This study focuses on the ultra-deep tight sandstone gas reservoirs in the Cretaceous Bashijiqike Formation of the Dabei area， Kelasu structural belt， Kuqa Depression. Based on the novel theory of overpressure-dissolved gas proposed by Academician Xie Yuhong and integrating multi-disciplinary data， we systematically elucidate the distribution characteristics and enrichment mechanisms of overpressure-dissolved gas in this area. Overpressure-dissolved gas is defined as a special phase state in which natural gas is saturated and dissolved in formation water and coexists with free gas under overpressure conditions （pressure coefficient>1.5）. The study confirms that the Dabei area exhibits favorable geological conditions for overpressure-dissolved gas accumulation， characterized by a persistent strong overpressure system （pressure coefficient of 1.56-2.38）， thick gypsum-salt caprocks， fractured tight reservoirs， and strong late-stage gas charging. In blocks such as A18 within the Dabei area， the percentage of overpressure-dissolved gas resources exceeds 50%， indicating significant exploration and development potential. Enrichment is synergistically controlled by four key factors： overpressure maintenance， caprock sealing， fracture migration pathways， and the source-reservoir pressure differential， exhibiting a pattern of “overpressure sealing， fracture conduits， and differential enrichment”. Structural highs， fracture zones， and areas with strong overpressure are identified as favorable targets for overpressure-dissolved gas enrichment. These insights effectively broaden the horizon for the evaluation and development of ultra-deep unconventional natural gas resources.
The Himalayan-stage episodic tectonic evolution of the Kuqa fold-thrust belt plays a critical role in controlling hydrocarbon accumulation； however， a systematic understanding of its detailed processes and controlling mechanisms remains inadequate. Based on field outcrops， drilling data， and seismic profiles， combined with growth strata analysis and balanced cross-section restoration， this study systematically characterizes the temporal framework of the Himalayan-stage tectonic evolution in this belt and investigates its spatiotemporal coupling relationship with hydrocarbon accumulation. The results reveal distinct spatiotemporal variations： Temporally， the Himalayan-stage tectonic activity can be divided into three episodes and nine sub-episodes， exhibiting a four-stage evolution characterized by progressively increasing intensity-namely， initial compression， episodic enhancement from the Late Oligocene to Early Miocene， rapid uplift during the Middle Miocene， and widespread uplift from the Pliocene to Pleistocene. This episodic process directly controls the multi-stage hydrocarbon accumulation. Early-stage tectonic activity （during the deposition of the Jidike Formation） formed low-amplitude structural traps and initiated crude oil charging， whereas late-stage intense uplift （since the Pliocene） facilitated trap finalization and induced large-scale natural gas charging， forming a typical “early oil and late gas” multi-stage accumulation model. Spatially， the intensity of tectonic activity shows a progressive variation from north to south and from west to east. The central-western segments， such as the Kela-Keshen and Bozi-Dabei areas， experienced early tectonic initiation and sustained strong activity， resulting in densely developed fault systems and structural traps， as well as high hydrocarbon charging intensity and high maturity. In contrast， the eastern segment exhibited relative stability during the Middle Miocene and short-term rapid activity since the Pliocene. Lateral variations in tectonic activity， combined with the detachment effect of gypsum-salt layers， collectively control the types and spatial distribution of traps， thereby influencing the degree of hydrocarbon enrichment and exploration potential. This study systematically constructs a spatiotemporal coupling model of tectonics and hydrocarbon accumulation， clarifying the controlling role of episodic tectonics in the hydrocarbon accumulation process， which provides guidance for play evaluation and exploration decision-making.
The Luntai Fault Zone is a key boundary structure controlling hydrocarbon accumulation in the northern Tabei Uplift of the Tarim Basin. Its segmented differential deformation characteristics and evolutionary history are fundamental to understanding the regional hydrocarbon accumulation patterns and guiding exploration deployment. Based on detailed structural interpretation of high-resolution merged 3D seismic data， this study systematically investigates the deformation characteristics of the fault zone， with emphasis on its segmented differential deformation， evolutionary history， and main controlling factors. Seismic profiles reveal that the Mesozoic-Cenozoic structural layer is characterized by syn-sedimentary normal faults forming horst-graben structures， whereas the pre-Mesozoic structural layer exhibits basement-involved thrust faults. In cross-sectional view， the Mesozoic-Cenozoic structural layer manifests as syn-sedimentary normal faults， while the pre-Mesozoic structural layer displays a basement-involved thrust fault structure， demonstrating a two-segment architecture. Planarly， it shows segmented differential deformation features： the eastern segment exhibits left-lateral， right-stepping en echelon strike-slip characteristics， the central segment displays left-lateral， left-stepping feather-like fault characteristics， and the western segment is characterized by left-lateral， left-stepping faults transitioning from en echelon to feather-like geometries. Balanced restoration， combined with regional geological analysis， indicates that the evolutionary history of the Luntai Fault Zone can be divided into four distinct phases： （1） Early Caledonian-Late Hercynian thrust fault development stage； （2） Late Hercynian-Late Yanshanian ongoing fault activity stage； （3） Late Yanshanian-Early Himalayan transtensional fault development stage； （4） Early-Late Himalayan transtension of the Luntai Fault coupled with thrusting in the Kuqa foreland belt stage. Significant differential evolution is observed among the fault segments. The segmented differential deformation of the Luntai Fault is the result of superimposed multiple tectonic events. During the Paleozoic， the fault zone was initially shaped by a series of regional compressional stress fields， including： （1） Cambrian nearly N-S compression from the subduction of the Paleo-Kunlun Ocean； （2） Middle Ordovician nearly E-W compression from the Altun-Tarim collision； （3） Late Ordovician NW-SE compression from the intensified Altun collisional orogeny. However， the key event responsible for the present-day segmentation occurred during the Late Hercynian， when NE-trending strike-slip faults originating from the northern slope of the Tazhong Uplift propagated northeastward， cutting across and reactivating the pre-existing Luntai Fault. This strike-slip overprint is interpreted as the primary control on the segmented differential deformation pattern. Furthermore， during subsequent tectonic reactivation， the presence of unconformities and weak mudstone layers in different fault segments promoted local mechanical partitioning， facilitating the lateral transition between dip-slip and strike-slip components and thereby refining and complicating the segmented characteristics of the fault system.
Shale gas is one of the critical resources for the energy strategy transition of China. In recent years， although significant breakthroughs have been made in lacustrine shale oil and gas exploration in China， the mechanisms of organic matter enrichment in key shale gas-bearing strata remain unclear. This study analyzed core samples from Wells XY1 and Z1 in the eastern Sichuan Basin， focusing on total organic carbon （TOC）， mercury （Hg）， and major-trace elements， aiming to elucidate the effects of volcanism on organic matter enrichment in the Middle-Lower Jurassic shales. We identified episodic peaks in mercury content and Hg/TOC ratios in sublayers I to V of the Lower Jurassic Dongyuemiao Member， indicating contemporaneous volcanism， which is likely related to the Sinemurian-Pliensbachian Boundary Event （SPBE）. Paleoenvironmental reconstruction indices suggest that volcanic activity drove a shift in sublayer V of the Dongyuemiao Member from oxygen-rich freshwater deposition under humid conditions to oxygen-poor saline deposition under arid conditions. The input of nutrient elements into the lake system enhanced primary productivity， as reflected by elevated P/Al ratios and Cu and Ni enrichment factors. In addition， moderate sedimentation rates and a restricted depositional setting facilitated the formation of organic-rich strata. Similarly， intensified volcanic activity increased the flux of nutrient elements into the lake basin， enhancing paleo-productivity and organic matter burial， which facilitated the development of organic-rich shale strata from sublayers IV to VIII of the lower sub-member of the Liang-2 Member of the Middle Jurassic Lianggaoshan Formation. This provided a sufficient material basis for shale gas accumulation in the Middle-Lower Jurassic strata of the eastern Sichuan Basin.
The Jurassic Lianggaoshan Formation shale oil and gas in the Pingchang area of northeastern Sichuan Basin exhibits high gas-oil ratios （GOR）， yet the controlling factors of hydrocarbon accumulation and the fluid phase behavior remain unclear. To clarify the hydrocarbon accumulation conditions and phase distribution patterns， an integrated study incorporating geological analysis， laboratory experiments， and well logging data was conducted. The results show that： （1） The Liang 1-2 sub-member of the Lianggaoshan Formation contains deep lacustrine organic-rich shale with vitrinite reflectance of 1.41%-1.70%， indicating a high-mature stage for condensate gas generation. The reservoir is characterized by ultra-low porosity and permeability， with fractures and macropores serving as the main flow pathways. （2） Paleoburial depth exhibits a strong positive correlation with vitrinite reflectance， fundamentally controlling the areal variation in GOR， which increases from the southwest to the northeast of the Pingchang area. （3） The in-situ fluid of the Lianggaoshan Formation in the Pingchang area is condensate gas. The two-phase region in the P-T phase diagram shrinks within nanopores， favoring gas-phase occurrence under reservoir conditions. In-situ NMR verifies that condensate gas accounts for 22.80%-28.13% of the pore volume， with 12.70%-14.47% being released upon depressurization. （4） Production logging and well-test data reveal that retrograde condensation occurs near the perforation clusters of horizontal wells， forming oil-gas-water three-phase flow， which reduces oil permeability and causes pressure depletion， and this is the primary reason for the rapid productivity decline. This study confirms that the Lianggaoshan Formation in the Pingchang area is a condensate gas reservoir controlled by paleoburial depth. The findings on accumulation characteristics and phase behavior provide a theoretical basis for formulating production strategies focused on maintaining reservoir pressure.
To clarify the fracture-controlled accumulation mechanism in basin-margin tight sandstone reservoirs， this study focuses on the Upper Paleozoic tight sandstone reservoirs in the Xinzhao area of the Ordos Basin. Based on core observation， thin section identification， imaging logging， and cathodoluminescence data， the fracture development characteristics were analyzed. Combined with authigenic illite dating and fluid inclusion analysis， the coupling relationship between fracture development stages and natural gas charging processes was revealed. The results indicate that both bedding fractures and tectonic fractures are developed in the study area. Bedding fractures， formed during the stable subsidence stage prior to the Yanshanian movement， made little contribution to natural gas accumulation. In contrast， the two-stage tectonic fractures represent the dominant fracture type and exhibit a good spatiotemporal match with the two phases of gas charging. The first stage of tectonic fractures， formed during the early Yanshanian movement， corresponds to the initial gas charging event at 185-167 Ma. These fractures were characterized by poor effectiveness and connectivity， coinciding with a limited charging scale， thus exerting a minimal control on hydrocarbon formation. The second stage of tectonic fractures， formed during the middle Yanshanian movement， corresponds to the main gas accumulation stage at 142-115 Ma. Dominated by unfilled high-angle and vertical fractures， this stage featured extensive development and excellent connectivity， making a critical contribution to the large-scale migration and accumulation of natural gas. A coupling model of “tectonic stress-driven， staged fracture development， and spatiotemporally matched gas charging”. This model demonstrates that the key to tight sandstone accumulation in the basin margin lies in the spatiotemporal coordination of tectonic evolution， fracture development， and natural gas charging. The research results provide a theoretical basis for understanding tight gas accumulation mechanisms and optimizing favorable exploration zones in similar areas.
The provenance of Cenozoic sediments in the northern margin of the Qaidam Basin has long been controversial. In this study， we investigate the provenance of clastic rocks from the lower member of the Paleogene Xiaganchaigou Formation in the Mabei area using an integrated approach of petrology， sedimentology， and geochemistry， including thin-section petrography， heavy mineral analysis， and major/trace element geochemistry. The results show that the lower member of the Xiaganchaigou Formation in the Mabei area comprises braided fluvial deposits， consisting predominantly of coarse conglomerates， conglomerates， gravelly coarse sandstones， mudstones， and silty mudstones. The sandstones are mainly feldspathic litharenites and lithic feldspathic sandstones， with lithic fragments dominated by metamorphic rocks， along with minor igneous and sedimentary lithic fragments. The heavy mineral assemblages are characterized by magnetite， garnet， zircon， epidote， and leucoxene， with minor amounts of tourmaline， hematite， sphene， and hornblende. The geochemical test results show that the main elements have good consistency with various parameters of the oceanic island arc. The large ion lithophilic elements Rb， Pb， and high field strength elements Th， U， Zr， and Hf are relatively enriched. The rare earth elements show an overall high content， with light rare earth elements enriched and heavy rare earth elements flat， showing obvious negative Eu anomalies. Indicating that the source rocks mainly come from felsic rocks in the upper crust， with a tectonic environment of oceanic island arcs and active continental margins. Comparison of heavy mineral assemblages and elemental geochemical characteristics between the study area and adjacent mountain ranges reveals that the Mabei area shares consistent geochemical affinities with the Jiulongshan and Lvliangshan mountains. Therefore， it is believed that the Paleogene sediments of the lower member of the Xiaganchaigou Formation in the Mabei area are proximal deposits derived primarily from the Jiulongshan and Lvliangshan mountains.
A major breakthrough has been achieved in shale oil exploration in the Lucaogou Formation in the northern Jimusar Sag. However， the complex lithology and poorly understood formation mechanism of high-quality reservoirs in this formation restrict further exploration and development deployment. In this study， the petrological characteristics， pore space types， porosity and permeability， diagenesis， and diagenetic evolution of the Lucaogou Formation shale oil reservoirs are analyzed using core observation， thin-section and scanning electron microscope （SEM） examination， X-ray diffraction （XRD） analysis， and porosity/permeability measurements. Based on these analyses， the formation mechanism of high-quality shale oil reservoirs in this interval was further summarized. The results show that the Lucaogou Formation shale oil reservoirs can be lithologically classified into three types： fine sandstones/siltstones， carbonates， and mudstones. Compared with the central and eastern parts of the sag， the northern part contains higher proportions of fine sandstones/siltstones and granular carbonate rocks. The reservoir pore space mainly consists of dissolved caves， fractures， dissolved pores， intergranular pores， and intercrystalline pores （or fractures）. The fine sandstone/siltstone reservoirs have the highest physical properties， followed by carbonate reservoirs， whereas mudstone reservoirs have the lowest. The shale oil reservoirs have undergone alkaline diagenesis during the syngenetic to early diagenetic stage， followed by acidic diagenesis during the middle diagenetic stage. The development of high-quality reservoirs is controlled by sedimentary environment， acidic dissolution， and authigenesis of alkaline feldspar and clay minerals. The detrital beach-bar and mixed beach-bar microfacies are the main development areas for high-quality shale oil reservoirs in the Lucaogou Formation in the northern Jimusar Sag. This study points out the formation mechanism and distribution pattern of high-quality reservoirs in this interval， which is of great significance for the identification of favorable exploration zones and optimal target well selection in the study area.
The alkaline lake shale of the Fengcheng Formation in the Mahu Sag， NW Junggar Basin， is generally characterized by a scarcity of clay minerals. However， the Fengcheng Formation in the Hala’alate Mountain area， located on the northern margin of the Mahu Sag， is rich in clay minerals. Studying the distribution and formation mechanisms of clay minerals in this area is crucial for understanding the evolution of clay minerals in the Mahu Sag and their impact on shale reservoir properties. Through XRD analysis， thin-section petrography， and Ar-ion polished-SEM observations of the Fengcheng Formation in the Hala’alate Mountain area， we found that clay minerals are mainly distributed in the thrust sheets characterized by marginal sedimentary deposits， with an average concent of 22%， whereas the parautochthonous deposits in the central alkaline lake are deficient in clay minerals， with an average concent of only 2.2%. The main clay minerals are magnesium-bearing smectite stevensite and sepiolite， which are distributed exclusively as dispersed micro-aggregates （5-20 μm） in mudstones and argillaceous siltstones， where abundant intercrystalline pores are preserved. Cluster analysis of XRD results shows that stevensite in the Fengcheng Formation has a stronger correlation with analcite than other minerals， indicating that stevensite precipitated directly from magnesium-rich alkaline pore water. Sepiolite， in contrast， shows a stronger correlation with detrital plagioclase， indicating that it was formed by transformation from detrital clay minerals during interaction with magnesium-rich alkaline water. Laterally， the clay minerals in the Fengcheng Formation show a zonation from sepiolite near the lake margin to magnesium-bearing smectite and then to illite toward the center. The enrichment of magnesium-bearing clay minerals in the Hala’alate Mountain area indicates that the original alkaline lake did not lack detrital clay supply. The present deficiency of clay minerals in the non-marginal shales can be attributed to the transformation and dissolution of detrital clay minerals in highly alkaline water， which resulted in the formation of numerous intercrystalline pores in authigenic minerals and matrix-dissolved pores in the shale matrix.
To address the limited understanding of the controlling effect of the Central Sichuan Paleo-uplift on the Qiongzhusi Formation shale and the unclear geological significance of gas accumulation in this interval， this study systematically investigated the shale gas accumulation characteristics of the Qiongzhusi Formation using core observation， focused ion beam scanning electron microscopy （FIB-SEM）， and coupled tectonic-sedimentary evolution analysis of the Central Sichuan Paleo-uplift， with emphasis on the morphological features， formation mechanisms， and controlling factors of microscopic gas pores， as well as their impacts on shale gas accumulation. The results show that： （1） The pore types in the Qiongzhusi Formation shale can be classified into organic matter pores， inorganic pores and gas pores. The gas pores are circular or elliptical， 50-500 nm in diameter， occurring mainly within organic matter or in intergranular pores， and accounting for 15%-25% of the total pore volume. （2） Gas pores form during thermal maturation of organic matter （R O >2.0%）. When the gas pressure generated by hydrocarbon generation exceeds the strength of the rock matrix， pores are created. Gas pores are best developed in shales with TOC >2.0% and R O =2.0%-3.5%. （3） The evolution of the Central Sichuan Paleo-uplift controls gas pore development： the Caledonian uplift promoted organic maturation； stable subsidence during the Yanshanian provided favorable conditions for gas pore preservation； and tectonic readjustment during the Himalayan episode optimized pore-fracture connectivity. （4） Gas pores increase shale reservoir permeability by one or two orders of magnitude， improving fluid flow capacity and forming a coupled “source-reservoir-pore-fracture” accumulation system. The findings enrich the theory of pore evolution in shale gas reservoirs and provide a new geological basis for deep shale gas exploration in the Qiongzhusi Formation of the Sichuan Basin.
To address the problem that strong heterogeneity in pore structures of medium-rank deep coal seams restricts efficient development， this study combines multiple experimental methods with fractal theory to systematically characterize the full-scale pore structure of deep coal seams in the northeastern Ordos Basin. Fractal analysis identifies 15 nm as a critical pore size threshold. The full-scale pore size distribution is mainly within the ranges of 0.5-1.2 nm and 10-3 000 nm， with the highest pore volume proportion occurring in the 10-100 nm range. Pores at different scales all exhibit significant multifractal characteristics and are influenced by regions of low probability density. The parameter Δα indicates that micropores and mesopores have stronger heterogeneity than macropores， whereas mesopores exhibit the best connectivity. Increasing thermal maturity reduces macropore heterogeneity； organic matter dominates the development of 15-100 nm pores and enhances micropore connectivity； moisture reduces micropore roughness and mesopore connectivity； and clay minerals in the ash content cause the mesopore distribution to be dominated by high-probability density regions.
Natural fractures play an important role in shale oil and gas evaluation and sweet spot prediction. Based on logging and core data from the cored interval of Well Niuye 1 in the Dongying Sag of Bohai Bay Basin， this study systematically investigates the development and distribution characteristics of natural fractures in the lower Es 3 to upper Es 4 shale intervals from a multi-scale perspective， and further analyzes their controlling factors and implications for hydrocarbon exploration. The results show that： （1） Two types of natural fractures are developed in the shale of Dongying Sag： bedding fractures and non-bedding fractures， with bedding fractures accounting for the majority. （2） The development of bedding fractures shows a certain correlation with mineral composition， TOC content， and lamina development， with a notably correlation observed at higher TOC contents or more pronounced lamina. （3） The development of bedding fractures is closely related to lithology and contributes significantly to micrometer-scale pore space， with open bedding fractures serving as crucial storage and flow pathways for shale oil. Therefore， we believe that natural fractures can reflect the oil-bearing potential of shale to some extent and also contribute substantially to its reservoir quality. Therefore， natural fractures should be considered as an evaluation factor in shale reservoir assessment.
In recent studies of coal-rock gas （deep coalbed methane） in the Benxi Formation of the Ordos Basin， the occurrence of associated crude oil and condensate within coal rocks has been identified. Gas composition and isotopic analyses， combined with Rock-Eval pyrolysis， biomarker analysis， and petrographic observations of the No.8 coal seam and its associated mudstones from the Shenmu-Fugu area （Shenfu area）， reveal that the methane in the Benxi Formation gas has low δ¹³C₁ and δD values， as well as low C₁/（C₂+C₃） ratios， exhibiting geochemical characteristics typical of oil- and condensate-associated gas. Pyrolysis results indicate that the organic matter in the Benxi coal-measure source rocks is hydrogen-rich and oxygen-poor， demonstrating significant oil-generation potential. The average total organic carbon （TOC） content is 63.32% for coals and 11.9% for mudstones and carbonaceous mudstones. Pyrolysis parameters including S₁ and S₁+S₂ surpass those of proven oil shales， indicating excellent oil-generation capacity. The chloroform bitumen “A” and light oils from Benxi coals share similar biomarker assemblages. Specifically， the biomarkers （Pr/Ph < 3.2， low C₂₄ tetracyclic terpane ratios， prominent gammacerane， and a V-shaped C₂₇-C₂₈-C₂₉ sterane distribution） indicate a suboxic to reducing transitional marine-continental depositional environment with relatively high salinity and contributions from aquatic organisms. Petrographic observations reveal that oily bitumen is primarily present within intergranular pores of clay minerals and late-stage fractures. Its distribution pattern indicates that hydrocarbons preferentially charged along clay mineral margins and wide fractures， and were subsequently retained within connected fracture systems， providing direct evidence for in-situ oil generation from coal. By integrating contour maps of vitrinite reflectance （R O）， hydrocarbon content， C₁/（C₂+C₃） ratios， methane carbon and hydrogen isotopes， and their composite indices， four favorable areas for coal-derived oil were predicted： the Su-72， Huo-21-Shen-124， Yuyang-Jia-32-4， and Jin-32 well blocks.
The Baiyun Sag in the Pearl River Mouth Basin is a Cenozoic faulted rift basin located on the passive continental margin of the northern South China Sea. It is characterized by multiple hydrocarbon sources， multi-phase hydrocarbon charging， and diverse hydrocarbon types. However， the genetic types and main source rocks of natural gas in this area remain controversial. In this study， 10 natural gas samples were collected from the southern deepwater area of Baiyun Sag for comprehensive geochemical analyses， including gas composition， conventional compound-specific carbon isotopes， methane clumped isotopes， and propane position-specific carbon isotopes. Combining these data with information on source rock development， burial and hydrocarbon generation history， and hydrocarbon charging history， the genetic types and main source rocks of natural gas in the study area were determined. The results demonstrate that： （1） Multi-dimensional isotopic signatures indicate that the natural gases are oil- and condensate-associated gases， mainly derived from kerogen cracking gas generated by high-quality lacustrine facies oil-prone source rocks， with possible contributions from bitumen/crude oil cracking gas. （2） Methane clumped isotope compositions revealed that the natural gases were generated at temperatures of 133-190 ℃. The maturity calculated from propane position-specific carbon isotopes ranges from 0.84%-1.76% EasyR O， corresponding to the crude oil to condensate stage. （3） Integration of the multi-dimensional isotopic data with the regional petroleum geology indicates that the primary gas source rocks in the southern deepwater area are the semi-deep to deep lacustrine source rocks of the WC4 member and the shallow lacustrine source rocks of the WC3 member of the Wenchang Formation. Given the relatively low thermal maturity in this area， the slope and surrounding uplift zones are interpreted as favorable exploration targets for crude oil and condensate， whereas the area near the sag center may hold greater potential for natural gas exploration.
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