Modifying reservoir surface wetting properties is an appealing topic to the upstream oil and gas industry for enhancing hydrocarbon recovery as the shifting of reservoir rock surface wetting from oil-wet to water-wet has enhanced the oil recovery by as much as 70–80%. In the last few decades, research has been conducted on core flooding experiments to reveal wettability alteration mechanisms associated with macroscopic fluid flow in reservoirs. In recent years, the microscopic wetting state and fluid distribution behavior have been studied using micromodel experimental techniques to promote the fundamental mechanisms of wettability alteration. To provide the concurrent knowledge and technology development, this comprehensive review focuses on micromodel investigations for wettability alteration in chemical-enhanced oil recovery using surfactants and/or nanofluids that reveal microscopic behaviors on the wetting state, fluid distribution, and their associated mechanisms. This comprehensive review focuses on micromodel investigations for wettability alteration in chemical-enhanced oil recovery using surfactants and/or nanofluids that reveal microscopic behaviors on the wetting state, fluid distribution, and their associated mechanisms. Wettability characteristics and measurement techniques are thoroughly assessed to understand the critical role of wettability for enhanced oil recovery. With the microfluidic-based studies, the effect of relative permeability along with the pore network and wetting order on oil recovery have been discussed. Later on, the new development in phase diagram related to viscus fingering and capillary fingering regime have been reviewed via various micromodels. Then, the wettability alteration mechanisms and governing parameters by surfactant and nanoparticles are summarized. Additionally, recent micromodel experiments on surfactants and nanofluid-assisted enhanced oil recovery are reviewed and listed, along with their fabrication methods.

A significant challenge to hydraulic fracturing is premature particle settling and uneven particle distribution in a formation during injection. Even though various research work were conducted on particle transport, gaps still exist in the fundamental proppant–proppant interaction mechanisms. This study utilizes an experimental approach to understand proppant interactions during gravitational settling in various test conditions. High-speed imaging coupled with particle image velocimetry (PIV) was implemented to provide a space and time-resolved investigation of multi-proppant interactions. The multi-perspective experimental study uncovered the coupled effect of viscosity and multi-particle mix ratio on slurry velocity. The PIV analysis highlights unique agglomeration and particle interactive patterns. The results indicate that the mix ratio has a significant effect on proppant interactive behavior and settling characteristics, especially as the solution viscosity increases. This conclusion was drawn from observing no signs of agglomeration in the low viscosity regime, although slight differences in proppant interactions were noted as the mix ratios were altered. On the other hand, the intermediate regime demonstrates formed agglomerates with unique patterns for different viscosity and mix ratios. The observed patterns were quantified using both velocity and proppant concentration analysis. Finally, the results indicate the existence of a reduced velocity condition at a given viscosity and particle mix ratio.

With increasing energy demands and depleting oil accessibility in reservoirs, the investigation of more effective enhanced oil recovery (EOR) methods for deep and tight reservoirs is imminent. This study investigates a novel hybrid EOR method, a synergistic approach of nonionic surfactant flooding with intermediate CO₂-based oil swelling. This study is focused on the efficiency of surfactant flooding and low-pressure oil swelling in oil recovery. We conducted a fluorescence-based microscopic analysis in a microchannel to explore the effect of sodium dodecyl sulfate (SDS) surfactant on CO₂ diffusion in Texas crude oil. Based on the change in emission intensity of oil, the results revealed that SDS enhanced CO₂ diffusion at low pressure in oil, primarily due to SDS aggregation and reduced interfacial tension at the CO₂ gas–oil interface. To validate the feasibility of our proposed EOR method, we adopted a ‘reservoir-on-a-chip’ approach, incorporating flooding tests in a polymethylmethacrylate (PMMA)-based micromodel. We estimated the cumulative oil recovery by comparing the results of two-stage surfactant flooding with intermediate CO₂ swelling at different pressures. This novel hybrid approach test consisted of a three-stage sequence: an initial flooding stage, followed by intermediate CO₂ swelling, and a second flooding stage. The results revealed an increase in cumulative oil recovery by nearly 10% upon a 2% (w/v) solution of SDS and water flooding compared to just water flooding. The results showed the visual phenomenon of oil imbibition during the surfactant flooding process. This innovative approach holds immense potential for future EOR processes, characterized by its unique combination of surfactant flooding and CO₂ swelling, yielding higher oil recovery.

Carbon capture and storage (CCS) technologies are employed to mitigate global warming by removing carbon from the atmosphere. To enhance carbon capture efficiency, nanoparticles have gained considerable attention as catalysts due to their large surface area, tunable properties, regeneration, and enhanced reactivity. However, it poses some challenges, such as nanoparticle aggregation and reduced effectiveness in sustainable solvents like seawater. To address these limitations and promote an environmentally sustainable method for carbon capture, this study evaluates the CO₂ capture efficiency of seawater using nickel nanoparticles (NiNPs) coated with polyvinylpyrrolidone (PVP) as a catalyst. We examined the time-dependent size variations of CO₂ bubbles in a flow-focusing microchannel using high-speed bubble-based microfluidics, directly associated with transitory CO₂ dissolution into the surrounding solution. We hypothesized that smaller polymer-coated NiNPs, due to their higher surface-to-volume ratio, can enhance CO₂ solubility and capture rates under identical environmental conditions. To verify this, polymer-coated NiNPs of three different sizes—5 nm, 10 nm, and 20 nm—were synthesized and tested. The experiments revealed that 5 nm NiNPs achieved a CO₂ dissolution rate of 77%, in contrast to 71% for 10 nm and 43% for 20 nm particles. These findings validate the hypothesis, demonstrating that smaller nanoparticles facilitate more effective CO₂ capture using equivalent material quantities, thereby potentially improving the overall efficiency of CO₂ reduction. This innovative approach contributes to advancing NiNP-based catalysts for saltwater-based CO₂ capture.

As the consumption of fossil fuel resources has continuously increased to meet global fuel demands for power generation, atmospheric emissions of greenhouse gases, particularly carbon dioxide (CO~2~), have rapidly increased over the last century. Increased CO~2~ emissions have caused serious international concerns about global warming, sea-level rise, and ocean acidification.