Deep fractured-vuggy carbonate reservoirs， shaped by paleogeomorphology， structures， and karstification， exhibit various types， significant scale differences， high discreteness， and extreme heterogeneity， making it difficult to immediately apply conventional modelling methods to these reservoirs. In this study， we investigate the Ordovician carbonate reservoirs in the Tahe oilfield. To deal with the key issues in modelling these reservoirs， including a lack of guidance on the reservoirs’ developmental models， constraints from actual statistical laws， and the modelling and optimization algorithms of fracture-cave architectures， we develop a series of fine modelling techniques for the fracture-vug architectures， which center on genetic classification， multiple constraints， and multi-point statistics. Regarding reservoir architecture characterization， physical property modelling， and multi-type model integration， we introduce five major distinctive techniques with great efforts， namely multiple-point statistical modelling for a subsurface paleo-river system， multi-constraint modelling for fault-controlled karst reservoirs under zoning， collaborative simulation for genesis-controlled epikarst reservoirs， physical property simulation using karst facies control combined with equivalent calculation， and genetic sequence-based multi-type model integration and relevant dynamic optimization. The geological modelling of fractured-vuggy reservoirs has undergone four shifts： a shift in the modelling objects from external reservoir morphology to the internal geneses architecture of fractures， pores and caves， a shift in inter-well reservoir simulation from a single constraint to multiple control， a shift in modelling methods from the predominance of seismically sculptured geological modelling to multidisciplinary collaborative characterization， and a shift in modelling tools from merely commercial software to a combination of commercial software and independently developed modules. The results indicate that the techniques developed in this study can significantly enhance the coincidence rate of the geological model developed with drilled wells， serving to support geological modelling of 15 units in the Tahe oilfield， covering geological reserves of approximately 1.5×10⁸ t. Additionally， the newly developed model has been employed to refine reserve composition， perform numerical simulation of reservoirs， and adjust development schemes with remarkable effects， laying a geological foundation for developing measures to tap into the remaining oil potential and enhance oil recovery of fractured-vuggy carbonate oil reservoirs.

In recent years， strike-slip fault system over large areas has been identified in multiple cratonic basins in China， representing a significant structural style in interior cratonic basins. With the strike-slip fault system in the northern Tarim Basin in mind， we apply techniques like seismic-geological analysis of the faulted structure， discrete element numerical simulation of the fault dynamic evolution， finite element numerical simulation of off-fault deformations， and structural analysis of the fault cores and associated damage zones （also referred to as the fault core-damage zone architectures） to study. In combination with well production data， new understandings on the origin of the strike-slip fault system and its control on hydrocarbon accumulation are proposed. The results are as follows. （1） The strike-slip fault system in the northern Tarim Basin is formed as a result of northward thrusting of large thrust belts to accommodate regional shortening under the non-coaxial extrusion in the central Tarim Basin， featuring a dynamic genetic mechanism of non-coaxial extrusion and accommodation of regional deformations. （2） With increasing strike-slip fault displacement， the crackle and mosaic breccias in the fault cores gradually evolve into chaotic breccias and cataclasites. The resulted breccias of high evolutionary degree can reduce the fault core-damage zone permeability. （3） The pressure-ridge structures along the strike-slip faults formed under intense strike-slip transpressional stress， is characterized by extension in the upper part and compression in the lower part， resulting in the fault-controlled reservoirs in large scale primarily occurring at depths. （4） The decoupling of the gypsum-salt layer with the overlying strata related to the strike-slip faulting plays an important role in controlling the vertical hydrocarbon migration. （5） Layered deformation， as an inherent characteristic of the strike-slip faults with small displacement at great deeps， governs the vertical migration and accumulation of hydrocarbons in multiple layers along the strike-slip faults.

In recent years， breakthroughs have been achieved in hydrocarbon exploration efforts in the ultra-deep marine carbonate rocks of strike-slip fault systems in the northern Tarim Basin. However， the Fuman oilfield in the basin exhibits pronounced differences in hydrocarbon distribution and enrichment， with the mechanisms driving the differential hydrocarbon accumulation in ultra-deep reservoirs governed by strike-slip faults remaining unclear. In this study， we investigate the geometric structures and evolution of strike-slip faults in the Fuman area， as well as their role in hydrocarbon migration and accumulation. By analyzing the hydrocarbon accumulation and enrichment mechanisms， we identify the dominant factors controlling hydrocarbon accumulation in ultra-deep carbonate reservoirs in the area. The results indicate that the strike-slip faults in the study area experienced a dynamic evolutionary process consisting of the early extension or weak compression， the middle-stage transpression， extension， or translation slip， and the late-stage stabilization， successive development， or tenso-shear inversion. The F_I5 and F_I17 fault zones underwent alternating compression， shear， and tensile stresses， resulting in significant evolutionary differences across their various parts. In contrast， the F_I7 and F_Il6 fault zones were primarily subjected to shear and tensile stresses， leading to relatively simple evolutionary processes. The faults with differential evolutionary processes exhibit distinct geometric structures， resulting in varying configurations of their connection to source rocks， hydrocarbon transport capacities， and reservoir properties. Consequently， three hydrocarbon charging models are formed： vertical charging as represented by F_I5 and F_I16， lateral migration for adjustment by F_I7， and a combination of the former two patterns by F_I17. The hydrocarbon charging process is governed by the differential evolution of fault zones. The late-stage strong activity of faults in the eastern part of the Fuman area， combined with the charging and accumulation of substantial highly mature pyrolysis gas during the Himalayan movement， results in the formation of a hydrocarbon distribution pattern characterized by “oil in the west and gas in the east”. Furthermore， the evolutionary differences across various parts of the fault zones cause more complex changes in hydrocarbon properties. For reservoirs dominated by vertical hydrocarbon charging， the degree of hydrocarbon enrichment is determined by the coupling of the connection to source rocks， hydrocarbon transport capacities， and reservoir properties of fault zones. Meanwhile， the hydrocarbon properties of the reservoirs are governed by the various hydrocarbon charging stages. For reservoirs dominated by lateral hydrocarbon migration， the degree of hydrocarbon enrichment and hydrocarbon property changes are controlled by their properties and the extent of lateral connections within.

Previous classification schemes for the third-order sequences in the Upper Triassic Huangshanjie Formation in the Kuqa Depression， Tarim Basin have different views on the nature of its internal key boundaries and the sedimentary evolution process. Following fine observation and analyses of outcrops in the Kuqa Depression， we reclassify the third-order sequences in the Huangshanjie Formation. The results indicate that the four members of the Huangshanjie Formation constitute two third-order sequences： SQ1 and SQ2. SQ1 comprises the 1^st， 2^nd， and 3^rd members of the formation， proving thin in the east and thick in the west. SQ2 consists of the 4^th member of the formation， being thick in the east and thin in the west. Both sequences contain lowstand systems tracts （LSTs）， transgressive systems tracts （TSTs）， and highstand systems tracts （HSTs）. The third-order sequence boundaries， i.e.， SB1， SB2， and SB3， correspond to the bottom boundary of the Huangshanjie Formation， the top boundary of the 3^rd member of the formation， and the top boundary of the formation， respectively. SB1 and SB3 exhibit sharp transitions of lithology and lithofacies， with SB3 also identified as an erosional and depositional hiatus surface. SB2 emerges as a depositional hiatus caused by regional uplifting， and forms regional paleosol that can be correlated far away. The changes of basin-mountain coupling govern the formation of the two third-order sequences in the formation， in which the paleo-Tianshan Mountain experienced two episodes of rapid uplifting during the initial deposition of the LSTs and HSTs in SQ1， and then got eroded to peneplain at the end of SQ1 deposition. Accordingly， the basin’s sedimentary response transitions from the early intense subsidence and rapid sedimentary infilling to the stable subsidence and sedimentary infilling， and then to the second phase of intense subsidence and rapid sedimentary infilling to form the SQ1. After depositional hiatus， the basin continues to be filled steadily under the background of weak subsidence， forming SQ2.

A Y-shaped thrust-detachment fault striking NNE-near NS directions is developed in the middle of the Tarim Basin， composed of strike-slip for a half and thrust for another half. The fault exhibits significantly different structural style from those in adjacent areas and involve varying fault systems on both sides. However， its formation mechanisms and structural evolution remain unclear. In this study， we investigate the formation mechanisms and evolutionary characteristics with the structural analysis of the Hotan River and Lan’ga fault zones. Comparing the two fault zones in terms of the hydrocarbon accumulation characteristics in the Tahe oilfield， we delve into the characteristics of hydrocarbon migration and accumulation along the Hotan River fault zone. The results indicate that the Lan’ga and Hotan River fault zones are formed during the Late Caledonian， featuring a semi-strike-slip， semi-reverse-thrust Y-shaped thrust-detachment structure. These fault zones converge downwards into strike-slip faults and thrust upwards into the Silurian strata， forming faulted anticlines. Regional in-situ stress is identified as the main cause of the formation of both fault zones. At the end of the Early Ordovician， large-scale NNE- and NNW-trending strike-slip faults were formed in the Tabei Uplift and NNE-trending strike-slip faults were formed in the Bachu Uplift due to stresses from the southwest， southeast， and north. During the Late Caledonian， thrust-detachment faults that converged downward into strike-slip faults and thrust upward to the Silurian strata were formed due to the compression from Eastern Kunlun Orogen and the South Tianshan Ocean， cutting through the strike-slip faults. Thus， those strike-slip faults in their hanging walls got reactivated. Consequently， their hanging walls exhibit more developed fracture networks and a higher degree of fracturing compared to their foot walls and other areas. As a result of late-stage tectonic movements， these strike-slip faults continue to develop in the thrust fault zones， which further dislocate the thrust faults. The Lan’ga fault zone presents two favorable hydrocarbon accumulation models： （1） of the main NNE-trending strike-slip faults transecting the fault-karst reservoir dipping upward， and （2） of the fault-karst reservoirs characterized by segmented hydrocarbon enrichment along the secondary NNE-trending strike-slip faults. Specifically， the hydrocarbon charging along main faults in the Hotan River structural zone underwent lateral adjustment into the secondary NNE-trending strike-slip-controlled reservoirs of fractured-vuggy type during the Late Hercynian， leading to the formation of fault-karst reservoirs， which exhibit segmented hydrocarbon accumulation along the fault zones. The NNE-directed fault-karst reservoirs in the southern anticline zone represent the favorable exploration target.

Shallow-water deltas represent a hot research topic in sedimentology. However， there is a lack of studies and reports on shallow-water deltas featuring an arid climate， intermittently oscillating water bodies， and complex sedimentary characteristics and processes. Using data from core observation， logging， analyses， assays， and seismic surveys， along with modern analogs and sedimentary numerical simulations， we systematically investigate the sedimentary facies of the Jurassic Qigu Formation （J₃q） in the Yongjin area within the hinterland of the Junggar Basin. Accordingly， the sedimentary models of the shallow-water deltas formed in arid settings （also referred to as arid shallow-water deltas） in the J₃q are established. The results indicate that as the Junggar Basin’s climate grew to be arid during the Middle-to-Late Jurassic， the sedimentary water bodies in the J₃q became shallow and oscillated frequently. Consequently， shallow-water braided river deltas were deposited in sand sets 1‒3 of this formation. In contrast， the sedimentary facies of sand set 4 of the formation shifted to meandering-river deltas due to reduced provenance supply and persistent drought. In contrast， shallow-water deltas formed in a humid climate frequently feature rapidly varying subaqueous distributary channels， with various channel sand sets coming into being as the channels gradually bifurcated and diverted while extending. These deltaic sand bodies display alternating red and gray colors， with sandstones proving fine-grained， low-maturity， and locally distributed. Persistent drought leads to a constant decrease in the lacustrine basin accommodation space. As a result， mouth sandbars are rarely found in the deltaic lobes， and the sedimentary sand bodies are dominated by subaqueous distributary channel sands of various morphologies. The sedimentary bodies with single-channel provenance supply exhibit limited scales and pronounced lithofacies differentiation along water flow directions， leading to the development of three sedimentary microfacies： high-energy subaqueous trunk channels， medium- to high-energy reticular distributary channels， and low-energy modified distributary channels. The low connectivity among individual sand bodies and the strong heterogeneity of storage spaces complicate the hydrocarbon exploration and production in arid shallow-water deltas.

The Middle Permian saline lacustrine shales are identified as the most significant source rocks in the eastern Junggar Basin. Investigating their gas-generating potential and contribution to gas accumulation holds great significance for hydrocarbon exploration. Based on logs of wells newly drilled in recent years， as well as data from petrology， organic geochemistry， semi-open pyrolysis simulation experiments， and natural gas geochemical analysis， we systematically evaluate the gas-generating potential of the Middle Permian saline lacustrine source rocks， clarify the origin of natural gas from within， and delineate favorable targets for natural gas exploration. The results indicate that in the Dongdaohaizi Sag， the thickness of the Middle Permian saline lacustrine source rocks increases gradually from its margin to center， generally exceeding 350 m and reaching a maximum of 600 m at the center. In the Fukang Sag， two zones of thick Middle Permian saline lacustrine source rocks are determined， namely the northeastern margin and the south-central portion， where the source rock thicknesses primarily range from 200 to 250 m and exceed 400 m， respectively. The Middle Permian saline lacustrine source rocks in both sags principally exhibit medium to excellent quality， with oil-prone kerogen widely developed which is characterized by considerable thicknesses， high contents of retained hydrocarbons， and generally entering the gas window stage. All these suggest the potential for large-scale gas generation. The petroliferous gas generated by the Middle Permian saline lacustrine source rocks has been discovered in the eastern Junggar Basin， distributed primarily in the Fukang Sag， Dongdaohaizi Sag， and the Fukang fault zone. Besides， the petroliferous gas generated from the Middle Permian source rocks is also found mixed with the coal-derived gas in the Kelameili gas field and the Cainan oil and gas field. The ultra-deep reservoirs in the Fukang and Dongdaohaizi sags in the eastern Junggar Basin are favorable for the exploration of petroliferous gas， which can be divided into three favorable gas exploration zones： conventional gas outside source rocks， tight gas inside source rocks， and shale gas inside source rocks.

In recent years， major breakthroughs in shale oil exploration have been achieved in the Ganchaigou area of the Qaidam Basin， highlighting the significance of investigating the lithofacies and reservoir characteristics of the plateau saline lacustrine basin for sweet spot identification. Focusing on shale oil reservoirs in the Ganchaigou area， we identify the lithofacies types and systematically examine the differences in the reservoir and oil-bearing properties of shales with varying lithofacies. Furthermore， we determine dominant lithofacies and primary factors controlling the reservoir formation. The methods employed in this study include core and thin section identification， whole-rock mineralogy and in-situ trace-element distribution testing， large-field splicing scanning electron microscopy （MAPS）， high pressure mercury injection （HPMI） and nitrogen adsorption experiments， along with one-dimensional nuclear magnetic resonance （NMR） measurements. The results indicate that the reservoirs in the study area exhibit four lithofacies： massive limy dolomite （carbonate mineral content： above 70 %）， laminated limy dolomite （carbonate mineral content： 50 %-70 %）， lamellar mixed siliciclastic-carbonate rock （carbonate mineral content： 10 %-50 %）， and mixed siliciclastic-carbonate rock with intermittent horizontal beddings （carbonate mineral content： 10 %-50 %）. The massive and laminated limy dolomites， among others， exhibit the predominance of intercrystalline pores， large reservoir spaces with high connectivity， and pores with large oil saturation index （OSI）， thus serving as dominant lithofacies； The lamellar mixed siliciclastic-carbonate rock manifest poorly developed matrix pores but high permeability due to intensively developed laminae； The mixed siliciclastic-carbonate rock with intermittent horizontal beddings， lacking pores and fractures， display poor reservoir properties. The reservoir formation process of the dominant lithofacies is governed by three factors： （1） carbonate fabrics， which determine the degree of macropore development； （2） the contents of terrigenous felsic fine-grained sediments and clay minerals， which dictate the specific surface adsorptivity； and （3） the developmental degree of laminae， which can ultimately enhance the reservoir permeability.

This study aims to investigate the thermal evolution characteristics of organic matter in the Lower Silurian Longmaxi Formation， southern Sichuan Basin. Data from wells， lithology， and temperature experiments is applied to examine the present-day geothermal field characteristics； Laser-excited Raman spectroscopy is employed to measure and calculate the vitrinite reflectance （RmcR_o） of organic matter in shales in the Longmaxi Formation. Using R_o as a constraint and the BasinMod technique for numerical simulations of basins， we reconstruct both the heat flow history in the southern Sichuan Basin and the thermal evolution history of organic matter in the Longmaxi Formation within the basin. The results show that the bitumen in the reservoirs of the Longmaxi Formation in the southern Sichuan Basin exhibits RmcR_o values varying from 2.7 % to 3.9 %， indicating the presence of overmature organic matter， with the maturity increasing gradually from the Weiyuan to Luzhou and then to Changning blocks. During the Caledonian， most organic matter was yet to reach the hydrocarbon generation threshold. From the Dongwu to the Indosinian orogenies， the organic matter in the northern Weiyuan and northwestern Chongqing areas featured low to medium maturity， while that in the Changning-Ningxi blocks and the southern Luzhou block was highly mature and overmature， respectively. During the Yanshanian movement， the organic matter in the Longmaxi Formation in the southern Sichuan Basin was generally overmature. The thermal evolution of organic matter in the Longmaxi Formation in the southern Sichuan Basin is jointly affected by several geological factors such as paleogeomorphology， paleo-burial depth， eruption of the Emeishan Basalt， and tectonic uplifting. Of these， the paleo-burial depth and eruption of the Emeishan Basalt are identified as the primary factors.

In recent years， high-yield industrial gas flow has been obtained from the Maokou Formation in multiple wells such as JT1 and MX145 in the central Sichuan Basin， indicating great potential for hydrocarbon exploration and exploitation of this formation. However， the characteristics of and main factors controlling the reservoirs therein remain unclear， severely restricting in-depth hydrocarbon exploration. Aiming to investigate reservoirs of the Maokou Formation in Longnvsi area， central Sichuan Basin， the study delves into the geological characteristics such as lithology， physical properties， and pore-throat structure， along with the local geochemical characteristics via rock and ore tests under the guidance of reservoir geology. Accordingly， the major factors governing the development of high-quality reservoirs within the formation are proposed. The results indicate that dolomite and limestone reservoirs occur in the Maokou Formation， with primary reservoir rocks of crystal dolomites， brecciated dolomites， and granular limestones. The dolomite reservoir rocks can be categorized into three types and six subtypes， while the limestone reservoir rocks can be divided into four types and five subtypes. Storage spaces in the reservoirs consist primarily of intercrystalline pores， nonselective dissolution pores， and karst caves. The structural-dissolution fractured-vuggy system formed by the matching of vugs and fractures， exhibits a large storage space， extensive distribution， and high connectivity， which establish this system as a favorable reservoir. Regarding the formation and evolutionary pattern of the reservoirs， the reservoir framework is caused by sedimentation and dolomitization， and reservoir modification can be attributed to superimposed karstification and tectonism. In all， the primary factors governing the development of high-quality reservoirs include sedimentation， diagenesis， and tectonism， and brecciated dolomites are identified as high-quality reservoir rocks.

The Permian Dalong Formation in the northeastern Sichuan Basin contains a suite of high-quality marine shales， with shale reservoirs governing shale gas enrichment. In this study， we investigate the deep-shelf shales in this formation using data from scanning electron microscopy （SEM） of argon-ion milled shale samples， low-temperature nitrogen adsorption and desorption method， and mercury injection capillary pressure （MICP） technique. The geochemistry and mineralogy of shales in the Dalong Formation reveal the dominant factors controlling the occurrence of shale reservoirs in the Formation while comparing with those of other marine shale reservoirs in the Sichuan Basin， including the Silurian Longmaxi Formation， the 3^rd member of the Permian Maokou Formation （also referred to as the Mao 3 Member）， and the 2^nd member of the Permian Wujiaping Formation （also referred to as the Wu 2 Member）. The results indicate that high-quality shales occur in deep-shelf and basin facies in the northeastern Sichuan Basin. These shales show a ring-shaped distribution along the Kaijiang-Liangping shelf， with a thickness ranging from 20 to 35 m. The deep-shelf shales in the Dalong Formation comprise mixed siliceous and calcareous siliceous shales. In the Nanjiang area， the shales measure 20 to 30 m in thickness and are dominated by mixed siliceous shales. In the Puguang area， they exhibit greater thicknesses ranging from 30 to 35 m and consist primarily of calcareous siliceous shales. In contrast， near the central part of the Kaijiang-Liangping shelf， the shales are slightly thinner， around 20 m， and predominately comprise siliceous shales. The shale reservoirs in the Dalong Formation feature high total organic carbon （TOC） content， brittleness index， porosity， and gas content. As porous reservoirs dominated by organic pores， these reservoirs typically exhibit high porosity combined with ultra-low permeability， a large proportion of micropores， and excellent pore connectivity. The developmental degree and types of pores in the Dalong Formation shale reservoirs are determined by the sedimentary setting， as the pores therein preserved in the late stage under fluid overpressure. Compared to marine shales in other strata in the Sichuan Basin， the shales in the Dalong Formation exhibit a lithologic assemblage dominated by grayish-black siliceous shales intercalated with thinly laminated argillaceous limestones. The presence of numerous limestone intercalations vertically leads to high lithologic heterogeneity. While shales in different strata share similarities in their main storage space types， that is， organic pores dominate in all， the shale reservoirs in the Dalong and Longmaxi formations generally exhibit relatively lower porosity.

The differences in sedimentary filling within a continental lacustrine basin， caused by lake-level fluctuations， pose significant impacts on hydrocarbon generation and enrichment， while the lake-level fluctuations are notably influenced by climatic changes. In this study， we investigate the continuous lacustrine sedimentary records preserved in the 1^st member of the Shaximiao Formation （also referred to as the Sha 1 Member） of the early Middle Jurassic in the central Sichuan Basin. Using the high-resolution natural gamma-ray （GR） log data as paleoclimate proxies， we explore the cyclostratigraphy of the early Middle Jurassic continental strata. Through the filtering of long and short eccentricity cycles， we establish a floating astronomical time scale （ATS） for the Sha 1 Member. The results indicate that the sedimentary strata in the lacustrine basin of the Sha 1 Member preserve well-defined response signals to astronomical cycles. Calculations by the ATS reveal that the Sha 1 Member in the central Sichuan Basin underwent continuous deposition for approximately 2.43 Ma. The combination of eccentricity maxima and relatively high precession amplitude suggests a warm and humid climate. In this case， the lake level rose relatively， resulting in the development of argillaceous sediment. In contrast， the combination of eccentricity minima and relatively low precession amplitude implies a cold and arid climate. In this case， sandy sediment occurred， the thickness of which is modulated by precession amplitude. The driving forces of the orbital cycles at different scales during the early Middle Jurassic jointly determined the climatic changes， which caused lake-level fluctuations and further affected the sediment distribution.

Breakthroughs in hydrocarbon exploration in well Mitan 1 demonstrate that the 4^th member of the Ordovician Majiagou Formation （also referred to as the Ma 4 Member） in the eastern Ordos Basin has great potential for hydrocarbon exploration. However， the limited understanding of the paleotectonic framework of the Ma 4 Member in this region has restricted natural gas exploration in this member. Using aeromagnetic data， seismic sections， and drilling data， outcrop observation， and geochemical analysis， we identify the Shenmu-Zhidan low paleo-uplift within the Ma 4 Member in the eastern Ordos Basin， as well as the formation mechanisms of the paleo-uplift. The controlling effects of the paleo-uplift on the sedimentary reservoirs of the Ma 4 Member are thereby discussed. The results indicate that the Shenmu-Zhidan low paleo-uplift extends in the NE direction， with a width of approximately 140 km， a length of around 250 km， and an area of 3.8×10⁴ km². This low paleo-uplift was formed during the deposition of the Ma 4 Member under the combined influence of the compositional differences of the paleobasement and syndepositional normal faults. Specifically， under the effects of syndepositional normal faulting， the paleobasement in the footwall of the normal faults evolves into relatively high-lying low paleo-uplifts， while that in their hanging wall underwent subsidence and evolves into relatively low-lying depressions or sags. The Shenmu-Zhidan low paleo-uplift is relatively high-lying， containing microbial mounds， mud mounds， and psammitic shoals， which can develop into high-quality dolomite reservoirs in the presence of penecontemporaneous dolomitization. Additionally， this paleo-uplift exhibits a sequence of widely developed anhydrite layers with thicknesses varying from 1 to 12 m. The dolomite reservoirs in the Ma 4 Member within the low paleo-uplift zone are sealed by tight limestones laterally and anhydrite layers vertically， allowing them to form lithologic traps with excellent sealing performance. The lithologic traps of dolomites in the Ma 4 Member within the Shenmu-Zhidan low paleo-uplift， located in present-day structurally high parts， exhibit well-developed faults and effective sealing ability， which create favorable conditions for natural gas migration and enrichment.

To provide guidance on the exploration and production of transitional shale gas， we investigate the sweet spots of transitional shale gas in the 3^rd submember of the 2^nd member of the Shanxi Formation （the Shan 2³ submember） in the Daning-Jixian block along the eastern margin of the Ordos Basin and those of marine shale gas in the 1^st sublayer of the 1^st submember of the 1^st member of the Longmaxi Formation （the Long 1¹ submember） in the southern Sichuan Basin. A combination of core and thin section observations， whole-rock and clay mineralogy by X-ray diffraction （XRD）， organic geochemical analysis， scanning electron microscopy （SEM）， N₂ adsorption， CH₄ isothermal adsorption， and major and trace element analyses， is applied to conduct a systematic comparative study on the characteristics and formation mechanisms of these sweet spots. The results indicate that the sweet spots of marine shale gas exhibit stable distributions and consistent development， while those of transitional shale gas show lateral discontinuities and occur across multiple layers vertically. The sweet spots of transitional shale gas feature high total organic carbon （TOC） content， medium to high maturity， and gas-prone organic matter of kerogen type Ⅱ₂-Ⅲ. In contrast， the sweet spots of marine shale gas are characterized by relatively high TOC content， high to over maturity， and oil-prone organic matter f kerogen type Ⅰ-Ⅱ₁. In the sweet spots of transitional shale gas， clay minerals are prevalent， where mesopores and macropores take a larger portion governing the occurrence of free gas. Organic matter in these sweet spots principally exhibits micropores， which contribute significantly to the specific surface area and determine the occurrence of adsorbed gas. In contrast， the sweet spots of marine shale gas display a dominance of quartz minerals. Their organic matter contains both micropores and mesopores， which serve as primary storage spaces for shale gas. The sweet spots of transitional shale gas predominantly exhibit adsorbed gas （average proportion： 66.06 %）， while those of marine shale gas show predominant free gas， with adsorbed gas accounting for merely 11.15 % ~ 43.75 %. The organic matter enrichment in both types of sweet spots is governed by paleoclimate， paleoenvironment， and geologic events. Moreover， terrigenous debris input also plays a significant role in the formation of transitional shale gas sweet spots. The maximum single-well production of transitional shale gas in the Ordos Basin has been determined at up to 79，000 m³/d， demonstrating promising prospects for exploring transitional shale gas in the basin.

The Jiyang Depression in the Bohai Bay Basin boasts abundant shale oil resources， with a preliminary estimate of over 10 billion t. Analyzing， investigating， and summarizing theories on the formation， enrichment， and high-yield nature of shale oil are significant for guiding shale oil exploration and production efforts in this region. We systematically examine the formation and evolutionary characteristics of organic matter， as well as the enrichment and mobility of shale oil， in two major shale oil-bearing sequences in the Jiyang Depression： the upper submember of the 4^th member of the Paleogene Shahejie Formation （also referred to as the Sha 4 Member） and the lower submember of the 3^rd member of the Formation （also referred to as the Sha 3 Member）. Accordingly， the theoretical understanding of the hydrocarbon generation， reservoir formation， and shale oil enrichment and high-yield nature of middle- to-low maturity shales is proposed for the faulted lacustrine basin in the depression. The results indicate that shales in this basin exhibit a high abundance of organic matter and medium-to-low maturity during deposition. These characteristics establish the shales as high-quality source rocks with high hydrocarbon-generating potential and low activation energy for hydrocarbon generation. During the deposition of shales in the Shahejie Formation within the Jiyang Depression， lipoid compounds such as halophilic bacteria and algae were present in saline water bodies， resulting in the high paleoproductivity of organic matter， low activation energy for hydrocarbon generation in sulfur-rich organic facies， and high hydrocarbon conversion rate. Additionally， the depositional period of the shales was marked by early hydrocarbon generation and expulsion， with the free oil content peaking at a vitrinite reflectance （R_o） value of approximately 0.65 %. The organic-rich layers and porous laminae， frequently interbedded， display regular distributions and a favorable source-reservoir configuration. The thick shale sequences generally exhibit high pressure as their self-sealing performance remains undestroyed by low-order faults in the sub-sag zone. The shale oil-bearing sequences largely consist of laminated carbonate-rich shales and laminated mixed shales. Both types of lithofacies exhibit the characteristics of high-quality shale oil sweet spots， as evidenced by shale oil enrichment governed by laminae and shale oil flow influenced by fracture networks， with the lamina assemblages determining the distribution of reservoir spaces. The spatial coupling of multi-scale and multi-type matrix microfractures with induced fracture networks forms an efficient seepage system with superimposed natural and artificial multi-scale fracture networks in shales. Consequently， the shales demonstrate oil enrichment throughout all shale sequences of the laminated framework.

Prolonged waterflooding leads to the development of waterflood-induced fractures in tight sandstone reservoirs. Clarifying the dynamic responses and evolutionary characteristics of these fractures holds great geological significance for the emplacement of dense well patterns and the tapping of residual oil potential of tight sandstone reservoirs. Integrating data from core observations， logs， oil production， pressure-buildup well tests， and water injection profiles， we explore the dynamic responses and distributions of waterflood-induced fractures across different development stages within the tight sandstone reservoirs in the 8^th member of the Yanchang Formation （also referred to as the Chang 8 Member） in well block L， Jiyuan oilfield， Ordos Basin. The results indicate that waterflood-induced fractures in the tight sandstone reservoirs of the Chang 8 Member within well block L originate from the propagation of natural fractures， and the natural fractures exhibit a preferential opening direction of NEE-SWW and NE-SW， followed by NW-SE. The water injection profiles of injection wells tend to exhibit small water absorption thickness but high water absorption capacity due to the formation of waterflood-induced fractures. Concurrently， the production performance curves of wells display a spurt or stepped upward trend in water cut， while pressure-buildup well tests reveal open double- logarithmic derivative curves that trend upward at a slope of 1/2. In the case where waterflood-induced fractures occur between production and injection wells， the production well test-interpreted formation pressure exceeds that in wells without waterflood-induced fractures and even far surpasses the initial formation pressure. In the initial development stage of tight sandstone reservoirs in the Chang 8 Member within well block L， waterflood-induced fractures in the reservoirs are primarily found in east-central， northeastern， and southeastern parts of the well block， where natural fractures are well developed. Waterflooding causes changes in the reservoir stress and thereby the opening pressure of natural fractures decreases. As a result， in the middle development stage， waterflood-induced fractures striking NW-SW come into being in the southern and north-central parts of well block L， accompanied by the small-scale propagation of pre-existing waterflood-induced fractures. In the late development stage， further waterflooding triggers the opening of natural fractures in different orientations around injection wells， leading to the formation of small-scale waterflood-induced fractures. This further exacerbates the fracture-induced waterlogging of production wells.

To reveal the mechanical properties and microfracturing mechanisms of shales， we investigate shales in the Silurian Longmaxi Formation in the southern Sichuan Basin using X-ray diffraction （XRD） analysis， together with triaxial compression， micro-computed tomography （micro-CT） and scanning electron microscopy （SEM） tests. The results indicate that the mechanical properties and reservoir physical properties of shale are significantly influenced by its mineral composition and confining pressure. Specifically， an increase in the brittle mineral content enhances its elastic modulus and peak stress， indicating positive correlations between these mechanical properties and the brittle mineral content. In contrast， higher clay mineral content increases the shale plasticity while reducing its rock strength. As confining pressure increases， fractures in the shale gradually close， and the pores deform and contract， leading to reduced porosity. A higher confining pressure results in greater compression. Two dominant types of fractures form during shale damage： boundary fractures occurring at interfaces between mineral grains and internal fractures occurring within grains. For shales with similar mechanical properties， increasing confining pressure shifts their dominant fracture type from boundary to internal fractures. Additionally， higher confining pressure causes the boundary and internal fractures to evolve into fracture zones， leading to an increased fracture density in the shale.

Dolomites， distributed extensively across the world， are known to contain abundant hydrocarbon resources. However， questions regarding their formation mechanisms and reservoir space preservation are yet to be clarified. We delve into recent significant advances in the study of dolomites’ genetic mechanisms and factors governing their reservoir space， along with emerging experimental techniques. The findings indicate that low-temperature ordered dolomites can be successfully synthesized through dissolution-reprecipitation reactions and that dolomite formation is constrained by both thermodynamic and kinetic barriers. Various dolomitization models have been established， expanded， and improved， including the newly constructed organic matter- or microbially induced dolomitization model， the enhanced inorganically catalyzed dolomitization model， and the modified mixed-water-zone dolomitization model. Furthermore， the model for dolomitization by evaporative pumping and seepage reflux of brines has been expanded， and the burial dolomitization model has been refined. The findings highlight the significant controlling effects of the original sedimentary environment and late-stage diagenetic transformations on the evolution of dolomite reservoirs. Moderate dolomitization and secondary dissolution increase the porosity of dolomite reservoirs. In contrast， excess cementation， precipitation of substantial hydrothermal minerals， and mild to moderate recrystallization lead to a decrease in reservoir porosity. Novel experimental techniques have been developed， including element microanalysis， Mg-Ca isotopic tracing， in-situ U-Pb isotopic dating by laser ablation inductively coupled plasma mass spectrometry （LA-ICP/MS）， clumped isotope thermometry， confocal laser scanning microscopy （CLSM） combined with CT scanning imaging， and nuclear magnetic resonance （NMR） combined with spectral induced polarization （SIP）. Additionally， techniques for the forward modeling of dolomite reservoirs and the multiscale quantitative characterization of the 3D structures and fluid mobility of dolomite pores have also been developed. These emerging techniques provide significant technical support for research on the genetic mechanisms and reservoir space of dolomites.

Carbon emissions from fossil fuels pose tremendous challenges to environmental sustainability. Hence， exploring clean energy with low or even zero carbon emissions represents a major scientific issue and technical difficulty in energy research. Natural hydrogen gas （NHG） is considered the ideal clean energy for the future due to its high heating value （HHV）， zero carbon emissions， and low price. In this study， we analyze the hydrogen production methods and their trends， the formation and enrichment mechanisms and distribution of NHG， and recent advances in the theories and technologies for determining the formation， tracing， transport， and preservation of NHG. Furthermore， a comprehensive investigation of the novel methods and recent achievements in natural hydrogen exploration across the world lays the foundation to pinpoint critical scientific issues regarding the theory and technology of the formation， preservation， and accumulation of natural hydrogen. It can be concluded that natural hydrogen features substantial resources， various formation mechanisms， complex accumulation processes， and highly risky exploration and development. This necessitates intensified research on fundamental theories and proactive research and development of technologies and equipment for natural hydrogen exploration and development. To this end， we propose an innovative approach of identifying “fairy circles” using remote sensing， determining natural hydrogen sources through geophysical exploration， and delineating exploration targets using geochemical exploration. It is recommended that relevant government departments and industrial sectors actively push forward the study and exploration and development of natural hydrogen by means of supportive policies rolled out， and top-level design strengthened.

This study aims to enhance the exploration and exploitation of China's natural hydrogen reservoirs and to advance research on the distribution， enrichment mechanisms， and accumulation conditions of natural hydrogen. Based on a literature review， we perform a case study of natural hydrogen exploration in the Mali hydrogen field within the Taoudeni Basin in Africa and introduce global advances in natural hydrogen exploration. The results reveal that the hydrogen in the Mali gas field most likely originates from the active serpentinization of 2.2-2.1 Ga rocks in the Leo-Man Shield of the West African Craton and， thus， is the product of reactions of ferrous irons in rocks with water. The Mali hydrogen field contains two distinct types of reservoirs， namely the upper dolomitic carbonate reservoir and the lower sandstone reservoir， where free hydrogen and dissolved hydrogen are primarily found， respectively. Hydrogen migrates from the source to these reservoirs primarily along faults， subsequently accumulating beneath diabase cap rocks. Increasingly more companies have engaged in natural hydrogen exploration worldwide， with their number surging from three in 2020 to 40 in 2023， and multiple countries have started to issue hydrogen exploration licenses. Nevertheless， the exploration and production of natural hydrogen are still in their initial stages， with only a few successful cases. Therefore， greater efforts are necessary to conduct scientific exploration and achieve technological breakthroughs.