for Journals by Title or ISSN
for Articles by Keywords
help

Publisher: Ke Ai   (Total: 15 journals)   [Sort by number of followers]

Showing 1 - 15 of 15 Journals sorted alphabetically
Advances in Climate Change Research     Open Access   (Followers: 12, SJR: 0.321, h-index: 5)
Animal Nutrition     Open Access   (Followers: 17)
Bioactive Materials     Open Access   (Followers: 1)
Chronic Diseases and Translational Medicine     Open Access  
Emerging Contaminants     Open Access  
Geodesy and Geodynamics     Open Access  
Green Energy & Environment     Open Access   (Followers: 2)
Infectious Disease Modelling     Open Access   (Followers: 1)
J. of Finance and Data Science     Open Access   (Followers: 2)
J. of Natural Gas Geoscience     Open Access  
Non-coding RNA Research     Open Access  
Petroleum     Open Access  
Plant Diversity     Open Access  
Synthetic and Systems Biotechnology     Open Access  
World J. of Otorhinolaryngology - Head and Neck Surgery     Open Access  
Journal Cover Journal of Natural Gas Geoscience
  [0 followers]  Follow
    
  This is an Open Access Journal Open Access journal
   ISSN (Print) 2468-256X
   Published by Ke Ai Homepage  [15 journals]
  • Accumulation conditions and exploration potential of Wufeng-Longmaxi
           Formations shale gas in Wuxi area, Northeastern Sichuan Basin, China

    • Abstract: Publication date: Available online 20 December 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Wei Wu, Xuewen Shi, Jia Liu, Du Li, Jun Xie, Shengxian Zhao, Chunhai Ji, Ying Hu, Yanbo Guo
      Wufeng-Longmaxi Formations shale gas is a new exploration field in Wuxi area, Sichuan Basin, China. Some geological parameters related to shale gas evaluation of the new exploration wells in Wuxi area have been studied, including shale reservoir, gas-bearing, geochemical and paleontological characteristics. The study suggests that the original shale gas generation conditions of the area were good, but later this area went through serious and multi-phase tectonic damage. The major evidences include that: the δ13C2 value of shale gas is obviously higher than that in areas with the same maturity, indicating the shale gas is mainly late kerogen cracking gas and high hydrocarbon expulsion efficiency; the porosity of shale in Wuxi area is very low because of strong tectonic movements and lack of retained oil in the shale; some shale cores near faults even show very weak metamorphic characteristics with intense cleavage, and the epidermis of graptolite fossils was pyrolyzed. The comprehensive study shows shale gas in Wuxi area has prospective resources, but the possibility to get scale commercial production in recent time is very low.

      PubDate: 2018-01-10T05:04:02Z
       
  • Cracking and thermal maturity of Ordovician oils from Tahe Oilfield, Tarim
           Basin, NW China

    • Abstract: Publication date: Available online 19 December 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Anlai Ma, Zhijun Jin, Cuishan Zhu, Zhenrui Bai
      The thermal maturity of the Ordovician oils from the Tahe oilfield of Tarim Basin, NW China was assessed through various maturity parameters, such as biomarkers, aromatic parameters, and diamondoid parameters. Both Ts/(Ts+Tm) and C29Ts/(C29H+C29Ts) values indicate that the maturity of oils has not reached the condensates stage, which is consistent with the maturity obtained by MPI1. However, the diamondoid maturity suggests that the oil maturity ranges 1.1%–1.6% Ro, which is apparently higher than that of the maturity obtained by the biomarker and MPI1. This discrepancy in maturity may indicate that the Ordovician reservoir has multiple filling history. The 4-MD+3-MD concentration of oils disperses and increases slowly when the Ts/(Ts+Tm) value is lower than 0.55. Meanwhile, the value increases rapidly when the Ts/(Ts+Tm) value is higher than 0.55. It is proposed that the diamondoid baseline is about 15 μg/goil for marine oils in the Tahe oilfield based on the diamondoid concentration of marine oils from reservoirs of various age. The concentration of 4-MD+3-MD of most Ordovician oils generally ranges from 4.5 to 35 μg/goil, suggesting that the degree of oil-cracking is lower than 50% and the deep Ordovician have potential of oil exploration. The distribution of the concentration of 4-MD+3-MD is characterized by being high in the east and south, low in the west and north, proposing that the two migration pathways exit in the oilfield, which are from east to west and from south to north, respectively. The migration directions are consistent with the results obtained from the oil density and the maturity parameters such as Ts/(Ts+Tm). Thus, suggesting the concentration of 4-MD+3-MD can be used as migration index in oilfield scale.

      PubDate: 2018-01-10T05:04:02Z
       
  • Hydrocarbon phase limit and conversion process in the deep formation from
           Qikou Sag of Bohai Bay rift lacustrine basin, China

    • Abstract: Publication date: Available online 19 December 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Yan Liu, Yongjing Tian, Chiyin Yang, Dunqing Xiao, Qianjin Liao, Chen Shen, Yunpeng Fan, Penghai Tang, Xiugang Pu, Wenya Jiang
      It is an important research direction for the prediction of hydrocarbon phase in the reservoir during the deep exploration of rift basins in eastern China. The typical lacustrine crude oil of Shahejie Formation in Qikou Sag was used for oil cracking to gas simulation experiment by the gold tube in this paper. Then, the kinetic parameters obtained from the experimental data were studied during the cracking reactions and the hydrocarbon phase conversion process under geological conditions. The results showed that the activation energy of the oil cracking to gas from the BH-28 lacustrine crude oil ranged from 250 kJ/mol to 270 kJ/mol with an average of E O = 255.47 kJ/mol, and the frequency factor was about A = 1014 s−1. It is higher than that of typical marine oil E O = 246.97 kJ/mol. Using these kinetic parameters, the simulated cracking process of the lacustrine oil of Shahejie Formation was far different from that of marine oil from western China under the same geological heating rate (3 °C/Ma). And the simulated oil cracking degree in Well Niudong-1 is 73.9%, almost the same with the conversion cracking degree (60%–75%) by concentrations of 3,4-dimethyldiamantane. The kinetics of oil cracking gas could be used to investigate the oil cracking degree easily, then to get the theoretical separate oil phase depth limit. By using this model, oil in Qikou Sag, as a theoretical separate phase destruction, occurs above 5700 m depth limit (R O is about 2.0%, reservoir temperature = 209 °C, with cracking transition C of 62.5%), and condensate gas destruction occurs above 6700 m depth limit (R O is about 3.2%, reservoir temperature = 240 °C, with C to 99%) under the geological conditions from Qikou Sag. Actually, the hydrocarbon phase is affected by many factors. For example, migration and changes of temperature and pressure conditions have great influence on phase conversion behavior. The injection of gas, originated from kerogen cracking gas and oil cracking gas in deeper, could increase GOR and the real separate phase depth would reduce.

      PubDate: 2018-01-10T05:04:02Z
       
  • Evaluation of source rocks in the 5th member of the Upper Triassic Xujiahe
           Formation in the Xinchang Gas Field, the Western Sichuan Depression, China
           

    • Abstract: Publication date: Available online 19 December 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Xiaoqi Wu, Yingbin Chen, Guowei Zhao, Xiaowei Du, Huasheng Zeng, Ping Wang, Yanqing Wang, Ye Hu
      The 5th member of the Upper Triassic Xujiahe Formation (T3 x 5) is one of the important targets for terrigenous natural gas exploration in the Xinchang Gas Field in the Western Sichuan Depression, however, the quality of the T3 x 5 source rocks is poorly studied and the understanding of it is controversial. Studies have been conducted on the development and organic geochemical characteristics of the T3 x 5 mudstone in the Xinchang Gas Field, and the results indicate that, the T3 x 5 mudstone in the Xinchang Gas Field display an average thickness of 285.3 m, and the thickness of each submember increases from north to south. The average TOC content, hydrocarbon potential (S1+S2) and chloroform bitumen “A” content of T3 x 5 mudstone are 2.17%, 2.26 mg/g and 0.264‰, respectively, with the organic abundance mainly reaching the standard of medium source rocks. The kerogen type index (TI) is lower than 0 with the mean δ13C value of −25.0‰, indicating mainly humic and sapropelic-humic types of organic matters. The average vitrinite reflectance (R O) value is 1.17%, indicating the stage after the peak of oil generation. The gas generation intensity of T3 x 5 mudstone is generally in the range of (3–16) × 108 m3/km2, which suggests the resource basis for the generation of medium-small gas fields. The total amount of natural gas generated by T3 x 5 mudstone in the Xinchang Gas Field is relatively low, and the generated gas cannot completely displace the water in the formation, therefore, the fullness of gas in the reservoirs is generally low, which causes the simultaneous production of gas and water and the low gas production in the process of production test.

      PubDate: 2018-01-10T05:04:02Z
       
  • Characteristics of shale nanopore system and its internal gas flow: A case
           study of the lower Silurian Longmaxi Formation shale from Sichuan Basin,
           China

    • Abstract: Publication date: Available online 28 November 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Yunfeng Yang, Fang Bao
      The gas flow in shale nanopores undergoes a transition from continuum-transition flow regimes to Knudsen diffusion, rather than the traditional Darcy flow, due to the dynamic properties of shale gas. Thus, becoming the premise in understanding gas flow regime within the shale nanopores to further investigate how shale permeability evolves during gas depletion as well as to predict gas production. The microstructure features of Longmaxi Formation shale (Longmaxi Shale), characterized by SEM imaging, MICP, and gas adsorption, are dominated by micropores and mesopores that are less than 10 nm in size on average. Judging from the pore sizes of Longmaxi Shale and the general reservoir pressures, the gas flow inside shale matrix is determined as slip flow and transition flow regimes by Knudsen number. About the investigation of the Barnett Shale, a second-order slip model is superior to the first-order slip model in describing apparent permeability of Longmaxi Shale. Then and there, the velocity profile and volumetric flow rate in Longmaxi Shale are discussed with a second-order slip model. The gas velocity on the pore walls becomes larger as pressure decreases. The gas production enhancement due to gas slippage effect brings about a higher yield than that of Darcy's Law. However, shale itself is highly heterogeneous in pore geometry. Therefore, the model construction of gas flow simulation must be based on refined shale pore models.

      PubDate: 2018-01-10T05:04:02Z
       
  • Geological characteristics, main challenges and future prospect of shale
           gas

    • Abstract: Publication date: Available online 28 November 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Caineng Zou, Qun Zhao, Dazhong Dong, Zhi Yang, Zhen Qiu, Feng liang, Nan Wang, Yong Huang, Anxiang Duan, Qin Zhang, Zhiming Hu
      The development of shale gas in the United States has made a breakthrough, profoundly changed the pattern of oil and gas supply. It created the “shale gas revolution” on a global scale. Based on the practice of shale gas development in China and abroad, this paper aims to: (1) Summarize 5 basic characteristics, which are shale gas resource distribution, reservoir space, sweet spot area (section), hydrocarbon type and development mode. (2) Divide China shale development into three stages: scientific exploration, technological breakthrough and mature development. The United States is divided into three stages: scientific exploration, technological breakthrough and mature development. The United States is divided into three stages: scientific exploration, technological breakthrough and mature development. (3) Identify 4 challenges in the future development of China shale gas industry. It includes non-marine shale gas potential, core technology and equipment for resource deep than 3500 m, complex surface “factory mode” production, human geography and other non-technical factors. (4) Process economic evaluation under the conditions of government financial subsidies. China's shale gas project FIRR is about 8.0%–9.0%. Considering the global shale gas resources, consumer demand and other factors, it global shale gas production is expected to reach 1.1 × 1012m3 by 2040.

      PubDate: 2018-01-10T05:04:02Z
       
  • Controlling factors of volcanic hydrocarbon reservoirs in Bohai Bay Basin,
           China

    • Abstract: Publication date: Available online 2 November 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Chun Yang, Lianhua Hou, Fan Yang, Xia Luo, Jinhong Wang
      Volcanic hydrocarbon reservoirs are developed in the Mesozoic and Cenozoic strata in Bohai Bay Basin in China. There is more than one hundred million tons of proven oil reserves in the said reservoir. They performed different actors for oil and gas accumulation in the basin. Faults controlled the distribution and accumulation of oil and gas related to volcanic rocks in Bohai Bay Basin. Not to mention, the zone near the faults is favorable for the development of good reservoirs. Volcanic rocks and volcanism can serve several roles during the course of hydrocarbon generation and accumulation. Volcanism can promote hydrocarbon generation from source rocks. Simultaneously, volcanic activity can damage petroleum reservoirs. Volcanic rocks can be both the reservoirs and the cap-rocks or obscured layer in the basin. The occurrence of volcanic rocks in source rocks can form fractures more easily compared to that in sandstones. Finally, volcanic rocks also control the distribution of mantle-derived CO2 gas reservoirs in the basin.

      PubDate: 2017-11-05T17:58:51Z
       
  • Stable carbon isotopic composition of light hydrocarbons and n-alkanes of
           condensates in the Tarim Basin, NW China

    • Abstract: Publication date: Available online 2 September 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Shipeng Huang, Chenchen Fang, Weilong Peng, Qingchun Jiang, Ziqi Feng
      The carbon isotope ratios of individual light hydrocarbons and the n-alkanes of twenty-one condensates from the Tarim Basin, as well as 47 condensates and oils from other petroliferous basins (Ordos Basin, Sichuan Basin, Turpan-Harmi Basin, Qiongdongnan Basin, Beibuwan Basin and Bohay Bay Basin) in China, were analyzed. We investigated the oil–oil correlation, the effects of gas washing and maturity, as well as the distinguishing parameters of humic and sapropelic condensates, and have come to the following conclusion. The carbon isotopic patterns of condensates and oils in the Ordovician strata of Tarim Basin are very similar, indicating they originate from the same type of source rocks. The condensates from Dawanqi oil field and Yinan 2, as well as Ti'ergen and Yitikelike gas fields, have similar carbon isotopic patterns. Thus, they probably have originated from the same terrestrial Jurassic source rock. The carbon isotopic patterns of the condensates from the Dabei, Kela 2, and Keshen gas fields are also similar, indicating they are of the same oil family and sourced from the Triassic and Jurassic terrestrial source rock. The carbon isotopic ratios of 2MP, 3-MP, 3-MH, and nC5-8 are much more susceptible to maturity level than other light hydrocarbons. Gas washing has minor effects on the δ13C compositions of individual light hydrocarbons and n-alkanes, although it causes <2‰ shifts. The δ13C compositions of MCP, CH, MCH, benzene, and toluene can be used as identification parameters for humic and sapropelic condensates. Humic condensates generally have δ13CMCP > −25‰, δ13CCH > −24‰, δ13CMCH > −24‰, δ13Cbenzene > −25‰, and δ13Ctoluene > −24‰, whereas sapropelic condensates mainly have δ13CMCP < −26‰, δ13CCH < −26‰, δ13CMCH < −24‰, δ13Cbenzene < −25‰ and δ13Ctoluene < −24‰. Moreover, the mixing humic and sapropelic condensates usually show intermediate values.

      PubDate: 2017-09-07T20:35:02Z
       
  • Insight into the C8 light hydrocarbon compositional differences between
           coal-derived and oil-associated gases

    • Abstract: Publication date: Available online 24 August 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Guoyi Hu, Weilong Peng, Cong Yu
      To analyze the C8 light hydrocarbon of absorbed gas in the source rock and natural gas, both the PY-GC and GC were applied. This is done in order to develop the discrimination parameters of different genetic gases. Eight samples, including six mudstones with type II1 and type I organic matter and two coals, were analyzed by PY-GC. On the other hand, the sixteen typical coal-derived gases and sixteen oil-associated gases were analyzed by GC. The results show that there exists a great difference in the ratio of 2-methylheptane and 1-cis-3-dimethylcyclohexane in coal-derived gases, oil-associated gases, and source rock absorbed gases. The ratio in coal-derived gases is less than 0.5, whereas it is higher than 0.5 in oil-associated gases. In addition, there are also differences in the relative composition of C8 normal alkanes, isoparaffin, and cycloparaffin in coal-derived and oil-associated gases. Coal-derived gas is characterized by high cycloparaffin content that is generally higher than 40%, while the oil-associated gas exhibits low cycloparaffin content that generally less than 40%, as well as high isoparaffin content. Therefore, these parameters can be used to identify a coal-derived gas from an oil-associated gas.

      PubDate: 2017-08-31T22:01:04Z
       
  • Genetic types and origins of natural gases from eastern Fukang
           Sub-depression of the Junggar Basin, NW China: Implication for low-mature
           coal-derived gases

    • Abstract: Publication date: Available online 18 July 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Deyu Gong, Yi Wang, Miao Yuan, Chaowei Liu, Julei Mi, Shan Lu, Lili Zhao
      Although the Fukang Sub-depression is the largest hydrocarbon generation depression in the Junggar Basin and promises favorable potential for oil and gas exploration, only several small–medium oil/gas accumulations have been discovered so far. After analyzing the molecular and stable carbon isotopic compositions of natural gases and its associated low molecular weight hydrocarbons (LMWHs) from eastern Fukang Sub-depression, their genetic types and origins are discussed in this study. Natural gases are wet gases with an average dryness coefficient of 0.84. Stable carbon isotopes of methane and ethane are well correlated with the thermal evolution trend of coal-derived gases. The C5–7 LMWHs are enriched in methyl cyclohexane but they lack n-alkanes, indicating a predominance of higher plant input. Gases have maturities ranging 0.76%–0.93%Ro and are well consistent with their low n-heptane (H) and iso-heptane (I) contents. The geochemical characteristics of natural gases from eastern Fukang Sub-depression are quite similar with those from the Turpan–Hami Basin. Their gases are considered to be low-mature gases derived from the Lower–Middle Jurassic coal measures. In contrast, they show remarkable differences with those from the Wucaiwan gas field; they are considered to have high-mature gases derived from the Carboniferous coal measures.

      PubDate: 2017-07-19T20:35:29Z
       
  • Further comprehension of natural gas accumulation, distribution, and
           prediction prospects in China

    • Abstract: Publication date: Available online 18 July 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Jun Li, Yuanqi She, Shuzheng Xiang, Aihong Shi, Shen Yang, Liyan Shao
      In-depth research reveals that the natural gas accumulation and distribution are characterized by cycle, sequence, equilibrium, traceability, and multi-stage. To be specific, every geotectonic cycle represents a gas reservoir forming system where natural gas is generated, migrated, accumulated, and formed into a reservoir in a certain play. Essentially, hydrocarbon accumulation occurs when migration force and resistance reach an equilibrium. In this situation, the closer to the source rock, the higher the accumulation efficiency is. Historically, reservoirs were formed in multiple phases. Moreover, zones in and adjacent to source rocks, unconformity belts, and faulted anticline belts are favorable areas to finding large gas fields. Apart from the common unconformity belts and faulted anticline belts, in-source and near-source zones should be considered as critical targets for future exploration. Subsequent exploration should focus on Upper Palaeozoic in the southeastern Ordos Basin, Triassic in southwestern Sichuan Basin, Jurassic in the northern section of the Kuqa Depression and other zones where no great breakthroughs have been made.

      PubDate: 2017-07-19T20:35:29Z
       
  • The experimental study on H2S generation during thermal recovery process
           for heavy oil from the Eastern Venezuela Basin

    • Abstract: Publication date: Available online 18 July 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Jingkui Mi, Bin Zhang, Zhijun Shen, Wensong Huang, Andrés Casalins
      Hydrogen sulfide (H2S) is toxic, corrosive and environmentally damaging. It is not only found in oil and gas development, but is also often found in heavy oil exploitation. In this study, three heavy oils were selected from the Orinoco Heavy Oil Belt in the southern part of the Eastern Venezuela Basin. Thermal cracking experiments in gold sealed tubes were then conducted using the heavy oils. The objective of the experiment is to unravel the H2S generation mechanism and utility in establishing a development program for heavy oil thermal recovery. The results of the oil isothermal cracking experiments show that the H2S yield increases with the increasing cracking temperature and holding time at 150 °C and 250 °C. Carbon dioxide (CO2) is the main component in gaseous products and its concentration is more than 80% in our experiments. The yields of CO2, H2S and total hydrocarbon gas present similar varying trend that increases with increasing isothermal time. The sulfur contents in group compositions of the original oil from the CJS-48 well and that of the residual oils with different cracking time at 250 °C were then measured. The analytical results show that most sulfur (>75%) exists in aromatics both in original oil and in the residual oils cracked at 250 °C, not to mention, no sulfur was measured in saturates. Although the decrease of sulfur in aromatics with the increased cracking time is low, it has great significance to the H2S generation during thermal recovery of heavy oil for more than 75% sulfur existed in aromatics. The decrease of sulfur content in resin and asphaltene of cracking residues with increased cracking time indicates that the sulfur existed in resin and asphaltene has some contribution to H2S generation during the thermal recovery process of heavy oil.

      PubDate: 2017-07-19T20:35:29Z
       
  • Differential extension and dynamic model of the deep-water area of the
           Pearl River Mouth Basin, northern South China Sea

    • Abstract: Publication date: Available online 15 July 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Caili Lü, Gongcheng Zhang, Dongsheng Yang, Huijun Gao
      Based on the flexural-cantilever model and flexural isostasy model, three independent quantitative methods have been used to calculate the stretching factors of the upper crust, whole crust, and whole lithosphere in the deep-water area of the Pearl River Mouth Basin, northern South China Sea. These results demonstrate that depth-dependent stretching has occurred within the lithosphere of the study area. The lithospheric extension shows lateral differences between the Baiyun Sag and the Kaiping–Shunde Sags. The broad forearc pre-rifting basement and hot thinned lithosphere tend to generate a structural style of wide half-graben in the Baiyun Sag, while the volcanic arc basement and normal or thickened lithosphere form a structural style of narrow half-graben in the Kaiping–Shunde Sags. In line with the lithospheric deformational features and tectonic evolution stages, we propose three various dynamic mechanisms at different tectonic stages, and they are probably uniform, composite, and depth-dependent extension models, respectively.

      PubDate: 2017-07-19T20:35:29Z
       
  • Distribution of platform edge reefs and beach as well as their major
           controlling factors over the Changxing-Feixianguan formations in northeast
           Sichuan Basin, China

    • Abstract: Publication date: Available online 19 June 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Mancang Liu, Wei Yang, Hui Jin, Wulin Mo, Saijun Wu, Nan Su
      The platform facie, platform edge facie, slope, and basin facie were developed in the Chengkou-Western Hubei Trough zones during the Upper Permian Changxing Formation's Early Triassic Feixianguan period; during this time the platform edge had the most favorable sedimentary facie. The Changxing Formation was composed of three sections in which the second section was rich in framework reef, whereas the third one was rich in micro-reefs at the bottom. Recently, it has been discovered that abundant platform edge shoals are developed in the third member and that oolitic shoals with large thickness are widely distributed. This paper systematically investigated the influence of the changes in reef-building organism system on the development of organic reefs. The results show that the distribution of bank belts is determined through paleogeography framework. The rapid change of relative sea level affects the formation and movement of bank belts. In addition, the regional tectonic activity controls the distribution and transformation of the bank belts. Finally, the prospective zone in the Chengkou-Western Hubei area was evaluated and divided into four favorable zones, in which the Wanyuan-Yunyang area was deemed to be most advantageous.

      PubDate: 2017-06-21T10:31:07Z
       
  • Accumulation mechanism of tight sandstone gas in low gas generation
           intensity area

    • Abstract: Publication date: Available online 19 June 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Fudong Zhang, Jian Li, Jun Li, Shen Yang, Yuanqi She, Liyan Shao, Hui Guan, Qiuying Zhu, Jianying Guo
      Before 11th five-year plan, geologists proposed the viewpoint that the gas generation intensity that's more than 20 × 108 m3/km2 was an important condition for forming conventional large gas fields. However, recent exploration findings indicate that large-area tight sandstone gas that has a gas generation intensity of less than 20 × 108 m3/km2 can still form reserves. This is an area worth exploring. Through innovative accumulation simulation, microscopic pore throat analysis of reservoirs, and dissection of typical gas reservoirs, several factors have been established, including the comprehensive evaluation models involving gas charging pressure, reservoir physical properties, and lower gas generation limit. In addition, the paper has made it certain that the tight sandstone gas in a low gas generation intensity area has accumulation characteristics such as “partial water displacing, long-term gas supply, gas control by tight reservoirs of scale, gas abundance control by physical properties, combined control and enrichment of dominant resources, etc.”, and has proposed the viewpoint that this area has the accumulation mechanism that of a “non-dominant transportation, long-term continuous charging, reservoir controlling by physical property difference, and enrichment in partial sweet spots” and shows discontinuous “patchy distribution” on the plane. This is of much significance to fine exploration and development of the trillion cubic meter resources of the low gas generation intensity areas in the west of Sulige gas field.

      PubDate: 2017-06-21T10:31:07Z
       
  • Geochemical characteristics and origin of natural gas reservoired the
           natural gas reservoired in the 4th Member of the Middle Triassic Leikoupo
           Formation in the Western Sichuan Depression, Sichuan Basin, China

    • Abstract: Publication date: Available online 20 May 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Xiaoqi Wu, Yingbin Chen, Guangxiang Liu, Huasheng Zeng, Yanqing Wang, Ye Hu, Wenhui Liu
      The gas exploration in the 4th Member of the Middle Triassic Leikoupo Formation (T2 l 4) in the Western Sichuan Depression has achieved a continuous breakthrough in the recent years. However, the gas origin and source remain controversial. The study on the geochemical characteristics indicates that the T2 l 4 gas in the Western Sichuan Depression is typically dry. Its dryness coefficient is generally higher than 0.99. The δ13C1 and δ13C2 values range from −35.1‰ to −29.3‰ and −34.8‰ to −31.9‰, respectively, with the exception of one gas sample from Well PZ1 with the δ13C2 value of −26.4‰. The δDC1 value ranges from −164‰ to −136‰. The gas souring index is positively correlated with the δ13C2 value in comparison to the δ13C1. The T2 l 4 gas has experienced heavy alkane-dominated TSR instead of the methane-dominated TSR. The T2 l 4 gas in the Western Sichuan Depression generally displays a GSI value lower than 0.01 with the exception of two gas samples from Well PZ1 (0.036, 0.04); they indicate extremely low TSR alteration extent. Gas origin identification points out that the T2 l 4 gas in the Western Sichuan Depression is mainly oil-type gas that has reached the secondary gas cracking stage. The CO2 in the T2 l 4 gas that has high δ13C values are mainly inorganic. They are mainly derived from the interaction between acidic fluids and carbonate reservoirs.

      PubDate: 2017-05-23T23:25:45Z
       
  • Comparison of geochemical characteristics and forming environment of
           volcanic rocks in Northern Xinjiang and the Songliao Basin, China

    • Abstract: Publication date: Available online 9 May 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Yanzhao Wei, Xia Zhao, Shan Lu, Zhongying Zhao
      The tectonic settings of Northern Xinjiang, Songliao Basin, and its peripheral areas all belong to the Paleoasian orogenic region. Their main structures are all composed of multiple continental segments and peripheral fold belts. Similar tectonic setting and complicated basement structure give rise to the similarities and differences in the forming environment and geochemical characteristics of volcanic rocks in the two regions. The similarities include lack of typical calc-alkalic volcanic rocks, inconsistent covariant relationship between oxide content and SiO2 in contents calc-alkalic volcanic rock in the consuming zone, the distribution pattern of trace elements featuring the enrichment of highly incompatible elements, Nb negative anomaly, La positive anomaly, Ba partially positive anomaly, as well as different enrichment degrees of light rare earth. The differences between the Northern Xinjiang and Songliao Basin are characterized by the developed alkalic basalt, rich and highly incompatible elements, and light rare earth. Volcanic rocks in Northern Xinjiang shows an increase in both total rare earth and light rare earth enrichment from south to north, whereas the total rare earth and light rare earth enrichment in Songliao Basin are also higher than the adjacent Daxing'anling. Generally, both the Carboniferous-Lower Permian volcanic rock in Northern Xinjiang and Mesozoic volcanic rock in Songliao Basin and its peripheral areas developed in the post-collision intracontinental extensional tectonic environment, indicating that the post-collision extensional basin in Junggar-Xingmeng Paleoasian Ocean orogenic region has promising oil-gas exploration potential for volcanic reservoirs.

      PubDate: 2017-05-11T22:02:23Z
       
  • Sedimentary characteristics and controlling factors of shelf sand ridges
           in the Pearl River Mouth Basin, northeast of South China Sea

    • Abstract: Publication date: Available online 19 April 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Xiangtao Zhang, Lin Ding, Jiayuan Du, Daoli Liu, Hanqing Liu
      Shelf sand ridge is a significant type of reservoir in the continental marginal basin, and it has drawn so much attention from sedimentologists and petroleum geologists. We were able to investigate the morphology, distribution, and sedimentary structures of shelf sand ridges systematically in this study based on the integration of high-resolution 3D seismic data, well logging, and cores. These shelf sand ridges are an asymmetrical mound-like structure in profiles, and they developed on an ancient uplift in the forced regression system tract and are onlapped by the overlying strata. In the plane, shelf sand ridges present as linear-shaped, which is different from the classical radial pattern; not to mention, they are separated into two parts by low amplitude tidal muddy channels. Corrugated bedding, tidal bedding, and scouring features are distinguished in cores of shelf sand ridges together with the coarsening up in lithology. All of these sedimentary characteristics indicate that shelf sand ridges deposited in the Pearl River Mouth Basin are reconstructed by the tidal and coastal current.

      PubDate: 2017-04-20T20:10:00Z
       
  • Main factors for large accumulations of natural gas in the marine
           carbonate strata of the Eastern Sichuan Basin, China

    • Abstract: Publication date: Available online 13 April 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Quanyou Liu, Zhijun Jin, Bing Zhou, Dongya Zhu, Qingqiang Meng
      The natural gas accumulation zone, where the marine carbonate rock strata are developed, was formed in the eastern Sichuan Basin under the influence of several main tectonic movements (Caledonian Movement, Indosinian Movement, Yanshanian Movement, and Himalayan Movement). Most natural gas reservoirs exhibit the structural-stratigraphic traps together with multistage accumulation, late-stage adjustment and reformation, et cetera. The natural gas accumulation zone (or so-called gas reservoir groups) is controlled by the following main factors: multi-sourced and multi-formed hydrocarbons for marine source rocks (i.e. Lower Silurian Longmaxi Formation, Lower Permian, Upper Permian Longtan Formation), paleo-uplift, paleoslope, and the hinge belt controlled by the steep dip structures, namely the Lower and Middle Triassic high-quality gypsum. Three sets of high-quality source rocks (i.e. S1 l, P1, P2 l) account for the abundant hydrocarbon supply for natural gas accumulation in the eastern Sichuan area, especially in the destructed oil reservoir formed earlier. The said destructed oil reservoir not only provides the preservation space for natural gas reservoir that will take place later, but it also provides the hydrocarbon source for thermal cracking of hydrocarbons and thermochemical sulfate reduction (TSR). Although the gas reservoirs in the eastern part of the Sichuan Basin experienced multi-stage adjustment and reformation at later times, the thick and high-quality gypsum as well as the mudstone, as available caprocks, have offered a good preservation condition for the underlying gas reservoirs. The paleohighs (e.g. Luzhou paleohigh and Kaijiang paleohigh), the Permian platform margin slope, and the structurally transformed slope under the function of the steep dip anticline in the eastern Sichuan not only form the high-quality carbonate reservoir, but they also became favorable for oil and gas accumulation. The difference in hydrocarbon generation history of the source rock and multistage accumulation of hydrocarbons in the eastern part of the Sichuan Basin caused the diversity in the location of the gas reservoirs, where the gas reservoirs with low H2S contents are distributed in the eastern Sichuan Basin (e.g. Jiannan gas field), while the gas reservoirs with high H2S content are located in the northeastern Sichuan Basin (e.g. Puguang gas field).

      PubDate: 2017-04-20T20:10:00Z
       
  • Study on the lower limits of petrophysical parameters of the Upper
           Paleozoic tight sandstone gas reservoirs in the Ordos Basin, China

    • Abstract: Publication date: Available online 23 March 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Huiying Cui, Ningning Zhong, Jian Li, Dongliang Wang, Zhisheng Li, Aisheng Hao, Feng Liang
      There hasn't been a clear understanding of the lower limits of petrophysical parameters of tight sandstone gas reservoirs so far. However, it is an important question directly related to exploration and development strategies. Research methods of the lower limits of petrophysical parameters are reviewed. The new minimum flow pore throat radius method is used to determine the lower limit of flow pore throat radius. The relative permeability curve method, irreducible water saturation method, and testing method, are used to determine the lower limits of porosity, permeability, and gas saturation. After the comprehensive analysis, the lower limits of petrophysical parameters of the Upper Paleozoic tight sandstone gas reservoirs in Ordos Basin are thought as follows: the minimum flow pore throat radius is 0.02 μm, the lower limits of porosity are 3%, the permeability is 0.02 × 10−3 μm2 and the gas saturation is 20%. Besides, the influence of formation pressure on porosity and permeability, the tight sandstone gas filling mechanism, and reservoir characterization petrophysical parameters of tight sandstone reservoirs are further discussed.

      PubDate: 2017-03-28T08:08:32Z
       
  • Genesis and distribution of hydrogen sulfide in deep heavy oil of the
           Halahatang area in the Tarim Basin, China

    • Abstract: Publication date: Available online 23 March 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Guangyou Zhu, Xingwang Liu, Haijun Yang, Jin Su, Yongfeng Zhu, Yu Wang, Chonghao Sun
      As the largest oil-and-gas-bearing basin in China, the Tarim Basin contains rich oil and gas resources buried deep underground. In recent years, large oil fields have been discovered in the Halahatang area of the northern Tarim Basin. The reservoir is buried 6000–7300 m underground. This reservoir is dominated by the Ordovician carbonate rocks, and the crude oil is mainly heavy oil. As a crude oil-associated gas, the natural gas generally contains hydrogen sulfide (H2S). The heavy oil in this region is the deepest buried heavy oil found in the world. H2S is also associated with the deepest buried natural gas. The burial, preservation and degree of biodegradation of a paleo-reservoir can be used to predict the distribution of H2S. According to research findings, there is a clear planar distribution pattern of H2S content: high in the east and north, and low in the west and south. We compared the physical properties of crude oil and the analysis of the composition of natural gas and isotopes, biomarker compounds of crude oil and groundwater. We find that the content of H2S in natural gas bears some relation to the physical properties and degree of biodegradation of crude oil. Crude oil density, sulfur content, colloid, and asphaltene have positive correlations with H2S content in natural gas. The formation of H2S is controlled by the degradation and densification of crude oil. Crude oil densification can lead to an increase of the sulfur content. The rise in the temperature of the reservoir resulting from the depth of burial causes the thermal decomposition of sulfur compounds to produce H2S. The generation of H2S by the thermal decomposition of sulfur compounds is confirmed by data on sulfur isotopes. The distribution of H2S can then be predicted based on the burial conditions of the paleo-reservoir and the degree of biodegradation. In the south Rewapu of the Halahatang area, the thick cap rock of the Ordovician oil reservoir was preserved well in the late Hercynian Period, without undergoing biodegradation. The oil is mainly normal oil and light oil. Sulfur content in the crude oil is quite low, making it impossible to generate a large amount of H2S in the later stages of deep burial.

      PubDate: 2017-03-28T08:08:32Z
       
  • Characterization of shale gas enrichment in the Wufeng
           Formation–Longmaxi Formation in the Sichuan Basin of China and
           evaluation of its geological construction–transformation evolution
           sequence

    • Abstract: Publication date: Available online 22 March 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Zhiliang He, Zongquan Hu, Haikuan Nie, Shuangjian Li, Jin Xu
      Shale gas in Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation in the Sichuan Basin is one of the key strata being explored and developed in China, where shale gas reservoirs have been found in Fuling, Weiyuan, Changning and Zhaotong. Characteristics of shale gas enrichment in the formation shown by detailed profiling and analysis are summarized as “high, handsome and rich”. “High” mainly refers to the high quality of original materials for the formation of shale with excellent key parameters, including the good type and high abundance of organic matters, high content of brittle minerals and moderate thermal evolution. “Handsome” means late and weak deformation, favorable deformation mode and structure, and appropriate uplift and current burial depth. “Rich” includes high gas content, high formation pressure coefficient, good reservoir property, favorable reservoir scale transformation and high initial and final output, with relative ease of development and obvious economic benefit. For shale gas enrichment and high yield, it is important that the combination of shale was deposited and formed in excellent conditions (geological construction), and then underwent appropriate tectonic deformation, uplift, and erosion (geological transformation). Evaluation based on geological construction (evolution sequence from formation to the reservoir) includes sequence stratigraphy and sediment, hydrocarbon generation and formation of reservoir pores. Based on geological transformation (evolution sequence from the reservoir to preservation), the strata should be evaluated for structural deformation, the formation of reservoir fracture and preservation of shale gas. The evaluation of the “construction - transformation” sequence is to cover the whole process of shale gas formation and preservation. This way, both positive and negative effects of the formation-transformation sequence on shale gas are assessed. The evaluation models based on this strategy would be more accurate, reliable and would avoid bias derived from indiscriminate and simplistic use of all parameters in the models.

      PubDate: 2017-03-28T08:08:32Z
       
  • Reservoir characteristics and control factors of Carboniferous volcanic
           gas reservoirs in the Dixi area of Junggar Basin, China

    • Abstract: Publication date: Available online 17 March 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Ji'an Shi, Guoqiang Sun, Shuncun Zhang, Hui Guo, Shengyin Zhang, Shekuan Du
      Field outcrop observation, drilling core description, thin-section analysis, SEM analysis, and geochemistry, indicate that Dixi area of Carboniferous volcanic rock gas reservoir belongs to the volcanic rock oil reservoir of the authigenic gas reservoir. The source rocks make contact with volcanic rock reservoir directly or by fault, and having the characteristics of near source accumulation. The volcanic rock reservoir rocks mainly consist of acidic rhyolite and dacite, intermediate andesite, basic basalt and volcanic breccia: (1) Acidic rhyolite and dacite reservoirs are developed in the middle-lower part of the structure, have suffered strong denudation effect, and the secondary pores have formed in the weathering and tectonic burial stages, but primary pores are not developed within the early diagenesis stage. Average porosity is only at 8%, and the maximum porosity is at 13.5%, with oil and gas accumulation showing poor performance. (2) Intermediate andesite and basic basalt reservoirs are mainly distributed near the crater, which resembles the size of and suggests a volcanic eruption. Primary pores are formed in the early diagenetic stage, secondary pores developed in weathering and erosion transformation stage, and secondary fractures formed in the tectonic burial stage. The average porosity is at 9.2%, and the maximum porosity is at 21.9%: it is of the high-quality reservoir types in Dixi area. (3) The volcanic breccia reservoir has the same diagenetic features with sedimentary rocks, but also has the same mineral composition with volcanic rock; rigid components can keep the primary porosity without being affected by compaction during the burial process. At the same time, the brittleness of volcanic breccia reservoir makes it easily fracture under the stress; internal fracture was developmental. Volcanic breccia developed in the structural high part and suffered a long-term leaching effect. The original pore-fracture combination also made volcanic breccia reservoir more easily leached by fresh water or groundwater, leading to secondary erosion pores. Volcanic rock weathering obviously has control on reservoir properties, and while the thickness of the weathering crust is 200–300 m, the properties of volcanic rock reservoir are the best. This is attributed mainly to the period during and after the volcano eruption, in which tectonism made the brittle volcanic rock develop a large number of fractures and micro cracks. This has led to the increased permeability of volcanic rock reservoir, the weathering and leaching effect of volcanic rock diagenetic late phase (which also formed lots of secondary pores), and greatly improved reservoir conditions. The overlying Permian Wutonggou formation mudstone provided high-quality cap rock for oil and gas accumulation.

      PubDate: 2017-03-19T23:38:58Z
       
  • Types and characteristics of carbonate reservoirs and their implication on
           hydrocarbon exploration: A case study from the eastern Tarim Basin, NW
           China

    • Abstract: Publication date: Available online 27 February 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Shiwei Huang, You Zhang, Xingping Zheng, Qifa Zhu, Guanming Shao, Yanqing Cao, Xiguang Chen, Zhao Yang, Xiaojia Bai
      Carbonate rocks are deposited in the Ordovician, Cambrian, and Sinian of eastern Tarim Basin with a cumulative maximum thickness exceeding 2000 m. They are the main carriers of oil and gas, and a great deal of natural gas has been found there in the past five years. Based on lithofacies and reservoir differences, natural gas exploration domains of eastern Tarim Basin can be classified into five types: Ordovician platform limestone; Ordovician platform dolomite; Cambrian platform margin mound shoal; Cambrian slope gravity flow deposits, and; Sinian dolomite. Carbonate reservoir characteristics of all the types were synthetically analyzed through observation on drilling core and thin sections, porosity and permeability measurement, and logging data of over 10 drilling wells. We find distribution of part of good fracture and cave reservoir in carbonate platform limestone of Ordovician. In the Ordovician, platform facies dolomite is better than limestone, and in the Cambrian, platform margin mound shoal dolomite has large stacking thickness. Good quality and significantly thick carbonate gravity deposit flow can be found in the Cambrian slope, and effective reservoir has also been found in Sinian dolomite. Commercial gas has been found in the limestone and dolomite of Ordovician in Shunnan and Gucheng areas. Exploration experiences from these two areas are instructive, enabling a deeper understanding of this scene.

      PubDate: 2017-03-06T07:49:23Z
       
  • Architecture and quantitative assessment of channeled clastic deposits,
           Shihezi sandstone (Lower Permian), Ordos Basin, China

    • Abstract: Publication date: Available online 2 February 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Chengye Jia, Ailin Jia, Xin Zhao, Jianlin Guo, Haifa Tang
      Lower Permian Shihezi sandstone in Ordos Basin is the largest gas reservoir in China. Architecture elements of channel, overbank and floodplain facies of braided channel deposits were identified through an outcrops survey, and their proportion of channel facies have been quantitatively estimated from well logging. Characteristics of architecture elements, such as sand thickness, bounding surfaces and lithofacies were investigated through outcrops and core. Petrology of Shihezi sandstone has also been studied in detail. Analysis on sandstone components shows that monocrystalline quartz with approximately 76% bulk volume, and lithic up to 5%–45% bulk volume, are the two main components. Litharenite and lithic quartz sandstone are the main rock types. Compaction is concluded by former researchers as the control factor of low permeability. Examination through thin section reveals that secondary pores developed well in coarse sand. Inter-granular dissolution is included as the positive effect to increasing porosity, and is concluded as the control factor to the generation of net pay. Scale of coarse grained channel fills and channel bar sandstone bodies are quantitatively estimated. Strike-oriented, dip-oriented, and vertical distribution of channel fills and channel bar sandstone bodies have been investigated. The geometry of sand bodies can be depicted as an elongated lens. Subsurface mapping reveals that channel sandstone bodies distribute widely from both lateral and longitudinal cross section profiles, and are poorly connected.

      PubDate: 2017-02-05T01:34:58Z
       
  • Seepage system of oil-gas and its exploration in Yinggehai Basin located
           at northwest of South China Sea

    • Abstract: Publication date: Available online 2 February 2017
      Source:Journal of Natural Gas Geoscience
      Author(s): Jiaxiong He, Wei Zhang, Zhengquan Lu
      Seepage systems of oil-gas in Yinggehai Basin are divided into two types, namely: “micro-seepage”, which is presented by gas chimneys and pockmarks; and “macro-seepage”, which is also called oil-gas outflow; and, in addition, the combination of the two basic types. Among the oil seepage systems, the combined seepage system at Yingdong Slope of Yinggehai Basin is the most eye-catching, and gas chimneys and pockmarks micro-leakage systems in mud diapir zones in the central part of the basin are very common. Both the indications of large-scale oil-gas outflow at Yingdong Slope, which have been booming for a hundred years; and the occurrence of pockmarks at the central mud diapir belt, along with the chaotic seismic reflection of widely-distributed shallow gas chimneys—have shown that hydrocarbon in this area is sufficient and oil-gas is now in dynamic equilibrium of the processes of accumulation, migration, gathering and dispersing. It builds up good conditions for the accumulation, migration, gathering and reserving of oil and gas. However, it must be noted that the results of oil-gas exploration at Yingdong Slope didn't turn out to be satisfactory, despite the presence of oil-gas outflow and gas chimney combined seepage systems. So, strengthen synthesized analysis and study on oil-gas seepage systems and on the conditions for accumulation, migration, gathering and dispersing; the forecasting and evaluation to the advantageous conditions for enriched oil and gas zones; and trap preservation in accordance with the dynamic balance theories; are of significant importance for purposes of exploration.

      PubDate: 2017-02-05T01:34:58Z
       
 
 
JournalTOCs
School of Mathematical and Computer Sciences
Heriot-Watt University
Edinburgh, EH14 4AS, UK
Email: journaltocs@hw.ac.uk
Tel: +00 44 (0)131 4513762
Fax: +00 44 (0)131 4513327
 
Home (Search)
Subjects A-Z
Publishers A-Z
Customise
APIs
Your IP address: 54.81.68.240
 
About JournalTOCs
API
Help
News (blog, publications)
JournalTOCs on Twitter   JournalTOCs on Facebook

JournalTOCs © 2009-