The lower member of the Middle Jurassic Xishanyao Formation (J₂x¹⁺²) sandstones are significant exploratory targets for hydrocarbon resources in the Taibei Sag of the Turpan-Hami Basin, northwestern China. Formation of anomalously high porosity/permeability in deeply buried J₂x¹⁺² sandstones and reservoir quality prediction were investigated using a variety of petrographic analyses. These results show that the J₂x¹⁺² sandstones are mostly feldspathic litharenites and litharenites, which are characterized by moderate-to good sorting, silty to medium granularity, and point- to long grain contacts. The J₂x¹⁺² sandstone has low porosity (avg 6.0%) and permeability (avg 1.12 mD), but shows anomalously high porosity/permeability at depth interval of 3850–4050 m. There is a noticeable variation in pore types and sizes from intergranular-intragranular dissolution pores with a size mode of 2.0 μm in anomalously high porosity (AHP) sandstones, to major intragranular dissolution pores with a size mode of 0.5 μm in normally high porosity (NHP) sandstones, to most micropores with a size mode of 0.25 μm occurred in the normally low porosity (NLP) sandstones. The compaction is the main cause of porosity destruction, resulting in an average porosity loss of 89.6%. However, the authigenic minerals have relatively little influence on reservoir quality. The combination of nappe tectonics and well-sorted particles alleviated the compaction and thus preserved more intergranular pores in the AHP sandstones. Dissolution further increases the porosity and eventually forms the AHP sandstones. The strong carbonate-cemented facies (SCC), tightly compacted facies (TC), moderately compacted with moderate dissolution facies (MCMD), and weakly compacted with strong dissolution facies (WCSD) are determined in the J₂x¹⁺² sandstones. The sandstones with SCC and TC are recognized as the NLP reservoirs. The MCMD and WCSD correspond to the NHP and AHP reservoirs, respectively. The reservoir quality predicted using the constructed diagenetic facies charts is in good agreement with the photomicrograph observations and physical property tests. Additionally, the AHP reservoirs are still developed in the deeply buried sandstones with depths larger than 4000 m.

Caprock sealing capacity is paramount for the safety and efficacy of geological carbon storage. This study investigates the evolution of mudstone caprock sealing capacity under CO₂–mechanical coupling, integrating experimental rock mechanics with fluid–solid coupling numerical simulations. Laboratory experiments reveal that caprock permeability exhibits strong stress sensitivity, decreasing exponentially with increasing effective stress. The stress sensitivity coefficient is highly dependent on initial pore pressure and porosity, being greatest under low-pore-pressure and high-porosity conditions. Furthermore, permeability loss during loading is partially irreversible due to plastic deformation. Numerical simulations, conducted using an integrated Petrel + Visage + Eclipse workflow, quantify the influence of caprock physical and mechanical properties on sealing capacity during CO₂ injection. The results demonstrate that vertical total stress increases with increasing porosity, Young’s modulus, and permeability, with permeability exerting the most significant control. Conversely, vertical effective stress decreases with increases in these parameters, with porosity causing the largest variation. We conclude that lower caprock permeability and porosity are most critical for enhancing sealing integrity, while a higher Young’s modulus improves mechanical stability. These findings provide a theoretical basis and practical methodology for evaluating caprock sealing capacity and ensuring the secure storage of CO₂.

Automatic bedding extraction from borehole images of shale beddings and cross beddings is essential for reducing labor-intensive manual tasks. Three main types of algorithms, including Autodip, Random Hough Transform (RHT), and Pairing Algorithm Based Detection (PABD), have been proposed in the past decades but have never been directly compared. In this study, we first propose a novel method integrating a heuristic genetic algorithm (Autodip integrate with Genetic Algorithm, ADGA) to overcome the low efficiency of the Autodip algorithm. This method improves the efficiency by a factor of 3, and even by a factor of 21 with the addition of automatic constraints, while maintaining the advantages of high accuracy. Furthermore, to verify the effectiveness of the improved algorithm, all extraction algorithms are compared and analyzed systematically for the first time. The results demonstrate that three algorithms have presented their unique advantages and adaptability. The ADGA has the best stability, extraction accuracy, and image fitness for shale beddings. The PBAD algorithm shows its superiority in cross-bedding. The RHT has the best efficiency with moderate stability. In addition, the extraction results produced by RHT are of poor quality for images with high density and low amplitude bedding (less than about 10 pixels) due to the inadequate performance of the structure tensor image processing. This research will significantly promote the future development of automatic bedding extraction algorithms for industrial applications.

In natural micro-nanoscale porous media, the movable fluid porosity can effectively represent storage and permeable properties, but various mineral compositions have complicated effects on it. Taking saline lacustrine shale as an example, this study researched the effects of mineral composition on movable fluid porosity, based on nuclear magnetic resonance (NMR), focused ion beam (FIB), and x-ray diffraction (XRD) experiments. The results show that movable fluid porosity exhibits a stronger dependence on porosity than movable fluid saturation does. Micropores (1000 nm) are mostly developed in silicate and gypsum minerals, and have a highly heterogeneous distribution. In contrast, carbonate intercrystalline pores are dominated by mesopores (100−1000 nm), and behave strongly heterogeneously. Many mesopores play a positive role in generating highly movable fluid porosity, but the development of micropores and macropores is not conducive to an increase in movable fluid porosity. Overall, a significant negative effect is observed between silicate mineral content and movable fluid porosity, and carbonate mineral content has a strong positive effect on movable fluid porosity, whereas movable fluid porosity exhibits a relatively small reduction with an increase in the gypsum.