Enhanced Oil Recovery with ASP Flooding
Using alkali-surfactant-polymer (ASP) flooding to retrieve oil reserves in mature wells gets a boost.
A New ASP Preparation and Injection System
February 3, 2012
The debate of whether more onshore and offshore drilling for oil and gas within the U.S. should occur has become a political football game, with the respective sides unwilling to budge from their long-held positions.
Currently, vast reserves of conventional oil deposits are below our feet and have only been partially tapped. These deposits may have been discovered as many as 50 years ago, but their wells were capped when reduced recovery rates no longer made them cost-efficient.
Now, recent advances in oil production and oil recovery technology can make those old, supposedly played-out wells vibrant producers again. The challenge is finding and using the correct—and most cost-effective—technology to retrieve these previously hard-to-reach oil deposits.
This article identifies a new method of enhanced oil recovery (EOR) that relies on the injection of a chemical concoction consisting of alkalis, surfactants and polymers into the well to help the trapped oil rise to the surface.
The most difficult parts of oil production are locating the deposit and drilling the wells. When wells are first drilled, the product is flowing freely. This is known as primary recovery. During this time, as little as 10 percent of the reservoir’s oil makes its way up the well bore. After a few years, the natural pressure of the reservoir is no longer enough to produce oil.
In the past, significant deposits remain trapped underground, and the well was abandoned because of economic restraints on production. The company would then initiate secondary recovery. In this stage of production, water is injected into the reservoir where it displaces the oil, allowing it to flow to the well bore and up to the surface. This secondary recovery process can generally recover between 20 and 40 percent of a reservoir’s remaining oil.
This means that anywhere from 50 to 70 percent of the reservoir’s recoverable product is still underground. At this point, the oil producer has two options:
- Initiate one of many EOR operations (gas injection, chemical injection or thermal recovery)
- If the cost of EOR is too prohibitive, cap the well and move on to the next
For years, many wells were abandoned because the cost of EOR operations outweighed the return that would be realized on the recovered oil. However, that has changed in recent years for two reasons:
- The cost of oil has consistently crested the $100-per-barrel threshold
- Improvements in EOR technology have made it more economical and increased the ability to maximize a reservoir’s recovery rate.
One EOR technology that has proven effective in delivering a reservoir’s trapped oil to the well bore is chemical injection. In this type operation, a chemical cocktail is injected into the well where it interacts with the water that remains from the secondary recovery stage. The process frees the trapped oil, making it recoverable. Of chemical injection applications, one that is most successful—with many oilfields realizing a 20 percent increase in the return of original oil in place (OOIP)—is alkali-surfactant-polymer (ASP) flooding.
In the ASP process, an alkaline agent, usually either caustic soda (NaOH) or soda ash (Na2CO3); a low dose of surfactant (0.05 to 0.5 percent concentration); and a polymer, which increases the viscosity of the fluid and makes it more stable, are combined with softened water and injected into the well. This ASP combination helps achieve ultra-low interfacial tension between it and the trapped oil, which allows the alkali to penetrate deeply into the formation. This enables more of the trapped oil to interact with the ASP fluid, which, in turn, allows the release of more of it to flow to the well bore.
Two choices are available when considering polymers that can be used in the ASP-flooding process: dry polymers or liquid polymers. In most cases where large-scale recovery operations are in place, the better choice is dry polymers. This is true for a number of reasons:
- The volume of the chemical concoction used in ASP flooding is so high—the flow rates of ASP well injections can approach 400 gallons per minute—that a constant trainload supply of liquid polymer would be needed onsite.
- The massive amounts of polymer that are used exceed the viability and reliability of liquid-polymer equipment operation.
- Liquid polymer can be 2.5 times more expensive than dry polymer.
Having an ample supply of dry polymer on hand is half the equation. The other is being able to rely on a system that can adequately wet that dry polymer and then inject it into the ASP cocktail before it is pumped into the well bore. A new polymer preparation system is becoming an invaluable and reliable tool in an oilfield’s EOR operations.
A New ASP Preparation and Injection System
The new technology is ideal for EOR applications because it uses a negative pressure, blower-induced conveyance system to transport and disperse the dry polymer prior to the wetting process. Dispersing dry polymer prior so that it comes into contact with the dilution water ensures effective polymer-particle wetting. The result is reduced mix and hydration times higher polymer performance and lower chemical costs.