## 5 Conclusions  
Integrated tests of FE-SEM imaging, isothermal methane adsorption at different temperatures and pressures, and NMR experiments of saturated methane at different temperatures and pressures were conducted on the shale cores at the same layers but at different burial depths in the southern Sichuan Basin in China. After reaching the maximum burial depth, the shale reservoir gradually uplifts to its current burial depth as a result of different tectonic processes, and the pore structure and gas content evolve accordingly. As the shale reservoir rises upwards, the pressure of the overlying strata gradually decreases, and a large number of inorganic pores and microfractures are formed and expand during the pressure-release process. However, under the influence of the pressure difference between the regions inside and outside the OM pores, as well as the surface tension of OM, the OM pores first expand from 50-200 nm to 200-500 nm. After the pressure difference between the regions inside and outside the pores exceeds the surface tension of the OM, OM pores with large pore sizes rupture and then fuse with pinholes to form a network-like feature with pore sizes smaller than 50 nm. A method of isothermal methane adsorption onto powder-sized samples was used to test the adsorbed gas content, along with an NMR method employing saturated methane on plug-sized samples to test the free gas content. As the burial depth of the shale reservoirs decreased from 4200 m to 1000 m, the total gas content decreased from 18.88 m\({}^{3}\)/t to 6.91 m\({}^{3}\)/t, and the proportion of free gas decreased from 84.47% to 36.82%. The reason for this is that during the process of shale reservoir uplift, the inorganic pores and microfractures expand, resulting in the weakening of the self-sealing ability of shale reservoirs and the escape of free gas, leading to a decrease in total gas content. At the same time, an increase in the complexity of the organic pores provides more adsorption sites for methane molecules, leading to shale gas mainly being present in an adsorption state, accounting for about 60% under low formation temperature (60 \({}^{\circ}\)C) conditions. According to the new methods that we have established, the prediction results indicate that free gas dominates at deeper burial depths in shale reservoirs with a porosity of 6%, accounting for about 80% at 4500 m; in addition, the total gas content is 18.89 m\({}^{3}\)/t, which is much larger than the values yielded by traditional prediction models (9.21 m\({}^{3}\)/t). The high gas content in deep shale reservoirs may be attributed to confinement effects and the sustained generation of organic-matter hydrocarbons. However, the temperature (<100 \({}^{\circ}\)C) and pressure (30 MPa) for studying the confinement effect are relatively low, far lower than the formation temperature (140 \({}^{\circ}\)C) and pressure (65 MPa) of deep shale reservoirs. Therefore, the confinement effect and methane phase state under high-temperature and high-pressure conditions represent important research directions in the future. At the same time, there is a lack of research on time compensation for the sustained hydrocarbon generation of shale organic matter under deep burial conditions. Therefore, our research results not only strengthen belief in the high yield of deep shale gas but also provide a direction for the geological development research of deep shale gas. Conceptualization, Y.F. and Y.G. ; methodology, R.Z. ; validation, Y.J. ; formal analysis, Y.F. ; investigation, X.F. and Y.G. ; data curation, Y.F. ; writing--original draft preparation, Y.F. and Y.G. ; writing--review and editing, Y.F. and R.Z. ; visualization, Y.F. ; supervision, Y.J. ; project administration, Y.J. All authors have read and agreed to the published version of the manuscript. **Funding:** The research was supported by the National Natural Science Foundation of China (No. 42272171), the Science and Technology Cooperation Program of CNPC\(-\)SWPU Innovation Alliance (No.