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Modified cell-to-cell method for slim tube test simulation considering the porous media effect

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Getting More Oil Out of Old Rocks

Many of the world’s oil fields are aging, and pushing out the last portions of oil is becoming harder and more expensive. One of the most promising strategies is to inject gas into the rock so that it mixes with the oil and helps sweep it toward production wells. This study tackles a surprisingly subtle question that strongly affects the success and cost of such projects: how does the structure of the rock itself change the pressure needed for the injected gas to fully mix with the oil?

When Gas and Oil Truly Mix

For gas injection to work at its best, the injected gas and the in-place oil must become fully miscible, meaning they blend into a single, uniform fluid without a sharp boundary. Engineers describe the lowest pressure at which this complete mixing happens as the minimum miscibility pressure, or MMP. Operating above the MMP can greatly increase the amount of oil recovered, but it also demands stronger surface equipment and thicker pipelines, which raises costs. Traditionally, MMP is measured in the lab with a long, thin, rock-filled tube called a slim tube, or estimated using computer models that treat the fluids as if they were in open space, largely ignoring how the rock’s small pores alter their behavior.

Why Tiny Pores Change Fluid Behavior

Inside a real rock, oil and gas are not floating freely; they are squeezed into networks of microscopic pores. In these confined spaces, fluid molecules interact strongly with the surrounding rock walls. Heavy components in the oil tend to stick to the pore surfaces, and the curvature of tiny pores creates capillary forces that resist fluid movement. These effects shift the temperatures and pressures at which fluids change phase and mix. Earlier models tried to capture confinement by representing the rock as a single idealized tube. The authors argue that this is not realistic enough for rocks with a mix of pore sizes and connectivities, especially the “tight” formations that are becoming increasingly important in modern production.

A More Realistic Digital Slim Tube

To address this, the researchers carried out classic slim-tube experiments with real reservoir oil and a hydrocarbon gas at several pressures and at 100 °C, then built a new numerical model designed to mimic the test more faithfully.

Figure 1
Figure 1.
They represented the porous rock as a bundle of many small tubes whose combined properties match the measured porosity (how much void space the rock has) and permeability (how easily fluids flow). Into this framework they wove several key improvements: a version of a standard thermodynamic formula, the Peng–Robinson equation of state, modified so that its predictions depend explicitly on porosity and permeability; adjustments to the way critical temperatures and pressures shift in confined pores; inclusion of capillary forces directly in the gas–liquid equilibrium calculations; and a revised rule for how gas and oil move from one cell to the next after gas “breaks through,” capturing the tendency of gas to carve channels through the rock.

Matching Experiments and Revealing Rock Effects

The enhanced model, called a modified cell‑to‑cell simulation (MCCS), was benchmarked against the physical slim‑tube tests. By running the model with increasing numbers of cells and extrapolating to an effectively infinite number, the authors minimized numerical smearing and obtained a sharp prediction of ultimate oil recovery at each pressure.

Figure 2
Figure 2.
The model reproduced the measured MMP of about 25 MPa within roughly three percent and showed only about 5.5 percent average deviation in oil recovery across all test pressures, slightly overestimating recovery in a way that provides a conservative safety margin for design. Crucially, when they varied the ratio of permeability to porosity, a simple measure of how tight the rock is, the simulations indicated that as this ratio becomes smaller—that is, as pores become smaller and flow paths more restrictive—the MMP drops noticeably, especially when the ratio falls below about 10. At the same time, tighter rocks showed higher oil recovery at a fixed pressure because conditions inside the pores move closer to full miscibility.

What This Means for Future Oil Projects

In plain terms, this work suggests that very tight rocks, long considered difficult targets, may actually require less pressure than expected to achieve full gas–oil mixing, provided this confinement effect is properly accounted for. The new modeling approach links that insight directly to measurable rock properties, allowing engineers to estimate MMP more reliably for a wide range of reservoirs without running endless costly lab tests. While the method still simplifies the true complexity of pore networks, it offers a practical, physics‑based tool for screening and early design of gas‑injection projects, and it highlights that the tiniest details inside the rock can make a big difference in how easily we can coax out the remaining oil.

Citation: Safaei, A., Riazi, M., Jafarzadegan, M. et al. Modified cell-to-cell method for slim tube test simulation considering the porous media effect. Sci Rep 16, 8557 (2026). https://doi.org/10.1038/s41598-026-38525-4

Keywords: gas injection, minimum miscibility pressure, porous media, enhanced oil recovery, tight reservoirs