Responding to climate change represents a tremendous challenge to the community with a shared future for mankind. China has committed itself to achieving carbon peaking goal by 2030 and carbon neutrality goal by 2060. The dual carbon goals are not only China’s solemn commitments to the world as a responsible power but also key strategic objectives of the systematic socio-economic reforms， transition， and development of the country. Energy plays a crucial role in reaching carbon neutrality. Given China’s particular situation featuring a high proportion of fossil energy and rapidly increasing rigid demand of energy， this study proposes a pathway for China’s energy transition. In this aspect energy transition is guided initially by government policies and driven by market forces in the long term while focusing on both carbon emission reduction and carbon sequestration， capture， utilization and storage. Carbon pricing， through carbon taxes and emissions trading， lies at the core of the pathway， with the future proportion of fossil energy in the primary energy mix and the level of end-use electrification serving as critical indicators. Specifically， it is recommended to fully leverage government guidance and market dominance to facilitate energy transition and reach carbon neutrality in China， and there is a vital need to vigorously develop core technologies for both carbon emission reduction and carbon sequestration， capture， utilization and storage. Furthermore， it is necessary to effectively manage relationships of economic development with carbon neutrality and energy security， between national emission reduction targets and those of all provinces， cities， and enterprises， between traditional fossil energy companies and emerging new energy enterprises， between short-term actions and long-term goals regarding carbon emission reduction， and the coordinated progress on carbon emission reduction for China and the other countries across the world.

This study introduces the connotation of technological synergy for enhancing hydrocarbon recovery， and proposes the synergy of secondary recovery （water flooding） with tertiary recovery （CO₂ flooding） （also referred to as the synergy of 3+2） to significantly improve the recovery of mature fields with high water cut， as well as corresponding measures taken to facilitate the technological synergy execution. What’s more， the synergy of thermal fluids with multiple displacing mediums is also established to substantially improve heavy oil recovery， and is applied in practice， showing a 21.9 % increase in the recovery for heavy oils that are typically difficult to extract. Furthermore， the synergy of multi-displacing-mediums compounded thermal flooding with multilateral wells is successfully applied to expand the upper limit of the viscosity for heavy oil recovery to 750，000 mPa·s and reduced the lower limit of the produced reservoir thickness to 1.5 m. Future research on the synergy alternatives for enhancing hydrocarbon recovery should focus on the synergy of hydraulic fracturing-assisted oil displacement with waterflooding for low-permeability reservoirs， the synergy of gas flooding， water flooding， and injection-production well pattern optimization for fractured-vuggy oil reservoirs， the synergy of injection-production ratio optimization， artificial lift and gathering system for mature oilfields， as well as combined drainage gas recovery for shale gas.

The control of various structural styles on hydrocarbon accumulation proves to be a major scientific challenge for hydrocarbon exploration. Based on a summary of previous research achievements and exploration experience， we systematically organize the evolution and genetic models of different structure styles in the petroliferous basins of China， and analyze their control on hydrocarbon accumulation. The findings are as follows： （1） Four major structural styles are identified in petroliferous basins of China： extensional， contractional， strike-slip， and superimposed structures. The extensional structure， among others， primarily controls basin formation， while the contractional and strike-slip structures principally govern basin reconstruction. （2） These structural styles play significantly different roles in hydrocarbon generation， migration， and accumulation. Specifically， the extensional structure controls the development of source rocks， favorable reservoirs， and cap rocks， key factors to hydrocarbon accumulation in the basins. In contrast， the contractional， strike-slip， and superimposed structures dictate hydrocarbon migration and the evolution of traps. （3） Under the combined influence of tectonics and other factors， faults themselves can serve as reservoirs， providing spaces for hydrocarbon accumulation. This fault reservoir represents an emerging hydrocarbon exploration target presently.

Geochemical parameters serve as important indicators for shale oil enrichment and mobility evaluation. Using pyrolysis experiments of minerals/post-extraction shale residues mixed with oil/alkanes， as well as the comparison and forward modeling of pyrolysis parameters of oil-generating shales before and after shale extraction using organic reagents， we perform a case study of the oil-generating shales in the Bakken Formation of the Williston Basin and the Paleogene Shahejie Formation of the Jiyang Depression in the Bohai Bay Basin. Accordingly， the characteristics of shale oil enrichment and corresponding responses of geochemical parameters are analyzed to investigate the lower limits of the oil saturation index （OSI） and productivity index （PI） as indicators of shale oil enrichment and mobility. The results reveal that conventional Rock-Eval pyrolysis on oil in rock generates both free hydrocarbons （S₁） and pyrolyzed hydrocarbons （S₂）， affecting the S₂ curve’s peak style and peak temperature for hydrocarbon pyrolysis （T_max）. Crude oil enrichment in shales， thereby， leads to anomalously high values of OSI and PI and anomalously low T_max values， with these three parameters in coordinated variation. Oil-rich shales with a low organic matter content exhibit more pronounced anomalies in pyrolysis parameters. In contrast， for organic-rich shales， their OSI and PI values tend to stabilize after the total organic carbon （TOC） content reaches a specific threshold. The liquid-solid interactions in shales affect the lower limits of indicators for hydrocarbon mobility. A systematic analysis of the Bakken Formation in one well in the Williston Basin and the Shahejie Formation in three wells in the Jiyang Depression indicates that the lower limits of OSI for the enriched shale oil and its mobility fall below 50 ~ 75 mg/g， corresponding to PI values of 0.12 ~ 0.20. The lower limit of OSI for the enriched shale oil and its mobility is closely associated with shale lithology and crude oil properties， with carbonate-rich shales exhibiting lower limits of OSI for shale oil mobility.

The Phanerozoic evolutionary processes of the Tethyan and Paleo-Asian tectonic domains have delivered profound impacts on the Tarim Basin， including the formation of prototype basins and sedimentary filling processes， as well as hydrocarbon accumulation and later adjustment and modification. Both the ProtoTethys and Paleo-Asian oceans experienced phases of expansion， subduction， closure， and collisional orogenesis. Specifically， the Tethyan tectonic domain progressed through the Proto-， Paleo-， and Neo-Tethys stages in a row. Meanwhile， the Paleo-Asian Ocean underwent a complex extension-convergence process within a Neoproterozoic-Paleozoic framework involving multiple continents， islands， and oceans. Due to the coevolution of the Tethys Ocean （the Kunlun - Altyn Tagh branch） and the Paleo-Asian Ocean （the South Tianshan Ocean as a branch）， the Tarim Basin experienced two extension-convergence megabasin cycles from the Neoproterozoic to the Eopaleozoic and from the Neopaleozoic to the Cenozoic. These cycles， along with eustatic sea-level changes and climatic cycles， facilitated the formation of high-quality source rocks and various large-scale reservoirs and cap rocks， which jointly created a superior material foundation for hydrocarbon generation and accumulation. The hydrocarbon accumulation effects ncontrolled by the coevolution of the Tethys and Paleo-Asian oceans are manifested in the following aspects： differential hydrocarbon accumulation and enrichment across different parts of the non-foreland area （i.e.area covered by Paleozoic marine sediments） in the Tarim Basin under a variety of basin prototypes and later tectonic modifications； high-quality source rocks widely seen in the northern depression serving as the foundation for large-scale hydrocarbon enrichment in the northern Tarim， Shuntuoguole low uplift and Tazhong area； two types of large-scale reservoirs with distinct characteristics： fault-controlled fractured-vuggy and fractured-vuggy karst types formed under tectonic fracturing and paleokarstification associated with multi-phase tectonic movements； and the differential evolution of structures and geothermal fields in the accumulation zone dictating the regular changes in hydrocarbon phase state and secondary alterations. Favorable hydrocarbon exploration targets in the non-foreland area include large paleo-uplifts， unconformities， strike-slip fault zones， high-energy facies tracts， and areas where these three factors overlapping.

Investigating the Cretaceous paleotectonic framework， prototype basins， and lithofacies paleogeographic characteristics of the Tethyan domain is essential for gaining a deeper understanding of the hydrocarbon accumulation patterns therein. Focusing on prototype basins and lithofacies paleogeographic characteristics during the Early Cretaceous （125 Ma±） and Late Cretaceous （90 Ma±） in the Tethyan domain， this study highlights the role of the Cretaceous structural and sedimentary evolution in governing hydrocarbon accumulation and enrichment in the domain. The results indicate the rapid spreading of the Neo-Tethys Ocean during the Early Cretaceous （125 Ma±）. Accordingly， the Tethyan domain near Laurasia witnessed the formation of passive margin， rift， and back-arc basins in the Europe-North Africa and Middle East-Central Asia sections； the development of passive margin and back-arc basins in its western China-India section， and the occurrence of intracratonic basins in its eastern China-Southeast Asia section. In contrast， the Tethyan domain near Gondwanaland featured extensive passive margin basins during this period. As the Neo-Tethys Ocean began to contract during the Late Cretaceous （90 Ma±）， the passive margin basins in the Tethyan domain near Gondwana and the rift basins and back-arc basins in the realm near Laurasia were maintained and further developed. Throughout the Early and Late Cretaceous， lithofacies assemblages dominated by thickly laminated sandstones， mudstones， and carbonate rocks were widely seen along both the northern and southern margins of the Tethyan domain， with multiple source rock-reservoir-caprock assemblages favorable for hydrocarbon accumulation formed vertically. Notably， regions along the northern margin of Gondwana， including North Africa， the Middle East， and the northern Australian Plate， exhibit superior geological conditions for hydrocarbon accumulation. During the Cretaceous， the Persian Gulf region of the Middle East exhibited passive margin prototype basins with littoral-neritic to bathyal sediments against a relatively stable plate. In comparison， the Arabian Plate’s low-latitude environment facilitated the formation and preservation of large quantities of organic-rich source rocks， as well as the multiple reservoir-caprock assemblages of high quality.

The Central Canyon gas field， with reserves exceeding 100 billion cubic meters， has been discovered on the southern slope of the Lingshui Sag in the Qiongdongnan Basin， confirming the hydrocarbon-rich nature of this sag. Despite local breakthroughs， lithological reservoir exploration in block LS13-2 on the northern slope of the Lingshui Sag has yielded merely gas shows rather than substantial reserves， indicating unsatisfactory exploration outcomes. This study aims to determine the hydrocarbon accumulation patterns and play fairways in the block. By analyzing petroliferous basins and critical factors controlling hydrocarbon accumulation， we propose a novel philosophy of hydrocarbon exploration and identify paly fairways for hydrocarbon accumulation. The results indicate that block LS13-2 exhibits generally favorable conditions for hydrocarbon accumulation， which lay the foundations for the formation of large- to medium-sized oil and gas fields characterized by sufficient hydrocarbon sources， large-scale reservoirs， efficient carrier systems， and generally excellent preservation conditions. Nevertheless， the exploration of the Miocene lithologic traps faces challenges due to unfavorable factors such as the main hydrocarbon expulsion stage of source rocks occurring earlier than trap formation and the low vertical hydrocarbon transport capability of faults. Accordingly， we develop a three-dimension exploration assessment methodology consisting of early hydrocarbon accumulation， lithologic traps， and fault-sand body conduit system. The assessment results indicate that the submarine fan zone of the western ramp features favorable hydrocarbon accumulation conditions encompassing primary hydrocarbon reservoirs， large-scale lithologic traps， and efficient fault-sand body carrier systems， establishing this zone as an optimal play fairway.

Since hydrocarbon accumulation is closely associated with structures， examining structures and hydrocarbon preservation conditions is significant for hydrocarbon exploration. In this study， we explore the fault characteristics and the differential distribution of structural styles in the western Hubei - eastern Chongqing area and classify the structural units in this area. Furthermore， we describe the types and evolution of faults and other geological structures in this area and analyze their impacts on hydrocarbon preservation. The results reveal that the western portion of the southern structural zone of the middle Yangtze Block in this area has undergone multi-stage basin-orogen couplings since the Mesozoic. This has led to a high intensity of structural deformations and the formation of basement-involved faults and cap rock-detachment faults. A method to assess the hydrocarbon preservation conditions in this structurally complex area is proposed in this study. The assessment results suggest that areas west of the Qiyueshan fault are more favorable compared with those east of it in hydrocarbon preservation. Among others， the Wanxian synclinorium displays the optimal preservation conditions， followed by the Shizhu synclinorium. In the western Hunan-Hubei fold belt， the Lichuan structural belt demonstrates the most favorable conditions for hydrocarbon preservation， succeeded by the Enshi structural belt， with the Nanbei Town-Sangzhi Shimen structural belt exhibiting the least favorable conditions. The findings of this study have proven effective in exploring shale gas， tight gas， and karst reservoirs in the Hongxing and Yi’en areas.

Shales in the 2^nd member of the Paleogene Kongdian Formation （also referred to as the Kong 2 Member） in the Cangdong Sag contain high-abundance organic matter， showing great potential for shale oil exploration. However， the mechanisms underlying the organic matter enrichment are yet to be clarified due to the lack of fine geochemical research. Given this， we investigate the factors influencing of organic matter enrichment and the enrichment model in the Kong 2 Member shale using whole-rock X-ray diffraction， maceral identification on polished surfaces of whole-rock shale samples， rock pyrolysis， measurement of the total organic carbon （TOC） content， chromatography-mass spectrometry of saturated hydrocarbons， carbon isotopic analysis of monomer hydrocarbons， and the analyses and tests of major and trace elements. The results indicate that the organic matter enrichment inthe Kong 2 Member shale is influenced by multiple factors including terrigenous clastic input， paleoproductivity， paleoclimate， paleo-water depth， and paleosalinity. These factors govern the growth and development of algae and bacteria in the lacustrine basin of the Cangdong Sag， contributing to the formation of organic matter enrichment horizons with high TOC content during the T-R cycle transition period of the fifth-order sequence. Specifically， the terrigenous clastic input introducing abundant nutrients enhanced the biological productivity of the lacustrine basin. The paleoclimate， paleo-water depth， and paleosalinity largely determined the terrigenous/aquatic ratio （TAR） of the lacustrine basin. Furthermore， bacterial activity transformed organic matter， increasing the H/C atomic ratio and the saprofication degree of the shale. Shales in sublayer ⑧， primarily taking shape during the T-R cycle transition， of the C₃ layer under development are formed under paleoenvironmental conditions of a warm and humid climate， low salinity， and deep water. This sublayer， with an average TOC content of 2.7 %， S₁ of 3.7 mg/g， and producible oil index （POI） of 215 mg/g， boasts high abundance and favorable organic matter types， proving to be favorable landing zone for horizontal wells.

A fine characterization of the segmented growth process and differential evolution characteristics of these faults is conducted using the latest 3D seismic data to investigate the segmented growth-induced spatiotemporally differential evolution and mechanisms governing hydrocarbon accumulation of the low-angle normal faults in the Bonan swell within the Bohai Bay Basin. Furthermore， we explore the genetic mechanisms of these faults and their controlling effects on hydrocarbon accumulation while considering the regional tectonic setting. The findings indicate that faults F₁ and F₂ at the southern boundary of the Bonan swell are low-angle normal faults. Both originated from the Mesozoic NWW- to nearly-EW-trending pre-existing thrust faults， which underwent negative inversion and subsequent reactivation during the Cenozoic. Fault F₁ exhibits segmented connections laterally and multiple episodes of activity vertically； its central segment inherits continuous activity from the original fault plane， while its western and eastern segments vertically overlap with the NEE-trending fault newly formed during the rifting episode Ⅱ and the nearly-EW-trending fault during the rifting episode Ⅲ， respectively. These collectively create the present morphology of fault F₁. The controlling effects of the low-angle normal faults on hydrocarbon accumulation are as follows： （1） The fault-controlled sides exhibit a large sedimentary scale， thus providing sufficient spaces for deposition. Consequently， large-scale sand bodies on steep slopes are developed. （2） The low-angle normal faults， which have remained active for a prolonged time， provide channels for vertical hydrocarbon migration and determine the horizons of vertical hydrocarbon enrichment. The multiphase activity of these faults has transformed the physical properties of deep reservoirs， with the activity intensity being closely related to the formation of high-quality reservoirs.

This study aims to reveal the differential oil enrichment mechanisms of tight （low-permeability） sandstone reservoirs in the Paleogene Shahejie Formation in the Linnan Sub-sag， Bohai Bay Basin. Initially， we categorize the source rock-reservoir assemblages in the Linnan Sub-sag based on their spatial distribution and lithologic combination. The analysis on oil-bearing properties， hydrocarbon supply， reservoir storage spaces， conduit system， and migration and accumulation dynamics of various source rock-reservoir assemblages is carried out using an integration of data of logging， well tests， production tests and core analysis and tests. Accordingly， the differential oil enrichment model is established for tight （low-permeability） sandstone reservoirs. The results indicate that the source rock-reservoir assemblages in the study area can be categorized into three types， which can be further divided into six subtypes： the source-reservoir coexistence type， including interbedded and intercalated sub-types； the source-reservoir adjoining type， comprising three distinct subtypes with reservoirs located above， between， or below source rocks； and the source-reservoir separation type， including a subtype with reservoirs located below source rocks. These types correspond to three oil enrichment model of the tight （low-permeability） sandstone reservoirs. The source-reservoir coexistence type exhibits an oil enrichment model featuring “a strong hydrocarbon supply， strong migration and accumulation dynamics， efficient charging， and reservoir-controlled oil enrichment.” Specifically， this type boasts the optimal hydrocarbon supply conditions， the strongest migration and accumulation dynamics， and efficient hydrocarbon charging via pores and fractures， all of which contribute to the most favorable oil-bearing properties. Compared to that of the intercalated subtype， the hydrocarbon enrichment scale of the interbedded subtype is restricted by sand-body thicknesses. The source-reservoir adjoining type manifests an oil enrichment model characterized by a comparatively strong hydrocarbon supply， differential migration and accumulation dynamics， combined conduit systems， and multiple factor-controlled oil enrichment. In detail， this type features a comparatively favorable hydrocarbon supply， significant changes in the migration and accumulation dynamics， and combined conduit systems consisting of pores， fractures， faults， and sand bodies， with hydrocarbon preferentially charging reservoirs with favorable physical properties and pore structures. This type of source rock-reservoir assemblage exhibits comparatively favorable oil-bearing properties. Among others， its subtype with reservoirs located between source rocks outperforms the other two subtypes in terms of both hydrocarbon supply and migration and accumulation dynamics， thus demonstrating the optimum oil-bearing properties. The source-reservoir separation type displays a pattern characterized by a weak hydrocarbon supply， weak migration and accumulation dynamics， conduit systems including faults and sand bodies， and oil enrichment under the control of conduits and reservoirs. Due to the weak hydrocarbon supply and migration and accumulation dynamics， effective transport pathways composed of faults and sand bodies， along with the presence of high-quality reservoirs， are crucial to hydrocarbon enrichment. This type of source rock-reservoir assemblage generally exhibits inferior oil-bearing properties.

The study intends to clarify the undefined dominant factors controlling the tight sandstone gas enrichment and challenges associated with play fairway mapping through the exploration of the 5^th member of the Permian Shiqianfeng Formation （hereafter referred to as the Qian 5 Member） in the Shenmu gas field， Ordos Basin. A combination of seismic， drilling， log， and laboratory data is applied to examine the characteristics of tight-gas reservoirs， analyze the impacts of various factors including faults， reservoirs， cap rocks， barriers， source rocks， and the elevation on tight gas enrichment， and map play fairways for tight gas exploration. The results indicate that the sand bodies of the Qian 5 Member originate from the distributary channels of the braided river delta plain subfacies and that inherited strike-slip faults play a role in improving the reservoir properties and transporting natural gas. The gas reservoir in the member exhibits a porosity mainly ranging from 6.0 % to 12.0 % （average： 9.1 %） and permeability from 0.20×10^-3 to 0.80×10^-3 μm² （median： 0.49×10.0^-3 μm²）. The reservoir is of a lenticular tight gas reservoir， exhibiting a quasi-continuous distribution characterized by lateral contiguity and vertical superimposition. Primary factors controlling tight gas enrichment include faults and reservoir physical properties. In contrast， the thicknesses of cap rocks， barriers， and coal seams in source rocks produce relatively weak controlling effects on tight gas enrichment， and the elevation delivers no impact in this regard. In the case where the distance between a gas well and faults exceeds 9 km， the reservoir shale content is greater than 12 %， and the thickness of mudstone barriers exceeds 210 m， the degree of natural gas enrichment increases as the values of these parameters decrease. Conversely， under conditions where the porosity is below 9 %， the permeability falls below 0.5×10^-3 μm²， the thickness of mudstone cap rocks is less than 120 m， and the coal seam thickness within source rocks is less than 15 m， the degree of natural gas enrichment improves with increasing values of these parameters. It is proposed to employ the gas enrichment indices to map the play fairways of tight-gas reservoirs. Using this method， a total of 14 Class Ⅰ and 22 Class Ⅱ play fairways primarily distributed in the eastern Shenmu gas field are identified.

Based on a systematic analysis of the data from well cores， we divide the lithologic assemblages of shales in the Jurassic Lianggaoshan Formation in the Sichuan Basin into pure， shelly， and silty categories， which are further categorized into five types. A summary of differences in the macroscopic and microscopic characteristics of shale reservoirs of different lithologic assemblages is then deduced to identify and evaluate the occurrence states and mobility of fluids in these reservoirs， and determine the optimal lithologic assemblage types. The results indicate that the shale oil in the Lianggaoshan Formation is of free and adsorbed types， with the former occurring as movable and/or irreducible oil. Among shale pores， small pores primarily contain adsorbed and irreducible oil， mesopores largely hold irreducible and movable oil， and macropores mainly contain movable oil. The 2D nuclear magnetic resonance （NMR） analysis reveals that zones with T₂ ≥ 0.2 ms and 1 ≤ T₁/T₂ < 10 represent the signals of movable and irreducible oil and those with T₂ < 0.2 ms and 10 ≤ T₁/T₂ < 100 denote the signals of adsorbed oil. This enables the establishment of an identification chart of 2D NMR T₁-T₂ spectra for fluids of different occurrence states in the Lianggaoshan Formation. The pore size conversion based on the NMR analysis reveals that pores containing free oil in shales of the formation have a minimum pore size of 60 nm. Accordingly， a classification scheme for pores in the shale oil reservoirs is developed based on pore size and the occurrence state of fluids. Factors directly affecting the occurrence and mobility of shale oil in the Lianggaoshan Formation are identified as organic matter content， fluid flowability， mineral composition， and pore structure. The silty shale assemblage， characterized by well-developed macropores and microfractures and a high proportion of pores containing movable oil， is favorable for the enrichment of movable oil. Besides， its silty laminae provide both substantial reservoir spaces and enhance pore connectivity， which create favorable conditions for the accumulation， occurrence， and flow of shale oil. Therefore， the silty shale assemblage stands as a favorable lithologic assemblage category in the Lianggaoshan Formation， with intervals where this assemblage occurs serving as play fairways for shale oil exploration and exploitation in the Lianggaoshan Formation， Sichuan Basin. Therefore， determining the pore-fracture configuration in the silty shale assemblage is of primary significance in research to achieving breakthroughs in shale oil exploration and exploitation of the Lianggaoshan Formation.

A fine interpretation of the S80 strike-slip fault zone in the Tahe area of Tarim Basin is carried out by comprehensively utilizing core data， logs， the widths and total volume of the lost intervals in individual wells， high-precision 3D seismic data， and multilayer coherence attributes. Its spatial distribution， and activity intensity and stages are determined thereby， and its controlling effects on the Ordovician reservoirs are explored. The findings indicate that the S80 strike-slip fault zone can be divided into the western， central， and eastern subzones along its strike. These three subzones generally show a noticeable increase in the number， length， and width of overlapping segments from the Cambrian to the Ordovician strata vertically. Laterally， the S80 strike-slip fault zone， from SW to NE， exhibits the contraction of its transtensional segments， the expansion of its transpressional segments， and the gradual disappearance of its pure strike-slip segment. Furthermore， the activity of this fault zone proves strong in its central subzone but weak in its western and eastern subzones. The S80 strike-slip fault zone experienced four activity stages， namely the Middle Caledonian， the Late Caledonian-Early Hercynian， the Late Hercynian， and the Indosinian-Early Himalayan， with the former two stages predominating. This fault zone experienced sinistral strike-slip in the former two stages but dextral in the latter two stages. Three types of reservoirs are developed along the S80 strike-slip fault zone： cavernous， compound （fractured-vuggy and vuggy-fractured types）， and fractured types. The development of dissolution vugs is closely related to the segmented activity of strike-slip faults， with the transpressional and translational segments featuring strong activity， as well as the periphery of the major faults of the transtensional segment characterized by weak activity， serving as favorable parts for the development of dissolution vugs. The transpressional segment of the Middle Ordovician Yijianfang Formation exhibits a high linear density of fractures， while those of the Middle Ordovician Yijianfang Formation to the Middle-Lower Ordovician Yingshan Formation show a significantly decreased linear density of fractures vertically， leading to a limited dissolution capacity. The transtensional segment in the Middle Ordovician Yijianfang Formation has a moderate linear density of fractures， and those of the Middle Ordovician Yijianfang Formation to the Middle-Lower Ordovician Yingshan Formation exhibit well-developed fractures and dissolution vugs with an elevated number and scale， establishing this interval as a favorable area for reservoir development.

The formation of hydrocarbon reservoirs in the Tarim Basin is significantly influenced by strike-slip fault zones， whose connectivity with source rocks is vital for hydrocarbon migration and accumulation. The 3D seismic data helps us to assess the connectivity of source rocks with the F_Ⅰ17 strike-slip fault zone in block Ⅱ of the Fuman oilfield using both a discrete element model （DEM） for Riedel shear structures and a perfectly plastic medium- stress ascending function model. The findings reveal that the drag-point depth （h） of the en echelon faults of F_I17 during the Late Hercynian obtained by theoretical calculation is far less than that measured by the Riedel shear DEM. This discrepancy suggests that the strike-slip faults of F_Ⅰ17 originated from T-tensional rupturing rather than R-shear rupturing. The average depths of source rocks connected to the F_I17 reach up to 9-18 km， suggesting that this fault zone acts as an immediate channel for the migration of hydrocarbons generated by the underlying source rocks of the Yurtus Formation at a burial depth of over 10 km to the overlying fault-karst （or fractured karst） traps of the Ordovician to form reservoirs. The depth （H） of source rocks connected to the F_I17 zone increase from north to south. Parameters of the fault-controlled hydrocarbon reservoirs of F_I17 zone， such as crude oil density， natural gas dryness coefficient， and hydrocarbon charging stages and their respective contributive degrees， are closely associated with the connectivity of F_I17 zone with source rocks. Thereby， such connectivity plays a role in controlling hydrocarbon accumulation， with the controlling effects varying with the order， along-strike segmentation， activity intensity， and strike-slip fault-cut strata. The connectivity of the F_I17 with source rocks changes significantly along the fault strikes， which affects the efficiency of vertical hydrocarbon transport.

Intermediate-basic volcanic rocks are extensively distributed in the deep Lower Cretaceous Huoshiling Formation of the Songliao Basin. However， their intricate lithologies and lithofacies， as well as the strong lateral heterogeneity of their reservoirs， complicate the prediction of reservoir sweet spots， restricting the exploration and exploitation of hydrocarbon resources. Focusing on the Chaganhua area， we investigate the lithofacies and reservoir characteristics of deep intermediate-basic volcanic rocks in the Songliao Basin and develop a methodology for identifying volcanic conduits， favorable lithofacies and lithologies， and reservoir sweet spots within the volcanic rocks. The key findings are as follows. （1） Three facies with six subfacies are primarily identified in the volcanic rocks. High-quality reservoirs predominantly comprise coarse- and fine-grained tuffs and tuffaceous sandstones. Reservoirs of the volcanic explosive facies are the most extensive in the proximal-middle facies belts. The distribution of tuffs with favorable lithologies is governed by the facies belts. Furthermore， the reservoir sweet spots of the volcanic rocks are primarily governed by their physical and gas-bearing properties. （2） For various volcanic eruptive phases， volcanic conduits are identified based on fracture density， along with the superimposed profiles of ant tracking and seismic data. This helps determine the proximal volcanic facies belts. Then， in combination with the thickness of volcanic edifices and the energy half-time attribute， the boundaries between middle-distance and distal volcanic facies belts are identified， facilitating the qualitative characterization of areas containing reservoir sweet spots. （3） To minimize the multiplicity of solutions in the quantitative prediction of intermediate-basic volcanic reservoirs using seismic data inversion， we preferentially employ low wave impedance， low density， and low Lame constant to characterize tuffs， reservoirs with high porosity as indicated by nuclear magnetic resonance （NMR）， and gas layers， respectively. Accordingly， based on the porosity data volumes derived from pre-stack density inversion， we eliminate the interference from the sedimentary tuffs， low-porosity layers， and non-gas layers sequentially， obtaining reliable predictions of the spatial distribution of reservoir sweet spots. It is verified that the predicted results align with the distribution pattern of favorable facies belts and agree with interpretations of drilled gas layers. The qualitative identification and stepwise quantitative characterization of the spatial distribution of reservoir sweet spots based on favorable facies belts， have been successfully applied to well emplacement， yielding encouraging outcomes. Therefore， this methodology is highly applicable in the seismic prediction of sweet spot distribution in deep volcanic rocks.

Recent years have witnessed significant progress in the exploration and exploitation of shale oil in continental basins in East China. However， the assessment of shale oil productivity is largely hindered by the evaluation of oil mobility. By investigating the shale oil in the Subei Basin， we propose two well-log-based methods for assessing the movable oil content in shales： the two-dimensional nuclear magnetic resonance （2D NMR） method and the conventional logging. An identification plot for movable oil is thereby established using the 2D NMR-derived longitudinal and transverse relaxation time （T₁ and T₂， respectively）， acting to assess fluid types like adsorbed oil and irreducible water. By exploring the relationships of free hydrocarbon content （S₁） with sedimentary environments and structures， along with the correlation between S₁ and logging responses， we analyze the response sensitivities of conventional well-log-derived resistivity and sonic interval transit time to S₁ and organic matter content， and establish a well-log-based quantitative assessment model for S₁. Furthermore， a method for assessing S₁ using log data is developed to calculate both movable oil saturation and oil content. The results reveal that saline environments and lamellar structures promote hydrocarbon generation and migration from organic matter， resulting in high S₁.

Tectonic fractures serve as primary reservoir spaces of carbonate rocks， and local stress-induced tectonic fracturing acts as a prominent factor influencing their development. Simulating tectonic stress fields using the finite element method has become an important method for tectonic fracture prediction. However， this method faces challenges such as large discrepancies between model setting and actual geologic condition， low efficiency in obtaining optimal boundary conditions， and undefined factors governing the development of tectonic fractures. To address these issues， a method for constructing a heterogeneous rock mechanics model and a self-adaptive boundary constraint algorithm are introduced to enhance the precision of stress field simulations， and quantitatively characterize fracture development in reservoirs using parameters such as reservoir rupture rate and fault activity. Then， by quantitatively exploring the impacts of differences in strike-slip fault deformations and stress perturbations on tectonic fractures， the most significant factors controlling fracture development are selected to construct a development index for fractured carbonate reservoirs， and quantitatively investigate its dominant controlling factors. Lastly， based on reservoir scale prediction， as well as single-well fracture logs and core interpretations， we build a geologic model of fractured carbonate reservoirs at different levels. This method has been applied to the Ordovician carbonate reservoirs in the No. 18 fault zone and adjacent regions in Shunbei area， Tarim Basin. The application results indicate that the degree of fracture development decreases in the order of transtensional， translational， and transpressional fault segments of the fault zone and that higher deformation amplitude of strata is associated with a higher developmental degree of fractures. In addition， the development index of fractured reservoirs is constructed using the rock mechanical parameters， distances from faults， horizontal bidirectional stress differences， stress heterogeneity coefficient， and comprehensive rupture rate of reservoirs. The reservoir classification results based on this index align closely with actual geologic conditions.

The lacustrine shale oil reservoirs of the Fengcheng Formation in the Mahu Sag， Junggar Basin have burial depths exceeding 4 500 m. Natural fractures in these reservoirs， serving as important storage spaces and seepage channels， are critical to the enrichment and high yield of shale oil. There is a lack of systematic study on their effectiveness evaluation despite existing characterization of these fractures in previous works， severely restricting the further exploration and exploitation of shale oil in the Mahu Sag. Given this， we conduct a systematic study on the distribution patterns and effectiveness evaluation of natural fractures in the study area using formation microresistivity imaging （FMI） logs. The results indicate that there exist two types of natural fractures in the lacustrine shale oil reservoirs in the study area： cross-layer fractures and intralayer fractures. The cross-layer fractures are characterized by a large scale， with heights generally reaching up to several meters or above， and their distribution is governed by faulting. The intralayer fractures are found within brittle beds， and their heights are limited by the thickness of rock layers， largely less than 50 cm. Vertically， the fracture density in a single well is positively correlated with the brittle mineral content. Laterally， the fracture density gradually decreases with increasing distance from faults. Fractures with different orientations exhibit greatly varying degrees of filling. The NW-SE-trending fractures， among others， are mostly not filled with minerals， thus boasting high effectiveness. As the burial depth increases， fracture apertures generally trend downward. The evaluation results reveal that the NEE-SWW-trending fractures exhibit the largest aperture and， accordingly， the highest effectiveness.

This study aims to improve currently used method for predicting the displacement pressure of fractured rocks in order to more accurately and scientifically reflect actual subsurface conditions. Given that fractured and surrounding rocks exhibit a positive correlation between their displacement pressures and their degrees of compaction and diagenesis， the displacement pressure ratio between fractured rocks and surrounding rocks at the same burial depth should equal their ratio of the degree of compaction and diagenesis. Based on this equivalence， we can derive the relationship between the displacement pressures of fractured rocks and surrounding rocks at the same burial depth， thus improving the existing predictive method. The improved method is applied to predict the displacement pressure of fault F₁-induced fractured rocks in regional mudstone cap rocks in the lower section of the 1^st member of the Damoguaihe Formation （also referred to as the Da 1 Member） in the Huhenuoren anticlinal zone of the Beier Sag， Hailaer Basin. The results indicate that the displacement pressure predicted using the improved method is significantly lower than that derived from the original method， aligning more accurately with the actual observation that the oil and gas in the 2^nd member of the Nantun Formation （also referred to as the Nan 2 Member） along fault F₁ are merely detected in the structurally higher parts. Therefore， the improved method for predicting the displacement pressure of fractured rocks can be employed effectively to estimate the displacement pressure of extensional fault-induced fractured rocks in brittle strata of sandstone-mudstone petroliferous basins.