China is abundant in natural gas resources， and the role of large gas fields as a cornerstone in the development of the natural gas industry is particularly prominent. By 2025， China's annual natural gas production had reached 2 619×108 m3， elevating the country to the fourth-largest gas producer globally， with large gas fields contributing approximately 75% of the total output. Confronting China's complex surface and subsurface challenges-ranging from conventional structural， stratigraphic-lithologic gas fields to unconventional tight gas， shale gas， and coalbed methane gas provinces-the theories and technologies concerning the formation and distribution of large gas fields have continuously evolved. This evolution has progressed from traditional， qualitative， broad-brush approaches to semi-quantitative and quantitative assessments of prospective zones. This progress has guided and propelled the continuous development and growth of China's natural gas industry system， exemplified by major gas provinces such as the Ordos， Tarim， and Sichuan basins. Research into the quantitative and semi-quantitative indicators of formation conditions and main controlling factors for China's large gas fields， which began in the 1980 s， has culminated after nearly 40 years of persistent effort. This study systematically proposes a set of core quantitative evaluation indicators and main controlling factors for hydrocarbon accumulation in China’s large gas fields. These include：Enrichment in gas generation centers and their periphery with sufficient generative intensity（generally exceeding 20×108 m3/km2）， late-stage accumulation（since the Paleogene and Neogene periods， i.e.， 65 Ma before present）， and enrichment in areas with relatively low gas potential areas（relatively low-value zones）. The construction and development of this semi-quantitative to quantitative evaluation indicator system represent a quantitative leap and an applied guideline for natural gas geological theory， advancing from “generation mechanisms-genetic identification-quantitative evaluation”. It holds milestone significance in theoretical innovation， technological application， and industrialization. This system has propelled the leapfrog development of China's natural gas industry from theoretical innovation to production capacity construction， exerting a profound influence on both domestic and international academic and industrial circles. Its core contribution lies in transforming geological principles into operational exploration evaluation methods. In the new era， innovating and developing this quantitative-semi-quantitative evaluation indicator system provides a Chinese solution for the exploration of complex natural gas reservoirs and associated resources globally， carrying significant practical implications.
China holds vast tight oil resources， but their poor reservoir quality requires hydraulic fracturing-typically combined with horizontal wells-for efficient development. However， multi-stage fracturing is strongly influenced by in-situ stresses， fracture interactions， and operational parameters， leading to unpredictable fracture geometry and suboptimal stimulation design. Conventional models either lack accuracy or are too computationally expensive for field-scale optimization. To address this， we develop an improved Displacement Discontinuity Method （DDM）-based multi-fracture propagation model that couples fluid flow and rock deformation. The model enables real-time updating of reservoir properties under fracturing-induced stress changes and incorporates the impact of adjacent-well fracturing through dynamic data synchronization between local fracture solutions and a global block model. An SRV quantification workflow is thus established for rapid and accurate estimation of porosity and permeability evolution. Applied to Wells T28 and T104 in the block P8 of Daqing Oilfield， the model achieves fracture geometry fitting accuracies of 91% and 93%-outperforming finite element simulations （88% and 85%）-and yields production history matches of 93% and 95%， demonstrating its reliability and practical value for optimizing tight oil recovery.
The ultra-deep fractured gas reservoirs generally have deep burial， high pressure， tight matrix and multi-scale fracture development in Kuqa Depression， Tarim Basin， the production capacity varies greatly between blocks and wells. In particular， the production of some wells is as high as 10 million cubic meters every day， which is 3-5 times different from the production capacity of adjacent wells. There is little research on productivity calculation models for ultra-deep fractured gas reservoirs in existing literatures， and there is an urgent need to systematically study the factors affecting the production capacity of such gas reservoirs and establish new effective production capacity evaluation methods. Based on the analysis of the correlation between factors such as geology， drilling and completion， a productivity prediction model considering factors such as non-Darcy flow， stress sensitivity and material balance is established. The research results show that： （1） The factors affecting the productivity of gas wells include tight reservoir matrix， geological characteristics of fracture development， drilling pollution， completion pollution， well type， matching degree of perforation and fractures， production well clearance under the condition of large pressure difference， wellbore pressure loss， etc. （2） By regressing the parameters such as fracture dispersion coefficient， linear density， flowback rate， etc.， which are critical to gas well productivity， fracture characterization parameters are constructed. （3） The proportion of productivity contribution of fracture system and matrix system is logarithmic with the permeability range. （4） The production capacity evaluation process is formed， and the error between the production capacity of Well A-1 calculated by the model and the test results is less than 2%.
For many years， the exploration of natural gas in the large structural belts of the northern Qaidam Basin have been unsatisfactory， which may be related to the traditional understanding of deep-seated paleo-anticlinal traps under the dual-layer structural model. Through seismic data interpretation and analysis， it is concluded that the structural style of this area is mainly of synsedimentary compressional strike-slip structures developed in the late Himalayan period. The strong deformed ones usually are ruptured anticlines with fault extending to the surface resulting in low abundance traps of underfilled gas accumulation， while the gentle anticline of Chahan which developed as synsedimentary overlying anticline over uplifting blocks faulted by compressional strike slip movement at depth is of high effect. Because strike slip belt moved only along fault within the linear band， the sags between them usually are of weak deformation which is conducive to the preservation of gas reservoirs and is a favorable area for gas exploration. Pingdong Sag located among Altun， Jianshan and Eboliang belts is of gentle deformation during the Cenozoic and exhibits relatively complete distribution of three Mesozoic-Cenozoic tectonic layers containing whole geologic elements of gas system. The deep Jurassic source rocks within the sag are of larger thickness and stable distribution which is currently in the stage of gas generation suggesting gas accumulating at the later Himalaya stage. The faulted block structure of the lower tectonic layer in the Cenozoic era created a migration-accumulation system. The lower Youshashan Formation （N2 1） delta front sand bodies and mudstone layer above formed an ideal reservoir-cap assemblage， while the lacustrine mudstone and evaporite in the upper tectonic layer （N2 2， N2 3， Q） offered an ideal regional seal for gas pools. Analysis suggests that the Chahan anticline over source rock developed contemporaneously with major gas generation and is a potential large gas field. Subtle traps beneath the regional cover layers such as low amplitude anticlines， fault blocks， lithological traps on tectonic setting， and fault-sandstone combinations within sub-sags in the Pingdong Sag are favorable exploration areas for natural gas. This study also has reference significance for natural gas exploration in areas similar to the tectonics of the Qaidam Basin.
The Kuqa Depression exhibits substantial exploration potential， with the Dibei area representing a significant breakthrough region for tight gas exploration in the Ahe Formation in recent years. To address rapid lithological and grain-size variations and strong heterogeneity within the Ahe Formation reservoirs， this study utilized integrated data from cores， thin sections， whole-rock and clay X-ray diffraction， and well logs to systematically classify reservoir lithofacies types， elucidate the characteristic differences among various lithofacies， delineate the distribution of superior reservoir zones， and reveal the genetic mechanisms of tight reservoirs. The results indicate： （1） The Ahe Formation reservoirs in the Dibei area are classified into four lithofacies： Lithofacies A （dominated by coarse sandstone and sandy conglomerate）， B （primarily medium-to-coarse sandstone）， C （mainly fine-to-medium sandstone and siltstone）， and D （comprising siltstone and mudstone）. Laterally， Lithofacies A is predominantly distributed in the northern and eastern parts of the D2 structural zone and the eastern part of the D14 structural zone； Lithofacies B is widely distributed； while Lithofacies C and D are concentrated in the western segment of the D2 structural zone. Vertically， the middle to upper subunits are dominated by coarse-grained Lithofacies A and B， whereas the lower subunit is mainly composed of fine-grained Lithofacies C and D. （2） Diagenetic pathways exhibit facies-controlled divergence： coarse-grained Lithofacies A and B， characterized by rigid grain support， inhibit compaction and are dominated by dissolution that enhances secondary porosity development， resulting in high pore abundance and improved connectivity. In contrast， fine-grained Lithofacies C and D undergo intense compaction and cementation， with pores dominated by micropores and poor interpore connectivity. （3） Lithofacies exert significant control on reservoir quality： coarse-grained Lithofacies A， experiencing weak compaction， strong dissolution， and weak cementation， exhibits the best petrophysical properties （porosity： 6.22%； permeability： 2.72×10-3 µm2） and develops a composite pore network of dissolution pores and microfractures； Lithofacies B shows relatively good properties （porosity： 5.02%； permeability： 1.13×10-3 µm2） with weak compaction， relatively strong dissolution， and weak cementation； whereas Lithofacies C and D， affected by intense compaction and cementation， display limited porosity development and the poorest reservoir quality. This study reveals that the synergistic effects of sedimentation and diagenesis primarily govern reservoir heterogeneity， providing key geological insights for the efficient exploration of tight gas in the Kuqa Depression.
In view of the outcrops of Chang 7 Member in the southern section of Ordos Basin， the characteristics of sedimentation and reservoir quality distribution were studied by field survey and comprehensive testing methods. The research results showed the following. （1） The sedimentary facies types and sedimentary characteristics of hyperpycnal flow are clarified， and the identification marks of hyperpycnal flow are determined. The sedimentary characteristics of the Chang 7 Member include： cross bedding， climbing bedding， reddish-brown mud gravel， yellow-brown cladding mud gravel， reverse-normal grain sequence combination， bimodal characteristics of grain size frequency curve and intra-layer micro-erosion surface. （2） The types of sedimentary microfacies of hyperpycnal flow in the study area are divided， and the difference characteristics of reservoir quality at different scales are clarified. According to the lithology and configuration characteristics， three sedimentary microfacies are divided： branch channel， lobe body and lobe body edge. In terms of architecture characteristics， there are various superposition patterns between sand bodies. The reservoir quality of branch channel microfacies is better than that of lobe body and lobe body edge microfacies. The reservoir quality of sand body with larger thickness of the same sedimentary microfacies is better， and the reservoir quality of the middle and upper parts of single sand body is better than that of the lower part. （3） The controlling factors of the reservoir quality difference of hyperpycnal flow are revealed， and the formation mechanism of the difference is clarified. Reservoir quality is affected by mineral composition， provenance， grain size and sorting， sand body thickness and diagenetic fluid. Feldspar content， grain size， sorting and sand body thickness are the main controlling factors of reservoir quality. Based on the characteristics and differences of diagenetic evolution， eight diagenetic evolution units are established， among which the best reservoirs are developed in the middle and upper parts of the thick sand of the branch channel， the middle part of the thick sand of the lobe body and the middle part of the sandstone of the lobe body edge with tuffaceous sandstone. The research results can provide geological basis for the prediction and potential evaluation of high-quality tight sandstone reservoirs in the Chang 7 Member.
The central and eastern Ordos Basin is abundant in oil and gas resources but faces challenges due to unclear dynamics boundaries and distribution laws. To address this， based on logging and testing data， methods like reservoir physical property statistical analysis， driving force contribution analysis， case analysis， numerical simulation analysis， dry layer ratio analysis and hydrocarbon saturation analysis were employed. The lower limit of buoyancy accumulation and the bottom limit of hydrocarbon accumulation were determined. The free and confined dynamic fields were divided， and the boundary of unconventional tight oil and gas reservoirs was defined. Results show that the burial depth for the lower limit of buoyancy accumulation is 1 350-1 750 m， with porosity of 10% and permeability of 1×10-3 μm2. The critical porosity for the bottom limit of accumulation is 2%， corresponding to a burial depth of 5 060-5 224.98 m. In the free dynamic field， oil and gas concentrate in high-structure traps， with reservoir porosity >10% and permeability >1×10-3 μm2. In the confined dynamic field， they concentrate in high-structure， depression， and slope areas， with porosity of 2%-10%. These findings guide unconventional oil and gas exploration in the region.
Both the Sinian-Cambrian reservoirs in the Anyue Gas Field and the Permian-Triassic reservoirs in northeastern Sichuan are hosted in dolomite formations. They have undergone comparable deep burial and high-temperature evolution， as well as paleo-oil cracking processes； however， compared with the latter， the former exhibits a notably lower H₂S concentration. The controlling factors responsible for this discrepancy remain insufficiently and unsystematically understood. In this study， gas geochemical and formation water data were obtained from 13 wells in the Anyue Gas Field and compiled from 79 wells previously reported from the Sinian-Cambrian reservoirs in central Sichuan and the Permian-Triassic reservoirs in northeastern Sichuan. By integrating analyses of gas composition， carbon and hydrogen isotopes， sulfur isotopes， elemental composition of reservoir bitumen， hydrocarbon generation potential， burial and thermal histories， and sulfate ion concentrations in formation water， the causes of H₂S content differences between the two regions were systematically investigated. Four major conclusions were drawn： （1） In both regions， H₂S is primarily generated through thermochemical sulfate reduction （TSR）. （2） Differences in hydrocarbon supply capacity and petroleum system evolution are not the dominant controls on the distribution of H₂S-bearing reservoirs. （3） The sources of SO₄²⁻ differ between the two areas. In the northeastern Sichuan Feixianguan Formation， sulfur is mainly derived from anhydrite layers or nodules within the reservoir， whereas in the Changxing Formation and the Sinian-Cambrian reservoirs of central Sichuan， sulfur predominantly originates from sulfate released during dolomitization. Because the lattice-bound sulfate （CAS） content in central Sichuan dolomites is significantly lower than that in the Changxing Formation， the sulfate supply is relatively limited， resulting in weaker TSR intensity. （4） Formation waters in the northeastern Sichuan Permian-Triassic reservoirs generally exhibit higher SO₄²⁻ concentrations， and high-H₂S reservoirs spatially correspond to sulfate-enriched strata. In contrast， formation waters in the Anyue Gas Field often contain SO₄²⁻ concentrations below detection limits. Thus， variation in SO₄²⁻ concentration in formation water is the principal cause of H₂S content differences between the two regions. These findings provide critical theoretical insights into the controlling factors of H₂S variability and TSR intensity in sulfur-bearing gas reservoirs， and offer valuable guidance for the safety exploration of such reservoirs.
The discovery of an abnormal high-pressure reservoir in the Funing Formation of the Gaoyou Sag， Subei Basin， is opening new prospects for the sustainable development of oilfields. Paleo-fluid pressure was calculated using fluid inclusions， while PetroMod simulated the pressure evolution history of the Funing Formation. The origin and evolution of overpressure were investigated using a combination of multiple logging methods， Bowers’ method， and the velocity-density cross-plot method， along with logging data and shale porosity. The results indicate that vertically， overpressure occurs from the middle part of E1 f 4 to the top of E1 f 1. Overpressure is confined to the inner slope area with relatively low amplitude （the maximum pressure coefficient at present is approximately 1.5）. Abnormal high pressure within the mudstone sections of E1 f 4 and E1 f 2 was not caused by disequilibrium compaction， but rather by hydrocarbon generation pressurization. Overpressure in the E1 f 1 and E1 f 3 reservoirs is attributed to pressure transmission. Abnormal high pressure in the Funing Formation emerged as early as the Dainan sedimentary period. Formation pressure underwent a rapid increase before 37 Ma， followed by a rapid reduction during 37-23 Ma， and then a slow rise from 23 Ma to the present. However， the present pressure has not fully recovered to its peak geological levels. Abnormal pressure systems control hydrocarbon accumulation through the “migration-driving force-conduit-seal” tri-element coupling mechanism， whose dynamic evolution and matching degree with tectonic-sedimentary activities determine the extent of hydrocarbon enrichment. This research provides a significant theoretical foundation for expanding hydrocarbon exploration in the inner slope of the Gaoyou Sag.
The 21/27 structure in the southwestern Huizhou Sag of the Pearl River Mouth Basin is a key target area for oil and gas exploration in the South China Sea， and the volcanic reservoir of the Paleocene Shenhu Formation has seriously constrained the exploration and development of oil and gas reservoirs in the zone due to the complexity of the lithology and lithofacies and the lack of clarity of the reservoir mechanism. This study is aimed at the mechanism and prediction of volcanic reservoirs in this area， and for the first time， through the fusion of seismic， drilling， logging and physical thin section multi-source data， systematically reveals the lithological and petrographic differentiation law of the volcanic reservoirs and the spatial evolution mechanism of the reservoirs. The results of the study show that： （1） the volcanic reservoirs of the Paleocene Shenhu Formation in the 21/27 structure of Huizhou Sag are composed of seven lithologies， which belong to five categories and eight subclasses of petrographic types， among which the eruptive phase and the volcanic conglomerate in the volcanic channel phase are conducive to the development of high-quality reservoirs； （2） the main storage space of Cenozoic volcanic mainly consists of secondary lysimetric holes and fractures， and the second dissolution of organic acids is the key to the formation of high-quality reservoirs； （3） based on the study of reservoir development mechanism， we have constructed a reservoir development model of “dominant lithofacies controlling reservoir-organic acid dissolution increasing pore-structural activity expanding fracture”， which is a breakthrough from the traditional theoretical framework of single reservoir formation. The research results provide a theoretical model for the exploration of complex volcanic oil and gas reservoirs， which is of great significance for theoretical innovation and practical guidance for the exploration of volcanic oil and gas in the Pearl River Mouth Basin and similar geological backgrounds.
The Triassic Yanchang Formation in the Ordos Basin is characterized by two sets of source rocks， Chang 7 and Chang 9 members. Among them， the Chang 9 Member is considered an ideal potential area for the discovery of major strategic oil and gas reserves， following the Chang 7 Member， in the Changqing Oilfield. However， due to the low level of exploration and the relatively weak sedimentary environment research in the Chang 9 Member， studies on the organic matter formation processes and enrichment mechanisms remain limited. This paper focuses on the mudstone of the Chang 9 Member in the northern Shaanxi region of the Ordos Basin and systematically reveals the sedimentary environment and organic matter enrichment mechanisms using X-ray diffraction （XRD）， total organic carbon （TOC）， and major and trace element analyses. The study indicates that the Chang 9 mudstone was deposited in a deep lake to semi-deep lake environment under semi-arid to semi-humid climatic conditions， characterized by a closed water body， high paleo-salinity， and favorable redox conditions， which created the key background for organic matter preservation. The TOC content of the mudstone ranges from 0.29% to 9.90% （average 2.87%）， with Type II and Type I kerogen being dominant， indicating significant hydrocarbon source potential and important exploration and development value. Organic matter enrichment is controlled by the synergistic effects of redox conditions， paleoclimate， clastic input， and paleo-productivity. Among these factors， the reducing environment is the key factor controlling organic matter enrichment， while enhanced paleo-productivity driven by volcanic activity provided an important source of organic matter. Additionally， paleoclimate and increased terrestrial input contributed to the diversity of organic matter sources. This study clarifies that the organic matter enrichment in the Chang 9 Member is dominated by a “preservation-priority” mechanism， in which a “short-term high input + high preservation” model formed under an anoxic to weakly reducing environment， strong productivity， and a closed lake basin triggered by volcanic activity. This provides crucial geological support for shale oil and gas exploration in the Ordos Basin.
The multi-phase tectonics of western Hubei create favorable shale gas enrichment conditions， but research on its origin types and enrichment-controlling factors remains relatively weak. Following analysis of the gas composition and hydrocarbon isotope signature， combined with a study of the reservoir lithology and pore structure， the genesis and enrichment patterns of shale gas in the Dalong Formation have been revealed. The Upper Permian Dalong shale in western Hubei exhibits high TOC （5.82%） and R O （2.36%）， indicating excellent hydrocarbon generation potential. The gas is dominated by CH4， with minor C2H6， CO2， and N2. Hydrocarbon isotopic compositions（δ13C1 values range from -29.6‰ to -25.4‰， δ13C2 values range from -34.6‰ to -29.7‰； δD1 values range from -137‰ to -133‰， and δD2 values range from -111‰ to -103‰） identify that the gas from the Dalong Formation is thermogenic oil-type gas. A carbon isotope reversal phenomenon（δ13C1>δ13C2）is observed in the study area， which is related to the cracking of liquid hydrocarbons during the overmature stage. values range from -26.8‰ to -18.5‰， confirming its organic thermogenic origin. The reservoir exhibits well-developed pores and fractures， with siliceous rocks mainly containing intergranular pores， organic matter pores， and peloid pores， while carbonate rocks are dominated by bedding fractures， dissolution pores/fractures， and local fractures. Pore size distributions indicate that carbonate rock intervals are more favorable for gas accumulation. The gas enrichment in the Dalong Formation is thus dually controlled by lithology and pore structure.
Multiple wells deployed by SINOPEC in the Upper Permian Wujiaping Formation of the eastern Sichuan Basin have yielded high-yield industrial gas flows. However， the genesis mechanism of high-quality shale reservoirs in the Permian Wujiaping Formation remains unclear，which has to some extent constrained the exploration and development of shale gas.This study systematically investigates the characteristics and genesis of high-quality shale reservoirs in the Wujiaping Formation based on drilling， logging， and geochemical data. Results indicate that the second member of Wujiaping Formation developed slope-to-shelf shales exhibiting high organic carbon content（TOC，average 7.78%），high porosity（average 4.52%），high gas content（average 7.60 m³/t）， high brittle mineral content（average 74.7%）， and thin reservoir thickness （15-25 m） collectively termed the “four highs and one thin” characteristics. The genesis mechanism of high-quality shale reservoirs in the Wujiaping Formation primarily involves four aspects： First， volcanic activity， paleoenvironment， and anoxic conditions provided the material basis for organic matter accumulation. Volcanism and arid-hot paleoclimate jointly promoted high paleoproductivity， while the slope-deep water shelf depositional environment supplied oxygen-depleted to anaerobic conditions for organic enrichment. Second， high thermal evolution and diagenesis ensured pore development in high-quality shale reservoirs. Pore structure is synergistically controlled by siliceous and carbonate minerals， with biogenic silica and carbonate minerals jointly supporting the highly brittle reservoir framework. Secondary dissolution further optimized the pore structure. Third， stable tectonics and cap/floor strata provided favorable preservation conditions for better shale reservoirs. Fourth， high brittleness and well-developed fractures ensure good compressibility in deep Permian shales. These findings provide theoretical basis and guidance for Permian shale gas exploration and development in the Sichuan Basin.
Conventional approaches， such as multivariate regression， empirical formulas， and petrophysical models， commonly fail to adequately capture the complex nonlinear relationships between logging curves and reservoir parameters， resulting in suboptimal accuracy for grading prediction of shale reservoirs. This study focuses on deep shales derived from the Wufeng Formation and the first sub-member of the first member of the Longmaxi Formation （marked as LMX1 1） in western Chongqing area. A reservoir type identification model based on the Bayesian optimized LightGBM algorithm was developed， with the SHAP algorithm employed to quantitatively evaluate the importance of logging curves. Subsequently， the model was applied to grading evaluation of deep shale reservoirs within the target area. The results demonstrate that， compared to the regression strategy， the classification strategy achieved significant improvements in model complexity， computational efficiency， and identification performance in deep shale reservoir identification. An identification model of shale reservoir types was established using the classification scheme， yielding weighted precision and weighted recall of 89.7% and 89.6% for LightGBM algorithm， which are superior to those for RF （87.52% and 86.96%， respectively） and SVM （83.61% and 81.8%， respectively） algorithms， respectively， on the testing dataset for reservoir type identification. DEN， GR， and CNL logs proved most critical for identifying Types I and III shale reservoirs， whereas DEN， AC， and CNL logs exhibited heightened importance for the identification of Type II reservoirs. Furthermore， logging curves exert a complex nonlinear influence on model decisions. The grading evaluation results show that Type I reservoirs are predominantly developed in the upper Wufeng Formation and the first sub-layer of the LMX1 1. The Bayesian optimized LightGBM algorithm facilitates efficient and precise identification of shale reservoir types， offering a novel approach for reservoir classification evaluation.
Underground hydrogen storage （UHS） is a key technology for promoting renewable energy integration， mitigating wind and solar curtailment， and stabilizing grid output. However， China currently has no operational UHS projects. Although experience from underground gas storage and carbon dioxide sequestration can be used for reference， the unique physicochemical properties of hydrogen require further investigation. Based on an extensive review of domestic and international literature， this paper summarizes the classification and development status of UHS， with a focus on research progress in hydrogen migration-diffusion mechanisms， biochemical reactions， and safety evaluation. Studies indicate that depleted oil and gas reservoirs， aquifers， and salt caverns are suitable structures for large-scale and long-term hydrogen storage. Nevertheless， challenges such as high diffusivity， geochemical reactions， microbial activity， and geomechanical risks remain， and current research in these areas is clearly inadequate. There is a need to strengthen studies on multi-process coupling mechanisms. Finally， considering geological conditions， this paper analyzes the prospects for underground hydrogen storage， showing that tight sandstone gas reservoirs alone have the potential to store at least 337 million tons of hydrogen. The findings of this study can provide critical scientific justification and engineering feasibility support for formulating China’s large-scale hydrogen storage strategy and promoting the development of major demonstration projects for UHS.
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