The lower third member of Shahejie Formation （Es3） was traditionally considered as the main source rock for oilfields in Shulu Sag， Bohai Bay Basin. The exploration practice of Huabei Oilfield Company showed the middle-deep conglomerate-marl lacustrine carbonate tight reservoirs have great potential of natural gas resources， which provides a new field and direction for exploration of natural gas in the oil-rich Bohai Bay Basin. There are conglomerate， marl and （calcareous） mudstone and other lithology developed in the lower Es3 of Shulu Sag， and all of them have hydrocarbon generation potential， among which the laminar marls have the highest hydrocarbon generation ability and they are mainly distributed in sequences 2 to 3 in the central depression； the middle-deep reservoirs have extremely low porosity and ultra-low permeability， and their physical properties are not controlled by burial depth. The vertical and horizontal distribution of hydrocarbon reservoirs and their fluid properties in the sag are controlled by the thermal evolution degree of hydrocarbon source rock by hydrous pyrolysis experiments and exploration data. There is a successive change from tight oil to tight gas accumulation sequence from shallow to deep， including tight oil belt， oil-gas paragenesis zone and pure gas zone. The volume method and resource abundance analogy method are used to predict the natural gas resources of 672.1×108 m3 in Shulu Sag， and it is pointed out that the Jingu 11 well area in the central depression area is a favorable practical direction for the exploration of middle and deep natural gas.
Deep fluid was increasingly identified involved in all processes of hydrocarbon accumulation. Based on data from drilling core， petrology， fluid inclusions and organic geochemistry， we discussed the detailed evidences of the activities of the deep fluid as well as its effect on hydrocarbon accumulation. The evidences include： （1） Abnormal high-temperature fluid inclusions in Paleogene reservoir； （2） CO2 gas in discovered reservoir being inorganic origin from volcanic mantles； （3） Oxygen isotopic values in calcite filled veins much higher than surrounding rock； （4） Cubic and pyritohedron pyrite found in sediments with Co/Ni ratio more than 1 indicating hydrothermal origin. These all showed that there might be deep fluid participated in the reservoir accumulation， the affection of which includes hydrocarbon generation and expulsion as well as reservoir reconstruction. The deep fluids promoted the evolution of source rocks in this area and increased hydrocarbon generation volume. As for reservoir quality， it has the constructive role of hydrothermal corrosion and the destructive role of hydrothermal calcite and late dolomite cement and filling.
During the Cenozoic， sea-land transition processes have important controlling effect on the depositional and petroleum geological characteristics of the northern South China Sea sedimentary basins. Based on the latest research results of IODP and the existing data in the basin， researches about the formation process of marine sediments in the northern South China Sea are carried out， and its geological significance for hydrocarbon exploration is carried out， in order to provide a basis for the future exploration and development of oil and gas resources. With the seafloor expansion process， the northern South China Sea correspondingly showed a westward and southward marine transgression during the Cenozoic. In Eocene， marine transgression firstly occurred in the Taixinan Basin in the eastern South China Sea. Later it was not until Late Oligocene that marine transgression occurred in the Yinggehai Basin of the western South China Sea. IODP 367/368 site revealed that the initial marine transgression occurred at ca. 34 Ma， and coincided with the start of the South China sea seafloor spreading. The southwest sub-basin of the South China Sea was originally formed at ca. 23 Ma， and large-scale transgression with drastic sedimentary environment changes took place during this time. Marine source rock strata in the northern South China Sea basins gradually get younger from east to west， which is also consistent with the westward marine transgression processes. Under the comprehensive impacts of both South China Sea expansion and global sea level changes， carbonate platforms also evolved from east to west， and from south to north， and formed a self-generation and self-storage oil and gas reservoir pattern in the northern South China Sea. Conclusively， sea-land transition has controlled sedimentary infilling processes within different basins， which were formed as material foundation for petroleum resources. Horizontally， the northern South China Sea source-reservoir-cap assemblage was dominated by provenances and sedimentary environment evolution. Vertically， on the other hand， it was mainly controlled by regional tectonic events and sea level changes.
Southern South China Sea has a complex evolutionary process， where multiple plates converge here， and rich in oil-gas resources. This paper starts with seismic data and drilling data， combined with the geological data of oil and gas fields in the southern South China Sea， guided by regional tectonic and sedimentary characteristics， determines the genetic type and evolution process of the basin in the southern South China Sea， and discusses the differences of oil and gas geological conditions and petroleum play. And it can be divided into four regional petroleum plays by T50， T70 and T100 unconformities for the main basins in the southern South China Sea. They are Pre-Paleogene play， Eocene-Lower Oligocene play， Upper Oligocene-Lower Miocene play and Middle Miocene-Upper Miocene play， which is totally different from others. The reason is that， controlled by basin tectonic evolution and paleogeographic position， the pattern of the main basins in the southern South China Sea is mainly the basin prototype with the most advantageous development scale， and the dominant basin prototype determines the oil and gas geological conditions and the main accumulation assemblages of each basin.
This paper aims at the sedimentary characteristics and sedimentary facies model of lacustrine carbonate rocks of Buxin Formation in Sanshui Basin. Petrological characteristics were analyzed by using core， thin section， scanning electron microscope and X-ray diffraction data. Combined with trace element data， sedimentary environment analysis was carried out. The carbonate sedimentary facies model is established based on the analysis of continuous well profile. The results are as follows： （1）The carbonate rocks of Buxin Formation in Sanshui Basin are mainly composed of muddy limestone， biological limestone and micrite limestone. The overall lithology of carbonate rocks is fine， with high matrix content and low particle content. The cement is mainly mud crystal. The thickness of single layer is thin. （2）The carbonate rocks of Buxin Formation were formed in the gentle slope environment of lake basin with poor provenance. The overall hydrodynamic force is weak. It is formed in the oxygen-poor and anoxic environment. It is characterized by saline water chemical deposition and local biological deposition under relatively weak hydrodynamic conditions. （3）The sedimentary model of gentle slope carbonate rock controlled by paleotopography and lake wave is established. Carbonate rocks are mainly developed in the lakeside shallow lake area. The lakeside can be divided into two microfacies： sand mud flat and muddy lime flat. The shallow lake can be divided into three microfacies： biological shoal， muddy lime shallow lake and muddy shallow lake. The development of carbonate rocks with different microfacies has obvious differentiation. The dominant lithology of muddy lime flat is muddy limestone. The dominant lithology of biological shoal is biolimestone. The dominant lithology of muddy lime shallow lake is micritic limestone. The research results can provide basis for industrial mapping of carbonate sedimentary facies and prediction of reservoir distribution.
The sedimentary and diagenetic evolution process of carbonate rock formations is complicated， and the rock types are relatively diverse. The logging response characteristics of rocks vary greatly， which brings difficulties to lithology identification. Traditional methods have insufficient ability to express the vertical structure characteristics of logging parameters and the diversity of lithological characteristics. We propose a deep learning model based on capsule network to improve the recognition effect of complex carbonate lithology. The capsule network extracts the time series characteristics of logging parameters through the convolution structure， and expresses the invariance and covariation of the features with the capsule vector. The model we proposed can effectively dig out the internal relationship between logging parameters and lithology in the spatial sequence structure characteristics， thereby construct a high-precision lithology recognition model. Taking the carbonate reservoir in block W in the eastern area of Sulige Gas Field as an example， the application research of capsule network in lithology identification is carried out. First， the training set and the test set are divided based on six logging parameters that are sensitive to lithology information. Secondly， build the capsule network model based on multi-scale convolution and jump connection structure. Compared with traditional machine learning methods and conventional deep learning methods （K Nearest Neighbors， Naive Bayes， Support Vector Machines， BP Neural Networks and Convolutional Neural Networks， etc.）， the recognition accuracy of the lithology recognition model based on the capsule network reaches 96.65%. The recognition accuracy is improved by 1.59%-32.06%. The experimental results show that the capsule network can effectively extract the time series characteristics and vertical structure characteristics of the logging data， and provide a new idea for the identification of complex carbonate lithology.
Deep and tight gas reservoir is one of the hot spots now. Because of the large burial depth and low permeability the existing diffusion-filtration model cann’t accurately predict the concentration distribution of the reservoir, thus affects the formulation of development schema. ZHU（1989） put forward the concept of expansion diffusion coefficient based on the principle of diffusion originating from the change of chemical potential gradient, and established a Diffusion-filtration model considering pressure effect. However, this model does not consider the phenomena of gas collision and slippage with the pore surface in the process of tight gas reservoir flow. Based on the original model, the absorption term is added, and the collision slip phenomenon of gas in tight reservoir is considered in the motion equation, so that the new model can describe the flow law of gas in tight reservoir, and the influencing factors of the new model are analyzed. The results show that the expansion diffusion coefficient caused by pressure can increase production of gas more than 10%. The lower the permeability is, the greater the influence is. Molecular diffusion plays a major role in the whole production process, and the diffusion caused by pressure mainly affects the early stage of production and near well zone. The diffusion caused by pressure has a greater impact on low-permeability and high-pressure gas reservoirs.
Estimation of gas in place is a hot issue in the field of oil and gas reservoir engineering. Material balance method and its derivative methods are widely employed in determining gas in place or well-controlled reserves， but their costs are usually high. To determine gas in place of abnormally pressured gas reservoirs with desirable accuracy and efficiency， this paper derives an iterative calculation method taking the pore restriction of reservoir rocks and the volume expansion of bound water into account， and proposes the selection strategy for initial iteration value. The method, called VRRLT-APGR (variable-rate reservoir limits testing for abnormally pressured gas reservoirs) here, combines the mathematical model of gas flow through porous media which is solved on the basis of the fundamentals of natural gas flow, with the material balance principle of overpressured gas reservoirs. Numerical simulation data under various production scenarios and two field cases with variable-rate/variable-pressure conditions are used to verify its effectiveness， and generally the calculation error for gas in place is no more than 5% under the condition that production data should be recorded reliably and credibly. VRRLT-APGR method works very well for both gas reservoirs with abnormal high pressure and those with normal pressure in virtue of its strict theoretical basis， which also takes into consideration the changes in flowrate and variations of gas properties as functions of pressure.
After CO2 dry fracturing， the gas enters the tight sandstone gas reservoir and is replaced with reservoir oil and gas through the method of simmering wells， which can improve the oil and gas reservoir recovery rate and solve the problem of CO2 storage， reduce its emissions， and protect the environment. And increasing oilfield production has double benefits. The macro benefits of CO2 simmering well replacement in oil and gas reservoirs are obvious， but there are few studies on the micro-erosion effect of CO2 on reservoir pore throats during simmering well replacement. In this paper， based on the indoor design displacement experiments of C7 and C8 reservoirs and H8 and S2 gas reservoirs in PetroChina Changqing Oilfield Company， the efficiency of CO2 replacement and displacement of oil and gas in stewed wells is studied， and the effects of CO2 replacement process on the mineral composition of the reservoir are studied by combining XRD and SEM scanning results and the influence of microscopic pore throat structure. The results show that in oil reservoirs， CO2 displacement oil displacement efficiency is generally low （25.27%）， and it is greatly affected by core permeability， while the time of simmering well has relatively little influence on its displacement efficiency； in gas reservoirs， CO2 displacement methane gas displacement efficiency is higher（76.50%）， and the core permeability is less affected， but the simmering time has a relatively large impact on its replacement efficiency； XRD results show that CO2 has a weak dissolution effect on the clay minerals of the reservoir； SEM results show that after CO2 erosion， a small amount of alteration products on the surface of the core pore and throat are attached to the surface of the rock particles， making the shape， boundary and pore structure of the rock mineral particles slightly blurred， and simmering； the longer the well time， the more serious the solid surface erosion.
In order to make clear the generation and enrichment regularity of deep gas in Xingshan Sag of Songliao Basin， we systematically analysed the geochemical characteristic of deep gas， based on comprehensive data such as chemical components and carbon isotope composition in 76 wells. The results show that the gas in Huoshiling Formation is short of methane and enrichment of heavy hydrocarbon， and carbon isotope is the lightest. While the gas in Denglouku Formation is characterized by enrichment of methane and short of heavy hydrocarbon， carbon isotope is the greatest. Gas in Yingcheng Formation is somewhere in between. The generation of deep gas in different layers are not exactly corresponding to each other， the gas in Huoshiling Formation is a mixture of coal-formed gas and oil-related gas， while gas in Yingcheng Formation is mainly coal-formed gas with little amount of oil-related gas. Mixing of oil-related gas with coal-formed gas is the reason for δ13C1 and δ13C2 partial reversal. The gas in Denglouku Formation is all coal-formed gas， the mixture of coal-formed gas with different maturity stages is the reason for δ13C2 and δ13C3 partial reversal. The fault is the necessary pathway for gas migration and accumulation among different genetic types， while gas of different genetic types and high-yielding gas wells are all affected by the distribution of mudstone and coal， the enrichment of deep gas is controlled by the combined effect of source and fault.
In order to clarify the organic matter source， maturity and depositional environment of crude oil in the northwestern Qaidam Basin， studies are carried out to better understand the genesis and accumulation pattern of crude oil in the northwestern Qaidam Basin. Systematic analyses were performed on 41 saturated hydrocarbons and aromatic hydrocarbons of crude oil in the Paleogene and Neogene reservoirs of the Xiaoliangshan Depression and Mangya Depression of the northwestern Qaidam Basin. According to the distribution characteristics of the aromatic compounds of Paleogene and Neogene reservoirs crude oil in Xiaoliangshan Depression and Mangya Depression of northwestern Qaidam Basin， crude oil is generally divided into two groups. In the first type of crude oil， the relative content of aromatic compounds is the highest in the triaromatic steroid series， followed by the relative content of the naphthalene series， phenanthrene series， trifluorene series， and the chrysene series. In the second type of crude oil， phenanthrene series have the highest relative content of aromatic compounds， followed by the relative content of naphthalene series， trifluorene series， triaromatic steroid series， and chrysene series. The distribution characteristics of molecular biomarkers in the saturated hydrocarbon and aromatic hydrocarbon which implies the source of organic matter， depositional environment and maturity indicate that the Paleogene and Neogene reservoirs crude oils from Xiaoliangshan Depression and Mangya Depression of the northwestern Qaidam Basin belong to light brackish-brackish lacustrine oil， and are in the mature stage of evolution， dominated by low aquatic organisms， supplemented by terrestrial higher plants. The water bodies of the main source rocks of the Paleogene-Neogene in this area have a strong stratification degree and reduction. In the Xiaoliangshan Depression and Mangya Depression of the northwestern Qaidam Basin， from the northwest to the southeast， the stratification of water in the main source rocks of different tectonic belts during the sedimentation period gradually deteriorates， the reducibility decreases sequentially， and the maturity increases. It shows that the Paleogene and Neogene reservoirs crude oil and gas in this area has the characteristics of near-source reservoir formation. The Honggouzi， Xiaoliangshan， Xiandong and Xianshuiquan tectonic belts near the Altun Mountains are important areas for future crude oil exploration， while the Youquanzi， Nanyishan， Dafengshan， Huangguamao and Kaitemilike structural belts in the slope area are important areas for crude oils and natural gas exploration in the future.
Radon， a radioactive inert gas， is a direct daughter of radium， an intermediate product of the decay of uranium and thorium. Radon and its daughters enter the surface system with the extraction of natural gas， causing harm to equipment and human body. This paper introduces the source， harm， release mechanism， detection method and influencing factors of radon， and collects the content of radon in natural gas in some countries. With the continuous expansion of shale gas exploitation in recent years， radon in shale gas has been widely concerned. Radon levels in Marcellus shale gas in the northeastern United States are at 37-95 312 Bq/m3. At present， there is no systematic research on radon content in natural gas in China， and only relevant reports published around 1994. The average radon content in natural gas in China is similar to or slightly lower than the median radon content of natural gas in the world， but the indoor radon content may increase when domestic gas is used. The detection methods of radon in natural gas are summarized. It is suggested that the detection and research of radon in natural gas should be vigorously carried out， and the prevention and control of radon in natural gas should be strengthened.
The reservoirs in the intra-platform of the Sinian Dengying Formation in the central Sichuan Basin are characterized by poor property and thin thickness. According to the reservoir classification standards of the marginal platform， there is no clear correspondence between the reservoir thickness and the drilling output in the intra-platform， which limits the exploration and development of the Dengying Formation. So we carried out the division of reservoirs in the intra-platform in central Sichuan Basin， the analysis of well logging and seismic response characteristics， and the study of reservoir prediction methods. The results show that the cave reservoir is the key factor for the intra-platform to control the well production. Logging response shows the phenomenon of leakage and blowout during the drilling process， and well log response features are characterized by acoustic time difference greater than 180 μs/m， density less than 2.65 g/cm3， and large dark clusters in the imaging image. The cave reservoirs in the intra-platform are mainly developed on the top of Dengying Formation. The seismic response is characterized by weak amplitude of Dengying Formation top and weak peak within 20 ms below it. According to this， using the technology of removing strong reflection and attribute fusion， the reservoir prediction carried out in the GS19 area is very consistent with the drilling results， and many development wells have been deployed. We provide a new idea for the exploration and development of the Dengying Formation in the central Sichuan area.
The research of characterization of underground sand bodies under the conditions of sparse well pattern and large well spacing is difficult in the initial stage of oil and gas field development. This paper takes seismic data as the leading factor， combines wells and earthquakes， and uses waveform indicator inversion technology to identify the boundary and superimposition relationship of the distributary channel sand bodies in the upper Shihezi Formation in the Linxing S area， and clarifies the superimposition of distributary channels， relationship and its influencing factors. The superimposed type of distributary channel is controlled by A/S and channel energy. Four types of high-energy independent sand bodies， high-energy laterally cut sand bodies， vertical tangentially stacked sand bodies， and high-energy superposed sand bodies are identified on the seismic profile. There are three types of low-energy superimposed sand bodies： Superposed sand bodies and low-energy superposed sand bodies， low lateral spliced sand bodies， and low-energy isolated sand bodies. Compared with sand bodies developed in low-energy environments， sand bodies in high-energy environments have a larger scale and better physical properties， and high-quality reservoirs are easy to develop. Using this method to identify the superposition relationship of sand bodies can effectively provide a basis for sand body and gas reservoir prediction and guide well pattern deployment.
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