Based on new understandings of the whole petroleum system theory for coal measures, and utilizing data from coal-rock gas wells and other oil and gas wells in numerous pilot test areas for key parameter validation, this study conducted a national resource assessment of coal-rock gas widely developed in marine-continental transitional and continental strata in major petroliferous basins like Ordos, Sichuan and Junggar in China. The main achievements and understandings were obtained as follows. (1) A resource evaluation methodology for coal-rock gas was established, incorporating varying geological/data conditions. (2) Key parameter thresholds for deep coal-rock gas resource evaluation were defined, including the upper limits of critical depth (1 500, 2 000, 2 500 m), lower limit of reservoir thickness (1 m), and lower limits of gas content in medium-low rank and medium-high rank coals (2, 10 m³/t), depending on varying geological conditions across basins. (3) Methods for determining key parameters such as gas content, porosity, and technical recovery factor were developed using the basic data from coal-rock gas experiments/tests and logging. (4) Evaluation results indicate that the geological resources of coal-rock gas in the 14 major basins of onshore China amount to 55.11×10¹² m³. Resources at depths of 1 500-3 000, 3 000-5 000, 5 000-6 000 m account for 50.29%, 43.11%, 6.60% of the total, respectively. Resource classification shows that Class I, II, and III resources constitute 21.80%, 32.76%, 45.44%, with the Class I and II technically recoverable resources of approximately 13.23×10¹² m³. (5) The Ordos Basin remains the most favorable province, while the Sichuan, Junggar and Tarim basins are the promising targets, for future exploration and development of coal-rock gas in the country. Other basins including Bohai Bay, Qaidam, Tuha, Songliao and Hailar are considered as prospective options. Coal-rock gas production is expected to reach 500×10⁸ m³ annually within the next 10-15 years, positioning it as a major contributor to the natural gas production growth of China and a crucial alternative resource for ensuring the national gas supply.

The traditional binary hydrocarbon-generation patterns are inadequate for accurately evaluating the hydrocarbon- generation potential of different types of source rocks in the Permian Pusige Formation in the piedmont of southwestern Tarim Basin, especially the resource potential of light oil and condensate. We selected the Pusige Formation source rocks from the piedmont of southwestern Tarim Basin to conduct closed gold tube pyrolysis experiments, recovered the hydrocarbon-generation process under geological conditions using the method of hydrocarbon-generation kinetics, and established multi-component hydrocarbon-generation patterns of source rocks with three quality levels. The results show that the total hydrocarbon yields of good (TOC = 1.35%), fair (TOC = 0.70%), and poor (TOC = 0.24%) source rocks are 648, 236 and 108 mg/g, respectively. The good source rock shows more concentrate oil-generation process, while fair source rock has stronger dry gas potential at the high-maturity stage. Furthermore, based on the characteristics of hydrocarbon generation of the Pusige Formation source rocks, the formation and evolution of oil and gas can be divided into the immature, and heavy hydrocarbon, light hydrocarbon, wet gas, and dry gas generation stages. The proposed multi-component hydrocarbon-generation patterns are used to evaluate the hydrocarbon-generation potential and resources of different reservoirs. The resources of heavy oil, light oil, wet gas, and dry gas generated by the Pusige Formation source rocks in the study area are estimated to be 225×10⁸ t, 150×10⁸ t, 3×10¹² m³ and 6×10¹² m³, respectively. The Pusige Formation source rocks in the piedmont of southwestern Tarim Basin exhibit great hydrocarbon-generation potential, providing the material foundation for forming large oil and gas fields. This area rich in light resources is promising for future petroleum exploration, and it is expected to become a national resource strategic base in China.

Under the guidance of the whole petroleum system theory, using seismic, drilling and laboratory analysis data, and combined with the practical achievements of oil and gas exploration, the distribution patterns of different types of natural gas in the deep-water area of the Qiongdongnan Basin of China were systematically reviewed, the orderly symbiosis mechanisms and hydrocarbon accumulation processes of diverse gas reservoirs were analyzed, and a composite whole petroleum system model for the deep-water strongly active basins in the northern South China Sea was constructed. In the deep-water area of the Qiongdongnan Basin, there are three sets of source rocks, namely the Eocene, the Oligocene, and the upper Miocene-Quaternary, and three whole petroleum systems can be accordingly classified. The source rocks have the characteristics of multilayers, multiple types, and multiple hydrocarbon generation centers. The Eocene lacustrine source rocks, Oligocene marine and continental dual-origin source rocks, and upper Miocene-Quaternary marine source rocks form multiple hydrocarbon generation centers, which are orderly distributed from east to west. The reservoirs are characterized by multiple geological ages, multiple rock types, and multiple hydrodynamic influences, and exist as a reservoir composite superposition pattern with basement buried hill-lower traction flow sandbody-upper gravity flow sandbody vertically in the deep-water area. Fluid activities within the basin are controlled by free dynamic fields, confined dynamic fields, and bound dynamic fields. The natural gas in the whole petroleum system presents an orderly distribution of shale gas (speculated)-tight gas-conventional gas-ultra-shallow gas-hydrate from bottom to top. The research results have verified the adaptability of the whole petroleum system theory in the deep-water area of the Qiongdongnan Basin, providing a theoretical support for the exploration of complex oil and gas resources in the deep-water area, and are expected to effectively guide the distribution prediction and exploration of different types of petroleum resources in deep-water areas.

Using the latest global datasets of hydrocarbon fields and reservoirs, this study systematically investigates the characteristics of differential hydrocarbon enrichment and its primary controlling factors in the southern Tethys Domain within the context of Tethys tectonic evolution. The results indicate that although the southern Tethys Domain comprises only one-third of the Tethys Domain in areal extent, it hosts nearly 80% of its total hydrocarbon reserves, exhibiting a markedly uneven distribution pattern. Specifically, the Middle East sub-segment is identified as the core enrichment area, with the Arabian Basin serving as a typical example. Through tectonic subdivision, classification of sedimentary basins, analysis of source rock distribution and reservoir-seal assemblages, as well as an integrated investigation of the relationship between succeeding paleo-uplifts and hydrocarbon enrichment, the study demonstrates that the superimposition patterns of prototype basins, the scale and distribution of source rocks, the effectiveness of reservoir-seal assemblages, and the basement paleo-uplifts are the key factors governing hydrocarbon enrichment in the southern Tethys Domain. The findings of this study provide valuable references for deeper understanding of hydrocarbon accumulation patterns in the central and northern Tethys Domain and even other global regions with similar geological settings, and offer a scientific basis for selection of favorable play fairways in the southern Tethys Domain.

To clarify the main enrichment-controlling factors and accumulation mechanisms of shale gas in the Permian Dalong Formation within the Western Hubei-Eastern Chongqing complex structural zone, this study systematically reveals the enrichment patterns and accumulation model through analysis of typical drilling data, geochemical testing, scanning electron microscopy (SEM), methane isothermal adsorption experiments, numerical simulations, and research on tectonic evolution and preservation condition. The results are obtained in two aspects. First, the enrichment of shale gas in the Dalong Formation is synergistically controlled by four factors, i.e. rift troughs controlling shale development, provenance controlling reservoir heterogeneity, temperature and pressure controlling gas occurrence, and structure controlling differential enrichment. The geometry and scale of rift troughs (Chengkou-Western Hubei, and Kaijiang-Liangping) determine the development of organic-rich shale (average TOC>6%, thickness of 15-50 m). Multi-source materials lead to strong heterogeneity of the reservoir, with endogenous minerals as the main component (accounting for 74.31%), and the pores mainly organic matter pores (micropores and mesopores accounting for 93.4%). The formation temperature and pressure control the occurrence state of shale gas, with adsorbed gas (higher than 50%) dominantly in 500-2 750 m depth, while free gas (higher than 50%) prevailing at depth deeper than 2 750 m depth. The uplift, erosion, and fault systems associated with the Yanshanian tectonic activity result in differential enrichment of shale gas, with three structural styles—broad gentle anticlines, residual synclines, and low gentle slopes—exhibiting relatively high shale gas enrichment. Second, the self-sealing mechanism of medium-shallow shale gas in the Western Hubei-Eastern Chongqing complex structural zone is revealed. Specifically, the Dalong Formation shale aquifer forms a lateral seal for shale gas in the downdip direction via water films and capillary forces, and it combines with the overlying Daye Formation limestone and underlying Xiayao Formation tight layers to establish a synclinal/monoclinal self-sealing accumulation model. The geological insights, such as “four-factor synergistic control” and self-sealing accumulation model, provide a dynamic coupling evaluation framework for shale gas in complex structural zones, promoting the transition of shale gas exploration and evaluation from static descriptions to integrated reservoir-tectonic-fluid analysis.

The well deployment in the Ordovician Yingshan Formation in the Gucheng area of the Tarim Basin mainly focuses on the inner gentle slope in the western part of the study area, which results in a low drilling success rate. To address this issue, this study focused on reconstructing sedimentary models and the adjustment strategies for oil and gas exploration. The carbonate sedimentary model of the Yingshan Formation was re-evaluated using the data of seismic interpretation, core observations, thin-section analyses, carbon isotopic composition, well logging, detrital zircon U-Pb dating, and carbonate mineral U-Pb dating. Then, the favorable sedimentary facies belts were delineated, and updated prospective exploration targets were proposed. The results demonstrate that the sedimentary model of the Yingshan Formation in the Gucheng area is characterized as a rimmed platform system, exhibiting an orderly west-to-east sedimentary sequence transition from restricted/open platform environments through the platform margin and slope settings, ultimately grading into basinal deposits. The platform margin, distinguished by thick successions of grain shoals overlain by interlayered karst zones, is the most favorable distribution area for large-scale reservoirs. Guided by this revised sedimentary model, Well Gutan-1 was successfully drilled within the outer platform margin, encountering over 90% high-energy grain shoal facies with well-developed porous and fractured-vuggy reservoirs, and achieving industrial oil and gas flow. It is confirmed that the platform margin is the priority area for oil and gas exploration in the Ordovician System of the Gucheng area, thereby effectively ending the prolonged exploration stagnation in the Yingshan Formation of the Gucheng area.

Taking the shale of the second member of the Paleogene Funing Formation in the Qintong Sag, Subei Basin, China, as an example, this study integrates methods such as rock section imaging, optical and electron microscopy, micro-area mineral analysis and laser confocal in-situ observation, assisted by Wood’s alloy impregnation and other auxiliary techniques, to systematically investigate lamina types and combinations, pore-fracture units and fracture systems, hydrocarbon occurrence and shale oil enrichment patterns. The following results are obtained. (1) Three basic lamina types, i.e. felsic, clay-rich, and carbonate, are identified in the study area. Their combinations are controlled by the interplay of climate, hydrodynamics, and tectonics, with vertical distribution influenced by lake-level fluctuations and event sedimentation. (2) Reservoir space is controlled by lithological composition, predominantly comprising intergranular pores and fractures within felsic laminae and intercrystalline pores and fractures within clay-rich laminae, which together with dissolution pores and organic matter pores form a matrix pore-fracture system. This system, combined with bedding fractures, structural fractures, and overpressure fractures, constitutes a hierarchical and three-dimensional transport network. (3) The “felsic + clay-rich + organic-rich” lamina combination exhibits an optimal pore-fracture configuration, serving as the preferred shale oil reservoir unit, continuously distributed in sub-members I-II. (4) A “hierarchical migration - dynamic sealing” in-source enrichment model is established. Specifically, hydrocarbon generation in clay-rich laminae creates overpressure, driving migration through nanoscale pore-fracture networks and forming localized accumulations; subsequent fracture formation from overpressure breaches lamina interfaces, allowing hydrocarbons to migrate under capillary pressure into micrometer-scale porous domains in felsic laminae; structural fractures connect multiple laminae to form a 3D seepage system, while cementation zones associated with micro-faults and lamina interfaces create dynamic sealing. Ultimately, shale oil accumulates in source via the coupling of pores, fractures and laminae.

Focusing on the geochronological issues related to the matching relationship between the strike-slip fault activity and the stages of hydrocarbon generation, reservoir formation, and hydrocarbon accumulation, this study aims to quantitatively constrain the tectonic-burial history, hydrocarbon generation history, reservoir porosity evolution history, and hydrocarbon accumulation history by determining the isotopic ages and temperatures of multiphase calcites (particularly the calcites which contain hydrocarbon-bearing fluid inclusions) and quartzs filling the fractures in the Ordovician strata within the non-foreland area of Tarim Basin. Three major findings have been obtained. (1) According to the tectonic-burial history restored under the constraint of the isotopic ages and temperatures, the non-foreland area of the Tarim Basin experienced a continuous burial process during the Cambrian-Ordovician period, with only a minor uplift at the end of the Silurian. Overall, the area was characterized by continuous hydrocarbon generation and a gradual increase in vitrinite reflectance (R_o). (2) While mechanical compaction and pressure-solution during burial progressively reduced the matrix porosity, the strike-slip fault activity during the Middle Caledonian II and III episodes induced physical fragmentation, which created extensive interbreccia pores, fault cavities, and structural fractures as seepage pathways for surface runoff, and, in conjunction with interlayer karstification, led to the development of widespread dissolution vugs. The formation of fracture-vug system in the Ordovician limestone provided effective storage space for hydrocarbons generated during the Late Caledonian and subsequent periods. (3) The Ordovician fault-karst limestone reservoirs underwent four stages of hydrocarbon accumulation: low-medium maturity liquid hydrocarbons during the Middle-Late Caledonian, medium-high maturity liquid hydrocarbons during the Middle-Late Hercynian, high maturity liquid hydrocarbons during the Indosinian, and high-over maturity gas during the Middle Yanshanian. Variations in hydrocarbon accumulation among different strike-slip faults or different segments of the same fault are controlled by differences in source rock maturity across structural units, as well as by the timing of fault activity and fault-related connectivity to hydrocarbon sources. This research also establishes a geochronological framework for investigating strike-slip fault- controlled reservoir formation and hydrocarbon accumulation, facilitating a more accurate determination of the reservoir formation and hydrocarbon accumulation stages, and providing critical insights for evaluating hydrocarbon enrichment zones in fault-controlled reservoirs.

To address the unclear permeability evolution mechanisms during in-situ conversion of deep continental shale, this study employs a pioneering online THMC (thermo-hydro-mechanical-chemical)-CT coupled experimental system to investigate the permeability evolution, dynamic pore-fracture structural responses, and hydrocarbon production behavior under high-temperature and high-stress conditions. The results show that: (1) Under high stress constraints (axial/confining stresses of 50/25, 100/50 MPa), shale permeability exhibits a three-stage evolution with increasing temperature, including a low-permeability stage (25-350 °C), a rapid-increase stage (350-450 °C), and a significant-decrease stage (450-600 °C). (2) Under coupled in-situ stress (25/20 MPa axial/confining stress) and temperature, fractures undergo a dynamic “two-expansion and two-contraction” process, where the first expansion (25-300 °C) and first contraction (300-350 °C) correspond to the low-permeability stage, the second expansion (350-450 °C) corresponds to the rapid-increase stage, and the second contraction (450-550 °C) corresponds to the significant-decrease stage. (3) The controlling mechanisms at each stage are as follows: at temperatures up to 350 °C, the maximum yield of retained oil and the filling of heavy hydrocarbons in pores and fractures result in reduced permeability. Between 350 °C and 450 °C, thermal cracking and kerogen decomposition jointly enhance pore-fracture network development. Above 450 °C, illitization of clay minerals, matrix plastic deformation, and fracture closure under stress result in permeability reduction. These findings clarify the staged permeability behavior and associated mechanisms, providing essential theoretical and experimental support for the temperature-stress synergistic optimization of in-situ shale oil conversion processes.

Based on the data of reservoir rock cores and 3D seismic inversion for reservoir, a comprehensive analysis was conducted using in-situ U-Pb dating of calcite cements, fluid inclusions, and geochemical data of fractured-vuggy reservoirs to investigate the key controls on the formation of reservoirs along the ultra-deep strike-slip fault zone in the depression, northern Tarim Basin, and establish the reservoir development model. The Middle Ordovician Yijianfang Formation contains tight matrix reservoirs and strike-slip faults with small displacement but relatively wide damage zone, forming a series of fault-fracture and fault-karst reservoirs which are distributed contiguously along the fault zone. Strike-slip faulting occurred during the deposition of the Yijianfang Formation, giving rise to penecontemporaneous atmospheric freshwater dissolved pores/vugs. The U-Pb ages of 440-468 Ma obtained from calcite cements in the fractures/vugs indicate that the reservoirs along the strike-slip fault zone were formed in Middle to Late Ordovician. Data of reservoir fluid inclusions, trace elements, and C/O/Sr isotopic compositions suggest that the fracture/vug cementation and filling took place in a penecontemporaneous to shallow burial stages dominated by atmospheric freshwater. On the basis of intra-platform high-energy shoal deposits, strike-slip faulting coupled with dissolution is identified as the primary control on reservoir formation and spatial distribution, and a penecontemporaneous-shallow burial strike-slip fault-controlled reservoir development model is thus proposed. Comprehensive analysis indicates that large-scale fault-fracture and fault-karst reservoirs can develop along ultra-deep strike-slip fault zone in intracratonic depression, with their scales and distribution scope controlled by the coupling of facies, faulting, and dissolution processes in the penecontemporaneous-shallow burial stages.

The faults and associated fracture zones in the tight sandstone reservoirs of the fifth member of the Triassic Xujiahe Formation (Xu-5 Member) in the Wubaochang area, northeastern Sichuan Basin, play a critical role in controlling gas well productivity. To delineate the distribution patterns of the faults and associated fracture zones in this area, a transfer-trained convolutional neural network (CNN) model and an XGBoost (eXtreme Gradient Boosting)-based intelligent seismic attribute fusion method were employed to identify faults and fracture zones, respectively, enabling precise characterization of their spatial distribution. The faults in the Wubaochang area are classified into first- to fourth-order structures, with the average fracture zone width on the hanging wall exceeding that of the footwall, demonstrating a strong positive correlation between fracture zone width and fault displacement. The study area is divided into three distinct deformation regions (southern, central and northern regions) featuring five fault structural styles (duplex, duplex-backthrust, imbricate thrust, synclinorium imbricate-backthrust, and anticlinorium imbricate-backthrust) and four corresponding fracture zone development patterns (duplex, duplex-backthrust, synclinorium imbricate-backthrust, and anticlinorium imbricate-backthrust). Based on the controlling effects of faults on gas enrichment, the dual-source hydrocarbon-supply zones are interpreted to be distributed in the northern and central regions, while the southern region is identified as gas-escape zones. By integrating the distribution of favorable reservoir development areas and fracture zones, two classes of gas enrichment zones (Class I and II) are delineated. Class I zones are primarily distributed in the northern region and the transitional zone from the southern to central regions, whereas Class II zones are concentrated in the central region. Class I zones exhibit dual-source hydrocarbon-supply conditions, larger-scale fracture zone development, and higher favorability compared to Class II zones. According to the defined gas accumulation effectiveness in different types of fracture zones, a high-productivity gas well model for the Wubaochang area is proposed, emphasizing “dual-source faults controlling enrichment, effective fracture zones controlling high production, and high matrix porosity ensuring sustained production”. Targeted drilling directions for different favorable zones are further optimized based on this model.

Through systematic investigation of deep coal-rock gas in the Ordos Basin, NW China, this work analysed the thickness distribution of the entire Upper Paleozoic coal-rock intervals, quantified the resource potential of representative areas (a 12 000 km² rectangular block in the eastern Ordos Basin roughly centered on Yulin City), clarified the occurrence characteristics of coal-rock gas, and identified key development indicators for gas wells, thereby defining the direction for iterative optimization of key technologies. (1) The total coal-rock gas in-place of the Upper Paleozoic coal seams 1^#-10^# in the resource evaluation region is assessed at 5.66×10¹² m³, of which coal seam 8^#, currently the main target interval, contains about 3.08×10¹² m³, accounting for roughly 54% of the total. (2) Deep coal-rock gas is characterized by a high ratio of free gas. Under the conditions of 2 000 m burial depth, 6.35% porosity, 95% free gas saturation, and 22.13 m³/t total gas content, the free gas content of the reservoir is estimated to be ca. 40% of the total gas. (3) Three productivity evaluation models (triangular, convex, concave) are developed for horizontal wells, of which the triangular model can serve as the reference model for predicting the estimated ultimate recovery (EUR) throughout the lifecycle of coal-rock gas wells. Using the triangular model with a 7 m coal thickness, 1 500 m effective lateral length and 400 m well spacing, the average single-well EUR is determined to be 4 621.28×10⁴ m³. (4) Development of the coal seam 8^# should employ horizontal wells with pressure-controlled production. Meanwhile, it can be further optimized by adopting the cost-effective strategies of Sulige Gas Field in the Ordos Basin, China. (5) To achieve cost-effective development and increase primary recovery factor, key technologies must undergo continuous iteration and upgrading, focusing on accelerating drilling, extending effective lateral lengths, high-intensity reservoir stimulation, and well-pattern optimization.

Low-salinity fracturing fluids tend to induce ion migration, alter wettability, and cause fluctuations in gas desorption efficiency when penetrating deep coal seams. Taking the No. 8 coal from the Daning-Jixian area in the Ordos Basin, NW China, as a representative example, this study employs physical simulation experiments to reveal the coupled control mechanism of salinity gradient on the ion-coal matrix-gas/water interfacial system and its key role in the imbibition-desorption process. The increasing ionic concentration improves the hydrophobicity of coal, with multivalent ions exhibiting particularly significant effects. The imbibition and ion diffusion occur in opposite directions, with imbibition equilibrium being achieved earlier than ionic equilibrium. Water-coal interactions induce both mineral dissolution and secondary precipitation. When a low-salinity fracturing fluid is injected into a high-salinity reservoir, the osmotic-pressure difference drives imbibition, promotes CH₄ desorption, but results in higher fluid loss. Conversely, injecting high-salinity fracturing fluid into a low-salinity reservoir creates a reverse osmotic gradient that suppresses leak-off while improving flowback efficiency. Based on these findings, a high-low salinity sequential injection strategy is proposed for deep coal seams: high-salinity fluid is first injected to form stable fracture networks, followed by low-salinity fluid to enlarge the imbibition zone and enhance CH₄ desorption and diffusion. Moderate well soaking is recommended to increase the imbibition volume, thereby achieving multiple positive effects such as maintaining reservoir pressure, preserving formation energy, and promoting imbibition-driven displacement.

To reveal the complex crude oil-CO₂ interaction mechanism and oil mobilization behavior during CO₂ huff-n-puff in shale-type shale oil reservoirs, CO₂ huff-n-puff experiments with on-line nuclear magnetic resonance monitoring were conducted on Gulong shale cores, combined with the prediction model of CO₂ dynamic diffusion coefficient, the flow mechanism and factors influencing oil mobilization during CO₂ huff and puff in Gulong shale oil reservoirs are studied, and the diffusion and mass transfer behavior of CO₂ in shale is investigated. The results show that at the injection stage, CO₂ invades into macropores near the injection end, and drives part of the crude oil to micropores in the deep part of the core. At the shut-in stage, the crude oil gradually reflows to macropores near the injection end and is redistributed in the core. At the production stage, the oil mobilization zone is gradually expanded from the production end (injection end) to the deep part of the core. The contribution ratio of produced oil from macropores and micropores is about 8︰3 after production. The diffusion coefficient of CO₂ in shale porous media gradually decreases with the advance of diffusion front at shut-in stage. The better the porosity and permeability of core samples, the higher the CO₂ concentration at diffusion front, the greater the CO₂ diffusion coefficient, and the slower the diffusion decline rate is. Increasing the huff and puff cycles could effectively enhance oil displacement efficiency, though its impact on the crude oil mobilization zone remains insignificant. The crude oil in small pores of the small layer with undeveloped laminae is difficult to be produced during CO₂ huff and puff, and the oil recovery is only 12.72 %. The crude oil in macropores and micropores of the small layer with developed laminae can be effectively mobilized during CO₂ huff and puff, and the oil recovery can reach 39.11%.

The compound system of polyacrylamide hydrogels and surfactant solutions are used for enhanced oil recovery (EOR). The polyacrylamide hydrogels are injected into block high-permeability zones firstly, followed by a low-cost sacrificial agent, then an oil-displacing surfactant, and finally an aqueous polymer solution containing diethanolamine, to enhance oil production. The hydrogels are selected through oscillatory rheometry, while the surfactant is optimized after optical imaging analysis. The EOR performance of the compound system is evaluated through core flooding experiments and reservoir numerical simulation. Specifically, the properly cross-linked polyacrylamide hydrogel can be selected using its elastic modulus as a quantitative parameter while accounting for pore structure. The sacrificial agent is used to block active adsorption sites in the rock matrix before mobilizing more crude oil with a nonionic-anionic surfactant system. The addition of the mild organic alkali (diethanolamine) into the polymer slug reduces surfactant adsorption and improves sweep efficiency, thereby enhancing the oil-washing effect. Flooding experimental results show that the sequential injection of hydrogel and surfactant compositions prolongs the period of increasing pressure gradient during subsequent waterflooding and significantly boosts oil production, achieving a 21-percentage-point increase in oil displacement efficiency. Numerical simulation for the target reservoir in the West Siberian oil province confirms the effectiveness, projecting a maximum cumulative oil increase of 6 851 t over three years.

This paper systematically reviews the advances in shale oil and gas drilling fluid technology, provides an in-depth analysis of the critical bottlenecks in each technology and explores their future development directions. Several technologies have been developed for shale oil and gas: water-based drilling fluids with a core emphasis on sealing, inhibition and lubrication; oil-based drilling fluids centered around wellbore strengthening, low-oil-water-ratio emulsions, and synthetic-based systems; drilling fluids for reservoir protection based on clay-free, under-balanced, and interfacial modification; as well as lost circulation control technologies founded on bridging, gelling, responsive, and composite mechanisms. A comprehensive analysis indicates that existing technologies are still plagued by several bottlenecks, including inadequate high-temperature and contamination resistance, prohibitive costs, and poor formation adaptability. Drilling operations still face severe challenges such as wellbore instability, reservoir damage and severe fluid losses. Accordingly, the following prospects for future shale oil and gas drilling fluid technology are proposed: (1) Water-based drilling fluids require a focus on the synergistic effects of nanoscale plugging and chemical inhibition, the development of smart responsive lubricants, and enhanced resistance to high temperatures and acid gas contamination. (2) Oil-based drilling fluids should achieve breakthroughs in novel emulsifiers for cost-effectiveness and high-temperature resistance, alongside intensified research efforts in environmentally friendly technologies. (3) Reservoir protective drilling fluids necessitate the development of a real-time prediction and diagnosis expert system for formation damage, coupled with the advancement and application of high-temperature resistant additives and intelligent integrated pressure control equipment. (4) Lost circulation control technologies should be dedicated to developing smart responsive plugging materials and strengthening their compatibility with fracture networks.

A temperature-sensitive mud cake remover (G315) was developed using ethyl lactate as the primary component. Based on this, a temperature-sensitive acidic completion fluid (CF-G315) was formulated. Core evaluation tests, mud cake dissolution tests and corrosion tests were conducted to analyze the mud cake removal performance of G315, the removal efficiency of CF-G315, and its ability to modify the near-wellbore reservoirs, corrosion to casing and hydrolysis performance. Results indicate that ethyl lactate in G315 exhibits weak acidity at room temperature and decomposes into lactic acid under high temperatures. The lactic acid reacts with the calcium carbonate in the mud cake, generating bubbles that dislodge the mud cake and form soluble salts that are subsequently removed by fluid flow, thereby ensuring effective mud cake clearance. CF-G315 removes mud cake efficiently and enhances near-wellbore reservoir permeability. It demonstrates low corrosivity and environmental compatibility, contributing to equipment safety, simplified operational procedures and reduced operational risks. CF-G315 is promising for application in scenarios such as horizontal wells, open-hole completions and gravel pack completions.

Four types of volcanic rock samples, i.e. breccia, andesite, tuff, and dacite, selected from the Carboniferous in the Junggar Basin were characterized through experiments such as X-ray diffraction (XRD), scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) for identifying the acid imbibition and ion diffusion behaviors during fracture acidizing in volcanic rock reservoirs. The results demonstrate that the invaded acid dissolves the minerals and alters the pore structure in the reservoir. Volcanic rocks of different lithologies exhibit substantial variations in their acidification and dissolution effects. Breccia and andesite, which contain abundant calcite and other soluble minerals, show markedly improved pore connectivity after acidizing. In addition, pronounced differences are observed between the acid-induced dissolution responses of oil-rich and water-rich pores within volcanic rocks. In water-rich pores, acid-induced dissolution is dominated by H⁺ diffusion, whereas in oil-rich pores, imbibition-driven dissolution is the primary mechanism. The hydrated hydrogen-ion network formed in water-rich pores enhances H⁺ diffusion, facilitating uniform dissolution across pore scales. As a result, the pore structure becomes more homogenized, leading to a reduction in fractal dimension. In oil-rich pores, acid imbibition driven by capillary pressure is the predominant mechanism, enabling small pores to be dissolved preferentially, followed by medium to large pores. Consequently, the overall extent of acid erosion remains limited, and pore heterogeneity persists at a high level. Both the acid-imbibition and ion-diffusion processes exhibit a three-stage evolution: linear-transitional-stable. In the linear stage, the acid imbibition and H⁺ diffusion distances scale proportionally with the square root of time. In the transitional stage, the H⁺ diffusion rate decreases due to pore-throat blockage induced by the hydration and precipitation of clay minerals. Concurrently, acid imbibition and mineral dissolution enhance the fluid flow capacity, partially offsetting the attenuation of capillary pressure, and sustaining the increase in imbibition rate. In the stable stage, both acid imbibition and ion diffusion approach equilibrium.

Outcrop coal samples from the Shizhuang South Block of the Qinshui Basin, Shanxi Province, China, were subjected to true triaxial hydraulic fracturing experiments to simulate fracture propagation. Combined with CT scanning and three-dimensional fracture reconstruction, the study examined fracture propagation patterns and bedding activation behaviors under variable pumping-rate fracturing in coal reservoirs. Results indicate that the variable pumping-rate fracturing technique effectively overcomes the strong trapping effect of coal bedding. Micro-fractures are initiated at multiple weak points along bedding planes, leading to multi-point fracture initiation and competitive propagation of fractures toward the far field, thereby generating a more complex three-dimensional fracture network. The geometry and aperture of the induced fracture network are primarily controlled by the ramp-up rate of injection flowrate. A gradual ramp-up favors the development of a more complex fracture network, though at the expense of lower breakdown pressure, insufficient initiation, and narrower apertures. In contrast, a rapid ramp-up produces wider fractures and larger propped lengths, but results in more pronounced aperture fluctuations. For coal reservoirs with relatively high rock strength, a moderately higher ramp-up rate is recommended to avoid excessively narrow fractures and potential proppant bridging. Different coal lithotypes necessitate tailored ramp-up strategies to optimize fracture morphology and stimulation effectiveness.

This study reviews the recent progress and trends of carbon capture, utilization and storage (CCUS) technologies, with a particular focus on related policy orientations, technological status, and representative projects across North America, Europe, the Middle East, and China. The technical connotations of CCUS are elucidated, and the existing issues and challenges are identified from the perspectives of technology, economics, safety and system integration. The CO₂ capture technologies are relatively mature; the emergence of novel processes such as direct air capture (DAC) and advanced materials such as metal-organic frameworks (MOFs) offer new choices for efficient capture, but issues related to high energy consumption and operational costs remain unresolved. The CO₂ geological utilization has developed earlier, where breakthroughs rely on effective source matching, enhanced miscibility and increased swept volume. The CO₂ chemical utilization exhibits broad market potential for producing high value-added products, and the development of catalytic systems with high conversion efficiency and low cost is identified as the core challenge. For CO₂ storage, diverse geological bodies provide vast theoretical capacities on both land and offshore worldwide, but subsidy policies and carbon market regulation are required to offset the limited economic returns of storage technologies. This study highlights several frontier technologies, including low-concentration CO₂ capture, CO₂-enhanced oil recovery (EOR), CO₂-based green fuel synthesis, microbial CO₂ conversion, CO₂ mineralization and hydrogen production, and CO₂ cushion gas replacement in underground gas storage (UGS). Through cost-effective innovation, regional pipeline network development, flexible technology integration, coordinated macro-policy regulation, and cross-disciplinary collaboration, CCUS can achieve a transformative scale-up from million-ton and ten-million-ton capacities to the hundred-million-ton level, contributing to the achievement of the carbon neutrality goals of China.

Based on the survey of saline lacustrine shales in the Permian Lucaogou Formation and Fengcheng Formation in the Junggar Basin, it is found that the sweet intervals of these shale oil strata are enriched with lithium. In certain intervals, lithium contents reach up to 700 μg/g, with produced water concentrations estimated to 517.2 μg/g—an underexplored resource with considerable potential that has yet to receive adequate attention. The sedimentary environment, depositional process, and geochemical characteristics of these intervals were analyzed, indicating that lithium enrichment in saline lacustrine shale is controlled by multiple factors during deposition and diagenesis. The salinity of lake water during sedimentation plays a key role in lithium accumulation, with lithium primarily concentrated in carbonate-rich intervals, and diagenesis further affects its distribution. To assess the potential for lithium co-production in shale oil development, future research should be based on the enrichment mechanisms of lithium and hydrocarbons in lacustrine shales, predict the distribution patterns of oil and lithium-rich intervals, and evaluate the economic feasibility of an “oil-lithium integrated sweet spot”. Efficient lithium extraction and environmental protection technologies need to be explored to optimize resource development. Saline lacustrine shale oil development not only ensures stable oil and gas supplies but also, if lithium co-production is realized, could enhance China’s lithium security, contributing significantly to the country’s energy transformation.