Surfactant-stabilized CO₂ foam is a promising technology to reduce CO₂ mobility in geologic CO₂ storage and CO₂ enhanced oil recovery processes. In this study, various combinations of a non-ionic surfactant, Alkyl polyglycoside, along with cationic surfactants were ingeniously examined to enhance carbon storage and facilitate oil recovery through CO₂-based foam flooding. Specifically, for the first time, the investigation focused on the impact of altering the alkyl chain length and counter-ion type of the cationic surfactants. The surfactant combinations were first screened based on surfactant characterization, surface and interfacial tension studies and bulk foam experiments. The interfacial tension studies showed that, in combination with Alkyl polyglycosides, the C₁₆ (cetyltrimethylammonium bromide and cetyltrimethylammonium chloride) alkyl chain length cationic surfactants exhibited less interfacial tension values than the C₁₂ (dodecyltrimethylammonium bromide and dodecyltrimethylammonium chloride) alkyl chain length cationic surfactant. The bulk foam experiments established that Alkyl polyglycosides/C₁₆ combination showed higher foamability and foam stability than Alkyl polyglycosides/C₁₂ combination. The bulk foam investigation showed that the optimized concentration of Alkyl polyglycosides/cationic-surfactant was 0.3/0.15 wt%. The surfactant combinations screened from these studies were evaluated for EOR coreflooding experiments at 1250 psi and 60 ℃. The incremental oil recovery obtained for baseline CO₂ and Alkyl polyglycosides/cetyltrimethylammonium bromide foam flooding was 18.5% and 32.7%, respectively. The estimated carbon storage potential for baseline CO₂ g and Alkyl polyglycosides/cetyltrimethylammonium bromide foam flooding was 11.9% and 23.7%, respectively. The combination of Alkyl polyglycosides cetyltrimethylammonium bromide surfactant was demonstrated as an effective solution for increased oil recovery and carbon storage.

The efficiency of CO₂ injection for enhanced oil recovery and carbon storage is limited by severe viscosity and density differences between CO₂ and reservoir fluids and reservoir heterogeneity. In-situ generation of CO₂ foam can improve the mobility ratio to increase oil displacement and CO₂ storage capacity in geological formations. The aim of this work was to investigate the ability of CO₂ foam to increase oil production and associated CO₂ storage potential, compared to other CO₂ injection methods, in experiments that deploy field-scale injection strategies. Additionally, the effect of oil on CO₂ foam generation and stability was investigated. Three different injection strategies were implemented in the CO₂ enhanced oil recovery and associated CO₂ storage experiments: pure CO₂ injection, water-alternating-gas and surfactant-alternating-gas. Foam generation during surfactant-alternating-gas experiments showed reduced CO₂ mobility compared to water-alternating-gas and pure CO₂ injections indicated by the increase in apparent viscosity. CO₂ foam increased oil recovery by 50% compared to pure CO₂ injection and 25% compared to water-alternating-gas. In addition, CO₂ storage capacity increased from 12% during pure CO₂ 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 CO₂ foam generation contributed to CO₂ mobility reduction resulting in increased CO₂ storage capacity with foam.