Enhanced Oil Recovery: Surfactant Flooding and Polymer Flooding Chemistry

Enhanced oil recovery (EOR) technologies have become increasingly critical as conventional reservoirs mature and global operators seek to extract every viable barrel from existing fields. Among tertiary recovery methods, chemical EOR—particularly surfactant flooding and polymer flooding—offers some of the most compelling incremental recovery potential, routinely adding 5–25% of original oil in place (OOIP) beyond primary and secondary methods.

The Physics Behind Chemical EOR

Primary recovery taps reservoir pressure. Secondary recovery (waterflooding) sweeps much of the mobile oil, yet typically leaves 60–70% of OOIP stranded due to two mechanisms: capillary trapping of residual oil in pore throats, and viscous fingering caused by the mobility contrast between injected water and reservoir oil. Chemical EOR directly attacks both failure modes.

Capillary number (Nc) governs whether oil mobilizes from pore throats: Nc = v·μ / σ. Surfactants reduce interfacial tension (σ) by 3–4 orders of magnitude, driving Nc above the critical threshold (~10⁻⁴) needed for mobilization.
Mobility ratio (M) governs sweep efficiency: M = (krw/μw) / (kro/μo). Polymer flooding increases aqueous-phase viscosity, reducing M toward unity and suppressing fingering.

Surfactant Flooding: Chemistry and Formulation

Effective surfactant systems for EOR must achieve ultra-low IFT (< 10⁻³ mN/m) against crude oil while tolerating high salinity and temperature.

Surfactant Classes Used in EOR

Surfactant Type	Typical IFT Reduction	Salinity Tolerance	Temperature Limit
Anionic (petroleum sulfonate)	10⁻² – 10⁻³ mN/m	Low–moderate	≤ 80°C
Anionic (internal olefin sulfonate, IOS)	10⁻³ – 10⁻⁴ mN/m	High (up to 200,000 ppm TDS)	≤ 120°C
Zwitterionic (betaine, sulfobetaine)	10⁻³ – 10⁻⁴ mN/m	Very high	≤ 130°C
Non-ionic (alcohol ethoxylate)	10⁻² mN/m	Moderate	≤ 70°C
Biosurfactant (sophorolipid)	10⁻² mN/m	Low	≤ 60°C

Injection concentration: Surfactant slugs are typically injected at 0.1–0.5 wt% active concentration in a slug volume of 0.1–0.3 pore volumes (PV), followed by a polymer drive. Over-dosing above 1 wt% rarely improves recovery proportionally and increases cost sharply.

Co-solvent and Alkali Synergies

Surfactant-polymer (SP) flooding is often extended to alkali-surfactant-polymer (ASP) systems:

Alkali (Na₂CO₃ at 0.5–2 wt%, or NaOH at 0.05–0.2 wt%) reacts with naphthenic acids in crude to generate in-situ soap, reducing the external surfactant requirement by 30–60%.
Co-solvents (isopropanol, sec-butanol at 0.5–2 wt%) suppress surfactant partitioning into oil, maintaining the active concentration in the aqueous phase.
Optimal salinity: Each surfactant-oil-brine system has a characteristic optimal salinity where IFT is minimized (Winsor Type III microemulsion). Field formulations must be tuned within ±15% of optimal salinity to maintain ultra-low IFT throughout the reservoir.

Polymer Flooding: Rheology and Reservoir Conformance

Polymer flooding does not reduce IFT; it improves volumetric sweep efficiency by:

Reducing the mobility ratio (M < 1 is ideal).
Plugging high-permeability streaks (in-depth profile control with cross-linked systems).
Reducing water cut in producer wells.

Polymer Types and Performance

Polymer	Viscosity at 1,000 ppm (mPa·s)	Max Temperature	Salinity Tolerance	Shear Stability
HPAM (partially hydrolyzed polyacrylamide)	8–25	≤ 85°C	< 50,000 ppm TDS	Moderate
Sulfonated HPAM (AMPS co-polymer)	6–18	≤ 110°C	Up to 200,000 ppm TDS	Good
Xanthan gum	15–40	≤ 80°C	Moderate	Excellent
Hydrophobically associated polymer (HAP)	20–80	≤ 100°C	High	Good

Injection concentration: Field pilots typically inject HPAM or sulfonated polyacrylamide at 500–2,000 ppm (0.05–0.2 wt%), targeting an in-situ viscosity of 10–40 mPa·s. Concentration is selected to achieve M ≤ 0.5 while minimizing injectivity loss (avoid plugging near-wellbore).

Molecular Weight Considerations

Low MW (5–8 million Da): Better injectivity in low-permeability rock (< 100 mD); lower viscosity per ppm.
High MW (15–25 million Da): Superior viscosification in moderate-permeability rock (100–1,000 mD); requires careful shear management through perforations and surface equipment.

A rule of thumb: polymer MW (millions Da) × reservoir permeability (mD) / 1,000 should be < 3 to avoid mechanical degradation at the wellbore face.

SP and ASP Flood Design: Key Decision Parameters

Slug sequence (ASP example): [Pre-flush brine] → [Alkali + Surfactant + Polymer slug, 0.1–0.3 PV] → [Polymer drive, 0.5–1.0 PV] → [Chase water]

Critical design choices:

Salinity gradient: Design pre-flush salinity slightly above optimal to prevent surfactant adsorption on clays before the slug arrives.
Adsorption control: Add sacrificial agents (lignosulfonates, polyacrylate, sodium silicate at 200–1,000 ppm) to pre-saturate clay surfaces and reduce surfactant adsorption from > 2 mg/g rock to < 0.3 mg/g.
pH management: ASP systems maintain pH 10–11 to minimize surfactant hydrolysis and maximize in-situ soap generation.
Produced fluid handling: ASP effluent is an emulsion-rich, high-pH stream; plan for demulsifier dosing (50–300 ppm) and water treatment upfront.

Field Performance Benchmarks

Project	Method	OOIP Recovery Increment	Polymer/Surfactant Dosage
Daqing (China)	Polymer	+12–15% OOIP	HPAM 1,000–1,500 ppm, 0.7 PV
Shengli (China)	ASP	+18–22% OOIP	IOS 0.3 wt%, Na₂CO₃ 1.2 wt%
Wyoming (USA)	SP	+10–14% OOIP	Petroleum sulfonate 0.2 wt%
North Sea pilot	Polymer	+8–12% OOIP	HPAM 1,200 ppm, high-MW

Chemzip supplies a comprehensive portfolio of EOR chemicals for oilfield operators and formulation chemists—including high-performance sulfonated polyacrylamides, internal olefin sulfonates, zwitterionic betaine surfactants, sacrificial adsorption agents, and co-solvents. All products are available with full technical data sheets, compatibility testing support, and competitive bulk pricing for pilot and full-field deployment. Contact our technical team to discuss formulation optimization for your specific reservoir conditions.