The Lunnan oilfield in the Tarim Basin, one of China’s major onshore oilfields with substantial geological reserves, faces particular challenges due to the complexity of its reservoir environment and the dispersion of remaining oil. Carbon dioxide, a greenhouse gas, presents an opportunity for enhanced oil recovery (EOR) and geological storage. In this context, the use of carbon dioxide for EOR can simultaneously address environmental concerns and improve oil recovery rates. This study focuses on the TI reservoir in the No. 2 well area of the Lunnan oilfield, employing advanced techniques to analyze the micro- and macro-characteristics of carbon dioxide flooding. Results: From the microscopic point of view, carbon dioxide flooding is mainly miscible with crude oil, which has a strong component exchange effect and can be displaced in the form of full pores, and the microscopic displacement efficiency is close to 100%. Macroscopically, under the combined injection and production of different injected hydrocarbon pore volume multiples (HCPVs), it is injected at the upper and lower layers of the interlayer and produced far away from the lower layer of the interlayer, with a total recovery rate of 52.83%. With the increase in the HCPV, the recovery increased rapidly at first and then slowly, and the HCPV at the demarcation point was 0.5, while the oil production rate increased in a wave-like manner and then decreased rapidly, and the HCPV at the breakthrough point of TI gas was 0.5. However, when the upper and lower layers far away from the interlayer are injected at the same time, the upper and lower layers of the interlayer are produced at the same time, and the total recovery rate can reach 83.02%. With the increase in the HCPV, the recovery rate increases rapidly at first and then slowly, and the HCPV at the turning point is 6.52. The oil production rate increases in a wave-like manner, then decreases rapidly, rises rapidly, and then decreases slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas is 0.63, and the HCPV at the injection–production transition point is 0.63. The total recovery rate of carbon dioxide miscible displacement can reach 88.68% under the condition of separate injection and combined production with different injected hydrocarbon pore volume multiples. With the increase in the HCPV, the recovery increased rapidly at first and then slowly. The HCPV at the demarcation point was 6.5, the oil production rate increased in a wave-like manner, then decreased rapidly, increased rapidly, and then decreased slowly in a wave-like manner. The HCPV at the breakthrough point of TI gas was 0.63, and the HCPV at the injection–production transition point was 6.5. The research results provide data support for the physical reality of the microscopic and macroscopic sweep characteristics of carbon dioxide flooding in the Lunnan oilfield, Tarim Basin.

This study investigates gas injection gravity miscible flooding to enhance oil recovery in fractured-vuggy volatile oil reservoirs of the Fuman area, Tarim Basin. The Fuman 210 reservoir, containing light oil with high maturity, large column heights, and strong fracture control, provides favorable conditions for gravity-driven flooding. Laboratory tests show that natural gas and CO₂ achieve miscibility, while N₂ reaches near-miscibility. Mixed gas injection, especially at a natural gas to nitrogen ratio of 1:4, effectively lowers minimum miscibility pressure and enhances displacement efficiency. Full-diameter core experiments confirm that miscibility improves oil washing and expands the sweep volume. Based on these results, a stepped three-dimensional well network was designed, integrating shallow injection with deep production. Optimal parameters were determined: injection rates of 50,000–100,000 m³/day per well and stage-specific injection–production ratios (1.2–1.5 early, 1.0–1.2 middle, 0.8–1.0 late). Field pilots validated the method, maintaining stable production for seven years and achieving a recovery factor of 30.03%. By contrast, conventional development relies on depletion and limited water flooding, and dry gas injection yields only 12.6%. Thus, the proposed approach improves recovery by 17.4 percentage points. The novelty of this work lies in establishing the feasibility of mixed nitrogen–natural gas miscible flooding for ultra-deep fault-controlled carbonate reservoirs and introducing an innovative stepped well network model. These findings provide new technical guidance for large-scale application in similar reservoirs.

This study conducts a comprehensive investigation into theformation mechanisms of unconventional oil reservoirs within the Carboniferous strata of the Hudson Oilfield in the Tarim Basin. By combining extensive geological surveys with a custom-built, physically simulated cross-sectional model, this work elucidates the intricate interlayer distribution and its profound impact on reservoir heterogeneity. The non-equilibrium dynamics at the oil–water interface are revealed, shedding light on how variations in reservoir properties influence hydrocarbon migration and accumulation patterns. Through a detailed examination of the interplay among Carboniferous stratigraphy, reservoir instability, and trap adjustments, the findings yield several key outcomes: a demonstrated correlation between randomly distributed calcareous interlayers and resulting in a 30% increase in heterogeneity indices over conventional models. Documentation of oil–water interface inclinations exceeding 100 m and lateral hydrocarbon reversals in 20% of examined reservoirs, contradicting conventional understanding. Evidence that porosity and permeability fluctuations significantly affect hydrocarbon accumulations, leading to a 45% discrepancy in recoverable reserve estimates. And the application of advanced simulations, enhancing unconventional reservoir prediction accuracy by 25% compared to standard geological techniques. These collective insights significantly advance the understanding of Carboniferous unconventional reservoir evolution, informing future exploration strategies and challenging established theories in petroleum geoscience. This highlights the necessity of accounting for reservoir instability and interlayer intricacy in deciphering unconventional hydrocarbon systems.