Shale oil and gas development is shifting from single stimulation methods toward integrated recovery strategies that combine flow-mechanism understanding, enhanced oil recovery, and carbon utilization and storage. Based on the discussions in Session “Shale Oil and Gas Flow Mechanisms and Enhanced Oil Recovery” of the second “International Geo-Energy Frontier Forum”, this work summarizes recent advances in thermally assisted CO₂ huff-n-puff, supercritical CO₂ flow and multiscale CO₂ foam simulation, in-situ upgrading and thermal conversion, micro/nanobubble injection, dual geological-engineering sweet-spot identification, and shut-in optimization. The major bottleneck is no longer the lack of individual stimulation methods, but the insufficient integration among pore-scale mechanisms, fracture-matrix interactions, field-scale simulation, and carbon storage accounting. Future research should focus on mechanism-informed pilot design, lithology-specific upscaling models, CO₂-thermal-chemical coupled processes, and standardized evaluation workflows linking recovery efficiency with carbon sequestration performance.

Subsequent CO₂ injection can enhance oil recovery and achieve carbon sequestration in shale reservoirs, which is crucial for energy sustainability and environmental protection. However, for continental sedimentary shale oil, the development process must consider the multiscale matrix-fracture structure and the impact of heterogeneous wettability on fluid-solid interactions. Moreover, the mechanisms of CO₂ miscibility and interfacial behavior in post-fracturing reservoirs remain unclear. In this study, a laminated shale micro-model with fracture based on scanning electron microscopy observations was designed, and the process of fracturing fluid flowback and subsequent CO₂ huff-n-puff were simulated. Results showed that forced imbibition primarily affects limestone layers, while spontaneous imbibition affects mudstone layers, contributing 89.3% and 10.7% to the affected area, respectively. The oil recovery mechanism of CO₂ is mainly influenced by pressure, transfer from displacement-carry at low pressure to dissolution-extraction, and eventually to diffusion-extraction in the miscible state. Additionally, before reaching miscibility, Taylor dispersion, Kelvin-Helmholtz instability, Rayleigh-Taylor instability, and Marangoni effects occur at the oil-CO₂ interface, leading to interfacial turbulent instability. Lastly, water huff-n-puff produces membrane and isolated droplet residual oil, while immiscible CO₂ breaks cluster residual oil into columnar residual oil. Miscible CO₂ enhances the recovery of various residual oils, improving oil recovery and facilitating CO₂ storage. This study provides insights for post-fracturing CO₂ huff-n-puff development of continental sedimentary shale oil and CO₂ sequestration, promoting energy utilization and environmental improvement.

CO₂ dry fracturing is a promising alternative method to water fracturing in tight gas reservoirs, especially in water-scarce areas such as the Loess Plateau. The CO₂ flowback efficiency is a critical factor that affects the final gas production effect. However, there have been few studies focusing on the flowback characteristics after CO₂ dry fracturing. In this study, an extensive core-to-field scale study was conducted to investigate CO₂ flowback characteristics and CH₄ production behavior. Firstly, to investigate the impact of core properties and production conditions on CO₂ flowback, a series of laboratory experiments at the core scale were conducted. Then, the key factors affecting the flowback were analyzed using the grey correlation method based on field data. Finally, taking the construction parameters of Well S60 as an example, a dual-permeability model was used to characterize the different seepage fields in the matrix and fracture for tight gas reservoirs. The production parameters after CO₂ dry fracturing were then optimized. Experimental results demonstrate that CO₂ dry fracturing is more effective than slickwater fracturing, with a 9.2% increase in CH₄ recovery. The increase in core permeability plays a positive role in improving CH₄ production and CO₂ flowback. The soaking process is mainly affected by CO₂ diffusion, and the soaking time should be controlled within 12 h. Increasing the flowback pressure gradient results in a significant increase in both CH₄ recovery and CO₂ flowback efficiency. While, an increase in CO₂ injection is not conducive to CH₄ production and CO₂ flowback. Based on the experimental and field data, the important factors affecting flowback and production were comprehensively and effectively discussed. The results show that permeability is the most important factor, followed by porosity and effective thickness. Considering flowback efficiency and the influence of proppant reflux, the injection volume should be the minimum volume that meets the requirements for generating fractures. The soaking time should be short which is 1 day in this study, and the optimal bottom hole flowback pressure should be set at 10 MPa. This study aims to improve the understanding of CO₂ dry fracturing in tight gas reservoirs and provide valuable insights for optimizing the process parameters.