Scientists Reveal the Atomic-Scale Secrets of CO2 Oil Recovery and Carbon Storage

Deep beneath the Earth’s surface, a quiet chemical drama unfolds every time carbon dioxide is pumped into an oil reservoir. Injected CO2 meets crude oil, salty formation water, and porous rock in a tightly confined, high-pressure environment, and the outcome of that three-way encounter determines both how much additional oil can be recovered and whether the greenhouse gas will stay locked underground for centuries. A comprehensive new review published in the Journal of Saudi Chemical Society by researchers at Liaoning Petrochemical University and Northeast Petroleum University has now pulled together the scattered microscopic evidence from hundreds of experiments and simulations, offering the field its most integrated picture yet of the oil–water–rock interactions that govern CO2-enhanced oil recovery and geological carbon storage.

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