Chemical Plugging Optimization for Channeling Control During CO2 Flooding Using Multi-Surrogate Collaborative Prescreening

Abstract

During CO2 flooding, unfavorable mobility ratios and interlayer heterogeneity can induce preferential flow through high-permeability intervals, leaving central low-permeability intervals insufficiently swept and rich in remaining oil. To address the strong coupling among composite chemical-plugging parameters and the high computational cost of CMG-STARS simulations for individual candidate strategies, this study proposes an adaptive heterogeneous ensemble surrogate-assisted differential-evolution method (AHES-DE). The method integrates radial basis function, inverse-distance weighting, and ridge-linear surrogate models, whose predictions are dynamically weighted according to leave-one-out cross-validation errors. Explorer, Exploiter, and Robust roles are used for global search, local exploitation, and prediction-risk control, respectively, with differential-evolution offspring generation embedded in the Exploiter role. A stratified one-injector–four-producer conceptual model with a 21 × 21 × 6 grid was used to establish a numerical evaluation workflow comprising CO2 injection, preferential-channel development, composite chemical plugging, and subsequent displacement. Mobile chemical concentration, adsorbed preformed particle gel (PPG) mass density, water-phase resistance factor, oil saturation at a common termination time, and net economic value (NEV) were used to evaluate treatment performance. Under an equal budget of 150 high-fidelity CMG-STARS evaluations per method, the reported single-seed final best-so-far NEVs were 2.45405 × 109 CNY for AHES-DE, 2.44888 × 109 CNY for differential evolution (DE), and 2.44698 × 109 CNY for Latin hypercube sampling (LHS). The layer-resolved responses indicate more pronounced chemical transport, retention, and resistance development in the upper and lower preferential intervals, while the oil saturation in the central low-permeability interval decreased further after treatment, indicating that flow redistribution facilitated remaining-oil mobilization. A realistic geological model was further used to assess the engineering consistency of the identified flow-control mechanism.