Foam-enhanced oil recovery (EOR) is poised to become one of the most promising tertiary recovery techniques to keep up with the continuously increasing global energy demands. Due to their low sensitivity to gravity and permeability heterogeneities that improve sweep efficiency, foams are the preferred injection fluids over water or gas. Although foam injection has been used in the field to improve oil recovery and control gas mobility, its success is still hindered by several conceptual and operational challenges with regard to its stability and foamability under reservoir conditions. This can be attributed to the insufficient attention given to the mechanisms underlying foam generation and stability at the microscopic level in many studies. For a deeper understanding, this study reviews the most pertinent published works on foam-EOR. The major objective is to provide a broad basis for subsequent laboratory and field applications of foam-EOR. In this work, we highlighted foam classification and characterization, as well as the crucial factors impacting foam formation, stability, and oil recovery. Additionally, the principal mechanisms of foam generation are thoroughly explained. Finally, the most recent developments in foam generation and stability improvement are discussed. Foam-EOR is comprehensively reviewed in this work, with an emphasis on both theoretical and practical applications.

By trapping CO₂ and storing it in matured and depleted geological formations, atmospheric CO₂ release can be reduced. Carbon capture and storage on a large scale can help to stabilize atmospheric greenhouse gas emissions. This can be achieved by using anthropogenic CO₂ for enhanced oil recovery (EOR), which encourages advances in secure CO₂ storage while enhancing the oil production process. This interaction is expected to hasten the development of CO₂ storage technology and lower emissions from oil producing operations. Reducing CO₂ mobility in the reservoir is crucial to achieving this goal as effectively as possible, and in situ foam generation offers a viable solution. It has been shown that implementing a blend of CO₂ and foaming solution considerably reduces CO₂ mobility and front propagation. Although there have been a few reviews of carbon capture, utilization, and storage (CCUS), none of these have concentrated on the role of foam EOR in achieving carbon neutrality. Therefore, in this brief review, methods for achieving carbon neutrality with foam EOR are comprehensively reviewed. In order to store CO₂, the utilisation of atmospheric CO₂ to generate foam is the main topic of this review. This approach can boost financial incentives for the energy sector, help to lower carbon emissions, and make it possible to produce oil from depleted reservoirs in a more sustainable way. Thus, identifying and examining the governing mechanisms that affect CO₂ storage during foam flooding as well as reviewing the various techniques for estimating CO₂ storage under actual reservoir circumstances are among the goals of this work.

Effective production of oil from carbonate reservoirs often requires the application of improved oil recovery technologies such as waterflooding. However, conventional waterflooding in carbonates usually results in low hydrocarbon recovery as most of these formations exhibit a complex pore throats structure and are mostly oil-wet. Therefore, improved insight into the causes of hydrophobic wetting behavior of such reservoirs is important for understanding the fluid distribution, displacement and enhancing recovery processes. The characterization of fluid-rock interactions is, however, challenging with existing laboratory methods, which are typically based on macroscale (mm) observations. In this experimental study, an advanced imaging technique, namely environmental scanning electron microscope, was applied for the comprehensive investigation of microscale (µm) wettability variations in carbonate rocks covered with organic layers. For the first time, the presence of organic layers on the sample was proved using energy dispersive X-ray mapping. Furthermore, the chemical bond of this layer and carbonate rock surfaces was determined using the transmission electron microscopy and electron energy-loss spectroscopy. The thickness of layer was estimated by using image processing software. These findings show that the application of combined microscopic techniques reveals important details about the reason of hydrophobic wetting properties of real carbonate rocks.

Carbonate hydrocarbon reservoirs are considered as potential candidates for chemically enhanced oil recovery and for CO₂ geological storage. However, investigation of one main controlling parameter—wettability—is usually performed by conventional integral methods at the core-scale. Moreover, literature reports show that wettability distribution may vary at the micro-scale due to the chemical heterogeneity of the reservoir and residing fluids. These differences may profoundly affect the derivation of other reservoir parameters such as relative permeability and capillary pressure, thus rendering subsequent simulations inaccurate. Here we developed an innovative approach by comparing the wettability distribution on carbonates at micro and macro-scale by combining live-imaging of controlled condensation experiments and X-ray mapping with sessile drop technique. The wettability was quantified by measuring the differences in contact angles before and after aging in palmitic, stearic and naphthenic acids. Furthermore, the influence of organic acids on wettability was examined at micro-scale, which revealed wetting heterogeneity of the surface (i.e., mixed wettability), while corresponding macro-scale measurements indicated hydrophobic wetting properties. The thickness of the adsorbed acid layer was determined, and it was correlated with the wetting properties. These findings bring into question the applicability of macro-scale data in reservoir modeling for enhanced oil recovery and geological storage of greenhouse gases.

This review discusses the theoretical basis and examples of implementation of various molecular modeling approaches to the investigation of the properties of surfactants. These surfactant properties include the ability to reduce the interfacial tension and alter the wettability and viscosity of solutions for the purposes of chemical flooding of crude oil reservoirs. A comparative analysis of the advantages and disadvantages of the existing molecular dynamics simulation methods is further provided. It is shown that molecular modeling methods can significantly facilitate the choice of surfactants for specific oil field conditions and can serve as a potential alternative to experimental measurements.