Despite significant exploration breakthroughs， the exploration potential and targets of the Permian shale gas in the Yangtze region， South China remain poorly understood due to factors such as complex sedimentary facies variation， differentiated source rock-reservoir combination conditions， and varying tectonic activity-induced preservation conditions. A systematic investigation of the characteristics and distribution， exploration potential， and preservation conditions of the Permian shale sequences， proposes the exploration prospects and targets of the Permian shale gas in the Yangtze region. The results indicate that the studied Permian shales in the Yangtze region are of two types， namely the marine and marine-continental transitional shales， which comprise three suites of organic-rich shales， i.e.， the Gufeng， Longtan （Wujiaping）， and Dalong formations. The shale distribution is governed by the continental-margin （intracontinental） rift basins and intracratonic depression basins. Specifically， the marine-continental transitional shales of the Longtan Formation are mainly seen in the intracratonic depression basins in the western and southeastern parts of the Yangtze region， while the marine shales of the Gufeng （Wujiaping） and Dalong formations occur predominantly in the continental-margin （intracontinental） rift basins along the northern margin of the Yangtze region. The marine shales exhibit high brittle mineral content， high total organic carbon （TOC） content， well-developed organic pores， and high gas content. In contrast， the marine-continental transitional shales show high TOC content， moderate thermal evolution， well-developed inorganic pores， and generally low， highly variable gas content. Tectonic activities and associated preservation conditions represent critical factors controlling the exploration potential of the Permian shale gas in the Yangtze region. Areas with weak tectonic deformations， such as the western Hubei Province and the Sichuan， Jianghan， and Subei basins， exhibit favorable preservation conditions， thus holding considerable exploration potential. To address geological engineering challenges and accelerate the exploration and production of the Permian shale gas in the Yangtze region， it is recommended to intensify research on fine-grained sedimentary facies zone delineation， dynamic evolutionary patterns of shale gas enrichment， comprehensive evaluation metrics for shale gas preservation conditions， and adaptive technical systems for reservoir stimulation.

China’s shale gas resources are mainly distributed in the Sichuan Basin and its periphery， middle Yangtze Block， Tarim Basin， Guizhong Depression， and the Ordos Basin. Innovations in geological theories and breakthroughs in engineering technologies have propelled the rapid development of China’s shale gas industry. To effectively alleviate the supply-demand imbalance of oil and gas in China， it is crucial to keep expanding the shale gas exploration and exploitation fields to achieve a leap forward in the shale gas industry. The results of this study indicate that by the end of 2023， China had achieved cumulative proven geological reserves of shale gas of 2.96 × 10¹² m³ and an annual shale gas output of around 250 × 10⁸ m³， which， all originating from the Wufeng-Longmaxi formations in the Sichuan Basin and its periphery， account for about 15 % and 13 % of the country’s total proven geological reserves and annual output of natural gas， respectively. The shallow to moderately deep marine strata in the Sichuan Basin and its periphery are recognized as the major contributor to the stable production and further reserve growth of shale gas. Currently， China is expanding shale gas exploration and exploitation into new areas， including deep to ultradeep strata in the Sichuan Basin， normal-pressure marine facies in structurally complex regions outside the basin， the Cambrian and Permian sequences， and new-type reservoirs like those of the continental and marine-continental transitional facies. It is predicted that by 2035， the annual shale gas output will reach up to 1 000 × 10⁸ m³， representing about one-third of China’s total annual production of natural gas. It is recommended to intensify domestic shale gas exploration and exploitation， and enrich the development of multi-type shale gas reservoir geological theories and supporting key technologies， which are expected to significantly drive the additions to reserves from reserve growth of shale gas. China’s geological resources of shale gas are estimated at 118.67 × 10¹² m³， holding enormous potential for further exploration and exploitation.

Trace elements and rare earth elements （REEs） are of great value in reconstructing diagenetic environments and tracing the diagenetic fluid evolution. Presently， the solution method is recognized as a well-established， commonly used analytical method， but due to its high demand for powdered samples， it is only applicable to mixed samples of multiple diagenetic microfabrics with relatively low accuracy. With the support of the State Energy Key Laboratory for Carbonate Oil and Gas， we conduct the research and development of new techniques for analyzing trace elements and REEs in carbonate minerals， achieving three significant outcomes. First， upgrading the technique for testing trace elements and REEs in carbonate minerals with solution method. The required quantity of powdered samples gets reduced from 50 mg to 10 mg， meeting the sampling and testing requirements of microfabrics. Moreover， less time is needed for sample analysis and tests， so does the acid consumption， falling from 10 mL to 2 mL， resulting in a lower relative error of analysis and tests of 2 % ~ 5 % from 5 % ~ 10 %. Second， developing a new continuous laser mapping technique for trace elements and REEs using a laser ablation system and a triple quadrupole inductively coupled plasma mass spectrometer （ICP-MS） platform. With this technique， the lower limit of detection content is reduced from 1-10 ppb to a sub-ppb level， while the spatial resolution of images rises from ≥ 5 µm to ≤ 1 µm， and the time efficiency for image scanning and processing is increased by 10 times. Third， besides its applications in reconstructing the diagenetic environments of microfabrics and tracing the diagenetic fluid evolution， this new technique developed can improve the success rate and accuracy of laser-ablation U-Pb isotopic absolute dating.

Over more than four decades of hydrocarbon exploration in the Dongpu Sag within the Bohai Bay Basin， the sub-sag zones， critical targets for hydrocarbon exploration， have accounted for 49 % of the total exploration area. However， their proven geological reserves constitute only 1 % of the total， highlighting an exploration dilemma characterized by abundant residual hydrocarbon resources， low proven geological reserves， limited oil production despite tested oil flow， and difficulties in expanding the development of discovered hydrocarbon resources. Based on the increasingly intensive investigation of hydrocarbon enrichment patterns in recent years， we systematically explore the source rocks， source rock-reservoir configurations， and hydrocarbon accumulation sequences in different types of sub-sags within the Dongpu Sag while integrating various data from core observation， logging， analyses， and laboratory tests. The results indicate that： ① effective source rocks with relatively small thicknesses and high organic matter abundance （TOC content > 1 %） serve as the major source rocks in the sub-sag zones. This finding challenges the traditional understanding that source rocks are widely developed in sub-sags， facilitating the delineation of exploration targets； ② High-frequency lake-level fluctuations have resulted in a unique sedimentary rhythm of alternating sandstone and mudstone layers. The vertical superimposition of effective source rocks and sand bodies， along with the contiguous distribution of reservoirs near sub-sags， overturns the traditional view that sub-sags contain well-developed mudstones while lacking well-developed reservoirs； ③ Hydrocarbon charging and fluid overpressure are identified as the dominant factors governing the formation of reservoirs near sub-sags， significantly extending the lower depth limit of effective reservoirs. This challenges the long-standing perception that the so-called “death boundary” for the formation of effective reservoirs in continental clastic rocks is 3 500 m； ④ Additionally， hydrocarbon reservoirs in the sub-sag zones feature sequential hydrocarbon accumulation， contradicting the traditional belief that no hydrocarbon reservoirs occur below aquifers. Based on these insights， exploration breakthroughs have been achieved， including high-yield hydrocarbon flow exceeding 100 m³ oil-gas valent weight on a daily basis in the Gegangji Sub-sag， kilometer-thick oil-bearing intervals in the southwestern sub-sag zone， and the shale/tight oil resources at the hundred-million-ton level in the Qianliyuan Sub-sag. These achievements have driven the strategic shift in hydrocarbon exploration from tectonic zones to sub-sag zones in the Dongpu Sag， facilitating the delineation of exploration targets for large-scale reserve growth. The results of this study provide valuable guidance for hydrocarbon exploration in sub-sag zones within the Bohai Bay Basin.

Breakthroughs have been achieved in the exploration of lacustrine shale oil. However， the dominant geological factors controlling the enrichment and high yield of shale oil remain unclear， restricting its efficient exploitation. The fine characterization of various laminae can reveal the major factors controlling shale oil enrichment. This study focuses on the carbonate-rich shales of the Paleogene Shahejie Formation in the Jiyang Depression. Using thin section observations and field emission scanning electron microscopy （FE-SEM）， we analyze the reservoir spaces and oil-bearing properties of typical laminae and reveal the controlling effects of the lamina assemblages of shales on oil enrichment. The results indicate that carbonate-rich shales in the upper sub-member of the 4th member of the Shahejie Formation （Es₄^U） within the Jiyang Depression contain five lamina types： fibrous calcite laminae， micritic calcite laminae， very fine crystalline calcite laminae， clay-mineral-rich laminae， and mixed laminae. Major lamina assemblages include the combination of micritic calcite laminae， clay-mineral-rich laminae， and mixed laminae， and the combination of fibrous calcite laminae， very fine crystalline calcite laminae， clay-mineral-rich laminae， and mixed laminae. The clay-mineral-rich and mixed laminae， among others， exhibit high organic matter content， serving as the material basis for shale oil enrichment. Meanwhile， the very fine crystalline calcite laminae， with well-developed reservoir spaces， act as preferential storage media for shale oil. Additionally， the superposition of clay-mineral-rich laminae with very fine crystalline or micritic calcite laminae forms the optimal lamina configuration for shale oil enrichment. Therefore， the carbonate-rich shales with the clay-mineral-rich laminae and very fine crystalline or micritic calcite laminae assemblage serve as an important target for shale oil exploration and exploitation.

The hydrocarbon supply modes and accumulation processes of buried hills are yet to be clarified in the Dongpu Sag， Bohai Bay Basin. In this regard， we systematically classify the buried hills based on their morphologies and internal structures. In combination with the developmental characteristics of source rocks and the source rock-reservoir contact relationships， we determine the hydrocarbon supply modes of various buried hills， as well as the controlling effects of the fault-sand body-unconformity carrier system on the hydrocarbon accumulation process. Accordingly， the hydrocarbon enrichment and accumulation patterns of buried hills in the Dongpu Sag are proposed. The results indicate that the Dongpu Sag exhibits three buried-hill morphologies： residual， fault-block， and decollement. These hills can be categorized into five types based on their internal structures， namely monoclinal-residual， folded-residual， monoclinal-fault-block， folded fault-block， and monoclinal-decollement buried hills， with the monoclinal-fault-block type predominating. Hydrocarbon reservoirs therein are primarily supplied by two suites of source rocks， unidirectionally or bidirectionally. Hydrocarbon charging occurs principally through five supply modes： stepped， bridging， lateral-contact， full-contact， and cutting-through. Therefore， the hydrocarbon migration efficiency and accumulation processes in these buried hills are under the action of diverse hydrocarbon transport conditions. The differential hydrocarbon migration and accumulation in fault-block buried hills are primarily governed by the vertical transport capacity of faults， lateral transport capacity of sandstones， and the lateral sealing performance of faults. In addition， for hydrocarbon accumulation near the unconformities in the buried hills， the transport capacity of the unconformities represents a key controlling factor， determining the locations of hydrocarbon enrichment and the scales of hydrocarbon reservoirs. The differential hydrocarbon accumulation in the buried hills is attributed primarily to the differences in hydrocarbon supply modes and transport conditions. Specifically， the compressional-tensile folded-block-block buried hills， receiving bidirectional hydrocarbon supply through full contact and bridging， exhibit the most significant hydrocarbon enrichment. In contrast， the erosional monoclinal-residual buried hills with unidirectional， stepped hydrocarbon supply display a relatively low degree of hydrocarbon enrichment.

Exploring the structure and hydrocarbon generation characteristics of kerogen at a molecular scale and revealing its reaction pathway for hydrocarbon generation and generation model holds great significance for the study on the hydrocarbon generation of kerogen in low-maturity shales and shale oil exploration. A combination of analytical techniques including ultimate analysis， solid-state ¹³C nuclear magnetic resonance （¹³C NMR） spectroscopy， X-ray photoelectron spectroscopy （XPS）， and Fourier transform infrared spectroscopy （FTIR）， is applied to investigate the heteroatom morphology， carbon skeleton structure， and aliphatic and aromatic functional groups of kerogen in low-maturity shales from the 4th member of the Paleocene Shahejie Formation in the Shuguang area， Western Sag， Liaohe Depression. Accordingly， a two-dimensional average molecular structure model of kerogen is established with C₁₈₈H₃₁₀O₁₄N₄S， which boasts a high proportion （73.40 %） of aliphatics， a low proportion of aromatics， and long aliphatic chains （methylene chain carbon number： 5.04）. The results of the reactive force field molecular dynamics （ReaxFF MD） simulation reveal that the mass fractions of gaseous hydrocarbons （C₁—C₄）， light oil components （C₅—C₁₃）， and heavy oil components （C₁₄—C₃₉） reach up to 41.32 % at 3 500 K， 20.75 % at 3 300 K， and 30.22 % at 2 800 K， respectively， with a conversion rate of kerogen pyrolysis up to 61.67 %. The hydrocarbon generation process of kerogen in the shales progresses through multiple stages， including structural transformation， weak bond breaking， strong bond breaking， secondary cracking， and polycondensation reaction sequentially. During these stages， kerogen molecules undergo the bond breaking of heteroatoms and carbon-hydrogen atoms in both aliphatics and aromatics， as well as dehydrogenation-induced polycondensation reactions of aromatic rings.

The 3rd member of the Shahejie Formation （Es³） in the Qibei Sub-sag， Huanghua Depression， Bohai Bay Basin holds enormous potential for shale oil exploration and exploitation. Using systematic experiments and analyses including core and thin section observations， scanning electron microscopy （SEM）， X-ray diffraction （XRD）， high-pressure mercury injection， total organic carbon （TOC） content analysis， and rock pyrolysis analysis， we explore the geological conditions and controlling factors for shale oil enrichment in the Es^3（1）. Six typical lithofacies of the Es^3（1） are identified： laminated medium-grained calcareous-dolomitic shale， laminated fine-grained mixed shale， lamellar fine-grained mixed mudstone， lamellar medium-grained mixed mudstone， lamellar coarse-grained felsic mudstone， and massive medium-grained mixed mudstone. These mudstones/shales exhibit a TOC content ranging from 0.23 % to 2.57 %， with organic matter dominated by Types Ⅱ₁ to Type Ⅲ kerogen. The Es^3（1） shales display peak pyrolysis temperatures （T_max） varying from 435 ℃ to 463 ℃， indicating that these shales are generally in the mature stage of thermal evolution. Major reservoir space types identified in the study area include intergranular pores， intercrystalline pores， inter-clay-flake pores， intragranular dissolution pores， organic pores，and microfractures. Shale oil predominantly occurs in inter-clay-flake and dissolution pores with small pore-throats， as well as intercrystalline pores and microfractures， both with large pore throats. Major factors controlling shale oil enrichment in the Es^3（1） include TOC content， organic matter type， reservoir type， and sedimentary structures， which together form microscopic source rock-reservoir assemblages. Among the various lithofacies， the laminated medium-grained calcareous-dolomitic shale， laminated fine-grained mixed shale， and the lamellar fine-grained mixed mudstone exhibit effective source rock-reservoir assemblages， establishing themselves as favorable lithofacies for shale oil enrichment in the study area.

High-content natural hydrogen has been discovered in well SK-2 of the Continental Scientific Drilling Project of the Cretaceous Songliao Basin. Hydrogen gas in reservoirs with varying lithologies exhibits different complex adsorption characteristics. Using experimental data from reservoirs with natural hydrogen anomaly shows in well SK-2 and molecular dynamics methodology， we investigate the adsorption characteristics of natural hydrogen in reservoirs with varying lithologies under different geologic conditions. Furthermore， we explore the occurrence variation pattern of natural hydrogen based on temperature， pressure， pore diameter， pore type， and competitive adsorption of gases. The results indicate that the reservoirs with natural hydrogen anomaly shows exhibit a hydrogen content of up to 26.89 %， a mineral composition dominated by clay and quartz and a relatively high organic matter content. Pores of organic matter and clay in these reservoirs absorb natural gas rich in hydrogen. Among them， pores with relatively small sizes （0.4 ~ 7.0 nm in diameter） may serve as the primary spaces for hydrogen gas occurrence. In pores larger than 0.5 nm that contain both hydrogen gas and methane， the adsorbed hydrogen gas content remains low， while the content of free hydrogen gas increases with pore size. Montmorillonite demonstrates the highest adsorption capacity for hydrogen gas. However， competitive adsorption for methane reduces the hydrogen gas content in pores， hindering its enrichment. An increase in pressure significantly enhances the adsorption capacity of pores for hydrogen gas， whereas a rising temperature intensifies their desorption process for hydrogen gas. As the temperature increases， adsorbed hydrogen gas in pores of quartz and illite is more prone to convert into free gas. Micropores manifest a relatively high adsorption capacity for hydrogen gas， serving as the primary spaces for the occurrence of adsorbed hydrogen gas. The deep iron-rich rocks or mantle activity in the study area ensure sufficient hydrogen gas supply， enabling natural hydrogen generated to accumulate in deep sedimentary reservoirs. The hydrogen gas content gradually decreases with the generation of hydrocarbon gases， the conversion of adsorbed hydrogen gas into free gas， and hydrogen gas dissipation， leading to the formation of hydrogen-rich natural gas accumulation zones dominated by methane.

Normal faults are widely distributed throughout the Jurassic strata in the northern Sichuan Basin. However， their genetic mechanisms are yet to be clarified under the continuous compression from foreland basins. A detailed characterization and comparative analysis of faults at various structural locations is conducted using 3D seismic data， and the major controlling factors， genetic mechanisms， and multi-phase structural superimposition process of the Jurassic normal faults are investigated under a compressional tectonic setting. The results indicate that the Jurassic normal faults in the northern Sichuan Basin are a product of tensile strain caused by the folding and bending of strata during uplift. These faults exhibit a uniform and scattered planar distribution， forming numerous graben structures consisting of two or more normal faults with small throws and short displacements that dip in opposite directions. The strikes and numbers of these faults are controlled by the compressional directions and structural phases of surrounding thrust belts， with normal faults perpendicular to the compressional directions formed in each structural phase. The Jurassic normal faults within the northern Sichuan Basin are formed in response to the intracontinental orogeny of the Longmenshan， Micangshan， and Dabashan mountains. Stratum folding and bending formed during the formation of front uplift lead to the development of these faults， with multi-phase， multi-directional tectonic activities in the superimposed structural zone resulting in the formation of complex normal fault assemblages. The Jurassic normal faults in the northern Sichuan Basin are associated structures formed during uplift and deformation in a compressional tectonic setting rather than resulting directly from compressional stress fields.

Lacustrine shales typically exhibit distinct mineral-pore network frameworks for diverse lithofacies， significantly influencing the formation and evolution of primary and secondary pores in the shales. Based on data from whole-rock analysis by X-ray diffraction （XRD） mineralogy， total organic carbon （TOC） content analysis， scanning electron microscopy （SEM）， and N₂ adsorption experiments， we examine shale samples from the Jurassic Da’anzhai Member in cored wells LA1， RA1， and G10 in the central Sichuan Basin. To be specific， we investigate the petrological characteristics of these shale samples， as well as the characteristics and evolutionary mechanisms of their pore structures. The results indicate that the shales in the Da’anzhai Member can be categorized into seven lithofacies types： organic-lean limestone silty shale （OLLS）， organic-moderate limestone silty shale （OMLS）， organic-moderate limestone clay shale （OMLC）， organic-moderate silty clay shale （OMSC）， organic-rich silty clay shale （ORSC）， organic-lean argillaceous shale （OLAS） and organic-moderate argillaceous shale （OMAS）. Reserving spaces in these shales are dominated by intercrystalline pores in clay minerals. The OLLS exhibits well-developed intergranular pores among brittle grains， characterized by relatively low pore volume and specific surface area. In contrast， the OMAS and OLAS contain the most developed intercrystalline pores in clay minerals， featuring the highest pore volume and specific surface area. The clay-mineral intercrystalline pore diameters and the pore volumes of organic matter and clay minerals are significantly influenced by the compositions of detrital and clay minerals. Shales with a detrital mineral content of less than 25 % manifest a relatively high total pore volume due to the elevated pore volume of high-content clay minerals. For shales with a detrital mineral content of 25 % and above， the TOC content varies greatly despite the high pore volume of organic matter. As a result， the total pore volume of these shales is jointly affected by organic matter and inorganic minerals. The evolution of the mineral-pore network frameworks indicates that organic matter and mineral components govern the occurrence and intensity of diagenetic events， leading to diverse evolutionary characteristics of the pore structures and pore network frameworks across various lithofacies at present.

Climate constitutes a crucial factor in the oil shale mineralization， given its pronounced influence on the growth of lacustrine organisms and the depositional environment.. During the late Middle Jurassic， the Qaidam Basin experienced a major climate shift from humid to arid conditions. Amid this transition， a continuously distributed sequence of lacustrine oil shales was deposited in the basin. Focusing on these oil shales， we explore the coevolutionary relationships between aridification and oil shale mineralization using methods such as palynology and geochemistry. The results indicate that the oil shales of the shale interval of the Shimengou Formation were deposited under varying humidity conditions. Specifically， the black， massive oil shales in the lower part are formed in freshwater lakes under a relatively humid climate， while the laminated oil shales in the upper part in saline lakes under arid conditions. During the humid phase， lush terrestrial vegetation and a high flux of terrigenous sediments supplied abundant terrigenous organic matter and clastics to the lakes. This created mixed organic matter sources and a dysoxic environment for organic matter preservation. As a result， medium-quality oil shales with high hydrocarbon-generating potential are created. During the arid phase， reduced terrestrial vegetation and the proliferation of algae led to the formation of algae-dominated organic matter sources. Concurrently， the anoxic， high-salinity sediment-water environment significantly enhances the preservation efficiency of organic matter. Hence， medium- to slightly high-quality oil shales with excellent hydrocarbon-generating potential occur. The salinization of lacustrine basins， induced by the aridification， is identified as the key factor in driving the transition between the two oil shale metallogenic models. This study provides insights into the coupling mechanism between aridification and oil shale mineralization and enrichment while also offering an important basis for predicting high-quality oil shales within the Qaidam Basin.

Volcanic ash input holds significant impacts on the reconstruction of sedimentary environments in saline lacustrine basins. Specifically， when abundant trace elements from volcanic ash enter lakes and are preserved in tandem with sediment， the element contents in lacustrine strata cannot accurately reflect the original sedimentary setting. Focusing on the 2nd member of the Permian Lucaogou Formation （P₂l²） in the Tiaohu-Malang Sag within the Santanghu Basin， we investigate the mechanisms by which volcanic ash alteration affects element anomalies in fine-grained mixed deposits using major， trace， and rare earth element analyses， gas chromatography-mass spectrometry （GC-MS） of saturated hydrocarbons， whole-rock X-ray diffraction （XRD）， total organic carbon （TOC） content determination， and thin section observation. Accordingly， the saline lacustrine sedimentary environment under the action of volcanic ash is reconstructed. The results indicate that the P₂l² consists of fine-grained tuffaceous materials and carbonates， with the total content of felsic and carbonate minerals reaching up to 95 % on average， suggesting gradational mixed sedimentation at facies margins in a broad sense. Under the influence of alteration such as early dissolution in water and mid-late devitrification and organic acid corrosion， substantial volcanic ash thermodynamically unstable released various high-abundance nutrient ions （including metal ions） into pore fluids， which significantly interfered with the elements including Ni， Co， S， P， and Ga in the fine-grained mixed rocks of the P₂l². As a result， these elements cannot accurately reflect the original sedimentary environment. Biomarker compounds， together with the analysis of major and trace element data after screening and correction， reveal a hot and arid climate during the deposition of the P₂l²， featuring limited water supply to the lacustrine basin and extremely high salinity and low oxygen concentration of the lake. Volcanic activity played a significant role in regulating the sedimentary environment of the P₂l². The transition from intense to intermittent volcanic eruptions corresponded to an increasingly hot and arid climate， along with elevated water evaporation， water salinity， and oxygen concentration， leading to the deposition of various types of rock assemblages.

Gaining a deep understanding of the sedimentary characteristics and models of submarine fans in the Meishan Formation on the north slope of the Ledong Sag in the Qiongdongnan Basin holds great significance for guiding natural gas exploration in this formation. Using detailed core observations and descriptions， as well as data from seismic surveys， well logging， analysis， and tests， we investigate the sedimentary characteristics and models of submarine fans in the study area based on sequence stratigraphy and sedimentology. The results indicate that the submarine fans developed in the Meishan Formation on the north slope of the Ledong Sag are supplied by the western and northern provenance areas. The western provenance area-sourced submarine fan is primarily distributed in the sedimentary basin region below the slope break zone. Since the deposition occurs in the low-lying area as restricted by structures， the western provenance area-sourced submarine fan exhibits intensively distributed channels on the seismic section， with their literal edges displaying a pronounced onlap pattern. While the northern provenance area-sourced submarine fan occurs on the northeastern continental slope of the Ledong Sag. On the seismic section， its sand bodies close to the distal end of the fan show continuous progradation， leading to a downlap pattern. The two submarine fans differ significantly. Specifically， the western provenance area-sourced submarine fan lacks typical fan body shape and seismic responses of channels， with thickly laminated sandstones directly overlapping the slope areas on both sides， and it mainly involves gray fine-grained sandstones at great thickness and with a composition of quartz （average content of 76 %） and feldspar （average content of 12 %）. The northern provenance area-sourced submarine fan， on the other hand， is composed predominantly of gray siltstones at small thickness， with sandstones mainly composed of quartz （average content of 55 %） and lithic fragments （average content of 30 %）. The formation and evolution of submarine fans in the study area are principally governed by sea level， provenance， and paleogeography. The formation of slope break zones and low sea level create favorable conditions for the formation of submarine fans， while sediment supply and basin landforms determine submarine fan types. Sufficient sediment supply greatly facilitates the formation of confined submarine fans； otherwise unconfined submarine fans are likely to develop. The western provenance area-sourced submarine fan is classified as the confined type， where restricted basin boundaries result in extremely developed sandy debris-flow deposits， frequent migration and diversion of channels， and weakly developed turbidite-flow deposits. Based on these findings， we summarize the developmental characteristics and major factors controlling the confined submarine fan of the Meishan Formation on the north slope of the Ledong Sag and establish its sedimentary model， aiming to provide a reference for hydrocarbon exploration in similar sedimentary bodies.

Constructing a porosity prediction model for ultradeep fractured-vuggy hydrocarbon reservoirs holds great significance for their exploration and exploitation. These reservoirs， with burial depths exceeding 7 500 m， exhibit relatively low signal-to-noise ratios （SNRs） and extremely significant heterogeneity in fractures and vugs. These factors lead to major deviations between the porosity predicted using seismic wave impedance-based models and well log interpretation results for fractured-vuggy reservoirs. In this study， we propose a deep learning-based model for predicting the reservoir porosity involving the nonlinear relationships among multiple seismic attributes. Specifically， eight seismic attributes related to reservoir porosity are selected to construct a seismic attribute training set that matches log-derived porosity. Then， the skewed distribution of seismic attributes in the training set is corrected using the Box-Cox transformation， and then optimized with the seismic facies-constrained deep learning model as well as the Bayesian algorithms. A mathematical model is thereby established illustrating the nonlinear relationships between multiple seismic attributes and reservoir porosity. Compared to the commonly used seismic wave impedance-based prediction model， the newly proposed model can increase the goodness of fit of validation wells from 24 % to 92 %， substantially enhancing the prediction accuracy.

Continental shale oil represents a strategic replacement for improving reserves and well productivity in China. However， its development is facing two major challenges： the limited mobility of hydrocarbon fluids and poor reservoir fracability. To address these issues， we explore the mechanism and application of supercritical carbon dioxide （SC-CO₂） hybrid fracturing for shale oil in the Jiyang Depression， Shengli oilfield， through an array of tests， including the SC-CO₂-water-rock interactions， diffusion and displacement， true triaxial compression， and triaxial compression. The results indicate that dissolution with SC-CO₂ can increase shale porosity by 1 ~ 5 times， resulting in the predominance of mesopores and macropores. In addition， the fractures get enlarged as the reaction goes on. Specifically， the fracture width increased from 399 nm after 2-hour dissolution to 1.535 μm after 12 h， representing a fourfold increase in width， and concurrent permeability increase by 1 ~ 3 orders of magnitude. The SC-CO₂-invovled oil extraction achieved an efficiency of up to 24 %， with minimal effects observed beyond 30 h. Compared to dry shales， the tensile strength of shales subjected to SC-CO₂-water treatment decreased by 31 %. Unlike dry fracturing， SC-CO₂ hybrid fracturing can create bedding-parallel fractures by removing barriers to enhance bedding connectivity， which tend to form a complex fracture network in combination with subsequent hydraulic fractures. Grounded on theoretical research in lab， we conduct field tests of SC-CO₂ fracturing. The test results indicate that， in well Y-1， the average fracture propagation pressure for all sections decreased from 103.4 MPa before CO₂ injection to 100.5 MPa after CO₂ injection. Additionally， microseismic events recorded during fracturing in well Y-1 became more concentrated， with an average event number of 160.8 and an average effective stimulated rock volume （SRV） of 647 800 m³ overall. Moreover， both the viscosity and density of reservoir fluids decreased， resulting in an improvement in their mobility.

Ultra-deep fault-controlled reservoirs exhibit tabular shapes， extreme thickness， and significant gravitational differentiation in the components of multistage fluids. Their post-injection fluid phases differ greatly from those of conventional sandstone reservoirs. A lack of clear understanding of the mechanisms underlying gas injections in these reservoirs has severely hindered their gas injection performance. Using high-temperature and high-pressure full-field visualized experiments on oil-gas miscibility to clarify the static contact and miscible characteristics of oil and gas， we use a vertically placed empty， long sand-pack tube to simulate fault-controlled cavity-type reservoirs. For condensate gas with a high liquid content after retrograde condensation， phase behavior experiments are conducted with top and bottom gas injections. Based on the analysis of fluid samples collected at multiple stages at different positions along the long sand-pack tube， we investigate the contact modes and phase transition characteristics of oil and gas under both gas injection ways， and then clarify vertical compositional gradients formed under the action of gravity and diffusion. The results indicate that top gas injection leads to a limited oil-gas contact area under miscibility pressure， resulting in a low exchange rate of oil and gas components， insufficient volumetric expansion of oil， and ultimately the failure to form oil-gas miscible phase. Under the combined effects of gravity and diffusion， the dynamic cycle of “heavy drop and light rise” of components under the action of gravity and diffusion occurs， forming a vertical component gradient. Notably， the C₂₀₊ content in the gas condensate at the bottom of the tube is 3.4 times that at the top. In contrast， bottom gas injection enhances both gas injection volume and the area and frequency of oil-gas contacts， facilitating multiple oil-gas contacts to develop local miscible phases， while expanding the range of recoverable gas condensate components， reducing the vertical difference in C₂₀₊ content in gas condensate to 2.1 times. The cumulative recovery of gas condensate from three rounds of bottom gas injections is enhanced to 32.66 %， more than double that achieved through three rounds of top gas injections （14.13 %）.

Provenance studiy holds great significance for tracing the source-to-sink process and clarifying the distribution patterns of favorable reservoirs. The sequence from the Kongdian Formation to the lower submember of the 4th member of the Shahejie Formation （also referred to as the Sequence） in the Dongying Sag represents a suite of red deposits filled in the initial rifting stage of the Bohai Bay Basin under the joint control of multiple provenance. However， there is still controversy regarding their directions. To reveal its provenance characteristics at this stage， we systematically analyze the detrital composition and heavy minerals of sandstones， as well as conduct geochemical tests ofmajor and trace elements of mudstones and detrital zircon U-Pb dating. The results indicate that the sandstones in the Sequence primarily consist of lithic feldspar sandstones， exhibiting low compositional maturity with lithic fragments dominated by metamorphic and igneous rocks. The main heavy minerals in the sandstones include zircon， garnet， ilmenite， and apatite. The whole-rock major element analysis of mudstones in the Sequence reveals high silicon and aluminum contents and rich alkali. The trace element data show that the mudstones are relatively enriched in Li， Cr， and Cs. Regarding rare earth elements （REEs）， the mudstones feature enrichment of light REEs （LREEs） and negative Eu anomalies. The U-Pb isotope ages of detrital zircons in the Sequence range from 2 817 Ma to 75 Ma， concentrated in 175 ~ 130 Ma， 315 ~ 250 Ma， 1 900 ~ 1 855 Ma， and around 2 500 Ma. The Sequence is deposited under complex provenance conditions against the background of intense tectonic activities， with primary parental rocks encompassing the Archean intermediate-acid igneous rocks and metamorphic rocks， the Paleoproterozoic intermediate-mafic igneous rocks， the Lower Paleozoic carbonate rocks， and the Mesozoic intermediate-mafic igneous rocks， along with significant contribution from recycled clastics of the Mesozoic and Paleozoic. In all， it is indicative of proximal depositional systems during the Sequence formation， mainly consisting of Binxian-Chenjiazhuang， Guangrao， and Luxi-Qingcheng systems.

Retrograde condensation and severe water block were observed during the post-fracturing exploitation of condensate shale gas reservoirs in the Dongyuemiao Member of the Lower Jurassic Ziliujing Formation in the Fuxing area， Sichuan Basin. To quantitatively investigate the retrograde condensation and the coexistence and flow characteristics of oil， gas， and water during post-fracturing exploitation of these reservoirs， we conduct retrograde condensation experiments on a shale core while considering fracturing fluid retention， with N₂ flooding used as the control group to eliminate the stress-sensitive interference of shale. Based on gas permeability tests and the compositional analyses of produced oil and gas， we assess the retrograde condensation and the compositional variations in the produced oil and gas. Additionally， core-scale numerical simulations of retrograde condensation are conducted to qualitatively and quantitatively analyze the occurrence and flow characteristics of oil， gas， and water in the core. The results indicate that the damage of retrograde condensation decreases the effective gas permeability by 40 % in the absence of fracturing fluids and by 30 % in their presence. The water phase preferentially occupies small pore throats， weakening the oil phase’s ability to occupy these spaces and lowering the critical saturation of gas condensate. During retrograde condensation process， heavy components are retained in the core， while certain intermediate components （C₂—C₁₀） initially enter the oil phase due to retrograde condensation effect and then dissolve into condensate gas again as the pressure drops. After retrograde condensation occurs in the core， gas condensate rapidly reaches its critical saturation rather than accumulating indefinitely. Moreover， the period of post-retrograde condensation is characterized by a small single-phase seepage zone of condensate gas but a large oil-gas co-seepage zone.

Shale oil and gas hold considerable exploration potential as significant unconventional hydrocarbon resources. The fracability of shales plays a vital role in the exploration and exploitation of shale oil and gas reservoirs and is typically measured using elastic parameters. In this study， we comprehensively investigate domestic and international advances in research on the elastic parameters of shales， along with associated issues and challenges. The results indicate numerous measurement methods for the elastic parameters of shales， including experimental methods （e.g.， compression， ultrasonic measurement， nanoindentation， and acoustic logging） and theoretical calculation methods （e.g.， digital core calculation， equivalent medium theory， and molecular dynamics simulation）. Given the advantages， limitations， and application conditions of these methods， it is necessary to select scientific， accurate ones based on specific situations. Despite their relatively high accuracy， laboratory experimental methods are affected by sampling rates and experimental conditions. For instance， acoustic logging provides continuous， dynamic elastic parameters， capable of reflecting the mechanical properties of shales under instantaneous loading. However， these properties somewhat differ from those under long-term static loading in actual strata. Regarding theoretical calculation methods based on physical models， albeit with well-defined physical implications， these models require many input parameters and complex equations， which lead to reduced practicality. Additionally， these models typically neglect or make assumptions on non-primary factors excessively. For example， molecular dynamics simulation can simulate the elastic parameters of composite materials composed of multiple minerals while remaining simple and convenient to use. However， it still differs from actual geological models with complex and highly variable subsurface conditions， leading to discrepancies between simulation results and actual values. The elastic parameters of shales are primarily affected by factors including mineral composition， natural fractures， confining pressure， pore structure， diagenesis， and temperature. Additionally， they are influenced by organic matter characteristics， the properties and temperature of fluids within shales， sample size， bedding， and in-situ stress difference. Future studies should focus on the R&D of advanced technologies in terms of the quantitative relationships， multi-scale characteristics， and complex geologic environments of shales.

This study explores the relationship between gas recovery and water invasion dynamics in carbonate gas reservoirs with varying storage spaces to achieve their efficient exploitation. Using physical simulation experiments on vuggy， fractured， and fractured-vuggy carbonate rock samples taken from gas reservoirs in the Sinian Dengying Formation， Sichuan Basin， we comparatively analyze the water invasion dynamics of these reservoirs， and propose a novel equation for predicting water invasion dynamics： \omega =A{R}^B. The results indicate that the proposed method is highly effective in predicting water invasion in rock samples with different 3D storage space structures， and applicable for both heterogeneous gas reservoirs with bottom water and carbonate gas reservoirs. Furthermore， it provides encouraging prediction results of apparent relative pressure and fitted water invasion volume for both vuggy cores with strong homogeneity and fractured-vuggy cores with extreme heterogeneity. Under identical experimental conditions， carbonate gas reservoirs with varying degrees of heterogeneity exhibit distinct variation in coefficient A （related to gas production rate） and constant B （associated with water invasion intensity） values. For the cores of carbonate gas reservoirs， the extent and connectivity of pores are positively correlated with the producing reserves through water drive. Higer reservoir heterogeneity is associated with a more significant reduction in formation energy and a steeper decline in actual apparent relative pressure during the late stage of reservoir exploitation. Notably， among the tested cores， water body energy produces the least impact on the experimental results of the vuggy cores compared to the fractured and fractured-vuggy cores.

The Mahu Sag in the Junggar Basin holds significant potential for oil and gas exploitation and development. However， the strong reservoir heterogeneity therein leads to a rapid decline in oil and gas production. Presently， the pre-CO₂ fracturing， gas flooding， sequestration （PCFS） synergistic technology is commonly employed for enhanced oil recovery from glutenite reservoirs. This study aims to investigate the impact of CO₂-water-rock interactions on pore structures during pre-flushing CO₂ fracturing， as well as CO₂ migration patterns in the process of gas flooding. Using a glutenite core taken from the Mahu Sag， we perform CO₂ soaking experiments， high-precision micro-computed tomography （micro-CT）， and volume of fluid （VOF） method-based numerical simulations of two-phase flow in 3D digital cores. The results indicate that CO₂-water-rock interactions facilitate the dissolution-derived expansion of the pore structure， and the originally isolated channels converge into sheets， increasing the sweep range of CO₂ clusters. Meanwhile， this process induces secondary mineral precipitation and expansion， which can block or restructure pathways for fluid flow and， accordingly， change the flow paths and velocity of fluids in the pore structure. These， thereby， hinder the formation of the preferential flow pathways. Nevertheless， compared to the negative impact of secondary mineral precipitation and expansion， the pore space expansion under CO₂ soaking-induced dissolution is greater in positive effect. Specifically， the permeability is improved， so does the seepage capacity of pore structures. CO₂ clusters in different flow channels exhibit different morphologies （like convex or concave） at the displacement front. In the representative elementary volume （REV） models before and after CO₂ soaking， the dimensionless parameters （i.e.， capillary number C_a， contact angle θ， and viscosity ratio M） exert varying degrees of influence on the displacement efficiency. Specifically， in the REV model after CO₂ soaking， exhibiting a relatively higher degree of porosity evolution， the displacement efficiency is more sensitive to changes in the dimensionless parameters. This indicates that the PCFS synergistic technology is more effective in the exploitation of reservoirs with higher-degree porosity development.