The coal seams of Shanxi Formation and Benxi Formation of Upper Paleozoic in Yan'an Gas Field are developed， and the burial depth is generally more than 2 000 m. The coal seams are widely distributed and have great exploration and development prospects， which can provide strong support for future deep coalbed methane exploration and research. In this study， 5^# coal seam and 8^# coal seam in the deep part of typical wells in Yan'an Gas Field were selected for high-precision coalbed methane field analysis experiments. Through a variety of experimental methods and means， the characteristics of coal and rock reservoirs， differential gas-bearing characteristics and their main controlling factors were studied in depth. Four evaluation units were divided in the eastern， central， western and southern areas of Yan'an Gas Field. Taking 5^# coal seam and 8^# coal seam as the main evaluation layers， the potential of deep coalbed methane resources in Yan'an Gas Field was evaluated by various resource evaluation methods. The results show that the thickness of 5^# coal seam is thin， with an average of 1.6 m； the thickness of 8^# coal seam is relatively large， with an average of 2.3 m. The coal and rock of 5^# coal seam and 8^# coal seam are characterized by ultra-low porosity and ultra-low permeability reservoirs. The pore development is mainly affected by organic matter and minerals， resulting in complex pore structure characteristics. The 5^# coal seam and 8^# coal seam have high organic carbon abundance， large porosity and permeability， and high vitrinite content， indicating that they have strong adsorption， good reservoir physical properties and pore connectivity. The coal rock has entered the stage of dry gas generation， and the potential of coalbed methane resources is large， which is conducive to the formation of coalbed methane reservoirs with high abundance. The four selected old natural gas wells are all successfully ignited， indicating that the deep coalbed methane potential of 5^# coal seam and 8^# coal seam is great. Through the volume method and analogy method， the coalbed methane resources of 5^# coal seam and 8^# coal seam in Yan 'an gas field are calculated to be （2.96-3.54）×10¹² m³，and the coalbed methane resources are calculated by Delphi method weight to be 3.06×10¹² m³， which shows the high exploration potential of deep coalbed methane in Yan'an Gas Field. It is concluded that the 5^# coal seam and 8^# coalbed methane in Yan'an Gas Field have good accumulation conditions and great exploration and development potential， and are expected to become the replacement resources for the continuous and stable production of the gas field.

Significant breakthrough in petroleum exploration has been obtained recently in the Ordovician strata in the eastern Shunbei area， Tarim Basin， which is benefit from the identification of fault-controlled carbonated fracture-vuggy reservoir and prediction of its distribution. As the exploration moves into westward area， the development of multiple sets of complex intrusive rock in the Upper Ordovician has caused poor seismic imaging， which has great impact on the identification of fractures and reservoirs in the Middle and Lower Ordovician and restricts the exploration process in this area. Based on the drilling， 3D seismic data and regional geological background， this study established a variety of complex intrusions and fracture-vuggy reservoirs model and carried out seismic refection forward modelling of Middle and Lower Ordovician reservoirs on the basis of detailed study of the characteristics of intrusions developed in the Upper Ordovician in the Shunbei area. According to the study， the intrusive rock not only leads to the disjunction of phase at the edge of the intrusion in the seismic profile， but also forms pseudo-faults in the Upper Ordovician underside. In addition， the nearly horizontal thick-bedded， multi-layered intrusions can also cause the formation of multiple waves in the Middle and Lower Ordovician. Furthermore， the multiple waves can strength the amplitude of the beaded reflection caused by the fractures and cavities， which increase the difficulties in the re-cognization of the favorable reservoirs. By combining forward modeling and seismic attributes， the fault identification method is defined， both of the relationship between intrusive rock thickness and amplitude and the influence degree of intrusive rock on reservoir imaging are quantified， all of which can greatly improve the reliability of fault identification and the accuracy of reservoir description， thus provide a geophysical basis for the next exploration deployment.

“全国沉积学大会”是由中国地质学会沉积地质专业委员会、中国矿物岩石地球化学学会沉积学专业委
员会发起的四年一届的全国性学术会议， 是全国沉积学界交流的最高学术平台。第八届全国沉积学大会定
于2025 年4 月22—25 日在北京市举行。本次大会共设置7 个议题，33 个专题。其中专题5-E2“陆相细粒沉
积及资源效应”：面向陆相细粒沉积及资源效应基础理论前沿和热点，包括不同类型湖盆细粒沉积发育机理
与有机质富集模式，构造—气候等重大地质事件对湖盆细粒沉积发育、有机碳埋藏的影响，有机—无机相互
作用与细粒沉积成岩、生烃差异，陆相页岩油储层形成与富集等前沿科学问题和陆相页岩油勘探面临的关
键问题。
为集中探讨陆相细粒沉积及资源效应基础理论前沿和热点，加速推动细粒沉积及其油气资源的勘探开
发与产业化发展，专题召集人一致同意，在《天然气地球科学》组织“第八届全国沉积学大会：陆相细粒沉积
及资源效应”专辑，就陆相细粒沉积及资源效应等相关研究及应用撰文讨论，以期开拓新的研究思路，加强
学科交叉与学术创新。专辑拟定于2025 年下半年以正刊形式在《天然气地球科学》刊出。
请感兴趣的专家学者积极参会，并投稿。
1. 专辑征稿范围（包括但不限于）
（1）重大地质事件与陆相细粒沉积；
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（3）陆相细粒沉积岩形成机理与发育模式；
（4）有机—无机相互作用与陆相细粒沉积成岩—生烃演化；
（5）陆相页岩储层形成机理；
（6）陆相页岩油富集机理与勘探开发进展。
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2025 年4 月30 日。
4. 会议/专辑召集人
邱 振 高级工程师 中国石油勘探开发研究院 qiuzhen316@163.com
梁 超 教授 中国石油大学（华东） liangchao0318@163.com
刘忠宝 高级工程师 中国石化石油勘探开发研究院 liuzb.syky@sinopec.com
卞从胜 高级工程师 中国石油勘探开发研究院 biancongsheng@126.com
杨伟伟 正高级工程师 中国石油长庆油田分公司 yww1_cq@petrochina.com.cn
李一凡 副教授 中国地质大学（北京） liyifan@cugb.edu.cn
孙平昌 教授 吉林大学 sunpc@jlu.edu.cn
吴 靖 教授 山东科技大学地球科学与工程学院 wujing6524982@163.com
王永超 高级工程师 中国石油大庆油田勘探开发研究院 wyc0168@126.com
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6. 专辑联系人
李小燕 0931-8277790 lixy@llas.ac.cn
 

Recent exploration has shown that the Ordos Basin has a good potential of helium resource. However， its distribution and resource calculation method are still controversial， which impede the understanding of the helium enrichment rule and subsequent exploration in the Ordos Basin. Therefore， we systematically studied the Changqing oilfield helium contents， distributions， and its resources. The results show that helium in Qingyang，Yichuan and western Sulige gas fields are above the industrial and enriched helium standards，which have the helium contents of 0.121%-0.204%（averagely 0.144%），0.060%-0.177%（averagely 0.086%） and 0.018%- 0.168%（averagely 0.053%），respectively. In contrast， Yulin， Jingbian， Shenmu， and Zizhou-Mizhi gas fields generally have relatively lower helium concentrations （averagely 0.034%）. Such distribution characteristics reveal that the content of helium in the margin of the basin is higher than that of the center. Vertically， the highest helium appears in the Permian and the lowest appears in the Ordovician. According to the new established helium resources evaluation method， the calculated in-situ helium production of He-8 and Shan-1 reservoirs is 6.27×10⁶ m³ and 1.39×10⁶ m³ respectively， accounting for 52.69% and 3.11% of the total helium production， which means the external source rocks is the main contributing source area of helium. The helium production of the metamorphic basement， sedimentary sequences， and Indosinian magmatic plutons in the southwestern margin of the basin is 2.14×10¹⁰ m³， 1.44×10¹⁰ m³， and 1.74×10⁷ m³， respectively， with total helium resources of about 358×10⁸ m³.

With the development of deep and unconventional oil and gas exploration， condensate oil has attracted more and more attention as a high-quality resource. For systematic study the exploration status and the complex formation mechanisms of condensate oil and other key problems， the condensate oil has been analyzed in terms of definition， exploration history， distribution characteristics， origin classification and quantitative analysis. It is pointed out that the proved geological reserves of condensate oil in China are about 710 million tons and there are 163 condensate oil and gas fields （reservoirs）. Condensate gas fields with proven reserves of more than 10 million tons mainly distributed in Tarim Basin and Bohai Bay Basin， which has the characteristics of the coexistence of large condensate gas fields in eastern and western China. On the basis of innovative understanding of primary condensate gas reservoirs， the source-reservoir relationship and other factors are further considered， and the two types of primary and secondary condensate gas reservoirs discovered in China are further divided into two sub-categories： Remote （external） and near （internal）. It also improves the shortcomings of primary condensate gas reservoirs in the aspects of hydrocarbon generation parent material， evolution stage and accumulation mode. According to the established new genetic types， we then reviewed the genetic types and accumulation characteristics of condensate gas reservoirs in China. It is pointed out that no matter in terms of the number of condensate gas reservoirs or proven reserves， China's condensate oil is mainly of primary origin. The primary condensate in China accounts for about 70% of the total proved geological reserves， and the proportion of secondary condensate is about 30%. The proportion of remote （external） accumulation types （about 57%） is higher than that of near （internal） （43%）.

The deep shale gas reservoirs in the north Luzhou District of the Sichuan Basin are affected by multiple phases of tectonic movements， and are characterized by complex tectonic conditions， rapid changes in in-situ stress， which leading to the difficulties of in-situ stress prediction. A specific in-situ stress seismic approach based on pre-stack azimuthal anisotropic inversion is proposed. Pre-stack AVAZ inversion approach applied azimuthal anisotropy AVA equation under Bayes theory framework. The elastic and anisotropic parameters of the shale gas reservoir are inverted from pre-stack Offset Vector Tile （OVT） gather. Meanwhile， a formula Differential Horizontal Stress Ratio （DHSR） based on the fracture density and Poisson's ratio representation is derived， which is utilized to estimate the DHSR of shale gas reservoir. Wufeng Formation-Long 1 submember and favorable areas for shale gas exploration and development were delineated. This provides reliable geophysical evidence for reserve evaluation， well trajectory design， and reservoir stimulation in the study area. Using this method， deep shale gas in the Wufeng Formation–Long11 subsection of the northern Luzhou area in the Sichuan Basin was predicted by DHSR， and favorable areas for shale gas exploration and development were delineated. This provides a reliable geophysical basis for the reservoir evaluation， well trajectories designment， and reservoir modification.

The largest integrated marine carbonate gas field-Anyue Gas Field in China has been found in the central Sichuan Basin. However， the deep （>4 500 m） carbonate reservoir has low porosity-permeability and extremely strong heterogeneity， which has constrained the large-scale production and development in the deep carbonate reservoirs. For this contribution， the small （vertical displacement <20 m） strike-slip faults interpretation and seismic prediction of the strike-slip fault damage zone are carried out in Anyue Gas Field， and has firstly deployed well drilling on “sweet spot” reservoir （high porosity-permeability reservoir） along the strike-slip fault zones. Based on steerable pyramid reprocessing of 3D seismic data， the small Ⅲ-IV order strike-slip faults can be identified， and the total 1 860 km length of strike-slip faults in Anyue Gas Field have been found and mapped. The symmetric illumination attribute processed by the navigation pyramid was used to characterize the deep dolomite strike-slip fault fracture zone. The area of the strike-slip fault fracture zone was discovered and confirmed to be 1 440 km²， indicating that there is a large-scale fault-controlled “sweet spot” along the weak strike-slip fault zone. Through these data， a new development plan of the deep gas reservoir is proposed from sedimentary microfacies-controlled large-scale reservoir to preferential drilling of fault-controlled “sweet spot” reservoir. In this context， pilot test wells have been firstly deployed in different fault damage zones， and subsequently completed wells have penetrated fracture-vug reservoirs and obtained high gas production more than one times in the deep reservoirs. In the deep carbonate reservoirs， 49 development wells located in the strike-slip fault damage zones had an annual gas production up to 50.4×10⁸ m³ in 2023， which is the first pre-Mesozoic deep strike-slip fault-controlled large gas fields. The development practice in Anyue Gas Field has suggested a tremendous potential of high-yield and high-efficient development of deep strike-slip fault-controlled “sweet spot” reservoirs， and initiated a new exploitation frontier of deep strike-slip fault-controlled gas reservoir in the Sichuan Basin.

Although the sedimentary environment of the Chang 7 shale of Yanchang Formation in the Ordos Basin has been extensively studied， it remains a topic of ongoing debate， especially in the northern margin of the basin. This is due to the highly heterogeneous nature of the lacustrine shales and the substantially different depositional environment. To address this issue， we collected shale cores from the Well F75 located in the northern part of the Ordos Basin， and systematically measured the biomarker proxies， aiming to provide new insights into this debate. The results show that the Chang 7 source rocks in the northern part of the basin have high organic carbon contents， with an average TOC of 4.58% and an average S ₁+S ₂ of 18.03 mg/g. The organic matter is primarily type II₁， indicating that the studied samples can be categorized as the premium source rocks. The thermal history across the entire well shows that the samples are mostly in the low maturity stage， with some being immature. Among all the samples， those in the Chang 7₃ sub-member have relatively higher organic matter abundance， maturity and hydrogen index， allowing them to have better hydrocarbon potential. Biomarker compounds show that the Chang 7 Member was， in general， deposited in a reducing freshwater sedimentary environment. Additionally， the C₂₇-C₂₈-C₂₉ sterane distribution indicated that the organic matter of Chang 7₁ and Chang 7₂ was mainly derived from phytoplankton， while that of Chang 7₃ instead mainly derived from mixed sources， particularly in a specific depth. In the middle section of Chang 7₃ sub-member， there is a significant shift in the organic matter source and sedimentary environment. The organic matter is unexpectedly dominated by terrigenous higher plants， and the reducibility of the water body is shown to be weakened. This change reflects a high influx of terrigenous material， which may be linked to enhanced flood events due to warm and humid climate. When comparing the shales from the southern and northern margins of the basin， it is clear that the gammacerane index value is higher in the southern， with higher C₂₇ sterane content and lower C₂₉ sterane content. In the southern margin， the water body was relatively stable with higher salinity， more pronounced stratification， and predominantly planktonic organic matter serving as the primary source for the organic-rich sediment. Additionally， widely deposited volcanic ash is evident along the southern margin. Hence， the varied sedimentary conditions along the northern and southern margins of the Ordos Basin account for the different organic matter enrichment. The pronounced volcanic events close to the southern margin introduced substantial nutrient influx， fostering prolific primary productivity， including algae and plankton， which led to relatively high organic matter accumulation. In contrast， the notable terrigenous influx along the northern margin diluted the organic matter content， with a relatively greater contribution from higher plants.

The study of the causes of overpressure is the basis for stress prediction and the research on hydrocarbon accumulation. The Jurassic overpressure is widely distributed in the Mosuowan uplift， located in the central part of the Junggar Basin， which is closely related to hydrocarbon accumulation， making it an important topic for further research. This study comprehensively utilizes various methods such as log curves combination analysis， Bowers method， velocity-density crossplotting， correlation of porosities， and comprehensive analyses to discuss the causes of overpressure. The research shows that overpressure is generally developed in the Jurassic of Mosuowan uplift， Junggar Basin. The overpressure is mainly located in the deep formation of 4 000-4 500 m， and the pressure coefficient ranges from 0.92 to 2.11， with an average pressure coefficient of 1.33. On the planar scale， the eastern part experiences more significant overpressure， with pressure coefficients of up to 2.1， while the western part has relatively weaker overpressure， with pressure coefficients reaching up to 1.6. Sonic transit time， density， and resistivity log responses show clear indications of overpressure， with varying degrees of reversal. Based on the comprehensive analysis using multiple methods， it is determined that the overpressure in the Jurassic formations of the Mosuowan uplift in the Junggar Basin is mainly influenced by hydrocarbon generation and pressure transmission. The contribution of chemical compaction is slightly higher in the eastern part than in the western part， while the contribution of under compaction is weak or nonexistent.

At present， the breakthrough of shale gas exploration in China is mainly concentrated in the medium and shallow overpressured shale gas reservoir. With the deepening of research， shale gas exploration gradually goes to the deep layer. The Baima block of Fuling shale gas field is a deep overpressured gas reservoir with great exploration potential. Based on the well logging data and test analysis data of Wufeng-Longmaxi formations in well J148-1， the gas bearing characteristics and influencing factors of Wufeng-Longmaxi formations are analyzed in this paper， and the formation and enrichment mechanism of shale gas and the accumulation model of shale gas are discussed. The shale gas content of Wufeng-Longmaxi formations ranges from 1.09 to 6.81 m³/t （with an average of 3.15 m³/t）， and increases with increasing depth. The average gas content of small formations 1-3 is 5.35 m³/t， which is a favorable shale gas interval. The total organic matter content， mineral composition， reservoir properties and preservation conditions all have a certain control effect on the gas content of the shale.TOC of the Wufeng-Longmaxi formations is between 1.29% and 5.50%（with an average of 2.75%）， and increases with the increase of burial depth. Quartz content is 17.2%-64.7% （average 36.1%）， feldspar content is 2.7%-14.5% （average 8.0%）， carbonate mineral content is 2.0 %-56.6% （average 12.6%）， pyrite content is 1.4%-6.7% （average 3.4%）. The clay mineral content is 17.2%-54.3% （average 40.1%）. The porosity of 1-4 layers is between 2.38% and 5.64% （average 4.06 %）， the porosity of 8-9 layers is between 1.95 % and 2.75% （average 2.24%）， and the permeability of 1-4 layers is between 0.03×10^-3 and 16.43×10^-3 μm² （average 0.75×10^-3 μm²）. The permeability of 8-9 small layer ranges from 0.05×10^-3 to 55.63×10^-3 μm² （the average is 2.31×10^-3 μm²）， and the total organic matter content， brittle mineral content and porosity are positively correlated with the gas content. There are three types of pores in the shale： inorganic pores， organic pores and micro-fractures， mainly organic pores. The study area is far from the main fault， regional cap layer is developed， top and bottom lithology is dense， preservation conditions are good， free gas is abundant， and the reservoir formation model is broad and slow syncline. The shale of Wufeng-Longmaxi formations in the study area was immature from the end of Ordovician to the Late Silurian， entered the mature stage in the late Silurian， entered the high mature stage in the Middle Jurassic， entered the over-mature stage in the Late Jurassic， and stopped thermal evolution in the Middle Cretaceous.

The Xingkai rifting resulted in the formation of an extensional trough in the Deyang-Anyue area of the Sichuan Basin. The deposition of the Lower Cambrian Qiongzhusi Formation is obviously controlled by the trough pattern， and many sets of black carbonaceous shale and gray-black silty shale are developed inside it. It has been proved by exploration that it has great development potential. However， the understanding of sedimentary facies， sedimentary model and favorable facies belt of Qiongzhusi Formation is still unclear， which restricts the long-term deployment of exploration and development. Therefore， with the help of a large number of macro and micro observation techniques such as core， thin section and scanning electron microscope， combined with geophysical data and key geological parameter analysis， this study summarizes the sedimentary facies signs， geophysical facies signs and quantitative facies signs of Qiongzhusi Formation in the middle part of Deyang-Anyue rift trough， finely dissects the sedimentary facies belt distribution of Qiongzhusi Formation， establishes the sedimentary evolution model of Qiongzhusi Formation shale in the middle part of Deyang-Anyue rift trough， and compares the mineral composition， TOC， U/Th， Y/Ho， shale thickness and other indicators to optimize the favorable facies belt. The results show that： The Qiongzhusi Formation can be divided into three subfacies： Continental uplift， continental slope and continental shelf. The continental shelf is further divided into deep-water shelf facies in the trough and shallow-water shelf facies outside the trough with the trough as the boundary. According to the sedimentary characteristics and environmental differences， it is further divided into siliceous mud shelf facies， （including） silty mud shelf facies， muddy silty sand shelf facies and muddy silty sand shelf facies.

The Qiongzhusi Formation of Cambrian （∈₁ q） in Sichuan Basin is the most favorable strata for exploration and development of shale gas besides the Wufeng Formation of Ordovician （O₃ w） and Longmaxi Formation of Silurian （S₁ l）. Taking the middle part of Deyang-Anyue rift trough as the research object， meanwhile utilizing existing seismic， drilling， logging， experimental data， this paper has analyzed the basic characteristics of ∈₁ q shale gas reservoirs， and has analyzed the differences between shale gas reservoirs of ∈₁ q and S₁ l in southern Sichuan Basin， and also has provided technical support for evaluation of layers， optimal selection of advantageous areas in ∈₁ q. The main conclusions are as follows： （1） There are differences in sedimentary paleogeomorphology of ∈₁ q， which can be divided into three kinds of sedimentary paleogeomorphology in trough， slope and outside zone of trough， which control the thickness distribution and quality of shale reservoir. （2） In the middle part of Deyang-Anyu rift trough， the sedimentary environment is superior， and the preservation conditions are good； the structure is simple， the thickness of reservoir is large， and the horizontal stress difference between two directions is small， which are conducive to reservoir reconstruction； the buried depth of the target layer is large， which brings challenges to the implementation of the project. （3）The evaluation of layers and optimal selection of advantageous areas of ∈₁ q should follow the overall idea of “vertical stratification and horizontal zonation”. In the vertical direction， the black shale of layer⑤ should be the main target of the current research， and gradually expand to other layers； in the plane direction， the paleogeomorphic region of the trough and slope should be the main areas to be explored at present， and gradually expand to the zone outside the trough.

A significant breakthrough has been made in the Upper Paleozoic play in Dagang area of Huanghua Depression， Bohai Bay Basin over the past four years. This paper aims to analyze the key factors of hydrocarbon accumulation and identify the exploration prospective area. The geological， geochemical， logging and seismic data are allowed to investigate the source rock， reservoir distribution and properties， natural gas charging time and petroleum system model. The results show that the upper Paleozoic coal bedding source rocks have good organic matter with two peak periods of hydrocarbon generation. The reservoir responds low porosity and low permeability clastic rocks， but secondary pores and fractures have developed as a result of subsequent later tectonic movement. The origin source rock， secondary pore reservoir and the activity of faults are the key controlling factors for the gas accumulation. We build a petroleum system model as “two periods of hydrocarbon expulsion， source-sink superimposed， late fault activity reshape prospect， late gas charging”. The gentle high in the deep depression buried hill zone and slope of buried hill will be the promising exploration area. Three favorable target areas for future exploration are proposed： the slope area of Wumaying-Wangguantun sag， Dongguang Dongyi and Qibei.

Recently， a number of wells such as YT1H and ZT1 in the Ordos Basin have made new discoveries of natural gas in the Permian Taiyuan Formation limestone， revealing that the limestone of the Taiyuan Formation has good exploration potential. However， there are still problems such as unclear reservoir genesis mechanism and key reservoir formation mode in the Taiyuan Formation limestone， which seriously restricts the further gas exploration and deployment of this layer. Therefore， based on the abundant core， thin section and physical property data of Taiyuan Formation， this paper systematically studies the relationship between the development of limestone reservoir and the early exposed karst， and establishes the karst reservoir control model in the early limestone diagenesis. The results show that： （1） The early diagenetic karstification mainly developed in granular limestone and mostly located in the middle and upper part of the upward shallower sequence. The identifiable karst features include fabric selective dissolution， solution fissure/solution gully， solution speckle， karst breccia and multi-phase exposed surface， etc. （2） The intensity of karstification in single cycle gradually increased from the bottom to the top. The karst at the bottom of the cycle was weak， with local development of chip mold holes， while the karst reconstruction scope expanded upward. Dominant channels and dissolution mottling began to develop， and the karst process was moderate. In contrast， the upper karst system in the cycle cleaved and dissociated the bedrock， developed karst breccia， and exhibited overdeveloped karst processes. （3） Under the control of exposure time， high and low frequency cycles are developed in the study area， and the exposed surface of high frequency cycles is mostly found in limestone， which is an“episodic” cycle interface， and the inner karst intensity is manifested as karst non-development → selective degradation of bioclastic debris → dominant channel and dissolution spots， while the low frequency cycle interface only appears at the top of the slope section or Maergou section of the limestone， and the inner karst intensity is manifested as dominant channel → dissolution spots → karst breccia. （4） The high-quality limestone reservoir mainly developed in the middle and upper parts of the quaternary cycle， that is， the moderate karst reconstruction area， and the reservoir quality of the lower part of the cycle and the top part of the cycle became significantly worse. It is believed that the multi-stage karst in the early diagenetic stage not only controls the development and distribution of limestone reservoirs in the study area， but also greatly improves the reservoir and seepage capacity， which is the key factor for the formation of limestone reservoirs in Taiyuan Formation.

At present， all the helium used in industrial development comes from the crustal-derived helium in the helium-rich natural gas reservoir. Natural gas is the carrier of crustal-derived helium， and its generation， accumulation， and helium release are closely related to the tectonic thermal evolution of the basin. It is important to systematically evaluate the influence of tectonic thermal evolution on the helium release in a basin to clarify the enrichment of natural gas and helium. The Weihe Basin， as the first sedimentary basin with helium mining rights in China， is rich in helium gas resources. This article takes the Weihe Basin as an example to systematically simulate the tectonic and thermal evolution history of the basin. At the same time， it deeply analyzes the occurrence characteristics of hydrocarbon source rocks and helium source minerals， estimates the amount of helium resources generated and released by the main helium source minerals in the Huashan rock mass， and explores the impact of basin tectonic and thermal evolution on the enrichment of helium rich natural gas reservoirs. The aim is to provide new ideas for the establishment and improvement of a helium resource investigation and evaluation system. The results show that： （1） The crustal-derived helium gas in the Weihe Basin mainly comes from helium source minerals rich in U and Th elements such as zircon， apatite， etc.， which are relatively scattered in rocks. The temperature range （>180 ℃） where natural gas is generated in large quantities and the main helium source minerals release helium gas has a high degree of overlap. （2） After the formation of the basement， the Weihe Basin underwent Paleozoic sedimentation and was subsequently strongly uplifted and eroded. A large number of Indosinian and Yanshanian granite bodies were formed on the surface， in which helium source minerals rich in uranium and thorium elements （mainly calcite， zircon， and apatite） continuously decayed to generate helium gas and partially enclosed the helium gas in the mineral lattice. The faulting of the Cenozoic era led to rapid subsidence of the basin since approximately 40 Ma， followed by accelerated subsidence around 5 Ma， resulting in rapid warming of the strata. Natural gas was generated from Paleozoic source rocks， and helium gas generated from helium source minerals was released in a concentrated manner. The two have a spatiotemporal coupling relationship. During the migration process， natural gas continuously carries scattered helium gas into traps， thereby forming helium rich natural gas reservoirs. （3） According to the helium sealing temperature of the main helium source minerals and the characteristics of helium gas accumulation in many basins with helium rich natural gas， the helium sealing zone （<60 ℃）， partially sealing zone （60-220 ℃） and unsealing zone （>220 ℃） can be divided.

Based on thin section identification， the organic geochemistry， XRD， combined with scanning electron microscopy， N₂ isothermal adsorption and high pressure mercury injection tests， the characteristics of laminated shale lithofacies were identified and the reservoir pore structure was comprehensively analyzed， and then the favorable shale lithofacies and main controlling factors of pore development were clarified. According to the classification standard of “abundance of organic matter and mineral composition”， the shale of Qingshankou Formation is divided into seven lithofacies： M-L， S-M， M-M， C-M， S-H， M-H and C-H. The kind of C-H shale lithofacies is regarded as the favorable type in the study area， because it has absolute hydrocarbon generation potential， and its reservoir space is well developed with superior pore structure parameters， which is dominated by slit clay mineral intercrystalline pores， intergranular pores and micro-fractures. The shale reservoir space of Qingshankou Formation is controlled by laminae development， TOC content and mineral composition. The felsic lamination effectively alleviates overlying rock compaction， organic acid diffusion and formation of overpressure fractures improve macropore volume ratio， and the clay mineral intercrystalline pores and fractures provide the main specific surface area and pore volume.

Hydrogeochemical characteristics of coalbed methane co-produced water have significant implications for the secondary biogenic methane. Understanding the relationship between groundwater and secondary biogenic methane is crucial for natural gas exploration and development. The chemical compositions， hydrogen and oxygen isotopic compositions （ {\mathrm{\delta }}^{\mathrm{18}} {\mathrm{O}}_{{\mathrm{H}}_{\mathrm{2}}\mathrm{O}} and \mathrm{\delta } {\mathrm{D}}_{{\mathrm{H}}_{\mathrm{2}}\mathrm{O}}）， the abundance and isotopic compositions （δ¹³C_DIC and Δ¹⁴C_DIC） of dissolved inorganic carbon （DIC） of fifty-seven CBM co-produced water samples and three river samples from six blocks of Qinshui Basin in China are analyzed in this study. Results show that hydrogen and oxygen isotopes are distributed near the atmospheric precipitation line， suggesting that coalbed methane well-produced water mainly originates from atmospheric precipitation. Sulfate microbial reduction is identified as a crucial factor in the enrichment of deuterium isotopes in the Zhengzhuang and Yangquan blocks. The chemical composition of water produced from coalbed methane wells in the study area is predominantly of Na-HCO₃ type. The evolution of geochemical compositions of coal seam water is controlled by water-rock interaction and cation exchange processes. Stable isotope analysis of water from coalbed methane wells in the six study blocks in the Qinshui Basin shows elevated δ¹³C_DIC values （from -4.19‰ to 34.80‰， average 16.51‰）， and a clear positive correlation with dissolved inorganic carbon content， likely indicating the result of microbial methane production. The negative correlation between δ¹³C_DIC and SO₄ ^2- in coalbed methane produced water， as well as the positive drift in \mathrm{\delta } {\mathrm{D}}_{{\mathrm{H}}_{\mathrm{2}}\mathrm{O}}，suggests the widespread occurrence of secondary biogenic methane in coalbeds with different maturities in the Qinshui Basin. The negative correlation between δ¹³C_DIC and vitrinite reflectance （R _Omax） further indicates the presence of secondary biogenic methane in coal beds with different maturities， particularly in shallowly buried and low maturity coal beds. The integration of geochemistry and microbiology will further elucidate the pathways and mechanisms of secondary biogenic methane formation.

To elucidate the provenance of intricate deep crude oils in the Lower Paleozoic strata， in this paper， a systematic geochemical analysis of Lower Paleozoic source rocks and crude oil samples in Tarim Basin has been carried out. The juxtaposition of samples subjected to natural evolutionary processes and thermal simulation experiments unveiled that certain aromatic indices exhibit remarkable stability， particularly 1-alkyl-2，3，6-aryl isoprenoids （2，3，6-AIPs）， which demonstrates pronounced resistance to anti-secondary-alteration. A comprehensive assessment of the hydrocarbon generation potential of Lower Paleozoic source rocks identified five series of organically enriched strata （Lower Cambrian Yuertus Formation （Є₁ y）， Middle-Lower Ordovician Heituao Formation， Middle Ordovician from the Xihexiu section， Middle-Upper Ordovician Sargan Formation， and Upper Ordovician Lianglitage Formation）. These were categorized into three distinct groups：“low salt-green algae”，“high salt-dinoflagellates”， and “photic-zone euxinia （PZE）-green sulfur bacteria （GSB），” predicated on the presence of stable aromatic biomarkers， including 2，3，6-AIPs. And crude oils were categorized into two distinct groups： PZE-green algae oil and PZE-GSB oil. Notably， PZE-GSB source rocks （mainly developed from the Є₁ y） contained abundant 2，3，6-AIPs， showing similarity to almost all crude oils from the Tazhong and Tabei areas， Tarim Basin. Through oil-source correlation and the quantitative deconvolution of mixed crude oils， it was ascertained that the source rock harboring 2，3，6-AIPs likely plays a pivotal role in the substantial contributions to the extant deep crude oil reserves in the Tarim Basin. Therefore， finely determining the spatial distribution of this source rock developed under the special biological-environmental condition （PZE-GSB）， in the next stage， would provide significant reference for the targeted exploration of deep complex crude oil in the Lower Paleozoic from the Tarim Basin and even the world.

Significant breakthroughs have been made in the exploration of marine-continental transitional shale gas in the eastern Ordos Basin， but the related research obviously lags behind that of marine shale gas. Taking the Zhaoxian shale samples from Benxi Formation in Hengshan-Wupu area in the eastern Ordos Basin as the research object， the characteristics of the Zhaoxian shale reservoir in the area were comprehensively characterized by comprehensive experiments such as vitrinite reflectance， total organic carbon（TOC）， thin section， scanning electron microscopy （SEM）， X-ray whole rock diffraction （XRD）， pore permeability， low-temperature liquid nitrogen adsorption， methane isothermal adsorption， gas content and mechanical properties tests in this paper. The effects of pore structure parameters and TOC content on the adsorption capacity of shale were discussed， and the exploration potential of the Zhaoxian shale in the study area was finally comprehensively analyzed. The results show that： （1） Zhaoxian shale in the study area is a typical marine-continental transitional shale， with complex rock and mineral composition， high clay minerals and felsic minerals， with an average proportion of 47.4% and 36.4%， respectively； （2） The organic matter types of Zhaoxian shale are mainly Types I₂ and III kerogen， with high maturity and an average organic matter content of 5.30%. The organic-rich shale accounts for a relatively high proportion and has strong gas generation capacity. （3） Micro-nano scale fractures and pores are developed in Zhaoxian shale， and micro-fractures are developed in both organic matter and inorganic minerals， with fracture widths ranging from 0.01 to 1 μm. The pore types of liquid nitrogen adsorption were mainly narrow pores， with an average pore size of 13.67 nm，an average specific surface area of 6.56 m²/g， and an average total pore volume of 0.0176 cm³/g. BET specific surface area is positively correlated with the fractal dimension of pore structure， and negatively correlated with the average pore size. （4） The pore permeability of Zhaoxian shale is low， with an average Langmuir volume of 3.14 cm³/g， an average gas content of 1.52 cm³/g， an average brittleness index of 0.526， an average Young's modulus of 40.88 GPa， and an average Poisson's ratio of 0.22. （5） The Zhaoxian shale reservoir conditions in the study area are generally comparable to Shan 2 Member in Daning–Jixian area， with superior resource conditions， good transformability， and large shale gas exploration potential.

The Nanjiang area in the northeastern Sichuan Basin is a low exploration area in the pre-mountainous belt of the Micang Mountains. And Well A1 drilled a natural gas reservoir without clear principle in the Xujiahe Formation. To distinguish the hydrocarbon accumulation model of gas fields in the fourth member of the Xujiahe Formation， the curvature of the stratum top surface and abnormal signals of well logs and seismic attribution have been carried out. Through these studies， the direction of the tectonic stress and fractured reservoirs which are controlled by curvature are identified. It is indicated that the distribution of the gas field is controlled by the distance of the Micang Mountain and the Daba Mountain. Where the Micang Mountain and the Daba Mountain stress together is the favorable zone. Fractures were developed with the relative curvature >0.2， and more fractures were open with the relative curvature >0.4. However， the gas would be dissipated if the fractured reservoir was controlled by faults. After compaction， cementation and densification， the fractures can be used as geological desserts to enrich natural gas in the fourth member of the Xujiahe Formation. With the orogenic movement of the Daba Mountains， the fractures were developed due to tectonic movements where the relative curvature was high. Hydrocarbon charged into the fracture traps of the fourth member of the Xujiahe Formation.

The explorational breakthroughs have consistently revealed a huge new oil and gas production area in the Bozi-Dabei regions within the western Kelasu structural belt， Kuqa Depression， Tarim Basin. However， oil and gas compositions， physical properties， and oil and gas reservoir types are complex. There are unclear oil and gas phase states and physical property distribution rules， and the main controlling factors of oil and gas phase states are not clear. In this study， 75 production-well data were systematically collected for statistical analysis and phase simulation， including hydrocarbon compositions and physical parameters of oil and gas production （e.g.， density， viscosity， colloidal content， asphaltene content， dryness coefficient， production gas-oil ratio）. Oil and gas reservoirs were divided into four types of volatile oil reservoirs， condensate gas reservoirs， wet gas reservoirs and dry gas reservoirs according to the dryness coefficient and gas-oil ratio， and then the phase characteristics and occurrence of oil and gas were reconstructed under geological conditions to reveal the main controlling geological factors of phase distribution. The results indicate that the hydrocarbon fluids are generally characterized by the distribution of block-divided from east to west and belt-divided from north to south in the study area. The physical parameters （e.g.， density， viscosity etc.） show a gradual increasing trend from west to east. The occurrence of oil and gas transforms from liquid phase to condensate phase， condensate （wet gas） phase and dry gas phase from deep to shallow reservoirs. Four types of oil and gas are located in circle-curved distribution caused by the maturity differences of the Jurassic Qiakemake source rocks. The distribution of target strata controls the distribution of volatile oil reservoirs， condensate gas reservoirs and wet gas reservoirs. The distribution of dry gas reservoirs is attributed to the combined contribution of mature Jurassic and high-over mature Triassic source rocks. This study has successfully confirmed the distribution of oil and gas phases and physical properties， exploring the main controlling factors for the complexity of oil and gas phases in the Bozi-Dabei regions， which can provide theory-supported helps for the further oil and gas exploration and development in the Kuqa Depression.

In order to explore the diagenetic characteristics， influence mechanism and the distribution of dominant diagenetic facies of Fengcheng Formation in the southern margin of Mahu Sag， this paper quantitatively characterized the reservoir transformation intensity of compaction， cementation and dissolution on the basis of the analysis of petrological characteristics， pore types， diagenesis and diagenetic environment evolution， and established a diagenetic facies division scheme. Based on the evaluation results of single well coring interval， the characteristics of diagenetic facies distribution are described， and the influencing mechanism of diagenetic facies distribution is explained. The results show that the reservoir space of Fengcheng Formation in the study area is characterized by a dual medium of “matrix-pores dominated and micro-fractures supplemented”， in which the intra/intergranular dissolved pores are dominant in the matrix pores. The Fengcheng Formation has undergone the evolution of alkaline sedimentary environment and alkali-acid-alkaline diagenetic environment. The alkaline sedimentary and early alkaline diagenetic stages are the important periods for the loss of intergranular pore cementation， the hydrolysis of volcanic materials and the formation of solution pore by plagioclase albitization. The reaming in the acidic diagenetic environment in the middle stage makes the dissolution pore become the main reservoir space， and the densification degree is somewhat eased. In the late alkaline diagenetic environment， the concentration of alkaline mineral ions increases again and begins to precipitate in the remaining intergranular pores， solution pores， and other reservoir spaces， and the reservoir densification degree is further improved. The cementation and dissolution of fan delta plain and front junction in the study area were weak， and more compact phases developed， with an average porosity of about 4.9%. From the inner front of the fan delta to the junction of the outer front， the dissolution is stronger than the cementation， and the cementation-dissolution phases are dominant， with an average porosity of about 6.6%， and the dissolution phases with an average porosity of 9% are near the central and southern faults. The outer front of fan delta is mostly developed with solution-cementation facies， and the average porosity of the reservoir is about 3.1%. In general， alkaline diagenesis in the alkaline lake sedimentary setting has a two-sided effect on reservoir reconstruction， and the cementation-dissolution phases and the dissolution phases under the control of acid/alkaline dissolution are favorable places for tight oil accumulation in this area， and are also the key factors for the high productivity in this area.

Significant breakthroughs were made in the exploration and development of the Weirong area. Taking the Longmaxi shale as the object， we analyzed its gas-bearing characteristics and main controlling factors by means of XRD and on-site gas content test. The results are as follows： the area develops low-carbon-carbon rich shale， which is at the high-over-mature stage. The average total gas content is 2.78 m³/t， and the present desorption gas is mainly free gas， with an average of 2.25 m³/t， and the average adsorption gas is 0.53 m³/t. Carbon-rich mixed siliceous shale is the dominant lithology. There is a positive correlation between the TOC content， pore structure， and their respective gas contents， and at the same time the TOC content affects the pore structure， so that the TOC content is the main controlling factor. Therefore， TOC content is the main controlling factor and pore structure is the direct factor. Clay content is negatively correlated with gas content， and R _O content is positively correlated with gas content.

To systematically study the development characteristics and transformation modes of clay minerals in alkaline lake shale， and explore the development of clay minerals in alkaline lake sedimentary environments， Based on scanning electron microscopy （SEM） observation and X-ray diffraction， this paper investigates the characteristics and dynamic transformation of clay minerals in different sedimentary environments of the Fengcheng Formation shale in Mahu Sag. In the sedimentary center of the alkaline lake， only a small amount of clay minerals （<5%） are developed， mainly characterized by smectite （S） and illite-smectite mixed layers （I/S）. The detrital clay minerals were dissolved in a strongly alkaline diagenetic environment， transforming into authigenic silicate minerals such as K-feldspar. Moreover， the presence of CO₃ ^2－/HCO₃ ^－ can delay the transformation of clay minerals in the sedimentary center. In the edge slope zone， the content of clay minerals （average 11.57%）， which is mainly the illite （I）， chlorite （C）， and I/S is higher than that in the sedimentary center. The diagenetic environment is transformed from strongly alkaline to weakly alkaline-weakly acidic， and the primitive detrital clay minerals have not been dissolved and can be preserved in the early diagenetic stage， and illitization and chloritization occurr with the increase of stratigraphic temperature and pressure. The transformation of clay minerals can produce many brittle minerals such as authigenic quartz and K-feldspar， which not only increases the brittleness of shale reservoirs but also generates secondary pores and fractures， and is beneficial for the exploration and development of shale oil and gas.

Marine-terrestrial transitional shale gas is another important strategic replacement resource after the commercial development of marine shale gas. Marine-terrestrial transitional shale has the characteristics of strong heterogeneity， rapid depositional phase change， and complex lithology combination. Geological theories of marine shale gas can not be fully applied to marine-continental transitional facies， and the controlling factors of shale gas enrichment in the marine and continental transition facies are not well understood， which restricts efficient exploration and development. Taking the Shan₂ ³ sub-member shale in the Daqi area of the eastern margin of the Ordos Basin as an example， the geochemical characteristics and reservoir characteristics of shale were investigated through experiments such as microscopic analysis， gas adsorption， high-pressure mercury intrusion， breakthrough pressure， diffusion coefficient， and overburden pore permeability. This research elucidated the controlling factors of shale gas accumulation in marine-continental transitional facies. The research results indicate that the Shan₂ ³ sub-member shale in the marine-continental transitional facies exhibits high organic matter abundance， high maturity， and predominantly humic-type characteristics. The pore types are mainly dominated by inorganic mineral pores， with relatively fewer organic pores and microfractures. The conclusion suggests that the enrichment of marine-continental transitional facies shale gas is primarily controlled by a combination of organic matter abundance， pore size， lithological composition， and structural evolution. High organic matter abundance enhances the adsorption capacity of shale， providing more adsorption sites for methane gas molecules in micropores. The combination of shale-coal and shale-ash favors the in-situ enrichment of shale gas. Stable tectonics and appropriate burial depth facilitate the preservation of shale gas. Furthermore， an evolutionary model for the storage and sealing capacity of marine-continental transitional facies shale gas in the Dagang area has been established. The above findings can provide geological theoretical guidance for sweet spot prediction and rapid development of pilot test areas for marine-continental transitional facies shale gas.

In recent years， the Middle Jurassic Shaximiao Formation in the Qiulin-Jinhua and Bajiaochang structures in the central Sichuan Basin has become a hot spot of exploration. However， the origin of tight gas in the Shaximiao Formation in the study area remains unclear. In this study， the hydrocarbon generation potential of source rocks was evaluated based on total organic carbon content （TOC） and Rock-Eval pyrolysis of thirty-seven mudstone samples from the Da’anzhai Member of the Lower Jurassic Ziliujing Formation， the Lianggaoshan Formation， and the Upper Triassic Xujiahe Formation. Moreover， nineteen gas samples from the Shaximiao and Xujiahe formations were analyzed using gas chromatography and isotope ratio mass spectrometry to determine their origin. The results show that mudstones from the Da’anzhai Member and Lianggaoshan Formation are good source rocks at the mature stage， with type Ⅱ₁-Ⅱ₂ kerogen， TOC content ranging from 0.48% to 2.79% （average 1.30%）. In contrast， the mudstones of the Xujiahe Formation are mature–highly mature hydrocarbon source rocks， with type III kerogen and variable organic matter abundance. Most gas samples from the Qiulin-Jinhua areas show similar characteristics to those from the Xinchang Structure in western Sichuan Basin， indicating mature-highly mature coal-type gas sourced from the Xujiahe Formation with minor Jurassic contributions. The Bajiaochang area is dominated by mature coal-type gas and mixed gas sourced from the Xujiahe Formation and Jurassic source rocks， while the Gongshanmiao area produces oil-type gas from Jurassic sources. Regionally， Jurassic source rock contributions to Shaximiao Formation gas increase from west to central Sichuan Basin， controlling gas reservoir distribution. Coal-type gas of the Shaximiao Formation in Qiulin-Jinhua area may be transported laterally primarily from western Sichuan Basin via faults and fluvial sandstone reservoirs， supported by the similar gas maturity of gas and accumulation timing to the Shaximiao Formation reservoirs in western Sichuan Basin. In the Bajiaochang area， faults connecting the Shaximiao Formation reservoir with both the Xujiahe Formation and Jurassic source rocks are well-developed， resulting insignificantly increased proportions of mixed gas. Thus， fault-mediated vertical transmission represents a critical pathway for natural gas charging in this area.

The trace elements and rare earth elements of sedimentary rocks are closely related to the sedimentary environment， which is an effective means to study the sedimentary paleoenvironment. The Permian in northeastern Sichuan is an important period in geological history， but the research on its geochemical characteristics and paleo-marine environment is still weak. In this study， the Wujiaping Formation in Yanggudong section is selected as the research object， based on field outcrop section observation and the identification of thin sections and indoor microscope thin-section identification， combined with geochemical analysis methods such as trace elements and rare earth elements， to explore the significance of geochemical characteristics indicative of its sedimentary paleoenvironment. The results show that： （1） Sr/Ba and Th/U indicate that the sedimentary period of Wujiaping Formation in Yanggudong section was in a saltwater marine environment； （2） Indicators of paleo-oxidative phases of sedimentary environments， such as V/Cr， V/（V+Ni） and Ni/Co， show that the paleoenvironment during the deposition of Wujiaping Formation in Yanggudong section was in an oxygen-poor-anoxic state； （3） The ratios of Sr/Cu and Rb/Sr indicate that the paleoclimate during the deposition period was mainly arid environment； （4） The original provenance has the affinity of continental margin tectonic background， and the （La/Yb）_N-ΣREE correspondence reflects that the sediments are predominantly derived from sedimentary rocks.

Fracture bodies usually develop in the slip fault systems in sedimentary basins， and the fractures have strong concealment， and traditional fracture identification techniques do not perform well. Existing fracture interpretation strategies for target layers usually adopt a local view， ignoring the overall characteristics of fracture body fractures. Through the use of the U-ResNet deep learning model， all strata of the Zhenjing Block in Ordos Basin were identified for fractures. Combined with dip-guided seismic attribute slices， the formation mechanism， periods and levels of fractures were revealed， and for the first time， the NWW slip distance was estimated. By analyzing the extension characteristics of deep fractures， it was confirmed that the three groups of NWW-oriented slide fractures in the southern part of the block are essentially flower structures， and their rootstock extended to the basal fractures， confirming the reactivation of basal fractures in multiple tectonic movements. The cross-section and plan style of Chang 8 fracture body were divided， and a diamond-pulling rift was identified on the NEE fracture， providing seismic evidence for the NEE fracture slip movement. In addition， three spindle-depression fracture combinations were found， explaining the formation reasons of staggered-step faults， and giving the favorable combination style of fracture bodies and their distribution positions on the plane. The study shows that the application of deep learning fracture technology and a full-view interpretation strategy helps to reveal the development characteristics and evolution rules of complex high-angle slip fracture bodies.

The mid-deep CBM has the characteristics of high gas content， high saturation， and contains free gas. New well seismic calibration and multi-attribute joint tectonic interpretation techniques are adopted to finely understand the tectonics， calibrate the interpreted layers， and accurately identify the faults and trapped columns. The unit water influx in An13 reservoir area of Anze block of the west wing of southern Qinshui Basin is below 4 m³/（m·d） in the area， and the main body is below 1 m³/（m·d）， with weak hydrodynamic conditions. The statistical results of the coring data of the evaluation wells show that： （1） The cracks in the study area are relatively developed， the west is more developed than the east， the anisotropy is stronger at each point in the crack development area， the cracks in the direction of near north-south and near east-west are relatively developed， which belongs to the stress mechanism of the strike-slip faults， and the direction of the maximum horizontal principal stress NNE is favorable for the extension of fracturing cracks. （2） The porosity of the 3^# coal seam averages 4.48%-4.5%. In the process of tectonic folding， due to the uplift of strata in the dorsal part， the pressure of strata decreases， methane is transported from the low part of the tectonics to the high part of the tectonics through the channels of pore space and fissure， etc.， and the water of the coal seam seeps from the high to the low part of the tectonics due to the effect of gravity， and the coal seam gas enrichment mode of “the top of the tectonics is rich in gas and poor in water， the waist gas and water coexist， the bottom of the gas rich in water and poor in gas” is formed step by step. In order to obtain high gas production， it is necessary to find a favorable area in the reservoir where the gas saturation of the coal bed is more than 70% and the gas content is more than 14 m³/t. （3） For the open system of the reservoir with external water recharge， the supply boundary pressure remains unchanged， and the pressure within the drainage range decreases slowly due to external water recharge； when the reservoir is a closed system， the water body of the reservoir is of the stagnant type； when the reservoir is a semi-closed system， the water body of the reservoir is of the weak runoff type. （4） Coalbed methane wells in the Mabidong block of the west wing of southern Qinshui Basin are generally buried at a depth of 800-1 200 m， with an average fracturing fluid volume of 946.5 m³. The single-phase flow period after returning to the drainage adopts a fixed water production volume and a fixed flow pressure rate， and the single-phase flow pressure drop rate is kept at 0.05-0.1 MPa/d， with the average time of the single-phase period of 108 days， the cumulative drainage volume of 560 m³， and an average desorption pressure of 4 MPa， and the drainage curve is of the rising water production type， with a sharp peak before desorption and a long stable production period.

Effective reservoirs are one of the key points of tight sandstone oil and gas exploration and development， and the mechanism and evolution process of effective reservoir space formation under the overall low permeability to tight condition are the key to understanding effective reservoirs. Taking the second member of the Shaximiao Formation in the Jinqiu Gas Field in central Sichuan as the research object， the characteristics and differences of reservoir petrology and diagenesis were analyzed by comprehensive use of rock mineralogy， electron microscopy （SEM）， carbon and oxygen isotope analysis methods， and the formation and evolution process of effective reservoir petrofacies was explored. In view of the characteristics of strong heterogeneity of the reservoir in the second member of the Shaximiao Formation， three sandstone petrofacies were divided according to the differences in petrological structure， diagenesis degree and process， and pore characteristics. Among them， permeable reservoir sandstone has medium compaction， rich cementation types but low total amount， strong dissolution and good porosity. The porous permeability of ductile lithic-rich sandstone and tightly carbonate-cemented sandstone is poor， the former is strongly compacted and leads to rock densification， and the latter is dense due to a large amount of calcite crystalline cementation in the pores. The composition and structure of the original sediments control the diagenesis of the rocks in the reservoir， and different types of petrofacies have undergone different diagenetic evolution. The ductile lithic-rich sandstone and tightly carbonate-cemented sandstone have become dense in the early diagenetic stage， constituting interlayers of various scales in the reservoir， while the fluid activity and fluid-rock interaction occurred in the buried evolution of the permeable reservoir sandstone， and a large number of primary pores were retained in the early diagenetic stage， and the fluid action was active in the later stage， forming an effective reservoir petrofacies with relatively developed pore space and good physical properties in the tight reservoir，this rock phase is mostly distributed in the middle to lower parts of single sand bodies in distributary channels.