ASP Flooding: Definition, Chemical EOR, and Oil Recovery

Alkaline-surfactant-polymer (ASP) flooding is a three-component chemical enhanced oil recovery (EOR) technique that combines an alkaline agent, a synthetic surfactant, and a water-soluble polymer into a single injected slug to mobilize and displace crude oil that conventional waterflooding has left behind in the reservoir. By simultaneously reducing interfacial tension (IFT) at the oil-water contact to near-zero levels and improving the viscosity ratio between the injected fluid and the resident oil, ASP flooding routinely recovers an additional 10 to 20 percent of the original oil in place (OOIP) beyond the waterflood baseline. The process draws on decades of chemical EOR research and has been deployed at commercial scale in China, the United States, and Canada, making it one of the most thoroughly field-tested tertiary recovery methods available to operators today.

Key Takeaways

• ASP flooding uses three synergistic agents: an alkali (typically sodium carbonate, Na₂CO₃) that reacts with acidic crude components to generate in-situ petroleum soap, a synthetic surfactant that drives IFT below 0.001 mN/m, and a high-molecular-weight polymer (usually HPAM) that controls mobility and sweep efficiency.
• The alkali reduces the consumption of synthetic surfactant by neutralizing reservoir minerals and generating its own surface-active species, which can cut total chemical costs by 30 to 50 percent compared with surfactant-only flooding.
• Screening criteria are strict: crude oil total acid number (TAN) above 0.5 mg KOH/g, reservoir temperature below 90 degrees C (194 degrees F), salinity below 30,000 ppm total dissolved solids (TDS), and low carbonate mineral content to avoid excessive alkali consumption.
• Daqing Oil Field in China is the world's largest ASP flood, with commercial-scale pilots demonstrating incremental recovery of 12 to 19 percent OOIP over waterflood performance and cumulative production in the hundreds of millions of barrels.
• Post-flood produced water handling is the dominant operational challenge: alkaline conditions create stable emulsions and scale in surface facilities, requiring purpose-built demulsification, softening, and water treatment trains before reinjection or disposal.

How ASP Flooding Works

An ASP flood is designed to attack two separate reasons why waterflood alone leaves so much oil in the ground. The first reason is capillary trapping: after a waterflood, residual oil saturation (S_or) in swept zones commonly ranges from 20 to 35 percent pore volume, held in place by capillary forces at the oil-brine interface. The ratio of viscous-to-capillary forces is captured by the capillary number (N_c); to mobilize trapped oil, N_c must increase by roughly three to four orders of magnitude above the typical waterflood value near 10^-7. The combined alkali-surfactant package achieves this by driving IFT from roughly 20-30 mN/m (brine-crude) down to 0.001 mN/m or lower, raising N_c into the range where the oil-water meniscus can be deformed and displaced. The second reason is poor volumetric sweep: because most reservoir crudes are more viscous than injected brine, the waterflood front becomes unstable, fingers through the oil, and bypasses large portions of the pattern. The polymer component addresses this by increasing the apparent viscosity of the injected slug to roughly 5 to 20 times that of brine, stabilizing the displacement front and forcing the chemical slug into lower-permeability zones that the waterflood never contacted.

The role of each component in the chemical slug is distinct but interdependent. The alkali (sodium carbonate at 0.5 to 2.0 wt%, or sodium hydroxide in older designs) reacts with naphthenic acids and other carboxylic acid groups present in the crude to saponify them, forming natural petroleum soaps in situ. These soaps are themselves surface-active and contribute to IFT reduction, but more importantly they reduce adsorption of the expensive synthetic surfactant onto reservoir rock surfaces, which is the key economic lever of the ASP design. The synthetic surfactant package, typically blended from petroleum sulfonates, alpha-olefin sulfonates (AOS), internal olefin sulfonates (IOS), or extended surfactants, is formulated to achieve ultra-low IFT across the salinity and temperature window of the specific reservoir, with the alkali shifting the optimal salinity of the surfactant system to match formation water conditions. Surfactant concentration in the main slug typically runs 0.1 to 0.5 wt%. The polymer, almost universally partially hydrolyzed polyacrylamide (HPAM) or its thermally stabilized variant (PHPA), is blended into both the main chemical slug (0.1 to 0.2 wt%) and a chase polymer buffer slug (0.05 to 0.15 wt%) that follows it. The polymer buffer maintains mobility control behind the chemical bank, preventing the lower-viscosity chase water from fingering through and bypassing the recovered oil bank that is being driven toward producing wells.

Slug design follows a standard sequence: a small alkaline pre-flush (to condition rock wettability and consume reactive minerals), followed by the main ASP slug (typically 0.1 to 0.3 pore volumes), then a polymer drive slug (0.3 to 0.5 pore volumes), and finally a tapering water flood to push the polymer out and recover the oil bank at producing wells. Total project duration from ASP injection start to peak oil response commonly ranges from 12 to 30 months depending on well spacing and permeability. Incremental oil is produced as a broad, low-concentration peak rather than the sharp rise seen in gas flooding, which means surface facilities must be sized for sustained emulsion handling rather than brief peak rates.

The Three Components in Detail

Alkali

Sodium carbonate (Na₂CO₃) is the alkali of choice in most modern ASP designs because it generates a mildly alkaline pH (10 to 11.5) that is sufficient to saponify naphthenic acids without causing severe precipitation of divalent cations (Ca²⁺, Mg²⁺) as calcium carbonate scale. Sodium hydroxide (NaOH) achieves higher pH (12+) and stronger saponification but triggers aggressive silicate dissolution and severe scaling in carbonate-bearing formations. Sodium metaborate and sodium orthosilicate have been evaluated as alternatives that buffer pH in a narrower range while providing some corrosion protection in steel tubulars. The alkali concentration must be optimized against the reservoir's alkali demand, which includes both the in-situ soap generation reaction with crude acid components and the irreversible consumption by clay minerals, carbonate cement, and formation formation water hardness. Alkali demand testing on reservoir core and brine is an essential step in ASP project design.

Surfactant

The synthetic surfactant drives IFT to the ultra-low range needed to mobilize residual oil at connate-water saturations typical of a waterflood-depleted zone. The most widely used anionic surfactant families for ASP applications are: petroleum sulfonates (derived from sulfonation of aromatic fractions of crude oil or refinery cuts, low cost but variable composition); alpha-olefin sulfonates (AOS, synthesized from linear alpha olefins C14-C16, good hydrolytic stability); internal olefin sulfonates (IOS, sulfonation of internal olefins, highly tolerant of high salinity and divalent cations); and extended surfactants (propoxylated or ethoxylated versions of the above, enabling IFT minimization over a broader salinity window). The surfactant formulation is almost always a blend of two or more components to achieve ultra-low IFT across the temperature and salinity gradient between injector and producer. Achieving IFT below 0.001 mN/m (1 micro-Newton per meter) requires precisely matching the hydrophile-lipophile balance (HLB) of the surfactant to the crude oil composition, which is validated by spinning drop tensiometry at reservoir conditions. Surfactant adsorption onto reservoir rock remains the primary cost risk: in sandstone reservoirs, adsorption losses of 0.1 to 0.4 mg surfactant per gram of rock are typical without alkali; the alkali reduces this to 0.02 to 0.08 mg/g, a four- to fivefold improvement that is the economic foundation of the ASP concept.

Polymer

The polymer component addresses mobility control, which is the volumetric sweep problem that chemical flooding alone cannot solve. HPAM with a molecular weight of 10 to 25 million Daltons is injected at concentrations of 500 to 2,000 ppm, producing apparent viscosities of 5 to 50 mPa-s in porous media at reservoir shear rates. Polymer flooding without the chemical components has itself been shown to increase oil recovery by 5 to 12 percent OOIP in suitable reservoirs (the Pelican Lake polymer flood operated by Canadian Natural Resources Limited in Alberta is one of the most extensive examples in North America), demonstrating the sweep efficiency value of the polymer component alone. In the ASP combination, the polymer prevents the chemical slug from fingering through the oil bank and diluting before it has achieved its displacement work. HPAM degrades at temperatures above 80 degrees C (176 degrees F) through thermal hydrolysis, which at high pH (above 11) and high temperature can cause precipitation of polyacrylate-calcium complexes. This temperature sensitivity, combined with the alkali constraint (less than 90 degrees C / 194 degrees F), is one of the two dominant reservoir screening constraints on ASP applicability. Xanthan gum has been evaluated as a thermally stable polymer alternative but its higher cost and susceptibility to biodegradation have kept HPAM dominant. Related topics: artificial lift modifications are often required in ASP projects as emulsion production increases pump loads.

Reservoir Screening Criteria

Not all reservoirs are candidates for ASP flooding. Industry screening guidelines, refined from pilot experience at Daqing, West Kiehl, and other projects, specify the following preferred ranges:

• Crude TAN: above 0.5 mg KOH per gram of oil (sufficient naphthenic acid content to generate meaningful in-situ soap)
• Oil viscosity: below 100 mPa-s at reservoir conditions (polymer mobility control becomes impractical for heavier crudes without thermal co-injection)
• Temperature: below 90 degrees C (194 degrees F) for HPAM stability; below 70 degrees C (158 degrees F) preferred for economic polymer performance
• Salinity: below 30,000 ppm TDS; divalent cation concentration (Ca²⁺ + Mg²⁺) below 500 ppm to prevent surfactant precipitation and HPAM crosslinking
• Permeability: above 50 millidarcies (mD) to allow polymer injection at acceptable pressures (higher-MW HPAM cannot enter pore throats in tight formations)
• Net-to-gross: above 0.5; heavily layered or highly heterogeneous reservoirs reduce sweep efficiency even with polymer
• Lithology: sandstone preferred; high-clay-content sands and carbonate reservoirs have high alkali demand and are generally unsuitable
• Current oil saturation: residual oil saturation above 20 percent pore volume post-waterflood to justify chemical costs