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Alkaline-surfactant-polymer (ASP) flooding

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Alkaline-Surfactant-Polymer (ASP) Flooding is one of the proven technology in chemically enhanced oil recovery (CEOR) methods, which can be used for recovering heavy oil containing organic acids from sandstone formations. ASP Flooding belongs to a class of CEOR method that uses the benefits of combinations of chemicals simultaneously i.e. Alkali, Surfactant and Polymer.

The ASP flooding is one of the main methods in chemical enhanced recovery. Similar to other chemical EOR, ASP is used to improve the mobility ratio and increase the capillary number, mainly by making the interfacial tension (IFT) between the displacing and the displaced phases small, usually by about 1,000 folds[1]. This combination of chemicals can be considered a perfect solution to improve mobility ratio and capillary number. Thus, this method can enhanced the oil production with the improvement of both the sweep and displacement efficiency[2].

Alkaline-surfactant-polymer flooding technique is for more than 20 % OOIP and has been successful in three completed projects in North America as well as several projects in China[3]. ASP flooding technique has shown to be an economically viable technology in comparison with water floods.

CEOR Classification

ASP Flooding Mechanism

The recovery efficiency of a flood is the product of the volumetric sweep efficiency and displacement efficiency[4]. Polymer can increase the viscosity of injection water so as to improve the mobility ratio between the displacement and displaced phases, which is the basic of ASP flooding.

A typical ASP injection process has three slugs: pre-slug, main ASP slug, and post-slug. The function of a pre-slug is to inject polymer solution for profile improvement. Sometimes, alkaline slug is injected as a pre- slug. Its objective is to remove high-concentration divalent to avoid association with the subsequent surfactants

ASP flooding involves injection of alkali to generate in situ surfactants, surfactants to reduce interfacial tension between displacing and displaced phase and polymer to improve mobility ratio and thus sweep efficiency, and is followed by extended waterflood. In a system with water and oil, a surfactant will reduce the interfacial tension between the two liquid phases, which “liberates” residual oil held by capillary forces i.e. a reduction of capillary pressure in the reservoir. This “liberated” oil can now be more easily mobilized and produced.

Concentration of alkali, surfactant and polymers used in the process depends upon oil type, salinity of the solution, pressure, temperature and injection water quality. Polymer is used for improving mobility ratio which greatly contributes to the expansion of sweep efficiency[5]. The use of the alkali and the surfactant is to reduce interfacial tension between the displacing phase and the oil phase so as to improve the oil displacement efficiency. Alkali could also reduce the adsorption of expensive surfactants.

ASP Flood

ASP Flooding Screening Criteria

Enhanced oil recovery (EOR) processes are well known for incrementing oil production; however, the selection of the most suitable method to adopt for specific field applications is challenging. Therefore, it is pertinent to consider certain screening parameters before application of any recovery method and the most important ones are geology and mineralogy. Few important parameters to consider for ASP Flooding are:

  • Preferred for sandstones reservoir
  • Stratification desirable
  • Reservoir Temperature less than 200 °F
  • Salinity < 20,000 ppm
  • Lower Ca++ and Mg++ contents
  • Formation relatively homogeneous
  • Oil Viscosity < 35 cp and API Gravity > 20 °API
  • Oil composition is light to intermediate components
  • Oil Saturation > 35 %
  • Average Permeability > 10 md

ASP Chemical Contents

Chemical composition of ASP Flooding is based on:

  • Alkaline Content

Alkaline for ASP is Sodium Hydroxide (NaOH) and Sodium Carbonate (Na2CO3). Alkali is often added to the aqueous solution to increase efficiency as it helps to reduce surfactant adsorption to the rock[6].

Potential Alkali reactions in formation are:

2NaOH + Ca+2-> 2Na+ + Ca OH)2

2NaOH + Mg+2-> 2Na++ Mg(OH)2

Na2CO3 + Ca+2-> 2Na+ + Ca CO3

Na2CO3 + Mg+2-> 2Na+ + Mg CO3

  • Surfactant

Types of surfactant in ASP are:

  1. Alkyl Benzene Sulfonates

  2. Petroleum Sulfonates

  3. Lignosulfonates

  4. Petroleum Carboxylates

  5. Biologically Produced Surfactants

These surfactants aid in the generation of an ultra-low IFT between the oil and water.

  • Polymer

In ASP flooding, polymer is Hydrolyzed Polyacrylamide (HPAM). A water-soluble polymer is added to increase the viscosity of the water phase to improve mobility control[7]. The effectiveness of HPAM relies in the following chemical features:

  • The lack of oxygen single bonds (-O-) in the polymer backbone (carbon chain) provides thermal stability.
  • The presence of non‐ionic hydrophilic group (i.e. -CONH2) promotes chemical stability.
  • The carboxyl group (-COO-) resulting from the hydrolysis of the amide groups reduces the adsorption tendency of HPAMs onto rock surfaces and increases its viscosity.
  • The cost of the polymer is relatively low[8].
Structure of HPAM[9]

ASP Benefits

ASP flooding has the following benefits over other CEOR methods:

  • ASP is a cost‐effective process.
  • The synergistic effects of the ASP mixture make this process attractive for EOR applications.
  • The amount of chemical consumed per unit volume of oil produced during ASP flooding is usually low when the three chemical slugs (alkaline, surfactant and polymer) are injected in sequence or as a single slug[10].

ASP Flooding Limitations

Some of the limitations of the ASP process are related to:

  • Issues with chemical separation (i.e. Chromatographic separation).
  • Water treatment cost.
  • Emulsions and scale formation that could make the process complex.
  • Issues with creating contact with the formation oil.
  • Potential corrosion /scale problems in the pipeline and equipment.


  1. Thomas, S., & Ali, S. M. (2001). Micellar flooding and ASP-chemical methods for enhanced oil recovery. Journal of Canadian Petroleum Technology, 40(02).
  2. Hillary, A., Taiwo, O. A., Mamudu, A., & Olafuyi, O. (2016, August). Analysis of ASP Flooding in a Shallow Oil Reservoir in the Niger Delta. In SPE Nigeria Annual International Conference and Exhibition. Society of Petroleum Engineers.
  3. Lake, L. W. (1989). Enhanced oil recovery.
  4. Clarke, A., Howe, A. M., Mitchell, J., Staniland, J., & Hawkes, L. A. (2016). How viscoelastic-polymer flooding enhances displacement efficiency. SPE Journal, 21(03), 0675-0687.
  5. Mishra, S., Bera, A., & Mandal, A. (2014). Effect of polymer adsorption on permeability reduction in enhanced oil recovery. Journal of Petroleum Engineering, 2014.
  6. Khan, M. Y., Samanta, A., Ojha, K., & Mandal, A. (2009). Design of alkaline/surfactant/polymer (ASP) slug and its use in enhanced oil recovery. Petroleum Science and Technology, 27(17), 1926-1942.
  8. Abidin, A. Z., Puspasari, T., & Nugroho, W. A. (2012). Polymers for enhanced oil recovery technology. Procedia Chemistry, 4, 11-16.
  9. Aluhwal, H., & Kalifa, O. (2008). Simulation study of improving oil recovery by polymer flooding in a Malaysian reservoir. Department of Petroleum Engineering, Universiti Teknologi Malaysia, 212.
  10. Froning, H. R., & Leach, R. O. (1967). Determination of chemical requirements and applicability of wettability alteration flooding. Journal of Petroleum Technology, 19(06), 839-843.