Describing the organic-inorganic pore evolution influenced by mineral composition is crucial for characterizing shale oil storage capacity and flow in shale, and it also helps predict storage capacity for sequestered CO₂. Using laboratory pyrolysis experiments to artificially mature shale samples at relatively high temperatures and short times, this study compares a series of natural samples with different thermal maturations, which can better reflect the real underground pore evolution. A total of 30 natural shales spanning from low to high maturity were collected from the Cretaceous Qingshankou Formation of the Songliao Basin, and the analysis results revealed four main typical shales, namely argillaceous shale, felsic shale, calcareous shale, and mixed shale. The existence of clay minerals, quartz and feldspar promote the development of > 50 nm pores, while 0-20 nm pores are mainly developed in clay minerals and organic matter. When the content of total organic carbon is less than 2.5 wt.%, it displays a positive correlation with the specific surface area, but the correlation becomes negative for samples with a content of total organic carbon greater than 2.5 wt.%. The organic pores are most developed at the peak oil maturity, while inorganic pores are most developed during the oil window, and tend to be stable at high maturity. Argillaceous shale in the high maturity stage may be favorable for petroleum exploration in the Qingshankou Formation of the Songliao Basin. Mixed shale and calcareous shale may not be conducive to the short-term storage of CO₂ due to strong reactions with CO₂ at the beginning. On the other hand, argillaceous shale and felsic shale may be conducive to the long-term storage of CO₂.

Herein, a method of physical modeling of CO₂-brine-rock interaction and characterization of mineral and pore evolution at in-situ conditions is established. The nested preparation and installation of the same sample with different sizes could protect and keep the integrality of the millimeter-size sample in conventional high-temperature and high-pressure reactors. This paper establishes a procedure to obtain the three-dimensional comparison of minerals and pores before and after the reaction at in-situ conditions. The resolution is updated from 5-10 $\mu$m to 10 nm, which could be helpful for modeling CO₂-brine-rock interaction in unconventional tight reservoirs. This method could be applied to CO₂-enhanced oil recovery as well as CO₂ capture, utilization, and storage scientific research. Furthermore, it may shed light on the carbon sequestration schemes in the Chinese petroleum industry.