The Lunnan oilfield, nestled within the Tarim Basin, represents a prototypical extra-low-permeability sandstone reservoir, distinguished by high-quality crude oil characterised by a low viscosity, density, and gel content. The effective exploitation of such reservoirs hinges on the implementation of carbon dioxide (CO₂) flooding techniques. This study, focusing on the sandstone reservoirs of Lunnan, delves into the mechanisms of CO₂-assisted oil displacement under diverse operational parameters: injection pressures, CO₂ concentration levels, and variations in crude oil properties. It integrates analyses on the high-pressure, high-temperature behaviour of CO₂, the dynamics of CO₂ injection and expansion, prolonged core flood characteristics, and the governing principles of minimum miscible pressure transitions. The findings reveal a nuanced interplay between variables: CO₂’s density and viscosity initially surge with escalating injection pressures before stabilising, whereas they experience a gradual decline with increasing temperature. Enhanced CO₂ injection correlates with a heightened expansion coefficient, yet the density increment of degassed crude oil remains marginal. Notably, CO₂ viscosity undergoes a substantial reduction under stratigraphic pressures. The sequential application of water alternating gas (WAG) followed by continuous CO₂ flooding attains oil recovery efficiency surpassing 90%, emphasising the superiority of uninterrupted CO₂ injection over processes lacking profiling. The presence of non-miscible hydrocarbon gases in segmented plug drives impedes the oil displacement efficiency, underscoring the importance of CO₂ purity in the displacement medium. Furthermore, a marked trend emerges in crude oil recovery rates as the replacement pressure escalates, exhibiting an initial rapid enhancement succeeded by a gradual rise. Collectively, these insights offer a robust theoretical foundation endorsing the deployment of CO₂ flooding strategies for enhancing oil recovery from sandstone reservoirs, thereby contributing valuable data to the advancement of enhanced oil recovery (EOR) technologies in challenging, low-permeability environments.

The hydrocarbon-bearing formation of Miano gas field belongs to the Early Cretaceous and it is bounded by two shale intervals, which are considered as maximum flooding surfaces (MFS). The hydrocarbon-bearing interval includes two reservoir units: a tight gas reservoir and its overlying conventional reservoir. Core samples, borehole logs, and well production performance revealed that the two reservoirs present reversed trends in reservoir quality through the gas field without obvious barriers. The average shale volume of the tight gas reservoir changes from 24.3% to 12.2% and the average permeability changes from 32.65 mD to 0.02 mD from the south to north. However, the average effective porosity of the overlaying conventional reservoir increases from 20% to 26% and the average permeability increases from 10 mD to 300 mD. The reversed trends in the two reservoirs lead to challenges in production forecast and development well proposals in the tight gas reservoir. Therefore, reservoir characterization and a predictive reservoir model are essential for further exploitation of Miano gas field. The geological genesis analysis integrating cores, borehole logs, and three-dimensional (3D) seismic data reveals that the producing interval of the tight gas reservoir is tidal-influenced shore facies deposition with intergranular pore space reduced by mineral cementation during burial diagenesis, while the overlaying conventional reservoir is fluvial-influenced deltaic deposition with abundant, well-connected intergranular macropores, which leads to a better reservoir quality. A reservoir model containing both the tight gas reservoir and the conventional reservoir is constructed considering the reservoir nature understanding, and the accuracy of the model is confirmed by reservoir surveillance activities with the simulation model. The study will be critical to the further reservoir development and hydrocarbon production in Miano gas field.

To address the problem of serious gas channeling during CO₂ flooding in low-permeability reservoirs, which leads to poor oil recovery, this study developed a CO₂-resistant gel using a novel CO₂-responsive polymer (ADA) for gas channel control. The ADA polymer was synthesized via free-radical copolymerization of acrylamide (AM), dimethylaminopropyl methacrylamide (DMAPMA), and 2-acrylamido-2-methylpropanesulfonic acid (AMPS), which introduced protonatable tertiary-amine groups and sulfonate moieties into the polymer backbone. Comprehensive characterizations confirmed the designed structure and adequate thermal stability of the ADA polymer. Rheological tests demonstrated that the ADA polymer solution exhibits significant CO₂-triggered viscosity enhancement and excellent shear resistance. When crosslinked with phenolic resin, the resulting ADA gel showed outstanding CO₂ tolerance under simulated reservoir conditions (110 °C, 10 MPa). After 600 s of CO₂ exposure, the ADA gel retained over 99% of its initial viscosity, whereas a conventional HPAM-based industrial gel degraded to 61% of its original viscosity. The CO₂-resistance mechanism involves protonation of tertiary amines to form quaternary ammonium salts, which electrostatically interact with sulfonate groups, creating a reinforced dual-crosslinked network that effectively protects the gel from H⁺ ion attack. Core flooding experiments confirmed its ability to enhance oil recovery by plugging high-permeability channels and diverting flow, achieving a final recovery of up to 48.5% in heterogeneous cores. This work provides a novel gel system for improving sweep efficiency and storage security during CO₂ flooding in low-permeability reservoirs.

CO₂ flooding is an effective technique for enhancing oil recovery in low-permeability reservoirs. However, it is often hindered by severe CO₂ channeling. This challenge is particularly pronounced in near-wellbore regions with large pressure differentials and in fractured reservoirs, where high CO₂ injection rates and rapid breakthrough require channel blocking systems with high mechanical strength and excellent CO₂-resistant performance. In this work, a smart responsive polymer was synthesized and subsequently crosslinked with a highly active phenolic resin crosslinking agent to develop a smart responsive polymer gel channel blocking system. The resulting gel exhibits CO₂-responsive strength enhancement and excellent CO₂-resistant performance. The static and dynamic gelation behaviors, nonlinear rheological properties, CO₂-resistant performance, channel blocking, and enhanced oil recovery performance of the smart responsive polymer gel were systematically investigated. The results demonstrate that the polymer gel maintains good structural stability during dynamic transport in the reservoir and does not undergo significant strength degradation under shear conditions. Moreover, the smart responsive polymer gel exhibits excellent CO₂-resistant performance within a temperature range of 80–110 °C, salinity up to 10 × 10⁴ mg/L, and pressure up to 20 MPa. Moreover, the system shows a significant enhancement in channel blocking and enhanced oil recovery performance, highlighting its promising potential for effective CO₂ flooding channel blocking in low-permeability reservoirs.