Different types of natural gas have different carbon and hydrogen isotopic compositions， so the carbon and hydrogen isotopic composition of natural gas is one of the important indicators of natural gas origin identification. With the continuous development of natural gas exploration technology and the continuous growth of exploration data， understanding of the origin and source of natural gas is also deepening， and how to update and verify the existing data to ensure the applicability of natural gas genetic identification figure has become crucial. This study comprehensively analyzes the stable carbon and hydrogen isotope characteristics of different genetic types of natural gases in Sichuan， Tarim， Ordos， Turpan-Hami， Songliao， Northern Jiangsu， Sanshui， Qaidam， and Bohai Bay basins in China， together with abiotic gases from the Lost City of the Middle Atlantic Ridge， and the genetic identification diagrams related to commonly used carbon and hydrogen isotopes are evaluated. The following four conclusions are obtained： （1） The carbon isotopic values of methane （δ13C1）， ethane （δ13C2）， propane （δ13C3） and butane （δ13C4） of natural gases from China are from -89.4‰ to -11.4‰ （average of -36.6 ‰），-66.0‰ to -17.5‰（average of -29.4‰），-49.5‰ to -13.2‰（average of -27.3‰）， -38.5‰ to -16.0‰（average of -25.6‰），respectively. （2） The hydrogen isotopic values of methane （δD1）， ethane （δD2） and propane （δD3） of natural gases from China range from -287‰ to -111‰ （average of -177‰）， -249‰ to -94‰ （average of -158‰）， and -237‰ to -75‰ （average of -146‰）， respectively. （3） The carbon and hydrogen isotopic distribution patterns among methane and its homologues of natural gases in China are mainly in positive order （δ13C1<δ13C2<δ13C3<δ13C4， δD1<δD2<δD3）. The fractionation amplitude between methane and ethane is greater than that between ethane and propane （Δ（δ13C2-δ13C1）> Δ（δ13C3-δ13C2）， Δ（δD2-δD1）>Δ（δD3-δD2）） in most natural gas samples. （4） The δ13C1–δ13C2–δ13C3， the δ13C1–δD1， δ13C1–C1/C2+3， Δ（δ13C2-δ13C1）–Δ（δ13C3-δ13C2） and Δ（δD2-δD1）–Δ（δD3-δD2） charts， can be used to identify the gas origin in many different cases， and the combined application between different charts can enhance the identification effect.
The oil and gas discovered in the Junggar Basin are mainly distributed in the periphery of the Central Depression and the uplift area within the depression. The exploration degree of Dongdaohaizi Sag is the lowest among the many secondary sags in the Central Depression， and the research degree of its main source rock， the Middle Permian Pingdiquan Formation， is also very low. Based on core thin section observation， total organic carbon， kerogen carbon isotope composition， Rock-Eval pyrolysis and biomarker analysis， the hydrocarbon-generating potential and formation environment of the Pingdiquan Formation source rocks were systematically evaluated， and compared with the Middle Permian Lucaogou Formation source rocks in the neighboring Fukang Sag. The results show that the lithology of the Pingdiquan Formation source rocks in the Dongdaohaizi Sag is primarily composed of deep gray-black gray mudstone， silty mudstone and mudstone in the profundal zone，and mainly composed of gray-dark gray mudstone and silty mudstone in the sublittoral zone， which is a set of deep to semi-deep lacustrine sediments. The Pingdiquan Formation source rocks mainly comprise of type Ⅱ kerogen， and belong to medium to good source rock. In the Late Permian， this set of source rocks entered the threshold of hydrocarbon generation， and now the whole has entered the stage of dry gas generation. The Pingdiquan Formation source rocks were deposited in a brackish environment with main input of aquatic organisms such as bacteria and algae， supplemented by the input of terrigenous higher plants. The Pingdiquan Formation source rocks in the Dongdaohaizi Sag share similar geochemical characteristics with the Middle Permian Lucaougou Formation source rocks in the Fukang Sag. At present， a series of exploration breakthroughs have been made around the latter， implying that the Pingdiquan Formation petroleum system in the Dongdaohaizi Sag may also has good exploration potential. The research results further consolidate the resource potential of the Permian petroleum system in the Junggar Basin， and provide an important reference for oil and gas exploration in the Dongdaohaizi Sag and its periphery.
In the past，crude oil was the main petroleum exploration target in the Weixi’nan Sag of Beibuwan Basin. However， it’s difficult to find oil over time. Now natural gas is dominant in increasing reserve and production of petroleum in this area. The degree of exploration and research of natural gas is very low. Especially， the geochemical characteristics and source of natural gas still remain unknown， which constrains the following exploration progress. Based on the natural gas components， light hydrocarbon compositions and stable carbon isotope data， this research investigates the geochemical characteristics， genetic types and sources of natural gas in the Weixi’nan Sag of Beibuwan Basin. Results show that： （1） Natural gas is mainly composed by hydrocarbons. Methane is dominated in the natural gas. The molar proportion of methane is between 53.73% and 95.80% （averages 74.80%）. The content of heavy hydrocarbons （C2-5） is relatively high， with an average molar proportion of 19.80%. The natural gas dryness coefficient is generally less than 0.95， implying that it’s a typical wet gas. The non-hydrocarbon gases are mainly N2 and CO2， and their contents are relatively low. （2） Among the C7 light hydrocarbon compounds， n-heptane content is relatively high， and averages at 37.18% （ranges from 21.74% to 51.02%）. The second is methylcyclohexane， with an average content of 34.46%. The dimethylcyclopentane content is 28.36%. These indicate that the source materials are complex. The source materials are mainly sapropelic kerogen， and part of them are mixed kerogen. Only a few of the source materials are humic kerogen. （3）The δ13C1 and δ13C2 values of natural gas are from -54.8‰ to -34.4‰ and -35.2‰ to -25.6‰， respectively. The carbon isotope of the gaseous hydrocarbons is generally positive sequence distribution. Only some gas samples display partial reversal of the carbon isotope， which is probably related to the mixed gases that originates from the same source rock at different thermal evolution stages， or the same type of gases originating from different source rocks. （4） The natural gas is mainly oil-type gas， and originates from the same source rock with crude oil. They were produced by the decomposition of sapropelic kerogen during the matured-highly matured evolution stages. It is inferred that the natural gas is mainly contributed by the oil shales of the lower sequence of the second member of Liushagang Formation. The upper sequence of the third member of Liushagang Formation contributes partly to the formation of natural gas. The research results reveal the geochemical characteristics and sources of natural gas in the Weixi’nan Sag of Beibuwan Basin， and provide important guidance for the following exploration and development of natural gas in this area.
Hydrogeochemical characteristics of coalbed methane co-produced water have significant implications for the secondary biogenic methane. Understanding the relationship between groundwater and secondary biogenic methane is crucial for natural gas exploration and development. The chemical compositions， hydrogen and oxygen isotopic compositions （ and ）， the abundance and isotopic compositions （δ13CDIC and Δ14CDIC） of dissolved inorganic carbon （DIC） of fifty-seven CBM co-produced water samples and three river samples from six blocks of Qinshui Basin in China are analyzed in this study. Results show that hydrogen and oxygen isotopes are distributed near the atmospheric precipitation line， suggesting that coalbed methane well-produced water mainly originates from atmospheric precipitation. Sulfate microbial reduction is identified as a crucial factor in the enrichment of deuterium isotopes in the Zhengzhuang and Yangquan blocks. The chemical composition of water produced from coalbed methane wells in the study area is predominantly of Na-HCO3 type. The evolution of geochemical compositions of coal seam water is controlled by water-rock interaction and cation exchange processes. Stable isotope analysis of water from coalbed methane wells in the six study blocks in the Qinshui Basin shows elevated δ13CDIC values （from -4.19‰ to 34.80‰， average 16.51‰）， and a clear positive correlation with dissolved inorganic carbon content， likely indicating the result of microbial methane production. The negative correlation between δ13CDIC and SO4 2- in coalbed methane produced water， as well as the positive drift in ，suggests the widespread occurrence of secondary biogenic methane in coalbeds with different maturities in the Qinshui Basin. The negative correlation between δ13CDIC and vitrinite reflectance （R Omax） further indicates the presence of secondary biogenic methane in coal beds with different maturities， particularly in shallowly buried and low maturity coal beds. The integration of geochemistry and microbiology will further elucidate the pathways and mechanisms of secondary biogenic methane formation.
With the development of deep and unconventional oil and gas exploration， condensate oil has attracted more and more attention as a high-quality resource. For systematic study the exploration status and the complex formation mechanisms of condensate oil and other key problems， the condensate oil has been analyzed in terms of definition， exploration history， distribution characteristics， origin classification and quantitative analysis. It is pointed out that the proved geological reserves of condensate oil in China are about 710 million tons and there are 163 condensate oil and gas fields （reservoirs）. Condensate gas fields with proven reserves of more than 10 million tons mainly distributed in Tarim Basin and Bohai Bay Basin， which has the characteristics of the coexistence of large condensate gas fields in eastern and western China. On the basis of innovative understanding of primary condensate gas reservoirs， the source-reservoir relationship and other factors are further considered， and the two types of primary and secondary condensate gas reservoirs discovered in China are further divided into two sub-categories： Remote （external） and near （internal）. It also improves the shortcomings of primary condensate gas reservoirs in the aspects of hydrocarbon generation parent material， evolution stage and accumulation mode. According to the established new genetic types， we then reviewed the genetic types and accumulation characteristics of condensate gas reservoirs in China. It is pointed out that no matter in terms of the number of condensate gas reservoirs or proven reserves， China's condensate oil is mainly of primary origin. The primary condensate in China accounts for about 70% of the total proved geological reserves， and the proportion of secondary condensate is about 30%. The proportion of remote （external） accumulation types （about 57%） is higher than that of near （internal） （43%）.
The Linhe Formation in the Linhe Depression of Hetao Basin still develops high-quality reservoirs and produces high industrial oil flow at depths of over 6 000 m， but there are significant differences in the physical properties of clastic rock reservoirs with similar burial depths. In order to clarify the causes of reservoir physical property differences and reduce the risk of deep to ultra deep oil and gas exploration， the Linhe Formation in the Linhe Depression was taken as the research object. Based on comprehensive data such as core， cast thin sections， scanning electron microscopy， and clay minerals， petrology， physical properties， and diagenetic characteristics were studied to study reservoir characteristics and the causes of physical property differences. The results show that the reservoir rocks of the Linhe Formation are mainly characterized by rich quartz， with an average quartz content of 72% and a filling material content ranging from 1% to 28%. The porosity of the reservoir ranges from 1% to 29.2%， and the storage space is mainly composed of primary intergranular pores. The reservoir has differential diagenetic characteristics of overall weak compaction weak cementation， and partial strong compaction strong cementation. The reservoir mainly develops three types of rock facies：Rich cementitious sandstone， rich mud mixed sandstone， and low interstitial sandstone. Rich cementitious sandstone has a finer particle size， strong cementation， and dense physical properties； Rich mud mixed sandstone has a high content of plastic debris and poor sorting， strong compaction， and poor physical properties； Low porosity sandstone is rich in rigid particles and well sorted， with weak compaction and cementation， developed primary pores， and good physical properties. The physical properties of the Linhe Formation reservoir in the Linhe Depression are jointly controlled by sedimentation and diagenesis. The dynamic conditions of sedimentary water determine the particle size， sorting， and mud matrix content of the sand body， which in turn affects the later compaction strength and physical property evolution of the reservoir. The thickness of the sand body controls the content and distribution of cement in the reservoir， which in turn affects the reservoir properties.
The study of ancient structures is important for oil and gas exploration and development， as it plays a controlling role in the development characteristics of oil and gas reservoirs， hydrocarbon generation， and reservoir formation. However， the extensive development of normal faults in complex fault areas of faulted basins increases the difficulty of three-dimensional ancient structure restoration. There are still certain problems in the study of ancient structures in faulted basins， such as the restoration of erosion， fault removal， and compaction correction. In response to the strong heterogeneity of the target layer in the research area and the poor effectiveness of existing porosity recovery and compaction correction methods due to the complex relationship between porosity and depth， this study uses methods such as stratigraphic compaction correction， layer flattening ancient structure recovery， 3D mapping， etc. to study the ancient structure recovery of the lower section of the fourth member of Shahejie Formation （Es 4 x） in the Bonan Sag of Jiyang Depression， Bohai Bay Basin. This study innovatively introduces density logging （DEN） data and proposes a new approach for compaction correction research using the principle of conservation of formation materials； and based on the layer flattening ancient structure restoration method， the thickness of the strata is obtained through research such as fault removal and apparent thickness restoration. The original thickness of the strata is obtained using methods such as erosion amount， compaction correction， and structural equilibrium profile analysis. Finally， a 3D mapping software is used to compile a three-dimensional spatial morphology map of the ancient structure. The new ancient structure map can more accurately reflect the geomorphic characteristics of the sedimentation under the fourth sand layer. Thus， a three-dimensional spatial paleotectonic restoration method suitable for complex fault zones in faulted basins was proposed.
The hydrocarbon accumulation processes an event in geological history， and restoring the porosity of the carrier formation in key stages of accumulation can help quantitatively restore the geological conditions during the accumulation period and better understand the process of oil and gas accumulation. By comprehensively utilizing various technical methods such as thin section identification， micro area U-Pb dating， fluid-inclusion analysis， and rock property testing， the diagenetic evolution sequence of the second member of Dengying Formation （Deng 2 Member） carrier formation in the Penglai area has been established. Based on the time coupling relationship between the “diagenetic evolution sequence and hydrocarbon accumulation period”， the paleoporosity characteristics of the Deng 2 Member carrier formation at each key accumulation stage have been restored using the method of pore inversion and stripping. By using abundant core measured porosity data to calibrate logging porosity， and then based on the relationship between wave impedance and porosity， the 3D seismic wave impedance inversion results are converted into the current reservoir porosity values， and the relationship between paleo-porosity and current porosity is used to restore the distribution characteristics of ancient pores in each key reservoir formation stage of the upper member of the Deng 2 Member， in order to clarify the transport capacity of the carrier formation in the key reservoir formation stage. The porosity of the paleo oil reservoir period and the cracking gas generation period slightly increased compared to the current period， and the first and second adjustment periods were basically consistent with the current porosity. In each key reservoir formation period， the porosity in the upper and middle parts of the Deng 2 Member is developed， with a large distribution range of high porosity and good oil and gas transport performance， which is conducive to large-scale oil and gas accumulation and accumulation. The porosity in the lower part of the upper section of Deng 2 Member is underdeveloped， and high porosity is scattered， resulting in a decrease in oil and gas transport performance， which is not conducive to large-scale hydrocarbon accumulation.
The Qijiang area on the southeastern edge of the Sichuan Basin has developed thrust fold belts since the Jurassic， but there is a lack of systematic research on multiple types of fault systems and their control over oil and gas since the deep Paleozoic. Based on the drilling and high-precision 3D seismic data， the identification of faults in Qijiang area and its adjacent areas is carried out according to the high-precision coherence and other geophysical properties. The profile shape and plane distribution are characterized， and the differences in the formation and evolution process of different faults and their control over the formation and preservation of oil and gas reservoirs are clarified. The research results indicate that the Qijiang area mainly develops two types of faults： thrust and strike slip. The profile is characterized by multiple sets of detachment layers with layered fracture characteristics. The plane mainly develops three sets of faults in the NNW-SSE， NE-SW， and near W-E directions. The NNW-SSE trending fault is a longitudinal overlap of the Lower Paleozoic strike slip fault during the Caledonian period and the Upper Paleozoic Mesozoic thrust fault during the Yanshan period； The NE-SW trending fault is a reverse thrust of the Hercynian ring-shaped normal fault during the Yanshanian period； The nearly W-E trending fault is a reverse fault formed during the Xishan period by the orogenic compression in the direction of Daluoshan on the southern edge of the basin. The development of karst reservoirs in the Maokou Formation was controlled by NNW-SSE trending strike slip faults and NE-SW trending normal faults under the tension background of the Haixi period； Under the compression background of the Yanshan period， the activation of faults formed structural fractures and connected the source and reservoir， and the overlapping of source faults and large-scale reservoirs is a key area for the exploration of Permian oil and gas in the Qijiang area； The strength of the strike slip effect of the NNW-SSE trending fault since the Xishan period controls the later stable preservation conditions of shale gas in the Silurian Longmaxi Formation.
The potential of tight gas resource of Xujiahe Formation in the Western Sichuan Depression is great， but the water productivity of an individual well is an important factor restricting the efficient development of the gas reservoir of the second member of Xujiahe Formation （Xu 2 Member， Tx 2）. Based on the analysis of the gas and water enrichment characteristics of the Xu 2 Member tight gas reservoir in the Xinchang-Xinsheng area， combined with experimental techniques such as cast thin sections， nuclear magnetic resonance， and high-pressure mercury intrusion， it was clarified that fractures and matrix reservoirs have important effects on gas and water enrichment. The controlling effect of gas accumulation can reveal the formation mechanism of gas and water in tight gas reservoirs.The results showed that： （1） There are five types of gas-water relationship in the study area， which are rich gas-rich water type， rich gas-poor water type， little gas-poor water type， poor gas-rich water type and poor gas-poor water type. The rich gas-rich water type and little gas-poor water type gas-water relations are mainly distributed in the upper shallow sub-member of the Tx 2 along with the large-scale faults. The rich gas-rich water type and poor gas-rich water type gas-water relations are distributed in the middle sub-member near the fourth-grade faults which were widely developed in the study area. The poor gas-poor water type gas-water relations were mainly distributed in the lower sub-member and far away from the developed faults. （2） The fourth-grade faults which were active in the hydrocarbon charging periods and the two-period fractures in high degree are dominant for the accumulation of the gas and water. Furthermore， the heterogeneity disparity of the sandstone reservoir led by the disparity of the reservoir physical properties caused the differentiation between the gas and water in the lateral. The microscopic pore structures of the tight sandstone reservoirs had influences on the gas-water interaction and seepage and hence the partial gas-water distribution. （3） Gas and water enrichment is coupled by the macro control of reservoir heterogeneity and fracture reconstruction and the micro control of reservoir pore structure， and five types of fracture-sand body assemblage were divided. Among them， the tight sandstone reservoirs characterized by high porosity and permeability with the development of high-degree fractures in the fault-fracture zone is most conducive to gas enrichment， while the sandstone reservoirs characterized by low porosity and permeability in the non-fault-fracture zone is not conducive to gas and water development. The research results will provide a favorable basis for the exploration and development of tight sandstone gas reservoirs.
HY area is an important natural gas exploration area in the central and southern Xihu Sag of East China Sea Basin， with a relatively low level of exploration. Insufficient understanding of the natural gas reservoir formation mechanism has constrained further exploration expansion. Integrated utilization of laboratory data of natural gas， source rocks， and reservoirs were used to clarify the process of natural gas accumulation. Taking natural gas carbon isotopes as the research object， the controlling factors of its distribution were analyzed and the natural gas charging model was established in the HY area， and the favorable exploration directions were pointed out. The following research results are obtained. First， the natural gas of HY area is coal-type gas， derived from humic-type kerogen. Second， the carbon isotope composition and thermal evolution degree of kerogen in source rocks are the main factors controlling the planar distribution of natural gas carbon isotopes in the HY area. The lateral migration characteristics of natural gas are not significant， showing downward generation and upward storage， vertical migration， and near source charging characteristics. Third， the relationship between the early and late stages of gas charging and the time of reservoir densification is an important reason for the vertical distribution of carbon isotope. The first stage reservoir has not been densified， and the carbon isotope is “light in the upper and heavy in the lower” distribution. In the second stage of deep reservoir densification， the carbon isotope is “upper heavy and lower light” distribution. Fourth， there are two kinds of natural gas charging modes， early and late， in HY area. In conclusion， the intensity of natural gas injection and the effectiveness of traps determine the scale of gas reservoirs in the early charging mode dominated area. Natural gas charging intensity， trap effectiveness and reservoir physical properties determine the scale of gas reservoirs in the late charging mode dominated area.
The deep shale gas reservoirs in the north Luzhou District of the Sichuan Basin are affected by multiple phases of tectonic movements， and are characterized by complex tectonic conditions， rapid changes in in-situ stress， which leading to the difficulties of in-situ stress prediction. A specific in-situ stress seismic approach based on pre-stack azimuthal anisotropic inversion is proposed. Pre-stack AVAZ inversion approach applied azimuthal anisotropy AVA equation under Bayes theory framework. The elastic and anisotropic parameters of the shale gas reservoir are inverted from pre-stack Offset Vector Tile （OVT） gather. Meanwhile， a formula Differential Horizontal Stress Ratio （DHSR） based on the fracture density and Poisson's ratio representation is derived， which is utilized to estimate the DHSR of shale gas reservoir. Wufeng Formation-Long 1 submember and favorable areas for shale gas exploration and development were delineated. This provides reliable geophysical evidence for reserve evaluation， well trajectory design， and reservoir stimulation in the study area. Using this method， deep shale gas in the Wufeng Formation–Long11 subsection of the northern Luzhou area in the Sichuan Basin was predicted by DHSR， and favorable areas for shale gas exploration and development were delineated. This provides a reliable geophysical basis for the reservoir evaluation， well trajectories designment， and reservoir modification.
The largest integrated marine carbonate gas field-Anyue Gas Field in China has been found in the central Sichuan Basin. However， the deep （>4 500 m） carbonate reservoir has low porosity-permeability and extremely strong heterogeneity， which has constrained the large-scale production and development in the deep carbonate reservoirs. For this contribution， the small （vertical displacement <20 m） strike-slip faults interpretation and seismic prediction of the strike-slip fault damage zone are carried out in Anyue Gas Field， and has firstly deployed well drilling on “sweet spot” reservoir （high porosity-permeability reservoir） along the strike-slip fault zones. Based on steerable pyramid reprocessing of 3D seismic data， the small Ⅲ-IV order strike-slip faults can be identified， and the total 1 860 km length of strike-slip faults in Anyue Gas Field have been found and mapped. The symmetric illumination attribute processed by the navigation pyramid was used to characterize the deep dolomite strike-slip fault fracture zone. The area of the strike-slip fault fracture zone was discovered and confirmed to be 1 440 km2， indicating that there is a large-scale fault-controlled “sweet spot” along the weak strike-slip fault zone. Through these data， a new development plan of the deep gas reservoir is proposed from sedimentary microfacies-controlled large-scale reservoir to preferential drilling of fault-controlled “sweet spot” reservoir. In this context， pilot test wells have been firstly deployed in different fault damage zones， and subsequently completed wells have penetrated fracture-vug reservoirs and obtained high gas production more than one times in the deep reservoirs. In the deep carbonate reservoirs， 49 development wells located in the strike-slip fault damage zones had an annual gas production up to 50.4×108 m3 in 2023， which is the first pre-Mesozoic deep strike-slip fault-controlled large gas fields. The development practice in Anyue Gas Field has suggested a tremendous potential of high-yield and high-efficient development of deep strike-slip fault-controlled “sweet spot” reservoirs， and initiated a new exploitation frontier of deep strike-slip fault-controlled gas reservoir in the Sichuan Basin.
The deep-buried tight sandstone reservoirs of the Xishanyao Formation in Yongjin area， Junggar Basin have significant exploration potential. However， the reservoirs exhibit poor physical properties， strong heterogeneity， limited wells， and poor seismic data quality， making the prediction and characterization of favorable sand body distribution challenging. Based on sedimentary background analysis， this study employs sedimentary forward modelling and simulation parameter analysis to construct a four-dimensional sedimentology model of the braided river delta of the Xishanyao Formation in the study area， and also predicts favorable facies and the distribution of sand bodies between wells. The results indicate that there are four flood surface in the Xishanyao Formation， and the Xishanyao Formation can be divided into four fourth-order sequences. Based on the sequence framework and vertical changes of sporopollen content， the simulated evolution process of the lake level is set to seven regression and six transgressions. Results from the reconstruction of paleoenvironment and paleo-water depth based on trace element suggest that during the sedimentation period of the Xishanyao Formation， the environment was weakly oxidizing to weakly reducing，with relatively shallow water depth， averaging about 34.69 m. Using the systematic trial and error method， simulation results confirm that when the parameter K for sediment concentration in river water is set to 0.08 g/L， the conformity of layer thickness among six wells is higher than 89%， with the highest lithological conformity at individual well points. The simulated study indicates that large-scale river deposits dominated， primarily characterized by vertical aggradation， and the river channel complexes were relatively extensive in the early stage of Xishanyao Formation deposition. In the middle stage， the river system exhibited a smaller scale and limited developed characteristics. In the late stage， the features were characterized by small， rapidly laterally migrating rivers with a broad distribution. Braided river delta plain distributary channels are favorable exploration targets in the area. Between Wells Y1 and Y3， as well as between Wells Y2 and Y6， there is a high probability of well-developed channel systems， making them favorable exploration targets in the region.
To explore the sealing ability and the risk of the caprock after local damage caused by strong injection and production of underground gas storages （UGSs）， a dynamic sealing experimental evaluation method for “damage” caprock was established. Using caprock samples from two UGSs in eastern （S） and western （D） China， the effective stress during the operation of the gas storage was simulated and the experiments were conducted to reveal the evolution law of sealing ability for “damaged” caprock. And the optimal injection pressure for the damaged cap gas storage was comprehensively evaluated. The research found that： （1） Deep caprock samples experience a decrease in sealing ability after undergoing shear failure and forming fractures. Samples rich in brittle minerals exhibit a larger reduction in sealing ability， but still retain some sealing capacity under “in situ” simulated stress. （2） The multi-cycle injection and production fatigue effect in the UGS leads to a slight enhancement in caprock sealing ability both before and after the integrity damage of the caprock. （3） The risk of capillary seal failure in the caprock of S and D UGSs is higher than the risk of tensile failure. The above conclusions indicate that during the multi-cycle injection and production operation of UGSs， the sealing ability of the caprock undergoes continuous changes with injection and production fatigue and mechanical damage. Based on the understanding of the evolution mechanism of sealing， the node analysis of the cap rock sealing capacity can determine and optimize the injection-production operating pressure， providing technical means for extending the safe operation life cycle of UGSs.
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