The efficiency of CO 2 injection for enhanced oil recovery and carbon storage is limited by severe viscosity and density differences between CO 2 and reservoir fluids and reservoir heterogeneity. In-situ generation of CO 2 foam can improve the mobility ratio to increase oil displacement and CO 2 storage capacity in geological formations. The aim of this work was to investigate the ability of CO 2 foam to increase oil production and associated CO 2 storage potential, compared to other CO 2 injection methods, in experiments that deploy field-scale injection strategies. Additionally, the effect of oil on CO 2 foam generation and stability was investigated. Three different injection strategies were implemented in the CO 2 enhanced oil recovery and associated CO 2 storage experiments: pure CO 2 injection, water-alternating-gas and surfactant-alternating-gas. Foam generation during surfactantalternating-gas experiments showed reduced CO 2 mobility compared to water-alternatinggas and pure CO 2 injections indicated by the increase in apparent viscosity. CO 2 foam increased oil recovery by 50% compared to pure CO 2 injection and 25% compared to water-alternating-gas. In addition, CO 2 storage capacity increased from 12% during pure CO 2 injection up to 70% during surfactant-alternating-gas injections. Experiments performed at high oil saturations revealed a delay in foam generation until a critical oil saturation of 30% was reached. Oil/water emulsions in addition to CO 2 foam generation contributed to CO 2 mobility reduction resulting in increased CO 2 storage capacity with foam.

CO2 foam is an effective method to reduce CO2 mobility and improve displacement efficiency in CO2 enhanced oil recovery (EOR) and CO2 storage applications. Foam strength and stability are key parameters that influence the efficiency of the foam which depend on several factors including the presence of oil, injection velocity and rock type. The aim of this work was to evaluate the effect of rock type on CO2 foam strength and stability by conducting corefloods with sandstone and carbonate rocks at reservoir conditions. The effect of injection velocity and the presence of residual oil on the foam generation and displacement efficiency was also investigated. Steady-state CO2 injections revealed differences in foam generation, strength and stability in sandstone compared to carbonate based on the calculated apparent viscosities. Results showed that the strongest foam was generated in sandstone compared to carbonates because of higher absolute permeability. Drainage-like co-injections with increasing gas fraction showed the relation between rock permeability and the limiting capillary pressure and co-injection at different injection velocities revealed shear-thinning foam rheology in both rock types. Despite stronger foam generation in sandstone, unsteady-state CO2 injections showed similar oil displacement efficiency in both rock types. CO2 foam increased oil recovery by 200% in both rocks compared to CO2 injection without foam. In addition, foam showed a significant impact on water displacement compared to pure CO2 injection which is advantageous for CO2 storage applications. Water recovery during CO2 EOR was 60% in sandstone and 88% in limestone. Dissolution of calcite was observed in limestone, which increased pore space and the CO2 storage capacity. Overall, the results indicate that CO2 foam generation, stability and coalescence are sensitive to rock permeability and pore geometry in the conducted experiments.

This work presents a multiscale experimental and numerical investigation of CO2 foam generation, strength, and propagation during alternating injection of surfactant solution and CO2 at reservoir conditions. Evaluations were conducted at the core-scale and with a field-scale radial simulation model representing a CO2 foam field pilot injection well. The objective of the experimental work was to evaluate foam generation, strength, and propagation during unsteady-state surfactant-alternating-gas (SAG) injection. The SAG injection rapidly generated foam based upon the increased apparent viscosity compared to an identical water-alternating-gas (WAG) injection, without surfactant. The apparent foam viscosity of the SAG continually increased with each subsequent cycle, indicating continued foam generation and propagation into the core. The maximum apparent viscosity of the SAG was 146 cP, whereas the maximum apparent viscosity of the WAG was 2.4 cP. The laboratory methodology captured transient CO2 foam flow which sheds light on field-scale CO2 foam flow. The single-injection well radial reservoir simulation model investigated foam generation, strength, and propagation during a recently completed field pilot. The objective was to tune the model to match the observed bottom hole pressure data from the foam pilot and evaluate foam propagation distance. A reasonable match was achieved by reducing the reference mobility reduction factor parameter of the foam model. This suggested that the foam generated during the pilot was not as strong as observed in the laboratory, but it has propagated approximately 400 ft from the injection well, more than halfway to the nearest producer, at the end of pilot injection.