There are significant disparities in both the gas abundance and enrichment degree of Jurassic Shaximiao Formation gas reservoirs in the central Sichuan Basin， posing a serious hindrance to the exploration and development of tight sandstone gas in this formation. To address this， the present study conducts a comprehensive analysis of various reservoir formation factors， including source rock， reservoir characteristics， paleo-structure during the accumulation period， fault-sand configuration， and their evolutionary patterns. By integrating previous knowledge， it is concluded that the differential reservoir formation of tight sandstone gas in the central Sichuan region is primarily influenced by the presence of high-quality reservoirs， favorable fault-sand configuration types during the accumulation period， and the evolution of such configurations throughout ancient and modern times. In line with this analysis， a novel model for the evolution of differential reservoirs is proposed， encompassing key elements such as differential hydrocarbon supply from two distinct source rocks， differential fault-sand configuration， differential enrichment of high-quality reservoirs， and differential adjustment of fault-sand evolution. Specifically， the Shaximiao Formation gas reservoir in central Sichuan receives differential hydrocarbon supply from two distinct sources： coal-type gas from the Xu5 Member and oil-type gas from the Da'anzhai Member. Moreover， the characteristics of oil-type gas， mixed gas， and coal-type gas exhibit noticeable variations across the study area， particularly from the northeast to the southwest. During the accumulation period， the abundance of gas reservoirs in the sand group with faults and gently inclined sand bodies （Type ③） surpasses that in the sand group with faults and near-horizontal sand bodies （Type ①）. Additionally， the gas reservoirs exhibit differential charging. High-quality reservoirs demonstrate excellent reservoir capacity and a high degree of enrichment， contributing to the differential enrichment of gas reservoir formation. Furthermore， the gas content of the reservoirs varies depending on the type of fault-sand evolution. The inheritance-preserved fault-sand evolution （type I） yields the highest gas content， followed by the adjusted residual type （type II）， while the reverse loss type （type III） exhibits the lowest gas content. This indicates that the gas reservoirs undergo differential adjustments throughout their evolution.

Recently， the first self-operated well in the buried hill field was drilled around Yacheng 13-1 Gas Field， and the commercial discovery made the gas field glow with new vitality. In order to further explore the exploration value of Yacheng 13-1 structure， it is necessary to clarify its source of oil and gas for realizing the resource potential of the area. Based on the analysis and test data of new and old drilling samples， starting from the geochemical characteristics of oil and gas， this paper carefully analyzes the genetic types and distribution rules of oil and gas in Yacheng 13-1 Gas Field， and defines the source of oil and gas. The analysis shows that the natural gas in Yacheng 13-1 Gas Field is coal type gas， and the natural gas and condensate in the south and north blocks are obviously different. The dryness coefficient of natural gas is “dry in the north and wet in the south”， the carbon isotope of hydrocarbon gas is “heavy in the north and light in the south”， and the maturity is “high in the north and low in the south”. The density， viscosity， freezing point and wax content of the condensate in the north block are higher than those in the south block， and the aromatics content and planting ratio of the condensate in the north block are also significantly higher than those in the south block. This difference is mainly related to the composition and maturity of oil and gas parent materials. In the north block， the input of terrigenous hydrocarbon source materials is more， and the contribution of lower aquatic organisms in the south block is increased. Further oil source correlation shows that the oil and gas in the north block of Yacheng 13-1 Gas Field has the characteristics of “double sources”， with contributions from both the local coal measures source rocks of Yacheng Formation in the north block and the Oligocene source rocks of Yinggehai Sag. The oil and gas in the south block mainly comes from the terrigenous marine facies sapropelic source rocks of the Yacheng Formation in the Yanan Depression.

The western part of the Hangjinqi area of the Ordos Basin is the key area for natural gas exploration and development in recent years. The upper sandstone of the Shanxi Formation is the main gas-bearing layer， and the lower coal seam is the main gas source rock， which has the characteristics of tight reservoir and strong heterogeneity. At present， there is still a lack of systematic research on the reservoir characteristics and effective reservoir genesis of the Shanxi Formation in the western part of Hangjinqi area， which restricts the late oil and gas exploration process in this area. Therefore， this study comprehensively analyzed the petrology， physical properties and diagenetic characteristics of the reservoir of the Shanxi Formation in the western part of Hangjinqi area by comprehensively using various analysis and test data such as drilling and logging data， core data， rock casting sheets， scanning electron microscopy， physical property test， mercury pressure and clarified the origin of its dominant reservoir. The results show that the dominant reservoirs are mainly distributed in the heart beach and river channel sand， mainly sandstone and medium coarse sandstone. The reservoir space is mainly intergranular pores， and the permeability is mainly distributed in （0.2-2.4）×10^-3 μm²， which belongs to low-ultra-low permeability reservoirs， the pore-throat combination relationship is mainly porous-medium and small larynx， and the micro-fractures are relatively developed. The overall diagenesis of the reservoir is complex， including compaction， cementation， alternating alteration and dissolution， and the reservoir as a whole is in the B stage of middle diagenetic. The dominant reservoir is mainly intergranular pores， which are mainly controlled by sedimentation， and dissolution pores are also the main reasons for improving the physical properties of the reservoir， which are controlled by sedimentation and diagenesis.

The booming of shale gas production provides “clean energy”， while followed by potential environmental risks. Drilling cuttings and flowback/produced water are the major waste or wastewater during shale gas production. They show large differences on composition and element concentration due to geochemical information and additives diversity， which causes large challenge on solid waste and wastewater treatments. This review focused on the occurrence and distribution of inorganic and heavy metal in both drilling cutting and flowback/produced water， then tried to discriminate their potential pathways into aquatic systems and soil， as well as their possible impacts. We proposed suggestion of future study， and hope this should be useful for pollution prevention and control as well as risk management related to shale gas exploitation in our country in the future.

Total organic carbon content（TOC） is a key parameter in the evaluation of hydrocarbon source rocks. Accurate calculation of TOC using logging data plays an important role in the comprehensive evaluation of hydrocarbon source rocks. Currently， the traditional natural gamma method and ΔLogR method for evaluating the TOC of the first member of the Maokou Formation in the southeastern Sichuan Basin are both inadequate. Therefore， on the basis of the logging response characterization of the first member of the Maokou Formation， the TOC calculation results of ΔLogR method and gamma ray method are combined to construct the parameter T reflecting the carbonate mineral content （Car）. Further， the T values are classified， the TOC calculation results of the natural gamma Ray method and the ΔLogR method are optimized， and a new ΔLogR-GR method is established， which can effectively solve the shortcomings of the traditional TOC calculation methods. The application example confirms that the ΔLogR-GR method is more accurate than the traditional natural gamma and ΔLogR methods， and is more consistent with the TOC measurement results of geochemical elemental logging （ECS）， with the absolute value of error lower than 0.3， which is highly applicable and reliable.

The K structural belt of the Pinghu Slope in the Xihu Depression of East China Sea Basin is enriched in oil and gas， and the hydrocarbon migration and accumulation process is complex. Studying the hydrocarbon migration and accumulation patterns along fault strike and controlling factors can provide a theoretical basis for oil and gas exploration in similar areas. Therefore， comprehensive analysis methods such as natural gas composition and carbon isotope of natural gas were used to study the origin of natural gas and the hydrocarbon migration direction of the K structural belt， clarify the controlling factors for oil and gas migration along fault strike， and summarize the hydrocarbon migration and accumulation patterns along fault strike. The research results show that the natural gas in the K structural belt is mainly coal-type gas， whose maturity is higher than that of the local source rock， and is sourced from the source rock in the eastern subsag. The changing trend of hydrocarbon migration tracing parameters indicates that there are three hydrocarbon migration directions in the study area， all of which are along the fault strike. On the whole， the K structural belt of the Pinghu Slope has a hydrocarbon migration and accumulation model of “vertical migration of damage zone， strike migration along damage zone and sand body， fault zone and cap rock sealing， and high point trap accumulation”. The conditions that oil and gas can migrate long distance along the fault strike are the fault zone and sand body transport channel and the fault has good vertical and lateral sealing. Obvious fault zone structures were developed in the study area， and damage zones had good physical properties， which were the vertical and lateral hydrocarbon migration pathways. The sand bodies of the Pinghu Formation have the characteristics of large thickness， high connectivity， and good physical properties， making it a favorable transporting layer for hydrocarbon lateral migration. The lower limit values of fault juxtaposition thickness for sealing oil and natural gas of the Pinghu Formation are 6 m and 10 m， respectively. The fault juxtaposition thickness of the three main faults is greater than 10 m， indicating good vertical sealing. The SGR values at different positions and depths of the main fault range from 32.1% to 91.1%， which is higher than the lower limit of sealing oil and gas （30%）， and has good lateral sealing.

In view of the unclear understanding of the development range of the Changxing Formation bioreef reservoir in the Longhuichang-Tieshan area of northeastern Sichuan Basin and the vague understanding of the relationship between gas reservoirs， the seismic geological characteristics of bioreef reservoirs were summarized by utilizing the drilling and logging data， and studying the effects of reservoir parameters， structural location and strike-slip faults on the development of bioreef gas reservoirs. The research shows that the bioreef reservoirs in the area are vertically developed in the middle and upper parts of the Changxing Formation， and horizontally developed in the platform margin and the local high landform area in the platform. The west wing of the Longhuichang structure and the southwest side of the Tieshannan structure are potential exploration favorable areas. By comparing and analyzing the relationship between bioreef gas reservoirs in the study area， the controlling effects of reservoir parameters， structural location， strike-slip faults and other factors on the development of bioreef gas reservoirs are clarified. It is found that the above factors have no obvious strong linear relationship but a comprehensive effect on the development of gas reservoirs. The enrichment mode and failure mode of favorable gas reservoirs in the study area are analyzed and established， which provides technical support for further exploration of Changxing Formation bioreef gas reservoirs in northeastern Sichuan Basin.

The Upper Paleozoic in Ordos Basin is the main gas-bearing reservoir， but what restricts the basin’s further exploration is the dispute of different provenance systems and tectonic-sedimentary pattern in the early-middle Permian in the southwest. Based on the main， trace and rare earth elements test results of 85 Lower and Middle Permian samples and 16 zircon analysis data， the sediment sources and their controlled filling processes of the Taiyuan-Shihezi Stage in the southwestern Ordos Basin are comprehensively analyzed by multiple methods. According to the provenance background of trace and rare earth elements， it is considered that the tectonic background of Taiyuan Formation is mainly passive continental margin， and Shanxi Formation and Shihezi Formation are active continental margin and continental island arc. The provenance system of Taiyuan Formation is single and the parent rock composition is complex. In the sedimentary period of Shihezi Formation in Shanxi Province， there were many provenance systems， and the parent rock composition tended to be stable. The zircon U-Pb age of Taiyuan Formation is mainly distributed in 400-500 Ma and shows a single peak distribution. The samples of Shanxi Formation can be roughly divided into three sections： 280-500 Ma， 1 824-1 873 Ma and 2 440-2 569 Ma； the zircon U-Pb age ranges from 254 Ma to 2 769.2 Ma and the zircon age spectrum varies greatly in different regions. Based on the results of various provenances， it is considered that the provenance of Taiyuan Formation in the study area mainly comes from North Qilian， while the influence of northern Central Asian orogenic belt is limited； during the sedimentary period of Shanxi Formation， the uplift of Qilian structural belt intensified and the source was enhanced， but it was lower than the ancient basement in North China in the same period. During the sedimentary period of Shihezi Formation， the source supply of ancient basement in North China Craton increased， while the influence of Central Asian orogenic belt gradually increased and became the second largest source， and the study area of local source supply in North Qinling and North Qilian belongs to the intersection area of north-south source and sink systems in Ordos Basin.

The Zitong Sag is the single tectonic unit without large-scale exploration discoveries in the central part of the Western Sichuan Depression in the Sichuan Basin， and the current understandings on the source rock quality， gas source and exploration prospect are weak. This study indicates that， the terrigenous source rocks in the Zitong Sag are mainly in the Upper Triassic strata with high-over maturity， in which the mudstone in the 3^rd Member of the Xujiahe Formation displays the highest organic abundance with the average TOC content of 2.46%， whereas the mudstone in the Lower Jurassic Baitianba Formation and carbonate rocks in the Middle Triassic Leikoupo Formation mainly display the TOC contents lower than 0.5%， and the effective source rocks have been rarely revealed. Natural gas from the 4^th Member of the Xujiahe Formation in Well MY1 is typical coal-derived gas and derived from the coal-measure source rocks in the 3^rd Member of the Xujiahe Formation， whereas the gas from the 4^th Member of the Leikoupo Formation of in Well YX1 is oil-associated gas and derived from the argillaceous source rocks in the Upper Permian Longtan Formation. The exploration prospect of different strata in the Zitong Sag is constrained by the hydrocarbon supply capacity of source rocks， source-reservoir assemblage， and transportation system. The lower submember of the 4^th Member of the Xujiahe Formation is the most favorable exploration field in the sag followed by the 2^nd Member of the Xujiahe Formation. The understanding of exploration potential of the Middle-Upper Jurassic strata and Middle Triassic Leikoupo Formation is significantly constrained by the conducting system， whereas that of the Middle and Upper Permian strata depends on further study of the physical property of the reservoirs and the distribution of the platform margins， respectively.

Hydrogen， as a versatile and widely applicable clean energy source， is poised to play a pivotal role in the global transition towards sustainable energy systems. Presently， the hydrogen production capacities of existing systems fall short of satisfying the burgeoning demand for clean energy solutions. A new and remarkable development within this context is the emergence of natural hydrogen， a geologically sourced， renewable， and clean hydrogen variant. This has drawn considerable attention from numerous nations， holding the potential to reshape the landscape of hydrogen-based energy in the future. Based on comprehensive research encompassing the current status of natural hydrogen exploration and utilization both on the domestic and international fronts， coupled with advancements in this domain， several critical insights have been gleaned： （1） Several countries， including the United States， Russia， France， and Australia， have made substantial strides in the exploration and research of natural hydrogen gas reservoirs. Plans for drilling and extraction operations are in motion. In contrast， China is still at an incipient stage in this field. （2） Natural hydrogen gas reservoirs exhibit five distinct geological characteristics： extensive distribution within deep strata across major tectonic plate regions globally， structural faults， and intra-layer fractures serving as primary conduits for hydrogen migration， the overall quantity of free hydrogen determining reservoir size， variability in burial depths， and the identification of hydrogen-rich sweet spots within these reservoirs. These features categorize hydrogen reservoirs as dynamic storage systems. （3） Natural hydrogen arises through a multitude of mechanisms， encompassing deep degassing， serpentinization， and water splitting. These hydrogen reservoirs predominantly manifest across seven regions： onshore igneous rock areas， Kimberlite rock formations， ore bodies， evaporite rock deposits， oil and gas fields， rift zone rock formations， and pre-Cambrian basement rocks. （4） Present estimates place hydrogen production at （254±91）×10⁹ m³/a， significantly underscoring the actual resource potential. Consequently， natural hydrogen emerges as a promising cornerstone for global clean hydrogen production. Within this context， it is imperative to consider prevailing research techniques and theoretical developments both domestically and abroad. This， alongside an emphasis on the academic discipline of natural hydrogen， underscores the critical theoretical and technical challenges that confront the development of natural hydrogen in China. In response， this article proffers pertinent recommendations and directions for further study.

Carbonate gas reservoirs are an important field for increasing natural gas storage and production in China，and determining the lower limit of reservoir physical properties is an important research work in various stages of exploration and development. At present，the methods for determining the lower limit of reservoir physical properties in carbonate gas reservoirs in China are scattered and lack systematicity， which contradicts the actual application in mines. In response to this issue， this article systematically summarized and expanded the concept of the lower limit of reservoir physical properties，and proposed a new concept for the study of the lower limit system of reservoir physical properties. The new concept system integrated the relationship between core analysis， testing analysis， and dynamic analysis， and discussed the current research status and existing problems of various methods in these three aspects. Focusing on the needs and contradictions of determining the lower limit of reservoir physical properties in carbonate gas reservoirs，this paper proposed three research suggestions： the principle of systematically studying the lower limit of reservoir physical properties，the systematicity of determining the lower limit of physical properties， the impact of different well types and reservoir transformation processes on the lower limit of physical properties， and the determination of the lower limit of reservoir physical properties based on dynamic analysis results. The aim is to enhance the scientific and effective research of the lower limit of reservoir physical properties in carbonate gas reservoirs，as well as the universality of field applications.

The Bozhong Depression， situated in the heart of the Bohai Bay Basin， is the largest hydrocarbon-rich depression in the Bohai Sea. It is characterized by the development of deep Paleoproterozoic Dongying and Shahejie formations， which are generally associated with overpressure. This study focuses on the deep anomalous high porosity zone in the Well QHD35-A at the east pitching end of Shijiutuo Bulge in the Bohai Bay Basin. The research employs microscopic observation and well logging analysis to investigate the cause of the anomalous high porosity zone and its influence on oil and gas reservoirs. The existence of a pressure sealing box was confirmed based on the research results on tectonic background， depositional background， type of reservoir space， and physical properties of reservoirs. The pressure sealing box， characterized by thick mudstone at the top and bottom and large primary pores in the thick sandstone in the middle， has a significant impact on the transportation and preservation of oil and gas. The sealing of the top， bottom， and lateral directions， along with the internal anomalous pressure， provides conditions conducive to oil and gas preservation and transportation. The findings of this research are beneficial for the identification and utilization of storage tanks and the effectiveness of their closure under such geological conditions.

In order to clarify the karst characteristics and diagenetic facies distribution law of the Carboniferous KT-I layer in B Oilfield， east margin of Pre-Caspian Basin， the following conclusions are drawn from the comprehensive application of drilling core， thin section， conventional physical property analysis and logging data： （1） In the study area， the KT-I layer was obviously reformed by the karst in the early diagenzoic stage， and the karst cycle was closely related to the sedimentary cycle， which controlled the distribution of reservoirs. The high-quality reservoirs mainly developed in the grain beach and dolomite flat in the middle and upper part of the karst cycle. （2） The diagenetic facies of the KT-I layer in the study area can be divided into seven types， which are： eogenetic strong dissolution facies， eogenetic medium dissolution facies， eogenetic weak dissolution facies， eogenetic dolomitization strong dissolution facies， eogenetic dolomitization medium dissolution facies， cementation facies and compaction facies， among which， except the cementation phase and compaction phase are destructive diagenetic phases， the rest are constructive diagenetic phases. （3） The particle beach and dolomite flat of A2 and A3 small layers in the middle and northeast of the study area are the areas where constructive diagenetic facies zone develops， and are the preferred areas for exploration and development of KT-I layer. These understandings have certain theoretical and practical significance for the study of reservoir development mechanism and the later exploration and development of B Oilfield.

The sandstone reservoir still experienced a long time of diagenesis after the key accumulation period， and the reservoir properties have been changing， which belongs to a “dynamic evolution” process. It is often not ideal to evaluate the oil and gas properties of the reservoir in the accumulation period by using the present reservoir physical properties. In view of the above problems， taking the tight sandstone gas reservoir of the first member of Shihezi Formation （He 1 Member） of Lower Permian in Hangjinqi area， northern Ordos Basin as an example， the lower limit of current gas bearing property of tight sandstone reservoir was determined from the perspective of oil and gas accumulation dynamics and combined with various geological data such as analysis， testing， logging interpretation and gas test results. Then the basin simulation and the porosity depth push back are used to recover the increment of porosity change after the reservoir accumulation period， so as to determine the critical physical property lower limit of tight sandstone gas accumulation period. The paleo-porosity recovery method is used to analyze whether the reservoir is an effective reservoir in the accumulation period， and the excess porosity is further used to evaluate the oil and gas properties of the sandstone reservoir. The results show that： （1） The lower limit of gas-bearing porosity of the He 1 Member in the study area is 4.25%， the average increment of porosity after reservoir accumulation period is 3.1%， and the critical porosity during reservoir accumulation period is 7.35%. （2） Through the quantitative restoration method of paleo-porosity evolution， it is determined that most of the sandstone reservoirs in the He 1 Member have not reached the critical porosity of reservoir formation period， and the sandstone reservoir as a whole still has a good lateral transport capacity. （3） There is a better correlation between excess porosity and daily natural gas production， which reveals that it is effective to use excess porosity to evaluate the oil and gas properties of tight sandstone reservoirs. Therefore， the comprehensive determination of critical physical properties of sandstone reservoirs during reservoir formation and the application of excess porosity to evaluate reservoir oil-bearing properties have important guidance and reference significance for unconventional oil and gas reservoir evaluation.

The Songnan-Baodao Sag is another important deepwater exploration area with huge oil and gas exploration potential discovered after the Lingshui Sag in the Qiongdongnan Basin. The structural background of the northern step-fault zone is complex， and it has undergone multiple stages of stress field deformation and superimposed evolution since the Cenozoic era. The complex structural system formed has an important controlling effect on the formation of large and medium-sized oil and gas fields in the deep water area. This paper systematically studies the geometry， kinematics， and dynamics of the Songnan-Baodao northern step-fault zone using newly collected and processed high-precision 3D seismic data and new exploration results covering the research area， based on comprehensive interpretation of fine seismic profile structures and strata， combined with techniques such as quantitative analysis of fault activity， inversion of subsidence history， and restoration of tectonic evolution history. The research results show that the Songnan-Baodao northern step-fault zone is a right step oblique and co directional superimposed step-fault zone composed of No.2 fault， No.2-1 fault， No.12 fault， and No.12-1 fault. It has undergone the evolution process from a high angle normal fault in the direction of Eocene NE to a high angle and low angle extensional detachment fault in the direction of Oligocene near EW， and has controlled the development of large detachment basins in the central depression zone. The large transition zones formed at the overlapping positions of the faults have become the key structural factors controlling the main source rocks， source sink systems， and large reservoirs in the fan delta and braided river delta of the third member of the Eocene and Yacheng Formation.

The key timings related to the petroleum evolution， which play key roles in both exploration target optimization and oil/gas resource assessment， attract petroleum geologists’ attention worldwide. In recent years， the hydrocarbon （oil， bitumen） Re-Os isotope dating was innovatively applied to constrain the timing related to oil/gas generation， however， the obtained Re-Os isochron ages are complex and hard to understand sometimes. Based on various geochemistry and geochronology data on the Sinian to Cambrian nature gas reservoirs of the Sichuan Basin， this work reconstructed the hydrocarbon evolution process of the reservoir and discussed the meaning of various type bitumen Re-Os dating results. The gas accumulation in the Sinian-Cambrian reservoir experienced four stages of evolution and they are （1） initial oil generation during Ordovician to Silurian， （2） secondary oil generation during Triassic， （3） gas generation by thermal cracking of liquid oil from Jurassic to Cretaceous， and （4） gas reservoir redistribution since the Late Cretaceous. The bitumen Re-Os dates （ca. 485 Ma） characterized low maturity and biodegradation from the western Sichuan Basin record the oil generation during Ordovician before Caledonian tectonic event. The Re-Os dates （ca.184-128 Ma） of the highly mature bitumen that associated with the MVT Pb-Zn deposits in the northern Sichuan Basin reflect the information of both liquid oil cracking and TSR process. The complex Re-Os dates （ca. 414 Ma， ca.154 Ma） of highly mature bitumen from central Sichuan Basin seem to record different age information either related oil generation or gas generation. For the future studies， in order to understand the meaning of Re-Os dates， the genetic type， maturity， thermal cracking or TSR degrees of the bitumen are suggested to explore.

The depositional environments of the Lower Cambrian Qiongzhusi Formation in different regions of the Sichuan Basin exhibit significant variations due to structural-sedimentary heterogeneities. However， there has been a lack of systematic comparison and understanding of the geochemical characteristics of deposition in different areas of the Qiongzhusi Formation. By collecting and organizing published geochemical data from 16 wells and nine outcrop sections of the Lower Cambrian Qiongzhusi Formation in the Sichuan Basin， and integrating previous knowledge， a comparative analysis of the sedimentary geochemical characteristics of the Qiongzhusi Formation in different regions of the Sichuan Basin was conducted. The following understandings were obtained with regards to the enrichment of organic matter： （1）The northern section of the Deyang-Anyue rift had a more reducing paleo-environment compared to the southern section， which was more conducive to the enrichment of organic matter and the formation and preservation of high-quality source rocks. （2）From the deepwater shelf area of the rift to the shallow-water shelf area in the northeast of the Sichuan Basin， there was a transition from anoxic to oxidized paleo-environment. Conversely， from the southwestern shallow-water shelf area to the middle section of the Deyang-Anyue rift area and the southwestern shallow-water shelf area to the southeastern shallow-water shelf area， the sedimentary water bodies got more reducing. （3）The northern and central sections of the rift both reflected a high level of paleo-productivity， and the widespread hydrothermal influence during the Qiongzhusi period in the Sichuan Basin provided highly favorable conditions for organic matter enrichment. （4）The organic matter abundance in the northern section of the Deyang-Anyue rift and the southwestern shallow-water shelf area was mainly influenced by paleo-productivity intensity. In the northeastern and southeastern shallow-water shelf area， organic matter abundance was mainly controlled by paleo-redox conditions. The organic matter enrichment in the middle section of the Deyang-Anyue rift was the result of the combined effects of high paleo-productivity and the anoxic to dysoxic paleo-oxygenation conditions. This research contributes to a deeper understanding of the sedimentary environment and hydrocarbon source rock formation conditions of the Qiongzhusi Formation in the Sichuan Basin， providing important theoretical and practical implications for deep and ultra-deep oil and gas exploration.

Typical condensate reservoirs are developed in the No.4 fault zone in Shunbei area of the Tarim Basin. The exploration expansion is restricted by the unclear genetic mechanism and main controlling factors of condensate accumulation.Based on the comprehensive analysis of organic geochemical characteristics and regional geological background， the genetic mechanism and main controlling factors of condensate accumulation of the No.4 fault zone in Shunbei area are identified，and the following understandings are mainly obtained：（1）the condensate oil and gas reservoirs in the No.4 fault zone in Shunbei area are mainly primary condensate reservoirs， and the formation of condensate reservoirs is mainly affected by the differential maturation of organic matter， multi-phase accumulation and secondary alteration； （2） the overall secondary effect of condensate oil and gas reservoirs in the Shunbei No.4 fault zone is relatively weak， but the secondary effect experienced by the middle and southern sections is relatively stronger than that of the northern section； secondary processes include oil cracking， gas invasion， and TSR； and （3） the enrichment degree of condensate oil and gas reservoirs in the northern section of the Shunbei No. 4 fault zone is significantly higher than that in the middle and southern sections； the enrichment and high production of condensate oil and gas are mainly controlled by transport conditions and reservoir size. The stronger the fault activity， the better the transport conditions， the larger the reservoir size， and the thinner the gypsum salt rock， which is more conducive to the upward migration of oil and gas along strike slip faults， resulting in high production and enrichment of condensate.

The study of light hydrocarbon geochemistry is an important component of the study of deep to ultra deep natural gas generation mechanisms. Taking the Tarim Basin and Sichuan Basin as examples， on the basis of light hydrocarbon analysis of 36 natural gas samples from Tazhong I， Keshen， Longgang， Anyue and other gas fields， the light hydrocarbon composition of China's deep to ultra deep natural gas is divided into three types， one of which is dominated by alkanes， such as Ordovician natural gas in Tazhong area of Tarim Basin， reflecting that the gas source mainly enters the initial cracking stage from crude oil； The second type is mainly cycloalkanes， such as natural gas from the Longwangmiao Formation in Anyue Gas Field of Sichuan Basin， which is a product of a large amount of crude oil cracking stage， reflecting the high maturity of crude oil cracking gas； The third type is mainly composed of aromatic hydrocarbons， such as the natural gas of the Cretaceous in the Dabei Gas Field of Tarim Basin， which was generated during the over mature stage of coal bearing source rocks. The different characteristics of light hydrocarbon composition can also reflect the sources of deep to ultra deep natural gas. Deep to ultra deep natural gas related to marine source rocks is mostly rich in alkanes， while most of the gas from coal bearing source rocks is rich in aromatics. In addition， thermochemical sulfate reduction （TSR） may also have an impact on the light hydrocarbon composition of natural gas， and should be considered when studying the sources and formation stages of marine deep to ultra deep natural gas.

The discovery of gas reservoirs in the Kongdian Formation in Wumaying area of Huanghua Depression of Bohai Bay Basin brought a new breakthrough in natural gas accumulation layers and opened up a new exploration field. To reveal the natural gas accumulation pattern and resource potential of the Kongdian Formation， and to promote the exploration of the Paleogene gas reservoirs in the Huanghua Depression， the controlling effects of fault-caprock configuration in the Wumaying area on natural gas migration from the coal source rock of the Upper Paleozoic to the Kongdian Formation was quantitatively studied with the focus on the supply of natural gas， by using well-seismic data. The results show that： （1） Transportation faults provide channels for the vertical migration of natural gas to the Kongdian Formation， and position where fault activity rate during the accumulation period is greater than 3.6 m/Ma is the dominant conduit. （2） The fault-caprock configuration sealing of the third member of Kongdian Formation-Mesozoic Erathem caprocks controls the migration and accumulation layers of natural gas. Vertical leakage occurs in area where caprock faulted-contact thickness is less than 34 m， which is favorable for the migration of natural gas through the caprock to the Kongdian Formation. （3） Fault transmission and fault-caprock configurations sealing jointly control the supply of natural gas to the Kongdian Formation， and the overlap between fault’s dominant conduits and the vertical leakage zones of fault-caprock configuration is a favorable site for natural gas migration to the Kongdian Formation.

In recent years， exploration breakthroughs have been made in Linhe Depression of Hetao Basin， but the research on the geochemical characteristics and oil sources of crude oil is concentrated in the southern Jilantai tectonic belt， while the research on the central Nalin Lake and the northern Xinglong tectonic belt is still lacking. The experimental analysis of Rock-Eval pyrolysis， TOC and saturated hydrocarbon gas chromatography-mass spectrometry is carried out. The results are as follows： （1） The crude oil in the study area is formed in the strong reducing saline environment. The parent source in the southern area is mainly aquatic organisms and algae， while in the northern is dominated by terrestrial organisms. （2） The crude oil in Jilantai tectonic belt comes from the local source rock of Guyang Formation. The crude oil in the Xinglong tectonic belt has the characteristics of “self-generation and self-storage”. The crude oil comes from the same layer， mainly local source rocks. The crude oil in Nalinhu tectonic belt has the characteristics of “mixed source”. （3） The change of maturity， parent source and the existence of sulfur-rich source rock in strong reduction environment led to the great change of crude oil physical properties in the study area. The determination of the characteristics of crude oil and source rock and the relationship between oil and source rock can provide guidance for further research on hydrocarbon generation mechanism and resource quantity， and is also conducive to oil and gas exploration and deployment.

The overpressure distribution in different tectonic locations of the Xinglong structural belt in the Linhe Depression of the Hetao Basin varies greatly and the evolutionary process is complex. The overpressure mechanisms in the Linhe Formation in the study area were identified， the contribution of different overpressure mechanisms and overpressure evolution were quantitatively evaluated， the distribution pattern of overpressure differences in different tectonic sites was clarified， based on well logging， logging and actual measured pore pressure， using the modified overpressure identification plate and numerical simulation method as well as the actual geological conditions. The results show that： （1） the overpressure of the Linhe Formation in the study area gradually increases from the tectonic high part to the trough area， and the overpressure mechanism of source rock in the study area is hydrocarbon generation and disequilibrium compaction， and the overpressure mechanism in the reservoir is disequilibrium compaction and overpressure transference； （2） the composition of the overpressure contribution of each mechanism varies greatly among the different lithological formations in the study area， the contribution of hydrocarbon generation to the total overpressure of the Linhe Formation source rocks in the study area ranges from 56.68% to 89.30%， and the contribution of overpressure transference to the total overpressure of the Linhe Formation reservoirs in the study area ranges from 63.80% to 96.09%； （3） at 5.3 Ma， disequilibrium compaction began to form in source rocks and reservoirs of the Linhe Formation in the study area， and then increased slowly to the present， while hydrocarbon generation in source rocks and overpressure transference in reservoirs began to form since 5.3 Ma and 3 Ma， respectively， and increased rapidly to the present. The results will provide a reference and guide for the future oil and gas exploration work in the area.

Drilling of the second section of the Qingshankou Formation in the Daqingzi well of the Songliao Basin revealed a highly complex distribution pattern of sand bodies. With the continuous deepening of exploration， a series of contradictions between geological understanding and production practice such as early “deep lake type” delta sedimentation and shallow water delta sedimentation have become increasingly prominent. To solve the above problems， the author conducted systematic core observation and core data analysis. Core observation shows that there are a large number of storm rocks indicating the characteristics of storm sedimentation in the Qing-2 section. Lithology and particle size analysis reveal that the sedimentation in the study area has dual attributes of traction flow and gravity flow， indicating that in addition to the development of delta sedimentation， the Qing-2 section also develops storm sedimentation. After analysis and research， the storm rocks developed in the study area can be divided into five types based on the vertical sedimentary sequence： I， II， III， IV， and V. Furthermore， according to the sedimentary process and transportation distance of different types of storm rocks， they will be further divided into three types on the plane： In-situ storm rocks， near source storm rocks， and far source storm rocks. Among them， in-situ storm rocks are mainly classified as Class I， II， III， and IV are all near source storm rocks， and Class V is far source storm rocks. Based on the sedimentary characteristics of storm rocks and their planar distribution， a sedimentary model of storm rocks in the study area was established， thus forming an understanding of the joint effect of delta front sedimentation and storm sedimentation in the Qing'er section of the Daqingzijing area， and reasonably explaining the distribution pattern of actual drilled sand bodies. The research results can provide practical guidance for the efficient exploration and development of oil and gas in the later stage， and can also provide model guidance for sedimentation in similar oilfield areas.

At present， interlayer shale oil is the focus of shale oil exploration and development. How to quantitatively evaluate the occurrence and content of free and adsorbed hydrocarbons in shale oil reservoirs and the fluidity of hydrocarbons is the key to the exploration and development of Chang 7 shale oil. By means of nuclear magnetic resonance and constant velocity mercury injection， the reservoir properties， hydrocarbon occurrence and oil content of Chang 7 interbedded shale oil in the eastern region of Longdong were analyzed. The results of NMR experiments showed that the permeability of Chang 7₁， Chang 7₂ and Chang 7₃ sub-members was not much different， and they were all distributed in about 0.006×10^-3 μm². Among them， Chang 7₂ sub-member had the highest porosity and mobile fluid saturation， while Chang 7₃ sub-member had the lowest. In the constant velocity mercury injection experiment， the average pore radius size of the three sub-members of Chang 7 was not much different （130-150 μm）， but the average throat radius size of Chang 7₃ sub-member （6-8 μm） was significantly better than that of the other two sub-members （less than 0.5 μm）， and the pore throat characteristics of Chang 7₃ sub-member were better than those of the other two sub-members. In terms of the evaluation of free and adsorbed hydrocarbons， the free hydrocarbon content of Chang 7₁ sub-member is significantly higher than that of Chang 7 sub-member， and the Chang 7₁ sub-member has a large area of continuous distribution of sand bodies， so compared with Chang 7₂ sub-member， Chang 7₁ sub-member has more advantages in resource development. For Chang 7₃ sub-member， the total extraction amount and absolute free hydrocarbon content are the highest. If large contiguous sand bodies can be found， it will also have certain development significance.

After the discovery of the Anyue trillion gas field in the Central Sichuan Basin paleo-uplift， marine multilayer systems in the slope area of the paleo-uplift were discovered. The fourth member of Dengying Formation （Deng 4 Member） in the Penglai gas area of the ancient uplift slope has superior reservoir formation conditions， which may be an important area for deep oil and gas accumulation in the basin. Based on the analysis of seismic and logging data， the reservoir formation conditions of the Deng 4 Member in the Penglai gas area are evaluated， the favorable exploration areas are pointed out， and the exploration potential is prospected. Research has shown that： （1） Thick block shaped mound beach facies porous reservoirs are developed in the large platform margin zone of the Deng 4 Member， with reservoir lithology mainly consisting of algal tuff dolomite， algal sand debris dolomite， mud powder crystal dolomite， and siliceous dolomite. The reservoir is 169 m thick and has an average porosity of 3.1%. （2） The sedimentary micro geomorphology and synsedimentary faults jointly control the differentiation of the platform margin facies belt in the Penglai gas area， and the platform depression facies belt is developed in the upward dipping direction of the Deng 4 Member， which has the conditions for lithological sealing. And there are two subfacies developed in the platform margin zone， namely the mound beach body and the depression between the mound beach， which have multiple geological conditions for the development of large-scale lithologic traps. The total area of lithologic traps is 2 650 km². （3） The in-situ accumulation of oil and gas in the Deng 4 Member in Penglai gas bearing area has gone through three stages： the formation of ancient oil reservoirs， the cracking of crude oil into gas， and the adjustment and finalization of gas reservoirs， forming multiple large-scale structural lithologic oil and gas reservoir groups today.

The western area of Kelasu structural belt in Kuqa foreland basin is a key area of oil and gas exploration in Tarim Basin， with natural gas resources of more than one trillion cubic meters. However， it has long been trapped in the problems of complex structural deformation in the western part of the salt-bearing fold thrust belt， which makes it difficult to implement structural traps in the study area. This article is based on the precise interpretation of three-dimensional seismic data in the research area， constructing a two-dimensional geometric structural geological model， and analyzing the lateral salt related structural styles and structural combination characteristics of the Kelasu salt bearing fold thrust belt. The research results indicate that in the western part of the Kelasu Structural belt， there are respectively the development of the Awat segment monocline-thick salt pillow-high amplitude imbricate/stacking structure， the Bozi segment monocline-salt welding + low amplitude salt pillow-imbricate/pop up structure and the Dabei segment monocline + thrust fault-salt welding + salt anticline-imbricate/stacking anticline structure， reflecting a horizontal “east-west segmentation”. Vertically， there are structural features of “differential overlap”. To establish a three-dimensional structural model of the research area， and to further combine the lateral differential distribution characteristics of gypsum layers and the stacking relationship of main faults， it is indicated that the differences in structural segmentation of the Awat， Bozi， and Dabei blocks mainly depend on the preexisting structures and the non-uniform characteristics of salt thickness.

The mineral and rock composition and fabric of the alkaline volcanic clastic rock reservoir in the Chaganhua sub-sag of the Changling Fault Depression in the southern Songliao Basin are complex， and the genetic mechanism， diagenesis， and main controlling factors of the reservoir are unclear， which restricts the prediction and fine characterization of high-quality reservoirs and affects the further efficient development of gas reservoirs. Through microscopic observation， whole rock mineral analysis， mercury intrusion， and nano CT scanning， combined with special logging， this article systematically analyzes the petrological characteristics， volcanic lithofacies characteristics， reservoir microscopic characteristics， and fracture characteristics. It is believed that there are seven main types of diagenesis in the area， including devitrification， dissolution， and alteration. Based on this， the main controlling factors for the development of volcanic clastic rock reservoirs in the Chaganhua sub-sag are clarified. It is believed that the volcanic detrital rocks in this area belong to sodium rich alkaline volcanic rocks， and the type， mineral composition， and rock particle size of the detrital rocks are the material basis for determining the quality of the reservoir. In the later stage， three different types of secondary pores are generated through devitrification， dissolution， and alteration. At the same time， a large number of natural fractures generated by tectonic stress are conducive to the formation of secondary pores， which improves and communicates the microscopic seepage of the reservoir. The formation of a reservoir with the characteristics of "three pores and one fracture" and a unique microscopic seepage field has certain guiding significance for the evaluation and dessert prediction of sodium rich alkaline volcanic clastic rock reservoirs， laying a solid foundation for the subsequent efficient development of gas reservoirs.

This paper focuses on the common problem of low recovery of fractured-porous gas reservoirs due to water invasion， develops a large-scale planar physical simulation model based on a typical gas reservoir geological model， and establishes a large-scale physical simulation experiment method and device for fractured-porous gas reservoirs. Physical simulation experiments on drainage optimization were carried out to enhance gas recovery， and the effects of aquifer size and gas production rate on the water invasion behavior and recovery of gas reservoirs were studied. The effect of drainage timing， drainage volume， and drainage method was explored. The results show that： （1） The water energy acting on a single well and the gas production rate have significant effects on the advancement velocity of the water invasion front， the characteristics of water invasion， and the gas reservoir recovery. The deployment of the well network and the recovery rate should be optimized to reduce the water invasion damage during the development process. （2） The technical measures such as drainage timing， drainage volume， and drainage method have significant effects on enhancing gas recovery， and reasonable optimization plans should be reformulated according to the actual conditions of gas reservoirs. The results of the study are useful for formulating technical schemes for similar reservoirs to enhance gas recovery.

The deep sandstone of Huagang Formation in Xihu Depression of East China Sea Basin belongs to the ultra-low porosity and ultra-low permeability tight reservoir. The mechanism of pore structure is unclear due to intense diagenesis. Optical microscope， SEM-CL， SEM-EDS， XRD， NMR， HPMI and RCP were used to ascertain the mineral composition， diagenetic characteristics and pore formation mechanism of reservoir， quantitative characterization of micro-porosity structure of reservoir and analysis the influence of sedimentation and diagenesis on the pore structure of reservoir. The results show the existence of three main pore types： dissolution pores， intergranular pores of clay minerals and primary pores. Due to the characteristics of coarser grain size and higher quartz content， the high-energy braided river channel has a better pore throat preservation ability and pore structure. Both quartz cementation and clay mineral cementation worsen the pore structure， but the pore structure is more affected by clay mineral cementation. Due to the weak dissolution degree of K-feldspar in the study area， the effect of dissolution on pore structure differentiation is mainly reflected in debris dissolution on the pore structure. Mobile fluid porosity is more suitable for characterizing reservoir fluid mobility. Both clay mineral cementation and quartz cementation reduce pore throat size and expand pore throat distribution， resulting in lower mobile fluid porosity.

The accurate calculation and distribution characteristics of CBM saturation are directly related to the prediction of CBM enrichment area and the effective formulation of CBM development plan. Based on the adsorption isotherm curve of coalbed methane in the Daning-Jixian gas field， this paper gives a calculation model of coalbed gas saturation， and then fully excavates the geophysics logging information， a logging method is established to determine the parameters of Lannister volume， Lannister pressure， reservoir pressure and gas content in coal bed gas saturation， and a logging method for deep coal bed gas saturation is formed. The method is programmed to realize the computer visual automatic processing of gas saturation of 8^# coal reservoirs in each well depth in the area， and the plane distribution map of gas saturation in the study area is drawn. The study shows that the method described in this paper can be used to calculate the gas saturation of 8^# coal reservoir in the deep part of the study area， and the gas saturation of the coal bed in the study area increases from east to west on the whole， from the north to the south after the first decline， and then decline after the increase. The supersaturated gas reservoir area is located in Wells Daji 50 and Daji 37 in the south of the study area， and the saturated gas reservoir area is mainly located in the north and middle of the study area. This method can provide a new way for geophysics log to predict gas saturation in deep coalbed and a basic parameter for prediction of CBM enrichment area.

Helium is an important strategic resource that plays an irreplaceable role in aerospace， medical imaging and high-tech manufacturing.Noble gases have three major sources： crust， mantle and atmosphere， and their isotopic characteristics vary greatly among reservoirs， which can effectively reveal the crust-mantle evolution and the interactions between the various layers， and provide an important tool for tracing the enrichment process of “weak source” helium. Here it summarized the studies on the noble gas isotopic characteristics in typical helium-rich areas such as Hugoton-Panhandle in the U.S. and the oil and gas fields in the northern margin of Qaidam Basin in China， as well as the hot springs in the Tanzanian rift zone and the geothermal gas in the Weihe Basin in China. The results show that the helium-rich reservoirs were discovered in petroliferous basins in China and most of the ³He/⁴He ratios that are currently valuable for industrial exploitation in the world show a crustal source， i.e.， they are generated through the alpha radioactive decay of helium source elements such as uranium and thorium. In addition， the ²⁰Ne/³⁶Ar ratios that are currently valuable for industrial exploitation in the world show a crustal source， i.e.， they are generated through the alpha radioactive decay of helium source elements such as uranium and thorium. In addition， the ²⁰Ne/³⁶Ar ratios and isotopic concentrations of ²⁰Ne and ³⁶Ar in different reservoirs are quite different， suggesting that the helium-rich reservoirs have undergone different oil-gas-water equilibrium processes， and helium enrichment is closely related to the transportation of the groundwater and main gas components. The positive correlations between ⁴He and ²⁰Ne in hydrocarbons and N₂ gas reservoirs rich in crust-derived helium indicate that the enrichment of ⁴He in gas reservoirs may be closely related to groundwater， and that helium should be dissolved in groundwater before being exsolved into the gas reservoirs. Besides， mantle-derived CO₂ reservoirs are usually small in size and the process of helium enrichment may be due to the nature that CO₂ can be easily dissolved in groundwater or be mineralized into carbonate minerals， resulting in the decrease of CO₂ concentration and the increase of the relative abundance of helium. In the end， four favorable conditions for helium reservoir formation were further put forward： sufficient helium sources from ancient cratons and U-T-rich granites， development of new tectonic activities，existence of groundwater systems and free gas phases， and moderate recharge of the main gas components in the reservoir relative to helium gas.

The flowback fluid and produced water （FPW） generated from shale gas extraction containing a large amount of organic contaminants are highly uncertain and complex， posing a threat to the ecosystem and human health. While numerous studies have quantitatively or qualitatively analyzed the key components of organic contaminants in FPW in the United States， systematic research on the types and concentrations of organic contaminants related to shale gas exploitation in China is still lacking. This study aims to provide a comprehensive overview of the composition of organic contaminants in FPW from shale gas exploitation in both China and the United States. Furthermore， it analyzes major differences in key organic contaminants between the two countries and explores potential reasons for these variations. The research suggests that the concentrations of the majority of organic compounds in FPW from China are lower than those found in the United States， such as benzene series compounds and polycyclic aromatic hydrocarbons. However， there is still a lack of quantitative data on organic compounds in FPW. This emphasizes the need to intensify efforts in identifying and quantitatively analyzing priority pollutants that are specific to the shale gas exploitation in China.

Through the analysis of natural gas composition， carbon and hydrogen isotopes of alkane gases， reservoir bitumen， source rock conditions， and source-reservoir combination， the gas source differences and sources of natural gas in the Permian Changxing Formation-Triassic Feixianguan Formation on both sides of the Kaijiang-Liangping trough were clarified， and favorable exploration directions for the coal-formed gas generated by the Longtan Formation were pointed out in the Sichuan Basin. The following understanding was obtained： （1） The natural gas in the Changxing-Feixianguan formations is mainly composed of alkane gas， which is typical dry gas； （2） The carbon isotope values of methane and ethane in the Changxing-Feixianguan formations on the east side of the trough are lighter than those on the west side. The ethane carbon isotope in the Longgang Gas Field on the west side is heavier than that in the Yuanba Gas Field， while the value of methane hydrogen isotope is lower than that in the Yuanba Gas Field； （3） The natural gas from Luojiazhai， Puguang， and Yuanba gas fields mainly comes from the sapropelic organic matter of the Wujiaping Formation with kerogen type II₁-I； the Longgang Gas Field is a mixture of coal-formed gas and oil type gas， with a slightly higher content of coal-formed one， originating from the mixed organic matter of the Wujiaping Formation with kerogen type of II₁-II₂； （4） Multiple types of gas， such as coal rock gas， tight sandstone gas， and shale gas， can be formed within the Longtan Formation. The Suining-Luzhou and Langzhong-Guang'an-Fuling areas are favorable zones for the exploration of coal rock gas and marine-continental transitional shale gas， respectively. The reef and shoal development areas of the Changxing Formation in the Suining-Hechuan and Guang'an-Nanchong areas are also favorable exploration areas for coal-formed gas.

The residual distribution of the Permian in the northern margin of the Qaidam Basin has attracted significant attention due to its relevance to gaining a deeper understanding of the late Paleozoic sedimentary and tectonic evolution and facilitating further development and utilization of energy resources. This study focuses on the field geological observations and systematic detrital zircon geochronology research of the Taiyuan Formation in the Mobar section of the Lenghu area， located in the western section of the northern margin of Qadam Basin. In this study， tuffaceous sandstones were identified in the western section of the northern margin of Qaidam Basin. The detrital zircons from these sandstones yielded an average age of 294 Ma， we think that these strata should be defined as the Lower Permian. Furthermore， by integrating the characteristics of detrital zircons and lithological assemblages from the eastern section， it is inferred that Early Permian sedimentary strata are extensively preserved in Qaidam Basin. The collected samples from the Lower Permian mainly exhibit two detrital zircon age groups， ranging from 280 to 329 Ma and 415 to 468 Ma， respectively. The primary sources of these age groups correspond to various magmatic rocks in the tectonic belt of the northern margin， the ultrahigh-pressure metamorphic belt of the northern margin of Qaidam Basin， the Liuhe Group， and the Dakendaban Group. Since the Permian， the Kunlun Ocean has been characterized by continuous subduction， plate fracturing， or retreat， and significant upwelling of the asthenosphere beneath the subduction zone. This has triggered transient and large-scale volcanic activity， with volcanic debris serving as the main source for the sedimentary strata. The discovery of the Upper Paleozoic-Lower Permian strata in the study area provides a new direction for oil and gas geological research and exploration deployment in the northern margin of Qaidam Basin.

The granitic buried-hill is an important oil and gas exploration field in the deep water area of the Qiongdongnan Basin in the western part of the South China Sea， among which the granitic buried-hill area of the Lingnan Low Uplift has a low degree of natural gas resources exploration and great exploration potential. In order to accelerate the exploration process of the buried-hill on the Lingnan Low Uplift， the comprehensive evaluation of hydrocarbon accumulation conditions such as hydrocarbon source conditions， reservoir cap combination， and transmission system was carried out， and a variety of geophysical means were combined to predict the fracture reservoirs in the buried-hill and pointed out favorable targets for subsequent evaluation. The results show that： （1） The buried-hill on the Lingnan Low Uplift， adjacent to the Ledong-Lingshui hydrocarbon-rich sag， developing the coupled reservoir cap assemblage composed of Neogene thick cover of marine mudstone and Mesozoic granite buried-hill reservoir， having the advantages of composite migration mode composed of large source-connected faults， buried-hill insider faults and inherited structural ridges， as well as large source storage pressure difference and near-source charging， has superior storage conditions. （2） The application of likelihood， ant body， curvature body and attribute fusion technology， combined with regional tectonic stress field and main fault production status， comprehensively predict the spread characteristics of the buried-hill fracture reservoirs in the Lingnan Low Uplift， and delineate the favorable exploration area， such as Ling 1 and Ling 4， which is helpful to promote the subsequent exploration and evaluation work. The Lingnan Low Uplift， having excellent hydrocarbon accumulation conditions， which is predicted that there are multiple tectonic zones with reservoir development and high probability of large-scale accumulation， is a new favorable direction for oil and gas exploration in the deep water areas in addition to the Central Canyon of the Qiongdongnan Basin.

The study of pore throat structure characteristics of tight sandstone reservoirs in the 8th member of Yanchang Formation （Chang 8 Member） in Zhijing-Ansai area of Ordos Basin is mainly based on qualitative description methods such as casting thin sections， scanning electron microscopy and micron CT scanning， combined with quantitative analysis methods such as high pressure mercury injection and nuclear magnetic resonance. The analysis mainly focuses on the correlation between the pore throat structure and the oiliness of tight sandstone reservoir. The results indicate that the tight sandstone reservoir in the study area mainly features residual intergranular pores， solution pores， and intercrystalline pores. The overall displacement pressure and median pressure of pore throat are high， the radius of pore throat is small and the connectivity is poor. The mercury injection capillary pressure curve for intergranular pores is superior to that of intragranular pores， showing high mercury saturation， and NMR exhibits clear bimodal or trimodal patterns. The oiliness of the tight sandstone reservoir is influenced by pore throat size distribution， the relative proportion of pores to throats， and pore throat connectivity. Pore-throats favoring oil and gas charging fall within the radius range of 0.01-1.0 μm， and the frequency distribution of pore-throats within this range should account for over 40% of the total pore-throat count. Optimal oiliness is associated with a moderate ratio of pores to throats， better pore-throat sorting， and improved connectivity.

The Xujiahe Formation in the eastern Sichuan Basin is an important oil and gas exploration layer. However， the lack of macroscopic understanding of the temporal and spatial configuration of the provenance-sedimentary pattern under the constraints of the basin-mountain coupling relationship has restricted further exploration and development. On the basis of drilling and field outcrop observation and two-dimensional seismic line data， combined with the characteristics of paleocurrent， heavy mineral assemblage， rare earth elements and detrital zircon， the paleogeographic evolution process under the control of peripheral tectonic activities was established. Three provenance systems were divided： the Micang-Dabashan tectonic belt， the Jiangnan-Xuefeng tectonic belt， and the Qianzhong ancient land. It is mainly continental clastic rock deposition and braided river delta-lake sedimentary system is developed. The delta sedimentary system was developed in each period， and the lake sedimentary system was mainly developed in the middle area of the T₃ x ³， and migrated to the west in the T₃ x ⁵. In the Late Triassic， the subduction of the Yangtze plate and the North China plate collided with the orogenic movement， which also interact with the Cathaysia block， so that the Micang-Dabashan tectonic belt uplifted and the supply gradually increased， and the Jiangnan-Xuefeng tectonic belt continued to supply. During the T₃ x ³ period， the Micang-Dabashan tectonic belt gradually began to be active but its supply was limited. The Jiangnan-Xuefeng orogenic belt was widely uplifted and eroded. The sedimentary center was located in the central Dazhu and Linshui. During the T₃ x ⁴-T₃ x ⁵， the intensification of tectonic action caused the strong uplift of the surrounding provenance area. It was a multi-provenance deposit. The sedimentary center migrated westward to Guang'an and Hechuan areas. During the T₃ x ⁶， the Yangtze block continued to subduct northward， so that the Micang-Dabashan tectonic belt remained uplifted and the exposed basement was eroded. The sand bodies were gradually filled up. The sedimentary center continued to migrate westward to Tongnan area. The reconstruction of the paleogeographic evolution under the control of the peripheral tectonic belt of the Xujiahe Formation provides important practical guiding significance for oil and gas exploration.

The Longwang Formation gas reservoir in Moxi area of Sichuan Basin has great resource potential， but the gas reservoir has strong heterogeneity and complicated gas-water relationship. The main controlling factors of water invasion under different water invasion modes are not clear， and the increasingly severe water invasion situation makes it difficult to effectively use the reserves， thus affecting the gas reservoir recovery. Based on the data of core， thin section， conventional and imaging logging， seismic and production dynamics， the types of producing wells are divided， and the main controlling factors and rules of water invasion in different well areas are determined by combining dynamic and static data. The results show that： （1） According to the characteristics of water production， wells can be divided into four types： fast rising， slow rising， stable and compound types， and the water production characteristics of four types of wells are obviously different. （2） Different water production types are controlled by the coupling of the fracture development degree， the distribution of karst cavern high permeability layer， the tectonic amplitude and reservoir connectivity. Fast-rising water-producing wells are mainly controlled by the degree of fracture development， continuous-rising water-producing wells are mainly controlled by the distribution of dissolved cave-type high-permeability layers， stable water-producing wells have relatively homogeneous reservoirs， and composite water-producing wells are controlled by multiple factors. （3） Different well areas show different water invasion modes under the influence of different main controlling factors： the water influx mode in the MX009-3 well area is fractured water channeling type with fast water influx speed and high water production； the water influx mode in the MX8 well area is the high permeability layer fingering type， and the water production rate rises rapidly and then tends to be stable； the MX10 well area is an apparently homogeneous reservoir， the water invasion mode is edge water tongue type， and edge water advance is relatively uniform； the MX204 well area is located in the gas-water transition zone， which shows the bottom cone transgression type. The research results can provide geological guidance for improving gas reservoir recovery and adjusting development technology policy， and provide reference for the research and development evaluation of water invasion law in the same type of water gas reservoir.

High-quality reservoirs have been discovered in the southwestern part of Baiyun Depression in the Pearl River Mouth Basin of the South China Sea through new drilling wells， but there are few studies on the pore evolution and diagenetic processes of the reservoirs of the Zhuhai Formation in this region， which restricts the evaluation of high-quality reservoirs and the effective prediction of potential sweet spot zones. In this paper， the latest deep-sea drilling core of the Zhuhai Formation in Baiyun Depression was selected as the research object， and then based on a large number of thin sections， cast thin sections， X-ray diffraction， and rock physical property tests， a systematic study was carried out to investigate the rock characteristics， pore evolution， diagenesis， and the impact on reservoir properties. It is found that the sandstone reservoirs of the Zhuhai Formation are mainly feldspathic sandstone and feldspathic clastic sandstone. The pore types of the reservoir are mainly primary and secondary dissolution pores， and the primary pores are mostly modified， while the dissolution pores are more common. The sandstone reservoirs of the Zhuhai Formation in the target area have experienced strong diagenetic modification， including compaction， cementation， dissolution， and accountable action. This paper summarizes the existence of four typical diagenetic phases in the Zhuhai Formation in the southwestern Baiyun Depression， the mechanically compacted phase of medium-fine-grained sandstone， the siliceous cementation phase of medium-fine-grained sandstone， the carbonate cementation phase of fine-fine-grained sandstone， and the mixed cementation-dissolution phase of medium-fine-grained sandstone， and analyzes the coupling relationship between diagenesis， diagenetic phase and pore evolution. Through the analysis of the factors affecting the development of high-quality reservoirs， it is found that compaction is the main factor controlling the quality of reservoirs， and it controls the physical properties of reservoirs at different depths； cementation and dissolution are the secondary factors controlling the physical properties of reservoirs， and they control the differences in the physical properties of reservoirs in different phase zones； the content of carbonates and clays are obviously negatively correlated with their physical properties； reservoirs close to hydrocarbon centers receive a large amount of acidic fluids， which cause a large amount of acidic fluids， which cause the coupling relationship between the stage of formation and pore evolution. The reservoir near the hydrocarbon center receives a large amount of acidic fluids， and the secondary pores formed by dissolution greatly improve the physical properties of the reservoir. This study is beneficial to enriching the theoretical system of reservoir research in the Zhuhai Formation of the Baiyun Depression and is also conducive to the regional evaluation， prediction and description of reservoirs， as well as providing a scientific basis for oil and gas exploration under similar geological conditions.

This research focuses on the contentious issue of oil-gas content and multiple sets of source rocks and oil-source relationships in the Carboniferous and Permian of Well J15 in the Jimsar Depression， eastern Junggar Basin. Through analysis of physical properties， group composition， carbon isotope and biomarker characteristics of crude oil and oil sands in the Upper Paleozoic， crude oil is classified into types A， B， and C， based on biomarker composition and carbon isotopes. The origins of these oil types are defined， leading to the establishment of a C-P oil and gas accumulation model. Type A oil is found in the Wutonggou Formation and Upper Lucaogou Formation， sourced from low-maturity oil in the saline lake source rocks of the Lucaogou Formation. Type B oil is located in the Lower Lucaogou Formation and the top of the b member of Songkaersu Formation. It is sourced from higher maturity source rocks in the deep depression of the b member of Songkaersu Formation， and is mixed with a small amount of crude oil produced by the Lucaogou Formation， exhibiting lateral migration characteristics. Type C oil is found in the volcanic rock interlayer within the source rock of the Songkaersu Formation， representing low-maturity oil from near-source self-generation and self-storage. This understanding affirms the effectiveness of the Carboniferous source rocks in the eastern Junggar Basin， providing a crucial basis for the exploration of the strategic breakthrough area of Carboniferous oil and gas.