Recent Advances in Surfactant EOR
George J. Hirasaki, SPE, Clarence A. Miller, SPE, and Maura Puerto, Rice University
Copyright © 2011 Society of Petroleum Engineers
Th is paper (SPE 115386) was accepted for prentation at th e SPE Annual Tech nical Conference and Exhibition, Denver, 21–24 September 2008, and revid for publication.
Original manuscript received for review 19 July 2010. Revid manuscript received for
review 22 December 2010. Paper peer approved 18 January 2011.
Summary
In this paper, recent advances in surfactant enhanced oil recovery (EOR) are reviewed. The addition of alkali to surfactant flooding in the 1980s reduced the amount of surfactant required, and the process became known as alkaline/surfactant/polymer flooding (ASP). It was recently found that the adsorption of anionic surfac-tants on calcite and dolomite can also be significantly reduced with sodium carbonate as the alkali, thus making the process applicable for carbonate formations. The same chemicals are als
o capable of altering the wettability of carbonate formations from strongly oil-wet to preferentially water-wet. This wettability alteration in combination with ultralow interfacial tension (IFT) makes it pos-sible to displace oil from preferentially oil-wet carbonate matrix to fractures by oil/water gravity drainage.
The alkaline/surfactant process consists of injecting alkali and synthetic surfactant. The alkali generates soap in situ by reaction between the alkali and naphthenic acids in the crude oil. It was recently recognized that the local ratio of soap/surfactant deter-mines the local optimal salinity for minimum IFT. Recognition of this dependence makes it possible to design a strategy to maximize oil recovery with the least amount of surfactant and to inject poly-mer with the surfactant without pha paration. An additional benefit of the prence of the soap component is that it generates an oil-rich colloidal dispersion that produces ultralow IFT over a much wider range of salinity than in its abnce.
It was once thought that a cosolvent such as alcohol was necessary to make a microemulsion without gel-like phas or a polymer-rich pha parating from the surfactant solution. An example of an alternative to the u of alcohol is to blend two dissimilar surfactants: a branched alkoxylated sulfate and a double-tailed, internal olefin sulfonate. The single-pha region with NaCl or CaCl 2 is
greater for the blend than for either sur-factant alone. It is also possible to incorporate polymer into such aqueous surfactant solutions without pha paration under some conditions. The injected surfactant solution has underoptimum pha behavior with the crude oil. It becomes optimum only as it mixes with the in-situ-generated soap, which is generally more hydrophobic than the injected surfactant. However, some crude oils do not have a sufficiently high acid number for this approach to work.
Foam can be ud for mobility control by alternating slugs of gas with slugs of surfactant solution. Besides effective oil dis-placement in a homogeneous sandpack, it demonstrated greatly improved sweep in a layered sandpack.
Introduction
It is generally considered that only approximately one-third of the petroleum prent in known rervoirs is economically recoverable with established technology (i.e., primary-recovery methods using gas pressure and other natural forces in the rervoir, and cond-ary recovery by waterflooding). It has long been an objective of the industry to develop improved process to increa overall recovery. However, the low oil prices that prevailed from the mid-1980s until recently
provided little incentive for rearch on EOR, especially surfactant process with substantial initial cost for chemicals. In light of the current higher prices and accompanying revival of interest, it ems appropriate to review understanding of, and prospects for, surfactant EOR.
Adding surfactant to injected water to reduce oil/water IF T and/or alter wettability and thereby increa recovery is not a new idea [e, for instance, Uren and F ahmy (1927)]. Indeed, a few early field trials where small amounts of surfactant were injected did produce small increas in oil recovery. The increas were probably caud mainly by wettability changes, although the data were inconclusive for asssing mechanisms. The results were not sufficiently promising to stimulate u of surfactants on a larger scale. A related long-held concept for improving recovery is to generate surfactant in situ by injecting an alkaline solution (Atkin-son 1927), which is less expensive than synthetic surfactants and converts naphthenic acids in the crude oil to soaps. Early results were not encouraging, and the relative importance of likely process mechanisms was not understood (Johnson 1976). Other references to early work on surfactants are given by Hill et al. (1973).
Two different approaches stimulated significant advances in surfactant EOR process in the 1960s. The surfactants were made either by direct sulfonation of aromatic groups in refinery streams or crude oils, or by organic synthesis of alkyl/aryl sulfonates, which allowed for the surfactant to be tailo
red to the rervoir of interest. The advantages of the surfactants are their low cost, their wide range of properties, and the availability of raw materials in somewhat large quantities.
Miscible flooding was an active area of rearch, but the sol-vents being considered, such as enriched gas and LPG, exhibited poor rervoir sweep becau the adver mobility ratio promoted viscous fingering and the low solvent density led to gravity over-ride. Seeking a solvent miscible with oil but having a higher vis-cosity and density, Gogarty and coworkers at Marathon propod using a slug of an oil-continuous microemulsion made of hydro-carbon, a petroleum sulfonate surfactant, an alcohol, and water or brine [e review by Gogarty (1977)]. Holm and coworkers at Union Oil advocated a similar process using a “soluble oil,” which was also an oil-continuous microemulsion made mainly of crude oil, some mineral oil, petroleum sulfonate, a cosolvent such as eth-ylene glycol monobutyl ether, and water, as summarized by Holm (1977). Slugs of the materials miscible displaced oil and with better sweep than previous solvents. However, it was not initially recognized that process success also depended on maintaining ultralow IFT at the rear of the slug, where it was displaced by an aqueous polymer solution and became a Winsor I microemulsion (Hirasaki 1981).
The other approach involved injection of a surfactant formula-tion made of a petroleum sulfonate and alcohol in an aqueous electrolyte solution. Key to the success of this approach were systematic studi
es of oil displacement leading to recognition that a dimensionless capillary number N v c =/ controlled the amount of residual oil remaining after flooding an oil-containing core at interstitial velocity v with an aqueous solution having a viscosity µ and IFT with the oil (Taber 1969; Stegemeier 1977; Melro and Brandner 1974; F oster 1973). In situations when gravity is important, the Bond number must be included (Pennell et al. 1996). This work revealed that at typical rervoir velocities, IF T had to be reduced from crude-oil/brine values of 20 to 30 mN/m to
values in the range of 0.001 to 0.01 mN/m to achieve low values of residual-oil saturation (<0.05).
Several rearch groups found that ultralow IFTs in the required
range could be achieved using petroleum-sulfonate/alcohol mix-tures (Hill et al. 1973; F oster 1973; Cayias et al. 1977). They also found systematic variations of IFT when changing such vari-ables as salinity, oil composition, and temperature. An important
contribution was the work of Healy et al. (1976) [e also Reed and Healy (1977)], who demonstrated a relationship between IFT and microemulsion pha behavior. Core tests using continuous surfactant injection at the optimal salinity also yielded the highest recovery of waterflood residual oil. Their studies ud mixtures of an alcohol cosolvent with synthetic alkyl/aryl sulfonates, i
n par-
ticular C
9, C
12
, and C
15
orthoxylene sulfonates, which can be made
from oligomers of propylene with more reproducible compositions than tho belonging to petroleum sulfonates.
Conventional Pha Behavior for Ultralow IFT. The under-standing of ultralow IFT in oil-recovery process was advanced when Healy et al. (1976) explained how the Winsor defi nition of equilibrium microemulsion pha behavior (I, II, and III, or lower-pha, upper-pha, and middle-ph
a microemulsion, respec-tively) described the changes of pha behavior, solubilization of oil and water, and IFT as a function of salinity for anionic surfac-tants. The surfactant is able to solubilize an increasing amount of oil and a decreasing amount of water as salinity is incread. The “optimal salinity” determined from pha behavior is the salinity at which the microemulsion solubilizes equal amounts of oil and water. The optimal salinity at which equilibrium IF Ts between the microemulsion pha and excess-oil or excess-water pha become equal (and thus the sum becomes a minimum) is clo to the optimal salinity from pha behavior. There are correlations between the “solubilization parameters” (ratio of oil/surfactant
V o /V
s
or water/surfactant V
w
/V
s
by volume) and the IF Ts of the
microemulsion with the respective excess phas (Huh 1979). Thus, one can estimate the value of the equilibrium IF T at the optimal salinity from the value of the solubilization parameters at the optimal salinity (where they are equal).
Nelson and Pope (1978) recognized that the appearance of a mid-dle-pha microemulsion (Winsor III) is dependent on the amounts of water, oil, and surfactant prent. Thus, they defined the Type III pha environment as the range of salinity at which a middle-pha microemulsion may exist if one were to scan the water/oil/surfactant ternary diagram. This distinction is important at very high or very low surfactant concentrations becau the volume of the middle-pha microemulsion is proportional to the surfactant concentration. At high surfactant concentrations, more of the excess phas are solubilized, and thus the excess phas have smaller volume or are not prent. If the surfactant concentration is high enough, the “middle-pha” microemulsion pha may appear as a single pha at or near optimal conditions. On the other hand, at low surfactant concentrations but above the critical micelle concentration, the volume of the middle-pha microemulsion is minute and its prence may not be visually detected or sampled for IFT measurements.
The nanostructure of the microemulsion should be recognized to distinguish it from macroemulsions or liquid-crystal dispersions or phas. Macroemulsions are nonequilibrium dispersions that change with time or may be in a metastable condition. Liquid-crystal phas are condend, ordered phas that usually are birefringent (rotate polarized light), viscous, and tend to inhibit emulsion coalescence (Healey and Reed 1974). Microemulsions are equilibrium isotropic phas that may have a bicontinuous structure with near-zero mean curvature at or near optimal condi-tions (Scriven 1976). (Microemulsions are oil-swollen micelles in water at underoptimum conditions and reverd micelles in oil at overoptimum conditions.) It was once thought that it is necessary to have a cosolvent (alcohol) to have a microemulsion with an anionic surfactant. However, it is now recognized that it is possible to have microemulsions without alcohol at room temperature by using branched surfactants (Abe et al. 1986).
Salinity-scan tests are ud routinely to screen pha behavior of surfactant formulations before conducting more time-consuming coreflood tests (Levitt et al. 2009; Flaaten et al. 2009; Mohammadi et al. 2009). The minimum IFT is correlated with the solubilization parameters at the optimal salinity. The prence of viscous, struc-tured, or birefringent phas and/or stable macroemulsions is easily obrved. Apparent viscosities of phas prent in 5-mL samples in aled glass pipettes can be m
easured by the falling-sphere method, even for opaque phas (Lopez-Salinas et al.2009).Surfactant Requirements and Structures
In a successful displacement process, the injected surfactant slug must first achieve ultralow IFT to mobilize residual oil and create an oil bank where both oil and water flow as continuous phas (Bourrel and Schechter 1988). Second, it must maintain ultralow IFT at the moving displacement front to prevent mobilized oil from being trapped by capillary forces. Becau of the way they are pre-pared, commercial surfactants are invariably mixtures of multiple species, which rais questions as to whether chromatographic paration (i.e., preferential adsorption on pore surfaces or pref-erential partitioning into the oil pha of some species) can cau IFT variations with possible adver effects on oil recovery. When alcohol is ud in the formulation, it partitions among the bulk-oil and brine phas and the surfactant films in a manner different from the surfactant. The alcohol must then be carefully lected and tested to ensure there is no deleterious effect of chromato-graphic paration (Dwarakanath et al. 2008; Sahni et al. 2010). In the surfactant films, alcohol rves as a cosolvent, making the films less rigid and thereby increasing the rate of equilibration and preventing formation of undesirable viscous phas and emulsions instead of the desired low-viscosity microemulsions. Alcohol can also rve as a cosurfactant, altering, for instance, the optimal
salin-ity required to achieve ultralow IF T. Alcohols with short chains such as propanol increa optimal salinity for sulfonate surfactants, while longer-chain alcohols such as pentanol and hexanol decrea optimal salinity. For petroleum sulfonates and synthetic alkyl/aryl sulfonates with light crude oils, it has been found that 2-butanol acts as a cosolvent but has less effect on optimal salinity than other alcohols.
A disadvantage of using alcohol is that it decreas solubiliza-tion of oil and water in microemulsions, and hence increas the minimum value of IFT achievable with a given surfactant (Salter 1977). Also, it destabilizes foam that may be desired for mobility control with the slug and in the drive. F or temperatures below approximately 60°C, the need for alcohol’s cosolvent effect can be reduced or eliminated by some combination of the following strategies: (1) using surfactants with branched hydrocarbon chains, (2) adding ethylene oxide (EO) and/or less-hydrophilic propylene oxide (PO) groups to the surfactant, and (3) using mixtures of surfactants with different hydrocarbon-chain lengths or structures. Such measures counter the tendency of long, straight hydrocarbon chains of nearly equal length to form condend surfactant films and the lamellar liquid-crystalline pha. At high temperatures, incread thermal motion promotes more-flexible surfactant films and disruption of ordered structures, but it does not always elimi-nate viscous phas and emulsions. F u
rther studies are needed to investigate ufulness of the or other strategies for high temperatures.
The u of branched hydrocarbon chains to minimize or elimi-nate alcohol requirements was discusd by Wade, Schechter, and coworkers (Abe et al.1986). An isotridecyl hydrophobe was ud in Exxon’s pilot test in the Loudon field. The hydrophilic part of the surfactant was a chain consisting of short PO and EO gments and a sulfate group (Maerker and Gale 1992). With this combina-tion of the first two strategies, no alcohol was required. The Neodol 67 hydrophobe developed and manufactured by Shell Chemical has an average of 1.5 methyl groups added randomly along a straight C
15
–C
16
chain that provides another type of branching. A propoxyl-ated sulfate with this hydrophobe has been blended with an internal olefin sulfonate, which is also branched, and ud to displace west Texas crude oils in low-salinity, ambient-temperature laboratory tests, both with (Levitt et al. 2009) and without (Liu et al. 2008) alcohol. In this ca, all three strategies were combined.
Long-term surfactant stability at rervoir conditions is another surfactant requirement. Provided that pH is maintained at slightly alkaline levels and calcium concentration is not too high, hydro-lysis of sulfate surfactants is limited for temperatures up to 50–60°C (Talley 1988). Surfactants with other head groups, most likely sulfonates or carboxylates, will be needed for rervoirs at higher temperatures. Becau the sulfonate group is added at different points along the hydrocarbon chain during synthesis, internal olefin sulfonate (IOS) surfactants consist of species with
a twin-tailed structure, a different type of branching. Results of laboratory studies of IOS pha behavior at high temperatures have recently been prented (Barnes et al. 2008, 2010; Zhao et al. 2008, Puerto et al. 2010). Hydrocarbon-chain lengths ranged
from C
15–C
18
to C
24
–C
28
. However, the effect of dissolved calcium
and magnesium ions, which most likely cau surfactant precipita-tion, was not investigated in the studies (e Fig. 3 of Liu et al. 2008). Moreover, the current availability of internal olefins of long chain length, as would be required for low or moderate rervoir salinities, is limited. Alpha olefin sulfonate (AOS) surfactants have the same potential disadvantages and are not as highly branched as IOS surfactants.
Sulfonate groups cannot be added directly to alcohols, includ-ing tho with EO and/or PO chains. One approach is to prepare sulfonates with glycidyl chloride or epichlorohydrin, where a three-carbon chain is added between the EO or PO chain and the sulfonate group. Wellington and Richardson (1997) described some results with such surfactants. F urther information on their synthesis and initial pha-behavior results for propoxy glycidyl sulfonates with the Neodol 67 hydrophobe is given by Barnes et al. (2008). Puerto et al. (2010) prented pha behavior showing that suitable ethoxy or propoxy glycidyl sulfonates could produce microemulsions with high solubiliza
tion over a wide range of opti-mal salinities with n-octane as the oil at temperatures up to 120°C. They also noted that becau the surfactants typically exhibit pha paration (cloud point) at high temperatures and salinities, it may be necessary to blend them with other surfactants such as IOS, which are also stable at high temperatures.
Until recent years, nearly all work was directed toward EOR in sandstone rervoirs owing to concerns that in the high-divalent-ion environment of carbonate rervoirs, petroleum or synthetic sulfonates would adsorb excessively and/or form calcium and magnesium salts that would either precipitate or partition into the oil pha. The exception was the work of Adams and Schievelbein (1987), who conducted laboratory experiments and two field tests showing that oil could be displaced in a carbonate rervoir using a mixture of petroleum sulfonates and ethoxylated sulfate surfac-tants. The ethoxy groups add tolerance to divalent ions. Recent work with carbonate rervoirs ud ethoxylated or propoxylated sulfates, as discusd in the later ction on wettability.
Alcohol-Free Surfactant Slugs for Injection
The surfactant slug to be injected should be a single-pha micel-lar solution. Especially when polymer is added to increa slug viscosity, it is esntial to prevent paration into polymer-rich and
surfactant-rich phas, which yields highly viscous phas unsuitable for either injection or propagation through the forma-tion (Trushenski 1977). At low temperatures, oil-free mixtures of petroleum sulfonate/alcohol or synthetic sulfonate/alcohol mix-tures with brine are often translucent micellar solutions at salinities well below optimal, but contain lamellar liquid crystal and exhibit birefringence near optimal salinity where ultralow IF T is found upon mixing with crude oil (Miller et al. 1986). In the abnce of polymer, the lamellar pha is often disperd in brine as particles having maximum dimensions of at least veral microm-eters. When polymer is added to such a turbid dispersion of the lamellar pha, it produces a polymer-rich aqueous solution and a more concentrated surfactant dispersion (Qutubuddin et al. 1985). This undesirable behavior can sometimes be avoided by adding sufficient alcohol. However, u of alcohol has disadvantages, as indicated previously.
The lamellar pha was obrved in surfactant/brine mixtures in the abnce of oil even for Exxon’s Loudon formulation mentioned previously (Ghosh 1985), where, as indicated, branching and addition of EO/PO groups allowed low-viscosity microemulsions to be formed and ultralow IFT to be achieved with the crude oil without the need to add alcohol. Exxon avoided pha paration when polymer was added to the injected slug by including a paraf-finic white oil of high molecular weight in the form
ulation. That is, they injected a white oil-in-water microemulsion (Winsor I), which became a bicontinuous microemulsion when mixed with substantial volumes of crude oil in the rervoir (Maerker and Gale 1992).
As temperature increas, the lamellar liquid-crystal pha may melt. However, the surfactant/brine mixture is still unsuitable for injection if paration into two or more liquid phas occurs near optimal salinity (Benton and Miller 1983). Even if bulk pha paration does not occur, turbid solutions are sometimes obrved. The solutions usually have large, anisotropic micelles and parate into surfactant-rich and polymer-rich phas with the addition of polymer. The phas can parate and/or plug the porous media into which they are injected. Adding alcohol can reduce micelle size and prevent pha paration in some cas. As indicated previously, addition of a paraffinic-oil which yields an oil-in-water microemulsion with nearly spherical drops is another approach for preventing pha paration when polymer is prent. Within limits, the higher the molecular weight of the oil added to produce an oil-in-water microemulsion, the less oil is needed to formulate single phas with polymer for mobility control.
Another approach to formulate single-pha injection composi-tions would be to find surfactants or surfactant blends that neither exhibit pha paration nor form turbid solutions or liquid crystal-line
dispersions at conditions of interest (Flaaten et al. 2009; Sahni et al. 2010). Blends of the branched surfactant Neodol 67 propoxyl-ated sulfate (N67-7POS), having an average of ven PO groups with the twin-tailed surfactant IOS 15-18, an IOS (Barnes et al. 2010) made from a feedstock containing mainly C
15
–C
18
chains, are interesting in this respect. Fig. 1 shows pha behavior at ambient temperature of 3 wt% aqueous solutions of such surfactant blends containing 1 wt% Na
2
CO
3
and varying NaCl concentration but no alcohol or polymer. IOS 15-18 alone precipitates above 4 wt% NaCl in such solutions. In contrast, solutions of the propoxylated sulfate alone do not precipitate but instead become cloudy above the same salinity, as droplets of a cond liquid pha form and scatter light. Addition of IOS 15-18 to the propoxylated sulfate makes the mixture more hydrophilic, thereby raising the salinity at which pha paration occurs to a value higher than for either sur-factant alone. For instance, the 4:1 blend (hereafter NI blend) (i.e., 80% N67-7POS and 20% IOS 15-18) exhibits pha paration at approximately 6 wt% NaCl (plus 1% Na
2
CO
3
), although slight cloudiness occurs above approximately 3.5 wt% NaCl. Addition of 0.5 wt% of partially hydrolyzed polyacrylamide to a 0.5 wt% solution of this blend in a solution containing 4 wt% NaCl and 1 wt% Na
2
CO
3
produces pha paration, although similar addition of polymer to a solution containing only 2 wt% NaCl does not (Liu et al. 2008). Pha-behavior studies show that the optimal salinity of this blend with a west Texas crude oil is approximately 5 wt% NaCl (with 1 wt% Na
2
CO
3
) when the amount of surfactant prent is much greater than soap formed from the naphthenic acids in the crude oil. However, in alkaline/surfactant process, it is best to inject at lower salinities, as discusd later, becau the surfactant encounters conditions during the process with greater ratios of soap-to-surfactant and correspondingly lower optimal salinities. Indeed, excellent recovery of the west Texas crude oil was obrved in sandpack experiments when a single-pha mix-ture of the 4:1 blend and polymer was injected at 2 wt% NaCl with 1 wt% Na
2
CO
3
(Liu et al.2008). At 2% NaCl, the surfactant micelles are not highly anisotropic, and polymer and surfactant can coexist in the same pha.
A similar approach was ud by F alls et al. (1994) in an alkaline/surfactant field test. They added a small amount of the nonionic surfactant Neodol 25-12 to the main injected surfactant, a blend of IOSs, to make the formulation sufficiently hydrophilic to form a single micellar solution during storage at ambient tempera-ture. Becau this surfactant becomes less hydrophilic at higher temperatures, it did not adverly affect process performance at the rervoir temperature of approximately 57°C.
Alkaline/Surfactant Process: Role of Alkali Nelson et al. (1984) propod injection of a solution containing both surfactant and alkali for EOR. Such process have attracted and continue to attract considerable interest. They have been labeled by different names, but will be collectively described here
as alkaline/surfactant process (Nelson et al. 1984; Peru and Lorenz 1990; Surkalo 1990; Baviere et al. 1995).
The primary role of the alkali in an alkaline/surfactant process is to reduce adsorption of the surfactant during displacement through the formation and questering divalent ions. An addi-tional benefit of alkali is that the soap is formed in situ from the naphthenic acid in the crude oil (Johnson 1976). As indicated pre-viously, the generation of soap allows the surfactant to be injected at lower salinities than if ud alone, which further reduces adsorp-tion and facilitates incorporation of polymer in the surfactant slug. Also, alkali can alter formation wettability to reach either more water-wet or more oil-wet states. In fractured oil-wet rervoirs, the combined effect of alkali and surfactant in making the matrix preferentially water-wet is esntial for an effective process. The benefits of alkali will occur only where alkali is prent. Thus, it is important to determine “alkali consumption,” which controls the rate of propagation of alkali through the formation.
R educed Surfactant Adsorption. The discussion here will be limited to anionic surfactants (Wesn and Harwell 2000). The primary mechanism for the adsorption of anionic surfactants on
sandstone- and carbonate-formation material is the ionic attrac-tion between positively charged mine
ral sites and the negative surfactant anion (Tabatabal et al. 1993; Zhang and Somasundaran 2006). Thus, the role of the alkali is to be a “potential-determining ion” to rever the charge on positively charged mineral sites. The potential-determining ions for oxide minerals are the hydronium and hydroxide ions. The pH at which the charge revers is the “isoelectric point” if measured by electrophoresis (zeta potential) and is the “point-of-zero-charge” if determined by titration. The values are tabulated for most common minerals (Lyklema 1995). Silica is negatively charged at rervoir conditions and exhibits negligible adsorption of anionic surfactants. Clays (at neutral pH) have negative charge at the faces and positive charge at the edges. The clay edges are alumina-like and thus are expected to rever their charge at a pH of approximately 9. Carbonate formations and sandstone-cementing material can be calcite or dolomite. The latter minerals also have an isoelectric point of approximately pH 9, but carbonate ions, as well as the calcium and magnesium ions, are more signifi cant potential-determining ions. The zeta potential of calcite is negative even at neutral pH in the prence of 0.1 N carbonate/bicarbonate ions (Hirasaki and Zhang 2004). If a for-mation contains iron minerals, the oxidation/reduction conditions infl uence whether the surface iron sites are Fe 3+ or Fe 2+. Adsorption of anionic surfactant for one sandstone was found to be lower by more than a factor of two for reducing rather than for oxidizing conditions (Wang 1993). Surfactant adsorption is only one com-ponent of surfactant retention. Pha trapping of surfactant can be more signifi cant and will be discusd later.
Alkaline preflush had been advocated for both questering divalent ions and reducing sulfonate adsorption (Holm and Rob-ertson 1981). In subquent work, alkali has been injected with the surfactant. Adsorption of anionic surfactants on Berea sandstone was reduced veral-fold with addition of sodium carbonate for petroleum sulfonate (Bae and Petrick 1977) or with addition of sodium silicate or hydroxide for alcohol ethoxysulfate (Nelson et al. 1984). The reduction of adsorption on Berea sandstone with sodium bicarbonate was 68% in a dynamic experiment (Peru and Lorenz 1990). Static and dynamic adsorption of anionic surfactants on calcite and dolomite was decread by an order of magnitude with addition of sodium carbonate, but insignificantly with sodium hydroxide (e Figs. 2 through 4) (Hirasaki and Zhang 2004; Seethepalli et al. 2004; Zhang et al. 2006; Liu et al. 2008; Tabata-bal et al. 1993). (The TC Blend of Figs. 2 through 4 is an earlier blend of isotridecyl 4PO sulfate and C12 3EO sulfate. Rearch
on it was discontinued becau its optimal salinity was too high for the application of interest.)Divalent-Ion Sequestration. The pha behavior of anionic sur-factant systems is much more nsitive to a change in divalent ions (e.g., Ca 2+ and Mg 2+) compared to monovalent ions (e.g., Na +), especially at low surfactant concentrations (Nelson 1981). This is problematic in sandstones becau of ion exchange between the clay, brine, and surfactant micelles (Hill et al. 197
7; Pope et al. 1978; Hirasaki 1982). This exchange can result in the pha behav-ior becoming overoptimum, with resulting large surfactant reten-tion (Glover et al. 1979, Gupta 1982). Alkali anions (e.g., carbon-ate, silicate, and phosphate) that have low solubility product with divalent cations will quester divalent cations to low concentra-tions (Holm and Robertson 1981). Hydroxide is not as effective for questration of calcium becau the solubility product of calcium hydroxide is not very low. Sodium metaborate has recently been introduced as an alkali that may quester divalent ions (Flaaten et al. 2009; Zhang et al. 2008). A common problem with alkali injection is that softened water is needed to avoid scaling.Generation of Soap. The original concept of alkali fl ooding was the reduction of oil/water IFT by in-situ generation of soap, which is an anionic surfactant, sodium naphthenate (Jennings 1975). Ultralow IF T usually required injection of relatively fresh water with a low concentration of alkali becau optimal salinity (total electrolyte concentration) of the in-situ-generated soap is usually low (e.g., <1% electrolyte). If the alkali concentration is too low, alkali consumption reactions may result in a large retardation of Pha boundary Clear solution T wo clear phas Precipitation
Cloudy solution Cloudy after nine months
Multipha Region
One-Pha Region
10987
6543210
% N a C l
1:1 4:1 9:1
N67:IOS (w/w)
IOS N67
Fig. 1—Effect of added NaCl on pha behavior of 3 wt% solutions of N67/IOS mixtures containing 1 wt% Na 2CO 3 (L iu et al. 2008).
the alkali displacement front. The concept of alkaline/surfactant fl ooding is to inject a surfactant with the alkaline solution such that mixture of the in-situ-generated soap and injected surfactant has an optimal salinity that is tailored to the rervoir fl uids (Nelson et al. 1984; Surkalo 1990).
The common method ud to determine the amount of naph-thenic acid in crude oil is the total acid number (TAN), determined by nonaqueous titration with a ba (Fan and Buckley 2007). If sodium naphthenate is to act as a surfactant, it should partition into the aqueous pha at low electrolyte concentrations and be measurable by hyamine titration for anionic surfactants. It was found that the sodium naphthenate determined by extraction into the aqueous pha and measured by hyamine titration is less than the TAN value (Liu et al. 2010). It is hypothesized that the TAN includes components that are too lipophilic to be extracted to the aqueous pha and/or too hydrophilic to be detected by hyamine titration.Alkali Consumption. The ASP process should be designed such that displacement fronts of the alkali, surfactant, and polymer travel together. The mechanisms responsible for the retardation of the alkali front include silica dissolution, clay dissolution with zeo-lite precipitation, anhydrite or gypsum dissolution with calcite (or calcium hydroxide or silicate) precipitation, dolomite dissolution with calcium and magnesium silicate precipitation, hydrogen-ion exchange, divalent-ion exchange with precipitation, and mixing with divalent ions in formation water with precipitation (Ehrlich and Wygal 1977; Holm and Robertson 1981; Southwick 1985; Cheng 1986; Novosad and Novosad 1984; Jenn and Radke 1988; Mohammadi et al. 2009). Naphthenic acids in crude oil also react with alkali and thus contribute to consumption, but the amount is usually small compared to the mentioned inorganic mineral reactions. Silica dissolution can be controlled by using a buffered system such as sodium carbonate or silicate rather than hydroxide
(Southwick 1985). Clay dissolution is strongly dependent on the
A d s o r p t i o n D e n s i t y ,10–3 m m o l /m 2
Residual Surf. Conc., mmol/l
2.5
2.01.5
1.0
0.5
0.0
0.0 0.5 1.0 1.5 2.0 2.5
Original 0.05%TC blend
0.05%TC blend/3.5% Na 2CO 3
Original 0.1%TC blend
0.05%TC blend
0.05%TC blend/4% Na 2CO 30.1%TC blend
0.05%TC blend/3% Na 2CO 30.05%TC blend/4.5% Na 2CO 30.1%TC blend//3% Na 2CO 3
Fig. 2—Static adsorption of TC blend surfactant on dolomite sand. BET surface area of the calcite: 17.8 m 2/g (Zhang et al. 2006).
D i m e n s i o n l e s s C o n c e n t r a t i o n
Injected V olume, PV
1.00.90.80.70.60.50.40.30.20.10.0
Expr. 1
v =1.2 feet/day beta=0.34±0.03Φ=0.335Expr. 2
v =12 feet/day beta=0.22±0.03Φ=0.338
Cl −
Expr. 2
Expr. 1
Calculated from dolomite isotherm beta=0.04
0.0 0.5 1.0 1.5 2.0 2.5 3.0
Fig. 3—Dynamic adsorption of 0.2% TC blend surfactant without Na 2CO 3 on dolomite sand (Zhang et al. 2006).
pH and type of clay, and is kinetically limited (Sydansk 1982). Thus, acidic clay such as kaolinite, as well as high temperature, will increa the importance of this mechanism.
A limitation of the application of sodium carbonate in carbonate formations is that if anhydrite or gypsum is prent, it will dissolve and precipitate as calcite (Hirasaki et al. 2005; Liu 2007). This is detrimental for dolomite formations becau they may have origi-nated from evaporite deposits where gypsum is usually prent. An alternative alkali is sodium metaborate (Zhang et al. 2008; Flaaten et al. 2009). However, longer-term experiments and equilibrium calculations indicate that this metaborate will also precipitate.
Alkaline/Surfactant Process: Wettability
Alteration
Wettability is the next most important factor in waterflood recov-ery after geology (Morrow 1990). The recovery efficiency of a flooding process is a function of the displacement efficiency and sweep efficiency. The efficiencies are a function of the residual-oil saturation (waterflood and chemical flood) and mobility ratio, respectively. The residual-oil saturation to waterflooding is a function of wettability, with the lowest value at intermediate wet-tability (Jadhunandan and Morrow 1995). The mobility ratio is a function of the ratio of water relative permeability to oil relative permeability at their respective endpoints or at a specific satura-tion. The mobility ratio or relative permeability ratio becomes progressively larger as the wettability changes from water-wet to
oil-wet (Anderson 1987b). When a formation is strongly oil-wet,
it can have both a high waterflood residual-oil saturation and unfavorable mobility ratio. In addition, an oil-wet formation will have capillary resistance to imbibition of water (Anderson 1987a). F ormation wettability can be altered by pH (Wagner and Leach 1959; Ehrlich et al. 1974; Takamura and Chow 1985; Buckley et al. 1989, Dubey and Doe 1993), surfactants that adsorb on the minerals (Somasundaran and Zhang 2006) or remove adsorbed naphthenic acids (Standnes and Austad 2000), and acids or bas
(Cuiec 1977). The process are now incorporated into chemi-cal-flood simulators (Anderson et al. 2006; Delshad et al. 2006; Adibhatla and Mohanty 2007, 2008).
Sandstone Formations. Wettability alteration to more water-wet or more oil-wet conditions was propod as one of the mechanisms of caustic fl ooding (Wagner and Leach 1959; Ehrlich et al. 1974;
Johnson 1976). Our current understanding of microemulsion pha behavior and wettability is that the system wettability is likely to be preferentially water-wet when the salinity is below the optimal salinity (Winsor I). When the system is overoptimum (Winsor II), macroemulsions tend to be oil-external. An oil-external mac-roemulsion will trap water and have a low oil and water relative permeability, similar to what one expects with oil-wet porous media. The optimal salinity for a conventional alkali fl ooding system is dependent on the in-situ-generated sodium naphthenate soap, and is usually below approximately 1% electrolyte strength. Becau salinity of rervoir brine typically exceeds this value, a conventional alkali fl ood often generates overoptimum and oil-wet conditions. We show later in this review that this behavior can be avoided by injecting the alkali and surfactant in the Winsor I region. After mixing with the fl uids in the rervoir of interest, it will pass through the Winsor III, low-IF T region. Even a high-salinity sandstone formation that is initially oil-we
t may be altered to preferentially water-wet by injecting alkali with a hydrophilic surfactant in the Winsor I region. Carbonate Formations. Wettability alteration has received more attention recently for carbonate formations compared to sand-stones becau carbonate formations are much more likely to be preferentially oil-wet (Treiber and Owens 1972). Also, carbonate formations are more likely to be fractured and will depend on spontaneous imbibition or buoyancy for displacement of oil from the matrix to the fracture.
Wettability-alteration tests on plates of calcite, marble, lime-stone, and dolomite with different surfactants and sodium carbon-ate have been ud to identify many systems that are altered to preferentially water-wet with low anionic-surfactant concentra-tions (Hirasaki and Zhang 2004; Seethepalli et al. 2004; Zhang et al. 2006; Adibhatla and Mohanty 2008; Gupta et al. 2009). Sodium carbonate has an important role becau the carbonate ion is a potential-determining ion for calcite and dolomite (Hirasaki and Zhang 2004).Spontaneous Imbibition. Spontaneous imbibition is the process
by which a wetting fl
uid is drawn into a porous medium by capil-lary action (Morrow and Mason 2001). The prence of surfactant in some cas lowers the IFT, and thus the capillary pressure, to
negligible values. Spontaneous displacement can still occur in this ca by buoyancy or gravity drainage (Schechter et al. 1994).
The rearch group of Austad has investigated spontane-ous imbibition into chalk-formation material with enhancement by cationic and nonionic surfactants and/or sulfate ions prent in 0.00.10.20.30.40.50.60.70.80.91.0
0.0
0.5
1.0
1.5
2.0
2.5
3.0
Injected Volume, PV
D i m e n s i o n l e s s C o n c e n t r a t i o n
Experimental Data for NaCl Experimental Data for Surfactant Simulation Curve for Surfactant Simulation Curve for NaCl
0.1%CS330+0.1%TDA-4PO +0.3MNa 2CO 3beta=0.07±0.04v =1.2 feet/day
Fig. 4—Dynamic adsorption of 0.2% TC blend/0.3-M Na 2CO 3 on dolomite sand (Zhang et al. 2006).
