By conducting experimental analyses, including thermal pyrolysis, micro-/nano-CT, argon-ion polishing field emission scanning electron microscopy (FE-SEM), confocal laser scanning microscopy (CLSM), and two-dimensional nuclear magnetic resonance (2D NMR), the Gulong shale oil in the Songliao Basin was investigated with respect to formation model, pore structure and accumulation mechanism. First, in the Gulong shale, there are a large number of pico-algae, nano-algae and dinoflagellates, which were formed in brackish water environment and constituted the hydrogen-rich oil source materials of shale. Second, most of the oil-generating materials of the Qingshankou Formation shale exist in the form of organo-clay complex. During organic matter thermal evolution, clay minerals had double effects of suppression and catalytic hydrogenation, which expanded shale oil window and increased light hydrocarbon yield. Third, the formation of storage space in the Gulong Shale was related to dissolution and hydrocarbon generation. With the diagenesis, micro-/nano-pores increased, pore diameter decreased and more bedding fractures appeared, which jointly gave rise to the unique reservoir with dual media (i.e. nano-scale pores and micro-scale bedding fractures) in the Gulong shale. Fourth, the micro-/nano-scale oil storage unit in the Gulong shale exhibits independent oil/gas occurrence phase, and shows that all-size pores contain oils, which occur in condensate state in micropores or in oil-gas two phase (or liquid) state in macropores/mesopores. The understanding about Gulong shale oil formation and accumulation mechanism has theoretical and practical significance for advancing continental shale oil exploration in China.

Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.

The largest Precambrian gas field (Anyue gas field) in China has been discovered in the central Sichuan Basin. However, the deep ancient Ediacaran (Sinian) dolomite presents a substantial challenge due to their tightness and heterogeneity, rather than assumed large-area stratified reservoirs controlled by mound-shoal microfacies. This complicates the characterization of “sweet spot” reservoirs crucial for efficient gas exploitation. By analyzing compiled geological, geophysical and production data, this study investigates the impact of strike-slip fault on the development and distribution of high-quality “sweet spot” (fractured-vuggy) reservoirs in the Ediacaran dolomite of the Anyue gas field. The dolomite matrix reservoir exhibits low porosity (less than 4%) and low permeability (less than 0.5×10^-3 μm²). Contrarily, fractures and their dissolution processes along strike-slip fault zone significantly enhance matrix permeability by more than one order of magnitude and matrix porosity by more than one time. Widespread “sweet spot” fracture-vuggy reservoirs are found along the strike-slip fault zone, formed at the end of the Ediacaran. These fractured reservoirs are controlled by the coupling mechanisms of sedimentary microfacies, fracturing and karstification. Karstification prevails at the platform margin, while both fracturing and karstification control high-quality reservoirs in the intraplatform, resulting in reservoir diversity in terms of scale, assemblage and type. The architecture of the strike-slip fault zone governed the differential distribution of fracture zones and the fault-controlled “sweet spot” reservoirs, leading to wide fractured-vuggy reservoirs across the strike-slip fault zone. In conclusion, the intracratonic weak strike-slip fault can play a crucial role in improving tight carbonate reservoir, and the strike-slip fault-related “sweet spot” reservoir emerges as a unique and promising target for the efficient development of deep hydrocarbon resources. Tailored development strategies need to be implemented for these reservoirs, considering the diverse and differential impacts exerted by strike-slip faults on the reservoirs.

To understand the reservoir property and hydrocarbon accumulation conditions of the Middle and Upper Ordovician intraplatform shoal between ultra-deep main strike-slip faults in Fuman Oilfield of the Tarim Basin, China, the main strike-slip faults in and around well FD1 in the basin were analyzed in terms of sedimentary facies, sequence stratigraphy, intraplatform shoal reservoir property, and oil and gas origins, based on drilling data. The Yingshan Formation intraplatform shoal between the main strike-slip faults is superimposed with low-order faults to form a new type of hydrocarbon play. Firstly, hydrocarbons generated from the Lower Cambrian Yuertusi Formation source rocks vertically migrated into the second member of Yingshan Formation through the main strike-slip faults, and then migrated laterally until they were accumulated. A small amount of oil from Well FD1 came from the Yuertusi Formation source rocks in the mature stage, and a large amount of gas originated from oil cracking in the ultra-deep reservoirs. Therefore, the secondary gas condensate reservoir in Well FD1 is characterized by high gas to oil ratio, dry gas (dryness coefficient being 0.970) and hybrid origin. This new type of hydrocarbon play characterized by intraplatform shoal and low-order fault suggests a prospect of continuous hydrocarbon-bearing area in Fuman Oilfield, which will expand the ultrap-deep oil and gas exploration in the oilfield.

By analyzing the corrosion of phosphate completion fluid on the P110 steel at 170 °C, the high-temperature corrosion mechanism of phosphate completion fluid was revealed, and a corrosion inhibition method by membrane transformation was proposed and an efficient membrane-forming agent was selected. Scanning electron microscope (SEM) images, X-ray energy spectrum and X-ray diffraction results were used to characterize the microscopic morphology, elemental composition and phase composition of the precipitation membrane on the surface of the test piece. The effect and mechanism of corrosion inhibition by membrane transformation were clarified. The phosphate completion fluid eroded the test piece by high-temperature water vapor and its hydrolyzed products to form a membrane of iron phosphate corrosion product. By changing the corrosion reaction path, the Zn²⁺ membrane-forming agent could generate KZnPO₄ precipitation membrane with high temperature resistance, uniform thickness and tight crystal packing on the surface of the test piece, which could inhibit the corrosion of the test piece, with efficiency up to 69.63%. The Cu²⁺ membrane-forming agent electrochemically reacted with Fe to precipitate trace elemental Cu on the surface of the test piece, thus forming a protective membrane, which could inhibit metal corrosion, with efficiency up to 96.64%, but the wear resistance was poor. After combining 0.05% Cu²⁺ and 0.25% Zn²⁺, a composite protective membrane of KZnPO₄ crystal and elemental Cu was formed on the surface of the test piece. The corrosion inhibition efficiency reached 93.03%, which ensured the high corrosion inhibition efficiency and generated a precipitation membrane resistant to temperature and wear.

Based on the recent oil and gas discoveries and geological understandings on the ultra-deep strata of sedimentary basins, the formation and occurrence of hydrocarbons in the ultra-deep strata were investigated with respect to the processes of basin formation, hydrocarbon generation, reservoir formation and hydrocarbon accumulation, and key issues in ultra-deep oil and gas exploration were discussed. The ultra-deep strata in China underwent two extensional-convergent cycles in the Meso-Neoproterozoic Era and the Early Paleozoic Era respectively, with the tectonic-sedimentary differentiation producing the spatially adjacent source-reservoir assemblages. There are diverse large-scale carbonate reservoirs such as mound-beach, dolomite, karst fracture-vug, fractured karst and faulted zone, as well as over-pressured clastic rock and fractured bedrock reservoirs. Hydrocarbons were accumulated in multiple stages, accompanied by adjusting and finalizing in the late stage. The distribution of hydrocarbons is controlled by high-energy beach zone, regional unconformity, paleo-high and large-scale fault zone. The ultra-deep strata endow oil and gas resources as 33% of the remaining total resources, suggesting an important successive domain for hydrocarbon development in China. The large-scale pool-forming geologic units and giant hydrocarbon enrichment zones in ultra-deep strata are key and promising prospects for delivering successive discoveries. The geological conditions and enrichment zone prediction of ultra-deep oil and gas are key issues of petroleum geology.

Combining low salinity water (LSW) with surfactants has an enormous potential for enhancing oil recovery processes. However, there is no consensus about the mechanisms involved, in addition to the fact that several studies have been conducted in model systems, while experiments with rocks and reservoir fluids are scarce. This study presents a core-flooding experiment of LSW injection, with and without surfactant, using the core and heavy oil samples obtained from a sandstone reservoir in southeastern Mexico. The effluents and the crude oil obtained at each stage were analyzed. The study was complemented by tomographic analysis. The results revealed that LSW injection and hybrid process with surfactants obtained an increase of 11.4 percentage points in recovery factor. Various phenomena were caused by LSW flooding, such as changes in wettability and pH, ion exchange, mineral dissolution, detachment of fines and modification of the hydrocarbon profile. In the surfactant flooding, the reduction of interfacial tension and alteration of wettability were the main mechanisms involved. The findings of this work also showed that the conditions believed to be necessary for enhanced oil recovery with LSW, such as the presence of kaolinite or high acid number oil, are not relevant.

Based on the measurements of petrological, petrophysical and elastic properties of the samples of different sedimentary facies in the fourth member of Sinian Dengying Formation (Deng 4 Member) in the Sichuan Basin, the diagenetic processes of reservoirs of different sedimentary facies and their controls on the petrophysical properties were discussed. The results show that cracks and mineral composition jointly control the petrophysical properties, and both are significantly influenced by sedimentary environment and diagenesis. The microbial dolomite of mound-shoal facies mainly experienced multi-stage dolomitization, penecontemporaneous dissolution, tectonic rupture and hydrothermal/organic acid dissolution processes, giving rise to cracks and dissolved pores. The grannular dolomite of inter-mound-shoal bottomland or dolomitic lagoon facies mainly underwent mechanical compaction, burial dolomitization and tectonic-hydrothermal action, creating cracks and intercrystalline pores. The diagenesis related to crack development increases the pressure- and saturation-dependent effects of samples, leading to significant decrease in the compressional wave impedance and Poisson's ratio. Dolomitization changes the properties of mineral particles, resulting in a Poisson's ratio close to dolomite. The muddy, siliceous and calcareous sediments in the low-energy environment lead to the decrease of impedance and the differential change of Poisson's ratio (significantly increased or decreased). The samples with both cracks and dissolved pores show high P-wave velocity dispersion characteristics, and the P-wave velocity dispersion of samples with only fractures or pores is the lowest.

Based on rock mineral and geochemical analysis, microscopic observation, physical property measurement, and thin laminae separation test, etc., the characteristics of typical laminae of the Paleogene Shahejie Formation carbonate-rich shale in the Jiyang Depression were analyzed, and the organic matter abundance, reservoir properties, and oil-bearing properties of different laminae were compared. Typical shale storage-seepage structures were classified, and the mobility of oil in different types of shale storage-seepage structure was compared. The results show that the repeated superposition of mud laminae and calcite laminae are the main layer structure of carbonate-rich shales. The calcite laminae are divided into micritic calcite laminae, sparry calcite laminae and fibrous calcite vein. The mud-rich laminae are the main contributor to the organic matter abundance and porosity of shale, with the best hydrocarbon generation potential, reservoir capacity, and oil-bearing property. The micritic calcite laminae also have relatively good hydrocarbon generation potential, reservoir capacity and oil-bearing property. The sparry calcite laminae and fibrous calcite vein have good permeability and conductivity. Four types of shale storage-seepage structure are developed in the carbonate-rich shale, and the mobility of oil in each type of storage-seepage structure is in descending order: sparry calcite laminae enriched shale storage-seepage structure, mixed calcite laminae enriched shale storage-seepage structure, fibrous calcite vein enriched shale storage-seepage structure, and micritic calcite laminae enriched shale storage-seepage structure. The exploration targets of carbonate-rich shale in the Jiyang Depression Shahejie Formation are different in terms of storage-seepage structure at different thermal evolution stages.

The complexity of diagenesis and hydrocarbon accumulation in the deep reservoirs in southern Junggar Basin restricts hydrocarbon exploration in the lower reservoir assemblage. The lithofacies and diagenesis of reservoirs in the Cretaceous Qingshuihe Formation in the Gaoquan structure of the Sikeshu Sag, southern Junggar Basin were analyzed. On this basis, the thermal history was calibrated using calcite in-situ U-Pb dating and fluid inclusion analysis to depict the hydrocarbon accumulation process in the Gaoquan structure. The results show that the Qingshuihe reservoir experienced two phases of calcite cementation and three phases of hydrocarbon charging. The calcite cements are dated to be (122.1±6.4) Ma, (14.4±1.0) Ma - (14.2±0.3) Ma. The hydrocarbon charging events occurred at around 14.2-30.0 Ma (low-mature oil), 14.2 Ma (mature oil), and 2 Ma (high-mature gas). The latter two phases of hydrocarbon charging contributed dominantly to the formation of reservoir. Due to the S-N compressive thrust activity during the late Himalayan period since 2 Ma, the traps in the Gaoquan structure were reshaped, especially the effective traps which developed in the main reservoir-forming period were decreased significantly in scale, resulting in weak hydrocarbon shows in the middle-lower part of the structure. This indicates that the effective traps in key reservoir-forming period controlled hydrocarbon enrichment and distribution in the lower reservoir assemblage. Calcite U-Pb dating combined with fluid inclusion analysis can help effectively describe the complex diagenesis and hydrocarbon accumulation process in the central-west part of the basin.

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.

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.

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 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.

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.

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.

The existing approaches for identifying events in horizontal well fracturing are difficult, time-consuming, inaccurate, and incapable of real-time warning. Through improvement of data analysis and deep learning algorithm, together with the analysis on data and information of horizontal well fracturing in shale gas reservoirs, this paper presents a method for intelligent identification and real-time warning of diverse complex events in horizontal well fracturing. An identification model for "point" events in fracturing is established based on the Att-BiLSTM neural network, along with the broad learning system (BLS) and the BP neural network, and it realizes the intelligent identification of the start/end of fracturing, formation breakdown, instantaneous shut-in, and other events, with an accuracy of over 97%. An identification model for "phase" events in fracturing is established based on enhanced Unet++ network, and it realizes the intelligent identification of pump ball, pre-acid treatment, temporary plugging fracturing, sand plugging, and other events, with an error of less than 0.002. Moreover, a real-time prediction model for fracturing pressure is built based on the Att-BiLSTM neural network, and it realizes the real-time warning of diverse events in fracturing. The proposed method can provide an intelligent, efficient and accurate identification of events in fracturing to support the decision-making.

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 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 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.

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.

The gas-water distribution and production heterogeneity of tight gas reservoirs have been summarized from experimental and geological observations, but the charging and accumulation mechanisms have not been examined quantitatively by mathematical model. The tight gas charging and accumulation mechanisms were revealed from a combination of physical simulation of nuclear magnetic resonance coupling displacement, numerical simulation considering material and mechanical equilibria, as well as actual geological observation. The results show that gas migrates into tight rocks to preferentially form a gas saturation stabilization zone near the source-reservoir interface. When the gas source is insufficient, gas saturation reduction zone and uncharged zone are formed in sequence from the source-reservoir interface. The better the source rock conditions with more gas expulsion volume and higher overpressure, the thicker the gas saturation stabilization and reduction zones, and the higher the overall gas saturation. When the source rock conditions are limited, the better the tight reservoir conditions with higher porosity and permeability as well as larger pore throat, the thinner the gas saturation stabilization and reduction zones, but the gas saturation is high. The sweet spot of tight gas is developed in the high-quality reservoir near the source rock, which often corresponds to the gas saturation stabilization zone. The numerical simulation results by mathematical model agree well with the physical simulation results by nuclear magnetic resonance coupling displacement, and reasonably explain the gas-water distribution and production pattern of deep reservoirs in the Xujiaweizi fault depression of the Songliao Basin and tight gas reservoirs in the Linxing-Huangfu area of the Ordos Basin.

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.

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.

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.

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.

The relationship between fracture calcite veins and shale gas enrichment in the deep Ordovician Wufeng Formation-Silurian Longmaxi Formation (Wufeng-Longmaxi) shales in southern Sichuan Basin was investigated through core and thin section observations, cathodoluminescence analysis, isotopic geochemistry analysis, fluid inclusion testing, and basin simulation. Tectonic fracture calcite veins mainly in the undulating part of the structure and non-tectonic fracture calcite veins are mainly formed in the gentle part of the structure. The latter, mainly induced by hydrocarbon generation, occurred at the stage of peak oil and gas generation, while the former turned up with the formation of Luzhou paleouplift during the Indosinian. Under the influence of hydrocarbon generation pressurization process, fractures were opened and closed frequently, and oil and gas episodic activities are recorded by veins. The formation pressure coefficient at the maximum paleodepth exceeds 2.0. The formation uplift stage after the Late Yanshanian is the key period for shale gas migration. Shale gas migrates along the bedding to the high part of the structure. The greater the structural fluctuation is, the more intense the shale gas migration activity is, and the loss is more. The gentler the formation is, the weaker the shale gas migration activity is, and the loss is less. The shale gas enrichment in the core of gentle anticlines and gentle synclines is relatively higher.

According to the transversely isotropic theory and weak plane criterion, and considering the mechanical damages due to stress unloading and hydration during drilling, a shale wellbore stability model with the influence of stress unloading and hydration was established using triaxial test and shear test. Then, factors influencing the wellbore stability in shale were analyzed. The results indicate that stress unloading occurs during drilling in shale. The larger the confining pressure and axial stress, the more remarkable weakening of shale strength caused by stress unloading. The stress unloading range is positively correlated with the weakening degree of shale strength. Shale with a higher development degree of bedding is more prone to damage along bedding. In this case, during stress unloading, the synergistic effect of weak structural plane and stress unloading happens, leading to a higher weakening degree of shale strength and poorer mechanical stability, which brings a higher risk of wellbore instability. Fluid tends to invade shale through bedding, promoting the shale hydration. Hydration also can weaken shale mechanical stability, causing the decline of wellbore stability. Influence of stress unloading on collapse pressure of shale mainly occurs at the early stage of drilling, while the influence of hydration on wellbore stability mainly happens at the late stage of drilling. Bedding, stress unloading and hydration jointly affect the wellbore stability in shale. The presented shale wellbore stability model with the influence of stress unloading and hydration considers the influences of the three factors. Field application demonstrates that the prediction results of the model agree with the actual drilling results, verifying the reliability of the model.

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 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.

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.

Based on the drilling, logging, experimental and testing data of Well PD1, a shallow normal-pressure shale gas well in the Laochangping anticline in southeastern Sichuan Basin, the shallow shale gas reservoirs of the Ordovician Wufeng Formation to Silurian Longmaxi Formation (Wufeng-Longmaxi) were investigated in terms of geological characteristics, occurrence mechanism, and adsorption-desorption characteristics, to reveal the enrichment laws and high-yield mechanism of shallow normal-pressure shale gas in complex structure areas. First, the shallow shale gas reservoirs are similar to the medium-deep shale gas reservoirs in static indicators such as high-quality shale thickness, geochemistry, physical properties and mineral composition, but the former is geologically characterized by low formation pressure coefficient, low gas content, high proportion of adsorbed gas, low in-situ stress, and big difference between principal stresses. Second, shallow shales in the complex structure areas have the gas occurrence characteristics including low total gas content (1.1-4.8 m³/t), high adsorbed gas content (2.5-2.8 m³/t), low sensitive desorption pressure (1.7-2.5 MPa), and good self-sealing. Third, the adsorbed gas enrichment of shales is mainly controlled by organic matter abundance, formation temperature and formation pressure: the higher the organic matter abundance and formation pressure, the lower the formation temperature and the higher the adsorption capacity, which is more beneficial for the adsorbed gas occurrence. Fourth, the shallow normal-pressure shale gas corresponds to low sensitive desorption pressure. The adsorbed gas can be rapidly desorbed and recovered when the flowing pressure is reduced below the sensitive desorption pressure. Fifth, the exploration breakthrough of Well PD1 demonstrates that the shallow complex structure areas with adsorbed gas in dominance can form large-scale shale reservoirs, and confirms the good exploration potential of shallow normal-pressure shale gas in the margin of the Sichuan Basin.

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.

Molecular dynamics method was used to establish composite wall/inorganic nanopores of three pore sizes, three shale oil systems, five CO₂-cosolvent systems, and pure CO₂ system. The process of CO₂-cosolvent displacement of crude oil in shale nanopores and carbon storage was simulated and the influencing factors of displacement and storage were analyzed. It is shown that the attraction of the quartz wall to shale oil increases with the degree of hydroxylation. The higher the degree of quartz hydroxylation, the more difficult it is to extract the polar components of shale oil. Nanopore size also has a great impact on shale oil displacement efficiency. The larger the pore size, the higher the shale oil displacement efficiency. The closer the cosolvent molecules are to the polarity of the shale oil, the higher the mutual solubility of CO₂ and shale oil. The more the non-polar components of shale oil, the lower the mutual solubility of CO₂ and shale oil with highly polar cosolvent. Ethyl acetate is more effective in stripping relatively high polar shale oil, while dimethyl ether is more effective in stripping relatively low polar shale oil. Kerogen is highly adsorptive, especially to CO₂. The CO₂ inside the kerogen is not easy to diffuse and leak, thus allowing for a stable carbon storage. The highest CO₂ storage rate is observed when dimethyl ether is used as a cosolvent, and the best storage stability is observed when ethyl acetate is used as a cosolvent.

On the basis of sorting out current understanding of solid bitumen (SB) in shales and taking organic-rich shales in the first member of the Cretaceous Qingshankou Formation in the Songliao Basin as an example, the definition, classification, occurrence and evolution path of SB are systemtically studied, and the indicative significance of SB reflectance (R_ob) on maturity and its influence on the development of reservoir space are discussed and summarized. The results show that the difference of primary maceral types is primarily responsible for the different evolution paths of SB. Most of the pre-oil bitumen is in-situ SB with only a small amount being of migrated SB, while most of the post-oil bitumen and pyrobitumen are migrated SB. From the immature to early oil maturity stage, bituminite, vitrinite, and inertinite can be distinguished from SB based on their optical characteristics under reflected light, and alginite can be differentiated from SB by their fluorescence characteristics. Under scanning electron microscope, in-situ SB and migrated SB can be effectively identified. R_ob increases linearly with increasing vitrinite reflectance (R_o), as a result of a decrease of aliphatic structure and the enhancement of aromatization of SB. Within the oil window three types of secondary pores may develop in SB, including modified mineral pores, devolatilization cracks and bubble holes. At a high maturity stage spongy pores may develop in pyrobitumen. Scanning electron microscopy combined with in-situ SEM-Raman spectroscopy can further reveal the structral information of different types of SB, thus providing crucial data for understanding for understanding OM migration paths, dynamics, and distances at micro-scale.

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.

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.

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.