Search Results (4)

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. Full article

For over four decades, carbon dioxide (CO₂) has been instrumental in enhancing oil extraction through advanced recovery techniques. One such method, water alternating gas (WAG) injection, while effective, grapples with limitations like gas channeling and gravity segregation. To tackle the aforementioned issues, this paper proposes an upgrade coupling method named alkaline-surfactant-polymer alternating gas (ASPAG). ASP flooding and CO₂ are injected alternately into the reservoir to enhance the recovery of the WAG process. The uniqueness of this method lies in the fact that polymers could help profile modification, CO₂ would miscible mix with oil, and alkaline surfactant would reduce oil–water interfacial tension (IFT). To analyze the feasibility of ASPAG, a couples model considering both gas flooding and ASP flooding processes is established by using the CMG-STARS (Version 2021) to study the performance of ASPAG and compare the recovery among ASPAG, WAG, and ASP flooding. Our research delved into the ASPAG’s adaptability across reservoirs varying in average permeability, interlayer heterogeneity, formation rhythmicity, and fluid properties. Key findings include that ASPAG surpasses the conventional WAG in sweep and displacement efficiency, elevating oil recovery by 12–17%, and in comparison to ASP, ASPAG bolsters displacement efficiency, leading to a 9–11% increase in oil recovery. The primary flooding mechanism of ASPAG stems from the ASP slug’s ability to diminish the interfacial tension, enhancing the oil and water mobility ratio, which is particularly efficient in medium-high permeability layers. Through sensitivity analysis, ASPAG is best suited for mid-high-permeability reservoirs characterized by low crude oil viscosity and a composite reverse sedimentary rhythm. This study offers invaluable insights into the underlying mechanisms and critical parameters that influence the alkaline-surfactant-polymer alternating gas method’s success for enhanced oil recovery. Furthermore, it unveils an innovative strategy to boost oil recovery in medium-to-high-permeability reservoirs. Full article

CO₂ flooding is a pivotal technique for significantly enhancing oil recovery in low-permeability reservoirs. The movement and sweeping rules at the front of CO₂ flooding play a critical role in oil recovery; yet, a comprehensive quantitative analysis remains an area in need of refinement. In this study, we developed 1-D and 2-D numerical simulation models to explore the sweeping behavior of miscible, immiscible, and partly miscible CO₂ flooding patterns. The front position and movement rules of the three CO₂ flooding patterns were determined. A novel approach to the contour area calculation method was introduced to quantitatively characterize the sweep coefficients, and the sweeping rules are discussed regarding the geological parameters, oil viscosity, and injection–production parameters. Furthermore, the Random Forest (RF) algorithm was employed to identify the controlling factor of the sweep coefficient, as determined through the use of out-of-bag (OOB) data permutation analysis. The results showed that the miscible front was located at the point of maximum CO₂ content in the oil phase. The immiscible front occurred at the point of maximum interfacial tension near the production well. Remarkably, the immiscible front moved at a faster rate compared with the miscible front. Geological parameters, including porosity, permeability, and reservoir thickness, significantly impacted the gravity segregation effect, thereby influencing the CO₂ sweep coefficient. Immiscible flooding exhibited the highest degree of gravity segregation, with a maximum gravity segregation degree (GSD) reaching 78.1. The permeability ratio was a crucial factor, with a lower limit of approximately 5.0 for reservoirs suitable for CO₂ flooding. Injection–production parameters also played a pivotal role in terms of the sweep coefficient. Decreased well spacing and increased gas injection rates were found to enhance sweep coefficients by suppressing gravity segregation. Additionally, higher gas injection rates could improve the miscibility degree of partly miscible flooding from 0.69 to 1.0. Oil viscosity proved to be a significant factor influencing the sweep coefficients, with high seepage resistance due to increasing oil viscosity dominating the miscible and partly miscible flooding patterns. Conversely, gravity segregation primarily governed the sweep coefficient in immiscible flooding. In terms of controlling factors, the permeability ratio emerged as a paramount influence, with a factor importance value (FI) reaching 1.04. The findings of this study can help for a better understanding of sweeping rules of CO₂ flooding and providing valuable insights for optimizing oil recovery strategies in the field applications of CO₂ flooding. Full article

In recent years, there has been significant focus on the issue of global carbon emissions. One of the most prominent areas of research in this regard is the use of carbon capture, utilization, and storage (CCUS) technology in the petrochemical industry. At present, the utilization of CO₂ Assisted Gravity Drainage (CAGD) in oil reservoirs, particularly those containing bottom water, is considered to be in the early stages of exploration and development. In this study, a mechanistic model was built, and five key factors influencing CAGD were analyzed. These factors included the reservoir structure, CO₂ injection site, initial formation pressure, reservoir thickness, and CO₂ injection rate. Then, the applicable rules governing CAGD in oil reservoirs with bottom water were obtained. Finally, these rules were employed in an actual reservoir to optimize the injection-production parameters. The results of the influence factor analysis indicated that CAGD was more suitable for anticline structural reservoirs. The combined top-waist CO₂ injection could fully utilize gravity differentiation in a short timeframe to expand the lateral sweep range of the CO₂. CAGD was more effective when the reservoir pressure was greater than the minimum miscible pressure and the reservoir thickness was between 25–50 m. The generation of a secondary CO₂ cap was favored when the CO₂ injection rate was 35,000 m³/d. Results from A Oilfield applications indicated that, following the application of CAGD technology, A Oilfield experienced an increase in cumulative oil production of 15.76 × 10⁴ t, a 10% reduction in water cut, and an amount of 82.15 × 10⁶ m³ of CO₂ that was sequestered in the subsurface. These findings can offer practical insights and guidance for the future development of CAGD techniques in similar reservoirs. Full article