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The Science of
Enhanced Oil Recovery

Behind TIORCO's success is the ability to bring the right blend of three key ingredients to each EOR project:
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ASP/SP

Alkaline Surfactant Polymer / Surfactant Polymer Technologies

Overview
Primary and Secondary Recovery techniques together are able to recover only about 35-50% of oil form the reservoir. This leaves a significant amount of oil remaining in the reservoir. Chemical flooding (using surfactants) is one of the available technologies that can be used to recover up to an additional 35%.

Surfactant flooding is a well known concept that has been practiced in the field for many decades. Current technology is a progressive and gradual development of technologies and ideas that have existed for a long time. The key difference is the amount of surfactant used in projects today is much lower due to high purity.

SURFACTANT FLOODING
Surfactant flooding is usually carried out after a waterflood. There are two main types of surfactant flooding – Alkaline Surfactant Polymer (ASP) or Surfactant Polymer (SP) flooding.

ASP vs. SP
ASP formulation typically consists of about 0.5-1% alkali, 0.1% surfactant and 0.1% polymer, while a SP formulation consist of 1% surfactant and 0.1% polymer. The choice between ASP or SP depends on a number of factors.

  • Acid value of the oil
  • Quality of water – if divalent ion concentration is high, >100 ppm, SP may have to be used
  • Economics of project
  • Ability to carry out water softening or desalination (geographic location)

All components are injected together into the reservoir as a “slug” and it is not a sequential injection. Typically, the A/SP slug is injected at about 0.3-0.4 PV for effective performance. The alkaline component react with the acidic moieties that exist in the oil creating natural soap and also helps reduce the adsorption of the surfactant on the rock. The surfactant component helps in releasing the oil from the rock and reduces the interfacial tension between water and oil. The polymer (typically, partially hydrolyzed polyacrylamide or HPAM) acts as the viscosity modifier and helps mobilize the oil. Typically, an A/SP flood is followed up with an equivalent pore volume injection of a polymer “push” solution. This helps reduce the slope of oil recovery decline and helps extend the production for a longer period of time. 

ASP Graphic

Pre-work for (A)SP
Today, typical implementation of (A)SP in the field (pilot scale) take about 3-4 years. This is mainly because of the lab developmental work that goes into the choice of the various components. Additionally, implementation requires significant capital expenditure for polymer hydration equipment, blending equipment and specialty injection pumps.

The lab work that goes into designing a surfactant flooding project is as follows:

  • Fluid analysis (water and oil analysis) 
  • Fluid-fluid work (phase behavior work) to identify alkali and surfactants
  • Alkali identification
  • Alkali concentration
  • Surfactant concentration
  • Static adsorption of surfactant on reservoir rock
  • Core flood Work
  • Oil displacement efficiency
  • Adsorption studies
  • Simulation or modeling work

Chemical EOR Project Planning

The various aspects of implementation of a chemical EOR project are summarized below.


  • Field History and Status
  • Field Geology
  • Oil Type
  • Available Water / CO2
  • Polymer, SP, ASP
  • Existing Equipment
  • Economic Modeling
  • Feedstock Supply Capacity
  • Prove Chemicals
  • IFT / Phase Behavior
  • Core Floods
  • Water TX plan
  • Flood Pattern Injection Plan
  • Equipment Design
  • Water TX Plan
  • Develop Capital Cost
  • Refine Economics Modeling
  • Install Capital
  • Train Operators
  • Contract Services
  • Purchase Chemical
  • Manage Chemical Inventory
  • Monitor Flood
  • Demulsify Oil and Water
  • Treat Water

Case References

ASP Formulation Design for Heavy Oil
Jieyuan Zhang, R. Ravikiran, David Freiberg, and Charles Thomas, SPE 153570, 2012

“Enhanced wettability alteration by surfactants with multiple hydrophilic moieties,”
Salehi, M., Johnson, S.J. & Liang, J.-T.: Journal of Surfactants and Detergents, 13 (3), 243-246, 2010

Development of High-Performance Surfactants for Difficult Oils
Ping Zhao, SPE, Adam C. Jackson, SPE, Chris Britton, Do Hoon Kim, Larry N. Britton, David B. Levitt, SPE, and Gary A. Pope, SPE, The University of Texas | SPE 113432-MSMechanisms of Enhanced Natural

Imbibition with Novel Chemicals
Jieyuan Zhang, Quoc Nguyen, Adam Flaaten, and Gary Pope, SPE 113453, 2008

Other Types of Surfactant Products

Imbibition/Wettability Alteration
Surfactants can be used in chemical EOR to change the wettability of the reservoir rock –in this approach, reservoir rock that is predominantly oil wet can be altered to become water wet, which releases the oil from the rock.

Insitu Foam
In this approach, which is suitable for immiscible gas injection projects such as nitrogen produced natural gas, steam, or CO2, surfactant solution in water is pumped into the reservoir followed by the immiscible gas injection. This causes formation of foam that blocks of high permeability zones and forces the nitrogen/CO2 to sweep the low permeability zones. This approach is called Surfactant Alternating Gas (SAG) and variations of this are also know - Foam alternating Gas (FAG) and Foam alternating water alternating Gas (FAWAG).

Foam for Mobility Control
In situations where polymer usage is not suitable, foam can also be used as a mobility control agent to replace polymer in chemical EOR projects. This would typically be considered in low permeability reservoirs or in offshore areas where polymers are considered to be environmentally unfriendly.