Dynamic Interfacial Tension Behavior of Pure and Binary Surfactant System

Surfactants are very important surface-active agents in implementation of chemical enhanced oil recovery for oil-water interfacial tension and wettability alteration. However, the high adsorption of surfactant on reservoir rock reduces the efficiency of surfactant flooding. Conventionally, inorganic alkali has been introduced to reduce adsorption of surfactant, but alkali will lead to the formation of emulsion, formation damage and scaling. Therefore, lignosulfonate, a sacrificial agent has been introduced as an alternative to inorganic alkali. In this paper, the critical micelle concentration (CMC) and dynamic interfacial tension (IFT) behavior of a pure and binary system of internal olefin sulfonate (IOS) and lignosulfonate (LS) at brine-decane interfaces are determined by using a spinning drop method. The physicochemical properties of pure and binary of IOS and LS system are determined by conductivity and pH measurements. The CMC value of IOS in 3.5 wt% brine salinity is higher compared to LS due to the isomeric branched of IOS which can occupy a larger area per molecules. The dynamic interfacial tension of IOS shows the fast adsorption of surfactant molecules to the brine-decane interfaces. This is indicated by the fast equilibrium interfacial tension reached by IOS. In comparison, the LS pure system shows decreasing behavior of dynamic interfacial tension. The fast adsorption at the interfaces is only reached for higher LS concentrations. The synergy effect between IOS and LS system shows a reduction in the interfacial value with LS optimum concentration of 0.6 wt%. The drop in conductivity and pH values indicated the development of a tightly packed lamellar liquid crystalline structure. These physicochemical properties are in agreement with the dynamic interfacial tension behavior of the IOS and LS system. This study has demonstrated the significant impact of the LS addition in reducing the dynamic interfacial tension of the surfactant system.

Oil Recovery by Alkaline/Surfactant/Foam Flooding: Effect of Drive-Foam Quality on Oil-Bank Propagation

Summary Alkaline/surfactant/foam (ASF) flooding is a novel enhanced–oil–recovery (EOR) process that increases oil recovery over waterflooding by combining foaming with a decrease in the oil/water interfacial tension (IFT) by two to three orders of magnitude. We conducted an experimental study regarding the formation of an oil bank and its displacement by foam drives with foam qualities within the range of 57 to 97%. The experiments included bulk phase behavior tests using n–hexadecane and a single internal olefin sulfonate surfactant, and a series of computed–tomography (CT) –scanned coreflood experiments using Bentheimer Sandstone cores. The main goal of this study was to investigate the effect of drive–foam quality on oil–bank displacement. The surfactant formulation was found to lower the oil/water IFT by at least two orders of magnitude. Coreflood results, at under-optimum salinity conditions yielding an oil/water IFT on the order of 10–1 mN/m, showed similar ultimate–oil–recovery factors for the range of drive–foam qualities studied. A more distinct frontal oil–bank displacement was observed at lower drive–foam qualities investigated, yielding an increased oil–production rate. The findings in this study suggested that dispersive characteristics at the leading edge of the generated oil bank in this work were strongly related to the surfactant slug size used, the lowest drive–foam quality assessed yielded the highest apparent foam viscosity (and, thus, the most stable oil–bank displacement), and drive–foam strength increased upon touching the oil bank when using drive–foam qualities of 57 and 77%.

Effects of Hardness and Cosurfactant on Phase Behavior of Alcohol-Free Alkyl Propoxylated Sulfate Systems

Summary The effect of hardness was investigated on equilibrium phase behavior in the absence of alcohol for blends of three alcohol propoxy sulfates (APSs) with an internal olefin sulfonate (IOS) with a C15–18 chain length. Hard brines investigated were synthetic seawater (SW), 2*SW, and 3*SW, the last two with double and triple the total ionic content of SW with all ions present in the same relative proportions as in SW, respectively. Optimal blends of the APS/IOS systems formed microemulsions with n-octane that had high solubilization suitable for enhanced oil recovery at both ≈25°C and 50°C. However, oil-free aqueous solutions of the optimal blends in 2*SW and 3*SW, as well as in 8 and 12% NaCl solutions with similar ionic strengths, exhibited cloudiness and/or precipitation and were unsuitable for injection. In SW at 25°C, the aqueous solution of the optimal blend of C16–17 7 propylene oxide sulfate, made from a branched alcohol, and IOS15–18, was clear and suitable for injection. A salinity map prepared for blends of these surfactants illustrates how such maps facilitate the selection of injection compositions in which injection and reservoir salinities differ. The same APS was blended with other APSs and alcohol ethoxy sulfates (AESs) in SW at ≈25°C, yielding microemulsions with high n-octane solubilization and clear aqueous solutions at optimal conditions. Three APS/AES blends were found to form suitable microemulsions in SW with a crude oil at its reservoir temperature near 50°C. Optimal conditions were nearly the same for hard brines and NaCl solutions with similar ionic strengths between SW and 3*SW. Although the aqueous solutions for the optimal blends with crude oil were slightly cloudy, small changes in blend ratio led to formation of lower phase microemulsions with clear aqueous solutions. When injection and reservoir brines differ, it may be preferable to inject at such slightly underoptimum conditions to avoid generating upper phase, Winsor II, conditions produced by inevitable mixing of injected and formation brines.

Ammonia as Alkali for Alkaline/Surfactant/Polymer Floods

Summary Ammonia is logistically preferred over sodium carbonate for alkaline/surfactant/polymer (ASP) enhanced-oil-recovery projects because of its low molar mass and the possibility for it to be delivered as a liquid. On an offshore platform, space and weight savings can be the determining factor in deciding whether an ASP project is feasible. Logistics may also be critical in determining the economic feasibility of projects in remote locations. Ammonia as alkali together with a surfactant blend of alkyl propoxy sulfate/internal olefin sulfonate (APS/IOS) functions as an effective alkali. Surfactant adsorption is low, and oil recovery in corefloods is high. Static adsorption tests show that low surfactant adsorption is attained at pH >9, a condition that ammonia satisfies at low solution concentration. It is expected that ammonia has a performance deficiency relative to sodium carbonate in that it does not precipitate calcium from solution. Calcium accumulation in the ammonia ASP solution will occur, caused by ion exchange from clays. The high oil recovery for ammonia and the calcium accumulation in ASP and surfactant/polymer corefloods with APS/IOS blends show that this surfactant system is effective and calcium-tolerant. Also, phase behavior and interfacial-tension (IFT) measurements suggest that APS/IOS blends remain effective in the presence of calcium. Ethylene oxide/propylene oxide sulfates (such as the used APS) are known commercially available, calcium-tolerant surfactants. However, because of hydrolysis, sulfate-type surfactants are suitable for use only in lower-temperature reservoirs. Very different behavior was noticed for phase-behavior measurements with calcium-intolerant surfactants such as alkyl benzene sulfonates and IOS. In this case, calcium addition results in a very high IFT and complete separation of oil and brine. Presumably, this will result in low oil recovery. A preferred approach for ASP offshore with divalent-ion-intolerant surfactants may be the use of a hybrid alkali system combining the attributes of sodium carbonate and ammonia. The concept is to supply the bulk of the alkalinity for an ASP flood by ammonia with all the inherent logistical advantages. A minor quantity of sodium carbonate is added to the formulation to specifically precipitate calcium ions.

Ultra-Low Interfacial Tension and Retention of Internal Olefin Sulfonate (IOS) for EOR

Surfactant ultra-low interfacial tension (IFT) for internal olefin sulfonate with iso-amylalcohol (IAA) as co-solvent against heptane, octane and decane at 20 °C, 50 °C, and 90 °C respectively have been systematically investigated, as well as the dynamic retention in porous media. The results show for oils with alkane carbon number from 7 to 10 and temperature from 20 °C to 90 °C, optimal salinity starts from 6.5 wt% to 11.6 wt% NaCl, where ultra-low IFT occurs. While at high salinity (at least from 6 wt% NaCl ), the retention is too high for surfactant flooding to be applicable. Only internal olefin sulfonate with co-solvent alone can not provide a perfect formulation with ultra-low IFT and low retention.

Surfactant Systems for EOR in High-Temperature, High-Salinity Environments

Summary A systematic study was made of phase behavior of alkoxyglycidylether sulfonates (AGESs). These surfactants were screened with either NaCl-only brines or NaCl-only brines and n-octane at water/ oil ratio (WOR) ~1 for temperatures between approximately 85 and 120°C. All test cases were free of alcohols and other cosolvents. Classical Winsor phase behavior was observed in most scans, with optimal salinities ranging from less than 1% NaCl to more than 20% NaCl for AGESs with suitable combinations of hydrophobe and alkoxy chain type [ethylene oxide (EO) or propylene oxide (PO)] and chain length. Oil solubilization was high, indicating that ultralow interfacial tensions existed near optimal conditions. The test results for 120°C at WOR~1 have been summarized in a map, which might provide a useful guide for initial selection of such surfactants for EOR processes. Saline solutions of AGESs separate at elevated temperatures into two liquid phases (the cloud-point phenomenon), which may be problematic when they are injected into high-temperature reservoirs. An example is provided that indicates that this situation can be alleviated by blending suitable AGES and internal olefin sulfonate (IOS) surfactants. Synergy between the two types of surfactant resulted in transparent, single-phase aqueous solutions for some blends, but not for the individual surfactants, over a range of conditions including in synthetic seawater. Such blends are promising because both AGES and IOS surfactants have structural features that can be adjusted during manufacture to give a range of properties to suit reservoir conditions (temperature, salinity, and crude-oil type).