In order to improve the evaluation effect of rock mechanical parameters of Lucaogou Formation in Jimsar Depression， rock mechanical parameters such as compressive strength and elastic modulus were obtained by carrying out mechanical tests such as uniaxial/triaxial compression， Brazilian cleavage and fracture toughness. Combined with Pearson correlation coefficient， the influencing factors were analyzed， and the prediction model of rock mechanical parameters of Lucaogou Formation was constructed. The results show that there are obvious differences in rock mechanical characteristics of different lithology in Lucaogou Formation. The key factors affecting rock mechanical parameters are P-wave velocity， density and clay mineral content. The prediction model of rock mechanical parameters is established. The correlation coefficients are more than 0.8， and the average relative error is less than 15%. Based on the acoustic time difference， density and gamma logging information， the rock mechanical parameters of Lucaogou Formation in the study area are calculated. The average relative error between the formation fracture pressure obtained based on this and the measured value of fracture pressure is 2.32%. The logging prediction method of rock mechanics parameters established by comprehensively considering the effects of acoustic velocity， density and shale content provides reliable rock mechanics data support for wellbore stability evaluation and fracturing operation of shale oil reservoir.
Tight sandstone gas reservoirs are characterized by low porosity， low permeability， and strong non-homogeneity. Fracturing is required for development， and post-fracturing production capacity is influenced by multiple factors， making accurate prediction difficult. Based on the concept of geo-engineering integration， engineering parameters， physical parameters， and logging parameters were comprehensively considered. A mutual information coefficient model was applied to identify the key factors controlling production capacity， and a Sparrow Search Algorithm （SSA） optimized Random Forest （RF） model was established for prediction. Taking the Qingshimao Gas Field as a case study， model performance was evaluated using root mean square error， mean squared error， mean absolute error， and coefficient of determination， and compared with RF models optimized by Particle Swarm Optimization （PSO） and Butterfly Optimization Algorithm （BOA）. The results show that RLLD， GR， SH， SD， VOE， and CNL are key factors， with resistivity being the most significant. Parameter tuning through SSA by adjusting population size， iteration number， and cross-validation effectively improved prediction accuracy. The proposed SSA-RF model outperforms PSO-RF and BOA-RF， providing a reliable approach for post-fracturing productivity evaluation of tight sandstone gas reservoirs.
The Ledong Diapir Zone in the Yinggehai Basin exhibits substantial exploration potential. However， this area is characterized by abundant shallow gas accumulations and well-developed faults and fractures. These features manifest seismically as blank-weak or chaotic reflection patterns， hindering the reliable interpretation of internal structures， stratigraphy， and geological bodies within the diapir zone， thereby severely constraining exploration evaluation studies. To enhance imaging within the diapir-obscured zones， delineate structural features， and identify favorable reservoirs， this study employed forward modeling to clarify the causes of seismic obscuration. A targeted approach combining multiple attenuation and energy restoration techniques was implemented for structural imaging. Furthermore， seismic response analysis for identifying structures and reservoir bodies within the diapir zone was conducted， establishing an integrated seismic-geological technical workflow for imaging， structural interpretation， and reservoir identification in diapir-obscured zones. Studies show that： （1） The primary causes for poor imaging in the diapir zone are multiples generated by shallow gas and its absorptive/scattering effects （gas shadow）. Generalized 3D Surface-Related Multiple Elimination （SRME） and a “two-step” energy restoration method can effectively suppress strong diffracted multiples， improve the signal-to-noise ratio， and recover energy within blank reflection zones. （2） The Ledong 2X diapir structure is a NW-SE trending elongated anticline， featuring two culminations （northern and southern）. The northern culmination exhibits weaker diapiric activity and minimal faulting， representing a favorable hydrocarbon accumulation site. （3） The Ledong 2X diapir zone develops turbidite sand， slope fans， and coastal sand reservoirs， exhibiting low-frequency strong amplitude seismic anomalies. In conclusion， integrated research focusing on imaging， structural analysis， and seismic reservoir characterization within the diapir-obscured zones has confirmed the presence of advantageous structures and reservoirs within the Ledong 2X diapir. This area represents a significant domain for expanding hydrocarbon reserves. The methodologies and findings presented in this study provide valuable insights for offshore hydrocarbon exploration in diapir-affected regions.
In order to investigate the hydrocarbon distribution characteristics at the Huhenuoren Fault in the Beier Sag of Hailar Basin， a three-time-node-active period， cessation of faulting， and the present time-is established to characterize the vertical sealing behavior of faults in mudstone caps. Specifically： during the active period， the longitudinal sealing capability of the fault within the mudstone caprock was determined by the paleo-mudstone content of the fault infill material and the maximum required thickness for vertical connection within the mudstone caprock； during the cessation of activity， the longitudinal sealing capability of the fault within the mudstone caprock was determined by the paleo-mudstone content of the fault infill material and the minimum required mudstone content for longitudinal sealing； and after the current cessation of activity， the longitudinal sealing capability of the fault within the mudstone caprock was determined by the mudstone content of the fault rock and the minimum required mudstone content for longitudinal sealing. The longitudinal sealing capacity of the Lower Cretaceous about the lower first member of Damoguaihe Formation （Lower First Member） within the Huhenuoren fault zone was evaluated at three distinct time points， the results show that at study sites 1-3， 5， 7-8， and 12-15， the Huhenuoren Fault exhibits vertical sealing within the Lower Member I mudstone caprock at all three time intervals. Conversely， at sites 4， 6， and 9-11， the fault does not provide vertical sealing at any of the time intervals；Thus， sites 1-3， 5， 7-8， and 12-15 are favorable locations for hydrocarbon accumulation and preservation in the Nantun Formation second section （southern second section） of the fault. This is the fundamental reason why hydrocarbons have been observed at sites 7-8 and 12-15 in the southern second section of the Huhenuoren Fault， whereas sites 1-3 and 5， though vertically sealed， have not accumulated hydrocarbons due to their position in structural lows with insufficient hydrocarbon supply.
In order to clarify the characteristics and controlling factors of tight sandstone reservoirs with early continuous deep burial and late shallow burial， taking the fourth member of the Xujiahe Formation in the Jianyang area， Sichuan Basin as an example， through a large number of core and thin section observations， as well as experimental analysis such as laser confocal microscopy， field emission scanning electron microscopy， and CT， it is proposed that under high and low temperature gradients and early continuous deep burial and late shallow burial conditions， compaction and cementation lead to reservoir densification， dissolution and fracture effectively improve reservoir properties. The research results indicate that： （1） In the Jianyang area， the sand bodies of the subaqueous distributary channels in the front edge of the braided river delta of the fourth segment are stacked and connected， with large thickness， coarse particle size， and wide distribution area， laying the foundation for the development of tight sandstone reservoirs； （2） The storage space types of the tight sandstone reservoir in the fourth section of the Jianyang area are mainly intergranular dissolution pores and intragranular dissolution pores. The reservoir has low physical properties and poor pore structure. The diagenesis of the reservoir mainly undergoes compaction， cementation， and dissolution. The compaction effect is the main reason for the densification of the Xu-4 reservoir in the Jianyang area， while the cementation effect leads to further densification of the reservoir. The network of pore and fracture systems formed by dissolution and fracture formation is the “sweet spot” distribution area of the fourth member of Xujiahe Formation tight sandstone reservoir.
The Middle Permian Maokou Formation in Central Sichuan has great resource potential to form high-quality reserves of 100 billion cubic meters of natural gas. In view of the problem that the distribution characteristics and main controlling factors of gas and water in the area are not clear， the fluid geochemical characteristics are clarified by comprehensively using indoor core experimental data， logging interpretation results， three-dimensional seismic data and production performance data， the distribution characteristics of gas and water are revealed， and the geological factors affecting the distribution of gas and water are further discussed. The results show that the natural gas of Maokou Formation in Central Sichuan is mainly composed of methane， which belongs to the origin of crude oil cracking. The formation water is characterized by CaCl2 type， and its chemical characteristics show that this area is a favorable area for oil and gas accumulation and preservation； The thickness of the gas water transition zone is closely related to the reservoir quality. The reservoir characteristics of low porosity， ultra-low permeability and strong heterogeneity lead to the wide distribution of the gas water transition zone； There are several independent gas water systems in this area， and there is no uniform gas water interface. The gas water distribution mainly has three modes：Vertical differentiation， fault diversion and heterogeneous retention， showing the characteristics of differentiated gas water production； The distribution of gas and water is controlled by many factors， such as reservoir physical properties and heterogeneity， tectonic amplitude， fault activity sequence， hydrocarbon source rock distribution and so on. It is proposed that “dominant lithofacies-local high amplitude structures-early faults-strong hydrocarbon generation”is the preferred standard for sweet spot areas. The research results can provide key theoretical basis for the evaluation of favorable exploration zones and the optimization of development well locations in Maokou Formation， and have important reference significance for the efficient exploration and development of similar low-permeability carbonate gas reservoirs.
Previous studies on hydrocarbon charge dating in the Shaximiao Formation of Jinqiu Gas Field in the central Sichuan Basin are rather sparse and unsystematic， resulting in insufficient understanding of gas accumulation formation and adjustment process. It is of great importance to further clarify hydrocarbon charging history and to understand dynamic evolutions of gas accumulations of Jinqiu Gas Field. An integrated fluid inclusion method of petrography， micro-fluorescence spectroscopy， microthermometry， laser Raman spectroscopy， and paleo-pressure simulation has been employed， combined with the thermal/burial history simulation of typical wells and hydrocarbon generation history simulation of source rocks. The results show that oil inclusions and methane gaseous hydrocarbon inclusions occur in the Shaximiao Formation reservoirs in the study area. Those hydrocarbon inclusions are mainly distributed in healed microfractures within and cutting through quartz grains， and within quartz overgrowths and carbonate cements in the middle diagenetic stage. The aqueous inclusions， coeval with oil inclusions and gaseous hydrocarbon inclusions， have homogenization temperature ranges from 103.8 to 145.0 ℃ and from 81.3 to 149.0 ℃， respectively. Burial history modeling indicates that the reservoirs were buried to the maximum depth at the end of the Early Cretaceous followed by tectonic uplift since the Late Cretaceous to the present-day. The activity history and intensity of hydrocarbon source-related faults directly affected oil and gas supply. The reservoirs undergone two periods of hydrocarbon charge： the end of early Cretaceous to middle Paleocene （104-59 Ma）， the end of Oligocene to the present-day （24-0 Ma）. During hydrocarbon charge and accumulation， the Longquanshan fault， Jiao-1 flaut， Lianghe-1 fault and those normal faults cutting the Lower Jurassic were activated， and the gas from the Xujiahe Formation and the oil from the Lower Jurassic migrated vertically along faults and leaked into and accumulated in the Shaximiao Formation. During the first charging period， the reservoirs were medium-over pressured， and then changed to normal and abnormally low pressure state during uplift. The research results are of great significance for the tight sandstone gas exploration and deployment of the Shaximiao Formation in central Sichuan Basin
A number of shale gas wells have been drilled with good gas measurement in Xiaoheba Formation in Nanchuan area， Southeast Chongqing. To analyze the natural gas exploration potential of the Xiaoheba Formation， the gas accumulation conditions and accumulation models of the Xiaoheba Formation in Nanchuan area were analyzed based on outcrop， core， well logging， experimental analysis and seismic data. The results show that： （1） The Xiaoheba Formation in the Nanchuan area is a deltaic front and pre-deltaic deposit， mainly composed of siltstone and argillaceous siltstone， with a relatively large thickness. （2） The lithology is tight， showing the characteristics of strong compaction. With an average porosity of 0.84% and an average permeability of 0.1×10-3 μm2， it is an extremely low porosity and tight reservoir. The reservoir space is dominated by micro-fractures and corrosion pores， forming a pore-fracture reservoir. The low mercury removal efficiency indicates that the reservoir has strong horizontal and vertical heterogeneity. （3） There is no obvious correlation with gas measurement and the structure. Adjacent wells on the same platform are different from gas survey locations and thickness， presenting the characteristics of fractured gas reservoirs. （4） Based on the prediction of curvature and seismic properties of the ant body， it is believed that the through-source fractures are the natural gas migration channels of the Xiaoheba Formation. （5） Due to the lateral sealing of Xiaoheba Formation and the sealing of the overlying Hanjiadian Formation， natural gas gathered in the fracture and formed a fractured reservoir accumulation model. The research results guide the Xiaoheba Formation in the upper return fracturing of the old well， which has made a breakthrough in the exploration of Xiaoheba Formation in Nanchuan area. And the research results have important guiding significance to Xiaoheba Formation in Sichuan Basin.
In response to the issue of numerous， redundant， and complexly interpreted biomarker parameters in the field of molecular geochemistry， this paper proposes a novel comprehensive index evaluation method. Focusing on the Yanchang Formation in the Ordos Basin， the study employs factor analysis to screen out biomarker parameters most closely related to organic matter maturity， parent material type， and water salinity. Three comprehensive indices， namely Maturity Index （MI）， Parent Material Index （PMI）， and Water Salinity Index （WSI）， are constructed through linear combinations of these selected parameters. Applications of these comprehensive indices in different layers and blocks of the Yanchang Formation demonstrate their ability to represent the geochemical characteristics of organic matter more concisely and clearly， with higher accuracy and reliability compared to single parameters. Research findings based on these indices reveal that the maturity of organic matter in the Yanchang Formation gradually increases with depth， the Chang 7 oil group exhibits a significant aquatic origin of organic matter， and deeper oil groups such as Chang 9 and Chang 10 have relatively higher water salinity. Additionally， the distribution patterns of maturity， parent material type， and water salinity across different blocks on the plane are complex， indicating the diversity of geological features. The comprehensive index method proposed in this paper provides a new perspective for molecular geochemistry research and holds significant importance for oil and gas exploration under complex geological conditions.
The Shenmu Gas Field， located in the northeastern Ordos Basin， is currently in a phase of efficient development and continuous production expansion， with the S51 well block serving as a core area where the Permian Shanxi Formation acts as the main gas-producing layer. Although the well block exhibits significant reservoir concentration， the distribution patterns of remaining gas remain unclear. To address this issue， this study conducts a detailed analysis of sand body stacking patterns based on well logging， mud logging， core observations， and cast thin sections， the relationship between sand body stacking patterns and remaining gas distribution was systematically investigated by integrating sedimentary facies， reservoir properties， and gas reservoir characteristics. The results show that the second Member of Shanxi Formation in the S51 well block is dominated by delta plain subfacies， with medium- to coarse-grained sandstones exhibiting massive and parallel bedding， while dissolution pores constitute the primary reservoir space. Single sand body stacking patterns are classified into isolated， superimposed， and vertically incised-overlapping types vertically， and separated， abutted， and laterally incised-overlapping types horizontally. Among these， the laterally and vertically incised-overlapping sand bodies demonstrate better physical properties and higher gas saturation. Combined with gas reservoir plane and profile analyses， multi-stage lateral and vertical incision and overlapping of sand bodies， along with structural highs， are found to be more favorable for gas accumulation. These findings provide valuable guidance for future remaining gas potential assessment and development optimization in the Shenmu Gas Field.
Current research on the control of multiple detachment layers on the tectonic pattern in the eastern Kuqa Depression， including the Neogene Jidike Formation gypsum-salt rock， the Cretaceous Shushanhe Formation mudstone， and the Triassic-Jurassic coal-bearing strata， is relatively weak. Through field geological investigation and high-precision 3D seismic data interpretation， the structural deformation style in the eastern Kuqa Depression was established. By comparing and analyzing the control of ancient uplifts， gypsum and salt rocks， mudstone， coal-bearing strata， tectonic stress， and different lithological combinations on structural deformation， and combining numerical simulation experiments and balanced section restoration， the characteristics， controlling factors， and deformation mechanisms of coal-related structural deformation in the eastern Kuqa Depression were systematically analyzed. The study suggests that the basement ancient uplift controls the soluble space and deformation space range of the Mesozoic coal-bearing strata and mudstone. The common point of the control of gypsum and salt rocks， mudstone， and coal-bearing strata on the structure is that they influence or change the structural deformation style by increasing the plasticity of the strata. On the surface of the plastic layer， detachment thrust structures usually develop， while basement-involved structures develop beneath the plastic layer. Strongly plastic layers flow and accumulate to thicken， while weakly plastic layers locally detach and stack vertically. Non-plastic layers undergo overall thrust deformation. The coal-bearing strata in the eastern Kuqa Depression are the main factor controlling structural deformation. The number， thickness， and burial depth of coal seams， together with the basement ancient uplift， jointly control the structural deformation. The number of coal seams controls the development scale and amplitude of thrust faults； more coal seams result in more developed multi-layer thrust structures， wider coal-bearing structures， and greater uplift amplitudes. The thickness of coal seams controls the deformation mode； thin coal seams mainly undergo basement-involved deformation， while thick coal seams undergo plastic detachment and folding deformation. The burial depth of coal seams controls the amplitude of structural deformation and the deformation style of coal-bearing structures. The basement ancient uplift controls the scale and range of the thrust belt； thrust faults disappear where the coal seams pinch out. In the eastern Kuqa Depression， with the coal-bearing strata as the detachment surface， layer-by-layer detachment， vertical stacking， and cooperative deformation occur during compression. In the Dibei2–Ixi1 well section， the coal-bearing strata are thick and strongly thrust， with multi-layer detachment and stacking of coal-bearing strata. The coal-bearing structures are relatively simple， arranged in rows and belts， and develop trap styles such as wedge-shaped thrusts， fault-type layer slides， fault blocks， and sudden structures， with significant potential for oil and gas exploration.
Reservoir research is central to the exploration and accumulation studies of shale gas. Accurately characterizing the pore structure of shale is crucial for elucidating the gas storage conditions and migration capabilities. Taking the Longmaxi Formation shale in the Luzhou area as a case study， we developed a method for quantitative characterization of shale pore structures based on gas adsorption and large-scale scanning electron microscopy （SEM）. The results indicate that： （1） The pore types within the Longmaxi Formation shale include clay mineral interlayer pores， dolomite dissolution pores， pyrite intercrystalline pores， feldspar and dolomite dissolution pores， intramineral fractures， and organic matter pores. Notably， organic matter pores account for 72.93% of the total pore area， while dissolution pores contribute about 14.04%， and intergranular pores make up approximately 13.03%； （2） Our proposed method for the quantitative characterization of shale pore structures， integrating gas adsorption and large-scale stitching SEM， demonstrates that micropores predominantly contribute to the total pore volume， with macropores and mesopores contributing similarly. This approach， which combines gas injection techniques and imaging observations， addresses the inaccuracies encountered in traditional fluid injection methods for larger meso- and macropores， offering new insights for the study of pore structures in shale and unconventional reservoirs.
The second member of the Kongdian Formation （Ek 2） in the Cangdong Sag， Bohai Bay Basin， hosts a set of organic-rich shale intervals， which are the key targets for shale oil exploration. However， due to the lack of constraints from a high-resolution sequence stratigraphic framework， the controlling factors of shale sedimentation remain unclear. Taking Well G108-8 in the Cangdong Sag as a case study， through wavelet transform analysis of GR logging data， a high-frequency sequence stratigraphic framework at the sixth-order scale was established. By integrating geochemical testing data and X-ray mineral diffraction （XRD） analyses， the mineral distribution characteristics， organic geochemical characteristics， shale sedimentary environment characteristics， and their controlling factors within high-frequency sequences were systematically studied. A shale sedimentary assemblage model driven by paleoclimate was established. The results demonstrate that： （1） The organic-rich shale of the Ek 2 was divided into 21 sixth-order sequences （SQ1-SQ21）， which are classified into three sedimentary stages based on sedimentary environment evolution characteristics： rapid lake transgression phase（SQ1-SQ6），oscillating lake transgression phase（SQ7-SQ17），and stable highstand phase（SQ18-SQ21）. The shale lithofacies are dominated by felsic， calcareous-dolomitic， and mixed shales， with organic matter dominated by Type I and II1 kerogen， collectively within the oil generation window. （2） During shale deposition， the enrichment of organic matter and mineral composition were primarily controlled by paleoclimate. Paleoclimate serves as the dominant controlling factor， governing organic matter enrichment by modulating paleo-water depth， paleoproductivity， paleo-redox conditions， and terrigenous clastic input. Concurrently， it regulates the proportions of felsic minerals and clay minerals by controlling terrigenous clastic input， while modulating carbonate mineral content by controlling paleosalinity. （3） Under the constraints of the high-frequency sequence framework， four distinct shale assemblage patterns （A-D） are identified in the Ek 2， with their primary distributions characterized as follows： Type A （rapid transgression phase / early oscillatory transgression phase）， Type B （rapid transgression phase/late stable highstand phase）， Type C （oscillatory transgression phase） and Type D （early oscillatory transgression phase）. Based on these findings， a shale assemblage model driven by paleoclimate was established.
Helium escapes easily from gas reservoirs through diffusion， which requires caprocks with low porosity and permeability， such as gypsum and mudstone layers， for effective sealing. However， the microscopic diffusion mechanisms of helium within the pores and throats of tight caprocks， as well as the influence of lithology and associated gases， are not well understood. Using molecular dynamics simulations， we modeled the pores of caprocks with different lithologies and simulated helium adsorption， diffusion， and flow behaviors within them. The results indicate that： （1） Lower temperatures， higher gas pressures， and smaller pore sizes in caprocks reduce helium diffusion， thus improving sealing effectiveness. Under the same conditions and pore sizes， helium diffuses and flows faster in halite and kaolinite pores， followed by montmorillonite and calcite， and the slowest in gypsum pores； （2） Considering actual throat sizes in caprocks， gypsum and halite provide the best sealing for helium， followed by montmorillonite and kaolinite， with calcite being the least effective； （3） Methane and water in the gas reservoir preferentially adsorb onto pore surfaces， thereby slowing helium diffusion. This effect is more pronounced at higher concentrations， and when pore water content exceeds 90%， the diffusion coefficient of helium approaches zero. Overall， smaller pore throats， higher gas pressures， lower temperatures， and high concentrations of associated gases and water in caprock throats help reduce helium loss. Gypsum rock layers are the most effective at sealing helium， followed by mudstones， and tight carbonates are the least effective.
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