The potential of hydrocarbon resources in Awati Sag and its surrounding marine source rocks is huge， and the development of marine sandstone reservoirs is a key factor restricting oil and gas exploration in the Keping thrust nappe belt of Awati Sag. Taking the Upper Ordovician-Lower Silurian Kepingtage Formation sandstone as an example， this paper， by combining outcrop， drilling， seismic and experimental data， uses multi-factor superposition analysis method to determine the sedimentary system， reservoir characteristics and exploration significance of large-scale sand bodies in marine environment. The results show that the Kepingtage Formation in the western margin of Awati Sag was dominated by constructive tidal delta sedimentary system in the early stage and shoreline sedimentary system in the late stage. The sandstone of Kepingtage Formation is dominated by lithic sandstone， followed by lithic quartz sandstone， which has the characteristics of low compositional maturity and high structural maturity. Intergranular pores and structural fractures are developed， and the porosity is generally 6%-10%. It is dominated by Class IV reservoirs， and there are a few Class II reservoirs in Class III reservoirs. Mainly controlled by sedimentary microfacies and tectonic extrusion， the progradation belt of thrust napp and the delta and foreshore sandstone reservoirs in the slope area of the west margin of Awati Sag are relatively developed. The fault block and sandstone updip pink-out oil and gas reservoirs are developed on the northwest slope of Awati Sag， and the favorable zone area reaches 4 320 km2. The estimated natural gas resources are 707.6 billion square meters and the oil resources are 7 817 million tons. The deep-ultra-deep weak structural compression area in the Keping thrust-nappe front is a strategic advantageous area for the exploration of structure-lithologic reservoirs.
The explorational breakthroughs have consistently revealed a huge new oil and gas production area in the Bozi-Dabei regions within the western Kelasu structural belt， Kuqa Depression， Tarim Basin. However， oil and gas compositions， physical properties， and oil and gas reservoir types are complex. There are unclear oil and gas phase states and physical property distribution rules， and the main controlling factors of oil and gas phase states are not clear. In this study， 75 production-well data were systematically collected for statistical analysis and phase simulation， including hydrocarbon compositions and physical parameters of oil and gas production （e.g.， density， viscosity， colloidal content， asphaltene content， dryness coefficient， production gas-oil ratio）. Oil and gas reservoirs were divided into four types of volatile oil reservoirs， condensate gas reservoirs， wet gas reservoirs and dry gas reservoirs according to the dryness coefficient and gas-oil ratio， and then the phase characteristics and occurrence of oil and gas were reconstructed under geological conditions to reveal the main controlling geological factors of phase distribution. The results indicate that the hydrocarbon fluids are generally characterized by the distribution of block-divided from east to west and belt-divided from north to south in the study area. The physical parameters （e.g.， density， viscosity etc.） show a gradual increasing trend from west to east. The occurrence of oil and gas transforms from liquid phase to condensate phase， condensate （wet gas） phase and dry gas phase from deep to shallow reservoirs. Four types of oil and gas are located in circle-curved distribution caused by the maturity differences of the Jurassic Qiakemake source rocks. The distribution of target strata controls the distribution of volatile oil reservoirs， condensate gas reservoirs and wet gas reservoirs. The distribution of dry gas reservoirs is attributed to the combined contribution of mature Jurassic and high-over mature Triassic source rocks. This study has successfully confirmed the distribution of oil and gas phases and physical properties， exploring the main controlling factors for the complexity of oil and gas phases in the Bozi-Dabei regions， which can provide theory-supported helps for the further oil and gas exploration and development in the Kuqa Depression.
At present， the study on the tectonic deformation characteristics， deformation mechanism and controlling factors of multiple sets of detachment layers such as salt rock and coal measure strata during compressive tectonic activity is relatively weak. In this paper， based on high-precision 3D seismic data and drilling data， the multi-detachment tectonic deformation patterns of the western， middle and eastern sections of Kuqa foreland thrust belt are established. Combined with numerical simulation and tectonic evolution， the characteristics， controlling factors and deformation mechanism of the multi-detachment tectonic deformation of Kuqa foreland thrust belt are systematically analyzed. It is divided into five structural layers： upper salt layer， salt layer， lower salt layer， coal layer and lower coal layer. The analysis shows that the Kuqa foreland thrust belt has experienced multiple tectonic activities such as late Hercysian-Indosinian， Yanshanian and Alpine， and the paleothrust structure formed in the late Hercysian-Indosinian controlled the Mesozoic sedimentary pattern. The distribution difference between the detachment layer of the salt rock and coal measure strata and the paleo-uplift jointly controlled the stratified tectonic deformation， and the paleo-uplift controlled the distribution of the detachment layer and the scale of the thrust belt. Salt rock controls shallow and subsalt thrust structures， and coal measure strata controls thrust belt front and subcoal thrust structures. The salt layer is dominated by cap slippage， the imbricated thrust structure is developed under the salt， the salt dome， salt pillow and salt puncture are formed by the plastic flow of the salt rock， the coal seam crumples and deforms， the coal layer shear thrust and the coal layer slippage thrust are characterized by “integral extrusion， multi-layer slippage， vertical superposition and stratified deformation”. The coal measure strata are not only the source rock， but also the cap layer and the slip layer. The whole Mesozoic strata have coaxial deformation in the process of tectonic compression. The thrust fault below the coal measure strata has the characteristics of a row of belts， and the slip thrust fault in the coal layer is simple， the structure is wider and slower， and the oil and gas exploration potential is larger.
In order to explore the diagenetic characteristics， influence mechanism and the distribution of dominant diagenetic facies of Fengcheng Formation in the southern margin of Mahu Sag， this paper quantitatively characterized the reservoir transformation intensity of compaction， cementation and dissolution on the basis of the analysis of petrological characteristics， pore types， diagenesis and diagenetic environment evolution， and established a diagenetic facies division scheme. Based on the evaluation results of single well coring interval， the characteristics of diagenetic facies distribution are described， and the influencing mechanism of diagenetic facies distribution is explained. The results show that the reservoir space of Fengcheng Formation in the study area is characterized by a dual medium of “matrix-pores dominated and micro-fractures supplemented”， in which the intra/intergranular dissolved pores are dominant in the matrix pores. The Fengcheng Formation has undergone the evolution of alkaline sedimentary environment and alkali-acid-alkaline diagenetic environment. The alkaline sedimentary and early alkaline diagenetic stages are the important periods for the loss of intergranular pore cementation， the hydrolysis of volcanic materials and the formation of solution pore by plagioclase albitization. The reaming in the acidic diagenetic environment in the middle stage makes the dissolution pore become the main reservoir space， and the densification degree is somewhat eased. In the late alkaline diagenetic environment， the concentration of alkaline mineral ions increases again and begins to precipitate in the remaining intergranular pores， solution pores， and other reservoir spaces， and the reservoir densification degree is further improved. The cementation and dissolution of fan delta plain and front junction in the study area were weak， and more compact phases developed， with an average porosity of about 4.9%. From the inner front of the fan delta to the junction of the outer front， the dissolution is stronger than the cementation， and the cementation-dissolution phases are dominant， with an average porosity of about 6.6%， and the dissolution phases with an average porosity of 9% are near the central and southern faults. The outer front of fan delta is mostly developed with solution-cementation facies， and the average porosity of the reservoir is about 3.1%. In general， alkaline diagenesis in the alkaline lake sedimentary setting has a two-sided effect on reservoir reconstruction， and the cementation-dissolution phases and the dissolution phases under the control of acid/alkaline dissolution are favorable places for tight oil accumulation in this area， and are also the key factors for the high productivity in this area.
The Lucaogou Formation of the Permian is developed in the Ji’nan Sag， located in the eastern Junggar Basin. However， there remains a lack of clarity regarding the sedimentary paleoenvironment and organic matter enrichment mechanism within this formation. Therefore， this study aims to investigate the sedimentary paleoenvironment and paleoproductivity of the Lucaogou Formation in our study area using various analytical techniques such as total organic carbon analysis， rock pyrolysis， major and trace element analysis， as well as saturated hydrocarbon chromatography/mass spectrometry. This will enable us to gain insights into the mechanisms responsible for organic matter enrichment within the Lucaogou Formation. Our findings reveal that： （1） Based on total organic carbon and rock pyrolysis parameters analysis， it can be concluded that there is generally abundant organic matter within the Lucaogou Formation in Ji’nan Sag with predominantly type I and type II1 kerogen indicating low-mature to mature stages with high hydrocarbon generation potential. （2） Biomarker parameter analysis suggests that aquatic organisms and terrigenous higher plants are major contributors to organic matter composition within the Lucaogou Formation； additionally， higher input of terrigenous organic matter is observed in its second member. （3） Analysis of major and trace elements along with biomarkers-related parameters indicates that source rocks from our study area were deposited under arid or brackish water conditions characterized by weak reduction levels ranging from shallow water to semi-deep water environments with low paleoproductivity； however， wet-semi-arid conditions prevailed during deposition of source rocks from second member accompanied by fresh water settings exhibiting weak reduction-weak oxidation characteristics at shallow depths resulting in moderate paleoproductivity levels. （4） According to the comprehensive study and analysis of the abundance of organic matter in the source rocks of Lucaogou Formation and different paleosedimentary environment conditions in the study area， the enrichment of organic matter in Lu1 Member is mainly controlled by the abundance and preservation conditions of aquatic organisms. The initial productivity of Lu2 Member dominated the enrichment of organic matter.
The study of the causes of overpressure is the basis for stress prediction and the research on hydrocarbon accumulation. The Jurassic overpressure is widely distributed in the Mosuowan uplift， located in the central part of the Junggar Basin， which is closely related to hydrocarbon accumulation， making it an important topic for further research. This study comprehensively utilizes various methods such as log curves combination analysis， Bowers method， velocity-density crossplotting， correlation of porosities， and comprehensive analyses to discuss the causes of overpressure. The research shows that overpressure is generally developed in the Jurassic of Mosuowan uplift， Junggar Basin. The overpressure is mainly located in the deep formation of 4 000-4 500 m， and the pressure coefficient ranges from 0.92 to 2.11， with an average pressure coefficient of 1.33. On the planar scale， the eastern part experiences more significant overpressure， with pressure coefficients of up to 2.1， while the western part has relatively weaker overpressure， with pressure coefficients reaching up to 1.6. Sonic transit time， density， and resistivity log responses show clear indications of overpressure， with varying degrees of reversal. Based on the comprehensive analysis using multiple methods， it is determined that the overpressure in the Jurassic formations of the Mosuowan uplift in the Junggar Basin is mainly influenced by hydrocarbon generation and pressure transmission. The contribution of chemical compaction is slightly higher in the eastern part than in the western part， while the contribution of under compaction is weak or nonexistent.
A significant breakthrough has been made in the Upper Paleozoic play in Dagang area of Huanghua Depression， Bohai Bay Basin over the past four years. This paper aims to analyze the key factors of hydrocarbon accumulation and identify the exploration prospective area. The geological， geochemical， logging and seismic data are allowed to investigate the source rock， reservoir distribution and properties， natural gas charging time and petroleum system model. The results show that the upper Paleozoic coal bedding source rocks have good organic matter with two peak periods of hydrocarbon generation. The reservoir responds low porosity and low permeability clastic rocks， but secondary pores and fractures have developed as a result of subsequent later tectonic movement. The origin source rock， secondary pore reservoir and the activity of faults are the key controlling factors for the gas accumulation. We build a petroleum system model as “two periods of hydrocarbon expulsion， source-sink superimposed， late fault activity reshape prospect， late gas charging”. The gentle high in the deep depression buried hill zone and slope of buried hill will be the promising exploration area. Three favorable target areas for future exploration are proposed： the slope area of Wumaying-Wangguantun sag， Dongguang Dongyi and Qibei.
The geochemical characteristics of Paleozoic natural gas in the southern part of the Ordos Basin are significantly different from those in the northern part. In addition to the increase in dryness coefficient caused by the increase in organic matter maturity of the source rocks and the heavier carbon isotope composition of methane， the CO2 gas content in the natural gas in the upper Paleozoic in the southern part of the basin is higher， and there is a common phenomenon of methane and ethane carbon isotope composition inversion. This article takes gas geochemistry as the main research method， and based on a systematic comparison of the north-south differences of natural gas in the Paleozoic Basin， discusses the origin and source of natural gas. The natural gas of the Upper Paleozoic in the southern part of the basin is mainly composed of high over mature coal type gas， and some sample gas geochemical indicators in some areas reflect the characteristics of lower paleomarine hydrocarbon sources. The overall inversion of methane and ethane carbon isotope composition in the Upper Paleozoic natural gas in the southern part of the basin is related to the mixing of different types of natural gas. The varying degrees of mixing of Lower Paleozoic oil type gas with relatively high ethane content and lighter ethane carbon isotope composition are the main reasons for the inversion of carbon isotope composition of Upper Paleozoic natural gas in the southern part of the basin. The geochemical indicators of natural gas in the Lower Paleozoic in the southern part of the basin reflect typical marine hydrocarbon source characteristics， and the possibility of a small amount of Upper Paleozoic coal type gas mixing cannot be ruled out.
In recent years， significant breakthroughs have been made in the exploration of marine shale gas in the Ordovician Wulalik Formation in the western Ordos Basin. The TOC content of shale in the Wulalik Formation is low， and the relevant geochemical indicators of the source rocks have not reached the “sweet spot” standards for marine shale gas exploration. Therefore， it is of great significance to clarify the origin and source of natural gas in the Wulalik Formation. Through gas geochemical research methods， the genetic types and sources of natural gas in the Wulalik Formation have been revealed. The research results show that there are significant differences in the geochemical characteristics of natural gas in the Wulalik Formation， and the genetic types are mainly distributed in the transitional areas between coal type gas and marine oil type gas， exhibiting characteristics of mixed sources. Among them， Well ZP 1 belongs to a typical marine oil type gas， which is “self-generated and self-stored” shale gas. Other natural gas samples from the Wulalik Formation reflect varying degrees of mixing characteristics of coal type gas. The natural gas reservoir formation mode of the Wulalik Formation is characterized by the joint supply of hydrocarbons from the coal source rocks of the Carboniferous Permian and the marine source rocks of the Lower Paleozoic Ordovician Wulalik Formation， forming two types of oil and gas reservoirs： Young-generation and old-storage， and self-generation and self-storage.
The elemental geochemical information of sediments can well reflect the information of sediment source area， paleoclimate and paleoenvironment， and there is a close relationship between sediment grain size and elemental geochemical information. In order to further explore the genesis of different fluvial sand bodies in the Shaximiao Formation under the arid background and the relationship between sediment grain size and sedimentary phase and elemental geochemistry， the sedimentary phase characteristics and elemental geochemistry of the Well Yanqian 1 in the western Sichuan area are systematically analyzed. The results show that： （1） The stratigraphy of the Shaximiao Formation in Well Yanqian 1 is dominated by reddish-brown mudstone and gray gravel， and a set of river floodplain deposits is developed， which can be classified into five kinds of lithologic phase combinations， namely， large river channel， small river channel， watercourse at the mouth of the river， river floodplain， and river floodplain lakes. （2） The elemental geochemistry of different lithologic phase combinations has obvious differences， and the large river channel shows a low content of Fe and high content of SiO2， while the SiO2 content of the watercourses and small rivers is slightly lower； the riverine lakes show the characteristics of “high Fe content and low SiO2 content”； and the river floodplains show the characteristics of “high Fe content and high SiO2 content”； while the river floodplain is characterized by “high Fe content and high SiO2 content”. The rock phase assemblage as a whole shows that the higher the SiO2 content， the larger the grain size； and the decisive watercourse， small river channel and river floodplain are mostly developed in a relatively humid climate environment. （3） The combination of the elements and ratios such as knot and Al2O3/TiO2， Cr/Zr and TiO2/Zr indicates that the Shaximiao Formation of the Well Yanqian 1 is close to the source area， and the host rock is mainly a feldspathic quartzite， with the main tectonic background being the continental island arc background. （4） According to Mg/Ca， Fe/Mn， Sr/Ba， V/（V+Ni） and Cu/Zn and other elements and their ratios， the water environment of the Shaximiao Formation during the depositional period was mainly a terrestrial freshwater environment， and the lower Shaximiao Formation to the upper Shaximiao Formation showed two oxidation-reduction environmental change processes， and the climate change is more frequent， and the climate appeared to have many changes from wet to dry， but the overall situation from the lower to the upper Shaximiao Formation is not as clear. Overall， the climate is more arid from the lower Shaximiao Formation to the upper Shaximiao Formation. The study provides a basis for restoring the depositional environment of the Shaximiao Formation in the West Sichuan Depression， and further exploring the formation law of different rock phase assemblages and the distribution of favorable reservoir sands.
At present， the breakthrough of shale gas exploration in China is mainly concentrated in the medium and shallow overpressured shale gas reservoir. With the deepening of research， shale gas exploration gradually goes to the deep layer. The Baima block of Fuling shale gas field is a deep overpressured gas reservoir with great exploration potential. Based on the well logging data and test analysis data of Wufeng-Longmaxi formations in well J148-1， the gas bearing characteristics and influencing factors of Wufeng-Longmaxi formations are analyzed in this paper， and the formation and enrichment mechanism of shale gas and the accumulation model of shale gas are discussed. The shale gas content of Wufeng-Longmaxi formations ranges from 1.09 to 6.81 m3/t （with an average of 3.15 m3/t）， and increases with increasing depth. The average gas content of small formations 1-3 is 5.35 m3/t， which is a favorable shale gas interval. The total organic matter content， mineral composition， reservoir properties and preservation conditions all have a certain control effect on the gas content of the shale.TOC of the Wufeng-Longmaxi formations is between 1.29% and 5.50%（with an average of 2.75%）， and increases with the increase of burial depth. Quartz content is 17.2%-64.7% （average 36.1%）， feldspar content is 2.7%-14.5% （average 8.0%）， carbonate mineral content is 2.0 %-56.6% （average 12.6%）， pyrite content is 1.4%-6.7% （average 3.4%）. The clay mineral content is 17.2%-54.3% （average 40.1%）. The porosity of 1-4 layers is between 2.38% and 5.64% （average 4.06 %）， the porosity of 8-9 layers is between 1.95 % and 2.75% （average 2.24%）， and the permeability of 1-4 layers is between 0.03×10-3 and 16.43×10-3 μm2 （average 0.75×10-3 μm2）. The permeability of 8-9 small layer ranges from 0.05×10-3 to 55.63×10-3 μm2 （the average is 2.31×10-3 μm2）， and the total organic matter content， brittle mineral content and porosity are positively correlated with the gas content. There are three types of pores in the shale： inorganic pores， organic pores and micro-fractures， mainly organic pores. The study area is far from the main fault， regional cap layer is developed， top and bottom lithology is dense， preservation conditions are good， free gas is abundant， and the reservoir formation model is broad and slow syncline. The shale of Wufeng-Longmaxi formations in the study area was immature from the end of Ordovician to the Late Silurian， entered the mature stage in the late Silurian， entered the high mature stage in the Middle Jurassic， entered the over-mature stage in the Late Jurassic， and stopped thermal evolution in the Middle Cretaceous.
Based on thin section identification， the organic geochemistry， XRD， combined with scanning electron microscopy， N2 isothermal adsorption and high pressure mercury injection tests， the characteristics of laminated shale lithofacies were identified and the reservoir pore structure was comprehensively analyzed， and then the favorable shale lithofacies and main controlling factors of pore development were clarified. According to the classification standard of “abundance of organic matter and mineral composition”， the shale of Qingshankou Formation is divided into seven lithofacies： M-L， S-M， M-M， C-M， S-H， M-H and C-H. The kind of C-H shale lithofacies is regarded as the favorable type in the study area， because it has absolute hydrocarbon generation potential， and its reservoir space is well developed with superior pore structure parameters， which is dominated by slit clay mineral intercrystalline pores， intergranular pores and micro-fractures. The shale reservoir space of Qingshankou Formation is controlled by laminae development， TOC content and mineral composition. The felsic lamination effectively alleviates overlying rock compaction， organic acid diffusion and formation of overpressure fractures improve macropore volume ratio， and the clay mineral intercrystalline pores and fractures provide the main specific surface area and pore volume.
Recent exploration has shown that the Ordos Basin has a good potential of helium resource. However， its distribution and resource calculation method are still controversial， which impede the understanding of the helium enrichment rule and subsequent exploration in the Ordos Basin. Therefore， we systematically studied the Changqing oilfield helium contents， distributions， and its resources. The results show that helium in Qingyang，Yichuan and western Sulige gas fields are above the industrial and enriched helium standards，which have the helium contents of 0.121%-0.204%（averagely 0.144%），0.060%-0.177%（averagely 0.086%） and 0.018%- 0.168%（averagely 0.053%），respectively. In contrast， Yulin， Jingbian， Shenmu， and Zizhou-Mizhi gas fields generally have relatively lower helium concentrations （averagely 0.034%）. Such distribution characteristics reveal that the content of helium in the margin of the basin is higher than that of the center. Vertically， the highest helium appears in the Permian and the lowest appears in the Ordovician. According to the new established helium resources evaluation method， the calculated in-situ helium production of He-8 and Shan-1 reservoirs is 6.27×106 m3 and 1.39×106 m3 respectively， accounting for 52.69% and 3.11% of the total helium production， which means the external source rocks is the main contributing source area of helium. The helium production of the metamorphic basement， sedimentary sequences， and Indosinian magmatic plutons in the southwestern margin of the basin is 2.14×1010 m3， 1.44×1010 m3， and 1.74×107 m3， respectively， with total helium resources of about 358×108 m3.
In recent years， China has carried out fruitful exploration and development of medium and shallow shale gas with a burial depth of 700-2 000 m in Zhaotong Shale Gas Demonstration Zone of Sichuan Basin. However， horizontal well technology and large-scale hydraulic fracturing technology adopted in shale gas development have the risk of water environment pollution， especially in the carbonate rock distribution area in southern China， which has complex geological conditions and fragile ecological environment. The study of water environmental pollution risk is particularly important. In this study， the composition of trace elements， anions， cations， and strontium isotopes in the flowback water of Y105 well area with vertical depth <2 500 m in the Taiyang block， Zhaotong area， Sichuan Basin was analyzed and compared with that of Weiyuan， Changning and Fuling shale gas fields. It is pointed out that shale gas fracturing flowback water in Y105 well area of Taiyang shallow layer has the following three characteristics： （1） The flowback water is high in salts and heavy metals. The average contents of K， Na， Ca and Mg were 153 mg/L，7 473 mg/L，162 mg/L， 34 mg/L， respectively， and the average contents of Cl and Br were 10 912 mg/L and 52 mg/L， respectively. The average contents of Li， B， Sr， Ba and Rb were 21.9 mg/L， 14.3 mg/L， 27.8 mg/L， 37.4 mg/L and 0.25 mg/L respectively， which could not be directly discharged. The average Br/Cl ratio is 0.002 1， it is relatively rich in Ca and poor in Mg compared with evaporative seawater， the content of Sr， Ba and Rb is positively correlated with the content of Cl. All of them indicate that the flowback water is the mixture product of the fracturing injected fluid and entrapped brine of the host shale formation. The high salt end of the flowback water has the characteristics of evaporative seawater， but it also experiences water-rock reaction. （2） The 87Sr/86Sr ratio ranges from 0.716 5 to 0.717 2 （with an average value of 0.716 7）， indicating that there is a strong water-rock interaction between fracturing injected fluid and shale formations with high strontium isotope ratios. Compared with the flowback water in Weiyuan， Changning and Fuling shale gas fields， flowback water in the Taiyang block has relatively low 87Sr/86Sr ratios， but still much higher than that of surface water and biocides， which is a good identification index. （3） The element composition of the flowback water has a certain correlation with the vertical burial depth of the shale. For example， when the vertical depth of the Y105H3 platform increases from 2 245.16 m to 2 406.16 m， the content of cations， ions， and trace elements has varying degrees of change， and shows a certain change law， which may reflect the influence of temperature， pressure and other factors.
甘公网安备 62010202000678号
