This paper takes three lithologies of shales， namely felsic shale， mixed shale， and clayey shale in the Qingshankou Formation in the Gulong Sag of the Songliao Basin as research objects， analyzes oil mobilization characteristics of the microscopic pore-throats through spontaneous oil and gas escape by natural energy as well as the synergistic effect of imbibition and CO2 huff-and-puff in laminated shale oil reservoirs， and explores suitable enhanced oil recovery （EOR） methods for shales. The full-scale pore structures were analyzed by combining high-pressure repeated mercury intrusion （HPRMI）， low-temperature N2， and CO2 adsorption experiments. The characteristics of depletion development were analyzed through the experiment of gas exhaust and oil extraction of pressure-maintained full-diameter shale cores. The mobilization characteristics of shale oil under the synergistic effect of imbibition and CO2 huff-and-puff were analyzed by integrating huff-and-puff experiments and online magnetic resonance imaging （NMR） scanning. The results indicate that macropore volume and the proportion of repeatedly mobilizable pores gradually decrease， and oil-gas escape capacity weakens in the order of felsic shale， mixed shale and clayey shale. Gas exhaust and oil extraction occur during the depressurization in pressure-maintained shale cores， with methane as the dominant gas component. The proportions of C2-C4 and C6-C20 components both increase with the extension of escape duration. The nano-scale pores and throats contributing greatly to oil recovery can be gradually mobilized through one cycle of imbibition huff-and-puff， followed by two cycles of CO2 huff-and-puff. For the three types of shales， the macropores of the felsic shale with a pore diameter larger than 100 nm have the largest pore volume， achieving the highest huff-and-puff recovery of 49.76%. The imbibition huff-puff mobilizes nano-scale and submicron-scale pores and throats larger than 5 nm. The mixed shale has the highest mesopore volume， mainly producing mesopores and adjacent macropores. In clayey shale， mesopores and micropores with pore diameters less than 15 nm are the most well-developed. The recovery increases evenly in each cycle of huff-and-puff， suggesting a relatively high potential for EOR.
The underground gas storage business in China is in a stage of rapid development， but the supporting intelligent construction is still in the exploratory phase. The industry has not reached a unified understanding of the top-level architectures， technical systems， and standards for intelligent gas storage construction. To explore the direction and technical feasibility of intelligent gas storage construction in China， after comparing the advanced construction models of intelligent gas storage both in China and abroad and considering the current information technology level and status of the oil and gas industry in China， a set of intelligent gas storage construction methods was formed and applied to the first intelligent gas storage construction project of PetroChina. Practice has shown that under the deep integration of new-generation information technology and gas storage business， intelligent gas storage in China can achieve visualization of production factors， controllable production processes， predictable operational risks， and multi-disciplinary collaboration， significantly improving the quality and efficiency of gas storage operation and management. This has formed key technologies and construction systems for intelligent gas storage， providing references and insights for the management upgrade and value growth of the gas storage industry， while also exploring a construction model and direction for the intelligent development of gas storage in China.
Breakthrough pressure of caprocks is a critical parameter for evaluating the sealing integrity of projects such as CO2 geological storage， geothermal resource development， and underground gas storage， and its accurate determination is essential for leakage risk assessment. However， existing methods for determining breakthrough pressure encompass multiple approaches， including laboratory testing， empirical formulas based on key controlling factors， and regional-scale inversion， resulting in a complex methodological system with varying applicability conditions that urgently requires systematic review and comparative analysis. This paper systematically reviews the methodological framework for determining breakthrough pressure from the laboratory to the regional scale. At the laboratory scale， methods include indirect techniques （e.g.， mercury intrusion porosimetry （MIP） and nuclear magnetic resonance （NMR） T2 spectrometry）， and direct techniques （e.g.， step-by-step， continuous， dynamic， impulse， and Racking methods）. Among these， the dynamic and Racking methods achieve a favorable balance between testing efficiency and accuracy， while the step-by-step method， though the most time-consuming， remains regarded as the “gold standard” for its highest accuracy. At the local scale， the key-controlling-factor method establishes empirical relationships between breakthrough pressure and permeability （via a log-log model）， porosity （via exponential， power-law， or quadratic functions）， and other parameters such as clay content， vitrinite reflectance， resistivity， pseudo-impedance， and NMR T2 relaxation time. The accuracy of this approach depends on the lithology and the appropriateness of the selected parameters. At the regional scale， inversion methods based on acoustic transit time （Δt） and interval velocity （Vc）， using the Dix formula， enable continuous prediction of breakthrough pressure from well points to basin scale. Comparative analysis indicates that each method has its own advantages and limitations in terms of accuracy， time consumption， and equipment requirements. Therefore， method selection should comprehensively consider lithological characteristics， study scale， and engineering demands. For mudstone and shale， porosity or clay content should be prioritized as the controlling factor； for sandstone， permeability proves to be the most effective indicator. For carbonate rocks， a multi-parameter fusion approach is recommended. Future efforts should further elucidate the influence mechanism of effective stress on test results， develop machine learning models that integrate multi-source parameters to enhance the accuracy and universality of the key-controlling-factor method， and promote the standardization of testing methodologies.
The Kalashayi Formation is the main hydrocarbon-generating interval of the Carboniferous strata in the southwestern Tarim Basin. This set of source rocks has been proven to be the main contributor to oil and gas fields such as Kekeya and Bashituopu， but its hydrocarbon generation potential and distribution are still unclear. Therefore， taking the carboniferous source rocks of the Kalashayi Formation in the southwestern Tarim Basin as the research object， this study focused on the investigation of organic geochemical characteristics， spatial distribution patterns， and the mechanism of organic matter enrichment， aiming to provide theoretical support for oil and gas exploration in the study area. The organic geochemical characteristics and distribution patterns of source rocks in the southwestern Tarim Basin were characterized by analyzing total organic carbon content and rock pyrolysis parameters， observing kerogen macerals， measuring vitrinite reflectance， and testing major and trace elements， combined with well logging and seismic data. Furthermore， the enrichment mechanism of organic matter in source rocks was discussed from the perspectives of paleoproductivity， paleoredox conditions， paleosalinity， paleoclimate and terrigenous clastic input. The results show that the Carboniferous source rocks of the Kalashayi Formation in the southwestern Tarim Basin are mainly dark mudstones， with an average TOC of about 1.0%. The organic matter is type Ⅱ-Ⅲ kerogen， dominated by type Ⅲ kerogen， and maturity increases progressively from the moderately mature stage in the Maigaiti Slope and Bachu Uplift to the high-to-overmature stage in the piedmont belt. Hydrocarbon source rocks of the Kalashayi Formation are dominated by lagoon-marsh facies deposits， which are distributed around Well Ma-6 in the Bachu Uplift， as well as in the Kashi Depression and the Heshilafu area within the piedmont belt. During the sedimentary period of the middle sandstone-mudstone section of the Kalashayi Formation， the paleoproductivity was high， and the sedimentary environment tended to be oxygen-poor or oxygen-deficient. Moreover， enhanced terrigenous clastic input introduces additional terrestrial organic matter. The enrichment of organic matter in the Carboniferous Kalashayi Formation across the southwestern Tarim Basin is collectively controlled by multiple factors， including paleoproductivity， redox conditions， paleoclimate， paleosalinity， and terrigenous clastic input. Notably， the middle sandstone-mudstone section represents the most favorable interval for organic matter enrichment， resulting from the combined effects of high paleoproductivity， anoxic to dysoxic conditions， and continuous terrestrial organic matter supply. This section constitutes a key target for hydrocarbon exploration in the study area.
During CO2 geological utilization and storage， CO2-water-rock interactions alter pore structures and physical properties of reservoirs， impacting CO2-enhanced oil recovery （EOR） and long-term storage stability. This study investigated the effects of CO2-water-rock interactions on the mineral composition and physical properties such as pore structures and overburden porosity and permeability of shale from the Permian Lucaogou Formation， Jimsar Sag， Junggar Basin by using qualitative and quantitative techniques （X-ray diffraction （XRD）， field emission scanning electron microscopy （FE-SEM）， low-temperature N2 adsorption test， and overburden porosity and permeability test）. The results show the following： ① The mineral composition of the Lucaogou Formation is dominated by clay minerals， quartz， plagioclase， and dolomite. After CO2/water immersion， potassium feldspar， plagioclase， and dolomite undergo significant dissolution， which results in a decrease in their relative content. In contrast， the relative content of clay minerals and quartz increases， which can be attributed to differences in mineral dissolution capacity and the formation of secondary minerals. ② Various pore types are developed in the Lucaogou Formation， with intergranular and intragranular dissolved pores being dominant. CO2/water immersion further enlarges the original pores and induces the formation of new pores and microfractures. ③ Under the combined effects of newly formed meso/micropores and the enlargement of original pores， the N2 adsorption capacity of the samples increases after CO2/water immersion. Meanwhile， the average pore diameter decreases， whereas the specific surface area and total pore volume increase. The fractal dimensions D1 and D2 also increase， indicating enhanced pore structure complexity. ④ Overall， dissolution is stronger than precipitation， which leads to increases in both porosity and permeability. However， under overburden pressure， the stress sensitivity of porosity and permeability is enhanced， and the hysteresis of porosity and permeability becomes more pronounced during the unloading stage.
