The two trillion square gas areas of Kela-Keshen and Boz-Dabei in the northern Kuqa Depression of Tarim Basin have entered the stage of large-scale development. In order to guide gas exploration and development efficiently， it is necessary to further refine and deepen the basic geological aspects such as sedimentation and sand body distribution. In this paper， based on the observation and measurement of outcrop section， the analysis of macroscopic lithic facies and typical sedimentary structure characteristics， and combined with underground data， the sedimentary microfacies characteristics and configuration of the skeleton sand body of the third member of Bashijiqike Formation （Ba 3 Member） in the northern Kuqa Depression are systematically studied. The results show that there are 21 types of rock facies in the Ba 3 Member of the northern outcrop area of the Kuqa Depression， which are in the front subfacies of the fan delta as a whole， and the sedimentary microfacies of the sand body are underwater distributary channel， estuary bar and far bar. The microfacies of the skeleton sand body are mainly recession-type near-shore and far-shore underwater distributary channels， of which the overall lithology granularity of the near-shore underwater distributary channel is coarse-grained （40% conglomerate and pebbly sandstone， 50% medium-fine sandstone）， and the overall lithology granularity of the far bank underwater distributary channel is finer （85% silt-fine-medium-fine sandstone， 15% sandstone in gravel）. The single layer sand body of the underwater distributary channel in the outlying area has large thickness and good lateral continuity， which is usually formed by the vertical overlapping continuous pieces of single-stage channel. The maximum thickness of single-stage composite channel sand body can reach 15-20 m， the average thickness is 7-10 m， and the lateral extension range is more than 2 km， which can form the regular model reservoir. From east to west， the sand body in the outcrop area becomes smaller and the vertical continuity becomes worse. The sand body is the most developed and the lateral continuity is the best in the maximum advance period of fan delta. The sand body configuration of the Ba 3 Member in the outcrop area is comparable to that of the well of Dabei Gas Field， and the microfacies type and size of the skeleton sand body are consistent. The study on the sedimentary microfacies and configuration characteristics of the skeleton sand body of the Ba 3 Member in the northern Kuqa Depression provides the basic geological basis for the exploration and development of deep and ultra-deep natural gas.
The Well Mitan-1 obtained high-yield industrial gas flow in the fourth member of the Majiagou Formation of Ordovician（O1m4） in the mid-eastern Ordos Basin， which has achieved a major breakthrough in the exploration of Ordovician subsalt natural gas. However， there are disputes on the origin of natural gas in Well Mitan-1 at present. The measured results show that the natural gas in Well Mitan-1 is mainly composed of alkane gas （95.18%）， the gas drying coefficient （C1/C1-5）is 0.947， the content of H2S is 3.49%， and there is also a small amount of N2 and CO2 in non-hydrocarbon gas. The carbon isotopic compositions of methane， ethane and propane in the natural gas are -45.5‰，-26.4‰ and -24.3‰， respectively. Based on the regional geological background， the characteristics of potential source rocks and the geochemical characteristics of natural gas， it is considered that the natural gas in Well Mitan-1 is self-generated and self-accumulated oil-associated gas in Ordovician subsalt carbonate rocks. However， there are some geochemical anomalies， such as methane carbon isotope value （δ13C1） is lighter and ethane carbon isotope （δ13C2） has the characteristics of coal-type gas. Combined with the thermal simulation experiment of hydrocarbon generation and the characteristics of residual gas in rocks， it is considered that the special geochemical characteristics of Well Mitan-1 are closely related to the gypsum rocks. On the one hand， the ubiquitous gypsum-rock provides a good caprock， which makes retainment of the early-generated natural gas. On the other hand， the existence of gypsum rock promotes the generation of heavy hydrocarbon gases （
The expulsion gas intensity of Upper Paleozoic source rocks in the Linxing-Shenfu Gas Field at the eastern margin of the Ordos Basin is quantitatively evaluated based on the material balance method. The lower limits of TOC for effective source rocks of the Benxi， Taiyuan， and Shanxi formations in the Linxing region were determined to be 2.2%， 3.3%， and 6.3%， respectively； the lower limits of TOC for effective source rocks of the Benxi and Taiyuan formations in the Shenfu area were 6.3% and 9.0%， respectively， and the source rocks of the Shanxi Formation were ineffective source rocks because they can not be effectively expel gas. Based on the test gas capacity method and mechanical balance method， the Upper Paleozoic tight sandstone reservoir quality boundaries of the Linxing-Shenfu Gas Field were determined， and the reservoir grading was evaluated based on this method. Among them， conventional sandstone reservoir： porosity>15%， permeability >0.78×10-3 μm2； Class I tight sandstone reservoir： porosity 8%-15%， permeability（0.3-0.78）×10-3 μm2； Class II tight sandstone reservoir： porosity 6%-8%， permeability （0.1-0.3）×10-3 μm2； Class III tight sandstone reservoir： porosity <6%， permeability <0.1×10-3 μm2. The comprehensive gas source rock lower limit， reservoir grading evaluation， logging evaluation， and well production capacity analysis show that the differential configuration of the three elements of hydrocarbon source rock quality， reservoir quality， and inter stratigraphic fault migration channels in the Upper Paleozoic of the Linxing-Shenfu Gas Field is the controlling factor of differential gas enrichment. The gas saturation of conventional/class I tight sandstone reservoirs in the in-source rock and near-source rock formations near the effective source rocks is usually high and easy to obtain production capacity； the gas saturation of conventional reservoirs in the distant-source rock formations matching the inter stratigraphic fault transport channels is relatively high and can be used as exploration targets， and the exploration potential of distant-source rock formations in areas with sparse development of inter stratigraphic fault migration channels is limited.
The influence of hydrothermal fluid on hydrocarbon accumulation has become a hot spot in the study of petroleum geology in petroliferous basins. Through drilling core observation， rock thin section identification， temperature measurement of fluid inclusions， carbon and oxygen isotopes， element geochemistry， formation water analysis and other experimental technical methods， the characteristics of hydrothermal activity in the carbonate reservoir of Majiagou Formation， Jingbian Gas Field， Ordos Basin are analyzed， and the geological significance of hydrothermal activity for oil and gas is discussed. The result shows that the characteristics of hydrothermal activity of Majiagou Formation in Jingbian Gas Field are mainly reflected in the hydrothermal pyrite filling dissolution pores， the abnormal increase of homogenization temperature of fluid inclusions， the carbon and oxygen isotopes of vein calcite and the H2S sulfur isotopes in natural gas indicate the high temperature hydrothermal anomaly， and the rare-earth elements in dolomite show obvious δEu positive anomaly and δCe negative anomaly， and all the samples are distributed in the hydrothermal origin region of Ya/La-Yb/Ca intersection diagram， and some major and trace elements are significantly increased due to hydrothermal action. The characteristics of formation water show the result of the comprehensive action of various geological factors. Therefore， it is inferred that the deep hydrothermal fluid rises through basement faults and paleofaults， and enter Majiagou Formation along the unconformity surface at the top of the Ma 5 Member and paleofaults. In the early stage， the unstable components in the rock can be dissolved， forming a large number of secondary dissolution pores， which plays a constructive role in the reservoir. In the later stage， with the decrease of the temperature and the change of the pressure system of the hydrothermal fluid， the pyrite， quartz and calcite formed by the hydrothermal fluid began to precipitate in a large amount， filling dissolution pores and fractures， which played a destructive role in the reservoir.
As one of the important target layers for tight sandstone gas exploration in the Ordos Basin， the study of diagenesis affecting reservoir performance is relatively weak in the eighth member of Shihezi Formation （He 8 Member， P1x8） of Permian. Based on the core， thin section， scanning electron microscopy， cuttings logging and physical properties of P1x8， Su 75 block， the diagenesis of tight sandstone and its influence on reservoir genesis are comprehensively analyzed. The results show that the reservoir lithology of P1x8 is mainly feldspar quartz sandstone， which is generally a porous reservoir with low porosity and low permeability. The reservoir space of the reservoir is dominated by various dissolution pores， which account for more than 90%， while the primary pore， intergranular pore and fracture account for relatively little. P1x8 is in the middle diagenetic stage A-middle diagenetic stage B， and its diagenetic evolution sequence is early mechanical compaction-quartz I-chlorite film-intergranular kaolinite， illite cementation-debris and feldspar dissolution I-a small amount of authigenic quartz， illite cementation-a small amount of quartz II-a small amount of feldspar， calcite dissolution-quartz III. Reservoir development is mainly influenced by compaction， cementation and dissolution. Compaction reduces the porosity of reservoir by 22.36%， dropping to 0%-28.6%， with an average value of 12.65%. Cementation reduces the porosity by 9.12% to 0%-9.45%， with an average of 2.22%. The porosity of the reservoir increased by 0.0%-22.4%， with an average increase of 15.8%. The dissolution of cuttings， matrix， calcite and feldspar increased the fracture porosity by 18.65%， 12.3%， 17.5% and 14.3%， respectively.
In recent years， major breakthroughs have been made in oil and gas exploration of the eighth member of Yanchang Formation （Chang 8 Member） in southern Tianhuan Depression， Ordos Basin， which is a new field for increasing oil and gas production in the basin. As a new exploration area on the edge of the basin， there is a lack of understanding of the source of oil and gas， the coupling relationship between the structural evolution of Tianhuan Depression and hydrocarbon accumulation period， the process of oil and gas charging and the main controlling factors of hydrocarbon accumulation. Based on the relationship between source rock， oil source correlation， sand body distribution， tectonic evolution and hydrocarbon charging period， the main controlling factors of reservoir formation are analyzed， and the dynamic accumulation model of Chang 8 reservoir is established. The results show that the Chang 8 crude oil in the study area can be divided into A， B and C， in which class A is the main crude oil. There are three stages of hydrocarbon charging in Chang 8 reservoir， the first stage is the end of Jurassic （about 140-150 Ma）， the second stage is the Early Cretaceous （about 125-130 Ma） and the third stage is the late Cretaceous （about 100-110 Ma）. Oil and gas accumulation and adjustment in the study area are closely related to tectonic evolution. Tianhuan Depression was formed in the Late Jurassic to Early Cretaceous， and the structure controlled the period of oil and gas charging. The formation of Tianhuan Depression changed the direction of oil and gas charging， and source rocks controlled the scale of oil and gas distribution. This study is of great significance to next step of oil and gas exploration in the western margin of Ordos Basin.
The Upper Paleozoic tight sandstone in the Dingbei area has certain oil and gas exploration potential， but its diagenetic facies and distribution are more complex than conventional clastic rocks. The diagenesis and diagenetic evolution of the tight sandstone reservoirs containing volcanic ash in Tai 2 Member and He 1 Member in the north of Dingbei area are studied by using the data of ordinary thin slice， cast thin slice， scanning electron microscope， X-ray diffraction and logging response. The results show that： （1） The tight sandstone reservoir in the study area has undergone diagenesis such as volcanic ash alteration， compaction-pressure dissolution， cementation， metasomatism and autogenetic mineral filling which are unfavorable to the reservoir and diagenesis such as dissolution and fracture which are favorable to the reservoir. Different volcanic ash forms different diagenetic facies through diagenetic evolution， which further affects the reservoir performance. In the study area， the medium-basic volcanic ash can easily lead to the formation of dissolution phase， and the reservoir performance is good. （2） Based on the comprehensive factors such as diagenetic environment, mineral composition and diagenesis, five types of diagenetic facies are divided according to the diagenetic facies division standard of “diagenetic environment⁃lithology⁃diagenesis”:The compact diagenetic facies of atmospheric freshwater plastic granular sandstone, the dissolution compaction diagenetic facies of soluble granular sandstone in acidic environment, the dissolution diagenetic facies of soluble granular sandstone in acidic environment into rock facies, the dissolution diagenetic facies of soluble granular sandstone in acidic environment and the cemented metasomatic diagenetic facies of carbonate minerals in alkaline environment, among which the dissolution diagenetic facies of soluble granular sandstone in acidic environment is the most favorable. （3） The distribution characteristics of diagenetic facies in the study area are determined according to the logging discrimination characteristics of each diagenetic facies. The distribution of high-quality diagenetic facies in the small layers of Tai 2 Member and He 1 Member is influenced by the thickness of channel sand body in the longitudinal direction and the distribution of sedimentary microfacies in the plane.
Helium has become an important strategic resource because of its unique chemical properties. China's helium resources are relatively poor， and the security situation of helium resources is extremely serious. Helium has been discovered in Ordos Basin， but there are great differences in the understanding of helium volume fraction in the natural gas in the basin and insufficient understanding of the distribution law of helium resources at present， which restricts the potential evaluation and development and utilization of helium resources in the Ordos Basin. In this paper， based on the extensive collection and understanding of previous research results， the distribution of helium in Ordos Basin was analyzed based on magnetic anomaly data and helium content test results of 347 natural gas samples. The helium content of natural gas samples from Sulige， Qingyang and Yichuan gas fields is measured， and it is found that the helium content reaches the industrial level. The average helium content in Qing 1 well block of Qingyang Gas Field and Su 47 well block of Sulige Gas Field is more than 0.1%. We analyzed the magnetic anomaly based on the magnetic characteristics of rocks， and the results indicate that the magnetic anomaly of Ordos Basin have obvious zoning characteristics， reflecting the geological characteristics of multi-stage integration of basin basement. The regional magnetic anomaly variations are mainly related to the lithology of the basin basement， and the high magnetic anomaly bands may be caused by the strong magnetic rock mass such as the archaean-Lower Proterozoic deep metamorphic gneiss， metaggrin， basic volcanic rocks， and the corresponding granites in the basin basement. Low magnetic anomaly is mainly caused by weak magnetic rock mass such as slate， schist， phyllite， quartzite and marble. The helium gas in Ordos Basin is mainly derived from crust， and the deep metamorphic rocks in the lower Proterozoic are the helium source rocks in Ordos Basin. The northeast high magnetic anomaly belt in Pingliang-Qingyang-Yan’an-Jiaxian area in the middle of ordos Basin is the main helium distribution area.
Current studies have found that there is a coupling effect between the accumulation of helium and natural gas， and the two show an allogenetic and co-storage relationship. The differences of helium accumulation between Dongsheng and Daniudi gas fields in the Ordos Basin were analyzed from the aspects of helium source rock and migration mode. The results showed that： （1） The main helium source of the two gas fields is basement rock helium gas. The helium source rock of Dongsheng Gas Field may contain basement rock and coal seam rich in U and Th， while the helium source rock of Daniudi Gas Field may contain basement rock， coal seam and bauxite rock. （2） In Dongsheng Gas Field， faults connected with the basement are developed， providing a channel for the migration of alkane gas and helium gas. In Daniudi Gas Field， basement faults also exist， but the gas field is migrated by micro-fractures generated by hydrocarbon generation. （3） It is concluded that the deep and large fault connecting basement and reservoir plays an obvious role in the accumulation of helium gas.
Based on core data， physical property， well logging， gas test， composition， helium distribution of 13 new wells， in combination with regional tectonic evolution， depositional background and typical gas reservoir profile， geological characteristics and main controlling factors of helium-rich gas reservoirs have been explored. The results show that three gas reservoirs formed from bottom to top， i.e.， granite and metamorphite fractured reservoir in basement， tight sandstone structural reservoirs in Devonian and huge continuous carbonate reservoirs in Lower Carboniferous. The fracture developed on structural points controls high production and gas is well displayed in low structural area. Dry gas is rich in helium and the helium content is lower from basement to Carboniferous. The pre-Devonian large-scale granite and metamorphite basement is the main helium source， and the high-gamma sandstones of Devonian and Carboniferous are the secondary source. The fracture is filled up and conducts in two-ways， gas from Carboniferous source rocks migrate downward and helium migrate upward. Thick interbedded gypsum-tight limestone on the top of Lower Carboniferous is the regional caprock preserving helium-rich gas reservoir.
Tight gas reservoir is the main hydrocarbon accumulation type in the Sulige Gas Field. Block Su 39 is one of the most important exploration zones in the gas-water transition zone of the Sulige Gas Field. Based on the data of trial production， well logging， reservoir， and geological setting， the gas-water distribution pattern of Taiyuan Formation（P1t）-H8 member（P2h8） in block Su 39 is systematically studied. The research results showed that the gas-water distribution can be divided into five types， including pure gas type， same-layer gas-water type， upper gas-lower water type， upper water-lower gas type， and pure water type. The distribution range is regulated by hydrocarbon generation intensity， while the distance between source and reservoir influences the longitudinal distribution. Local structure， faults， reservoir physical properties， and reservoir heterogeneity affect the vertical distribution of gas and water. Two distinct tight sandstone gas and water distribution models are established due to the difference of different source-reservoir combinations.
Tight tuffaceous sandstone is a special type of tight sandstone. Its pore structures and porosity permeability relationships are quite different from those of conventional tight sandstone. It is difficult to classify and evaluate the tight tuffaceous sandstone by using conventional reservoir classification methods. This paper studied the tight tuffaceous sandstone of Yingcheng Formation of Dehui fault depression in southern Songliao Basin， where Nuclear Magnetic Resonance （NMR） and high pressure mercury injection are the main means. Pore structure characteristics of tight tuffaceous sandstone are analyzed and the differences with conventival tight sandstone are compared. Correlation analysis was adopted where R50 （The throat radius corresponding to the mercury saturation of 50%） and movable fluid saturation are selected as the key parameters to establish a comprehensive new evaluation model for reservoir classification of tight tuffaceous sandstone. Results demonstrate that premium tight tuffaceous sandstone develops intergranular and intragranular dissolution effective pores， has noticeable right-sided T2 spectrum distribution and high movable fluid saturation， while inferior tight tuffaceous sandstone mainly has tuffaceous dissolution pores and intercrystalline pores and left-sided T2 sepctrum. In addition， the pore structure characteristics were analyzed by means of high pressure mercury injection and constant velocity mercury injection， and four typical mercury injection curves were identified，i.e.， large pore-tiny throat， middle pore-tiny throat， middle pore-micro throat and small pore-micro throat. The corresponding tuffaceous content gradually increases， and it was believed that the main reason for poor correlation between porosity and permeability was that tuff blockes key throats and then decreases permeability. Pore structures between tight tuffaceous sandstone and conventional tight sandstone are compared and analyzed. Tight tuffaceous sandstone developes more tiny pores， has worse porosity-permeability correlations， less effective storage capability and connectivity than conventional tight sandstone. R50 and movable fluid saturation are adopted and tight tuffaceous sandstond reservoirs are divided into type Ⅰ，Ⅱ，Ⅲ reservoirs and dry reservoir， where the classification results coincide with the testing results.
The exploration process of natural gas in Ordos Basin is closely related to the research progress of oil and gas geochemistry. In this paper， through the analysis of the geochemical system of a group of Paleozoic natural gas in the central and eastern Ordos Basin， combined with the collection and collation of previous geochemical data， the geological and geochemical correlation analysis of Paleozoic natural gas is carried out. The main source of natural gas in the Lower Paleozoic is further defined by the stratification and regional comparison of natural gas composition and hydrocarbon isotope composition in the Ordovician system. The results show that there are obvious differences in the geochemical characteristics and genesis of natural gas in different strata. The carbon isotopic composition of methane and ethane in the Upper Ordovician is relatively heavier， and carbon isotopic reversal exists between some methane and ethane， i.e.，
The Upper member of Xiaganchaigou Formation （E32） and the Shangganchaigou Formation （N1） source rocks are the main source rock strata of the Cenozoic petroleum system in the western Qaidam Basin. Due to the sedimentary center shifting from the Yingxiongling area to the Xiaoliangshan area， the geochemical characteristics show great differences in the region. In order to clarify the changes in organic matter origin and sedimentary environments of E32-N1 source rocks in the process of depocenter transferring and explore the formation mechanism of E32-N1 source rocks， organic petrology and organic geochemistry analysis have been carried out. The results show that the organic matter of E32-N1 source rocks in western Qaidam Basin is generally at a low-mature to mature stage. Affected by uplift， the maturity of E32 source rocks in Yingxiongling area is lower than that of N1 source rocks in Xiaoliangshan area. The paleoclimatic conditions were hot and dry during the deposition of the E32 source rock， resulting in the watermass stratification. The N1 source rocks in Xiaoliangshan area were deposited in an open lake basin with deepening water and decreasing salinity. The organic matter abundance of E32 source rocks in Yingxiongling area is higher than that of N1 source rocks in Xiaoliangshan area. The organic matter types of E32 source rocks in Yingxiongling area are mainly type I-II1， and their organic matter sources are mainly planktonic algae such as botryococcus， dinoflagellates and pediastrum， and prokaryotes such as sulfur bacteria. The organic matter sources of N1 source rocks in Xiaoliangshan area have changed from aquatic organisms to freshwater algae such as green algae with more terrestrial higher plants supplying organic matter. The organic matter is mainly type II1-II2. During the deposition of E32 source rocks in Yingxiongling area， watermass salinity was extremely high and bottom watermass environment was extremely anoxic. Compared with the E32 source rocks， the N1 source rock in Xiaoliangshan area deposited under brackish water and weak reducing conditions， which tend to be less OM preservation than E32 source rock. Accordingly， two sets of source rock differential formation patterns were established.
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