The review’s central argument is that the success or failure of CO2 flooding projects is decided at scales far smaller than any drilling engineer can see. When CO2 dissolves into crude oil, it weakens the van der Waals forces between hydrocarbon molecules, causing the oil to swell and its viscosity to plummet. In one set of high-pressure experiments on North China Oilfield crude at 108 degrees Celsius, CO2 dissolution expanded the oil volume by 45 percent while cutting viscosity by 64.2 percent and density by 16.4 percent. Molecular dynamics simulations explain why: small CO2 molecules wedge themselves between large hydrocarbon chains, replacing strong hydrocarbon–hydrocarbon attractions with weaker hydrocarbon–CO2 interactions, widening molecular spacing and lowering internal friction. The result is a fluid that flows far more readily through the tortuous pore throats of a reservoir.

That viscosity reduction is only part of the story. Under supercritical conditions—above roughly 31 degrees Celsius and 7.4 megapascals—CO2 behaves like a dense liquid with the diffusivity of a gas, allowing it to selectively extract light and intermediate hydrocarbon components from crude oil. Laboratory studies report that at 20 megapascals, supercritical CO2 can strip more than 60 percent of light components below C20 from the oil phase, sharply lowering interfacial tension and pushing the system toward miscibility, the condition in which gas and oil blend into a single phase and capillary resistance essentially vanishes. Achieving miscibility depends on the minimum miscibility pressure, a threshold the review identifies as a critical design parameter. Researchers have found they can lower that threshold using CO2-soluble polymers with oxygen-containing functional groups, which reduced it by 10 to 19.4 percent in recent experiments, and even by applying a direct-current electric field that converts heavy oil components into lighter ones and cut the miscibility pressure from 22.5 to 21.6 megapascals in one tight-sandstone study.

In shale reservoirs, where much of the oil is adsorbed onto organic kerogen and clay surfaces rather than sitting freely in pores, competition becomes the dominant mechanism. CO2 molecules, with their smaller diameter and stronger adsorption affinity for kerogen, preferentially occupy the wall sites and displace adsorbed hydrocarbons into the mobile phase. Simulation work shows the kerogen–CO2 interaction energy exceeds the kerogen–hydrocarbon interaction, driving a spontaneous molecular swap that liberates trapped oil while simultaneously sequestering CO2 in the adsorbed state—a rare example of a single process delivering both enhanced production and permanent storage. The advantage is conditional, however: molecular studies reveal that competitive adsorption intensifies at particular pore sizes, peaking near one nanometer, and that adsorption strength varies with temperature, peaking around 393 kelvin, before declining.

The review also devotes extensive attention to the aqueous phase, which acts as both a helper and a saboteur. CO2 dissolved in formation water forms weak carbonic acid, and simulations of blind-ended nanopores show the gas must first diffuse into the water film coating the rock, disrupt its hydrogen-bonded network, and rupture it before it can reach and mobilize oil trapped in dead-end pores. In one molecular dynamics study, water-film rupture occurred within a window of just a few picoseconds once CO2 intrusion began, opening a continuous mass-transfer pathway. Meanwhile, the water phase performs a valuable stabilizing role at the reservoir scale: by occupying pore throats and generating the Jamin effect—the blocking of flow channels by trapped droplets—it suppresses the gas channeling that otherwise lets injected CO2 bypass large volumes of oil. Water-alternating-gas injection schemes, in which slugs of water and CO2 are cycled, consistently outperform continuous gas injection in flow control and total recovery.

Yet the same water film can be an obstacle. Molecular simulations of a CO2–water film–oil–rock system found that a continuous one-nanometer-thick water film compressed crude oil molecules toward the pore center, raising the equivalent oil density by 86.9 percent and cutting its diffusion coefficient to 72.3 percent of its no-film value. The reviewers note that the field still lacks a unified quantitative criterion for when a water film shifts from barrier to conduit, and they flag high-salinity brines as an untested complication, since most simulations use idealized pure water.

The third pillar of the analysis concerns the rock itself. Carbonic acid reacts with reservoir minerals through dissolution, precipitation, and ion exchange, dynamically reshaping the pore network. Feldspars and carbonate cements dissolve preferentially, enlarging pores and throats and, in tight sandstones, raising porosity and permeability by roughly 3.2 and 9.9 percent respectively when injection pressure climbed from 15 to 25 megapascals. At Iceland’s CarbFix basalt project, field monitoring confirmed that more than 95 percent of injected CO2 was mineralized into solid carbonate within two years, demonstrating the potential for near-permanent sequestration in reactive rock types. But the review is candid about the risks: after sixty days of exposure to CO2-saturated brine, limestone lost 79.3 percent of its uniaxial compressive strength, a finding with serious implications for caprock integrity, while migrating kaolinite and other secondary clays can clog pore throats and reverse the permeability gains achieved by dissolution.

Wettability—the preference of a rock surface to be in contact with either oil or water—emerges as another linchpin. Nanoscale treatments with carbon nanodots shifted an oil-wet carbonate surface from a 122-degree contact angle to a weakly water-wet 86 degrees, and the resulting hydrophilic pore network generated capillary pressures that act as microscopic carbon seals, opposing CO2 migration as formation pressure declines. The reviewers argue that such hydrophilic conditions, if reliably engineered, could be the key to long-term storage security, though they caution that capillary trapping works against recovery during injection and for containment during storage—a duality that field designers must manage.

What ultimately distinguishes this review is its refusal to treat the three subsystems in isolation. The authors present an integrated conceptual framework tracing how CO2 front migration couples CO2–oil swelling and extraction, CO2–water acidification and film rupture, and CO2–rock mineral alteration across space and time. Their diagnosis of the field’s remaining gaps is blunt: most studies examine single mechanisms under idealized conditions, the transition conditions between competing effects are unknown, and no rigorous quantitative mapping exists from nanoscale mechanisms to macroscopic indicators such as recovery factor, gas-channeling risk, and sequestration stability. Heavy-component readsorption during depressurization, asphaltene precipitation triggered by light-component extraction, and clay-driven permeability damage in high-clay reservoirs all remain poorly predicted.

The proposed path forward is fourfold: quantifying the coupling among dissolution, extraction, adsorption, and mass transfer; building full-cycle dynamic models grounded in real reservoir temperatures, pressures, and salinities; establishing critical conditions for the dissolution–precipitation competition in multi-mineral rocks; and constructing cross-scale correlation models that link molecular behavior to field performance. For an industry and a climate agenda both betting heavily on carbon capture, utilization, and storage, the message is clear: the technology’s future will be won or lost not in the injection wellhead but in the picoseconds of molecular exchange and the microns of mineral dissolution unfolding deep in the reservoir. Making those invisible processes predictable, the authors conclude, is the core scientific foundation for scaling CCUS from pilot projects to planetary impact.

Subject of Research: Microscopic oil-water-rock interaction mechanisms during CO2 enhanced oil recovery and geological carbon storage

Article Title: Microscopic mechanisms of oil-water-rock interactions during CO2 enhanced oil recovery and storage: a comprehensive review

Article References: Qiao, Y., Han, Y., Deng, B., Kong, Y., Ma, H., & Fang, R. (2026). Microscopic mechanisms of oil-water-rock interactions during CO2 enhanced oil recovery and storage: a comprehensive review. Journal of Saudi Chemical Society, 30(5), Article 69. https://doi.org/10.1007/s44442-026-00124-3

Image Credits: AI Generated

DOI: 10.1007/s44442-026-00124-3

Keywords: CO2 enhanced oil recovery, carbon capture utilization and storage, CCUS, oil-water-rock interactions, molecular dynamics simulation, minimum miscibility pressure, wettability alteration, mineral dissolution, carbon sequestration, nanopore mass transfer, water-alternating-gas injection, geological storage

The research is spearheaded by prominent scientists Bing Wei and Valeriy Kadet, whose innovative approach integrates advanced software tools such as CMG-GEM to generate a robust reservoir model. This model incorporates a multitude of critical factors, including CO2 solubility, molecular diffusion, geochemical reactions, and the sensitivity of rock to stress. By calibrating the model with empirical data, the researchers have ensured that the predictions made are not just theoretical but represent real-world scenarios. This meticulous approach highlights the researchers’ commitment to creating practical solutions for enhancing oil recovery while minimizing environmental impact.

Cyclic CO2 injection is a technique designed to optimize CO2 utilization and decomposition within the reservoir environment. This process entails alternating between CO2 injection and production cycles, allowing for the dynamic interaction between CO2, crude oil, and geological structures. The uniqueness of this study lies in its comparative analysis of two distinct scenarios: the first being the exclusive consideration of CO2-crude oil interactions, and the second encompassing all mechanisms of CO2 storage. Through this comparative lens, the researchers were able to identify the effects of CO2 storage on oil recovery.

The experimental results are noteworthy, revealing that after ten cycles of CO2 injection, the optimized process yielded a 3.4% increase in oil recovery relative to the original oil in place (OOIP). This statistic highlights the potential efficacy of CO2-EOR methodologies in tight reservoirs. Furthermore, it was found that almost half of the injected CO2—approximately 48.3%—was sequestered underground, demonstrating a dual benefit of oil recovery and carbon storage.

However, the study also uncovers an intriguing trade-off. While CO2 storage improves overall carbon retention, it simultaneously impacts CO2-oil interactions. The researchers quantified this phenomenon, noting a 25.9% reduction in the CO2-oil mixing zone and a corresponding 2.2% decline in cumulative oil production. This observation indicates that while the goals of carbon storage are being met, a careful equilibrium must be maintained to ensure optimal oil recovery is not sacrificed in the process.

A deeper analysis of CO2 migration and transformation further enriches this study. It sheds light on the various forms in which CO2 can be stored—ranging from dissolved CO2 in oil and water to mineralized carbonates. The unique cyclical nature of the injection process significantly alters these storage forms. For instance, researchers identified that dissolved CO2 in the oil accounted for more than fifty percent of total CO2 retention; however, this also poses a risk of CO2 being released back during the production phase, which could undermine the very goals the study aims to achieve.

Another critical aspect examined in this research pertains to the geochemical reactions and changes in porosity and permeability of the reservoir following CO2 injection cycles. The results indicated that mineral dissolution and precipitation had profound effects on reservoir characteristics. In the ten cycles analyzed, porosity slightly diminished—0.86% in non-fractured zones and 0.81% in fractured areas—while permeability likewise showed modest reductions of 2.51% and 2.39%. Such changes could have significant implications for future CO2-EOR endeavors, highlighting the need for comprehensive long-term studies in various geologic settings.

Despite the promising findings, the researchers acknowledge limitations in their study, indicating that certain elements, such as the simplification of the geomechanical module and the uncertainty surrounding the reactive surface area (RSA) parameters, warrant further investigation. Such reflections emphasize the nuanced nature of geological processes and the complexity involved in optimizing CCUS methodologies.

This groundbreaking research, titled “CO2 Utilization and Geological Storage in Unconventional Reservoirs After Fracturing,” not only expands our understanding of CO2 dynamics within tight oil reservoirs but also lays the groundwork for future innovations in CCUS-EOR technology. The implications of this work extend beyond academic circles, offering strategic insights for industry practitioners and policymakers aiming to implement effective carbon management strategies.

In a climate-stricken world increasingly opting for cleaner energy solutions, the technologies surrounding CO2 management hold paramount importance. This study stands as a crucial contribution to the conversation surrounding climate-friendly oil recovery practices while promoting a balanced approach to industrial energy needs and environmental stewardship.

As we continue on the path towards deeper understanding and innovation in reservoir studies, research like that of Wei and Kadet is essential. It provides a blueprint for future efforts focused on both enhancing oil recovery and achieving substantial reductions in greenhouse gas emissions. With ongoing developments and more rigorous studies, the field is poised for growth, offering hope that the dual goals of increased energy production and climate change mitigation can be realized.

Subject of Research: Cyclic CO2 Injection in Unconventional Reservoirs
Article Title: CO2 Utilization and Geological Storage in Unconventional Reservoirs After Fracturing
News Publication Date: 17-Jan-2025
Web References: https://doi.org/10.1016/j.eng.2025.01.005
References: N/A
Image Credits: Jinzhou Zhao et al.

Keywords: Carbon capture, Geochemistry, Climate change mitigation, Climate modeling