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Sponsored by Petroleum Exploration and Production Research Institute Corporation,SINOPEC & Geological Society of China Chief Editor: Guo Xusheng ISSN 0253-9985 CN 11-4820/TE Bimonthly
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2026年第47卷第4期
Petroleum Geology
摘要：This study aims to address the critical challenge of understanding hydrocarbon accumulation mechanisms in ultra-deep sequences. Using interdisciplinary techniques， we systematically reveal the formation mechanisms of fault-controlled hydrocarbon reservoirs in the Shunbei oil and gas field， Tarim Basin. Given the complexity of hydrocarbon accumulation and serious difficulties in predicting ultra-deep hydrocarbon reservoirs， which are recognized as major challenges in hydrocarbon exploration， we innovatively develop a four-element spatiotemporal evolution analysis system that incorporates source rocks， faults， reservoirs， and traps. This system is expected to provide theoretical support for global ultra-deep hydrocarbon exploration. A multi-technique combined approach integrating high-precision 3D seismic interpretation， rock mechanics experiments， and fluid inclusion analysis is employed in this study. Specifically， the distribution characteristics of fault systems are identified through fine-scale seismic data processing. Meanwhile， the rupture and dissolution processes of carbonate rocks are determined using rock mechanics experiments， while the hydrocarbon accumulation stages are precisely divided using techniques including laser-excited Raman spectroscopy. By integrating multi-dimensional data， we elucidate the mechanisms underlying the core role that fault systems play in the hydrocarbon accumulation process. Five innovative insights are obtained in this study. First， fault zones are found to perform a triple function of conduction， controlled storage， and trapping determination. In addition to serving as pathways for hydrocarbon migration， faults also function as a key for reservoir development and trap evolution， establishing them as a critical factor governing hydrocarbon accumulation. Second， the internally coordinated mechanisms of the fault systems are identified， revealing that the combined effects of primary and secondary faults facilitate the formation of dissolution-rupture composite reservoir spaces within carbonate rocks. Third， the coupling relationship between strike-slip faulting and hydrocarbon charging is established， indicating that periodic faulting controls the major hydrocarbon accumulation periods by regulating the thermal evolution of source rocks. Fourth， the controlling effects of dynamic changes in fault sealing capacity on differential hydrocarbon accumulation are clarified， demonstrating that the spatiotemporal differences in the sealing capacity directly lead to differentiation in hydrocarbon occurrence. Fifth， an innovative model illustrating the dynamic coupling of faults’ controlling effects in ultra-deep hydrocarbon reservoirs is developed， revealing that the Shunbei oil and gas field is a result of multi-stage coupling between fault systems and factors governing hydrogen accumulation. Overall， this study systematically develops， for the first time， a theoretical system for the formation of ultra-deep fault-controlled hydrocarbon reservoirs. In this system， a novel hydrocarbon accumulation pattern characterized by dynamic coupling is introduced， challenging the traditional view of hydrocarbon accumulation as a static process. The study findings have provided accurate guidance for subsequent hydrocarbon exploration and exploitation of the Shunbei oil and gas field， while also promoting the transformation of ultra-deep hydrocarbon exploration from empirical prediction into a theory-driven paradigm. Furthermore， these results offer a critical reference for the exploration of similar ultra-deep hydrocarbon reservoirs worldwide.关键词：hydrocarbon accumulation mechanism;coevolution;source rock-fault-reservoir-trap;fault-controlled hydrocarbon reservoir;Shunbei oil and gas field;Tarim Basin387|98|0更新时间：2026-07-20Petroleum Geology
摘要：The 2nd member of the Feixianguan Formation （also referred to as the Fei 2 Member， T₁f ²） in the Yuanba area， northeastern Sichuan Basin develops multi-stage granular shoal carbonate reservoirs characterized by strong heterogeneity. However， their pore types and controlling factors for development remain poorly understood， significantly restricting reservoir evaluation and sweet-spot prediction. In this study， by integrating core and thin-section observations， physical property parameters， formation micro-imager （FMI） logs， and high-pressure mercury injection （HPMI） analysis results， we investigate the pore types of granular shoal carbonate reservoirs in the Fei 2 Member and determine their major controlling factors for development， aiming to provide a scientific basis for predicting favorable reservoirs in this member. The research results indicate that three-stage granular shoal carbonate reservoirs occur in the Fei 2 Member， including oolitic limestones， pisolitic limestones， and calcarenites， as well as residual doloarenites derived from localized dolomitization. These reservoirs are characterized by low to moderate porosity and low permeability and can be classified into fractured， vuggy， and fractured-vuggy types. The pore system in the reservoirs is dominated by intragranular dissolution pores and moldic pores， followed by intergranular and intercrystalline pores. Fractures are mainly of high-angle and stylolite-related types. The pore development is jointly controlled by sedimentary conditions， diagenesis， and tectonism. Both sedimentary microfacies and reservoir lithologies resulting from different sedimentary settings determine the characteristics of primary pores and cements， while indirectly governing the extent of secondary pore development. Environmental variations at diverse diagenetic stages control the types of diagenesis， thereby constraining the pore development in terms of type and scale. Among various diagenesis types， syngenetic-penecontemporaneous dissolution， burial dissolution， and dolomitization are critical to pore development in the member. Tectonic activity resulted in the formation of fractures， as well as adjacent dissolution pores and vugs， thus significantly enhancing reservoir porosity and permeability. Dolomitized granular shoal reservoirs of the dissolution pore-fracture type are identified as the most favorable reservoir type in the member， as their porosity and permeability are substantially enhanced by the effective combination of fractures， dissolution pores， and intercrystalline pores.关键词：pore type;reservoir physical property;granular shoal carbonate reservoir;the 2nd member of Feixianguan Formation;Yuanba area;northeastern Sichuan Basin279|73|0更新时间：2026-07-20Petroleum Geology
摘要：Multiple intervals of pebbly siltstone are developed within the shale succession of the Lower Cambrian Qiongzhusi Formation in the Sichuan Basin. Clarifying their genesis and distribution patterns is of great significance for advancing shale gas exploration and development. Based on core observation and log data from more than 20 wells in the central Sichuan Basin， together with 3D seismic data covering the Deyang-Anyue rift and its periphery， this study investigated the sedimentary characteristics and distribution patterns of pebbly siltstones and established a depositional model. As indicated by the research results， gravity-flow deposits are well developed in the central Sichuan Basin. Gravity-flow fans are commonly intercalated within gray- to dark-gray shales and are dominated by pebbly siltstone and fine-grained sandstone， with complete Bouma sequences and synsedimentary deformation structures. On seismic reflection profiles， these gravity-flow fans typically exhibit three main configurations， namely lenticular， worm-like， and parallel high-amplitude reflection types. In plan view， the fan bodies are characterized by blanket-like and lobate geometry. According to their genesis， the submarine fans in the basin can be classified into three major types： reworked， slump-related， and mixed types. Based on sediment provenance and dispersal characteristics， three sedimentary associations are recognized， namely delta （shoreline）-submarine fan， submarine fan， and delta （shoreline）-（contour-current-reworked） submarine fan associations. A submarine fan-contourite interaction depositional model and a spatial distribution model for submarine fans in the Qiongzhusi Formation of the central Sichuan Basin are proposed. It is suggested that the submarine fans of the Qiongzhusi Formation were formed by turbidity current deposition under a rapid transgressive setting， and their triggering mechanisms were primarily related to longshore currents and upwelling. The architecture， spatial distribution， and scale of these submarine fans were mainly controlled by their genetic mechanisms and the basin-floor configuration during deposition. The originally deposited submarine fans， together with blanket-like and lobate submarine fans subsequently reworked by contour currents， are encased within the shales of the Qiongzhusi Formation. Characterized by relatively shallow burial depths and favorable source-reservoir-caprock assemblages， these submarine fan bodies represent sweet spots for marine shale gas exploration and development and constitute the most promising targets for reserve growth and production enhancement in the Qiongzhusi Formation of the Sichuan Basin.关键词：pebbly siltstone;gravity flow;contour current;submarine fan;Qiongzhusi Formation;Cambrian;Sichuan Basin342|65|0更新时间：2026-07-20Petroleum Geology
摘要：The continental sequences in the Sichuan Basin are characterized by hydrocarbon supply from multiple suites of source rocks， diverse sedimentary systems， and superimposed hydrocarbon reservoirs belonging to multiple pressure systems. Within the continental sequences， there is a genetic linkage between different petroleum systems， making it challenging to fundamentally account for the genetic mechanisms of anomalous pressure based solely on analyses of individual sequences. Instead， there is an urgent need to determine， from the perspective of the whole petroleum system （WPS）， the formation mechanisms of different pressure systems across various sequences under the control of the fluid dynamic field， as well as the controlling effects of the pressure regimes on the hydrocarbon accumulation process. The results reveal the development of multiple anomalous pressure zones and distinct pressure systems within the continental sequences in the Sichuan Basin. Gas reservoirs with anomalously high pressure within the deep Xujiahe Formation in the western Sichuan Depression exhibit pressure coefficients reaching up to 1.50 ~ 1.70， while those with anomalously low pressure within the shallow Jurassic strata in the central Sichuan Basin show pressure coefficients as low as 0.45 ~ 0.47. The anomalously high pressure is primarily attributed to the hydrocarbon generation-induced pressurization of high-quality source rocks. Specifically， pressure increases of up to 35‒50 MPa are observed in the Xujiahe Formation， while the Da’anzhai Member of the Ziliujing Formation shows smaller pressure increases ranging from 3 MPa to 10 MPa. In contrast， the Late Cretaceous basin-scale stratigraphic uplift and denudation， accompanied by cooling， resulted in pressure reductions of generally 15‒20 MPa within sandstone reservoirs. Under such pronounced pressure contrasts between source rocks and reservoirs， multi-stage and multi-scale faults， formed by multiple tectonic movements， in the basin provide fluid migration pathways for deep and shallow fluid dynamic fields and pressure systems. Therefore， under the combined effects of sufficient driving forces and preferential migration pathways， hydrocarbons migrate from the deep overpressure system into the shallow underpressure system， resulting in the superimposed hydrocarbon accumulation within the continental sequences in the Sichuan Basin.关键词：genetic mechanism;whole petroleum system （WPS）;anomalous pressure;continental sequence;western-central Sichuan Basin;Sichuan Basin261|56|0更新时间：2026-07-20Petroleum Geology
摘要：This study aims to reveal the evolutionary patterns of pore structures in ultra-deep shales （burial depth 4 500 m） under the coupling of four fields， i.e.， geothermal， pressure， stress， and fluid fields （also referred to as four-field coupling）. By integrating multiple methods， including X-ray whole-rock analysis， scanning electron microscopy （SEM）， quantitative pore structure characterization， and basin modeling， we investigate the shales of the Lower Paleozoic Longmaxi Formation in three representative wells in the southeastern Sichuan Basin. The results reveal significantly different pore structures. In structural units characterized by overpressure and relatively constant temperature （well D5）， organic and inorganic pores show an equilibrium distribution， dominated by mesopores. In contrast， structural units subjected to hydrothermal pressurization （well F1） exhibit dense organic pores but relatively sparse inorganic pores， while those featuring low temperature and pressure relief （well S1） show organic pore collapse （porosity 2.50%）， with macropores and fracture systems predominating. The four-field coupling shows pore-controlling mechanisms of temperature-pressure synergy and stress-fluid co-shaping. Specifically， although vitrinite reflectance （Ro） values exceeding 3% tend to trigger organic pore collapse， the Ro threshold is dynamically adjusted by pressure regime and lithofacies. Overpressure conditions （pressure coefficient 1.80） effectively suppress compaction， with the pore volume decreasing by about 20% ~ 30% at the pressure relief stage. Furthermore， the stress field governs the propagation and connectivity of fractures， while acidic fluid dissolution promotes the formation of secondary pores with pore sizes ranging from 100 nm to 500 nm. A pore evolution pathway is established， consisting of a shallow burial stage （dominated by pressure field）， a hydrocarbon generation-induced pressurization stage （characterized by temperature-pressure synergy）， an overpressure formation stage （marked by the explosive development of organic pores）， an overpressure maintenance stage （featuring graphitization-induced organic pore shrinkage and fracture propagation）， and a pressure relief and adjustment stage （characterized by fracture-related modification）. Accordingly， a reservoir space classification model is proposed， in which reservoir spaces are categorized into an overpressure-primary pore type， a modification-complex pore type， and an intensive modification-fracture type. This model offers a geological basis for predicting sweet spots in deep shale gas exploration.关键词：four-field coupling;pore structure evolution;deep shale gas;Longmaxi Formation;southeastern Sichuan Basin255|62|0更新时间：2026-07-20Petroleum Geology
摘要：Investigating the controlling effects of strike-slip faults on hydrocarbon accumulation has emerged as the cutting edge and a hot topic of research in recent years. However， existing studies mostly focus on clastic and carbonate areas， while those on volcanic rocks remain limited. In this study， by integrating outcrop exploration， core observations， seismic interpretation， and log interpretation， we systematically explore the developmental characteristics， combination styles， and architectural features of strike-slip faults in the Carboniferous volcanic area of the eastern Chepaizi Uplift， western Junggar Basin. Accordingly， we determine the hydrocarbon accumulation patterns under the control of strike-slip faults in the volcanic area of the Chepaizi Uplift. The results indicate that the Carboniferous volcanic area primarily contains thrust faults and strike-slip faults， with the latter striking nearly SN， NWW， NE， and nearly EW. In the planar view， the strike-slip faults show reticulate and oblique combination styles. Among these， the reticulate fault combinations facilitate hydrocarbon accumulation， while the oblique fault combinations create more favorable conditions for hydrocarbon transport. In combination with outcrop and core observations， logs， and sample test results， two types of fault-zone architecture， i.e.， sliding fractured zones and induced fracture zones， are identified in the strike-slip fault zones. The sliding fractured zones are characterized by poor physical properties and thereby exhibit high sealing capacity. In contrast， the induced fracture zones show favorable physical properties， providing effective pathways for hydrocarbon migration. Analysis of hydrocarbon reservoirs in representative well blocks indicates that the Carboniferous volcanic rocks contain three types of hydrocarbon reservoirs： weathering-crust hydrocarbon reservoirs， fractured interior hydrocarbon reservoirs， and anticlinal interior hydrocarbon reservoirs. Accordingly， play fairways for hydrocarbon exploration are further identified.关键词：strike-slip fault;control of hydrocarbon accumulation;volcanic rock;Carboniferous;Chepaizi Uplift;Junggar Basin256|43|0更新时间：2026-07-20Petroleum Geology
摘要：The Bogda piedmont zone in the Junggar Basin experienced multiple stages of tectonic movements， as well as superimposed deformations and reworking， leading to complex tectono-sedimentary evolution. As a result， the distribution characteristics of high-quality source rocks in this piedmont zone remain poorly understood. Investigating the hydrocarbon reservoir types and accumulation model of the whole petroleum system （WPS） in this zone holds great significance for guiding hydrocarbon exploration in complex piedmont structural settings. Using data from outcrops， seismic surveys， newly drilled wells， and geochemical analysis， we examine the petroleum geological conditions and hydrocarbon accumulation types of the Permian WPS in the complex Bogda piedmont structural zone. Accordingly， a multi-dynamic hydrocarbon accumulation model together with an orderly hydrocarbon reservoir distribution pattern of the WPS is developed. The results indicate that the Middle Permian Lucaogou Formation in the Bogda piedmont zone contains a thick suite of high-quality lacustrine source rocks consisting primarily of black to grayish-black organic-rich shales. These source rocks were deposited in a semi-deep to deep saline lacustrine basin under a rift tectonic setting， with the subsidence and depositional center located at the present-day Bogda Mountain. These rocks exhibit a greater thickness， higher organic matter abundance， and higher thermal maturity as their distance from the Bogda Mountain decreases. The complex Bogda piedmont structural zone possesses the hydrocarbon accumulation conditions for a WPS. Specifically， with the high-quality source rocks in the Lucaogou Formation as a center， three types of favorable reservoirs are identified： （1） shales and tight sandstones in the Lucaogou Formation， situated within source rocks， （2） tight sandstones in the Jingjingzigou Formation， located beneath source rocks， and （3） tight sandstones in the Wutonggou Formation and sandstones in the Karamay Formation， both situated above source rocks. These three types of reservoirs are orderly distributed in space， and are connected to the high-quality source rocks of the Lucaogou Formation through faults formed at the late stage， creating favorable conditions for large-scale hydrocarbon accumulation. The complex Bogda piedmont structural zone exhibits three types of hydrocarbon reservoirs： （1） shale hydrocarbon reservoirs within source rocks， formed by retained hydrocarbons under the action of adsorption in a irreducible dynamic field， （2） tight-sand hydrocarbon reservoirs adjacent to source rocks， resulting from short-distance hydrocarbon migration driven predominantly by non-buoyancy in a restricted dynamic field， and （3） conventional hydrocarbon reservoirs above source rocks， formed by long-distance hydrocarbon migration driven primarily by buoyancy in a free dynamic field. These hydrocarbon reservoirs also show an orderly spatial distribution. Under the guidance of the hydrocarbon accumulation model of the WPS， major hydrocarbon discoveries have been made during exploratory drilling in the hanging wall of the Fukang fault zone and the Chaiwopu Sag， located along the northern and southern margins of the Bogda Mountain， respectively. These discoveries confirm the promising prospects for conventional and unconventional hydrocarbon exploration in the complex Bogda piedmont structural zone.关键词：whole petroleum system （WPS）;shale oil and gas;tight oil and gas;accumulation pattern;Lucaogou Formation;Permian;Bogda Mountain;Junggar Basin106|77|0更新时间：2026-07-20Petroleum Geology
摘要：Resource evaluation is a core foundation for oil and gas exploration and development， directly affecting exploration well deployment and exploration strategy formulation. The theory of the whole petroleum system （WPS） reveals the genetic mechanisms and orderly distribution patterns of the coexistence of conventional and unconventional hydrocarbon resources. It provides new theoretical and methodological guidance for the unified， joint， and quantitative evaluation of conventional and unconventional hydrocarbon resources in petroliferous basins. The Permian Fengcheng Formation in the Junggar Basin is the world’s first WPS confirmed by exploration practice. Based on the new “three-category and three-tier” hydrocarbon resource evaluation method for the WPS， this study quantitatively evaluated the hydrocarbon generation and expulsion characteristics of source rocks in the Fengcheng Formation， as well as the distribution characteristics of three categories of hydrocarbon resources， namely conventional， tight， and shale hydrocarbon resources， and three tiers of hydrocarbon resources， namely realistic， anticipated， and prospective hydrocarbon resources. As indicated by the research results， （1） the total hydrocarbon generation， total hydrocarbon expulsion， and total retained hydrocarbon amounts of source rocks in the Fengcheng Formation are 321.6 × 109， 141.2 × 109 and 180.4 × 109 t of oil equivalent， respectively， providing original hydrocarbon of 25.9 × 109， 115.3 × 109 and 180.4 × 109 t of oil equivalent for conventional， tight， and shale oil and gas resources. （2） The realistic resources with a recovery factor of 30%， anticipated resources with a recovery factor of 40%， and prospective resources with a recovery factor of 50% are 8.885 × 109， 15.782 × 109 and 22.930 × 109 t， respectively. Among them， the realistic conventional， tight， and shale oil and gas are 2.181 × 109， 3.663 × 109 and 3.041 × 109 t， respectively； the anticipated conventional， tight， and shale oil and gas are 2.812 × 109， 6.459 × 109 and 6.511 × 109 t， respectively； the prospective conventional， tight， and shale oil and gas are 3.795 × 109， 8.726 × 109 and 10.490 × 109 t， respectively. （3） The remaining realistic resources with a recovery factor of 30%， replacement resources with a recovery factor of 30% ~ 40%， and backup resources with a recovery factor of 40% ~ 50% are 7.142 × 109， 6.897 × 109 and 7.148 × 109 t of oil equivalent， respectively. Tight and shale oil and gas account for as much as 83% of the total， and 70% of hydrocarbon resources need enhanced oil recovery （EOR） to be converted into realistic recoverable volumes. Strengthening technical research on unconventional resource development and improving the recovery factor are therefore critical to improving the utilization efficiency of hydrocarbon resources.关键词：resource coefficient;source rock;whole petroleum system;hydrocarbon resource evaluation;Fengcheng Formation;Permian;Junggar Basin113|41|0更新时间：2026-07-20Petroleum Geology
摘要：Numerous scattered marine natural gas discoveries have been reported in the Ordos Basin； however， these discoveries generally exhibit relatively small proven reserves. This situation is closely linked to both the limited research on marine sequences and the substantially diverging understanding of gas accumulation mechanisms within the basin. Based on the intramolecular isotopic characteristics of natural gas， this study presents a systematic comparison of the geochemical characteristics and geological conditions of the Upper and Lower Paleozoic natural gas in the basin. The results indicate that natural gas from the 4th member of the Ordovician subsalt Majiagou Formation in the eastern Wushenqi paleo-uplift is typical crude oil-cracking gas. This gas generally experienced thermochemical sulfate reduction （TSR） to varying degrees during its accumulation， with the wet gas components exhibiting relatively heavy carbon isotopes due to intense oxidation. However， compared to the west-central Ordos Basin， the eastern Wushenqi paleo-uplift generally shows lighter methane carbon isotopic compositions （δ¹³C1<-40‰） in industrial production wells. This characteristic is inconsistent with the relatively heavy carbon isotopes （average δ¹³C of -27‰ ~ -26‰） of kerogen in the source rocks of the Majiagou Formation， suggesting additional gas contributions from deep source rocks （the Cambrian to Changchengian source rocks） to the natural gas in subsalt strata of the Majiagou Formation. In the eastern Wushenqi paleo-uplift， the presence of deep-seated faults is necessary for natural gas enrichment and high yield， and a multi-sequence stereoscopic gas accumulation pattern is identified， implying the development of paleo-hydrocarbon reservoirs in ancient strata. Intramolecular isotopic characteristics indicate that the Cambrian-Ordovician natural gas in the southern Ordos Basin is typical oil-associated gas. Such natural gas is predominantly derived from ancient （Changchengian/Cambrian） source rocks， rather than from coal-derived gas of an upper source rock - lower reservoir configuration or from mixed sources. This gas is extensively distributed from the Yichuan， Huangling， and Yan’an areas to the southern and western parts of the Jingbian gas field and is even widely identified in several wells in the central Jingbian gas field. The results of this study reveal that natural gas sourced from the Changchengian/Cambrian source rocks is extensively distributed across the Ordos Basin， establishing this basin as a rare potential gas province with confirmed possible contributions from the Changchengian source rocks in China and even worldwide.关键词：gas accumulation mode;intramolecular isotope;oil-type gas;Majiagou Formation;Ordovician;marine facies;Ordos Basin100|60|0更新时间：2026-07-20Petroleum Geology
摘要：The No. 8 and No. 9 coal seams of the Carboniferous Benxi Formation in the Linxing East Block， Ordos Basin， represent the principal targets for coalbed methane （CBM） exploration and development. However， due to limited understanding of their distinct coal-forming mechanisms， these seams have long been jointly exploited as a combined “No. 8+9 coal seam，” which fails to meet the requirements for refined development of medium- to deep-buried CBM reservoirs. Focusing on the No. 8 and No. 9 coal seams in this area， this study integrates core observations， well-log data， 3D seismic interpretation， and maceral composition analyses. High-frequency sequence stratigraphic analysis using integrated prediction error filter analysis （INPEFA）， together with paleogeomorphological reconstruction， is applied to reveal the distribution patterns of the two seams. Combined with coal-forming environment analysis， the developmental mechanisms of the two seams are systematically clarified. As indicated by the research results， both the No. 8 and No. 9 coal seams occur within the highstand systems tract （HST） of fourth-order sequences in the Benxi Formation， corresponding to the late phase of relative sea-level rise and the subsequent sustained sea-level fall during the Late Paleozoic. In contrast to the thin coal seams formed in the transgressive systems tract （TST）， HST coal seams exhibit relatively stable thickness and strong lateral continuity. Controlled by progressive sea-level fall， both seams display a seaward-migrating geometry with lateral dips toward the basin center. Well-logging responses indicate that the mudstone interlayer separating the two seams exhibits elevated bulk density （1.8 ~ 2.2 g/cm³）， serving as a reliable marker for distinguishing the No. 8 and No. 9 seams. During deposition of the Benxi Formation， the study area was characterized by a shallow marine setting with a transition from marine to continental depositional systems. The paleogeomorphology featured a gentle slope dipping from northwest （high） to southeast （low）， with well-developed barrier-bar island complexes. During the early HST， under relatively high sea level， the northwestern deltaic system and southeastern barrier island-lagoon complex jointly formed a favorable coal-accumulation zone for the No. 9 seam， resulting in mixed coal types of lagoonal and deltaic origin. During the late HST， continued sea-level fall led to the exposure of barrier bars， establishing a semi-restricted depositional setting. Consequently， the coal-accumulation center migrated southeastward， forming the No. 8 seam dominated by deltaic swamp coals. These observations demonstrate that the dynamic coupling between paleogeomorphology and sea-level fluctuations constitutes the primary control on differential coal seam development in marine-continental transitional settings. This study refines the application of the coupled “depositional environment， sea-level change， and paleogeomorphological evolution” framework to single-seam analysis， advances the understanding of single-seam formation mechanisms in the Benxi Formation of the eastern Ordos Basin， and provides a theoretical basis for the efficient development of CBM resources.关键词：marine-continental transitional settings;depositional environment;structural evolution;No. 8 coal seam;No. 9 coal seam;coalbed methane;Benxi Formation;Ordos Basin158|61|0更新时间：2026-07-20Petroleum Geology
摘要：As fault-controlled lacustrine basins enter the late syn-rift stage， tectonic activity gradually weakens and the growth rate of accommodation space slows down. Limited accommodation space makes sediment supply and depositional processes more complex， in which both direction and intensity are prone to significant fluctuations， resulting in highly variable architectural styles of composite sand bodies. Changes in local paleogeomorphology and sediment provenance further make it difficult to predict depositional distribution patterns and composite sand body architecture， which severely restrict fine reservoir characterization. Taking the Eocene Enping-Zhuhai Formation in the eastern Kaiping Sag， Pearl River Mouth Basin （PRMB）， as an example， this study aims to clarify the deltaic sedimentary evolution process in a marine-continental transitional setting during the late syn-rift stage by integrating core， well log， and 3D seismic data and applying combination of sedimentological analysis， facies-belt identification， and architectural-element dissection. An evolutionary model of “early lowstand fluvial-dominated delta while late highstand tide-influenced delta” is proposed. Guided by this model， four types of composite sand body architectural styles are identified： interbedded thick-thin stacking type， multiphase thick-bed stacking type， multiphase interbedded type with lateral continuity， and multiphase thin-bed type with lateral continuity. Corresponding to diverse stages of delta evolution， the study further indicates that， under an early multi-source supply background， multi-phase thick-bed stacking sand bodies and interbedded thick-thin stacking sand bodies developed during the lowstand systems tract （LST）； multi-phase thin-bed sand bodies with lateral continuity developed during the transgressive systems tract （TST）； and multiphase interbedded sand bodies with lateral continuity developed during the highstand systems tract （HST）. The research results provide new insights and methodological references for characterizing composite sand body architecture and predicting reservoirs finely during the late syn-rift stage.关键词：delta evolution;marine-continental transition;late syn-rift stage;sedimentary evolution;composite sand body;Enping-Zhuhai Formation;eastern Kaiping Sag;Pearl River Mouth Basin104|51|0更新时间：2026-07-20Petroleum Geology
摘要：The sequence stratigraphic architecture and pattern of shelf margins represent key components of sequence stratigraphy. However， the controlling effects of different shelf margin architecture types and their sequence patterns on the development of lithologic-stratigraphic traps remain poorly understood. In this study， we investigate the Baiyun Sag in the Pearl River Mouth Basin （PRMB） based on 1.5 × 104 km2 of 3D depth-domain seismic data， along with drilling and log data from 19 wells. Using analysis of shelf-slope break migration trajectories and the theory on the standardization of sequence stratigraphy， we quantitatively characterize the shelf margin architectures in the Lower Miocene Zhujiang Formation within the Baiyun Sag and identify their sequences and systems tract boundaries. Accordingly， variations in the characteristics and sequence patterns of different shelf margin architectures are determined. In combination with attribute slices extracted using the PaleoScan software， we explore the controlling effects of the shelf margin architectures and their sequence patterns on the formation of lithologic-stratigraphic traps. The results reveal that the Early Miocene Baiyun Sag contains two typical types of shelf margin architectures： progradational sand-rich type and retrogradational mud-rich type. The former type， dominated by a progradational stratal stacking pattern and low-angle ascending shelf-slope break migration trajectories， consists of a complete set of four systems tracts： the highstand systems tract （HST）， falling stage systems tract （FSST）， lowstand systems tract （LST）， and transgressive systems tract （TST）. In contrast， the retrogradational mud-rich shelf margin architectures， characterized by a retrogradational stratal stacking pattern and backstepping shelf-slope break migration trajectories， comprise only three systems tracts： HST， LST， and TST. The progradational sand-rich shelf margin architectures， featuring the presence of four systems tracts， exhibit multiple trap types， including stratigraphic traps such as unconformity-bounding traps and stratigraphic onlap traps， as well as lithologic traps like those formed by the updip pinchouts of fans， laterally sealed channel traps， and mud-rich channel-sealed traps. Additionally， lithologic-structural combination traps， including lobe-uplifting traps， sandy ridge-uplifting traps， and diapiric traps， formed under the combined influence of tectonism and paleogeomorphology， are identified within partial sand bodies of the progradational sand-rich shelf margin architectures. The type of shelf margin architectures plays a key role in determining the formation of lithologic-stratigraphic traps. Within the progradational sand-rich shelf margin architectures， sand bodies can bypass the shelf and migrate into deep-water areas. The resulting large-scale sand bodies in these areas form reservoirs， laying the foundation for trap formation. In contrast， within the retrogradational mud-rich shelf margin architectures， sand bodies tend to be retained within the shelf. Consequently， the deep-water areas are generally rich in mud， leading to underdeveloped traps. Meanwhile， trap types are controlled by the sequence stratigraphic patterns. Specifically， sequence boundaries govern the development of stratigraphic traps， while sand-rich systems tracts provide the depositional framework for a variety of lithologic traps .关键词：shelf margin architecture;sequence stratigraphic pattern;lithologic-stratigraphic trap;sequence stratigraphy;Zhujiang Formation;Baiyun Sag;Pearl River Mouth Basin （PRMB）121|43|0更新时间：2026-07-20Petroleum Geology
摘要：Based on seismic， well log， core， and grain-size data， this study investigated the complete fluid evolution process from shelf-edge deltas to submarine fans and its controlling factors in the lower member of the Zhujiang Formation in the early Miocene， Baiyun Sag， Pearl River Mouth Basin （PRMB）， from the perspective of slope break-geomorphology-fluid coupling framework. As indicated by the research results， （1） within the genetic sequence SQ21， bounded by the maximum flooding surface， the falling-stage systems tract characterized by the development of shelf-edge deltas and a shelf-slope break， whereas the lowstand systems tract comprises mass-transport complexes， lowstand submarine fans， concave-up slide surfaces， tectonic slope breaks， and depositional slope breaks. （2） Within sequence SQ21， sedimentary units dominated by different flow regimes exhibit an orderly evolution along the sediment transport pathway. The evolution begins with tractive current-dominated shelf-edge deltas at the shelf-slope break， followed by slide-dominated mass-transport complexes on the landward side between the shelf-slope break and tectonic slope break， and slump-debris flow-dominated mass-transport complexes on the seaward side. These deposits further evolve into sandy debris flow-dominated lowstand submarine fans between the tectonic and depositional slope breaks， and ultimately pass into turbidity current-dominated lowstand submarine fans beyond the depositional slope break， where the flows gradually dilute into low-density turbidity currents. （3） The systematic spatial distribution and orderly evolution “from delta to fan” are controlled by third-order slope breaks. The shelf-slope break induces sliding and slumping of shelf-edge deltas， and the resulting slump deposits transform into debris flows where the slope gradient decreases. Tectonic slope breaks accelerate liquefaction and mud-sand separation within debris flows， leading to the formation of sandy debris flows. Depositional slope breaks promote the dispersion and dilution of sandy debris flows， which evolve into high-density turbidity currents and ultimately into low-density turbidity currents. （4） This “topography-controlled flow evolution” mechanism outlined above is the fundamental cause cause of the spatial differentiation of deep-water sand bodies.关键词：sedimentation of slope break zones;gravity flow transformation;controlling factors of fluid transformation;sequence stratigraphic framework;lower member of Zhujiang Formation;Baiyun Sag;Pearl River Mouth Basin143|52|0更新时间：2026-07-20Petroleum Geology
摘要：The Lishui Sag in the East China Sea Basin has experienced multi-stage tectonic evolution and magmatic activity， resulting in extremely complex processes of hydrocarbon accumulation. Consequently， its hydrocarbon enrichment patterns have not been clearly understood and no large-scale commercial oil and gas fields have been discovered there to date. By integrating geochemistry， fluid inclusion analysis and basin modeling， this study compares hydrocarbon accumulation between Sub-sag B and Sub-sag C in the Lishui Sag to reveal the accumulation patterns. （1） Hydrocarbons in Sub-sag B are mainly derived from coal-bearing source rocks of the Cenozoic Lingfeng Formation， with organic matter composition dominated by terrestrial higher plants， whereas those in Sub-sag C are mainly sourced from the Yueguifeng Formation， with organic matter composition predominantly contributed by lower organisms. （2） Both sub-sags generally exhibit an overpressure environment， and the overpressure system and its overlying strata show a three-segmant vertical structure： an overpressured compartment， a convective layer at the top of the compartment， and a normal-pressure interval above the compartment （deep fluid retention zone）. （3） The overpressure-governed hydrocarbon charging in both sub-sags correspondingly results in a vertical three-segment hydrocarbon distribution pattern， coupled with the overpressure structure. Specifically， the peak homogenization temperatures of fluid inclusions increase normally with burial depth in the bottom compartment， remain nearly constant in the middle cap layer regardless of depth， and resume normal variation with depth in the upper normal-pressure zone. （4） Sub-sag B follows a transformational hydrocarbon accumulation model， where hydrocarbons initially accumulated within the compartment of the Lingfeng Formation， then migrated upward after deep fluids broke through the caprock， and re-accumulated in the Mingyuefeng Formation. Conversely， Sub-sag C follows an overpressure sealed hydrocarbon accumulation model， which is characterized by continuous hydrocarbon charging within the compartment， forming a “gas-above-oil” distribution pattern. （5） Affected by late magmatism， Sub-sag B is mainly formed via secondary modification， with hydrocarbons mainly accumulated in shallow traps above the overpressure zone. However， Sub-sag C is less affected by abnormal thermal events， making it difficult for hydrocarbons to break through the overpressure zone， and thus occurring mainly in deep traps within the overpressure system.关键词：hydrocarbon inclusion;overpressured compartment;hydrocarbon accumulation;Lishui Sag;East China Sea Basin82|32|0更新时间：2026-07-20Petroleum Geology
摘要：The Xihu Sag in the East China Sea Shelf Basin （ECSSB） represents a significant offshore petroliferous sag of China. Within this sag， the structurally moderate-to-high zones of the Pinghu slope belt have been intensively explored. In contrast， the near-sag zone of the slope belt is characterized by rapidly changing sedimentary environments and complex hydrocarbon transport systems under the influence of multi-stage tectonic movements. Consequently， the hydrocarbon accumulation pattern in this zone remains poorly understood， restricting further exploration efforts. This study focuses on the near-sag zone of the Pinghu slope belt. By integrating drilling data， data on cores and fluid inclusions， logs， and seismic and geochemical data， we systematically investigate the characteristics of source rocks， reservoirs， and transport systems in the Pinghu Formation， as well as the hydrocarbon accumulation stages. Furthermore， the major factors governing hydrocarbon accumulation are explored， and a hydrocarbon accumulation pattern is established. The results indicate that the in-situ source rocks of the Pinghu Formation in the near-sag zone are dominated by types Ⅱ and Ⅲ kerogens and exhibit high organic matter abundance. These proximal source rocks are generally in the high to overmature stage， holding great hydrocarbon generation potential. Reservoirs in the near-sag zone are composed primarily of feldspathic litharenites deposited in the tidal flat system. The reservoir spaces are dominated by primary intergranular pores， followed by secondary dissolution pores， while the reservoir physical properties show significant spatial variations. The near-sag zone exhibits composite hydrocarbon transport systems comprising multi-stage active faults， large-scale sand bodies， and widespread catchment ridges associated with hydrocarbon accumulation， providing primary pathways for efficient hydrocarbon migration. Hydrocarbons within the Pinghu Formation in the near-sag zone originate predominantly from proximal coal-bearing source rocks. Two stages of hydrocarbon charging are identified， each corresponding to the Longjing movement （16‒10 Ma） and the Okinawa Trough movement （5 Ma）， characterized by early oil charging followed by dominant gas charging. The primary characteristics of hydrocarbon accumulation in the near-sag zone include： （1） hydrocarbon supply from proximal source rocks； （2） reservoir development jointly controlled by high-energy facies belts， overpressure-induced resistance to compaction， and early-stage organic acid dissolution； and （3） hydrocarbon migration and accumulation governed by a composite fault-sand body-catchment ridge transport system. Accordingly， a hydrocarbon accumulation pattern for the near-sag zone is established， characterized by hydrocarbon supply from proximal high-quality source rocks， differential hydrocarbon migration and accumulation along the fault-sand body-catchment ridge transport system， and fault-sealing-controlled hydrocarbon enrichment in high-quality reservoirs. This hydrocarbon accumulation pattern provides a geological basis and reference for deep hydrocarbon exploration in the Pinghu slope belt of the Xihu Sag.关键词：transport system;hydrocarbon accumulation condition;Pinghu Formation;near-sag zone;Xihu Sag;East China Sea Shelf Basin （ECSSB）94|49|0更新时间：2026-07-20Petroleum Geology
摘要：Lithofacies types and their spatial distributions in fine-grained sedimentary rocks are the main factors controlling shale oil and gas enrichment. However， continental fine-grained sedimentary systems are characterized by highly heterogeneous lithofacies and complex depositional settings， making the quantitative and objective identification of lithofacies， as well as the establishment of its responses to depositional environments， particularly important for shale oil sweet-spot prediction. A paleoenvironment-controlled chemofacies stacking pattern was established for the 1st member of the Cretaceous Qingshankou Formation （Qing 1 Member） in the Songliao Basin. This was achieved through continuous portable X-ray fluorescence （pXRF） scanning and geochemical data analysis techniques， followed by chemofacies classification using elemental assemblages， principal component analysis （PCA）， K-means clustering， and Ward's hierarchical clustering. As indicated by the research results， （1） the fine-grained sedimentary rocks of the Qing 1 Member can be classified into three major chemofacies types and eight subtypes. The paleoenvironment was generally characterized by a humid climate and strong redox freshwater to brackish-water environment. Compared with the Sanzhao Sag， the Gulong Sag exhibits higher redox strength， greater paleowater depth， and locally elevated paleosalinity. （2） Vertically， the Gulong and Sanzhao sags display similar chemofacies evolution trends， both showing an upward increase in chemofacies diversity and accelerated facies succession changes. （3） Laterally， significant differences in chemofacies distribution exist between the two sags due to local variations in water properties and lacustrine-bottom topography. The Gulong Sag features highly diverse chemofacies types and rapid facies transitions， whereas the Sanzhao Sag exhibits fewer chemofacies types and relatively stable facies successions. （4） This study systematically investigated chemofacies classification and evolutionary stacking patterns in fine-grained sedimentary rocks， providing a methodological reference for similar studies and offering a theoretical basis and practical guidance for shale oil sweet-spot prediction in the study area.关键词：chemofacies;lithofacies;cluster analysis;depositional environment;fine-grained sedimentary rocks;shale oil;1st member of the Qingshankou Formation;Songliao Basin97|44|0更新时间：2026-07-20Petroleum Geology
摘要：The Santos Basin is one of the most prolific oil and gas basins globally. However， recent hydrocarbon exploration has revealed a series of geological risks within the basin， which emerge as key factors restricting prospect screening and deployment for subsequent exploration. In this study， based on the interpretation of 3D seismic data and an analysis of both discovered pre-salt oil and gas fields and dry exploratory wells， three major types of geological risks are identified： poor reservoir physical properties， absence of cap rocks， and elevated CO2 concentrations. These risks are primarily induced by multi-stage volcanic activity. First， volcanic activity led to the formation of late-stage structures， resulting in underdeveloped reservoirs in structural highs. Second， volcanic activity gave rise to salt windows， disrupting cap-rock integrity and thereby inducing hydrocarbon dissipation. Third， volcanic activity triggered the activation of deep-seated faults， facilitating the formation of high-CO2 gas reservoirs. By determining the chronological relationships among the five distinct stages of volcanic activity， timing of trap formation， and critical periods for hydrocarbon accumulation in the Santos Basin， while combining a detailed analysis of discovered hydrocarbon reservoirs and an investigation of hydrocarbon accumulation mechanisms within the basin， we establish five CO2 charging patterns under two scenarios： the presence and absence of volcanic activity following trap formation. The results of this study help effectively circumvent major geological risks and guide prospect screening and deployment for subsequent hydrocarbon exploration efforts. Furthermore， the results reveal that significant targets for future pre-salt hydrocarbon exploration in the basin include intra-depression uplifts in the central depression zone， small isolated platforms in the eastern uplift zone， and the structural traps in the eastern depression zone.关键词：geological risk;lacustrine carbonate rock;igneous rock;CO₂ gas reservoir;Santos Basin;Brazil77|33|0更新时间：2026-07-20Methods and Technologies
摘要：At present， more than 70% of newly added oil reserves across the world come from deep water. Some of these reserves， uneconomical to exploit due to the small resource volumes of individual oilfields， constraints imposed by deepwater and ultra-deepwater environments， and bottlenecks in key development technologies， are defined as deepwater marginal reserves. The oilfields with marginal reserves are defined as marginal oilfields.Marginal reserves of the marginal oilfields in the deepwater Congo Fan Basin， Angola， amount to 4 × 109 bbl. However， conventional reservoir prediction， fluid identification， and geological modeling techniques commonly yield multiple solutions due to the limited number of wells drilled， insufficient geological data， and strong heterogeneity of composite turbidite channels. Consequently， these techniques cannot meet the requirements for accurate reservoirs characterization of the marginal oilfields. Based on the sparse geological， drilling， well-log， 3D seismic， and testing data available from marginal oilfields， the study developed three technologies for deepwater turbidite-channel reservoirs of marginal oilfields： （1） a deep learning-based prediction method for composite turbidite channel reservoirs； （2） a centroid frequency-based fluid identification method for oil-water contact recognition； and （3） a new multiple-point geostatistical modeling constrained by reservoir architecture derived from a quantitative geological knowledge base. These technologies were applied to deepwater turbidite sandstone reservoirs formed by multi-stage composite channels in the PT and CS marginal oilfields in Angola. They enabled accurate prediction of reservoirs and fluids， characterization of internal architecture， and geological modeling of individual turbidite channels. Reservoir heterogeneity and the distribution of reserve abundance in turbidite-channel sandstone reservoirs were quantitatively characterized， providing a reliable basis for development decision-making and efficient well placement in marginal oilfields. These key technologies have become essential tools for the quantitative characterization and geological modeling of deepwater turbidite-channel sandstone reservoirs in Angola. They can also provide a technical reference for the evaluation and efficient development of marginal oilfields in analogous sparsely drilled deepwater blocks worldwide.关键词：Machine Learning;reservoir characterization;marginal oilfield;turbidite channel;deepwater;Angola82|26|0更新时间：2026-07-20Methods and Technologies
摘要：Beach-bar sand reservoirs in Shengli oilfield are characterized by low permeability and strong heterogeneity， resulting in uneven sweep efficiency and susceptibility to gas channeling during CO2 flooding. Therefore， it is essential to establish geological characterization methods suited to the characteristics of CO2 flooding to reveal the underlying mechanisms governing differential displacement within. To address this issue， a gas-flooding unit classification scheme applicable to beach-bar sand reservoirs under CO2 flooding was established and a multi-parameter integrated quantitative method for connectivity evaluation was proposed based on the hypothesis that gas-flooding unit division controls displacement behavior. On this basis， differential development technologies were developed. As indicated by the research results， （1） based on vertical stacking relationships， gas-flooding unit associations can be classified into four typical patterns： thick-bar with thin sheet， beach-bar interbedded， oil-bearing beach and dry beach interbedded， and isolated dry beach. （2） A multi-parameter integrated quantitative evaluation model for inter-well connectivity was established， enabling precise quantitative characterization of connectivity differences among different gas-flooding unit association patterns. （3） Differential development technologies for CO2 high-pressure miscible flooding were established for injection-production units at different connectivity levels. （4） Field application in the CO2 flooding demonstration area of the Gao 89-Fan 142 beach-bar sand reservoir significantly improved single-well productivity and reservoir recovery factor， thereby verifying the effectiveness of the differential development technology. （5） The research results provide new concepts and methodologies for geological characterization and efficient development of beach-bar sand reservoirs.关键词：differential development strategy;identification of CO2 seepage channels;connectivity evaluation;gas-flooding unit;CO2 high-pressure miscible flooding;beach-bar sand reservoir;Shengli oilfield90|32|0更新时间：2026-07-20Methods and Technologies
摘要：Hydrogen energy， as a key carrier for deep decarbonization， requires efficient underground hydrogen storage （UHS） technologies to support its large-scale deployment. Based on a numerical simulation model established for the Y gas reservoir in China， this study systematically analyzed the effects of hydrogen injection on enhanced gas recovery （H2-EGR）， the synergistic interaction mechanism， and the operational efficiency of UHS. The research results indicate that a three-stage transition model comprising enhanced recovery， synergistic operation， and hydrogen storage， can achieve EGR and stable UHS operation in a coordinated and optimized manner. The H2-EGR and synergy stages， effectively mitigated bottom-water rise， with water production declining from a steady rate of 25 m³/d to zero. Meanwhile， formation energy was replenished； after the synergy stage， the bottomhole pressure was 1.6 MPa higher than that under depletion development， and methane recovery increased by 3.73%. During the UHS operation stage， residual methane served as cushion gas to support the efficient establishment and stable operation of the UHS facility. Over multiple injection-production cycles， the methane-formation water boundary remained stable， with the hydrogen recovery rate reaching up to 83.64%， and the cushion-gas consumption rate limited to only 1.78%. This model achieves synergistic optimization of EGR and UHS facility construction， providing a viable technical pathway for accelerating the industrialization of hydrogen energy.关键词：collaborative model;energy replenishment and water control;integrated storage facility construction;UHS of gas-reservoir type;hydrogen-enhanced gas recovery （H2-EGR）87|27|0更新时间：2026-07-20Methods and Technologies
摘要：Magmatic-hydrothermal processes represent a pivotal driver behind cross-sphere material circulation and energy exchange within the Earth system， exerting a significant control over the formation and distribution of critical mineral resources such as hydrocarbons. In this study， we systematically compare the molecular geochemical signatures of hydrocarbons from global deep-sea and terrestrial magmatic-hydrothermal systems. Accordingly， the formation mechanisms of hydrocarbons of hydrothermal origin and those formed by hydrothermal reformation are investigated， and the influence of hydrothermal activity on hydrocarbon migration， accumulation， and preservation is explored in combination with geological settings. The results indicate that hydrothermal hydrocarbons exhibit complex molecular fingerprints， which partially overlap with the characteristics of low-maturity and biodegraded hydrocarbons， hydrocarbons formed by thermochemical sulfate reduction （TSR）， and hydrocarbons of combustion origin. The magmatic-hydrothermal environments give rise to diverse hydrocarbon origins. Specifically， short-chain hydrocarbons might have an abiogenic origin， such as Fischer-Tropsch synthesis， while long-chain hydrocarbons are primarily formed by microbial metabolism， as well as the pyrolysis and cracking of organic matter. Magmatic-hydrothermal processes exert significant control over hydrocarbon accumulation. Magmatic-hydrothermal fluids can carry and drive deep hydrocarbons to migrate upward along faults， facilitating their accumulation in shallow parts. The high temperatures and strong oxidation properties of these fluids can significantly modify pre-existing hydrocarbon reservoirs， while the associated release of substantial methane can change the phase distribution of hydrocarbons in reservoirs. The mechanisms behind magmatic-hydrothermally controlled hydrocarbon accumulation refer to the spatiotemporal coupling of the activity intensity and properties of magmatic-hydrothermal fluids with fault pathways， cap rock conditions， and paleo-hydrocarbon reservoirs in sedimentary basins. These factors jointly determine the present-day patterns of hydrocarbon enrichment and distribution. In regions characterized by intense magmatic-hydrothermal activity， hydrocarbon exploration must fully integrate the effects of fluid interactions. A deeper understanding of multi-factor coupled reservoir-controlling mechanisms is essential to effectively guide exploration practices in these complex geological settings.关键词：biomarkers;organic-inorganic interaction;deep hydrothermal fluids;hydrothermal controlled hydrocarbon accumulation;ultra-deep reservoirs;Tarim Basin85|38|0更新时间：2026-07-20Methods and Technologies
摘要：The upper member of the Guantao Formation in Block Zhong-2 of Chengdao oilfield develops typical meandering river deposits， featuring rapid lateral facies transitions and complex superimposed sandbodies. Constraints in offshore data acquisition have resulted in sparse development well patterns and degraded seismic data quality. These limitations hinder accurate sandbody prediction and fail to meet the requirements for remaining oil development. To address these challenges， this study proposes an intelligent reservoir prediction method based on geologically constrained multi-attribute fusion， with steps shown as follows. （1） Geological constraints are integrated via well-to-seismic calibration. By combining meandering river depositional models with datasets showing high local sandbody correlation， local reservoir distributions are accurately delineated to serve as supervisory labels for the intelligent algorithm. （2） Seismic attributes highly correlated with reservoir properties are optimized through attribute extraction and spectral decomposition to construct the training dataset. （3） An integrated Genetic Algorithm-Convolutional Neural Network （GA-CNN） algorithm is adopted to achieve high-resolution characterization of reservoir sandbodies under the sparse well patterns typical of offshore fields. The research results indicate that： （1） the proposed geologically constrained multi-attribute fusion method significantly enhances computational efficiency while simultaneously improving prediction accuracy； （2） the predicted planar attributes correlate well with sandbody thickness （coefficient of determination R2 = 0.865）， and the planform geometry and boundaries of the channels are faithfully recovered； （3） predicted sandbodies on cross-sections exhibit high consistency with well-based architectural profiles， as the comparison between the sampled prediction results and lithofacies log interpretations yielding an accuracy of 86.11%. This proposed method provides a high-precision， robust， and operational tool for reservoir prediction in analogous oilfields， demonstrating significant potential for broad industrial application.关键词：sparse well pattern;convolutional neural network （CNN）;genetic algorithm （GA）;intelligent fusion;meandering river;reservoir prediction;Block Zhong-2;Chengdao oilfield;Bohai Bay Basin117|39|0更新时间：2026-07-20-
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