cosurfactant, Oil & Gas Glossary

What Is a Cosurfactant?

Cosurfactant (also called co-solvent or secondary surfactant) is a chemical additive used alongside a primary surfactant in chemical enhanced oil recovery (EOR) to lower the interfacial tension (IFT) between residual oil and injected water to ultra-low values, typically below 10⁻³ mN/m. Common cosurfactants are medium-chain alcohols such as isobutanol, secondary butanol, n-pentanol, and 2-ethylhexanol, although nonionic surfactants like alkyl-aryl ethoxylates are increasingly used in modern formulations. The cosurfactant tunes the phase behavior of the surfactant-brine-oil system so the formulation produces a Winsor Type III microemulsion at the reservoir's salinity and temperature.

Key Takeaways

Cosurfactants partition between the aqueous and oleic phases to fine-tune surfactant packing at the oil-water interface, driving IFT to ultra-low values.
The target microemulsion is Winsor Type III, a middle-phase microemulsion in equilibrium with both excess oil and excess brine, which corresponds to optimal salinity.
Common cosurfactants include isobutanol, sec-butanol, n-pentanol, and 2-ethylhexanol; nonionic ethoxylated co-surfactants are now common in surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) blends.
Salinity scans in the laboratory identify the optimal salinity at which IFT minimizes and oil recovery maximizes.
Field applications include the West Kiehl ASP project (Wyoming), Lawrence ASP (Illinois Basin), and the giant Daqing ASP floods in China.

How Cosurfactants Work

A primary surfactant adsorbs at the oil-water interface, with its hydrophilic head in water and its hydrophobic tail in oil. By itself, the primary surfactant rarely produces the ultra-low IFT needed to mobilize residual oil ganglia trapped by capillary forces in pore throats. Adding a cosurfactant changes the average curvature of the interface and the phase behavior of the surfactant-brine-oil system. Short and medium-chain alcohols partition into both phases, soften the interfacial film, and prevent the surfactant from forming gels, liquid crystals, or unwanted macroemulsions that would block pores rather than mobilize oil.

The hallmark of a properly tuned formulation is the appearance of a middle-phase microemulsion that solubilizes equal volumes of oil and water, the Winsor Type III state. At this point IFT against both excess phases reaches a minimum, often below 10⁻³ mN/m, and the capillary number rises by three to four orders of magnitude. Trapped residual oil is mobilized, the displacement front becomes piston-like, and recoveries beyond conventional waterflooding become achievable.

Fast Facts: Cosurfactant

Typical chemicals: isobutanol, sec-butanol, n-pentanol, 2-ethylhexanol, ethoxylated alcohols
Concentration: typically 0.5 to 2.0 weight percent of injection slug
Target IFT: ≤ 10⁻³ mN/m (ultra-low)
Target microemulsion: Winsor Type III (middle-phase)
Optimal salinity test: salinity scan with pipette tubes, 7 to 14 days equilibration
Solubilization parameter (σ*): target ≥ 10 (cm³ oil + cm³ water per gram surfactant)
Used in: SP (surfactant-polymer) and ASP (alkali-surfactant-polymer) floods
Field examples: West Kiehl, Lawrence, Daqing, Mangala, Bhagyam

Field Tip:

Always design the cosurfactant for the actual reservoir crude and connate brine, not a generic stock oil. Asphaltene content, naphthenic acid concentration, and divalent cation loading (calcium, magnesium) shift optimal salinity dramatically. A formulation that gives a Type III microemulsion in lab tests with a model oil can collapse to Type II or Type I when injected against live reservoir fluids.

Salinity Scans and Microemulsion Phase Behavior

Phase behavior testing is the foundation of cosurfactant selection. A laboratory salinity scan places equal volumes of crude oil and brine, plus a fixed dose of surfactant and cosurfactant, into a series of sealed pipettes. Salinity is varied across each pipette by adjusting NaCl or reservoir-blended brine. After equilibration at reservoir temperature for a week or longer, the chemist measures the volumes of the upper (excess oil), middle (microemulsion), and lower (excess brine) phases.

At low salinity the system is Winsor Type I, an oil-in-water microemulsion below an excess-oil layer. At high salinity it flips to Winsor Type II, a water-in-oil microemulsion above an excess-brine layer. At an intermediate salinity, the optimal salinity, the system passes through Winsor Type III, where a middle-phase microemulsion contains both oil and water in equal amounts. Optimal salinity is the design target. The cosurfactant is selected and dosed to place Type III at the salinity that the slug will actually experience downhole, accounting for connate brine mixing, ion exchange, and chromatographic separation.

Surfactant-Polymer and Alkali-Surfactant-Polymer Floods

Cosurfactants appear in two main chemical EOR architectures. Surfactant-polymer (SP) flooding injects a surfactant slug to mobilize residual oil, followed by a polymer drive (typically partially hydrolyzed polyacrylamide) to provide mobility control and prevent fingering. Alkali-surfactant-polymer (ASP) flooding adds a sodium carbonate or sodium hydroxide alkali to react with naphthenic acids in the crude, generating in-situ soap surfactants and reducing the synthetic surfactant requirement (and therefore cost).

The Daqing field in China has run the world's largest ASP project for over two decades, recovering tens of millions of incremental barrels. The West Kiehl pilot in Wyoming and the Lawrence ASP project in the Illinois Basin demonstrated commercial economics in onshore U.S. sandstones. India's Mangala and Bhagyam fields in Rajasthan operate large-scale ASP injection. Each project's cosurfactant dose, primary surfactant chemistry, alkali type, and polymer molecular weight were tuned to the specific crude composition, brine chemistry, and reservoir temperature.

Cosurfactant is also referred to as:

Cosolvent, used when the additive is primarily an alcohol that improves solubility and prevents gel formation.
Secondary surfactant, when a second nonionic or anionic surfactant complements the primary species.
Linker, in some academic literature describing molecules that bridge between water-soluble and oil-soluble surfactant components.

Frequently Asked Questions About Cosurfactants

Why can't a single surfactant achieve ultra-low IFT on its own?

Most single surfactants form rigid interfacial films, gels, or liquid crystals at high concentration, which prevent the system from reaching the balanced curvature required for a Type III microemulsion. The cosurfactant softens the film, partitions between phases, and lets the system find optimal salinity without forming kinetically stable but useless emulsions.

What's the difference between a cosurfactant and an alkali in ASP flooding?

The cosurfactant is a small-molecule additive (alcohol or nonionic) blended with the primary surfactant before injection. The alkali (Na2CO3 or NaOH) reacts in-situ with naphthenic acids in the crude oil to generate soap surfactants on the fly, reducing the synthetic surfactant requirement and the project's chemical cost.

How is the optimal salinity determined?

Through a salinity scan: a series of pipettes at varying salinity are equilibrated with crude, surfactant, and cosurfactant for 7 to 14 days at reservoir temperature. The salinity at which middle-phase microemulsion volume is maximized and IFT is minimized is the optimal salinity used for slug design.

Why Cosurfactants Matter in Oil and Gas

Conventional waterflooding leaves 30 to 60 percent of the original oil in place trapped by capillary forces. Chemical EOR with properly designed surfactant-cosurfactant-polymer systems can recover an additional 10 to 25 percent of OOIP, turning mature fields into long-life producers and unlocking reserves that would otherwise be abandoned. The cosurfactant is the small but critical molecule that lets the formulation hit ultra-low IFT, achieve the Winsor Type III microemulsion, and convert lab phase behavior into field-scale incremental recovery.