One of the most in-demand energy resources in modern society is petroleum or crude oil. The crude oil can be displaced and produced by injecting water, gas, or chemicals into the reservoir. Carbon dioxide (CO2) flooding is a widely applied recovery technology for crude oil production, especially when the CO2 source is abundant, and the reservoir pressure is higher than the minimum miscible pressure of CO2 and crude oil. However, the low viscosity and low density of CO2 cause viscous fingering and gas override. In addition, the reservoir heterogeneity favors CO2 transport through the high permeability layer. Therefore, these characteristics lead to an early CO2 breakthrough and thus lower the sweep efficiency and oil recovery of CO2 flooding. In recent years, CO2 foam flooding has attracted wide attention and it can increase the apparent viscosity of CO2 by decreasing the relative permeability of CO2 in porous media. As such, the mobility of CO2 can be decreased and the swept volume of CO2 flooding is significantly increased, making CO2 foam a promising technique of enhanced oil recovery (EOR). However, most of the current CO2 foam flooding technologies cannot be used at high temperature (120°C) and high salinity (22% total dissolved solid) conditions. The convectional surfactant for CO2 foam flooding can either degrade under high temperature or precipitate under high salinity conditions. Therefore, developing formulations that can tolerate these harsh conditions is challenging for EOR purposes.
A review of related literature reveals that research delving on CO2 foam under high temperature and high salinity conditions and its related modeling and simulation studies are very limited. To bridge this gap, Rice University researchers: Dr. Guoqing Jian(lead author), Dr. Leilei Zhang, Maura Puerto, Professor Sibani Biswal and Professor George Hirasaki, in collaboration with Chang Da and Professor Keith Johnston from The University of Texas developed a novel diamine surfactant-based supercritical CO2 foam formulation which can be used for high temperature and ultra-high salinity carbonate reservoirs in the presence of crude oil. The fluid mechanics and simulation study show that the supercritical CO2 foam can recover almost all the oil that cannot be recovered by the conventional CO2 flooding process.
In their approach, Duomeen TTM, a new diamine cationic surfactant, was found effective to generate CO2 foam under harsh conditions. The foam can be generated in situ by both co-injection and surfactant alternating gas injection methods. Foam transport and propagation were characterized as a function of the foam quality, shear rate, permeability, surfactant concentration, and method of injection. The research team also reported oil recovery when utilizing TTM CO2 foam under miscible conditions in the presence of crude oil. Results show the CO2 foam can recovery the oil by higher than 97%. Finally, the scientists utilized the experimental results to obtain parameters for the STARS foam model by optimizing multiple variables related to the dry out, shear-thinning, and surfactant concentration effects. And their reservoir simulation study shows a significantly improved swept volume and oil recovery at large reservoir scale when using their technology. Their work is currently published in the research journal, Energy & Fuels. Their finding is significant as there are billions of barrels of oil left behind in the reservoirs in the United States after conventional CO2 flooding, and supercritical CO2 foam flooding can recovery those oil in place.
Dr. Guoqing Jian, the first author of this paper, says that the recovery of oil from high temperature and ultra-high salinity carbonate reservoirs is very difficult and challenging. Conventional chemical EOR methods such as polymer flooding or surfactant-polymer flooding don’t work well because polymer can degrade under high-temperature conditions and the adsorption of traditional surfactant is high or even precipitation. He said that the surfactant formulation they developed can generate supercritical CO2 foam in high-temperature rock pores in the subsurface reservoirs. Unlike traditional surfactants which will precipitate under ultra-high salinity condition, the surfactant formulation the authors developed can form viscoelastic fluids with high salinity and stabilize the foams. In addition, the CO2 foam they designed is a smart fluid. It is preferentially flow through the rock pores where oil is not recovered, and miscible with the oil thus recover it. Once the oil is recovered, it will automatically shut-off the pores with foam films and find oil in other pore spaces. This process keeps iterating until almost all the oil in the reservoir is recovered. The key is the novel diamine surfactant formulation they developed.
In summary, the study presented a novel amine-based surfactant for supercritical CO2 foam flooding in carbonate rock at high temperature (120 °C), high salinity (22% total dissolved solids), and CO2-oil miscible conditions. The foam can be situ generated in the rock pores with very small pressure gradient required. In addition, the formulations the authors developed can be switched to highly protonated cationic surfactant in the presence of CO2 and brine. Thus, the adsorption of this surfactant on the positive carbonate rock is very low.
Generally, the work demonstrated high efficiency of enhanced oil recovery by utilizing a diamine surfactant stabilized supercritical CO2 foam under harsh reservoir conditions. In a statement to Advances in Engineering, Dr. Guoqing Jian, the first author explained their results highlighted the high potential of utilizing diamine-based surfactant for CO2 foam EOR for application in high-temperature and ultra-high salinity carbonate reservoirs.
Guoqing Jian, Leilei Zhang, Chang Da, Maura Puerto, Keith P. Johnston, Sibani L. Biswal, George J. Hirasaki. Evaluating the Transport Behavior of CO2 Foam in the Presence of Crude Oil under High-Temperature and High-Salinity Conditions for Carbonate Reservoirs. Energy Fuels 2019, volume 33, page 6038−6047.