Release Date: February 03, 2015
DOE-Sponsored Project Tests Novel Method to Increase Oil Recovery
Successful laboratory tests at the Energy Department’s National Energy Technology Laboratory (NETL) have verified that the use of a brine-soluble ionic surfactant could improve the efficiency of carbon dioxide enhanced oil recovery (CO2-EOR).
Surfactants stabilize the formation of foams composed of high-pressure CO2 bubbles separated by thin films of surfactant-stabilized brine. The tiny foam bubbles allow the CO2 to function as an extremely thick fluid which an operator can use to effectively clog high-permeability, oil-depleted "thief" zones, in which fluids could be lost. Carbon dioxide injected after a foam is established will tend to flow into the oil-rich low-permeability layers, thereby increasing incremental oil production, decreasing CO2 used, and reducing associated recycling and re-compression costs.
The testing paves the way for the first field test in which a surfactant will be dissolved in both the brine and CO2 phase of a new EOR effort. This new process supports technologies being developed by the Office of Fossil Energy’s Natural Gas and Oil Program to increase oil recovery beyond current state-of-the-art techniques.
CO2-EOR facilitates the extraction of oil from reserves that would otherwise be too difficult or costly to retrieve. NETL’s research focuses on a process in which a commercial surfactant is dissolved in high-salinity brine. Researchers are also focusing on a novel process in which a surfactant is dissolved in the brine and a different surfactant is dissolved in the CO2.
High-pressure CO2 has been used for decades to enhance the recovery of oil, but historical data shows that various components may impede sweep efficiency, the effectiveness of an EOR process based on the volume of the reservoir contacted by the injected fluid. Poor sweep efficiency may be caused by the difference in how easily CO2 moves through the reservoir compared to the thickness of the oil. Another factor is poor conformance control—a lack of uniformity in the distribution of injected CO2—resulting from CO2 flowing through highly permeable thief zones that contain little recoverable oil.
NETL researchers took a rock core sample that was representative of a typical reservoir and used an apparatus that pushes fluid through the rock to conduct mobility testing for conformance control. The core sample contained various layers consisting of different degrees of permeability, including the high-permeability thief zones. When using an 80 percent quality foam (meaning that 80 volume percent of the foam is gas), a significant drop in pressure was observed, indicating that the CO2 foam was much thicker than pure CO2. In addition, CT imaging of simulated CO2-EOR experiments in Berea sandstone cores illustrated that injected CO2 preferentially flowed through high-permeability bedding planes in the absence of surfactant-in-brine foam. When the tests were repeated with diluted brine containing the surfactant, distinct plug-like flow was observed, signaling foam formation and the inhibition of preferential flow of CO2 into thief zones.
Prior to NETL’s laboratory testing, nearly all field tests involved foams that use surfactants dissolved only in the brine phase; however, NETL’s positive test results on the brine-soluble surfactant are expanding the applications. A CO2-EOR operator recently initiated a single-well pilot test that involves the injection of surfactant dissolved in brine alternating with pure CO2, followed by the continuous injection of CO2. Success in this pilot test will lead to the first field test in which surfactant would be dissolved in both the brine and the CO2 phase of an alternating brine-CO2 gas process. This first-of-its kind test will help prove the merit of this novel EOR approach.