Recent deployed well Lutan-1 in the northern margin of Qaidam Basin has achieved successive breakthroughs in Jurassic Dameigou Formation sandstone and Paleogene Lulehe Formation, revealing significant exploration potential for lithologic gas reservoirs in the slope-sag belt of this region. Based on the whole petroleum system accumulation theory, geological conditions and main controlling factors of natural gas accumulation were systematically analyzed, and the direction for further exploration was clarified. The results show that: (1) Major hydrocarbon-generating sags such as Yibei Sag are well preserved, and Jurassic coal-measure source rocks widely distributed, with large thickness and high maturity, providing abundant gas sources for natural gas accumulation. (2) Controlled by paleo-gully and slope-break geomorphology, Paleogene Lulehe Formation and Jurassic Dameigou Formation developed large area sandstone reservoirs in the slope zone, forming sand-rich belts. Lulehe Formation mudstone and Jurassic Dameigou Formation mudstone are efficient regional caprocks, while the regional unconformity at Paleogene base serves as a key migration pathway, jointly controlling the continuous accumulation of sandstone reservoirs in the stable slope. The breakthrough of well Lutan-1 marks a shift in exploration strategy from uplift to slope-sag zones in this area, confirming the accumulation model of “unconformity network migration, near-source efficient charging, high-quality caprock sealing, and paleo-geomorphology controlling sandstone enrichment”， which is conducive to the exploration and study of the whole petroleum system for coal-measure gas in the northern margin of Qaidam Basin. （3） According to the new exploration concept of “moving down slope and into sags, searching for gas near sources”, four major paleo-slope zones on the periphery of Yibei Sag have great exploration potential and may be the key areas for future large-scale reserves expansion.

Ordovician carbonate strata of Shunbei-Tahe area of Tarim Basin widely develop dome structures， several wells have obtained high-yield industrial oil and gas flows， which shows good resource potential. Based on data of high-precision 3D seismic， well logging， and core testing analysis， taking 150 dome structures from the periphery of well H1 and the southeastern slope zone of Akekule uplift in Shunbei area as examples， the geometric characteristics， genesis mechanisms， and reservoir features of dome structures were systematically analyzed. The results show that：（1） Ordovician dome structures in northern Tarim Basin are concentric-ring-shaped in plan view， which can be classified into four types：R-type， T-type， contraction-type， and composite-type. In cross-section， they exhibit a torch-like shape of “narrow at the bottom and wide at the top”. （2） The main body of dome structures formed during Middle Caledonian episode Ⅰ-Ⅱ， as a result of the combined effects of regional shear stress field and lithological differences, and is a genesis mechanism of “shear stress induction-interlayer slip-local uplift”. （3） The dome structure reservoir is a “fracture-cavity and pore-cavity” composite reservoir system， cha-racterized by the advantages of “faults connecting to the source， vertical migration and accumulation, surrounding rock sealing， and independent hydrocarbon accumulation”， with large resource scale. It is a significant new frontier for deep to ultra deep petroleum exploration.

Naiman Sag of Kailu Basin has developed unique trona deposit, which is paragenetically associated with salt and crude oil. Based on the data of seismic, logging data, drilling core laboratory analysis, the lithology assemblage, ore characteristics, deposit features and distribution patterns of the trona deposit in Cretaceous Yixian Formation were clarified. Meanwhile, the genesis and patterns of the deposit were investigated in terms of paleostructure, paleoclimate, sources of ore-forming materials, and their coupling relationships. The research results indicate that: (1) The Yixian Formation deposit of Cretaceous in Naiman Sag is characterized by deep burial, steep dip, fault development, thin individual layers and numerous interbeds. Ore body shape is approximately elliptical, with a north-south distribution direction and a lenticular distribution pattern featuring thickened centers and thinning edges. Two sedimentary sequences are developed: A soda-lake type sequence (mudstone-dolomite → trona → mudstone) dominates the deposit margins, while a saline-lake type sequence (mudstone-dolomite → trona → halite → trona → mudstone) prevails in the central zone. On the plane, trona-saline trona-salt distribute in an annular pattern. (2) The deposits are generally oil-bearing. Within mudstone layers, crude oil occurs in intergranular pores of fine clastics, inter-crystalline pores of clay minerals, fractures, and kerogen. In trona and salt layers, hydrocarbons primarily reside in mineral inter-crystalline pores and fractures, cleavage fractures, inclusions, and lattice defects. (3) The trona deposit in the study area is a ternary coupled mineral model of “paleogeomorphology-paleoclimate-volcanic activity”, the deposition of Yixian Formation constituted a closed lacustrine basin. Sodium ions (Na⁺) were continuously supplied to the basin by sodium-rich andesitic rocks in the periphery. The decomposition of organic-rich mudstone produces considerable CO₂, which increases the concentration of CO₂ in brine. The frequent volcanic activities during the Yanshan period led to the upwelling of deep-seated hydrothermal fluids and mantle-derived gas through faults, providing a large amount of CO₂ and Na⁺ -rich hydrothermal fluid. A persistent arid climate towards the end of Yixian Formation resulted in extreme concentration of the lake water, reaching saturation and precipitating trona or halite. Subsequent diagenesis formed the present trona deposit.

Based on drilling, logging, and seismic data, distribution patterns and enrichment mechanisms of uranium in the overlying uranium-rich layers of subtle organic reefs in Permian Changxing Formation of Yuanba area in Sichuan Basin，were systematically analyzed. An “anoxic sealed” sedimentary model for overlying uranium-rich layers of subtle organic reefs was established. Guided by the model, an integrated technical system of “seismic target processing-uranium-rich layer constraint-fine characterization” was constructed, which achieved the detailed characterization of such reefs and predicted favorable development areas. The results show that: （1） Based on the vertical distribution of uranium content, the upper Changxing Formation in Yuanba area can be divided into three types, such as stable, top-enriched, and overall-enriched, among which the top-enriched type is the key indicator for identifying subtle organic reefs. Under the guidance of “anoxic sealed” sedimentary model, during the late depositional stage of Changxing Formation， the barrier effect of the platform-margin reef belt generated restricted anoxic environment in its back-reef area, reefs growth ceased and reefs were subsequently capped by uranium-rich layers, forming the vertical architecture of “uranium-rich layer-subtle reef ”. （2） The integrated “seismic target processing-uranium-rich layer constraint-fine characterization” technical system improves imaging quality through geological target-driven seismic processing, uses uranium enrichment distribution to focus on target areas, and then establishes a subtle organic reef seismic identification model combined with forward modeling, achieving fine characterization of the spatial morphology of reefs. According to the plane distribution characteristics of subtle organic reefs characterized by the integrated technical system, subtle organic reefs are relatively concentrated and larger in scale in W104-W11 well area and north of well W123 on the landward side, with individual reef areas of 0.36-1.25 km². In contrast, reefs are more scattered and smaller in scale towards the inner platform, with individual reef areas less than 0.40 km². （3） For the first well W102-4H drilled on the subtle organic reefs in the uranium-rich overlayer of the study area, tested natural gas production reached 65.50×10⁴ m³/d, with calculated open-flow capacity of 265.12×10⁴ m³/d. The south of well W104 and well W11 are also favorable targets for subtle organic reefs, with an estimated gas production excee-ding 100.00×10⁴ m³/d.

Existing rock physics models cannot accurately characterize the variation of elastic parameters in overpressure reservoir, which limits the precision of overpressure reservoir characterization. Taking overpressure re-servoirs of Miocene Huangliu Formation in Ledong slope of Yinggehai Basin as an example, a multi-porosity rock physics model for overpressure reservoirs was proposed, and its application performance was analyzed. Based on the proposed model, the influence factors of elastic parameters in overpressure reservoirs were analyzed, and a rock physics template incorporating formation effective stress and porosity parameters were established. The results show that: （1） The multi-porosity overpressure rock physics modeling method is proposed based on the multi-porosity theory by comprehensively considering effects of soft pores, stiff pores, and bound-water. By introducing the formation pressure coefficient and effective stress into the pore-space stiffness theory, and employing a gradient-based optimization algorithm to adaptively optimize pore aspect ratios, the model captures the variation of elastic parameters with effective stress under complex pore structures. （2） The predicted P-wave and S-wave velocities of Huangliu Formation in Ledong slope area by this model are in high agreement with well logging interpretations, with prediction errors below 8%. Compared with conventional models, the proposed model achieves the best fitting performance, with the highest R² values of 0.920 and 0.937, respectively. （3） In overpressure reservoirs, rock elastic parameters are jointly controlled by five factors, including effective stress, soft-pore proportion, clay content, bound-water porosity, and movable-fluid porosity. In overpressure formations, with increasing pore pressure and decreasing effective stress, the P-wave to S-wave velo-city ratio (v_p/v_s) increases. Compared with sandstone, mudstone exhibits lower velocity and higher v_p/v_s values. The v_p/v_s ratio is the sensitive parameter for distinguishing sandstone from mudstone in overpressure clastic reservoirs. In the study area, the discriminant threshold of v_p/v_s for sandstone and mudstone is approximately 1.64 in the normal-pressure section, and 1.70-1.75 in the overpressure section. （4） The sandstone reservoir distribution predicted by the v_p/v_s section inverted on the basis of the proposed multi-porosity overpressure rock physics model is basically identical with the gas logging interpretation conclusion.

Based on the testing and analyses on helium volume fraction, isotopic composition, and mass fractions of uranium (U) and thorium (Th) in source rocks of 91 natural gas samples from drilling wells and 68 helium source rock samples from Yanchang exploration area of Ordos Basin, the distribution and origin of helium, helium-supplying potential of various helium source rock types were clarified, main controlling factors for helium enrichment were systematically discussed. The results show that: （1） The volume fraction of helium of Yanchang exploration area of Ordos Basin ranges from 0.009% to 0.217%, with an average of 0.059%. Among them, 6.5% of samples meet the high-helium standard (≥ 0.1%). On the plane, the helium abundance shows a pattern of “high in the south and low in the north”, with Luochuan and Fuxian being high-helium areas, and Zizhou, Jingbian being helium-poor areas. Vertically, the helium content shows little variation across different strata, indicating stable distribution. （2） The helium in the study area is a typical crust-derived helium, with helium isotope R/Ra values all less than 0.1, and the crustal contribution proportion reaching 99.73%. Multiple sets of helium source rocks, including Precambrian crystalline basement, Changcheng system, and Upper Paleozoic, are developed in the area. The helium generation of Precambrian basement and Changcheng system far exceeds that of Upper Paleozoic, with basement helium generation of 3 164.04×10⁸ m³, accounting for 95.99% of the total helium generation. （3） Regarding main controlling factors for enrichment, Precambrian and Changcheng system in the study area serve as main helium sources, with Upper Paleozoic helium source rocks as back-up. Facilitated by deep and large faults in the basin, a dual-source helium supply model of “dominant deep sources and auxiliary Upper Paleozoic sources” has been formed. Deep and large faults are the key pathways connecting deep helium sources, while the strong dilution effect on helium production caused by the hydrocarbon generation of Upper Paleozoic source rocks is the core factor leading to the differential accumulation of helium between the south and the north.

By comprehensively utilizing well logging and seismic interpretation data, activity characteristics of Cretaceous Shahezi Formation synsedimentary faults in Lishu fault depression of southern Songliao Basin were analyzed. The paleogeomorphology was reconstructed based on the impression method, and the controlling role of paleogeomorphology on sedimentary systems were explored. The results show that: （1） The fault activity rate during the deposition of Member 2 of Cretaceous Shahezi Formation in Lishu fault depression was generally higher than that during the deposition of Member 1, showing a trend of first increasing and then decreasing towards the north. （2） During the depositional period of Shahezi Formation, the steep slope zone of Lishu fault depression primarily developed nearshore subaqueous fan and deep-lacustrine sedimentary systems, while the gentle slope zone mainly developed fan delta and shallow-lacustrine sedimentary systems. （3） The paleogeomorphology of the study area controls the distribution of sedimentary facies and sand bodies. Four paleogeomorphic types,such as valleys,transverse uplifts (subaqueous uplifts), strike slopes, and structural slope-break zones,have been identified,all of them exert significant control on sand bodies distribution. Valleys can serve as sand transport pathways, controlling the progression of sand bodies from source areas to depositional areas, and also acting as depositional unloading units. Transverse uplifts developed along the edges of steep slope scarps promote the fan-shaped dispersal of sand bodies into the basin. Strike slopes control the lateral extension of sand bodies, and activity at the terminations of synsedimentary faults governs the pathways of sand diffusion from source areas into the basin. Structural slope-break zones control the transport, migration, and enrichment locations of sand bodies within the basin, which are favorable zones for exploring sandstone oil and gas reservoirs. （4） The depositional period of Shahezi Formation in the study area exhibited a paleogeomorphy sand control model of“multi-source supply—fault-controlled channels—paleogeomorphic sand accumulation”.

Based on seismic, drilling, well logging and geochemical testing and analysis, the method for determining the accumulation time of hydrocarbon transported by sandstone-fault system to shallow layers was proposed. The accumulation time of oil transported by the lower submember of the first member of Shahejie Formation （Es₁^x） sandbody-Zhaobei Fault transport system to Guantao Formation was clarified, and the relationship between the accumulation time and hydrocarbon distribution of Guantao Formation and its upper reservoirs was analyzed.Research results show that: （1） The method for determining the accumulation time of hydrocarbon transported by sandstone-fault system to shallow reservoirs is as follows: the hydrocarbon transport time of sandbody is obtained by superimposing the formation time of sandbody, the duration of sealing capacity of overlying mudstone caprock (the period from the synchronization of mudstone and sandbody sealing indices to present), the sandbody tilting time during the last fault activity, and the hydrocarbon expulsion time of source rock. By restoring the paleo-thickness of mudstone caprock and paleo-fault throws of faults in different geological periods, and calculating their difference, the paleo-residual thickness of mudstone caprock in each period can be obtained. The hydrocarbon migration time of fault is the time interval from the time corresponding to the maximum residual thickness required for the fault to penetrate mudstone caprocks, to the termination of fault activity. The superposition of hydrocarbon transport time by sandbody and by fault is the final accumulation time of hydrocarbon transported by sand-fault system to shallow layers. （2） In the study area, the hydrocarbon migration time through the sandbody pathway of Es₁^x is the sedimentary period of Minghuazhen Formation. The time when Zhaobei Fault simultaneously cut through mudstone caprocks of the middle submember of the first member of Shahejie Formation (Es₁^z) and the second member of Dongying Formation (Ed₂) was from the middle sedimentary period to the end of Minghuazhen Formation. The accumulation time of oil transported to the shallow Guantao Formation via Es₁^x sandbody-Zhaobei Fault system was from the middle sedimentary period to the end of Minghuazhen Formation, which is consistent with the hydrocarbon charging time obtained from the homogenization temperature of fluid inclusions in Guantao Formation combined with burial-thermal history. （3） The limited duration of oil transportation to Guantao Formation via Es₁^x sandbody-Zhaobei Fault system in the study area, is the fundamental reason for the current restricted occurrence scale of hydrocarbon in Guantao Formation near Zhaobei Fault. Zhaobei Fault did not cut through the mudstone caprock of Minghuazhen Formation, so there is no hydrocarbon accumulation above Minghuazhen Formation.

Silurian Longmaxi Formation shale in Hechuan area of central Sichuan Basin is widely distributed, with good quality source rock, which makes it a key target for shale gas exploration. Based on core experiment analysis and logging data, lithofacies were classified and logging intelligently was identified through mineral composition and TOC content. Lithofacies types and spatial distribution characteristics of Longmaxi Formation were clarified, and favorable lithofacies zones were delineated. The results show that: (1) Longmaxi Formation of Hechuan area in central Sichuan Basin has developed seven types of shale lithofacies, primarily dominated by organic-rich and organic-poor felsic shale lithofacies, organic-rich and organic-poor argillaceous-felsic mixed shale lithofacies, and organic-poor argillaceous shale lithofacies, with minor development of organic-rich mixed shale lithofacies and organic-rich calcareous-felsic mixed shale lithofacies. Among them, the organic-rich felsic shale lithofacies, organic-rich mixed shale lithofacies, and organic-rich calcareous-felsic mixed shale lithofacies are favorable targets for exploration. (2) The intelligent logging identification method involves introducing BSMOTE algorithm to balance minority lithofacies samples, constructing an ensemble learning model to achieve primary classification of mineral composition, and using a Principal Component Analysis-based Support Vector Regression (PCA-SVR) model to predict TOC content for secondary classification. BSMOTE-AdaBoost model was identified as the optimal model for primary lithofacies classification, while PCA-SVR model demonstrated high accuracy in secondary classification. Blind well verification confirmed an overall lithofacies identification accuracy of 86.7%, indicating strong regional applicability. (3) Shale lithofacies distribution of Longmaxi Formation in Hechuan area is controlled by paleo-water depth and provenance supply. Vertically, the lithofacies exhibit an evolutionary trend from organic-rich felsic shale facies to organic-poor mixed shale facies from the bottom towards the top. On the plane, favorable lithofacies migrate from NW to SE. The continuous distribution zone of organic-rich felsic facies in Long 1₁¹ sublayer represents the key target for exploration.

When dealing with complex geological structures， the cross-correlation of back-propagated reflected waves with normally propagating wavefield in elastic reverse-time migration （RTM） generates strong-amplitude low-frequency noise. To address the issues of computational instability and insufficient accuracy of conventional Poynting vector-based traveling wave separation RTM algorithm， TI （transversely isotropic） media RTM method based on optical flow vector was proposed. By integrating optical flow theory with anisotropic elastic wave dynamics， through iterative computations， the proposed mothod obtains a more accurate vector that closely approximates the true wavefield propagation direction， effectively suppressing migration noise. The results show that：（1） The optical flow vector derived from the constant-wavefield assumption over adjacent time steps and the spatial smoothness assumption of wavefields in TI media eliminates the instability inherent in Poynting vectors， and accurately indicates the P-wave and S-wave propagation direction in TI media. （2） The traveling wave separation method based on optical flow vector can accurately decompose wavefields into up-， down-， left-， and right-traveling wave. （3） The optical flow vector-based TI media RTM algorithm effectively avoids cross-correlation imaging of wavefields along identical paths， and can suppress migration noise.

Based on in-situ calcite U-Pb dating, fluid inclusion analysis, and basin modelling, the petrological and fluid activity characteristics of Ordovician Lianglitage Formation in Tazhong area were delineated. The oil and gas charging episodes were systematically analyzed, and reservoir formation models were characterized. Research results show that: （1） Main rock types of Ordovician Lianglitage Formation reservoir in Tazhong area are granular limestone and biogenic limestone, and storage space types include pores, karst caves, and fractures. （2） Two phases of calcite cements develop in the reservoir, with the first phase of calcite cement emitting bright red catho-doluminescence light, and the corresponding U-Pb age of 427.0 ± 4.2 Ma, and the second phase of calcite cement displaying orange-yellow cathodoluminescence light, and the corresponding U-Pb age of 369.0 ± 14.0 Ma. (3) Two types of oil inclusion assemblages (OIA) have been identified. Type I OIA emits yellow and pale yellow fluorescence, corresponding to the oil charge timing of 425.0-410.0 Ma. Type Ⅱ OIA emits blue fluorescence, corresponding to the oil charge timing of 325.0-320.0 Ma. (4) Lianglitage Formation reservoir in the study area has mainly experienced two episodes of oil charging and one episode of natural gas charging. The first episode of oil charging occurred in the late Caledonian period, the second episode of oil charging occurred in the middle Hercynian period, and the natural gas charging occurred in the late Himalayan period. The formation of this oil and gas reservoir is the result of synergistic effects of multiple factors, including high-quality reservoirs, multi-stage hydrocarbon supply, efficient transportation, effective sealing, and favorable structural backgrounds.

In recent years, significant progress has been made in hydrocarbon exploration of Sinian Doushantuo Formation in the Yangtze craton. Combided field outcrop profiles observations and laboratory analysis, the stratigraphic distribution and sedimentary characteristics of Doushantuo Formation in the periphery of Hannan paleo-uplift in northwestern Sichuan Basin were systematically summarized, and the control mechanism of the tectonic on the development of source rocks in Doushantuo Formation were revealed. Research results show that: （1） Diffe-rent sedimentary systems were developed during the sedimentary period of Doushantuo Formation in the eastern and western sides of Hannan paleo-uplift. The western side developed a stable gentle slope sedimentary system characterized by mixed clastic and carbonate rocks,while the eastern side underwent a complete sedimentary succession of “slope filling-stable shelf-carbonate gentle slope”. （2） The sedimentary differentiation characteristics of both sides of Hannan paleo-uplift are controlled by the subduction-transition boundary of Panxi-Hannan island arc.The western side corresponds to the subduction boundary,with wide and gentle sedimentary terrain.The eastern side is located at the transition boundary, with steep slopes and continuous subsidence, providing favorable tectonic-paleogeographic conditions for deep-water anoxic environments and the development of high-quality source rocks. （3） The eastern side of Hannan paleo-uplift (Zhenba-Chengkou area) contains high-quality source rocks, with high TOC values (2.75%-4.76%) due to earlier-initiated tectonic activity, continuous subsidence, oxygen deficient reducing environment, and high paleoproductivity driven by hydrothermal activity. Due to constraints such as tectonic stability and poor preservation conditions, the western side develops limited-scale, medium-poor quality source rocks, with average TOC values of 1.20%-1.65%.

Shale oil reservoirs subjected to complex hydraulic fracturing are prone to evolve into dual porosity media. Due to differences in matrix-fracture seepage behavior and the areal heterogeneity of “concentration-viscosity” after CO₂ injection, the pressure-response mechanism of CO₂ flooding becomes highly complex, resulting in insufficient accuracy in pressure-transient characterization and parameter inversion. Fick’s law was employed to investigate the CO₂ distribution characteristics. A dual porosity flow model was established by simultaneously accounting for concentration-viscosity-pressure coupling and the matrix threshold pressure gradient. The governing flow equations are solved numerically to generate pressure-transient curves for CO₂ flooding in dual porosity reservoirs, and effects of the matrix threshold pressure gradient, elastic storativity ratio, interporosity-flow coefficient, injection rate, and diffusion coefficient on the pressure-transient behavior were analyzed. The results show that: (1) A larger matrix threshold pressure gradient leads to a more pronounced late-time upturn of both pressure and pressure-derivative curves on the well testing curve. （2） A smaller elastic storativity ratio produces a wider and deeper “trough” in the pressure-derivative curve during the interporosity-flow stage. （3） With decreasing interporosity-flow coefficient, matrix-to-fracture crossflow slows down,the “trough” in the pressure-derivative curve moves to the right and becomes deeper. A larger interporosity-flow coefficient makes the late-time upturn in the pressure curve more evident. （4） A higher injection rate increases both pressure and pressure-derivative levels over the entire testing period and narrows the “trough” during the interporosity-flow stage. （5） The diffusion coefficient mainly influences the radial-flow stage of the composite system in the late stage: a larger diffusion coefficient causes this stage to occur earlier, reduces flow resistance, and shifts the pressure and pressure-derivative curves downward. （6） The proposed model enables quantitative characterization of pressure-transient features during CO₂ injection in fractured wells of Daqing Oilfield.

Using three-dimensional seismic data, drilling and logging data, and geochemical testing data，the depression structure, structural evolution characteristics, source rock distribution, and controlling effects of hydrocarbon accumulation in Miaoxinan area of Bohai Bay Basin were studied. The results show that: （1） Miaoxinan area is a transformed depression formed by the Tan-Lu strike-slip fault. During Middle-Late Eocene, the near east-west regional compression movement led to the transformation of the depression structure from NWW to NEE, the fourth section of Shahejie Formation (E₂s₄) was gradually weakened in erosion intensity from east to west, and source rocks of E₂s₄ in south sag of Miaoxi Sag on the east side were completely eroded. The high-sulfur and salty high-quality source rocks of E₂s₄ in the east sag of Huanghekou Sag on the west side have been preserved. （2） The east sag of Huanghekou Sag has developed long-term active faults that extend deep into source rocks of E₂s₃ and E₂s₄, oil and gas migrate and accumulate upward along the source-connecting faults, demonstrating the characteristics of deep and shallow compound hydrocarbon accumulation. （3） The south sag of Miaoxi Sag has only developed low-maturity hydrocarbon source rocks in E₂s₃, and the late stage activity of source-connecting faults is poor, oil and gas are difficult to break through the thick mudstone cap of Dongying Formation, and natural gas reserves have only been discovered in deep E₂s₁ and E₂s₂. In Middle-Late Eocene, the near east and west compression activities of eastern China played an important controlling role in the structure of basin margin depression, the distribution of source rocks and the accumulation of oil and gas.

Upper Permian Leping Formation of Pingle Depression is an important coal measure strata in south China， with favorable conditions for the formation of coal measure shale gas reservoirs. Mineral composition， organic geochemical characteristics， pore types， pore structure， and influencing factors of pore development of Leping Formation coal measure shale reservoir in the west section of Pingle Depression were studied through testing methods， such as thin section identification， X-ray diffraction， organic geochemical analysis， scanning electron microscopy， high-pressure mercury intrusion， low-temperature N₂ and CO₂ adsorption， and exploration prospects of shale gas were explored. The results show that： （1） The coal measure shale of Permian Leping Formation in Pingle Depression of Lower Yangtze region is mainly composed of detrital grain， mud and charcoal， with high content of brittle minerals and good fracability. TOC content of coal measures shale is relatively high， kerogen types are Ⅱ₁ and Ⅲ， and thermal evolution reaches high maturity to over maturity stage. （2） The porosity of shale is mostly 3.75%-4.67%， and the permeability is 0.006 2-0.009 1 mD， with low-porosity and low-permeability characteristics. The pore types are mainly intergranular pores， intragranular pores and microcracks， with fewer organic pores. （3） Average pore volume of shale is 0.020 2 cm³/g， average specific surface area is 15.02 m²/g. Mesopores contribute the most to the total pore volume， while micropores contribute the most to the total specific surface area. The pore size is characterized by “multi-peak” distribution. （4） Quartz and carbonate minerals can promote the development of mesopore and inhibit the development of micropores. The increase of quartz content reduces pore heterogeneity， and the increase of carbonate minerals improves pore heterogeneity. Clay minerals and organic matter can promote micropores development and inhibit mesopore development. Clay minerals increase pore heterogeneity， while organic matter strengthens pore homogeneity. （5） The coal measure shale in the study area exhibit good fracability， hydrocarbon generation potential， reservoir capacity， and with good preservation conditions. Yang-qiao， Fengcheng， Fujiaxu， and Taiyangxu are selected as favorable areas for coal measures shale gas exploration， with Fengcheng area being the primary target for further exploration.

In recent years, natural gas resources have been successively discovered in marine carbonate rocks of Ordovician Honghuayuan Formation (O₁h) and Baota Formation (O₂b) in Weiyuan area of Sichuan Basin, which shows favorable exploration potential. Based on integrated analyses of composition and carbon isotopes of natural gas, source rock features, fluid inclusion characteristics and burial-thermal evolution, the origin of natural gas and hydrocarbon charging episodes in the study area were determined, and hydrocarbon accumulation models along with its controlling factors for Ordovician natural gas were explored. The results show that： （1） Ordovician O₁h and O₂b natural gases in Weiyuan area exhibit high dryness coefficient, with an average value of 0.995 8，and belong to over-mature oil-type gas, they are mixed gases derived from both kerogen cracking and crude oil cracking, formed at different stages but from the same source. The carbon isotope reversal in the natural gas primarily results from thermochemical sulfate reduction (TSR) and over-mature background. Hydrocarbon source rocks of Є₁q serve as the main hydrocarbon supply layers for the natural gas in O₁h and O₂b. Є₁q source rocks have medium-good quality, with an average total organic carbon (TOC) of 1.90% and a mean hydrocarbon generation potential (S₁ + S₂) of 0.27 mg/g. The organic matter type is Type I, indicating over-maturity, with R_o of 2.74%-3.28% and T_max of 397-499 ℃. （2） In the study area, O₁h and O₂b formed paleo-oil reservoirs and paleo-gas reservoirs during Late Permian and Early Cretaceous, respectively. After the Himalayan orogeny, gas reservoirs underwent structural adjustment, forming structural-stratigraphic-lithological composite reservoirs controlled by large-scale anticline and strike-slip fault system. Reservoir rocks developed in upper O₁h and O₂b predominantly composed of dolomite, while the lower Є₁q supplied hydrocarbons, forming a hydrocarbon accumulation model of “lower-generation and upper-storage”. （3） Hydrocarbon accumulations of Ordovician O₁h and O₂b are mainly controlled by the quality of dolomite reservoirs, and the migration capacity of strike-slips and reverse faults. The “sweet spots” for natural gas enrichment are overlapping zones of high parts of anticlinal traps and the faults along the aulacogen margin.

By comprehensively utilizing technologies such as core observation, physical property testing, conventional logging, and imaging logging, reservoir formation conditions and hydrocarbon accumulation models of the buried hill in Binxian uplift of Dongying Sag in Bohai Bay Basin were systematically analyzed. Research results show that: （1） Archean reservoir types of Binxian uplift in Dongying Sag are fractured reservoirs and weathered crust reservoirs,with the weathered crust exhibiting a double-layer structure of dissolution layer and disintegration layer. Dissolution layers are mostly distributed in the lower part of the slope, making them optimal reservoirs. （2） The buried hill oil source of the study area comes from the third member of Shahejie Formation（Es3） and the fourth member of Shahejie Formation （Es4） source rocks in Lijin sub-depression, which has undergone two stages of hydrocarbon generation. The reservoir is dominated by weathered crust dissolution layers, with high-conductivity fractures and dissolution fractures as main reservoir spaces. Caprocks are thick dark mudstones of Es3 and Es4,with good sealing capacity. Migration pathways include two types: vertical migration along faults and lateral migration along unconformity surfaces. （3） The source-reservoir configuration relationship of buried hills in the study area has significant impacts on the reservoir formation. Paleogeomorphology and fracture density have controlling effects on reservoir quality. Faults and fractures are main migration channels for oil and gas. There are two types of oil and gas reservoirs,including “new source and old reservoir-lateral pinch out” type and “new source and old reservoir-buried hill top” type. The former is distributed in the central slope zone, where hydrocarbons migrate laterally from source rocks into buried hill reservoirs in contact with mudstones. The latter is distributed near large faults in the eastern slope zone, where oil and gas migrate vertically along faults to the top of the buried hill. （4） Compared with Shulu buried hill in Jizhong Depression, the study area exhibit an obvious double-layer structure of weathered crust, with lateral pinch out accumulation model as the dominant model and hydrocarbon properties being unitary. Five favorable zones are identified, among which Zone Ⅱ and Zone Ⅲ located in the central slope zone of the buried hill have optimal reservoir formation conditions and represent the most favorable exploration targets.

Northwest Guizhou hosts vast coal reserves and abundant coal-measure gas resources, demonstrating promising development prospect. Based on coal-proximate analysis, scanning electron microscope, isothermal adsorption, gas-composition analysis and gas-content measurements, reservoir formation condition of coalbed methane (CBM) of Permian Longtan Formation in the central part of Northwest Guizhou was studied from four aspects: gas-generation condition, reservoir properties, reservoir-cap assemblages and gas-bearing properties. The results show that: （1） Coal rocks in the central part of Northwest Guizhou are of high quality, mainly formed in water-inundated and humid settings. They are dominated by type Ⅲ organic matter, with an average organic matter abundance of 63.25%. Thermal maturity is high, with vitrinite reflectance (R_o) ranging from 2.54% to 3.50%, indicating strong hydrocarbon generation potential. （2） CBM in the study area is mainly methane,with dryness coefficient greater than 0.99，and mass volume of 5.68-20.12 cm³/g, exhibiting a distribution characteristic of “high in the north and low in the south”. （3） Coal rocks in the study area mainly develop three types of pore: intercrystalline pores, organic matter pores and microfractures. The reservoirs show strong adsorption capacity but weak seepage ability, and exhibit strong fracturing potential. （4） During the sedimentary period of Longtan Formation in the study area, two types （coal mudstone and coal siltstone） of reservoir-cap assemblages mainly formed under the influence of marine-continental transitional environment, which is the reservoir formation model of “self generation and self storage”.

For the evaluation of oil shale resources in basins with medium-low exploration levels, traditional volumetric methods and geological parameter analogy methods have limitations. An indirect parameter volumetric method is more suitable for resource evaluation of Appalachian Basin in North America. Based on the good positive correlation between total organic carbon content (TOC) of shale and its oil content, the threshold value and oil content range of oil shale were determined, and the correction coefficient was calculated. The correction coefficient was further applied to obtain the thickness, area, and pyrolysis hydrocarbon quantity (S₂) of oil shale, thereby the oil resource of oil shale was estimated. The results show that: （1） Oil shale resources in Appalachian Basin of North America are primarily distributed in the western Ohio area. The main formation of Ohio area is the Upper Devonian Ohio shale, which can be further divided into three submembers from bottom to top: Huron, Chagrin, and Cleveland. The lithology is predominantly deep gray to black shale, with thin interbeds of siltstone.（2） TOC of Ohio shale in the study area is 1%-12%, with oil content ranging from 0.33% to 9.31%. The oil content of oil shale ranges from 3.50% to 9.31%, S₂ is 35.2-95.7 mg/g and correction coefficient is 0.647. （3） Multiplying the mud shale thickness by the correction coefficient obtain the oil shale thickness of 10-80 m in the study area. Convert TOC contour lines into oil content contour lines, and the area delineated by an oil content of 3.50% is the oil shale area, which is 46,120 km². （4） Using the indirect parameter volumetric method, the estimated oil resource of surface dry distillation and in-situ transformation oil shale in the study area are 202×10⁸ t and 173×10⁸ t, respectively, with corresponding recoverable resources of 86×10⁸ t and 39×10⁸ t, respectively.

Ordovician fracture-cavity carbonate reservoirs in Lungu Oilfield of Tabei area represent a significant target for ultra-deep hydrocarbon exploration in China. Based on high-density seismic data, well logging, and dynamic production data, a multi-field coupling reservoir prediction theoretical framework integrating structure, karst, and fluid was established for Ordovician fracture-cavity carbonate reservoirs in Lungu Oilfield of Tabei area. Through quantitative characterization technology of fracture-cavity systems, the reservoir development patterns and main controlling factors of hydrocarbon enrichment were systematically revealed. The results show that: (1) Ordovician reservoir in Lungu Oilfield exhibits strong heterogeneity, and the reservoir space can be classified into four types: intercrystalline pores mainly develop in grain dolomite, with pore sizes ranging from 5 to 20 μm. Intergranular dissolution pores are mainly formed by selective dissolution of granular limestone, such as oolitic limestone, with pore sizes ranging from 50 to 200 μm, which are the main seepage channels of the reservoir. Microfracture widths are mostly less than 10 μm. Biogenic pores mainly develop in bioclastic limestone, commonly found in biological framework pores, such as crinoid stems, with pore sizes ranging from 100 to 500 μm. (2) Epikarst reservoirs are distributed in sheets over paleo-geomorphic highlands, subterranean river karst reservoirs exhibit bead-like distribution along paleo-water systems, and fault-controlled karst reservoirs are bead-string distributed along fault zones. Multi-attribute fusion and 3D geological modeling technologies can achieve holistic 3D spatial characterization of karst reservoirs. (3) The degree of hydrocarbon enrichment is controlled by karst facies-faults-reservoir scale. Class Ⅰ high-enrichment areas are concentrated in NE/NEE-oriented fault zones, with residual hill thickness greater than 90 m, effective porosity greater than 8%, and effective thickness greater than 550 m, forming a hydrocarbon accumulation model characterized by fault and fracture-cavity dual transport and multi-stage composite charging. Differentiated development strategies of “lateral tracking of epikarst reservoirs, 3D evaluation of subterranean river areas, and directional transportation of fault-controlled areas” can increase production capacity by 15%-30%, and add reserves of more than 200×10⁴ t.

Sequence stratigraphic concepts and methods provide novel tools for performing stratigraphic analysis, allowing us to improve our understanding of depositional models and basin evolution. Main controls and depositional elements (e.g. surfaces, systems tracts, parasequences, etc.) recognized in conventional sequence strati-graphy are designed for marine-related systems. In contrast, the sequence stratigraphy of lacustrine successions is much more complex, because it is not driven by sea-level changes, but by a complex interaction between tecto-nics and high-frequency climatic cycles. Through systematic analysis of lacustrine sedimentary systems, the re-levant concepts of lacustrine sequence stratigraphy were clarified. The controlling effects of allocyclic cycles on lacustrine sedimentation and sequence stratigraphy, accommodation space types of lacustrine basins and their significance for sequence stratigraphy and hydrocarbon genesis were explored.The results show that： （1） The lacustrine sedimentary conditions can be classified as three types: Underfilled, balanced-fill and overfilled lakes. There are significant differences in water salinity, sedimentary sequences, and system tracts under different lacustrine sedimentary conditions. Underfilled lakes are hydrologically closed lakes, and consequently, the lake-level can highly fluctuate, driven by high-frequency wet-dry climatic cycles. During wet periods, rivers supply water and sediments, resulting in fining-and thinning-upward elementary depositional sequences (EDS) accumulated during the transgressive systems tract (TST). In contrast, dry periods are characterized by a relative lake-level fall with the subaerial exposure of lake margin areas during the regressive systems tract (RST). Lake water salinity are brackish to hypersaline. Balanced-fill lakes are partially closed lakes, and consequently, they have characteristics of both underfilled and overfilled lakes. During the TST, the lake is in underfilled condition, and consequently, the introduction of water and sediment will accumulate a fining-upward interval until reaching the spill point during the maximum flooding. The RST is accumulated under an overfilled lake condition, with coarsening-upward progradational littoral deltas and related subaqueous delta deposits. Lake water salinity are brackish to freshwater. Overfilled lakes are hydrologically open lakes. Most deposits accumulate during the RST, forming coarsening-upward progradational littoral deposits, with associated subaqueous deltas. All overfilled lakes are freshwater lakes. （2） Subsidence is crucial for allowing the long-term preservation of lacustrine depo-sits. Lakes can temporarily store water and sediments in areas that lack subsidence, but these deposits will not be preserved in the stratigraphic record. Subsiding lakes develop permanent accommodation space and hanging lakes develop temporary accommodation space. Although hanging lakes cannot permanently store sediments,they can flood subsiding lakes with the near-instantaneous release of a substantial volume of water, creating favorable conditions for the accumulation of organic-rich shales. This rapid flooding from hanging lakes induced a forced transgression (FT), which is a large-scale rapid transgression (xenoconformity) not related to the normal sediment and water supply from local source areas.

In the middle to late stage of low-permeability condensate gas reservoirs development， rapid deliverability decline and reduced recovery due to condensate oil blockage often occur. Taking No. 1 sandbody in the second member of Jurassic Sangonghe Formation in Qianshao 4 well block in Mobei uplift of Junggar Basin as an example， a high-precision numerical simulation model was established by combining multi-scale parameters integration with wellstream phase-behavior correction， and remaining gas distribution prediction and potential-tapping schemes evaluation were conducted. The results show that：（1） The thickness of No. 1 sandbody in the second member of Jurassic Sangonghe Formation in Qianshao 4 well block in Mobei uplift of Junggar Basin is about 20 m，the average porosity is about 12%， the average permeability is about 1.5 mD， with strong heterogeneity and poor local connectivity. （2） Using data collaboration to constrain sandbodies distribution and porosity/permeability parameters， combining fluid composition inversion in condensate gas wells and bottomhole pressure coupling， an integrated model of “geology-phase behavior-wellbore” was established，significantly improving the characterization accuracy of sandbody architecture and porosity/permeability parameters. The correlation coefficients between the modeling porosity/permeability and measured values were greater than 0.99. The fitting accuracy between the calculation results of the model and historical condensate gas production is greater than 96%， revealing that the high part of well Qianshao 401 in the study area represents a typical remaining gas enrichment zone of “high gas saturation but poor connectivity”. （3） Based on remaining gas distribution， the proposed lateral drilling potential-tapping scheme for well Qianshao 401，can provide an additional recoverable reserve of 0.37×10⁸ m³ and increase daily gas production by 4×10⁴ m³. The prediction results suggest that the well can achieve stable production until 2030 if the constant gas recovery rate of 5.1% is maintained.

Allan diagram analysis is of great significance for the study of fault sealing. Taking Archean buried hill hydrocarbon reservoir in Xinglongtai structural belt of Liaohe Depression as an example, an improved Allan diagram method based on high-resolution geological modeling technology was proposed to analyze fault sealing by integrating well logging, 3D seismic, and experimental analysis and testing data. The results show that: （1） The high-resolution geological model established based on the well-seismic integration can address the issue of missing well-location data. Based on a detailed analysis of lithology development and fracture-forming capability in various regions of the metamorphic buried hill, the high-resolution geological model can accurately depict the stratigraphic contact relationship and lithology distribution pattern on both sides of the fault. After manual inspection and adjustment, the final improved Allan diagram can be formed. （2） There are six lithology docking patterns on the fault plane in the study area. The docking patterns with good sealing properties include breccia-mudstone, migmatite-mudstone, migmatite-gneiss, migmatite-breccia, and breccia-breccia. The peripheral faults F3 and F5 in the area are completely sealed, and the altitude of the leakage point in the area is -4 390 m. （3） Cross-verification was carried out by combining the fuzzy mathematics method and the on-site fluid distribution. The analysis results of each region were highly consistent with the lateral fault sealing analyzed by the improved Allan diagram method, indicating that the method shows excellent applicability and accuracy in metamorphic buried hills and has high application value.

Triassic Chang 7 member shale is the main source rock in Huanxian area of the western Ordos Basin. Through rock pyrolysis, total organic carbon measurement, gas chromatography-mass spectrometry, and AI-assisted comprehensive biomarker analysis， geochemical characteristics of crude oils and source rocks were systematically studied，the origin of crude oil and the proportion of hydrocarbon supply from mudstones and shales were clarified, and their hydrocarbon accumulation models were explored. The results show that： （1） Triassic Chang 7 member in the eastern Huanxian area is primarily developed shale,characterized by high organic matter abundance, favorable organic matter type, significant hydrocarbon generation potential. In contrast, the western part is dominated by dark mudstone, with TOC values ranging from 0.40% to 6.23%, hydrocarbon generation potential （S₁ + S₂） of 0.50-13.13 mg/g, organic matter types of TypeⅡ and Ⅲ, and an average vitrinite reflectance (R_o) of 0.84%, indicating a mature stage. It belongs to a medium-poor source rock with relatively lower hydrocarbon generation potential compared to shale. （2） Biomarker compositions of eastern shales and western mudstones are fundamentally similar, but significant differences exist in certain biomarker parameter ratios. Eastern shales exhibit low Pr/Ph ratios, high Ts/Tm, C₂₉Ts/C₂₉H, C₃₀*/C₂₉H, and C₃₀*/C₃₀H values. In contrast, western dark mudstones display relatively high Pr/Ph ratios, low Ts/Tm, C₂₉Ts/C₂₉H, C₃₀*/C₂₉H, and C₃₀*/C₃₀H values. These differences reflect the controlling effect of paleo-sedimentary environments on the development of mudstones and shales in the study area. （3） Chang 8 member in the study area develops three types of crude oil: Type A is crude oil predominantly from the eastern Chang 8 member, exhibiting high Ts/Tm and C₂₉Ts/C₂₉H values, along with relative high C₃₀*/C₂₉H and C₃₀*/C₃₀H values, type A is primarily derived from eastern shales. Type C, though currently less abundant, is characterized by low Ts/Tm, C₂₉Ts/C₂₉H, C₃₀*/C₂₉H, and C₃₀*/C₃₀H values, predominant sourcing from western mudstone. Type B, found in the western Chang 8 member, displays intermediate biomarker between type A and type C, with moderate Ts/Tm, C₂₉Ts/C₂₉H, C₃₀*/C₂₉H, and C₃₀*/C₃₀H values. It is a mixed crude oil composition dominantly contributed by eastern shales.

To address the challenges of determining mineral composition and improving porosity estimation in deep glutenite reservoirs, taking the tight glutenite reservoirs of Cretaceous Qingshuihe Formation in the southern margin of Junggar Basin as an example, an optimized logging interpretation method based on the beluga whale optimization (BWO) algorithm was proposed, and the computational results of this method demonstrate higher consistency with the laboratory analysis data of core samples. The results show that: （1） The process of BWO-based optimized logging interpretation for reservoirs is as follows: By integrating data of core, thin section, and scanning electron microscopy, a multi-composition volumetric physical model of the study area is established; based on conventional logging data, a logging response equation is established and then solve it with BWO algorithm; with the least squares method as the basic theory, an optimized logging objective function is established by combining multiple volumetric physical model and logging response equation. （2） The proposed method demonstrates excellent global and local search capabilities, fast convergence, high computational accuracy, and strong scalability. Test simulations showed that the objective function stabilizes after approximately 40 iterations during logging curve inversion. The calculated mineral contents show good correlation with actual data, with mean absolute errors below 1.50% and mean relative errors below 11.50%. （3） The primary minerals of deep glutenite reservoir in the southern margin of Junggar Basin are quartz, feldspar, calcite, dolomite, and clay. The absolute errors for mineral content and porosity calculated by the BWO-based optimized logging interpretation method and the measured core data are less than 3.00% and 0.26%, respectively, significantly outperforming conventional methods.

Sanmenxia Basin has considerable hydrocarbon exploration potential， but its overall exploration degree remains low. Focusing on Wumu Sag and Pinglu Sag， combined with measurements of source rock organic matter abundance， development characteristics of Paleogene sedimentary systems and source rocks were analyzed， and tectono-sedimentary evolution models and hydrocarbon accumulation conditions were clarified based on field outcrop observations， 2D seismic data， and drilling data. The results show that： （1） Paleogene in Sanmenxia Basin deve-loped five sedimentary facies and nine subfacies. Menli Formation is dominated by alluvial fan deposits. Podi Formation develops alluvial fan， fan delta， and lacustrine deposits. Xiao’an Formation is dominated by lacustrine deposits， and Liulinhe Formation mainly develops alluvial fan and braided river deposits. Different sags show significant differences in sedimentary filling， and facies belts are generally narrow and laterally migrate rapidly. （2） The tectono-sedimentary evolution of the basin has gone through 4 stages of “syn-rift to post-rift depression”. During the initial rifting stage， corresponding to Menli period， strong extension produced several isolated deep sags. During the intense rifting stage， corresponding to Podi period， basement experienced significant differential subsidence， leading to lake basin expansion and short-term lacustrine flooding. During the rift-depression transition stage， corresponding to Xiao’an period， the basin became interconnected and entered a relatively stable depositional stage， and the deep-lake reached its maximum scope. During the depression-subsidence stage， corresponding to Liulinhe period， tectonic activity tended to stabilize， and the lake basin gradually shrank and eventually disappeared. （3） Source rocks in the study area are mainly developed in the deep-lake black mud shale of Podi Formation and the deep to semi-deep lake gray-black mudstone of Xiao’an Formation. High-quality source rock samples account for 25% of the total， with Xiao’an Formation representing the principal source rock interval. In Wumu Sag， TOC values of Xiao’an Formation range from 0.29% to 31.10%， with an average of 2.06%， TOC values of Podi Formation range from 0.40% to 22.00%， with an average of 5.33%. The anomalously high TOC values or large fluctuations observed in some samples are related to outcrop preservation conditions and the development of coal streaks. （4） The study area mainly develops three types of hydrocarbon accumulation assemblages， including “self generation and self storage”， “lower generation and upper storage”， and locally “upper generation and lower storage”. Overall， it is characterized by near-source hydrocarbon supply and short-distance migration for reservoir formation， and the central structural belt represents the favorable exploration zone.

Through well-to-seismic calibration, establishment of different surrounding rock lithology-coal rock models, and wave equation forward modeling, the lithologies, coal rock thickness, and seismic response characteristics of Carboniferous Benxi Formation surrounding rock in northern Mizhi area of Ordos Basin were analyzed. Three thickness prediction methods of coal rock gas reservoir, such as amplitude fitting method, impe-dance inversion method, and reflection coefficient inversion method, were contrasted and evaluated. The results show that: （1） The geological conditions of Carboniferous Benxi Formation coal rock gas reservoir in Mizhi area are complex. The overlying lithology are mainly sandstone, limestone, and mudstone. Physical properties of coal rock and surrounding rock strata are significant different, coal rock are with characteristics of low natural gamma, low density, high neutron, high acoustic time difference, and high resistivity. Different surrounding rocks have a significant impact on seismic response characteristics of coal rock layers, and the planar distribution of surrounding rocks can affect the accuracy of coal seam thickness prediction. （2） During wave equation forward modeling for different lithological combinations, when the coal rock thickness is less than the tuned thickness of 12.5 m, the amplitude value increases with the increase of coal rock thickness.When the thickness of coal rock reaches 12.5 m, the amplitude value reaches its peak.When the thickness of coal rock is greater than 12.5 m, the amplitude value begins to slowly decrease as the thickness of coal rock increases. （3） The reflection coefficient inversion method is suitable for the evaluation and development stages of coal rock gas reservoirs. The coal rock top and bottom re-interpretation technology is less affected by amplitude,and the predicted thickness of coal rock gas reservoir in the study area shows the highest consistency with the actual thickness, reaching 88.9%.

Multi-stage activities of strike-slip faults of Fuman Oilfield in Tarim Basin significantly control hydrocarbon migration and accumulation in deep to ultra-deep reservoirs. Based on 3D seismic data interpretation of Fuman Oilfield， structural characteristics and tectonic evolution of F_I 5 fault， F_I 7 fault， F_I 16 fault， and F_I 17 fault were delineated， and their influences on hydrocarbon migration and accumulation were analyzed. The results show that： （1） F_I 5 fault， F_I 7 fault， F_I 16 fault， and F_I 17 fault primarily underwent four stages of tectonic evolution： Early Caledonian， episode Ⅰ of middle Caledonian， episode Ⅲ of middle Caledonian， and late Caledonian-early Hercynian. Among them， episode Ⅰ of middle Caledonian and episode Ⅲ of middle Caledonian were the main active periods. F_I 5 fault and F_I 17 fault were more active than F_I 7 fault and F_I 16 fault, with F_I 16 fault exhibi-ting the weakest activity. （2） F_I 5 fault and F_I 17 fault have source connectivity and improve the reservoir property. F_I 7 fault has no source connectivity， but its conductivity and reservoir improvement ability are good， while F_I 16 fault has poor source connectivity， conductivity, and reservoir improvement ability. （3） During late Caledonian， oil and gas underwent certain scale vertical charging along F_I 5 fault and F_I 17 fault， while migration and enrichment rarely occurred along F_I 7 fault， and the scale of vertical charging along F_I 16 fault zone was relatively small. In late Hercynian， large-scale vertical hydrocarbon migration and accumulation occurred along F_I 5 fault and F_I 17 fault. F_I 7 fault did not connect to hydrocarbon source， resulting in limited vertical migration and accumulation of oil and gas along it. Lateral migration and accumulation may have occurred and had a certain scale， while the scale of vertical migration and accumulation along F_I 16 fault was relatively small. （4） During Himalayan， Lower Cambrian source rocks in the eastern part of Fuman area entered the over-mature gas generation stage. While Middle Cambrian gypsum-salt layers failed to form an effective seal， leading to significant gas washing in petroleum reservoirs near F_I 16 fault and F_I 17 fault， resulting in an overall increase in gas-oil ratio.

The overall understanding of medium to small-scale basins onshore China is low, with not high degree exploration, and hydrocarbon potential and exploration direction remain unclear, but some basins have achieved large-scale oil and gas discoveries. By incorporating medium to small-scale basins across the country into a same basin type for overall systematic comparison, key geological factors for hydrocarbon accumulation in medium to small-scale basins were explored, and then strategic selection and favorable basin optimization for exploration in medium to small-scale basins were carried out to clarify the exploration direction. The results show that: （1） Tectonic domain and their activity process are key controlling factors that determine geological features of medium to small-scale basins in group. Primary basin groups are mainly developed in periphery of the relative large and stable tectonic domain, transformed remnant basins are mainly developed within the tectonically active zones and superimposed basins are mostly developed in areas experienced multi-phase tectonic activity. （2） Primary basins mainly develop Meso-Cenozoic lake-marsh coal measure strata and lacustrine mudstone source rocks, mainly with Ⅱ-Ⅲ type organic matter, and the abundance in some of basins are more than 0.5%, but the maturity in different basins, different strata and different parts of the same strata varies greatly. Partial transformed remnant basins develop source rock of Paleozoic marine or marine-terrestrial transitional carbonate and mudstone, mainly with Ⅰ-Ⅱ type organic matter, and the abundance in some of basins are more than 0.3%, and the overall maturity is high and in maturity to over-maturity phase. Source rocks in superimposed basins mainly develop within middle to lower assemblages. （3） Main factors that determine the enrichment of hydrocarbon in some medium to small-scale basins include: The primary basin has undergone a complete lake-basin infilling evolution, the uplift and erosion to the transformed remnant basin did not destroy the main part of high-quality source rocks, the late transformation of superimposed basin are favorable for the maturing and preserving of high-quality source rock. Which have undergone deep burial in late period. The basin region has deep thermal background, characterized by high geothermal gradients, which are conducive to the maturing of source rocks, large-scale migration of hydrocarbon and effective preservation of generated hydrocarbons. （4） Primary basins surrounding Ordos Basin, some transformed remnant basins in Pan-Hexi region, some strike-slip and pull apart basins along Tan-Lu fault zone, some Paleozoic remnant basins with lower degree of late modification and Cenozoic primary basins in the South, and middle to lower assemblages of some superimposed basins in stable areas of West are favorable for hydrocarbon exploration onshore China. The near-source exploration or along dominant paths of fluid migration is the key to hydrocarbon exploration in medium to small-scale basins, medium to small-scale basins have become an important replacement domain for onshore hydrocarbon exploration strategic selection of China.

The shale oil resource potential of continental petroliferous basins in China is significant，and heterogeneity of the mud shale reservoir controls its oil-bearing and fracability. Based on testings, such as core observation, total organic carbon (TOC) and pyrolysis, whole rock and clay mineral X-ray diffraction analysis, high-pressure mercury intrusion and nitrogen (N₂) adsorption experiment, heterogeneity characteristics of Triassic Chang 7 shale reservoir in Zhidan area of Ordos Basin were systematically revealed, and its control effect on shale oil enrichment was discussed. The results show that: （1） Triassic Chang 7 in Zhidan area of Ordos Basin is mainly composed of dark mudstone and black shale, which can be divided into felsic mudstone facies, clayey mudstone facies, and mixed shale facies. The macroscopic heterogeneity of different lithofacies is mainly influenced by terrestrial input,volcanic activity frequency, and sedimentary environments, manifested as the greater frequency of bedding distribution and more frequent changes in lithology, and stronger heterogeneity. On a microscopic level, from clayed mudstone, felsic mudstone to mixed shale, the heterogeneity gradually increases with the increasing frequency of bedding. （2） The mineral composition and TOC content of different lithologies vary significantly, exhibiting strong heterogeneity characteristics. （3） The pore types of Chang 7 mud shale re-servoir in the study area are diverse, including intergranular pores, intragranular pores, clay mineral intercrystalline pores, pyrite intercrystalline pores, and microfractures. The pore structure is mainly mesoporous, with pore diameters ranging from 10 to 100 nm, developing “ink bottle” shaped pores and parallel plate-shaped pores. （4） Lithology, mineral content, TOC content, and pore structure all have controlling effects on Chang 7 shale oil in the study area. Among them, lithofacies, TOC content and average pore diameter have relatively obvious positive correlations with oil-bearing property indicators, which are the main controlling factors for shale oil enrichment. The “sweet spot” segment of shale oil enrichment can be predicted by integrating the heterogeneity characteristics of mud shale, oil-bearing property, brittleness index and movable oil evaluation criteria.

Through comprehensive analysis of palynological assemblages, zircon U-Pb ages, and sedimentary sequences from Permian outcrops in Bogda piedmont on the northern margin of Tuha Basin, the stratigraphic attribution was re-evaluated, the lithofacies paleogeography during the deposition of Lucaogou Formation/Ta’erlang Formation around Bogda mountains was reconstructed, and the exploration potential of the area was discussed. The results show that: （1） The palynological assemblages originally assigned to Ta’erlang Formation in Zhaobishan and Ertanggou sections are significantly different from those of Ta’erlang Formation/Lucaogou Formation in Ta’erlanggou and eastern Junggar Basin, but consistent with those of Wutonggou Formation in eastern Junggar Basin, and thus should be revised as Wutonggou Formation. The regional dark strata originally placed at the top of Yierxitu Formation whose sedimentary sequence and volcanic rock ages can be compared with those of Lucaogou Formation around Bogda mountains, and should be classified as Ta’erlang Formation. Zircon ages indicate Early Permian, earlier than the previously considered Middle Permian. （2） During the deposition of Ta’erlang Formation, Bogda mountains served as the depositional center, and the piedmont zone was in the environment of saline semi-deep-lake to deep-lake facies to half saline semi-deep lake,with the potential to form high-quality source rocks. （3） Permian source rocks in Taibei Sag are of relatively good quality, especially those in the northern part of the sag. The northern piedmont zone lies above the hydrocarbon generation center and contains numerous untested structural traps. The wedge-shaped structures and piedmont deep layer are the prospective areas for new breakthroughs of the mature Permian petroleum system in Tuha Basin.

Chu-Sarysu Basin in Kazakhstan is a helium-rich basin. Through the geological characteristic analysis of helium-rich gas reservoirs in different tectonic units and different horizons of the basin, helium enrichment conditions of the basin was discussed, a helium enrichment model jointly controlled by helium sources and caprocks was established, revealing the direction of helium exploration in China. The results show that: （1） Helium has been found in all 5 sets of reservoir-cap combinations in different depressions of Chu-Sarysu Basin, showing the characteristic of helium enrichment throughout the basin. Helium enrichment is positively correlated with nitrogen and has no direct relationship with tectonic units or gas reservoir types, but shows differential enrichment among different horizons. The reservoir-cap combination composed of Lower Carboniferous Serpukhovian limestone-mudstone has the lowest helium content but the highest hydrocarbon gas content. While Permian subsalt sandstones have the highest helium content, with a volume fraction up to 0.68%, and low hydrocarbon gas content. （2） The Precambrian ancient uranium-rich bedrock, tectonic uplift since Triassic, poor source rocks, and multiple sets of caprocks development in the study area are basic conditions for helium enrichment in the basin. Helium coexists with sandstone type uranium deposits, and the development of sandstone type uranium deposits has an indicative effect on helium enrichment. Multiple sets of caprocks, such as salt rocks, gypsum rocks, and mudstones, combined with the small molecular size and strong diffusion capacity of helium, are important reasons for the formation of multi-layered helium enrichment. Meanwhile, the dilution of helium by hydrocarbon carrier gas is also an important factor causing differential helium enrichment in different horizons. （3） The basement and tectonic evolution of Junggar Basin in China are similar to those of Chu-Sarysu Basin. Carboniferous in eastern Junggar, Lunan, Shinan, and Santanghu basins represent promising targets for future helium exploration.

Traditional logging interpretation methods exhibit low accuracy in identifying fluid properties in tight sandstone reservoirs, in response to such problem, an intelligent identification method for reservoir fluid based on GWO-XGBoost model was proposed, and it was applied to Triassic Chang 8 tight sandstone reservoirs in Hongde area of Ordos Basin. The results show that: （1） Taking actual well testing data of Triassic Chang 8 tight sandstone reservoir in Hongde area of Ordos Basin as the target variable, nine logging curves, including acoustic, spontaneous potential, density, caliper, neutron, natural gamma, and three resistivity logs (AT 20, AT60, and AT90)，were selected as features parameters through principal component analysis. Then, key hyperpara-meters of XGBoost model were globally optimized using grey wolf optimization (GWO) algorithm. （2） GWO-XGBoost model has an accuracy of 96.55% in identifying reservoir fluid types, which is significantly higher than XGBoost, Random Forest (RF), and Support Vector Machine (SVM) models by 6.03%, 6.89%, and 22.41%, respectively. （3） In practical single-well applications, GWO-XGBoost model, through comprehensive analysis and nonlinear feature learning of multi-dimensional logging responses, effectively overcomes the common misclassification between low-resistivity oil layers and high-resistivity water layers in manual interpretation. This model exhibits high stability and reliability under complex reservoir conditions, providing effective technical support for improving the efficiency of tight sandstone oil and gas exploration and development.

Yaojie mining area in Minhe Basin has good exploration potential for coalbed methane. Using drilling, logging, and experimental testing data, the distribution and hydrocarbon generation capacity of coal seams in Yaojie mining area of Minhe Basin were systematically analyzed, and the coalbed methane accumulation condition and accumulation models of Jurassic No. 2 coal seam were clarified, and favorable areas were predicted. The results show that: （1） Yaojie mining area in Minhe Basin has been transformed by multi-stage tectonic movements, forming a coal-controlled fault of “first reverse and then positive”.The sedimentary facies are mainly river-swamp-lacustrine facies, No. 2 coal seam is distributed in a “thick in the east and thin in the west” belt shape and belongs to medium-stage fat coal, with longitudinal thermal evolution degree and vitrinite increa-sing with the increase of burial depth. The coal rock is dominated by semi-dark to semi-bright primary structural coal, with relatively developed pores but poor permeability. （2） The total mass volume of gas in the air-dried basis of No. 2 coal seam in the study area is 6.10-8.78 cm³/g, with an average of 7.53 cm³/g. The mass volume of methane is 1.18-6.72 cm³/g, with an average of 4.46 cm³/g. The gas component is dominated by CH₄, CO₂ and N₂. Vertically, the proportion of CH₄ increases as the burial depth increases and temperature-pressure rises. Horizontally, methane content shows a distribution pattern of high-values in the middle (Haishiwan syncline axis) and decreasing towards the north and south. （3） In the study area, the thickness of No. 2 coal seam is relatively large, mostly greater than 10 m, and No. 2 coal seam has a high degree of thermal evolution (R_o up to 1.12%), providing material foundation for coalbed methane enrichment. Vertically, increased vitrinite content and decreased ash content optimize storage conditions. Carbonaceous mudstone/mudstone roof/bed plates, sealed water bodies, boundary fault zones, and Haishiwan syncline jointly ensure the accumulation of coalbed methane. The areas with high thermal evolution degree, sufficient gas source, proximity to syncline core and far away from faults are geological class Ⅰ “sweet spot” zones.

Microseismic monitoring technology faces challenges, such as difficulty in weak signal identification, low real-time processing efficiency, and weak microseismic response to fractures in shale gas fracturing ope-rations. To address these issues, a high-precision microseismic event identification method was proposed based on source scanning algorithm (SSA), incorporating a multi-level collapse grid search approach. Real-time loca-lization was achieved using GPU parallel computing technology. The results show that:（1）Through the wavefield energy scanning and superposition mechanism, dynamic correction and coherent superposition are performed on virtual sources to enhance characteristics of weak P-wave signals. Combined with the multi-level collapsing grid search strategy of “coarse grid global scanning + fine grid local precise searching”, the positioning efficiency and accuracy are improved simultaneously. After introducing the GPU-parallelized narrow band fast marching method (FMM), the traveltime calculation efficiency is increased by about 16 times. （2） Numerical experiments show that under low signal-to-noise ratio conditions, the positioning result of the multi-level collapse grid search is close to the real source, and its accuracy is superior to that of the single coarse grid search. In the application of a drilling platform, event points obtained by this method and the conventional method show a northeastward zonal distribution, the event depth can extend up to 300-400 m, the hydraulic fracture event points are more concentrated around the wellbore, and more weak energy events can be identified. （3） In the monitoring of shale gas fracturing construction in Sichuan, characteristics of hydraulic fractures and induced natural fractures can be distinguished from multiple dimensions. Spatially, the former gathers near the wellbore of the current fracturing section with regular morphology, while the latter is far from the fracturing section with irregular and asymmetric distribution. Temporally, events of the former are concentrated during the fracturing construction period, while the latter has significant aftereffect and continues to occur within 30 minutes after pump shutdown. In terms of waveform, the former has high dominant frequency, clear direct wave and simple structure, while the latter has low dominant frequency, long energy duration and multiple subsequent waves. In terms of relative magnitude, the former is generally low, while the latter is high, corresponding to a larger fracture scale. Combined with the relative magnitude and spatial distribution characteristics of events, distribution models of “natural fracture response zone” and “fracturing main control zone” can be constructed, providing a reliable basis for fracturing effect evaluation and geological interpretation.

Paleogeomorphologic framework exerts significant control on the spatial distribution of facies-controlled carbonate reservoirs. Based on geophysical data such as core thin sections, conventional logging data, the original thickness of individual wells in Triassic Feixianguan Formation was restored in Puguang area through analysis of differential compaction and pressure dissolution of lithofacies. Combined with 3D seismic data, the paleogeomorphology was reconstructed, and the structural subsidence of individual wells was identified using the INPEFA curve. The decompaction and pressure dissolution restoration results were integrated to further refine the paleogeomorphology during the depositional period. Research results show that: （1） Feixianguan Formation in Puguang area develop seven major rock types, including granular dolomite, micritic-granular dolomite, crystalline dolomite, micritic dolomite, granular limestone, micritic-granular limestone, and micritic limestone. Based on compaction recovery coefficients and pressure dissolution recovery coefficients, decompaction coefficients of different lithofacies were calculated. Granular dolomite exhibits the smallest decompaction coef-ficient of 1.25, indicating little change between its present-day thickness and original sedimentary thickness, whereas micritic limestone exhibits a relatively large decompaction coefficient of 3.09, with its present-day thickness differing by more than two times from the original thickness. （2） The identification of tectonic subsidence using the INPEFA method is a single-well sequence identification technique based on GR curve trend spectrum analysis. Combined with Walther’s law, the key mechanism of this method for identifying tectonic subsidence was clarified, and the INPEFA mean value of 0.5 was used as the threshold to distinguish normal sedimentary areas and tectonic subsidence areas. （3） The distribution of shoal deposits is controlled by paleogeomorphology and tectonic subsidence. In tectonic stable areas, shoal deposits are concentrated in high parts of the paleogeomorphology; whereas in tectonic active areas, shoal deposits develop in regions with positive paleogeomorphology and the INPEFA mean value of less than 0.5. （4） The accuracy of paleogeomorphology restored through decompaction, pressure dissolution, and tectonic subsidence analysis has been significantly improved, which can effectively identify and eliminate spurious topographic highs caused by differential subsidence, thus more clearly revealing controlling effects of paleogeomorphology on the development of high-quality reservoirs.

Lower Jurassic Lianggaoshan Formation and Ziliujing Formation lacustrine facies dark mud shales widely develop in eastern Sichuan Basin, making them key fields for shale oil and gas exploration. Through the description and sampling analysis of key drilling and typical stratigraphic profiles, lithofacies combinations of terrestrial shale were classified, and comparative analyses were conducted on reservoir formation conditions of shale oil and gas in different lithofacies. The results show that: （1） Lower Jurassic terrestrial shale series in eastern Sichuan Basin exhibit fast sedimentary facies changes and complex lithofacies combinations. Compared with Lower Paleozoic marine shales, they have geological characteristics of “multiple development layers, large cumulative thickness (40-115 m), small single-layer thickness (< 25 m), poor continuity”. （2） Lower Jurassic continental shale in the study area can be divided into three categories: siliceous shale, clayey shale, and shell calcareous shale. Lithological characteristics of different lithofacies types vary greatly and are mainly controlled by their original sedimentary environment. （3） The hydrocarbon generation capacity and storage performance of laminated carbon-bearing clayey shale and carbon-bearing shell-bearing clayey shale are relatively good, organic types of the shale are mainly mixed type of sapropelic mud (mainly type Ⅱ₁), with TOC generally exceeding 1.2%. Organic matter pores and microcracks are well-developed, with effective poro-sity mostly above 3.0%, which have favorable conditions for hydraulic fracturing and transformation, and also are favorable lithofacies types for oil and gas enrichment and accumulation. （4） Favorable areas for shale hydrocarbon accumulation in Lianggaoshan Formation of the study area are distributed in Wanzhou-Liangping area and Dianjiang-Fengdu area. Favorable areas for hydrocarbon accumulation in Da’anzhai section of Ziliujing Formation are distributed in Liangping-Kaijiang-Wanzhou area. Favorable areas for hydrocarbon accumulation in Dongyuemiao section of Ziliujing Formation are distributed in Dianjiang-Liangping-Zhongxian area.

Focusing on Cretaceous Sa-Pu reservoir in eastern Daqing placanticline, the occurrence state and evolution of microscopic remaining oil under different permeability conditions were systematically investigated by integrating high-resolution computed tomography （CT） scanning with water flooding experiments. Numerical simulations of relative permeability and wettability were conducted to formulate strategies for enhanced oil recovery. The results show that: （1） Cretaceous Sa-Pu reservoir in eastern Daqing placanticline is characterized by an average pore-throat radius of 6.1-8.0 μm, pore-throat ratioof 2.1-2.4, and connected porosity exceeding 95%. The pore throat structure of high permeability reservoirs (> 150.0 mD) is relatively homogeneity and well connected, while low-permeability reservoirs (< 50.0 mD) with strong heterogeneity, a disparity that fundamentally go-verns oil-water two-phase flow behavior and remaining oil spatial distribution. （2） The water flooding experiment and CT scanning results of core samples in the study area show that: microscopic remaining oil was identified as four types of occurrence state, such as network-like, pore-clustered, oil-film, and isolated-droplet forms. During water flooding, the remaining oil morphology evolves primarily from network-like to pore-clustered. In the early stage of displacement, well-connected network-like oil is dominated, and the recovery factor increases rapidly. As displacement progresses, in the middle and later stages, remaining oil becomes predominantly trapped in pore throats as pore clusters, resulting in a significant decline in oil displacement efficiency and a rapid rise in water-cut. Reservoir permeability is a key factor in controlling the evolution of the remaining oil morphology. High permeability reservoirs have longer low water-cut periods and higher ultimate recovery factor due to the more developed initial network-like oil. (3) Numerical simulations reveal Sa-Pu reservoir’s strong oil-wet nature, demonstrating that wettability reversal technology significantly enhances oil-phase mobility, with an average reduction in trapped oil saturation of 8.9%. (4) Differentiated development strategies based on permeability grading are proposed in the study area. Well pattern optimization is recommended at the high water-cut stage for high-permeability reservoirs, followed by wettability reversal and chemical flooding at the extra-high water-cut stage. Wettability reversal is implemented during the medium water-cut stage for medium-permeability reservoirs, and wettability reversal combined with chemical flooding are implemented during medium-to-low water-cut stages for low-permeability reservoirs.

Comprehensively utilizing data from core observation, thin section identification, logging interpretation, physical property analysis, and geochemical testing, reservoir characteristics and main controlling factors of carbonate reservoirs in the second member of Lower Triassic Jialingjiang Formation in Puguang area of Sichuan Basin were systematically analyzed. The coupling mechanism between tidal flat deposition controlled by paleogeomorphology and multi-stage diagenetic modifications was clarified, an evolution model for high-quality reservoirs was established, and favorable exploration areas were predicted. The results show that: （1） In Puguang area, reservoir rocks of the second member of Lower Triassic Jialingjiang Formation are dominated by granular dolomite and silt-sized crystalline dolomite, reservoir spaces mainly include intergranular dissolved pores, intercrystalline dissolved pores, and fractures. Reservoirs are generally of low porosity and low permeability, with local occurrences of high porosity and high permeability or low porosity and high permeability. （2） In the study area, compaction and cementation lead to the reduction of primary pores, while dolomitization forms intercrystalline pores and enhances compaction resistance. The seepage-reflux model and evaporation-pumping model represent formation mechanisms of the silt-sized crystalline dolomite and micritic dolomite, respectively. Penecontemporaneous meteoric freshwater dissolution superimposed with burial-stage organic acid dissolution significantly improves the pore structure, and the high-angle fracture network formed by tectonic fracturing enhances reservoir porosity and permeability. （3） Reservoir development of the second member of Jialingjiang Formation in the study area is dually controlled by sedimentary microfacies and diagenesis. Relatively high-quality reservoirs are mainly formed in granular shoal and dolomitic flat microfacies. Dolomitization and dissolution are key factors to the development of high-quality reservoirs, and fracturing improves reservoir connectivity. （4） Class I favorable exploration areas of the second member of Jialingjiang Formation in the study area are mainly distributed in Shuangmiaochang area, which are subfacies of intra platform shoals. There are 5 favorable exploration areas of Class Ⅱ, which develop intra platform beach facies, and distribute in Shuangmiao-chang, Qingxichang, Maoba, and Fenshuiling areas. There are 3 favorable exploration areas of Class Ⅲ, with the development of dolomitic flat, gray flat microfacies or intra platform beach subfacies, which distribute in Chuanfu 85 well area, Ming Ⅰ well area, and Leiyinpu area.

Lower Triassic Jialingjiang Formation in Sichuan Basin is an important natural gas reservoir system, where typical carbonate-evaporite paragenesis systems are widely developed. Based on core, thin section, and master logging data, the classification of paragenesis system types, sedimentary microfacies identification, and main controlling factors of sedimentary evolution of Triassic Jialingjiang Formation in the southeastern Sichuan Basin were systematically conducted, and distribution patterns of carbonate-evaporite paragenesis systems were clarified. The results show that： （1） Carbonate-evaporite paragenesis systems of Triassic Jialingjiang Formation in the southeastern Sichuan Basin can be classified into three major categories and five subcategories: overlapped type (carbonate rock overlying evaporite and evaporite overlying carbonate rock), interbedded type (carbonate rock and evaporite interbedded ), and intercalated type (evaporite intercalated with carbonate rock and carbonate rock intercalated with evaporite). A total of 11 paragenesis system microfacies types were identified, including gypsum, gypsiferous dolomite, gypsiferous limestone, micritic dolomite, finely crystalline dolomite, granular dolomite, and bioclastic limestone, and 7 types of microfacies associations were summarized. （2） The formation and distribution of the carbonate-evaporite paragenesis systems in the study area are controlled by the coupling of sea level fluctuations and paleogeomorphology. High-frequency sea level cycles dominate the vertical evolutionary sequence, while the paleogeomorphological framework shaped by paleo-uplifts and paleo-depressions constrained the lateral distribution patterns of paragenesis systems. （3） The “carbonate rock overlying evaporite”subtype within the overlapped category and the interbedded paragenesis systems exhibit good reservoir-caprock configurations and relatively superior preservation conditions.