The largest carbonate condensate field has been found in the Tarim Basin, NW China. Different from sandstone condensate gas reservoirs, however, the conventional gas injection for pressure maintenance development is not favorable for Ordovician fracture-cave reservoirs. Based on this, in this paper, 21 sets of displacement experiments in full-diameter cores and a pilot test in 11 boreholes were carried out to study enhanced oil recovery (EOR) in complicated carbonate reservoirs. The experimental results show that the seepage channels of the gas condensate reservoirs are fractures, which are quite different from sandstone pore-throat structures. Condensate oil recovery using water injection was up to 57–88% in unfilled fractured caves and at ca. 52–80% in sand-filled fractured caves. These values are much higher than the 14–46% and 17–58% values obtained from the depletion and gas injection experiments, respectively. The water injection in 11 wells showed that the condensate oil recovery increased by 0–17.7% (avg. 3.1%). The effective EOR for residual oil replacement using water injection may be attributed to fractures, as the gas channel leads to an ineffective gas circulation and pipe flow in fracture-cave reservoirs, which is favorable for waterflood development. The complicated fracture network in the deep subsurface may be the key element in the varied and lower oil recovery rates obtained from the wells than from the experiments. This case study provides new insights for the exploitation of similar condensate gas reservoirs.

Accurate dynamic reserve estimation is essential for effective reservoir development, particularly in fractured vuggy carbonate reservoirs characterized by complex pore structures, multiple spatial scales, and pronounced heterogeneity. Traditional reserve evaluation methods often struggle to account for the coupled behavior of pores, fractures, and vugs, leading to limited reliability. In this study, a modified material balance equation is proposed that explicitly considers the contributions of matrix pores, fractures, and vugs, as well as the influence of varying aquifer multiples. To validate the model, physical experiments were conducted using cores with different fracture–vug configurations under five distinct aquifer multiples. A field case analysis was also performed using production data from representative wells in the Fuman Oilfield. The results demonstrate that the proposed model achieves a fitting accuracy exceeding 94%, effectively capturing the dynamics of fractured vuggy systems with active water drive. The model enables quantitative evaluation of single-well reserves and aquifer multiples, providing a reliable basis for estimating effective recoverable reserves. Furthermore, by comparing simulated formation pressures (excluding aquifer effects) with actual static pressures, the contribution of external aquifer support to reservoir energy can be quantitatively assessed. This approach offers a practical and robust framework for reserve estimation, pressure diagnosis, and development strategy optimization in strongly water-driven fractured vuggy reservoirs.

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.

Fracture–vuggy carbonate reservoirs exhibit strong heterogeneity, spatial discontinuity, and highly variable porosity, which limit the effectiveness of traditional seismic attributes and conventional inversion. Focusing on the XX well block in the Tarim Basin, this study develops a rock-physics-constrained Physics-Constrained TransUNet method for intelligent porosity prediction. A carbonate-specific rock-physics model is first established, considering mineral composition, pore type, and water saturation, ensuring physical consistency between porosity, elastic parameters, and seismic responses. On this basis, a deep-learning framework integrating U-Net multi-scale feature extraction and Transformer global modeling is constructed. By embedding rock-physics priors, regularization constraints, and log-derived porosity labels, the method forms a unified physics- and data-driven inversion scheme. Applications to multiple deep wells and 3D post-stack seismic data from the FI7 fault zone demonstrate stable training, rapid convergence, and strong capability in capturing nonlinear porosity–seismic relationships. Compared with conventional inversion, the proposed approach significantly improves prediction accuracy in cavern-dominated intervals, fractured zones, and areas with abrupt porosity changes, while maintaining robust lateral continuity. Inter-well sections and target-layer slices further verify its effectiveness in identifying fracture–dissolution–vug composite reservoirs. The method provides a practical and reliable workflow for porosity prediction in ultra-deep carbonate reservoirs, supporting fine reservoir characterization and sweet-spot evaluation.

Geological modeling is a three-dimensional (3D) representation of comprehensive geological research results in oil fields. In this paper, first, the comprehensive geological research results were fully applied to establish geological models such as matrix, reservoir, and fractures in the study area. Second, in response to the geological characteristics of carbonate fractured and vuggy reservoirs, various data are integrated. Finally, by collecting and organizing various basic data mentioned above, a refined geological model of the oil reservoir in the study area is established. Results show that (a) Due to the complexity of the distribution of cracks and pores, the presence of these unrelated grids also affects the observation of target cracks and pores. (b) There may be multiple adjacent nodes in the initial access node. The strategy of depth-first traversal is to first access the first adjacent node. (c) There is a significant difference between the connected units extracted solely from static data and the connected units reextracted after fine-tuning the crack position considering dynamic data

This study investigates the impact of different injection media and gas injection methods on oil recovery in the Fuman Oilfield within the Tarim Basin, aiming to optimize gas injection strategies for enhancing oil recovery in the Manshen 4 well area, known for its light, low‐viscosity, low‐sulfur volatile oil and stable strata thickness. The research employs experimental analyses to assess the miscible displacement characteristics of nitrogen, hydrocarbon gas, and carbon dioxide under varying pressures. Findings show that nitrogen achieves miscible displacement at higher pressures (47.5 and 45 MPa), whereas carbon dioxide has the lowest minimum miscibility pressure (MMP). Hydrocarbon gas shows miscibility at intermediate pressures (44 and 41 MPa). In the early stages of gas injection, nitrogen is most effective due to its ease of achieving miscibility. For later stages, hydrocarbon gas and carbon dioxide are more beneficial because of their enhanced solubility and miscibility with the volatile oil, leading to increased recovery rates. The study recommends a strategy combining top nitrogen injection–bottom water injection, and mid‐level oil production to maximize recovery efficiency and maintain optimal production levels. This study innovatively combines different gas injection media at different injection stages and proposes a top nitrogen injection–bottom water injection and mid‐level oil production strategy, which is a new attempt in enhancing oil recovery in similar volatile oil reservoirs. It provides a more comprehensive and efficient solution compared to previous single‐medium injection methods. These results offer valuable guidance for the Fuman Oilfield and similar geological settings.