最新刊期
卷 47 ， 期 3 ， 2026
- 摘要：A systematic review and summary of the developmental history and advances in experimental techniques for carbonate reservoirs reveals that technological progress in experimentation serves as a fundamental driving force behind theoretical and technological innovations in the field. The research results are as follows. （1） The evolution from macro-scale reservoir characterization via visual inspection and magnifying lenses in the 1950s and 1960s to modern digital outcrop acquisition， 3D micro-to-nano pore imaging， and multi-scale reservoir heterogeneity characterization and modeling in the 21st century， underscores the pivotal role of theoretical and experimental technological advancements， particularly in carbonate petrology， sedimentology， sequence stratigraphy， and the deployment of sophisticated experimental equipment. （2） “Geochronology， thermometry， barometry， and fluid property tracing” represent the most cutting-edge geochemical testing techniques for carbonate reservoirs in the 21st century. The iterative upgrading from bulk-rock to in-situ micro-area analysis， from solution-based methods to laser ablation， and from point detection to area mapping defines the future trajectory of the field. Furthermore， digital transformation and intelligent development provide the impetus for these technical upgrades， which will yield more comprehensive and reliable data for investigating the genesis of diagenetic fabrics and diagenetic-porosity evolution. （3） The high-temperature and high-pressure （HTHP） visualization apparatus for reservoir formation simulation across tectonic stages in ultra-deep layers is the core equipment for investigating the genetic mechanisms of ultra-deep reservoirs. It can accurately replicate ultra-HTHP geological environments， enabling dynamic forward modeling of water-rock interaction processes across tectonic stages， and integrates in-situ real-time monitoring of fluid properties and rock permeability. This apparatus provides direct experimental evidence for unraveling the formation mechanisms， preservation conditions， and spatial distribution patterns of secondary porosity in ultra-deep carbonate reservoirs. The elucidation of hydrocarbon accumulation mechanisms in ultra-deep carbonate reservoirs via simulation experiments represents a defining future research trend. （4） Reservoir prediction is the ultimate objective of reservoir characterization， evaluation， genesis， and modeling. Given that geophysical techniques are the primary tools for reservoir identification and prediction， it is highly recommended to strengthen the organic integration of experimental carbonate reservoir techniques with geophysical methods.关键词：elemental geochemistry;isotopic geochemistry;geochemical analysis;reservoir simulation experiment;reservoir characterization;carbonate reservoir259|90|0更新时间：2026-07-06
- 摘要：Shale oil and gas and coalbed methane （CBM） have become major focuses of unconventional oil and gas exploration and development. However， whether they can be defined as “reservoirs” and their formation mechanisms remain unclear. Based on an analysis and summary of the concept of source-rock hydrocarbon reservoirs， this study investigates the formation mechanisms of such reservoirs and redefines them as layered sweet-spot intervals （or sweet-spot zones） formed within source rocks through micro-scale migration and accumulation or retention， with oil content （S1） or gas content （C） reaching industrial thresholds. As indicated by the research results， source-rock hydrocarbon reservoirs are characterized by source-reservoir integration， micro-scale migration and accumulation， and continuous distribution. Their formation mechanisms involve pressure differences as the driving force， micro- to nano-scale pore-throat and fracture systems as migration pathways， self-sealing as the preservation mechanism， and heterogeneity-induced micro-scale migration and accumulation leading to the formation of sweet spots. According to rock type and hydrocarbon-generation characteristics， source-rock hydrocarbon reservoirs can be classified into two major categories： shale oil and gas reservoirs and CBM reservoirs. Shale oil and gas reservoirs are accumulations of oil and gas generated and retained in mature to over-mature mudstones and shales， as well as in thin interbeds， where dominant fabric facies and the trandenscent effect are critical to hydrocarbon enrichment and accumulation. CBM reservoirs are accumulations of natural gas generated and retained in immature to over-mature coalbeds， in which high-quality coal rocks and favorable preservation conditions are the key to hydrocarbon accumulation and productivity. Significant progress has been achieved in the exploration and development of source-rock hydrocarbon reservoirs in the Bohai Bay Basin and the Ordos Basin. In the shale oil reservoir of the 2nd member of the Kongdian Formation in the Cangdong Sag， Bohai Bay Basin， the peak daily oil production of a single horizontal well reached 208 t， and the first economically viable continental shale oil development platform in China with an annual capacity of 100 × 103 t has been established. In the CBM reservoir of the Daning-Jixian block， Ordos Basin， the average estimated ultimate recovery （EUR） per well is expected to reach 55.67 × 106 m³， and a CBM field with an annual oil-equivalent production capacity of 2.00 × 106 t has been built. Source-rock hydrocarbon reservoirs are therefore expected to become an important domain for increasing oil and gas reserves and production in China.关键词：formation mechanism;self-sealing effect;micro-scale migration and accumulation;sweet-spot interval;shale oil;shale gas;coalbed methane （CBM）;source-rock hydrocarbon reservoir208|87|0更新时间：2026-07-06
- 摘要：Hydrocarbon exploration and exploitation have progressively shifted toward 10 000-meter-deep onshore plays， 1 000-meter-deep offshore plays， unconventional plays， and residual oil in mature oilfields. The emerging frontiers are characterized by diverse reservoir types， complex geological conditions， and considerable difficulties in exploration and development， posing challenges such as incompatibilities between existing methodological and technical systems and exploration and exploitation targets to research on well logging geology. This study presents a summary of the evolution of research on well logging geology in terms of depth， scale， span， and dimension for hydrocarbon exploration and exploitation. The results indicate that logging geology research is gradually advancing towards in-depth interdisciplinary integration and multidimensional development. The integration of geology， logging， seismology， engineering， and artificial intelligence （AI） can enhance the efficiency of hydrocarbon exploration and exploitation while reducing costs and risks. In the development of deep to ultra-deep onshore plays at depths of about 10 000 m， the combination of logging and geology allows revealing the genetic mechanisms of reservoirs and analyzing major factors controlling reservoir quality， thereby achieving a comprehensive reservoir evaluation. For unconventional hydrocarbon reservoirs， research on well logging geology enables the identification of the geological characteristics of millimeter-scale laminae， as well as analyses of subtle variations in oil-bearing properties and oil mobility within micro- to nano-scale pore throats. On the spatial scale， logging technology allows for the detection of wellbores， near-well areas， and far-well regions， achieving the characterization of point-line-plane-volume full-space geological information. On the temporal scale， logging technology enables the analysis of changes in log data before and after fracturing or water injection， thus contributing to fine-scale hydrocarbon development. Driven by AI empowerment， the future integration of multidisciplinary dimensions， that is， geology， well logging， seismology， and engineering， will further expand the application domains and scope of well logging geology， accelerating its development. This will offer robust technical support for future hydrocarbon exploration and exploitation.关键词：micro- to nano-meter scale;depth of about 10 000 m;spatiotemporal span;multidisciplinary dimension;well logging geology142|73|0更新时间：2026-07-06
- 摘要：Transform continental margin basins have emerged as important frontier areas for global oil and gas exploration， with several significant discoveries reported in recent years. Based on a comprehensive analysis of the distribution patterns and structural styles of typical transform continental margin basins worldwide， this study proposes a three-stage basin evolution model consisting of the “rifting phase， sag phase， and continental margin phase”. Correspondingly， a tripartite tectonostratigraphic framework comprising the rift sequence， sag sequence， continental margin sequence is established to clarify the influence of basin architecture and tectonostratigraphic layering on key elements of the petroleum system， including source rock development and reservoir distribution. As indicated by the research results， during the sag phase， influenced by the barrier effects of marginal ridges or plateau structures， restricted marine environments widely developed on the landward side， providing favorable geological conditions for the large-scale development of high-quality source rocks. During the continental margin phase， depositional systems were jointly controlled by sediment supply and climatic variations， forming three major reservoir types： base-of-slope fan， large progradational delta， and platform-margin carbonate. The depositional thickness of these sedimentary successions exerted first-order control on the thermal evolution of the underlying source rocks. On this basis， three typical hydrocarbon accumulation models are proposed： base-of-slope fan reservoirs， in which efficient coupling with sag-phase source rocks result in the formation of high-quality source-reservoir assemblages， with microfracture networks facilitating hydrocarbon migration； large progradational delta reservoirs characterized by commonly developed sandstone traps such as rollover anticlines， compressional structures， and diapiric structures， providing favorable conditions for hydrocarbon accumulation； platform-margin reef reservoirs， occurring adjacent to slope source kitchens， where hydrocarbons migrate vertically along fracture corridors and accumulate in high-porosity and high-permeability reefal reservoirs. Base-of-slope fans， deltas， and platform-margin carbonates developed in transform continental margin basins along the equatorial Atlantic margin， East Africa， and both margins of the Central Atlantic exhibit enormous hydrocarbon resource potential.关键词：hydrocarbon potential;sedimentary infill;sag-phase source rock;tectonostratigraphic layer;transform continental margin basin;passive continental margin127|46|0更新时间：2026-07-06
- 摘要：The Yingen-Ejinaqi Basin （also referred to as the Yin’e Basin） represents a Meso-Cenozoic faulted lacustrine basin occurring on the pre-Mesozoic metamorphic folded basement. In 2025， high-yield oil flow with a daily oil equivalent exceeding 400 m3 was obtained from well G18 drilled in the hinterland of the basin. In this study， based on the latest exploration outcomes from wells G6 and G18， we investigate the factors governing the reservoir formation， as well as the hydrocarbon properties and sources， of hydrocarbon reservoirs in the metamorphic folded buried hills within the Yin’e Basin. Accordingly， the major factors controlling the hydrocarbon enrichment and high productivity of the buried-hill hydrocarbon reservoirs are analyzed， and the hydrocarbon accumulation pattern of these reservoirs is established. Field geological explorations and laboratory tests indicate that dolomite marbles represent the dominant lithofacies for reservoir formation in bedrock buried hills. These marbles contain three-stage fractures due to the modification by multi-stage tectonic activities. Reticular storage complexes are formed by the coupling of pores， fractures， and vugs， with the distribution of favorable reservoirs primarily controlled by the coupling of regional dynamic metamorphism and deep-seated faults. The test and analytical results of trace elements reveal that the 1st member of the Bayin Gobi Formation （also referred to as the Ba 1 Member） was deposited in a weakly reducing， brackish-water environment. Such a sedimentary setting created favorable conditions for the development and preservation of organic matter， leading to the formation of lamellar shales with organic matter dominated by type Ⅱ1 kerogen. These shales are characterized by high total organic carbon （TOC） content， early-stage oil generation， and late-stage gas generation. Controlled by the depocenters of sub-sags， these shales primarily occur in the middle and lower parts of slope zones. The hydrocarbon enrichment and high productivity of hydrocarbon reservoirs in metamorphic folded buried hills in the Yin’e Basin are attributed to three key factors. First， multi-stage faulting， along with weathering and leaching， plays a key role in the reservoir formation of dolomite marbles. Second， the distribution of high-quality source rocks in the middle and lower parts of slope zones determines the hydrocarbon generation， migration， and enrichment of the buried-hill hydrocarbon reservoirs. Third， sustained and intense proximal hydrocarbon charging is identified as the key factor contributing to the high productivity of these reservoirs. The key reason for exploration breakthroughs in the buried-hill hydrocarbon reservoirs is the integrated application of multi-source information fusion technologies.关键词：dolomite marble;metamorphic rock fold;bedrock buried hill;high-quality hydrocarbon source rock;buried hill hydrocarbon reservoir;Guaizihu Sag;Yingen-Ejinaqi Basin117|42|0更新时间：2026-07-06
- 摘要：A deviated well Y106 and a horizontal well Y108C were drilled in the 4th member of the Paleogene Funing Formation （also referred to as the Fu 4 Member） in the Gaoyou Sag， Subei Basin. Post-fracturing tests recorded peak daily oil and gas equivalents reaching up to 32.9 t and 54.6 t， respectively， marking a new breakthrough in shale oil exploration in a new sequence， i.e.， the Fu 4 Member， following the previous breakthrough in shale oil exploration in the Fu 2 Member. This study aims to develop a comprehensive understanding of the shale oil enrichment pattern in the Fu 4 Member. By integrating data from seismic surveys， well logging， core observations， and laboratory tests， we systematically analyze the geological characteristics of the shales and summarize the major factors controlling the shale oil enrichment in the Fu 4 Member. These will provide a basis for further expanding the exploration scope and evaluating the resource potential. The results indicate that laminated mixed shales occur in the Fu 4 Member in the deep-lying sag zone of the Gaoyou Sag. The major factors controlling shale oil enrichment are summarized as follows. （1） Favorable hydrocarbon generation conditions as the shales exhibit great thicknesses， moderate organic matter abundance， high-quality hydrocarbon-generating parent materials， and appropriate thermal maturity； （2） efficient source rock-reservoir combinations， as the frequent interbedding of carbonate and clay laminae results in the formation of efficient source rock-reservoir combinations； （3） multi-scale pore-fracture systems， facilitated by laminated structures， and composed of fractures and inorganic pores of diverse types and scales， providing favorable storage and seepage spaces for shale oil enrichment； and （4） favorable hydrocarbon preservation conditions， with the high sealing capacities of the roof and floor strata， coupled with underdeveloped faults and anomalously high pressure， jointly creating favorable compartments for shale oil preservation and enrichment. The breakthrough in shale oil exploration in the Fu 4 Member marks a strategic expansion of shale oil exploration in the Gaoyou Sag， from the Fu 2 Member in the complex fault-block area on the slope to the Fu 4 Member in the tectonically stable deep-lying sag area. Accordingly， a new target for large-scale reserve growth has been identified. This advancement will contribute to the improvement of the technical system for the exploration and exploitation of shale oil with medium to low total organic carbon （TOC） content from a complex fault-block area on a slope to a tectonically stable deep-lying sag area within a continental faulted basin.关键词：exploration breakthrough;shale oil;4th member of the Paleogene Funing Formation （Fu 4 Member）;Gaoyou Sag;Subei Basin96|48|0更新时间：2026-07-06
- 摘要：For mixed shales occurring in the Jiyang Depression， Bohai Bay Basin， the controlling mechanisms of their diagenetic evolution over pore development remain poorly understood， and their diagenetic differentiation and corresponding pore response mechanisms have yet to be revealed. In this study， we investigate the mixed shales in the Minfeng Sub-sag， Jiyang Depression. Using multiple experimental methods， including petrographic and mineralogical analysis， scanning electron microscopy （SEM）， nuclear magnetic resonance （NMR）， and low-temperature nitrogen adsorption， we investigate the diagenetic and reservoir-formation processes of carbonate， felsic， and clay minerals. The results indicate that primary pores in the mixed shales include intergranular pores of quartz， intercrystalline pores of calcites and dolomites， and clay interlayer pores. Four evolutionary stages for the formation of high-quality reservoirs are proposed： framework building， authigenic mineral-supported pore preservation， dissolution-induced porosity enhancement， and overpressure-preserved porosity. Specifically， during the early diagenetic stages A1-A2， the weak dissolution and recrystallization of micritic calcites contribute to the formation of millimeter-scale lamellar frameworks， providing a structural basis for pore preservation. Subsequently， from the early diagenetic stage A2 to the middle diagenetic stage A1， K+ released from the dissolution of K-feldspars facilitates the transformation of mixed illite-montmorillonite into illite， leading to the release of SiO2 and the precipitation of authigenic quartz. Consequently， rigid frameworks supported by authigenic quartz are formed locally. During the middle diagenetic stages A1-A2， calcites and feldspars are dissolved by organic acids， contributing to increased pore sizes and improved reservoir properties. Afterward， during the middle diagenetic stages B1-B2， overpressured fluids sustain pores and induce microfractures， thereby connecting isolated pore throats. These four progressive stages， namely rigid framework building， pore support and enhancement， dissolution-induced porosity enhancement， and overpressure-preserved porosity， completely reveal the mechanisms behind the diagenetic evolution of reservoirs， pore development， and reservoir property enhancement for shales in the study area.关键词：diagenetic evolution;mixed shale;shale oil;Minfeng Sub-sag;Jiyang Depression;Bohai Bay Basin94|57|0更新时间：2026-07-06
- 摘要：Mixed shales occur in continental saline lacustrine basins in China， exhibiting complex lithologies and various types of pores. The occurrence and distribution characteristics of multicomponent hydrocarbons within shale pores affect shale oil mobility and estimated ultimate recovery （EUR） per well. Focusing on the 2nd member of the Kongdian Formation （also referred to as the Kong 2 Member） in the Cangdong Sag， Bohai Bay Basin， we analyze the geochemical characteristics， biomarker variations， and reservoir fluorescence characteristics of shale oil produced at different recovery stages. Accordingly， the occurrence characteristics of shale oil within micro- and nano-scale pores and their impacts on shale oil mobility are systematically analyzed. The results indicate that the hydrocarbon components of shale oil exhibit cyclic variations during the development process. A higher frequency of these variations is associated with more rapid replenishment of light hydrocarbons， as well as a more stable miscible flow regime and a higher flow rate of multicomponent hydrocarbons. During the recovery of shale oil at great burial depths， hydrocarbons produced in the early stage show higher maturity， while those recovered in the late stage exhibit lower maturity. This pattern indicates that shale oil generated in different periods occurs in independent micro- and nano-scale pores without mixing. In contrast， for shale oil at shallow burial depths， no significant differentiation in hydrocarbon maturity is observed throughout the oil recovery. Hydrocarbons with higher maturity occur primarily within the micron-scale macropores in felsic laminae， whereas those with lower maturity are primarily confined to nano-scale micropores. Saline lacustrine basins are characterized by early and multi-stage hydrocarbon generation， coupled with multi-stage hydrocarbon accumulation and enrichment. Consequently， shale oil with different hydrocarbon compositions occurs in subsurface micro- and nano-scale pores. This facilitates hydrocarbon component flow， thereby enhancing the expulsion of heavy components from micro- and nano-scale pores and ultimately increasing the flow rate of shale oil.关键词：occurrence characteristics;enrichment process;component flow;thermal maturity;shale oil;2nd member of the Kongdian Formation （Kong 2 Member）;Cangdong Sag;saline lacustrine basin78|48|0更新时间：2026-07-06
- 摘要：The original morphologies of volcanic edifices in a basin are often poorly preserved due to weathering and denudation， leading to inaccurate predictions of their lithology. The morphological characteristics of volcanic edifices are indicative of their lithologic assemblages， so it’s of great significance for reconstructing the original morphologies of buried volcanic edifices in hydrocarbon exploration of volcanic rocks. In this study， we investigate multiple buried remnant volcanic edifices in the LK 7-A structure of the Bodong swell within the Bohai Bay Basin. The denudation thicknesses of these volcanic edifices are quantified using the structural trend analysis and the balanced cross-section technique. Subsequently， their original morphologies are reconstructed through inversion. Models for discriminating volcanic edifice types are established based on the parameters of modern volcanic edifices， such as volume， diameter， slope， and height. Using these models， the types of volcanic edifices reconstructed in the basin are determined. After validation and correction using lithological data acquired through drilling， the models are employed to predict the lithologic assemblages of volcanic edifices in areas with limited or no well control. The results indicate that the original Mesozoic volcanic edifices in the LK 7-A structure are dominated by composite volcanoes and lava domes. Among these， the No. 1 volcanic edifice represents a composite volcano consisting of interbedded rocks of intermediate-acidic explosive and effusive facies， with a lithologic assemblage composed of trachyandesite-rhyolite-andesite interbeds. These discrimination results show good agreement with drilling data from well LK7-A-X. The No. 6 volcanic edifice is predicted to be a lava dome formed by the extrusion of high-viscosity acidic magmas， with its lithology inferred to be dominated by acidic explosive and effusive facies. Overall， the lithologic assemblages of buried volcanic edifices in a basin can be accurately predicted using （1） the combination of the structural trend method and balanced cross-section technique for volcanic edifice reconstruction， （2） the prediction model based on the correlation between volcanic edifice types and lithologic assemblages， and （3） five characteristic parameters （i.e.， basement diameter， height， aspect ratio， slope， and volume） of volcanic landforms.关键词：structural trend method;volcanic edifice reconstruction;lithologic assemblage prediction;Mesozoic volcanic rock;LK 7-A structure;Bodong swell;Bohai Bay Basin55|32|0更新时间：2026-07-06
- 摘要：The 2nd member of the Paleogene Kongdian Formation （Kong 2 Member） in the Cangdong Sag， Bohai Bay Basin contains thick-bedded organic-rich shale sequences， suggesting promising prospects for resource exploration. However， there remains a lack of a systematic understanding of the coupling relationships between the lithofacies and pore structure of shales， restricting the thorough analysis of shale oil enrichment mechanisms. This study aims to determine the microscopic pore structure characteristics of reservoirs of different lithofacies in the Kong 2 Member shales within the Cangdong Sag. Specifically， the microscopic pore structures are characterized at multiple scales using a range of techniques， including X-ray diffraction （XRD）， total organic carbon content （TOC） analysis， argon ion milling-field emission scanning electron microscopy （FE-SEM）， N2 and CO2 adsorption， the automated mineral identification and characterization system （AMICS）， and three-dimensional （3D） reconstruction using focused ion beam-scanning electron microscopy （FIB-SEM）. The results reveal that five shale lithofacies occur in the study area： lamellar felsic shale， lamellar mixed shale， massive mixed shale， lamellar carbonate shale， and massive carbonate shale. These shale lithofacies contain various types of reservoir spaces， including inorganic pores， organic pores， and microfractures， with significant variations in pore structure. Nevertheless， in all shale lithofacies， the pore sizes predominantly range from 2 nm to 200 nm， with nanopores acting as the primary contributors to the reservoir space. Among these lithofacies， the lamellar felsic shale and lamellar mixed shale exhibit large pore volumes due to the presence of macro-pores and microfractures. In contrast， the organic-rich lamellar shale exhibits higher connectivity compared to other lithofacies. Regarding the occurrence states of organic matter， syngenetic organic matter， interstitial organic matter， and organic matter-clay mineral complexes exhibit diverse morphologies and contact relationships with surrounding minerals， contributing differently to pore volume and connectivity. Notably， the syngenetic organic matter in high-frequency lamellar shale can improve the pore structure. The deposition and evolution of organic matter and mineral components control the modification of reservoir pore systems. The compressive resistance of the felsic mineral matrix is favorable for pore preservation. In contrast， although lamellar and massive carbonate shales contain extensively developed dissolution pores， the cementation between minerals limits their porosity and connectivity. Furthermore， erosional fluids generated under moderately high TOC content and thermal evolution migrate along lamina interfaces and microfractures， playing a significant role in creating differential reservoir performance across the various shale lithofacies.关键词：pore structure;lithofacies;shale;the 2nd member of the Paleogene Kongdian Formation （Kong 2 Member）;Paleogene;Cangdong Sag;Bohai Bay Basin74|56|0更新时间：2026-07-06
- 摘要：The fourth member of the Shahejie Formation （Es4） in the Western Sag of the Liaohe Depression， Bohai Bay Basin， hosts multiple types of shale oil. With favorable geological conditions and promising exploration prospects， it represents the primary target for shale oil exploration in the Liaohe oil and gas province. To clarify the enrichment characteristics and exploration potential of shale oil in this province， systematic studies were conducted on the hydrocarbon generation and storage processes and the oil-bearing properties of the Es4 member based on drilling， well logging， seismic surveys， and various analytical test datasets. A shale oil enrichment model was established； sweet spots were identified and evaluated； and exploration practices in this area were systematically analyzed. As indicated by the research results， the total organic carbon content （TOC） ranges from 0.20% to 11.86%， the hydrocarbon generation potential （S1+S2） has a peak value of 100 mg/g and an average value of 40 mg/g， organic matter is dominated by Type Ⅰ‒Ⅱ1， vitrinite reflectance （Ro） ranges from 0.38% to 0.79%， and maximum pyrolysis temperature （Tmax） is mainly at 440 ~ 450 ℃. Overall， the organic matter is characterized by favorable types， high abundance， and is in the medium-to-high maturity stage. The Es4 is mainly composed of clay minerals， quartz， K-feldspar， plagioclase， ammonium feldspar， calcite， dolomite group minerals and pyrite， with well-developed laminae displaying diverse stacking patterns. The main lithofacies include laminated calcareous-dolomitic shale， laminated felsic shale， and laminated mixed shale. Dissolution pores， intercrystalline pores， organic pores， dissolution fractures， and bedding fractures are well developed throughout the member. The overall porosity is relatively low， and the pore system is primarily composed of micro- to nano-scale pores； mesopores （pore diameter of 10 ~ 100 nm） are dominant， accompanied by a small proportion of macropores. Oil and gas are mainly stored in bedding fractures， intercrystalline pores， microfractures， organic pores， intergranular pores， and calcite cleavage fractures. Sedimentation provides the essential material basis for shale oil enrichment. Moderate total organic carbon content （TOC of 2% ~ 4%） and medium-to-high thermal maturity are prerequisites for enrichment， resulting in a shale oil enrichment model for this area. Based on a multi-parameter integrated reservoir evaluation method， Type I reservoirs in sublayers c11 and c12 are dominated by calcareous mud shale， while those in sublayers c8‒c10 are dominated by dolomitic （calcareous） mud shale and argillaceous dolomite， with brittleness increasing proportionately with dolomite content. Combined with pre-stack seismic inversion， the planar distribution of sweet spots was predicted. This study systematically summarizes the geological characteristics and enrichment model of shale oil in the Es4 member of the Western Sag and effectively identifies sweet spots， providing a reliable geological basis for shale oil exploration program design in this province.关键词：hydrocarbon generation characteristics;reservoir development characteristics;enrichment model;sweet spot evaluation;shale oil;Western Sag;Bohai Bay Basin61|42|0更新时间：2026-07-06
- 摘要：Significant progress has been achieved in the shale oil exploration of the 7th oil group of the Yanchang Formation （also referred to as the Chang 7 oil group） in the Ordos Basin. Specifically， the 1st and 2nd oil sub-groups of the Chang 7 oil group （also referred to as the Chang 71 and Chang 72 oil sub-groups， respectively） are primarily characterized by interbedded-type shale oil， which has achieved commercial exploitation. Furthermore， breakthroughs in risk exploration have been made for shale oil in the 3rd oil sub-group of the Chang 7 oil group （also referred to as the Chang 73 oil sub-group）， with probable petroleum initially-in-place of 272 × 106 t having been reported. In this study， we systematically review the recent advances in geological insights into and new technical breakthroughs in shale oil exploration in the Chang 73 oil sub-group. Based on a summary of exploration implications， we propose future development directions of shale oil exploration in the Chang 7 oil group. The lithofacies， depositional origins， reservoir properties， oil-bearing properties， and hydrocarbon accumulation mechanisms of the Chang 73 oil sub-group are determined in this study. Specifically， this oil sub-group primarily contains deep-lacustrine basin deposits， which are dominated by shales. These deposits mostly occur as thinly interbedded and lamellar structures vertically and exhibit thick， extensively distributed mudstones， shales， and silty mudstones laterally. Flume experiments and three-dimensional （3D） focused ion beam-scanning electron microscopy （FIB-SEM） reconstructions demonstrate that hyperpycnal flows act as the dominant mechanism governing the formation of sandy fine-grained sediments in the Chang 73 oil sub-group. The development of these hyperpycnal flows was jointly controlled by frequent flood events and the steep-slope terrain in the southwest. In contrast， shales were formed primarily due to suspension settling and intense hydrodynamic reworking. Organic-inorganic diagenetic coupling identified in the shale sequences of the Chang 73 oil sub-group， promoted intergranular and dissolution pores in sandstones and siliceous laminae， interlayer fractures， and intercrystalline pores in shales as reservoir spaces. The hydrocarbon accumulation in the Chang 73 oil sub-group is predominantly governed by retention and micro-migration. All lithologies in this oil sub-group generally bear oil， with average oil saturation exceeding 55% and free hydrocarbons accounting for up to 80% of the total. Accordingly， we propose a hydrocarbon accumulation pattern of the oil-bearing compartment type， characterized by pervasive distribution of multi-type fine-grained sediments， co-existing micro/nano pore-throat systems as reservoir spaces， and favorable oil-bearing properties across the entire shale sequences. Therefore， it is recommended to consider the organic-rich shale-siltstone-tuff assemblages in the Chang 73 oil sub-group as a whole exploration target. This will help advance systematic， integrated shale oil exploration and exploitation in the study area.关键词：fine-grained sediment;hydrocarbon enrichment of the oil-bearing compartment type;shale oil;Chang 73 oil sub-group;Ordos Basin67|72|0更新时间：2026-07-06
- 摘要：The origin of tight oil in the 8th oil group of the Triassic Yanchang Formation （also referred to as the Chang 8 oil group） in the Ordos Basin remains controversial in previous studies. By integrating a range of experimental and analytical methods， including the total organic carbon （TOC） content measurement， Rock-Eval pyrolysis， biomarker identification， confocal laser scanning microscopy （CLSM）， and nuclear magnetic resonance （NMR）， we thoroughly analyze the distribution characteristics of 17α（H）-diahopanes in 33 source rock samples and 12 crude oil samples from the eastern Ordos Basin. Accordingly， the tight oil charging models in the Chang 8 oil group are explored. The results indicate that the source rock and crude oil samples all contained 17α（H）-diahopanes， which are highly indicative of oil-source correlation. The distribution characteristics of 17α（H）-diahopanes reveal that in well Y426， crude oil in the 1st sub-group of the Chang 8 oil group （the Chang 81 oil sub-group） might originate primarily from the black shales of the 3rd sub-group of the 7th oil group of the Yanchang Formation （the Chang 7³ oil sub-group）， while that in the 2nd sub-group of the Chang 8 oil group （the Chang 82 oil sub-group） was likely derived from the black shales of the 1st sub-group of the 9th oil group of the Yanchang Formation （the Chang 91 oil sub-group）. In contrast， in well Y1011， crude oil in the Chang 8¹ oil sub-group might be sourced primarily from the dark mudstones of the same oil sub-group， while that in the Chang 8² oil sub-group likely originated from the dark mudstones within itself. In well Y426， the Chang 8¹ and Chang 8² oil sub-groups consist primarily of interbedded thickly layered sandstones and thinly layered mudstones， featuring favorable physical properties. In this well， crude oil from the black shales of the Chang 7³ and Chang 9¹ oil sub-groups can migrate into the delta-front sand bodies of the Chang 8¹ and Chang 8² oil sub-groups， respectively， through high-permeability sand bodies. In well Y1011， the Chang 8¹ and Chang 8² oil sub-groups are dominated by interbeds comprising thickly layered mudstones and thinly layered sandstones， suggesting poor reservoir physical properties. In this case， it is difficult for crude oil generated by the black shales of the Chang 7³ and Chang 9¹ oil sub-groups to migrate into reservoirs of the Chang 8¹ and Chang 8² oil sub-groups. Additionally， stratigraphic heterogeneity exerts a significant impact on oil-source correlation results， underscoring the need to comprehensively identify the oil sources of the Chang 8 oil group by combining geological conditions.关键词：17α（H）-diahopane;biomarker;oil-source correlation;Yanchang Formation;tight reservoir;Ordos Basin43|30|0更新时间：2026-07-06
- 摘要：When used for the comprehensive evaluation of shale oil sweet spots in the Yingxiongling area， the traditional lithology-electric crossplots face many challenges， including low accuracy and difficulties in selecting optimal sensitive parameters and establishing adaptive evaluation criteria. To address these limitations， we propose a comprehensive evaluation approach that integrates principal component analysis （PCA）-based multi-parameter weighting with the analytic hierarchy process （AHP）. This approach facilitates the scientific selection of sensitive parameters and the comprehensive quantitative evaluation of shale oil sweet spots in the Yingxiongling area. Six core parameters are identified through Pearson correlation analysis： porosity， oil saturation， total organic carbon （TOC） content， rock pyrolysis-derived free hydrocarbons content （S1）， brittle mineral content， and carbonate content. The weights of these parameters are determined based on the loadings and variance contribution rates of the principal components. Accordingly， a linearly weighted comprehensive evaluation model for sweet spots， along with criteria for classification and comprehensive evaluation， is established. Under the guidance of this novel model， daily oil flow rates of 17.61 m3 and 13.7 m3 were tested from sweet spot intervals in wells C12 and C20， respectively， while a post-fracturing daily oil flow rate of 20.5 m3 was tested in well CP13. For the horizontal section of well CP13， the comprehensive index showed a significant positive correlation with the liquid production contribution rate detected using an oil-phase tracer. These results demonstrate that the proposed model is suitable and can be widely applied in shale oil sweet spot evaluation.关键词：principal component analysis （PCA）;sensitive parameter;comprehensive evaluation;sweet spot;shale oil;Yingxiongling area;Qaidam Basin44|29|0更新时间：2026-07-06
- 摘要：The Gulong Sag in the Songliao Basin is an important region of China where significant breakthroughs have been achieved in the exploration of medium- and high-maturity lacustrine shale oil. However， the major controlling factors and evolution patterns of shale reservoirs in this sag remain poorly understood. This study focuses on shales in the 1st member of the Qingshankou Formation （also referred to as the Qing 1 Member） in the Gulong Sag. By integrating multiple analytical techniques， including Rock-Eval pyrolysis， X-ray diffraction （XRD）， scanning electron microscopy （SEM）， nitrogen adsorption， high-pressure mercury injection （HPMI）， and nuclear magnetic resonance （NMR）， we systematically analyze the organic geochemical characteristics of the shales， as well as the reservoir space types and their sizes and distribution patterns. The analytical results show that the shales in the sag contain organic matter dominated by high-quality Type Ⅰ kerogen. These shales were deposited in a semi-deep to deep lacustrine anoxic environment and are currently in oil generation state with moderate to high maturity. Reservoir development in the shales is jointly governed by the sedimentary environment， diagenesis， organic matter type， and thermal evolution. Specifically， intense compaction and cementation in the early stage lead to substantial loss of primary pores. With an increase in thermal maturity， the dissolution of minerals such as feldspars， together with the hydrocarbon generation of organic matter， collectively contribute to secondary pore growth. Consequently， reservoir spaces in the shales progressively evolve into an organic-matter- and clay-hosted composite pore system dominated by nano-scale pores. The reservoir space evolution pattern of shales in the Qing 1 Member established in this study provides an important theoretical basis for shale oil exploration in the Gulong Sag. Furthermore， other relevant patterns and research approaches involved in this study may provide references for the exploration of other shale oil plays.关键词：pore structure;reservoir development;major controlling factor;evolution pattern;shale oil;Qingshankou Formation;Songliao Basin53|45|0更新时间：2026-07-06
- 摘要：Tuff-rich mixed shales， representing an important class of unconventional hydrocarbon resources， exhibit diverse components， rapid lithofacies variations， complex diagenetic evolution， and strong heterogeneity. For these shales， there remains a lack of a systematic understanding of the diagenetic evolutionary processes and reservoir formation mechanisms of different lithofacies， restricting target area selection and evaluation for shale oil exploration. In this study， we investigate the diagenesis， reservoir formation， and favorable exploration targets of mixed shales with unique components in the 2nd Member of the Lucaogou Formation （also referred to as the Lu 2 Member） in the Santanghu Basin. To this end， a range of test methods are employed， including core characterization， thin section observation， scanning electron microscopy （SEM）， whole-rock X-ray diffraction （XRD） analysis， electron probe microanalysis， high-pressure mercury injection （HPMI）， and nuclear magnetic resonance （NMR）， along with measurements of porosity， permeability， and oil saturation. The results indicate that the mixed shales of the Lu 2 Member are composed primarily of tuffaceous materials， carbonates， and organic matter and can be classified into 10 lithofacies， which are frequently interbedded. The mixed shales mainly contain nano- to micro-scale intercrystalline pores in dolomites， devitrification-induced pores in volcanic ash， and dissolution pores， suggesting complex pore structures. Distinct lithofacies exhibit significant differences in physical and oil-bearing properties. Among these， massive lithofacies featuring low organic matter abundance and composed primarily of a single component display the most favorable properties， followed by lamellar transitional lithofacies dominated by dolomites， while lamellar transitional lithofacies composed primarily of tuffaceous materials show the poorest physical and oil-bearing properties. The shale component types and their differential diagenetic evolution govern reservoir quality. Rapid deep burial and compaction in the early stage represent primary factors responsible for the deterioration of reservoir physical properties. However， they occurred earlier than other diagenetic processes. Furthermore， dolomitization and devitrification occurred before organic acid-induced dissolution. This diagenetic evolutionary sequence provides effective spaces for organic acid migration while also offering a material basis for dissolution， serving as the key mechanism behind the formation of high-quality reservoirs. A comprehensive analysis reveals that favorable exploration targets in the Lu 2 Member include the basin margin zone and the slope zone near the basin margin.关键词：tuffaceous material;reservoir formation mechanism;diagenetic process;mixed shale;Lucaogou Formation;Santanghu Basin64|40|0更新时间：2026-07-06
- 摘要：The study systematically characterized reservoir characteristics and highlighted primary factors controlling reservoir tightening based on cast thin-section petrography and petrophysical analysis of core samples from five wells， including well G119. The research results show that the Lianggaoshan Formation sandstones in the central Sichuan Basin exhibit fine-grained， well-sorted texture； however， lithofacies vary significantly across different systems tracts. The transgressive systems tract （TST） is characterized by quartz sandstones and lithic quartz sandstones featuring high quartz and low feldspar contents alongside unstable sedimentary lithic fragments， whereas the highstand systems tract （HST） predominantly develops lithic sandstones and feldspathic lithic sandstones. The quartz-rich sandstones of the TST is collectively controlled by the forebulge gentle slope setting， distal provenance， intense hydrodynamic winnowing， and“relay quartz supply”sourcing from the weathered horizons of the pre-existing alluvial plain. The sandstones exhibit an average porosity of 2.56% and an average permeability of 0.11 × 10⁻³ μm². Intense compaction （accounting for an average loss of 83.5% of primary porosity） and early-stage pervasive calcite cementation （observed in 25% of samples） are the critical drivers of reservoir densification. Dissolution is poorly developed with a thin section porosity less than 0.5%）， and this is primarily limited by the scarcity of soluble feldspar， rapid compaction rates， and insufficient organic acid supply from adjacent source rocks. By contrast， reservoirs relatively high in quality with an average porosity reaching 7.56%， are developed within distributary channel sandstones with low matrix content at the base of the TST. Excessively high quartz content increases the risks of wear to drill bit and hydraulic fracturing operations. HST sandstones， which possess higher feldspar and lithic contents than TST sandstones， offer better drillability and stimulation potential， serving as promising succession intervals for future exploration.关键词：quartz content;genetic mechanism;sandstone reservoir;Lianggaoshan Formation;Jurassic;central Sichuan Basin;Sichuan Basin76|38|0更新时间：2026-07-06
- 摘要：This study characterized the types， geological features， and differences in gas-bearing properties of reservoir-seepage units， investigated the controlling effects of geological structures， reservoir fractures， and petrophysical properties on gas-bearing potential， and elucidated the differential enrichment mechanisms of natural gas. Using seismic data， imaging logs， core observations， high-pressure mercury injection （HPMI）， and production data， we aim to address the challenges of diverse reservoir-seepage unit types and unclear primary controlling factors of natural gas enrichment in the tight sandstones of the Triassic Xujiahe Formation in the western Sichuan Depression， Sichuan Basin. As indicated by the research results， four types of reservoir-seepage units are identified in the study area： fault-fracture， fold-fracture， fault-fold-fracture， and matrix types. The matrix-type units， characterized by underdeveloped tectonic fractures， exhibit inferior petrophysical properties and low gas-bearing potential. In contrast， the fault-fracture， fold-fracture， and fault-fold-fracture types， which are governed by tectonic deformation， feature well-developed fracture networks， enhanced physical properties， and higher gas-bearing potential. Meanwhile， fracture-rich units， medium- and high-angle fractures significantly enhance vertical permeability and expand the effective range of gas charging. Fracture density and the proportion of medium- and high-angle fractures typically decrease with increasing distance from faults， with the 200 ~ 600 m range identified as the optimal interval for gas enrichment. Furthermore， the fold width-to-height ratio exerts a clear influence on fracture intensity； areas proximate to fold hinges exhibit higher fracture densities and a greater proportion of medium- and high-angle fractures， providing superior conduits for gas accumulation. Finally， effective pore preservation is critical for gas enrichment in matrix-type units， and those with chlorite rims and superior sorting represent the most favorable sites for accumulation.关键词：differential enrichment;pore preservation;reservoir-seepage unit;tight sand gas;tectonic fractures;Xujiahe Formation;Western Sichuan Depression105|45|0更新时间：2026-07-06
- 摘要：Debris flow-dominated submarine fans are a critical type of deep-water gravity-flow deposits and constitute a key research target for deep-water hydrocarbon exploration and submarine geohazard assessment. The Upper Permian Maomaolong Formation in the Hezuo region of the Western Qinling Orogenic belt contains well-preserved outcrops of typical debris flow-dominated submarine fan deposits， which record the Late Permian deep-marine sedimentation events. This study focused on the Laoloudi and Cegou sections. Integrating high-resolution three-dimensional （3D） digital outcrop models， field sedimentological investigation， and petrographic microscope analysis in laboratory， we reveal the development characteristics and genetic mechanisms of submarine fans. As indicated by the research results， the Upper Permian Maomaolong Formation in the Hezuo region of the Western Qinling Orogenic belt was divided into seven lithofacies， including two conglomerate lithofacies， four sandstone lithofacies， and one mudstone lithofacies. The gravity-flow deposits include cohesive debris-flow deposits， coarse-grained hybrid event beds， and high-density turbidites. The cohesive debris-flow deposits， among others， were further subdivided into moderate- to low-strength and high-strength cohesive deposits， whereas the coarse-grained hybrid event beds represented the products of fluid transformation from moderate- to low-strength cohesive debris flows. However， the gravity-flow fan bodies in the Maomaolong Formation exhibit sheet-like or tabular geometries and were dominated by lobe deposits， with channels being poorly developed or absent. Based on event-bed thickness， sandstone ratios， and lithofacies associations， the lobe system was further classified into two architectural units： proximal and distal lobes. Furthermore， the debris flow-dominated submarine fan in the Hezuo region is developed in a paleogeomorphic framework of “narrow shelf-steep slope-deep basin”， while controlled by a composite transport mechanism involving slope instability and shelf-current reworking. This submarine fan type is characterized by the dominance of multi-type debris-flow deposits and the coexistence of composite flow-transformation products， exhibiting rapid lateral facies transitions and pronounced heterogeneity. These findings provide important insights for the prediction and architectural characterization of deep-water gravity-flow hydrocarbon reservoirs.关键词：genetic mechanism;flow transformation;hybrid event bed;submarine fan;subaqueous debris flow;gravity-flow deposits;Maomaolong Formation;Western Qinling Orogenic Belt55|35|0更新时间：2026-07-06
Petroleum Geology
- 摘要：Thermochemical sulfate reduction （TSR） is a common secondary alteration occurring in deep carbonate reservoirs. Earlier TSR simulation experiments have focused on reaction kinetics， gaseous product compositions， carbon isotopes of individual gas components， and sulfur isotope fractionation in H₂S， but the formation and evolutionary patterns of TSR-sensitive molecular markers remain poorly understood. To address this gap， a condensate sample from well Fengshen-1 in the Minfeng subsag of the Dongying Sag， Bohai Bay Basin， was selected as the study sample. Closed-system simulation experiments were conducted for 80 h under three sulfur-bearing systems： CaSO₄， MgSO₄， and elemental sulfur. Quantitative analyses of gas composition， compound-specific carbon isotopes of gas components， and liquid-phase products were then used to systematically characterize the alteration effects of TSR on liquid hydrocarbon molecules. As indicated by the experimental results， all three systems generated both hydrocarbon and non-hydrocarbon gases， and H₂S yields increased in the order of CaSO₄ system < MgSO₄ system < elemental sulfur system. Methane carbon-isotope fractionation followed the sequence CaSO₄ system < elemental sulfur system < MgSO₄ system， whereas CO₂ carbon isotopes showed the opposite trend， following the order of CaSO₄ system > elemental sulfur system > MgSO₄ system. Across all three systems， n-alkane concentrations in the liquid products decreased by 42% to 57%， with Pr/nC₁₇ and Ph/nC₁₈ ratios also decreasing markedly， indicating that isoprenoid alkanes degraded faster than n-alkanes. At the same time， aromatic hydrocarbon concentrations， alkyl dibenzothiophene （DBT） series concentrations， and dibenzothiophene/phenanthrene ratios all increased markedly， suggesting sulfur radical‑mediated aromatization reactions. Diamondoid concentrations and adamantane maturity indices also increased substantially， and a complete C₀-C₃ thiadiamondoid series was first detected at Easy%Ro of 1.21%， confirming the progressive enrichment of thiadiamondoids via sulfur-radical addition. On this basis， this study establishes an evolutionary model for TSR-sensitive molecular markers， demonstrating that the stability of the pristane/phytane （Pr/Ph） ratio， coupled with the contrast in degradation rates between n-alkanes and isoprenoid alkanes， serve as two indicators for evaluating TSR alteration intensity. It also shows that the staged generation of thiadiamondoids can serve as a new proxy for evaluating TSR intensity， while isotopic fractionation differences among the three sulfur-bearing systems provide critical geochemical evidence for tracing TSR reaction pathways in hydrocarbon reservoirs. These findings have significant implications for identifying TSR-induced secondary alteration processes in deep and ultra-deep carbonate reservoirs at the molecular geochemical level.关键词：n-alkane;diamondoid;thiadiamondoid;dibenzothiophene;thermochemical sulfate reduction;molecular geochemistry;Dongying Sag;Bohai Bay Basin49|23|0更新时间：2026-07-06
- 摘要：The Carboniferous Benxi Formation in the Ordos Basin holds substantial potential for deep coalbed methane （CBM） development. However， hydraulic fracturing operations commonly induce damage to coal reservoirs， resulting in low gas recovery rates. In this study， systematic experiments were conducted on deep coal rock samples from the Benxi Formation in the Ordos Basin， including supercritical （SC）-CO2 soaking， three-point bending tests， scanning electron microscopy （SEM）， and nuclear magnetic resonance （NMR） analyses. As indicated by the research results， SC-CO2 exposure exerts a time-dependent， nonlinear influence on the mechanical properties of coal， characterized by an initial short-term enhancement followed by long-term deterioration. Peak load， fracture toughness， and elastic modulus reached relatively high values after 5 days of soaking. With prolonged exposure， however， the pore structure progressively deteriorated due to dissolution， leading to a 25.62% reduction in fracture toughness and a 33.29% reduction in elastic modulus after 20 days. Meanwhile， SC-CO2 significantly enhances pore connectivity and alters fluid occurrence patterns. Loosely structured coal rocks with well-developed porosity exhibits greater sensitivity， with the total T2 spectrum area increasing by 40.2%. In terms of failure modes， the fractures of untreated coal rocks were predominantly of brittle vertical penetration with relatively regular propagation paths. After SC-CO2 soaking， fracture propagation is increasingly controlled by the interplay between bedding development and dissolution-induced weakening. This led to more complex fracture geometries， as evidenced by an increase in fracture fractal dimensions. The most pronounced fluctuations occur in samples with bedding perpendicular to the loading direction， with a maximum fractal dimension increase of 12.8%. SEM observations indicate that SC-CO2 dissolution induces multiscale damage to the microstructure of coal rocks. At the micrometer scale， calcite dissolution results in localized pore networks. At the hundred-micrometer scale， micro-cracks initiate at dissolution zone boundaries and propagate into through-going fractures. At the millimeter scale， accumulated damage drives micro-crack coalescence along mechanically weakened pathways， ultimately forming complex fracture networks.关键词：damage characteristics;three-point bending test;supercritical CO2;fracture behavior;deep coal rock;coal rock gas development;Benxi Formation;Ordos Basin71|28|0更新时间：2026-07-06
- 摘要：With the continuous advancement in lacustrine shale oil exploration and development in China， traditional reservoir evaluation methods are facing a series of challenges in microscale characterization. In this study， we analyze the advantages and limitations of existing reservoir evaluation techniques and methods. Accordingly， a more intelligent， comprehensive shale reservoir evaluation method that integrates multidimensional data is proposed. Based on the Adaptive Pyramid Context Network （APCNet） for semantic segmentation， combined with the previously independently developed shale pore-fracture segmentation network （ShaleSeger）， this method enables intelligent segmentation of minerals and pore structures within reservoirs. By further integrating image processing techniques with mathematical statistics， the method allows for both the quantitative calculation of the shale brittleness index and the fine-scale characterization of pore structures. The analytical results indicate that this proposed method serves to provide more specific， comprehensive， and quantitative analytical data for shale oil and gas exploration and development， as well as sweet spot identification. These analytical data in turn facilitate the quantitative evaluation of resource potential in shale hydrocarbon reservoirs and assist in the comprehensive assessment of relevant technical difficulties and economic benefits. The systematic solution established based on the proposed method offers a reliable basis for intelligent decision-making in the efficient exploration of lacustrine shale oil and gas. Additionally， this study presents a thorough analysis of challenges associated with current intelligent analysis techniques for lacustrine shale reservoirs and points out focus for future research.关键词：intelligent core analysis technology;deep learning;semantic segmentation;microscopic reservoir evaluation;shale oil;Gulong Region;Songliao Basin47|41|0更新时间：2026-07-06
Methods and Technologies
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