Computational Modeling and Experimental Investigation of CO2-Hydrocarbon System Within Cross-Scale Porous Media

Abstract

CO₂ flooding plays a crucial role in enhancing oil recovery and achieving carbon reduction targets, particularly in unconventional reservoirs with complex pore structures. The phase behavior of CO₂ and hydrocarbons at different scales significantly affects oil recovery efficiency, yet its underlying mechanisms remain insufficiently understood. This study improves existing thermodynamic models by introducing Helmholtz free energy as a convergence criterion and incorporating adsorption effects in micro- and nano-scale pores. This study refines existing thermodynamic models by incorporating Helmholtz free energy as a convergence criterion, offering a more accurate representation of confined phase behavior. Unlike conventional Gibbs free energy-based models, this approach effectively accounts for confinement-induced deviations in phase equilibrium, ensuring improved predictive accuracy for nanoscale reservoirs. Additionally, adsorption effects in micro- and nano-scale pores are explicitly integrated to enhance model reliability. A multi-scale thermodynamic model for CO₂-hydrocarbon systems is developed and validated through physical simulations. Key findings indicate that as the scale decreases from bulk to 10 nm, the bubble point pressure shows a deviation of 5% to 23%, while the density of confined fluids increases by approximately 2%. The results also reveal that smaller pores restrict gas expansion, leading to an enhanced CO₂ solubility effect and stronger phase mixing behavior. Through phase diagram analysis, density expansion, multi-stage contact, and differential separation simulations, we further clarify how confinement influences CO₂ injection efficiency. These findings provide new insights into phase behavior changes in confined porous media, improving the accuracy of CO₂ flooding predictions. The proposed model offers a more precise framework for evaluating phase transitions in unconventional reservoirs, aiding in the optimization of CO₂-based enhanced oil recovery strategies.

Keywords: CO2 flooding; confined fluids; enhanced oil recovery; multi-scale; phase behavior.

Figure 1

The average error rate of model calculation and experimental results under different grouping methods.

Figure 2

Comparison of phase envelope predictions: Helmholtz-based model provides improved accuracy under confinement. (a) Saturation pressure (b) expansion coefficient.

Figure 3

Phase envelope shrinkage of B131 formation oil at different pore sizes.

Figure 4

Morphology of CO₂ and B131 formation oil in PVT as pressure increases.

Figure 5

Gas phase component gradient with pressure.

Figure 6

B131 formation oil-CO₂ system: liquid and gas phase composition changes with pressure. (a) liquid phase (b) gas phase.

Figure 7

Bubble point pressure variation with decreasing pore size.

Figure 8

Saturation pressure reduction in confined nanopores.

Figure 9

Comparison of composition changes in multi-stage contact experiments and model calculation results (a) liquid phase (b) gas phase. (The calculations were performed using the forward method.)

Figure 10

Comparison of gas/liquid phase volume and molecular weight changes in multi-stage contact experiments with model calculation composition changes. (The calculations in this figure were performed using the forward method.).

Figure 11

Comparison of liquid phase composition changes in multi-stage contact experiments and model calculation results (a) liquid phase (b) gas phase. (The calculations in this figure were performed using the backward method.)

Figure 12

Comparison of gas/liquid phase volume and molecular weight changes in multi-stage contact experiments with model calculation composition changes. (The calculations in this figure were performed using the backward method.)

Figure 13

(a) Gas–liquid interfacial tension vs. scale variation [42]. (b) Model repeated calculation of gas–liquid interfacial tension versus scale change and the verification effect of Wu et al.

Figure 14

The PT phase envelope of formation oil changes at different scales (a) B131 (b) B18 (c) B79 (d) B18 -CO₂.

Figure 15

Enlarged results of PT phase envelopes at different scales of fluid near the formation temperature (a) B131 (b) B18 (c) B79 (d) B18-CO₂.

Figure 16

(a) Variation law of fluid saturation pressure at different scales in the equilibrium mass expansion process. (b) Variation law of fluid density at different scales for equilibrium mass expansion.

Figure 17

Scale-dependent variation of liquid phase composition at 50 bar increased retention of heavier hydrocarbons in smaller pores.

Figure 18

Scale-dependent variation of gas phase composition at 50 bar enhanced CO₂ retention and depletion of lighter hydrocarbons in smaller pores.

Figure 19

Variation of liquid phase components at different scales in the fourth stage of backward multi-stage contact process.

Figure 20

Variation of liquid phase components at different scales in the fifth stage of backward multi-stage contact process.

Figure 21

Variation of gas phase components at different scales in the first stage forword multi-stage contact process.