The recovery of heavy oil is challenging due to its high viscosity. Especially in water flooding, the high viscosity of heavy oil induces a high water/oil mobility ratio, resulting in frequent channeling and fingering. In the present work, the viscosity reduction in heavy oil caused by foaming agents is studied. Among the studied foam systems, the KX-048 foaming agent had the best oil viscosity reduction performance. It also shows excellent foaming performance, including large foam volume, long foam half-life, and high foam comprehensive index. With the reduction in oil viscosity, the KX-048 foaming agent decreases the foam/oil mobility to 0.28, which is beneficial for controlling gas channeling and fingering in foam flooding. Moreover, Foam flooding experiments in heterogeneous sand-pack models indicate that KX-048 has excellent efficiency in improving oil recovery, especially in the low-permeable tube. The chosen KX-048 foaming agent could provide a promising pathway for improving heavy oil recovery.

The peripheral reservoirs of the Daqing Oilfield exhibit low permeability and partial heterogeneity, resulting in a rapid injection pressure increase, limited sweep efficiency, and significant residual oil retention. To enhance recovery, this study synthesized a fluorocarbon siloxane (FHB) via free radical addition for rock surface wettability modification. At a concentration of 0.1 wt%, FHB increased water and oil contact angles to 136° and 117°, respectively, at 60 °C. Fourier transform infrared spectroscopy, thermogravimetric analysis, and aging tests confirmed stable hydrophobic/oleophobic properties through chemical bonding to the rock. Furthermore, the low surface energy FHB significantly reduced adhesion work and decreased oil-water interfacial tension from 27 mN/m to 0.55 mN/m, thereby improving fluid transport in pore throats and promoting residual oil mobilization. Core flooding experiments resulted in an increase in total recovery by 11%, with low-field NMR analysis confirming reduced oil saturation across various pore sizes. A field trial in a production well in Daqing Oilfield successfully increased output from 3.1 t/d to 4.9 t/d, validating the efficacy of this strategy under real reservoir conditions—representing the first successful field application of a fluorocarbon-based modifier for wettability alteration and oil production enhancement in China. This study provides valuable experimental data and a practical framework for implementing chemical-enhanced recovery.

This study establishes a covalently anchored wettability alteration strategy for enhanced oil recovery (EOR) using perfluorinated siloxane (CQ), addressing limitations of conventional modifiers reliant on unstable physical adsorption. Instead, CQ forms irreversible chemical bonds with rock surfaces via Si-O-Si linkages (verified by FT-IR/EDS), imparting durable amphiphobicity with water and oil contact angles of 135° and 116°, respectively. This modification exhibits exceptional stability: increasing salinity from 2536 to 10,659 mg/L reduced angles by only 6° (water) and 4° (oil), while 70 °C aging in aqueous/oleic phases preserved amphiphobicity without reversion—supported by >300 °C thermal decomposition in TGA; confirming chemical bonding durability. Mechanistic analysis identifies dual EOR pathways: amphiphobic surfaces lower rolling angles, surface free energy (SFE), and fluid adhesion to facilitate pore migration, while CQ intrinsically reduces oil-water interfacial tension (IFT). Core displacement experiments showed that injecting 0.05 wt% CQ followed by secondary waterflooding yielded an additional 10–18% increase in oil recovery. This improvement is attributed to enhanced mobilization of residual oil, with greater EOR efficacy observed in smaller pore throats. Field trials at the Huabei Oilfield validated practical applicability: Production rates of test wells C-9 and C-17 increased several-fold, accompanied by reduced water cuts. Integrating fundamental research, laboratory experiments, and field validation, this work systematically demonstrates a wettability-alteration-based EOR method and offers important technical insights for analogous reservoir development.

To address the challenges of low displacement efficiency and gas channeling in the Lukqin thick oil reservoir, characterized by high viscosity (286 mPa·s) and strong heterogeneity (permeability contrast 5–10), this study systematically investigated water flooding and foam flooding mechanisms using a large-scale 2D sandpack model (5 m × 1 m × 0.04 m). Experimental results indicate that water flooding achieves only 30% oil recovery due to a mobility ratio imbalance (M = 128) and preferential channeling. In contrast, foam flooding enhances recovery by 15–20% (final recovery: 45%) through synergistic mechanisms of dynamic high-permeability channel plugging and mobility ratio optimization. By innovatively integrating electrical resistivity tomography with HSV color mapping, this work achieves the first visualization of foam migration pathways in meter-scale heterogeneous reservoirs at a spatial resolution of ≤0.5 cm, reducing monitoring costs by approximately 30% compared to conventional CT techniques. Key controlling factors for gas channeling (injection rate, foam quality, permeability contrast) are identified, and a nonlinear predictive model for plugging strength ((S = 0.70C^0.6 k_r^−0.28) (R² = 0.91)) is established. A composite optimization strategy—combining high-concentration slugs (0.7% AOS), salt-resistant polymer-enhanced foaming, and multi-round profile control—achieves a 67% reduction in gas channeling. This study elucidates the dynamic plugging mechanisms of foam flooding in heterogeneous thick oil reservoirs through large-scale physical simulations and data fusion, offering direct technical guidance for optimizing foam flooding operations in the Lukqin Oilfield and analogous reservoirs.

In this study, a 5 m×1 m×0.04 m sand filling model was constructed to simulate Lukqin thick oil reservoir, and the development rules of water flooding and foam flooding were systematically analyzed. The results show that the recovery rate of water flooding is only 30% due to the imbalance of mobility ratio and gas channeling. By integrating electrical resistivity tomography (ERT) with HSV (Hue-Saturation-Value) color mapping, this study pioneers the first visualization of foam migration in meter-scale heterogeneous reservoirs (5 m × 1 m × 0.04 m) with a spatial resolution of ≤0.5 cm. This surpasses the limitations of conventional CT scanning (typical resolution ≥2 cm) and X-ray tomography (cost: 500–800 per scan), offering a 30% reduction in monitoring costs. The proposed 5 m × 1 m × 0.04 m sandpack model reveals that foam flooding enhances oil recovery by 15–20% via synergistic mechanisms of dynamic high-permeability channel plugging (governed by S=0.7C0.6kr−0.28) and mobility ratio optimization, surpassing the 30% recovery limit of conventional water flooding. The main controlling factors of gas channeling (injection speed, foam quality, permeability heterogeneity) are revealed, and the optimization of injection parameters, improvement of foam formulation, combined with numerical simulation and other synergistic techniques are proposed. The proposed large-scale physical simulation methods advance the understanding of foam flooding mechanisms in meter-scale heterogeneous reservoirs, directly guiding the optimization of air foam flooding operations in the Lukqin oilfield.