A seepage-geomechanical coupled embedded fracture flow model has been established for multi-field coupled simulation in tight oil reservoirs, revealing the patterns of change in pressure field, seepage field, and stress field after long-term water injection in tight oil reservoirs. Based on this, a technique for enhanced oil recovery (EOR) combining multi-field reconstruction and combination of displacement and imbibition in tight oil reservoirs has been proposed. The study shows that after long-term water flooding for tight oil development, the pressure diffusion range is limited, making it difficult to establish an effective displacement system. The variation in geostress exhibits diversity, with the change in horizontal minimum principal stress being greater than that in horizontal maximum principal stress, and the variation around the injection wells being more significant than that around the production wells. The deflection of geostress direction around injection wells is also large. The technology for EOR through multi-field reconstruction and combination of displacement and imbibition employs water injection wells converted to production and large-scale fracturing techniques to restructure the artificial fracture network system. Through a full lifecycle energy replenishment method of pre-fracturing energy supplementation, energy increase during fracturing, well soaking for energy storage, and combination of displacement and imbibition, it effectively addresses the issue of easy channeling of the injection medium and difficult energy replenishment after large-scale fracturing. By intensifying the imbibition effect through the coordination of multiple wells, it reconstructs the combined system of displacement and imbibition under a complex fracture network, transitioning from avoiding fractures to utilizing them, thereby improving microscopic sweep and oil displacement efficiencies. Field application in Block Yuan 284 of the Huaqing Oilfield in the Ordos Basin has demonstrated that this technology increases the recovery factor by 12 percentage points, enabling large scale and efficient development of tight oil.

This work systematically reviews the complex mechanisms of CO₂-water-rock interactions, microscopic simulations of reactive transport (dissolution, precipitation and precipitate migration) in porous media, and microscopic simulations of CO₂-water-rock system. The work points out the 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 precipitate 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 and throat space and explicitly observe changes in the fluid-solid interfaces of porous media during reactions. At present, the 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, and coupling mechanisms of multiple physicochemical processes. In future studies, it is essential to innovate experimental methods to decouple “dissolution-precipitation-precipitate 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 simulation methods, coordinate the boundary conditions of different physicochemical processes, and, finally, achieve coupled flow simulation of “dissolution-precipitation-precipitate migration” within CO₂-water-rock systems.

Based on the elastic theory of porous media, embedded discrete fracture model and finite volume method, and considering the micro-seepage mechanism of shale gas, a fully coupled seepage-geomechanical model suitable for fractured shale gas reservoirs is established, the optimization method of refracturing timing is proposed, and the influencing factors of refracturing timing are analyzed based on the data from shale gas well in Fuling of Sichuan Basin. The results show that due to the depletion of formation pressure, the percentage of the maximum horizontal principal stress reversal area in the total area increases and then decreases with time. The closer the area is to the hydraulic fracture, the shorter the time for the peak of the stress reversal area percentage curve to appear, and the shorter the time for the final zero return (to the initial state). The optimum time of refracturing is affected by matrix permeability, initial stress difference and natural fracture approach angle. The larger the matrix permeability and initial stress difference is, the shorter the time for stress reversal area percentage curve to reach peak and return to the initial state, and the earlier the time to take refracturing measures. The larger the natural fracture approach angle is, the more difficult it is for stress reversal to occur near the fracture, and the earlier the optimum refracturing time is. The more likely the stress reversal occurs at the far end of the artificial fracture, the later the optimal time of refracturing is. Reservoirs with low matrix permeability have a rapid decrease in single well productivity. To ensure economic efficiency, measures such as shut-in or gas injection can be taken to restore the stress, and refracturing can be implemented in advance.

Foam stability tests were performed using sodium dodecyl sulfate (SDS) surfactant and SiO₂ nanoparticles as foaming system at different asphaltene concentrations, and the half-life of CO₂ foam was measured. The mechanism of foam stability reduction in the presence of asphaltene was analyzed by scanning electron microscope (SEM), UV adsorption spectrophotometric concentration measurement and Zeta potential measurement. When the mass ratio of synthetic oil to foam-formation suspension was 1:9 and the asphaltene mass fraction increased from 0 to 15%, the half-life of SDS-stabilized foams decreased from 751 s to 239 s, and the half-life of SDS/silica-stabilized foams decreased from 912 s to 298 s. When the mass ratio of synthetic oil to foam-formation suspension was 2:8 and the asphaltene mass fraction increased from 0 to 15%, the half-life of SDS-stabilized foams decreased from 526 s to 171 s, and the half-life of SDS/silica-stabilized foams decreased from 660 s to 205 s. In addition, due to asphaltene-SDS/silica interaction in the aqueous phase, the absolute value of Zeta potential decreases, and the surface charges of particles reduce, leading to the reduction of repulsive forces between two interfaces of thin liquid film, which in turn, damages the foam stability.

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, superficial velocity of the mixture and void fraction increase with the air flow rate when the water flow rate is constant. The liquid film thickness decreases when the air flow rate increases. The liquid and air productions increase when the perforation density increases at the inlet section compared with increasing the perforation density at the outlet 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 liquid flux is higher when the perforation density increases at the inlet section, and increases with the radial air flow rate.

To analyze the episodic alteration of Middle Permian carbonate reservoirs by complex hydrothermal fluid in southwestern Sichuan Basin, petrology, geochemistry, fluid inclusion and U-Pb dating researches are conducted. The fractures and vugs of Middle Permian Qixia-Maokou formations are filled with multi-stage medium-coarse saddle dolomites and associated hydrothermal minerals, which indicates that the early limestone/dolomite episodic alteration was caused by the large-scale, high-temperature, deep magnesium-rich brine along flowing channels such as basement faults or associated fractures under the tectonic compression and napping during the Indosinian. The time of magnesium-rich hydrothermal activity was from the Middle Triassic to the Late Triassic. The siliceous and calcite fillings were triggered by hydrothermal alteration in the Middle and Late Yanshanian Movement and Himalayan Movement. Hydrothermal dolomitization is controlled by fault, hydrothermal property, flowing channel and surrounding rock lithology, which occur as equilibrium effect of porosity and permeability. The thick massive grainstone/dolomites were mainly altered by modification such as hydrothermal dolomitization/recrystallization, brecciation and fracture-vugs filling. Early thin-medium packstones were mainly altered by dissolution and infilling of fracturing, bedding dolomitization, dissolution and associated mineral fillings. The dissolved vugs and fractures are the main reservoir space under hydrothermal conditions, and the connection of dissolved vugs and network fractures is favorable for forming high-quality dolomite reservoir. Hydrothermal dolomite reservoirs are developed within a range of 1 km near faults, with a thickness of 30-60 m. Hydrothermal dolomite reservoirs with local connected pore/vugs and fractures have exploration potential.

Considering the phase behaviors in condensate gas reservoirs and the oil-gas two-phase linear flow and boundary-dominated flow in the reservoir, a method for predicting the relationship between oil saturation and pressure in the full-path of tight condensate gas well is proposed, and a model for predicting the transient production from tight condensate gas wells with multiphase flow is established. The research indicates that the relationship curve between condensate oil saturation and pressure is crucial for calculating the pseudo-pressure. In the early stage of production or in areas far from the wellbore with high reservoir pressure, the condensate oil saturation can be calculated using early-stage production dynamic data through material balance models. In the late stage of production or in areas close to the wellbore with low reservoir pressure, the condensate oil saturation can be calculated using the data of constant composition expansion test. In the middle stages of production or when reservoir pressure is at an intermediate level, the data obtained from the previous two stages can be interpolated to form a complete full-path relationship curve between oil saturation and pressure. Through simulation and field application, the new method is verified to be reliable and practical. It can be applied for prediction of middle-stage and late-stage production of tight condensate gas wells and assessment of single-well recoverable reserves.

Taking the Lower Permian Fengcheng Formation shale in Mahu Sag of Junggar Basin, NW China, as an example, core observation, test analysis, geological analysis and numerical simulation were applied to identify the shale oil micro-migration phenomenon. The hydrocarbon micro-migration in shale oil was quantitatively evaluated and verified by a self-created hydrocarbon expulsion potential method, and the petroleum geological significance of shale oil micro-migration evaluation was determined. Results show that significant micro-migration can be recognized between the organic-rich lamina and organic-poor lamina. The organic-rich lamina has strong hydrocarbon generation ability. The heavy components of hydrocarbon preferentially retained by kerogen swelling or adsorption, while the light components of hydrocarbon were migrated and accumulated to the interbedded felsic or carbonate organic-poor laminae as free oil. About 69% of the Fengcheng Formation shale samples in Well MY1 exhibit hydrocarbon charging phenomenon, while 31% of those exhibit hydrocarbon expulsion phenomenon. The reliability of the micro-migration evaluation results was verified by combining the group components based on the geochromatography effect, two-dimension nuclear magnetic resonance analysis, and the geochemical behavior of inorganic manganese elements in the process of hydrocarbon migration. Micro-migration is a bridge connecting the hydrocarbon accumulation elements in shale formations, which reflects the whole process of shale oil generation, expulsion and accumulation, and controls the content and composition of shale oil. The identification and evaluation of shale oil micro-migration will provide new perspectives for dynamically differential enrichment mechanism of shale oil and establishing a “multi-peak model in oil generation” of shale.

Based on the analysis of the fluid inclusion homogenization temperature and apatite fission track on the northern slope zone of the Bongor Basin in Chad, this paper studied the time and stages of hydrocarbon accumulation in the study area. The results show that: (1) The brine inclusions of the samples from the Kubla and Prosopis formations in the Lower Cretaceous coexisting with the hydrocarbon generally present two sets of peak ranges of homogenization temperature, with the peak ranges of low temperature and high temperature being 75-105 °C and 115-135 °C, respectively; (2) The samples from the Kubla and Prosopis formations have experienced five tectonic evolution stages, i.e., rapid subsidence in the Early Cretaceous, tectonic inversion in the Late Cretaceous, small subsidence in the Paleogene, uplift at the turn of the Paleogene and Neogene, and subsidence since the Miocene, in which the denudation thickness of the Late Cretaceous and after the turn of the Paleogene and Neogene are ~1.8 km and ~0.5 km, respectively. The cumulative denudation thickness of the two periods is about 2.3 km; (3) Using the brine inclusion homogenization temperature coexisting with the hydrocarbon as the capture temperature of the hydrocarbon, and combining with the apatite fission track thermal history modeling, the result shows that the Kubla and Prosopis formations in the Lower Cretaceous on the northern slope of the Bongor Basin have the same hydrocarbon accumulation time and stages, both of which have undergone two stages of hydrocarbon charging at 80-95 Ma and 65-80 Ma. The first stage of charging corresponds to the initial migration of hydrocarbon at the end of the Early Cretaceous rapid sedimentation, while the second stage of charging is in the stage of intense tectonic inversion in the Late Cretaceous.

The Ediacaran-Ordovician strata within three major marine basins (Tarim, Sichuan, and Ordos) in China are analyzed. Based on previous studies focusing on the characteristics of the Neoproterozoic-Cambrian strata within the three major basins (East Siberian, Oman, and Officer in Australia) overseas, the carbonate-evaporite assemblages in the target interval are divided into three types: intercalated carbonate and gypsum salt, interbedded carbonate and gypsum salt, and coexisted carbonate, gypsum salt and clastic rock. Moreover, the concept and definition of the carbonate-evaporite assemblage are clarified. The results indicate that the oil and gas in the carbonate-evaporite assemblage are originated from two types of source rocks: shale and argillaceous carbonate, and confirmed the capability of gypsum salt in the saline environment to drive the source rock hydrocarbon generation. The dolomite reservoirs are classified in two types: gypseous dolomite flat, and grain shoal & microbial mound. This study clarifies that the penecontemporaneous or epigenic leaching of atmospheric fresh water mainly controlled the large-scale development of reservoirs. Afterwards, burial dissolution transformed and reworked the reservoirs. The hydrocarbon accumulation in carbonate-evaporite assemblage can be categorized into eight sub-models under three models (sub-evaporite hydrocarbon accumulation, supra-evaporite hydrocarbon accumulation, and inter-evaporite hydrocarbon accumulation). As a result, the Cambrian strata in the Tazhong Uplift North Slope, Maigaiti Slope and Mazatag Front Uplift Zone of the Tarim Basin, the Cambrian strata in the eastern-southern area of the Sichuan Basin, and the inter-evaporite Ma-4 Member of Ordovician in the Ordos Basin, China, are defined as favorable targets for future exploration.

Based on core and thin section data, the source rock samples from the Fengcheng Formation in the Mahu Sag of the Junggar Basin were analyzed in terms of zircon SIMS U-Pb geochronology, organic carbon isotopic composition, major and trace element contents, as well as petrology. Two zircon U-Pb ages of (306.0±5.2) Ma and (303.5±3.7) Ma were obtained from the first member of the Fengcheng Formation. Combined with carbon isotopic stratigraphy, it is inferred that the depositional age of the Fengcheng Formation is about 297-306 Ma, spanning the Carboniferous-Permian boundary and corresponding to the interglacial period between C4 and P1 glacial events. 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 the Fengcheng Formation, associated with the occurrence of evaporite minerals and reedmergnerite, indicating that the high salinity of the water mass was related to hydrothermal activity. Comprehensive analysis suggests that the warm and humid climate during the deposition of Fengcheng Formation is conducive to the growth of organic matter such as algae and bacteria in the lake, and accelerates the continental weathering, driving the input of nutrients. Volcanic activities supply a large amount of nutrients and stimulate primary productivity. The warm climate and high salinity are conducive to water stratification, leading to water anoxia that benefits organic matter preservation. The above factors interact and jointly control the enrichment of organic matter in the Fengcheng Formation of Mahu Sag.

Based on the practice of oil and gas exploration in the Huizhou Sag of the Pearl River Mouth Basin, the geochemical indexes of source rocks were measured, the reservoir development morphology was restored, the rocks and minerals were characterized microscopically, the measured trap sealing indexes were compared, the biomarker compounds of crude oil were extracted, the genesis of condensate gas was identified, and the reservoir-forming conditions were examined. On this basis, the Paleogene Enping Formation in the Huizhou 26 subsag was systematically analyzed for the potential of oil and gas resources, the development characteristics of large-scale high-quality conglomerate reservoirs, the trapping effectiveness of faults, the hydrocarbon migration and accumulation model, and the formation conditions and exploration targets of large- and medium-sized glutenite-rich oil and gas fields. The research results were obtained in four aspects. First, the Paleogene Wenchang Formation in the Huizhou 26 subsag develops extensive and thick high-quality source rocks of semi-deep to deep lacustrine subfacies, which have typical hydrocarbon expulsion characteristics of "great oil generation in the early stage and huge gas expulsion in the late stage", providing a sufficient material basis for hydrocarbon accumulation in the Enping Formation. Second, under the joint control of the steep slope zone and transition zone of the fault within the sag, the large-scale near-source glutenite reservoirs are highly heterogeneous, with the development scale dominated hierarchically by three factors (favorable facies zone, particle component, and microfracture). The (subaqueous) distributary channels near the fault system, with equal grains, a low mud content (<5%), and a high content of feldspar composition, are conducive to the development of sweet spot reservoirs. Third, the strike-slip pressurization trap covered by stable lake flooding mudstone is a necessary condition for oil and gas preservation, and the NE and nearly EW faults obliquely to the principal stress have the best control on traps. Fourth, the spatiotemporal configuration of high-quality source rocks, fault transport/sealing, and glutenite reservoirs controls the degree of hydrocarbon enrichment. From top to bottom, three hydrocarbon accumulation units, i.e. low-fill zone, transition zone, and high-fill zone, are recognized. The main area of the channel in the nearly pressurized source-connecting fault zone is favorable for large-scale hydrocarbon enrichment. The research results suggest a new direction for the exploration of large-scale glutenite-rich reservoirs in the Enping Formation of the Pearl River Mouth Basin, and present a major breakthrough in oil and gas exploration.

To clarify the formation and distribution of feldspar dissolution pores and predict the distribution of high-quality reservoir in gravity flow sandstone of the 7^th member of Triassic Yanchang Formation (Chang 7 Member) in the Ordos Basin, thin sections, scanning electron microscopy, energy spectrum analysis, X-ray diffraction whole rock analysis, and dissolution experiments are employed in this study to investigate the characteristics and control factors of feldspar dissolution pores. The results show that: (1) Three types of diagenetic processes are observed in the feldspar of Chang 7 sandstone in the study area: secondary overgrowth of feldspar, replacement by clay and calcite, and dissolution of detrital feldspar. (2) The feldspar dissolution of Chang 7 tight sandstone is caused by organic acid, and is further affected by the type of feldspar, the degree of early feldspar alteration, and the buffering effect of mica debris on organic acid. (3) Feldspars have varying degrees of dissolution. Potassium feldspar is more susceptible to dissolution than plagioclase. Among potassium feldspar, orthoclase is more soluble than microcline, and unaltered feldspar is more soluble than early kaolinized or sericitized feldspar. (4) The dissolution experiment demonstrated that the presence of mica can hinder the dissolution of feldspar. Mica of the same mass has a significantly stronger capacity to consume organic acids than feldspar. (5) Dissolution pores in feldspar of Chang 7 Member are more abundant in areas with low mica content, and they improve the reservoir physical properties, while in areas with high mica content, the number of feldspar dissolution pores decreases significantly.

Thin section and argon-ion polishing scanning electron microscope observations were used to analyze the sedimentary and diagenetic environments and main diagenesis of the Permian Fengcheng Formation shales in different depositional zones of Mahu Sag in the Junggar Basin, and to reconstruct their differential diagenetic evolutional processes. The diagenetic environment of shales in the lake-central zone kept alkaline, which mainly underwent the early stage (R_o<0.5%) dominated by the authigenesis of Na-carbonates and K-feldspar and the late stage (R_o>0.5%) dominated by the replacement of Na-carbonates by reedmergnerite. The shales from the marginal zone underwent a transition from weak alkaline to acidic diagenetic environments, with the early stage dominated by the authigenesis of Mg-bearing clay and silica and the late stage dominated by the dissolution of feldspar and carbonate minerals. The shales from the transitional zone also underwent a transition from an early alkaline diagenetic environment, evidenced by the formation of dolomite and zeolite, to a late acidic diagenetic environment, represented by the reedmergnerite replacement and silicification of feldspar and carbonate minerals. The differences in formation of authigenic minerals during early diagenetic stage determine the fracability of shales. The differences in dissolution of minerals during late diagenetic stage control the content of free shale oil. Dolomitic shale in the transitional zone and siltstone in the marginal zone have relatively high content of free shale oil and strong fracability, and are favorable “sweet spots” for shale oil exploitation and development.

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 isotopic composition. The Benxi Formation coal rocks cover an area of 16×10⁴ km2, with thicknesses ranging from 2 m to 25 m, primarily consisting of bright and semi-bright coals with primitive structures and low volatile and ash contents, 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 thermal evolution (R_o of 1.2%-2.8%), and a high gas-generating capacity. They also have high stable carbon isotopic values (δ¹³C₁ of -37.6‰ to -16‰; δ¹³C₂ of -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 (0.001-14.600)×10^-3 μm² (averaging 2.32×10^-3 μm²). 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, with good sealing conditions and high peak values of total hydrocarbon in gas logging. A model of coal rock gas accumulation has been constructed, which includes 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, source-reservoir integration, and five types of efficient 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 12.33×10¹² m³. 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 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 in China.

The types, occurrence and composition of authigenic clay minerals in argillaceous limestone of sepiolite-bearing strata of the first member of the Middle Permian Maokou Formation (Mao-1 Member) in eastern Sichuan Basin were investigated through outcrop section measurement, core observation, thin section identification, argon ion polishing, X-ray diffraction, scanning electron microscope, energy spectrum analysis and laser ablation-inductively coupled plasma-mass spectrometry. 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 Si⁴⁺ and Mg²⁺-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-stevensite-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 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.

Based on the microfluidic technology, a microscopic visualization model was used to simulate the gas injection process in the initial construction stage and the bottom water invasion/gas injection process in the cyclical injection-production stage of the underground gas storage (UGS) rebuilt from water-invaded gas reservoirs. Through analysis of the gas-liquid contact stabilization mechanism, flow and occurrence, the optimal control method for lifecycle efficient operation of UGS was explored. The results show that in the initial construction stage of UGS, the action of gravity should be fully utilized by regulating the gas injection rate, so as to ensure the macroscopically stable migration of the gas-liquid contact, and greatly improve the gas sweeping capacity, providing a large pore space for gas storage in the subsequent cyclical injection-production stage. In the cyclical injection-production stage of UGS, a constant gas storage and production rate leads to a low pore space utilization. Gradually increasing the gas storage and production rate, that is, transitioning from small volume to large volume, can continuously break the hydraulic equilibrium of the remaining fluid in the porous media, which then expands the pore space and flow channels. This is conducive to the expansion of UGS capacity and efficiency for purpose of peak shaving and supply guarantee.

Based on the geochemical, seismic, logging and drilling data, the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin 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 nose structure around sag 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 pressure difference between source and reservoir drives the charging of tight oil. The fault-sandbody transport system determines the migration and accumulation of oil and gas. The positive structure is the favorable place for tight oil enrichment, and the fault-horst zone is the key part of syncline area for tight oil exploration. Third, based on the source-reservoir relationship, transport mode, accumulation dynamics and other elements, three tight oil enrichment models are recognized in the Fuyu reservoirs: (1) vertical or lateral migration of hydrocarbon from source rocks to adjacent reservoir rocks, that is, driven by overpressure, hydrocarbon generated is migrated 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 sandbodies that are separated from the source rocks; and (3) migration of hydrocarbon 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 then migrates laterally through sandbodies. Fourth, the differences in oil source conditions, charging drive, fault distribution, 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 Sag has good conditions for tight oil enrichment and has been less explored, and it is an important new zone for tight oil exploration in the future.

This article elucidates the concept of large model technology, summarizes the research status of large model technology both domestically and internationally, provides an overview of the application status of large models in vertical industries, outlines the challenges and issues confronted in applying large models in the oil and gas sector, and offers prospects for the application of large models in the oil and gas industry. The existing large models can be briefly divided into three categories: large language models, visual large models, and multimodal large models. The application of large models in the oil and gas industry is still in its infancy. Based on open-source large language models, some oil and gas enterprises have released large language model products using methods like fine-tuning and retrieval augmented generation. Scholars have attempted to develop scenario-specific models for oil and gas operations by using visual/multimodal foundation models. A few researchers have constructed pre-trained foundation models for seismic data processing and interpretation, as well as core analysis. The application of large models in the oil and gas industry faces challenges such as current data quantity and quality being difficult to support the training of large models, high research and development costs, and poor algorithm autonomy and control. The application of large models should be guided by the needs of oil and gas business, taking the application of large models as an opportunity to improve data lifecycle management, enhance data governance capabilities, promote the construction of computing power, strengthen the construction of “artificial intelligence + energy” composite teams, and boost the autonomy and control of large model technology.

The miscibility of flue gas and different types of light oils is investigated through slender-tube miscible displacement experiment at high temperature and high pressure. Under the conditions of high temperature and high pressure, the miscible displacement of flue gas and light oil is possible. At the same temperature, there is a linear relationship between oil displacement efficiency and pressure. At the same pressure, the oil displacement efficiency increases gently and then rapidly to more than 90% to achieve miscible displacement with the increase of temperature. The rapid increase of oil displacement efficiency is closely related to the process that the light components of oil transit in phase state due to distillation with the rise of temperature. Moreover, at the same pressure, the lighter the oil, the lower the minimum miscibility temperature between flue gas and oil, which allows easier miscibility and ultimately better performance of thermal miscible flooding by air injection. The miscibility between flue gas and light oil at high temperature and high pressure is more typically characterized by phase transition at high temperature in supercritical state, and it is different from the contact extraction miscibility of CO₂ under conventional high pressure conditions.

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 during drilling and completion process in shale reservoir is revealed, and the protection measures are raised. The 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 the 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 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, forming 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, optimizing fracturing fluid system to protect fracture conductivity are put forward for reservoir protection.

Deep coal seams 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. 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 technique for deep coalbed methane (CBM) horizontal wells. This technique involves massive injection with high pumping rate + high-intensity proppant injection + perforation with equal apertures and limited flow + temporary plugging and diverting fractures + slick water with integrated variable viscosity + graded proppants with multiple sizes. The technique 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 flow rate 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.

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 fluvial 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 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 parent 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 sand-to-strata ratio of 43.7%-73.0%, but the physical properties are different among the fault steps. Fourth, the large delta development model of the small source area in the step fault zone with multi-stage uplift is established. It suggests that the episodic uplift provides sufficient sediments, the fluvial 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 decide 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.

Based on an elaboration of the resource potential and annual production of tight sandstone gas and shale gas in the United States and China, this paper reviews the researches on the distribution of tight sandstone gas and shale gas reservoirs, and analyzes the distribution characteristics and genetic types of tight sandstone gas reservoirs. In the United States, the proportion of tight sandstone gas in the total gas production declined from 20%-35% in 2008 to about 8% in 2023, and the shale gas production was 8 310×10⁸ m³ in 2023, about 80% of the total gas production, in contrast to the range of 5%-17% during 2000-2008. In China, the proportion of tight sandstone gas in the total gas production increased from 16% in 2010 to 28% or higher in 2023. China began to produce shale gas in 2012, with the production reaching 250×10⁸ m³ in 2023, about 11% of the total gas production of the country. The distribution of shale gas reservoirs is continuous. According to the fault presence, fault displacement and gas layer thickness, the continuous shale gas reservoirs can be divided into two types: continuity and intermittency. Most previous studies believed that both tight sandstone gas reservoirs and shale gas reservoirs are continuous, but this paper holds that the distribution of tight sandstone gas reservoirs is not continuous. According to the trap types, tight sandstone gas reservoirs can be divided into lithologic, anticlinal, and synclinal reservoirs. The tight sandstone gas is coal-derived in typical basins in China and Egypt, but oil-type gas in typical basins in the United States and Oman.

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle-Late Devonian, Early Carboniferous (Middle-Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian-Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and "shale reservoirs" are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×10¹² t and 290×10¹² m³, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the "shale revolution", the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007-2023, shale oil and gas production in the United States increased from approximately 11.2×10⁴ tons of oil equivalent per day (toe/d) to over 300.0×10⁴ toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Laboratory experiments, numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO₂ injection. The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO₂ injection, and the influences of CO₂ pre-pad on shale mechanical properties. Numerical simulations were performed about influences of CO₂ pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency. The findings obtained were applied to the field tests of CO₂ pre-pad fracturing and single well puff-n-huff. The results show that the efficiency of CO₂ puff-n-huff is affected by micro- and nano-scale effect, kerogen, adsorbed oil and so on, and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil. In the "injection + soaking" stage, the exploitation degree of heavy hydrocarbons is enhanced by CO₂ through its effects of solubility-diffusion and mass-transfer. In the "huff" stage, crude oil in large pores is displaced by CO₂ to surrounding larger pores or bedding fractures and finally flows to the production well. The injection of CO₂ pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure, and the CO₂ is liable to filter along the bedding surface, thereby creating a more complex fracture. Increasing the volume of CO₂ pre-pad can improve the energizing effect, and enhance the replenishment of formation energy. Moreover, the oil recovery is more enhanced by CO₂ huff-n-puff with the lower shale matrix permeability, the lower formation pressure, and the larger heavy hydrocarbon content. The field tests demonstrate a good performance with the pressure maintained well after CO₂ pre-pad fracturing, the formation energy replenished effectively after CO₂ huff-n-puff in a single well, and the well productivity improved.

This study conducted temporary plugging and diversion fracturing (TPDF) experiments using a true triaxial fracturing simulation system within a laboratory setting that replicated a lab-based horizontal well completion 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. 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 breaking 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 breaking 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 are primarily distributed near the perforation cluster apertures which initiated complex fractures.

Based on the observation and analysis of cores and thin sections, and combined with cathodoluminescence, laser Raman, fluid inclusions, and in-situ LA-ICP-MS U-Pb dating, the genetic mechanism and petroleum geological significance of calcite veins in shales of the Cretaceous Qingshankou Formation in the Songliao Basin were investigated. Macroscopically, the calcite veins are bedding parallel, and show lenticular, S-shaped, cone-in-cone and pinnate structures. Microscopically, they can be divided into syntaxial blocky or columnar calcite veins and antitaxial fibrous calcite veins. The aqueous fluid inclusions in blocky calcite veins have a homogenization temperature of 132.5-145.1 °C, the in-situ U-Pb dating age of blocky calcite veins is (69.9±5.2) Ma, suggesting that the middle maturity period of source rocks and the conventional oil formation period in the Qingshankou Formation are the sedimentary period of Mingshui Formation in Late Cretaceous. The aqueous fluid inclusions in fibrous calcite veins with the homogenization temperature of 141.2-157.4 °C, yields the U-Pb age of (44.7±6.9) Ma, indicating that the middle-high maturity period of source rocks and the Gulong shale oil formation period in the Qingshankou Formation are the sedimentary period of Paleocene Yi'an Formaiton. The syntaxial blocky or columnar calcite veins were formed sensitively to the diagenetic evolution and hydrocarbon generation, mainly in three stages (fracture opening, vein-forming fluid filling, and vein growth). Tectonic extrusion activities and fluid overpressure are induction factors for the formation of fractures, and vein-forming fluid flows mainly as diffusion in a short distance. These veins generally follow a competitive growth mode. The antitaxial fibrous calcite veins were formed under the driving of the force of crystallization in a non-competitive growth environment. It is considered that the calcite veins in organic-rich shale of the Qingshankou Formation in the study area has important implications for local tectonic activities, fluid overpressure, hydrocarbon generation and expulsion, and diagenesis-hydrocarbon accumulation dating of the Songliao Basin.

Based on the three-dimensional elastic-plastic finite element analysis of the 8" (203.2 mm) drill collar joint, this paper studies the mechanical characteristics of the pin and box of NC56 drill collar joints under complex load conditions, as well as the downhole secondary makeup features, and calculates the downhole equivalent impact torque with the relative offset at the shoulder of internal and external threads. On the basis of verifying the correctness of the calculation results by using measured results in Well GT1, the prediction model of the downhole equivalent impact torque is formed and applied in the first extra-deep well with a depth over 10 000 m in China (Well SDTK1). The results indicate that under complex loads, the stress distribution in drill collar joints is uneven, with relatively higher von Mises stress at the shoulder and the threads close to the shoulder. For 203.2 mm drill collar joints pre-tightened according to the make-up torque recommended by American Petroleum Institute standards, when the downhole equivalent impact torque exceeds 65 kN·m, the preload balance of the joint is disrupted, leading to secondary make-up of the joint. As the downhole equivalent impact torque increases, the relative offset at the shoulder of internal and external threads increases. The calculation results reveal that there exists significant downhole impact torque in Well SDTK1 with complex loading environment. It is necessary to use double shoulder collar joints to improve the impact torque resistance of the joint or optimize the operating parameters to reduce the downhole impact torque, and effectively prevent drilling tool failure.

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 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 isotopic 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.

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 loss of pore volume caused by sulfur deposition and adsorption mainly comes from the medium and large pores with sizes bigger than 1 000 μm. Liquid sulfur has a stronger adsorption and deposition ability in smaller pore spaces, and 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 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 forms of flocculence, cobweb, or retinitis, causing different changes in the pore structure and physical property of the reservoir.

Based on seismic, drilling, and source rock analysis data, the petroleum geological characteristics and future exploration direction of the oil-rich sags in the Central and West African Rift System (CWARS) are discussed. The study shows that the Central African Rift System mainly develops high-quality lacustrine source rocks in the Lower Cretaceous, and the West African Rift System mainly develops high-quality terrigenous organic matter-rich marine source rocks in the Upper Cretaceous, and the two types of source rocks provide a material basis for the enrichment of oil and gas in the CWARS. Multiple sets of reservoir rocks including fractured basement and three sets of regional cap rocks in the Lower Cretaceous, the Upper Cretaceous, and the Paleogene are developed in the CWARS. Since the Late Mesozoic, due to the geodynamic factors including the dextral strike-slip movement of the Central African Shear Zone, the basins in different directions of the CWARS differ in terms of rifting stages, intervals of regional cap rocks, trap types and accumulation models. The NE-SW trending basins have mainly preserved one stage of rifting in the Early Cretaceous, with regional cap rocks developed in the Lower Cretaceous strata, forming traps of reverse anticlines, flower-shaped structures and basement buried hill, and two types of hydrocarbon accumulation models of "source and reservoir in the same formation, and accumulation inside source rocks" and "up-source and down-reservoir, and accumulation below source rocks". The NW-SE basins are characterized by multiple rifting stages superimposition, with the development of regional cap rocks in the Upper Cretaceous and Paleogene, forming traps of draping anticlines, faulted anticlines, antithetic fault blocks and the accumulation model of "down-source and up-reservoir, and accumulation above source rocks". The combination of reservoir and cap rocks inside source rocks of basins with multiple superimposed rifting stages, as well as the lithologic reservoirs and the shale oil inside source rocks of strong inversion basins are important fields for future exploration in basins of the CWARS.

Taking the Paleogene Shahejie Formation in Nanpu sag of Bohai Bay Basin as an example, this study comprehensively utilizes seismic, mud logging, well logging, physical property analysis and core thin section data to investigate the metamorphic reservoir formed by contact metamorphism after igneous rock intrusion. (1) A geological model of the igneous intrusion contact metamorphic system is proposed, which can be divided into five structural layers vertically: the intrusion, upper metamorphic aureole, lower metamorphic aureole, normal sedimentary layers on the roof and floor. (2) The intrusion is characterized by xenoliths indicating intrusive facies at the top, regular changes in rock texture and mineral crystallization from the center to the edge on a microscopic scale, and low-angle oblique penetrations of the intrusion through sedimentary strata on a macroscopic scale. The metamorphic aureole has characteristics such as sedimentary rocks as the host rock, typical palimpsest textures developed, various low-temperature thermal metamorphic minerals developed, and medium-low grade thermal metamorphic rocks as the lithology. (3) The reservoir in contact metamorphic aureole has two types of reservoir spaces: matrix pores and fractures. The matrix pores are secondary “intergranular pores” distributed around metamorphic minerals after thermal metamorphic transformation in metasandstones. The fractures are mainly structural fractures and intrusive compressive fractures in metamudstones. The reservoirs generally have three spatial distribution characteristics: layered, porphyritic and hydrocarbon impregnation along fracture. (4) The distribution of reservoirs in the metamorphic aureole is mainly controlled by the intensity of thermal baking. Furthermore, the distribution of favorable reservoirs is controlled by the coupling of favorable lithofacies and thermal contact metamorphism, intrusive compression and hydrothermal dissolution. The proposal and application of the geological model of the intrusion contact metamorphic system are expected to promote the discovery of exploration targets of contact metamorphic rock in Nanpu sag, and provide a reference for the study and exploration of deep contact metamorphic rock reservoirs in the Bohai Bay Basin.

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 to perform proppant transport experiments. The typical characteristics of proppant transport and placement 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-carrying 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 22.16 percentage points 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.

Based on the organic geochemical data and the molecular and stable carbon isotopic compositions of natural gas of the Lower Permian Fengcheng Formation in the western Central Depression of Junggar Basin, combined with sedimentary environment analysis and hydrocarbon-generating 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 rocks, and the retained liquid hydrocarbon is conducive to late cracking into gas, with characteristics of high gas-generating potential and late accumulation; (2) The maximum thickness of Fengcheng source rock reaches 900 m. The source rock has entered the main gas-generating stage in Penyijingxi and Shawan sags, and the area with gas-generating 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. Great attention should be paid to these targets.

Based on the new data of drilling, seismic, logging, test and experiments, the key scientific problems in reservoir formation, hydrocarbon accumulation and efficient oil and gas development methods of deep and ultra-deep marine carbonate strata in the central and western superimposed basin in China have been continuously studied. (1) The fault-controlled carbonate reservoir and the ancient dolomite reservoir are two important types of reservoirs in the deep and ultra-deep marine carbonates. According to the formation origin, the large-scale fault-controlled reservoir can be further divided into three types: fracture-cavity reservoir formed by tectonic rupture, fault and fluid-controlled reservoir, and shoal and mound reservoir modified by fault and fluid. The Sinian microbial dolomites are developed in the aragonite-dolomite sea. The predominant mound-shoal facies, early dolomitization and dissolution, acidic fluid environment, anhydrite capping and overpressure are the key factors for the formation and preservation of high-quality dolomite reservoirs. (2) The organic-rich shale of the marine carbonate strata in the superimposed basins of central and western China are mainly developed in the sedimentary environments of deep-water shelf of passive continental margin and carbonate ramp. The tectonic-thermal system is the important factor controlling the hydrocarbon phase in deep and ultra-deep reservoirs, and the reformed dynamic field controls oil and gas accumulation and distribution in deep and ultra-deep marine carbonates. (3) During the development of high-sulfur gas fields such as Puguang, sulfur precipitation blocks the wellbore. The application of sulfur solvent combined with coiled tubing has a significant effect on removing sulfur blockage. The integrated technology of dual-medium modeling and numerical simulation based on sedimentary simulation can accurately characterize the spatial distribution and changes of the water invasion front. Afterward, water control strategies for the entire life cycle of gas wells are proposed, including flow rate management, water drainage and plugging. (4) In the development of ultra-deep fault-controlled fractured-cavity reservoirs, well production declines rapidly due to the permeability reduction, which is a consequence of reservoir stress-sensitivity. The rapid phase change in condensate gas reservoir and pressure decline significantly affect the recovery of condensate oil. Innovative development methods such as gravity drive through water and natural gas injection, and natural gas drive through top injection and bottom production for ultra-deep fault-controlled condensate gas reservoirs are proposed. By adopting the hierarchical geological modeling and the fluid-solid-thermal coupled numerical simulation, the accuracy of producing performance prediction in oil and gas reservoirs has been effectively improved.

Based on the global basement reservoir database and the dissection of basement reservoirs in China, the characteristics of hydrocarbon accumulation in basement reservoirs are analyzed, and the favorable conditions for hydrocarbon accumulation in deep basement reservoirs are investigated to highlight the exploration targets. The discovered basement reservoirs worldwide are mainly buried in the Archean and Precambrian granitic and metamorphic formations with depths less than 4500 m, and the relatively large reservoirs have been found in rift, back-arc and foreland basins in tectonic active zones of the Meso-Cenozoic plates. The hydrocarbon accumulation in basement reservoirs exhibits the characteristics in three aspects. First, the porous-fractured reservoirs with low porosity and ultra-low permeability are dominant, where extensive hydrocarbon accumulation occurred during the weathering denudation and later tectonic reworking of the basin basement. High resistance to compaction allows the physical properties of these highly heterogeneous reservoirs to be independent of the buried depth. Second, the hydrocarbons were sourced from the formations outside the basement. The source-reservoir assemblages are divided into contacted source rock-basement and separated source rock-basement patterns. Third, the abnormal high pressure in the source rock and the normal-low pressure in the basement reservoirs cause a large pressure difference between the source rock and the reservoirs, which is conducive to the pumping effect of hydrocarbons in the deep basement. The deep basement prospects are mainly evaluated by the factors such as tectonic activity of basement, source-reservoir combination, development of large deep faults (especially strike-slip faults), and regional seals. The Precambrian crystalline basements at the margin of the intracontinental rifts in cratonic basins, as well as the Paleozoic folded basements and the Meso-Cenozoic fault-block basements adjacent to the hydrocarbon generation depressions, have favorable conditions for hydrocarbon accumulation, and thus they are considered as the main targets for future exploration of deep basement reservoirs.

Based on the geochemical parameters and analytical data, the heat conservation equation, mass balance law, Rayleigh fractionation model and other methods were used to quantify the in-situ yield and external flux of crust-derived helium, and the initial He concentration and thermal driving mechanism of mantle-derived helium, in the Ledong Diapir area, the Yinggehai Basin, in order to understand the genetic source, migration and accumulation mechanisms of helium under deep thermal fluid activities. The average content of mantle-derived He is only 0.001 4%, the ³He/⁴He value is (0.002-2.190)×10^?6, and the R/R_a value ranges from 0.01 to 1.52, indicating the contribution of mantle-derived He is 0.09%-19.84%, while the proportion of crust-derived helium can reach over 80%. Quantitative analysis indicates that the crust-derived helium is dominated by external input, followed by in-situ production, in the Ledong diapir area. The crust- derived helium exhibits an in-situ ⁴He yield rate of (7.66- 7.95)×10^?13 cm³/(a·g), an in-situ ⁴He yield of (4.10-4.25)× 10^?4 cm³/g, and an external ⁴He influx of (5.84-9.06)×10^?2 cm³/g. These results may be related to atmospheric recharge into formation fluid and deep rock-water interactions. The ratio of initial mole volume of ³He to enthalpy (W) is (0.004-0.018) ×10^?11 cm³/J, and the heat contribution from the deep mantle (X_M) accounts for 7.63%-36.18%, indicating that deep hot fluid activities drive the migration of mantle-derived ³He. The primary helium migration depends on advection, while the secondary migration is controlled by hydrothermal degassing and gas-liquid separation. From deep to shallow layers, the CO₂/³He value rises from 1.34×10⁹ to 486×10⁹, indicating large amount of CO₂ has escaped. Under the influence of deep thermal fluid, helium migration and accumulation mechanisms include: deep heat driven diffusion, advection release, vertical hydrothermal degassing, shallow lateral migration, accumulation in traps far from faults, partial pressure balance and sealing capability.

Aiming at the problem that the data-driven automatic correlation methods which are difficult to adapt to the automatic correlation of oil-bearing strata with large changes in lateral sedimentary facies and strata thickness, an intelligent automatic correlation method of oil-bearing strata based on pattern constraints is formed. We propose to introduce knowledge-driven in automatic correlation of oil-bearing strata, constraining the correlation process by stratigraphic sedimentary patterns and improving the similarity measuring machine and conditional constraint dynamic time warping algorithm to automate the correlation of marker layers and the interfaces of each stratum. The application in Shishen 100 block in the Shinan Oilfield of the Bohai Bay Basin shows that the coincidence rate of the marker layers identified by this method is over 95.00%, and the average coincidence rate of identified oil-bearing strata reaches 90.02% compared to artificial correlation results, which is about 17 percentage points higher than that of the existing automatic correlation methods. The accuracy of the automatic correlation of oil-bearing strata has been effectively improved.

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) °C/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.