Alkaline-Surfactant-Polymer Flooding

Key Takeaways

• The alkaline component reduces synthetic surfactant adsorption by 50 to 80%, fundamentally changing the economics of chemical EOR from marginal (surfactant alone) to potentially profitable by cutting the surfactant consumption needed to saturate reservoir rock adsorption sites before active IFT reduction begins: Anionic surfactant adsorption on sandstone quartz and feldspar surfaces (0.5 to 2.0 mg surfactant/g rock) consumes the injected chemical before it can generate IFT reduction in the advancing front. At a surfactant cost of CAD 8 to 20/kg (AOS C16-C18), this adsorption demand alone imposes a chemical cost that makes standalone surfactant flooding uneconomic for typical WCSB sandstone reservoirs. Adding 1.0 wt% Na₂CO₃ raises pore-water pH to 11.5, deprotonating silanol groups on quartz surfaces (increasing negative surface charge that electrostatically repels anionic surfactant), precipitating Ca²⁺ and Mg²⁺ as carbonates (removing the divalent cation bridges that facilitate anionic surfactant adsorption), and generating in-situ sodium carboxylate soap from crude oil acids (competing for adsorption sites). Laboratory tests on Cardium core confirm adsorption reduction from 1.8 mg/g to 0.4 mg/g with Na₂CO₃ addition — a 78% reduction that shifts the surfactant economics into the profitable range at CAD 60/bbl Bow River oil pricing.
• The optimal salinity condition S* is the single most critical laboratory measurement in ASP design, defining the formation water salinity at which the chosen surfactant formulation achieves minimum IFT (below 0.001 mN/m) through Winsor Type III microemulsion formation with the specific crude oil in the target reservoir at reservoir temperature: Below S*, the surfactant partitions into the water phase (Winsor Type I, O/W emulsion, moderate IFT 0.01-0.1 mN/m); above S*, surfactant partitions into the oil phase (Winsor Type II, W/O emulsion, moderate IFT); at S*, the surfactant forms a bicontinuous microemulsion in equilibrium with both excess oil and water phases, and IFT with both phases approaches zero. For an AOS C16-C18 formulated for Pembina Cardium crude at 28°C, S* is approximately 80,000 mg/L NaCl equivalent — significantly higher than the Cardium formation brine salinity of 15,000 to 35,000 mg/L. Bringing the injected brine to S* requires co-solvents (isopropanol 0.5 to 2.0 wt%) or surfactant blending (AOS + petroleum sulfonate 70/30 wt%) to shift S* downward toward reservoir brine salinity. Salinity scan phase behaviour experiments in glass tubes (10 to 15 salinity points from 10,000 to 150,000 mg/L NaCl) at reservoir temperature, requiring 3 to 8 weeks of equilibration, define S* for each crude-surfactant combination and are a non-negotiable step in any ASP project design.
• Polymer molecular weight selection for the ASP slug must balance the viscosity needed to achieve mobility ratio M below 1 against the minimum pore throat diameter required for unimpeded polymer transport, with HPAM of 15 million Daltons unsuitable for reservoirs below 50 to 100 mD permeability where mechanical entrapment causes rapid injectivity loss: A 15-million-Dalton HPAM molecule in solution has a hydrodynamic radius of approximately 200 to 300 nm, requiring pore throat diameters of at least 1,000 to 1,500 nm for unimpeded flow. Below 50 to 100 mD reservoir permeability, the smallest pore throats mechanically trap HPAM and injectivity falls within weeks. Montney and Duvernay tight formations (0.001 to 0.01 mD) are completely unsuitable for polymer or ASP flooding; Cardium (10 to 80 mD) requires lower-MW polymer (5 to 8 million Daltons) at higher concentration; Pelican Lake Mannville A sand (100 to 800 mD) and Lloydminster Colony (500 to 2,000 mD) are well-suited for 15 to 20 million Dalton HPAM at 1,200 to 1,800 mg/L, achieving solution viscosities of 30 to 120 cP at field shear rates and mobility ratios below 0.5 relative to the 2,000 to 8,000 cP Pelican Lake heavy crude. Xanthan biopolymer (naturally lower MW at equivalent viscosity) provides an alternative for tighter reservoirs but is susceptible to microbial degradation without continuous biocide addition.
• Stable oil-in-water emulsions produced by ASP flooding impose significant surface facility costs that reduce net incremental oil revenue by 20 to 35%, requiring electrostatic coalescers, increased demulsifier dosage, and extended separator retention time beyond standard waterflood battery design: The combination of ultra-low IFT (from surfactant) and increased displacing-phase viscosity (from polymer) produces stable O/W emulsions with Sauter mean droplet diameters of 10 to 50 microns and static coalescence times of 2 to 12 hours — far beyond the 15 to 30 minutes of retention in standard free-water knockouts. Daqing ASP wells documented FWKO emulsion retention times of 4 to 8 hours, requiring electrostatic coalescers (CAD 180,000 to 450,000 per battery) and demulsifier increases from 20-80 ppm (waterflood baseline) to 200 to 500 ppm. Produced water from ASP floods contains residual HPAM at 50 to 300 mg/L, increasing viscosity to 1.5 to 3.0 cP and reducing suspended-solids settling in water disposal systems. Total surface facility upgrade costs for a 10-well ASP pilot in the Pelican Lake area were estimated by Cenovus Energy at CAD 6.2 million in 2014 (approximately CAD 620,000 per producing well), a fixed capital component that must be amortised across the incremental oil production in the field development economics.
• The Daqing commercial ASP programme — the world's largest chemical EOR project by injection well count and cumulative incremental production — confirms that ASP is commercially viable at field scale under favourable conditions and documents the operational challenges that make ASP management more complex than conventional polymer flooding: Daqing began commercial-pattern-scale ASP injection in 1999 using 1.2 wt% Na₂CO₃, 0.3 wt% petroleum sulfonate, and 1,000 mg/L HPAM (12 million Daltons). By 2010 more than 800 injection wells were active; incremental oil recovery of 15 to 22% OOIP above polymer flood baseline was confirmed, with total ASP cumulative production exceeding 1.2 billion barrels through 2020. Operational challenges documented at Daqing include: CaCO₃ and BaSO₄ scale in approximately 30% of producing wells annually (requiring acid stimulation); emulsion processing reducing battery throughput by 20 to 40% at peak; and produced water HPAM of 100 to 400 mg/L requiring flocculation before reinjection to prevent permeability damage in disposal formations. The Daqing engineering team developed and published solutions to all three challenges in SPE papers 89360, 127559, and 166283, and these protocols are now the reference basis for ASP flood design in Canada and the Permian Basin.