Faults are the main pathways for natural gas migration in Pinghu Slope of Xihu Sag, East China Sea Basin, and have obvious controlling effects on differential hydrocarbon accumulation. Clarifying the migration characteristics and migration-accumulation patterns of natural gas along faults can effectively guide the prediction of favorable hydrocarbon migration-accumulation areas in Xihu Sag and similar regions. Therefore, by integrating data from well logging, seismic surveys, and analytical test data including natural gas composition, carbon isotopes, inclusion homogenization temperatures, and abundance, the migration characteristics of natural gas along static faults were systematically studied, and the migration-accumulation patterns along static faults were further clarified. Results showed that there were two stages of hydrocarbon accumulation for natural gas in Pinghu Slope, namely, the depositional period of Miocene Yuquan Formation-Liulang Formation and the depositional period of Pliocene Santan Formation (or Pleistocene Donghai Group) to present. Faults were basically in static state during natural gas accumulation periods, and inclusion abundance values within fault zones ranged from 1% to 5%, indicating continuous migration of natural gas along static faults. The equivalent maturity of natural gas in Pinghu Slope was 1.08% to 1.23%, which was much higher than the maximum maturity of local source rocks, indicating that the gas source mainly came from high-maturity source rocks in adjacent sags. Hydrocarbon migration pathway tracing results showed that natural gas in A and B structures mainly migrated along fault strikes; natural gas in H and J structures mainly migrated vertically along faults and laterally across faults; natural gas in C and F structures mainly migrated along fault strikes and laterally across faults. Based on the above characteristics, three types of natural gas migration-accumulation patterns along faults were determined: "stepwise", "strike-parallel", and "strike-stepwise composite" patterns.

To deeply analyze the intrinsic relationship between lithofacies characteristics and the mechanical properties of deep carbonate rocks, the study focuses on the Ordovician Yingshan Formation in the Tahe area of the Tarim Basin. Drilling cores, rock thin sections, and rock mechanics experimental data were comprehensively analyzed to clarify the lithofacies types of the carbonate rocks. Rock components were quantitatively characterized using ImageJ software, and the correlations between different lithofacies and rock mechanical properties were revealed. Three main carbonate rock lithofacies were identified in the Yingshan Formation of the Tahe area: sparry grained limestone, fine-medium crystalline dolomite, and micritic grained limestone. Experimental results revealed significant differences in rock mechanical properties among these lithofacies. Specifically, the fine-medium crystalline dolomite exhibited the highest compressive strength, Young’s modulus, and compressional and shear wave velocities, while the corresponding parameters of the micritic and sparry grained limestones decreased successively. The micritic grained limestone had the highest Poisson’s ratio, while the sparry grained limestone had the lowest. Additionally, multiple regression models with three linear equations were developed to describe the relationships between lithofacies and rock mechanics, among which Model 2 achieved the best correlation (R²=0.777). The study elucidated the genetic mechanisms underlying the variations in rock mechanical properties across different lithofacies. Grain size and cement content were the main controlling factors. The compressional and shear wave velocities of grained limestone decreased with increasing grain size, accompanied by a corresponding decrease in compressive strength. In contrast, as cement content increased, the shear and compressional wave velocities significantly decreased, and a linear functional relationship was observed between particle size and cement content. The study is expected to predict the mechanical properties of deep carbonate rocks through detailed lithofacies analysis, thereby advancing the geological and engineering integration process of oil and gas production.

The gypsum-salt rocks of the Lower and Middle Cambrian in the Tarim Basin are the critical cap rocks controlling the success of deep to ultra-deep subsalt hydrocarbon exploration. However, their diagenetic evolution and the influencing mechanisms on reservoir pore development remain unclear, thereby constraining exploration deployment. Based on core thin-section observations, drilling and logging data, and integration of previous research findings, the lithological types, spatial distribution patterns, and diagenetic evolution characteristics of the gypsum-salt rocks were systematically identified. The coupling relationship between these characteristics and reservoir pore preservation in subsalt reservoirs was further investigated. The results showed that: (1) The lithology of the gypsum-salt rocks was predominantly composed of gypsum rock, salt rock, and gypsum-bearing/gypsiferous dolostone. The gypsum rock exhibited laminated and massive structures, the salt rock was massive, and the gypsum-bearing/gypsiferous dolostone formed banded and lenticular structures. In planar view, the Bachu-Tazhong area served as the salt accumulation center, with thickness gradually decreasing outwards. The vertically distribution exhibited evolutionary characteristics of thinner strata in the Lower Cambrian and thicker strata in the Middle Cambrian. (2) The gypsum-salt rocks experienced a complex diagenetic history, which could be divided into three stages: syngenetic gypsum nodule growth and dolomitization in a sabkha environment; gypsum-to-anhydrite transformation during burial, which significantly enhanced rock densification; and plastic flow under late-stage tectonic stress, forming a dense sealing caprock. (3) Analysis of mechanisms revealed that the closed system formed by the thick gypsum-salt rocks of the Middle Cambrian could effectively block external diagenetic fluid activity during the mid-to-deep burial stages, significantly suppressing pressure dissolution and cementation in the reservoirs. This was the primary controlling factor for the preservation of early primary and secondary pores in the subsalt reservoirs. The research findings deepen the understanding of the reservoir-controlling mechanisms of evaporite cap rocks and provide geological guidance for deep to ultra-deep hydrocarbon exploration.

With the continuous growth of global energy demand, deep and ultra-deep oil and gas exploration and development have become key areas in the oil and gas industry. The Kuqa Depression in the Tarim Basin, China, is rich in deep and ultra-deep oil and gas resources, but it is affected by intense tectonic compression, leading to complex structural styles and significant variations in in-situ stress distribution, posing major challenges to oil and gas exploration and development. This study aims to clarify the structural deformation patterns and their main controlling factors in the Kelasu tectonic belt, reveal how structure and stress coupling influences hydrocarbon accumulation, optimize strategies for deep and ultra-deep exploration, and improve development efficiency. Taking the Kelasu tectonic belt in the Kuqa Depression, Tarim Basin as the research object, this study explored the characteristics of structural styles, influencing factors, and in-situ stress response characteristics in different segments through structural profile analysis and numerical simulation. The results showed that there were significant differences in structural styles and in-situ stress distribution among different segments of the Kelasu tectonic belt. The western Awate segment developed a "double-layer" thrust-nappe structure under intense compression, exhibiting strong compressional characteristics with high stress values at both ends of the high-angle faults. The eastern Keshen segment was dominated by pop-up and imbricate thrust structures, exhibiting a stress concentration pattern indicative of significant fault slip, with stress concentrated at the tops of faults and the bases of pop-up structures. The Bozi-Dabei segment was characterized by broad and gentle synclines in suprasalt structures, with well-developed salt welds and widely distributed subsalt pop-up structures, accompanied by localized stress concentration. Based on dynamic numerical simulations, a quantitative analysis was conducted on influencing factors, including fault friction coefficient, shortening amount, and fault dip angle. It is concluded that shortening amount and fault dip angle are the main controlling factors causing differences in structural styles and current in-situ stress distribution.

As one of the most important gas-bearing structures in the central depression of the Yinggehai Basin, the diapir-associated gas field group has proven geological natural gas reserves of about 180 billion m³. However, the natural gas accumulation characteristics differ significantly across different regions of the diapir, which seriously affects natural gas exploration process in the central depression. Therefore, taking gas reservoirs in different regions (core, affected region, and unaffected region) of the Dongfang 1-1 diapir as research objects, the study employed gas component analysis, carbon isotope analysis, sandstone physical property tests, and inclusion tests to investigate the natural gas composition and source, reservoir characteristics, migration systems, charging stages, and caprock sealing capacity. The results indicated that the natural gas in the second member of the Pliocene Yinggehai Formation (Y2) in the diapiric core and the first member of the Miocene Huangliu Formation (H1) in the unaffected zone was mainly CH₄, with an average content of 69.98%. In contrast, CO₂ content in the H1 reservoirs of the affected zone and diapiric core was higher, reaching up to 65.99%. The diapiric core and unaffected zone used diapiric faults and associated micro-fractures, respectively, as the main migration systems. The H1 and Y2 gas reservoirs corresponded to the second and third stages of natural gas charging, respectively. The physical properties of the H1 reservoirs improved progressively from the diapiric core towards the affected and unaffected zones. Both the H1 and Y2 reservoirs showed strong overpressure and overpressure characteristics, with formation pressure coefficients of approximately 1.8 and 1.5, respectively. The overlying mudstone caprock of the H1 reservoir in the unaffected zone demonstrated strong physical sealing capacity, with a fracture pressure coefficient less than 0.9, followed by the affected zone, and poorest in the diapiric core. Based on these results, three natural gas migration-accumulation modes were established for the different regions of the Dongfang 1-1 diapir: (1) diapiric core: early hydrocarbon gas charging, late non-hydrocarbon gas charging, overpressure sealing in medium-deep low-permeability reservoirs, and conventional physical sealing in shallow layers; (2) diapir-affected zone: early hydrocarbon gas charging accompanied by mudstone-controlled physical sealing and late non-hydrocarbon gas charging accompanied by overpressure sealing in low-permeability reservoirs; (3) diapir-unaffected zone: hydrocarbon gas charging, micro-fracture migration, and mudstone-controlled physical sealing.

The shale gas in the first member of the Silurian Longmaxi Formation in the southern Sichuan Basin exhibits promising potential for exploration and development. To clarify the influence of the development characteristics of natural fractures in shales on shale gas enrichment patterns, the organic-rich shales in the first member of the Longmaxi Formation in the Luzhou area, southern Sichuan Basin were selected as the study objects. Utilizing drilling cores, thin-section identification, and geophysical well logging data, this study investigated the types and development characteristics of fractures in the Longmaxi Formation shales in the study area through comprehensive geological analysis methods. The results showed that the fracture types were mainly structural fractures (shear fractures) and non-structural fractures. Structurally, the degree of fracture development was negatively correlated with the distance from faults, with fractures being well-developed in the anticline areas and less developed in the syncline areas. In terms of non-structural factors, fracture density was positively correlated with total organic carbon content (≥2%) and brittle mineral content (≥44%). The gas-bearing capacity of organic-rich shales in the study area was affected by factors such as the degree of fracture filling, the relationship between the current in-situ stress direction and the fracture strike, and the degree of fracture dispersion. Among these, partially filled and unfilled fractures, fractures intersecting with the current maximum principal stress at high oblique angles, and fracture networks with scattered strikes significantly enhanced the gas-bearing capacity of shales. This study divided the effective fractures in the organic-rich shales of the first member of the Longmaxi Formation in the Luzhou area of the southern Sichuan Basin into 6 Class Ⅰ favorable areas and 7 Class Ⅱ favorable areas. It identified the anticline areas and areas adjacent to fault zones as the exploration target areas. These findings provide important theoretical support and practical guidance for the exploration and development of shale gas in the Luzhou area of the southern Sichuan Basin.

The Archean metamorphic buried-hill reservoirs in Bozhong 19-6 Gas Field, Bohai Bay Basin are deeply buried, with complex fracture formation mechanisms and distribution patterns. Research and prediction methods for effective fractured reservoirs are still lacking, seriously restricting the efficient development of this gas field. Based on seismic, core, well logging, and other data, fracture development mechanisms and distribution characteristics of reservoirs were clarified through multi-stage paleo-tectonic stress field analysis. The current stress distribution characteristics in the study area were simulated using the finite element method. Finally, a prediction method for effective buried-hill fractured reservoirs was established based on the coupling of paleo-present stress fields. The results showed that: (1) Fracture development in the study area was controlled by multi-stage tectonic movements. Indosinian-Yanshanian compression formed the initial fractures, and Himalayan extension and strike-slip movements reactivated and modified the early fractures. (2) Structurally, the study area could be divided into western compression and eastern strike-slip zones, with the core of the compression zone and the strike-slip zone being favorable areas for fracture development. (3) The current stress field characteristics showed that current maximum horizontal principal stress direction in the study area was generally NEE75°-SEE105°. Influenced by regional dextral strike-slip faults, the current maximum horizontal principal stress direction showed a SEE-E-NEE directional change from west to east. (4) Based on the prediction using paleo-present stress field coupling, effective fractured reservoirs were classified into three categories. Class Ⅰ area, distributed near the core of the compression zone and the strike-slip zone, showed the most developed effective fractured reservoirs. Class Ⅱ area was located in high positions of eastern well area near the strike-slip zone. Class Ⅲ area, situated in structurally lower positions, exhibited relatively poor development of effective fractured reservoirs.

The Jurassic Lianggaoshan Formation in the Sichuan Basin is characterized by widely distributed, thick organic-rich shale. In recent years, high-yield industrial oil and gas flows have been obtained in shale reservoirs of the first member of the Lianggaoshan Formation (Liang 1) as well as sandstone and mudstone interbedded reservoirs of the second member of the Lianggaoshan Formation (Liang 2), showing good resource potential. The high yield makes the Lianggaoshan Formation an important successor field for shallow oil and gas exploration in the Sichuan Basin. Using whole rock X-ray diffraction, organic geochemical analysis, and scanning electron microscopy (SEM), combined with a comparison of accumulation elements, the main controlling factors of shale oil and gas accumulation in the Lianggaoshan Formation of the eastern Sichuan Basin were discussed. The average porosity of shale in Liang 1 member is 4.45%, with reservoir space mainly consisting of intragranular and intergranular dissolution pores of clay minerals, and locally developed organic pores, bedding fractures, and high-angle fractures. The shale reservoirs have high brittle mineral content, moderate two-way horizontal stress difference, and good compressibility. The total organic carbon (TOC) content isolines exhibit ring-shaped distribution, with TOC content exceeding 1.8% in the Dianjiang, Liangping and Zhongxian hydrocarbon generation center. Organic matter types are mainly type Ⅱ₂ and type Ⅲ, with an average organic matter maturity (R_o) of 1.14%, generally in the mature to highly mature stage. Three main controlling factors were observed for shale oil and gas enrichment and high production in the Lianggaoshan Formation: (1) sedimentation, which controlled source, (2) overpressure, which promoted enrichment, and (3) fracturing, which facilitated migration. Among them, sedimentation-controlled source and abnormal overpressure-driven enrichment are more critical than fracturing in controlling oil and gas migration. Using parameters such as continuous thickness of high-quality shale, formation pressure coefficient, micro-fracture development degree, and brittleness index, the evaluation criterion for favorable areas of shale oil and gas in the Lianggaoshan Formation of the eastern Sichuan Basin was established. Based on exploration experience in adjacent areas, it is recommended to prioritize the three high-quality sublayers of Liang 1 member as the primary targets vertically, while focusing regionally on favorable type I areas such as the Zhongxian and Wanxian synclines. An integrated geological and engineering exploration for core areas of the syncline with burial depth greater than 2 500 m should be conducted.

A series of fine-grained sediments with mixed origins of mudstone-dolomite and clastic rock are developed in the Cretaceous of Qingxi Sag in the Jiuquan Basin, providing favorable conditions for shale oil enrichment. Samples of different lithofacies were selected as research objects, and a series of analytical tests were conducted, including rock pyrolysis, total organic carbon, X-ray diffraction, scanning electron microscope (SEM) analysis, rock thin section observation, low-temperature nitrogen adsorption, and high-pressure mercury intrusion experiments. Through the comprehensive applications of mineral petrology, organic geochemistry, and reservoir physical property analyses, detailed reservoir characterization and oil-bearing evaluation were conducted for shale oil in the sag. The research results showed that:(1) The shale mineral compositions and lithologies in the sag were complex, and the main lithofacies types were dolomitic shale, fine siltstone, gravelly sandstone, and mudstone. The corresponding shale oil types were mixed sedimentation (in a broad sense) and interbedded types. The fine siltstone exhibited the best oil-bearing property, followed by dolomitic shale, and both of them were favorable reservoirs for shale oil. (2) The pore sizes of shale reservoirs were distributed in the range of 10 nm to 100 μm, among which fine siltstone had a relatively uniform pore size distribution, conducive to the enrichment of shale oil. (3) Based on total organic carbon (TOC) content, S₁ content, and oil saturation index (OSI), the oil-bearing properties of shale oil were evaluated and classified into ineffective resources, low-efficiency resources, medium-efficiency resources, and high-efficiency resources. (4) Based on shale lithofacies, geochemical characteristics, reservoir physical property characteristics, microscopic pore structure, and oil-bearing characteristics, the shale oil in the sag was divided into Class Ⅰ, Class Ⅱ, and Class Ⅲ sweet spots, in descending order of resource quality. This study clarified the reservoir and oil-bearing characteristics of the shale oil in the Qingxi Sag and categorized shale oil sweet spots, which is of great significance for shale oil exploration in the sag.

Current research on sedimentary paleoenvironments and the main factors controlling organic matter enrichment in the southern Sichuan Basin primarily focuses on the Luzhou subsag area, while studies on the Weiyuan area near the Leshan-Longnüsi paleo-uplift are relatively scarce. This has led to an unclear understanding of the main controlling factors of organic matter enrichment in the area. Accordingly, through a comparative analysis of the sedimentological and organic geochemical characteristics of the Lower Silurian Longmaxi Formation on the western margin of the Weiyuan area, the main controlling factors and formation models of organic matter enrichment were explored. The results indicated that during the LM1-LM5 sedimentary periods (Rhuddanian), the basin experienced flexural subsidence. Tectonic activity was stable, sea level was at its highest, terrigenous clastic input was low, and the water body was predominantly anoxic. Preservation conditions, terrigenous clastic input, and paleoproductivity collectively resulted in the highest organic matter content in this sedimentary period. In the LM6 sedimentary period (early Aeronian), the basin entered a flexural-migration phase. Tectonic activity intensified, the barrier in the passive continental margin area of northern Chongqing began to open, ocean current activity strengthened, and the bottom-water environment was mainly anoxic to dysoxic. The deterioration of preservation conditions and the increased paleoproductivity were the main factors leading to only minor difference in total organic carbon (TOC) content compared with the LM1-LM5 sedimentary periods. During the LM7 sedimentary period (middle Aeronian), the barrier continued to open, sea level dropped further, bottom-water reducibility became worsened, and ocean current activity continued to intensity. The deterioration of preservation conditions and increased terrigenous clastic input were the main factors causing the decrease in organic matter content. During the LM8 sedimentary period (late Aeronian), ocean current activity reached its peak and paleoproductivity rose to its highest level. However, the bottom-water environment became dysoxic to oxic. The deterioration of preservation conditions was the main factor causing the organic matter content to drop to its lowest level. It is concluded that the continuous decrease in organic matter content within the study area is closely related to the sedimentary paleoenvironment evolution process, which was primarily controlled by paleogeomorphology and sea-level fluctuations.

Although significant hydrocarbon exploration achievements have been made in the Sayin Hudug Trough of the Eerdeng Sum Sag, Erlian Basin, systematic studies on source rocks remains limited, and the resource potential is still unclear. Based on test and analytical data, a systematic evaluation of the source rocks in the study area was conducted. The study predicted the distribution of effective source rocks and clarified the oil and gas resource potential of this area. Research results showed that source rocks in the A’ershan Formation (K₁ba) of the Sayin Hudug Trough in the Eerdeng Sum Sag had relatively high organic matter abundance, was more humic, and was in a mature stage of thermal evolution, making them the main source rocks of the trough. In addition, the first member of the Tengger Formation (K₁bt₁) also showed relatively good source rock development in certain areas, such as in the northern sub-trough, and could serve as a secondary source rock. Geochemical characteristics varied across different sub-troughs, mainly in organic matter abundance. For example, the average total organic carbon (TOC) of K₁ba source rocks in the northern sub-trough was 1.15%, slightly higher than the 0.97% in the southern sub-trough. Biomarker compound and trace element data showed that both K₁ba and K₁bt₁ source rocks were formed in freshwater sedimentary environments of semi-humid to semi-arid climates under weak reduction and weak oxidation conditions. The organic matter was mainly derived from mixed inputs of aquatic organisms and higher plants, with higher plants having a slight biogenic advantage. The lower limit of TOC content for effective source rocks was determined to be 1.0%. Effective source rocks were mainly distributed in the sedimentary centers of the three secondary structural units, i.e., northern, middle, and southern sub-troughs. The total oil resources in the Sayin Hudug Trough were predicted to be 54.188 7×10⁶ t. The southern sub-trough had the greatest oil and gas potential, followed by the northern sub-trough.

To provide a basis for investigating the resource potential and hydrocarbon accumulation patterns of the Cretaceous source rocks in the Junggar Basin, organic petrology, detailed geochemical characterization, and closed-system thermal simulation technology were employed. The study analyzed the geochemical characteristics and hydrocarbon generation potential of Cretaceous source rocks in different blocks of the basin. These source rocks showed strong heterogeneity and generally of low quality. However, high-quality source rocks were also present. Type Ⅰ and Type Ⅱ₁ source rocks accounted for 39.6% of the total, and source rocks with total organic carbon (TOC) content ＞1.0% accounted for 17.5%. In the Shawan, Manas and Hutubi area, located in the middle section of the southern margin of the basin, the Cretaceous source rocks had the largest sedimentary thickness, with dark mudstone thickness reaching up to 574 m and burial depth generally exceeding 6 000 m. The organic matter was mainly Type Ⅱ (89.1%), with 8.7% of the source rocks having TOC ＞1.0%. Vitrinite reflectance (R_o) values ranged 0.82% to 1.01%, indicating that the source rocks were currently at the peak stage of oil generation. The source rocks had Pr/Ph values of 0.31 to 1.20 and gammacerane/C₃₁ hopane ratios of 0.46 to 8.12, with dominant abundances of C₂₇ and C₂₉ regular steranes. C₂₇, C₂₈, and C₂₉ regular steranes showed V-shaped distributions, indicating deposition in a strongly reducing, saline lacustrine environment. Aquatic algae were well-developed, and organic macerals developed lamalginite that emitted strong yellow fluorescence, indicating strong oil generation capacity. Cretaceous Type Ⅰ and Ⅱ₁ source rocks had maximum oil generation up to 660.0 mg/g and 284.0 mg/g, respectively, with peak oil generation at R_o = 1.0%. Comprehensive study indicates that in the Shawan, Manas and Hutubi area, located in the middle section of the southern margin of the Junggar Basin, the Cretaceous source rocks are thick, rich in oil-generating lamalginite, currently at the peak stage of oil generation, and possess high oil generation capacity, making the area the most favorable target for Cretaceous-sourced oil generation.

The coal rock gas resources in the 8# coal seam of the Carboniferous Benxi Formation in the central and eastern Ordos Basin have great potential. By analyzing the gas components and carbon and hydrogen isotope compositions of the desorbed gas from 33 coal rock samples of the 8# coal seam in 3 coal rock gas wells of this area, and combining these results with the geological characteristics and gas contents of the coal rocks, the genesis of coal rock gas and the salinity characteristics of the sedimentary water bodies were revealed, and the causes of the abnormal methane carbon isotope in coal rock gas were discussed. The results showed that in the Benxi 8# coal rock gas, the CH₄ content ranged from 88.50% to 97.12%, and the C₂H₆ content ranged from 0.23% to 1.92%. Among the non-hydrocarbon gases, the CO₂ content ranged from 2.51% to 7.18%, and the N₂ content was less than 4.50%. The δ¹³C₁, δ¹³C₂, δ¹³C_CO2, δ²H_C1, and δ²H_C2 values of the Benxi 8# coal rock gas ranged from -37.6‰ to -25.8‰, -19.4‰ to -16.0‰, -12.6‰ to -6.0‰, -185.0‰ to -158.0‰, and -131.0‰ to -103.0‰, respectively. Considering the gas components, carbon isotope compositions, the high level of thermal evolution, the strong gas-generating potential of the coal rocks, and the tectonic stability of the coal rock distribution area, it was concluded that the Benxi 8# coal rock gas in the central and eastern Ordos Basin was high to over mature thermogenic gas, derived from the thermal transformation of humic organic matter within coal seams, representing self-generated and self-stored coal-derived gas. The CO₂ in the coal rock gas was of mixed origin, generated from both the thermal cracking of organic matter and the thermal decomposition of carbonate minerals. The hydrogen isotope characteristics of the coal rock gas revealed that the sedimentary water bodies of the Benxi 8# coal rock in the central and eastern Ordos Basin were brackish to saline, representing a transitional marine-continental sedimentary environment. A good negative correlation existed between δ¹³C₁ of the coal rock gas and the gas content, indicating that better storage and preservation conditions resulted in a higher degree of gas "accumulation". In high to over mature coal rocks, the δ¹³C₁ value of "accumulated" gas was significantly lighter, and the gas-bearing capacity of the coal rocks was better.

Fracture veins are a research hotspot in shale gas exploration and development, and they play a significant role in revealing paleotectonic movements, fluid burial, and reservoir evolution processes. The Weiyuan-Rongchang north area, as a key block for current shale gas development, still lacks clarity regarding the development characteristics and formation age of fracture veins in its deep shale formations, as well as their relationship with tectonic and sedimentary evolution. The genesis and geological significance of these features require further investigation. Therefore, this study took the vein minerals in the deep shale fractures of Longmaxi Formation in this area as the research object. Through petrographic observation, cathodoluminescence analysis, fluid inclusion homogenization temperature testing, laser Raman spectroscopy analysis, U-Pb dating, and major and trace element and rare earth element testing, the genesis and geological significance of the fracture veins were revealed. The results showed that the calcite veins in deep shale fractures of the Longmaxi Formation in the Weiyuan-Rongchang north area formed in an oxidizing environment with relatively low paleofluid temperature and shallow burial depth, and their fluid source was groundwater influenced by hydrothermal activity. The U-Pb dating results showed that the formation age of the calcite veins was about (245.2 ± 5.1)Ma. The homogeneous temperature of coeval aqueous inclusions was mainly concentrated at 130 to 150 ℃, corresponding to the first stage of fluid charging, indicating that the initial opening of fractures occurred earlier than the formation age of the vein (245.2 ± 5.1)Ma. The calcite veins in this stage reflected that the Longmaxi Formation shale was affected by tectonic activity, with fracture systems communicating with the external environment, but the overall scale was limited, and the shale gas preservation conditions were not significantly damaged.

The Ediacaran-Cambrian transition is a key stage of marine environmental fluctuation and biological evolution in geological history. However, the interrelationships among volcanic/hydrothermal activity, seawater salinity changes, and the Cambrian Explosion in shallow-water areas along the southeastern margin of the Nanhua Basin remain unclear. Drilling samples of the Lower Cambrian from the margin of the paleo-uplift in the central Hunan as research objects were analyzed using scanning electron microscopy, inorganic geochemistry, and silicon isotope techniques to elucidate the enrichment carriers and genesis of mercury in sedimentary rocks, the spatio-temporal distribution of seawater salinity, and the sources of siliceous material. Significant mercury anomalies were observed in the basal Cambrian shales surrounding the paleo-uplift, with mercury primarily enriched in organic matter, serving as an effective indicator of volcanic/hydrothermal fluid input. Volcanic/hydrothermal activity was relatively active during the transition from Cambrian Stage 2 to Stage 3 (about 526 to 521 Ma) and gradually declined in the late Stage 3 (about 518 Ma). Water salinity around the paleo-uplift was relatively high, while the deep-water area of central Hunan showed characteristics of freshwater to brackish environments. This difference may be related to the connectivity with the open sea and the degree of water retention. In the early Cambrian, the area around the paleo-uplift experienced a saline environment, which gradually evolved into brackish to freshwater conditions as water retention increased. Additionally, shales of the Niutitang Formation around the paleo-uplift contained abundant siliceous material. In the lower section, silica was mainly biogenic with minor terrigenous and volcanic origins, while in the upper section, silica primarily sourced from a mixture of silica-rich seawater and hydrothermal input. Episodic volcanic/hydrothermal activities and paleogeographic patterns during the Early Cambrian in the shallow-water areas along the southeastern margin of the Nanhua Basin jointly drove salinity stratification and multi-source silica supply. These findings reveal the differential evolution between shallow- and deep-water basins and provide key geochemical constraints for understanding marine environmental fluctuations in the Nanhua Basin.

The overpressured reservoirs in the Huangliu Formation of the Dongfang area, Yinggehai Basin, are characterized by fine lithology, poor physical properties, complex storage space, and strong heterogeneity, which lead to poor correspondence between nuclear magnetic resonance (NMR) T₂ spectrum and capillary pressure curves, making the conversion between relaxation time and pore-throat radius challenging. To clarify the distribution relationship between NMR T₂ spectrum and pore-throat radius in such reservoirs and solve the difficulty in converting relaxation time to pore-throat radius, a segmented modeling method was adopted. Combining conventional physical properties, X-ray diffraction, NMR, and high-pressure mercury injection experiments, the conversion relationship between relaxation time and pore-throat radius was developed. The main controlling factors of surface relaxivity in different relaxation intervals were thoroughly analyzed. A four-factor regression analysis method was used to build a dynamic characterization model for surface relaxivity. The model achieved a relatively good calculation performance, with average relative errors of long and short relaxation components being 9.965% and 2.227%, respectively. The results indicated that the NMR T₂ spectrum and mercury injection-based pore-throat radius distribution curves of the reservoirs showed obvious segmented characteristics near 5.7 ms (corresponding to a pore-throat radius of about 0.1 μm). The surface relaxivity of short relaxation component (T₂ < 5.7 ms) was significantly lower than that of long relaxation component (T₂ > 5.7 ms), confirming notable differences in surface relaxation mechanisms across different pores sizes. Surface relaxivity was jointly influenced by reservoir physical properties, mineral composition, and pore structure. The surface relaxivity of short relaxation component was mainly affected by clay content, while the long relaxation component was mainly controlled by pore structure complexity. Based on this, a dynamic surface relaxivity characterization model was constructed through optimizing sensitive factors for different relaxation intervals, achieving quantitative prediction of surface relaxivity. Meanwhile, the correspondence accuracy between relaxation time and pore-throat radius was significantly improved through the segmented conversion method. This approach provides a theoretical basis and methodological support for the accurate conversion of pore-throat radius based on NMR T₂ spectrum. The findings are significant for precisely characterizing the pore structure of overpressured reservoirs and improving the accuracy of reservoir evaluation.

In the Zhongtaishan-Bajiaochang area of the central Sichuan Basin, the second member of the Jurassic Shaximiao Formation develops multiple stages of channel sand bodies that are frequently superimposed vertically. P-wave and S-wave velocity slices provide distinct advantages for studying their distribution characteristics and vertical evolution patterns. Based on high-resolution sequence stratigraphy and sedimentary responses to changes in accommodation space, the second member of the Jurassic Shaximiao Formation was divided into 4 fourth-order sequences. By integrating core, logging facies, and seismic facies data, the study determined that channel facies dominate. Each sand group was formed by the superimposition and migration of multiple channel sand bodies. Seismic reflections were mainly characterized by continuous to weakly continuous parallel reflections, with some bright spots observable in contrast, representing channel deposits. To address the challenge of severe overlap of wave impedance of sandstone and mudstone, P-wave and S-wave velocities were identified as sensitive parameters for effective lithology discrimination. Based on pre-stack simultaneous inversion, a P-wave to S-wave velocity ratio data volume capable of distinguishing sandstone from mudstone was obtained. Using this lithologically meaningful data volume, seismic sedimentology research was then carried out. Typical stratigraphic slices were employed to identify river channels and classify river types by drawing analogies between modern and ancient systems, and the controlling effect of accommodation space on channel scale was discussed. The results showed that the second member of the Jurassic Shaximiao Formation in the Zhongtaishan-Bajiaochang area was dominated by meandering river facies, with 18 stages of river channels developed vertically. Two main river types were developed, i.e., straight rivers and low-sinuosity meandering rivers, and in some slices, multiple river types coexisted. Sand bodies No. 7-9 were developed under conditions of low accommodation space, where channels overlapped and were large in scale, making them key targets for further exploration and development of the second member of the Jurassic Shaximiao Formation.

A field test of nitrogen injection for enhanced oil recovery was conducted in the deep carbonate oil reservoir of Fuman Oilfield, Tarim Basin. In the nitrogen injection process, whether phase miscibility occurs can affect oil recovery efficiency, and understanding the variations in fluid phase states during nitrogen injection under non-equilibrium conditions in the formation is of significant importance. To clarify the changes in fluid phase state and the miscibility pressure during nitrogen injection-assisted gravity flooding in deep carbonate reservoirs, Manshen X reservoir was taken as an example. By conducting nitrogen injection phase experiments, the phase characteristics under non-equilibrium and equilibrium conditions after nitrogen injection were obtained. The discrimination diagram of variation of formation fluid type with injection volume and the diagram of variation of formation fluid saturation pressure with injection volume were established, thereby determining the miscibility pressure during nitrogen injection. The results showed that under non-equilibrium conditions, when a small amount of nitrogen was injected, it mixed with formation fluids to form a single phase. As the injection volume increased, a three-phase coexistence state appeared with a nitrogen phase at the top, a gas phase in the middle, and an oil phase at the bottom. When the nitrogen injection volume reached 0.8 PV, the nitrogen phase gradually disappeared. Under equilibrium conditions, after nitrogen injection, the fluids showed an "opalescence phenomenon" at the saturation pressure, and the saturation pressure increased with increasing injection volume. After the injection volume reached 0.2 PV, the fluids exhibited two phases under an injection pressure of 55 MPa. After the injection volume reached 0.8 PV, the fluids presented two phases under a formation pressure of 81 MPa. Based on the discrimination diagram of variation of formation fluid type with injection volume and the diagram of variation of formation fluid saturation pressure with injection volume, the minimum miscibility pressure for nitrogen injection in the Manshen X reservoir was determined to be 48 MPa. Under an injection pressure of 55 MPa, nitrogen injection-assisted gravity flooding could achieve miscibility. Under non-equilibrium conditions, a significant gravity segregation characteristic developed from top to bottom, resulting in a gradual decrease in nitrogen content and a gradual increase in hydrocarbon component content from the top to the bottom of the Manshen X reservoir after gas injection.

The deep tight sandstone gas reservoirs in the northern slope belt of the Kuqa Depression, Tarim Basin, are key area for natural gas reserve expansion and production enhancement in China, and hydraulic fracturing technology for these reservoirs is a critical means for hydrocarbon production enhancement. However, the complex geological conditions in deep layers lead to unclear propagation patterns and influencing factors of hydraulic fractures, requiring quantitative analysis to reveal the propagation patterns of hydraulic fractures under the action of multi-field coupling. Focusing on the high-temperature and high-pressure geological environment of deep gas reservoirs in the northern slope belt of the Kuqa Depression, a thermo-fluid-solid-chemical coupling model was established considering geomechanical factors such as "stress and fracture weak planes". Using finite element numerical simulation, the propagation patterns of hydraulic fractures were elucidated. The results showed that: (1) The dynamic propagation process of hydraulic fractures was significantly influenced by thermo-fluid-solid-chemical coupling, which determined the propagation patterns of hydraulic fractures. (2) Complex fracture networks tended to form in zones with low horizontal stress differences, and differences in horizontal stress gradient induced asymmetric propagation of hydraulic fractures. (3) During the propagation of hydraulic fractures, natural fractures were preferentially activated, and the occurrence of natural fractures affected the propagation direction of hydraulic fractures. When the angle between natural fracture and hydraulic fracture was large, the propagation of hydraulic fractures tended to stop and pass through natural fractures. When the angle was small, hydraulic fractures tended to activate natural fractures or both activate and pass through them. (4)The perforation inclination angle was positively correlated with the fracture deflection angle. The effect of injection rate on fracture area had an optimal upper limit. A greater temperature difference between fracturing fluid and formation more easily generated tensile fractures and resulted in a lower fracture initiation pressure.

As the changes of oil properties and stress-sensitive formation permeability, the flow governing equations for early-stage depletion development in reservoirs with high formation-saturation pressure difference is strong nonlinear. By the definition of pseudo-pressure function and pseudo-time factor and considering partially penetrated vertical fracture wells in such reservoirs, the mathematical model was established. Using Laplace transform, finite Fourier cosine transform, and the point sink superposition principle, the bottomhole pressure solution for a partially penetrated infinite-conductivity vertical fracture well was obtained. By incorporating the conductivity influence function, Duhamel’s convolution principle and material balance equation of closed reservoir, the production solution for a finite-conductivity fracture well was further derived. Parameter sensitivity analysis demonstrates that: for reservoirs with high formation-saturation pressure difference exhibiting stress sensitivity, implementing a rational production strategy can effectively avoid both formation permeability damage caused by excessive drawdown and the risk of dissolved gas liberates due to rapid pressure decline. The objectives should be central fracture placement within the reservoir and a vertical penetration ratio exceeding 0.5 when fracturing designing. Besides, the optimal fracture half-length and permeability should be determined based on geological characteristics and operational constraints. This study provides a methodology for forecasting production performance and inverting formation parameters of partially penetrated wells in reservoirs with high formation-saturation pressure difference. It also offers a theoretical basis for optimizing production strategies and determining the timing for formation energy replenishment in such reservoirs.