In order to study the paleo-fluid characteristics of Devonian Shetianqiao Formation in Shaoyang Sag， central Hunan and its indication for shale gas preservation， fracture vein samples of Well Shuangdi 1 were systematically collected and fluid geochemistry， electronic probe and inclusion analysis were carried out. The results show that the δ13C and δ18O of calcite vein are not significantly different from those of surrounding rock. The difference between the carbon and oxygen isotopes of calcite veins and surrounding rocks are very small， the oxygen isotopes of calcite veins are smaller than surrounding rocks， while the carbon isotopes are similar to surrounding rocks， the carbon and oxygen isotopes of calcite veins are all smaller than surrounding rocks， which respectively represent three different sealing conditions： closed system with low water/rock ratio， cross layers fluid mixing and atmospheric water mixing. The closed system section with low water/rock ratio indicated by paleo-fluid is a gas show section， indicating its long-term sealing property. The Fe and Mn contents of calcite veins indicate oxidizing environment of fracture zone， which has mixture with paleo-atmospheric water. The fluid activities of the Shetianqiao Formation is characterized by multiple stages， Sm-Nd isotopic dating reveals that the formation time of vertical angle veins in the lower part of Shetianqiao Formation is 149 Ma， the formation depth is 3.2 km and with the fluid gas content is poor， indicating that the shale gas reservoir has suffered strong damage. The comprehensive study shows that the strong compression and uplift of Yanshan movement makes strong structural deformation in central Hunan， especially the fracture development， early denudation time， high intensity and unfavorable structural preservation conditions in the sag margin area. The deformation in the middle of the sag are weaker and the preservation conditions are relatively favorable， but the Devonian System was platform facies area， which was not conducive to shale development. Therefore， the shale of the upper part of Upper Devonian Menggongao Formation in the middle of Shaoyang Sag should be taken as the exploration direction， combined with sedimentary facies and cap rock thickness analysis.
The Central Hunan Depression is an important area in southern China where shale gas exploration extends from the upper reaches to the middle reaches of the Yangtze River. And the Devonian Shetianqiao Formation is the key layer of shale gas exploration in the area. Based on the field outcrop and drilling data of Lianyuan Sag in central Hunan Depression， the geological conditions of shale gas accumulation in Shetianqiao Formation were analyzed by using the data of laboratory testing， logging and field gas-bearing monitoring. The controlling factors for differential enrichment of shale gas were discussed. And the following research results were obtained. （1） Gray black-black shale， calcareous shale and marlstone are mainly developed in the basin facies area between carbonate platforms in Lianyuan Sag. The shale with a thickness of more than 80 m， high content of organic matter（TOC>1%）， good type of organic matter （sapropelic type and humus-saproptlic type） and moderate thermal evolution degree（2.0%<RO<3.0%）has good hydrocarbon generation conditions. （2） The Shetianqiao Formation shale is a type of siliceous shale and mixed shale with high content of brittle minerals. The shale reservoir space is dominated by inorganic pores and fractures， and it is a fracture-porosity reservoir with ultra-low porosity and ultra-low permeability. The pore volume is mainly provided by mesopores and macropores. （3） The shale gas reservoir of Shetianqiao Formation is a residual normal pressure gas reservoir. It mainly experienced three stages of forming and evolution：Early in-situ accumulation， medium-term adjustment and transformation， and late dissipation-residue. The Middle Jurassic-Early Cretaceous is the most important period of accumulation and transformation. （4） Organic-rich shale formed in deep-water anoxic environment of basin facies between platforms is the basis for gas enrichment and accumulation in Shetianqiao Formation. Good preservation conditions are the key to gas accumulation. The development characteristics of fractures and related pores controls the distribution of high-quality reservoirs and the shale gas enrichment. In conclusion， the shale gas of Shetianqiao Formation has the enrichment and accumulation pattern of “integration of source and reservoir， differential distribution， sedimentary facies controlling hydrocarbon supply and favorable area， and structure-fracture determining preservation conditions and gas enrichment”. The wide and gentle syncline structure in the basin facies area is a favorable region for gas enrichment， and the development zone of pores and fractures are favorable locations for gas enrichment.
A set of silicon-rich and carbon-rich shale reservoirs are developed in the second member of Permian Wujiaping Formation （Wu2 Member）in the Hongxing area of eastern Sichuan Basin， which have been proved to be a set of high-quality gas-bearing shale reservoir based on exploration activities. The set of shale primary quality （organic carbon content， lithology and mineralogy， sedimentary structure） has strong heterogeneity characteristics in vertical direction， directly affecting the gas-bearing property and removability of shale reservoir. Based on the establishment of shale isochronous stratigraphic correlation framework， this study systematically investigates the vertical heterogeneity characteristics of the shale reservoir in rock and mineral composition， sedimentary structure， organic matter abundance and organic matter types. The main controlling factors of heterogeneity are discussed from the aspects of sedimentation， marine paleo-productivity and redox environment. The vertical heterogeneity is mainly controlled by factors such as paleoclimate， volcanic activity and sea level rise and fall. The ancient climate and sea level fluctuations jointly control the supply of terrigenous detrital minerals， volcanic activity controls the paleo-productivity of surface seawater， thereby controlling the content of organic matter and authigenic silica， the continental volcanic activity and submarine volcano activity led to the development of tuff thin interbeds and siliceous strips and other special lithologic interbeds in shale reservoirs， which affected the modifiability of shale reservoirs themselves.
The Lower Carboniferous Luzhai Formation in the Guizhong Depression of Dian-Qian-Gui Basin is thicker than the Longmaxi Formation in the Sichuan Basin， and is expected to become a major breakthrough field after the Sichuan Basin and Yunnan-Guizhou region. However， the geological conditions are more complicated. In order to explore the enrichment conditions and main controlling factors of shale gas in Guangxi， the Lower Carboniferous Luzhai Formation in the Guizhong Depression is taken as the research object. Using the data of drilling， logging， seismic， magnetotelluric sounding， analysis and testing， the enrichment conditions and main controlling factors are studied. The research shows that： （1） The organic-rich shale of the Lower Carboniferous Luzhai Formation in the Guizhong Depression has large thickness， wide distribution， high abundance of organic matter， good type of organic matter， high maturity-over-maturity stage， and good reservoir conditions such as high porosity. The maximum analytical gas content in the field is 2.9 m3/t， and the isothermal adsorption experiment shows that the maximum adsorption capacity is 5.32 m3/t， indicating good preservation conditions. Compared with typical shale gas reservoirs at home and abroad， Luzhai Formation has good shale gas enrichment conditions. （2） The main controlling factors of shale gas enrichment in Luzhai Formation of Lower Carboniferous Series in Guizhong Depression are： The basin or deepwater shelf facies are favorable zones for shale gas enrichment， and the combined gas of “residual hydrocarbon” and kerogen at moderate burial depth ensures sufficient gas source， with RO of 1.5%-3.5%， which is the best window for the coupling of source and reservoir. Slow uplift and favorable structural styles are the key factors for shale gas enrichment. （3） Based on the characteristics of large denudation thickness， high thermal evolution degree and multi-stage fault activity in Guizhong Depression， it is concluded that Liucheng North area， Luzhai area， Nandan area and Huanjiang area are favorable areas for shale gas exploration in Luzhai Formation.
High-quality reservoirs developed in the Bashijiqike Formation and Baxigai Formation sandstones of the Lower Cretaceous in the Bozi-Dabei area， Kuqa Depression of Tarim Basin， in which highly yielding industrial gas flow is obtained within a burial depth of 8 200 m. The target formation has experienced multiple phases of tectonic movements， and the development of multi-genetic fractures provides the reservoir with efficient storage and seepage space. Based on the results of drilling core， field profile survey， imaging logging， and experimental analysis， the authors portray the fractures in the Lower Cretaceous dense sandstone reservoir of the Bozi-Dabei area， clarify the characteristics and controlling factors of multi-genesis and multi-period fractures， and propose an effective fracture development model under geo-stress control. The Bozi-Dabei area is subjected to a high extrusion stress environment with relatively gentle deformation， mainly developed regional tectonic fractures and fault related fractures， where deformation-related factures are less developed. The results of a combination of multi-attribute data determination techniques， including fracture filling， inter-cutting relationship， fracture filling isotope， inclusions and cathode luminescence tests， indicate that the reservoir fractures have experienced three major periods of tectonic movement. Regional tectonic fracture development is mainly controlled by stratigraphic lithology and stratigraphic thickness； Fault co-derived fractures are influenced by the distance from the fault and the location of the upper and lower plates of the fault. The shift in the direction of the late horizontal maximum principal stress will cause the early fractures to open or close under different conditions in the Bozi-Dabei area， which in turn affects the degree of fracture opening and effectiveness. When the horizontal maximum principal stress is deflected to intersect with the early fractures at a smaller angle or even superimpose， the fracture effectiveness of the related group system in the deflection direction is better， and the overall coordination is developed. The distribution characteristics of the fracture system in the highly productive reservoir are the result of a dominant configuration of multi-phase activities.
Deep tight sandstone gas is a hot spot in oil and gas exploration in recent years， and it is of great significance to clarify the genetic mechanism of overpressure in deep tight clastic rock reservoirs for deep oil and gas exploration. Taking the tight clastic rock reservoirs in the Yingcheng Formation-Shahezi Formation of the Longfengshan sub-sag in the Changling Fault Depression of Songliao Basin as the research object， in view of the unclear understanding of the causes of overpressure and the lack of research on its impact on reservoir quality， using the methods of casting thin section， scanning electron microscope， well logging overpressure identification and inclusion paleo-pressure recovery， the formation of overpressure in Yingcheng-Shahezi formations and its influence on tight clastic rock reservoirs are studied. The results show that the overpressure of the Yingcheng-Shahezi formations in the Longfengshan sub-sag is mainly caused by the hydrocarbon-generation pressurization. The paleo-pressure recovery results show that there was obvious overpressure in the Yingcheng Formation during the two periods of oil and gas charging， indicating that there was overpressure caused by hydrocarbon-generating pressurization during the accumulation period. The overpressure controls the episodic hydrocarbon expulsion process， which makes the micro-fractures open in stages in the reservoir， and the unclosed micro-fractures increase the connectivity of the reservoir and improve the permeability of the reservoir.
The sediment type and evolution are the response of peripheral plate tectonic activities， and profoundly affect the reservoir quality of shale. The sediment types and evolution of marine shale at the turn of Late Ordovician-Early Silurian were revealed by detailed description of the Wufeng Formation shale core， full-scale imaging of large thin sections and field emission scanning electron microscopy analysis of argon ion polished sections in southern Sichuan. Marine shale mainly develops three shallow-water fine-grained sediments： fine-grained turbidites， source mixing sediments and in-situ mixing sediments. The fine-grained turbidite is dominated by clastic quartz （45.5%-54.5%） and clay minerals （29.0%-38.9%）， and nine typical sedimentary sequences can be clearly seen. The source mixing sediment is mainly composed of quartz （36.5%）， carbonate （24.3%） and clay minerals （39.3%）， and carbonate minerals are mainly exogenous transport deposits. In-situ mixing sediments is dominated by clay minerals （30.5%）， ankerite （39.5%） and calcite （26.5%）， and carbonate minerals are mainly derived from in-situ. The fine-grained turbidite are mainly developed in the graptolite zone WF1-2， the source mixing sediment is mainly developed in the graptolite zone WF3， and the in-situ mixing sediment is mainly developed in the graptolite zone WF4. The sediment type and distribution reflect the characteristics and evolution of the tectonic activity of the surrounding plate. During the sedimentary period of the graptolite zone WF1-2， fine-grained turbidite developed， indicating that the tectonic compression of the surrounding plate was strong， and the terrestrial supply was sufficient. During the sedimentary period of the graptolite zone WF3， the source mixing sediment developed， indicating that the tectonic activity of the surrounding plate was weakened， and the terrestrial supply was reduced. During the sedimentary period of graptolite zone WF4， the in-situ mixing sediment developed， indicating that the tectonic activity of the surrounding plate was further weakened， and the terrestrial supply was further reduced. The sediment type directly affects the reservoir quality of shale. The porosity and total organic carbon content of fine-grained turbidite sediment are the lowest， while those of in-situ mixing sediment are the highest.
There has been very limited studies focusing on the fault system in Jurassic strata in Sichuan Basin， restricting the understanding of the hydrocarbon accumulation mode of the Shaximiao Formation and the expansion of exploration range. Based on interpretation and coherent slice analysis of abundant seismic data， it is newly discovered that normal faults are widely developed in northern central Sichuan Basin in Jurassic strata. These faults mainly extend from Lower to Upper Jurassic strata， and is characterized by the continuous arrangement of NEE-trending small faults in the plane， while a few NNE-trending and NNW trending faults are developed. The Jurassic fault combination are different in the basin， where the normal faults are mainly distributed in the low uplift of the central Sichuan and the north of central Sichuan. According to the comparison of geochemical data， the normal faults could communicate the Jurassic source rocks and Shaximiao Formation reservoir in these areas. The newly discovered normal faults are superimposed with the middle and Lower Jurassic source rocks in the northern central Sichuan Basin. A new hydrocarbon accumulation model of hydrocarbon generation from the middle and lower Jurassic and normal faults communication could be formed. Among these areas， multi-stage channel superimposed development zone near normal faults is one of the favorable exploration directions.
Lacustrine-delta sandstone of Lianggaoshan Formation has great potential of tight oil and gas resources in eastern Sichuan Basin. It is the key to determine diagenetic evolution and genetic mechanism of tight reservoir distribution prediction. However， genetic mechanism of Lianggaoshan Formation sandstone reservoir was still poorly understood in the eastern Sichuan Basin. Therefore， thin section， X-ray diffraction， scanning electron microscopy， physical property analysis， NMR porosity and high-pressure mercury injection were used to systematically study the petrology， reservoir space， porosity and permeability， and diagenesis. Moreover， genetic evolution mechanism of sandstone reservoir was also systematically analyzed. The main conclusions are as follows： （1） Lianggaoshan Formation sandstone mainly comprise fine-grained lithic sandstone and minor medium-grained and silty lithic sandstone with moderate sorted grains. The reservoir space mainly consists of intergranular dissolved pores， intragranular dissolved pores and primary pores. The porosity ranges from 0 to 8%， and the permeability ranges mainly from 0.001×10-3 μm2 to 0.01×10-3 μm2. （2） Diagenesis mainly includes mechanical compaction， calcite cementation， authigenic chlorite and dissolution. Calcite cements include early pore filling and late replacement of grains. Chlorite mainly occurs as grain coating. The feldspar and calcite cements were main subject of dissolution. （3） The underwater branching channel of high-level system was the mass basis of high-quality reservoir development. Mechanical compaction was the main cause of reservoir densification. The early chlorite coating can protect the pores and provide space for the subsequent precipitation of calcite cementation. The early pore-filling calcite decreased porosity by occupying the pore space. Feldspar and early calcite can produce secondary pore through dissolution. Source rock evolution can provide organic acid and for dissolution. The physical property of reservoirs at the bottom of the sandbody （the main body of sandbody） is better than those in the middle and upper part of the sandbody （the edge of the sandbody）. This study can provide important theoretical support for the reservoir prediction.
In recent years， dozens of tight sandstone gas exploration wells in the southeast of Ordos Basin has tapped industrial gas flows and a pilot area has been developed efficiently， showing this area has a bright exploration and development prospect for tight sandstone gas. It is well-known that good gas source conditions provided by high-quality source rocks， strong hydrocarbon generation pressurization and dynamic conditions for reservoir formation are the fundamental conditions controlling the formation of large tight sandstone gas field， but source rocks in the study area haven’t been investigated systematically. In this work， based on large amount of well logging， mud logging， core， analysis and assay data， geochemical characteristics and planar distribution of coal measure source rocks in southeast of Ordos Basin have been analyzed in detail， logging interpretation model of the total organic carbon content （TOC） of coal measure source rocks have been established， and hydrocarbon generation intensity of the source rocks have been calculated on this basis. The results show that： （1）In the Upper Paleozoic of southeastern Ordos Basin， coal， carbonaceous mudstone and dark mudstone have average TOC contents of 56.2%， 9.6% and 2.4%， respectively.The organic matter type of coal is type Ⅲ， and are all in over-mature dry gas generation stage. （2）On the plane，coal and dark mudstone are widely developed in Benxi Formation and Shanxi Formation and thicken gradually from the northwest to east， while carbonaceous mudstone is thin in the study area. （3）Logging parameters such as GR， AC and DEN matching best with the measured data were picked out to establish TOC logging interpretation models of coal， carbonaceous mudstone and dark mudstone source rocks respectively by using multiple regression method.（4）The Upper Paleozoic source rocks in the southeast of Ordos Basin have higher hydrocarbon generation intensities of （17.6-58.3）×108 m3/km2，with an average of 38.4×108 m3/km2， in which the coal seams have higher hydrocarbon generation intensity than dark mudstone and carbonaceous mudstone units， and the source rocks in the east part has the highest hydrocarbon generation intensity of mainly between （29.2-58.3）×108 m3/km2， on average 42.4×108 m3/km2.
The study of the factors affecting the movable fluid of tight sandstones can effectively improve the accuracy of reservoir development potential evaluation. The typical tight sandstone samples of Shanxi Formation in the eastern Ordos Basin were collected， and the effects of clay minerals and pore-throat characteristics on the movable fluid were analyzed by using multiple tests， including thin section petrography， scanning electron microscopy， X-ray diffraction， rate-controlled porosimetry， and nuclear magnetic resonance. Based on the pore types， the tight sandstones were divided into three types as follows： （a） Intergranular pore-dissolution pore-intercrystalline pore type （type-I）； （b） Dissolution pore-intercrystalline pore type （type-II）； and （c） Intercrystalline pore type （type-III）. The contents of movable fluid saturation （MFS） of sandstones ranged from 9.39% to 78.79%， with an average of 41.63%， and had a moderate positive correlation with permeability. The study showed that the clay minerals were not conducive to movable fluid， and the pores larger than 200 μm and throats larger than 1 μm were conducive to fluid mobility. The high content of illite occurred as pore-bridging phases， which played a significant role in inhibiting fluid mobility. The type-I sandstones had high MFS values， of which the pores greater than 200 μm occupied a relatively high proportion， and the throats greater than 1μm occupied more than 50%. The contents of MFS in type-II sandstones varied greatly. However， with the increase of dissolution pores and the decrease of intercrystalline pores， the binding on the fluid caused by the pore-throats was weakened， resulting in the increase of the MFS values. The type-III sandstones were dominated by pores less than 200 μm， and throats less than 0.5 μm accounted for more than 50%. Thus， the contents of MFS in type-III sandstones were extremely low.
In the development of coalbed methane （CBM）， the inflow performance is an important basis for formulating a reasonable production system， which can maximize the stable production time and improve the final production. Aiming at the problem that there is no explicit equation of bottom hole pressure and multiple factors to evaluate the unsteady inflow performance， an explicit calculation model of bottom hole pressure and time， stress sensitivity coefficient， skin coefficient， total production， and start-up pressure gradient is established by using theoretical derivation and multiple factor fitting methods. The model is verified with production data， and the factors affecting the bottom hole pressure are analyzed. The results show that the accuracy of the model can reach 82.3%-94.76% from the initial production stage to the stable pressure stage， which can effectively evaluate the influence of various factors on production and bottom hole pressure， and provide technical support for optimizing the drainage system.
Previous researchers have carried out researches on reservoir characteristics and reservoir-forming conditions of the Loushanguan Group giant thick dolostone of Cambrian in the northern Qianbei Depression， but the studies on its geochemical characteristics and paleo-marine environment are still weak. Based on field investigations， this paper analyzed the lithological and isotopic characteristics of the Loushanguan Group， and then discussed the paleo-marine environment and evolution. The results show that the ordering degree of dolomite ranges from 0.63 to 0.91， with an average of 0.78， and the dolomite content is basically above 95%， with relatively low detrital mineral content. The δ13C values of the rocks range form －1.94‰ to 2.78‰， with an average of -1.02‰. The δ13C values distributed within the carbon isotopic composition of middle to late Cambrian seawater. The evolution trend of the δ13C curve shows that the sea level was relatively low and fluctuated frequently during the early to middle stages of sedimentation. A higher level transgression occurred in the middle period. Accompanied by low-frequency and low amplitude oscillations in the seawater， the sea level gradually decreased in the middle and late stages of sedimentation.The values of δ18O is －8.32‰-－6.24‰， with an average of －7.19‰， which is slightly positive compared with Cambrian seawater and Cambrian limestone. The strontium isotope 87Sr/86Sr values range from 0.709 45 to 0.710 33， which is significantly higher than the Sr isotopic composition of seawater in the same stage. This anomaly may be related to the diagenetic reformation by the Sr rich fluids from the lower strata during the deep burial period. The paleo-salinity index Z values are mainly distributed in the range of 120.02‰ to 129.65‰， with an average of 121.63‰， indicated that the Loushanguan Group deposited in salinized seawater. The surface temperature of seawater was concentrated between 18 ℃ and 23 ℃， with an average of 21.17 ℃， indicating that the main part of Loushanguan Period was a hot subtropical climate. The clay mineral assemblage in the stratigraphy showed strong evaporation， and the sedimentary water was a high salinity alkaline medium. The Th/K ratio is distributed between 3 and 6， indicating that the overall energy of the seawater was low. The U/Th ratio fluctuates between 0.75 and 1.25， reflecting the oxygen-poor characteristics of paleo-marine. The paleo-environmental elements are well coupled with the sedimentary features， and the sedimentary features of Loushanguan Group reflected the unique global climate and paleo-marine conditions of the period. The above achievements have important theoretical and practical implications for the reconstruction of the Cambrian paleoenvironmental and paleo-ecological evolutionary history of the Yangzi Plateau and the world.
The Junggar Basin is a typical superimposed basin with multiple hydrocarbon sources in western China. Five sets of gas source rock series are developed， including the Carboniferous， Permian Jiamuhe Formation， Permian Fengcheng Formation， Permian Lower Wuerhe Formation， and Jurassic. The main gas source rocks are widely distributed in the basin. Some areas are in the high over mature stage， entering the main gas generation period of gas source rocks， and have the material basis for exploring atmospheric fields. The natural gas in Junggar Basin has the characteristics of multiple sources， mixed sources and complex genesis. The conventional natural gas genesis identification indicators are inaccurate in identifying the origin of natural gas in some areas. In order to solve this problem， this paper systematically combs and analyzes the geochemical characteristics of natural gas in different layers and regions， combines the hydrocarbon generation characteristics of different source rocks， establishes a new chart for identifying the origin of natural gas， and identifies the origin of natural gas in Junggar Basin. This paper puts forward the following views： （1） It is difficult to define oil type gas in high evolution stage and coal type gas in low evolution stage in the Junggar Basin with traditional methods. Failure to effectively classify natural gas type and maturity will affect gas source identification and genesis research in this area， and new identification methods need to be established. （2） In this paper， a chart for identifying the origin and source of natural gas in Junggar Basin has been established， which can effectively identify the origin and source of natural gas in different strata and regions， and is applicable to coal type gas in low evolutionary stage and oil type gas in high evolutionary stage. （3） Plenty of oil type gas exists in the Permian Fengcheng Formation and Lower Wuerhe Formation in Mahu and Shawan in the northwest margin， and the Carboniferous， Permian Jiamuhe Formation and Jurassic source rocks also make significant contributions； Jurassic coal type gas is mainly distributed in the south of Junggar Basin from low mature to over mature stages； The eastern part and the hinterland of the Junggar basin are dominated by the coal type gas of the Carboniferous and Jurassic in the high evolution stage， mixed with some Permian oil type gas.
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