Products
ASP/SP
Alkaline Surfactant Polymer / Surfactant Polymer Technologies

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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 or Surfactant Polymer Flooding. All components are injected together into the reservoir as an ASP “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 reacts with the acidic moieties that exist in the oil creating natural soap and also helps with reducing the adsorption of the surfactant on the rock. Surfactant component helps in releasing the oil from the rock and reducing the interfacial tension between water and oil, while the polymer (typically, partially hydrolyzed polyacrylamide or HPAM) acts as the viscosity modifier and helps mobilize the oil. Typically, a (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.

The diagram (from: NETL) depicts a surfactant flooding process in a 5-spot well pattern. In an ideal situation, the ASP slug creates an oil bank as it moves through the reservoir.

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

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

Field Screening & Identification

Develop EOR Chemicals

Flood Design

Implement Flood

Oil Recovery

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/water Treat water

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)