In oil production, CO2 flooding is widely applied for oilfield development. CO2 flooding involves the injection of carbon dioxide into an oil reservoir with the goal being to increase output when extracting oil; especially in reservoirs that have higher pressure than the minimum miscible pressure for the CO2 and crude oil. However, the intrinsic properties of low viscosity and low density in CO2 can lead to viscous fingering and gas override when comparing it with other reservoir fluids. In addition, reservoir heterogeneity especially for high-permeability layers or thief zones favors CO2 transport for making the CO2 flooding less efficient. These CO2 characteristics lead to a low sweep efficiency that results in poor oil recovery from miscible flooding.
To address this issue, CO2 foam technology has been reported as an effective mobility control method owing to the fact that foam can decrease the CO2 relative permeability in porous media and thus reduces its mobility. As such, CO2 foam has become a promising technique for fluid-mobility control and also enhancing oil recovery in the miscible CO2 flooding process. The success of CO2-foam flooding relies on the choice of surfactant formulation for a specific reservoir and on a comprehensive understanding of the transport phenomenon of CO2-foam in porous media. An idea surfactant is such that with low adsorption, the decent foaming ability for surfactant alternating gas injections and also no formation of viscous emulsions after contact of oil. It is not easy to develop such a surfactant formulation, you need to consider all these aspects from injection to production and even the downstream processing of produced oil; the researcher Dr. Guoqing Jian says.
A review of noteworthy literature reveals nonionic surfactants are potential candidates of low adsorption for low-temperature reservoirs. Unfortunately, the research of nonionic surfactants for CO2 mobility control in carbonate reservoirs is very limited, especially for a pilot scale test. To bridge this gap, Rice University researchers Dr. Guoqing Jian, Dr. Leilei Zhang, Maura C. Puerto, Dr. Samaneh Soroush, Dr. Sibani Lisa Biswal, and Dr. George J. Hirasaki, in collaboration with Dr. Zachary Alcorn and Dr. Arne Graue from the University of Bergen, developed a strategy of using ethoxylated nonionic surfactant for CO2-foam mobility control under the East Seminole reservoir conditions. Their goal was to deliver a surfactant formulation and the injection strategies acceptable for a field pilot test in the East Seminole oil field in West Texas. Their work is currently published in the research journal, SPE Journal, which is a well-known leading journal for petroleum engineers.
Dr. Guoqing Jian, the first author of this paper, found that an ethoxylated nonionic surfactant with 22 -EO- groups shows ultra-low adsorption on carbonate but very good foaming ability in porous media. They called this surfactant as L24-22. And it is cheap for large-scale production which makes it an ideal candidate for a real foam pilot test. They got funded by the Norwegian Research Council CLIMIT program to do comprehensive research on CO2 foam using this surfactant and deliver this technology to a pilot test. In their approach, they focused on developing strategies for addressing the problem of scaling, surfactant degradation control, and injection scheme design. They also developed foam fluid models for this specific project which can be incorporated into large reservoir simulators.
To this end, the author studied the behavior of dense CO2-foam in the presence and the absence of East Seminole crude oil using a high-pressure windowed cell under reservoir conditions of pressure and temperature. The foam transport behavior in limestone cores in the absence and presence of crude oil was also investigated, and the experimental data were fitted by the STARS foam model to obtain foam parameters. The test results revealed that strong CO2-foam forms in either a bulk-foam test or foam-flow test. More so, an oxygen scavenger, carbohydrazide, was found effective for controlling the long-term stability of the surfactant. In addition, a cost-effective phosphonate scale inhibitor was investigated and is capable of solving the scaling issue in the gypsum-oversaturated reservoir brine.
In summary, the study presented a comprehensive laboratory investigation of a novel nonionic surfactant for CO2 foam mobility control pilot test in the East Seminole field, a heterogeneous carbonate reservoir in the Permian Basin of west Texas. CO2 foam using L24-22 surfactant shows excellent mobility control in the presence of crude oil in rocks. This technology can also be used for other oil fields with similar reservoir conditions. In a statement to Advances in Engineering, Dr. Guoqing Jian, the first author of the study explained their studies will significantly enable the advances of the CO2 foam technology for large scale field applications including surfactant formulation development, foam flow tests, emulsion analysis, pilot facility design, and foam flow modeling, etc. This is a benchmark study of how to design a foam technology by considering all these factors governing the success for a pilot test.
Guoqing Jian, Zachary Alcorn, Leilei Zhang, Maura C. Puerto, Samaneh Soroush, Arne Graue, Sibani Lisa Biswal, George J. Hirasaki. Evaluation of a Nonionic Surfactant Foam for CO2 Mobility Control in a Heterogeneous Carbonate Reservoir. SPE Journal; volume 25 (06): page 3481–3493.