The geological storage of carbon dioxide (CO₂) is the most suitable option to achieve a large-scale and low-cost CO₂ emissions worldwide, but the selection of favorable areas for the geological storage is the main issue. In this study, evaluation indicators were selected considering four aspects, namely geological conditions, storage potential, hydrogeological conditions, and engineering conditions, based on drilling, geophysical, and geochemical data from the Beibu Gulf Basin. The analytical hierarchy process and the fuzzy comprehensive evaluation method were used to evaluate the suitability of this basin for geological storage of CO₂. The results suggested that: (1) the Beibu Gulf Basin is suitable for CO₂ geological storage, and the evaluation grade is the highest rating level; (2) considering the techno-economic feasibility, it is necessary to select the target area for CO₂ geological storage with suitable burial depth, superior reservoir conditions, proximity to the CO₂ collection device, and a high degree of exploration.

Carbon dioxide (CO₂) storage in underwater reservoirs is a valuable method of reducing carbon emissions. Saline aquifers such as those in the South Yellow Sea Basin (SYSB), China, have great potential for geological CO₂ storage. Thus, we use the recommended calculation method of USDOE and a formation volume model to determine the geological conditions for CO₂ storage and estimate the CO₂ storage capacity of the Cenozoic saline aquifers in the SYSB (depth: 800–3200 m). Overall, the SYSB exhibits weak fault activity and seismicity, medium and low geothermal fields, four types of source sandstone reservoir, and four sets of carbon reservoir–caprock assemblages developed from the Cenozoic strata, providing relatively good geological conditions for CO₂ storage. The estimated capacity of the Cenozoic strata ranges from 39.59 Gt to 426.94 Gt (average: 155.25 Gt), indicating an extensive storage capacity that can meet the carbon sequestration needs of Shandong and Jiangsu Provinces for approximately 89 years. The Yantai Depression has a lower geothermal gradient and terrestrial heat, weaker seismic activity, and double the storage capacity of the Qingdao Depression, indicating that it is the most suitable area for Cenozoic CO₂ storage in the SYSB, whereas the Laoshan Uplift is not suitable for storage. This study provides a scientific basis for the selection of offshore CO₂ storage sites.

Deepwater regions have emerged as pivotal domains for global oil and gas exploration and development, serving as strategic alternatives to conventional resources. The Silk Road region is distinguished by its abundant oil and gas reserves and stands as a leading arena for worldwide exploration and development in the oil and gas sector. Since 2012, a series of atmospheric fields have been discovered in the deep sea of the Luwuma Basin and the Tanzania Basin, with cumulative recoverable reserves reaching 4.4 × 10¹² and 8.3 × 10¹¹ m³, including multiple oil and gas fields ranking among the top ten global discoveries at that time. Profound advancements have been achieved in the exploration of deepwater oil and gas reserves along the Silk Road. However, deepwater oil and gas exploration presents challenges, such as high development costs and risks, leading to certain areas remaining underexplored and exhibiting a relatively low level of exploration activity, thereby hinting at considerable untapped potential. Deepwater sedimentary basins along the Silk Road predominantly adhere to a distribution pattern characterized as “one horizontal and one vertical”. The “horizontal” dimension refers to the deepwater basin grouping within the Neo-Tethys tectonic domain, primarily extending from east to west. Conversely, the “vertical” dimension denotes the deepwater basin grouping along the East African continental margin, predominantly extending from north to south. Recent discoveries of deepwater oil and gas reserves validate the presence of foundational elements within Silk Road basins conducive to the formation of substantial oil and gas reservoirs and the establishment of efficient migration pathways. Despite these achievements, exploration activities in deepwater oil and gas resources along the Silk Road remain relatively limited. Future exploration endeavors in deepwater regions will predominantly focus on identifying structural and lithological traps. In the deepwater areas of the Bay of Bengal, the emphasis is on lithological traps formed by Neogene turbidite sandstone deposits. In the deepwater regions of Pakistan, the focus shifts to lithological traps emerging from Neogene bio-reefs and river-channel sandstone accumulations. Along the deepwater coastline of East Africa, the focus is on lithological traps formed by nearshore Mesozoic–Cenozoic bio-reefs and seafloor turbidite sandstone formations. Within the deepwater regions of Southeast Asia, the primary objective is to locate large structural-type oil and gas fields. Analyzing the characteristics of oil and gas discoveries in deepwater areas aims to enhance the theory of the control of the formation of deepwater oil and gas, providing valuable insights for predicting future exploration directions.

The Upper Permian Longtan Formation in the Laoshan Uplift of the South Yellow Sea Basin hosts thick and distinctive tight sandstones. However, a comprehensive understanding of its pore structure and reservoir classification remains lacking. This study investigates the fully cored well, CSDP-2, utilizing thin section analysis, scanning electron microscopy, energy spectrum analysis, X-ray diffraction, high-pressure mercury intrusion, and nuclear magnetic resonance to characterize its petrophysical properties, pore space, and movable fluid characteristics. Additionally, fractal principles are further employed to examine reservoir heterogeneity and conduct a quantitative assessment, considering the complexity of tight sandstone pore structures. The findings reveal that the sandstones predominantly comprise feldspathic litharenites, with an average porosity of 1.567% and permeability of 0.099 mD, primarily containing intragranular pores. Two distinct sets of pores with significantly different sizes (r < 2 μm; r > 6 μm) were identified, displaying relatively high fractal dimensions and discrete distribution. Movable fluids primarily occupy pores with radii > 0.019 μm, reflecting pronounced overall heterogeneity. The reservoir was classified into three categories utilizing permeability, median radius, and movable fluid saturation as key evaluation parameters, with Class I representing a relatively high-quality reservoir. These findings advance our understanding of the pore development mechanism of tight sandstone reservoirs and provide geological evidence for further hydrocarbon exploration in this study area.

The geological storage of carbon dioxide (CO₂) in offshore saline aquifers stands as a primary option for reducing CO₂ emissions in coastal regions. China’s coastal regions, particularly Shandong and Jiangsu provinces, face significant challenges in CO₂ reduction. Therefore, evaluating the feasibility of CO₂ geological storage in the adjacent seas is critical. To assess the suitability of a CO₂ storage site, understanding its structural and reservoir characteristics is essential to mitigate injection and storage risks. In this study, we analyzed the structural characteristics and potential traps of the Yantai Depression in the South Yellow Sea Basin based on seismic data interpretation. We further conducted well logging analysis and post-stack seismic inversion to obtain lithological data, including acoustic impedance and sandstone content percentages from the Cenozoic Funing Formation, Dainan–Sanduo Formation, and Yancheng Formation. Our findings highlight that the Yantai Depression in the South Yellow Sea Basin exhibits diverse structural traps and favorable reservoir–caprock combinations, suggesting promising geological conditions for CO₂ storage. This area emerges as a suitable candidate for implementing CO₂ geological storage initiatives.

Carbon Capture, Utilization and Storage-Enhanced Oil Recovery (CCUS-EOR) technology can effectively improve crude oil recovery while simultaneously sequestering CO ₂ in geological formations to reduce emissions. The distribution and migration patterns of oil and gas in reservoir rock masses remain one of the key issues worthy of study, among which CO ₂ -oil displacement experiments are the most direct research method. Nuclear Magnetic Resonance (NMR) provides technical assurance for the visualization and quantification of displacement experiments. Different from previous studies, we selected experimental cores based on their pore characteristics and optimized the experimental scheme. Strictly controlled single variables were used to determine the effects of various factors, including injection pressure, temperature, pore structure, permeability, and crude oil viscosity, on CO₂ flooding efficiency. An in-depth analysis of the oil and gas migration mechanisms during CO ₂ flooding was conducted using T ₂ relaxation spectra and oil-filled porosity distribution maps. The study identified oil recovery has nonlinear relationship with injection pressure and near-linear relationships with temperature, compared the displacement differences between medium and high viscosity oils, and revealed the dominant role of pore structure on oil recovery effectiveness. It is worth noting that the order-of-magnitude change in permeability did not significantly improve oil recovery, which is quite different from previous studies.