最新刊期
卷 46 ， 期 4 ， 2025
- 摘要：Although the fundamental principles behind the basic hydrocarbon accumulation and distribution patterns within a whole petroleum system （WPS） are universal， these patterns tend to vary in actual geological settings， reflecting the dialectical relationship between theoretical universality and geological particularity. To address this challenge， we systematically analyze the differences in the hydrocarbon enrichment characteristics of WPSs under varying conditions. The results indicate that the differences in the hydrocarbon accumulation characteristics are determined by three fundamental conditions， i.e.， geodynamic setting， reservoir medium， and source rocks， as well as their coupling relationships. Based on the combinations of key hydrocarbon accumulation factors in the three conditions， we classify WPSs into 48 types and propose a nomenclature rule. The results highlight four practically significant WPS types： those with clastic rock sequences， carbonate sequences， coal-bearing sequences， and near-surface special sequences as reservoirs， which are particularly important for further hydrocarbon resource development. Accordingly， we systematically elucidate the fundamental characteristics， hydrocarbon enrichment patterns， and resource potential of the four types of WPSs， demonstrating their respective resource development directions and major plays. Specifically， reservoirs of clastic sequences are governed by diagenesis dominated by typical tightening laws and exhibit shallow buoyancy-driven hydrocarbon accumulation depths （BHADs）. In these reservoirs， deep unconventional tight hydrocarbon resources show extensive plays， suggesting broad exploration prospects. Carbonate reservoirs are primarily of the hypergene weathering-related vuggy type， with high-quality intervals potentially preserved in deep to ultra-deep strata. These reservoirs contain a high proportion of conventional resources and hold huge potential for deep to ultra-deep resource development. In coal-bearing sequences， coals exhibit high gas generation and expulsion capacities， while natural gas in peripheral reservoirs shows a wide and continuous distribution. Furthermore， coals with high thermal maturity develop abundant cleats and exhibit anomalously high porosity and permeability， while their peripheral reservoirs demonstrate high sealing performance after gas accumulation. These factors are conducive to free gas enrichment in coal-bearing sequences. The near-surface special sequences， although characterized by complex hydrocarbon accumulation conditions， hold vast resource potential， including heavy oil bitumen， natural gas hydrates， and water-soluble natural gas. Advancing research and development of key technologies， alongside reducing exploitation costs， will facilitate the efficient utilization and rapid development of these resources.关键词：hydrocarbon resource development direction;classification scheme;fossil fuel;conventional hydrocarbon;unconventional hydrocarbon;whole petroleum system （WPS）;hydrocarbon accumulation48|30|7更新时间：2025-09-19
Academician Forum
- 摘要：The concept of the whole petroleum system （WPS）proposed and the ordered distribution pattern of conventional and unconventional hydrocarbon reservoirs established serve to unify petroleum geology theories， providing an entirely new theory and methods for guiding hydrocarbon exploration and exploitation. However， when applied to complex geological conditions such as those of superimposed basins in China， the WPS theory， originally formulated under general geological conditions， encounters several challenges. First， due to the lack of objective indices for quantitative characterization and the disruptions caused by late-stage tectonic activities， the idenfitication or prediction of buoyancy-driven hydrocarbon accumulation depth （BHAD） is hard in practice. Second， the formation and distribution of hydrocarbon reservoirs are governed by the combined effects of multiple driving forces， multiple stages， and diverse elements， complicating the identification of the hydrocarbon accumulation dynamics and reservoir types. Third， reservoirs such as those of the carbonate and clastic types exhibit varying wettability and interfacial tension properties， which lead to difficulties in predicting the maximum burial depth of hydrocarbon reservoirs and favorable hydrocarbon enrichment areas under actual geological conditions. Last， during the evolution of the WPS， hydrocarbon migration and accumulation are controlled by multiple factors including dynamic force types， capillary pressure differences between source rocks and reservoirs， hydrocarbon fluid properties， and tectonic activities. Consequently， establishing the hydrocarbon enrichment model of the WPS remains a challenge. To address these challenges， we explore various methods and technologies based on data from globally discovered hydrocarbon reservoirs， including their physical properties， productivity variations， and wettability. Accordingly， we develop new methods for identifying the BHAD， assessing hydrocarbon accumulation dynamics， and predicting the maximum burial depth of oil and gas resources. Furthermore， we determine the hydrocarbon enrichment model of the WPS. The results of this study offer new approaches to improve， develop， and apply the WPS theory under complex geological conditions.关键词：dynamic boundary of hydrocarbon accumulation;maximum burial depth of hydrocarbon reservoir;dynamic field of hydrocarbon accumulation;dynamic mechanism behind hydrocarbon accumulation;oil and gas resources;hydrocarbon enrichment model;conventional and unconventional oil and gas;whole petroleum system （WPS）31|27|3更新时间：2025-09-19
- 摘要：The newly established whole petroleum system （WPS） theory has attracted wide attention from both academic and industrial communities. Its related achievements have ranked among the Top 10 Scientific and Technological Advances of PetroChina and the Top 10 Landmark Achievements in China’s Oil and Gas Exploration and Development. Recognized as a major fundamental theoretical innovation in the industry， the WPS theory has prompted new directions for petroleum geology research in theory. Additionally， it provides effective solutions for predicting and evaluating hydrocarbon resources under complex geological conditions， improving the classic paradigms of “buoyancy-driven hydrocarbon migration and accumulation” and “trap-controlled hydrocarbon accumulation”. This WPS theory has several core connotations. First， it contributes to the unification of conventional and unconventional petroleum geology theories. Second， it reveals the mechanisms behind the joint hydrocarbon accumulation of the WPS and offers a unified genetic model and prediction method， laying scientific foundation for predicting and evaluating diverse oil and gas resources. Third， it summarized the hydrocarbon accumulation pattern of the WPS， along with a classification scheme and a quantitative evaluation system. The application of the WPS theory has led to significant achievements in exploration practices， while offering new directions for the evaluation and prediction of oil and gas resources. Currently， the theoretical framework of the WPS is still being constantly refined and developed. In its application to future hydrocarbon exploration practices， the major research directions include the formation， evolution， and distribution of hydrocarbon resources within a WPS， as well as their classification， mutual transformation， and symbiotic pattern. Besides， it is advisable to develop both new-generation basin simulation systems and key technologies for predicting and evaluating hydrocarbon resources based on the WPS theory. These efforts will provide effective guidance for hydrocarbon exploration under complex geological conditions， ultimately facilitating efficient exploration and exploitation of oil and gas resources.关键词：petroleum system;petroleum geology;whole petroleum system （WPS）;hydrocarbon exploration;hydrocarbon accumulation mechanism;oil and gas resources;conventional and unconventional oil and gas resources27|33|1更新时间：2025-09-19
- 摘要：The mechanisms underlying the self-sealing accumulation of unconventional hydrocarbons form the core of the whole petroleum system （WPS） theory. Forces driving the self-sealing process originate from intermolecular interactions， and their manifestations and mechanisms vary with reservoir media and geological conditions. In this study， a series of results and insights are obtained through systematic investigation. Essentially， the self-sealing accumulation of unconventional hydrocarbons is a non-buoyancy process dominated by intermolecular interactions. For the first time， three major mechanisms behind the self-sealing accumulation are systematically identified： interfacial effect， confinement effect， and steric hindrance effect. The principles and scaling effects of these mechanisms are accordingly defined. Factors influencing the forces that drive the self-sealing of various unconventional hydrocarbon resources are determined. Specifically， the self-sealing of tight hydrocarbons and free shale hydrocarbons is predominantly driven by capillary pressure at megapascal （MPa） level， governed by the pore size， interfacial tension， and wettability of reservoirs. In contrast， the self-sealing of adsorbed shale hydrocarbons and coalbed methane （CBM） is primarily driven by molecular adsorption forces under the confinement effect， with the adsorption energy jointly influenced by mineral surface properties， pore structure， temperature and pressure conditions， and fluid characteristics. Models describing self-sealing governed by the relative sizes of pores and hydrocarbon molecules are established. These models reveal that under ultra-tight pores， where pore sizes are comparable to molecular sizes， the steric hinderance effect predominates， causing mechanical obstruction for large molecules. When pore sizes are less than 38 times molecular sizes， differential adsorption of hydrocarbons becomes significant， leading to the gradual emergence of the confinement effect. Conversely， when pore sizes are far larger than molecular sizes， self-sealing is primarily driven by the interfacial effect. This study presents a systematic elucidation of various types of intermolecular interactions involved in the self-sealing of unconventional hydrocarbons， along with methods for their quantitative characterization. The results of this study deepen the understanding of the mechanisms governing the self-sealing accumulation and offer a theoretical guide for research into the distribution patterns of unconventional hydrocarbon reservoirs.关键词：intermolecular interaction;van der Waals force;steric hindrance effect;confinement effect;self-sealing effect;whole petroleum system （WPS）;hydrocarbon accumulation mechanism;unconventional hydrocarbons28|30|0更新时间：2025-09-19
- 摘要：The theory of the whole petroleum system （WPS） defines the orderly distribution of conventional， tight， and shale reservoirs， providing an important theoretical basis for the combined evaluation， exploration， and exploitation of conventional and unconventional hydrocarbon reservoirs. However， during the evolution of the WPS， complex hydrocarbon reservoirs are formed by the superimposed， composite hydrocarbon accumulation processes characterized by multiple driving forces， multiple stages， and diverse elements. It’s hard to identify and explain these complex reservoirs using the orderly distribution pattern of various hydrocarbon reservoirs. Based on dynamic hydrocarbon accumulation processes， we categorize and analyze typical hydrocarbon reservoirs across six major basins of China. Furthermore， we explore the mechanisms controlling the conversion between conventional and unconventional hydrocarbon reservoirs during the evolution of the WPS. The results indicate that all types of hydrocarbon reservoirs exhibit genetic correlations according to the basic principle of the WPS. As hydrocarbon dynamic fields evolve， the formation and development of deep media （especially carbonate reservoirs） are governed by compaction and diagenesis， while intensively reformed by geofluid activities and tectonic stress， among others. A distinctive distribution pattern of hydrocarbon reservoirs occurs as a result. Systematic analysis reveals four conversion models between conventional and unconventional hydrocarbon reservoirs， namely， compaction-induced tightness， stress reformation， geofluid reformation， and special medium reformation. The combined effects of multiple geological processes lead to more complex hydrocarbon accumulation characteristics and reservoir distribution patterns. This study holds great significance for deepening the understanding of the dynamic evolution process and mechanisms of the WPS， providing a theoretical basis for determining the formation and distribution patterns of hydrocarbon reservoirs in the WPS under complex geological conditions.关键词：hydrocarbon dynamic field;hydrocarbon reservoir conversion;reformed hydrocarbon reservoir;complex hydrocarbon reservoir;whole petroleum system （WPS）37|30|2更新时间：2025-09-19
- 摘要：Accurately measuring the wetting angles， interfacial tension， and pore-throat radii of reservoir rocks under high temperature and pressure conditions or in ultra-tight reservoir environments remains challenging due to laboratory limitations and instrument constraints. These challenges complicate the determination of capillary pressure during hydrocarbon migration and accumulation. Given this， we calculate the wetting angles of the calcite， montmorillonite， quartz， and feldspar surfaces， as well as oil-water and gas-water interfacial tension， under relatively low temperature and pressure conditions using molecular dynamics simulation. After validating the high consistency between the simulation results and experimental data， we expand this method to high temperature and pressure conditions to simulate the corresponding variations in the above parameters. Furthermore， we calculate the pore-throat radii of reservoirs using the multiple linear regression method. Through systematic simulations based on the regional settings of the Junggar， Ordos， and Songliao basins， we obtain data on burial depth-varying wetting angles， interfacial tension， and pore-throat radii of sandstone， volcanic， and carbonate reservoirs under high-， medium-， and low-temperature geothermal fields in China. Accordingly， the quantitative relationships are established between these parameters and the temperature-pressure conditions of petroliferous basins. The simulation results indicate that the water wetting angles of calcite， montmorillonite， quartz， and feldspar decrease gradually with increasing temperature， suggesting enhanced hydrophilicity. In contrast， the water wetting angles of these minerals increase with pressure， leading to reduced hydrophilicity. Generally， in oil reservoirs， calcite tends to exhibit oil-wet behavior， montmorillonite shows neutrality to water-wet characteristics， while quartz and feldspar primarily display water-wet properties. The oil-water interfacial tension decreases gradually with rising temperature but increases progressively with pressure. In contrast， the gas-water interfacial tension decreases with rising temperature and declines further with increasing pressure. The pore throat radii of rocks show certain correlations with porosity and permeability， suggesting that reservoir physical properties play a significant role in fluid migration. The minerals exhibit significantly different wettability， interfacial tension， and pore-throat structures across varying geothermal fields. Their wetting angles trend downward with increasing geothermal gradient. Meanwhile， their interfacial tension also decreases gradually with increasing geothermal gradient， which reduces molecular interactions at oil-water or gas-water interfaces， thereby enhancing fluid mobility.关键词：pore throat radius of the reservoir;capillary pressure;wetting angle of the reservoir;interfacial tension of the reservoir;molecular dynamic simulation;quantitative evaluation of the whole petroleum system;hydrocarbon migration23|25|1更新时间：2025-09-19
- 摘要：With the transition of the global energy supply/demand landscape， shale oil exploration and exploitation have emerged as a significant developmental direction in the energy sector. Based on constant extensive research for over a decade and a summary of onshore shale oil exploration in the Shengli and Dagang oilfields， coupled with the sedimentary background of the Bohai Bay Basin， we categorize the offshore shale oil reservoirs in the basin into matrix， lamina， and sandwich types. The lamina and sandwich types， among others， are further divided into sandy lamina， mixed lamina， sandy sandwich， and mixed sandwich subtypes. Using this classification， we assess the types， distributions， and resource potential of shale oil reservoirs in the Laizhou Bay， Huanghekou， and Liaozhong sags. New technological and theoretical advances are achieved in four aspects： the hydrocarbon generation and expulsion mechanisms and assessment methods of source rocks， the characterization of reservoirs of fine-grained sedimentary rocks， mechanisms of differential shale oil enrichment， and criteria for sweet spot evaluation. Nevertheless， shale oil exploration in the Bohai Bay Basin still faces multiple challenges imposed by complex geological structures， diverse sequences， and insufficient accuracy in pore structure characterization. In the future， it is necessary to intensify digital basin modeling， construct a comprehensive and unified standard system for reservoir characterization， innovate experimental and simulation methods， and promote the in-depth integration of geology， geochemistry， and engineering technology. Furthermore， it is recommended to prioritize key issues including mechanisms underlying shale oil enrichment， the identification of shale oil sweet spots， and large-scale shale oil production. This will help comprehensively enhance the understanding of unconventional hydrocarbon resources， as well as their exploration and exploitation efficiency.关键词：reservoir characterization;hydrocarbon generation and expulsion theory;sweet spot evaluation;shale oil enrichment;shale oil;Bohai Bay Basin32|36|1更新时间：2025-09-19
- 摘要：Widespread shale， tight， and conventional hydrocarbon reservoirs coexist in continental faulted basins in eastern China， as characterized by complex reservoir distribution patterns. Based on the whole petroleum system theory and the dynamic field model for hydrocarbon accumulation， we investigate the Nanpu Sag in the Bohai Bay Basin. By analyzing representative hydrocarbon reservoirs， we identify the dynamic boundaries of varying hydrocarbon reservoir types， delineate the dynamic fields for hydrocarbon accumulation， and examine the hydrocarbon accumulation characteristics within each dynamic field. Accordingly， the dynamic field evolution-controlled hydrocarbon accumulation model in the whole petroleum system is established with the genetic mechanisms of the hydrocarbon reservoirs elucidated. The results indicate that the Nanpu Sag exhibits three dynamic boundaries： the buoyancy-driven hydrocarbon accumulation depth （BHAD）， the hydrocarbon accumulation depth limit （HADL）， and the active source-rock depth limit （ASDL）. These boundaries delineate a free， a restricted， and an irreducible dynamic field for hydrocarbon accumulation， which govern the conventional， tight， and shale hydrocarbon reservoirs， respectively that are distributed in a regular pattern from top to bottom. The BHAD corresponds to a critical porosity of 10.0%， a permeability of 1 × 10-3 μm2， and a pore-throat radius of 0.380 μm. The HADL is characterized by a critical porosity of 2.0% and a pore-throat radius of 0.037 μm. For the ASDL， the critical porosity is predicted to be 1.0%， corresponding to a vitrinite reflectance （Ro） of approximately 3.3%. These dynamic boundaries differ across varying areas primarily due to the influence of lithology and geothermal gradient. Specifically， a coarser-grained lithology and a lower thermal gradient are associated with a deeper BHAD. During the late depositional stage of the Dongying Formation， conventional hydrocarbon reservoirs are primarily formed due to the presence of the free hydrocarbon dynamic field. During the late depositional stage of the Minghuazhen Formation， tight hydrocarbon reservoirs were principally formed under the action of the restricted dynamic field. At present， the free dynamic field predominates in the shallow to intermediate stratigraphic levels with conventional hydrocarbon reservoirs occurring， the restricted dynamic field is primarily distributed in the intermediate to deep layers with tight hydrocarbon reservoirs forming， and the deep irreducible dynamic field contributes to the formation of shale hydrocarbon reservoirs in the Gaoliu area and the Linque Sub-sag. Therefore， the Linque Sub-sag—Gaoliu area in the Nanpu Sag exhibits a distribution and evolutionary sequence of shale， tight， and conventional hydrocarbon reservoirs within the Paleogene-Neogene whole petroleum system from sub-sags to the basin margin.关键词：buoyancy-driven hydrocarbon accumulation depth （BHAD）;hydrocarbon accumulation depth limit （HADL）;active source-rock depth limit （ASDL）;dynamic field of hydrocarbon accumulation;whole petroleum system;dynamics of petroleum migration and accumulation;Nanpu Sag;Bohai Bay Basin21|23|0更新时间：2025-09-19
- 摘要：The Dongpu Sag represents a typical sedimentary sag of the saline lake facies. Presently， the hydrocarbon exploration in this sag is in a period of stagnation. By combining geological and geochemical methods， we systematically analyze the generation conditions， genetic mechanisms， and differential accumulation characteristics of hydrocarbons in this sag. The results indicate that the Dongpu Sag contains five suites of source rock sequences and four suites of evaporite sequences， exhibiting a structural framework characterized by multiple faults， uplifts， and sub-sags. The reservoirs in the sag feature significant heterogeneity and diverse hydrocarbon properties and genetic types， forming a large-scale whole petroleum system consisting of complete medium and shallow conventional hydrocarbon reservoirs， along with deep tight and shale hydrocarbon reservoirs with excellent accumulation conditions. Further investigation reveals that the properties and spatial distribution of hydrocarbons in the Dongpu Sag are governed by nine sub-sags， resulting in nine hydrocarbon types in three categories of sedimentary facies： saline， transitional， and freshwater facies in the northern， central， and southern parts， respectively. Accordingly， 11 hydrocarbon accumulation models are identified. The central uplift zone， or the intra-sub-sag uplift tectonic zone， in the salt-bearing area serves as the most hydrocarbon-enriched area， with conventional hydrocarbon reservoirs predominating. Based on the theory of the whole petroleum system， we establish a comprehensive hydrocarbon accumulation model subjected to varying dynamic fields and determine play fairways of conventional， tight， and shale hydrocarbons， thus laying a scientific basis for the future emplacement of hydrocarbon exploratory wells in the study area.关键词：shale oil and gas;tight oil and gas;conventional hydrocarbon reservoir;hydrocarbon genesis;whole petroleum system;accumulation model;Dongpu Sag;Bohai Bay Basin24|23|1更新时间：2025-09-19
- 摘要：This study aims to delve into the ordered distribution and the mechanisms underlying differential hydrocarbon enrichment of conventional and unconventional hydrocarbon reservoirs in the whole petroleum system （WPS） of a petroliferous basin. Focusing on the Dongpu Sag of the Bohai Bay Basin， we analyze the ordered distribution characteristics of hydrocarbon reservoirs in the WPS of the Paleogene Shahejie Formation， and delineate the dynamic fields for hydrocarbon accumulation and reveal the mechanisms behind differential hydrocarbon enrichment. The results indicate that the hydrocarbon reservoirs in the WPS of the Shahejie Formation exhibit an ordered distribution pattern， with conventional oil reservoirs， conventional volatile oil reservoirs， and tight gas reservoirs distributed sequentially from the structural high to the slope zone and then to the sub-sag zone. The buoyancy-driven hydrocarbon accumulation depth （BHAD） in the Shahejie Formation corresponds to average porosities ranging from 10.0% and 12.0% and an average burial depth of 3 580 m. In contrast， the hydrocarbon accumulation depth limit （HADL） in this formation is associated with an average porosity of 1.9% and an average burial depth of 5 580 m. Based on their genetic mechanisms， hydrocarbon reservoirs in the Shahejie Formation can be categorized into three types： （1） conventional hydrocarbon reservoirs formed in free dynamic field dominated by buoyancy； （2） tight and reformed hydrocarbon reservoirs formed in confined dynamic field dominated by non-buoyancy such as hydrocarbon generation-induced expansion force； and （3） shale hydrocarbon reservoirs formed in bound dynamic field. The hydrocarbon accumulation pattern varies across different structural locations. In the structural highs， hydrocarbon accumulation patterns include “early generation-single source （dominant）-upper accumulation，” “late generation-mixed sources （dominant）-middle accumulation，” and “late generation-self-sourced reservoir-lower accumulation.” In the slope zone， the hydrocarbon accumulation pattern proves to be of “early generation-transport along fault-slope-salt-mud sealing-mixed accumulation of crude oils with the same source but varying maturities.” In contrast， the sub-sag zone is dominated by self-sourced gas reservoirs.关键词：ordered distribution;differential hydrocarbon enrichment;whole petroleum system （WPS）;hydrocarbon accumulation pattern;lacustrine rift basin;Shahejie Formation;Dongpu Sag;Bohai Bay Basin28|26|0更新时间：2025-09-19
- 摘要：Currently， identifying viable hydrocarbon exploration targets in high-maturity exploration provinces remains a critical challenge for mature oilfields. Using geological and geochemical methods， we analyze the characteristics of the whole petroleum system （WPS） in the Western Sag in the Liaohe Depression， Bohai Bay Basin. The results indicate that the Western Sag contains 12 proven oil and gas fields and 18 pay zones， exhibiting complete hydrocarbon phases and rich hydrocarbon reservoir types. The proven petroleum reserves in the sag exhibit a normal distribution pattern from younger to older strata. The region from the slope margin to the sag shows a stepped distribution of heavy oil， light oil， and condensate gas reservoirs sequentially. The organic matter of the major source rocks is characterized by favorable kerogen types （types Ⅰ and Ⅱ）， high abundance （TOC content： 9%）， and a wide maturity range （Ro values： 0.4% ~ 3.0%）. Four types of crude oil are found in the sag： a mature type of freshwater origin， a low-maturity type of saline water origin， a type of mixed freshwater and saline water origin， and a mature type of deep-seated origin. Proven hydrocarbon resources in the sag are characterized by the controlling effects of source rocks on the distribution of hydrocarbons of varying origins. These resources show hydrocarbon accumulation governed by paleo-uplifts and structural highs， hydrocarbon migration along major faults， and the distribution of varying hydrocarbon pool types controlled by sedimentary facies and the physical properties of sand bodies and reservoirs. Furthermore， these hydrocarbon resources are characterized by well-matched hydrocarbon generation and accumulation conditions and diverse hydrocarbon accumulation patterns. The WPS theory reveals that hydrocarbon accumulations within the free fluid dynamic regime of the Western Sag are primarily confined to stratigraphic intervals at depths less than 3 500 m. In addition， shale hydrocarbon reservoirs， deep tight hydrocarbon reservoirs （burial depths > 3 500 m）， and buried-hill zones are identified as important targets for unconventional hydrocarbon exploration in the sag.关键词：hydrocarbon genesis;unconventional hydrocarbon;whole petroleum system （WPS）;hydrocarbon accumulation characteristics;Shahejie Formation;Western Sag;Bohai Bay Basin22|25|1更新时间：2025-09-19
- 摘要：The deep whole petroleum system in the Xujiaweizi Fault Depression of the Songliao Basin consists primarily of three parts： （1） shale gas retained in the Cretaceous Shahezi Formation source rocks； （2） tight gas reservoirs formed through long-distance migration； and （3） fault-transported gas accumulations in both basement metamorphic rocks and volcanic rocks of the Yingcheng Formation. Within this system， tight and shale gases tend to be interrelated rather than occurring independently. However， previous studies largely investigated them separately， failing to systematically analyze their paragenetic characteristics and interrelations. This study examines the stratigraphic interval consisting of shales interbedded with sandy conglomerates in the Shahezi Formation， Xujiaweizi Fault Depression. The shale gas retained and the tight gas that migrates over a short distance are analyzed together as tight sequence gas. Based on the clarification of gas generation and expulsion capabilities of source rocks and the gas storage capacity of reservoirs within the tight sequence system， we establish the three- and four-fold criteria for grading evaluation of source rocks and reservoirs， respectively. Considering the sand-to-mud ratios， we develop numerical models to elucidate the partitioning and distribution patterns of gas resources in the tight sequence system with varying source rock-reservoir configurations during the coupled reservoir formation of tight and shale gases. Accordingly， we determine the complementary or co-enrichment relationships between tight and shale gases. The results indicate that the tight sequence system containing coupled tight and shale gases can be categorized into 24 distinct types. Among these， four types featuring grade Ⅰ or Ⅱ source rocks， grade Ⅰ or Ⅱ tight reservoirs， and sand-to-mud ratios equal to or below their optimal value represent the co-enrichment areas of tight and shale gases. Four types characterized by grade Ⅰ or Ⅱ source rocks， grade Ⅰ or Ⅱ tight reservoirs， and sand-to-mud ratios exceeding their optimal value denote areas with shale gas enrichment， and tight gas enrichment immediately adjacent to source rocks. Eight types exhibiting grade Ⅰ or Ⅱ source rocks， grade Ⅲ or Ⅳ reservoirs， and any sand-to-mud ratios represent areas enriched in shale gas enrichment but depleted in tight gas. The remaining eight types featuring grade Ⅲ source rocks， any grades of reservoirs， and any sand-to-mud ratios represent the co-depletion areas of tight and shale gases. Generally， the Shahezi Formation exhibits overall co-enrichment， together with local occurrences of complementation. Major co-enrichment areas are located in the Anda-Songzhan area in the north. However， the sweet spots of the two gases do not completely overlap in these areas. It is recommended that joint exploitation of both gases should be attempted in well block Dashen-24 and the Songzhan area， while highlighting tight gas recovery in other areas.关键词：coupled reservoir formation;whole petroleum system;tight gas;shale gas;accumulation mechanism;Shahezi Formation;Xujiaweizi Fault Depression;Songliao Basin26|24|0更新时间：2025-09-19
- 摘要：Based on the theory of the whole petroleum system （WPS）， we systematically reveal the differential characteristics of conventional and unconventional reservoirs in continental sequences within the western-central Sichuan Basin. Accordingly， the mechanisms underlying the control of these differential characteristics on hydrocarbon accumulation are explained. Through analyses and experiments， including core observations， thin section observations， high-pressure mercury injection （HPMI）， nuclear magnetic resonance （NMR）， and scanning electron microscopy （SEM）， we comprehensively analyze the reservoir characteristics and their variation patterns， as well as the genetic mechanisms of relatively high-quality reservoirs. Additionally， we determine parameters for the grading and classification evaluation of various types of reservoirs and establish the evaluation criteria. The results show that the conventional and unconventional reservoirs in the WPS of continental sequences in the western-central Sichuan Basin exhibit a spatially superimposed pattern in distribution. Specifically， the intermediate to shallow strata overlying the buoyancy-driven hydrocarbon accumulation depth （BHAD） exhibit strong free fluid activities， resulting in conventional high-quality reservoirs with low permeability under the joint control of sedimentary facies and fluids. The intermediate to deep tight sandstones exhibit multi-stage superimposed channel deposits and enhanced capillary resistance. Furthermore， fractures are developed in these sandstones under intense tectonic compression， resulting in multiple types of reservoirs， such as pore， fractured， and pore-fractured reservoirs， jointly governed by lithofacies， fluids， and faults. In contrast， deep lamellar shale reservoirs are generally dominated by nanoscale pores. Within hydrodynamic fields predominantly characterized by strong overpressure and diffusive forces， the occurrence of the shale reservoirs is significantly governed by the joint effects of lithofacies assemblages， organic matter abundance， and the overpressure system. For the intermediate to shallow conventional， low-permeability reservoirs， the grading and classification evaluation focuses on sedimentary and diagenetic facies， along with pore types. The evaluation results indicate that these reservoirs can be classified into four types， with types Ⅰ and Ⅱ serving as the high-quality ones. Both reservoir types primarily occur in the deltaic plain and front， with moderate to strong dissolution identified as their key genetic mechanism. The grading and classification evaluation of the intermediate to deep tight sandstone reservoirs principally considers pores， fractures， lithofacies， and pore structures. Types Ⅰ and Ⅱ of these reservoirs represent high-quality pore reservoirs， primarily occurring in medium- to coarse-grained sandstone in massive and parallel beddings. Integrating reservoir thickness， lithofacies assemblages， reservoir physical properties， degree of organic matter enrichment， brittle mineral content， and the volumetric proportion of movable oil， we classify the intermediate to deep shale reservoirs in the Da’anzhai Member of the Jurassic Ziliujing Formation into types Ⅰ， Ⅱ， Ⅲ， and Ⅳ. Types Ⅰ and Ⅱ， among others， are relatively high-quality reservoirs， consisting predominantly of pure shales and shales interbedded with shell layers.关键词：tight hydrocarbon reservoir;shale hydrocarbon reservoir;continental sequence;whole petroleum system （WPS）;reservoir evaluation;western-central Sichuan Basin30|27|2更新时间：2025-09-19
- 摘要：Presently， large-scale oil and gas fields discovered in deep carbonate rocks are predominantly distributed within porous dolomite reservoirs and fractured-vuggy karst limestone reservoirs. However， recent discoveries in wells Pengshen 12 and Nanchong 2 in the Sichuan Basin confirm the presence of porous limestone reservoirs in the 2nd member of the deep Maokou Formation （also referred to as the Mao 2 Member）. This finding challenges the traditional geological understanding of reservoirs， establishing the porous limestone reservoirs as a hot research topic. In this study， geological insights are gained using core and thin section observations， geochemical analysis of reservoirs， and reservoir identification and tracking through well-tied seismic interpretation. The results indicate that porous bioclastic limestone reservoirs are present in the Mao 2 Member. The dominant storage spaces include intergranular pores， biological cavity pores， moldic pores， and dissolved pores， which are formed in sedimentary and supergene environments. Specifically， the reservoir encountered in drilling well Pengshen 12 exhibits a cumulative thickness of 24.80 m， an average measured porosity of 5.1%， and an average measured permeability of 0.05 × 10-3 μm2. Early hydrocarbon charging and the presence of anomalous overpressure （overpressured compartments） are identified as key factors contributing to the deep preservation of pores formed during the sedimentary and early supergene stages. The intermittently distributed porous bioclastic limestones are wrapped by relatively tight micritic limestones， resulting in the formation of local anomalous overpressure within bioclastic shoals under the influence of ultra-high temperatures at great depths. Reservoirs in the Mao 2 Member are sandwiched by the floor of tight micritic limestones of the Mao 1 Member and the roof of tight mudstones interbedded with limestones from the Wujiaping Formation. This configuration facilitates the formation of regional anomalous overpressure in the Mao 2 Member. The mechanisms underlying pore formation and preservation suggest that the large-scale porous limestone reservoirs in the Mao 2 Member are developed under a combination of favorable conditions： intermittently distributed porous bioclastic shoals， early hydrocarbon charging， local anomalous overpressure within individual shoals， and regional anomalous overpressure. These reservoirs exhibit a laterally intermittent distribution. Based on the identification of bioclastic shoals， the roof and floor of the member， it is predicted through well-tied seismic interpretation that favorable bioclastic limestone shoal reservoirs cover an area of 9.5 × 104 km2. These insights provide a theoretical foundation for the occurrence of porous limestone reservoirs in deep parts， expanding the exploration targets of deep limestone reservoirs in the Sichuan Basin. Additionally， this study offers a valuable reference for the exploration of deep limestone reservoirs in other basins.关键词：pore formation and preservation;anomalous overpressure;porous limestone reservoir;deep-buried reservoir;Maokou Formation;central Sichuan Basin25|25|2更新时间：2025-09-19
- 摘要：The Mahu Sag in the Junggar Basin exhibits differential reservoir formation mechanisms across its whole petroleum system （WPS）. In this study， we investigate the petrology， reservoir spaces， and physical properties of representative oil-bearing strata in the WPS， including the Lower Permian Fengcheng Formation， the Upper Permian Urho Formation， and the Lower Triassic Baikouquan Formation to the Upper Triassic BaiJiantan Formation. By combining analyses of major elements and carbon-oxygen isotopes， we examine the mechanisms governing hydrocarbon-water-rock interactions in these formations and analyze the differences in the reservoir formation mechanisms. The results indicate that primary factors controlling the formation of high-quality coarse-grained clastic reservoirs from the Upper Permian Urho Formation to the Triassic strata include sedimentary processes， hydrocarbon-water-rock interactions， and associated mineral dissolution. Different oil-bearing horizons show significantly varying hydrocarbon-water-rock interaction mechanisms and mineral dissolution characteristics. Specifically， the Upper Permian Urho Formation is characterized by extensive laumontite cementation formed by the volcanic material alteration during early diagenesis. Laumontite re-dissolution occurred under the action of organic acids carried by hydrocarbon-bearing fluids， and the resulting dissolution pores act as the primary reservoir spaces in the Upper Permian Urho Formation. In the Baikouquan Formation， high-valent Mn and Fe oxides induced the thermal oxidation of hydrocarbons， generating significant amounts of 13C-deficient CO2. The resulting dissolution of K-feldspar enhanced reservoir physical properties， especially permeability. In the Middle Triassic Karamay Formation， only limited hydrocarbons were oxidized due to an insufficient supply of oxidizing agents. Instead， organic acids carried by hydrocarbon-bearing fluids induced the partial dissolution of K-feldspar， enhancing reservoir quality locally. In contrast， the Baijiantan Formation experienced minimal hydrocarbon-water-rock interactions， with reservoir quality predominantly dictated by sedimentation and the degree of calcareous cementation. Shale oil reservoirs in the Fengcheng Formation are significantly governed by lithofacies. In this formation， compaction and cementation reduced reservoir physical properties. In contrast， organic acids produced during hydrocarbon generation promoted the dissolution of carbonate minerals and feldspar， improving reservoir physical properties. Generally， the development of high-quality deep coarse-grained clastic reservoirs in the Mahu Sag is intimately associated with hydrocarbon-water-rock interactions. Therefore， the mechanisms behind these interactions merit greater attention. Additionally， research on organic-rich， fine-grained reservoirs should highlight the differences caused by varying lithofacies.关键词：hydrocarbon oxidation;hydrocarbon-water-rock interaction;whole petroleum system;reservoir genesis;Mahu Sag;Junggar Basin25|21|0更新时间：2025-09-19
- 摘要：The whole petroleum system in the Permian Fengcheng Formation of the Mahu Sag within the Junggar Basin comprises conventional， tight， and shale hydrocarbon reservoirs， whose formation and distribution are governed by the coupling effects of multiple dynamic fields. Using statistical and geological analyses， we systematically investigate the dynamic boundaries among the three reservoir types and the differences in the contributions of migration dynamics to these reservoirs. Based on data from physical property tests of 1024 conventional and unconventional reservoir samples， 1 235 high-pressure mercury injection （MICP） experiments， and pyrolysis of 1630 samples， we define the quantitative relationships of porosity， permeability， and maximum pore-throat radius with burial depth. Accordingly， the critical parameters are determined for the buoyancy-driven hydrocarbon accumulation depth （BHAD）， hydrocarbon accumulation depth limit （HADL）， and active source-rock depth limit （ASDL）. The results indicate that the BHAD corresponds to a burial depth of 4 290.86 m （porosity： 8%， permeability： 1 × 10-3 μm2， pore-throat radius： 0.800 μm）. The HADL is approximately 8 000.00 m （porosity： 2%， pore-throat radius： 0.025 μm）， while the ASDL corresponds to a critical burial depth of approximately 10 000.00 m. Using the quadripartite method， we quantitatively assess the contributions of buoyancy， capillary pressure difference， tectonic stress， and fluid dissolution. The results reveal that the conventional hydrocarbon reservoirs （above the BHAD） are dominated by buoyancy-driven migration， primarily found in the deltaic plain facies along the margin of the Mahu Sag. In contrast， the hydrocarbon migration of unconventional reservoirs （below the BHAD） is controlled by capillary pressure difference， as well as hydrocarbon generation and expulsion dynamics. These reservoirs are principally distributed in the slope transition zone and the sag center， characterized by delta front and shallow to semi-deep lacustrine subfacies. By determining the quantitative relationships of porosity， permeability， and maximum pore-throat radius with burial depth and by assessing the dynamic contributions using the quadripartite method， this study serves to advance the theoretical framework of the hydrocarbon accumulation dynamics in the whole petroleum system， providing scientific support for the collaborative exploration and efficient exploitation of conventional and unconventional hydrocarbon resources in the Junggar Basin and comparable geological settings.关键词：buoyancy-driven hydrocarbon accumulation depth （BHAD）;hydrocarbon accumulation depth limit （HADL）;active source-rock depth limit （ASDL）;hydrocarbon migration dynamics;whole petroleum system;Fengcheng Formation;Mahu Sag;Junggar Basin27|29|0更新时间：2025-09-19
- 摘要：The whole petroleum system （WPS） theory serves to introduce a new perspective for hydrocarbon exploration， contributing to significant achievements in exploration practices across multiple basins. Under actual geological conditions， hydrocarbon reservoirs tend to exhibit complex formation processes due to the interplay of multiple dynamic forces. Identifying the dynamic types that drive the formation of complex hydrocarbon reservoirs within a WPS and quantifying their respective contributions have become a key challenge in current research on hydrocarbon accumulation. As a distinct category of distal tight hydrocarbon reservoirs in the WPS， the tight sandy conglomerate reservoirs of the Triassic Baikouquan Formation in the Mahu Sag， Junggar Basin represent a globally rare sandy conglomerate oil play with abundant reserves. A new technique for identifying the buoyancy-driven hydrocarbon accumulation depth （BHAD） in a WPS reveals that the BHAD of the Baikouquan Formation corresponds to a critical porosity of 12% and a critical permeability of 1 × 10-3 μm2. Accordingly， four driving forces of hydrocarbon migration and accumulation in the formation’s sandy conglomerate oil reservoirs are identified， namely， the buoyancy （Ⅰ） and non-buoyancy forces （Ⅱ）， tectonic stress （Ⅲ1）， and the geofluid activity （Ⅲ2）， which contribute 13.10%， 45.32%， 37.44%， and 4.14%， respectively to the proven reserves of these reservoirs. The contributions of major driving forces indicate that the sandy conglomerate oil reservoirs represent a joint-dynamic accumulation type dominated by non-buoyancy and tectonic stress reformation. Petrographic and fluid inclusion analyses reveal that oil reservoirs in the Baikouquan Formation underwent two key hydrocarbon charging events during the Early Jurassic and Early Cretaceous. During the first accumulation stage， tight and conventional oil reservoirs are formed under the action of capillary pressure and buoyancy， respectively. In contrast， during the second accumulation stage， tight oil reservoirs are primarily formed through capillary pressure. Currently， these oil reservoirs have evolved into two distinct types： low-porosity， low-permeability tight reservoirs formed by capillary pressure and tectonic stress-reformed low-porosity， high-permeability fractured oil reservoirs. Analysis of the coupling relationships between geological factors during key accumulation stages reveals that the sandy conglomerate oil reservoirs in the Baikouquan Formation exhibit a composite accumulation model characterized by multiple driving forces， multiple stages， and multi-lithofacies. Determining the dynamic mechanisms behind hydrocarbon accumulation in distal tight hydrocarbon reservoirs will provide a new philosophy for the efficient exploration and exploitation of these reservoirs while also offering an important practical basis for improving the WPS theory.关键词：accumulation dynamics;whole petroleum system （WPS）;tight sandy conglomerate;complex hydrocarbon reservoir;Baikouquan Formation;Mahu Sag;Junggar Basin31|27|0更新时间：2025-09-19
- 摘要：Deep carbonate hydrocarbon reservoirs in the platform-basin area of the Tarim Basin represent a significant hydrocarbon pay interval in China， holding considerable resource potential. However， their transformation characteristics， genetic models， and distribution patterns remain poorly understood due to the influence of multi-phase tectonic activities， multi-stage hydrocarbon charging， and late-stage adjustments and modifications. These hinder the progress of effective deep and ultra-deep hydrocarbon exploration therein. Based on the theory of the whole petroleum system， we systematically investigate the transformation processes and genetic models of the Lower Paleozoic carbonate hydrocarbon reservoirs in the platform-basin area of the Tarim Basin. The results indicate that the reformed carbonate hydrocarbon reservoirs in the platform-basin area exhibit several distinct characteristics： （1） tectonization-induced failure of the dynamic boundaries for hydrocarbon accumulation； （2） tectonic movement-induced failure of the dynamic fields for hydrocarbon accumulation and migration； （3） the transformation of early-stage continuous， tight reservoirs into conventional fractured， fractured-vuggy， or pore-cavity reservoirs； （4） the formation of superimposed， consistently distributed hydrocarbon reservoirs， and （5） the emergence of novel fault-karst hydrocarbon reservoirs. These reservoirs are governed by the dynamic coupling of multiple factors， including sedimentary evolution， tectonic movements， hydrocarbon accumulation and migration stages， and preservation conditions. The failure of the dynamic boundaries for hydrocarbon accumulation occurred after three evolutionary stages of physicochemical effects. The reformed hydrocarbon reservoirs display an orderly distribution pattern characterized by vertical layering and lateral zoning. The vertical layering is primarily determined by the differences in lithologic assemblages and depositional environments， while the lateral zoning is controlled by the developmental degrees of faults and unconformities. In the platform-basin area， reef-shoal and unconformity-controlled pore-cavity reservoirs are predominantly distributed within free hydrodynamic fields. In contrast， fault-controlled fractured reservoirs are typically found in constrained hydrodynamic fields between the buoyancy-driven hydrocarbon accumulation depth （BHAD） and the baseline of hydrocarbon accumulation.关键词：genetic model;transformation characteristics;carbonate rock;Lower Paleozoic;non-foreland basin area;whole petroleum system;Tarim Basin27|27|1更新时间：2025-09-19
- 摘要：The Southwestern Depression of the Tarim Basin （also known as the Southwest Tarim Depression）， located in a basin-mountain transitional zone， hosts multiple suites of high-quality source rocks， including Cambrian， Ordovician， Carboniferous， Permian， and Jurassic formations. Despite their uncorrelated genesis and distribution， these strata contribute to the formation of complex hydrocarbon reservoirs with composite hydrocarbon sources through multi-stage tectonic evolution and hydrocarbon accumulation. Using the whole petroleum system （WPS） theory as a guide， we comprehensively analyze the petroleum geochemistry， reservoir characterization， and the reservoir occurrence. Accordingly， the hydrocarbon accumulation mechanisms and ordered distribution pattern of the multi-sourced composite hydrocarbon reservoirs within the WPS of the Southwest Tarim Depression is examined. The results indicate that these complex hydrocarbon reservoirs， shaped by the coupling of multi-source inputs， multi-stage tectonic superposition， and multi-dynamic modification， exhibit four fundamental characteristics. First， the hydrocarbon accumulation features hydrocarbon supply from multiple sources， including the Cambrian， Carboniferous， Permian， and Jurassic formations； mixed hydrocarbon contributions； and structurally controlled hydrocarbon migration and accumulation. Second， multi-stage tectonic superposition during the Caledonian， Late Hercynian， and Indo-Tianshan orogenic events， sculpt diverse hydrocarbon migration pathways and a multi-dynamic hydrocarbon accumulation system. This results in differential hydrocarbon accumulation and ordered distribution of conventional and unconventional hydrocarbon reservoirs. Third， during the system evolution， high-porosity and high-permeability reservoirs in the free-hydrocarbon dynamic field （F-HDF） govern the formation and distribution of conventional hydrocarbon reservoirs. In contrast， low-porosity and low-permeability reservoirs in the confined-hydrocarbon dynamic field （C-HDF） control the formation and distribution of tight hydrocarbon reservoirs， while intra-source ultra-tight reservoirs in the bound-hydrocarbon dynamic field （B-HDF） determine the formation and distribution of shale hydrocarbon reservoirs. Last， the stress deformation and fluid-rock interactions during dynamic field evolution gives rise to dual reservoir types （i.e.， fractured and vuggy reservoirs）， substantially complicating the genetic classification of multi-sourced， composite hydrocarbon accumulations.关键词：reformed hydrocarbon reservoir;conventional and unconventional hydrocarbon reservoirs;multi-sourced composite whole petroleum system （WPS）;hydrocarbon accumulation mechanism;fossil fuel;Southwest Tarim Depression;Tarim Basin23|23|0更新时间：2025-09-19
- 摘要：Since 2021， significant breakthroughs have been achieved in the exploration of deep coalbed methane （CBM） or coal-rock gas in the Carboniferous-Permian coal measures of the Ordos Basin， revealing broad development prospects. Meanwhile， wide attention has been directed to the genetic correlations and commingling production potential between CBM gas and other natural gas， such as tight gas， across multiple Carboniferous-Permian sequences within the basin. Based on the theory and a quantitative evaluation method of the whole petroleum system， we analyze the genetic mechanisms and interrelationships of various natural gas reservoirs that have already been identified in the basin. Accordingly， we establish the accumulation model of natural gas and define the orderly distribution pattern of gas reservoirs in the whole petroleum system of the coal measures. The results indicate that the boundaries of the whole petroleum system in the Carboniferous-Permian coal measures extend across the entire basin. The whole petroleum system exhibits three dynamic boundaries from shallow to deep： the buoyancy-driven hydrocarbon accumulation depth （BHAD）， the hydrocarbon accumulation depth limit （HADL）， and the active source-rock depth limit （ASDL）. Accordingly， three dynamic fields of hydrocarbon accumulation are developed between the Earth’s surface and the three dynamic boundaries， namely the free-hydrocarbon dynamic field， the confined-hydrocarbon dynamic field， and the bound-hydrocarbon dynamic field from top to bottom. During the evolution of the whole petroleum system， hydrocarbons expelled from source rocks migrate and accumulate predominantly under the action of buoyancy in the free-hydrocarbon dynamic field of the intermediate to shallow strata， and then enter into high-porosity， high-permeability reservoirs within traps to form conventional natural gas reservoirs. In contrast， within the confined-hydrocarbon dynamic field of the intermediate to deep strata， hydrocarbon migration and accumulation from source rocks are predominantly driven by differences in capillary pressure between the source rocks and reservoirs. Consequently， these hydrocarbons migrate into adjacent low-porosity， low-permeability reservoirs， resulting in the formation of tight gas reservoirs. In the bound-hydrocarbon dynamic field， primary hydrocarbons retained in source rocks migrate and accumulate predominantly through adsorption， contributing to the formation of CBM reservoirs characterized by integrated source rocks and reservoirs. The natural gas reservoirs in the basin generally display an orderly distribution pattern， with CBM reservoirs， tight gas reservoirs， and conventional gas reservoirs occurring sequentially from bottom to top. In the eastern Ordos Basin， the intermediate to shallow strata contain only limited conventional gas due to the overall uplift and the presence of tectonic fractures. In contrast， the intermediate to deep strata in this region demonstrate widely distributed tight gas， substantial thickness of target strata， varied gas-rich plays， and considerable resource potential， establishing them as an important target for sustainable exploration and development.关键词：fossil fuel;whole petroleum system;coalbed methane （CBM）;coal-measure gas;natural gas reservoir;Carboniferous-Permian coal measures;Ordos Basin26|29|2更新时间：2025-09-19
- 摘要：This study aims to determine the diagenetic environments， characteristics， and mechanisms of quartz dissolution in the Pinghu Formation within the Baowu area， Pinghu slope zone， Xihu Sag， East China Sea Shelf Basin （ECSSB）and to assess the impact of quartz dissolution on reservoirs. By integrating data from rock thin-section observation， scanning electron microscopy （SEM）， X-ray diffraction analysis， and heavy mineral analysis， along with the geochemical parameters of source rocks， we explore the quartz dissolution-related diagenetic environments and their evolutionary patterns. The research results indicate the occurrence of acidic and alkaline quartz dissolution with significantly different mechanisms in the study area. In the acidic digenetic environment， quartz dissolves through complexation with organic acids in the presence of alkali metal ions， while in the alkaline digenetic environment， quartz reacts directly with OH- to form HSiO3-. The evolution of diagenetic environments affects quartz dissolution， which can be classified into two types based on the characteristics of dissolution boundaries： metasomatic and porosity-enhancing types. The metasomatic dissolution by kaolinite occurs through organic acid dissolution in the presence of alkali metal ions， whereas the metasomatic dissolution by illite， chlorite， and carbonate minerals is driven by alkaline dissolution. The porosity-enhancing dissolution occurs in both acidic and alkaline environments. The degree of quartz dissolution varies significantly with the diagenetic environment， decreasing in the order of alkaline， acidic， acidic-alkaline transitional， and weakly acidic environments. Furthermore， this degree is positively correlated with the number of kinking crystal planes， temperature， and alkali metal ion content. The porosity-enhancing quartz dissolution includes kinking plane dissolution， flat plane dissolution （raindrop imprint-like）， and flat plane dissolution （honeycomb-like）， leading to the partial missing of quartz grains. The metasomatic quartz dissolution involves kaolinite， carbonate minerals， illite， and chlorite. Additionally， grain-edge dissolution， secondary overgrowth rim dissolution， and authigenic quartz dissolution improve pore structures and increase reservoir permeability. Notably， the metasomatic dissolution of quartz grains by clay minerals leads to the formation of intergranular and intercrystalline dissolution pores， significantly increasing the reservoir porosity.关键词：dissolution mechanism;diagenetic environment;quartz dissolution;Pinghu Formation;Xihu Sag;East China Sea Shelf Basin （ECSSB）22|21|0更新时间：2025-09-19
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