Alkaline Flooding

Key Takeaways

• The critical requirement for effective alkaline flooding is that the crude oil must contain sufficient carboxylic acid functional groups to generate the in-situ soap concentration needed for IFT reduction below 0.01 mN/m, with an acid number threshold of approximately 0.3 mg KOH/g representing the practical lower limit for a standalone alkaline flood with sodium hydroxide or sodium carbonate: The acid number of crude oil is measured by ASTM D664 (potentiometric titration with KOH in toluene/isopropanol solvent) and reflects the total concentration of acid species including aliphatic carboxylic acids (R-COOH), naphthenic acids (cycloalkyl carboxylic acids), and phenols. Pelican Lake Mannville heavy crude in the Wabasca-Desmarais area of northwestern Alberta has acid numbers of 1.5 to 4.8 mg KOH/g in the A sand and B sand zones, reflecting significant biodegradation of the original paraffinic crude into polar, acid-rich bio-transformed oil. This high acid number means that a 0.3 wt% Na₂CO₃ alkaline slug generates sufficient in-situ sodium carboxylate to reduce IFT from 22 mN/m to approximately 0.003 mN/m at 25°C reservoir temperature, as measured by spinning drop tensiometer in laboratory corefloods. By contrast, a Cardium crude with AN = 0.08 mg KOH/g generates only one-tenth the in-situ soap concentration, reducing IFT to only 1.5 to 5 mN/m with the same 0.3 wt% Na₂CO₃ — insufficient to mobilise significant additional residual oil without supplemental synthetic surfactant injection. A general rule used by EOR engineers is that alkaline flooding alone (without surfactant) is viable when AN exceeds 1.0 mg KOH/g and the reservoir temperature is below 80°C; above 80°C, in-situ soap components tend to break down by thermal hydrolysis. ASP flooding (alkaline + surfactant + polymer) is required for crude oils with AN of 0.3 to 1.0 mg KOH/g to achieve commercially meaningful IFT reduction.
• Alkali consumption by formation mineralogy, formation water ions, and crude oil acid content must be quantified before alkaline flood design, because uncompensated alkali losses to the reservoir rock and brine cause the IFT reduction zone to collapse and oil mobilisation to cease before the injected slug reaches the producers: Alkali consumption in a sandstone reservoir proceeds by four parallel reactions: (1) direct reaction with formation divalent cations Ca²⁺ and Mg²⁺ in injection water or formation brine to precipitate CaCO₃ or Mg(OH)₂ (alkali consumption rate proportional to divalent ion hardness, typically 0.1 to 2.0 kg NaOH per m³ water injected for hardness of 50 to 500 mg CaCO₃/L); (2) cation exchange with clay minerals (montmorillonite, illite) in the reservoir, which exchange Na⁺ from NaOH for Ca²⁺ and Mg²⁺ on clay exchange sites, consuming 0.5 to 2.5 kg NaOH per kg of clay; (3) dissolution of anhydrite (CaSO₄) or dolomite (CaMg(CO₃)₂) into the injected brine, releasing additional Ca²⁺ and Mg²⁺ that precipitate as carbonates and hydroxides and consume more alkali; and (4) reaction with the crude oil acid number (the desired reaction, generating soap). For a Pelican Lake Mannville reservoir with 12 wt% clay content and formation water hardness of 280 mg CaCO₃/L, total alkali consumption is estimated at 3.5 to 5.0 kg Na₂CO₃ per m³ pore volume contacted, requiring the injected Na₂CO₃ concentration to be set at 1.5 wt% (versus the laboratory-optimal 0.5 wt%) to ensure sufficient residual alkalinity reaches the advancing IFT-reduction front after mineral and ion losses. Pre-injection lime softening of the source water to below 20 mg CaCO₃/L hardness is a standard field practice that reduces alkali consumption by 40 to 70% in hard-water environments and is economically justified for multi-year injection programmes.
• The choice between NaOH, Na₂CO₃, and Na₂SiO₃ as the alkali agent involves trade-offs among pH level, precipitation tendency, reservoir compatibility, and chemical cost, with Na₂CO₃ (soda ash) the preferred choice for most WCSB sandstone alkaline floods because it provides an intermediate pH of 11.0 to 11.8 without precipitating silica or causing severe scaling in production wells: NaOH generates pH 12.5 to 13.0 at 0.5 wt% concentration, providing the strongest driving force for saponification but also the highest precipitation tendency for Mg(OH)₂ and Ca(OH)₂ in hardwater reservoirs, the highest risk of clay swelling and dispersion from aggressive Na⁺ exchange, and the highest tendency for asphaltene precipitation from heavy crudes at elevated pH. Na₂CO₃ generates pH 11.2 to 11.6 at 0.5 to 2.0 wt%, sufficient for saponification of moderate-to-high acid number crudes with lower precipitation risk; its buffering capacity also helps maintain consistent pH as alkali is consumed by mineral reactions. Na₂SiO₃ generates pH 12.0 to 12.5 and additionally provides silicate ions that act as secondary scale inhibitors and clay stabilisers, but it costs approximately 4 to 6× more per mole of OH^- equivalent than Na₂CO₃ and can precipitate amorphous silica in formation water containing calcium, potentially plugging near-wellbore permeability. Na₂CO₃ at 1.0 to 2.0 wt% and CAD 180 to 280/tonne (2024 bulk chemical pricing) is the economically dominant choice for WCSB alkaline flooding, with total chemical costs of CAD 8 to 25 per m³ of injected slug at 0.3 to 0.5 pore volume slug size.
• Wettability alteration from oil-wet to water-wet conditions is the second major mechanism of alkaline flooding and can independently improve waterflood sweep efficiency even in reservoirs where IFT reduction is incomplete due to low acid number or high alkali consumption: Many carbonate minerals (calcite, dolomite) and reservoir rocks in the WCSB that have been in contact with crude oil for geological timescales (tens to hundreds of millions of years) develop oil-wet or mixed-wet surface conditions through adsorption of polar crude oil components (resins, asphaltenes, naphthenic acids) on mineral surfaces. In an oil-wet reservoir, water injected during waterflooding does not imbibe spontaneously into oil-occupied small pores (capillary forces oppose rather than assist water entry), leaving higher residual oil saturation after waterflood (typically 35 to 45% in strongly oil-wet rock versus 15 to 25% in water-wet rock). Alkaline flooding alters wettability by replacing adsorbed acidic crude oil components at the mineral surface with in-situ soap molecules, shifting the contact angle from >90° (oil-wet) toward <90° (water-wet). Laboratory imbibition tests on Pelican Lake Mannville cores show spontaneous water imbibition recovery of 5 to 12% OOIP when cores pre-equilibrated with crude oil are immersed in 1.0 wt% Na₂CO₃ solution versus less than 2% OOIP imbibition in plain brine, confirming the wettability alteration mechanism is independently significant for heavy oil recovery. In field pilots, wettability alteration contributes an estimated 3 to 8% OOIP incremental recovery above the waterflood endpoint, in addition to the 5 to 15% OOIP from IFT reduction, for a combined alkaline flood incremental of 8 to 20% OOIP where both mechanisms operate fully.
• Emulsification during alkaline flooding can be either a beneficial mechanism (oil-in-water emulsion formation that entrains bypassed oil into the flowing stream) or a production penalty (stable emulsions at the surface that require additional demulsifier treatment and reduce facility throughput), and the balance between these two effects determines whether the field alkaline flood economics are positive: When IFT falls below approximately 0.05 mN/m, the Laplace pressure required to maintain a stable oil-water interface becomes negligible and spontaneous emulsification occurs as low-energy mechanical mixing in the pore network (from fluid flow and bubble mobilisation) fragments the dispersed phase. The resulting fine oil-in-water emulsion (droplet size 1 to 50 microns) flows through the porous medium with mobility approaching that of the continuous water phase, effectively transporting dispersed oil from poorly swept zones to the production wells without requiring the oil phase to form a coherent bank. Laboratory micromodel experiments on Berea sandstone show that alkaline-induced emulsification recovers 8 to 15% additional oil from regions not contacted by the waterflood front, particularly from low-permeability laminae and dead-end pores. However, the same emulsification that improves in-situ mobility imposes a surface processing burden: produced oil-in-water emulsions require demulsifier (typically 50 to 200 ppm of polypropylene oxide-polyethylene oxide block copolymer) plus elevated temperature (40 to 60°C in free-water knockouts) and extended retention time to break. For Pelican Lake Mannville alkaline flood pilots operated by Husky Energy at Brintnell, the additional demulsifier cost was CAD 12 to 18/m³ of produced emulsion, partially offsetting the incremental oil revenue from alkaline flooding and illustrating why careful surface facility sizing is an integral part of alkaline flood economic assessment.