The Ledong Diapir area of the Yinggehai Basin is characterized by high temperature and strong overpressure background, mud-fluid diapirism, and frequent thermal fluid activity. Based on the geochemical data of rare gas, heat conservation equation, mass balance law, Rayleigh fractionation model and other methods were used to systematically analyze the initial He concentration, thermal driving mechanism, in-situ yield and external flux of helium, as well as the migration and accumulation mechanism of helium in the Ledong Diapir area. The results show that, in the study area, the ³He/⁴He values are (0.002-2.190)×10^-6, and the R/Ra values are 0.01-1.52, indicating the contribution of mantle-derived helium. The CO₂/³He value increases from 1.34×10⁹ to 486×10⁹, indicating that the secondary migration of helium from deep to shallow strata was affected by crust-mantle mixing and degassing effects, with large-scale precipitation of CO₂ and apparent escape of ³He. Under standard conditions, the ratio of ³He to enthalpy is (0.006-0.018)×10^-12 cm³/J, and the heat contribution from the mantle source is low. The in-situ ⁴He yield is (7.66-7.95)×10^-13 cm³/(g·a), and there is a significant external ⁴He flux, which may be related to atmospheric recharge of formation fluid and deep rock-water interaction. The primary migration mode of helium in the study area is mainly advection, while the migration from deep to shallow strata is controlled by the mixing of crust-mantle gases, hydrothermal degassing, and gas-liquid separation. Under the influence of deep thermal fluid, the accumulation mechanism of helium includes deep helium release and efficient migration, lateral migration and trap aggregation, partial pressure balance and strong sealing.

The paper systematically reviews the current applications of various spatial information technologies in CO₂ sequestration monitoring, analyzes the challenges faced by spatial information technologies in CO₂ sequestration monitoring, and prospects the development of spatial information technologies in CO₂ sequestration monitoring. Currently, spatial information technologies applied in CO₂ sequestration monitoring mainly include five categories: eddy covariance method, remote sensing technology, geographic information system, Internet of Things technology, and global navigation satellite system. These technologies are involved in three aspects: monitoring data acquisition, positioning and data transmission, and data management and decision support. Challenges faced by spatial information technologies in CO₂ sequestration monitoring mainly include: selecting spatial information technologies that match different monitoring purposes, different platforms, and different monitoring sites; establishing effective data storage and computing capabilities to cope with the broad sources and large volumes of monitoring data; and promoting collaborative operations by interacting and validating spatial information technologies with mature monitoring technologies. In the future, it is necessary to establish methods and standards for designing spatial information technology monitoring schemes, develop collaborative application methods for cross-scale monitoring technologies, integrate spatial information technologies with artificial intelligence and high-performance computing technologies, and accelerate the application of spatial information technologies in carbon sequestration projects in China.

Based on the practice of waterflooding development in carbonate reservoirs in the Middle East, in order to solve the problem of the poor development effects caused by commingled injection and production, taking the thick bioclastic limestone reservoirs of Cretaceous in Iran-Iraq as an example, this paper proposes a balanced waterflooding development technology for thick and complex carbonate reservoirs. This technology is based on the fine division of development units by concealed baffles and barriers, the combination of multi well type and multi well pattern, and the construction of balanced water injection and recovery system as the core. For the thick carbonate reservoirs in in Iran and Iraq, which are extremely heterogeneous vertically with ultra-high permeability zones of various genesis, and highly concealed baffles an barriers, based on the technologies of characterization and sealing evaluation for concealed baffles an barriers, the balanced waterflooding development technology is proposed, and three types of balanced waterflooding development modes/techniques are formed, namely, conventional stratigraphic framework, fine stratigraphic framework, and deepened stratigraphic framework. Numerical simulations show that this technology can realize a fine and efficient waterflooding development to recover, in a balanced manner, the reserves of thick and complex carbonate reservoirs in Iran and Iraq. The proposed technology provides a reference for the development optimization of similar reservoirs.

A new pore type, nano-scale organo-clay complex pore, was first discovered based on argon ion polishing-field emission scanning electron microscopy, energy dispersive spectroscopy and focused ion-scanning electron microscopy in combination with TOC, R_o, X-ray diffraction etc. in the Cretacesous Qingshankou Formation shale in the Songliao Basin, NE China. Such pore characteristics and evolution study show that: (1) Organo-clay complex pores are developed in the shale matrix and in the form of spongy and reticular aggregates. Different from circular or oval organic pores discovered in other shales, a single organo-clay complex pore is square, rectangular, rhombus or slaty, with the pore diameter generally less than 200 nm. (2) With thermal maturity increasing, elements (C, Si, Al, O, Mg, Fe, etc.) in organo-clay complex change accordingly, showing that organic matter shrinkage due to hydrocarbon generation and clay mineral transformation both affect organo-clay complex pore formation. (3) At high thermal maturity, the Qingshankou Formation shale is dominated by nano-scale organo-clay complex pores with the percentage reaching more than 70%. The spatial connectivity of organo-clay complex pores is significantly better than that of organic pores. It is suggested that organo-complex pores are the main pore space of laminar shale at high thermal maturity and are the main oil and gas accumulation space in the core area of continental shale oil. The discovery of nano-scale organo-clay complex pores changes the conventional view that inorganic pores are the main reservoir space and has scientific significance for the study of shale oil formation mechanics and accumulation laws.

Based on new data from cores, drilling and logging, combined with extensive rock and mineral testing analysis, a systematic analysis is conducted on the characteristics, diagenesis types, genesis and controlling factors of deep to ultra-deep abnormally high porosity clastic rock reservoirs in the Oligocene Linhe Formation in the Hetao Basin. The reservoir space of the deep to ultra-deep clastic rock reservoirs in the Linhe Formation is mainly primary pores, and the coupling of three favorable diagenetic elements, namely the rock fabric with strong compaction resistance, weak thermal compaction diagenetic dynamic field, and diagenetic environment with weak fluid compaction-weak cementation, is conducive to the preservation of primary pores. The Linhe Formation clastic rocks have a superior preexisting material composition, with an average total content of 90% for quartz, feldspar, and rigid rock fragments, and strong resistance to compaction. The geothermal gradient in Linhe Depression in the range of (2.0-2.6) ℃/100 m is low, and together with the burial history of long-term shallow burial and late rapid deep burial, it forms a weak thermal compaction diagenetic dynamic field environment. The diagenetic environment of the saline lake basin is characterized by weak fluid compaction. At the same time, the paleosalinity has zoning characteristics, and weak cementation in low salinity areas is conducive to the preservation of primary pores. The hydrodynamic conditions of sedimentation, salinity differentiation of ancient water in saline lake basins, and sand body thickness jointly control the distribution of high-quality reservoirs in the Linhe Formation.

The transtensional faults in the area of Ziyang 3-D seismic survey is an important component of the Central Sichuan Transtensional (strike-slip) Fault System (CSTFS). The in-depth research on the transtensional faults in the Ziyang area is crucial for clarifying the basic hydrocarbon geological conditions of the area and even the central Sichuan Basin, and expanding the oil and gas exploration fields. With well and seismic data of the Ziyang area, through plane-section integrated structural interpretation, 3-D fault framework model building, fault throw analyzing, and balanced profile restoration, it is pointed out that the transtensional fault system in the Ziyang 3-D seismic survey consists of the northeast-trending F_I19 and F_I20 fault zones dominated by extensional deformation, as well as 3 sets of northwest-trending en echelon normal faults experienced dextral shear deformation. Among them, the F_I19 and F_I20 fault zones cut through the Neoproterozoic to Jialingjiang Formation, presenting a 3-D fault plane structure of an "S"-shaped ribbon. And before Permian and during the early Triassic, the F_I19 and F_I20 fault zones underwent at least two periods of structural superimposition. Besides, the 3 sets of northwest-trending en echelon normal faults are composed of small normal faults arranged in pairs, with opposite directions and partially left-stepped arrangement. And before Permian, they had formed almost, restricting the eastward growth and propagation of the F_I19 fault zone. As a conclusion, the F_I19 and F_I20 fault zones communicate multiple sets of source rocks and reservoirs from deep to shallow, and the timing of fault activity matches well with oil and gas generation peaks. Therefore, if there were favorable sedimentary facies and reservoirs developing on both sides of the F_I19 and F_I20 fault belts, the major reservoirs in the Longwangmiao Formation, Qixia Formation, Maokou Formation, and Jialingjiang Formation in this area are expected to achieve breakthroughs in oil and gas exploration.

Fiber is highly escapable in conventional slickwater, making it difficult to form fiber-proppant agglomerate with propppant and exhibit limited effectiveness. To solve these problems, a novel fiber structure stabilizer (FSS) is developed. Through microscopic structural observations and performance evaluations in indoor experiments, the mechanism of proppant placement under the action of the FSS and the effects of the FSS on proppant placement dimensions and fracture conductivity were elucidated. The results reveal that the FSS facilitates the formation of robust fiber-proppant agglomerates by polymer, fiber, and quartz sand. Compared to bare proppants, these agglomerates exhibit reduced density, increased volume, and enlarged contact area with the fluid during settlement, leading to heightened buoyancy and drag forces, ultimately resulting in slower settling velocities and enhanced transportability into deeper regions of the fracture. Co-injecting the fiber and the FSS alongside the proppant into the reservoir effectively reduces the fiber escape rate, increases the proppant volume in the slickwater, and boosts the proppant placement height, conveyance distance and fracture conductivity, while also decreasing the proppant backflow. Experimental results indicate an optimal FSS mass fraction of 0.3%. The application of this FSS in over 80 wells targeting tight gas, shale oil, and shale gas reservoirs has substantiated its strong adaptability and general suitability for meeting the production enhancement, cost reduction, and sand control requirements of such wells.

The Bohai Bay Basin, as a super oil-rich basin in the world, is characterized by cyclic evolution and complex regional tectonic stress field, and its lifecycle tectonic evolution controls the formation of regional source rocks. The main pre-Cenozoic stratigraphic system and lithological distribution are determined through geological mapping, and the dynamics of the pre-Cenozoic geotectonic evolution of the Bohai Bay Basin are investigated systematically using the newly acquired high-quality seismic data and the latest exploration results in the study area. The North China Craton where the Bohai Bay Basin is located in rests at the intersection of three tectonic domains: the Paleo-Asian Ocean, the Tethys Ocean, and the Pacific Ocean. It has experienced the alternation and superposition of tectonic cycles of different periods, directions and natures, and experienced five stages of the tectonic evolution and sedimentary building, i.e. Middle-Late Proterozoic continental rift trough, Early Paleozoic marginal-craton depression carbonate building, Late Paleozoic marine-continental transitional intracraton depression, Mesozoic intracontinental strike-slip-extensional tectonics, and Cenozoic intracontinental rifting. The cyclic evolution of the basin, especially the multi-stage compression, strike-slip and extensional tectonics processes in the Hercynian, Indosinian, Yanshan and Himalayan since the Late Paleozoic, controlled the development, reconstruction and preservation of several sets of high-quality source rocks, represented by the Late Paleozoic Carboniferous-Permian coal-measure source rocks and the Paleogene world-class extra-high-quality lacustrine source rocks, which provided an important guarantee for the hydrocarbon accumulation in the oil-rich superbasin.

An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang depression of Nanxiang Basin as an example. The characteristic curve of capillary pressure and relative permeability was obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing. The study showed that optimization of the SRV fracturing fluid volume strength should meet the requirements of estimated ultimate recovery(EUR), increased oil recovery by forced imbibition and enhancement of formation pressure and fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition associated oil displacement caused by insufficient fluid amount or increase of costs and potential of formation damage caused by excessive fluid amount. Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with well EUR and a optimal fluid volume strength existed, above which the well EUR increase rate kept decreasing. An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production. Field test results of X-1 well proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.

This study conducted temporary plugging and division fracturing (TPDF) simulation experiments using a true triaxial fracturing simulation system based on a completion simulation of horizontal well with multi-cluster sand jetting perforation. The effects of temporary plugging agent (TPA) particle size, TPA concentration, single-cluster perforation number and cluster number on plugging pressure, multi-fracture diversion pattern and distribution of TPAs were investigated. The results show that a combination of TPAs with small particle sizes within the fracture and large particle sizes within the segment is conducive to increasing the plugging pressure and promoting the diversion of multi-fractures. The addition of fibers can quickly achieve ultra-high pressure, but it may lead to longitudinal fractures extending along the wellbore. The temporary plugging peak pressure increases with an increase in the concentration of the TPA, reaching a peak at a certain concentration, and further increases do not significantly improve the temporary plugging peak pressure. The fracture pressure and temporary plugging peak pressure show a decreasing trend with an increase in single-cluster perforation number. A lower number of single-cluster perforations is beneficial for increasing the fracture pressure and temporary plugging peak pressure, and it has a more significant control on the propagation of multi-cluster fractures. A lower number of clusters is not conducive to increasing the total number and complexity of artificial fractures, while a higher number of clusters makes it difficult to achieve effective plugging. The TPAs within the fracture is mainly concentrated in the complex fracture areas, especially at the intersections of fractures. Meanwhile, the TPAs within the segment is primarily distributed near the perforation cluster apertures which initiated complex fractures.

Based on the latest results of near-source exploration in the Middle and Lower Jurassic of the Tuha Basin, a new understanding of the source rocks, reservoir conditions, and source-reservoir-cap rock combinations of the Jurassic Shuixigou Group in the Taibei Sag is established using the concept of the whole petroleum system, and the petroleum in the coal-measure whole petroleum system is analyzed thoroughly. The results are obtained in three aspects. First, the coal-measure source rocks of the Badaowan Formation and Xishanyao Formation and the argillaceous source rocks of the Sangonghe Formation in the Shuixigou Group exhibit the characteristics of long-term hydrocarbon generation, multiple hydrocarbon generation peaks, and simultaneous oil and gas generation, providing sufficient oil and gas sources for the whole petroleum system in the Jurassic coal-bearing basin. Second, multi-phase shallow braided river delta-shallow lacustrine deposits contribute multiple types of reservoirs (e.g. sandstone, tight sandstone, shale and coal rock) in slope and depression areas, providing effective storage space for the complete physical reservoir formation in coal-measure strata. Third, three phases of hydrocarbon charging and structural evolution, as well as effective configuration of multiple types of reservoirs, result in the sequential accumulation of conventional-unconventional hydrocarbons. From high structural positions to depression, there are conventional structural and structural-lithological reservoirs far from the source, low-saturation structural-lithological reservoirs near the source, and tight sandstone gas, coal rock gas and shale oil accumulations within the source. Typically, the tight sandstone gas and coal rock gas are the key options for further exploration, and the shale oil and gas in the depression area is worth of more attention. The new understanding of the whole petroleum system in the coal-bearing basin will further enrich and improve the geological theory of the whole petroleum system, and provide new ideas for the overall exploration of oil and gas resources in the Tuha Basin.

Based on the geological and geophysical data of Mesozoic oil-gas exploration in Bohai Bay Basin and the recently discovered high-yield volcanic oil and gas wells, this paper methodically summarizes the formation conditions of large- and medium-sized Cretaceous volcanic oil and gas reservoirs in the Bohai Sea. Research shows that the Mesozoic large intermediate-felsic lava and intermediate-felsic composite volcanic edifices in the Bohai Sea are the material basis for the formation of large-scale volcanic reservoirs. The upper subfacies of effusive facies and cryptoexplosive breccia subfacies of volcanic conduit facies of volcanic vent-proximal facies belts are favorable for large-scale volcanic reservoir formation. Two types of efficient reservoirs, characterized by high porosity and medium to low permeability, as well as medium porosity and medium to low permeability, are the core of the formation of large- and medium-sized volcanic reservoirs. The reservoir with high porosity and medium to low permeability is formed by intermediate-felsic lava or the cryptoexplosive breccia superimposed by intensive dissolution. The reservoir with medium porosity and medium to low permeability is formed by intense tectonism superimposed by fluid dissolution. Weathering and tectonic transformation are main formation mechanisms for large and medium-sized volcanic reservoirs in the study area. The “source-reservoir draping type” at the low source is the optimum source-reservoir configuration relationship for large- and medium-sized volcanic reservoirs. There exists favorable volcanic facies, efficient reservoirs and source-reservoir draping configuration relationship on the periphery of Bozhong Sag, and the large intermediate-felsic lava and intermediate-felsic composite volcanic edifices close to strike-slip faults and their branch faults are the main directions of future exploration.

Based on the data of outcrop, core, logging, gas testing, and experiments, the natural gas accumulation and aluminous rock mineralization integrated research method was adopted to analyze the controlling factors of aluminous rock series effective reservoirs in the Ordos Basin, as well as the configuration of coal-measure source rocks and aluminous rock series reservoirs. A natural gas accumulation model was constructed to evaluate the exploration potential of aluminous rock series gas under coal seam in the basin. The results show that the aluminous rock series effective reservoirs in the Ordos Basin is mainly composed of honeycomb-shaped bauxites with porous residual pisolitic and detrital structures, with the diasporite content of greater than 80% and dissolved pores as the main storage space. The bauxite reservoirs are believed to have been formed under a model that levelization controls the material supply, karst paleogeomorphology controls diagenesis, and land surface leaching improves reservoir quality. The hot humid climate and sea level changes in the Late Carboniferous-Early Permian dominated the development of a typical coal-aluminum-iron three-stage stratigraphic structure. The natural gas generated by the extensive hydrocarbon generation of coal-measure source rocks was accumulated in aluminous rock series reservoirs under the coal seam, indicating a model of hydrocarbon accumulation under the source. During the Upper Carboniferous-Lower Permian, the coal-aluminum-iron three-stage stratigraphic structure was developed in the relatively low-lying area on the edge of an ancient land or island in the North China landmass. The aluminous rock series gas reservoirs, which are clustered at multiple points in lenticular shape, are important new natural gas exploration field with great potential in the Upper Paleozoic of North China Craton.

Based on the organic geochemical data and the component and stable carbon isotopic composition of natural gas of the Lower Permian Fengcheng Formation in the western Central Depression of Junggar Basin, combined with sedimentary environment analysis and hydrocarbon generation simulation, the gas-generating potential of the Fengcheng source rock is evaluated, the distribution of large-scale effective source kitchen is described, the genetic types of natural gas are clarified, and four types of favorable exploration targets are selected. The results show that: (1) The Fengcheng Formation is a set of oil-prone source rock, and the retained liquid hydrocarbon is conducive to late cracking into gas, with high gas-generating potential and characteristics of late accumulation; (2) The maximum thickness of Fengcheng source rock reaches 900 m. The source rock has entered the main gas-generating stage in Well Pen-1 western and Shawan sags, and the area with gas generation intensity greater than 20×10⁸ m³/km² is approximately 6 500 km². (3) Around the western Central Depression, highly mature oil-type gas with light carbon isotope composition was identified to be derived from the Fengcheng source rocks mainly, while the rest was coal-derived gas from the Carboniferous source rock; (4) Four types of favorable exploration targets with exploration potential were developed in the western Central Depression which are structural traps neighboring to the source, stratigraphic traps neighboring to the source, shale-gas type within the source, and structural traps within the source.

The previous researches on the subsidence in the southern part of the Ordos Basin during the Triassic period mainly focused on the sedimentary period of the Chang 7 Member, with insufficient understanding of the subsidence in other periods of the initial stage of the basin. Based on a large number of newly added deep well data in recent years, the subsidence of the Ordos Basin in the Mid-late Triassic is systematically studied, and it is proposed that the Ordos Basin experienced two important subsidence events during this depositional period. Through contrastive analysis of the two stages of tectonic subsidence, including stratigraphic characteristics, lithology combination, location of catchment area and sedimentary evolution, it is proposed that both of them are responses to the Indosinian Qinling tectonic activity on the northern edge of the Craton Basin with the feature of fast subsiding. (1) The early subsidence occurred in Chang 10 Member was featured by high amplitude, large debris supply and fast deposition rate, with mainly coarse debris filling and rapid subsidence accompanied by rapid accumulation, resulting in strata thickness increasing from northeast to southwest in wedge-shape. The subsidence center was located in Huanxian-Zhenyuan-Qingyang-Zhengning areas of southwestern basin with the strata thickness of 800-1 300 m. The subsidence center deviating from the depocenter developed multiple catchment areas, until then, unified lake basin has not been formed yet. (2) Under the combined action of subsidence and Carnian heavy rainfall event during the deposition period of Chang 7 Member, a large deep-water depression was formed at slow deposition rate, with the subsidence center coincided with the depocenter basically in the Mahuangshan-Huachi-Huangling areas. The deep-water sediments were 120-320 m thick in the subsidence center, characterized by fine grain mainly. There are differences in the mechanism between the two stages of subsidence. The early one was the response to the northward subduction of the MianLue Ocean and intense depression under compression in Qinling during Mid-Triassic. The later subsidence is controlled by the weak extensional tectonic environment of the post-collision stage during Late Triassic.

Based on the displacement discontinuity method and the discrete fracture unified pipe network model, a sequential iterative numerical method was used to construct a fracturing-production integrated numerical model of shale gas well considering the two-phase flow of gas and water. The model accounts for the influence of natural fractures and matrix properties on the fracturing process and directly applies post-fracturing formation pressure and water saturation to subsequent well shut-in and production simulation, allowing for a more accurate fracturing-production integrated simulation. The simulation results show that the reservoir physical properties have great impacts on fracture propagation, and the reasonable prediction of formation pressure and reservoir fluid distribution after the fracturing is critical to accurately predict the gas and fluid production of shale gas wells. Compared with the conventional method, the proposed model can more accurately simulate the water and gas production by considering the impact of fracturing on both matrix pressure and water saturation. The established model is applied to the integrated fracturing-production simulation of actual horizontal shale gas wells, yielding the simulation results in good agreement with the actual production data, thus verifying the accuracy of the model.

In traditional well log depth matching tasks, manual adjustments are required, which means significantly labor-intensive for multiple wells, leading to low work efficiency. To address this challenge, this paper introduces a multi-agent deep reinforcement learning (MARL) method to automate the depth matching of multi-well logs. This method defines multiple top-down dual sliding windows based on the convolutional neural network (CNN) to extract and capture similar feature sequences on well logs, and it establishes an interaction mechanism between agents and the environment to control the depth matching process. Specifically, the agent selects an action to translate or scale the feature sequence based on the double deep Q-network (DDQN). Through the feedback of the reward, it evaluates the effectiveness of each action, aiming to obtain the optimal strategy and achieve the matching task. Our experiments show that MARL can automatically perform depth matches for well-logs, reducing manual intervention. In the application to the oil field, a comparative analysis of dynamic time warping (DTW), deep Q-learning network (DQN), and DDQN methods revealed that the DDQN algorithm, with its dual-network evaluation mechanism, significantly improves performance by identifying and aligning more details in the well log feature sequences, thus achieving higher depth matching accuracy.

Based on the independently developed true triaxial multi-physical field large-scale physical simulation system of in-situ injection and production, we conducted physical simulation on the long-term injection and production of multiple wells in the hot dry rocks in the Gonghe Basin of Qinghai Province. By virtue of multi-well connectivity experiments, the spatial distribution characteristics of the natural fracture system in the rock samples and the connectivity between fracture and wellbore were clarified. Then, the injection and production wells were selected to conduct the experiments, namely one injection well and two production wells, one injection well and one production well. The variation of several physical parameters in the production well was analyzed, such as the flow rate, the temperature, the heat recovery rate, and the fluid recovery rate. The results show that under the combination of thermal shock and injection pressure, the fracture conductivity was enhanced, and the production temperature showed a downward trend. The larger the flow rate, the faster the decrease. When the local closed area of the fracture was gradually activated, new heat transfer areas were generated, resulting in a lower rate of increase or decrease in the mining temperature. The heat recovery rate was mainly controlled by the extraction flow rate and the temperature difference between injection and production fluid. In addition, as the conductivity of the leak-off channel increased, the fluid recovery rate of the production well rapidly decreased. The influence mechanisms of dominant channels and fluid leak-off on thermal recovery performance were different. The former limits the heat exchange area, while the latter affects the flow rate of the produced fluid. However, both of them were important factors affecting the long-term and efficient development of hot dry rock.

The Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin develops tight oil below the source rocks. Based on the geochemical, seismic, logging, and drilling data, the Fuyu reservoirs are systematically studied in terms of the geological characteristics, the tight oil enrichment model and its major controlling factors. First, the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation, with the development of ring-concave nose structure and the broad and continuous distribution of sand bodies. The reservoirs are tight on the whole. Second, the configuration of multiple elements, such as high-quality source rocks, reservoir rocks, fault, overpressure and structure, controls the tight oil enrichment in the Fuyu reservoirs. The source-reservoir combination controls the tight oil distribution pattern. The fault-sandbody transport system determines the migration and accumulation of oil and gas. The pressure difference between source and reservoir drives the charging of tight oil. The positive structure is the favorable place for tight oil enrichment, and the fault-horst zone is the key part of syncline for tight oil exploration. Third, based on the source-reservoir relationship, transport mode, drive and other elements, three tight oil enrichment models are recognized in the Fuyu reservoirs: (1) vertical or lateral transport of hydrocarbon from source rocks to adjacent reservoir rocks, that is, driven by overpressure, hydrocarbon generated by the source rocks is transported vertically or laterally to and accumulates in the adjacent reservoir rocks; (2) transport of hydrocarbon through faults between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downward through faults to the reservoir rocks that are separated from the source rocks; and (3) sandbody migration of hydrocarbon downwards through faults and sandbodies between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks, and migrates laterally through sandbodies. Fourth, the differences in oil source conditions, fracture distribution, charging drive, sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs. Comprehensive analysis suggests that the Fuyu reservoir in the Qijia-Gulong Depression has good conditions for tight oil and has been less explored, and it is an important new zone for tight oil exploration in the future.

Exploration and development of large gas fields is an important way for a country to rapidly develop its natural gas industry. From 1991 to 2020, China has discovered 68 new large gas fields, boosting its annual gas output to 1 925×10⁸ m³ in 2020, making it the fourth largest gas producing country in the world. Based on 1696 molecular components and carbon isotopic composition data of alkane gas in 70 large gas fields in China, the characteristics of carbon isotope composition of alkane gas in large gas fields in China were obtained. The lightest and average values of δ¹³C₁, δ¹³C₂, δ¹³C₃ and δ¹³C₄ become heavier with increasing carbon number, while the heaviest values of δ¹³C₁, δ¹³C₂, δ¹³C₃ and δ¹³C₄ become lighter with increasing carbon number. The δ¹³C₁ values of large gas fields in China range from -71.2‰ to -11.4‰ (specifically, from -71.2‰ to -56.4‰ for bacterial gas, from -54.4‰ to -21.6‰ for oil-related gas, from -49.3‰ to -18.9‰ for coal-derived gas, and from -35.6‰ to -11.4‰ for abiogenic gas). Based on these data, the δ¹³C₁ chart of large gas fields in China was plotted. Moreover, the δ¹³C₁ values of natural gas in China range from -107.1‰ to -8.9‰, specifically, from -107.1‰ to -55.1‰ for bacterial gas, from -54.4‰ to -21.6‰ for oil-related gas, from -49.3‰ to -13.3‰ for coal-derived gas, and from -36.2‰ to -8.9‰ for abiogenic gas. Based on these data, the δ¹³C₁ chart of natural gas in China was plotted.

The ternary-element storage and flow theory for shale oil reservoirs in Jiyang Depression, Bohai Bay Basin, East China, was proposed based on the experiments of more than 10,000 meters cores and the practical production of more than 60 horizontal wells. The synergy of three elements (storage, fracture and pressure) contributes the enrichment and high production of shale oil in Jiyang Depression. The storage element controls the enrichment of shale oil; specifically, the presence of inorganic pores and fractures, as well as laminae textures of lime-mud rocks, in the saline lake basin, is conducive to the storage of shale oil, and the high hydrocarbon generating capacity and free hydrocarbon content are the material basis for high production. The fracture element controls the shale oil flow; specifically, natural fractures act as flow channels for shale oil to migrate and accumulate, and induced fractures communicate natural fractures to form complex fracture network, which is fundamental to high production. The pressure element controls the high and stable production of shale oil; specifically, the high formation pressure provides the drive force for the migration and accumulation of hydrocarbons, and fracturing stimulation significantly increases the elastic energy of rock and fluid, improves the imbibition replacement of oil in the pores/fractures, and reduces the stress sensitivity, guaranteeing the stable production of shale oil for a long time. Based on the ternary-element storage and flow theory, a 3D development technology was formed, with the core techniques of 3D well pattern optimization, 3D balanced fracturing, and full-cycle optimization of adjustment and control. This technology effectively guides the production and provides a support to the large-scale beneficial development of shale oil in Jiyang Depression.

Taking the Lower Cretaceous Qingshuihe Formation in the southern margin of Junggar Basin as an example, the influences of the burial process on the diagenesis and the development of high-quality reservoirs of deep and ultra-deep clastic rocks was investigated using thin section, scanning electron microscope, electron probe, stable isotopic composition and fluid inclusion data. The Qingshuihe Formation went through four burial stages of "slow shallow burial", "tectonic uplift", "progressive deep burial" and "rapid deep burial" successively. The stages of "slow shallow burial" and "tectonic uplift" not only can alleviate the mechanical compaction of grains, but also can maintain an open diagenetic system in the reservoir for a long time, which promotes the dissolution of soluble components by meteoric freshwater and inhibits the precipitation of dissolution products. The late “rapid deep burial” process contributed to the development of fluid overpressure, which effectively inhibits the destruction of primary pores by compaction and cementation. Moreover, the fluid overpressure promotes the development of microfractures in the reservoir, which enhances the dissolution effect of organic acids. Based on the quantitative reconstruction of porosity evolution history, it is found that the long-term "slow shallow burial" and "tectonic uplift" processes make the greatest contribution to the development of deep-ultra-deep high-quality clastic rock reservoirs, followed by the late "rapid deep burial" process, and the "progressive deep burial" process has little contribution.

Based on the methodology for petroleum systems and through the anatomy and geochemical study of typical helium-rich gas fields, the geological conditions, genetic mechanisms, and accumulation patterns of helium resources are investigated. Helium differs greatly from other natural gas resources in formation, migration, and accumulation. Helium is mostly generated due to the slow alpha decay of basement U/Th-rich elements or released from the deep crust-mantle, and then migrates along the multiple tectonic layers of the exosphere to the gas reservoir-forming system, where it accumulates depending on a suitable carrier gas. Crust-mantle-originated helium migration and conduction are mainly controlled by the multi-tectonic-layer conduction system consisting of lithospheric fractures, basement fractures, sedimentary layer fractures, and effective carriers. Based on the analysis of the helium-gas-water phase equilibrium in underground fluids and the phase-potential coupling, three occurrence states, i.e. water-soluble phase, gas phase, and free phase, in the process of helium migration and accumulation, as well as three migration mechanisms of helium, i.e. mass flow, seepage and diffusion, are proposed. The formation and enrichment of helium-rich gas reservoirs are usually controlled by three major factors, i.e. high-quality helium source, high-efficiency conduction, and suitable carrier, and conform to three genetic mechanisms, i.e. gas-stripping and convergence, buoyancy-driven, and differential pressure displacement. Helium-rich gas reservoirs discovered generally follow the distribution rule and geological pattern of "near helium source, adjacent to fault, low fluid potential area, and high site". To explore and evaluate helium-rich areas, it is necessary to conduct concurrent/parallel exploration with natural gas. The comprehensive evaluation and selection of profitable "source-trap connected, low fluid potential with high site, and gas/helium properly matched" helium-rich areas should focus on the coupling and matching of the helium formation, migration and accumulation elements with the natural gas source, reservoir and caprock conditions, and based on favored carrier gas trapping areas in local low fluid potential with tectonic high sites.

Deep coal seams generally show low permeability, low elastic modulus, high Poisson's ratio, strong plasticity, high fracture initiation pressure, difficulty in fracture extension, and difficulty in proppants addition. In this paper, we proposed the concept of large-scale stimulation by fracture network, balanced propagation and effective support of fracture network in fracturing design and developed the extreme massive hydraulic fracturing techniques for deep coalbed methane (CBM) horizontal wells. This technique involves massive injection with high pumping rate + high proppant concentration + perforation with equal apertures and limited flow + temporary plugging and diverting fractures + slick water with integrated variable viscosity + graded proppants with multiple sizes. The technology was applied in the pioneering test of a multi-stage fracturing horizontal well in deep CBM of Linxing block, eastern margin of the Ordos Basin. The injection flowrate is 18 m³/min, proppant intensity is 2.1 m³/m, and fracturing fluid intensity is 16.5 m³/m. After fracturing, a complex fracture network was formed, with an average fracture length of 205 m. The stimulated reservoir volume was 1 987×10⁴ m³, and the peak gas production rate reached 6.0×10⁴ m³/d, which achieved efficient development of deep CBM.

A three-dimensional reconstruction of rough fracture surfaces of hydraulically fractured rock outcrops is carried out by casting process, a large-scale experimental setup for visualizing rough fractures is built, and proppant transport experiments are performed. The typical characteristics of proppant transport in rough fractures and its intrinsic mechanisms are investigated, and the influences of fracture inclination, fracture width and fracturing fluid viscosity on proppant transport and placement in rough fractures are analyzed. The results show that the rough fractures cause variations in the shape of the flow channel and the fluid flow pattern, resulting in the bridging buildup during proppant transport to form unfilled zone, the emergence of multiple complex flow patterns such as channeling, reverse flow and bypassing of sand-laden fluid, and the influence on the stability of the sand dune. The proppant has a higher placement rate in inclined rough fractures, with a maximum increase of 34.77% in the experiments compared to vertical fractures, but exhibits poor stability of the sand dune. Reduced fracture width aggravates the bridging of proppant and induces higher pumping pressure. Increasing the viscosity of the fracturing fluid can weaken the proppant bridging phenomenon caused by the rough fractures.

For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid, the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture extension due to shale minerals erosion by oil-based drilling fluid. With the evaluation for the damage of natural and hydraulic fractures caused by mechanical properties weakening of shale fracture surface, fracture closure and rock powder blocking, the formation damage pattern is proposed with consideration of the compound effect of drilling fluid and fracturing fluid. The formation damage mechanism of drilling and completion process in shale reservoir is revealed, and the protection measures are raised. Results show that drilling fluid can deeply invade into the shale formation through natural and induced fractures, erode shale minerals and weaken the mechanical properties of shale during drilling process. In the process of hydraulic fracturing, the compound effect of drilling fluid and fracturing fluid further weakens the mechanical properties of shale, results in fracture closure and rock powder shedding, and thus induces stress-sensitive damage and solid blocking damage of natural/hydraulic fractures. The above damage can yield significant conductivity decrease of fractures, and restrict the high and stable production of shale oil and gas wells. The measures of anti-collapse and anti-blocking to accelerate the drilling of reservoir section, chemical membrane to prevent the weakening of the mechanical properties of shale fracture surface, strengthening the plugging of shale fracture and reducing the invasion range of drilling fluid, fracturing fluid system optimization to protect fracture conductivity are put forward for reservoir protection.

Based on core and thin section data, the source rock samples from the Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin were analyzed in terms of zircon SIMS U-Pb geochronology, organic carbon isotopes, major and trace element contents, as well as rock minerals. Two zircon U-Pb ages (306.0±5.2 Ma and 303.5±3.7 Ma) were obtained from the first member of Fengcheng Formation. Combined with organic carbon isotope stratigraphy, it is inferred that the depositional age of the Fengcheng Formation is about 297-306 Ma, spanning the Carboniferous-Permian boundary and placing the majority to the interglacial period between C4 and P1 glaciation. Multiple increases in Hg/TOC ratios and altered volcanic ash were found in the shale rocks of the Fengcheng Formation, indicating that multiple phases of volcanic activity occurred during its deposition. An interval with a high B/Ga ratio was found in the middle of the second member of Fengcheng Formation associated with the occurrence of evaporite minerals and searlesite, indicating that the high salinity of the water mass is related to hydrothermal activity. Comprehensive analysis suggests that the organic matter enrichment of the Fengcheng Formation is controlled by multiple factors such as paleoclimate, volcanic activity, and salinity. Warm and humid climate during the deposition of Fengcheng Formation is conducive to the growth of organic matter such as algae and bacteria in lake, and accelerates the continental weathering, driving the input of nutrients. Volcanic and hydrothermal activities supply a large amount of nutrients and stimulate primary productivity. The high salinity encourages water stratification, leading to water anoxia that benefits organic matter preservation.

To explore the geological characteristics and exploration potential of the Carboniferous Benxi Formation coal rock gas in the Ordos Basin, this paper presents a systematic research on the coal rock distribution, coal rock reservoirs, coal rock quality, and coal rock gas features, resources and enrichment. Coal rock gas is a high-quality resource distinct from coalbed methane, and it has unique features in terms of burial depth, gas source, reservoir, gas content, and carbon isotopes. The Benxi Formation coal rocks cover an area of 160 000 km⊃2;, with thicknesses ranging from 2 to 25 m, primarily consisting of bright and semi-bright coals with primitive structures and low volatile and ash content, indicating a good coal quality. The medium-to-high rank coal rocks have the total organic carbon (TOC) content ranging from 33.49% to 86.11%, averaging 75.16%. They have a high degree of evolution (R_o of 1.2%-2.8%), and a high gas-generating capacity. They also have high stable carbon isotope values (δ¹³C₁: -37.6‰ to -16‰; δ¹³C₂: -21.7‰ to -14.3‰). Deep coal rocks develop matrix pores such as gas bubble pores, organic pores, and inorganic mineral pores, which, together with cleats and fractures, form good reservoir spaces. The coal rock reservoirs exhibit the porosity of 0.54%-10.67% (averaging 5.42%) and the permeability of 0.001-14.6 mD (averaging 2.32 mD). Vertically, there are five types of coal rock gas accumulation and dissipation combinations, among which the coal rock-mudstone gas accumulation combination and the coal rock-limestone gas accumulation combination are the most important, which have good sealing conditions and high peak values of total hydrocarbon in gas logging during drilling. A model of efficient hydrocarbon accumulation has been constructed, which includes source-reservoir integration, widespread distribution of medium-to-high rank coal rocks continually generating gas, matrix pores and cleats/fractures in coal rocks acting as large-scale reservoir spaces, tight cap rocks providing sealing, and five types of enrichment patterns (lateral pinchout complex, lenses, low-amplitude structures, nose-like structures, and lithologically self-sealing). According to the geological characteristics of coal rock gas, the Benxi Formation is divided into 8 plays, and the estimated coal rock gas resources with a buried depth of more than 2 000 m are more than 12.33 trillion cubic meters. The above understandings guide the deployment of risk exploration. Two wells drilled accordingly obtained an industrial gas flow, driving the further deployment of exploratory and appraisal wells. Substantial breakthroughs have been achieved, with the possible reserves booked to be over a trillion cubic meters and the proved reserves over a hundred billion cubic meters, which is of great significance for the reserves increase and efficient development of natural gas reserves in China.

In order to clarify the influence of liquid sulfur deposition and adsorption to high-H₂S gas reservoirs, three types of natural cores with typical carbonate pore structures were selected for high-temperature and high-pressure core displacement experiments. Fine quantitative characterization of the cores in three steady states (original, after sulfur injection, and after gas flooding) was carried out using the nuclear magnetic resonance (NMR) transverse relaxation time spectrum and imaging, X-ray computer tomography (CT) of full-diameter cores, basic physical property testing, and field emission scanning electron microscopy imaging. The results show that the loss of pore volume caused by sulfur deposition and adsorption mainly comes from the medium and large pores with sizes bigger than 1000 μm. Liquid sulfur has a stronger adsorption and deposition ability in smaller pores and disconnected pore spaces, making it more likely to deposit and plug, which has a negative effect on pore volume and connectivity. It causes greater damage to reservoirs with poor original pore structures. The pore structure of the three types of carbonate reservoirs shows multiple fractal characteristics. The worse the pore structure, the greater the change of internal space pore distribution caused by liquid sulfur deposition and adsorption, and the stronger the heterogeneity. Liquid sulfur deposition and adsorption change the pore size distribution, pore connectivity, and heterogeneity of the rock, which further changes the physical properties of the reservoir. After sulfur injection and gas flooding, the permeability of Type I reservoirs with good physical properties decreased by 16%, and that of Types II and III reservoirs with poor physical properties decreased by 90% or more, suggesting an extremely high damage. This indicates that the worse the initial physical properties, the greater the damage of liquid sulfur deposition and adsorption. Liquid sulfur is adsorbed and deposited in different types of pore space in the form of flocculent, cobweb, or retinaculum, causing different changes in the pore structure and physical properties of the reservoir.

Based on the research and summary of igneous intrusions and contacted metamorphic rock reservoirs in Bohai Bay Basin, a geological model of igneous intrusion contact metamorphic system is proposed using seismic data, logging data, physical property analysis and oriented thin section, combined with the condensation characteristics of magma intrusion along the bedding of sedimentary rock, the high-temperature baking effect on the surrounding rock and the symbiotic relationship. This model is applied on the reservoirs of Paleogene Shahejie Formation in Nanpu sag, and the geological significance of reservoir is revealed. This system, consisted of the intrusion, the upper metamorphic zone and the lower metamorphic zone, as well as top and bottom host rock, has three basic elements: the intrusion, contact metamorphic zones (metamorphic rock reservoirs) and host rock. In this sense, a research method and process for determining intrusion bodies, identifying contact metamorphic zones, and characterizing metamorphic rock reservoirs have been established. The host rock of the system is sedimentary rock, which is metamorphic rock formed after thermal contact and metamorphism near the intrusion, with matrix pores and fractures as reservoir spaces. The matrix pores are secondary “intergranular pores” distributed around metamorphic minerals after baking, metamorphism and transformation. The fractures are mainly structural fractures and intrusive compression fractures. A mixed light source superposition display method for thin section is innovated, which can clearly display the identification, spatial distribution and connectivity of complex micro reservoir spaces. The thickness of the intrusion body and the intensity of baking control the reservoir spatial distribution of the contact metamorphic zone. The coupling of thermal contact and metamorphism with favorable lithology is the key to the formation of favorable reservoirs. The proposal and application of the geological model of the igneous intrusion contact metamorphic system have promoted the further research and exploration of contact metamorphic rock reservoirs in Nanpu sag, and has an instructional significance for the study of contact metamorphic reservoirs in the middle-deep strata of the Bohai Bay Basin.

The types, occurrence and composition of authigenic clay minerals in the first member of the Middle Permian Maokou Formation (Mao-1 Member) in eastern Sichuan Basin were investigated through outcrop section measurement, core description, thin section identification, argon ion polishing, XRD diffraction, SEM-EDS and LA-ICP-MS. The diagenetic evolution sequence of clay minerals was clarified, and the sedimentary-diagenetic evolution model of clay minerals was established. The results show that authigenic sepiolite minerals were precipitated in the Si^{4 +} and Mg^{2 +}-rich cool aragonite sea and sepiolite-bearing strata were formed in the Mao-1 Member. During burial diagenesis, authigenic clay minerals undergo two possible evolution sequences. First, from the early diagenetic stage A to the middle diagenetic stage A₁, the sepiolite kept stable in the shallow-buried environment lack of Al³⁺. It began to transform into stevensite in the middle diagenetic stage A₂, and then evolved into disordered talc in the middle diagenetic stage B₁ and finally into talc in the period from the middle diagenetic stage B₂ to the late diagenetic stage. Thus, the primary diagenetic evolution sequence of authigenic clay minerals, i.e. sepiolite-stevens-disordered talc-talc, was formed in the Mao-1 Member. Second, in the early diagenetic stage A, as Al³⁺ carried by the storm and upwelling currents was involved in the diagenetic process, trace of sepiolite started to evolve into smectite, and a part of smectite turned into chlorite. From the early diagenetic stage B to the middle diagenesis stage A₁, a part of smectite evolved to illite/smectite mixed layer (I/S). The I/S evolved initially into illite from the middle diagenesis stage A₂ to the middle diagenesis stage B₂, and then totally into illite in the late diagenesis stage. Thus, the secondary diagenetic evolution sequence of authigenic clay minerals, i.e. sepiolite-smectite-chlorite/illite, was formed in the Mao-1 Member. The types and evolution of authigenic clay minerals in argillaceous limestone of sepiolite-bearing strata are significant for petroleum geology in two aspects. First, sepiolite can adsorb and accumulate a large amount of organic matters, thereby effectively improving the quality and hydrocarbon generation potential of the source rocks of the Mao-1 Member. Second, the evolution from sepiolite to talc is accompanied by the formation of numerous organic matter pores and clay shrinkage pores/fractures, as well as the releasing of the Mg²⁺-rich diagenetic transformation fluid, which allows for the dolomitization of limestone within or around the sag. As a result, the new assemblages of self-generation and self-accumulation, and lower/side source and upper/lateral reservoir, are created in the Middle Permian, enhancing the hydrocarbon accumulation efficiency.

To address the issue of horizontal well production affected by the distribution of perforation density in the wellbore, a numerical model for simulating two-phase flow in a horizontal well is established under two perforation density distribution conditions (i.e. increasing the perforation density at inlet and outlet sections respectively). The simulation results are compared with experimental results to verify the reliability of the numerical simulation method. The behaviors of the total pressure drop, superficial velocity of air-water two-phase flow, void fraction, liquid film thickness, air production and liquid production that occur with various flow patterns are investigated under two perforation density distribution conditions based on the numerical model. The total pressure drop, mixture’s superficial velocity and void fraction increases with the air superficial velocity when the water superficial velocity is constant. The liquid film thickness decreases when the air superficial velocity increases. The liquid and air productions increase when the perforation density increases at the inlet section of the perforated horizontal wellbore. It is noted that the air production increases with the air flow rate. Liquid production increases with the bubble flow and begins to decrease at the transition point of the slug-stratified flow, then increases through the stratified wave flow. The normalized flux is higher when the perforation density increases at the inlet section, and increases with the radial air flow rate.

A physical simulation method with a combination of dynamic displacement and imbibition was established by integrating nuclear magnetic resonance (NMR) and CT scanning. The microscopic pore throat production mechanism of tight/shale oil dynamic imbibition and the influencing factors on the development effect of dynamic imbibition were analyzed. The dynamic seepage process of fracking-soaking-backflow-production integration was simulated, which reveals the dynamic production characteristics of different development stages and their contribution to enhancing oil recovery (EOR). The results show that the seepage of tight/shale reservoirs can be divided into three stages: strong displacement and weak imbibition produced rapidly by displacement between macropores and fractures, weak displacement and strong imbibition produced slowly by reverse imbibition of small pores, and weak displacement and weak imbibition at dynamic equilibrium. The greater the displacement pressure, the higher the displacement recovery, and the lower the imbibition recovery. However, if the displacement pressure is too high, the injected water is easy to break through the front and reduce the recovery degree. The higher the permeability, the greater the imbibition and displacement recovery, the shorter the time of imbibition balance, and the higher the final recovery. The fracture can effectively increase the imbibition contact area between matrix and water, reduce the oil-water seepage resistance, promote the oil-water displacement between matrix and fracture, and improve the oil displacement rate and recovery of the matrix. The soaking after fracturing is beneficial to the imbibition replacement and energy storage of the fluid; also, the effective use of the carrying of the backflow fluid and the displacement in the mining stage is the key to enhancing oil recovery.

Based on the analysis of light hydrocarbon compositions of natural gas and regional comparison in combination with the chemical components and carbon isotopic values of methane, the indication of geochemical characteristics of light hydrocarbon on the migration features and secondary alteration of natural gas from the Dongsheng gas field in the Ordos Basin is revealed, and the effect of migration on specific light hydrocarbon indexes is further discussed. The study indicates that, natural gas from the Lower Shihezi Formation (P₁x) in the Dongsheng gas field displays higher iso-C_5-7 contents than n-C_5-7, and the C_6-7 light hydrocarbons are mainly composed of paraffins with extremely low aromatic contents (<0.4%), whereas the C₇ light hydrocarbons are mainly dominated by methylcyclohexane, suggesting the characteristics of coal-derived gas with the influence by secondary alterations such as dissolution. The natural gas from the Dongsheng gas field has experienced free-phase migration from south to north and different degrees of dissolution after charging, and the gas in the Shiguhao area to the north of the Borjianghaizi fault has experienced apparent escape after accumulation. Long-distance migration in free phase results in the decrease of the relative contents of the methylcyclohexane in C₇ light hydrocarbons and the toluene/n-heptane ratio, as well as the increase of the n-heptane/methylcyclohexane ratio and heptane values. The dissolution causes the increase of isoheptane values of the light hydrocarbons, whereas the escape of natural gas in the Shiguhao area results in the increase of n-C_5-7 contents compared to the iso-C_5-7 contents.

In the mid-21st century, natural gas will enter its golden age, and the era of natural gas is arriving. This paper reviews global natural gas development stages and the revelation of American shale gas revolution, summarizes the development history and achievements of the natural gas industry in China, analyzes the status and challenges of natural gas in the green and low-carbon energy transition, and puts forward the natural gas industry development strategies under carbon neutral target in China. The natural gas industry in China has experienced three periods: start, growth, and leap forward. At present, China has become the fourth largest natural gas producer and third largest natural gas consumer in the world, and has made great achievements in natural gas exploration and development theory and technology, providing important support for the growth of production and reserves. China has set its goal of carbon neutrality to promote green and sustainable development, which brings opportunities and challenges for natural gas industry. Natural gas has significant low-carbon advantages, and gas-electric peak shaving boosts new energy development. For the national energy security and harmonious development between economy and ecology under the carbon neutrality goal, based on the principle of “comprehensive planning, technological innovation, multiple complementarity, multi-energy integration, flexibility and efficiency, optimization and upgrading”, the construction of the production-supply-storage-marketing system has to be improved so as to boost the development of the natural gas industry. Systematic measures and great efforts are needed. First, it is necessary to strengthen efforts in the exploration and development of natural gas, making plans and arrangement in key exploration and development areas, making breakthroughs in key science theories and technologies, in order to increase reserve and production. Second, it should promote green and innovative development of the natural gas by developing new techniques, expanding new fields and integrating with new energy. Third, there is a demand to realize transformation and upgrading of the supply and demand structure of natural gas by strengthening the layout of pipeline gas, liquefied natural gas and the construction of underground gas storage, establishing reserve system for improving abilities of emergency response and adjustment, raising the proportion of natural gas in the primary energy consumption and contributing to the transformation of energy consumption structure, realizing low-carbon resources utilization and clean energy consumption.

Super oil and gas basins provide the energy foundation for social progress and human development. In the context of climate change and carbon peak and carbon neutrality goals, constructing an integrated energy and carbon neutrality system that balances energy production and carbon reduction becomes crucial for the transformation of such basins. Under the framework of a green and intelligent energy system primarily based on “four news”, new energy, new electricity, new energy storage, and new intelligence energy, integrating a “super energy system” composed of a huge amount of underground resources of coal, oil, gas and heat highly overlapping with abundant wind and solar energy resources above ground, and a regional intelligent energy consumption system with integrated and coordinated development and utilization of fossil energy and new energy, with a carbon neutrality system centered around carbon cycling is essential. This paper aims to select the traditional oil and gas basins as “super energy basins” with the conditions to build world-class energy production and demonstration bases for carbon neutrality. The Ordos Basin has unique regional advantages, including abundant fossil fuel and new energy resources, as well as matching CO₂ sources and sinks, position it as a carbon neutrality “super energy basin” which explores the path of transformation of traditional oil and gas basins. Under the integrated development concept and mode of “coal + oil + gas + new energy + carbon capture, utilization, and storage (CCUS)/carbon capture and storage (CCS)”, the carbon neutrality in super energy basin is basically achieved, which enhance fossil energy supply and contribute to the carbon peak and carbon neutrality goals, establish a modern energy industry and promote green and sustainable development. The pioneering construction of the world-class carbon neutrality “super energy system” demonstration basin in China represented by the Ordos Basin will reshape the new concept and new mode of exploration and development of super energy basins, which is of great significance to the global energy revolution under carbon neutral.

Based on the 3D seismic data and the analysis and test data of lithology, electricity, thin sections and chronology obtained from drilling of the Qiongdongnan Basin, the characteristics and the quantitative analysis of the source-sink system are studied of the third member of the Upper Oligocene Lingshui Formation (Ling 3 Member) in the southern fault step zone of the Baodao Sag. First, the YL10 denudation area of the Ling 3 Member mainly developed two river systems in the east and west, resulting in the formation of two dominant sand transport channels and two delta lobes in southern Baodao Sag, which are generally large in the west and small in the east. The longitudinal evolution of the delta has experienced four stages: initiation, prosperity, intermittence, and rejuvenation. Second, the source-sink coupled quantitative calculation is performed depending on the parameters of the delta sand bodies, including development phases, distribution area, flattening thickness, area of different source rocks, and sand-forming coefficient, showing that the study area has the material basis for the formation of large-scale reservoir. Third, the drilling reveals that the delta of the Ling 3 Member is dominated by fine sandstone, with total sandstone thickness of 109-138 m, maximum single-layer sandstone thickness of 15.5-30.0 m, and net-to-gross ratio of 43.7%-73.0%, but the reservoir physical properties are obviously different among different fault steps. Fourth, the large delta development model of the multi-stage uplift small provenance area in the step fault zone is established. It suggests that the curtain uplift orogeny provides sufficient sediments, the river system and watershed area control the scale of the sand body, the multi-step active fault steps dominate the sand body transport channel, and local fault troughs decides the lateral propulsion direction of the sand body. The delta of the Ling 3 Member is coupled with fault blocks to form diverse traps, which are critical exploration targets in southern Baodao Sag.

The loose rocks in the Pleistocene Qigequan Formation in the Sanhu Depression of the Qaidam Basin contain biogas, which makes it difficult to characterize structural features, restore sedimentary facies, and predict reservoirs by using P-wave seismic data. To solve this problem, a S-wave 9-component 3D seismic dataset was introduced to seismic sedimentology (i.e., seismic geomorphology and seismic lithology) to build a fourth-order isochronous stratigraphic framework for purpose of sedimentary facies and reservoirs evaluation in the Sanhu region. Under this framework, the techniques of phase rotation, frequency decomposition and fusion, and stratal slicing were utilized to restore sedimentary facies of major marker beds with the guidance of sedimentary model reflected by satellite images. Techniques of seismic attribute extraction, principal component analysis, and random fitting were applied to calculate reservoir thickness and physical parameters of the key sand zones, and the results are satisfactory and confirmed by blind testing wells. The dominant sedimentary facies of major marker beds in the Qigequan Formation within the studied S-wave seismic survey are prodelta and shallow lake. There are lots of channels in the prodelta. In the key sand zone 4-1-4cd, sedimentary facies control reservoir thickness and porosity, and permeability is also affected by diagenesis. In the key sand zone, reservoirs are developed widely, with the biogas in place estimated to be over 79.17×10⁸ m³. Nearly half of the reserves are endowed outside of the known main gas field, which indicates a huge exploration potential.

This work systematically reviews the complex mechanisms of CO₂-water-rock interactions, microscopic simulations of porous media reactive transport (dissolution, precipitation, and precipitation migration), and the latest advancements in microscopic simulations of CO₂-water-rock system. The work points out key issues in current research and provides suggestions for future research. After injection of CO₂ into underground reservoirs, not only conventional pressure-driven flow and mass transfer processes occur, but also special physicochemical phenomena like dissolution, precipitation, and precipitation migration. The coupling of these processes causes complex changes in permeability and porosity parameters of the porous media. Pore-scale microscopic flow simulations can provide detailed information within the three-dimensional pore space and explicitly observe changes in the fluid-solid interfaces of porous media during reactions. At present, research has limitations in the decoupling of complex mechanisms, characterization of differential multi-mineral reactions, precipitation generation mechanisms and characterization (crystal nucleation and mineral detachment), simulation methods for precipitation-fluid interaction migration, and coupling mechanisms of multiple physicochemical processes. In future studies, it is essential to innovate experimental methods to decouple “dissolution-precipitation-precipitation migration” processes, improve the accuracy of experimental testing of minerals geochemical reaction-related parameters, build reliable characterization of various precipitation types, establish precipitation-fluid interaction and migration simulation methods, coordinate the boundary conditions of different physicochemical processes, and, finally, achieve coupled flow simulation of “dissolution-precipitation-precipitation migration” within CO₂-water-rock systems.

Based on the study of the distribution of intra-platform shoals and the characteristics of dolomite reservoirs in the Middle Permian Qixia Formation in the Gaoshiti-Moxi area of the Sichuan Basin, the controlling factors of reservoir development were analyzed, and the formation model of “intra-platform shoal type thin-layer dolomite reservoir” was established. The Qixia Formation is a regressive cycle from bottom to top, in which the first member (Qi1 Member) develops low-energy open sea microfacies, and the second member (Qi2 Member) evolves into intra-platform shoal and inter-beach sea with the sea level decreases. The intra-platform shoal is mainly distributed near the top of two secondary shallowing cycles of the Qi2 Member. The most important reservoir rock of the Qixia Formation is thin-layer fracture-cavity dolomite, followed by cavity dolomite. The semi-filled saddle dolomite is common in fracture-cavity, and intercrystalline pores and residual dissolution pores combined with fractures to form the effective pore-fracture network. Based on the coupling analysis of sedimentary and diagenesis characteristics, the reservoir formation model of “pre-depositional micro-palaeogeomorphology controlling beach, sedimentary beach controlling dolomite, penecontemporaneous dolomite laying the foundation, and late hydrothermal action effectively improving quality” was systematically established. The “first-order high zone” micro-paleogeomorphology before the deposition of the Qixia Formation controlled the development of the large area of intra-platform shoals in Gaoshiti area during the deposition of the Qi2 Member. Beach facies is the basic condition of early dolomitization, and the distribution range of intra-platform shoal and dolomite reservoir is highly consistent. The grain limestone of beach facies is transformed by two stages of dolomitization. The penecontemporaneous dolomitization is conducive to the preservation of primary pores and secondary dissolved pores. The burial hydrothermal fluid enters the early dolomite body along the fractures associated with the Emeishan basalt event, so that it is recrystallized into medium-coarse crystal dolomite. The intercrystalline pores and the residual vugs after the hydrothermal dissolution along the fracture formed the high-quality intraplatform shoal-type thin-layer dolomite reservoir. The establishment of this reservoir formation model can provide important theoretical support for the sustainable development of Permian gas reservoirs in the Sichuan Basin.