Surfactant Flooding

Key Takeaways

• Ultra-low interfacial tension is achieved by formulating surfactant systems near their optimal salinity or optimal hydrophilic-lipophilic deviation (HLD), a dimensionless parameter that balances the affinity of the surfactant molecule for the oil and water phases: at HLD equal to zero (optimal condition), the surfactant partitions equally between the oil and water phases through a microemulsion middle phase (Winsor Type III), and IFT between the microemulsion and both excess oil and excess water phases reaches its minimum value; above optimal salinity (HLD greater than zero, Winsor Type II), the surfactant preferentially partitions into the oil phase and IFT rises; below optimal salinity (HLD less than zero, Winsor Type I), the surfactant partitions into the water phase and IFT rises; the practical consequence of this behavior is that the surfactant formulation must be designed for the reservoir's specific brine salinity and temperature, because IFT at the Winsor Type III optimum can be 1,000 times lower than IFT at the Winsor Type I or II conditions encountered when the injected surfactant slug contacts formation brine of a different salinity; co-solvents (typically short-chain alcohols such as isopropanol or sec-butanol at 1 to 3 percent of the surfactant slug) are added to prevent formation of highly viscous lamellar liquid crystal phases and to extend the salinity window over which ultra-low IFT is maintained.
• Microemulsion phase behavior and Winsor classification govern the efficiency of surfactant flooding because the type and volume of microemulsion formed when the surfactant contacts oil determines how effectively the residual oil is solubilized and transported through the formation: Winsor Type I (oil-in-water microemulsion, surfactant-rich water phase in equilibrium with excess oil) forms below optimal salinity and solubilizes modest amounts of oil into the aqueous phase; Winsor Type III (bicontinuous or middle-phase microemulsion in equilibrium with both excess oil and excess water) forms near optimal salinity, achieves ultra-low IFT at both microemulsion-oil and microemulsion-water interfaces, and provides the highest oil solubilization ratios (typically 10 to 30 volumes of oil per volume of surfactant in the microemulsion phase); Winsor Type II (water-in-oil microemulsion, surfactant-rich oil phase in equilibrium with excess water) forms above optimal salinity; the solubilization ratio in the Winsor Type III region, measured in laboratory phase behavior experiments as the volume of oil (or water) solubilized per volume of surfactant in the microemulsion phase, is directly related to the minimum IFT achievable (Chun Huh's correlation: IFT approximately equal to C divided by solubilization ratio squared, where C is approximately 0.3 mN/m), making laboratory phase behavior screening the first step in surfactant formulation design before undertaking expensive core flood experiments.
• Alkali-surfactant-polymer (ASP) flooding combines three chemical EOR agents in a single slug to synergistically improve recovery over any individual chemical process: alkali (sodium carbonate or sodium hydroxide at 0.5 to 2 percent) reacts with naphthenic acids in the crude oil to form petroleum soaps (natural surfactants) in situ, reducing the external surfactant concentration required to achieve ultra-low IFT by as much as 10-fold compared to surfactant-only flooding; the alkali also reduces surfactant adsorption on silicate rock surfaces by raising pH and by competing with the surfactant for adsorption sites; the synthetic surfactant (internal olefin sulfonate, alpha olefin sulfonate, or branched alkyl propoxy sulfate at 0.1 to 0.5 percent) provides robust ultra-low IFT performance across a wider salinity range than is possible with natural soap alone; the polymer (partially hydrolyzed polyacrylamide or HPAM at 1,000 to 2,000 ppm) provides mobility control by increasing the viscosity of the chemical slug to prevent it from fingering through the oil bank; ASP flooding has achieved incremental recoveries of 15 to 25 percent of original oil in place above waterflood recovery in field pilots at Daqing (China), Soapflat (Texas), and Rangely (Colorado), making it the highest-recovery-factor chemical EOR method commercially demonstrated at field scale.
• Surfactant adsorption onto reservoir rock is the primary technical and economic barrier to commercial surfactant flooding, because adsorption depletes the surfactant concentration below the critical threshold required for ultra-low IFT before the slug can propagate through sufficient reservoir volume to mobilize meaningful oil: static adsorption of anionic surfactants on sandstone surfaces ranges from 0.1 to 1 milligrams of surfactant per gram of rock, depending on the clay content (kaolinite, illite, and chlorite have high surface areas that adsorb large surfactant quantities), the formation water hardness (divalent cations Ca2+ and Mg2+ increase anionic surfactant adsorption by forming insoluble divalent surfactant complexes that precipitate on rock surfaces), and the surfactant molecular structure (branched alkyl chains and propylene oxide groups reduce adsorption by creating steric hindrance at the adsorption site); sacrificial agents (cheap anionic surfactants or sodium silicate preflushes) can be injected before the surfactant slug to presaturate the rock adsorption sites, reducing main surfactant consumption; alkali injection reduces adsorption by up to 80 percent on silica surfaces; the economic viability of a surfactant flood requires that the cost of surfactant (typically USD 3 to 8 per pound for commercial IOS and AOS surfactants), multiplied by the mass of surfactant adsorbed and retained in the formation plus the mass produced in the effluent, be less than the revenue from the incremental oil recovery.
• Field applications of surfactant flooding span from small pilots in the 1970s through commercial-scale ASP floods at Daqing in the 1990s and 2000s, with the technology's evolution driven by improvements in surfactant chemistry, phase behavior understanding, and reservoir characterization: the Daqing ASP pilot (started 1994 in China's largest oilfield) demonstrated 20 percent incremental recovery over waterflood at field scale and launched large commercial ASP injection operations covering multiple injection patterns; North American ASP pilots at Soapflat field (Permian Basin, West Texas) demonstrated incremental recovery of 10 to 15 percent OOIP in carbonate reservoirs, which present additional challenges from higher divalent ion concentrations and calcite surface chemistry compared to sandstones; the Rangely field pilot in Colorado achieved positive results in a naturally fractured carbonate, where surfactant preferential entry into the matrix from the fractures mobilized oil that water injection had bypassed; the principal technical barriers for broader commercial adoption include (1) maintaining the surfactant chemical slug integrity as it disperses and dilutes over large interwell distances in heterogeneous reservoirs, (2) managing produced chemical handling and separation in facilities designed only for water and oil, (3) quantifying adsorption in the specific reservoir rock type before commitment to commercial-scale injection, and (4) securing adequate surfactant supply at consistent quality for multi-year injection programs at reasonable cost.