By investigating a large number of domestic and foreign literatures on casing deformation in shale gas wells，the types of casing deformation in shale gas wells were summarized，the differences and problems of influencing factors of casing deformation in deep and shallow shale gas wells were discussed，and the corresponding prevention measures and the main research directions in the next step were put forward. The results show that：（1）The types of casing deformation in shale gas wells mainly include squeezing diameter deformation and shear deformation. The probability of casing deformation in deep shale gas wells is greater than that in middle and shallow layers，and is mainly shear deformation.（2）The engineering factors that cause casing deformation include wellbore cooling，cementing quality，casing fatigue，casing quality and wellbore dogleg degree. The geological factors include rock mechanical properties，non-uniform in-situ stress stress and natural fracture/fault slip. The casing deformation of deep shale gas wells is mainly affected by natural fracture/fault slip.（3）Measures can be taken to reduce the risk of casing deformation，such as controlling wellbore temperature and injection strength，using cement with lower mechanical properties of cement sheath for cementing operation，appropriately reducing the outer diameter of casing，increasing wall thickness，improving steel grade，to improve casing quality，and smoothing well trajectory as far as possible. For deep shale gas wells，the risk of casing shear deformation can also be reduced by designing the extension direction of the horizontal section of the wellbore to be consistent with the bedding direction of the rock formation，mastering the fracture distribution，avoiding the high-risk shear slip section as much as possible，reasonably reducing the fracturing scale for different levels of slip risk sections，and adjusting the wellbore orientation.（4）The research directions of casing deformation prevention and control of shale gas wells mainly include four aspects：optimizing fracturing layers with good rock mechanical properties，analyzing the relationship between optimal well trajectory and in-situ stress，identifying and evaluating fractures，calculating fault slip and casing variables.

At present，the estimation of global natural hydrogen resources is enormous，and the understanding of its formation mechanism and enrichment rules is helpful for searching for large-scale accumulation areas of natural hydrogen. Through the statistical analysis of typical natural hydrogen displays both domestically and internation ally，the origin types of large-scale accumulation of global natural hydrogen gas were summarized，and the distri bution and accumulation characteristics of natural hydrogen gas reservoirs were analyzed. The results show that： （1）The origin of natural hydrogen is complex，mainly including water-rock reactions，degassing of deep-seated hydrogen from the mantle，water radiolysis，rock fragmentation，decomposition of organic matter，and biological activity. Among them，hydrogen generation through water-rock reactions and degassing of deep-seated hydrogen from the mantle are commonly occurring in nature，and widely present in various geological environments，with high hydrogen generation rates and large amounts. Therefore，they are the two most important origin types for the large-scale generation of natural hydrogen.（2）The natural hydrogen gas reservoirs are mainly developed in three geological backgrounds：plate subduction zones，pre-Cambrian iron-rich strata development areas，and rift tectonic systems.（3）The sealing conditions of natural hydrogen reservoirs are affacted by multiple factors，including not only the sealing ability of the cap rocks，but also the changes in the mechanical properties of the cap rocks caused by the active physical and chemical properties of hydrogen，which affect its brittleness-toughness and form fractures，resulting in the escape of hydrogen.（4）Metabolic activities of underground microorganisms by hydrogen，and hydrocarbon generation in the middle and deep layers are not conducive to the large-scale accumu lation of hydrogen. Therefore，when searching for favorable areas for natural hydrogen generation，areas where hydrogen is consumed in large quantities should be avoided.（5）Due to factors such as the short time of natural hydrogen generation and its diffusion，the accumulation of natural hydrogen shows dynamic characteristics. When hydrogen generation and escape are in a dynamic equilibrium，it can be enriched to accumulate. Groundwater is a necessary condition for hydrogen generation through water-rock reactions，and many natural hydrogen reservoirs discovered abroad are distributed in areas with good groundwater circulation.

Based on outcrops，drilling cores，logging and seismic data，the sedimentary filling process of Cambrian Canglangpu Formation in Sichuan Basin and adjacent areas were studied. The results show that：（1）The overall sedimentary structural pattern of the first member of Cambrian Canglangpu Formation（Cang-1 member） in Sichuan Basin presents “one uplift，four depressions，and two high zones” characteristics，with carbonate rocks as the main lithology. The second member of Canglangpu Formation（Cang-2 member）is gradually filled in，and the regional paleogeomorphology tend to be uniform，with clastic rocks being the main lithology. （2）During the sedimentary period of Cang-1 member in the study area，the barrier effects of Deyang-Anyue ancient rift trough led to an east-west differentiation sedimentary pattern in the plane. The western trough which is near the provenance，mainly developed mixed tidal flat deposits，while the eastern trough mainly developed carbonate deposits. During the sedimentary period of Cang-2 member，the barrier effects of trough was weakened，and the terrigenous debris significantly increased in the whole basin that were characterized by clastic rock shallow shelf deposits.（3）The high-quality dolomite reservoirs of Cang-1 member in the study area are mainly composed of residual oolitic dolomite，sandstone dolomite，and powder crystal dolomite. Macroscopically，the distribution of shoals is mainly controlled by underwater low uplift and relatively high parts of the platform depression edge. Microscopically，the reservoir space is mainly controlled by dolomitization and dissolution transformation，with intragranular dissolved pores，intergranular dissolved pores，and intercrystalline dissolved pores developed. It is adjacent to the high-quality source rocks of the underlying Qiongzhusi Formation and has an advantage of near-source filling and accumulation.

The marine shale of the Upper Permian Wujiaping Formation in Sichuan Basin is a hotspot for shale gas exploration and development. Based on X-ray diffraction，thin section identification，scanning electron microscopy，organic geochemistry，and low-temperature nitrogen adsorption，the distribution of sedimentary facies，characteristics of source rocks and reservoirs of the second member of Permian Wujiaping Formation （P₂w²）shale in the northeastern Sichuan Basin were conducted. The main controlling factors of reservoir development were clarified，and distribution of favorable reservoir zones was also analysed. The results show that： （1）The deposition of the P₂w² in the northeastern Sichuan Basin is influenced by the rise of sea level and the development of rifts，and is dominated by deep-water shelf facies，displaying a banded distribution in the areas of Dazhou-Kaijing-Wanzhou-Zhongxian.（2）The mineral composition of the P₂w² shale in the study area is complex with a high content of brittle minerals（67.9%）. They are similar to the Silurian Longmaxi Formation shale in Sichuan Basin，displaying biogenically influenced quartz with flocculated and framboids pyrite with small grains（< 6 μm），reflecting a reducing sedimentary water body conducive to the enrichment of organic matters. The average porosity of the P₂w² shale is 4.11%，with pore types including organic matter pores，intragranular pores，intergranular pores，and micro-fractures. The shale pore structure is dominated by mesopores，with a minor presence of micropores and macropores，where contribution rate of mesopore to pore volume is the largest. （3）The source rocks of P₂w² exhibit high TOC content and high maturity，with an average TOC content of 4.8% and an average R_o of 2.53%，reaching an over-mature stage，predominant type Ⅱ kerogen，indicating high hydrocarbon generation potential. It generally meets the criteria for a Class Ⅰ shale gas reservoirs.（4）P₂w² shale reservoir is mainly controlled by sedimentary environment and diagenetic transformation. The sedimentary environment of deep-water shelf is conducive to the formation of shale reservoirs. Quartz on resisting pressure and retaining pores，hydrocarbon generation from organic matterrs play a critical role in the formation of shale reservoirs. There is a positively correlated relationship between the quartz content，TOC content to porosity. It is considered that the Kaijiang-Liangping and Wanzhou areas should be favorable distribution areas for the P₂w² shale reservoirs.

The fault-controlled fracture-cavity condensate gas reservoirs in Shunbei Oilfield have special geological conditions and are difficult to develop. Based on the actual parameters of the gas reservoirs in Shunbei Oilfield，a quantitative analysis method integrated modeling and simulation was used to characterize the natural depletion of fault-controlled fracture-cavity condensate gas reservoirs，and corresponding pressure maintenance strategies were formulated. The results show that：（1）A hierarchical modeling method based on geophysical attribute depiction was adopted for different types of facies to obtain a fused three-dimensional reservoir facies model. Based on the data of wave impedance，logging data，and well testing interpretation，a three-dimensional porosity model and permeability model was obtained by using human-computer interaction and gradual nesting method. On this basis of two models，combined the fluid model obtained from PVT experiments，a multi-component numerical simulation model representing the characteristics of the fault-controlled fracture-cavity condensate gas reservoirs in the region can be obtained.（2）Retrograde condensation and stress sensitivity are two major factors that constrain the natural depletion development effect of such condensate gas reservoirs. The retrograde condensation shortens the stable production time of oil，increases the gas oil ratio，and reduces cumulative oil production. Fractures in reservoirs with stress sensitivity may close under certain stress conditions，resulting in the difficulty to produce some reserves connected to the fractures.（3）CH₄ is the optimal injection medium for pressure maintenance development，and the best injection effect occurs when it is injected slightly above the dew point pressure. Injection-production rate and injection time are positively correlated with the oil production increment，but the oil replacement rate decreases as the injection volume increases. For the injection-production well group，the scheme which adopts continuous injection and production mode first and then switch to pulse injection and continuous production mode is the best strategy for increasing oil production while preventing gas channeling. For the isolated well，the huff and puff injection and production method can be used to improve the condensate oil recovery. Further，both the injection and production wells are deployed in a cave，which is easier to make the injected gas act on the main reserves in the cave and drive out the main reserves in a directional way. Meanwhile，ensuring sufficient distance between injection and production wells is beneficial for preventing gas channeling and increasing the swept volume.

In seismic exploration，high-velocity or low-velocity tight sandstone reservoirs are often characterized by complex seismic response and strong heterogeneity，and it is difficult to establish a low-frequency model in inversion. With the constraints of AVO intercept and gradient attribute based on Bayesian classification and porosity， the lithofacies of the tight sandstone of Jurassic Shaximiao Formation in central Sichuan Basin was classified. The results show that：（1）Based on elastic wave theory，AVO analysis reflects the underground lithologies and pore fluid properties according to the variation of amplitude with offset. In the application process，AVO forward modeling was carried out based on the relevant parameter combination of different lithologies and fluids，AVO characteristics of known lithologies and fluid properties were obtained and compared with actual seismic records，and then a seismic response model for lithologies and oil and gas identification was established.（2）The crossplot analysis of porosity，intercept and gradient attributes established by model and actual data was used to clarify the internal relationship between the three，determine the classification criteria of lithofacies，fit the probability density function of different lithofacies，and divide the lithofacies of different porosity intervals，to realize the semi-quantitative prediction of porosity.（3）In the application of tight sandstone of the first member of Jurassic Shaximiao Formation in central Sichuan Basin，the lithofacies predicted by probability distribution based on Bayesian classification is up to 93.75% consistent with the actual drilling results，which verifies the feasibility and effectiveness of the method.

The source rock characteristics of the Permian Fengcheng Formation in Mahu Sag were defined based on a variety of petrographic and organic geochemical data，such as rock slices，total organic carbon（TOC）， rock-eval pyrolysis，chloroform bitumen“A”and vitrinite reflectance（R_o）. The evaluation standard of shale oil “sweet spot”was established，and the distribution characteristics of“sweet spot”in the study area were systematically described by taking typical wells as examples. The results show that：（1）The source rocks of Permian Fengcheng Formation in Mahu Sag are mainly composed of quartz，feldspar and dolomite，followed by calcite and clay minerals. The rock types include calcareous mudstone，sandy mudstone，dolomitic mudstone and mud stone.（2）The abundance of organic matter in source rocks with different lithologies is different，and TOC is 0.75% on average. The organic matter type is mainly type Ⅱ，which is the main source of oil generation，fol lowed by type Ⅰ and a small amount of type Ⅲ. It is in the low maturity to mature evolution stage，and dominated by medium to very high-quality source rocks.（3）TOC，chloroform bitumen“A”，free hydrocarbon S₁ and R_o were selected as evluation parameters for shale oil“sweet spot”and divided into four resource types：enriched， medium enriched，low efficiency and ineffective.（4）The evaluation results of shale oil“sweet spot”in typical well Maye 1 show that the shale oil exploration potential is the best in the layers with high TOC，chloroform bitu men“A”，S₁，and oil saturation index（OSI）. In addition，shale oil also has exploration potential in the relatively organic-poor interval with high S₁.

The sediment supply and infilling evolution of the Mesozoic in Halahatang-Hade area of Tarim Basin were studied by analyzing the changes in paleogeomorphic morphology，distribution of sedimentary systems， stratigraphic structure and sand-bodies development characteristics，based on the main measuring method of mineral composition analysis，calculation of sand to land ratio，seismic attribute analysis and logging response feature recognition. The results show that：（1）The provenance of the Triassic mainly came from the Tianshan orogenic belt in the northeast，with ZTR coefficient gradually increasing from the northern area to the central sag. During the Jurassic and Cretaceous，the provenance mainly came from the orogenic belt of Kunlun Mountains in the southeast and south. The ZTR coefficient of this period is gradually increasing from the northern and southern areas to the central sag.（2）In the late Triassic，with the proliferation of the Paleo-Tethys Ocean，the weakening of the uplift of the Tianshan Mountains in the north of the study area and the intensification of the uplift of the Kunlun Mountains in the south are the main reasons for this provenance transformation.（3）During the Triassic，the depression and deposition centers were located in the south of the study area，and a set of braided river delta and deep-water lake deposits in the NE-SW direction were mainly developed. During the Jurassic and Cretaceous，the depression and deposition centers migrated to the north of the study area，and a set of braided river delta and shallow lake deposits were developed in the direction of SE-NW and S-N respectively.（4）During the Triassic，the progradation direction of sand-bodies was mainly in the NE-SW direction. During the Jurassic and Cretaceous，the progradation direction of sand-bodies was mainly in the SE-NW and S-N direction respectively.（5）The exploration areas for Triassic lithologic reservoirs are located in the southwest of the study area，while the exploration areas for Jurassic and Cretaceous lithologic reservoirs are located in the northwest and north of the study area.

The Xixiangchi Formation of the Upper Cambrian is one of the selected field for oil and gas exploration in the eastern Sichuan Basin. Based on the stratigraphic and sedimentary evolution characteristics，the structural patterns and formation mechanism of the Upper Cambrian Xixiangchi Formation in eastern Sichuan Basin were analyzed by using the data of seismic profiles，boreholes，cores and geochemistry. The hydrocarbon accumulation conditions were analyzed from the aspects of source，reservoirs，caprock and migration，and the accumulation model was summarized. The results show that：（1）The deformation of the Cambrian Xixiangchi Formation is constrained by northwestward propagated lower detachment and upper detachment in the Middle Cambrian Gaotai gypsums and Silurian mudstones，and developed four types of structural traps of back-thrust structure， double imbricated structure，fault bend fold structure and salt diapiric-related fault bend fold structure. Two caprocks attribution to both detachment layers further separate the source rocks of the Lower Cambrian Qiongzhusi Formation and Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation from the Xixiangchi Formation that raised harsh accumulation conditions.（2）The Xixiangchi Formation in the study area has the conditions for oil and gas accumulation. The shales of Wufeng Formation to Longmaxi Formation are the main hydrocarbon source rocks，with a thickness of 300-700 m，TOC values of 2%-7% and Ro values of 2.4%-4.0%. The source rocks have strong hydrocarbon generation capacity and are at an over-mature stage. The shoal dolomites transformed by karst and fractures in the later sedimentary stage of Xixiangchi Formation are relatively high-quality and large-scale reservoirs，with a porosity greater than 2.1%. The Yanshanian tectonic uplift and deformation not only formed effective structural traps in Xixiangchi Formation，but also make it break through the Middle-Lower Ordovician cap rock and connect with Wufeng Formation to Longmaxi Formation，achieving lateral migration of oil and gas.（3）A late-stage natural gas accumulation model of the Xixiangchi Formation in the study area is summarized as “younger source rocks juxtaposition with older reservoir rocks are favor to gas migrate laterally into structural traps” . The thrust faults cause the Xixiangchi Formation and the Wufeng Formationto Longmaxi Formation in the hanging wall to be horizontally juxtaposed，forming a structural trap with a lateral connection between source and reservoir，improving the efficiency of hydrocarbon supply and accumulation.

In order to solve the problems of small coal thickness，small vertical fault distance of gas source fault，low signal-to-noise ratio of seismic data and difficult to predict the sweet spot reservoir of coal，rock and gas in Baijiahai uplift，Junggar basin. A“five-step method”is proposed，which is controlled stepwise. The re sults show that：（1）“Five-step”comprehensive technology provides a powerful technical means for coalbed methane“sweet spot”reservoir prediction，The specific method is to improve the signal-to-noise ratio and resolu tion of CRP gathers using construction edge preserving denoising and harmonic high-frequency recovery processing techniques；The combination of tuning thickness method and frequency division intelligent inversion method， the thickness distribution range of coalbed section and plane is quantitatively predicted；The deep learning intel ligent fracture detection technology was used to predict the fracture profile and plane distribution characteristics of gas source；Analysis of AVO characteristics with different gas saturation based on fluid replacement of coal and rock，the gas saturation is used to predict the gas distribution range in the study area；The“sweet spot”reser voir is located in the superposition of broken nose（or fault block），large coal rock thickness，gas source fracture and high gas saturation.（2）The“sweet spot”is mainly distributed in the fault nose or block trap on the north and south sides of the strike-slip fault in the northern part of the work area，A total of 31 coalbed methane“sweet spot”regions have developed，with a cumulative area of 231.9 km²，The exploration potential of the five“sweet spot”reservoirs on the north side of the strike-slip fault is greater.（3）The coincidence rate between the test index of the vertical well deployed by the research results and the real drilling results is 92%. At the same time， the trajectory of the horizontal well can be optimized and dynamically monitored to improve the productivity of a single well.

The exploration and development prospects of the Paleozoic area in the southern Ordos Basin are promising，but the exploration results have been unsatisfactory. Based on the latest core analysis，data of logging and 2D/3D seismic，a comprehensive evaluation was conducted for the Palaeozoic of Xunyi area. This evaluation focused on four aspects：gas source conditions，reservoir quality，source-reservoir configuration，and fracture conductivity. The results show that：（1）In the Xunyi area，potential hydrocarbon source rock types have been identified in the Taiyuan-Shanxi formations：black coal rock，black carbonaceous mudstone，dark gray，and gray mudstone. The organic matter types are all Type Ⅲ，with a vitrinite reflectance（R_o）ranging from 1.8% to 2.5%，indicating a high level of thermal maturity. The black coal rock and carbonaceous mudstone exhibit better hydrocarbon generation potential compared to the dark gray and gray mudstones.（2）The reservoirs are charac terized by ultra-low porosity and ultra-low permeability. The upper Paleozoic Shanxi Formation and He 1 mem ber consist of clastic rock reservoirs，with lithic sandstones accounting for 79%，and matrix content averaging 29%. The pore types are mainly intergranular and secondary dissolution pores，with plane porosity lower than 3%. The He 1 member is characterized by strong cementation and weak dissolution facies，while the Shanxi For mation exhibits strong compaction and matrix-rich infill facies. The high-quality carbonate reservoirs of the lower Paleozoic Majiagou Formation are dominated by sandy dolomite，with storage space mainly comprising dissolu tion pores，intercrystalline pores，and fractures. （3）The Paleozoic source-reservoir configurations include “lower-generation upper-storage”，“upper-generation lower-storage”，and“adjacent lateral-storage”configura tions. Among these，the adjacent lateral-storage configuration is the favorable source-reservoir combination for the lower Paleozoic Majiagou Formation. The Xunyi area experienced three phases of fault development：Paleo zoic，Triassic，and late Jurassic，with the late Jurassic faults providing good vertical fluid migration pathways. （4）The lower Paleozoic gas reservoirs are controlled by the pre-Carboniferous paleogeomorphology. The area adjacent to the eastern side of the deeply eroded paleotroughs is a favorable zone for Lower Paleozoic hydrocar bon accumulation. The upper Paleozoic gas reservoirs are controlled by effective drainage systems. Poor reservoir properties and the lack of open source-conducting faults in the northern part of the study area are the main rea sons for the unfavorable results in the upper Paleozoic.

In recent years, large oil and gas fields with reserves of billions of tons have been discovered of Neogene in Bohai Bay Basin. A comprehensive study was conducted on the sedimentary characteristics and paleoen-vironment of the shallow water delta in the lower section of the Minghuazhen Formation of the Neogene in the Kenli 6-1 oilfield in the Bohai Bay Basin，utilizing geological，logging，and seismic data. The results show that： （1）The sedimentary period of Minghuazhen Formation in Kenli 6-1 Oilfield in Bohai Bay Basin was characterized by a temperate humid climate，gentle terrain，ancient terrain slope less than 1°，average water depth less than 6.5 m， and abundant supply of sediment from the northeast direction.（2）The reservoir lithology is mainly composed of lithic feldspar sandstone，followed by feldspar sandstone and feldspar lithic sandstone；the probability curve of grain size is mainly in a two-stage form，and various sedimentary structures reflecting strong hydrodynamics are developed；the logging curves are mainly bell shaped and box shaped, and low amplitude tile shaped progradation features can be seen on the seismic profile.（3）The V1 layer underwater distributary channel has a long extension distance and narrow width, and is distributed in northeast-southwest direction as a whole；the farthest extension distance can reach 20.10 km，and the average length is 10.06 km；the width of the underwater distributary channel sand body is between 64 m and 420 m，with an average width of 219.65 m；the average thickness of the underwater distributary channel sand body is about 9.42 m. Based on the comprehensive distribution of sedimentary microfacies，the shallow water sedimentary style of Minghuazhen Formation in Kenli 6-1 Oilfield in Bohai Bay Basin was summarized. The research results provide strong geological basis for new drilling in the later stage of the oilfield，and also provide comparative materials for the exploration and development of other shallow water delta sediments in the Bohai Bay Basin.

Using seismic，logging，oil test，core，casting thin，physical property analysis and physical simulation experiments，the configuration relationship of hydrocarbon accumulation elements，enrichment law research and main controlling factors of hydrocarbon accumulation of Carboniferous reservoir in Chepaizi Uplift of Junggar Basin were discussed. The results show that：（1）The reservoir lithology in the study area is mainly tuff，andesite and breccia，and the reservoir space is mainly secondary pores and fractures. The porosity mostly less than 8%， and the permeability is concentrated in 0.1-10.0 mD，which belongs to ultra-low porosity and ultra-low permeability reservoir.（2）The enrichment，migration and accumulation elements of the reservoir are controlled by the union of three elements of“fault-reservoir-shell”：Deep and large faults are the channel of vertical migration of oil and gas；Weathering and leaching can improve reservoir physical properties and provide effective storage space for oil and gas enrichment；The Carboniferous itself and its overlying mudstone are generally relatively tight，form a good reservoir-cap combination with the fracture volcanic reservoirs；The configuration relationship between strike-slip faults and cap rocks plays an important role in controlling the vertical and lateral migration of oil and gas.（3）It is concluded that the reservoirs in the study area as a whole have the characteristics of “dual source hydrocarbon supply，multi-system transport，multi-type caprock，multi-layer oil-bearing，multireservoir type，and compound oil-bearing area”. There are significant differences in reservoir accumulation models in different regions and different depths. Horizontally，the near source is“fault blanket transport，lateral filling， near source weathering crust accumulation model”，and the far source is“dual source hydrocarbon supply， multiple transport types，hard shell sealing，far source fault shell accumulation model”. Vertically，the shallow part is“dual-source hydrocarbon supply，multiple transport types，hard shell sealing，shallow weathering crust accumulation mode”，and the deep part is“dual-source hydrocarbon supply，fault transport，tight rock sealing， deep fault body accumulation mode”.

Based on a two-dimensional model，a numerical simulation method was used to establish a numerical model of CO₂ immiscible flooding，and the level set method is used to simulate the microscopic seepage laws of CO₂ immiscible flooding and near miscible flooding under diffusion and adsorption. The microscopic seepage characteristics and diffusion adsorption characteristics of CO₂ in pores were studied，and the influences of the injection velocity，diffusion coefficient，and adsorption reaction rate constant on the microscopic seepage charac teristics of near miscible flooding were analyzed. The results show that：（1）The degree of reserve recovery of the CO₂ flooding numerical simulation using the phase field method is 51.29%，and the degree of reserve recov ery of theCO₂ flooding numerical simulation using the level set method is 53.60%. The level set method is more suitable for simulating the seepage process of CO₂ immiscible flooding.（2）Under immiscible flooding condi tions，CO₂ preferentially diffuses into large pores，with a recovery efficiency of 87.7%，an outlet gas content rate of 71.60%，and a maximumCO₂ surface adsorption concentration of 3.16×10^-4 mol/m². Under the conditions of near miscible flooding，CO₂ is more likely to diffuse into small pores，with a recovery efficiency of 91.1%，an outlet gas content rate of 97.01%，and a maximum CO₂ surface adsorption concentration of 5.81×10^-4 mol/m². （3）The microscopic seepage of miscible flooding is influenced by factors such as the injection velocity，diffu sion coefficient，and adsorption reaction rate constant. The injection rate increases，resulting in an increase in both the gas content and recovery rate at the outlet. An increase in diffusion coefficient and adsorption reaction rate constant will lead to an increase in recovery efficiency and a decrease in outlet gas content.

On the basis of rock physics analysis，a method combining waveform facies-controlled inversion and simulation，combined with pseudo acoustic impedance reconstruction technology and reservoir parameter indication construction technology based on coordinate rotation，was used to predict the dense sandstone reservoirs of the second member of Paleogene Kongdian Formation in the middle and high slope area of southern Cangdong sag in Huanghua Depression. The results show that：（1）The impedance curve has a poor recognition effect on sandstone and mudstone，while natural gamma ray can be used to effectively distinguish sandstone from mudstone with a limit value of 83 API. The preferred natural potential curve can be used to effectively distinguish sandstone from mudstone with a limit value of -13 mV，and it has a certain ability to distinguish reservoirs from non reservoirs.（2）The reconstructed pseudo acoustic impedance curve improves the recognition ability of sandstone and mudstone. The reservoir indicator curve based on coordinate rotation divides reservoirs and non reservoirs with a threshold value of -10，and the reservoir indicator curve can predict tight sandstone reservoirs. （3） The reservoir prediction method combining waveform facies-controlled inversion and simulation can improve the accuracy of tight sandstone reservoir prediction and reduce the multiplicity of reservoir predictions， with a reservoir prediction accuracy rate of 83.3%.

The tight sandstone of Jurassic Shaximiao Formation in northeastern Sichuan Basin has great exploration potential. The reservoir characteristics of Jurassic Shaximiao Formation in Wubaochang area of northeastern Sichuan Basin were studied by using analysis and testing data such as cast thin sections，scanning electron microscopy，cathodoluminescence，X-ray diffraction，properties，mercury injection and homogenization temperature of inclusions. Combined with seismic interpretation results，the reasons for reservoir densification and the distribution characteristics of high-quality reservoirs were analyzed. The results show that：（1）The sandstone reservoirs of Jurassic Shaximiao Formation in Wubaochang area of northeastern Sichuan Basin are characterized by high contents of feldspar and rock debris，general sorting and roundness，low structural maturity and compositional maturity，poor porosity and permeability correlation and poor pore structure，with reservoir porosity mostly less than 6%，permeability mostly less than 1 mD，and mainly developed fractured-porous reservoir.（2）The reservoirs of Jurassic Shaximiao Formation in the study area are in the middle diagenetic stage A. Calcareous cementation leads to local densification of the reservoirs，while burial compaction and laumontite cementation are the main causes for sandstone densification in Shaximiao Formation. Oil and gas continued to charge before and after reservoir densification.（3）Early chlorite rim cementation，atmospheric water leaching and tectonic rupture are the main constructive diagenesis，which are of great significance for the preservation of primary intergranular pores，the formation of secondary dissolved pores and the improvement of reservoir permeability.（4）Sedimentary microfacies，diagenesis and tectonic rupture control the distribution of high-quality reservoirs. The underwater distributary channel with early chlorite rim cementation，weak laumontite cementation，feldspar dissolution and fractures developed is the main development area of high-quality sandstone reservoirs.

The genetic types and its source of condensate oil and natural gas in Permian Formation，in southwest of Mahu Sag，is under controversy，the type of fluid phases is complex，which restricts the further expansion of deep oil and gas exploration in Mahu Sag. In this study，PVT phase simulation software was used to recover original reservoir fluid components oil and natural gas in Permian Formation，in southwest of Mahu Sag，com bined empirical statistical methods with P-T phase diagram to determine the phase types of discovered oil-gas reservoirs. The source and genetic types of different phase types of oil and gas is clarified by multiple means of geochemical analyses. The results show that：（1）The Permian oil and gas reservoirs in southwest of Mahu Sag are mainly distributed in Fengcheng and upper Urho Formation. The phase types of oil-gas reservoirs are multiple， black oil reservoir comes first，near critical high volatile reservoir and condensate gas reservoir（condensate gas reservoirs with oil rings and near-critical condensate gas reservoirs）comes second. Condensate gas reservoirs are mainly developed in Fengcheng Formation. The reservoir fluid components are mainly methane，and the content of C₇⁺ hydrocarbons is relatively small.（2）The parent organic matter type of the different phases oil in the Permian are slightly sapropelic，all of which are the products of the mature stage source rocks in the Fengcheng Formation. The condensate oil maturity is slightly higher than the other phase oil，and its physical properties are better than others，with the characteristics of low viscosity，low freezing point and low wax content.（3）The natural gas components in the Permian are mainly hydrocarbon gas，of which the average methane mole fraction is 86.21%， the non-hydrocarbon gas content is low，the maturity varies greatly，the value of R_o is 0.52%-2.39%. It is mainly the product of sapropelic source rocks in the Fengcheng Formation. The maturity of natural gas of the upper Urho Formation is higher，with an average R_o value of 1.99%，while the natural gas maturity of Fengcheng Formation is lower，with an average R_o value of 0.71%. The natural gas average R_o of the condensate gas reservoirs of the Fengcheng Formation is 0.85%.（4）Due to the influence of the Fengcheng Formation source rocks thermal evo lution difference and the difference reservoir physical properties，The Permian developed two sets of oil and gas accumulation systems，the oil and gas reservoirs of Fengcheng Formation are self-generation and self-reservation within the source rock，and the upper Urho Formation is lower-generation and upper-reservation outside the source rock.

Through core observation，experimental testing，geophysical interpretation and production dynamic data evaluation，the characteristics of source rocks and reservoirs of Ordovician Wufeng Formation-Silurian Longmaxi Formation in Ningxi area of Sichuan Basin were analyzed. Combined with the history of tectonicthermal evolution-pressure evolution and fault development，the main controlling factors of shale gas enrichment were discussed. The results show that：（1）Organic-rich shale in deep-water shelf facies is developed in Wufeng Formation to the submember of the first member of Longmaxi Formation（Long 11），The kerogen is mainly typeⅠ，with a high organic matter abundance，an average TOC value greater than 3.8%，and an average Ro value greater than 3.0%，indicating that it is in the over mature stage. High-quality source rocks are distributed in Wufeng Formation to the third sublayer of Long₁¹，whilethe fourth sublayer ofLong₁¹ has poor hydrocarbon generation potential.（2）The reservoir conditions of Wufeng Formation toLong₁¹ in the study area are superior， with a high brittleness index and an average value greater than 55%，showing a downward trend from bottom to top. The reservoir spaces include nanoscale inorganic and organic pores，as well as high angle shear fractures and vertical fractures caused by structural factors. The porosity ranges from 2.20% to 5.30%，with an average of 3.84%. The porosity of the first to third sublayers of Long₁¹ is relatively high.（3）The accumulation model of shale gas in the study area is “self generation and self reservoir” within the layer，controlled by source-reservoir configuration，tectonic-thermal evolution，fault level，and fracture development degree. The source-reservoir configuration controls the foundation，and the higher the brittle mineral content and porosity value，the higher the TOC value. Continuous burial of strata before Late Permian（250 Ma）and Emeishan Large Igneous Province promoted the pyrolysis and hydrocarbon generation of shale gas of Wufeng-Longmaxi Formation. From the Late Cretaceous（66 Ma）to the present，tectonic uplift has caused adjustment and loss of gas reservoirs. Faults developed within the layer are beneficial for the preservation of shale gas. The larger the scale of fault development， the less favorable it is for shale gas enrichment. The fracture system controls production capacity，with weak deformation and low fault density in the central part of the syncline，and moderate development of fractures， which is conducive to the enrichment of shale gas. However，the deformation of the structures around the syncline is strong，the fault density is high，and the fracture system is extremely developed，which is destructive to the enrichment of shale gas.

Based on the core analysis，data of well logs and seismic，the distribution characteristics and oil-gas enrichment conditions of tuff reservoirs of Cretaceous Huoshiling Formation in Dehui fault depression of Songliao Basin were analyzed by using forward modelling and multi-parameter inversion body fusion technology， and the distribution of high-quality reservoirs was predicted. The results show that：（1）The tuff of Cretaceous Huoshiling Formation in Dehui fault depression，Songliao Basin，is a pyroclastic rock formed by fissure eruption，which mainly consists of breccia-bearing welded tuff，breccia-bearing crystal tuff and sedimentary tuff. The seismic reflection shows low frequency，poor continuity，medium strong amplitude or weak amplitude. The sweet spot distribution of tuff reservoirs predicted by multi-parameter inversion body fusion technology has a high coincidence rate with drilling data. The average value of tuff reservoir drilling catching rate is 92.8%，and the average gas reservoir drilling catching rate is 81.0%，among which 12 wells has obtained industrial gasflow. The reservoirs of Huajia structural belt and Guojia fault step belt are mainly composed of breccie-bearing welded tuff and breccie-bearing crystal tuff，with developed faults，making these two areas as the high-quality reservoir zones.（2）The lithology and lithofacies template formed by matching the well log and seismic facies characteristics of the tuff in the study area were useful to identify seismic facie of the tuff. It was confirmed that the crater and proximal crater facie characterized by amplitude attributes are favorable lithology distribution areas. （3）High-quality source rocks developed in Huoshiling Formation，Shahezi Formation and Yingcheng Formation have a thickness of more than 300 meters，with TOC of 0.26%-5.08%，0.10%-5.55%，0.10%-9.74%，S₁+S₂ of 0.24-8.23 mg/g，0.12-18.15 mg/g，0.25-2.86 mg/g，and R_o of 0.6%-1.3%，1.1%-1.6%，1.0%-2.2%，respectively. With the characteristic of high abundance and moderate maturity，they lay a good material foundation for a large-scale reservoir formation.（4）The tuff gas reservoir in the study area is a set of tight gas reservoirs with source and reservoir lateral connection and high enrichment. The accumulation is mainly controlled by structural styles，faults development and hydrocarbon supply windows. The imbricated fault-bending folds formed by tension and extension，is the major factor to control the degree of hydrocarbon enrichment，and the size of faults and hydrocarbon supply windows determine the gas reservoir scale.

On the basis of the understanding of the characteristics of tight limestone reservoirs in the Da’anzhai Formation in the western area of Gongshanmiao of Sichuan Basin，the development scale of the fracture system was identified and graded by using the methods of thin section identification，logging response，and SMI And the main controlling factors of tight oil and high yield in the Da’anzhai Member were studied. The results show that：（1）The limestone of the Da’anzhai section is divided into two types of reservoirs：thick-bedded limestone and thin-bedded limestone. The limestone reservoir has an average porosity of 1.2% and an average permeability of 0.05×10^-3 μm²，which is a very low porosity and low permeability reservoir，and dissolution is an important factor in the formation of reservoir properties，and the reservoir space is mainly secondary dissolved pores and micro-fractures.（2）According to the size of the fault，the fault layer and the fault distance on the plane，the fault is divided into primary，secondary and tertiary. Among them，the Da’anzhai section is mainly affected by the primary and secondary faults，the fractures associated with faults can effectively improve the physical proper ties of the reservoir.（3）It is concluded that favorable facis development and t relationship of fault-reservoir con figuration are the control factor to determine the high yield of the reservoir. There are two high-yield models： “thin limestone first-level fracture”and“thick limestone first-level/second-level fracture”.

Based on the data of drilling，mud-logging，wire-logging，and measured formation pressure，the basin simulation technology considering multiple overpressure mechanisms was applied to identify the overpressure origins of Permian in the eastern Fukang Sag of Junggar Basin，and the evolution characteristics of overpressure of various origins were quantitatively restored. The results show that：（1）The Permian in the eastern Fukang Sag develops weak to strong overpressure，the formation pressure coefficient ranges from 1.36 to 1.88，and the excess pressure ranges from 12 to 49 MPa. The overpressure developed in different structural parts is obviously different. The overpressure in the sag is the highest，with formation pressure coefficient of 1.50-1.88 and excess pressure of 23-49 MPa，followed by slope zone，with a formation pressure coefficient of 1.52-1.79 and excess pressure of 24-37 MPa. It is relatively weakest in the uplift，with formation pressure coefficient ranging from 1.36 to 1.59 and excess pressure ranging from 12 to 23 MPa.（2）The origins of overpressure in the strata with different lithologies in the study area are different. The overpressure in the source rocks of Lucaogou Formation is caused by hydrocarbon generation and undercompaction，it is caused by overpressure transference and undercompaction in the reservoirs of the Upper Urho Formation，while it is caused by undercompaction in the mudstone cap rocks of the Upper Urho Formation.（3）The overpressure in the source rocks of the Lucaogou Formation and the mudstone cap rocks of the Upper Urho Formation in the study area has a continuous increasing characteristic. The contribution rate of hydrocarbon generation and pressure increase of the source rocks of the Lucaogou Formation gradually increases along the uplift，slope zone to the sag. The undercompacted pressure increase of the mudstone cap rocks of the Upper Urho Formation also shows the same changing trend. The overpressure in the reservoirs of Upper Urho Formation slowly increased from the Late Triassic to the Late Jurassic， then rapidly increased from the Late Jurassic to the Early Cretaceous，and slowly increased from the Late Cretaceous to present. The contribution rate of the pressurization of overpressure transference to the current reservoir overpressure ranges from 58.46% to 78.86%.

The Chang 7 member of Triassic in Ordos Basin is a key research area for shale oil. Through the determination of total organic carbon，chloroform extraction，rock pyrolysis，XRD whole rock mineral analysis，and scanning electron microscopy observation，the characteristics of source rocks of Triassic Chang 7 member in Qingcheng area of Ordos Basin were analyzed. A three-dimensional electrical logging model of organic carbon and logging curves was established by using multiple regression linear method，clarifying the spatial distribution characteristics of the source rocks and their reservoir control effects. The results show that：（1）The average TOC values of shale samples from Chang 7₁，Chang 7₂ and Chang 7₃ submembers in Qingcheng area of Ordos Basin are 5.01%， 6.04% and 6.76%，respectively，and the average values of chloroform bitumen “A” are 0.63%，0.67% and 0.73%，respectively. The overall organic matter types are mainly type Ⅱ₁ and type Ⅱ₂，which are in mature to high-mature stage. The oil content and mobility are good，reaching a good to excellent source rock level.（2）The shale samples are mainly composed of quartz feldspar and clay minerals. The pore types are mainly primary intergranular pores，intercrystalline pores and constricted fissures in organic matters，but the pore size distribution of each sample is different.（3）The lower limit of TOC in source rocks in the study area is 1.50%. The 7₂ submember near Qingcheng area and the 7₃ submember near Qingcheng and Huanxian areas are the main effective source rock development areas.（4）The TOC content and spatial distribution characteristics of effective source rocks affect the oil content of shale reservoirs，and the TOC content directly determines the level of oil production.

It is helpful to accurately predict the operation effect of underground coal gasifier to find out the difference and evolution law of pore structure of coal before and after drying. By selecting water and kerosene as saturated fluids to carry out low-field NMR experiment，the pore structure of the same sample under saturated and dry conditions was tested and compared. The dehydration evolution process of pore structure of coal samples was observed through X-CT technology and an evolution model was established，and pulse attenuation permeability test and low-temperature liquid nitrogen adsorption experiments were conducted to evaluate the mass transfer ability of coal samples. The results show that：（1）During the drying of lignite，pore shrinkage occurs while cracks are produced，and the total pore volume decreases from 0.630 cm³/g to 0.481 cm³/g，while the large pore volume significantly increases from 0.070 cm³/g to 0.420 cm³/g. Dehydration leads to pore concentration，with the large pore volume accounting for 88%.（2）The pore shrinkage during the drying of lignite is controlled by the degree of matrix shrinkage. The dehydration of different coal rock components can be summarized into two types of pore structure evolution models：the dehydration of matrix coal that is prone to shrink develops a large number of cracks at the edges or inside of the components，while the dehydration shrinkage of xylite-rich and charcoal-rich coal is weak，retaining a large number of primary pores and developing fewer cracks.（3）After the drying of the lignite，water is removed and the number of empty pores increases. The seepage state changes from single-phase water to gas-water two-phase and single-phase airflow，forming a good interconnected pore network. The seepage ability of the coal is significantly improved，and the permeability increases from 0.248 to 48.080 mD. The contribution of diffusive mass transfer is increased，with diffusion coefficient of medium and large pores in dry lignite being about 0.09 cm²/s at a temperature of 200 ℃ and a pressure of 0.5 MPa.

By analyzing the characteristics of source rocks and comparing the biomarker parameters of crude oil samples from typical wells，the crude oil sources and its migration and accumulation patterns of lithologic reservoirs of the lower Minghuazhen Formation of Neogene in Bozhong A-2 area in the southwest belt of Bozhong Sag were studied. The results show that：（1）The source rocks of the third member of Dongying Formation （E₃d₃）and the first and third members of Shahejie Formation（E₂s₁，E₂s₃）are developed longitudinally in the southwest belt of Bozhong Sag. The source rocks of E₃d₃ have C₁₉TT predominance，a high Ts abundance value and a “V”-shaped distribution of C₂₇-C₂₈-C₂₉ regular sterane. The source rocks of E₂s₁ have C₂₃TT predominance， similar Ts and Tm abundance values，a high abundance value of gammacerane and a “L”-shped distribution of C₂₇-C₂₈-C₂₉ regular sterane. The source rocks of E₂s₃ have C₂₁TT or C₂₃TT predominance，high Ts abundance value，and a “V”-shaped distribution of C₂₇-C₂₈-C₂₉ regular sterane，with C₂₇ predominance.（2）The difference distribution of physical parameters and gas chromatogram of crude oil shows that the filling capacity of crude oil in the southeast well area of Bozhong A-2 reservoir is stronger than that in the middle well area. The C₂₇-C₂₈-C₂₉ regular sterane distributed in a “L” shape and the peak value of 4-methylsteranes is large. In the upper part of the lower Minghuazhen Formation，the C₁₉TT/C₂₃TT is smaller，the MPI1 and MPI2 parameters are larger，total oil has a slightly heavy carbon isotope，indicating that the oil source is mainly supplied by E₂s₁ and supplemented by E₂s₃.（3）1-methylphenanthrene，9-methylphenanthrene，C₂₉ααS/（S+R），C₂₉ββ/ αα+ββ），dibenzothiophene series and QGF index parameters change regularly in each well of Bozhong A-2 reservoir，indicating that the crude oil is mainly charged from east to south to northwest. The comparison results of crude oil biomarker show that the deep crude oil in the southwest belt of Bozhong Sag firstly accumulated in Guantao Formation in Bozhong A-4 reservoir，transported vertically to the shallow lower Minghuazhen Formation，and then migrated horizontally along the wide sand bodies to lower Minghuazhen Formation of Bozhong A-2 reservoir，thus forming the current lithologic reservoirs.

The right bank of the Amu Darya River in Turkmenistan is characterized by the development of a sig nificant gypsums and salts of the upper Jurassic Kimmeridgian stage. It has important influence on the hydrocarbon enrichment and accumulation. By comprehensively utilizing data of drilling，core analysis and seismic，typi cal tectonic styles of different strata of the Jurassic gypsum salt layers in the Agayry region，eastern right bank of the Amu Darya River were identified by analyzing the geomorphology of the profile and portraying the seismic crossover frequency attributes. At the same time，the deformation mechanism of the gypsum salt rock and adja cent strata in the context of the regional tectonic movement was explored，and then the ancient structures of the key reservoir formation period were restored，further investigating the role of tectonics in controlling oil and gas transportation and reservoir formation in different periods. The results show that：（1）The upper and overlying strata of the upper salt layer of Jurassic gypsum salt layers in the Agayry region develop detachment folds，while the lower part develops a small amount of large salt pillow structures. The overall deformation degree of the middle gypsum lower salt layer lower gypsum layer is relatively low. Three types of small salt pillow structures and salt necking are developed within the lower salt layer，and typical reef/hill beach bodies can be identified be tween the salt pillow structures.（2）The function of tectonic compression stress and gravity decollement is the main driving forces for the formation of salt layer deformation. Based on the four key factors of "two major tec tonic movements，pre-existing landforms/structures，multi-layer differentiated deformation plastic strata，and longitudinal and transverse composite superimposed deformation”，a multi-layer superimposed complex struc tural deformation model was established.（3）The flow thickening of salt layers and backfilling method was used to restore the ancient structures of before the deposition of salt layers and during the peak period of hydrocarbon generation at the end of the Early Cretaceous in the study area. By integrating the history of hydrocarbon generation and expulsion，structural development，and gas well production，it was clarified that the ancient structures restored based on gypsum salt rock deformation are important factors for high natural gas accumulation and production， with characteristics of“continuous natural gas injection and multi-stage dynamic reservoir formation”. The inherited development areas of ancient and modern structures are the most favorable areas for natural gas enrichment.

Based on the analysis and test data of petroleum geochemistry，oil test and phase behavior analysis of condensate gas，basin modeling techniques were used to determine the characteristics，accumulation process and genetic mechanism of condensate gas reservoirs of Jurassic Sangonghe Formation in Qianshao well area of western well Pen-1 sag，Junggar Basin. The results show that：（1）The condensate reservoirs of Jurassic Sangonghe Formation are structural-lithologic reservoirs in western well Pen-1 sag. The high-quality reservoirs are mainly composed of gray fine-medium feldspathic detritus sandstone，with porosity ranging from 2.70% to 16.1%，an average value of 12.10%，permeability ranging from 0.016 mD to 109.000 mD，an average value of 14.17 mD. The reservoirs belong to middle porosity and low permeability reservoirs，and form reservoir-cap assemblage with two sets of source rocks from the underlying Permian Fengcheng Formation and lower Urho Formation.（2）The condensate oil in the study area is the product of the source rocks of lower Urho Formation within mature to high-mature stage，it has physical properties of low density，low viscosity，low freezing point and low wax content，and its n-alkanes are composed of low and medium carbon components.（3）The natural gas of condensate gas reservoirs in the study area is mainly composed of hydrocarbon gas，with concentrated distribution of methane and ethane carbon isotope values ranging from -37.40‰ to -36.84‰ and -27.55‰ to -26.54‰，respectively. It was derived from the cracking of humic-type source rocks of lower Urho Formation. （4）The condensate oil and gas generated by the source rocks of lower Urho Formation in the early Paleogene were continuously adjusted and finally charged in the early Neogene to form the present condensate gas reservoirs. The fluid composition has not changed since the reservoir formation，and the fluid phase type is also unchanged，so it is a primary condensate gas reservoir.

The natural gamma-ray（GR）logging data of the early-middle Jurassic Shuixigou Group from QinTan 1 borehole in Shengbei subsag，Tuha basin，was selected to analyze cyclostratigraphy and simulate sedimentary noise for the identification of stratigraphic Milankovitch signals and determination of the Earth’s orbital cycle’s forcing the lake level variations within the Tuha Basin. The stratigraphic division of Shuixigou Group was ana lyzed. The results show that：（1）The sedimentary cycles of 12.8～51.1 m，3～11.9 m，1.1～3.6 m，and 1.3～ 2.4 m were identified in the GR curves of the Early-Middle Jurassic Shuixigou Group in the Shengbei subsag of Tuha Basin，with a ratio of 21∶5∶1.5∶1，and the sedimentary rates of the Shuixigou Group are estimated as 3.6～ 11.7 cm·ka^-1 through astronomical calibration and correlation coefficient.（2）The sedimentary records of the Shuixigou Group were forced by the Milankovitch cycles，as evidenced by the presence of 405 ka long eccentricity， 99～131 ka short eccentricity，32.6～35.0 ka obliquity，and 20.0～24.8 ka precession cycles during the Middle and Early Jurassic in Tuha basin. The durations of Badaowan Formation（not drilled through），Sangonghe Formation and Xishanyao Formation in Qintan 1 borehole are 3.0 ±0.1 Ma，4.1 ±0.1 Ma and 9.0 ±0.1 Ma， respectively.（3）The fluctuation of lake level forced by the Earth’s orbital cycles of terrestrial lake basins，the simulation of lake level change by sedimentary noise confirms that the ultra-long period of ～1.5 Ma forced the lake level change of the Shuixigou Group in Taibei sag.

To address the complexity and heterogeneity of the pore structure of seventh member of Triassic Yanchang Formation（Chang 7 member）in Longdong area，a method based on the Zebra Optimization Algorithm-optimized Support Vector Regression（ZOA-SVR）model was proposed. This method utilizes formation pressure test data and conventional well logging curves. It was applied in actual wells，and compared with other machine learning models，as well as conventional methods for predicting formation pressure. The results show that：（1）The ZOA-SVR model uses actual formation pressure data as target variables，selecting seven input feature parameter，such as depth， sonic transit time，density，compensated neutron，natural gamma，deep resistivity，and clay content，associated with shale formation pressure data correlation above 0.7 in the study area. The model was trained with 40 samples， validated with 5-fold cross-validation，and optimized with 10 initial Zebra populations and a maximum of 70 iterations. After optimizing penalty factors and kernel parameters，the model achieved a fit indicator R² of 0.942. Predicted formation pressure data had absolute errors below 1 MPa on both training and test sets，with an aver age relative error of 2.42% compared to measured data.（2）The ZOA-SVR model demonstrated significant advantages in predicting of Chang 7 Member formation pressure in the study area compared to models based on Particle Swarm Optimization，Grey Wolf Algorithm，and Ant Colony Algorithm. It shows a better parameter adjustment and optimization capabilities，with coefficient of determination increases of 0.209，0.327，and 0.142 respectively. It also exhibited higher accuracy in pressure prediction compared to Equivalent Depth Method，Eaton Method，and Effective Stress Method，reducing relative errors by 32.53%，15.31%，and 5.91% respectively. （3）Application of the ZOA-SVR model in actual wells indicated stable vertical distribution of chang 7 Member formation pressure in the study area. Pressure in mud shale sections is higher than the sandstone sections，with pressure coefficients mainly range from 0.80 to 0.90，indicating an overall abnormally low pressure environment consistent with actual formation conditions.

A series of studies，such as coal seam connecting well profiles，logging-seismic calibration，seismic profile interpretation ，analysis of coal seam logging data，have been carried out to clarify the exploration direc tion of coalbed methane in the area of Encircling Dongdaohaizi sag. The results show that：（1）The Jurassic Xishanyao Formation and Badaowan Formation in this area developed coal seams with thick，widely distribu tion. Xishanyao Formation develops 2-3 layers of coal seams，with a cumulative maximum thickness of 20 m， Badaowan Formation develops 2-4 layers of coal seams，with a cumulative maximum thickness of 29 m. Analy sis of coal rock gas content and abnormal logging gas shows that good gas bearing property.（2）The analysis of the main controlling factors for coalbed methane reservoir formation indicates that the middle and lower Jurassic coal measure source rocks in the sag good，reaching a medium to good e source rock level，with Ro value rang ing from 0.6% to 0.8%. It has good ability to generate hydrocarbon gas. In addition，based on the analysis results of natural gas carbon isotopes，coalbed methane also can come from deep highly mature humic source rock. （3）Xishanyao Formation coal rock is a medium-low porosity and low permeability reservoir，with value of po rosity range from 7.0% to 20.8%，value of permeability range from 0.32 mD to 8.67 mD. Badaowan Formation coal rock is a low porosity and medium-low permeability reservoir，with value of porosity range from 5.6% to 7.8%，value of permeability range from 2.3 mD to13.83 mD. The coal seam is sandwiched between mudstones， and the regional mudstone cover is widely distributed above the coal seam，due to a good sealing conditions in this area.（4）There are two modes of coalbed methane enrichment and accumulation in this area：The model of coalbed methane enrichment and accumulation in the source area of the sag and a model of enriched external gas accumulation in the deep bulge area. It is considered that there are greater exploration potential of encircling Dongdaohaizi sag，especially，exploration in slope area of Dongdaohaizi sag northeastern direction and Dongdaohaizi sag northern slope to Dinan uplift.

Guided by the theory of sedimentology，the data of outcrops，drilling cores and logging were used to study the characteristics of deep-water deposits，including facies markers and sedimentary microfacies types，of Triassic Chang 7 reservoir in southeastern Ordos Basin，and the evolution law was revealed. The results show that：（1）Facies markers of deep-water deposits of Triassic Chang 7 reservoir in southeastern Ordos Basin include sedimentary structures such as horizontal bedding，Bouma sequence，trough mode，sliding and slump structure， tearing debris，mud-clad gravel，containing deep-water bivalves and fish fossils. The total suspended content in the grain size probability curve is large and the sorting is poor，and the features of zigzag，teethed box-bell-finger shaped and mudstone baseline can be seen on the logging curve.（2）The provenance of Chang 7 reservoir in the study area mainly comes from the northeast and south，with the development of deep to semi-deep lake，sublacustrine fan and shallow lake，and shallow lake sediment. The sublacustrine fan includes two types of gravity flow: turbidity flow and sandy debris flow. It can be further divided into microfacies such as gravity flow main channels，overflow deposits，gravity flow branch channels，inter branch channels，and lobes. The main channels of the sublacustrine fan mainly developed sandy debris flow deposits，while the branch channels and lobes are mainly developed turbidite deposits.（3）The sedimentary evolution law of Chang 7 reservoir in the study area is as follows: deep to semi-deep lake and sublacustrine fan deposits were developed in the central and southern parts of the study area，and shallow lake deposits were developed in the northeastern part. Four sublacustrine fans from the northeast direction were developed in the study area and two sublacustrine fans from the south were developed. The boundary between semi-deep lake and shallow lake extends along Yan’an-Ganquan belt from northwest direction. During the sedimentary period of Chang 7³，the range of deep to semi-deep lake was the largest，and the sublacustrine fan was locally developed. During the sedimentary period of Chang 7² and Chang 7¹，the development of sublacustrine fan gradually increased，while the range of deep lake to semi-deep lake gradually lessened，showing an overall trend of interactive sedimentation between deep lake to semi-deep lake and lacustrine fans.

Based on experimental analysis of source rock，gas and reservoir fluid inclusions，we systematically study the geochemical properties，development environment，origin and source of natural gas，hydrocarbon accumulation period and reservoir control function of the Cretaceous source rock in the Dehui fault depression， Songliao Basin. The results show that：（1）The TOC of Cretaceous source rocks in Dehui fault Depression is generally greater than 1%，the organic matter types are mainly type Ⅲ，and type Ⅱ samples are mainly distributed in Non gannan Depression，which is generally in the mature to high mature stage of abundant gas；The source rocks of Huoshiling Formation and Yingcheng Formation were formed in the depositional environment of reduction-weak reduction and high-water salinity，and the lower biogenic sources such as plankton and algae contributed more in the source rocks of Huoshiling Formation in Nongannan Depression，and the oil generation capacity was stronger. （2）The composition of cretaceous natural gas varies greatly，with alkane gas ranging from 2.0% to 98.5% and CO₂ content ranging from 0.1% to 96.5%；The main type of gas is coal-derived gas，and some gas samples show signatures of carbon isotope inversion because of secondary gas charging at different epochs. In the Guojia Depressions，Huajia Depressions and Nongannan Depressions，the hydrocarbon-bearing rocks are mainly the Huoshiling Formation. The gas in the Baojia Sink probably comes primarily from the source rock of the Zhuocheng For mation. The genetic type of CO₂ gas is predominantly inorganic. As the burial depth increases，the carbon isotopic composition of the carbonate cement shows a positive shift，indicating the risk of drilling deep into the highly inorganic CO₂ gas layer.（3）The source rocks in Nongannan Depression are in the stage of oil generation. From the south to the north，the thermal evolution degree of the source rocks increases gradually，which controls the phase distribution of“oil from the south to the north”and controls the hydrocarbon accumulation period. Industrial oil and gas wells are mainly located near the center of the high thick source rock，which controls the distribution of oil and gas reservoirs.

The rock composition and structure of lacustrine dolomite reservoirs are complex and diverse，and the use of logging data is of great significance for identifying dolomite lithology. In order to solve the problems of heavy workload and low recognition accuracy in traditional logging methods，a method of integrating spider web plot intersection plot principal component analysis is proposed to construct a lithology sensitive factor intersection plot and carry out comprehensive identification of lacustrine dolomite lithology. The results indicate that：（1）The fourth member of the Paleogene Shahejie Formation（Sha 4 Formation）in the Bamianhe area of Dongying Sag is mainly composed of granular dolomite，microcrystalline dolomite，mud crystalline dolomite， sandstone，and shale. Among them，granular dolomite，microcrystalline dolomite，and shale are the main rock types.（2）Selecting 6 types of feature parameters to analyze the differences between spider web diagrams and intersection diagrams of different rock types，among which GR and AC can effectively distinguish granular dolomite，and SP has a good distinguishing effect on sandstone. Based on the results of spider web diagrams and intersection diagrams，principal component analysis is applied to standardize the logging parameters，and principal components F1 and F2 with a cumulative variance contribution rate of 90.75% are constructed. A lithology discrimination model is established to comprehensively identify lithology.（3）Through the verification of production capacity and coring wells，the accuracy of lithology identification is as high as 85.4%. It is clear that the granular dolomite is distributed in a strip like pattern in the west along the SW-NE direction， transitioning to microcrystalline dolomite and mud crystal dolomite in the south and north，while irregularly distributed sandstone is dominant in the east. This fusion method can efficiently identify the lithology of dolomite and has strong guiding value for subsequent favorable reservoir evaluation and oil and gas exploration.

Based on the data of core，cast slice and laser confocal scanning electron microscopy，the fracture development characteristics and main controlling factors of Cretaceous Bashijiqike Formation in Keshen area of Kuqa Depression are analyzed，and their influence on reservoir physical properties and hydrocarbon accumulation effect is discussed. The results show that：（1）The rock type of Cretaceous Bashijiqike Formation in Keshen area of Kuqa Depression is dominated by lithic feldspar sandstone，which is a typical tight sandstone reservoir. Shear and tension fractures are mainly developed，and high angle and vertical fractures are mainly developed，and unfilled and semi-filled fractures occupy a relatively large proportion. The difference of fracture plane distribution in Keshen A and B gas reservoirs is mainly caused by the difference of structural location and stress evolution，and the fracture effectiveness of A gas reservoir is better than that of B gas reservoir.（2）There are differences for the fracture density and effectiveness in the different structural location. The fracture effectiveness is highest at the high point of the anticline，while the fracture density is high but the effectiveness is low at the saddle and wing near the fracture. The fracture effectiveness in sandstone is higher than that in mudstone. There is a nonlinear relationship between the thickness ratio of sand and mudstone and the fracture density，and the fracture density reaches its maximum value when the thickness ratio of sand and mudstone reaches 6.1，beyond which the fracture density gradually decreases.（3）Fracture development significantly increases the permeability of tight sandstone reservoirs；The fracture network can effectively connect the low permeability reservoir， improve the accumulation efficiency and migration ability of oil and gas，increase the reservoir reserves and enhance the resource development potential of the reservoir. This study has certain guiding significance for the migration and enrichment of oil and gas in the same type reservoir and the productivity of single well.

The reflection energy of middle-upper Jurassic Karlov-Oxfordian carbonate reservoir in the Agayry gas field on the right bank of the Amu Darya River is weak，and the signal-to-noise ratio of seismic data is low. Based on the analysis of reservoir characteristics and rock physics，the gas-bearing reservoir is predicted by prestack gather conditioning，well-seismic joint low-frequency impedance modeling，pre-stack ray domain elastic impedance inversion. The results show that：（1）The Calllovian-Oxfordian reservoirs in the middle and upper Jurassic of the Agayry gas field are mainly gentle slope carbonate rocks in the front edge of the platform. The lithology is mainly sandy limestone and bioclastic limestone. The reservoir space is dominated by pore-fracture type，which has the characteristics of low porosity，low permeability and strong heterogeneity. The results of rock physics analysis show that the effective gas-bearing reservoirs are mainly characterized by low longitudinal wave impedance，low shear modulus and low bulk modulus，and the shear modulus is the most sensitive to gasbearing reservoirs.（2）The pre-stack gathers are processed by means of prediction elimination denoising，singu lar value decomposition denoising and spectral balance energy compensation，which can effectively remove highfrequency and random noise such as abnormal amplitude，improve the effective signal strength and enhance the AVO characteristics at far offset. The well-seismic joint modeling method solves the problem of multi-solution inversion caused by the lack of low-frequency information of seismic data by introducing low-frequency layer velocity，which improves the inversion accuracy and effectively characterizes the lateral change of reservoir. The pre-stack ray domain elastic impedance inversion method has a good application effect in the study area. The P-wave and S-wave impedance inversion results show high resolution in both vertical and horizontal directions. The predicted gas-bearing reservoir thickness is more than 85% consistent with the results of logging interpreta tion. At the same time，the inversion indicated that lateral continuity of the gas layer is poor，which is consistent of the sedimentary characteristics of the gentle slope beach.（3）The carbonate reservoirs in the study area are favorable areas of exploration and development potential. There are many obvious gas shows in the undrilled areas in the east and southwest. The gas-bearing display of the upper Gap-XVhp is better.

Based on the data of drilling，mud-logging，wire-logging and source rock analysis and testing，the hydrocarbon generation potential and thermal evolution history of the source rocks of the Permian Pingdiquan Formation in Dongdaohaizi Sag of Junggar Basin were systematically studied. The results show that：（1）The hydrocarbon source rocks of the Permian Pingdiquan Formation in Dongdaohaizi Sag of Junggar Basin are mainly darkgray and gray black mudstones，which are dark in color and generally large in thickness. The thickness gradually increases from the northeastern slope area to the center of the sag，and gradually decreases toward the western Mosuowan uplift，with a maximum thickness of 536 m.（2）The organic matter abundance of the source rocks of Pingdiquan Formation in the study area is evaluated as medium to excellent levels，with the highest organic matter abundance in the first member of Pingdiquan Formation in the vertical direction and in Dinan 7 and Dinan 19 well areas in the northeast of the sag on plane. The organic matter type is mainly type Ⅱ₂-Ⅲ，with a few type Ⅱ₁，and it is the best in the second member of Pingdiquan Formation in the vertical direction. The organic matter type of source rocks near the central sag is mainly type Ⅱ₁-Ⅱ₂ on plane.（3）The simulation results of thermal evolution history show that the source rocks in the sag and slope areas reached their hydrocarbon generation peaks in the Late Triassic and Late Jurassic，respectively，and are currently in the high mature stage and mature stage，respectively.（4）There are two types of hydrocarbon accumulation models in the study area： “lowergeneration and upper-reservoir” and “self-generation and self-reservoir” . The source rocks of Pingdiquan Formation and the reservoirs of the Upper Urho Formation form “lower-generation and upper-reservoir” reservoirs， while the high-quality source rocks of the first and second members of Dingdiquan Formation and the small-scale fan delta deposits at the edge of the lake basin form “self-generation and self-reservoir” reservoirs within the Pingdiquan Formation，both of which have great potential for oil and gas exploration.

In order to clarify the characteristics，genesis and distribution of favorable reservoir in the second member of Xujiahe formation，comprehensively utilizing the thin sections，scanning electron microscopy， nuclear magnetic resonance，mercury injection and CT testing，the main controlling factors of tight gas reservoirs were analysed. And based on the macro and micro parameters，classify the tight gas reservoirs quantitatively and distribute foe different kinds of reservoirs according to Q-cluster analysis. The results show that：（1）The reservoirs in the second member of Xujiahe formation in Hechuan area of central of Sichuan Basin are lithic feldspar sandstone and feldspar lithic sandstone，with an average porosity and permeability of 6.58% and 0.21 mD， which is typical ultra-low porosity and low permeability reservoir. The reservoir space in the second member of Xujiahe Formation is mainly residual intergranular pore and intragranular dissolved pore，secondly is intergranular dissolved pore and fissure，the pore and throat radius range from 1.31 μm to 55 μm and 0.05 μm to 1.14 μm， classifying them as micrometer pores and millimeter-micrometer throats.（2）The granularity and shale content is controlled by the sedimentary，which is the basic for primary pore and its evaluate，while the pore distribution by compaction and cementation is 14.6%-20.1% and 9.8%-15.1%，which is the significance reason for the reservoir densification. The dissolution and chlorite formed lots of intragranular dissolved pore，and protect some intergranular pore，which is helpful to the improve the tight reservoir into favorable reservoir.（3）Multiple parameters such as reservoir quality and pore structure was selected to divide the tight gas reservoirs into 4 kinds of different reservoirs，the reservoir quality and pore structure are different from each other in different kinds of reservoirs. TheⅠ-type and Ⅱ-type reservoirs have a greater reservoir quality and pore structure，which is the main“sweet spot”in tight gas reservoirs and favorable development target in study area. TheⅠ-type and Ⅱ-type reservoirs are development in H1，H3 well in the central and H125 well in the east，and they concentrated development in the third and second layer in the upper of the second member of Xujiahe Formation.

Through the petrological characteristics and elemental geochemical testing and analysis of cores from Triassic long 7-layer drilling in Huachi area of Ordos Basin，the paleoenvironmental characteristics were analyzed by using V（/ V+Ni），Ni/Co，U/Th，Sr/Cu，CaO（/ MgO^*Al₂O₃），Sr/Ba，Fe/Mn，Mn/Ti，Babio values and P/Al values，combined with the content of total organic carbon，to analyze the paleoenvironmental. Paleoenvironmental characteristics such as Ancient climate，paleosalinity and paleoredox conditions. The results show that：（1）The rocks of Triassic Chang 7 member in Huachi area of Ordos Basin are mainly dark gray mudstone，dark gray gray mudstone，silty mudstone containing carbon debris and silty mudstone rich in organic matter. Intercrystalline pores and intergranular pores of clay minerals are the main pore types. In addition，a small number of dissolution pores and fine fractures can be seen.（2）In the study area，the organic matter productivity was significant during the deposition period of Chang 7，and the environment was mainly freshwater with low oxygen content，which was in a state of poor oxygen to hypoxia，while in the Chang 7₂ and 7₃ periods，some areas with deep water bodies had extremely strong reduction conditions，mainly warm and humid climate. Overall，it indicates a deep-water environment. And Chang 7₂ is located in the boundary zone of the deep-water area，and its water environment are obviously different from the adjacent Chang 7₁ and Chang 7₃ members，showing relatively low water depth conditions. The P/Al value and Babio value generally change in the Chang 7 member，from Chang 7₃ to Chang 7₁，they all show a process of increasing from bottom to top.（3）The paleosedimentary environment of the Chang 7 member in this area has suitable temperature and salinity conditions，coupled with the deep water and strong reduction，which jointly promote the extensive development，enrichment and preservation of organic matter. The source rock and the reservoir are interconnected through fractures，and the oil generated in the source rock is more easily transported to the reservoir layer through fractures. In addition，when the distance between the source rock and the reservoir is relatively close，the process of crude oil migration and accumulation will be more efficient，and finally form a high-quality source rock system. Source rock and reservoir configuration laid a solid foundation for large-scale enrichment of shale oil and created extremely favorable conditions.

Taking the group components of medium-low maturity shale oil in the third member of Paleogene Shahejie Formation in the Bohai Bay Basin as an example，a nano-scale model of shale soluble organic matter system was constructed through molecular dynamic simulation. The molecular occurrence state of shale soluble organic matter system at the nanoscale under geological conditions was investigated. And the limiting factors of shale oil movability were analyzed. The results show that：（1）The shale soluble organic matter system model consists of four group components of saturated hydrocarbons，aromatic hydrocarbons，non-hydrocarbons，asphaltenes and water，with mass fractions of 18.6%，18.9%，19.7%，38.6%，and 4.2%，respectively. The representative mol ecules for each of the four group components are nC₁₈，1-methylphenanthrene，the aromatic bicyclic structure with carboxylate-containing long-side-chain moieties，and C₅₈H₆₅NS，respectively.（2）In the initial state of simu lation，shale soluble organic matter system shows the uniform distribution of the various components with high energy. As the simulation progresses，the heterogeneity of the system increases and the energy decreases. The saturated and aromatic hydrocarbon molecules diffuse more easily，while the non-hydrocarbons and asphaltenes exhibit self-aggregation phenomena，resulting in the generation of a free subsystem dominated by dispersed small molecules（with a total mass fraction of saturated and aromatic hydrocarbons of 42.9%）and an aggregation subsystem dominated by macromolecular aggregates（with a total mass fraction of non-hydrocarbons and as phaltenes of 74.3%）. The free subsystem has a larger total molecular mass，66.7% of the total molecular mass of the original soluble organic matter simulation system，a faster diffusion rate，and a smaller density in the simu lated final state.（3）Molecular mass and polarity are essential factors affecting the mobility of shale oil in the nanoconfinement. Self-aggregation of polar molecules inevitably triggers heterogeneity in the soluble organic matter system，and the inhomogeneous distribution of polar molecular clusters，with adsorption in the nanopore throat space results in the blockage of shale oil transport channels，thus limiting the mobility of shale oil.

Based on fluid inclusion analysis，organic geochemistry data，and pressure simulation，the multiphase thermal fluid activity and natural gas migration-accumulation in the No. 2 fault zone of the BX19-2 structure in eastern Qiongdongnan Basin were studied. The results show that：（1）The natural gas in the BX19-2 structure primarily consists of hydrocarbon gases and CO₂，with the hydrocarbon gases being a mix of coal-derived gas and oil-derived gas. However，there is a significant variation in the composition of natural gas across different gas zones. The shallow gas zones in the Sanya Formation exhibit a relatively high content of hydrocarbon gases（volume fraction of 83.93%）and a low content of organogenic CO₂（volume fraction of 7.11%）. In contrast， the deeper gas zones in the Lingshui Formation contain relatively lower concentrations of hydrocarbon gases （volume fraction ranging from 16.10% to 76.63%）and higher concentrations of mantle-derived CO₂（volume fraction ranging from 18.70% to 81.56%）.（2）Fluid inclusions and geochemical parameters of rocks indicated that the hydrothermal activity was related to hydrocarbon migration，with variations in the depth and extent of the induced thermal anomalies. There were three phases of hydrocarbon-bearing hydrothermal activities occurred during the late Miocene（approximately 8.8 Ma），Pliocene（approximately 4.5 to 4.1 Ma），and Quaternary （approximately 1.1 to 0.1 Ma），respectively.（3）The hydrothermal fluids primarily utilized faults as major conduits for vertical，efficient，and rapid charging. Mantle-derived CO₂ from the deep Baodao Sag was injected during the late Pliocene to Quaternary period（approximately 2.2 to 0.5 Ma），displacing the hydrocarbon gases accumulated in the Lingshui Formation. Therefore，traps near the No. 2 fault zone of the Baodao Sag may pose a risk of encountering gas zones with high CO₂ content.