Summary We report results for a number of promising enhanced-oil-recovery (EOR) surfactants based upon a fast, low-cost laboratory screening process that is highly effective in selecting the best surfactants to use with different crude oils. Initial selection of surfactants is based upon desirable surfactant structure. Phase-behavior screening helps to quickly identify favorable surfactant formulations. Salinity scans are conducted to observe equilibration times, microemulsion viscosity, oil- and water-solubilization ratios, and interfacial tension (IFT). Cosurfactants and cosolvents are included to minimize gels, liquid crystals, and macroemulsions and to promote rapid equilibration to low-viscosity micro-emulsions. Branched alcohol propoxy sulfates (APS), internal olefin sulfonates, and branched alpha olefin sulfonates (AOS) have been identified as good EOR surfactants using this screening process. These surfactants are available at a low cost and are compatible with both polymers and alkali, such as sodium carbonate and, thus, are good candidates for both surfactant-polymer and alkali-surfactant-polymer EOR processes. One of the best formulations was tested in both sandstone and dolomite cores and found to give excellent oil recovery and low surfactant retention with a west Texas (WT) crude oil.
Several novel surfactants have shown excellent performance in tests using several crude oils that have properties, such as high wax content, that make high oil recovery with surfactants very difficult. High carbon-number, internal olefin sulfonates, when used with appropriate co-surfactants, co-solvents and alkali, produced the type of phase behavior and ultra-low interfacial tension needed for almost 100% oil recovery from laboratory core experiments. These surfactants could be used at both low and high temperatures and showed low retention in cores. This work demonstrates how the performance of both surfactant-polymer and alkaline-surfactant-polymer floods can be dramatically improved at the same or lower costs associated with conventional surfactants and co-solvents and at a wider range of reservoir conditions
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWe report results for a number of promising EOR surfactants based upon a fast, low-cost laboratory screening process that is highly effective in selecting the best surfactants to use with different crude oils. Initial selection of surfactants is based upon desirable surfactant structure. Phase behavior screening helps to quickly identify favorable surfactant formulations. Salinity scans are conducted to observe equilibration times, microemulsion viscosity, oil and water solubilization ratios and interfacial tension. Co-surfactants and co-solvents are included to minimize gels, liquid crystals and macroemulsions and to promote rapid equilibration to low-viscosity microemulsions. Branched alcohol propoxy sulfates, internal olefin sulfonates, and branched alpha olefin sulfonates have been identified as good EOR surfactants using this screening process. These surfactants are available at low cost and are compatible with both polymers and alkali such as sodium carbonate and thus are good candidates for both surfactantpolymer and alkali-surfactant-polymer EOR processes. One of the best formulations was tested in both sandstone and dolomite cores and found to give excellent oil recovery and low surfactant retention.
The effect of co-solvent on phase behavior was evaluated and an optimal surfactant/co-solvent formulation was selected based upon a combination of simulations and laboratory experiments. The co-solvent altered phase behavior, thereby necessitating a different approach for inducing effective salinity gradients. We present an approach where the hydrophilic nature of the co-solvent is used to maintain effective salinity gradients to optimize surfactant behavior but more importantly mitigate viscous microemulsions and reduce surfactant retention. By using a combination of laboratory experiments and simulations to match co-solvent behavior in UTCHEM, Using an understanding into co-solvent partitioning was developed such that the optimal conditions of ultra-low interfacial tensions are maintained for a longer duration during chemical flooding. We demonstrated that by adding the appropriate co-solvent and the correct amount of electrolyte in the chase solutions, we could maintain Winsor type III conditions for extended durations even with a small surfactant slug. The optimal co-solvent/electrolyte gradient recovered more than 90% of the residual oil in laboratory corefloods. The result illustrate the importance of characterizing the effect of co-solvent on surfactant phase behavior and the need for numerical modeling to optimize chemical flood design when co-solvent is used. Introduction The success of surfactant flooding rests on the ability of surfactant-oil mixtures to rapidly coalesce to form fluid and stable microemulsions with ultra-low tensions. Recent developments in the area of surfactant synthesis and screening have allowed the selection of high performance surfactant formulations for enhanced oil recovery.1, 2 These high-performance surfactant formulations require co-solvents toimprove phase behavior;reduce microemulsion viscosity; andensure surfactant-polymer compatibility. 1, 2 Such surfactant/co-solvent formulations show high oil recovery and low surfactant retention in corefloods. Numerical simulations are an important component to scale-up chemical flooding from lab to field-scale. Numerical simulations require matches of surfactant phase behavior and corefloods to obtain parameters for field-scale simulation. In typical simulation studies, the effect of co-solvent is usually neglected 3, 4, 5 and gross surfactant parameters are often used to capture chemical phase behavior. While this approach may be appropriate for formulations that use no co-solvent a design that includes the effect of co-solvent on surfactant phase behavior is preferred for accurate field-scale predictions. Co-solvents used for oil recovery are amphiphiles 6, 7 and have the ability to partition into aqueous, oleic and microemulsion phases. The ability to partition between the three phases allows co-solvents to significantly alter phase behavior. When a hydrophilic co-solvent is mixed with an anionic surfactant, an increase in optimal salinity is observed. Conversely, a lipophilic co-solvent will induce a reduction in optimal salinity. From these observations, Hedges8 used co-solvent scans to identify the appropriate co-solvent for a fixed optimal salinity. While co-solvents have been used widely in surfactant trials, their effect on phase behavior is often neglected due to the complexity of experimental measurements and incorporation into numerical simulation. An adverse consequence of ignoring co-solvent behavior could be chromatographic separation from the surfactant due to preferential partitioning. Such separation would induce changes in overall surfactant/co-solvent compositions along a dilution path and undesirable phase behavior.
Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.
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