Oil content is a critical indicator directly affecting the economic evaluation of shale oil resources. Due to the high volatility of light hydrocarbons in shale oil and the difficulty in accurately measuring some heavy hydrocarbons using traditional experimental methods， there is an urgent need to establish a comprehensive quantitative experimental method for total hydrocarbon components to scientifically characterize the retained hydrocarbon content in shale formations. This study takes the first pressure-preserved coring well for shale oil in the Ordos Basin as an example. By employing a combined approach of pressure-preserved coring， low-temperature treatment， and integrated pyrolysis-extraction， challenges such as light hydrocarbon loss and heavy hydrocarbon recovery were overcome， leading to the establishment of a quantitative evaluation method for retained hydrocarbons in shale formations under near in-situ conditions. The results show that compared with geochemical logging data， the proportion of measured light hydrocarbons in free hydrocarbons increased from 1.56% to 33.5%， indicating that the method effectively avoids the issue of light hydrocarbon loss in traditional experiments. The average ratio of heavy hydrocarbon content to S 1 reached 40%， demonstrating that the recovery of heavy hydrocarbons achieved by this method cannot be ignored. Based on integrated lithological and mobility characteristics， the depth interval of 1 985-1 996 m was selected as the target zone and a premium interval for fracturing and well testing in this well， with favorable results observed during testing. The application of this improved retained hydrocarbon evaluation technique corrects the impacts of light and heavy hydrocarbon components on shale resource assessment and is expected to effectively support the identification of favorable shale oil exploration targets and resource evaluation.
The Chang 7 interlayered shale oil in the Ordos Basin possesses significant exploration potential， yet the enrichment degree varies greatly across different zones， and the understanding of regionalized reservoir controlling factors remains unclear. Through comparative analysis of reservoir-forming elements such as source rocks， reservoirs， and lithological combinations in the Chang 7 interlayered shale oil in Longdong， Northern Shaanxi， and Jiyuan areas， the controlling factors for differential accumulation of interlayered shale oil have been identified， and a differential enrichment and reservoir formation model has been established. The research results indicate that the thin mud and thick sand development in the delta front of Northern Shaanxi， coupled with limited distribution of source rocks， is the key factor contributing to the poorer enrichment of interlayered shale oil compared to Longdong. In Jiyuan， despite the maximum thickness of source rocks in the Chang 7 Member， the small scale of sandstone reservoirs and poor lateral continuity， coupled with low hydrocarbon expulsion efficiency due to the thick mud and thin sand lithological combination， result in the smallest enrichment scale of interlayered shale oil， making it a favorable area for shale-type shale oil exploration. In the Huachi-Qingcheng area of Longdong， the development of thick mud and thick sand lithological combinations， coupled with high-quality reservoirs， determines the large-scale enrichment of interlayered shale oil. The fracture development in the Heshui area provides good transport conditions for the vertical migration of shale oil， and the better physical properties of the Chang 71 sub-member reservoirs result in a better enrichment scale of interlayered shale oil compared to the Chang 72 sub-member. A “four-element” joint control differential enrichment and accumulation model has been established， which includes high-quality source rock， high-quality reservoir enrichment， lithological combination accumulation， and fracture control. It points out that the delta front ends of Longdong and Northern Shaanxi are the main target areas for interlayered shale oil exploration， and the Chang 73 sub-member in Jiyuan is an important area for shale-type shale oil exploration， providing theoretical support for the optimization of sweet spots and development deployment of continental shale oil.
The Chang 73 sub-member in the Ordos Basin exhibits high organic matter abundance， which is the main source rock of shale oil in the Yanchang Formation. Due to the rapid variations in sedimentary environments and provenance supply， the shale in the Chang 73 sub-member displays diverse lamination assemblages and strong heterogeneity， resulting in unclear genetic relationship with organic matter enrichment. To clarify the lamination types， distribution characteristics， and developmental environments of the Chang 73 sub-member， Well X140H， a fully cored well in the Chang 73 sub-member within the deep-lake facies zone， is selected for detailed study. Through the analysis of lamination morphology， mineral composition， and organic matter abundance， five main lamination types are identified： silty felsic lamina （SF）， tuffaceous lamina （TF）， organic-rich clay laminae （ORC）， organic-bearing clay laminae （OBC）， and homogeneous clay layers （HC）， which were further subdivided into seven subtypes. Homogeneous clay laminae and silty felsic lamina are predominantly distributed in the upper and middle parts of the shale section within the Chang 7₃ sub-member. These layers represent the proximal end of gravity flow deposits. During the deposition period， intense chemical weathering and substantial terrigenous input occurred， with parent material of type Ⅱ₂. The hydrogen index （I H） is below 350 mg/g. Overall， these deposits are characterized by low primary productivity， an oxidizing environment， coupled with low organic matter abundance. Tuffaceous lamina is predominantly developed in the lower part of the shale section. Organic-bearing clay laminae are sparsely distributed in the middle part， while organic-rich clay laminae are present throughout the entire section. All three types of laminae are deposited under conditions of relatively weak hydrodynamic forces. During the deposition period， they were influenced by volcanic activities， resulting in weak chemical weathering and limited terrigenous input. The organic matter parent materials are mainly of Type Ⅰ and Type Ⅱ₁. These deposits are characterized by high primary productivity and strongly reducing environment， with a high abundance of organic matter， making them preferred targets for the development of pure shale type shale oil.
Turbidity current deposits in the deep-lake setting of the Chang 7 Member in the Ordos Basin are characterized by the rapid lateral variations and strong vertical heterogeneity. Current understanding of their sedimentary mechanisms remains insufficient， which restricts the efficient exploration of shale oil. To address this issue， this study systematically investigates the sedimentary mechanisms of turbidite deposits in the deep-lake setting of the Chang 7 Member through two aspects： geological analyses （including core observation， grain size analysis， logging interpretation and seismic attribute characterization） and numerical simulations （based on the Navier-Stokes equations and the turbulent k-ɛ model）， and further discusses their implications for shale oil exploration. The results show that when short-duration turbidity currents enter the deep-lake plain， their flow velocity attenuates rapidly， leading to sediment accumulation and the development of typical sedimentary structures such as massive bedding， parallel bedding and wavy lamination. In contrast， long-duration turbidity currents， despite an overall rapid reduction in flow velocity upon entering the deep-lake plain， maintain high flow velocity and intense turbulence in their heads. In addition to forming the aforementioned classic sedimentary structures， these turbidity currents erode lacustrine bottom sediments to generate sandstones containing abundant mud gravels and argillaceous clasts. Unlike the general parallel bedding arrangement or normal graded bedding described by the Bouma sequence， some of these mud gravels and argillaceous clasts even exhibit an undirected distribution， which is closely related to the intense turbulent flow regime in the turbidity current heads. Combined with the analysis of the 405 ka long eccentricity cycle， identification of sedimentary noise signals and variation analysis of the Mo/Ti ratio， a quantitative assessment of the erosion intensity of turbidity currents in the deep-lake plain was conducted. The results indicate that such erosion can cause the absence of sedimentary records of up to ~100 Ma in local areas. On the one hand， this phenomenon suggests that the quantification of sedimentary record gaps should be a prerequisite for conducting Milankovitch cycle studies in deep-lake areas. On the other hand， the long-term， multi-stage erosion by these erosive turbidity currents， converging under the influence of pre-existing microtopography， is likely the primary mechanism for the development of turbidite channels in the deep-lake plain. The scale of turbidite channels in the Chang 7 Member deep-lake setting decreases upward， which is overall controlled by the relatively reduced provenance supply caused by lake transgression. Moreover， the sand-rich sublacustrine fans， continuously supplied by turbidite channels， are important exploration targets for interbedded shale oil in deep-lake areas.
The oil and gas exploration in the Chang 8 Member of the southern Tianhuan Depression in Ordos Basin has made a breakthrough in high production， but there is obvious east-west differentiation in the reservoir physical properties. In order to clarify the reservoir differentiation evolution model of the Chang 8 Member and reduce the risk of oil and gas exploration in the edge of the basin， based on the study of petrology， physical properties， pore structure and diagenesis， the controlling effects of sedimentation， diagenesis， differential sedimentation and hydrocarbon evolution on the reservoir were clarified， and the differentiated development model of the reservoir in the Chang 8 Member was established. The results show that the Yanwu area develops a thick layer of diverging river sand body， the lithology is feldspathic clastic sandstone， the primary intergranular pores are dominant， Class I-II pore structures are developed， the average porosity is 15.10%， and the average permeability is 4.58×10-3 μm2， which is a low-porosity-ultra-low-permeability reservoir. The Mengba area develops many thin layers of sand body， the lithology is rocky feldspar sandstone， secondary dissolution pore is more developed， II-III pore structures are developed， the average porosity is 8.89%， the average permeability is 0.38×10-3 μm2， for the ultra-low pore-ultra-low permeability reservoir. The pore differential evolution of the reservoir in Chang 8 Member is mainly controlled by compaction and dissolution. 21.3% of pore reduction is caused by compaction and 4.6% of pore increase is caused by dissolution in Mengba area， while 14.5% of pore reduction is caused by compaction and 2.7% of pore increase is caused by dissolution in Yanwu area， which establishes the “thick sand body-passive rock-shallow burial-weak dissolution”. The two reservoir development models of “thick sand body-unsourced rock-shallow burial-weak dissolution” and “many thin sands-near-sourced rock-deep burial-strong dissolution” were established. The Chang 8 Member of the Yanwu area develops a thick layer of fluvial sand body， and the Chang 73 submember does not develop effective source rocks， so there is insufficient oil and gas filling， and the pore-enhancing effect of dissolution of exogenous organic acids is weak. In Mengba area， the Chang 8 Member develops thin sand body， the Chang 73 submember develops thick black shale， and the hydrocarbon generation process forms organic acids， which strongly enhance porosity through dissolution.
Revealing the constraining effect of paleogeomorphology on sedimentary systems and sediment distribution is the key to studying the sedimentary filling and evolution of basins. Aiming at the geological problem that the sedimentary controlling factors of the marine-continental transitional shale strata in the Shanxi Formation of the eastern margin of Ordos Basin， this study reconstructs the spatial pattern of pre-sedimentary paleogeomorphology of the Shan2 3 sub-member using the impression method with decompaction correction， based on 3D seismic data and combined with drilling data. A further systematic analysis of the controlling effect of paleogeomorphology on the deposition of shale strata was conducted， so as to provide a basis for the evaluation of shale gas “sweet spots”. The research shows that the pre-sedimentary paleogeomorphic of the Shan2 3 sub-member presented a spatial pattern of alternating uplifts and depressions. The combination of paleogeomorphology and sedimentary facies division effectively reveals the response relationship between the spatial distribution law of shale and the spatial pattern of paleogeomorphology. The shale deposition presents a “two-stage” sedimentary model， where the lower section is controlled by paleogeomorphology and the upper section by sedimentary facies. During the early sedimentary period of the Shan2 3 sub-member， sedimentation was completely controlled by paleogeomorphology， forming a sedimentary combination of delta front-barrier island-tidal flat-lagoon/bay. Paleogeomorphic depressions served as favorable enrichment areas for shale， and the relatively low-energy and reducing lagoon sedimentary environment was conducive to the enrichment and preservation of organic matter. The implementation effect of horizontal well has confirmed the reliability of shale distribution based on paleogeomorphology restoration. During the late sedimentary period of the Shan2 3 sub-member， the controlling effect of paleogeomorphology on sedimentation weakened significantly， and the sedimentary combination gradually transitioned to delta front-tidal flat-swamp. Large-scale tidal flat-swamp sedimentary environment influenced the deposition of shale， but the overall environment tended to be oxygen-rich， which was unfavorable for the preservation of organic matter. The analysis of the response relationship between the deposition of transitional shale strata and paleogeomorphology has laid an important foundation for the prediction of shale gas “sweet spots” in the study area.
To investigate the development characteristics and formation mechanisms of organic pores in continental shale， this study examines highly mature， organic-rich shale from the Jurassic Ziliujing Formation in the Sichuan Basin. Employing various experimental methods， including organic petrology， kerogen and group component carbon isotopes， argon-ion polishing-scanning electron microscopy （SEM）， and energy-dispersive X-ray spectroscopy （EDS）， we identified and classified organic matter components and organic pore types， and investigated the main controlling factors for organic pores formation in continental shale. The results indicate that： （1） The organic matter in the Ziliujing Formation shale primarily consists of primary morphologically preserved vitrinite （including fusinite/semifusinite） and secondary amorphous bituminite. Four types of higher plant debris components were identified： strip-shaped， silk shaped， branched， and block shaped. Five types of higher plant cellular structures were observed： reticular large-cavity thin-walled， reticular small-cavity thick-walled， irregular cavity， grape-cluster cavity， and tubular cavity. The bituminite components are constrained by the framework space of inorganic mineral particles and their symbiotic relationships with authigenic minerals， exhibiting four occurrence states： banded， scattered， interactive， and interpenetrating. （2） According to organic matter component types and occurrence/composite relationships with inorganic minerals， organic pores were classified into three categories comprising eight types： bituminite organic pores， bituminite-authigenic mineral composite organic pores， and vitrinite organic pores. Organic pores are commonly developed in bituminite and bituminite-authigenic mineral composites. （3） A “four-factor” controlling mechanism is proposed： （a） Organic matter component type provides the material basis for organic pore development； （b） The occurrence state of bituminite and thermal maturity are key factors controlling favorable organic pore development； （c） Hydrothermal activity promotes the development of organic pores within bituminite； （d） Preservation of cellular structures or bacterial modification facilitates organic pore development in vitrinite.
To investigate the factors influencing gas content variations in tight reservoirs of the western Sichuan Basin， this study employed multiple fractal dimension theory alongside centrifugal-NMR experiments， high-pressure mercury intrusion porosimetry， cast thin sections， scanning electron microscopy， and X-ray diffraction. These techniques successively characterized the pore structure and gas content properties of reservoirs in southwestern and northwestern Sichuan， thereby identifying the controlling factors for gas content variability. The results demonstrate that： （1） The pore systems in western Sichuan are predominantly composed of residual intergranular pores. In the southern region， gas-poor intervals exhibit extensive carbonate cementation filling most residual intergranular pores， while in the northern region， chlorite coatings are well-developed within the pores， with gas-poor reservoirs showing significant pore blockage by chlorite. （2） The gas saturation of reservoirs in western Sichuan ranges from 38.79% to 56.88%， with the southern region showing notably lower values （38.79%） compared to the northern area. （3） In the northern reservoirs， strong compaction has led to higher porosity reduction rates and relatively smaller pore spaces， while partial blockage of smaller pores by chlorite coatings further reduces gas-bearing capacity. In contrast， the southern reservoirs exhibit strong heterogeneity in nanopores that impedes gas migration， coupled with extensive carbonate cementation in certain intervals that severely restricts secondary pore development， collectively resulting in inferior gas-bearing properties.
Fluid inclusions are the historical records of hydrocarbon fluid activity in shale strata， which is of great significance for understanding the micro-migration and enrichment process of shale oil. In view of the main capture media of inclusions such as carbonate laminae， fracture veins and sandy interlayers in shale strata， the petrographic observation of fluid inclusions in shale strata was carried out. Combined with FIA analysis of fluid inclusion assemblages and basin numerical simulation， the capture time and stage of shale oil inclusions were accurately determined， and the oil and gas geological significance of the capture behavior of different media was discussed. The results show that two types of hydrocarbon-bearing inclusions， yellow-green fluorescence low maturity and blue-white fluorescence high maturity， are mainly developed in the shale strata of the upper Es 4 in Boxing sag， which are captured by quartz particles in carbonate laminae， calcite veins in various fractures and sandy interlayers. There are obvious differences in the capture time and period of different media. It is revealed that the enrichment process of shale oil in the upper Es 4 in Boxing sag can be divided into three stages： before tectonic uplift， during tectonic uplift and after tectonic uplift. The capture behavior of inclusions in carbonate laminae， fracture veins and sandy interlayers indicates the micro-migration and effective transport channels in the multi-stage enrichment process of shale oil.
Pyrite is widely developed in organic-rich shales. The morphology of framboidal pyrite， along with the particle size characteristics of the framboids and their constituent microcrystals， serves as a reliable tracer for the sedimentary water environment. This study focuses on the pyrite within the shales of the upper Es 4-lower Es 3 submembers in the Dongying Depression. The morphological characteristics of pyrite were observed using optical microscopy and scanning electron microscopy， and statistical analysis of the particle sizes of framboids and internal microcrystals was performed using ImageJ software. The results indicate that the particle size distribution of framboidal pyrite in the samples can be classified into three types：Tall-type（average particle size<5 μm， standard deviation of 1-2 μm）， Broad-type （average particle size between 5 and 10 μm， standard deviation of 2-6 μm）， and Fluctuant-type （average particle size > 10 μm， standard deviation of 6-10 μm）， which reflect different formation processes of framboidal pyrite. Simultaneously， within the Tall-type and Broad-type framboidal pyrites， a negative correlation is observed between the ratio of the framboid diameter （D） to the internal microcrystal size （d） and the degree of water column euxinia. The morphology and particle size characteristics of framboidal pyrite vary across different lithofacies， revealing that the redox conditions of the sedimentary water body in the study area were significantly influenced by hydrodynamic energy and the degree of climatic aridity. Specifically： in the LF1 （Felsic claystone）， framboidal pyrite is predominantly the Fluctuant-type， with a large framboid particle size distribution； in the LF2 （Organic-rich calcareous claystone）， it is primarily the Tall-type， with D/d < 6； in the LF3 （Organic-rich dolomitic claystone）， it is mainly the Tall-type， with D/d > 6； in the LF4 （Organic-rich argillaceous limestone）， it is primarily the Tall-type， but the D/d characteristics differ among different lamina types； and in the LF5 （Organic-rich mixed rock）， framboidal pyrite is mainly the Tall-type， with D/d ranging between 5.5 and 6.2， and it contains abundant euhedral pyrite and replacement pyrite.
The second member of Funing Formation in the Qintong Depression in the northern Jiangsu Basin has good prospects for shale oil exploration， but there are obvious differences in shale oil production capacity between its different sub-sections. The differences in the geochemical characteristics of their paleoenvironmental elements are revealed through the content or ratios of elements such as Mg， Al， Si， S， Ca， Fe， Cu， Mn， Ti， Ba， V， Ni， Rb and Sr， etc. The paleoproductivity of the lake basin in the Fu-2 Member gradually increases from submembers I to IV， while the paleowater temperature gradually decreases. Although the four sub-members were deposited under deep water， oxygen-poor reducing environment under saline conditions， there was a trend of gradually increasing water depth， enhanced reducing conditions， and freshening of the water from submember I to IV. These changes in the paleoenvironment led to differences in the lithology of mud shale. Additionally， the paleo-climate also changes from arid to a semi-arid. Changes in the paleoenvironment lead to differences in shale lithologies. The difference in autogenerated silicon content reveals that the clay mineral content of shale gradually increases from sub-member I to IV， and the engineering compressibility gradually becomes worse. It is inferred from the difference in quartz content that the effect of hydrothermal activity on the second member of Funing Formation may be ended in the sub-member III. In addition， minerals such as anhydrite， zeolite， barite， etc. formed by hydrothermal activities can form a favorable “self-sealing” system with the overpressure of the formation， which plays a key role in the preservation and enrichment of shale oil.
The H-56 block of the Daqingzi Oilfield in the Changling Sag represents a typical tight oil reservoir characterized by low porosity， complex pore structures， and strong heterogeneity. These factors exert a significant influence on the CO2 flooding process and its efficiency. In this study， high-temperature and high-pressure micro-visualization displacement experiments using real-core models were conducted based on the petrophysical properties and pore-throat structures of the reservoir. The mechanisms of CO2 flooding and the distribution characteristics of residual oil under different pore structures were systematically analyzed. Experimental results indicate that the reservoir cores in the study area are dominated by primary and secondary pores， with pore throats primarily exhibiting a curved-sheet morphology and intricate tortuosity， leading to distinctly hierarchical characteristics in pore-throat connectivity. Well-connected samples， characterized by well-developed and well-connected pore-throat networks， exhibited continuous and stable flow channels during CO2 flooding. The displacement pattern was mesh-like， and the residual oil saturation was low， primarily in the form of film-like and isolated island-like residual oil， with an ultimate recovery factor of approximately 75.32%. In contrast， poorly-connected samples showed poor pore-throat connectivity and limited flow pathways， resulting in an uneven and finger-like displacement front. The residual oil mainly occurred in connected and clustered forms， and the overall recovery factor was approximately 66.98%. The study demonstrates that differences in microscopic pore-throat structures are the key controlling factors affecting CO2 flooding efficiency and residual oil distribution. Capillary pressure， pore-throat morphology， and pore connectivity jointly determine the flow behavior of CO2 and the mobilization efficiency of residual oil within tight sandstone reservoirs. The results provide pore-scale evidence for the evaluation of CO2 flooding effects and the potential for remaining oil recovery in tight sandstone reservoirs.
Ancient alkaline lake sediments are important geological carriers of oil and gas， natural alkali minerals and boron minerals， and are also key objects for paleoecological research in deep-time extreme alkaline environments. The common paragenesis of natural alkali mineral layers， dolomite and organic-rich mudstone in ancient alkaline lake sediments indicates that there is a genetic connection between natural alkali minerals， dolomite and microorganisms， with the core being the microbial community-dolomite mutual feedback. To this end， this paper reviews the characteristics and occurrence conditions of the alkaline lake microbial community-dolomite mutual feedback， and discusses its impact on organic matter enrichment. The results show that the extreme alkalinity （pH>9） of alkaline lakes makes its biological communities dominated by microorganisms， and alkaliphilic/alkali-tolerant microorganisms such as cyanobacteria， sulfate-reducing bacteria and methanogens form the community. The alkaline lake microbial community promotes dolomite precipitation by changing the extracellular microenvironment and providing initial nucleation sites， thereby affecting the ion composition and concentration of the water body， driving the succession of the microbial community， and thus forming a microbial community-dolomite mutual feedback. Under the background of alternating dry and wet conditions and intermittent evaporation and concentration of water bodies， the alkaline lake microbial community-dolomite mutual feedback participates in the evolution of water chemical conditions， forming a brine type that is conducive to the precipitation of natural alkali minerals. The unique high pH conditions of the alkaline lake promote the dissolution of nutrients， neutralize harmful elements， increase the proportion of primary producers， and form high primary productivity； through early silicification， hot spring input， and the formation of natural alkali mineral shells， organic matter is effectively preserved， organic matter enrichment is promoted， and a material basis is provided for the development of high-quality source rocks. Primary dolomite is developed in the alkaline strata of the top of the core three and the bottom of the core two of the Paleogene in Anpeng， Biyang Sag， and characteristic biomarkers have been identified， providing direct evidence for the ancient alkaline lake microbial community-dolomite mutual feedback in this section.
In recent years， China's shale oil exploration has made new breakthroughs， and has become an important replacement resource to ensure China's energy security. Shale oil mainly occurs in shale layers dominated by shale， including those in mud-shale matrix pores and clastic rock interlayers adjacent to shale. Its occurrence and distribution are governed by the evolution of the pressure field during the basin dynamic processes. This study focuses on source-reservoir separated shale formations and utilizes a formation pore thermal-pressure hydrocarbon generation and expulsion simulation experimental apparatus to systematically conduct simulation experiments on hydrocarbon generation and expulsion under source-reservoir pressure differences （referring to the pressure difference between the entire shale formation and external conventional reservoirs）. The aim is to reveal the controlling mechanism of source-reservoir pressure differences on the spatial distribution of shale oil in shale matrix pores and clastic rock interlayers， and to explore its geological implications. The results indicate： （1） The mud-shale matrix pore space is the primary reservoir for shale oil， accounting for 60%-90% of the total resource （the less accessible portion）， while the sandstone interlayers contribute 10%-40% （the more producible portion）. This ratio evolves with increasing maturity， showing a trend of decreasing matrix proportion and increasing interlayer proportion. （2） The influence of source-reservoir pressure difference on shale oil distribution exhibits significant differentiation： it primarily exerts a destructive effect on oil retained in mud-shale matrix pores， especially pronounced in the high maturity stage； in contrast， it shows a “dual-effect” on oil in sandstone interlayers-pressure differences less than 6 MPa promote enrichment through short-distance migration and charging， whereas differences greater than 6 MPa inhibit enrichment due to long-distance migration and dissipation. （3） The total oil yield is mainly controlled by the maturity and original quality of the source rock， with relatively minor influence from the source-reservoir pressure difference. However， the gas yield exhibits a strong response to pressure difference， with higher gas production rates observed under larger pressure difference during the high maturity stage. The findings of this study provide experimental evidence and theoretical support for the “source-reservoir coupling” evaluation and the selection of exploration targets in continental shale oil systems.
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