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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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Volume 47 Issue 5，2026
Petroleum Geology
Prediction of hydrocarbon-rich sweet spots in volcanic rocks under the dynamic field-controlled accumulation setting of the whole petroleum system： Methods， principles， and practical applications
Abstract：The source rocks of the Permian Fengcheng Formation in the Junggar Basin possess considerable hydrocarbon exploration potential. However， the hydrocarbon sources and main factors controlling hydrocarbon enrichment in volcanic rock reservoirs along the northwestern margin of the basin have long remained unclear， resulting in a low success rate of sweet-spot drilling and limited reserve expansion， thereby constraining further exploration in the region. This study investigated the dynamic mechanisms of hydrocarbon accumulation and conducted quantitative evaluation of the volcanic rock reservoirs in the JL2 well block on the northwestern margin of the Junggar Basin， with the aim of precisely addressing key exploration challenges and identifying favorable exploration targets and their productivity potential. The investigation was based on the dynamic field-controlled accumulation theory of the whole petroleum system and incorporated 47 sets of geochemical data from the study area and well-test data from multiple high-yield wells. As indicated by the research results， （1） the critical thresholds defining the lower limit of buoyancy-driven hydrocarbon accumulation for local volcanic rocks stand at porosity of 9% and permeability of 1 × 10⁻³ μm². These two core parameters enable reliable classification of two major hydrocarbon accumulation domains—the free dynamic field and the confined dynamic field. （2） Quantitative characterization of four functional elements for primary accumulation （i.e.， source， facies， potential energy， and cap rock） confirms buoyancy as the dominant migration force within the free dynamic field， and a hydrocarbon-rich accumulation model was constructed based on the spatiotemporal configuration of these functional elements. （3） The dynamic field threshold of the facies-potential-source index （FPSI） served as a benchmark to quantitatively map hydrocarbon-rich sweet spots and precisely delineate potential exploration zones in the study area. （4） A quantitative dynamic-field model delivered calibrated productivity estimates for proposed drilling prospects. One new wildcat well location was prioritized and re-evaluation schemes covering eight prospective intervals across five existing wells were formulated. These findings clarify the hydrocarbon accumulation patterns and enrichment mechanisms of volcanic rock reservoirs in the study area. Its theoretical framework lays a solid foundation for refined exploration， efficient development， and reserve upgrading of volcanic hydrocarbon resources in the study area.Keywords：whole petroleum system;sweet-spot prediction and evaluation;buoyancy-driven hydrocarbon accumulation depth;dynamic field-controlled accumulation;Dynamic mechanism of hydrocarbon accumulation;volcanic rock;Junggar Basin495|177|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Research progress in enrichment processes and exploration technologies of natural hydrogen
Abstract：Natural hydrogen， characterized by its zero-carbon emission， low price， and sustainable supply， has emerged as a pivotal frontier in the development of hydrogen energy. Its enrichment process is fundamental to the formation and efficient utilization of natural hydrogen reservoirs. Based on a systematic review of relevant studies from both domestic and international sources， this study investigated the types of material foundations for natural hydrogen generation （hydrogen source rocks） and their differences in hydrogen-generation capacity， the dissipation mechanisms （including diffusion， dissolution， and adsorption） of natural hydrogen， the methodological similarities and differences between natural hydrogen and conventional oil and gas resource assessment， and the value of numerical simulation in advancing natural hydrogen research. As indicated by the research results， the distribution of natural hydrogen varies significantly due to diverse geotectonic structures； specifically， deep-seated faults serve both as pathways for deep-sourced hydrogen upwelling and as primary constraints on the distribution of effective hydrogen source rocks. However， current genetic identification using hydrogen and helium isotopes remains challenged by uncertainties regarding the co-genetic nature of hydrogen and helium， as well as the ambiguous evolutionary pathways of hydrogen isotopes. Furthermore， natural hydrogen faces complex preservation conditions. Diffusion， aqueous dissolution， and adsorption were identified as the primary drivers of hydrogen loss， which represent the most critical factors affecting the accuracy of resource assessment. In terms of resource evaluation， adapting conventional oil and gas assessment methods to natural hydrogen resources poses three major challenges， that is， differing evaluation logic， distinct evaluation criteria， and fundamental disparities in core parameters and quantification methods. Therefore， numerical simulation represents a key approach for quantifying natural hydrogen resource volumes and， following further development， can be more widely applied to studies of the migration and enrichment mechanisms of natural hydrogen.Keywords：numerical simulation;enrichment process;resource evaluation;hydrogen source rock;hydrogen generation;natural hydrogen372|123|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Progress in geological surveys of serpentinization-type natural hydrogen and related insights： A case study of the Hegenshan and Lajishan ophiolites
Abstract：Ophiolite belts are emerging as important targets for natural hydrogen exploration. Serpentinization is one of the major mechanisms responsible for natural hydrogen generation in the subsurface. Although ophiolite belts are widely distributed across China with numerous high-concentration hydrogen anomalies documented， the accumulation mechanisms and resource potential of natural hydrogen remain unclear. Preliminary progress has been made in geological surveys of natural hydrogen in the ophiolite belts of central Inner Mongolia and the southern Qilian region through the integrated application of technical methods， including the identification of fairy circles， measurements of soil hydrogen concentrations， and deep geophysical exploration. As indicated by the research results， （1） two zones characterized by high-magnetic and high-gravity anomalies associated with concealed ultramafic rocks were preliminarily identified in the Hegenshan ophiolite belt in central Inner Mongolia. A set of fairy circles and occurrences of natural hydrogen trapped in inclusions were also discovered. Together with the associated soil hydrogen seepage anomalies， these findings enabled the delineation of favorable zones for natural hydrogen generation and enrichment. （2） In the Lajishan ophiolite belt in the southern Qilian region， two large ultramafic bodies were recognized， characterized by high magnetization， high gravity and high electrical resistivity. The exposed peridotites show intense serpentinization with high Fe2+ and Fe3+ contents， as well as high Fe3+/Fe2+ ratios， indicating significant hydrogen generation through serpentinization and the presence of potential hydrogen sources. Several high-concentration soil hydrogen anomalies were detected， with a maximum value of 1 000 × 10-6， demonstrating promising exploration potential. （3） The preliminary survey results confirmed the existence of active natural hydrogen sources in the study areas， while revealing the key factors controlling the generation and enrichment of serpentinization-type natural hydrogen. These factors include the coupled effects of ultramafic rocks and an adequate water supply； the scale of ultramafic bodies and their coverage by sedimentary sequences， which serve to determine whether large-scale accumulation can occur； the residence time of hydrogen generation and trapping， which determines hydrogen retention time； and the persistent vs. transient accumulation behavior of hydrogen. （4） The findings also suggest favorable exploration targets： iron-rich rocks in the basement of early sedimentary basins and late-stage ultramafic intrusions rocks within sedimentary basins. The integrated exploration and development of natural hydrogen and geothermal resources have broad prospects. Geological surveys and research on natural hydrogen in China is still in its early stage， with both considerable potential and significant challenges. The progress and insights presented above are expected to help reduce the risks associated with natural hydrogen exploration and facilitate an early breakthrough in natural hydrogen resource discovery.Keywords：play fairway;geological survey;serpentinization;ultramafic rock;ophiolite belt;accumulation mechanism;natural hydrogen;southern Qilian region375|135|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Sedimentary characteristics of the microbial reef complex in the Lower Ordovician Liangjiashan Formation， Shimenzhai area， Qinhuangdao， Liujiang Basin
Abstract：The Liangjiashan Formation is widely developed in the Ordovician on the North China Platform， previous studies suggested that the Liangjiashan Formation mainly consists of argillaceous banded limestone， bioclastic limestone， and leopard-spotted limestone. It is characterized by abundant stromatolites and archaeocyathids， together with abundant biogenic dolomites. Recent studies indicate that substantial microbial carbonates are developed in the lower part of the Liangjiashan Formation， forming a microbial reef complex. To reveal the characteristics of the microbial reef in the Lower Ordovician Liangjiashan Formation in the Liangjiashan area of Shimenzhai， Qinhuangdao， a combination of fine outcrop description with microscopic identification of systematically collected samples was applied to characterize the microbial types， lithology， sedimentary structures， and vertical succession of the Shihuiyao section in the Liangjiashan area. As indicated by the research results， the microbial carbonates are rich in calcified cyanobacteria fossils， commonly including filamentous cyanobacteria， and net-like cyanobacteria and girvanella. Based on the mesoscopic characteristics of the carbonate bodies in the study area， four microbialite types were identified， namely thrombolite， stromatolite， leiolite， and laminite. Six types of microbial carbonate bodies were also recognized， namely bedded， wedge-shaped， mound-shaped， lenticular， mushroom-shaped， and columnar bodies. These rock bodies form rigid biogenic reef-building frameworks， building reef cores capable of resisting erosion caused by intense waves， tides， and storms， while also exerting binding and baffling effects， thereby forming the reef framework subfacies. This reef framework subfacies， together with the tempestite subfacies and storm-tidal delta subfacies， constitutes the microbial reef complex.Keywords：cyanobacteria;stromatolite;storm deposit;microbial carbonate;microbial reef complex;Liangjiashan Formation;Shimenzhai area;Liujiang Basin279|147|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Physical property differences and causes of organic-rich shale and organic-poor silty shale reservoirs in the Cambrian Qiongzhusi Formation， Central Sichuan Basin
Abstract：Commercial breakthroughs were achieved in both organic-rich shale and organic-poor silty shale gas reservoirs within the Lower Cambrian Qiongzhusi Formation of the Sichuan Basin. However， the pronounced differences in petrophysical properties between these two shale types and their underlying diagenetic controls remain poorly understood， thereby impeding reservoir-specific exploration strategies and targeted development. By integrating total organic carbon （TOC） analysis， X-ray diffraction （XRD）， and high-pressure mercury intrusion （HPMI） for geochemical and mineralogical characterization， low-temperature N₂ adsorption （LTNA）， low-pressure CO₂ adsorption （LPCA）， and spontaneous imbibition for pore structure assessment， and large-area imaging in scanning electron microscopy （MAPS-SEM）， energy-dispersive spectroscopy （EDS）， and quantitative evaluation of minerals by scanning electron microscopy （QEMSCAN） for microstructural imaging， we characterized the organic geochemical， mineralogical， petrophysical and microscopic pore structure characteristics of layer ⑤ organic-rich shale and layer ⑥ organic-poor silty shale of the Qiongzhusi Formation in the central Sichuan Basin. Meanwhile， the intensities of compaction， dissolution， and cementation were quantitatively assessed. The research results are as follows. （1） The two shale types exhibited similar mineral compositions； however， the organic-rich shale of layer ⑤ was superior to the organic-poor silty shale of layer ⑥ in terms of TOC content （avg. 2.03%）， porosity （avg. 3.80%）， and pore connectivity. Although the latter had relatively well-developed macropores， its total pore volume and specific surface area were lower. （2） The initial porosity of the organic-poor silty shale of layer ⑥ （avg. 65.40%） was slightly higher than that of the organic-rich shale of layer ⑤ （63.70%）； however， owing to its poorly sorted mineral grains and consequently lower compaction resistance， its porosity loss due to compaction （avg. 40.32%） was significantly higher than that of the organic-rich shale of layer ⑤ （avg. 33.06%）. （3） The high TOC content in the organic-rich shale of layer ⑤ promoted stronger acid-driven dissolution. The porosity increments derived from feldspar and carbonate mineral dissolution （avg. 0.43%） and from organic matter thermal evolution （avg. 0.12%） were both greater than that in the organic-poor silty shale of layer ⑥ （avg. 0.28% and 0.06%， respectively）. On the other hand， the abundant ions derived from intense dissolution in the sublayer also exacerbated cementation， resulting in a higher porosity loss due to cementation （avg. 19.76%） compared to the organic-poor silty shale of layer ⑥ （avg. 16.72%）. Taken together， these findings indicate that differences in compaction resistance arising from contrasting mineral grain sorting represent the primary control on the divergence in petrophysical properties between the two reservoir types. Furthermore， differences in the coupled intensity of dissolution-cementation， driven by TOC contrasts between the two shale types， further enhanced the discrepancy in reservoir quality.Keywords：petrophysical properties;diagenesis;organic-poor silty shale;organic-rich shale;Qiongzhusi Formation;Sichuan Basin372|122|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Marine reservoir formation models and hydrocarbon exploration potential in the southern Sichuan Basin
Abstract：Although marine sequences in the southern Sichuan are generally gas-bearing， hydrocarbon exploration discoveries remain disproportionate to the region’s resource potential compared with other zones in the basin. The key constraints are the poorly understood primary controlling factors governing reservoir formation and the unclear distribution patterns of large-scale reservoirs. Based on the latest exploration progress and integrating extensive field outcrop analyses， core testing data， and seismic interpretation， this study systematically evaluated the reservoir formation models and exploration potential of key marine sequences in the southern Sichuan Basin from the perspective of tectono-sedimentary differentiation. As indicated by the research results， although the southern Sichuan Basin shared the same evolutionary stages and cycles as the entire Sichuan Basin， it was relatively weakly affected by marginal tectonic stresses of the basin owing to its distal position relative to the Longmenshan tectonic belt and the Dabashan-Micangshan tectonic belt. Consequently， its sedimentary infill and evolution were governed by a dynamic regime of weak extension and weak compression. The differentiation features of the region are summarized as follows： rift-controlled differentiation during the Sinian （Ediacaran）-Early Cambrian， uplift-depression differentiation during the Middle-Late Cambrian to Silurian， reactivation-induced differentiation during the Early-Middle Permian， and paleogeomorphic differentiation during the Late Permian-Middle Triassic； since the Late Triassic， the region has been dominated by tectonic overprinting. Governed by this weak-differentiation dynamic background， three reservoir formation models were identified. First， the “dual-facies and pressure-field” relay reservoir formation model involves three key elements： sedimentary facies， diagenetic facies， and pressure field. In terms of reservoir-space architecture and evolution， sedimentary facies create the environment conducive to enrichment of dissolution-prone minerals， and sufficient mineral transformation provides the basis for porosity enhancement； diagenetic facies furnishes conditions favorable for diagenetic porosity modification， which in combination with widespread penecontemporaneous dissolution improve reservoir space； the pressure field sustains reservoir effectiveness with a stable overpressure system ensuring long-term capacity. The “facies-dissolution-fault” composite reservoir formation model includes three essential elements： favorable facies belts， dissolution-driven porosity enhancement， and interlayer faults. Favorable facies belts provide the fundamental framework that controls accumulation units at the macroscopic scale； dissolution-driven porosity enhancement is the key shaping reservoir architecture at the regional scale； interlayer faults spatially govern hydrocarbon enrichment， with platform margins or platform slope-break zones being optimal locations. While the “depositional-diagenetic” dual-phase superimposed reservoir formation model consists of sedimentary facies and diagenetic facies. Original high-energy facies belts underpin the development of large-scale high-quality reservoirs； tectonic uplifting-induced zoned karstification during the penecontemporaneous stage， is critical for the quality grading and spatial localization of large-scale， high-quality reservoirs； the superposition of early favorable sedimentary facies belts and penecontemporaneous diagenetic facies belts formed a dual-phase superimposed zone that ultimately controls the distribution of large-scale， high-quality reservoirs. Under the combined control of the four types of sedimentary differentiation and the three reservoir formation models， four types of hydrocarbon reservoirs were identified in the study area： near-source shoal-facies， laterally juxtaposed dolomite， facies-dissolution-fault composite， and marlstone oil and gas reservoirs. These reservoir types are systematically distributed across multiple stratigraphic horizons， defining a vertically stacked， multi-target exploration framework for the marine successions in the southern Sichuan Basin. In addition， the principal stratigraphic intervals associated with each reservoir formation and accumulation type were analyzed， and favorable exploration zones were identified.Keywords：genetic mechanism;reservoir type;sedimentary differentiation;reservoir formation model;marine strata;southern Sichuan Basin293|117|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Genesis of heterogeneity in the deep and ultra-deep tight sandstone reservoirs of the second member of the Triassic Xujiahe Formation， Western Sichuan Depression， Sichuan Basin
Abstract：To elucidate the heterogeneity and its origins in deep to ultra-deep clastic reservoirs， typical reservoirs of the 2nd member of the Xujiahe Formation （Xu 2 Member） in the western Sichuan Basin were selected as a case study. Integrated petrophysical testing， petrographic analyses， and diagenetic-fracture characterization were employed to systematically investigate the reservoir characteristics， heterogeneity patterns， and genetic features of Xu 2 Member in the western Sichuan Depression. As indicated by the research results， （1） the deep to ultra-deep reservoirs of Xu 2 Member exhibit an average porosity of 3.5% and an average permeability of 0.077 × 10⁻³ µm²， representing typical tight reservoirs. Diagenetic processes are complex and characterized by intense compaction， strong cementation， and weak dissolution. Multi-scale fractures are widely developed， with multi-stage fracturing and mineral infilling， resulting in extremely strong reservoir heterogeneity. （2） Reservoir heterogeneity is primarily manifested in physical-property variations. Sedimentary heterogeneity includes two aspects： material composition and sedimentary structure. Sedimentary architecture and lithofacies associations control the migration and precipitation of diagenetic materials at different scales， leading to significant variations in diagenetic type and intensity. The development of small-scale fractures is closely related to local stress magnitudes， sedimentary architecture interfaces， and lithofacies association types. （3） The variability of sedimentary environments and depositional processes， diagenetic environments and material migration， and stress regimes and fracture responses constitutes the key controlling factors underlying the origins of heterogeneity at different forms and scales in deep to ultra-deep reservoirs. （4） Detailed characterization of depositional processes， reconstruction of diagenetic evolution， and quantitative constraint of fracture responses are considered the main approaches for understanding the heterogeneity of deep to ultra-deep reservoirs.Keywords：origin;heterogeneity;clastic reservoir;deep to ultra-deep reservoir;Xu 2 Member;Sichuan Basin137|142|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Stacking patterns and sedimentary evolution characteristics of microbial mound-shoals in the 4th Member of the Sinian Dengying Formation， Gaomo area， Sichuan Basin
Abstract：The reservoirs in the 4th member of the Sinian Dengying Formation （Deng 4 Member）， Sichuan Basin are facies-controlled karst reservoirs formed by microbial mound-shoal deposits superimposed with dissolution and karstification. Clarifying the distribution and evolution characteristics of these microbial mound-shoals is essential for refined reservoir characterization. This study identified mound-shoal sedimentary microfacies types， characterized their stacking patterns and distribution characteristics across depositional stages， and clarified their sedimentary evolution processes and controls on reservoir development in the Deng 4 Member of the Gaomo area， Sichuan Basin， using integrated core， outcrop， well-log， and 3D seismic data. As indicated by the research results， （1） three types of mound-shoals developed in the Deng 4 Member under the control of relative water depth： vertically stacked， laterally migrating， and isolated types. The vertically stacked mound-shoals are characterized by massive aggradational geometry， displaying multi-layer parallel seismic events with moderate-to-weak amplitude and moderate-to-weak continuity. The laterally migrating type forms tabular laterally accreted or progradational mound-shoals， showing shingled seismic events with moderate-to-weak amplitude and moderate-to-weak continuity. The isolated type occurs as sheet-like mound-shoals， showing mound-shaped weak seismic reflections. （2） Temporally， mound-shoals were initially confined in distribution during the early depositional stage， dominated by migrating and isolated types. In the late stage， these complexes expanded， encompassing all three stacking patterns. （3） The average porosities of vertically stacked and laterally migrating mound-shoals are 5.2% and 3.3%， respectively. These two types contain well-developed high-quality reservoirs and are favorable exploration targets. In contrast， isolated mound-shoals have an average porosity of only 2.2%， with poorly developed high-quality reservoirs. The Deng 42 and Deng 43 sublayers in the platform-margin zone are dominated by vertically stacked mound-shoals and have relatively high development potential， whereas the intraplatform area is dominated by isolated mound-shoals， exhibiting poor reservoir performance.Keywords：stacking pattern;sedimentary evolution;microbial mound-shoal;Dengying Formation;Sinian;Gaomo area;Sichuan Basin83|130|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Sedimentary facies model of the Early Cambrian Maidiping-Qiongzhusi formations and its responses to the coupling of tectonics and sea-level changes in the Upper Yangtze region
Abstract：The Early Cambrian represents a critical period marked by the Rodinia supercontinent breakup and global marine transgressions. However， the sedimentary responses associated with the syn-rift to post-rift-depression transition along passive continental margins during this period， as well as their geological significance， remain poorly understood. In this study， we investigate the sedimentary facies model of the Maidiping-Qiongzhusi formations and its evolution within the Upper Yangtze region by fully utilizing data from 17 wells and 2 outcrop sections. The results indicate the presence of 5 sedimentary facies types in the study area， i.e.， tidal flat， deltaic， rift trough， neritic shelf， and turbidite facies， whose spatiotemporal evolution was governed by the rifting-to-depression tectonic sequence. During the rifting stage （i.e.， the deposition of the Maidiping Formation to the 6th sub-member of the Qiongzhusi Formation）， sedimentation was primarily confined within the Deyang-Anyue rift trough， characterized by the technically controlled basin architecture. During the depression stage （i.e.， the deposition of the 7th and 8th sub-members of the Qiongzhusi Formation）， sedimentation expanded laterally， transitioning into the widespread deposition of tidal flat and shelf facies， which is characterized by sea-level change-controlled sedimentary facies. On this basis， the origins of several critical paleooceanographic events are effectively constrained by sedimentological evidence. Specifically， the coupling relationship between phosphorites at the base of the Maidiping Formation and the Basal Cambrian Carbon Isotope Excursion （BACE） supports the integrated model involving volcanic/hydrothermal activity， nutrient salt inputs， increased productivity， and the formation of an anoxic environment. Furthermore， the high-frequency redox fluctuations recorded within the Qiongzhusi Formation provide direct evidence supporting the turbulent ocean hypothesis. Overall， this study provides an Early Paleozoic sedimentological example for the classical rifting-to-depression transition model while also supplementing sedimentological evidence for the dynamic changes in the oceanic redox interface during the Early Cambrian. Besides， the results of this study offer a critical geological basis for the prediction of ultra-deep shale gas sweet spots.Keywords：sea-level change;sedimentary facies model;shale gas exploration;Early Cambrian;Upper Yangtze region130|108|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
New insights into Late Carboniferous volcanic rocks of the Chengjisihanshan Formation in the Kebai fault zone， northwestern margin of the Junggar Basin， and their geological significance： Evidence from LA-ICP-MS zircon U-Pb dating of well Baiwu 21 and seismic data
Abstract：The Kebai fault zone is a critical area for the Late Paleozoic tecto-stratigraphic evolution and hydrocarbon exploration along the northwestern margin of the Junggar Basin. The stratigraphic assignment of the Carboniferous volcanic rocks in the fault zone has long been a controversial issue. The volcanic rock sequence encountered in well Baiwu 21 within the Kebai fault zone， previously assigned to the Early Permian Jiamuhe Formation， was selected as the research object. Integrated lithologicalassociation analysis， LA-ICP-MS zircon U-Pb dating， and seismic profile interpretation were conducted on this sequence to redefine its stratigraphic assignment. As indicated by the research results， （1） the volcaniclastic zircon U-Pb ages obtained from two tuffaceous sandy conglomerate samples of the volcanic rock sequence in well Baiwu 21 are （311.9 ± 2.2） Ma and （311.6 ± 2.2） Ma， respectively， indicating a formation age of the late stage of Late Carboniferous and reassigning the sequence to the Chengjisihanshan Formation （C2c）. （2） The rock suite is dominated by amygdaloidal andesite and basaltic andesite， exhibiting subalkaline， sodium-rich， and potassium-poor geochemical characteristics that are regionally consistent with those of the C2c， but markedly distinct from those of the Jiamuhe Formation （P1 jm）. （3） Seismic profile interpretation confirms that this stratigraphic unit has an angular unconformity contact with the underlying Lower Carboniferous Baogutu Formation （C1b）， mirroring the basal structural boundaries of the regional C2c rather than the sequence stacking pattern of P1 jm. Consequently， these multiple lines of evidence justify the redefinition of this volcanic rock sequence as part of the Chengjisihanshan Formation. This new insight resolves the long-standing controversy over stratigraphic division in the area， refines the Late Paleozoic stratigraphic framework along the northwestern margin of the Junggar Basin， and provides fresh chronological constraints on the closure timing and tectonic evolution of the western Paleo-Asian Ocean. Furthermore， it opens up new strata and horizons for deep Carboniferous hydrocarbon exploration in the northwestern margin of the Junggar Basin.Keywords：LA-ICP-MS zircon U-Pb dating;geochronology;stratigraphic redefinition;Chengjisihanshan Formation;Kebai fault zone;northwestern margin of the Junggar Basin108|84|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Enrichment mechanisms and play fairway prediction methods of coal-rock gas in the central-eastern Ordos Basin
Abstract：Significant breakthroughs have recently been achieved in deep coal-rock gas exploration in the Ordos Basin， opening up a new frontier for unconventional gas development. However， considerable discrepancies still exist regarding the enrichment mechanisms and favorable exploration targets of deep coal-rock gas， indicating that further research is needed. This study focuses on the No. 8 coal seam of the Benxi Formation， Upper Paleozoic， in the central-eastern Ordos Basin. Geological analysis， statistical analysis， and hydrocarbon dynamic field theory were comprehensively employed to investigate the enrichment conditions and favorable area distributions of deep coal-rock gas. As indicated by the research results， during the critical thermal evolution stage with vitrinite reflectance （Ro） ranging from approximately 1.5% to 2.5%， the hydrocarbon generation， reservoir development， migration， and preservation conditions of coal-rock gas exhibit significant spatiotemporal coupling characteristics， which exert a dominant control on the formation and distribution of gas-rich sweet spots. Specifically， these characteristics are reflected in the following four aspects： （1） coal rocks at this stage are characterized by high gas generation rates and strong hydrocarbon generation intensity， thereby providing a substantial material basis for gas enrichment； （2） coal rocks exhibit abnormally high porosity， with a secondary peak occurring at Ro ≈ 2.0%， while the pore volumes of both micropores and macropores increase synchronously， providing favorable reservoir space for coal-rock gas accumulation； （3） the cleat system of coal rocks is highly developed， and cleat density reaches its maximum at Ro ≈ 1.9%， forming efficient migration pathways for coal-rock gas accumulation； （4） the surrounding strata adjacent to coal seams are characterized by confined dynamic fields， thereby creating favorable preservation conditions for gas-rich sweet spots. On this basis， a comprehensive evaluation model for favorable deep coal-rock gas areas was established based on the quantitative characterization of the four key elements of “generation， reservoir， migration， and preservation.” A multi-parameter superposition method was further adopted to predict and grade favorable areas within the study area. The prediction results divided the study area into Class Ⅰ， Class Ⅱ， and Class Ⅲ favorable areas. Drilling results indicate that high-gas-content wells （gas content ≥ 18 m³/t） account for 90% of wells in Class Ⅰ favorable areas， with an average gas content of 24.04 m³/t. The prediction results are highly consistent with actual exploration performance. The research results provide a reliable theoretical basis and technical support for play fairway delineation and further exploration deployment of deep coal-rock gas in the Ordos Basin， and are of great significance for improving resource development efficiency and safeguarding national energy security.Keywords：pore structure;whole petroleum system;favorable area prediction;oil and gas enrichment;coal-rock gas;Ordos Basin131|95|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Study on the geological control factors and distribution patterns of shale oil enrichment and high productivity in the Jiyang Depression， Bohai Bay Basin
Abstract：Exploration breakthroughs have been achieved across multiple sags and stratigraphic intervals in the Paleogene of the Jiyang Depression， Bohai Bay Basin， with cumulative shale oil production exceeding 1.0 × 106 t. This area has become a viable replacement play for increasing reserves and production at Shengli oilfield. Based on geochemical analyses and production data from shale oil wells in the lower sub-member of the third member and the upper sub-member of the fourth member of the Paleogene Shahejie Formation （Es3L-Es4U）， this study systematically examines production behavior， geological control factors on enrichment and high productivity， and distribution patterns using statistical analysis， laboratory tests and typical case studies. As indicated by the research results， shale oil production in the Jiyang Depression is characterized by early oil discovery， high initial productivity， and a three-stage decline trend throughout the full lifecycle production. Shale oil enrichment and high productivity are jointly controlled by oil-bearing properties， reservoir quality， sealing capacity， and oil mobility. Favorable oil-bearing content and reservoir quality constitute the fundamental basis for oil enrichment and high productivity. In particular， carbonate-rich lithofacies with free hydrocarbon content （S1） greater than 2 mg/g and well-developed pore-fracture networks are more conducive to enrichment and high productivity. Effective sealing conditions provide a critical guarantee for shale oil preservation and productivity. Seal rocks of laminated shale facies enclosed by layered or massive lithofacies of poor physical properties， not only facilitate hydrocarbon retention but also promote the development of abnormally high pressure， thereby enhancing oil output. Favorable mobility conditions are the key to achieving high productivity. Well-connected pore-fracture networks in laminated carbonate-rich shales provide efficient seepage channels. Elevated formation temperatures and preferential water-wet conditions enhance imbibition-driven displacement， improving oil mobility and sustaining production. Abnormally high pressure further supplies the driving force for elastic oil production. Shale oil in the Jiyang Depression exhibits a facies-controlled， laterally contiguous distribution， with differential enrichment governed by fault systems. These findings provide a scientific basis for integrated deployment and efficient exploration， contributing to strategic breakthroughs and the development of national-level Jiyang Shale Oil Demonstration Zone.Keywords：reservoir capability;oil-bearing property;mobility;sealing capacity;distribution pattern;shale oil;Jiyang Depression;Bohai Bay Basin136|90|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Characteristics of retained hydrocarbons and dynamic mechanisms of continental shale oil accumulation in the Dongying Sag
Abstract：Accurate prediction of continental shale oil “sweet spots” is essential for achieving economically viable exploration and development， for which clarifying the distribution boundaries and accumulation mechanisms of effective retained hydrocarbons in shale is a critical prerequisite. The shales of the lower sub-member of the 3rd member of the Paleogene Shahejie Formation （Es3L） and the upper sub-member of the 4th member of the Paleogene Shahejie Formation （Es4U） in the Dongying Sag were investigated to elucidate the concept of effective retained hydrocarbons and the criteria for identifying their boundaries， determine the main controlling factors， analyze the dynamic mechanisms of hydrocarbon accumulation， and establish a dynamic equilibrium model for these boundaries. As indicated by the research results， sedimentary environment-controlled differences in hydrocarbon generation and expulsion result in different boundaries of effective retained hydrocarbons in the two stratigraphic intervals. With an oil saturation index （OSI） of 100 mg/g as the criterion， the effective retained hydrocarbon boundaries of Es3L and Es4U occur at depths of 3 000 ~ 4 000 m （thermal maturity， Ro = 0.48% ~ 0.85%） and 2 500 ~ 4 500 m （Ro = 0.38% ~ 1.32%）， respectively. The enrichment of effective retained hydrocarbons is jointly controlled by lithofacies， total organic carbon （TOC） content， vitrinite reflectance （Ro）， and formation pressure. Areas characterized by organic-rich laminated shale， TOC content > 2%， Ro within the oil window， and a pressure coefficient > 1.2， are favorable for enrichment. Shale oil accumulation is a non-buoyancy-driven process dominated by molecular forces. The driving force derived from molecular expansion achieves a dynamic equilibrium with the combined resistance exerted by capillary forces in nano-scale pore throats， interfacial adsorption forces， and other factors， thereby establishing a retention and enrichment model for shale oil characterized by surface adsorption， storage in macropores， and hindered migration in micropores. This model ultimately constrains the distribution boundary of effective retained hydrocarbons. This study improves the theoretical understanding of the intra-source retention and enrichment of continental shale oil and provides a geological basis for the quantitative prediction of shale oil “sweet spots” in the Dongying Sag and analogous continental basins.Keywords：unconventional oil and gas;hydrocarbon accumulation mechanism;hydrocarbon accumulation dynamics;retained hydrocarbon boundary;shale oil;Bohai Bay Basin;Dongying Sag86|85|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Dynamic evolution and controlling factors of source-to-sink systems for continental rift basins： A case study of the Wenchang Formation， southeastern Huizhou Sag， Pearl River Mouth Basin
Abstract：The Cenozoic continental rift basins are extensively developed in China. Under the influence of episodic extensional faulting， the constituent “source-conduit-sink” elements frequently undergo significant modification or reorganization， making deep-time source-to-sink （S2S） coupling a challenging issue in contemporary basin analysis. Recently， major exploration breakthroughs in the syn-rift successions of the southwestern Huizhou Sag， Pearl River Mouth Basin （PRMB）， have yielded a wealth of well， seismic， and analytical data， providing a robust foundation for addressing these complexities. By integrating prototype basin restoration with quantitative analysis of sediment provenance and catchment units， this study clarifies the differential evolution and response mechanisms of the S2S system of the Wenchang Formation， southwestern Huizhou Sag. The research results shows that denudation during the Early Wenchang Formation deposition was primarily concentrated on intra-basinal uplifts controlled by syn-sedimentary faults or basement upheaval， with a relatively restricted denudational extent and thicknesses ranging from 40 to 300 m， whereas the denudational area expanded significantly during the Late Wenchang period， reaching a maximum thickness of 500 m. Three major S2S systems were identified within and around the study area： the Southern （Huixi low uplift and Dongsha uplift）， Northern （northern uplift）， and Eastern （Huizhong uplift to the Huibei area） S2S systems. Specifically， the Southern system， controlled by pre-existing faults， exhibits well-defined watersheds and drainage divides and is subdivided into four first-order and eighteen second-order catchment units， with transport conduits dominated by structural transfer zones and fault-related valleys， exhibiting a width-to-depth ratio less than 10）； the Northern system’s drainage divides are jointly constrained by NE- and NW-trending faults， with 4 first-order catchment units identified for the early Wenchang period， which evolved into 5 during the late Wenchang period， and the transport pathways are characterized by lateral denudation， exhibiting a width-to-depth ratio greater than 20； the Eastern system lacks stable drainage divides， with sediment primarily sourced from fault-bounded steep slopes. The Huizhou Movement （ca. 43 Ma） caused a northwestward migration of the rifting center， accompanied by extensive basement uplift. This movement reshaped the paleogeomorphic framework from the early to late Wenchang periods， driving drainage divide retreat in the Southern system and reorganization in the Northern system， which profoundly impacted basin-filling patterns and reservoir sand-body distribution. This study elucidates the dynamic coupling of S2S systems and sand-body dispersal patterns driven by tectonic migration， providing insights for the analysis of similar complex rift basins.Keywords：formation denudation;dynamic coupling;source-to-sink system;tectonic-sedimentary evolution;rift basin;Wenchang Formation;Pearl River Mouth Basin188|131|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Petroleum Geology
Development， evolutionary characteristics， and genetic mechanisms of faults in the Haizhong Sag， Beibu Gulf Basin
Abstract：The Haizhong Sag in the Beibu Gulf Basin has undergone superimposed modification by multi-phase tectonic activity， resulting in a highly complex and interlaced fault system. Clarifying the fault orders， assemblage patterns， differences in fault activity， and spatiotemporal evolution is of great significance for hydrocarbon exploration in the Haizhong Sag. Based on merged 3D seismic data， this study systematically determined the fault assemblage patterns， plan-view distributions， and hierarchical characteristics， and elucidated the regional disparities and genetic mechanisms of fault evolution. As indicated by the research results， （1） the faults in the sag were classified into five orders and were mainly NE-， NEE-， near-EW-NWW-， and NW-trending， among which the NEE and nearly WE-NWW striking faults are predominant and exhibit stratification-dependent differences. To be specific， the near-EW-NWW-trending faults prevail in the northern sub-sag； NWW- and NE-trending faults dominate the northern steep-slope zone； the NEE- and near-EW-NWW-trending faults are interwoven in the southern gentle-slope zone. （2） Four fault styles were identified： extensional faults， strike-slip faults， composite extensional-strike-slip faults， and inverted faults. （3） Significant temporal disparities exist in fault activity sequences： the NWW-trending faults were mainly active during the Late Oligocene， whereas the NEE-trending faults experienced long-term activity from the Paleocene to the Oligocene， with their activity intensity decreasing from northwest to southeast. For instance， fault No. 3 intensified its activity during deposition of the Liushagang Formation， peaked during deposition of the 4th and 3rd members of the Weizhou Formation （Wei 4 and Wei 3 members）， and gradually weakened during deposition of the 2nd and 1st members of the Weizhou Formation （Wei 2 and Wei 1 members）. （4） The fundamental mechanism underlying the differential spatiotemporal fault activity in the Haizhong Sag lies in the transformation of stress field properties and directions driven by regional tectonic events， while the inherited reactivation and selective activation of pre-existing basement faults serve as critical controlling factors for differential fault evolution. （5） Differential fault activity was concentrated in four key evolutionary periods： the Paleocene-Middle Eocene， Late Eocene-Middle Oligocene， Late Oligocene， and the end of the Middle Miocene. Their core driving forces were derived from five key tectonic factors： India-Eurasia plate collision， Pacific plate subduction， subduction and extinction of the Paleo-South China Sea， South China Sea spreading， and strike-slip movement along the Ailaoshan-Red River Fault Zone. By regulating the evolution of the regional stress field and its synergistic interaction with pre-existing basement faults， these tectonic factors jointly controlled the spatiotemporal distribution， activity intensity， and evolutionary patterns of the faults in the Haizhong Sag.Keywords：fault system;fault activity;tectonic evolution;Haizhong sag;Beibu Gulf Basin109|153|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Methods and Technologies
Pore-scale modeling of supercritical CO2 displacement of shale gas under convection-diffusion-adsorption effects
Abstract：To achieve the dual goals of efficient shale gas development and geological CO2 sequestration， supercritical CO2 （Sc-CO2） displacement technology shows promising application potential. However， the microscopic mechanisms by which Sc-CO2 displaces CH4 in shale porous media remain insufficiently understood. In particular， the mass-transfer mechanisms at the pore scale are yet to be clarified. Based on the nanopore-matrix structure of shale， a two-dimensional pore-scale model was constructed in this study. The microscopic process and controlling factors of shale gas displacement by Sc-CO2 at 40 ℃ and 8 MPa were， thereby， systematically investigated under convection-diffusion-adsorption effects. As indicated by the research results， （1） in the pore space， Sc-CO2 forms a propagating concentration front through convection-diffusion， enabling efficient displacement of free CH4. In the matrix space， Sc-CO2 gradually replaces adsorbed CH4 owing to its stronger adsorption affinity. Its adsorption amount shows a three-stage evolution of zero adsorption， increase， and saturation， whereas the adsorbed CH4 amount undergoes a corresponding process of saturation maintenance， desorption， and depletion. （2） With increasing diffusion coefficient （Ds）， Sc-CO2 adsorption in the matrix is enhanced， but its convection-diffusion in the pores is weakened. This leads to a decrease in the Sc-CO2 concentration and an increase in the CH4 concentration in the pores. （3） As transport selectivity （sel） increases， Sc-CO2 adsorption in the matrix is enhanced， whereas pore-scale convection-diffusion is suppressed. As a resut， the Sc-CO2 concentration decreases and the equilibration time is prolonged， while the migration behavior of CH4 is less affected by sel. （4） An increase in the desorption rate constant （kd） significantly promotes CH4 desorption， resulting in a corresponding increase in the total CH4 concentration in the pore space. In contrast， Sc-CO2 is insensitive to changes in kd because of its strong adsorption， and both its adsorption amount and concentration remain stable.Keywords：convection-diffusion-adsorption;mass transfer;pore-scale modeling;nanoscale;supercritical carbon dioxide （Sc-CO2）;enhanced gas recovery;shale gas149|54|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Methods and Technologies
Multi-factor coupled material balance method for reserves calculation in shale condensate-gas reservoirs
Abstract：Reserve assessment of shale condensate-gas reservoirs is affected by multiple complex physical mechanisms， such as gas adsorption-desorption and condensate dropout， but their mechanisms of action and degrees of influence remain unclear. Based on fluid mole conservation and dynamic changes in reservoir volume， we established a material balance equation by comprehensively considering the multi-effect coupling of adsorption-desorption， condensate dropout， pore compression， bound water expansion， matrix shrinkage， and water vapor expansion. Subsequently， a new reserve calculation method was proposed through linearization. The reliability of the method was verified by case-application calculation and numerical simulation， and key factors affecting reserve assessment and their sensitivities were systematically analyzed through comparison with traditional methods. As indicated by the research results， （1） the proposed reserve calculation method requires only reservoir and fluid physical parameters， several average formation pressures， and cumulative production data. The original geological reserves of free-state and adsorbed-state condensate gas can be calculated from the slope and intercept of the linear function， respectively， thereby enabling the estimation of original geological reserves of both natural gas and condensate. （2） The relative error between the reserves calculated using the new method and the numerical simulation reference values is less than 1%， indicating high accuracy and reliability. When some factors are ignored， this method can be reduced to existing conventional methods， showing both comprehensiveness and compatibility. （3） Ignoring the adsorption effect causes the calculated reserves to be 40.71% lower than the actual value， whereas ignoring condensate dropout and pore compression causes the calculated reserves to be 17.71% higher than the actual value. In contrast， bound water expansion， matrix shrinkage， and water vapor expansion have only minor effects on reserve evaluation results. The research results can provide a theoretical basis for determining the development scale， optimizing well spacing， conducting performance analysis， and predicting recovery factors in shale condensate-gas reservoirs.Keywords：adsorption-desorption;retrograde condensation;material balance equation;original geological reserves;reserve calculation;condensate-gas reservoir;shale119|66|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Methods and Technologies
Theoretical basis and field application of fracture network activation and proppant-free stimulation for deep coal-rock gas development
Abstract：Coal-rock gas in the Ordos Basin represents an abundant， strategically vital resource for enhancing China’s natural gas supply capacity. However， these deep coal reservoirs exhibit extremely low permeability under in-situ conditions. Although current commercial production breakthroughs primarily rely on large-scale propped hydraulic fracturing， this method is constrained by high operational costs and marginal economic returns. Focusing on the No. 8 coal seam of the Benxi Formation in the eastern Ordos Basin， this study integrates reservoir characterization， rock mechanical testing， water-coal interaction experiments， and post-fracturing conductivity evaluations with field practices for comprehensive analysis. As indicated by the research results， the coal reservoirs are characterized by highly developed natural cleats and pronounced plastic deformation. Under the mechanical boundary conditions of “rigid support” provided by the roof and floor strata， a unique configuration similar to a “stress compartment” is established. The injection of high-pressure fluids induces coupled tensile-shear failure and structural slip within the coal matrix， promoting matrix fragmentation and activation of natural cleats， which ultimately generates a complex fracture network. The resulting fragmented coal significantly expands the available seepage space under in-situ conditions， allowing the unpropped fractures to maintain high conductivity even after fracturing fluid flowback. Based on these insights， the concept of “fracture-network activation and proppant-free stimulation” for coal-rock gas development was proposed， marking a technological paradigm shift from “controlled proppant transport with fluid rate stabilization” to “maximum proppant concentration，” and ultimately to “proppant-free fracturing.” Field pilot tests demonstrate that， under conditions of no proppant and similar fluid volumes， the single-well production is on par with that of conventional fracturing， indicating that fluid volume is a primary factor controlling well productivity. Specifically， a horizontal well with a 1 500 m lateral and subjected to proppant-free fracturing with 24 500 m³ of fluid， achieved a stable daily gas production exceeding 40 × 103 m³. This study concludes that proppant-free fracturing technology successfully capitalizes on the unique geological-engineering attributes of coal-rock reservoirs. While ensuring stable production， it offers substantial cost reduction and environmental advantages， holding profound implications for the commercial， large-scale development of deep coal-rock gas.Keywords：field test;water-coal interaction;physical simulation;permeability enhancement mechanism;stress compartment;fracture-network activation and proppant-free fracturing;coal-rock gas;Ordos Basin133|113|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Methods and Technologies
Construction of a TOC-based fractal dimension calculation formula for highly mature organic-rich marine shale and its main influencing factors： A case study of the Silurian Longmaxi Formation in southern Sichuan Basin
Abstract：Research on shale pore structure and its heterogeneity plays a pivotal role in the study of unconventional oil and gas reservoirs.Fractal dimension is a key parameter for characterizing the complexity of shale pore systems.However， existing fractal dimension calculation methods are typically computationally demanding and require substantial data.Moreover， the quantitative control law and mechanism of total organic carbon （TOC） content over the surface fractal dimension of highly evolved shale pores remain unclear.Shale samples were collected from the Silurian Longmaxi Formation in the Tiangongtang block and Weiyuan block in southern Sichuan Basin.TOC measurements， X-ray diffraction （XRD） mineral composition analysis， and nitrogen gas adsorption （N2-GA） experiments were conducted.On this basis， an empirical formula for calculating the fractal dimension （D1） based on TOC was established， yielding results with excellent equivalence to those obtained from the Frenkel-Halsey-Hill （FHH） model.Preliminary application results confirm that， compared with the D1 values calculated from measured data in the Changning area using the FHH model， the TOC-based D1 values have an average error of ± 0.012， an error range of no more than ± 2%， and a relative error within ± 2%.Compared with published fractal dimension data for the Wufeng Formation-Longmaxi Formation shale from parts of southern Sichuan Basin and the Jingmen exploration area in Hubei Province， the error narrowed to ± 0.027， with an error range of no more than ± 5% and a relative error within ± 10%.The TOC-based D1 can effectively characterize the roughness of pore surfaces in marine， highly evolved shale samples and has broad geological applicability.It can accurately characterize the pore structures of shales from highly mature shale formations and provide important theoretical and technical support for shale gas reservoir evaluation.Keywords：gas adsorption;fractal dimension;TOC;pore structure;reservoir evaluation;marine shale;Longmaxi Formation;Sichuan Basin93|108|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Methods and Technologies
Impact mechanism of frozen coring technology on reservoir fluid saturation and petrophysical parameters
Abstract：With the extensive development of shallow unconsolidated sandstone heavy oil resources， conventional sealed coring methods have struggled to address the issue of getting intact cores from unconsolidated sandstone reservoirs. Consequently， improvements in coring techniques have been made， resulting in the development and application of sealed cryogenic pressure-maintaining coring technology. However， field practice has shown that cryogenic coring may introduce deviations in the determination of reservoir oil saturation and petrophysical parameters. In this study， comparative experiments on artificial cores were systematically conducted at different freezing temperatures， and correspondingly the variation patterns of core oil saturation and petrophysical parameters， together with the impact mechanism， were analyzed in depth. The experimental results show that oil saturation exhibits significant nonlinear variation with freezing temperature： it generally decreases between -10 and -20 °C， slightly increases again at -40 °C， and rises markedly under cryogenic conditions at -60°C. Porosity， by contrast， shows an overall decreasing trend under low-temperature conditions. Based on the experimental observation and mechanism analysis， this study delves into the coupled influence of multiple factors， including phase transitions of crude oil components， ice-crystal plugging， microfracture development， and rock-fluid interactions， on oil saturation and porosity. A temperature-interval-based linear correction model for oil saturation was established using the experimental data. This model can， to a certain extent， correct measurement deviations introduced by freezing treatment， and provides experimental evidence and reference for restoring the original fluid occurrence state of cores and improving the accuracy of reserve evaluation for shallow unconsolidated sandstone reservoirs.Keywords：cryogenic coring;porosity;oil saturation;correction model;unconsolidated sandstone;heavy oil development93|75|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Methods and Technologies
Sandstone petrographic analysis integrating deep learning and image processing
Abstract：To overcome the high subjectivity of manual identification in traditional sandstone petrographic analysis and the limitations of conventional image analysis methods， which typically focus on isolated tasks and lack systematic quantitative characterization capabilities， this study proposes an integrated intelligent analysis scheme for thin-section images that covers both workflows and techniques. A sandstone petrographic analysis framework encompassing three major domains （i.e.， composition， texture， and porosity） was established. This framework defines a standardized analytical pathway from raw thin-section images to geological parameters. The deep learning and image processing technologies were integrated into this scheme. Specifically， the Mask R-CNN model was employed for the precise segmentation of detrital grains， and the MobileNet model was utilized for compositional classification； meanwhile， tailored image processing algorithms were integrated to systematically extract three categories of parameters： composition， texture （including grain size， sorting， roundness， and grain contacts）， and porosity （areal porosity and pore diameter）. Validation using sandstone samples from multiple basins was performed. As indicated by the research results， （1） the results of the integrated analysis were highly consistent with those of manual identification regarding key parameters， while demonstrating superior objectivity and precision in geologically complex scenarios such as quartz overgrowths； （2） the constructed sandstone analysis framework systematically generated “petrographic datasets”， successfully achieving a paradigm shift from qualitative description to quantitative analysis.Keywords：image processing;Mask R-CNN model;MobileNet model;deep learning;intelligent quantitative analysis;sandstone petrography161|99|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16Methods and Technologies
Well-seismic intelligent inversion method for tight sandstone reservoir prediction under coal-seam interference suppression
Abstract：The tight sandstone reservoirs in the 8th member of the Permian Lower Shihezi Formation （He 8 Member） and the 1st member of the Shanxi Formation （Shan 1 Member） along the eastern margin of the Ordos Basin are highly heterogeneous. Multiple coal seams and limestone beds are widely developed beneath the target reservoirs， resulting in complex and variable seismic reflection characteristics of the sandstone bodies. Conventional reservoir prediction methods are limited in their ability to finely characterize medium- to thin-bedded sand bodies and their interwell distribution. Therefore， an intelligent inversion method capable of suppressing coal-seam interference is urgently needed. Four forward conceptual models were established according to the sedimentary characteristics of the study area， and multi-wavelet decomposition and reconstruction were used to suppress strong reflections and reconstruct the time-frequency information from the seismic data. On this basis， frequency-decomposed intelligent inversion was combined with neural network modeling to establish a nonlinear mapping relationship between seismic waveform features and gamma-ray （GR） logs. This enabled integrated constraints and collaborative inversion of multi-source information， thereby improving the identification of medium- to thin-bedded sand bodies. As indicated by the research results， the forward modeling results show that underlying coal seams significantly interfere with the seismic responses of sand bodies， and the degree of interference varies with sand body stacking relationships， sand body thickness， and the vertical distance between the sand bodies and coal seams. After strong reflection suppression， the frequency-decomposed intelligent inversion method can accurately characterize the macroscale distribution of sand bodies and significantly improve the identification of medium- to thin-bedded sand bodies and the reliability of interwell prediction. When the sand body thickness exceeds 4 m， the sand body response ratio surpasses 90%， and the responses of well-adjacent traces are markedly improved compared with the original seismic waveforms. This fully reflects the constraint effect of well information and improves the resolution of sand body identification. Under the condition of coal-seam suppression， the neural-network-based frequency-decomposed intelligent inversion method exhibits good applicability and reliability. Three main types of sand body assemblage patterns were identified in the target interval of the study area： vertically stacked， laterally amalgamated， and isolated. This method compensates for the limitations of conventional acoustic impedance inversion in tight sandstone reservoir prediction and provides an effective technical approach for the fine characterization and spatial distribution prediction of tight sandstone reservoirs in the study area.Keywords：forward model;multi-wavelet decomposition and reconstruction;BP intelligent inversion;reservoir prediction;tight sandstone;coal-bearing formation;Sulige gas field210|74|0<HTML><L-PDF><Meta-XML>Updated：2026-09-16
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