The Ordos Basin， China's largest hydrocarbon production base， is rich in petroleum resources and characterized by diverse exploration plays. This paper systematically reviews the history of hydrocarbon exploration in the basin， summarizes key insights， identifies current fundamental research challenges， and proposes future exploration directions. This study synthesizes the development process of six major hydrocarbon fields and breakthrough achievements in petroleum exploration， with particular emphasis on elucidating the theoretical frameworks， exploration methodologies， and operational outcomes in two key unconventional domains： shale oil and coalbed methane. The continuous breakthroughs in the basin’s hydrocarbon exploration have always embodied the core concept of intellectual emancipation. The progressive exploration achievements demonstrate the “practice-cognition-repractice-recognition” methodology， which yields significant implications for theoretical advancement， technological innovation， and management paradigms. Addressing contemporary exploration constraints necessitates in-depth fundamental research on hydrocarbon source rock characterization， fault system architecture， and total petroleum systems. Future strategic priorities should focus on four key domains： source-rock-hosted unconventional resources， large-scale reserve growth in low-permeability reservoirs， high-efficiency precision exploration in shallow formations， and frontier exploration in new plays and strata. These initiatives will underpin sustainable hydrocarbon production in the basin， enhance national energy security， and provide a reference model for similar basins worldwide.
The northeastern Sulige Gas Field exhibits well-developed sand bodies in the Permian. However， the exploration and development results were unsatisfactory under the guidance of the previous “gas enrichment controlled by sweet spot” theory. Accordingly， the natural gas accumulation conditions and enrichment patterns in this area need to be re-evaluated. Therefore， this study utilized well logging data and geochemical testing experiments to characterize the coal-bearing rocks， calculate gas generation intensity， and analyze the sources of natural gas. The results show that the Upper Paleozoic coals in the study area are widely distributed with an average thickness of 9.1 m. However， the vitrinite reflectance （RO） value ranges between 0.8% and 1.1%， and the gas generation intensity is less than 0.8×10⁸ m³/km² in most areas， indicating significantly lower local gas supply capacity compared to the central Sulige Gas Field. The carbon isotope values of methane in the study area range from -37.7‰ to -28.1‰， which are equivalent to RO values of 1.0%-2.4%， generally higher than the RO values of local coal-bearing rocks. Analysis suggests that the relatively low-maturity gases （equivalent RO values =1.0%） are derived from local coal-bearing source rocks， whereas the relatively high-maturity gases （equivalent RO values =1.3%-2.4%） are laterally-migrated distal-sourced gases， which constitutes the dominant gas accumulation in the study area. High-porosity and high-permeability sand bodies （i.e.， sweet spots） are no longer the primary controlling factor for gas enrichment. Instead， exploration efforts should shift from sweet spots to traps along the migration pathways of distal-sourced gas.
The Qingshimao Gas Field in the Ordos Basin has a typical deep tight sandstone gas reservoir in the 8th member of the Lower Shihezi Formation of the Permian System （referred to as the He 8 Member）. The complex gas-water relationship is one of the important factors contributing to the difficulty in developing gas reservoirs in this area. By applying three-dimensional seismic data， well logging interpretation， core characteristics， and gas reservoir dynamics， this study deeply investigated the gas-water distribution characteristics， controlling factors， and distribution patterns of the tight sandstone gas reservoir in the He 8 Member. The tight sandstone gas reservoir in the He 8 Member is affected by insufficient gas source supply and weak gas reservoir charging capacity. The entire area shows the characteristic of gas-water interlayering in single wells in the vertical direction. The strength of hydrocarbon generation of source rocks in the south is stronger than that in the north， and the distribution of gas source fractures is dense in the east and sparse in the west， which determines the different gas and water charging intensities in different structural areas. The distribution of the gas reservoirs was determined by the southeast-dipping rhombic structural background during the formation period， coupled with the sealing configuration of the pre-existing NE-SW-trending controlling fractures. Meanwhile， variations in gas enrichment across the well area are dictated by the distribution of high-quality reservoirs within the braided river delta facies and the destructive modifications by NEE-trending adjustment faults since the Cenozoic. Consequently， a gas-water distribution model was established， which can be summarized as 'dominant channels controlling the migration paths， rhombic structures controlling the reservoir boundary， and sedimentary microfacies controlling the enrichment'. These findings provide valuable insights for the efficient development of deep to ultra-deep tight gas reservoirs in the Ordos Basin.
A set of thick salt rock is widely developed in the first member of Majiagou Formation （Ma 1 Member） in the central and eastern Ordos Basin， which has good sealing ability. In order to clarify the identification marks， sedimentary facies distribution and the control of oil and gas accumulation， based on the existing oil and gas geological data， the research method of “logging-seismic-geology” is adopted. Based on the logging response analysis of the coring section， the logging and seismic comprehensive identification of different lithologies is carried out， and the lithofacies paleogeography of the study area is reconstructed. The results show that the salt rock of Ma 1 Member has significant high acoustic time difference， low natural gamma and low density logging response characteristics. On the seismic section， it shows continuous strong amplitude and negative polarity reflection. The salt rock is centered on the Yanchang-Yichuan area and extends in the north-north-east direction. The overall pattern is “thick in the south and thin in the north”， and the southern part is dominated by pure salt rock， and the northern part is salt-gypsum mixed deposition. The analysis of hydrocarbon accumulation control shows that the thick layer of salt rock in the Ma 1 Member can be used as a regional key barrier layer， which has a significant controlling effect on the Cambrian hydrocarbon accumulation. When the salt rock is well developed， it vertically blocks the downward migration of coal-type gas in the Upper Paleozoic， resulting in insufficient hydrocarbon supply in the Cambrian reservoir. When salt rock is missing or incompletely developed， vertical faults become oil and gas migration channels to achieve effective filling of Cambrian reservoirs. This understanding can provide geological basis for the optimization of Cambrian natural gas exploration targets in the central and eastern parts of the basin.
The degree of vertical connectivity of faults plays a crucial role in hydrocarbon migration， accumulation， and reservoir formation， yet it remains difficult to evaluate effectively. To address this challenge， this study integrates high-precision 3D seismic data with static and dynamic exploration and production data， combining deep learning-based fault recognition techniques with structural fault analysis methods to investigate the vertical connectivity patterns of fault conduits and their hydrocarbon-controlling roles in southern Sichuan. Results indicate that interlayer thrust faults developed within the Permian strata， while strike-slip faults occur beneath the Permian， together forming a complex strike-slip-thrust fault conduit system characterized by a vertically layered structure of “deep strike-slip and shallow thrust.” The strike-slip-thrust fault conduit system exhibits diverse fault combinations but generally low vertical connectivity， resulting in multiple connectivity-non-connectivity patterns that lead to heterogeneous hydrocarbon charging. Evaluation of fault connectivity reveals that high-yield wells are predominantly concentrated along fully connected fault zones， where well-connected faults facilitate upward migration of deep-sourced hydrocarbons， demonstrating that the vertical connectivity of faults directly influences hydrocarbon migration and accumulation efficiency. Case studies confirm that the vertical connectivity of faults significantly controls hydrocarbon migration， accumulation， and enrichment； in the Luzhou area of southern Sichuan， zones where strike-slip-thrust faults are vertically connected represent favorable exploration targets.
With the deepening understanding of the Neoproterozoic seawater environment， the main controlling factors of reservoir development in the 2nd member of Sinian Dengying Formation （Deng Ⅱ Member） of the Penglai gas area， Sichuan Basin， require further in-depth investigation. Based on previous research findings， this study conducted core observation， thin-section identification， cathodoluminescence， scanning electron microscopy， and single-well burial-thermal history reconstruction. It systematically summarizes the main reservoir rock types， pore types， physical properties， and diagenetic characteristics of the Deng Ⅱ Member in the study area， aiming to clarify the key elements for the formation of high-quality reservoirs. The rock types in the Deng Ⅱ Member of the study area are predominantly microbiolite， grain dolomite， and crystalline dolomite. The matrix reservoir is characterized as a tight carbonate reservoir with low to ultra-low porosity and permeability， while abundant karst cavies are also observed， indicating strong heterogeneity. The development of high-quality reservoirs shows a strong correlation with the occurrence of microbiolite and grain dolomite. This study concludes that the formation of high-quality reservoirs in the Deng Ⅱ Member dolomite reservoirs in the Penglai gas area is primarily controlled by syndepositional to penecontemporaneous sedimentary facies and subsequent diagenetic alteration. The development of microbiolite and grain dolomite in the Deng Ⅱ Member is a prerequisite for high-quality reservoir formation. Penecontemporaneous meteoric water dissolution was the key driver for reservoir space development. The unique Neoproterozoic seawater background facilitated fibrous dolomite cementation， which effectively inhibited reservoir densification caused by burial diagenetic mineral infilling； furthermore， its distinctive morphological structure enhanced rock resistance to compaction， providing favorable conditions for reservoir preservation. Hydrocarbon fluid charging and tectonic fracturing during the burial stage contributed moderately to reservoir development.
Predicting the distribution of favorable reservoirs in the lowstand submarine fans in the XF area of the Yinggehai Basin is one of the key issues restricting the exploration and development effectiveness in this region. Based on data from seismic surveys， drilling and logging， cores， thin sections， and sample tests， this paper systematically characterized the development patterns of submarine fans and reservoir characteristics， identified the controlling factors of favorable reservoirs， and predicted the distribution of favorable reservoirs using sedimentological， thermodynamic， and kinetic methods. The results show that influenced by the source supply from the Lam River Delta， two lowstand submarine fans have developed in the XF area. Controlled by micropaleogeomorphology， in the western XF13-2 block， medium-thick-bedded composite channel fine sandstones are developed， followed by channelized lobe silt-fine sandstones； in the eastern XF13-1 block， medium-thin-bedded composite channel silt-fine sandstones are developed， followed by distributary channels and lobate （argillaceous） siltstones.The submarine fan reservoirs have a porosity of 5%-20% and a permeability of（0.1-100）×10⁻³ μm²， belonging to medium-low porosity and medium-low permeability reservoirs. The spatial distribution of favorable reservoirs is controlled by rock fabric and dissolution. In the western XF area， it is mainly controlled by rock fabric. The medium-thick-bedded channels with strong hydrodynamic conditions have low clay content， relatively coarse grain size， and develop favorable primary intergranular pore-type reservoirs. These reservoirs generally lack carbonate cementation and have weak dissolution， resulting in good physical properties. The eastern XF area is jointly controlled by both rock fabric and dissolution： the medium-thin-bedded composite channels to distributary channels with medium-strong hydrodynamic force have low argillaceous content and relatively coarse grain size， developing favorable dissolution-type reservoirs， where local dissolution is strong. The dissolution of K-feldspar is the main reason for the formation of favorable reservoirs in this area， exhibiting medium to good physical properties. Based on the "rock fabric-dissolution" dual reservoir-controlling mechanism of submarine fans， a three-step prediction method for favorable reservoirs-"dominant facies belt， dissolution thermodynamics， and dissolution kinetics"-is established， ultimately delineating the regional distribution range of favorable reservoirs. This study provides strong support for the optimization of exploration targets and well placement in submarine fans of the Yinggehai Basin， and also offers a methodological reference for the prediction of favorable submarine fan reservoirs in other basins.
Focusing on the evaluation of fractability in continental shale oil reservoirs， this study proposes an integrated method that combines production data-driven analysis with game theory-based collaborative optimization. Within a linear weighted model framework， an innovative game theory combined weighting mechanism is introduced to synergistically optimize the subjective weights determined by the Analytic Hierarchy Process and the objective weights calculated by the Entropy Weight Method， enabling the dynamic and rational allocation of contribution degrees for key parameters. Taking the shale oil from the Lucaogou Formation in the Jimusar area of the Junggar Basin as an example， the grey relational analysis and Pearson correlation coefficient method were comprehensively employed. Based on post-fracturing production data， five key geomechanical parameters were quantitatively identified： Reservoir brittleness index， minimum horizontal principal stress， minimum horizontal principal stress difference between interlayer and reservoir， horizontal stress difference， and tensile strength. Their optimized weights were determined as 0.331 5， 0.253 0， 0.171 8， 0.162 3， and 0.081 4， respectively. Model validation results show that the fractability evaluation index correlates significantly with post-fracturing production， with the coefficient of determination （R²） reaching 0.789 for modeling wells and 0.727 for application wells， indicating a significant improvement in evaluation accuracy compared to single weighting methods. This provides a reliable quantitative basis for fracture stage/cluster optimization and design in such reservoirs.
Volume fracturing with high injection rate and large treatment volume is considered as the primary stimulation method to shale reservoirs since it realizes the target of cracking reservoir matrix and shortens matrix flow distance. The ultimate fracture-matrix system after fracturing treatment inclines to be dual porosity system when fracture density is sufficiently large. Therefore， the release of adsorbed gas induces dramatic impacts on dual porosity flow dynamic. This paper investigates the impacts of adsorbed gas on reservoir dynamics through numerical simulation and pressure transient analysis， and explores the mechanism by theoretical derivation. It is indicated that gas desorption reduces the difference in elastic storage capacity and inter-media flow by increasing the synthetic storage ratio， thereby reducing the pressure propagation velocity. Moreover， Langmuir volume is positively correlated with the reduction of the inter-media flow effect， while how Langmuir pressure impacts it depends on the relationship between Langmuir pressure and initial reservoir pressure. This research is aimed to provide more information and references for flow characteristic analysis and fracturing stimulation evaluation of shale reservoirs.
Hydrocarbon generation and pore formation during the thermal evolution of organic matters in shale remains unclear. Based on MAPS technology nano-resolution petrological image datasets of each layer of the shale gas sweet spot section in the Longmaxi Formation of the Huang 202 block in the Yuxi Gas Field of the Sichuan Basin were acquired， in order to elucidate the hydrocarbon generation and pore formation during the thermal evolution of organic matters and investigate the organic matter pores' carrier. The results indicate that the organic matters were divided into two major categories， seven categories， and nine subcategories， and the organic matter subcategories are similar in the same layer but differ between layers. The sedimentary organic matter–clay aggregate was transformed into the pyrobitumen-clay aggregate through the kerogen-clay aggregate， the pre-oil bitumen-clay aggregate， and the solid bitumen-oil-clay aggregate. The migratory pre-oil bitumen was transformed into the pyrobitumen through the solid bitumen-oil mixture. The migratory oil was directly converted into the pyrobitumen. The total migration path of the migratory organic matters was from the Layer L11， through the Layers L12 and L13， to the Layer L14. The formation of macropores in the organic matters was closely related to the water-in-oil phenomenon caused by the opposite motion of hydrocarbon and formation water under the combined effects of hydrocarbon-generating pressurization and compaction pressurization. Macroporous organic matters occurred during the conversion of pre-oil bitumen to solid bitumen and oil， while the macropores in macropore and mesopore organic matters developed during the conversion of kerogen to pre-oil bitumen. Compaction exerted a significant influence on the development degree of macropores. The formation of mesopores was closely related to the gas-generating expansion during the conversion of solid bitumen into pyrobitumen. Compaction had a negligible effect on the development degree of mesopores. These innovative results supplement and develop the mechanism of hydrocarbon generation and pore formation during the thermal evolution of organic matters in shale， and resolve the controversy over organic matter pores' carrier for the first time through the 4 nm-resolution MAPS petrological image datasets， and provide a reasonable explanation for the sedimentary environment and productivity differences of each layer in the shale gas sweet spot section in the Longmaxi Formation of the Sichuan Basin， which is helpful for the exploration and development deployment of shale oil and gas. It is recommended to use the nano-resolution petrological image dataset acquired by MAPS technology as the first data for studying the pedigree of hydrocarbon generation and pore formation during the thermal evolution of organic matters and identifying the organic matter pores' carriers.
Organic-rich transitional shales of the Carboniferous Benxi Formation are widely distributed in the Ordos Basin. Yet， systematic reservoir evaluation has not been undertaken in the southeastern sector， leaving its exploration potential uncertain. Accordingly， this paper focuses on the shale in the first member of the Benxi Formation in this area. Based on experiments including thin sections， whole-rock and clay X-ray diffraction， total organic carbon testing， vitrinite reflectance measurement， porosity and permeability tests， high-pressure mercury intrusion， N2 adsorption， CO2 adsorption， and methane isothermal adsorption， its reservoir characteristics were comprehensively characterized， and its exploration potential was quantitatively evaluated through a comprehensive evaluation index. The results indicate that： （1） The organic matter of the first member of the Benxi Formation in the study area is primarily Type III， with high abundance and having entered the over-mature stage exhibiting an average TOC of 2.32% and an average RO of 2.44%. （2） The pore types are mainly intercrystalline pores between clay minerals， with poorly developed organic matter pores. The average pore size is 47.70 nm， the average pore volume is 12.44×10-3 cm3/g， and the average specific surface area is 7.65 m2/g. Higher organic matter abundance， lower clay mineral content， and organic matter maturity are favorable conditions for pore development. （3） The shale exhibits favorable adsorption capacity， with an average Langmuir volume of 2.12 cm³/g， and an estimated total gas content ranges from 1.00 to 1.81 cm³/g. （4） Siliceous clay-rich shale facies show relatively larger pore volume and specific surface area， with the most favorable predicted gas-bearing capacity， representing advantageous lithofacies； （5） The comprehensive reservoir evaluation index is 0.635， indicating Class II exploration potential. Although relatively favorable， the shale exhibits lower organic abundance and higher clay mineral content compared with other transitional shales that have yielded industrial gas flows. In conclusion， the first member of the Benxi Formation in the southeastern Ordos Basin holds significant exploration value. Targeting siliceous clay-rich shale facies， conducting pilot tests， and refining reservoir characterization and stimulation techniques are recommended strategies to enhance the likelihood of achieving industrial gas production.
The exploration potential of coal-rock gas in the Benxi Formation of Qingjian Block in Ordos Basin is significant， but due to the complex tectonic background， the distribution rules of its coal-rock seam， the dynamic relationship between the physical properties and gas-containing properties of the coal-rock reservoirs has not yet been fully clarified， which affects the exploration and evaluation work in the field of high-end coal-rock gas at the basin headquarters. Therefore， based on the coal-taken core well of Benxi Formation No.8 coal， Qingjian area， this paper carries out macroscopic description of coal-rock cores， reservoir isothermal adsorption experiments and CT scanning three-dimensional reconstruction and other testing methods. For the first time， the coal-rock distribution， coal quality characteristics， reservoir physical properties and storage combination conditions of the coal-rock seam of Benxi Formation No.8 coal， the study area was systematically revealed for the first time. The results show that the average thickness of the coal seam of No.8 is 3.8 m， the ash content is low， with an average of 12.92%， the vitrinite content is 79.8%， and the thermal evolution degree （RO=2.69%） reaches a high-over-mature stage. The total gas content is distributed between 18.72-30.27 m3/t， and the free gas content is 6.05 m3/t， accounting for 21.44%. The reservoir exhibits a porosity of 8.43%， with a single-peaked pore structure dominated by micropores， and a permeability of 1.45×10-3 μm2， where microfracture development significantly enhances connectivity. The limestone-coal-mudstone combination is the best， and the hydrological enclosure （CaCl2 type water） is conducive to the preservation of coal rock gas. The coal-rock and gas resource forecast in the research area is 318.8 billion cubic meters， and 1 001 km2 is preferred in Class I and II favorable areas. A typical horizontal-Well Y188H obtained a high-yield gas flow of 51 000 cubic meters per day， confirming the development potential of coal-rock gas in this area and has the prospect of large-scale development.
The continental shale oil reservoirs in China exhibit strong heterogeneity， with complex fluid occurrence and distribution patterns within the shale， leading to issues such as low shale oil and gas recovery rates. Therefore， CO2 injection for reservoir stimulation is a highly promising key technology in shale oil development. This study conducted supercritical carbon dioxide （SC-CO2） soaking experiments under high temperature and pressure conditions （100 ℃， 25 MPa） and characterized the pre- and post-soaking reservoir changes using methods such as X-ray diffraction （XRD）， gas adsorption， and high-pressure mercury intrusion. It systematically analyzed the reservoir stimulation mechanisms of SC-CO2 on four lithofacies shales in the Funing Formation of the Suibei Basin： felsic-clayey， felsic-dolomitic， felsic， and dolomitic. These findings indicate that after SC-CO2 soaking， carbonate minerals and organic matter dissolve preferentially， resulting in a passive increase in the relative content of quartz and clay minerals. The reconstruction of shale mineral composition leads to changes in pore structure， while the adsorption and swelling of clay minerals reduce micropore volume. Carbonate dissolution creates secondary pores， significantly increasing the throat radius. However， secondary precipitation clogs the throats， intensifying reservoir heterogeneity and reducing mesopore volume. Due to differences in mineral composition， the effects of SC-CO2 stimulation vary among different lithofacies shales. Felsic shales with high quartz content exhibit strong resistance to dissolution and are less affected. Dolomitic and felsic-dolomitic shales with high carbonate content are highly sensitive to SC-CO2 due to intense dissolution. Felsic-clayey shales， rich in clay， exhibit complex pore dynamic equilibrium constrained by mineral transformation and particle migration. This study provides a theoretical basis for CO2 injection in shale oil reservoirs to enhance oil recovery and carbon sequestration.
Clay minerals， such as kaolinite and montmorillonite， exhibit excellent adsorption capacities for CO2 and play an important role in CO2 sequestration in sedimentary strata like shales. To investigate the CO2 microscopic adsorption mechanism and their primary controlling factors in these typical clay minerals， this study constructed the molecular structure models of kaolinite and montmorillonite using the Materials Studio molecular simulation software. The adsorption behavior of CO2 within the pore structures of these clay minerals was simulated using the grand canonical Monte Carlo （GCMC） method. The results show that the dominant adsorption site of CO2 in kaolinite is the surface hydroxyl group， whereas in montmorillonite， it is the interlayer domain cation. Montmorillonite demonstrates a superior CO2 adsorption capacity and higher stability due to its stronger interlayer gas adsorption force. Clay mineral micropores have good adsorption stability for CO2. When the pore size increases， the adsorption capacity also increases， but it will lead to a decrease in adsorption stability. The increase in temperature has a negative impact on the CO2 adsorption performance of clay minerals. Conversely， the increase in pressure can promote the adsorption of CO2 by clay minerals， and this improvement effect is particularly significant within the lower pressure range of 0 to 5 MPa. Due to the coupling effect of both temperature and pressure with the increase in formation depth， Clay minerals mainly composed of micropores have the best adsorption efficiency at a depth from 2 to 3 km. The CO2 adsorption performance of hydrated clay minerals significantly declines due to the competitive adsorption effect of water molecules. A water saturation of only 20% can lead to a 20% to 35% reduction in the CO2 adsorption capacity of clay minerals at 20%. The microscopic adsorption mechanism and the key influencing factors of the adsorption process clarified in this study provide an important theoretical basis for evaluating the storage potential of clay minerals in CO2 geological storage and optimizing the practical application of CO2 geological storage.
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