The accurate calculation and distribution characteristics of CBM saturation are directly related to the prediction of CBM enrichment area and the effective formulation of CBM development plan. Based on the adsorption isotherm curve of coalbed methane in the Daning-Jixian gas field， this paper gives a calculation model of coalbed gas saturation， and then fully excavates the geophysics logging information， a logging method is established to determine the parameters of Lannister volume， Lannister pressure， reservoir pressure and gas content in coal bed gas saturation， and a logging method for deep coal bed gas saturation is formed. The method is programmed to realize the computer visual automatic processing of gas saturation of 8# coal reservoirs in each well depth in the area， and the plane distribution map of gas saturation in the study area is drawn. The study shows that the method described in this paper can be used to calculate the gas saturation of 8# coal reservoir in the deep part of the study area， and the gas saturation of the coal bed in the study area increases from east to west on the whole， from the north to the south after the first decline， and then decline after the increase. The supersaturated gas reservoir area is located in Wells Daji 50 and Daji 37 in the south of the study area， and the saturated gas reservoir area is mainly located in the north and middle of the study area. This method can provide a new way for geophysics log to predict gas saturation in deep coalbed and a basic parameter for prediction of CBM enrichment area.
To search for the distribution of deep coalbed methane resources， it is urgent to identify the macerals and pore distribution characteristics of deep coal reservoirs. Therefore， taking the No.8 coal seam in Well M172 as an example， the paper conducted coal macerals， nuclear magnetic resonance porosity， and electron microscopy imaging in the Yulin area. The paper analyzed the parameters such as pore fracture types， pore connectivity， porosity， and pore structure distribution of coal rocks in the Yulin area， and explored the main controlling factors that affect coal seam reservoir performance， such as pore structure and macerals， as well as the mechanism of gas pore formation. The research results indicate that： （1）There are three peaks in the nuclear magnetic relaxation time T2 of saturated water coal samples， with peaks located at 0.2 ms， 8 ms， and 300 ms， corresponding to adsorption pores， transition pores， and free pores， respectively， with adsorption pores being the main ones. （2）The total porosity and effective porosity of coal samples increase with the increase of vitrinite content； pores in coal rocks are related to the production of liquid hydrocarbons， and the matrix vitrinite develops a group of pores generated by the cracking of liquid hydrocarbons. （3）There are two types of occurrence states in deep coal seams： free gas and adsorbed gas. The coal seam has a higher gas content， and the gas saturation is generally supersaturated. The main controlling factors for coalbed methane accumulation are more complex， with multiple types of reservoir formation developed， such as fault shielding， hydrodynamic traps， structural lithology， and micro structures. The types of reservoir formation are more abundant than those in the middle and shallow layers. The study and genetic analysis of the pore structure characteristics of deep coal and rock in this article have certain geological significance for clarifying the formation laws of deep coalbed methane reservoirs.
At present， interlayer shale oil is the focus of shale oil exploration and development. How to quantitatively evaluate the occurrence and content of free and adsorbed hydrocarbons in shale oil reservoirs and the fluidity of hydrocarbons is the key to the exploration and development of Chang 7 shale oil. By means of nuclear magnetic resonance and constant velocity mercury injection， the reservoir properties， hydrocarbon occurrence and oil content of Chang 7 interbedded shale oil in the eastern region of Longdong were analyzed. The results of NMR experiments showed that the permeability of Chang 71， Chang 72 and Chang 73 sub-members was not much different， and they were all distributed in about 0.006×10-3 μm2. Among them， Chang 72 sub-member had the highest porosity and mobile fluid saturation， while Chang 73 sub-member had the lowest. In the constant velocity mercury injection experiment， the average pore radius size of the three sub-members of Chang 7 was not much different （130-150 μm）， but the average throat radius size of Chang 73 sub-member （6-8 μm） was significantly better than that of the other two sub-members （less than 0.5 μm）， and the pore throat characteristics of Chang 73 sub-member were better than those of the other two sub-members. In terms of the evaluation of free and adsorbed hydrocarbons， the free hydrocarbon content of Chang 71 sub-member is significantly higher than that of Chang 7 sub-member， and the Chang 71 sub-member has a large area of continuous distribution of sand bodies， so compared with Chang 72 sub-member， Chang 71 sub-member has more advantages in resource development. For Chang 73 sub-member， the total extraction amount and absolute free hydrocarbon content are the highest. If large contiguous sand bodies can be found， it will also have certain development significance.
It is greatly beneficial for shale gas development and increased production by characterizing the connectivity of natural fractures in shale reservoirs and evaluating the mechanical effectiveness under in-situ stress condition. Taking the Wufeng-Longmaxi formations in the Dingshan-Dongxi area， southeastern margin of Sichuan Basin as an example， the characteristics of natural fracture were identified by core observation， imaging logging， and 3D laser scanning， and their connectivity and mechanical effectiveness were characterized and analyzed. The results show that the natural fractures are mainly medium-high dip angle shear fractures， interlayer slip fractures， and bedding fractures with dominant NE and near EW strike， and the unfilled percentage is about 9.7%. Unfilled fractures mainly exist in interlayer slip fractures and high dip angle（>45°） shear fractures. The natural fracture types in the Dingshan-Dongxi area can be well distinguished by the image characteristics from imaging loggings. The topological analysis of the fracture network shows that the number of lines （CL） and the number of branches （CB） are generally lower than 2 and 1.5， respectively， indicating that fracture network is poorly connected. Furthermore， there are many fractures with more sets and good connectivity in the overlapping areas in Dingshan nose shaped folds. The connected fractures network mainly exists in the 1-3 sub-members and the longitudinal CL and CB are 1-3 times different. The joint roughness coefficient （JRC） of the natural fracture surface in the study area is between 2.2 and 14.1， which shows a decreasing trend with the increase of clay content. Under in-situ stress， all natural fractures are in mechanical ineffectiveness state. Among them， in the section of argillaceous and argillaceous-rich shale （clay content >30%） with small minimum principal stress and large two-directional stress difference， the low-high dip angle natural fracture with 30°-75° to the maximum principal stress has a better mechanical effectiveness. Our research can provide a reference for natural fracture fine model and “sweet pot” prediction of shale reservoirs.
Almost all the natural gas reserves of Carboniferous system have been found in volcanic rocks in Junggar Basin. Well Shiqian 1 has obtained high production industrial gas flow in carboniferous marine sandstone reservoir for the first time， which opens up a new field of carboniferous natural gas exploration in the basin. In order to evaluate the exploration potential of marine sandstone reservoirs， and point out the direction of natural gas exploration， comprehensive analyses for the source rocks， reservoirs， natural gas types， structural evolution and accumulation process of Shiqiantan Formation were carried out， and it is concluded that： （1） There are two sets of source rocks in Shiqiantan Formation. Influenced by transgressive and regressive environment， the two sets of source rocks have slight differences in the abundance of organic matter， thickness and distribution of organic matter. （2） Under the influence of compression and cementation， the pore space of marine sandstone reservoir is not developed， and the main reservoir space is micro-corrosion pore and micro-fracture， and the physical property of the reservoir is poor. （3） There are two types of natural gas in Shiqiantan Formation： oil-type gas and coal-type gas. The high-producing wells in the northeast direction of the depression show oil-type gas characteristics， and the natural gas mainly comes from the source rock of the lower member， while the low-producing wells in the northwest direction show coal-type gas characteristics， and the natural gas mainly comes from the source rock of the upper member. （4） The source rocks of Shiqiantan Formation have high hydrocarbon generation and great exploration potential. The source rocks of the lower section have good preservation conditions and favorable conditions for developing self-generated and self-storage gas reservoirs， and the exploration prospect is the best.
Taking the deep-ultra deep glutenite reservoirs of the Upper Wuerhe Formation of Permian in Fukang Sag and Dongdaohaizi Sag as the research object which are the representative of eastern Junggar Basin， the characteristics and main controlling factors of deep-ultra deep glutenite reservoirs are analyzed by using cores， thin sections and scanning electron microscope observation， combined with high-pressure mercury injection and logging imaging， to further reveal the reservoir development model of the Upper Wuerhe Formation in the eastern Junggar Basin. The results show that Fukang Sag and Dongdaohaizi Sag are deep-ultra deep glutenite reservoirs， of which Fukang Sag belongs to a typical low porosity to ultra-low permeability reservoir， while Dongdaohaizi Sag belongs to a low porosity to low permeability reservoir. There are differences in the types of reservoir spaces. Microfractures and corrosion pores are mainly developed in Fukang Sag， while a large number of corrosion pores exist in Dongdaohaizi Sag， with few fractures. Both compaction and cementation have a strong destructive effect on the reservoirs in the eastern Junggar Basin. However， the compaction effect in Fukang Sag is very strong， and the dissolution effect is weak. The large number of fractures generated by overpressure become effective channels for ultra deep oil and gas migration. The cracks in the Dongdaohaizi Sag are underdeveloped， and a large number of intra-particle corrosion pores generated by dissolution of feldspar and turbidite improve the reservoir properties. In addition， its rich turbidite also plays a compressive and pore retention role. There are two types of reservoir models developed in the Upper Wuerhe Formation of Permian in the eastern Junggar Basin： the deep fracture model represented by the Fukang Sag and the solution pore model rich in turbidite in the Dongdaohaizi Sag， which create good conditions for oil and gas accumulation in the deep-ultra deep reservoirs in the depression area.
The tight sandstone reservoir of the Sangonghe Formation in Taibei Sag is an important succession field in Turpan-Hami Basin and the formation process has not been clearly understood， which restricts the efficient exploration in this field. Therefore， in this paper， basin simulation， structural evolution history analysis， fluid inclusion testing and other methods are comprehensively used to simulate and study the key reservoir forming factors of tight sandstone reservoirs in Sangonghe Formation of Qiudong sub-sag， including hydrocarbon generation and expulsion history of source rock， reservoir diagenetic evolution history， regional structural evolution history， oil and gas charging history， and the matching relationship of these reservoir forming factors in geological history is systematically studied. The results show that the hydrocarbon generation and expulsion period， hydrocarbon charging period， reservoir evolution and tectonic setting configuration control the enrichment of hydrocarbon. The Sangonghe Formation experienced three stages of hydrocarbon charging in Qiudong sub-sag. The first stage occurred at the end of Early Cretaceous. Under the background of tectonic activity in the second stage of Yanshan Period， a limited amount of low-mature crude oil gathered in low-amplitude uplifts in depression areas and higher positions of Wenjisang structure to form low-mature oil reservoirs， and the reservoir is relatively dense. The second stage occurred at the end of Late Cretaceous， a large amount of oil and gas were produced by the mature source rocks while the expulsion of organic acids improved the sandstone reservoir space of Sangonghe Formation， which was conducive to the charging process of hydrocarbons and the mature oil and gas reservoirs were formed in the Wenjisang area and the low uplift area of Qiudong sub-sag （near Well J7H）. At the end of Paleogene， the Lower Jurassic source rocks began to generate a lot of gas. At this time， the reservoir was tight， the depression area was flat with stable structures which create a suitable condition for hydrocarbon near-source charging to form a large-scale tight condensate gas reservoir （containing oil）. It is proved that the Sangonghe Formation in Qiudong sub-sag favors the formation of large-scale tight condensate gas reservoirs， which is a promising area for future exploration of the Lower Jurassic in Taibei Sag.
The residual distribution of the Permian in the northern margin of the Qaidam Basin has attracted significant attention due to its relevance to gaining a deeper understanding of the late Paleozoic sedimentary and tectonic evolution and facilitating further development and utilization of energy resources. This study focuses on the field geological observations and systematic detrital zircon geochronology research of the Taiyuan Formation in the Mobar section of the Lenghu area， located in the western section of the northern margin of Qadam Basin. In this study， tuffaceous sandstones were identified in the western section of the northern margin of Qaidam Basin. The detrital zircons from these sandstones yielded an average age of 294 Ma， we think that these strata should be defined as the Lower Permian. Furthermore， by integrating the characteristics of detrital zircons and lithological assemblages from the eastern section， it is inferred that Early Permian sedimentary strata are extensively preserved in Qaidam Basin. The collected samples from the Lower Permian mainly exhibit two detrital zircon age groups， ranging from 280 to 329 Ma and 415 to 468 Ma， respectively. The primary sources of these age groups correspond to various magmatic rocks in the tectonic belt of the northern margin， the ultrahigh-pressure metamorphic belt of the northern margin of Qaidam Basin， the Liuhe Group， and the Dakendaban Group. Since the Permian， the Kunlun Ocean has been characterized by continuous subduction， plate fracturing， or retreat， and significant upwelling of the asthenosphere beneath the subduction zone. This has triggered transient and large-scale volcanic activity， with volcanic debris serving as the main source for the sedimentary strata. The discovery of the Upper Paleozoic-Lower Permian strata in the study area provides a new direction for oil and gas geological research and exploration deployment in the northern margin of Qaidam Basin.
The Songnan-Baodao Sag is another important deepwater exploration area with huge oil and gas exploration potential discovered after the Lingshui Sag in the Qiongdongnan Basin. The structural background of the northern step-fault zone is complex， and it has undergone multiple stages of stress field deformation and superimposed evolution since the Cenozoic era. The complex structural system formed has an important controlling effect on the formation of large and medium-sized oil and gas fields in the deep water area. This paper systematically studies the geometry， kinematics， and dynamics of the Songnan-Baodao northern step-fault zone using newly collected and processed high-precision 3D seismic data and new exploration results covering the research area， based on comprehensive interpretation of fine seismic profile structures and strata， combined with techniques such as quantitative analysis of fault activity， inversion of subsidence history， and restoration of tectonic evolution history. The research results show that the Songnan-Baodao northern step-fault zone is a right step oblique and co directional superimposed step-fault zone composed of No.2 fault， No.2-1 fault， No.12 fault， and No.12-1 fault. It has undergone the evolution process from a high angle normal fault in the direction of Eocene NE to a high angle and low angle extensional detachment fault in the direction of Oligocene near EW， and has controlled the development of large detachment basins in the central depression zone. The large transition zones formed at the overlapping positions of the faults have become the key structural factors controlling the main source rocks， source sink systems， and large reservoirs in the fan delta and braided river delta of the third member of the Eocene and Yacheng Formation.
The granitic buried-hill is an important oil and gas exploration field in the deep water area of the Qiongdongnan Basin in the western part of the South China Sea， among which the granitic buried-hill area of the Lingnan Low Uplift has a low degree of natural gas resources exploration and great exploration potential. In order to accelerate the exploration process of the buried-hill on the Lingnan Low Uplift， the comprehensive evaluation of hydrocarbon accumulation conditions such as hydrocarbon source conditions， reservoir cap combination， and transmission system was carried out， and a variety of geophysical means were combined to predict the fracture reservoirs in the buried-hill and pointed out favorable targets for subsequent evaluation. The results show that： （1） The buried-hill on the Lingnan Low Uplift， adjacent to the Ledong-Lingshui hydrocarbon-rich sag， developing the coupled reservoir cap assemblage composed of Neogene thick cover of marine mudstone and Mesozoic granite buried-hill reservoir， having the advantages of composite migration mode composed of large source-connected faults， buried-hill insider faults and inherited structural ridges， as well as large source storage pressure difference and near-source charging， has superior storage conditions. （2） The application of likelihood， ant body， curvature body and attribute fusion technology， combined with regional tectonic stress field and main fault production status， comprehensively predict the spread characteristics of the buried-hill fracture reservoirs in the Lingnan Low Uplift， and delineate the favorable exploration area， such as Ling 1 and Ling 4， which is helpful to promote the subsequent exploration and evaluation work. The Lingnan Low Uplift， having excellent hydrocarbon accumulation conditions， which is predicted that there are multiple tectonic zones with reservoir development and high probability of large-scale accumulation， is a new favorable direction for oil and gas exploration in the deep water areas in addition to the Central Canyon of the Qiongdongnan Basin.
Assemblage characteristics of biomarkers are mainly related to the sedimentary environment， source input of organic matters and maturity of source rocks. The studies of organic petrology show that the organic compositions of oil shales in Well BK4， Quse Formation in South Qiangtang Basin are rich in macerals derived from higher plants， such as vitrinites， inertinites and exinites， and also high in amorphous organic matter， mainly humic amorphogens. The analysis of biomarker compounds shows that the abundance of compounds with higher plant origin is lower， but the abundance of ones related to bacterial origin was higher. In terms of the composition and distribution of biomarkers related to the sedimentary environment， some compounds show the distribution characteristics of marine or saline lacustrine source rocks， such as low Pr/Ph value， high abundance of aromatic dinosteranes and dibenzothiophenes compounds. However， the source rock with these characteristics mentioned above contain abnormally high abundance diasteranes， high abundance C29Ts and extremely low abundance gammacerane， which also show some anomalies. The emergence of high abundance of bacterial biogenic compounds in oil shale shows that the role of bacterial microorganisms in the biochemical stage has an important influence on the combination of biomarker compounds. The differences in the sources and accumulation processes of terrestrial and aquatic organic matter and the differences in biochemical processes may be the main factors causing the abnormal assemblage of biomarkers.
In recent years， oil and gas exploration have achieved progress in the western part and northern margin of the the Qaidam Basin. But there is still a debate over the source of oil and gas in the new exploration areas. C5-C7 light hydrocarbons can be used to provide new information on the origin of natural gas. Natural gas samples were collected from the western part and northern margin of the Qaidam Basin. The components and individual carbon isotopes of C5-C7 light hydrocarbons in natural gas were analyzed. The results show that the light hydrocarbons from the western Qaidam Basin are characterized by a high content of n-heptane， and high carbon isotopes with δ13CMCC5 and δ13CMCC6 in the range from -23‰ to -18‰ and -24‰ to -20‰， respectively. While light hydrocarbons from the northern margin of the Qaidam Basin are featured by high contents of methylcyclohexane and toluene， and relatively low carbon isotopes with δ13CMCC5 and δ13CMCC6 in the range from -28‰ to -22‰ and -26‰ to -23‰， respectively. These characteristics indicate that the light hydrocarbons in the western Qaidam Basin mainly come from the saline lacustrine mudstones in the Paleogene-Neogene formation， and those in the northern Qaidam Basin are mainly generated from the Jurassic coal-bearing source rock. In addition， combined with the geochemical characteristics of natural gas and crude oil， the sources of oil and gas in the Nanyishan and Dongping fields are further studied. In the Nanyishan oil and gas field， natural gas may come from the Jurassic coal-bearing source rocks and Paleogene-Neogene source rock， and crude oils are mainly produced from Paleogene-Neogene source rock. In the Dongping gas field， natural gas is mainly generated from the Jurassic humic organic matters， while light hydrocarbons and condensate are mainly produced from the Jurassic sapropelic organic matters.
To guide the effective development of buried-hill fractured condensate gas reservoirs， in this paper， the experiments of gas injection into long cores and vertical-profile models are performed， which aims to study mechanisms of gas injection in terms of oil displacement efficiency and vertical sweep efficiency for buried-hill fractured condensate gas reservoirs， respectively. Results show that， for the depleted development， the oil recovery of fractured formation is higher than that of non-fractured homogeneous formation at early stage （>32 MPa）， but turns to be lower at mid-late stage （<32 MPa）. Under the maximum condensate pressure （23 MPa） and abandonment pressure （5 MPa）， fractures reduce the recovery rate of condensate oil by 1.37% and 4.77%， respectively. Injecting gas at maximum condensate pressure increases the recovery rate of condensate oil by 20% for homogeneous formation， and is not closely related to permeability. Affected by gas channeling， the recovery rate of condensate oil increases by 13.7% for fractured formation. During the gas-injection， the fractured formation presents two types of gas channels， i.e.， fracture and matrix-fracture， which is inferred from the dual-step pattern in gas-oil ratio curve whose inflection points are 0.4 HCP and 1.4 HCPV， respectively. The oil recovery increases significantly during gas injection， but is essentially coincidence with that in the full-time depletion during the subsequent depletion stage. Combining the gas-injection PVT experiments， it is proposed that the pressure maintaining and oil displacement， serve as the main mechanisms for improving oil displacement efficiency. In terms of the gas injection timing， the effect of high-pressure gas injection is significantly better than that of low-pressure gas injection for non-fractured reservoirs. As for fractured reservoirs， the impact of gas injection timing is not significant. In terms of vertical sweep efficiency， the barrier of the non-fractured reservoir has a certain obstruction effect on the gravity differentiation， but the gravity-drive characteristics is obvious in general with the highest gas-drive degree at reservoir top. The high-dip fractures in buried-hill reservoirs hinder the lateral flow of injected gas from injectors to producers. The gravity-drive characteristics is relatively weak， and no obvious low-saturation zone is formed. The gas-drive degree in the middle section is the highest. This study will provide effective guidance for the design of gas injection plans and dynamic tracking adjustments for buried-hill fractured condensate gas reservoirs.
The Longwang Formation gas reservoir in Moxi area of Sichuan Basin has great resource potential， but the gas reservoir has strong heterogeneity and complicated gas-water relationship. The main controlling factors of water invasion under different water invasion modes are not clear， and the increasingly severe water invasion situation makes it difficult to effectively use the reserves， thus affecting the gas reservoir recovery. Based on the data of core， thin section， conventional and imaging logging， seismic and production dynamics， the types of producing wells are divided， and the main controlling factors and rules of water invasion in different well areas are determined by combining dynamic and static data. The results show that： （1） According to the characteristics of water production， wells can be divided into four types： fast rising， slow rising， stable and compound types， and the water production characteristics of four types of wells are obviously different. （2） Different water production types are controlled by the coupling of the fracture development degree， the distribution of karst cavern high permeability layer， the tectonic amplitude and reservoir connectivity. Fast-rising water-producing wells are mainly controlled by the degree of fracture development， continuous-rising water-producing wells are mainly controlled by the distribution of dissolved cave-type high-permeability layers， stable water-producing wells have relatively homogeneous reservoirs， and composite water-producing wells are controlled by multiple factors. （3） Different well areas show different water invasion modes under the influence of different main controlling factors： the water influx mode in the MX009-3 well area is fractured water channeling type with fast water influx speed and high water production； the water influx mode in the MX8 well area is the high permeability layer fingering type， and the water production rate rises rapidly and then tends to be stable； the MX10 well area is an apparently homogeneous reservoir， the water invasion mode is edge water tongue type， and edge water advance is relatively uniform； the MX204 well area is located in the gas-water transition zone， which shows the bottom cone transgression type. The research results can provide geological guidance for improving gas reservoir recovery and adjusting development technology policy， and provide reference for the research and development evaluation of water invasion law in the same type of water gas reservoir.
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