An improved foam with the potential to increase oil production and CO₂ storage

A new formulation of CO₂ foams could help address one of the energy industry’s main challenges, specifically regarding the injection of CO₂ underground: controlling CO₂ mobility in reservoir porous media. This advancement has the potential to improve reservoir sweep, enhance oil recovery, and increase geological CO₂ retention. A recent study demonstrates that a polymer-reinforced CO₂ foam can multiply the flow resistance of CO₂, preventing it from moving inefficiently through the reservoir.

CO₂ injection is used in mature reservoirs to mobilize residual oil while allowing part of the gas to remain stored in geological formations, which potentially helps reduce anthropogenic emissions of this gas. However, this process faces a critical limitation. Due to its low density and high mobility, CO₂ can quickly migrate through areas of lower resistance, channel, or accumulate at the top of the reservoir. As a result, large areas may remain unswept, affecting both recovery efficiency and storage capacity.

To address this problem, researchers evaluated an improved variant of an existing technology: the use of foams to reduce gas mobility. Specifically, they analyzed an HPAM polymer-reinforced CO₂ foam—called CO₂ PEF—designed to increase the system’s stability and prolong its effect underground.

The study was conducted under laboratory conditions designed to replicate a real reservoir, with pressures of 90 bar and temperatures of 40 °C. The experiments included dynamic tests on sandstone cores of varying lengths, allowing researchers to observe the foam’s behavior as it moved through porous media.

The results were compelling. The polymer-reinforced foam exhibited significantly higher flow resistance than conventional foam. In some cases, the mobility reduction factor—a key measure for evaluating how effective flow control is—was up to seven times higher. The apparent viscosity of the system also increased significantly, indicating a greater ability to slow the advance of CO₂.

Another relevant finding was its persistent effect. Even after stopping the injection of chemicals and continuing with pure CO₂, flow resistance remained at high levels. This behavior suggests that the formulation not only acts during injection but also leaves a residual effect in the porous medium, prolonging mobility control without the need for continuous intervention.

Analysis of the long core also revealed a key phenomenon: the polymer foam generates greater resistance at the entry zones and slows its propagation inward. This behavior is consistent with polymer retention and the partial blocking of preferential channels, which could promote better redistribution of CO₂ within the reservoir. In practical terms, this effect improves oil displacement and reduces early gas channelling.

Although the results are promising, their application at field scale will depend on the specific conditions of each reservoir, such as salinity, temperature, heterogeneity, mineralogy, and injectivity. Furthermore, since the experiments did not include oil in the cores, the direct impact on the recovery factor must be evaluated in subsequent studies using oil-saturated cores. Even so, the study provides solid experimental evidence that polymer-reinforced foams can significantly outperform conventional formulations.

In a context where the industry is seeking solutions that combine energy efficiency and emissions reduction, this advancement could have significant implications. Improving CO₂ flow control not only optimizes hydrocarbon recovery but also increases the potential for safe underground gas storage, which is a key component of global climate change mitigation strategies.