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Publisher: Ke Ai   (Total: 30 journals)   [Sort by number of followers]

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Advanced Industrial and Engineering Polymer Research     Open Access   (Followers: 2)
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Animal Nutrition     Open Access   (Followers: 19, SJR: 0.442, CiteScore: 1)
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Clinical eHealth     Open Access  
Emerging Contaminants     Open Access   (SJR: 1.233, CiteScore: 3)
Frontiers in Laboratory Medicine     Open Access  
Geodesy and Geodynamics     Open Access   (SJR: 0.469, CiteScore: 1)
Green Energy & Environment     Open Access   (Followers: 2)
Infectious Disease Modelling     Open Access   (Followers: 2)
Intl. J. of Innovation Studies     Open Access  
Intl. J. of Lightweight Materials and Manufacture     Open Access  
J. of Finance and Data Science     Open Access   (Followers: 3)
J. of Natural Gas Geoscience     Open Access   (SJR: 0.783, CiteScore: 1)
Liver Research     Open Access  
Materials Science for Energy Technologies     Open Access   (Followers: 1)
Nanotechnology and Precision Engineering     Open Access  
Non-coding RNA Research     Open Access  
Oncology Signaling     Open Access  
Petroleum     Open Access  
Petroleum Exploration and Development     Open Access   (Followers: 3, SJR: 0.684, CiteScore: 2)
Petroleum Research     Open Access  
Plant Diversity     Open Access   (Followers: 1)
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Translational Medicine of Aging     Open Access  
Translational Metabolic Syndrome Research     Open Access  
Water-Energy Nexus     Open Access  
World J. of Otorhinolaryngology - Head and Neck Surgery     Open Access  
Journal Cover
Journal of Natural Gas Geoscience
Journal Prestige (SJR): 0.783
Citation Impact (citeScore): 1
Number of Followers: 0  

  This is an Open Access Journal Open Access journal
ISSN (Print) 2468-256X
Published by Ke Ai Homepage  [30 journals]
  • Experimental investigation of porosity and permeability change caused by
           salting out in tight sandstone gas reservoirs

    • Abstract: Publication date: December 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 6Author(s): Lijun You, Zhe Wang, Yili Kang, Yushan Zhao, Dujie Zhang Salt precipitation and its induced problems are increasingly prominent with the development of deep and ultra-deep tight sandstone gas reservoirs with high salinity formation water. In this paper, the change of porosity and permeability of a series of tight sandstone was measured, and then the morphology and occurrence state of crystalloid salt within the pore was observed by SEM. Meanwhile, high-pressure mercury injection analyzed the changes of pore size distribution. Experimental results show that salt precipitation could affect the porosity and permeability, which decreases by 53% and 65% after salt precipitation, respectively. The occurrence state of the crystalloid salt can be divided into three models: superposition growth along with the intergranular pore-fractures/natural micro-fractures, lamellar growth attached to the surface of the hydrophilic mineral like I/S interstratified mineral and the individual particles located in the corner of the pore. When the size of crystalloid salt is closer to the pore size distribution of tight sandstone, it will cause cracks and pore throat blockage easily. It is suggested that salt wash pretreatment should be carried out before analysis of tight sandstone with porosity less than 5%.
  • Effective stress characteristics in shale and its effect on shale gas

    • Abstract: Publication date: December 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 6Author(s): Weiyao Zhu, Dongxu Ma Research of effective stress characteristics on the productivity of shale gas has a great significance. The samples of the black shale and bedding shale at the Lower Silurian Longmaxi Formation in Sichuan Basin are selected. Microscopic pore structure characteristics are described by scanning electron microscopy, and the effective stress coefficient is measured by the cross-plotting method. The experimental results show that the effective stress coefficient of black shale is 0.29 on average and the bedding shale is 0.71. There are micro-fractures in bedding shale; thus pore pressure has a more significant influence on bedding shale than black shale. Fitting the relationship between effective stress and permeability by an exponential function, and the calculated stress sensitivity constants of black shale and bedding shale are 0.268 MPa−1 and 0.355 MPa−1, respectively. Recovery model of the fractured horizontal well was established according to experimental results involving effect of geological stress and flow scale, and the abandoned pressure approach was used to evaluate the recovery. The results show that the geological stress greatly influences the reservoir with developed micro-fractures, the production pressure should be adequately controlled for the high production well. The fractured block size and micro-fractures in the fractured block of the construction area have a significant influence on gas recovery; then for the reservoirs with small amount of micro-fractures and large fractured blocks, wellbore pressure should be controlled to improve the recovery.
  • Potential and favorable areas of petroleum exploration of ultra-deep
           marine strata more than 8000┬ám deep in the Tarim Basin, Northwest China

    • Abstract: Publication date: December 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 6Author(s): Guangyou Zhu, Yinghui Cao, Lei Yan, Haijun Yang, Chonghao Sun, Zhiyao Zhang, Tingting Li, Yongquan Chen At present, deep and ultra-deep oil and gas have become the research and exploration hotspots. With little drilling data available, the geological understanding on deep formations is still in the exploratory stage, but most petroleum geologists have universally acknowledged that the deeply-buried strata of Chinese marine craton basins are equipped with the conditions for abundant oil and gas resources. A series of discoveries have been made in the Ordovician and Cambrian strata. For Precambrian strata, besides breakthroughs in the Sichuan Basin, a lot of research or drilling work has been initiated in other basins. In the Tarim Basin, the current burial depth of the Lower Paleozoic and the Precambrian mainly ranges from 5000 to 12000 m. This is attributed to rapid subsidence and deposition since the Neogene. A large number of exploration discoveries have been made, and commercial productivity projects have been constructed at the depth less than 8000 m. Strata more than 8000 m deep will be a significant major prospecting exploration field in the future. The analyses of hydrocarbon accumulation conditions of the ultra-deep layers of the Tarim Basin provide theoretical guidance for ultra-deep oil and gas exploration. This research is based on source rocks in the Cambrian, Sinian, and Nanhua System, formation and preservation of ultra-deep carbonate reservoirs, phase of petroleum and accumulation assemblages in ultra-deep strata, the exploration fields deeper than 8000 m were also evaluated to sort out the most favorable areas and, future exploration focuses on the Ordovician, Cambrian, and Sinian strata are pointed out.
  • Resource potential, exploration prospects, and favorable direction for
           natural gas in deep formations in China

    • Abstract: Publication date: December 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 6Author(s): Jingdu Yu, Min Zheng, Jianzhong Li, Xiaozhi Wu, Qiulin Guo Natural gas contained in deep formation is a respect with strategic importance for hydrocarbon exploration in china, which presents a low ratio for being discovered only as 18.46%. It indicates that there is confirmative necessity and research value for clarifying the resource potential and ascertaining the favorable explorative direction. From elaborating the present condition in exploration for natural gas resource, methodologies including hydrocarbon generation, analogy and statistics are applied based in the result of the 4th resource assessment of PetroChina, which indicates there is a huge total amount of source potential. It occupies a predominant position as 20.31 × 1012 m3 as 55% of the entire amount of resource potential for natural gas. The anisotropic characteristic is presented in the respect of resource distribution. Sichuan, Tarim and Songliao Basin are recognized as the relatively more concentrated (76.70%) in resource potential. Similar feature in anisotropy also exists in the respect of lithology, carbonates occupies 57.27% of the proves reservoir of natural gas contained in deep formations, which mainly correlates to the marine strata of Paleozoic cratons in the center and west basins. In the respect of remaining resource, it is quite abundant as 16.56 × 1012 m3. 76.07% of the remaining resource is contained in three mains basins as Sichuan, Songliao and Tarim basin. In these basins, the favorable directions to further exploration for natural gas in deep formations are acquired as the clastic and volcanic reservoir from Jurrasic to Cretaceous system formed in the fault depression group of Songliao basin, the dolomite reservoir of the lithological facie as mound and shoal in the center of paleo-uplift in Sichuan Basin, bioclastic limestone and dolomite reservoir in the facies of reef flat contained in Changxing and Feixianguan formation in the north and northwest of Sichuan Basin, The dolomite reservoir from Devonian to lower Permian in the west of Sichuan Basin, the Ordovician dolomite reservoir in the facies of mound and shoal in the center of Tarim Basin, and Cretaceous clastic reservoir in Kuche depression of Tarim basin, etc., which consequently reveals the prominent prospect for natural gas contained in deep formations.
  • China's conventional and unconventional natural gas resources: Potential
           and exploration targets

    • Abstract: Publication date: December 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 6Author(s): Min Zheng, Jianzhong Li, Xiaozhi Wu, Shejiao Wang, Qiulin Guo, Jingdu Yu, Man Zheng, Ningsheng Chen, Qing Yi A series of significant breakthroughs in exploring conventional and unconventional natural gas resources have been achieved in new strata and new domains. However, the quality of the increased reserves has declined with the entry of unconventional resources into the reserves sequence. Therefore, the potential of conventional and unconventional natural gas resources as well as important exploration regions of the remaining natural gas resources need to be clarified, and favorable directions need to be established. On the basis of oil and gas exploration results, discoveries in petroleum geology, and exploration data of the past 10 years acquired by PetroChina, an entire system of resource assessment for conventional and unconventional oil and gas resources has been established. The fourth round of resource assessment has been systematically executed. The results indicate that the total conventional natural gas resources of China are 78 × 1012 m3, which shows an increase of 8 × 1012 m3 over the results of the third round of resource assessment. Unconventional resources include four types of resources: tight gas, shale gas, coalbed methane, and natural gas hydrates. Among them, tight gas reservoirs make up 21.86 × 1012 m3 (Jiyang, Dongpu, Nanxiang, Subei, and others were excluded from the assessed regions). In addition, shale gas, coalbed methane, and natural gas hydrate reservoirs make up 80.21 × 1012 m3, 29.82 × 1012 m3, and 153.06 × 1012 m3, respectively. The remaining resources for onshore conventional natural gas are distributed mainly in four significant domains, which are lithology–strata (clastic rock), marine carbonatites, foreland thrust belts, and complex tectonic belts. Of these, marine carbonatites and foreland thrust belts are the dominant domains. The resources for offshore natural gas are concentrated mainly in three domains, which are offshore structures, organic reefs, and lithology in deep water. The total remaining natural gas resources in marine carbonatites, foreland, lithology–strata, complex tectonic belts, and the South China Sea amount to 59.83 × 1012 m3, which is 94% of the remaining natural gas resources in China. Based on this assessment, favorable targets are selected including 10 targets for conventional resources, 4 for tight gas, 4 for coalbed methane, and 6 for shale gas.
  • Research status on thermal simulation experiment and several issues of

    • Abstract: Publication date: October 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 5Author(s): Weilong Peng, Guoyi Hu, Quanyou Liu, Nan Jia, Chenchen Fang, Deyu Gong, Cong Yu, Yue Lyu, Pengwei Wang, Ziqi Feng We study the research status of thermal simulation experiment and put forward three issues worthy of attention and five important development directions. Classification according to thermal simulation system is the most widely used classification scheme. Different thermal simulation experimental systems have their own characteristics, and according to different experimental purpose, a suitable thermal simulation experiment system can be selected according to different experimental purposes. The closed experimental system is more suitable for the thermal simulation experiment of humic source rocks. The online analysis of open system has unique advantages in the study of volatile components. The semi-open system is the most closest to the thermal simulation system of the thermal evolution of the source rocks in the actual geological condition. Three key issues are presented concerning the thermal simulation experiment are presented. The first is the influence of water on the thermal simulation experiment. The second is whether convincing isotope reversal can be presented expect Fischer–Tropsch synthesis. The third is that, in the study of the thermal simulation experiment, the model of hydrocarbon generation must be built in combination with the actual geological background. Five key development directions concerning the thermal simulation experiment are proposed. The first is thermal simulation experimental study on a relatively low temperature and a long time with water participation. The second is experimental research on thermal simulation of unconventional petroleum. The third is a study on the development of pore microcracks in source rocks and the correlation of the interaction of fluid discharge in thermal simulation experiments. The fourth is an experimental study on thermal simulation of carbonate source rock. The fifth is an experimental study of thermal simulation related to abnormal pressure.
  • Structural characteristics and main controlling factors on petroleum
           accumulation in Zagros Basin, Middle East

    • Abstract: Publication date: October 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 5Author(s): Xiaobing Liu, Zhixin Wen, Zhaoming Wang, Chengpeng Song, Zhengjun He Zagros Basin is one of the essential basins in the Middle East with the giant oil and gas reserves. It is indicated by regional tectonic and sedimentary evolution, basin structural division, petroleum distribution characteristics and main controlling factors of petroleum accumulation. It has experienced four significant phases which are early Paleozoic intra-Cratonic pull apart basin and platform margin basin, late Paleozoic platform margin basin, Mesozoic passive continental margin basin, and Cenozoic foreland basin. The Zagros Mountain Front Fault and High Zagros Fault divided the basin into foredeep zone, simply folded zone, and Zagros thrust fault zone from southwest to northeast. The oil fields are mainly located in the foredeep zone, while the gas fields are mostly in the simply folded zone and few fields are in the Zagros thrust fault zone. The Lower Cretaceous Kazhdumi Formation mudstone is the main source rock for the Mesozoic, and Cenozoic reservoirs and the Silurian Gahkum Formation mudstone is the main source rock for the Paleozoic reservoirs. The Cenozoic carbonate is main reservoir followed by the Cretaceous Sarvak and upper Permian Dalan carbonate. The evaporite and mudstone are the main seal in the foredeep zone, while the mudstone in the simple anticline zone. The anticline structure and the seal type is the main controlling factor for the petroleum accumulation.
  • Geochemical characteristics of source rocks in the Lower Cambrian
           Niutitang Formation in Guizhou Province, China

    • Abstract: Publication date: October 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 5Author(s): Zhibin Jia, Dujie Hou, Deqiang Sun, Yuhan Jiang, Ziming Zhang, Mei Hong Organic-rich source rock was closely related to the development of hydrothermal sedimentation in geochemistry and others. By studying the characteristics of the source rocks of Lower Cambrian Niutitang Formation in Guizhou Province of China, it was found that the strata affected by both terrigenous inputs and hydrothermal sediments. There were a few samples with a low gross amount of REEs, which widely varied in others. The influence of the hydrothermal sedimentation was stronger in Yangtiao and Jiumen sections, while relatively weaker in Lianxing and Wenshui sections. The content of As and Sb enriched in Niutitang Formation, which indicated the existence of the hydrothermal activity. The δEu/Al ratio can be used to distinguish and indicate the intensity of the hydrothermal sedimentation.
  • Carbon isotope and origin of the hydrocarbon gases in the Junggar Basin,

    • Abstract: Publication date: October 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 5Author(s): Lixin Pei, Wenzhe Gang, Chuanzhen Zhu, Yazhou Liu, Wenjun He, Yan Dong, Baoli Xiang The genetic type, source and distribution of hydrocarbon gases in the Junggar Basin were clarified through the carbon isotope analysis. Mature to post mature oil-type gas, mature to post mature coal-type gas, transition gas and biogas are identified in the Junggar Basin. Partly reversed order of carbon isotope of hydrocarbon gases in the Junggar Basin are attributed to one or several of the following reasons: mixing of oil-type and coal-type gases, mixing of coal-type gases of different source, mixing of coal-type gases of varied maturity, and microbial action. Three types of coal-type gases in the Junggar Basin are identified. The first type of coal-type gases characterized with high δ13C values of heavy hydrocarbon gases (δ13C2>−26.0‰) are the mature to high mature gases that are generated from Jurassic source rocks. The second type of coal-type gases characterized with low δ13C values of heavy hydrocarbon gases (δ13C2
  • Diagenetic evolution characteristics of Paleogene lacustrine carbonate
           reservoirs in central Bohai sea, China

    • Abstract: Publication date: October 2018Source: Journal of Natural Gas Geoscience, Volume 3, Issue 5Author(s): Zhengxiang Lv, Yuanhua Qing, Fu Zhao, Jiayang Wu, Xiandong Wang The distribution of high-quality reservoirs in Shahejie Formation of the Shijiutuo Uplift, Central Bohai Sea, is the key factor to determine the oil and gas accumulation. Likewise, diagenesis is the key factor to control the development of lacustrine carbonate reservoirs in Shahejie Formation. So, accurately analyzing the diagenesis is very important for improving reservoir prediction. By means of polarizing microscopy, fluorescence microscopy, scanning electron microscopy, cathodoluminescence and electron probe analysis techniques, reservoir characteristics and diagenetic evolution sequence are determined. The diagenetic stage was determined by X-ray diffraction of clay minerals. Gas-liquid inclusion homogenization temperature and oxygen isotope geothermometer are used to analyze the formation period of authigenic carbonate minerals. Bioclastic dolostone is the main type of carbonate rocks, followed by dolarenite. The visceral cavity pores and residual primary intergranular pores are the main reservoir space. The diagenetic evolution sequence is established based on the different occurrences of multistage dolomites and their relationship with other diagenesis phenomena, and the final diagenetic stage is the phase B of mesodiagenesis. The favorable diagenesis for reservoir physical properties is the early formation of the pore-lining dolomite deposited in the eodiagenesis and the grain-coating dolomite deposited in the syndiagenesis, both of which weaken the subsequent mechanical compaction to the reservoir porosity.
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