Chemical enhanced oil recovery is an advanced technology that addresses the mechanisms that produce oil. The standard way to view oil production is though the oil recovery equation shown below.



  • Np – Oil Recovery (Production)
  • ED – Pore to Pore (Unit) Displacement Efficiency
  • EV – Volumetric Sweep Efficiency
  • OOIP – Original Oil in Place

Typical oil recoveries are between 20-45% because ED and EV are low. Oil is trapped in the pores due to capillary forces, which accounts for low ED. The capillary force can be minimized by reducing the interfacial tension (IFT), thereby increasing ED. At high IFT the oil drops are stuck in the pores; reducing the IFT results in a more flexible oil drop that is mobile through the reservoir. The figure below shows a simplistic diagram of how the oil drop is affected by IFT.

EV is based on water’s ability to sweep oil to a producer. The key concept with EV is mobility ratio (M). A simplistic way to understand M is to view it as the ratio of the velocity of water to the velocity of oil. If water moves faster than the oil (high M), it will bypass the oil and break through faster than desired (fingering and channeling affects). If the water moves at the same speed as the oil, it will do a better job sweeping the oil. The figure below shows the effect M has in displacing oil. Polymer agents are added to injection water to viscosify the water and lower its mobility to a more favorable condition.

Chemical EOR represents the best methods of improving both efficiencies, ED and EV.

CEOR uses Surfactants and/or Alkali, and Polymers in an aqueous solution to improve recovery efficiency. Alkalis and Surfactants improve ED, mobilizing the oil that is trapped in the pores. Polymers improve EV by enhancing the water’s ability to sweep oil to neighboring production wells by increasing its viscosity.

Each field has a unique oil, water, rock and temperature environment, and therefore the CEOR formulation is specifically developed.

Unlike other forms of EOR, such as CO2 which requires a nearby source, chemical EOR can be applied anywhere chemical can be transported by road, rail, or boat.

Chemical EOR is implemented in stages and actual size/duration of each stage depends on economics.

Typical chemical flood incremental recovery is in the range of 5-30% OOIP, depending on the process selected and the characteristics of the reservoir.

The figure below shows the stage of implementation for an ASP flood.

  1. ASP stage – mobilizes oil trapped by capillary forces creating an oil bank
  2. Polymer stage – pushes oil bank to producer
  3. Water stage – final push to finish the project

The following sections describe the variations associated with chemical EOR.

 Mobility Control Polymer Polymer Flooding (P) is the addition of water soluble polymer to viscosify injection water in order to reduce its mobility relative to the oil. Reduction of the mobility attempts to overcome poor sweep efficiency that occurs when viscous oil is displaced with lower viscosity water. Most polymer floods use partially hydrolyzed polyacrylamide polymer (HPAM) because it is widely available and relatively inexpensive. Polymer concentration ranges from 500 ppm to as high as 3000 ppm in reservoirs with highly viscous oil. Use of conventional polymers is limited to ~80°C unless water with very low hardness is used or other chemicals agents are included to stabilize the polymer. However, other types of polymers can push beyond temperature and chemical limitations of HPAM. These include AMPS (copolymer with sulfuric acid) and NVP (with N-vinyl pyrrolidone). Permeability is limited to a minimum of ~25 mD because polymer molecules are large enough to plug the small pore throats found in low permeability formations.

Polymer flooding has been applied successfully throughout the world for over 40 years and it is currently the most widely used chemical flooding technology based on the number of field applications and the mass of polymer injected.

Surfactant Polymer Surfactant-Polymer (SP) involves adding low concentrations (0.1% to 2%) of a surfactant and/or co-surfactant and/or co-solvent and/or salt to the injection water in order to reduce the oil-water interfacial tension. Polymer is added to increase the solution viscosity in order to overcome viscous instability of low interfacial tension displacement. The SP solution is injected for 20% to 40% pore volume of the target oil-bearing zone, followed by similar volumes of polymer flush.

Conceptually, SP flooding addresses both sweep efficiency and displacement efficiency, limited only to those conditions limiting polymer flooding. Practically, the process is limited to the amount of surfactant and polymer that can be blended together because at some concentration of one in the presence of the other, the solution begins to separate. The concentration of surfactant used must be greater than the critical micelle concentration (CMC) at which point the interfacial tensions become very low for surfactant at “optimum” conditions. The CMC is often quite low. However, both polymer and, to a much greater degree, surfactant are adsorbed by the reservoir rock surface, which decreases their concentration as they progress through the reservoir. Thus the surfactant concentration must be high enough to overcome this adsorption loss.

Designing an SP flood is more complex than polymer flooding. The condition at which a surfactant formulation is “optimum” is related to the water salinity, temperature, and pH, as well as crude oil properties. This “optimum” condition is expressed by very low interfacial tension between the crude oil and surfactant solution. Certain types of surfactant can handle the different reservoir temperature, water salinity, etc. or other unfavorable conditions, but no surfactant is the silver bullet that can handle them all.

Micellar- Polymer Micellar-Polymer (MP) is similar to SP except higher concentrations of surfactant are used (2% to 12%) and are injected for lower pore volume (5% to 20%). This structuring and many other properties of micellar solutions are sensitive to changes in salinity, temperature, etc. The micellar “slug” is followed by a polymer flush as with SP process.

Micellar-Polymer flooding was widely researched by major oil companies as a means to overcome the limitations of surfactant-polymer flooding – principally the adsorption loss of surfactant. The process proved to be technically very successful in field scale demonstration projects by many major oil companies in the 70’s and 80’s (10% OOIP to 20% OOIP incremental oil), but was then, and would be now uneconomic due to the high concentrations of surfactant used and their associated costs.

Alkali- Polymer Alkali-Polymer (AP) flooding involves adding an alkaline agent along with polymer to softened injection water. The water must be softened because the alkaline agents would cause any divalent cations, such as calcium and magnesium, to precipitate, and this solid precipitate will plug most formations. The alkali reacts with components of some oils (saponify) to form “soap” that in the right environment will reduce the interfacial tension sufficiently to overcome capillary forces trapping the oil. The AP solution is injected for 20% to 40% pore volume and followed by a similar volume of polymer flush.

AP flooding has been and is currently being used in full field projects with incremental recoveries of 10% OOIP to 20% OOIP. Of all the chemical flooding processes, it probably has the most limited number of potential applications because not all oils have components that saponify. Also, softening water itself can be complex and costly, depending upon the water hardness and salinity. However, AP flooding is more economic than processes using surfactant because the cost of alkali is much lower than surfactant.

Alkali-Surfactant-Polymer Alkali-Surfactant-Polymer (ASP) flooding simply adds surfactant (0.05% to 0.5%) to an AP solution to broaden the range of reservoir environment for which the ASP process applies. Many light oils do not contain sufficient amounts of the components that react with alkali to reduce the oil-water interfacial tension sufficiently to overcome capillary forces trapping the oil. Blending surfactant with the alkali overcomes this barrier. As with Alkali-Polymer flooding, the water must have very low divalent ion content (hardness), often requiring softening.

One property of alkaline agents is that they change the reservoir rock chemistry in such a way as to significantly decrease polymer and surfactant adsorption. Therefore, ASP projects use lower concentrations of added surfactant than Surfactant-Polymer or Micellar-Polymer projects. ASP flooding is being applied in field projects around the world with incremental recoveries in some cases greater than 20% OOIP.