The deep Lower Cambrian Qiongzhusi Formation in the Sichuan Basin represents an important strategic domain for shale gas exploration in China. However， its reservoir conditions and main controlling factors have not yet been fully understood by the exploration community and in academia. Based on core samples， experimental analyses， and well logging data， this study investigates the reservoir characteristics and main controlling factors of the Qioangzhusi shale through a detailed dissection of key evaluation wells （including WY1， Z201 and GS17） and regional geological analysis. These results indicate that the pore systems within the deep Qiongzhusi Formation are fundamentally similar to those of the Silurian Longmaxi Formation， primarily consisting of residual intergranular pores， unstable mineral dissolution pores， clay mineral intercrystalline pores， organic matter pores and microfractures. However， compared with the Silurian Longmaxi Formation， the reservoir space configuration of the Qiongzhusi Formation exhibits distinct spatial heterogeneity， showing a “dual-mode” reservoir behavior： （1） The middle and lower sections of the first member （Qiong 1） resemble typical shale gas reservoirs， dominated by clay mineral intercrystalline pores and organic matter pores （collectively exceeding 60% of the total pore volume）， with a matrix permeability comparable to that of the Longmaxi Formation. （2） Conversely， the second member （Qiong 2） behaves more like a tight gas reservoir， predominantly featuring brittle mineral intraparticle/interparticle pores and organic matter pores （together exceeding 86% of the total pore volume）， with a matrix permeability more than one order of magnitude higher than that of Longmaxi Formation. The development of high-porosity and high-pressure zones in the deep Qiongzhusi Formation is jointly controlled by undercompaction and hydrocarbon generation within thick， deep-water shelf mudstones. Specifically， undercompaction generates and preserves numerous brittle mineral pores， whereas hydrocarbon generation produces extensive organic pore networks and feldspar dissolution pores， while inducing overpressure. Comprehensive analysis indicates that the reservoir quality of the deep Qiongzhusi Formation varies significantly across the basin， controlled by a combination of three factors： the Caledonian-Hercynian paleo-uplift setting， the intensity of the Late Permian thermal events， and undercompaction. Among these， the Caledonian-Hercynian paleo-tectonic background is the primary factor driving the variations in physical properties. The Ziyang area was located at the structural high of the paleo-uplift for a long period during the Caledonian-Hercynian stage， and was minimally affected by the Emeishan mantle plume during the Middle-Late Permian. Its burial history closely resembles that of the Longmaxi Formation in southern Sichuan， favoring the development and preservation of undercompacted， high-porosity， and high-pressure reservoirs. In contrast， the Qiongzhusi Formation in the Weiyuan anticline and its western adjacent exploration areas not only experienced burial depths of 500-1 500 m during the Caledonian-Hercynian stage but was also overprinted by the extreme thermal event in the Middle-Late Permian； as a result， undercompaction zones are only locally developed or absent， leading to a higher degree of rock compaction. In other exploration areas， the Qiongzhusi Formation was mostly deeply buried below 1 500 m during the Caledonian-Hercynian stage， where undercompaction zones failed to develop， resulting in generally poor physical properties.
Focusing on the main controlling factors of hydrocarbon accumulation and enrichment in multiple reservoirs of the Jurassic Yan'an Formation within the Ordos Basin， this study investigates the Hongde-Yanwu area in the western part of the basin as the primary subject. Based on field outcrops， drilling， well logging， and 3D seismic data， the developmental characteristics and spatial distribution patterns of Mesozoic faults and fractures in this region were systematically interpreted. Combined with hydrocarbon inclusion thermometry， burial history， and quantitative grain fluorescence （QGF） analysis， the main controlling factors of hydrocarbon enrichment in the multi-layer reservoirs of the Yan'an Formation were comprehensively analyzed， and their hydrocarbon accumulation and evolution processes were explored. The results indicate that the Mesozoic faults and fractures in the study area are predominantly oriented in the east-northeast （ENE） direction， with a secondary orientation in the northwest （NW） direction， and the major faults exhibit strike-slip characteristic. The north-northeast trending faults and fractures were primarily formed and localized during the late Yanshanian period， serving as the main migration pathways for hydrocarbons in the Jurassic Yan'an Formation. The Jurassic strata primarily experienced a hydrocarbon evolution process characterized by “contemporaneous migration-accumulation and episodic charging”. Furthermore， three typical evolution models for reservoir accumulation were classified： the “dual-high” charging model， the “paleo-high/present-low” adjustment model. The study proposes that the “dual-high” type and “paleo-low/present-high” models represent significant potential targets for the precise exploration of Jurassic oil reservoirs.
The reservoir development mechanism and resource potential evaluation of ancient， over-mature shales represent critical scientific issues in shale gas research. Focusing on Well ZD2 of the Doushantuo Formation in western Hubei， this study systematically characterizes the geochemical， mineralogical， and pore network features of shales using total organic carbon （TOC） analysis， laser Raman spectroscopy， helium porosity， X-ray diffraction （XRD）， field emission-scanning electron microscopy （FE-SEM）， and low-pressure gas adsorption. A comparative analysis was also conducted with a regional reference well to investigate reservoir heterogeneity. The results show that： （1） The Doushantuo Formation in Well ZD2 is primarily composed of calcareous shale and mixed shale， with TOC contents ranging from 0.10% to 1.58% （averaging 0.74%） and equivalent vitrinite reflectance values of 3.09%-3.39% （averaging 3.24%）， placing the shale at the over-mature stage. （2） The total porosity of the shale ranges from 1.88% to 6.62% （averaging 3.64%）， constituting a well-developed organic-inorganic composite pore system. The clay mineral content shows significant positive correlations with micropore， mesopore， and total pore volumes. Conversely， secondary carbonate cementation exerts a destructive effect on porosity， with its sealing/inhibition effect outweighing the constructive contribution of dissolution-induced porosity. Although organic matter generally develops micropores and mesopores， its correlation with the overall pore volume is weak due to its low baseline abundance. （3） A comparison with the more organic-rich Well EYY1 （average TOC=2.23%） reveals that both TOC and respective mineral contents exhibit significant correlations with pore volume. This demonstrates that the Doushantuo Formation shale reservoirs are dually controlled by organic matter abundance and mineral diagenesis. These findings provide new insights into the differential development mechanisms of ancient shale reservoirs in western Hubei and offer valuable references for the exploration and avaluation of over-mature shale gas resources.
Deep coalbed methane （CBM） exploration and development in the northeastern slope area of the Ordos Basin has recently achieved major breakthroughs， with multiple wells， including Well Y1， yielding high-yield industrial gas flows， demonstrating immense resource potential. However， the occurrence states and transmission mechanisms of deep CBM remain unclear， which constrains the accuracy of reserve evaluation and the scientific understanding of gas production patterns. Focusing on the high-yield gas-bearing coal seams of the Shanxi and Taiyuan Formations in Well Y1， this study systematically characterizes the pore structure of deep coals using scanning electron microscopy （SEM）， CO₂ and N₂ adsorption， and high-pressure mercury intrusion （HPMI） experiments. Based on methane isothermal adsorption experiments and molecular numerical simulations， a free gas volume calculation model was established by hierarchically deducting the volume of adsorbed gas， thereby revealing the methane occurrence states within various pore structures. Finally， using the Knudsen number （K n）， the transport of free gas in deep coal was classified into four transmission mechanisms and their corresponding pore-size ranges. The results indicate that： （1）Deep coals are predominantly characterized by micropores （pore size d < 2.0 nm）. Among them， the micropores in the No. 8 coal seam of the Taiyuan Formation are the most developed， with the average micropore volume accounting for up to 61.2% of the total pore volume. （2）Methane in deep coal seams primarily occurs as micropore-filling adsorption， which chiefly takes place in micropores with d ≤ 1.5 nm. In pores with d ranging from 1.5 nm to 50 nm， monolayer adsorption and free gas coexist， whereas pores with d > 50 nm are dominated by free gas. Notably， the No. 8 coal seam of the Taiyuan Formation exhibits “dual-rich” characteristics， harboring high volumes of both adsorbed and free gas. （3）The transmission of deep CBM is dominated by Darcy flow， which accounts for an average of 52.4% of the total transport. A higher proportion of Darcy flow is highly beneficial for the efficient exploitation of deep CBM. Consequently， the No. 8 coal seam， which possesses the “dual-rich” characteristics， represents the primary target for further exploration and development. This study provides a theoretical basis and technical support for the resource evaluation and development of deep CBM in similar regions.
The 8# coal seam of the Upper Carboniferous Benxi Formation in the Yichuan area of the Ordos Basin， with a burial depth of 1 800-2 500 m， is a key target for deep coalbed methane （CBM） exploration. In this study， geological exploration achievements and drilling production data were comprehensively utilized to conduct experimental analyses， including isothermal adsorption and gas content tests， integrated with microscopic characterization methods such as scanning electron microscopy （SEM） and full-diameter CT scanning. We systematically investigated the occurrence characteristics， coal petrology and quality， pore-fracture structure， and gas-bearing properties of the coal seam， identified the main controlling factors for methane enrichment， and carried out a comparative study on the accumulation model with the adjacent Daning-Jixian block. The results show that the 8# coal seam is dominated by bright and semi-bright primary structural coal， with an average vitrinite content of nearly 80% （vol.） and a mean vitrinite reflectance （R O） of 2.92%， placing it at the over-mature stage within the anthracite rank. It is characterized by low to medium-low ash content， ultra-low volatile matter， ultra-low moisture， and high fixed carbon. Micropores account for up to 83.65% of the total pore volume in the pore-fracture system， forming the core storage space for adsorbed gas. Combined with well-developed macropores and dense cleats， it constitutes a gas storage model featuring the “coexistence of adsorbed and free gas in dual states”. Gas-bearing analysis indicates that the average total gas content of the coal seam is 30.33 m³/t， with the peak free gas fraction reaching 34.12% and the gas saturation ranging from 102.5% to 151.8%， exhibiting “high gas content， high free gas abundance， and supersaturation” characteristics. The enrichment and accumulation of deep coalbed methane in this area are controlled by three key factors： （1） The complete cap rock system composed of limestone-mudstone double layers in the roof and floor effectively blocks the vertical escape of gas； （2） The weak hydrodynamic stagnant environment formed by high-salinity CaCl₂-type formation water inhibits the lateral migration of gas； （3） The increase in burial depth under the background of the west-dipping monocline structure （slope < 2°） leads to the enhancement of reservoir pressure， which strengthens gas adsorption and preservation. These factors jointly contribute to the complete accumulation model of “widespread hydrocarbon generation， box-type preservation， microstructural adjustment， and self-contained source-and-reservoir” in the study area. This research deepens the understanding of deep coalbed methane accumulation theories in the Ordos Basin and provides a scientific basis for the exploration and development in the Yichuan area.
To reveal the sedimentary characteristics and distribution patterns of deep-water gravity flows in the seventh member of the Triassic Yanchang Formation （the Chang 7 Member） in the southern Ordos Basin， this study systematically analyzes the types and controlling factors of gravity flow deposits in the Xunyi area based on core observations， well logging， mud logging， and grain size analysis. A deep-water gravity flow depositional model was established. The findings are as follows： （1） The Chang 7 Member in the Xunyi area exhibits four gravity flow microfacies： sandy debris flows， turbidity currents， slump deposits， and lacustrine mudstone/shale. The steep lake basin topography， abundant bidirectional sediment supply， and frequent seismic and volcanic activities triggered by the Indosinian orogeny serve as the topographic foundation， material source， and key triggering mechanisms for gravity flow development， respectively. （2） Along the sediment transport direction， a distinct deep-water sedimentary transition is observed： delta-front sands-slump deposits-sandy debris flows-turbidity currents. （3） The sandy debris flow sandbodies in the Chang 7 Member， characterized by superior reservoir properties and strong hydrocarbon shows， represent the most favorable microfacies. Their frequent interbedding and vertical stacking with high-quality lacustrine mudstone/shale form an excellent， intimately coupled source-reservoir symbiotic system， highlighting the significant hydrocarbon exploration potential of these gravity flow deposits in the area. These results provide robust support for increasing reserves and production in the Triassic Yanchang Formation of the Xunyi area， Ordos Basin.
As an important natural gas production area in China， the Jingbian Gas Field in the Ordos Basin has achieved a cumulative natural gas output of 1 121×10⁸ m³ by 2024 after more than 20 years of exploration and development. However， the Ma5₁₊₂ reservoir of the gas field is characterized by a high degree of reserve production， scattered distribution of remaining geological reserves， complex development of erosion grooves， and a low drilling encounter rate of the main gas-producing Ma5₁³ layer. Given that the pre-Carboniferous karst palaeogeomorphology plays a decisive role in the reservoir development and distribution of the Lower Paleozoic gas reservoirs in the Jingbian Gas Field， accurately reconstructing the karst palaeogeomorphology of this period and finely characterizing the palaeogrooves have become the key to addressing the above problems. On the basis of sorting out the principles， technical characteristics， application effects and limitations of existing palaeogeomorphology reconstruction methods in the gas field， this paper innovates a quantitative palaeogeomorphology reconstruction and groove identification method. The specific technical innovations include： （1） Considering the influence of palaeotectonics and weathering denudation on palaeogeomorphic forms， a quantitative palaeogeomorphology reconstruction method with sedimentary thickness compensation is innovated on the basis of palaeogeomorphology reconstruction from arbitrary horizontal data， realizing the synchronous reconstruction of palaeogeomorphology and palaeotectonics， and effectively distinguishing the geomorphic units of grooves， sinkholes and depressions. （2） A developmental model of karst paleogeomorphology in the gas field was established. It is proposed that hydrodynamic conditions were relatively strong in the karst slope zone， where grooves were predominantly developed， whereas hydrodynamic conditions were weaker on the karst platform and in the karst basin， where sinkholes were mainly developed. The macroscopic distribution patterns of grooves and sinkholes were clarified， providing guidance for their identification and characterization. （3） According to the sedimentary contact relationship between karst palaeogeomorphology and the second member of the Benxi Formation， and based on the theory of valley-controlled sand bodies， four types of identification models for grooves and sinkholes are proposed according to the sand-mud assemblages of the second member of the Benxi Formation， thus enabling the accurate identification of grooves and sinkholes. Combined with the palaeogeomorphology reconstruction with sedimentary compensation thickness and the karst development model， the comprehensive and fine identification of the three-level geomorphic units of the pre-Carboniferous karst palaeogeomorphology is realized. Through the application of the above technologies， the inter-well remaining reserves misidentified as grooves and depressions are released， increasing the gas-bearing area by 775 km². In the past two years， the drilling encounter rate of Ma5₁³ layer， the main layer of the Ma5₁₊₂ reservoir， in newly drilled development wells has reached 95%， and the effective reservoir drilling encounter rate has reached 83%， which is equivalent to the drilling level in the initial development stage. It is concluded that the constructed quantitative palaeogeomorphology reconstruction system for karst gas reservoirs solves the problem of low drilling encounter rate of main reservoirs in the middle and late development stages of the Jingbian Gas Field， which can effectively support the stable production technical adjustment of the Lower Paleozoic gas reservoirs in the Jingbian Gas Field， and has important reference significance for the development of similar gas reservoirs.
The Ordos Basin represents a key strategic domain for unconventional gas resources hosted in deep marine carbonate sequences. A thick gypsum-salt interval in the 5th member of the Majiagou Formation（Ma 5 Member） serves as an effective regional cap rock， isolating the underlying carbonate reservoir in the Ma 4 Member. Well MT1 achieved a high-yield industrial gas flow from the Ma 4 Member， marking a significant breakthrough in sub-salt natural gas exploration in the eastern Ordos Basin. However， the thermal effects of gypsum-salt on sub-salt source rock maturation remain poorly understood. Based on geological and geophysical data from Well MT1， this study integrates numerical modeling to quantify the influence of salt structures on geothermal field and source rock thermal evolution. The results indicate that the high thermal conductivity of the gypsum-salt acts as a thermal “chimney” rapidly transferring heat upward. This process elevates the temperature of overlying strata， lowers the temperature of underlying units， and significantly modifies the regional heat-flow distribution. Anticlinal salt structures exert stronger cooling effects on underlying formations than mound-shaped salt structures， thereby delaying the maturation of underlying source rocks. Basin modeling further suggests that， under the with-salt scenario， the Ma 1 Member source rock reached the hydrocarbon-generation threshold （R O=0.5%） approximately 8.5 Ma later than in the without-salt scenario， and the final R O at the base differs by ~ 0.1%. These findings demonstrate that the salt-related thermal effect is a major control on sub-salt hydrocarbon generation efficiency and charge timing. This work elucidates the distinctive thermal evolution mechanism of sub-salt carbonate gas reservoirs and provides thermodynamic constraints for sub-salt exploration in the Ordos Basin.
The Shan 1 to He 8 members at the northern margin of the Ordos Basin represent a critical period of transition from an epicontinental sea to an inland downwarped lake basin， and they constitute an important target interval for natural gas exploration in the Su 5 block. The detailed distribution of sedimentary sand bodies and the spatiotemporal evolution of microfacies， constrained by source-to-sink processes， are of great significance. Based on data such as core observations， drilling and logging curves， and grain size analysis， this paper clarifies the high-precision sedimentary microfacies evolution process of the Shan 1 to He 8 members in the Su 5 block， and identifies the sedimentary microfacies evolution model based on fluvial transformation processes and its response to source–sink processes in the northern Ordos Basin. Two major sedimentary systems， meandering rivers and braided rivers， are developed in the Shan 1 to He 8 members， encompassing seven types of microfacies associations including beach-bar cores， beach-bar margins， and channels. The sedimentary evolution exhibits clear stages： the Shan 1 Member is characterized by low-energy meandering river deposits， with isolated sand bodies and vertical superimposition， influenced by a humid climate and weak tectonic activity； the lower submember of the He 8 Member evolved into high-energy braided river deposits， with strongly connected and laterally continuous sand bodies， as enhanced tectonic activity led to a sharp increase in the flux of proximal coarse clastic materials； the upper submember of the He 8 Member is in a transitional stage from braided rivers to meandering rivers， with gradual topographic filling and leveling， significant meandering characteristics in the southern part， and continuous expansion of floodplain subfacies. During the sedimentary period of the Shan 1 to He 8 members， the provenance area shifted from a distal source to a proximal source， and then gradually stabilized under the filling and leveling process. These drove the sedimentary system to evolve from an initial low-energy meandering river supplied by sediments from the west to a high-energy braided river supplied by sediments from the northeast， and after stabilization， a sedimentary pattern of coexisting meandering and braided rivers gradually formed. This study provides a new perspective and scientific basis for the reconstruction of the Late Paleozoic paleogeography in the northern Ordos Basin and has important guiding significance for oil and gas exploration in this area.
Tight sandstone gas reservoirs of the Fifth Member of the Xujiahe Formation in the Jianyang area exhibits significant exploration potential. To deepen the understanding of the geological conditions for this self-contained source-and-reservoir tight gas reservoir， this paper presents a systematic study on the depositional environment， the relationship between sandstone and mudstone stacking， and the sedimentary microfacies evolution of the fifth member of the Xujiahe Formation in the Jianyang area. Based on the Jianyang area of central Sichuan and Well YQ1 as research subjects， and utilizing drilling and logging data， whole-interval major-trace-rare earth element analysis， and 3D seismic data， this study systematically reveals the paleoenvironmental characteristics of the Jianyang area and clarifies the microfacies evolution and its controlling factors under sedimentary environmental constraints. The study area primarily developed subaqueous distributary channels， mouth bars， distal bars， lakeshore beach-bars， and shallow lake mud microfacies. During the early depositional stage of the early lower submember of the Xu5 Member， the northwestern Longmenshan thrust-nappe belt entered a tectonic dormant period. Under a warm and humid climate， the water body was relatively deep-as indicated by the average Rb/Zr ratio of 1.42. Fed by the Jiangnan-Xuefeng paleocontinent， sheeted lakeshore beach-bar microfacies developed in the Jianyang area. During the depositional period of the late lower submember of the Xu5 Member， the climate was warmer and more humid. This period was a reductive environment with deeper anoxic waters. The sediments originating from the Jiangnan-Xuefeng tectonic zone developed a large area of punctate lake-wave-modified lakeshore beach dams. During the depositional period of the upper submember of the Xu5 Member， the uplift of the Jiangnan-Xuefeng tectonic zone continued to strengthen， the lake level slowly declined. The input of land provenance and sedimentation rate increased significantly. The development of the southeast-northwest oriented braided-river delta deposition was carried out. During this period， the deltaic sand body with large thickness and the lake-phase mud shale were developed with lateral buttressing and vertical stacking and having advantages of near and within reservoir accumulation. The sedimentary microfacies evolution study demonstrates the good source-reservoir configuration relationship and resource prospect of the tight gas reservoirs of the 5th member of the Xujiahe Formation in the Jianyang area， and provides a theoretical basis for further exploration and evaluation of the gas reservoirs within its provenance.
The exploration practice reveals that the Early Paleozoic platform margins of the three major craton basins in central and western China have great exploration potential， and the platform margins of the Sichuan Basin and the Tarim Basin have become the main battlefield for large-scale oil and gas exploration. In contrast， the discovery of oil and gas in the platform margin of the southern margin of the Ordos Basin is unsatisfactory. Because of the long-term controversy over its development location and distribution characteristics， and the strong transformation in the late Cambrian-Ordovician， the complex accumulation conditions， and the low degree of research and exploration， it has become a bottleneck restricting the basin resource evaluation and oil and gas exploration breakthrough. This study focuses on the Linyou-Chunhua area in the southern margin of the Ordos Basin. Based on the latest two-dimensional seismic data， peripheral drilling and regional geological data， it is innovatively proposed that the Cambrian in this area has the geological conditions for the development of large-scale platform margin zones， and the Cambrian-Ordovician tectonic-sedimentary evolution model is reconstructed ： the tectonic evolution sequence dominated by the Caledonian thrust is established， and the previous understanding of the dominance of the strike-slip faults in the Yanshanian period is revised. The sedimentary reveals the characteristics of multi-stage superimposed migration of mound-shoal bodies under the background of steep slope and narrow platform margin. Through the fusion technology of paleogeomorphology restoration and seismic sensitive attributes， the multi-stage large-scale mound-shoal bodies of Cambrian and Ordovician are finely identified. Based on the analysis of source-reservoir-cap conditions， a new hydrocarbon accumulation model featuring “large-scale development of platform margin mound-shoal bodies， hydrocarbon supply from high-quality shelf source rocks， and multi-stage 3D accumulation within mound-shoal bodies' was constructed， and it is clear that the central thrust-related anticlinal belt is a favorable exploration target area. The research results provide a new theoretical and decision-making basis for oil and gas exploration in the southern Ordos Basin. The results deepen the understanding of the evolution-reformation and hydrocarbon accumulation characteristics of the platform margin during the transformation from passive continental margin to active continental margin， and have important reference significance for the exploration of other similar tectonic background basins.
Accurate identification of reservoir fluids is a core task in oil and gas exploration and development. However， industry‑wide data are commonly constrained by inherent subsurface complexity， limited sample sizes， and high annotation costs. In addition， discrepancies in data dimensions and mismatched feature distributions between while‑drilling and completion stages further degrade the recognition accuracy and generalization ability of conventional machine learning methods. To address these challenges， this paper proposes an innovative few‑shot deep learning approach based on knowledge distillation. A teacher-student model architecture is constructed， where knowledge distillation is used to transfer the geological knowledge embedded in “privileged” data such as post‑drill wireline logging measurements into the student model， which relies only on while‑drilling data. The proposed method effectively mitigates data heterogeneity across different stages and enables accurate and robust identification of reservoir fluids from while‑drilling data under few‑shot conditions. Validation results on real datasets from the Xihu Sag and Huanghekou Sag demonstrate that the method significantly outperforms traditional machine learning algorithms in key evaluation metrics including precision， recall， and F1‑score， showing superior performance for while‑drilling applications. This work not only resolves critical difficulties in fluid property identification under data‑scarce scenarios but also establishes a highly scalable technical framework， providing a new technical pathway for few‑shot learning research in petroleum geology.
In reservoirs with low porosity and permeability， complex lithology， or complex hydrocarbon compositions， fluid responses on conventional logging curves are generally weak and indistinct， making it difficult to accurately identify reservoir types using conventional logging data alone. Therefore， when pressure-temperature （P-T） phase diagrams of multi-component hydrocarbon systems are available， the serve as the fundamental basis for identifying fluid phase states. However， the current manual and qualitative identification methods using P-T phase diagrams are incapable of rapidly quantifying the gas-oil ratio （GOR） and liquid content， resulting in low accuracy and poor time efficiency. To address these challenges， this paper presents a key algorithm designed to automatically determine the spatial relationship of the formation temperature-pressure point relative to the phase envelope and quality lines （iso-volume fraction lines） in a P-T phase diagram. Furthermore， based on these distinct positional relationships， the liquid oil volume fraction and free GOR under reservoir conditions can be calculated， enabling the estimation of the surface production GOR. Application examples show that by utilizing true vertical depth alongside temperature and pressure gradients， this automatic quantitative calculation method can generate a vertical profile of liquid oil volume fractions and GORs（free GOR under reservoir conditions and surface production GOR） that varies continuously with reservoir depth. The estimated surface production GOR is within the same order of magnitude as the well-test results. Furthermore， compared with the statistically derived stable production GOR and the GOR values analyzed from well stream fluid compositions， the relative error is less than 27%. This overcomes the long-standing bottlenecks of low efficiency and poor applicability associated with manual P-T diagram calculations. By analyzing the varying trends of underground free GOR with depth and the estimated surface production GOR， combined with the statistical distribution ranges of GORs across different reservoir types and their corresponding log responses， the fluid occurrence states and reservoir types can be precisely determined under formation conditions. This quantitative evaluation approach eliminates the ambiguity inherent in fluid identification using conventional logging data alone， thereby significantly improving the coincidence rate of reservoir fluid type identification via P-T phase diagrams.
As a clean and low-carbon natural energy source， natural hydrogen holds significant strategic importance for promoting energy structure transformation. However， the logging response mechanism of hydrogen-rich reservoirs remains unclear， and effective identification and evaluation methods are lacking， which restricts the exploration process of subsurface natural hydrogen resources. This paper aims to reveal the response laws of density and neutron logging in hydrogen-rich reservoirs through numerical simulation and to establish identification standards for distinguishing natural hydrogen from conventional natural gas （methane）. Based on the Monte Carlo simulation method， quantitative calibration relationships were first established for water-saturated limestone， correlating density logging count rates with formation density， and neutron logging long/short-spacing count ratios with porosity （hydrogen index）. Subsequently， the density and neutron logging response characteristics of hydrogen-rich reservoirs were simulated under varying porosity and hydrogen saturation conditions. Finally， a sensitivity analysis was conducted by comparing the differences between hydrogen and methane on density-neutron crossplots and neutron/density porosity ratio vs. gas saturation crossplots. The simulation results indicate that： （1）The presence of hydrogen leads to a decrease in apparent formation density， and the magnitude of this decrease expands with higher porosity. （2）Hydrogen-rich reservoirs exhibit a strong “excavation effect” on neutron logging， meaning that the apparent hydrogen index decreases significantly as hydrogen saturation increases. （3）On both the density-neutron crossplot and the neutron/density porosity ratio vs. saturation crossplot， hydrogen-rich reservoirs and methane-bearing formations both display “low density and low neutron” characteristics. However， as hydrogen saturation increases， the decline in the neutron/density porosity ratio is more drastic for hydrogen-rich reservoirs， becoming significantly lower than that of conventional methane reservoirs under identical gas saturation conditions. In conclusion， the combined application of density and neutron logging provides an effective approach for identifying hydrogen-rich reservoirs using conventional logging data. Hydrogen-rich reservoirs possess a unique “double low”（low density and low neutron） response pattern， and their “excavation effect” intensity is higher than that of conventional gas layers.
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