10 June 2019, Volume 30 Issue 6
    

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  • Good prospect of coal-derived gas in Yingjisu Sag,Tarim Basin
    Dai Jin-xing, Hong Feng, Ni Yun-yan, Liao Feng-rong
    Natural Gas Geoscience. 2019, 30(6): 771-782. https://doi.org/10.11764/j.issn.1672-1926.2019.05.017
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    Coal-derived gas determined by stable carbon isotopes were found in Well HYC 1 in the Yingjisu Sag,which brings new dawn for gas exploration in this sag.Thermal maturity of the source rocks is 0.50%-0.65%.According to the traditional views that industrial oil/gas accumulations can only be formed with thermal maturity of the source rocks over 0.70%,so the recoverable resources of coal-derived gas were only 245×108m3,and there was no drilling in the last 15 years.The TOC values of the Jurassic coal-measure mudstone,carbonaceous mudstone and coal in the Yingjisu Sag are similar to those in the Kuqa Depression,and both of them belong to medium-quality source rocks,so the potential of gas generation and accumulation is good.In the Yingjisu Sag,the Jurassic residual thickness is 1 000-2 000m.The distribution area with maximum thickness of coal is basically overlapped with the distribution areas with maximum thickness of carbonaceous mudstone and dark mudstone.The continuous distribution area is about 8 000km2,which should be the richest area and the most favorable exploration area for coal-derived gas resource,and gas fields will be discovered in the future.
  • Genetic types and exploration potential of natural gas in Bohai Bay Basin
    Zhao Chang-yi, Li Yong-xin, Wang Ju-feng, Liu Hai-tao, Deng Yan, Zhao Bo-ya
    Natural Gas Geoscience. 2019, 30(6): 783-789. https://doi.org/10.11764/j.issn.1672-1926.2019.05.016
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    The Bohai Bay Basin is one of the oil-bearing basins characterized by rich oil.After more than 50 years of exploration,a series of gas fields or oil and gas fields of different scales have been discovered.Among them,natural gas has been found to be mostly small and medium-sized gas fields,and gas reservoirs are used for condensate analysis.Through the analysis of the geochemical characteristics of gas fields in the northern China,Bodong,Dagang and Liaohe areas in the northern Bohai Bay Basin,it is found that the natural gas genesis types in the Bohai Bay Basin are rich,including bacterial gas,oil-type gas and coal-derived gas.The humic parent material and the mature-high mature thermal evolution stage have obvious advantages.Natural gas resources are mostly distributed in the vicinity of the source center of the source rock,and the deep layers of the hydrocarbon-generating depression and its adjacent convex parts,such as the Qibei sub-concave and the Banqiao sub-cave Paleogene,the Liaohe area western depression,the Paleogene,and the Qikou-Qianwu-Ordovician buried hills in the Upper Paleozoic buried hill and the Nanpu Sag are all the favorable exploration areas for natural gas.
  • Sources of coal-derived gas in marine strata in central Sichuan
    Qin Sheng-fei, Bai Bin, Yuan Miao, Zhou Guo-xiao, Yang Jin-dong
    Natural Gas Geoscience. 2019, 30(6): 790-797. https://doi.org/10.11764/j.issn.1672-1926.2019.05.012
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    There are gas reservoirs in the Triassic Leikoupo Formation,Jialingjiang Formation,Feixianguan Formation and Permian Changxing Formation in the marine strata of the central Sichuan Basin.Over the years,the gas sources in these gas reservoirs,especially the gas source of the Leikoupo Formation are still unclear.In this paper,the natural gas geochemistry,combined with geological background,are used to compare the composition and isotopes of natural gas in the Permian and Triassic gas reservoirs in the central Sichuan Basin.It is believed that many samples of the 4th member of Leikoupo Formation are coal-derived gas,and the natural gas comes from the overburden Xujiahe Formation source rock,and there is also some other natural gas from the Lower Leikoupo Formation source rock.The gas of the 1st member of Leikoupo and Jialingjiang Formation is homologous to the natural gas of Changxing and Feixianguan formations.In Longgang Gas Field,the natural gas of the Changxing and Feixianguan formations mainly comes from the coal-bearing source rocks of the Longtan Formation.In the Moxi Gas Field,the Longtan Formation may be transformed into the Wujiaping Formation in some areas,which is mainly composed of sapropelic organic matter,and the natural gas produced is oil-type gas.Gases from the corresponding overlying reservoirs of Changxing,Feixianguan and Jialingjiang formations,and also the 1st  member of Leikoupo Formation are coal-derived gas.


  • Main controlling factors of near-source and interbedded-accumulation tight sandstone gas from coal-bearing strata:A case study from natural gas of Xujiahe Formation,central Sichuan Basin
    Li Yong, Chen Shi-jia, Lu Jun-gang, Xiao Zheng-lu, He Qing-bo, Su Kai-ming, Li Jun-liang
    Natural Gas Geoscience. 2019, 30(6): 798-808. https://doi.org/10.11764/j.issn.1672-1926.2019.02.001
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    Xujiahe Formation in central Sichuan Basin is characterized by large-area gas-bearing,low-degree charging,local-enrichment high-yield and complicated water-gas distribution.To verify the characteristics and the main controlling factors of natural-gas accumulation in Xujiahe Formation,comprehensive analyses have been carried out including the component and carbon isotope of natural gas,the light hydrocarbon of source rock adsorbed gas,the distribution of source rock,the physical property of reservoirs,the structural amplitude and the abnormal pressure.The results showed that natural gas in Xujiahe Formation was coal-derived gas featured with near-source and interbedded-accumulation.The source rocks owned large thickness in total but thin layer in single,and they were interbedded with sandstone which had low gas intensity and weak gas charging ability.Abnormal pressure provided charging dynamics for natural gas migration.Natural gas preferred to migrate into good-property sandbodies when gas-source was insufficient and the physical property took control of the charging degree of gas reservoirs.Local low-amplitude structure controlled the distribution pattern of gas reservoirs under slow structural background,and the higher the structure was,the more full the gas-water differentiation would be,and the easier the pure gas reservoir would develop.Overall,sandbodies inside source in Xujiahe Formation had a wonderful exploration prospect,and the northwestern,3rd member in the southwestern and 5th  member in the central of Sichuan Basin were the favorable exploration target of gas reservoirs inside source.
  • Differences of continental hydrocarbon system between Longgang and Yuanba Gasfields in Sichuan Basin
    Zhou Guo-xiao, Wei Guo-qi, Hu Guo-yi
    Natural Gas Geoscience. 2019, 30(6): 809-818. https://doi.org/10.11764/j.issn.1672-1926.2019.05.010
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    The Longgang and Yuanba Gasfields are adjacent to each other in Sichuan Basin.However,their terrestrial gas sources are different.According to the characteristics of stable carbon and hydrogen isotope compositions of alkane gases derived from the natural gases,the Middle and Upper Triassic can be divided into two hydrocarbon systems,including T2l—T3x1-2 and T3x3-6.The former has the characteristics of mixed origin of coal-type gas and oil-type gas,and the latter belongs to coal-type gas.In the lower part of Xujiahe Formation,the origin of oil-type gas is not from underlying marine strata,but from sapropelic organic matter of Xiaotangzi Formation.On the contrary,pressurization of hydrocarbon generation combined with unconformity as well as karst reservoir development,Xiaotangzi Formation can be poured back into weathering crust of Leikoupo Formation as gas source to form upper generation and lower storage reservoirs.Otherwiese,the Middle and Lower Jurassic can also be divided into two hydrocarbon systems,the Middle Jurassic is self-generating gas reservoirs in the both areas of Longgang and Yuanba;In Yuanba area,secondary coal-formed gas reservoir of the Lower Jurassic is derived from the underlying strata of T3x3-6,while the gas reservoir of the Lower Jurassic belongs to self-generating and oil-type gas reservoir in Longgang area.In addition,the value of iC4 versusnC4  equal to 1 can be used as an index to judge the type of natural gas.As well as with the increase of dryness coefficient,the value of  iC4 versus nC4  tends to decrease slowly at mature stage and then rapidly reduce at high and over-mature stage.The hydrogen isotope of methane from the Xujiahe Formation is significantly different from that from the underlying marine facies and overlying inland freshwater lake facies,which can provide a reference for the hydrogen isotope of methane formed by sedimentary organic matter developed in brackish water.
  • Source of the Upper Paleozoic natural gas in Dingbei area in the Ordos Basin
    Wu Xiao-qi, Ni Chun-hua, Chen Ying-bin, Zhu Jian-hui, Li Kuang, Zeng Hua-sheng
    Natural Gas Geoscience. 2019, 30(6): 819-827. https://doi.org/10.11764/j.issn.1672-1926.2019.03.015
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    The Dingbei area is an important exploratory area in the Ordos Basin for SINOPEC,and natural gas exploration in the Upper Paleozoic strata in the area achieved great breakthrough in recent years.However,the origin and source of natural gas are weakly studied,and there is no consensus on whether the Upper Paleozoic gas in the basin has experienced large-scale lateral migration.Studies on the geochemical characteristics of natural gas indicate that,the Upper Paleozoic natural gas in the Dingbei area is typically dry gas with the dryness coefficient (C1/C1-5) of 0.977~0.986,and the δ13C1,δ13C2,and δD1 values are in the ranges of -30.6‰~-28.6‰,-25.9‰~-24.1‰,and -191‰~-177‰,respectively,with positive carbon and hydrogen isotopic sequence between CH4 and C2H6.Carbon and hydrogen isotope compositions of alkane gas suggest that the Upper Paleozoic gas in the Dingbei area is typically coal-derived gas.The calculated RO values according to the two-stage fractionation mode of coal-derived gas is consistent with the measured RO values of the Upper Paleozoic source rocks,which indicate that the Upper Paleozoic gas in the Dingbei area was mainly derived from in-situ source rocks in the Taiyuan and Shanxi formations.Compared with the Dingbei area,natural gas from the Daniudi gas field in the northeastern Ordos Basin displays lower δ13C1,C1/C1-5 and C1/C2+3 values and higher C2/C1 ratio,suggesting the lower maturity of source rocks rather than migration effect.The Upper Paleozoic natural gas in the Ordos Basin has not experienced large-scale lateral migration.


  • The rule of natural gas accumulation of the mid-assemblage of Ordovician Majiagou Formation in the central Ordos Basin
    Wu Wei-tao, Wang Yi, Zhao Jing-zhou, Yang Te-bo, Li Jun, Huang Zheng-liang
    Natural Gas Geoscience. 2019, 30(6): 828-839. https://doi.org/10.11764/j.issn.1672-1926.2019.04.003
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    The mid-assemblage (5th-10th sub-members of the 5th Member of Majiagou Formation) of the Ordovician Majiagou Formation in the Ordos basin is significant layers for gas exploration and research.Based on the drilling,logging,seismic data and gas testing experiment,the paper analyzes gas accumulation of Ordovician mid-assemblage and its genesis and origin,and further studies the natural gas accumulation rules of Ordovician mid-assemblage from conditions of source,reservoir,trap and structure.The research demonstrates that the gas dryness coefficient of the mid-assemblage of Ordovician Majiagou Formation is greater than 0.985 and belongs to dry gas.The patterns contain lithological accumulation and strati-graphical accumulation,the former has extensive distribution and the latter is only developed near the denudation surface;gas mainly originated from the Upper Paleozoic coalbed source rock.The total organic carbon content of the Lower Paleozoic carbonate rock is between 0.1%-0.2% which can play partial role in gas generation;the formation and distribution is simultaneously controlled by conditions of source,reservoir,seal,trap and structure.Natural gas is enriched near the denudation surface,migration channel controls enriched layers and extent of enrichment,seals and traps of trap patterns control the formation and distribution of gas accumulation,and structure evolution controls the characteristics of gas migration and accumulation.
  • Re-examination of genetic types and origins of natural gases from Dibei Uplift，eastern  Luliang Uplift，Junggar Basin
    Wei Yan-Zhao, Song Zhi-Hua, Qi Rui, Wang Wei, Gong De-Yu, Wang Feng
    Natural Gas Geoscience. 2019, 30(6): 840-849. https://doi.org/10.11764/j.issn.1672-1926.2019.03.012
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    The eastern part of Luliang Uplift has currently become the main target for gas exploration in the Junggar Basin.By now，several giant-medium gas fields (reservoirs)are discovered in the Dinan Uplift.Located north to the Dinan Uplift，the Dibei Uplift is surrounded by several hydrocarbon generating sags and developed several sets of source rocks，which promises a favorable gas accumulation condition.Based on molecular and stable carbon isotopic compositions of 9 gas samples from Dibei Uplift，in cooperation with the burial and hydrocarbon generation history of source rocks，genetic types and origins of natural gases and related secondary alterations were fully discussed in this study.A comparative study was also carried out with the geochemical characteristics of natural gases from Dinan Uplift.Gases from Dibei Uplift have complicated origins which could primarily be divided into three types:(1)Highly-mature coal-derived gas generated from the Upper Carboniferous Bashan coal measures;(2)Highly-mature oil-type gas generated from the marine source rocks in the Lower Carboniferous Jiangbasitao Formation or Songkaersu Formation);(3)Secondary microbial methane generated via the biodegradation of oils.Significant differences have been observed between gases from Dibei and Dinan Uplifts in the concentration of non-hydrocarbon gases，carbon isotopes and thermal maturities.Gases from the Dibei Uplift are at highly mature stage，which correlates well with the maturities of Carboniferous source rocks in the Wulungu Depression.Thus，these gases are most probably derived from the Wulungu Depression.
  • Genetic types,origins and accumulation process of natural gases from Dajing area,Junggar Basin
    Hu Zi-long, Bian Bao-li, Liu Hai-lei, Zhao Long, Lu Shan, Wang Shao-qing
    Natural Gas Geoscience. 2019, 30(6): 850-859. https://doi.org/10.11764/j.issn.1672-1926.2019.04.011
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    The Junggar Basin is characterized by more oil and less gas in exploration practice.No major breakthrough in natural gas exploration has been made since the discovery of the Kelameili Gas Field in 2008.In order to jump out from Kelameili Gas Field and look for a new area for natural gas exploration,this study systematically analyzed the components,carbon isotope and light hydrocarbons of natural gases from Dajing area in the eastern Junggar Basin.A comparative study was also performed with the adjacent areas.On this basis,combined with the simulation of source rocks burial history,and its generation and expulsion history,the natural gas accumulation process is determined.Results show that:(1)The natural gas from the Dajing area is coal-derived gas generated from the Upper Carboniferous Shiqiantan Formation at early gas generation stage.(2)Due to the heterogeneity of organic matters,the calculation error of the equivalent vitrinite reflectance of natural gas in the study area is approximately 0.41%,and its actual maturity should be around 1.05%,which is consistent with its dryness coefficient.(3)The Shiqiantan Formation source rocks in the study area generated low-mature coal-derived gas in the Middle and Late Jurassic,and the gas accumulated in the volcanic reservoirs with good reservoir conditions at the top of the Batamayineishan Formation,forming an self-generation and self-storage volcanic-lithologic gas reservoir.
  • Distribution characteristics of giant gas fields in the world and its enlightenment
    Liao Feng-rong, Hong Feng
    Natural Gas Geoscience. 2019, 30(6): 860-865. https://doi.org/10.11764/j.issn.1672-1926.2019.05.013
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    By the end of 2018,28 giant gas fields (recoverable reserves more than 1 trillion cubic meters) have been found in the world,distributed in 12 basins of 12 countries,and the distribution of giant gas fields is extremely uneven.Among them,there are 21 pure gas fields,4 gas cap fields,3 condensate gas fields.All the natural gas fileds are conventional gas fields except that the Medvezhye gas field is a tight gas field.The reservoir and source rock distribution of the giant gas fields are mostly located in the Paleozoic and Mesozoic.In terms of quantity and reserves of giant gas fields,the Silurian and the Cretaceous are the main source rocks and the Cretaceous and the Permian are the main reservoirs of the global giant gas fields.The lithology of the reservoir are dominated by sandstone and limestone,and the lithology of the source rock is dominated by shale.The exploration for giant and large gas fields in China should strengthen the comprehensive research of the whole basin in the large area,and the exploration of coal-formed gas and deep gas.
  • Geochemical characteristics and exploration potential of Jurassic coal-formed gas in northwest China
    Li Jian, Hao Ai-sheng, Qi Xue-ning, Chen Xuan, Guo Jian-ying, Ran Qi-gui, Li Zhi-sheng, Xie Zeng-ye, Zeng Xu, Li Jin, Wang Yu, Liu Ru-hong,
    Natural Gas Geoscience. 2019, 30(6): 866-879. https://doi.org/10.11764/j.issn.1672-1926.2019.05.018
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    Jurassic coal-measure strata are widely developed in northwest China,mainly distributed in the Tarim Basin,Junggar Basin,Qaidam Basin and Turpan-Hami Basin.The Jurassic coal-formed gas resources are abundant in northwest China.Although the tectonic and sedimentary environments of Northwest China were similar,the characteristics of Jurassic coal-formed gas in northwest China vary greatly.Therefore,the analysis and summary of the geochemical characteristics of coal-formed gas in Jurassic petroleum systems in different basins is of great significance for searching for  searching for different types of coal-formed gases.The drying coefficient of Jurassic coal-formed gas in western China showed three types:“unimodal type of wet gas”,“unimodal type of dry gas” and “bimodal type of dry gas and wet gas”.Carbon isotope values of Jurassic coal-formed methane in northwest China have wide range indicating source rock with maturity of low to over mature stages.The carbon isotope of coal-formed gas in northwest China is generally a positive carbon isotope series,partly with δ13C2-δ13C3 inversion.δ13C2-δ13C3 inversion was mainly caused by mixture of gases generated from different maturity or organic matter and bacterial effects.Maturity is the main reason for the great difference of Jurassic coal-formed gas in northwest China,and mixture of gases is also another important factor.The exploration degree of structural gas reservoirs is relatively high.Structural-lithological and lithological gas reservoirs and deep strata are important exploration reservoir types in the Lower Jurassic System in northwest China.Jurassic in Kuqa Depression,Cretaceous to Jurassic in Junggar Basin,mature to high mature Jurassic coal-formed gas in Tuha Basin and high to over mature Jurassic coal-formed gas in Qaidam Basin are potential exploration fields in northwest China.
  • Stable hydrogen isotopic characteristics of natural gas from the Xujiahe Formation in the central Sichuan Basin and its implications for water salinization 
    Ni Yun-yan, Liao Feng-rong, Yao Li-miao, Gao Jin-liang, Zhang Di-jia
    Natural Gas Geoscience. 2019, 30(6): 880-896. https://doi.org/10.11764/j.issn.1672-1926.2019.05.015
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    Based on the analysis of the components and carbon and hydrogen isotopes of gases from the Triassic Xujiahe and other formations in the Sichuan Basin,the gas origin,gas source and significance of hydrogen isotopes are studied by combining previous research results and regional geological background. The results show that gas from the Triassic Xujiahe Formation in the Sichuan Basin is mainly hydrocarbon gas. The content of methane is 67.89%-98.05%,and the content of heavy hydrocarbon (C2+) is 0.42%-16.62%. The content of non-hydrocarbon gas (CO2,N2) is low. Except the relatively high content of N2 and CO2 in the Well Yue121,the average content of N2 is 0.82% and the average value of CO2 is 0.26%. Gas from the Xujiahe Formation in Yuanba has average dryness coefficient as high as 0.991,which indicates the gas belongs to dry gas. While,gases from the Xujiahe Formation in other areas in the Central Sichuan Basin have dryness coefficient less than 0.95,indicative of wet gas. The δ13C1 value varies from -43.8‰ to -29.2‰,δ13C2 value ranges from -33.5‰ to -20.7‰,δ13C3 value is from -33.6‰ to -19.3‰ and δ13C4 value is from -27.2‰ to -22.2‰. The δD1 value is from -191‰ to -148‰,δD 2value is from -165‰ to -115‰ and δD3 value is from -153‰ to -107‰. Methane and its homologues (C2-4) become more enriched in 13C and D with increasing carbon number (δ13C1<δ13C2<δ13C3<δ13C4,δD1<δD2<δD3),which are consistent with the carbon and hydrogen isotopic characteristics of thermogenic gases. The thermal maturity RO of natural gas from Xujiahe Formation in Yuanba is 1.09%-1.78%,and the RO of the natural gas from Xujiahe Formation in other areas of Central Sichuan Basin is 0.64%-0.92%. Natural gas from the Xujiahe Formation in the central Sichuan Basin is mainly from the coal measure source rocks of the Xujiahe Formation. Natural gas from the 2nd member of Xujiahe Formation in Yuanba is mixed gas,a mixture of the high-mature coal-derived gas from the coal measure source rock of Xujiahe Formation and the Lower Cambrian (Lower Silurian) oil-cracked gas. The δD of methane from the Xujiahe Formation in the Sichuan Basin is relatively high,higher than -200‰. Compared to the coal-derived gas from the source rocks formed in limnetic facies with freshwater in the Taibei Sag,Turpan-Hami Basin,though at similar thermal maturity,the difference of the δD of methane can be as high as 90‰,indicating that the source rock of Xujiahe Formation is formed in an environment with water salinization.
  • Geochemical characteristics of deep-seated natural gas accumulation of the Keshen large gas field in the Kuqa Depression,Tarim Basin
    Wei Qiang, Li Xian-qing, Sun Ke-xin, Li Jin, Xiao Zhong-yao, Liang Wan-le, Zhang Ya-chao,
    Natural Gas Geoscience. 2019, 30(6): 897-907. https://doi.org/10.11764/j.issn.1672-1926.2019.04.008
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    The geochemical characteristics and genesis of deep-seated natural gas,type features and homogenization temperature of fluid inclusions,charge time of hydrocarbon and accumulation process of the Keshen large gas field in the Kuqa Depression,Tarim Basin were studied,by using the data of the quantification of gas components,carbon isotope compositions,micro temperature measurement of fluid inclusion,and hydrocarbon generation kinetics.The results show that deep-seated natural gas in the Keshen large gas field is dominated by alkanes,of which methane accounts for 87.30%-98.33%,the C2+ content is 0%-0.66%,and the dryness coefficient is 0.99%-1.0%.The δ13C1 and δ13C2 values are from -29.3‰ to -26.4‰ and from -21.4‰ to -16.1‰,respectively,indicative of the over mature coal-derived gas.There are two episodes of hydrocarbon inclusions in the Cretaceous Bashijiqike Formation reservoirs in the Keshen large gas field.The first phase inclusion is liquid inclusion with blue-white fluorescence color,which means that the early light oil was charged.The second phase inclusion is gas inclusion with non-fluorescence color.The homogenization temperature of aqueous inclusion symbiosis with gas inclusion is 145-160℃,which indicates that the late gas was charged.The Keshen large gas field has experienced large-scale natural gas charging history since the Late Kuche Formation sedimentary period (about 2.5Ma).Natural gas in the Keshen large gas field is mainly originated from Jurassic coal-bearing source rocks in the Keshen well area and center of Baicheng Sag,which is the late accumulation under the actions of rapid hydrocarbon-generation in the deep-buried strata and strong pressure difference gradient of resource-reservoir.
  • The distribution of gas and water and development strategy for deep-buried gasfield in Kuqa Depression,Tarim Basin
    Jia Ai-lin, Tang Hai-fa, Han Yong-xin, Lv Zhi-kai, Liu Qun-ming, Zhang Yong-zhong, Sun He-dong, Huang Wei-gang, Wang Ze-long
    Natural Gas Geoscience. 2019, 30(6): 908-918. https://doi.org/10.11764/j.issn.1672-1926.2019.05.014
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    Deep and ultra-deep buried reservoirs in Kuqa Depression are the most prospecting targets for natural gas exploration and development in Tarim Basin.These gas reservoirs are characterized by huge reserves,deep-buried formation (more than 3 500m),high temperature and abnormal high pressure,well-developed natural fracture,and complex gas-water distribution.The development practice shows that water invasion is occurred frequently in some development blocks,and thus result in the sharp decline of gas well production and low gas field productivity.In solving this problem,this paper presents a systematic static and dynamic evaluation technology for deep-buried gas reservoir with active edge water or bottom water.The methodology integrates description of static gas-water distribution,micro-water invasion mechanism and dynamic evaluation of water invasion.Based on above research,the character of gas-water distribution,the law of water invasion and the technical countermeasures of water control and development is established systematically.The results show that the distribution of gas and water in deep-buried reservoirs in Kuqa Depression is controlled by matrix property and the development degree of fracture net together.The gas-water distribution pattern can be divided into two types:Thin gas-water transition zone type (good matrix physical property type and especially developed fracture type) and thick gas-water transition zone type.The difference of gas-water distribution and fracture development directly results in the difference of water invasion location and dynamic characteristics of gas field,which is manifested in three types of water invasion:Integral uplift of edge-bottom water,coning of edge-bottom water along micro-fracture zone and longitudinal channeling of edge-bottom water along large fractures.Based on the above analysis,the technical countermeasures for water control,such as well spacing at high structural position to avoid water,optimizing gas production rate to stabilize water and drainage of old wells at the edge,are put forward systematically,which provide technical supports for efficient development and adjustment of deep-buried gas field in Kuqa Depression,Tarim Basin,and also provide reference for the development of similar gas fields in China.
  • Optimal deployment of multi-stage fractured horizontal wells in tight sandstone gas reservoirs
    Wei Yun-sheng, Jia Ai-lin, Guo Zhi, Meng De-wei, Wang Guo-ting
    Natural Gas Geoscience. 2019, 30(6): 919-924. https://doi.org/10.11764/j.issn.1672-1926.2019.05.009
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    For domestic tight sandstone gas reservoirs,the distribution of gas-bearing sand bodies which is difficult to predict accurately is scattered and the heterogeneity of reservoirs is strong.For the development mode of horizontal wells,there is a large distance between target B of two opposite horizontal wells,which will reduce the degree of area control and utilization of reserves.Starting from the investigation of foreign tight gas development practice,based on the analysis of effective sand body spatial distribution,scale and development dynamic characteristics of Sulige tight sandstone gas reservoir,combined with numerical simulation method,the paper demonstrates the development effect of horizontal wells under different deployment modes,and puts forward the optimal deployment scheme of horizontal wells.The results show that the target B of two horizontal wells in opposite direction is close to coincidence and the fracturing section is deployed equidistantly,which can greatly improve the level of reserves control and utilization of horizontal wells,and effectively improve the overall economic benefits of gas field development.The research and understanding have operability and application prospects in the actual development of dense gas.
  • Natural Gas geoscience 2019-6 covers and titles
    《天然气地球科学》-期封面及目次
    Natural Gas Geoscience. 2019, 30(6): 9061-9062.
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    《天然气地球科学》2019-6期封面及目次
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