful for examining the effect of fluids and chemical additives on rocks during enhanced oil recovery. For example, laboratory tests have shown decreasing permeability during flow tests using a specific micellar fluid. SEM examination of before and after rock samples revealed that smectite, an expandable clay, was reacting to the fluid and plugging pore throats, yielding reduced permeability. Reservoir studies using the SEM have shown that varying distributions and morphologies of clay minerals can be directly related to productivity of sandstones. Clay distribution, in order of decreasing reservoir quality and decreasing mean-pore-aperture size, is (1) discrete loosely packed clay particles, partially filling pores; (2) clay lining pores; and (3) clay bridging from one sand grain to an adjacent sand grain. Reservoir quality due to clay distribution types 1 and 2 is exemplified by Mesaverde sandstones in southwestern Wyoming. Measured porosities for the two types of reservoirs are similar, but permeability and, hence, productivity are markedly dissimilar. End_of_Article - Last_Page 539------------

Ion-Exchange Conditioning of Sandstones for Chemical Flooding

The ionic hardness of reservoir brines and clays can be destructive in some of the newer chemical flooding processes. Such aggressive conditions were treated in laboratory studies by preflushing with soft brines to displace the offending ions. Results for some cases show that successful preflushing requires large volumes of low- or moderate-salinity brine, whereas smaller volumes of more saline brines may be adequate. Introduction One current obstacle to the widespread use of certain tertiary oil recovery processes is the reservoir ionic environment that injected fluids must withstand. Those processes based on micellar fluids containing substantial processes based on micellar fluids containing substantial quantities of anionic surfactants (such as petroleum sulfonates) may be particularly vulnerable to the effects of high salinity or moderately high multivalent-cation concentration. Even when acceptable chemical formulations exist for specific ionic conditions, oil displacement efficiency may suffer if the reservoir brine composition is not reasonably constant throughout the reservoir. Reservoir conditioning is attempted primarily for these reasons. By injecting a brine of the desired composition ahead of a slug of micellar solution, the most favorable circumstances for effective performance of the chemicals may be established. This study examines the efficiency of preflushing in situations where ion-exchange phenomena are important. In particular, the replacement of divalent cations (such as calcium and magnesium) by less offensive monovalent cations (such as sodium) was studied. The effects of soluble minerals like gypsum or anhydrite were not considered; their behavior can be described adequately by relatively straightforward solubility relationships. Also, the use of chemicals in the preflush brine to react with divalent cations by precipitation or complex ion formation was not examined. It is hoped that this study can be used to determine whether such chemical treatments are needed. Basic Considerations Ion exchange is a process in which an ion bound to a surface is replaced by another ion of like electrical charge from a surrounding solution. In the simplest exchange cases, the total ionic charge on the surface does not change, nor does the bulk concentration of ionic charges in solution. Thus, even though the solution chemical composition may change, salinity will not change when defined as total equivalents of cations per unit volume (as done in this paper). Among the usual components of sandstone petroleum reservoirs, clay minerals are well known for their ion exchange properties. The cation exchange capacities (CEC) vary from about 10 meq (milliequivalents)/ 100 gm of kaolinite to about 100 meq/100 gm of montmorillonite. Other sandstone materials reported to possess ion-exchange properties are quartz, feldspars, and organic matter. The exchange capacities of quartz and feldspars are usually quite low, but the capacity of solid organic matter may be as high as 150 to 500 meq/100 gm. The major factors that appear to influence cation exchange and, thus, preflush efficiency are cation exchange capacity, brine composition, shape of exchange isotherm, and brine salinity. Fig. 1 shows two hypothetical exchange isotherms of an ion-exchanging substance in contact with a solution containing two cationic species. These curves represent the quantity of one species adsorbed on the ion exchanger as a function of its relative concentration in solution. JPT p. 959

Micellar Flooding The Propagation of the Polymer Mobility Buffer Bank

Abstract This study shows the factors that affect the polymer mobility buffer bank, that is, slug size and polymer mobility buffer bank, that is, slug size and concentration. The slug size is a function of polymer/chase-water mixing, polymer inaccessible polymer/chase-water mixing, polymer inaccessible pore volume (IPV), and polymer retention. The pore volume (IPV), and polymer retention. The designed polymer concentration depends on polymer apparent viscosity and, to varying degrees, on shear degradation. The polymer/chase-water mixing-zone volume at a given mobility ratio is the same for glycerine (classical miscible fluid), biopolymer, and polyacrylamide. However, the propagation rate of the polyacrylamide. However, the propagation rate of the mining zone is much higher for polymer than for glycerine because of IPV. Therefore, a larger polymer bank is required to protect the micellar polymer bank is required to protect the micellar slug than would be indicated by mixing-zone volume alone. IPV increased as polymer concentration decreased over the investigated range. A micellar fluid ahead of the polymer bank increased IPV. When polyacrylamides are used in the mobility buffer bank, their concentration should be increased to compensate for the effect of shear degradation. For each field application, shear-degradation tests should be conducted in field cores using field brine and at anticipated sand-face velocities. The loss of polyacrylamide effectiveness because of shear degradation should be determined from apparent viscosity measurement of the sheared polymer, not from polymer concentration, Brookfield viscosity, or screen factor. Introduction In a micellar flood, water-soluble polymers are used as a mobility buffer to protect the micellar slug from invasion by high-mobility chase water. In addition, polymer may be added to the micellar fluid to adjust viscosity, to improve sweep in a waterflood, as a preflush in micellar flood to improve the sweep, to control water production in producers, and for selective partial plugging of high-permeability thief zones. Biopolymers (Xanthan gum) and polyacrylamides are two classes of polymers most commonly used in oil recovery processes. processes. When designing a polymer slug for field application, proper sizing and chemical concentration are critical variables. In a micellar flood, the polymer-mobility buffer-bank size depends on polymer inaccessible pore volume (IPV), mixing, polymer inaccessible pore volume (IPV), mixing, and polymer retention. Because the primary purpose of the polymer bank is to provide adequate mobility control, a sufficient polymer concentration must be selected. However, the concentration for polyacrylamides often must be increased to account polyacrylamides often must be increased to account for losses resulting from shear degradation. This study was undertakento determine the magnitude of and variables affecting polymer inaccessible pore volume (IPV),to characterize the effect of IPV on polymer/chase-water mixing behavior, andto examine polyacrylamide shear degradation. In these IPV and mixing studies, the biopolymer is Kelzan MF TM (Xanflood); and the polyacrylamide is Dow Pusher 500. In shear polyacrylamide is Dow Pusher 500. In shear degradation studies, the polyacrylamides are Dow Pusher 500, Pusher 700, and Amoco Chemicals Pusher 500, Pusher 700, and Amoco Chemicals Sweepaid 105 (an experimental polymer). POLYMER INACCESSIBLE PORE VOLUME POLYMER INACCESSIBLE PORE VOLUME Polymers propagate through porous media more rapidly than through their carrier water. The pore space volume available for polymer flow is pore space volume available for polymer flow is less than the volume available to water. The volume in which polymer cannot flow commonly is called polymer inaccessible pore volume (IPV). The polymer inaccessible pore volume (IPV). The exact mechanism of IPV is not clear. However, it has been estimated that the polymer molecule size is of the same order as pore sizes in rock. In many cases, the smaller rock pores are not capable of transporting polymer molecules, but can transport water. Another phenomenon possibly contributing to IPV is the inability of the polymer molecule center to get near the pore wall. As a result, the average velocity of the polymer molecules is greater than that of water molecules. SPEJ p. 5

Effect of System Wettability on Oil Displacement By Micellar Flooding

This paper studies the recovery of waterflood residual oil by micellar floods using laboratory oil- and water-wet cores. Excellent agreement is found between experiment and theory. The study also shows greater chemical costs and decreases in injectivity for oil-wet systems. Introduction The recovery of waterflood residual oil in laboratory water-wet porous media by a micellar or microemulsion solution has been discussed extensively. Many studies have defined the requirements (mobility control and capillary number) for effective oil displacement, discussed the relationship of micellar fluid design and oil recovery performance, reported the laboratory data for design of field tests, discussed the mechanisms of oil displacement, and investigated surfactant loss. With few exceptions, similar studies in oil-wet media have not been reported, although at least three pilot micellar floods have been conducted or planned in intermediate or oil-wet reservoirs. Although one might expect the requirements for oil displacement to be similar in water- and oil-wet media, there are fundamental differences in the recovery of oil, as demonstrated by waterflood performance and in the physical structure and distribution of the waterflood residual oil. In particular, the reduction of interfacial tension required for displacement of the wetting phase has been investigated only theoretically and experimentally in synthetic systerms. Only one study containing laboratory micellar flood data in oil-wet cores has been presented. This study discussed the micellar fluid design for a planned pilot test and compared the fluid's oil recovery pilot test and compared the fluid's oil recovery performance in water-wet cores with oil-wet. The chosen performance in water-wet cores with oil-wet. The chosen surfactant system required almost twice the slug size for strongly oil-wet media to achieve the tertiary oil recovery obtained with water-wet cores. Such a comparison has not been determined yet because the requirements for oil displacement and the displacement mechanisms are not the same in oil- and water-wet systems. In other words, a fluid that is optimal for water-wet porous media may not be optimal for oil-wet porous media. This study was undertaken to determine whether there are significant differencesin the requirements for oil displacement by a micellar fluid in oil- and water-wet cores, andbetween the oil displacement mechanisms of micellar fluids in oil- and water-wet cores. The results of seven continuous-injection, micellar slug tests with three different micellar fluids are presented and discussed. Theories are proposed to explain differences in the oil recovery performance between oil- and water-wet cores. The results of a series of small-slug tests (7 to 35 percent PV micellar fluid injected) also are discussed. percent PV micellar fluid injected) also are discussed. Their performance is explained in terms of the proposed theories. The implications on micellar fluid design, both in oil- and water-wet media, are brought out. Evidence of a chromatographic separation of a micellar fluid is presented also. presented also. Requirements for Oil Displacement Effective oil displacement by micellar flooding requires an increase in mobility control and capillary, number (mu u/ gamma). Mobility control is a function of relative permeability. The water- and oil-wet relative-permeability permeability. The water- and oil-wet relative-permeability curves used in this study are depicted in Fig. 1. JPT P. 52

Laboratory Development of Lignosulfonate Gels for Sweep Improvement

Abstract The development of a lignosulfonate gel system for improving sweep efficiency is discussed. The gel mixture is injected as a low-viscosity fluid into a loose streak. After gelation occurs, subsequently injected fluids are diverted into lower-permeability intervals. The developed system is composed of 95 percent or More water, ammonium lignosulfonate, and a mixed activator of sodium dichromate and salt. Laboratory studies show that lignosulfonate gels exhibit the following properties:long gel times can be designed, e.g., gel times up to 2 1/2 months were obtained at 190 degrees F;gel strength can be controlled to produce the level of flow reductions required for a particular application. Controlled flow reduction, rather than complete flow blockage, is needed where the loose streak may contain appreciable amounts of oil recoverable by further waterflooding or by a miscible flood;available injection waters, even highly saline ones, can be used for mixing the gel solutions; andlignosulfonates, with no activator, gel when exposed to temperatures in the range of 300 to 450 degrees F. A fluid with these properties should be useful in controlling sweep in high-temperature reservoirs or steamfloods. Introduction Reservoir heterogeneities, such as loose streaks or fractures, may limit oil recovery in waterflood operations. The injected water may break through prematurely and producing wells abandoned because prematurely and producing wells abandoned because of high water cuts, even though much of the oil in the reservoir is left behind. In spite of sweep problems, many waterfloods have been successful problems, many waterfloods have been successful because water is inexpensive and can be cycled to displace oil gradually from the matrix or lower permeability regions. permeability regions. Recent papers have pointed out that good volumetric sweep efficiency is particularly important in miscible recovery operations. An expensive slug of gas solvent or micellar fluid recovers only the oil that is contacted on a single pass through the reservoir. Thus, it is important that the miscible fluid contact a significant portion of the reservoir. One suggested method for improving sweep to micellar fluid involves prepolymer injection. Because of the growing awareness of the importance of good sweep, greater emphasis is being placed on the diagnosis of reservoir heterogeneities and development of materials for correcting diverse sweep problems. Polymers in various forms have been proposed for improving volumetric sweep caused by a poor mobility ratio or by permeability contrasts. Gels are used for the more severe channeling problems caused by loose streaks. Solid fines and gels are used for fracture plugging. plugging. A previous paper discussed the development and application of alkaline silica gels for selective plugging. Silica gels have been and will continue plugging. Silica gels have been and will continue to be used where the need is to eliminate flow through high-capacity loose streaks. However, with continued application, it has become apparent the silica gels do have some limitations. These includeshort gel times at high temperatures (e.g., about 10 hours at 200 degrees F) that limit the volume of gel mixture that can be injected, andsensitivity to salts that necessitates the use of fresh water for mixing and preflushing and that causes premature gelation in formations containing soluble compounds (e.g, gypsum or anhydrite). This paper describes the development of lignosulfonate gels for improvement of sweep. These gels overcome some of the above limitations of silica gels and also offer additional advantages. DESCRIPTION OF THE SYSTEM This selected system is composed of 95 percent or more water, a lignosulfonate, and a mixed activator of sodium dichromate and salt. This system has evolved from a systematic evaluation of the known reaction of a lignosulfonate with dichromate. SPEJ P. 391

The Use of Tracers in Diagnosing Interwell Reservoir Heterogeneities - Field Results

A suite of "preferred" gas and water tracers is verified for field use in identifying interwell sweep problems and providing information useful to the design, control, and interpretation of a tertiary oil recovery process. Introduction In fluid injection projects, the channeling or by-passing of injected fluids through fractures and high permeability stringers results in poor reservoir sweep efficiency and low oil recovery. When the injected fluid is water, channeling problems have a less severe impact on the flood economics because water is relatively inexpensive and can be recovered and recycled through the reservoir to recover additional oil. However, many of the improved oil recovery processes employ expensive fluids, such as surfactants, micellar fluids, and solvents that must produce oil during a single pass of a relatively small volume produce oil during a single pass of a relatively small volume through the reservoir. It is important to identify and correct any serious reservoir heterogeneities that would lead to channeling and inefficient use of expensive improved recovery fluids. Some knowledge of the near wellbore reservoir heterogeneities can be derived from well logs and core permeability data. Pressure transient and pressure pulse tests are useful in detecting interwell fractures and in determining interwell communication. Other information sometimes is available from prior waterflood performance. A supportive method to determine reservoir interwell anatomy and how a reservoir would perform in an improved recovery process is to trace the interwell flow of injected water during an initial waterflood. For the past several years, the results of 20 tracer programs conducted in reservoirs undergoing programs conducted in reservoirs undergoing waterfloods, gas drives, and alternate water-solvent injection have become available to the author. These tracer programs provided a proving ground and opportunity to programs provided a proving ground and opportunity to screen the performance of numerous water and gas tracer materials. The results also helped arrive at a suite of "preferred" tracers for waterfloods and gas drives. This paper discusses the use of chemical and radioactive tracers to identify sweep problems in a tertiary miscible pilot area in West Texas, two potential micellar pilot areas in Wyoming, a Wyoming waterflood, and a hydrocarbon miscible project in Alberta, Canada. Discussion Information Obtainable From Interwell Tracing Specific information obtained from tracing the interwell flow of injected fluids through a subterranean formation and how this information is derived from the tracer data is discussed. This type of information is the objective of every oilfield tracing program and is useful in the design, control, and interpretation of subsequent tertiary oil recovery processes applied in that field. 1. Volumetric Sweep: The volume of fluid injected at an injection well to breakthrough of the traced fluid at an offset producer is indicative of the volumetric sweep efficiency between that pair of wells. Very small injected volumes to breakthrough (relative to the interwell pore volume) would indicate the existence of an interwell open fracture (or a very thin high permeability stringer) and would give an idea of the volume of that channel. Knowledge of channel volume is important to the sizing of a remedial treatment. JPT P. 1410

Displacement of Polymers in Waterflooded Porous Media and Its Effects on a Subsequent Micellar Flood

Abstract Injection of polymers in advance of a micellar fluid slug has been considered to improve reservoir volumetric sweep in a tertiary-mode micellar flood. An investigation was made of the injection of polyacrylamide-type polymers in waterflooded polyacrylamide-type polymers in waterflooded porous media and its effects on a subsequent porous media and its effects on a subsequent micellar flood. It was found that the presence of waterflood residual oil saturations in the porous medium increased the flow resistance and residual resistance factors (2- to 3.5-fold) compared with their corresponding values when the rock was free of residual oil. Inaccessible pore volume to polymer flow also appeared to be larger when waterflood residual oil saturations were present. These effects have been attributed to wettability and phase distribution of fluids in the porous medium. phase distribution of fluids in the porous medium. The study emphasized basic differences in the flow behavior of polymer injected ahead of a micellar slug (to improve sweep) and behind the micellar fluid (to control mobility). Both effects are for improved oil-recovery efficiency. Water mobility was greatly reduced following the displacement of polyacrylamide polymers in the waterflooded cores, yet mobility of the oil-water bank in a subsequent micellar flood was reduced to a lesser degree than the water bank. For a residual resistance factor to water ranging from 2 to 7, mobility control of a subsequent micellar flood could be achieved with a 22- to 39-percent increase in polymer concentration in the mobility buffer bank. This increase is in excess of the concentration required for a flood not preceded with polymer injection. Polymer preinjection had no adverse effects on oil displacement characteristics of the micellar fluid and appeared to reduce surfactant adsorption on the rock for the polymer-micellar system studied. Some experimental data indicated that the oil bank breaks through earlier and at a slightly higher oil cut in linear core floods. Such a result is theoretically feasible if the reduced-mobility water is not completely displaced at the front end (immiscible portion) of the oil-water bank. Oil-bank breakthrough probably would be delayed in the reservoir because of the action of the preinjected polymer to decrease the flow of fluids in polymer to decrease the flow of fluids in high-permeability zones. Introduction In a previous paper, preinjection of polymers in advance of a micellar slug was proposed as a means for improving reservoir volumetric sweep and oil recovery by a micellar flood. Increased flooding efficiency should result from reduced interwell permeability contrast in the reservoir following the polymer treatment. Preinjection of polymers also should result in better preflushing polymers also should result in better preflushing efficiency in displacing incompatible formation brines over "conventional" water preflushes. Thus, an improved oil-recovery method designed to increase reservoir volumetric sweep and miscibly recover tertiary oil consists ofpreinjection of a carefully designed slug of preinjection of a carefully designed slug of high-molecular-weight polyacrylamide polymers followed by a water-bank spacer to displace the polymer in the interwell area, andinjection of polymer in the interwell area, andinjection of a surfactant (micellar) slug followed by a polymer mobility buffer bank and chase water. The fluid banks that are injected or developed during the process are illustrated in Fig. 1. Mixing and process are illustrated in Fig. 1. Mixing and interaction zones at fluid-bank boundaries are not shown in the schematic. The preinjection of a polymer is intended to rectify interwell permeability variation. The polymer is injected in reservoir rock that has waterflood residual oil saturations. SPEJ p. 358

A Simple Spinning-Drop Interfacial Tensiometer

This article describes the design and use of a simple, relatively inexpensive device for measuring interfacial tension by the spinning-drop technique. The benefit of low interfacial tension between crude oil and a displacing phase (such as a micellar fluid) in tertiary oil recovery is well documented in the literature. Cayias et al. at the U. of Texas perfected the spinning-drop technique for measuring interfacial tension and created a great deal of interest in the use of this technique for formulating suitable micellar fluids. They designed, fabricated, and offered spinning-drop interfacial tensiometers for sale. Because of its capability of operating over a wide range of rotational speeds, the instrument is rather expensive. Use of spinning-drop interfacial-tension measurements for screening, designing, and evaluating micellar fluid systems requires several instruments because a single instrument can be used to make only about four measurements per day, depending on equilibration time. Thus, there is a real need for inexpensive spinning-drop instruments that permit interfacial-tension measurements for formulating micellar fluids on a "mass production" basis. We have found that for interfacial-tension measurements in the millidyne/centimeter region the capillary containing the fluids can be rotated conveniently at 3,600 rpm. A simple and comparatively inexpensive fixedspeed spinning-drop tensiometer can be made easily by using an aluminum collar to fasten a capillary tube to the end of the shaft of a hysteresis synchronous motor driven at 3,600 rpm by the line frequency (Fig. 1). Good quality motors of this type are smooth running and well balanced. P. 30

Micellar Flooding - Fluid Propagation, Interaction, and Mobility

Abstract Laboratory core tests show that small polymer-driven micellar slugs displace tertiary oil, polymer-driven micellar slugs displace tertiary oil, efficiently. Surfactant adsorption studies reveal nonclassical behavior. Polymer requirements are decreased by permeability-reducing micellar/clay interaction and by reduced losses behind a micellar slug. The required volume of polymer slug increases when the pore volume that is inaccessible to the polymer increases. Long-core tests with multiple polymer increases. Long-core tests with multiple pressure taps reveal the existence of a high-mobility pressure taps reveal the existence of a high-mobility oil-water bank and a low-mobility oil-micellar mixing zone. Introduction Micellar fluids that use petroleum sulfonate surfactants have been tested by several organizations as potential candidates for secondary and tertiary oil recovery operations. Typically, a micellar flood consists of a brine preflush to condition the formation, a bank of micellar fluid (5 to 40 percent PV) that displaces the oil, a mobility buffer (polymer) bank to drive the micellar slug, and a chase-water bank. Micellar flooding is attractive as an improved oil recovery process because it is not severely affected by gravity segregation and is not limited by ultimate surfactant availability. DEVELOPMENT OF MICELLAR FLUIDS The micellar fluids that have been developed by our laboratory for miscible waterflooding are microemulsions of high water content (85 to 95 percent by weight). These fluids generally are percent by weight). These fluids generally are prepared with 4 to 10 weight percent oil-soluble prepared with 4 to 10 weight percent oil-soluble hydrocarbon sulfonate (with an equivalent weight, EW, from 350 to 475) and an oil- or water-soluble alcohol cosurfactant. The cosurfactant performs several functions. In many cases it aids the water solubility of the sulfonate. Gale and Sandvik reported that systems that do not use cosurfactants require sulfonates with a broad EW range. The low-EW sulfonates provide water solubility for the high-EW material. Since the systems discussed here use a cosurfactant to perform this function, the EW range of the sulfonates we used is much narrower. An additional benefit of the cosurfactant is that sulfonate adsorption by the rock surface is reduced. SCREENING PROCEDURE Before core testing, crude oils that are potential candidates for micellar flooding are screened qualitatively against a number of micellar compositions of varying surfactant/cosurfactant ratio, monovalent ion concentration, and water content. Divalent ion tolerance and temperature are also examined. Preliminary qualitative screening tests are used to visually examine the degree of miscibility between the crude oil and the micellar solution. If a micellar fluid shows potential for oil displacement and is economically attractive, a core testing program is initiated. Typically, tertiary floods are conducted at reservoir conditions in fresh 2-in.-diameter, 4-ft-long Berea sandstone cores mounted in Hassler holders. A small volume of micellar fluid (from 2.5 to 10 percent PV) is injected at a linear advance rate of percent PV) is injected at a linear advance rate of about 2 ft/D and is followed by a bank of low-salinity, polymer-thickened water. If the tertiary recovery is encouraging, the micellar fluid is evaluated in detail. This evaluation involves extensive adsorption studies to optimize the fluid composition and long-core tests to examine the propagation and interaction of the fluid banks. propagation and interaction of the fluid banks. MICELLAR FLUID DEVELOPMENT FOR A PARTICULAR RESERVOIR The Second Wall Creek reservoir of the Salt Creek field north of Casper, Wyo., has been selected as one of the potential candidates for micellar flooding. The reservoir has a temperature of 110 degrees F, a crude oil viscosity of 4.0 cp, and an average permeability of 50 md. Analyses of the Second Wall Creek formation water and the Madison Field water (to be used as the micellar and polymer bank makeup water) are shown in Table 1. Both waters produce stable one-phase micellar fluids since the produce stable one-phase micellar fluids since the total dissolved solids and divalent ion contents are low. SPEJ P. 633

Salinity Effects of Micellar Flooding

Extensive laboratory flood tests have been conducted to optimize oil recovery with micellar slugs. A study was made of the effects of variables such as temperature, crude oil type, rock type, and surfactant-cosurfactant type, and of the effects of concentration and salinity of connate water, micellar slug, and chase water. The tests demonstrated conclusively that a pronounced benefit in oil recovery can be achieved by using a particular sequence of injected water compositions. For example, it was found that optimum oil recoveries are obtained if the micellar slug contains sufficient salt to produce effective miscibility or very low interfacial tension between the micellar slug and the oil and if the water injected immediately ahead of the micellar slug has approximately the same salt content as the slug itself. It was also found that the polymer drive water behind the micellar slug should be fresh water if optimum oil recovery is to be achieved. The effect of the salinity sequence is illustrated by data obtained in floods of a Wyoming crude oil from 4-ft Berea cores at 110 degrees F. The cores were saturated with water, driven to connate water saturation, waterflooded, and subsequently flooded with 10 percent PV water-external micellar slugs (92 percent water). PV water-external micellar slugs (92 percent water). The micellar slugs were driven with a 750-ppm solution of biopolymer to achieve mobility control. The flood rate for the micellar and polymer slugs was 2 ft/D. All flooding fluids were prepared with a "fresh water" of about 2,800 ppm total solids. Sodium chloride was added in preparing the saline waters and micellar fluid. Repeat tests established that the reproducibility of the data was 3 percent in residual oil saturation after the micellar-polymer injection. Curve 1 of Fig. 1 shows the oil fraction produced during a tertiary micellar flood when a preflush (waterflood) of the same salinity (16,000 ppm) as the micellar slug is employed. Curve 2 shows the oil fraction when fresh water precedes the micellar slug. The total oil recovery, both secondary and tertiary, with the saline water preflush was 95.7 percent of the original oil in place, whereas without the saline preflush the oil recovery was 74 percent. preflush the oil recovery was 74 percent. JPT P. 957

Development and Evaluation of Micellar Solutions To Improve Water Injectivity

By removing residual oil and organic skins from the vicinity of a well, water injection rates can be increased. The micellar compositions described here are highly effective for this purpose and are applicable under widely divergent field mixing and reservoir conditions. Introduction To achieve favorable oil productivity during a waterflood project, water injection rates must be maintained at a high level. Acidizing and fracturing are established techniques for increasing water injectivity. These treatments should be avoided, however, where a created fracture or channel might result in the bypassing of oil. Injectivity may be increased in some wells by removing organic deposits and residual oil from around the wellbore. Potentially y effective treatments are solvent-alcohol injection and micellar solution injection. The micellar compositions found most effective in improving injectivity are of the type described in the earlier work of Jones. These solutions, when used with special injection techniques, have been found to be effective under diverse reservoir conditions. We shall emphasize here the laboratory and developmental aspects, including both micellar composition studies and core displacement tests. Other literature discusses the use of micellar solutions in producing wells and in injection wells. Laboratory Evaluation The micellar solutions are composed of a hydrocarbon solvent (usually kerosene), a sulfonate surfactant, a cosurfactant (usually an alcohol or a modified alcohol), and water, which normally contains added amounts of an electrolyte such as sodium chloride. The micellar solutions normally are transparent and single phase. Laboratory tests show that a small slug of a micellar solution driven by water can displace all of the oil from a rock matrix. The micellar solution performs as a true solvent, similar in mechanism to that proposed by Morse. The surfactant and cosurfactant act as coupling agents to create a single-phase solution from two otherwise immiscible fluids. This mechanism may be compared to adding a mutually soluble alcohol or other solvent to a mixture of water and oil to create a single-phase, homogeneous solution. The type and amount of ingredients must be carefully selected to formulate a stable micellar solution. The surface chemistry explaining the various physical phenomena exhibited by micellar solutions physical phenomena exhibited by micellar solutions is highly complex so we shall not discuss it here. Requirements for a Versatile Composition In order that one composition may be effectively applied in many different reservoirs, the micellar fluid should exhibit the following properties. The micellar slug driven by water should be able to miscibly displace crude oils from various types of reservoir rock. It is desirable that the micellar solution be able to dissolve organic deposits, such as paraffins and asphaltenes, and to disperse solids or emulsions. The micellar solution should remain as a single-phase, homogeneous fluid over the expected range of surface and reservoir temperatures. It should be possible to prepare solutions with the various fresh waters that may be available near the treatment site. JPT P. 614