最新刊期
卷 47 ， 期 2 ， 2026
- 摘要：The century-long history of the oil and gas industry in the world has witnessed rapid advancements in petroleum exploration and an ever-expanding scope of research. The dynamic evaluation of oil and gas resources has played a crucial role in guiding and facilitating this process. Specifically， theoretical breakthroughs and initial exploration help identify new potential plays， while resource evaluation and exploration practices together drive both theoretical and technological progress. These contribute to a great leap forward in new areas of petroleum exploration. Over the past two decades， driven by technological advancements and the goals of achieving carbon neutrality and peak carbon dioxide emissions， global petroleum exploration efforts have been extended into deep-water environments， deep plays， and unconventional resources dominated by shale oil and gas， continuously opening new frontiers. According to the independent evaluation of the China National Petroleum Corporation （CNPC） 2024， the technically recoverable oil and gas resources worldwide amount to 1 868.4 billion tons of oil equivalent， with conventional recoverable resources accounting for 61.2% and unconventional recoverable resources representing 38.8%. Therefore， conventional hydrocarbon resources remain the primary source of utilization， while unconventional hydrocarbon resources serve as an effective supplement. In the next 30 years， oil and gas will continue to play a vital role in global primary energy consumption. In this context， Chinese oil companies should sustain production and ensure sustainable development by securing numerous new overseas petroleum exploration and exploitation projects. Focusing on the high-quality petroleum exploration and exploitation overseas and in combination with petroleum geological conditions， resource potential， and cooperation environments， top ten major regions should be given priority for conventional petroleum exploration in the next decade， such as the Russian Arctic， the Central South Atlantic， and offshore East Africa. For shale oil exploration， seven major regions should be highlighted， including the Arabian Basin in the Middle East， the Volga-Urals Basin and West Siberian Basin in Russia， and the Bongor Basin and the southern Chad Basin of the West and Central African rift system. With the profound transformation of the global energy landscape and increasing difficulties in resource development， petroleum exploration is confronted with unprecedented complex challenges. Moving forward， the deep integration of theory， technology， exploration models， and intelligence will be a critical approach to successful petroleum exploration in the future.关键词：deep-water;deep play;shale oil;resource evaluation;geological theory;artificial intelligence （AI）;petroleum exploration direction372|94|0更新时间：2026-04-13
- 摘要：The successful drilling of well Shendi Take-1 has opened a new era in the petroleum industry， marking the beginning of 10 000-meter deep hydrocarbon exploration. Consequently， investigating the hydrocarbon exploration depth to its limits and the boundaries for hydrocarbon occurrence has become a hot topic in the geological community. In this study， we present a systematic summary of the discoveries and geological theory of hydrocarbon exploration at a depth of 10 000 m. The hydrocarbon generation potential of the Nanhua， Ediacaran， and Cambrian source rocks is quantitatively assessed. It is demonstrated that the depth threshold for preserving liquid oil extends up to 9 000 m in basins with low geothermal gradients， thereby enhancing the potential for ultra-deep oil exploration. Mechanisms responsible for the preservation of large-scale oil reservoirs formed 250 million years ago are identified， supporting the exploration of ultra-deep ancient hydrocarbon reservoirs. Furthermore， it is proposed that carbonate reservoirs exhibit no definitive lower depth limit. Additionally， a new type of fractured-vuggy oil reservoirs， formed by complex seepage processes and characterized by multiple oil-water interfaces， is identified. This discovery reveals the mechanisms by which secondary geochemical processes modify the properties and phases of hydrocarbons. Ultra-high oil and gas columns are discovered in ultra-deep reservoirs， revealing the enrichment and distribution patterns of hydrocarbons in high-yield and high-efficiency wells. These findings provide theoretical support for achieving major hydrocarbon discoveries in ultra-deep reservoirs and for reshaping hydrocarbon exploration strategies. Furthermore， they also open the new frontier of hydrocarbon exploration at a depth of 10 000 m， marking a new era for the petroleum industry. Additionally， we analyze major challenges in the geological theory of hydrocarbon exploration at such a depth， propose the concept of limit hydrocarbon exploration depth， and examine the boundaries for hydrocarbon occurrence. It is therefore essential to accelerate efforts to bridge the knowledge gap created by the high temperature and high pressure conditions in the Earth’s interior， thereby enabling free hydrocarbon exploration within the limit depth range. Such progress will help position hydrocarbon resources in 10 000-m-deep plays as a vital component in safeguarding China’s energy security.关键词：well Shendi Take-1;hydrocarbon occurrence boundary;limit hydrocarbon exploration depth;10 000-meter-deep play;Nanhua System;Sinian system;Cambrian System;deep oil and gas exploration290|58|0更新时间：2026-04-13
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Quantitative characterization and modeling strategies of architectural units in carbonate platforms AI导读
摘要：Reservoirs within carbonate platforms are governed by complex variations in facies zones， exhibiting a wide range of sedimentary microfacies， including tidal channels and reef shoals. Since the sedimentary microfacies interbed with each other， carbonate platform reservoirs feature diverse architectural styles and complex macroscopic structures. Consequently， conventional individual modeling techniques are often inadequate to effectively characterize the reservoir structures of carbonate platforms that experienced rapid facies transitions under differential sedimentary settings. Therefore， it is necessary to develop quantitative characterization and modeling strategies for the architectural units of reservoirs tailored to different microfacies. By integrating core observations， logs， and seismic data， this study presents a hierarchical analysis of architectural units of carbonate reservoirs in the H oilfield in Iraq. As a result， two types of sedimentary architectural unit assemblages are identified within the carbonate platforms： tidal channel-bioclastic shoal complexes and tidal bioclastic delta complexes. Based on seismic response characteristics， the interface morphologies and spatial distribution patterns of these architectural units are delineated. Accordingly， for microfacies within these architectural units， we systematically analyze their differential overlapping styles in both plane and cross-section views based on their scales and evolution patterns. Furthermore， a layered and segmented modeling strategy is established for carbonate platform reservoirs. The analytical results indicate that tidal channel-bioclastic shoal complexes primarily occur within the MB1-2 layers. These architectural units exhibit roughly uniform thicknesses （average single-stage thickness of approximately 15 m） and high width-to-thickness ratios. Based on variations in architectural style， these complexes can be subdivided into three segments： meandering， aggradational， and migratory segments. Within each segment， distinct interfaces of tidal channel-bioclastic shoal complexes are identified. The primary differences among the three segments arise from tidal channels in different migration directions， which result in varying degrees of erosion and incision of bioclastic shoals under the influence of the meandering of single-stage tidal channels. Consequently， the shoal bodies show mutual truncation and stacking. Based on these findings， a multi-level architectural modeling strategy is proposed for tidal channel-bioclastic shoal complexes. Specifically， the 5th-level architectural model is established using a deterministic modeling method with deterministic interfaces as constraints. Then， the 4th-level architectural model is constructed within the framework of the 5th-level architectural model using the object-based modeling （OBM） method， with modeling parameters set based on the statistical geometric features of architectures. On the other hand， tidal bioclastic delta complexes are predominantly identified within the MB2 layer. These architectural units pinch out from the center toward both sides， featuring relatively large average single-stage thicknesses （approximately 30 m） and low width-to-thickness ratios. Based on variations in architectural style， these complexes can also be further subdivided into three segments： distal progradational delta， incised valley， and proximal retrogradational delta. Under the constraint of the 5th-level deterministic architectural interfaces， the 4th-level architectural models of tidal bioclastic delta complexes are established through multi-point statistics （MPS） simulation. During the modeling process， the progradational pattern of tidal deltas is incorporated for image training and modeling parameter setting. This study systematically reveals the architectural types and their geometric features within carbonate platforms and establishes modeling workflows based on geometric features， providing a reference for geological modeling of similar reservoirs.关键词：tidal channel;beach bar;tidal delta;architectural unit assemblage;architectural style;architectural unit of reservoir;carbonate platform261|47|0更新时间：2026-04-13 -
Key issues and reflections on the helium porosity determination of continental organic-rich shales AI导读
摘要：The current methods of helium porosity measurement for continental shales tends to yield underestimated porosity due to insufficient equilibration time. Based on the experimental principle of helium porosity determination， we conduct an ultra-long-term （60 h） systematic test using the helium expansion method on shale samples of varying specifications under different injection pressures， based onthe continental freshwater lacustrine basin shale reservoir system. Accordingly， a helium porosity determination method for continental organic-rich shales is proposed. The results indicate that the key factors influencing helium porosity measurement include pore structure， equilibration time， temperature， and injection pressure， which significantly restrict the degree of helium saturation. A prolonged equilibration time can effectively enhance the accuracy of helium porosity measurement. For shale samples from the 1st member of the Cretaceous Qingshankou Formation （also referred to as the Qing 1 Member） in the Songliao Basin， the porosity measured under a test duration of 60 h increased by 19.50% ~ 37.64% compared to that measured under a test duration of 25 min. Meanwhile， for the shale samples from the 3rd oil sub-group of the 7th oil group of the Triassic Yanchang Formation （also referred to as the Chang 73 oil sub-group） in the Ordos Basin， the porosity measured under a test duration of 60 h increased by 20.44% ~ 45.10% compared to that obtained under a 25-min test. Crushed samples can effectively shorten the time for pressure equilibration for tests. It is recommended that the grain sizes of crushed samples should be 3‒4 orders of magnitude of the dominant pore sizes. The helium saturation can be enhanced by extending the pressure equilibrium time and increasing the injection pressure. Furthermore， the experimental errors caused by the deviation of helium molecules from their ideal state can be reduced by introducing the compression factor， correction of weakly connected pores， and residual fluid correction. Shale reservoirs formed under different sedimentary systems exhibit different physical properties， pore types， and pore size distribution， as well as varying degrees of modification during the diagenetic evolution process. Therefore， the test conditions and experimental parameters for the helium porosity measurement should be determined based on the specific characteristics of shale reservoirs. It is recommended that the equilibration time should be set at equal to or longer than 36 h for shales from the Chang 73 oil sub-group and equal to or longer than 48 h for those from the Qingshankou Formation. A helium porosity-time prediction chart is developed in combination with numerical simulation， which can help reduce test costs and improve test accuracy.关键词：optimization of porosity testing;helium porosity;continental shale oil;shale oil reservoir;Chang 73 subgroup;Yanchang Formation;Ordos Basin301|40|0更新时间：2026-04-13 - 摘要：Calcites， brittle minerals that are extensively distributed in shales， hold great significance for indicating shale oil and gas occurrence， reservoir stimulation， and sedimentary environments. In recent years， increasing studies have been conducted on the types， genetic mechanisms， and geological significance of calcites in shales. However， systematic reviews on these topics remain limited. In this study， calcites in shales are categorized into two types initially： micritic calcites （including dispersed granular， nodular， and lamellar calcites， calcite cements， and biogenic calcites） and sparry calcites （including fibrous， bladed， and equiaxed calcites）. The subsequent results indicate that the formation of calcite veins is jointly driven by fluid overpressure， tectonic stress， and crystallization forces. The formation process is affected by microbial reduction in the early stage， relates to the decarboxylation of organic matter in the middle stage， and is associated with the methane thermochemical oxidation-related fluid activity in the late stage. During the thermal evolution of calcite veins， dissolution windows and retrograde dissolution also occur. Calcites in lacustrine and marine shales generally share similar formation mechanisms， with differences attributed primarily to sedimentary environments. The high degree of enrichment of micritic calcites， the combination of shales and bioclastic layers， and calcite inclusions all provide valuable indications for the reconstruction of paleosedimentary and diagenetic environments. Regarding shale brittleness， calcites both enhance the shales’ brittleness index and promote the propagation of hydraulically stimulated fracture networks as brittle minerals. However， their cementation reduces reservoir porosity， creating dual effects on reservoir stimulation. Additionally， calcite veins preserve records of the hydrocarbon migration process， while their dissolution pores and bedding-parallel fractures offer important reservoir spaces for shale oil and gas. Nevertheless， the genetic mechanisms of calcites in ancient， highly evolved shales and their coupling relationship with the hydrocarbon generation process of organic matter remain poorly understood. Furthermore， the accuracy of U-Pb dating techniques for calcites in shales is yet to be substantially improved， and further improvements in the precision of relevant detection techniques are required to further reveal the complex formation process of the calcites. Advancements in these areas will provide more improved theories for the sweet spot prediction and efficient exploitation of oil and gas from calcite-rich shales.关键词：brittleness index;geological significance;genetic mechanism;sedimentary environment;calcite vein;shale265|47|0更新时间：2026-04-13
- 摘要：Despite over 40 years of hydrocarbon exploration in the Haizhong Sag of the Beibuwan Basin， no substantial breakthroughs had been achieved until the successful drilling of two exploration wells： inclined well Hai 3 and well Hai 301. To determine the major factors controlling hydrocarbon accumulation and enrichment in the northern steep slope zone of the Haizhong sag （also referred to as the Haizhong steep slope zone）， we thoroughly investigate the relationships of hydrocarbon accumulation and enrichment with source rocks， reservoirs， hydrocarbon transport， and overpressure using the latest available data. The results indicate that high-quality source rocks of deep lacustrine facies are widely developed in the Liushagang Formation， Haizhong Sag， with hydrocarbon resources estimated at 2.5 × 108 t of oil equivalent， demonstrating great potential for sustained exploration. Large-scale， high-quality beach-bar sandstone reservoirs occur within the Haizhong steep slope zone， where beach-bar sand bodies exhibit vertical superimposition and lateral contiguous distribution. Among these， beach-bar sandstone reservoirs with relatively coarse grains show low matrix content and strong dissolution and have undergone fracturing modification， thereby featuring medium porosity and medium-low permeability. The slope zone contains an efficient three-dimensional fault-fracture transport system consisting of the No. 3 fault and its associated faults， as well as fractures. The major active period of these faults aligns with the peak hydrocarbon expulsion of source rocks， ensuring efficient hydrocarbon charging. The extensive development of high-quality source rocks provides a resource foundation for hydrocarbon accumulation in the Haizhong steep slope zone. Regarding the hydrocarbon enrichment in this zone， the occurrence of large-scale high-quality beach-bar sandstone reservoirs serves as a prerequisite， while the presence of an efficient overpressured fault-fracture transport system is identified as a key factor. Additionally， hydrocarbon charging under strong driving forces in an overpressure environment creates favorable conditions for hydrocarbon accumulation and enrichment.关键词：beach dam deposition;fault conduction;overpressure accumulation;accumulation enrichment factors;resource potential;Haizhong sag;Beibuwan Basin228|46|0更新时间：2026-04-13
- 摘要：The Paleogene Kongdian Formation in the Zaoyuan oilfield within the Cangdong Sag of the Bohai Bay Basin， a faulted lacustrine basin， contains tight-sand reservoirs. However， there remains a lack of consensus on the relationship between the reservoir tightening and hydrocarbon charging. In this study， we examine representative samples from the 2nd member of the Kongdian Formation （also referred to as the Kong 2 Member） in the Zaoyuan oilfield. By integrating thin section observations， field emission scanning electron microscopy （FE-SEM）， high-pressure mercury injection （HPMI）， low-temperature nitrogen adsorption， and fluid inclusion analysis， we reconstruct the reservoir tightening process and analyze its impact on hydrocarbon accumulation. The results reveal the presence of three types of microfacies in the Kong 2 Member： channel， lobe， and levee. Reservoirs in this member consist primarily of fine-grained sandstones and siltstones， with pores dominated by primary intergranular pores and secondary dissolution pores. The reservoir tightening in the Kong 2 Member is governed by sedimentary components and textural maturity， along with the imprint of diagenesis. The tightening process can be divided into three stages： moderate compaction-induced porosity reduction， weak to moderate dissolution-induced porosity increase， and weak to moderate cementation-induced porosity reduction. Reservoirs of varying sedimentary microfacies show differential reservoir tightening characteristics. Compared to sandstone reservoirs of the lobe microfacies， those of the levee and channel microfacies exhibit higher degrees of cementation-induced tightening due to a more open diagenetic chemical reaction system. Overall， in the Kong 2 Member， reservoir tightening occurred earlier than hydrocarbon accumulation. Variation in the tightening intensity across different sedimentary microfacies of sandstones is identified as the primary cause of the differential hydrocarbon enrichment. Additionally， natrolite cementation formed after hydrocarbon charging can be observed locally.关键词：levee;lobe;deep-water channel;diagenesis;tight sandstone;Kongdian Formation;Cangdong Sag;Bohai Bay Basin63|35|0更新时间：2026-04-13
- 摘要：Significant breakthroughs have been achieved in the exploration and exploitation of deep coalbed methane （CBM） in China， establishing CBM as an emerging focus of academic research. The San Juan Basin stands out as the most successful basin in CBM development to date. Therefore， the geological understanding and development experience of this basin can provide critical implications. In this study， we systematically organize geological insights into CBM in the San Juan Basin and analyze gas well production data up to 2019. The results indicate that the gas produced from the fairway zone of the basin consists of approximately 25% ~ 50% in-situ thermogenic gas， 12% ~ 60% migrated thermogenic gas， and 15% ~ 30% secondary biogenic gas. The basin contains three pressure systems： overpressured， transitional， and underpressured. The overpressured zones are characterized by vitrinite reflectance （Ro） values of coals generally exceeding 0.8% and an average CO₂ content of up to 6.5%， with dry gas predominating. In contrast， the underpressured zones show Ro values of coals below 0.7% and CO2 contents generally below 2.0%， with wet gas being dominant. The primary factors governing the high productivity of the fairway zone include a favorable sedimentary setting （thick coal seams + shale roof）， moderate coalification （generation of thermogenic gas and suitable for the generation of biogenic gas）， and significant hydrological regulation and well-developed structural framework for preservation. The productivity of CBM wells in the basin is jointly controlled by pressure systems， reservoir physical properties， and hydrogeological regulation， with gas and water contributions varying across different pay zones. The San Juan Basin has cumulative CBM production exceeding 650 × 109 m3 of CBM. Within the fairway zone， approximately one-third of CBM wells have single-well cumulative production of greater than 113 × 106 m3. Wells in this zone exhibit gas production cycles lasting more than 300 months， with most yielding over 18.2 × 106 m3 of gas in the first 24 months of production. To date， two high-production models of CBM development have been identified worldwide. The first model is exemplified by the San Juan， Powder River， and Surat basins， where large-scale stable gas production is primarily supported by favorable natural conditions， including shallow burial depths， large coal seam thickness， high permeability， and recharge by secondary biogenic gas. The second model is represented by the Ordos Basin， characterized by great burial depths， high coal ranks， low permeability， favorable preservation conditions， and the predominance of in-situ thermogenic gas. In this case， the effective CBM recovery relies heavily on stimulation technologies. For the future development of the CBM industry， it is necessary to continuously advance the integrated geological and engineering understandings to achieve large-scale commercial CBM recovery across different coal ranks and basin types.关键词：sweet spot;enrichment and high productivity;productivity evaluation;genesis;coalbed methane;Ordos Basin;San Juan Basin78|37|0更新时间：2026-04-13
- 摘要：The platform margin belts of the Dengying Formation flanking the Deyang-Anyue rift trough represent a critical frontier for natural gas exploration and development in the Sichuan Basin. While giant gas fields， such as Anyue and Penglai， have been discovered along the eastern margin， the sedimentary characteristics of the western margin and the architectural disparities between the two flanks remain poorly understood， thereby constraining further exploration efforts in the region. By integrating core descriptions， well logs， and 3D seismic data， we systematically characterize the development of the Dengying Formation platform margins on both sides of the trough. Lithofacies paleogeographic maps were reconstructed for key intervals， and refined sedimentary facies models were established for the dual-flank system. As indicated by the research results （1） During the Late Sinian deposition of the Dengying Formation， the platform margins on both flanks primarily consisted of microbial mound， shoal， and mound‑shoal complex facies， along with inter-mound/shoal subfacies， whereas the trough interior was dominated by slope-to-basin facies. （2） Distinct heterogeneities exist in the development and evolution of the platform margins. The eastern margin， controlled by basement faults， exhibits a steeply dipping， vertically stacked architecture with minimal lateral migration. In contrast， the western margin is characterized by multi-stage， gently sloping geometries with significant lateral migration distances. （3） Lithofacies paleogeographic mapping reveals substantial spatial variations in platform margin distribution between the second （Deng 2） and fourth （Deng 4） members of the Dengying Formation. During the Deng-2 period， the platform margin followed a quasi-circular distribution along the Chengdu-Suining-Zizhong trend. During the Deng-4 period， the platform margins expanded significantly， with the western margin trending NS along the Hongya-Jingyan-Zigong area and the eastern margin extending NS along the YantingSuining-Moxi area. Overall， the Deyang-Anyue rift trough is characterized by a “steep-east vs. gentle-west” and “single-stage-east vs. multi-stage-west” sedimentary facies model.关键词：lithofacies paleogeography;sedimentary facies model;Dengying Formation;platform margin belt;Deyang-Anyue rift trough;Sichuan Basin102|48|0更新时间：2026-04-13
- 摘要：This study aims to elucidate the structural characteristics of third-order reverse faults within the Permian-Triassic marine carbonate strata in the Da’an area， southern Sichuan Basin and to explore both the controlling effects of these faults on fractured-vuggy gas reservoirs and the distribution pattern of fault-controlled gas reservoirs. By integrating well-to-seismic calibration， plan-section combined fine-scale structural interpretation， 3D structure-fault modeling， and comprehensive analyses of drilling-related oil and gas shows， we systematically investigate the characteristics of the deformation structures associated with the third-order reverse fault system and its control on reservoir formation and hydrocarbon accumulation. The results indicate that the third-order reverse faults in the Da’an area generally exhibit dip angles ranging from 10° to 20°and dip-slip displacements reaching up to 400 ~ 550 m， representing intralayer local adjustment faults formed under regional compression. These third-order reverse faults largely show lateral extensions of less than 6 km， while some extend for up to more than 20 km， resulting in a cumulative length exceeding 530 km. Carbonate fracture zones on their hanging walls or footwalls cover areas ranging from 360 km2 to 600 km2. The tectonic fracture systems within the Permian-Triassic marine carbonate strata have strikes roughly consistent with those of the third-order reverse faults. They form fault-controlled fractured-vuggy reservoirs， with the distribution of gas reservoirs significantly governed by fault zones. Overall， the third-order reverse faults in the Permian-Triassic marine carbonate strata in the Da’an area represent a key geological factor in controlling the formation of fractured-vuggy gas reservoirs. The fault-controlled fractured-vuggy reservoirs hold great exploration potential. Nevertheless， tapping this potential requires technical breakthroughs in reservoir heterogeneity characterization， 3D geological modeling， and sweet spot prediction.关键词：3D structural modeling;fault-controlled fractured-vuggy reservoirs;structural deformation;fracture system;marine carbonate rocks;Permian-Triassic;Da’an area;Sichuan Basin125|51|0更新时间：2026-04-13
- 摘要：Studies on shale reservoir spaces mostly focus on matrix pores， as manifested by a lack of studies on microfractures’ role and on the quantitative characterization of multi-scale pore-fracture structures as a whole. This study delves into the shales of varying lithofacies from the Jurassic Lianggaoshan Formation， northeastern Sichuan Basin， using field emission scanning electron microscopy （FE-SEM） aided by a random forest algorithm for image processing， and achieves the automatic identification and quantitative characterization of organic and inorganic pores and fractures in the shales. Furthermore， by combining the large field-of-view （FoV） image stitching for SEM （SEM-Maps）， we comprehensively characterize the distribution characteristics of multi-scale pores and fractures in the shales. The results indicate that the random forest model can effectively distinguish organic and inorganic pores and fractures. The SEM-Maps images at the FoV scale of 300 μm × 300 μm are representative and can exclude the effects of heterogeneity. In addition， the shales with various lithofacies exhibit significantly different characteristics of pore-fracture structures. In detail， the medium-high organic matter lamellar felsic shales have a total pore-fracture areal porosity of up to 2.66%， significantly higher than that of low-organic-matter laminated felsic shales （1.66%） and low-organic-matter massive silty to fine-grained sandstones （0.99%）. In contrast， the shales with various lithofacies exhibit similar distributions of pore and micro-fracture scales， with the pore scales primarily falling in the range of 20 to 1000 nm， and the microfracture scales predominantly between 200 nm and 5 000 nm. Calculations based on single-component pore-fracture development coefficients， indicate that clay minerals are easier to form pores and fractures compared with felsic minerals in the Lianggaoshan Formation. This study not only reveals the differences in the multi-scale pore-fracture structures of shales with various lithofacies in the Lianggaoshan Formation， but also identifies the shale lithofacies with a high pore-fracture areal porosity and favorable pore-fracture types. These findings provide an important scientific basis for the precise assessment of sweet spots and efficient shale oil development.关键词：large field-of-view （FoV） image stitching;random forest algorithm;quantitative characterization;pore-fracture structure;shale;Lianggaoshan Formation;northeastern Sichuan Basin77|36|0更新时间：2026-04-13
- 摘要：The shale reservoirs of the Lower Cambrian Qiongzhusi Formation in the Sichuan Basin exhibit complex pore structures， which provide important spaces for pore water occurrence. However， the specific occurrence characteristics and their controlling factors remain poorly understood. In this study， we investigate deep marine shales from the Qiongzhusi Formation in the basin. By integrating a series of experiments， including water saturation centrifugation-nuclear magnetic resonance （NMR） combined tests， scanning electron microscopy （SEM）， nitrogen adsorption， and molecular dynamics simulation， we systematically reveal the microscopic occurrence characteristics of pore water in the shale reservoirs and their primary controlling factors. Accordingly， the corresponding pore water occurrence patterns are established. The results indicate that in deep marine shale samples from the Qiongzhusi Formation， totally irreducible fluids occur primarily in pores with a diameter smaller than 4.98 nm. In contrast， partly movable fluids are distributed in pores with sizes ranging from 4.98 nm to 8.54 nm， while pores larger than 8.54 nm mainly contain totally movable fluids. Molecular dynamics simulations reveal that water molecules are preferentially adsorbed on the surface of inorganic minerals， followed by methane molecules. With the increase of temperature and pressure （corresponding to the increase of buried depth of strata）， the adsorption capacity of both increases， but the presence of water molecules has a significant inhibitory effect on methane adsorption. Under high water saturation， the proportion of movable water increases significantly， while tectonism-induced microfractures further enlarge its occurrence space. Concurrently， the increased proportion of large pores reduces capillary pressure， leading to a decreased proportion of irreducible water which tend to primarily concentrate in small pores. Mineral composition， pore structure， tectonism， and the water saturation of reservoirs jointly constitute an interconnected system that governs the occurrence state of pore water in shales of the Qiongzhusi Formation. These findings serve to lay an important basis for advancing geological theories on deep shale gas accumulation.关键词：occurrence characteristics;controlling factor;pore water;deep marine shale;Qiongzhusi Formation;Sichuan Basin93|46|0更新时间：2026-04-13
- 摘要：The Linhe Depression in the Hetao Basin represents an important area for potential breakthroughs in hydrocarbon exploration of medium- and small-sized basins and ultra-deep strata in China. Although the Jilantai and Bayan oilfields have been discovered in recent years， multiple exploratory wells in this depression have failed to deliver expected results. The failure analysis suggests that insufficient oil sources represent a critical constraint on hydrocarbon exploration in the depression. Based on the latest exploration achievements and laboratory data， we systematically investigate the characteristics of source rocks therein and calculate their resource potential using an integrated approach that combines geological assessment， basin simulation， and resource prediction. The research results indicate that the Linhe Depression in the Hetao Basin experienced an evolutionary pattern during the Meso-Cenozoic characterized by multi-stage tectonic subsidence and staged migration of subsidence centers， with the Naoxi sub-sag acting as a long-term inherited subsidence center. The depression contains four suites of source rocks： source rocks of the Guyang， Wulate， Linhe， and Wuyuan formations. The source rocks of the Linhe Formation， among others， predominate， characterized by substantial thicknesses， extensive distribution， high organic matter abundance， and favorable kerogen types. Furthermore， these source rocks exhibit low activation energy for hydrocarbon generation， offering advantages including early maturity， early hydrocarbon expulsion， a wide oil window， and high efficiency of organic matter conversion. These characteristics and advantages are closely related to the deposition of the source rocks in a highly reducing， saline lacustrine sedimentary environment and the enrichment of algae and sulfur within organic matter. Basin simulation results identify the Pliocene-Quaternary as the major oil generation period of source rocks in the Linhe Depression， accounting for 83.1% of the total oil generated. This result aligns well with the late-stage tectonic activity and contributes to the formation of a rapid late-stage hydrocarbon accumulation model. Hydrocarbon resource evaluation indicates that the Linhe Depression has a total amount of generated oil of 31.19 × 109 t and petroleum resources of 2.299 × 109 t. Given that the current cumulative proven reserves account for merely 1.2% of the total petroleum resources， the Linhe Depression holds considerable potential for hydrocarbon exploration. Since the oil generation centers are concentrated in the Naoxi sub-sag and the central fault zone， future exploration efforts in the depression should focus on tectono-lithologic composite traps within the Linhe Formation in the central fault zone （including the Xinglong， Nalinhu， and Ulan Buh structural zones）， as well as lithologic traps and shale oil in the Linhe and Wuyuan formations in the sub-sag.关键词：oil generation intensity;resource volume;basin simulation;resource evaluation;source rock;Linhe Depression;Hetao Basin53|31|0更新时间：2026-04-13
- 摘要：In the Ordos Basin， the Ordovician Majiagou Formation is an important replacement for natural gas exploration. Large-scale natural gas resources， such as those in the Jingbian gas field， have been discovered in the weathered crust at its top. However， the origins and sources of these resources remain highly controversial. In this study， we analyze the components and geochemical characteristics （e.g.， carbon and hydrogen isotopic compositions） of natural gas from the Daniudi gas field. Accordingly， the origins and sources of natural gas are clarified within the Ordovician weathered crust reservoirs. The results indicate that the natural gas exhibits dryness coefficient （C1/C1-5） values ranging from 0.911 to 0.979 and CO2 content from 1.68% to 14.39%. H2S is observed in some samples， with content varying from 0.07 × 10-6 to 3.37 × 10-6 and gas sweetness index （GSI） values of merely 10-7 to 10-6 order of magnitude. Additionally， the δ13C1， δ13C2， δ13C3， and δD1 values of natural gas range from -40.0‰ to -33.2‰， -35.6‰ to -24.9‰， -30.7‰ to -24.1‰， and -209‰ to -184‰， respectively. The natural gas in the Ordovician weathered crust reservoirs did not undergo significant thermochemical sulfate reduction （TSR）. However， CO2 of inorganic origin， produced by the dissolution of carbonate reservoirs， was mixed into some samples during acid fracturing. Origin identification and gas-source correlation reveal that the natural gas in the weathered crust reservoirs is dominated by coal-derived gas generated from coal-measure source rocks in the Taiyuan Formation. Such coal-derived gas experienced significant fractionation during both vertical and lateral migration into the weathered crust reservoirs. Additionally， the gas reservoirs also contain a minor proportion of oil-associated gas formed by the secondary cracking of crude oil generated from the carbonate source rocks in the Majiagou Formation.关键词：carbon and hydrogen isotope;secondary transformation;gas-source correlation;natural gas origin;weathered crust;Odovician;Daniudi gas field;Ordos Basin65|32|0更新时间：2026-04-13
- 摘要：Given limited studies on the origin and spatial distribution patterns of matrix-type reservoir sweet spots in tight sandstones， we innovatively develop a methodology that combines conventional outcrop surveys with modern unmanned aerial vehicle （UAV）-based oblique photogrammetry. Specifically， hierarchical constraint-based architectural characterization approach is integrated with three-dimensional （3D） geological modeling and a range of modern analytical and testing techniques， including conventional porosity and permeability measurements， thin section observations， scanning electron microscopy （SEM）， nuclear magnetic resonance （NMR）， elemental analysis based on X-ray fluorescence （XRF）/X-ray diffraction （XRD）， and computed tomography （CT） scanning. Using these methods， we systematically perform lithofacies identification， interpret representative outcrop sections， and analyze the differential patterns of reservoir quality. Furthermore， we conduct 3D geological-engineering modeling and examine the spatial distribution pattern of sweet spots. The research results indicate that the integrated application of traditional outcrop characterization and UAV-based oblique photogrammetry significantly enhances both the dimension and precision of sedimentological investigation. A total of 12 lithofacies types are identified within the braided river delta in the outcrop area. Among these， distributary channels and distributary sandbars constitute the primary sand body frameworks， while mudstones deposited in interdistributary bays and abandoned channels act as key baffles and barriers. Three patterns for the quality difference of tight sand reservoirs are identified： （1） a filled， positive-rhythm pattern， typically characterized by upward-decreasing porosity within individual braided channels； （2） a lateral-aggradation-controlled migrating and stacking pattern， which exhibits a distinct progressive decrease in porosity along the lateral aggradation direction of channels and， accordingly， forms a complex， multi-stage， superimposed positive-rhythm structure； （3） a composite pattern that integrates the characteristics of the preceding two patterns. What’s more， 3D geological and engineering parameter models are constructed based on the reservoir architecture bounding surface algorithm. Using high-precision digital outcrop data acquired by UAV-based oblique photogrammetry， we successfully develop the 3D models of key lithofacies-controlled parameters， including porosity， Poisson’s ratio， Young’s modulus， and the brittleness index. These models comprehensively reveal the heterogeneity of tight sandstone outcrops at multiple scales. Based on the evaluation criteria covering geological and engineering parameters， the spatial distribution patterns of reservoir sweet spots in tight sandstones are identified， and the differential spatial distribution characteristics of various sweet spot types are further examined. The results of this study provide an important theoretical basis and practical guidance for future exploration and exploitation of tight-sand hydrocarbon resources.关键词：unmanned aerial vehicle （UAV）-based oblique photogrammetry;sweet spot;reservoir heterogeneity;tight sandstone;outcrop of the Ahe Formation;Tarim Basin58|26|0更新时间：2026-04-13
- 摘要：The Paleogene strata in the southwestern Huizhou Sag of the Pearl River Mouth Basin （PRMB） are characterized by a high sand content and the predominance of fault traps， where hydrocarbon accumulation is closely related to the lateral sealing capacity of faults. Drilling data reveal that in parts more adjacent to fault zones， reservoirs feature more developed calcareous cements within sandstones. However， the impact of cementation on the lateral sealing capacity of faults in the southwestern Huizhou Sag remains poorly understood. By integrating multiple techniques， including carbon and oxygen isotope analysis， cathodoluminescence， homogenization temperature measurements of fluid inclusions， and clumped isotope thermometry， we reveal the genetic mechanisms of calcareous cements within fault zones and clarify their role in modifying the seepage properties of the fault zones. Accordingly， a comprehensive evaluation index （Flcs） is developed to evaluate the lateral sealing capacity of trap-bounding faults. The research findings indicate that the formation of calcareous cements resulted from a combination of basement-derived hydrothermal fluids and the decarboxylation of sedimentary organic matter， as suggested by their carbon and oxygen isotope compositions. Specifically， these cements were formed in a weakly reducing to reducing environment， and their formation period （postdating the deposition of the Yuehai Formation） is roughly consistent with the hydrocarbon charging periods. Governed by the vertical differences in the thermal maturity of sedimentary organic matter， cementation within fault zones exhibits a distinct zonation. In zones with intense cementation， calcareous cements effectively block the fluid seepage pathways within fault zones， whose permeability decreases significantly with increasing cement content. Index Flcs is established by comprehensively considering the dual impacts of compaction and cementation on the seepage mechanisms of faults while combining fault-reservoir displacement pressure differences and cement zones determined by vitrinite reflectance （Ro）. Validation confirms high consistency between Flcs-based sealing evaluations and actual hydrocarbon-water distributions. Notably， Flcs values exceeding 0.4 suggest effective hydrocarbon sealing capacity.关键词：lateral sealing of faults;cementation;sand-rich formation;fault zone;Paleogene;Huizhou sag;Pearl River Mouth Basin （PRMB）35|25|0更新时间：2026-04-13
- 摘要：In the Qiongdongnan Basin， volcanic gas reservoirs are revealed for the first time in the S29-A structure， suggesting promising prospects for hydrocarbon exploration. This study aims to ascertain the developmental characteristics of the Neogene Miocene volcanic rock reservoirs in the Qiongdongnan Basin. Using the latest data from drilling， seismic survey， logging， thin section observation， and nuclear magnetic resonance （NMR） testing， we analyze the lithology， lithofacies， reservoir development characteristics， primary factors controlling reservoir development， and natural gas accumulation model of volcanic rocks in the S29-A block. The research results indicate that intermediate-basic pyroclastic rocks occur in the Miocene strata in the S29-A block， with three microfacies identified in the base surge subfacies of the explosive facies： crater to near-crater microfacies， proximal microfacies， and distal microfacies. A total of nine types of reservoir spaces in seven categories are determined. The reservoirs， proving porous-fractured， exhibit favorable physical properties and a high proportion of large-diameter pores， establishing them as high-quality volcanic rock reservoirs overall. The reservoir development is jointly governed by lithology， lithofacies， dissolution， and tectonism. The volcanic breccia reservoirs of the proximal microfacies exhibit the most favorable reservoir physical properties， with dissolution contributing more than 50% to their porosity enhancement. The Songnan-Baodao Sag and its periphery are characterized by extensive volcanic edifices in the Miocene strata， which have delineated three major volcanic rock zones， suggesting great potential for hydrocarbon exploration. Notably， volcanic edifices on the north side of the Wanhu volcanic rock zone exhibit favorable hydrocarbon accumulation conditions and a large scale， implying promising prospects for hydrocarbon exploration. Therefore， these volcanic edifices are expected to be a natural gas accumulation area with total resource potential exceeding 100 billion cm3.关键词：exploration prospect;reservoir development characteristics;pyroclastic rock reservoir;Songnan-Baodao Sag;Qiongdongnan Basin46|29|0更新时间：2026-04-13
Petroleum Geology
- 摘要：The Tong’s Chart is widely used in water flooding performance analysis， but a similar universal chart is lacking for gas injection performance analysis， making it difficult to evaluate the effectiveness of gas flooding and related measures in engineering applications. Through the momentum conservation equation in porous media， under steady-state flow conditions， the flow velocity of gas follows Darcy’s fractional flow law， whether in miscible or immiscible flooding. The study indicates that： ① Based on the fundamental theory of gas-liquid fractional flow， and considering the comprehensive effects of capillary pressure， gravity segregation， injection-production driving forces， and reservoir heterogeneity on the stable migration of the gas-liquid interface during gas injection after water flooding in heterogeneous reservoirs， a theoretical chart with strict theoretical significance for analyzing the performance of gas injection after water flooding in heterogeneous reservoirs was derived and established； ② A method and procedure for developing corresponding universal charts for specific reservoirs were proposed. Two distinct case reservoirs—the Layer CⅢ1 of the Donghe Block， Tarim Oilfield and the 4 Oil Group in the X Oilfield， both transitioning from water flooding to gas injection—were selected for detailed comparative analysis. The application of this method achieved favorable results in predicting the performance of both miscible gas-assisted flooding in the top of the Layer CⅢ1 of the Donghe Block， Tarim Oilfield and immiscible gas injection in the top of the 4 Oil Group in the X Oilfield， demonstrating its good universality for different types of gas flooding after water flooding； ③ This chart possesses universal functions similar to those of the Tong’s Chart. It can be used to analyze gas injection performance and assess the stability of the gas-liquid interface in gas injection reservoirs， thereby providing guidance for the regulation of gas injection development.关键词：recovery efficiency calibration;reserves controlled by gas flooding;evaluation of displacement stability during gas flooding;chart for gas flooding performance;heterogeneity;high-dip-angle oil reservoir;oilfield development36|21|0更新时间：2026-04-13
- 摘要：The distribution and characterization of microscopic residual oil have long been considered a bottleneck in the development of high-water-cut oilfields. This study presents a systematic review and analysis of the advances and challenges in research methods for microscopic residual oil in the late stage of oilfield development. Accordingly， we propose tailored methods and establish an index system for selecting optimal techniques， thereby providing the foundation for scientifically robust strategies to tap residual oil potential in the oilfields. The results indicate that physical experiments remain central to uncovering the microscopic occurrence patterns and complex seepage mechanisms of residual oil. Their effective application depends on the characterization objectives. Numerical simulation techniques， based on the mechanisms underlying physical experiments， allow for the simulation of dynamic fluid distribution and the prediction of residual oil potential using mathematical and physical models. Compared to traditional methods， machine learning-based techniques offer distinct advantages in the intelligent processing of experimental images， pore structure identification， fluid phase differentiation， residual oil morphology recognition， and the prediction of residual oil distribution. Current research trends show a shift toward the deep integration of physical experiments， numerical simulations， and machine learning. To address the complex challenges of tapping residual oil potential in the late stage of oilfield development， future breakthroughs are required in three key areas. First， physical experiment techniques should be advanced toward higher resolution， more realistic experimental conditions， and broader data dimensions. Second， numerical simulation techniques should be enhanced to achieve greater accuracy and computational efficiency in characterizing seepage mechanisms under complex geological conditions. Third， machine learning-based techniques should highlight the intelligent identification and cognitive understanding of the occurrence morphologies and evolutionary patterns of microscopic residual oil. It is necessary to develop a decision-making model that combines high-precision in situ experiments， multi-scale simulations， and forward-looking strategies. Such a model will play a critical role in surging the tapping efficiency of residual oil potential in high-water-cut oilfields.关键词：physical experiment;numerical simulation;Machine Learning;advance and prospect;microscopic residual oil;development of high-water-cut oilfield51|20|0更新时间：2026-04-13
- 摘要：Gas saturation assessment represents a key task in log interpretation and offers a critical basis for guidance on developing schemes for the exploration and exploitation of hydrocarbon reservoirs. Gas saturation is a crucial parameter for characterizing the distribution of fluids with various properties in reservoirs， and its accuracy directly affects the reserves estimation， productivity prediction， and development outcome assessment of reservoirs. Currently， the gas saturation interpretation models based on Archie's equation and electrical methods have seen wide application， with significant results being achieved. However， their effectiveness depends heavily on the representativeness of the collected rock samples. For argillaceous sandstone reservoirs with strong heterogeneity， it is difficult to comprehensively reflect their electroconductivity mechanism using fixed electrical parameters from individual rock samples. This limitation may lead to significant errors in prediction results， thereby reducing the accuracy and reliability of log interpretation. In this study， by analyzing the excavation effect observed in gas-bearing argillaceous sandstone reservoirs， we induce the parameter of density-neutron separation degree （DC）， defined as the degree of separation between the density and neutron log curves， based on the density-neutron logging correlation. The response characteristics of the density-neutron separation degree under different gas saturation levels， shale contents， and porosities are compared through numerical simulation. Accordingly， a novel non-electrical method for the quantitative assessment of gas saturation is established based on the density-neutron separation degree. Analysis of the assessment results of gas saturation in the argillaceous sandstone reservoirs of the G Formation， T Basin indicates that the conventional models based on Archie’s and Indonesian equations， which employ unified electrical parameters， are less suitable due to the strong heterogeneity of the target strata. In contrast， the proposed method based on the density-neutron separation degree shows greater adaptability and higher prediction accuracy. This method provides a reference for the gas saturation assessment of argillaceous sandstone reservoirs with strong heterogeneity.关键词：excavation effect;density-neutron separation degree （DC）;non-electrical method;gas saturation;argillaceous sandstone;reservoir evaluation26|28|0更新时间：2026-04-13
- 摘要：This study aims to determine the reaction mechanisms behind the in-situ gasification （ISG） of heavy oil and assess the feasibility of hydrogen production using exhaust heat from the steam chamber of steam-assisted gravity drainage （SAGD） and from in-situ combustion. Through experiments with a high-temperature high-pressure （HTHP） autoclave， we systematically explore the impacts of different atmospheres ［air， nitrogen （N2）， and carbon dioxide （CO2）］， varying temperatures （200 ℃ to 300 ℃）， and core powder catalysts of the same sandstone sample on hydrogen production from heavy oil. Using experiments with a fixed pressure （4 MPa）， constant temperatures， and a reaction time of 6 h under multiple atmospheres， as well as mass spectrometry， we reveal the potential and reaction mechanisms of hydrogen production under low temperatures ranging from 200 ℃ to 300 ℃. The results show that the N2 atmosphere yields the highest hydrogen production performance （hydrogen concentration： 4.4%） at a temperature of 300 ℃ attributed to the inert nature of N2， which inhibits hydrogen consumption. In contrast， the CO2 atmosphere shows relatively low hydrogen production efficiency. This occurred primarily because CO2 reacted with heavy oil to generate CO， thereby consuming part of the available hydrogen. The temperature-dependent hydrogen production process can be divided into three stages： the initial stage （150 ℃ to 250 ℃）， the pyrolysis stage （250 ℃ to 300 ℃）， and the high-efficiency stage （above 300 ℃）. Under the N2 atmosphere， core powder demonstrates a significant catalytic effect， increasing hydrogen production by 33%. This highlights the role of formation minerals in promoting low-temperature hydrogen production. This study clarifies the hydrogen production mechanisms under different conditions， providing a novel strategy for converting heavy oil into green resources.关键词：autoclave;catalysis;hydrogen;heavy oil;water-gas shift （WGS） reaction;coke36|20|0更新时间：2026-04-13
- 摘要：Shale oil development is facing challenges in accurately quantifying oil-bearing properties and determining key parameters. In this study， focusing on frozen core samples from the Paleogene Hetaoyuan Formation in the Nanyang Sag， Nanxiang Basin， we improve the experimental method for two-dimensional nuclear magnetic resonance （2D NMR）. Based on systematic oil-water calibration experiments， we conduct 2D NMR experiments， Rock-Eval pyrolysis， multi-step temperature-programmed pyrolysis， and azeotropic distillation on the samples. The experimental results reveal that the crude oil and pore water with different occurrence states in shales can be quantitatively characterized by determining the 2D NMR T1-T2 spectrum-based evaluation chart for shale oil， combined with calibration experiments. The results indicate that the contents of free and adsorbed oil calculated using 2D NMR slightly exceed those of free and adsorbed hydrocarbons determined by temperature-programmed pyrolysis， with strong positive correlations observed between the counterparts. These findings demonstrate that 2D NMR enables more effective hydrocarbon retention. In contrast， the effective porosity and oil saturation calculated using 2D NMR exhibit relatively weak correlations with gas logging-derived porosity and azeotropic distillation-derived oil saturation， respectively， reflecting the influence of sample properties and experimental methods. 2D NMR technology offers the effective retention of light hydrocarbons in shale oil. Meanwhile， this technology can yield oil-water saturation and multiple key parameters for quantitative shale oil evaluation， including the contents of free oil， adsorbed oil， and pore water. These advantages highlight the significant technical advantages and great application potential of 2D NMR in the geological assessment of shale oil.关键词：two-dimensional nuclear magnetic resonance （2D NMR）;evaluation of oil-bearing properties;shale oil;Hetaoyuan Formation;Nanyang Sag;Nanxiang Basin55|25|0更新时间：2026-04-13
Methods and Technologies
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