Abstract: To address the water lock effect induced by imbibition during hydraulic fracturing in shale gas reservoirs, the regulatory mechanisms of CO₂ phase states (gaseous CO₂ and supercritical CO₂) on pore structure and imbibition behavior in shale-water coupled systems are systematically investigated. Core samples from the Longmaxi Formation shale in the Sichuan Basin, deposited in shallow to deep-water shelf facies, are selected and subjected to four pretreatment conditions: untreated, hydration, G-CO₂-H₂O-shale coupling, and SC-CO₂-H₂O-shale coupling. By integrating low-temperature nitrogen adsorption, nuclear magnetic resonance (NMR), scanning electron microscopy (SEM), and ambient-pressure imbibition experiments, the evolution of pore structure is quantitatively characterized, and a quantitative relationship model between imbibition kinetics and pore parameters is established. The results show that: G-CO₂ treatment significantly reduces micro-mesopore volume and greatly enhances pore connectivity, while SC-CO₂ treatment simultaneously enlarges multiscale pores and induces macroscopic fractures, but leads to a notable decrease in specific surface area. G-CO₂ treatment yields the highest imbibition volume and rate, demonstrating the best potential for mitigating water lock; SC-CO₂ treatment increases imbibition volume by 24.6%, yet the imbibition efficiency decreased due to the expansion of hydration and compression of micropore volume. Analysis of imbibition kinetics reveals that the rate during the spontaneous imbibition stage is controlled by hydrophilicity and the volume fraction of P_Mic pores (pore size <  50 nm), whereas the rate in the diffusion stage correlates positively with pore connectivity and specific surface area. Phase state of CO₂ can actively regulate shale imbibition behavior through differentiated pore-structure modification. The imbibition-kinetics pore model provides a quantitative tool for fracturing design and flowback regulation. Furthermore, a process concept of composite fracturing combined with G-CO₂ injection for CH₄ displacement is proposed, wherein SC-CO₂ can be applied to suppress excessive fracturing-fluid imbibition and promote flowback, while G-CO₂ is used to enhance subsequent imbibition displacement and reservoir stimulation. This approach offers a new technical pathway for efficient shale-gas development coupled with CO₂ storage.