Pore-Scale Mechanisms of CO2–WAG Enhanced Oil Recovery in Tight Conglomerate Reservoirs: A Multicomponent Multiphase Lattice Boltzmann Study

Abstract

Understanding pore-scale displacement mechanisms of CO2–water-alternating-gas (WAG) injection in tight conglomerate reservoirs is critical for improving enhanced oil recovery (EOR) efficiency in these strongly heterogeneous systems. This study develops a three-component (oil–water–CO2) multicomponent multiphase multiple-relaxation-time lattice Boltzmann (MCMP-MRT-LBM) pore-scale numerical framework based on a digitized pore microstructure model of Class I conglomerate reservoirs in the Mahu Sag, Junggar Basin. Systematic simulations are conducted to evaluate the effects of injection mode, cycle number, injection velocity, and CO2 miscibility degree on microscopic displacement efficiency. Results demonstrate that CO2–WAG injection achieves a maximum recovery factor of 46.65%, substantially exceeding post-waterflooding CO2 flooding (35.77%) and conventional waterflooding (∼18%). Three synergistic pore-scale mechanisms underpin WAG’s superiority: alternating injection generates a Jamin-effect bubble plugging that redirects flow from macropores into low-permeability micropores; periodic fluid switching suppresses cumulative viscous fingering; and complementary CO2 extraction and water imbibition mechanisms synergistically mobilize residual oil across diverse morphologies. An optimal cycle number of four is identified, with recovery exhibiting nonmonotonic dependence on cycle frequency. Displacement efficiency peaks at moderate capillary numbers (Ca ∼10–3), while maintaining reservoir pressure above the minimum miscibility pressure (∼32 MPa) is essential for effective micropore residual oil mobilization. These pore-scale findings provide mechanistic guidance for optimizing CO2–WAG programs in the Mahu Sag and analogous tight conglomerate reservoirs worldwide.