Three-Phase Equilibrium of Hydrocarbon Mixtures in Nanopores: A Volume-Temperature Flash Calculation Approach

Abstract The thermodynamic properties and phase behaviors of nanoconfined fluids are crucial for accurately simulating fluid transport in shale nanopores. However, the commonly used cubic equations of state (EOS) with critical parameter shifts fail to account for fluid/pore wall interactions, leading to inaccuracies in predicting fluid properties within nanopores. More precise ab initio methodologies like density functional theory and molecular simulation demand extensive computational resources, limiting their practical application in large-scale reservoir simulations. Therefore, we aim to develop an efficient and accurate method based on a modified EOS to calculate the phase behaviors of fluids confined in nanopores. A fast and robust VT-flash calculation algorithm is proposed to determine the three-phase behavior of fluids in nanopores using a modified EOS that accounts for both confinement effects and fluid-wall interactions. The algorithm is based on directly minimizing the tangent plane distance or Helmholtz free energy using the Trust-Region modified Newton iteration method. The developed model is validated by comparing adsorption experimental results in nanopores and the fluid phase behavior of the bulk fluid. Then the model is used to analyze the phase behavior of pure fluids and fluid mixtures in nanopores. For pure component systems, fluid–solid interactions result in a sorbed phase with higher density than the bulk fluid, leading to increased spreading pressure. Both confinement effects and fluid–wall interactions significantly influence phase behavior: their combined action causes the two-phase envelope to shrink as pore size decreases. Confinement effects increase fluid covolume, while fluid–wall interactions weaken intermolecular attractions, lowering the critical temperature in smaller pores. Additionally, critical density increases in moderately sized pores due to the formation of dense sorbed layers, but decreases in smaller pores where confinement dominates through covolume expansion. The proposed algorithm provides an efficient and physically grounded framework for modeling multiphase behavior in nanopores and can be extended to simulate CO2-enhanced oil recovery and storage in shale reservoirs.