Deep to ultra-deep formations are important breakthroughs in oil and gas exploration at present and in the future. Understanding of the generation pathway， mechanism and potential of natural gas at high thermal maturation stages is beneficial to develop natural gas generation theory and to guide petroleum exploration in deep formations. Combined with extensive pyrolysis experiments and kinetic calculations， the maturity and temperature stages （gas generation time-limit） as well as potential of gas generation from various sources and pathways were discussed， and a multi-path gas generation model was established. The gas generation from thermal degradation of type I/II kerogens （kerogen primary cracking） can extend to RO of 3.5% with the maximum yield of 120-140 m3/tTOC， the potential of kerogen cracking gas at RO>2.0% can reach 20-40 m3/tTOC. The kinetics for the cracking of whole oil components were also addressed. It is proposed that intensive cracking of liquid hydrocarbons at a heating rate of 2 ℃/Ma mainly occurs at 190-220 ℃ with the corresponding maturity of RO=2.0%-2.3%. The contributions of gas derived from thermal cracking of residual hydrocarbons in source rocks and hydrocarbons outside the source are ~80 m3/tTOC and 200 m3/tTOC， respectively. The onset temperature for ethane cracking is higher than 230 ℃. Thermochemical sulfate reduction （TSR） leads to a decrease of 20–40 ℃ in temperature for the occurrence of oil cracking， accelerating the efficient accumulation of natural gas with high content of hydrogen sulfide （H2S）. Besides， gas generation via hydrogenation involving inorganic fluids and minerals promotes gas potential for about 20%-30%， and is one of the pathways for the generation of high-over mature gas in deep formations. The multi-path gas generation process constitutes an integrated evolution sequence of natural gas formation， revealing that there is large-scale gas exploration potential under the traditional “deadline” of oil and gas in deep to ultra-deep formations.
Helium has unique characteristics such as strong chemical inertness and low boiling point， and plays an irreplaceable role in high-tech industries and scientific research experiments. Helium is widely distributed as trace components on the earth， but the extraction of helium from helium-containing， helium-rich natural gas reservoirs is still the only way to industrially produce helium. At present， the world's discovered helium reserves are mainly distributed in the United States， Qatar， Algeria， Russia， Canada and other countries. The helium reserves of the above five countries account for 92% of the world's total reserves. There are three main sources of helium in natural gas reservoirs： atmospheric， crustal and mantle-derived. At present， the source of helium is mainly determined based on the value of 3He/4He. Generally， the 3He/4He value of atmospheric， crustal and mantle-derived helium are 1.4×10-6， 2×10-8 and 1.1×10-5， respectively. The accumulation conditions and characteristics of helium-rich natural gas have both common features and obvious differences with conventional natural gas reservoirs. Some areas with high hydrocarbon generation intensity that are conducive to the formation of large-scale oil and gas reservoirs are not conducive to the formation of helium-rich and high-helium gas reservoirs. Uplift areas with relatively low hydrocarbon generation intensity are conducive to the formation of helium-rich and high-helium gas reservoirs. The helium resources discovered in the world are mainly distributed in sedimentary basins under the platform background of the Late Proterozoic and Paleozoic. In addition， the Mesozoic-Cenozoic structure-magmatic activity is strong and the area with ancient granite basement is also a favorable area for the development of helium-rich gas reservoirs. Existing data indicate that China has discovered some helium-rich gas reservoirs in the Sichuan Basin， Tarim Basin， Qaidam Basin， Ordos Basin and Mesozoic and Cenozoic petroliferous basins in the eastern China. At the same time， unconventional natural gas fields also show good prospects for helium resource exploration， such as soluble gas in the Weihe Basin and shale gas in the Sichuan Basin. China's helium-rich natural gas has many points， types and good resource prospects， but the overall research level of helium resources is very low.
Migration and transportation system is the core content of far-source oil and gas reservoirs， and is the key link for long-distance migration and accumulation of oil and gas. Taking the Mesozoic-Cenozoic far-source oil and gas reservoirs in the southern slope of Kuqa foreland basin as an example， based on the clarification of oil and gas distribution in time and space， this paper studies various types of hydrocarbon transport elements and their combination characteristics， and develops 2D simulation experiment for different oil and gas migration and transportation systems. The simulation experiment explores the mechanism of long-distance migration and transportation of oil and gas， and provides a reference for the next exploration and deployment in the area. The study shows that the Mesozoic-Cenozoic in the southern slope of Kuqa foreland basin has developed three types of oil and gas transportation media， including faults， unconformities and sandstone layers. The combination of the three types of transportation media forms two types of oil and gas transportation systems： proximal depression zone oil source fault-unconformity， unconformity vertical oil and gas transportation systems and far source slope unconformity - normal fault， sand body and shallow lateral oil and gas transportation systems. Oil-source faults in the near-source depression are the key vertical oil and gas migration pathways， while the Cretaceous/Pre-Cretaceous， Paleogene/Cretaceous unconformities and widely distributed Cretaceous-Paleogene sandstone layers in the far-source slope area are the lateral oil and gas migration channels. Simulation experiments show that the long-distance migration and accumulation of oil and gas depend on three factors： The amount of crude oil entering the transport layer， the distance between traps and adjustments to normal faults， and the structure of unconformity： The amount of crude oil entering the transport layer determines the oil and gas migration force-the size of buoyancy； the distance between traps and adjustment of normal faults determines the preferential charging sequence of oil and gas. The lithological pinch-out zone or low-amplitude structure in the updip direction of the sand body has the most advantages for oil accumulation； the unconformity structure of high porosity and permeability sandstone has the dual advantages of physical properties and power， and is the core path of oil and gas migration. The heterogeneity of the Cretaceous/Pre-Cretaceous unconformity distribution is an important factor for the difference Cretaceous oil and gas distribution in this area. The wide distribution of the Paleogene/Cretaceous unconformity is the key of oil and gas accumulation of Paleogene in south slope of Kuqa foreland basin
Platform boundary mound-beach of Cambrian in Gucheng area is a significant exploration field in the eastern Tarim Basin， with wide distribution and large area， has a huge exploration potential. But the heterogeneity between mound-beaches of each period and within one single mound-beach is very strong which cause the difficulties in reservoir characterization and prediction. To solve those problems， seismic data， logging data and results of exploration wells were applied in this study. A comprehensive analysis was conducted based on multi-scale observation of core and thin sections. The result shows that there are 6 periods of mound-beaches can be found in the Cambrian platform boundary of Gucheng area. The lithologies of mound-beach reservoir are residual granular dolomite and microbial dolomite. Several kinds of fabric selective and not fabric selective reservoir space can be found in mound-beach reservoir based on which two types of reservoir were identified. One is pore-vug type， the other is fracture-vug type. Based on the shape recognized in the seismic data， mound-beach can be divided into prograde mound-beach and aggrade mound-beach. The mound flat and mound core have larger reservoir thickness in aggrade mound-beach. But to the prograde mound-beach， mound core and mound wing have better reservoir condition. Every micro facies of mound beach shows different reservoir characteristics. Among them， mound core has the best reservoir condition， mound flat is worse than mound core， mound wing is the worst. Paleogeomorphy controls sedimentary styles and reservoir distribution of mound-beach. Penecontemporaneous period karstification of fresh water and buried dissolution are constructive diagenesis to mound-beach reservoir. Fractures of multiple angle and scale can conduct reservoir space， promote corrosion and reservoir condition. The siliceous filling found in vugs and fractures is the result of metasomatism， which damages the reservoir conditions. The opinions above can provide basis for the study of accumulation condition and favorable area optimization in Gucheng area.
The dissolution and precipitation of carbonate and gypsum have a great impact on burial karst and pore preservation during burial process. In order to carry out the fine evaluation of carbonate-evaporite composite reservoir， we take the Cambrian reservoir in Tabei Uplift of Tarim Basin as the object， and establish the thermodynamics and kinetics models of fluid-mineral interaction according to the formation water ion content from 14 wells in Yingmai and Yaha areas and Well Luntan 1， combined with petrologic characteristics such as thin section observation and porosity. Results showed that the dissolution and precipitation reaction rate of carbonate minerals and gypsum and its ΔG relationship is a good index， dissolution rate increases with the decrease of ΔG and precipitation rate increases with the increase of ΔG. Calculation results show that Tabei Uplift Cambrian buried environment in general is beneficial to the dissolution of carbonate mineral gypsum combination and karstification is stronger in the northwest than that in the southeast， which is in good agreement with the test results of reservoir physical properties. This study provides a new method for quantitative prediction and evaluation of the favorable reservoir area of the deep burial carbonate-evaporite paragenetic association reservoir.
West Junggar provides an ideal natural laboratory to study the evolution of the Altaids. Although a considerable amount of work has been carried out to investigate the volcanic rocks， granitoid plutons and ophiolites of the West Junggar and discuss the tectonic evolution of the Altaids， few authors have examined the provenance and tectonic setting of the clastic sedimentary rocks of the area. The present research focuses mainly on the analysis of the major and trace element geochemistry data of the Upper Carboniferous mudstones samples from the field of the Hala’alat Mountains. The results suggest that these sedimentary rocks experienced a simple recycling process and with a low degree weathering conditions in the source areas. The trace element ratios of Eu/Eu*， La/Sc， La/Co， Th/Sc， Th/Co and Cr/Th， the diagram of La/Th-Hf， La/Sc-Co/Th， the chondrite-normalized REE patterns and the Eu anomalies suggest these sediments are dominated by intermediate to felsic provenance， with a few intermediate to mafic sediments. Analysis of the La-Th-Sc and Th-Sc-Zr/10 ternary plots suggest that the tectonic background is oceanic island arc （OIA） and continental island arc （CIA）.
Fracture is the main reservoir space and migration channel， so study of its characteristics and stages is helpful to clarify the distribution law of fracture and has important guiding significance for the development plan later. Based on the data of outcrop， core， imaging logging， carbon and oxygen isotope， fluid inclusion and rock acoustic emission， the characteristics， formation stage and distribution law of sandstone reservoir fractures in Mesozoic were studied in Yanchi area of Ordos Basin， including Yan'an Formation and Yanchang Formation. The results show that the fractures are well developed in Yanchi area， most of which are vertical and high angle structural fractures. The fracture length is 0.1-0.2 m， the fracture density is generally less than 0.2 m-1， the fracture is mainly filled with calcite， and the effectiveness is good， main direction is NE-SW， and there are some NW fractures， the average dip angle is 76.2°， and there is little difference in each layer. The formation period of Yanchang Formation fractures can be divided into three stages： Indosinian， Yanshanian and Himalayan， while the formation of fractures in Yan'an Formation was influenced by Yanshan movement and Himalayan movement， and the formation of fractures in sandstone reservoir is consistent with the main tectonic movement， and the model of fracture development is established in Yanchi area. In Indosinian epoch， NW and NE trending shear fractures were developed under the action of nearly NS trending stress； in Yanshanian epoch， NW and NE trending fractures were developed under the influence of NW trending stress； in Himalayan epoch， NEE and NE trending fractures were developed under the action of NE trending stress， and the fractures formed in earlier stage were also reformed by the later tectonic movement.
There are several sets of source rocks in Yanchang Formation of Mesozoic in Ordos Basin. At present， Chang 7 source rock is considered to be the main source rock of Yanchang Formation， but there is a lack of evaluation methods for hydrocarbon generation and expulsion of other source rocks and hydrocarbon accumulation contribution of source rocks. By means of basin simulation and based on a large number of basic geological data and exploration results， the geological body model and thermal history model are established to carry out the simulation research on hydrocarbon generation and expulsion and accumulation of multi-source layers in Yanchang Formation under geological constraints. The results show that the hydrocarbon generation conversion rate of each source rock in Yanchang Formation is mainly distributed in 45%-75%， which still has great hydrocarbon generation potential and has the geological conditions for the in-situ exploitation of shale oil. At present， the accumulative hydrocarbon generation is 123.3 billion tons and hydrocarbon expulsion is 90 billion tons， which is dominated by heavy hydrocarbon of
The second member of Feixianguan Formation of Triassic in Jiulongshan area of northwestern Sichuan has made major breakthroughs in natural gas exploration and has great exploration potential. Drilling data show that the second member of Feixianguan Formation has developed multiple sets of reservoirs， which are mainly concentrated in the upper sub-member of second member of Feixianguan Formation. The overall heterogeneity is strong， the lithology and physical properties are complex and changeable， the reservoir thickness is thin， and drilling is less， so it is difficult to determine the spatial distribution characteristics of oolitic beach reservoir， which restricts the natural gas exploration process in this area. For oolitic beach reservoir in the upper sub-member of the second member of Feixianguan Formation of Jiulongshan area， using downhole reservoir characteristics and 3D seismic data， the reflection characteristics of oolitic beach reservoir are analyzed， and then the seismic response model of oolitic beach reservoir is established by forward modeling. It is clear that the seismic response characteristics of the reservoir in this area are weak amplitude-continuous reflection； through the use of layer flattening impression method to restore the ancient landscape of the second section of Feixianguan Formation， combined with seismic facies analysis and seismic amplitude attribute characteristics， the distribution characteristics of favorable facies belt for oolitic beach development are determined. On the basis of the distribution of favorable facies belt， this paper uses the relative impedance based on tuning amplitude inversion and waveform difference inversion method to make a fine prediction of the spatial distribution of the reservoir， defines the spatial distribution characteristics of the reservoir， and predicts the thickness and fracture development of oolitic beach reservoir. The prediction results of the reservoir thickness are in good agreement with the actual drilling results， which confirms the application of this prediction method in this area. According to the fracture development， wave impedance value less than 1.6×106 g/（cm2·s）， reservoir thickness and other indicators， the favorable development area of oolitic beach reservoir is further delineated， which provides a favorable basis for the next exploration and development.
With the continuous deepening of domestic shale gas exploration and development， the ground and underground geological conditions have become more and more complex. In order to better find the “sweet spot” suitable for the occurrence of shale gas and support the efficient implementation of drilling and fracturing projects. Taking the Zhaotong National Shale Gas Demonstration Zone as an example， the systematic review summarizes the main controlling factors of the “sweet spot” and clarifies that the complex mountain shale gas “sweet spot” outside the basin is controlled by three major factors： （1）Superior reservoir indicators are the material basis for shale gas enrichment and high production； （2）Good preservation conditions are the key to shale gas “accumulation and production control”； （3） Favorable engineering quality is the core of efficient shale gas development. In view of the special geological background outside the basin， the analysis of preservation conditions and engineering quality is particularly important. Under the guidance of the concept of integration of geology and engineering， in view of the geological engineering characteristics of complex mountain shale gas in the south， based on the evaluation of drilling and logging data， we will give full play to the geophysical advantages， and focus on the three major “sweet spots” main controlling factors in the demonstration zone to carry out complex mountain shale gas storage. The comprehensive evaluation of the “sweet spots” of the layers finally achieves the unification of the geological “sweets” and the engineering “sweets”， laying a solid foundation for the efficient deployment and implementation of well positions. As the contradictions of “double complexity” of shale gas in southern mountainous areas become increasingly prominent， comprehensive reservoir evaluation techniques based on “sweet spots” main controlling factors will become particularly important. At the same time， the integration of geology and geophysical engineering will be the only way for the efficient development of unconventional oil and gas.
Reservoir diagenesis of Lower Jurassic Ahe Formation in Yiqikelike area， Kuqa Depression， Tarim Basin is complex， highly heterogeneous and characterized by low porosity and low permeability. According to the diagenesis and diagenetic minerals， the target strata were divided into five types of diagenetic facies： tightly compacted facies， carbonate cemented facies， unstable-components dissolution facies， dissolution micro-fracture facies and micro-fracture facies by observation of core， thin section， cast thin section and scanning electron microscope. Different diagenetic facies have different logging responses through cross-plot processing of conventional logging data. However， it is not possible to identify different diagenetic facies by cross-plot because of the overlap of logging information of different diagenetic facies. By using BP neural network to mine logging information， the training model has a high accuracy rate. By comparing with the thin section identification results and pore and permeability data， the accuracy of the learning model is verified， thus providing a basis for the logging identification of reservoir diagenetic facies in the interval lacking of coring.
The microgravity monitoring technology is to convert the superposition field into the difference field， and obtain the more real information of the change field. The result has nothing to do with the single well point. It is the objective description of the overall density and fluid change of the oil and gas reservoir， and it is the overall monitoring of the oil and gas reservoir. It creates conditions for overcoming the multi-solution of interpretation， and its monitoring results are closer to the truth. Therefore， this paper proposes to use the microgravity monitoring results to describe the distribution of residual gas， and to evaluate the development well location and the development potential of residual gas. Firstly， the characteristics of gas bearing formation on microgravity abnormal section are analyzed. Secondly， the development well location evaluation and residual gas potential evaluation model are established. Finally， the microgravity monitoring technology is applied to the Su14 infilled well area， the remaining gas plane distribution is described， the development well location and the remaining gas development potential of the Su14 infilled well area are evaluated， and the next step of the remaining gas development comprehensive adjustment plan and countermeasures for potential tapping are proposed. The adjustment method carried out index prediction， and used the numerical simulation results of the Su14 infilled well area and the production performance analysis results of the development wells to verify the accuracy of the microgravity monitoring residual gas distribution results and the evaluation model.
Taking the tight reservoir of Fengcheng Formation in Mahu Depression as the research object， the RFPA software of the numerical simulation platform for the real fracture process was used to study the propagation and extension law of reservoir fractures around the well during the fracturing process. On this basis， the influence of rock mechanical properties and horizontal principal stress difference on the fracture extension law of the reservoir around the well is studied. Grey correlation method is used to quantitatively analyze the influence degree of each factor on fracturing effect， and combined with analytic hierarchy process， the evaluation model of reservoir fracturing ability is constructed. The results show that the larger the horizontal principal stress difference is， the more obvious the directionality of fracture extension is. The lower the fracture initiation pressure is， the larger the fracture extension distance is. With the increase of compressive strength， tensile strength and elastic modulus， the cumulative number of acoustic emission decreases， and the fracture extension distance decreases. However， with the increase of Poisson's ratio， the cumulative number of acoustic emission increases， and the fracture extension distance increases. Based on the grey correlation method， the order of influencing the fracturing effect was determined as the horizontal stress difference > elastic modulus > tensile strength > uniaxial compressive strength > Poisson's ratio. Using the analytic hierarchy process （AHP）， a model for calculating the reservoir fracturing index is established， which takes into account the influence of horizontal stress difference， elastic modulus， tensile strength and uniaxial compressive strength， etc.， and has a good positive correlation with the extension distance and area of non-dimensional fracture. Combined with the test data of the fractured well， there is a positive correlation between the fracturability index and the oil recovery intensity.
In order to further study the mechanism of CO2 injection to enhance the recovery of condensate gas reservoir， experiments of the fluid properties of condensate gas reservoir affected by CO2 have been carried out. The results show that the dew point pressure of the condensate reservoir is reduced by injecting CO2， and the reduction rate increases with the increase of injection volume. The larger the injection volume， the faster the dew point pressure decreases， a 15.42% drop while injecting 0.4 HCPV CO2. With a smaller injection HCPV CO2， the effect on condensate oil is mainly dissolution， viscosity reduction and expansion. The increment of the condensate oil expansion volume is more than 9 times that of the extracted condensate oil volume， and the dissolved GOR and relative density will increase as the injection HCPV goes up. with a higher CO2 injection HCPV， extraction plays a major role， the production GOR increases rapidly， a growing number of the relative density of condensate oil，and the recovery percent reaching more than 83%. Under the actual formation condition， with the development of CO2 injection， which mainly reduces dew point pressure in the far well area， and pushes the dew-point-line to the producing well direction. In the early stage of the transition zone， dissolution expansion is the main factor， which compresses the zone area. In the later stage， extraction is the main factor， which pushes the hydraulic line towards the producing well and reduces the zone area near the well. In the early stage near the well zone， the flow channels are mainly formed by displacement， and in the middle and late stage， the flow channels are mainly formed by dissolution， expansion， transport and extraction. In conclusion， the development of CO2 injection in condensate gas reservoir compresses the area of gas-liquid two-phase zone， which can greatly enhance the recovery of condensate gas reservoir. The research results provide important technical support for CO2 injection development and technical extension of condensate gas reservoir.
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