There is a lack of a unified parameter and criterion system for optimal selection of shale oil and gas sweet-spot intervals at present. Although the total organic carbon （TOC） content is widely considered an essential parameter for the selection， the parameter alone may be insufficient to accurately evaluate sweet-spot without adequate consideration of shale reservoir conditions， resulting in deviation of evaluation results from the optimal sweet-spot intervals. Given this， we categorize the shale oil and gas sweet spots in China， and propose a new approach to the evaluation of shale oil and gas sweet-spot intervals based on source rock-reservoir units. Furthermore， an evaluation process of the new approach is proposed combining the analysis of typical regions and typical shale formations in China. The analytical results reveal that the source rock-reservoir units can be categorized into three types： separated， integrated， and paragenetic types. For separated source rock-reservoir units， the shale oil and gas sweet-spot intervals are characterized by a positive correlation between porosity and oil/gas-bearing properties， establishing porosity as the key parameter for selecting optimal sweet-spot intervals. For integrated source rock-reservoir units， the shale oil and gas sweet-spot intervals feature a positive correlation between the TOC content and oil/gas-bearing properties. This indicates that both the TOC content and porosity can serve as key parameters for the evaluation. In contrast， for paragenetic source rock-reservoir units， the oil/gas-bearing properties of shale oil and gas sweet-spot intervals are jointly governed by the TOC content and porosity， both of which should be jointly considered for accurate evaluation. The abovementioned analyses indicate that the evaluation of the shale oil and gas sweet-spot intervals should focus on favorable reservoir intervals rather than those with high organic matter abundance. Therefore， priority should be given to reservoir conditions in the evaluation methodology for optimal selection of shale oil and gas sweet-spot intervals. Specifically， it is necessary to introduce the integrated evaluation of reservoir conditions in terms of pores， fractures， and lamina and develop geophysical evaluation technologies in order to improve the evaluation accuracy.

The Tahe and Shunbei oil and gas fields， discovered by SINOPEC， are recognized as two major oil and gas fields in the Tabei non-foreland area of the Tarim Basin （also referred to as the study area）. Both fields exhibit contiguous hydrocarbon distribution and accumulation of multilayer systems， boasting the largest areas and the highest degrees of hydrocarbon enrichment in the study area. Focusing on the Ordovician hydrocarbon reservoirs in these two oil and gas fields， we investigate their hydrocarbon properties， multiple hydrocarbon phases， hydrocarbon accumulation patterns， differential hydrocarbon enrichment， production performance， and differential fault activity. Accordingly， we explore the orderly distribution of the Ordovician hydrocarbon systems in the study area. The results indicate that the orderly distributions of hydrocarbon properties and phases in the study area are jointly controlled by the multi-source and multi-stage hydrocarbon generation and expulsion， differential thermal evolution of source rocks， long-term stable evolution of paleo-uplifts and -slopes， and the formation and evolution of reservoirs. The major hydrocarbon accumulation periods of gas and ultra-heavy oil reservoirs， orderly distribution of hydrocarbon reservoir types， and the degree of hydrocarbon enrichment in the study area are governed by multi-stage structural adjustments and corresponding multi-stage hydrocarbon accumulation. In the Shunbei area， the hydrocarbon accumulation pattern is characterized by vertical hydrocarbon transport along faults and lateral transport via lithologic carrier beds and unconformities in the eastern part of the study area， determining that hydrocarbon accumulation in this area is predominantly driven by in-situ hydrocarbon charging， exhibiting great oil column heights. The differential hydrocarbon enrichment in this area is controlled by lateral hydrocarbon adjustments and the scale of source rock-rooted fault zones under certain slope gradient. The distribution of primary hydrocarbon reservoir， principally formed during the Late Hercynian and the Yanshanian， is governed by the evolutionary characteristics of source rocks in the area. In contrast， the Tahe area manifests a hydrocarbon accumulation pattern dominated by lateral hydrocarbon transport along faults， unconformities， and fracture-cavity karst bodies. The Tahe oil and gas field largely exhibits multi-stage hydrocarbon accumulation in vertically layered and laterally contiguous reservoirs， resulting in differential hydrocarbon accumulation governed by deep-seated fault zones and paleo-uplifts and -slopes. Against the backdrop of the overall orderly hydrocarbon accumulation in the hydrocarbon-rich zones， the source rock-rooted strike-slip fault zone functions to control hydrocarbon storage， accumulation and enrichment in an orderly manner， with hydrocarbons being trapped and enriched around the migration pathways around the deep-seated strike-slip fault zone. Given the orderly distribution of the Ordovician hydrocarbon system in the study area， it can be inferred that the potential areas for reserve and production increase via all-round exploration include the circum-western margin of the Manjiaer Depression， circum-Luntai fault zone， and the circum-Awati north slope.

The Surat block in Australia exhibits numerous thin coal seams （average thickness： 0.6 m） that are frequently interbedded with sandstones and mudstones， making it difficult to predict the occurrence locations and enrichment patterns of coalbed methane （CBM） in this block. With the progressive expansion toward deep CBM production， it is necessary to consider both CBM enrichment conditions and ground engineering layouts during deployment. To achieve large-scale commercial CBM production in the Surat block， we examine the essential characteristics of the major CBM reservoirs in the study area， and analyze the dominant factors governing the enrichment of low-rank CBM in these reservoirs， o which basis a comprehensive assessment system for play fairways based on three core parameters： producing interval thickness， gas content， and permeability is built. Using this assessment system， we map the play fairways of CBM. What’s more， a series of strategies for the efficient production of low-rank CBM in the study area are proposed while learning from China's successful experience in CBM production. For the prediction of gas content in coal seams， we introduce an innovative coal facies modeling process based on the probabilistic trend attribute of net-to-gross （NTG） ratios of coal phase， and a prediction process for in situ gas content in coal seams that integrates the trend of dry， ash-free gas content variation with burial depth， log data， and the data of core tests. Regarding well drilling and completion， a hybrid well placement scheme that combines vertical wells with cluster directional wells is proposed， and economic assessment parameters are adopted to optimize vertical-well spacing and the drilling pad spacing of cluster wells for CBM reservoirs at varying depths. In terms of gas production， comprehensively considering the production performance data and field pump inspection results， we propose a failure analysis process for screw pumps in vertical wells and optimize the design of lined oil tubing for deviated wells. Furthermore， the challenge of sand production is effectively addressed using jointly developed water-swellable packers. All these collectively enhance gas production efficiency. In respect of ground engineering， a ground facility arrangement workflow is developed in line with the concept of surface-subsurface integration. Additionally， we eliminate inefficient wells through optimization based on single-well net present value （NPV） and cumulative production. These technical strategies improve the internal rate of return （IRR） of projects， introducing new practices for large-scale CBM production in the Surat block.

The deeply buried Shahezi Formation in the Songliao Basin exhibits considerable coal-bearing rock thickness and abundant coal-rock gas （CRG） resources， establishing itself as an important CRG exploration target in the northern Songliao Basin. Based on the analyses of seismic， geological， and geochemical data， we investigate the coal-forming environment， hydrocarbon generation and evolution， reservoir-forming mechanisms， and CRG accumulation conditions and patterns in the formation. Accordingly， the enrichment patterns and future exploration targets of CRG are proposed in the downfaulted Songliao Basin. The results indicate the presence of extensive peat swamps in multiple downfaulted sediments during the deposition of the Shahezi Formation， with the significantly thick coal seams developed within providing a sound material basis for generating the CRG. Both the coal and mudstone characterized by high abundance and high maturity in the Shahezi Formation serve as source rocks for the enrichment and accumulation of CRG. The CRG in the Shahezi Formation features the coexistence of free and adsorbed gas， with the former accounting for 34.8 % to 43.3 % and the latter for 56.7 % to 65.2 %， as well as the deep anthracite exhibiting a gas content range of 33.83 ~ 36.56 cm³/t. The coal-bearing rocks in the Shahezi Formation contain a pore-fracture system consisting of organic pores and fractures， which provides effective spaces for CRG accumulation. The high breakthrough pressures of the reservoir-cap rock assemblages， consisting of coals and mudstones， and overpressured fluids within coal seams create favorable conditions for CRG preservation. Preliminary estimates suggest that the Shahezi Formation in the northern Songliao Basin boasts CRG resources of approximately 1.260×10¹² m³， including 0.853 × 10¹² m³ in the Xujiaweizi Fault Depression， and both the gentle slope zone on the east side of the Songzhan trough and the Xuxi trough are identified as the preferred targets for CRG exploration in the fault depression.

The provenance of black shales is primarily investigated using elemental geochemistry and mineralogy. Specifically， elemental geochemical approaches are employed to analyze the process of sediment transport and deposition， as well as ascertain the nature of parent rocks and tectonic setting through the analysis of major and trace elements， and rare earth elements （REEs）. Mineralogical techniques， on the other hand， serve to identify the locations of provenance areas and pathways of sediment transport by examining variations in mineral composition. The main limitation of this methodology is that it can only determine potential provenance areas， leaving their specific locations and extents， as well as sediment transport pathways unclear. This study focuses on the provenance of black shales in the Wufeng-Longmaxi formations in the southern Sichuan Basin. The results indicate that the active elements and compounds in the shales include Si， Al， Ca， Fe， Ba， Ta， Th， and Zr and that the inactive elements and compounds encompass Ti， P， Na， Mn， Yb， Lu， and Tm. The parent rocks exhibit low compositional maturity overall， having undergone low to moderate degrees of chemical weathering and transformation under warm and humid climatic conditions. In contrast， sedimentary sorting and recycling produce minimal impacts on variations in the elemental characteristics of the parent rocks. The parent rocks consist mainly of felsic igneous rocks， with tectonic setting dominated by a collision environment， followed by a rift environment locally. The sediment originates primarily from the Qianzhong-Xuefeng paleo-uplift， succeeded by the Leshan-Longnvsi paleo-uplift. Specifically， the sediment in well block Y203， the Changning and Luzhou areas， and the northeastern part of the southern Sichuan Basin is derived principally from the Qianzhong-Xuefeng paleo-uplift， while that near well W207 in the Weiyuan area originate primarily from the Leshan-Longnvsi paleo-uplift. Provenance analysis reveals multiple factors influencing the contents of major and trace elements， and mineral components in the sediment. Therefore， to accurately determine the provenance areas of shales and their distribution， it is necessary to integrate the stable isotope analysis， high-resolution geochemical techniques， multi-index， multidisciplinary study， and big data analytics.

In recent years， several exploration wells have revealed low-yield natural gas in the concealed structures of the 8^th member of the Upper Paleozoic Shihezi Formation and the 1^st member of the Upper Paleozoic Shanxi Formation in the thrust zone along the western margin of the Ordos Basin. Hence， investigating the concealed structures in the footwall of nappes is significant for natural gas exploration in the study area. Using the latest drilling results， seismic data， observations of petrographic thin sections， and organic geochemical data， we explore the characteristics of the Paleozoic concealed structures in the footwall of thrust nappes within the central section of the western margin of the Ordos Basin. Accordingly， the geological conditions for hydrocarbon accumulation and hydrocarbon exploration potential of the Ordovician Kelimoli Formation is analyzed and favorable exploration targets are proposed in the concealed structural zone. The results indicate that， under the influence of intense W-E-oriented stress of nappes during the Yanshanian movement （Jurassic to Cretaceous）， strata in the footwall of nappes in the study area deformed under passive compression and folding， resulting in the extensive development of SN-oriented concealed structures distributed in rows. These concealed structures exhibit large-scale traps and underdeveloped faults， suggesting favorable sealing performance. The Ordovician Kelimoli Formation contains high-energy ramp shoal reservoirs consisting primarily of medium-to-coarse-crystalline dolomites. These reservoirs exhibit storage spaces dominated by intercrystalline pores， intercrystalline dissolution pores， and fractures， with porosity ranging from 3 % to 6 % and permeability from 1 × 10^-3 to 8 × 10^-3 μm². Two suites of high-quality marine source rocks occur in the Wulalike and Kelimoli formations， with kerogen dominated by Types I and II1 and vitrinite reflectance （R_o） ranging from 1.50 % to 1.90 %. The study area exhibits both vertical and lateral hydrocarbon supply， a favorable source rock-reservoir configuration， and the formation of the concealed structure traps is well matched with the main hydrocarbon generation and expulsion period of source rocks. The superimposed areas of low-amplitude concealed structural zones and high-energy shoals serve as natural gas enrichment areas， with the favorable superimposed areas of 300 km² from preliminary prediction. Additionally， the Yandunshan， Huianbu， and Majiatan concealed structural zones in the Majiatan section along the western margin of the Ordos Basin are identified as favorable areas for future natural gas exploration in the Kelimoli Formation.

This study aims to identify the sedimentary characteristics of sequences in the 1st member of the Lower Shihezi Formation （hereafter referred to as the He 1 Member） in the Jin-77 well block within the Hangjinqi area， Dongsheng gas field， Ordos Basin. To this end， we investigate the log responses and seismic reflection signatures of lithofacies in the He 1 Member using data from core observations， well logs， and seismic data. In combination with the geophysical forward modeling results of sand bodies with various architectures， we summarize the comprehensive response patterns of sedimentary microfacies， log facies， and seismic facies of the He 1 Member. Accordingly， the sequence boundaries of the Lower Shihezi Formation and its overlying and underlying strata are delineated and the characteristics of their internal sedimentary microfacies are explored. What’s more， an integration and mutual constraining of well logs and seismic data is applied to determine the planar distribution of the sedimentary microfacies of the H1-2 sublayer using geophysical attribute-based stratal slicing technology. The results indicate the He 1 Member can be divided into four sublayers based on the high-frequency sequence framework and sand body distribution of the Lower Shihezi Formation. Sand bodies in the member are concentrated in the H1-1， H1-2， and H1-3 sublayers， with each sublayer measuring 15 ~ 20 m in thickness. A comprehensive analysis of lithologies， sedimentary structures， sedimentary facies markers， vertical lithologic assemblages， and sand body distribution characteristics reveals that the He 1 Member consists primarily of wandering braided-river deposit with limited storage space， sufficient supply， and unstable channels， and its main sedimentary microfacies include mid-channel bars， channels， and floodplains. The H1-2 sublayer， as the primary target interval， contains three or four nearly SN-trending braided river channels with widths ranging from 1 to 8 km. Among these channels， those in the north are identified as favorable sites for the development of mid-channel bar microfacies.

The boundary between two tectonic units in the northern Ordos Basin， namely the Yimeng Uplift and the Yishan Slope， remains controversial. In this study， we analyze the basement relief， stratigraphic distribution， basement faults， tectonic evolution， and hydrocarbon distribution characteristics in the northern Ordos Basin. The results indicate that the EW-NE-striking basement faults in the northern Ordos Basin governed the formation of the Yimeng Uplift as ramp structures. Among these basement faults， the pre-existing Xinzhao North-Porjianghaizi South （F4+F10） basement fault zone serves to separate the structural units before the Mesoproterozoic. The Hangjinqi fault zone （HFZ） runs across the northern Ordos Basin and consists primarily of three large-scale basement faults arranged in en echelon arrays， including the Porjianghaizi， Wulanjilinmiao， and Sanyanjing faults， which evolves from the selectively reactivated basement fault zone pre-existing as mentioned above during the Caledonian. During the Hercynian， Indosinian， and Yanshanian， The HFZ continued its inherited activities， having governed the tectono-sedimentary evolutionary framework of the northern Ordos Basin throughout various geological periods. The northern and southern basin separated by the HFZ exhibit significant differences in tectonic activity intensity， distribution and maturity of source rocks， variations in reservoirs and their physical properties， and hydrocarbon trap types. It can be concluded thereby that the HFZ controls the hydrocarbon generation and distribution in the northern Ordos Basin. It is， thereby， more reasonable to take the HFZ as the boundary between Yimeng Uplift and Yishan Slope， which will be of great significance to deepening understanding on the geology of the northern Ordos Basin and thereby guiding the hydrocarbon exploration therein.

Commercial oil flow with peak daily production ranging from 5.21 to 19.17 t has been achieved in shale oil exploitation in the 3rd member of the Hetaoyuan Formation （also referred to as the He 3 Member） in the Nanyang Sag， Nanxiang Basin. Therefore， investigating shale oil enrichment in this sag is significant for exploration. Using methods including core observation， log response analysis， thin section observation， scanning electron microscopy （SEM）， hydrocarbon generation and expulsion simulation， and confocal laser scanning microscopy （CLSM）， we investigate the formation conditions， occurrence characteristics， enrichment conditions， and exploration potential of freshwater lacustrine shale oil in the Nanxiang Basin. The results indicate that shales in the Nanyang Sag primarily occur in the upper part of the He 3 Member to the He 2 Member， with a maximum cumulative thickness reaching up to 1 400 m. The shale layers in the sag exhibit total organic carbon （TOC） content ranging from 0.18 % to 1.58 %， with an average of 0.84 %， and free hydrocarbon （S₁） content from 0.15 to 1.23 mg/g. Their organic matter is dominated by Type Ⅱ1， with vitrinite reflectance （R_o） values ranging from 0.5 % to 1.0 %， indicating moderate thermal maturity. The lithofacies of the shales consist principally of lamellar to laminated mixed shales， lamellar felsic shales， and lamellar dolomitic calcareous shales， with lamellar mixed shales predominating. The main storage spaces within the shales include matrix pores and fractures. The matrix pores are dominated by intergranular pores in clay minerals， intercrystalline pores， and dissolved pores， along with a small quantity of organic pores. These pores contribute to matrix porosity ranging from 0.2 % to 5.4 %， with an average of 3.1 %. The shale layers in the sag thereby exhibit moderate reserving properties， moderate shale oil mobility and good fracability. Calculations using the volumetric method reveal total shale oil resources in the sag reaching up to 2.01 × 10⁸ t， with the identified exploration area of play fairways covering 72.1 km².

Volcanic rocks in the Permian Jiamuhe Formation of the Jinlong oilfield in the Junggar Basin exhibit unclear lithofacies types and dominant reservoir distribution， which hinder the exploitation of the oil and gas resources therein. To address these challenges， we systematically analyze the volcanic facies types， reservoir physical properties， and storage space characteristics in the study area using data from core observations， log analysis， and laboratory tests. Accordingly， we establish lithofacies assemblage models， while clarifying their controlling effects on productivity. The results indicate that the volcanic rocks in the Jinlong oilfield in the Junggar Basin can be categorized into three facies： explosive， overflow， and volcanic sedimentary facies. The explosive facies， among others， consists primarily of welded volcaniclastic rocks and andesitic volcanic breccias， and exhibits an average porosity exceeding 10 %， forming dominant reservoirs. While the overflow facies is dominated by lavas， featuring an average porosity of below 6 %， and the volcanic sedimentary facies exhibits poor physical properties. In the volcanic reservoirs in the study area， vesicles， intra-amygdale pores， and dissolution pores predominate， with a minor presence of primary intergranular pores. Additionally， dissolution vugs are most developed at the top of the explosive and overflow facies. Fractures in the volcanic reservoirs are dominated by structural and dissolution fractures， with developmental degrees closely related to their distance from faults. The intermediate-acidic overflow facies mainly exhibits oblique and reticulate fractures， while the mafic overflow facies is dominated by high-angle， straight-split fractures. The study area exhibits four lithofacies assemblages： interbedded intermediate-acidic pyroclastic flow subfacies and intermediate-acidic overflow subfacies， frequently interbedded mafic pyroclastic flow subfacies and mafic overflow subfacies， interbedded neutral air-fall subfacies and neutral overflow subfacies， and interbedded neutral air-fall subfacies and intermediate-acidic pyroclastic flow subfacies. The interbedded neutral air-fall subfacies and intermediate-acidic pyroclastic flow subfacies exhibits the highest productivity， followed by interbedded intermediate-acidic pyroclastic flow subfacies and intermediate-acidic overflow subfacies and interbedded neutral air-fall subfacies and neutral overflow subfacies， and with the frequently interbedded mafic pyroclastic flow subfacies and mafic overflow subfacies coming at last in daily production. The productivity of the volcanic reservoirs is governed most significantly by the effective reservoir thickness and oil saturation， followed by porosity and formation pressure.

This study aims to reveal the genetic mechanisms underlying high-quality deep to ultra-deep clastic reservoirs in the hinterland of the Junggar Basin. Using the latest drilling data and core samples from the hinterland， as well as data from casting thin section observations， scanning electron microscopy （SEM）， spectral analysis， inclusion analysis， and X-ray diffraction （XRD） analysis， we investigate the origins of reservoirs in the Permian Upper Urho Formation and the Triassic Baikouquan and Karamay formations. The results indicate that differential diagenetic evolution governs the development of primary pores and secondary dissolution pores. The Karamay Formation underwent compaction， chlorite coating cementation， dissolution of feldspar/volcanic detritus， siliceous cementation， authigenic illite precipitation， and the late-stage calcite cementation sequentially， during which chlorite coatings emerged as the most significant diagenetic mineral for the preservation of primary pores. In contrast， the Upper Urho Formation experienced compaction， chlorite filling cementation， laumontite cementation， dissolution of laumontite/feldspar/volcanic detritus， siliceous cementation， authigenic illite precipitation， and the late-stage calcite cementation in sequence. The early-stage laumontite cementation and acid dissolution of laumontite/feldspar/volcanic detritus， among others， play a critical role in the formation of secondary pores. In the subaqueous distributary channels at the front of the shallow braided river delta， the strong hydrodynamic elutriation in high-energy facies zones results in superior primary pore structures in these reservoirs. This， combined with early-stage chlorite coatings and significant overpressure， collectively contributes to the preservation of primary pores. The early-stage cementation of high-hardness laumontite formed by the hydrothermal alteration of intermediate-mafic volcanic detritus resists the compaction and porosity reduction in the rapid deep burial stage. The acidic fluids from multi-stage hydrocarbon generation and overpressure transfer jointly accelerate the dissolution of aluminosilicate minerals and porosity enhancement. Under the background of low geotemperature， the Upper Urho-Baikouquan formations remain in middle diagenetic stages A and B， which has slowed down the diagenetic evolution and increased the lower depth limit for effective porosity development.

The Y-shaped anticline， situated in the Ningbo structural zone， Xihu Sag， has emerged as a focal point in hydrocarbon exploration and assessment in the East China Sea Shelf Basin in recent years. However， the dominant factors controlling the differential hydrocarbon accumulation and favorable exploration targets in this anticline are yet to be clarified. Through fine structural analysis， we investigate the segmented differential deformation of the Y-shaped anticline and controlling factors， as well as its significance on hydrocarbon accumulation. The results indicate that the Y-shaped anticline can be divided into southern， central， and northern segments based on the differences in structural morphology. The secondary anticlines in these segments are governed by various inverted faults， with the central segment exhibiting the most significant compressional uplift. The main factors controlling the differential deformation in the southern and northern segments include regional compressive stress， differences in pre-existing sub-sag-controlling faults， and localized stress concentration induced by rigid basement. In contrast， the central segment experienced uplift overall driven by intense compression and contraction. Consequently， the originally separated secondary anticlines in the southern and northern segments underwent deformation， eventually forming a large anticlinorium featuring disparities in the southern and northern parts. The differential deformation of the southern and northern segments， coupled with the multistage superimposed deformation， results in differential hydrocarbon accumulation in different parts of the Y-shaped anticline. It can be concluded from these findings that the Huagang and Longjing formations contain multiple favorable exploration targets， which will be of great help to gas exploration in the Xihu Sag.

Using data of the geochemistry， gas saturation， and rock and mineral compositions of formation water extracted from 34 wells， we discuss the origin of calcium-rich formation water in the 2^nd member of the Jurassic Shaximiao Formation （hereafter referred to as the Sha 2 Member） in the central Sichuan Basin， and accordingly explore the implications of the formation water for natural gas migration and accumulation of tight-sand gas reservoirs with source-reservoir separated. The results indicate that the formation water in the Sha 2 Member exhibits pronounced calcium enrichment and sodium depletion compared to that in other tight-sand gas reservoirs in China. The formation water in the member displays total dissolved solids （TDS） ranging from 3.3 to 45.6 g/L （CaCl₂ type） and equivalent concentration proportions of Ca²⁺ ［γ（Ca²⁺）］ ranging from 24.7 % to 69.5 %， based on which the formation water can be categorized into three types： high-calcium ［γ（Ca²⁺） ≥ 60 %］， medium-calcium ［40 % ≤ γ（Ca²⁺） < 60 %］， and low-calcium ［γ（Ca²⁺） < 40 %］ formation water. These three types of formation water differ greatly in chemical characteristics and distribution. Specifically， the high-calcium formation water is concentrated in channel sand bodies that are near and connected to Jiao ① fault. This type of formation water， among others， exhibits a high average TDS of 34.1 g/L， cations dominated by Ca²⁺， and the lowest Na⁺/Cl^- ratio， desulfurization coefficient， and carbonate equilibrium coefficient. The low-calcium formation water principally occurs in channel sand bodies that are distant from or not directly connected to the Jiao ① fault. This type of formation water manifests an average TDS of 3.9 g/L， cations dominated by Na⁺， and the highest Na⁺/Cl^- ratio， desulfurization coefficient， and carbonate equilibrium coefficient. The medium-calcium formation water exhibits an average TDS of 17.7 g/L and slightly different Na⁺ and Ca²⁺ concentrations， with Na⁺/Cl^- ratios， desulfurization coefficients， and carbonate equilibrium coefficients falling between those of the high- and low-calcium formation water. The calcium enrichment in formation water of the Sha 2 Member is primarily attributed to the mixing of formation water with a high Ca²⁺ concentration from the Xujiahe Formation. Additionally， subsequent water-rock interactions， especially the albitization of plagioclase， further contribute to the calcium enrichment and sodium depletion in the formation water of Sha 2 Member. The carbonate equilibrium coefficients， TDS， and γ（Ca²⁺） of formation water in the Sha 2 Member decrease gradually along the lateral migration pathway of natural gas. This indicates that the chemical indices of calcium-rich formation water can serve as reliable tracers for tight-sand gas reservoirs of separated source-reservoir type. For the Sha 2 Member， higher calcium enrichment in formation water is associated with more favorable gas-bearing properties of reservoirs， suggesting that the calcium-rich formation water is indicative of natural gas accumulation.

The unclear understanding of the Permian rifting evolution and sedimentary filling patterns in the Sichuan Basin has hindered hydrocarbon exploration in this region. Based on outcrop observations and the latest drilling， logging， and seismic data， we determine the sequences in the Maokou Formation within the eastern Sichuan Basin and investigate the formation filling process from deposition. The results indicate that rifting in the eastern Sichuan Basin began in the early to middle Middle Permian， as manifested by the initial rifting stage during the late depositional stage of the 1st member of the Maokou Formation （also referred to as the Mao 1 Member）， and the significantly intensified activation of Nos. 15 and 16 basement faults during the early depositional stage of the Mao 2 Member. In response to the tensile stress in the N-S direction， the sedimentary landscapes of study area are transformed as characterized by southern platforms and northern rifts. Following the late depositional stage of the Mao 2 Member， the tectonic activity got further intensified in the study area， evolving into a period of continuous rifting development. This multi-stage tectonic and sedimentary differentiation is likely influenced by the episodic activities of the Emeishan large igneous province （ELIP）， leading to the formation of multi-stage slope break zones. The Gufeng Member of the Maokou Formation in the Shizhu area， as well as the Cheng-20 and Zhang-12 well blocks， represents organic matter-rich deposits formed in low-lying areas of the carbonate platform. Meanwhile， the reservoirs of the high-energy shoal facies and the source rocks of the Gufeng Member in the low-lying areas create a favorable source rock-reservoir configuration. All these establish the areas as potential large-scale exploration region. Furthermore， the platform-margin shoal zone in well Cheng-23—Zhongxian County is identified as a natural gas play fairway.

Platform-margin zones in the upper sub-member of the 2^nd member of the Maokou Formation （also referred to as the Mao 2 Member） in the Sichuan Basin exhibit enormous hydrocarbon exploration potential， with constant breakthroughs having been made in the central to northwestern Sichuan Basin. However， the distribution pattern of platform-margin zones in the eastern Sichuan Basin remains unclear due to limited studies. Focusing on the eastern Sichuan Basin， we conduct sub-layer division and correlation， investigate the distribution and evolutionary pattern of the platform-margin zones therein， and propose hydrocarbon play fairways. The results indicate that the upper sub-member of the Mao 2 Member in the eastern Sichuan Basin exhibits two fourth-order eustatic cycles， as evidenced by lithologic assemblages and logs. Based on this finding， the upper sub-member can be divided into sub-layers 1 and 2. Both sub-layers consist of the sedimentary systems of rimmed carbonate platform facies， with major sedimentary subfacies including platform-margin shoals， inter-shoal lagoons， intra-platform shoals， and semi-restricted seas. The platform-margin zones in both sub-layers show similar distribution patterns， with platform-margin shoals along the Linshui-Fengdu and Dazhu-Zhongxian platform-margin zones spreading in the NW-SE direction. During the deposition of sub-layer 1， platform-margin shoals in both platform-margin zones display pronounced differentiation， separated by banded inter-shoal lagoons. During the deposition of the sub-layer 2， platform-margin shoals display lateral migration and an expanded planar distribution area， manifesting a contiguous development in the eastern part. The superimposition of penecontemporaneous karstification and dolomitization on platform-margin shoals is identified as the main cause of the formation of high-quality reservoirs. The Linshui-Fengdu and Dazhu-Zhongxian platform-margin zones are favorable for reservoir development， while slope-troughs and inter-shoal lagoons emerge as favorable areas for source rock development. The platform-margin shoals along the Dazhu-Zhongxian platform-margin zone exhibit great hydrocarbon exploration potential， serving as a new hydrocarbon play fairway.

The Da’an area， located in western Chongqing within the Sichuan Basin， serves as a promising new target for deep shale gas exploration in the Wufeng-Longmaxi formations. However， the pore microstructure characteristics of shale reservoirs in this area and their controlling effects on gas content are yet to be clarified， posing a challenge for shale gas exploration in depth. Using the analytical and test data from scanning electron microscopy （SEM）， low-temperature gas adsorption， and nuclear magnetic resonance （NMR） experiments， we investigate the features of pore microstructures of various lithofacies in deep shales in the Wufeng-Longmaxi formations， as well as their controlling effects on the differences in gas content. The results indicate the presence of four lithofacies in deep-seated shales in the Da’an area： siliceous shales， mixed siliceous shales， clayey siliceous shales， and mixed clayey-siliceous shales. Pores in the shales are dominated by organic pores， followed by intercrystalline pores， dissolution pores， and interlayer pores in clay minerals. Meanwhile， fractures also observed in the shales consist of organic matter-filled fractures， interlayer fractures in clay minerals， and tectonic stress-induced fractures. Primary pore structures in the deep-seated shales include mesopores （pore size ranging from 2 to 50 nm） and macropores （pore size greater than 50 nm）. An increased total organic carbon （TOC） content is conducive to the development of micropores （pore size less than 2 nm） and macropores. In contrast， the elevated content of siliceous and clay minerals foster the formation of macropores and mesopores， respectively. The gas content of the deep shales is positively correlated with the TOC content and the siliceous mineral content， so does the macropore volume to gas content. Shales with a high siliceous content manifest the optimal gas-bearing properties， establishing them as the favorable lithofacies for the enrichment of deep shale gas. Moderately shallow shales in the Da’an area primarily contain micropores and mesopores， with adsorbed gas predominating. In contrast， deep-seated shales in the area principally exhibit mesopores and macropores and the predominance of free gas. The well-developed macropores create favorable conditions for free gas preservation， thus increasing the gas content in the deep-seated shales.

Source rocks in the Upper Ordovician Qrebake Formation in the Shunbei area of the Tarim Basin have been newly discovered in recent exploration. Investigating their geochemical characteristics holds great significance for future hydrocarbon exploration. Using comprehensive geochemical experiments， analyses， and tests on source rock samples from six wells in the Shunbei area， we explore their organic matter abundance， types， and thermal maturity in the Upper Ordovician Qrebake Formation. The results indicate that the selected source rocks consist primarily of grayish-black mudstones， dark gray calcareous mudstones， and dark gray argillaceous limestones. The grayish-black mudstones， among others， exhibit total organic carbon （TOC） content ranging from 0.20 % to 2.81 % （average： 1.59 %） and Rock-Eval pyrolysis-based hydrocarbon generative potential （S₁+S₂） from 0.43 to 12.05 mg/g （average： 5.59 mg/g）. The dark gray calcareous mudstones show TOC content varying from 0.46 % to 2.24 % （average： 1.47 %） and S₁+S₂ from 0.18 to 1.97 mg/g （average： 0.91 mg/g）. In contrast， the dark gray argillaceous limestones manifest TOC content ranging from 0.22 % to 3.41 % （average： 1.72 %） and S₁+S₂ from 1.37 to 18.56 mg/g （average： 9.04 mg/g）. Notably， wells SB5， SB7， and SB71X present source rocks of the highest organic matter abundance. Source rocks in the Qrebake Formation are formed in a weakly reducing， brackish marine sedimentary environment， with parent materials originating primarily from low aquatic algae. Most samples exhibit hydrogen index （HI） values ranging between 289 and 512 mg/g （average： 416 mg/g）， suggesting humic-sapropelic organic matter （Type Ⅱ₁） with high hydrocarbon generative potential. Source rocks from well SB7 present vitrinite equivalent reflectance （R_{o， eq}） ranging from 0.55 % to 0.88 % （average： 0.72 %）， indicating low-to-moderate maturity. In well SB71X， the R_{o， eq} ranges from 0.53 % to 0.70 % （average： 0.62 %）， suggesting low-maturity source rocks. Meanwhile， source rocks from well SB5 display R_o，eq between 0.85 % and 0.95 % （average： 0.90 %） of moderate maturity. Source rocks in the formation measure from 20 to 25 m in thickness， distributed primarily in the intra-platform depressions in the Nos. 5 and 7 fault zones in the Shunbei area.

The microscopic gas and water retention mechanisms in tight， low-permeability reservoirs are yet to be clarified， severely limiting the enhancement of oil and gas recovery of these reservoirs. The study delves into the microscopic mechanisms of gas and water retention in tight sandstone reservoirs and evaluates the feasibility of CO₂ injection for enhancing recovery rates via innovative microscopic experimental methods and numerical simulations. Specifically， we establish an entirely new microscopic retention experimental process， while overcoming the limitations of traditional experimental methods， such as ultra-low experimental pressures （less than 0.20 MPa）， and the mismatch between experimental processes and actual production conditions. Combined with the microscopic numerical simulation technique， we identify four primary gas and water retention types in tight sandstone reservoirs， i.e.， blind end-corner retention， bypassing retention， cut-off retention， and “H-shaped” pore retention. On this basis， the mechanisms behind CO₂ injection for enhancing gas recovery of tight， low-permeability reservoirs can be concluded. That is， the CO₂ injection serves to strip water film， facilitate the mass transfer and diffusion replacement of methane， as well as effectively displace gas， significantly increasing natural gas recovery from tight pore throats. The results reveal that CO₂ injection can enhance natural gas recovery rate by 10 % to 19 %， representing an innovative technological approach for the efficient exploitation of tight， low-permeability gas reservoirs.

Abundant deep coal-rock gas in the Ordos Basin boasts enormous potential for exploration and development. The geological characteristics of deep coal-rock gas exhibit substantial regional changes， and reservoir simulation tests under various process conditions have revealed notable differences in the productivity of coal-rock gas wells. This study aims to investigate the main factors controlling the coal-rock gas productivity of horizontal wells. Using the dynamic and static data from deep coal-rock gas in the pilot test area and employing the analytical approach of geology-engineering integration， we depict the geological features of coals in detail and thoroughly assess the production indices of producing wells. Furthermore， geological and engineering assessments are carried out using methods such as Pearson correlation analysis， hierarchical clustering， and machine learning. The results indicate that under similar regional geological features such as coal structure and thermal maturity， coal thickness and gas-bearing property， two geological factors， significantly affect the productivity of coal-rock gas wells. Meanwhile， the total length of coals encountered during drilling （L）， total drill-in liquid volume （W）， proppant volume （S）， and proppant intensity （Sq） among engineering factors exhibit positive correlations with the productivity of coal-rock gas wells. Notably， engineering factors show more pronounced correlations with the first-year daily gas production compared to geological factors， and the composite geology-engineering factors display more significant correlations than individual factors. Increasing well-controlled drainage volume and stimulated reservoir volume （SRV） contributes to the high productivity of coal-rock gas wells. Assuming target coal thicknesses measuring 6 ~ 10 m and an average proppant intensity of 5.5 t/m， a lateral length of 1 000 ~ 1 500 m is required to achieve a single-well estimated ultimate recovery （EUR） of 5 000 × 10⁴ m³. A new method for predicting the single-well productivity of deep coal-rock gas， based on geological and engineering parameters， is developed using intelligent algorithms such as deep neural networks， support vector machines （SVMs）， and random forest models. This method achieves a coincidence rate of up to 91 % according to blind well verification with 22 wells involved.

Bitumen， which is widely found in the storage spaces of deep carbonate reservoirs， significantly affects the physical and gas-bearing properties of the reservoirs and complicates their resistivity logging responses. This makes it more difficult to evaluate the effectiveness of bitumen-bearing carbonate reservoirs， determine fluid properties， and calculate water saturation. This study focuses on the bitumen-bearing carbonate rocks of dissolved pore and cavity types in the Cambrian Longwangmiao Formation in the Gaoshiti-Moxi area， Anyue gas field， Sichuan Basin. Based on the analysis of the micro-CT scanning data， we characterize the pore structures and bitumen-filling characteristics of the carbonate reservoirs using digital core modeling. As a result， 3D rock conductivity models with varying bitumen content and water saturation conditions are established. Then， numerical simulations of rock conductivity are conducted using the finite element method， and the mechanisms through which bitumen influences the conductivity of carbonate rocks are investigated. The results indicate that the resistivities of bitumen-bearing carbonate rocks of both types exhibit a positive correlation with the bitumen content and a negative correlation with water saturation. Since the narrow throats in dissolved pore-type carbonate rocks are more prone to be blocked by bitumen， the conductivity of these rocks is more subjected to bitumen effect than the dissolved cavity-type carbonate rocks. Under low water saturation， formation water mainly occurs as irreducible water films on storage space surfaces. However， these water films become incomplete in the presence of bitumen， leading to a sharp increase in resistivity for both types of carbonate rocks. Compared to bitumen-bearing dissolved cavity-type carbonate rocks， the dissolved pore-type reservoirs exhibit a higher cementation exponent （m） and a lower saturation exponent （n）.

Given the diverse hydrocarbon compositions of the Jurassic lacustrine shale gas in the Sichuan Basin， we develop a molecular model for the organic matter-clay mineral composite pore system composed of kerogen and illite slit pores and composite pores. Using molecular dynamics simulations， we explore the microscopic occurrence characteristics of wet gas in the composite pore system and the influential factors related. The results indicate that at lower pressures， hydrocarbon molecules preferentially occupy space near kerogen walls within the composite pores， while the number of hydrocarbon molecules increases under high-pressure conditions， and the heavier hydrocarbon molecules are preferentially concentrated in space near kerogen walls within the composite pores， leaving lighter hydrocarbons to be confined to the illite walls. Under the same pressure conditions， a larger pore diameter meaning larger pore space， can accommodate more hydrocarbon molecules. Under high-pressure conditions， interactions between water molecules get enhanced， forming clusters due to hydrogen bonding. These water clusters can be found on the surface of the kerogen， or free in the composite pores， or develop into a water film on the surface of illite. The organic matter pores， composite pores， and clay mineral pores in the organic matter-clay mineral composite pore system all contribute to the occurrence of hydrocarbons. Compared to organic matter pores， the latter two pore types can accommodate a greater number of hydrocarbon molecules dominated by lighter ones， characterized by higher gas content and better mobility.

For ultradeep， fractured-vuggy carbonate karst reservoirs located in the strike-slip fault zone within the Tarim Basin， their three-dimensional architecture is identified as a primary factor influencing their connectivity and residual oil distribution. This study focuses on the geologic outcrop in the Yijianfang area within the basin that exhibits the characteristics of typical fractured-vuggy reservoirs. Using unmanned aerial vehicle （UAV）-based scanning of the outcrop， analysis of ground-penetrating radar （GPR） data， and the field measurements， we determine the parameters of the faults， fractures， and karst caves. By examining the distribution characteristics of the large and small karst caves， fault cores， and fracture zones exposed， we establish the developmental model of fractured-vuggy reservoirs in the outcrop area in the fault zone. Based on the mechanisms of Riedel shear structures and the stress ellipse theory， we analyze the structural characteristics of the strike-slip faults. Afterward， we conduct fine interpretations of the strike-slip fault， main body of fractured-vuggy reservoirs， and fracture zones in the Yueman well block of the Fuman oilfield based on 3D seismic data， while combining conventional interpretations with intelligent identification. With the help of interference tests of a well group， we identify the major factors controlling the connectivity of the fractured-vuggy reservoirs. Accordingly， we divide the reservoir units based on production performance including single-well productivity， water breakthrough cycle， changes in tubing pressure， and static pressure gradients of the wellbore. Additionally， we explore the impacts of reservoir architecture on residual oil distribution. The results indicate that the strike of the fault plane represents a primary factor governing the development of fractured-vuggy reservoirs. These fractured-vuggy karst reservoirs have evolved through three stages： the single fault-plane fault-fracture combination without karstification， single fault-plane fracture-karst cave combination with weak karstification， and single fault-plane fracture-karst cave combination with strong karstification. These evolutionary stages correspond to three combination patterns of fractured-vuggy karst reservoirs， namely the single， parallel， and complex fault-plane patterns. Data on production performance can serve as a basis for determining reservoir connectivity since single-well production， tubing pressure， and stratigraphic static pressure reflect the degree of reservoir connectivity. Fault-fractured-vuggy karst reservoirs with varying fault-plane combinations manifest three reservoir connectivity types： strong connectivity along the fault zones of the same strike， moderate connectivity via intersecting fault zones with different strikes， and lateral weak connectivity via non-intersecting fault zones with different strikes. The fractured-vuggy reservoirs with the oblique fault-fracture plane combination， manifest slightly weak connectivity， with fractures and reservoirs particularly well-developed at fault intersections. In contrast， the fractured-vuggy reservoirs with the single fault of the same strike exhibit strong internal connectivity， indicating great potential for oil exploitation.