Advanced Search

Indexed by SCI、CA、РЖ、PA、CSA、ZR、etc .

Volume 31 Issue 2
Apr.  2020
Turn off MathJax
Article Contents

Zhongrui Wu, Sheng He, Yuanjia Han, Gangyi Zhai, Xipeng He, Zhi Zhou. Effect of Organic Matter Type and Maturity on Organic Matter Pore Formation of Transitional Facies Shales: A Case Study on Upper Permian Longtan and Dalong Shales in Middle Yangtze Region, China. Journal of Earth Science, 2020, 31(2): 368-384. doi: 10.1007/s12583-019-1237-6
Citation: Zhongrui Wu, Sheng He, Yuanjia Han, Gangyi Zhai, Xipeng He, Zhi Zhou. Effect of Organic Matter Type and Maturity on Organic Matter Pore Formation of Transitional Facies Shales: A Case Study on Upper Permian Longtan and Dalong Shales in Middle Yangtze Region, China. Journal of Earth Science, 2020, 31(2): 368-384. doi: 10.1007/s12583-019-1237-6

Effect of Organic Matter Type and Maturity on Organic Matter Pore Formation of Transitional Facies Shales: A Case Study on Upper Permian Longtan and Dalong Shales in Middle Yangtze Region, China

doi: 10.1007/s12583-019-1237-6
Funds:

the National Key R & D program of China 2017YFE0103600

the China National Science and Technology Major Projects for financial assistance to this research 2016ZX05034002-003

the National Natural Science Foundation of China 41830431

the National Natural Science Foundation of China 41672139

More Information
  • Organic matter (OM) nanopores developed in transitional facies shales,i.e.,the Upper Permian Longtan and Dalong Formations in the Yangtze Platform,China,were investigated to determine the corresponding influence of thermal maturity and OM types within the geological conditions. A suite of 16 core samples were taken from Type-Ⅲ Longtan shales and Type-Ⅱ Dalong shales from two wells covering a maturity (Ro,vitrinite reflectance) ranging from 1.22% to 1.43% and 2.62% to 2.97%,respectively. Integrated analysis of the shale samples was carried out,including field-emission scanning electron microscopy (FE-SEM),low-pressure N2 and CO2 adsorption,high-pressure CH4 adsorption,and mercury intrusion capillary pressure (MICP) analysis. The fluid inclusions of liquid and gas hydrocarbons trapped in calcite vein samples in Dalong shales of two wells were studied using laser Raman and fluorescence spectroscopy. FE-SEM images indicated that OM pores in different formations varied substantially in terms of shape,size,and distribution density. OM pores in Type-Ⅱ Dalong shales of Well XY1 were mainly micropore,sparsely distributed in the gas-prone kerogen with a spot-like and irregular shape,while bitumen rarely developed observable pores. In contrast,the morphology of OM pores in Type-Ⅲ Longtan shales were significantly different,which was due to differences in the OM type. The primary OM pores in some terrestrial woody debris in Longtan shales had a relatively larger pore diameter,ranging from hundreds of nanometers to a few micrometers and were almost all rounded in shape,which might be one of the factors contributing to larger pore volume and gas adsorption capacity than Dalong shales of Well XY1. Comparing Dalong shales of Well XY1 with relatively lower thermal maturity,there were abundant spongy-like pores,densely developed in the pyrobitumen in Type-Ⅱ Dalong shales of Well EY1,with an irregular shape and diameter ranging from several to hundreds of nanometers. Many blue fluorescent oil inclusions and a small number of CH4 inclusions mixed with C2H6 could be observed within calcite veins in Dalong shales of Well XY1,whereas only CH4 inclusions could be identified within calcite veins in Dalong shales of Well EJ1. Therefore,thermal maturity not only controlled the type of hydrocarbons generated,but also makes a significant contribution to the formation of OM pores,resulting in larger pore volumes and adsorption capacity of Type-Ⅱ shale samples in the dry gas window.
  • 加载中
  • Ardakani, O. H., Sanei, H., Ghanizadeh, A., et al., 2017. Hydrocarbon Potential and Reservoir Characteristics of Lower Cretaceous Garbutt Formation, Liard Basin Canada. Fuel, 209:274-289. https://doi.org/10.1016/j.fuel.2017.07.106 doi:  10.1016/j.fuel.2017.07.106
    Ardakani, O. H., Sanei, H., Ghanizadeh, A., et al., 2018. Do all Fractions of Organic Matter Contribute Equally in Shale Porosity? A Case Study from Upper Ordovician Utica Shale, Southern Quebec, Canada. Marine and Petroleum Geology, 92:794-808. https://doi.org/10.13039/501100000159 doi:  10.13039/501100000159
    Bao, S., Lin, T., Nie, H., et al., 2016. Preliminary Study of the Transitional Facies Shale Gas Reservoir Characteristics:Taking Permian in the Xiangzhong Depression as an Example. Earth Science Frontiers, 23(1):44-53 (in Chinese with English Abstract) http://d.old.wanfangdata.com.cn/Periodical/dxqy201601004
    Bernard, S., Horsfield, B., Schulz, H. M., et al., 2012a. Geochemical Evolution of Organic-Rich Shales with Increasing Maturity:A STXM and TEM Study of the Posidonia Shale (Lower Toarcian, Northern Germany). Marine and Petroleum Geology, 31(1):70-89. https://doi.org/10.1016/j.marpetgeo.2011.05.010 doi:  10.1016/j.marpetgeo.2011.05.010
    Bernard, S., Wirth, R., Schreiber, A., et al., 2012b. Formation of Nanoporous Pyrobitumen Residues during Maturation of the Barnett Shale (Fort Worth Basin). International Journal of Coal Geology, 103:3-11. https://doi.org/10.1016/j.coal.2012.04.010 doi:  10.1016/j.coal.2012.04.010
    Bernard, S., Horsfield, B., 2014. Thermal Maturation of Gas Shale Systems. Annual Review of Earth and Planetary Sciences, 42(1):635-651. https://doi.org/10.1146/annurev-earth-060313-054850 doi:  10.1146/annurev-earth-060313-054850
    Cao, T. T., Deng, M., Song, Z. G., et al., 2018. Characteristics and Controlling Factors of Pore Structure of the Permian Shale in Southern Anhui Province, East China. Journal of Natural Gas Science and Engineering, 60:228-245. https://doi.org/10.1016/j.jngse.2018.10.018 doi:  10.1016/j.jngse.2018.10.018
    Cardott, B. J., Landis, C. R., Curtis, M. E., 2015. Post-Oil Solid Bitumen Network in the Woodford Shale, USA-A Potential Primary Migration Pathway. International Journal of Coal Geology, 139:106-113. https://doi.org/10.1016/j.coal.2014.08.012 doi:  10.1016/j.coal.2014.08.012
    Clarkson, C. R., Jensen, J. L., Pedersen, P. K., et al., 2012. Innovative Methods for Flow-Unit and Pore-Structure Analyses in a Tight Siltstone and Shale Gas Reservoir. AAPG Bulletin, 96(2):355-374. https://doi.org/10.1306/05181110171 doi:  10.1306/05181110171
    Curtis, M. E., Cardott, B. J., Sondergeld, C. H., et al., 2012. Development of Organic Porosity in the Woodford Shale with Increasing Thermal Maturity. International Journal of Coal Geology, 103:26-31. https://doi.org/10.1016/j.coal.2012.08.004 doi:  10.1016/j.coal.2012.08.004
    Curiale, J. A., 1983. Petroleum Occurrences and Source-Rock Potential of the Ouachita Mountains, Southeastern Oklahoma. Bull. Okla. Geol. Surv., 135:65
    Curiale, J. A., 1986. Origin of Solid Bitumens, with Emphasis on Biological Marker Results. Organic Geochemistry, 10(1-3):559-580. https://doi.org/10.1016/0146-6380(86)90054-9 doi:  10.1016/0146-6380(86)90054-9
    Dang, W., Zhang, J., Wei, X., et al., 2017. Geological Controls on Methane Adsorption Capacity of Lower Permian Transitional Black Shales in the Southern North China Basin, Central China:Experimental Results and Geological Implications. Journal of Petroleum Science and Engineering, 152:456-470 doi:  10.1016/j.petrol.2017.03.017
    Ding, J., Zhang, J., Yang, C., et al., 2019. Formation Evolution and Influencing Factors of Organic Pores in Shale. Journal of Southwest Petroleum University (Science & Technology Edition), 41(2):33-44 (in Chinese with English Abstract) http://d.old.wanfangdata.com.cn/Periodical/zgdizhi201802005
    Dong, T., Harris, N. B., Ayranci, K., et al., 2015. Porosity Characteristics of the Devonian Horn River Shale, Canada:Insights from Lithofacies Classification and Shale Composition. International Journal of Coal Geology, 141:74-90. https://doi.org/10.1016/j.coal.2015.03.001 doi:  10.1016/j.coal.2015.03.001
    Dong, T., Harris, N. B., Ayranci, K., et al., 2017. The Impact of Rock Composition on Geomechanical Properties of a Shale Formation:Middle and Upper Devonian Horn River Group Shale, Northeast British Columbia, Canada. AAPG Bulletin, 101(2):177-204 doi:  10.1306/07251615199
    Dong, T., He, S., Chen, M., et al., 2019. Quartz Types and Origins in the Paleozoic Wufeng-Longmaxi Formations, Eastern Sichuan Basin, China:Implications for Porosity Preservation in Shale Reservoirs. Marine and Petroleum Geology, 106:62-73. https://doi.org/10.1016/j.marpetgeo.2019.05.002 doi:  10.1016/j.marpetgeo.2019.05.002
    Ehsan, M., Gu, H., Akhtar, M. M., et al., 2018. Identification of Hydrocarbon Potential of Talhar Shale:Member of Lower Goru Formation by Using Well Logs Derived Parameters, Southern Lower Indus Basin, Pakistan. Journal of Earth Science, 29(3):587-593. https://doi.org/10.1007s12583-016-0910-2 doi:  10.1007/s12583-016-0910-2
    Fishman, N. S., Hackley, P. C., Lowers, H. A., et al., 2012. The Nature of Porosity in Organic-Rich Mudstones of the Upper Jurassic Kimmeridge Clay Formation, North Sea, Offshore United Kingdom. International Journal of Coal Geology, 103:32-50. https://doi.org/10.1016/j.coal.2012.07.012 doi:  10.1016/j.coal.2012.07.012
    Furmann, A., Mastalerz, M., Bish, D., et al., 2016. Porosity and Pore Size Distribution in Mudrocks from the Belle Fourche and Second White Specks Formations in Alberta, Canada. AAPG Bulletin, 100(8):1265-1288. https://doi.org/10.1306/02191615118 doi:  10.1306/02191615118
    Gibbs, J. W., 1948. The Collected Works of J. Willard Gibbs. Yale University Press, New Haven
    George, S. C., Ruble, T. E., Dutkiewicz, A., et al., 2001. Assessing the Maturity of Oil Trapped in Fluid Inclusions Using Molecular Geochemistry Data and Visually-Determined Fluorescence Colours. Applied Geochemistry, 16(4):451-473. https://doi.org/10.1016/s0883-2927(00)00051-2 doi:  10.1016/s0883-2927(00)00051-2
    Guo, H. J., He, R. L., Jia, W. L., et al., 2018. Pore Characteristics of Lacustrine Shale within the Oil Window in the Upper Triassic Yanchang Formation, Southeastern Ordos Basin, China. Marine and Petroleum Geology, 91:279-296. https://doi.org/10.1016/j.marpetgeo.2018.01.013 doi:  10.1016/j.marpetgeo.2018.01.013
    Hackley, P. C., Cardott, B. J., 2016. Application of Organic Petrography in North American Shale Petroleum Systems:A Review. International Journal of Coal Geology, 163:8-51. https://doi.org/10.1016/j.coal.2016.06.010 doi:  10.1016/j.coal.2016.06.010
    Han, Y. J., Horsfield, B., Wirth, R., et al., 2017. Oil Retention and Porosity Evolution in Organic-Rich Shales. AAPG Bulletin, 101(6):807-827. https://doi.org/10.1306/09221616069 doi:  10.1306/09221616069
    Hill, R. J., Tang, Y. C., Kaplan, I. R., 2003. Insights into Oil Cracking Based on Laboratory Experiments. Organic Geochemistry, 34(12):1651-1672. https://doi.org/10.1016/s0146-6380(03)00173-6 doi:  10.1016/s0146-6380(03)00173-6
    Hunt, J. M., 1996. Petroleum Geochemistry and Geology. WH Freeman and Company, New York. 1-58
    Jacob, H., 1989. Classification, Structure, Genesis and Practical Importance of Natural Solid Oil Bitumen ("Migrabitumen"). International Journal of Coal Geology, 11(1):65-79. https://doi.org/10.1016/0166-5162(89)90113-4 doi:  10.1016/0166-5162(89)90113-4
    Jarvie, D. M., Hill, R. J., Ruble, T. E., et al., 2007. Unconventional Shale-Gas Systems:The Mississippian Barnett Shale of North-Central Texas as One Model for Thermogenic Shale-Gas Assessment. AAPG Bulletin, 91(4):475-499. https://doi.org/10.1306/12190606068 doi:  10.1306/12190606068
    Lewan, M. D., Pawlewicz, M. J., 2017. Reevaluation of Thermal Maturity and Stages of Petroleum Formation of the Mississippian Barnett Shale, Fort Worth Basin, Texas. AAPG Bulletin, 101(12):1945-1970. https://doi.org/10.1306/01251716053 doi:  10.1306/01251716053
    Liang, X., Liu, S., Wang, S., et al., 2019. Analysis of the Oldest Carbonate Gas Reservoir in China-New Geological Significance of the Dengying Gas Reservoir in the Weiyuan Structure, Sichuan Basin. Journal of Earth Science, 30(2):348-366. https://doi.org/10.1007/s12583-017-0962-y doi:  10.1007/s12583-017-0962-y
    Liu, B., Schieber, J., Mastalerz, M., 2017. Combined SEM and Reflected Light Petrography of Organic Matter in the New Albany Shale (Devonian-Mississippian) in the Illinois Basin:A Perspective on Organic Pore Development with Thermal Maturation. International Journal of Coal Geology, 184:57-72. https://doi.org/10.13039/501100004543 doi:  10.13039/501100004543
    Liu, W. Q., Yao, J. X., Tong, J. N., et al., 2019. Organic Matter Accumulation on the Dalong Formation (Upper Permian) in Western Hubei, South China:Constraints from Multiple Geochemical Proxies and Pyrite Morphology. Palaeogeography, Palaeoclimatology, Palaeoecology, 514:677-689. https://doi.org/10.13039/501100002855 doi:  10.13039/501100002855
    Löhr, S. C., Baruch, E. T., Hall, P. A., et al., 2015. Is Organic Pore Development in Gas Shales Influenced by the Primary Porosity and Structure of Thermally Immature Organic Matter?. Organic Geochemistry, 87:119-132. https://doi.org/10.1016/j.orggeochem.2015.07.010 doi:  10.1016/j.orggeochem.2015.07.010
    Loucks, R. G., Reed, R. M., Ruppel, S. C., et al., 2009. Morphology, Genesis, and Distribution of Nanometer-Scale Pores in Siliceous Mudstones of the Mississippian Barnett Shale. Journal of Sedimentary Research, 79(12):848-861. https://doi.org/10.2110/jsr.2009.092 doi:  10.2110/jsr.2009.092
    Loucks, R. G., Reed, R. M., Ruppel, S. C., et al., 2012. Spectrum of Pore Types and Networks in Mudrocks and a Descriptive Classification for Matrix-Related Mudrock Pores. AAPG Bulletin, 96(6):1071-1098. https://doi.org/10.1306/08171111061 doi:  10.1306/08171111061
    Loucks, R. G., Reed, R. M., 2014. Scanning-Electron-Microscope Petrographic Evidence for Distinguishing Organic-Matter Pores Associated with Depositional Organic Matter versus Migrated Organic Matter in Mudrocks. GCAGS Transactions, 3:51-60 http://www.wanfangdata.com.cn/details/detail.do?_type=perio&id=CC0214853297
    Loucks, R. G., Ruppel, S. C., Wang, X. Z., et al., 2017. Pore Types, Pore-Network Analysis, and Pore Quantification of the Lacustrine Shale-Hydrocarbon System in the Late Triassic Yanchang Formation in the Southeastern Ordos Basin, China. Interpretation, 5(2):SF63-SF79. https://doi.org/10.1190/int-2016-0094.1 doi:  10.1190/int-2016-0094.1
    Lu, J. M., Ruppel, S. C., Rowe, H. D., 2015. Organic Matter Pores and Oil Generation in the Tuscaloosa Marine Shale. AAPG Bulletin, 99(2):333-357. https://doi.org/10.1306/08201414055 doi:  10.1306/08201414055
    Mastalerz, M., Glikson, M., 2000. In-situ Analysis of Solid Bitumen in Coal:Examples from the Bowen Basin and the Illinois Basin. International Journal of Coal Geology, 42(2/3):207-220. https://doi.org/10.1016/s0166-5162(99)00040-3 doi:  10.1016/s0166-5162(99)00040-3
    Mahlstedt, N., Horsfield, B., 2012. Metagenetic Methane Generation in Gas Shales I. Screening Protocols Using Immature Samples. Marine and Petroleum Geology, 31(1):27-42. https://doi.org/10.1016/j.marpetgeo.2011.06.011 doi:  10.1016/j.marpetgeo.2011.06.011
    Mastalerz, M., Schimmelmann, A., Drobniak, A., et al., 2013. Porosity of Devonian and Mississippian New Albany Shale across a Maturation Gradient:Insights from Organic Petrology, Gas Adsorption, and Mercury Intrusion. AAPG Bulletin, 97(10):1621-1643. https://doi.org/10.1306/04011312194 doi:  10.1306/04011312194
    Mastalerz, M., Drobniak, A., Stankiewicz, A. B., 2018. Origin, Properties, and Implications of Solid Bitumen in Source-Rock Reservoirs:A Review. International Journal of Coal Geology, 195:14-36. https://doi.org/10.1016/j.coal.2018.05.013 doi:  10.1016/j.coal.2018.05.013
    Milliken, K. L., Rudnicki, M., Awwiller, D. N., et al., 2013. Organic Matter-Hosted Pore System, Marcellus Formation (Devonian), Pennsylvania. AAPG Bulletin, 97(2):177-200. https://doi.org/10.1306/07231212048 doi:  10.1306/07231212048
    Misch, D., Gross, D., Hawranek, G., et al., 2019. Solid Bitumen in Shales:Petrographic Characteristics and Implications for Reservoir Characterization. International Journal of Coal Geology, 205:14-31. https://doi.org/10.13039/501100002428 doi:  10.13039/501100002428
    Nelson, P. H., 2009. Pore-Throat Sizes in Sandstones, Tight Sandstones, and Shales. AAPG Bulletin, 93(3):329-340. https://doi.org/10.1306/10240808059 doi:  10.1306/10240808059
    Peng, N., He, S., Hu, Q. H., et al., 2019. Organic Nanopore Structure and Fractal Characteristics of Wufeng and Lower Member of Longmaxi Shales in Southeastern Sichuan, China. Marine and Petroleum Geology, 103:456-472. https://doi.org/10.1016/j.marpetgeo.2019.03.017 doi:  10.1016/j.marpetgeo.2019.03.017
    Qiu, X., Liu, Y., Dong, X., 2019. Organic Geochemical Characteristics of Shale from Dalong Formation in Jianshi Area, Western Hubei. Lithologic Reservoirs, 31(2):96-104. https://doi.org/10.1016/j.palaeo.2018.11.015 doi:  10.1016/j.palaeo.2018.11.015
    Ross, D. J. K., Marc Bustin, R., 2009. The Importance of Shale Composition and Pore Structure upon Gas Storage Potential of Shale Gas Reservoirs. Marine and Petroleum Geology, 26(6):916-927. https://doi.org/10.1016/j.marpetgeo.2008.06.004 doi:  10.1016/j.marpetgeo.2008.06.004
    Stasiuk, L. D., Snowdon, L. R., 1997. Fluorescence Micro-Spectrometry of Synthetic and Natural Hydrocarbon Fluid Inclusions:Crude Oil Chemistry, Density and Application to Petroleum Migration. Applied Geochemistry, 12(3):229-241. https://doi.org/10.1016/s0883-2927(96)00047-9 doi:  10.1016/s0883-2927(96)00047-9
    Suárez-Ruiz, I., Flores, D., Mendonça Filho, J. G., et al., 2012. Review and Update of the Applications of Organic Petrology:Part 1, Geological Applications. International Journal of Coal Geology, 99:54-112. https://doi.org/10.1016/j.coal.2012.02.004 doi:  10.1016/j.coal.2012.02.004
    Taylor, G. H., Teichmüller, M., Davis, A., et al., 1998. Organic Petrology. Gebrüder Borntraeger, Stuttgart, Berlin. 704
    Scott, A. C., 1999. Organic Petrology. A New Handbook Incorporating Some Revised Parts of Stach's Textbook of Coal Petrology. Gebrüder Borntraeger, Price D. M., Berlin
    Thommes, M., Kaneko, K., Neimark, A. V., et al., 2015. Physisorption of Gases, with Special Reference to the Evaluation of Surface Area and Pore Size Distribution (IUPAC Technical Report). Pure and Applied Chemistry, 87(9/10):1051-1069. https://doi.org/10.1515/pac-2014-1117 doi:  10.1515/pac-2014-1117
    Tissot, B. P., Welte, D. H., 1984. Petroleum Formation and Occurrence, 2nd edn. Springer, Berlin
    Valenza, J. J. II, Drenzek, N., Marques, F., et al., 2013. Geochemical Controls on Shale Microstructure. Geology, 41(5):611-614. https://doi.org/10.1130/g33639.1 doi:  10.1130/g33639.1
    Videtich, P. E., Roger, K., 1988. Depositional, Diagenetic, Thermal, and Maturation Histories of Cretaceous Mishrif Formation, Fateh Field, Dubai. AAPG Bulletin, 72(10):1143-1159. https://doi.org/10.1306/703c996a-1707-11d7-8645000102c1865d doi:  10.1306/703c996a-1707-11d7-8645000102c1865d
    Waples, D. W., 2000. The Kinetics of In-Reservoir Oil Destruction and Gas Formation:Constraints from Experimental and Empirical Data, and from Thermodynamics. Organic Geochemistry, 31(6):553-575. https://doi.org/10.1016/s0146-6380(00)00023-1 doi:  10.1016/s0146-6380(00)00023-1
    Washburn, E. W., 1921. The Dynamics of Capillary Flow. Physical Review, 17(3):273-283. https://doi.org/10.1103/physrev.17.273 doi:  10.1103/physrev.17.273
    Washburn, E. W., 1921. Note on a Method of Determining the Distribution of Pore Sizes in a Porous Material. Proceedings of the National Academy of Sciences, 7(4):115-116. https://doi.org/10.1073/pnas.7(4):115 doi:  10.1073/pnas.7(4):115
    Wood, J. M., Sanei, H., Haeri-Ardakani, O., et al., 2018. Solid Bitumen in the Montney Formation:Diagnostic Petrographic Characteristics and Significance for Hydrocarbon Migration. International Journal of Coal Geology, 198:48-62. https://doi.org/10.13039/100007605 doi:  10.13039/100007605
    Wu, Z., He, S., He, X. P., et al., 2019. Pore Structure Characteristics and Comparisons of Upper Permian Longtan and Dalong Formation Transitional Facies Shale in Xiangzhong Lianyuan Depression. Earth Science, 44(11):3757-3772. https://doi.org/10.3799/dqkx.2019.084 (in Chinese with English Abstract) doi:  10.3799/dqkx.2019.084
    Xia, J., Song, Z. G., Wang, S. B., et al., 2017. Preliminary Study of Pore Structure and Methane Sorption Capacity of the Lower Cambrian Shales from the North Guizhou Province. Journal of Natural Gas Science and Engineering, 38:81-93. https://doi.org/10.1016/j.jngse.2016.12.021 doi:  10.1016/j.jngse.2016.12.021
    Xiong, F. Y., Jiang, Z. X., Chen, J. F., et al., 2016. The Role of the Residual Bitumen in the Gas Storage Capacity of Mature Lacustrine Shale:A Case Study of the Triassic Yanchang Shale, Ordos Basin, China. Marine and Petroleum Geology, 69:205-215. https://doi.org/10.1016/j.marpetgeo.2015.10.022 doi:  10.1016/j.marpetgeo.2015.10.022
    Xu, J., Sonnenberg, S. A., 2017. An SEM Study of Porosity in the Organic-rich Lower Bakken Member and Pronghorn Member, Bakken Formation, Williston Basin. Unconventional Resources Technology Conference, Austin, 24-26 July 2017. Society of Exploration Geophysicists, American Association of Petroleum Geologists, Society of Petroleum Engineers, 3213-3225
    Yang, R., He, S., Yi, J. Z., et al., 2016. Nano-Scale Pore Structure and Fractal Dimension of Organic-Rich Wufeng-Longmaxi Shale from Jiaoshiba Area, Sichuan Basin:Investigations Using FE-SEM, Gas Adsorption and Helium Pycnometry. Marine and Petroleum Geology, 70:27-45. https://doi.org/10.13039/501100004613 doi:  10.13039/501100004613
    Yang, R., He, S., Hu, Q. H., et al., 2017. Geochemical Characteristics and Origin of Natural Gas from Wufeng-Longmaxi Shales of the Fuling Gas Field, Sichuan Basin (China). International Journal of Coal Geology, 171:1-11. https://doi.org/10.13039/501100004613 doi:  10.13039/501100004613
    Zhao, S. F., Chen, W., Zhou, L., et al., 2019. Characteristics of Fluid Inclusions and Implications for the Timing of Hydrocarbon Accumulation in the Cretaceous Reservoirs, Kelasu Thrust Belt, Tarim Basin, China. Marine and Petroleum Geology, 99:473-487. https://doi.org/10.1016/j.marpetgeo.2018.10.041 doi:  10.1016/j.marpetgeo.2018.10.041
    Zhao, Y. J., Chen, H. H., 2008. The Relationship between Fluorescence Colors of Oil Inclusions and Their Maturities. Earth Science, 33(1):91-96 (in Chinese with English Abstract) http://www.wanfangdata.com.cn/details/detail.do?_type=perio&id=dqkx200801012
    Zhang, J., He, S., Yi, J., 2014. Rock Thermo-Acoustic Emission and Basin Modeling Technologies Applied to the Study of Maximum Paleotemperatures and Thermal Maturity Histories of Lower Paleozoic Marine Shales in the Western Middle Yangtze Area. Acta Petrolei Sinica, 35(1):58-67 (in Chinese with English Abstract) doi:  10.1038/aps.2013.122
    Zhang, Q., Liu, R. H., Pang, Z. L., et al., 2016. Characterization of Microscopic Pore Structures in Lower Silurian Black Shale (S1l), Southeastern Chongqing, China. Marine and Petroleum Geology, 71:250-259. https://doi.org/10.1016/j.marpetgeo.2015.12.015 doi:  10.1016/j.marpetgeo.2015.12.015
    Zhu, X. J., Cai, J. G., Wang, X. J., et al., 2014. Effects of Organic Components on the Relationships between Specific Surface Areas and Organic Matter in Mudrocks. International Journal of Coal Geology, 133:24-34. https://doi.org/10.1016/j.coal.2014.08.009 doi:  10.1016/j.coal.2014.08.009
  • 加载中
通讯作者: 陈斌, bchen63@163.com
  • 1. 

    沈阳化工大学材料科学与工程学院 沈阳 110142

  1. 本站搜索
  2. 百度学术搜索
  3. 万方数据库搜索
  4. CNKI搜索

Figures(14)  / Tables(2)

Article Metrics

Article views(94) PDF downloads(16) Cited by()

Related
Proportional views

Effect of Organic Matter Type and Maturity on Organic Matter Pore Formation of Transitional Facies Shales: A Case Study on Upper Permian Longtan and Dalong Shales in Middle Yangtze Region, China

doi: 10.1007/s12583-019-1237-6
Funds:

the National Key R & D program of China 2017YFE0103600

the China National Science and Technology Major Projects for financial assistance to this research 2016ZX05034002-003

the National Natural Science Foundation of China 41830431

the National Natural Science Foundation of China 41672139

    Corresponding author: Sheng He

Abstract: Organic matter (OM) nanopores developed in transitional facies shales,i.e.,the Upper Permian Longtan and Dalong Formations in the Yangtze Platform,China,were investigated to determine the corresponding influence of thermal maturity and OM types within the geological conditions. A suite of 16 core samples were taken from Type-Ⅲ Longtan shales and Type-Ⅱ Dalong shales from two wells covering a maturity (Ro,vitrinite reflectance) ranging from 1.22% to 1.43% and 2.62% to 2.97%,respectively. Integrated analysis of the shale samples was carried out,including field-emission scanning electron microscopy (FE-SEM),low-pressure N2 and CO2 adsorption,high-pressure CH4 adsorption,and mercury intrusion capillary pressure (MICP) analysis. The fluid inclusions of liquid and gas hydrocarbons trapped in calcite vein samples in Dalong shales of two wells were studied using laser Raman and fluorescence spectroscopy. FE-SEM images indicated that OM pores in different formations varied substantially in terms of shape,size,and distribution density. OM pores in Type-Ⅱ Dalong shales of Well XY1 were mainly micropore,sparsely distributed in the gas-prone kerogen with a spot-like and irregular shape,while bitumen rarely developed observable pores. In contrast,the morphology of OM pores in Type-Ⅲ Longtan shales were significantly different,which was due to differences in the OM type. The primary OM pores in some terrestrial woody debris in Longtan shales had a relatively larger pore diameter,ranging from hundreds of nanometers to a few micrometers and were almost all rounded in shape,which might be one of the factors contributing to larger pore volume and gas adsorption capacity than Dalong shales of Well XY1. Comparing Dalong shales of Well XY1 with relatively lower thermal maturity,there were abundant spongy-like pores,densely developed in the pyrobitumen in Type-Ⅱ Dalong shales of Well EY1,with an irregular shape and diameter ranging from several to hundreds of nanometers. Many blue fluorescent oil inclusions and a small number of CH4 inclusions mixed with C2H6 could be observed within calcite veins in Dalong shales of Well XY1,whereas only CH4 inclusions could be identified within calcite veins in Dalong shales of Well EJ1. Therefore,thermal maturity not only controlled the type of hydrocarbons generated,but also makes a significant contribution to the formation of OM pores,resulting in larger pore volumes and adsorption capacity of Type-Ⅱ shale samples in the dry gas window.

Zhongrui Wu, Sheng He, Yuanjia Han, Gangyi Zhai, Xipeng He, Zhi Zhou. Effect of Organic Matter Type and Maturity on Organic Matter Pore Formation of Transitional Facies Shales: A Case Study on Upper Permian Longtan and Dalong Shales in Middle Yangtze Region, China. Journal of Earth Science, 2020, 31(2): 368-384. doi: 10.1007/s12583-019-1237-6
Citation: Zhongrui Wu, Sheng He, Yuanjia Han, Gangyi Zhai, Xipeng He, Zhi Zhou. Effect of Organic Matter Type and Maturity on Organic Matter Pore Formation of Transitional Facies Shales: A Case Study on Upper Permian Longtan and Dalong Shales in Middle Yangtze Region, China. Journal of Earth Science, 2020, 31(2): 368-384. doi: 10.1007/s12583-019-1237-6
  • The considerable success of the North American shale gas revolution has triggered a global boom in shale gas exploration, and China has invested heavily in shale gas exploration and development in Paleozoic marine shale formations (Ehsan et al., 2018; Dong et al., 2017, 2015; Mastalerz et al., 2013; Loucks et al., 2012; Jarvie et al., 2007). With the proceeding shale gas exploration and production from the Lower Paleozoic shale formations, including Niutitang, Wufeng and Longmaxi formations, Fuling, Weiyuan and several other major shale gas fields have been discovered (Peng et al., 2019; Yang et al., 2017, 2016). Recently, the exploration of Permian shales in southern China has received increasing attention, especially the Upper Permian Longtan and Dalong formations, which are widely distributed in the Yangtze area (Wu et al., 2019; Bao et al., 2016). The high total organic carbon (TOC) content (mostly > 2%) and high thermal maturity (Ro=1.2%-3.0%) of the two shale formations indicate great potential for shale gas production. Compared with the over-mature marine shales in southern China, the depositional facies and thermal maturity of the Upper Permian Longtan and Dalong shales vary dramatically, resulting in significant differences in their OM type, mineral composition, and pore structures and hence gas adsorption capacity.

    Unlike conventional gas reservoir, shale gas reservoir has the characteristics of being "self-generation and self-accumulation" with extremely low porosity and permeability (Liang et al., 2019; Wu et al., 2019). Pore structure is one of the critical factors affecting the enrichment and distribution of shale gas (Peng et al., 2019; Cao et al., 2018). For shales containing mainly nanoscale pores, the pore structure is generally complex and heterogeneous (Clarkson et al., 2012; Nelson, 2009). The pore types in shales are generally classified as OM pores, interparticle pores, and intraparticle pores (Loucks et al., 2012). Among these, the nanoscale OM pores developed within bitumen and kerogen are the most important type, as these OM pores are usually connected with each other, building three-dimensional pore networks, which provide more space for gas storage (Dong et al., 2019; Lu et al., 2015). Apart from that, the nanoscale OM pores will increase specific surface areas, and therefore, significantly contribute to higher gas adsorption capacity (Zhang et al., 2016; Ross et al., 2009).

    OM pores can be divided into two types based on whether they are of bitumen or kerogen origin. The definition of bitumen remains vague at present, and there are numerous classifications and terminologies used, such as solid bitumen, pyrobitumen, asphalt, asphaltite, and migrabitumen (Cardott et al., 2015; Taylor et al., 1998; Curiale, 1986; Tissot and Welte, 1984). At present, the common classification of bitumen is solid bitumen and pyrobitumen (Misch et al., 2019; Mastalerz et al., 2018; Liu et al., 2017). In order to correlate bitumen formation with hydrocarbon generation from the perspective of the thermal conversion degree of the primary OM, solid bitumen can be further divided into pre-oil bitumen and post-oil bitumen (Cardott et al., 2015; Mastalerz et al., 2000; Curiale, 1986, 1983). During the process of thermal maturation, oil-prone kerogen is broken down to pre-oil bitumen, oil, post-oil bitumen, and finally pyrobitumen (Bernard et al., 2012a, b ; Jarvie et al., 2007; Jacob et al., 1989; Curiale et al., 1986). As reported in literature, the occurrence of solid bitumen is generally regarded as the secondary product from oil-prone kerogen by thermal degradation and hydrocarbon generation (Hackley and Cardott, 2016). Pre-oil bitumen is the early product formed during the conversation of kerogen to liquid hydrocarbons, with short migration distance to voids and fractures or in-situ accumulation (Mastalerz et al., 2018).

    In contrast, post-oil bitumen is the degradation residue of liquid hydrocarbons mobilized in the mineral matrix and accumulated in the interparticle space (Misch et al., 2019; Mastalerz et al., 2018, Mastalerz and Glikson, 2000; Curiale, 1986). Mahlstedt and Horsfield (2012) described post-oil bitumen as pore-occluding petroleum that can generate condensate oil and gas through secondary cracking. Pyrobitumen is the residues of formerly post-oil bitumen generated from secondary cracking and the formation of gas hydrocarbons (Misch et al., 2019; Suárez-Ruiz et al., 2012; Hill et al., 2003). According to organic geochemists, the maindifference between solid bitumen and pyrobitumen is that solid bitumen is soluble in CS2, while pyrobitumen is insoluble in CS2 (Hunt, 1996; Tissot and Welte, 1984). Lewan and Pawlewicz (2017) suggested that the lowest thermal maturity of Ro for secondary cracking and gas generation was 1.5%, meaning that the temperature boundary between solid bitumen and pyrobitumen was roughly 170 ℃. Waples (2000) reported that the occurrence of pyrobitumen was considered to be 150 ℃ or higher, and the corresponding Ro is above 1.2%.

    In recent years, an increasing number of researchers have focused on the evolution of OM pores with thermal maturity as well as other factors influencing the morphology and distribution of OM pores. Curtis et al. (2012) investigated shale samples with Ro ranging from 0.51% to 6.36% and found that there were no secondary pores in shale samples in the oil window (Ro < 0.90%). In contrast, secondary pores can be observed in shales sample with Ro greater than 1.23%. Cardott et al. (2015) stated that the OM in Woodford shales was post-oil bitumen, which is the solid carbon residue of previously migrated oil, and the secondary nanoscale OM pores started to generate at around Ro=0.9%. Bernard and Horsfield (2014), Bernard et al. (2012a) suggested that the nanoporous OM in the gas window of the Barnett shales was pyrobitumen, which was the residue of solid bitumen after secondary cracking and the generation of gaseous hydrocarbons. Furthermore, thermal maturity was not the only factor influencing the formation of OM pores. Other factors such as OM type and compaction can also affect the morphology and distribution density of OM pores. Liu et al. (2017) found that Type-Ⅲ OM tended to be nonporous and only part of the inertinite develop cellular pores. The terrestrial woody macerals such as vitrinite and inertinite did not have dramatic change with the increase of thermal maturity because of their poor potential in generating hydrocarbon. Milliken et al. (2013) studied Pennsylvania Marcellus Formation and argued that the dominant OM filling the intergranular spaces without distinct shapes developed numerous internal sponge-like pore, which contrasted sharply with the adjacent wood fragments. Therefore, it is imperative to classify pores in different types of OM with varying maturities.

    Shale samples were collected from two drilling wells in the Middle Yangtze area. Sixteen core samples from the Upper Permian Longtan and Dalong formations were selected from the wells XY1 and EJ1 to investigate the factors controlling pore structure. Qualitative and quantitative analysis was carried out, including field emission scanning electron microscopy (FE-SEM), low-pressure N2 and CO2 adsorption, high-pressure CH4 adsorption, and mercury intrusion capillary pressure (MICP) analysis. In order to study the retention of hydrocarbons, hydrocarbon fluid inclusions developed in calcite veins were investigated using a microscope equipped with both transmitted white and incident ultraviolet (UV) light and through Raman microprobe analyses. The principal objectives of the study were to (1) compare the differences in pore structure in Dalong and Longtan formations; (2) identify and classify the OM (kerogen, bitumen, and pyrobitumen) in shales of Dalong and Longtan formations with different thermal maturity and depositional environments; (3) investigate the OM pore microstructure, including the shape, size, and distributed density in different OM; and (4) discuss factors affecting pore development.

  • The wells XY1 and EJ1 are both located in the Middle Yangtze region (Fig. 1a). The Well XY1 is drilled in Xiangzhong Lianyuan Depression which lies between Hengshan uplift belt and Jiangnan-Xuefeng uplift belt (Fig. 1c). During the Longtan period, a set of shales with lagoon-swamp facies were deposited widely in Lianyuan Depression (Bao et al., 2016). Silty mudstone, muddy siltite, and coal seams can be observed in Longtan Formation. Afterwards, a transgression occurred and a set of platform basin facies shales were deposited during the Dalong period, characterized by shales, calcareous shales, and muddy limestone. The area where Well XY1 is located has undergone considerable uplift and erosion during Yanshanian and Himalayan periods, and the thickness of strata erosion was approximately 2 000 m (Bao et al., 2016), leading to the result that the present burial depths of Longtan and Dalong formations were 600-700 m.

    Figure 1.  (a) Location map of study area in the Yangtze Platform, (b) and (c) tectonic map of study area and well location (modified from Bao et al., 2016; Zhang et al., 2014).

    Well EJ1 is located in Huaguoping synclinore which lies between Sichuan Basin and Jiangnan-Xuefeng uplift belt (Fig. 1b). The depositional facies of the Upper Permian Dalong Formation in Well EJ1 is a platform basin (Liu et al., 2019). The Dalong shales in Well EJ1 are characterized by carbonaceous shales and shales. The area where Well EJ1 is located has undergone enormous uplift and erosion during Yanshanian-Himalayan epoch, and the erosional formation thickness was approximately 5 000 m (Zhang et al., 2014), leading to the result that the present burial depths of Dalong Formation were 820-860 m.

  • The stratigraphic column and sample location are presented in Fig. 2. A total of four and eight samples were selected from Longtan and Dalong formations in Well XY1, respectively, while a further set of four samples were taken from Dalong Formation in Well EJ1. In addition, two Dalong samples containing fracture calcite veins were taken from each well for further study to characterize the hydrocarbon inclusions.

    Figure 2.  Stratigraphic column of the Longtan Formation and Dalong Formation of wells EJ1 and XY1.

    All samples were pre-processed prior to the start of the experiment using a range of techniques including TOC measurement, XRD, low-pressure N2 and CO2 adsorption, high-pressure CH4 adsorption, mercury injection capillary pressure (MICP) measurement, and field-emission-scanning electron microscopy (FE-SEM) analysis. Samples with fracture calcite veins were treated as doubly polished sections, approximately 300 μm in thickness, for fluid inclusion analysis including petrographic observation and laser Raman spectral measurement.

  • The analysis of TOC content was performed by combustion in a CS-230 analyzer. All samples were crushed to less than 200 mesh and the powder was soaked in HCL solution in order to remove any carbonates. X-ray diffraction (XRD) analysis was carried out using an X'Pert PRO DY2198 X-ray diffractometer to calculate mineral composition.

  • Low-pressure CO2 and N2 adsorption tests were conducted on the 16 samples using a Quantachrome Autosorb iQ surface area analyzer to acquire adsorption-desorption isotherms and to calculate pore volumes. Approximately 1-2 g of 60-80 mesh sample powder was put in tubes and dried at 110 ℃ for 8 h to remove water and other gases. The CO2 adsorption was measured at temperature of 273 K and at 104.5 kPa pressure, while the N2 adsorption was conducted at temperature of 77.3 K and at 97 kPa pressure. The relative pressure (P/P0) of CO2 and N2 adsorption ranged from 0 to 0.32 and 0.01 to 0.99, respectively. Micropores (< 2 nm) were measured by CO2 adsorption using density functional theory (DFT) model. N2 adsorption data was used to measure the mesopore (2-50 nm) and macropore (> 50 nm) using Barrett Joyner Halenda (BJH) model.

    High-pressure CH4 adsorption analysis was performed using a RUBOTHERM isothermal adsorption instrument with maximum pressure of 35 MPa and temperature of 30 ℃. First, approximately 4-5 g of 60-80 mesh sample powder was put in the sample cell and heated to 100 ℃ in a vacuum for 4 h to remove the moisture and impurity gases. The Langmuir equation was used to obtain and fit the isothermal adsorption curve. The experiment could only measure the excess adsorption capacity. Due to the supercritical adsorption, the excess adsorption capacity would decrease with increasing pressure after reaching the maximum value. The excess adsorption capacity was transformed to absolute adsorption capacity according to the relationship proposed by Gibbs (Gibbs, 1948).

  • MICP analysis was performed to investigate pore-throat distribution using a Micromeritics AutoPore Ⅳ 9510 instrument at pressures ranging from 0.034 to 413 MPa. In order to avoid the influence of the sample surface roughness on the experimental results, several samples (XY-3, XY-4, XY-9, XY-11, EJ-2, and EJ-4) were cut into cubes (1×1×1 cm3) with smooth surfaces. The Washburn equation was used to calculate pore-throat size (Washburn, 1921a, b ). The surface tension of mercury was 485 dyne/cm. The contact angle between the mercury and porous media was 130°. The measured pore throat size ranged from 3 nm to 36 μm.

  • Six samples (XY-2, XY-6, XY-10, XY-11, EJ-2, and EJ-4) were selected to investigate the morphology of OM pores using a high-resolution FE-SEM (Zeiss Merlin) instrument equipped with an energy dispersive X-ray spectroscopy (EDS) to determine the elemental composition of the minerals. All the samples were first mechanically grinded and then argon-ion polished using the Leica EM TIC 3X ion-milling technique to create a super-smooth surface. The lowest pixel resolution was approximately 10 nm and the magnification ranged from 10 to 100×103. To enhance the electrical conductivity of the polished surface, all samples were sprayed with a 4 nm thick carbon layer.

  • Two calcite veins samples were selected to study fluid inclusions using a NIKON-LV100 microscope equipped with transmitted white and incident UV sources. Aromatic hydrocarbons and polar compounds in oil inclusions can emit fluorescence under UV light, while gaseous hydrocarbons such as CH4 and C2H6 in gas inclusions cannot emit fluorescence (Zhao et al., 2019). Therefore, oil inclusions can be identified by fluorescence under UV light. The composition of gas inclusions was detected by laser Raman spectrometry using a JY/Horiba LabRam HR800 Raman system. The 300 grooves/mm grating was used to collect the spectra of gas inclusions in the range 1 000-4 000 cm-1. The time needed to acquire the spectrum was approximately 100 seconds to guarantee a high signal-to-noise ratio.

  • The TOC contents of the 16 samples are listed in Table 1. Samples from Dalong Formation in Well XY1 mainly contained Type-Ⅱ OM with TOC ranging from 2.72% to 6.79%. Samples from Longtan Formation in Well XY1 contained mainly Type-Ⅲ OM with TOC ranging from 1.72% to 10.29% (Bao et al., 2016), TOC content of the coal sample was 38.41%. Samples from Dalong Formation in Well EJ1 contained Type-Ⅱ OM with TOC ranging from 5.52% to 11.25% (Qiu et al., 2019). The TOC of samples close to the coal seam increased in Longtan Formation (Fig. 2). The thermal maturity results showed that the Ro of Well XY1 samples ranged from 1.22% to 1.43%, which was assigned to early generation stage of the condensate oil and wet gas. The Ro of Well EJ1 samples ranged from 2.62% to 2.97%, which was assigned to the over-mature stage and generation of dry gas.

    Sample Depth (m) Formation Lithofacies TOC (%) Ro (%) Kerogen type Mineral composition (wt.%)
    Quartz Feldspar Dolomite Calcite Clay Pyrite Other
    XY-1 600.22 Dalong Black calcareous shale 3.69 1.34 60 6 2 10 20 2
    XY-2 602.67 Dalong 2.72 / 63 3 2 23 8 1
    XY-3 608.08 Dalong 4.96 1.22 45 7 4 19 23 2
    XY-4 612.76 Dalong 5.09 1.37 49 7 1 22 18 3
    XY-5 624.87 Dalong 5.07 / 33 7 2 19 36 3
    XY-6 629.59 Dalong 3.13 / 55 4 6 20 13 2
    XY-7 631.18 Dalong 6.79 / 49 5 / 10 33 3
    XY-8 641.78 Dalong 3.00 1.27 29 8 / 38 21 4
    XY-9 685.07 Longtan Grey-black silt mudstone 1.72 / 53 16 / / 31 /
    XY-10 689.10 Longtan Black-mudstone 7.17 / 14 5 / 2 57 / 22 (Siderite)
    XY-11 692.66 Longtan Black mudstone 10.29 1.41 32 3 5 / 60 /
    XY-12 697.81 Longtan Coal 38.41 1.43 40 / / / 48 12
    EJ-1 827.87 Dalong Black shale 5.52 2.62 12 30 / 40 14 2 2 (Gypsum)
    EJ-2 845.00 Dalong 6.14 2.84 70 7 1 8 11 3
    EJ-3 850.75 Dalong 11.25 2.97 76 7 3 9 4 1
    EJ-4 856.46 Dalong 7.62 / 52 10 1 8 26 3

    Table 1.  Basic properties of sixteen samples used in this work. TOC. total organic carbon (%), /. not available

    The mineral compositions of Dalong Formation in the wells XY1 and EJ1s mainly consisted of quartz, carbonate minerals, feldspar, and clay minerals. The clay fraction was the dominant mineral species for Longtan Formation in Well XY1, with almost no carbonate minerals present (Table 1).

  • According to the classification of isotherms proposed by IUPAC (Thommes et al., 2015), the CO2 adsorption isotherms of all 16 samples showed Type-Ⅰ curve characteristics (Figs. 3a-3c). Dalong Formation samples in Well XY1 displayed the least amount of adsorption, while Longtan Formation samples and Dalong Formation samples in Well EJ1 showed a much higher gas adsorption capacity, indicating that these samples had more micropores. Micropore volumes calculated from CO2 adsorption are listed in Table 2. Micropore volumes of Dalong Formation and Longtan Formation in Well XY1 were in the range of 0.002-0.005 and 0.004-0.010 cm3/g, respectively, while Dalong Formation in Well EJ1 had the highest micropore volumes ranging from 0.007 to 0.011 cm3/g.

    Figure 3.  CO2 adsorption (a)-(c) and N2 adsorption and desorption isotherms (d)-(f) of Longtan and Dalong samples determined in wells XY1 and EJ1.

    Sample ID Formation TOC (wt.%) DFT micropore volume (cm3/g) BJH mesopore volume (cm3/g) BJH macropore volume (cm3/g) Hg porosity (%)
    XY-1 Dalong 3.69 0.004 0.003 0.004 /
    XY-2 Dalong 2.72 0.003 0.003 0.004 /
    XY-3 Dalong 4.96 0.005 0.004 0.005 0.53
    XY-4 Dalong 5.09 0.004 0.003 0.007 0.31
    XY-5 Dalong 5.07 0.003 0.002 0.003 0.18
    XY-6 Dalong 3.13 0.002 0.003 0.005 0.26
    XY-7 Dalong 6.79 0.004 0.003 0.004 /
    XY-8 Dalong 3.00 0.003 0.004 0.004 /
    XY-9 Longtan 1.72 0.004 0.007 0.007 1.21
    XY-10 Longtan 7.17 0.010 0.012 0.004 /
    XY-11 Longtan 10.29 0.009 0.013 0.006 1.53
    XY-12 Longtan 38.41 0.010 0.002 0.004 /
    EJ-1 Dalong 5.52 0.007 0.013 0.008 0.85
    EJ-2 Dalong 6.14 0.008 0.013 0.006 2.12
    EJ-3 Dalong 11.25 0.011 0.019 0.013 5.42
    EJ-4 Dalong 7.62 0.010 0.016 0.007 1.63

    Table 2.  N2, CO2 adsorption and MICP results for Longtan and Dalong shales samples. DFT. density functional theory; BJH. Barrett Joyner Halenda method; micropore volume is obtained from CO2 adsorption by DFT; mesopore and macropore volume are obtained from N2 adsorption by DJH; Hg porosity is calculated by MICP

    Figures. 3d-3f show the N2 sorption-desorption isotherms of all 16 samples. According to the classification of isotherms proposed by IUPAC (Thommes et al., 2015), the isotherms of all 16 samples were Type-Ⅱ and Type-IV(a), indicating multi-layer adsorption. Dalong Formation samples in Well EJ1 had the highest amount of adsorption, which was approximately five times higher than that of Dalong Formation samples in Well XY1 and twice as much as that of Longtan Formation samples. From this we inferred that there were more pores present in Dalong Formation of Well EJ1. According to the classification of hysteresis loops proposed by IUPAC (Thommes et al., 2015), the hysteresis loops of Longtan samples in Well XY1 and Dalong samples in Well EJ1 were the mixture of H2(b) and H3 types, while the hysteresis loops of Dalong samples in Well XY1 were assigned to H4 (Fig. 3). All isotherms showed a hysteresis loop, indicating that capillary condensation had occurred in the mesopores. It was obvious that the opening of the hysteresis loops of Dalong samples in Well XY1 were narrow, reflecting relatively small pore size (Fig. 3d). The mesopore and macropore volumes were the highest in Dalong Formation samples from Well EJ1 and lowest in Dalong Formation samples from Well XY1 (Fig. 4).

    Figure 4.  The micropore, mesopore, macropore volume for Longtan and Dalong samples from wells XY1 and EJ1 (calculated from CO2 and N2 adsorption data).

    According to the classification of isotherms proposed by IUPAC (Thommes et al., 2015), the absolute CH4 adsorption isotherms of all the samples show the characteristics of Type I curve (Fig. 5) with varying Langmuir adsorption capacity.

    Figure 5.  High pressure CH4 adsorption isotherms (a)-(c) of Longtan and Dalong samples from wells XY1 and EJ1.

  • Figure 6 shows the curves of the mercury intrusion and extrusion at pressures ranging from 0.034 to 413 MPa. The mercury intrusion volumes of Dalong Formation samples from Well EJ1 were the highest (6.65-8.84 μL/g), which was approximately four times higher than that of Dalong Formation samples from Well XY1 (1.23-2.16 μL/g), and approximately twice as much as that of Longtan Formation samples (4.68-5.65 μL/g). As the mercury intrusion pressure ranged from 0.1 to 1 MPa, the XY-11 sample from Longtan Formation in Well XY1 took a larger volume of mercury than the other samples from Dalong Formation in both wells EJ1 and XY1s (Fig. 6). Therefore, it could be inferred that Longtan sample had more micron-sized pore throats, whereas Dalong sample had more nanoscale pore throats. When intrusion pressure reached 100 MPa, the volumes of mercury injected into Dalong samples of the EJ1 increased significantly (Fig. 6c), reflecting the good connectivity of the nanoscale pore throats. In contrast, the curves determined for Dalong samples from Well XY1 showed the least amount of injected mercury (Fig. 6a), indicating the worst pore development and connectivity. According to the distribution of pore throat histogram, 3-20 nm size pores account for a large proportion of the total pore volumes in Dalong Formation (Figs. 7a, 7b, 7e, 7f), whereas 20-200 nm size pores accounted for a large proportion of the total pore volumes in the Longtan Formation (Figs. 7 b, 7c). Porosity of Dalong samples in Well EJ1 (0.85%-5.41%) was much higher than that of Dalong samples in Well XY1 (0.18%-0.53%), and the porosity development of Longtan samples was between (1.21%-1.53%).

    Figure 6.  Cumulative mercury intrusion and extrusion curves (a)-(c) for Longtan and Dalong samples from wells XY1 and EJ1.

    Figure 7.  Histogram of pore throat diameter distribution of Longtan and Dalong formations shale samples from wells XY1 and EJ1.

  • Many oil inclusions with blue fluorescence were observed in the calcite veins developed in Dalong shales of Well XY1 (Figs. 8b, 8d). Under transmission light, oil inclusions were densely distributed and transparent where the coating wall was thin and clear (Figs. 8a, 8c). Gas inclusions were relatively dark under transmission light and sparsely distributed (Figs. 8a, 8e). Under UV light, a certain proportion of gas inclusions was covered with a thin layer of liquid hydrocarbon inside and emitted weak yellow-green fluorescence (Figs. 8b, 8d). A small number of pure gas inclusions did not emit fluorescence (Figs. 8e, 8f). The laser Raman spectrogram for the gas inclusions in Well XY1 showed a significant CH4 peak at wavelength 2 909.473 9 cm-1, indicating this was a pure CH4 inclusion (Fig. 9a). Except for the CH4 peak, some gas inclusions also presented weak C2H6 peaks (2 879.657 3 and 2 944.351 2 cm-1) on both sides of the CH4 peak (Fig. 9b), indicating that the gas inside was a mixture of gaseous hydrocarbons (CH4 and C2H6). A large number of experimental analyses have confirmed that fluorescence color can be used as an indicator of OM maturity (George et al., 2001; Stasiuk and Snowdon, 1997; Videtich and Roger, 1988). The evolution of OM from low mature to high mature will lead to a change of inclusion type from heavy oil inclusion to condensate oil inclusion. Meanwhile, the fluorescence color emitted will change consistently from red, to yellow, to yellow-green, and to blue (Zhao et al., 2019; Zhao and Chen, 2008). Based on the observation that all oil inclusions show blue fluorescence accompanied by a small amount of gas inclusion, we inferred that there was light oil generated and expelled from the adjacent Dalong Formation shales, which was accompanied by a small quantity of gas due to gas-prone maceral degradation in the kerogen. The characteristics of the hydrocarbon inclusions were also consistent with the measured Ro (1.22%-1.34%) of Dalong samples in Well XY1 (Table 1) which was in the early stage of the condensate oil and wet gas window.

    Figure 8.  Microscopic characteristics of fluid inclusions in calcite veins. (a), (b) The number of oil inclusions is predominated with blue fluorescence, Well XY1, 602 m; (c), (d) oil inclusions with blue fluorescence and gas inclusions with weak yellow-green fluorescence, Well XY1, 602 m; (e), (f) pure gas inclusions with no fluorescence, Well XY1, 602 m; (g), (h) CH4 inclusions Well XY1, 850.75 m.

    All hydrocarbon inclusions observed in calcite veins from Well EJ1 were gas inclusions without fluorescence (Figs. 8g, 8h). The laser Raman spectrogram for all gas inclusions showed a characteristic CH4 peak only (Fig. 9c). The measured Ro of the adjacent Dalong shales ranged between 2.62% and 2.97%, which was in the late stage of the dry gas window. It was inferred that the CH4 inclusions were the product of secondary cracking from the adjacent Dalong shales.

    Figure 9.  Laser Raman spectrograms for gas inclusions from wells XY1 and EJ1.

  • Based on observations of FE-SEM images, the interior of certain OM from Dalong shales of Well XY1 was not homogeneous and could be divided into dark and bright parts with distinct boundaries (Figs. 10a-10d). It is noticeable that spot-like and irregular pores were prone to develop in the light part, while dark part rarely developed observable pores. In addition, the boundary of bright part was irregular and serrated, whereas that of dark part was a regular and smooth curve (Figs. 10a-10d). Some OM partly filled the internal body cavity of the pyritized fossil (Fig. 10g). Many clay mineral flakes were entirely wrapped by OM (Figs. 10e, 10f). A small amount of OM which occurred as discrete particles with sharply defined edges and a relatively homogeneous internal texture can be observed within the mineral matrix (Figs. 10h, 10i).

    Figure 10.  FE-SEM images of OM from Dalong Formation in Well XY1. (a) OM divided into nonporous part (bitumen) and porous part (kerogen) with mesopores, Dalong Formation, Well XY1, 608.08 m; (b) bitumen having spot-like micropores and kerogen having irregular mesopores, Dalong Formation, Well XY1, 608.08 m; (c) OM divided into nonporous part (bitumen) and porous part (kerogen) with micropores, Well XY1, 624.87 m; (d) OM divided into nonporous part (bitumen) and porous part (kerogen) with micropores, Well XY1, 624.87 m; (e) kerogen enclosing plenty of clay mineral flakes, Well XY1, 608.08 m; (f) an enlargement of the rectangle area marked in Fig. 10e, showing a small amount of spot-like micropores, Well XY1, 624.87 m; (g) bitumen filling part of internal body cavity space of pyritized fossil, Well XY1, 608.08 m; (h) terrestrial woody debris with rounded shape and gas-prone kerogen with few micropores, Dalong Formation, XY1, 624.87 m; (i) an enlargement of the rectangle area marked in Fig. 10h, showing filling of bitumen in macropores in terrestrial woody debris (white arrow), Well XY1, 624.87 m.

    Milliken et al. (2013) found a similar phenomenon in Pennsylvania Marcellus shales and interpreted this as wood fragments. Loucks et al. (2017) observed similar OM which was micron-size and nonporous from Yanchang Formation in the Ordos Basin, and interpreted this to be Type Ⅲ woody maceral. In this study, we considered that this kind of OM was terrestrial woody debris derived from the original plant tissue. There was a distinct boundary between two different OM (Figs. 10h, 10i).

    The morphology of OM in Longtan shales of Well XY1 was significantly different from that in Dalong shales. As shown in Fig. 11, the OM in Longtan shales of Well XY1 had a distinct texture with a long strip shape. The boundary of the OM was smooth and regular. Due to compaction, some OM were highly curved and obviously oriented (Figs. 11e, 11f). The pore development in different OM varied considerably. Some OM were nonporous, while the adjacent one may possess a large number of pores, which were filled with quartz and illite (Figs. 11a-11d). Liu et al. (2017) found that vitrinite was nonporous, whereas the interior of inertinite generally had a certain number of circular cellular pores, some of which were filled with authigenic quartz. The sedimentary environment of Longtan Formation was lagoon-swamp facies and almost all OM was from terrestrial inputs. Sample XY-11 was very close to the coal seam at the base of Longtan Formation. Therefore, it was likely that the OM in Longtan Formation samples were all terrestrial woody debris.

    Figure 11.  FE-SEM images of organic matter from Well XY1, Longtan Formation. (a) Terrestrial woody debris with rounded pores, Well XY1, 692.66 m; (b) terrestrial woody debris with rounded pores and some nonporous kerogen debris, Well XY1, 692.66 m; (c) abundant rounded and nano-scale pores, Well XY1, 692.66 m; (d) curved and distorted kerogen debris and long-strip kerogen debris, Well XY1, 692.66 m; (e) an enlargement of the rectangle area marked in Fig. 11d, showing curved and distorted kerogen debris with rounded pores, Well XY1, 692.66 m; (f) kerogen debris with rounded pores, part of which are filled by quartz, Well XY1, 692.66 m.

    The morphology of the OM in Dalong samples of Well EJ1 all showed the characteristics of filling interparticle pores and appeared pervasive throughout the mineral matrix (Fig. 12). Moreover, they had an amorphous shape as well as significant flow structure (Figs. 12e, 12h, 12i). Some OM enclosed mineral grains and clay flakes (Figs. 12c-12e). There were a small number of terrestrial woody debris whose morphology was substantially different from that of the adjacent amorphous OM (Figs. 12g, 12h). There were some differences between the OM in Dalong shales in the two wells. Unlike the OM in Well XY1, which had a granular texture and develop only a small number of pores inside, the interior of the OM in Well EJ1 was almost filled with sponge-like nanopores (Figs. 12a-12c, 12f). As Dalong shales from the two wells had the same type of OM, thermal maturity may have been the determining factor that controled the morphology and inner structure of the OM.

    Figure 12.  FE-SEM images of OM in Well EJ1 Dalong Formation. (a) Pyrobitumen filling pore space within mineral grains, Well EJ1, 827.87 m; (b) an enlargement of the rectangle area marked in Fig. 11a, showing plenty of alveolate, spongy and irregular pores, Well EJ1, 827.87 m; (c) pyrobitumen enclosing clay mineral flakes with abundant nano-scale pores, Dalong Formation, Well EJ1, 856.46 m; (d) pyrobitumen enclosing mineral grains with abundant nano-scale organic pores, Dalong Formation, Well EJ1, 856.46 m; (e) pyrobitumen with flow structure, Well EJ1, 856.46 m; (f) pyrobitumen filling pore space within mineral grains with bubble-like, alveolate and spongy organic pores, 856.46 m; (g) terrestrial woody debris with long-strip shape, Well EJ1, 856.46 m; (h) terrestrial woody debris with rounded pores and pyrobitumen with flow structure, 856.46 m; (i) an enlargement of the rectangle area marked in Fig. 11h, showing distinct boundaries of pyrobitumen and terrestrial woody debris, 856.46 m.

  • FE-SEM images showed OM pores in shale samples from different formations were different in terms of shape, size, and distribution density (Figs. 10-12). The OM pores in Dalong shales of Well XY1 were mainly micropores, sparsely distributed in the OM (Fig. 10). The morphology of the micropores was spot-like, while most mesopores had a irregular shape. A small number of round macropores could be observed in the terrestrial woody debris (Figs. 10h, 10i). Considering the thermal maturity of the samples (Ro=1.22%-1.34%), it could be inferred that the tiny spot-like and irregular OM pores were caused by the generation of gaseous hydrocarbons in gas-prone maceral in kerogen, which was also consistent with the occurrence of a small amount of CH4 inclusion in calcite veins.

    The OM pores in Longtan shales of Well XY1 mainly consisted of mesopores and macropores, and had a relatively rounded shape with well defined-boundaries (Fig. 11). The distribution density of OM pores in different types of debris varied considerably. Some debris developed abundant pores with different sizes, ranging from several nanometers to hundreds of nanometers and even a few micrometers (Figs. 11a-11c), while other debris had only sporadic pores or no pores at all (Figs. 11b, 11d). Xu and Sonnenberg (2017) observed a similar phenomenon in the immature Bakken Shales, indicating that these rounded pores may not be the outcome of thermal evolution. The shape of the strip debris was extremely distorted and twisted, while the internal OM pores were still rounded and equant, implying that this kind of debris was hard enough to resist compaction (Figs. 11d-11e).

    FE-SEM images showed that the irregular and spongy-like pores with diameter ranging from several to hundreds of nanometers were densely developed in the OM from Dalong shales of Well EJ1 (Fig. 12). There was a small number of terrestrial woody debris that had no pores or only a few rounded pores (Figs. 12g, 12i). The higher degree of thermal evolution gave rise to more densely distributed pores in the OM, while the quantitative distribution of pores in the terrestrial woody debris was almost the same as that from the samples from Well XY1, indicating that these rounded pores in the woody debris were not the product of thermal evolution.

  • In the shale samples from Dalong Formation of Well XY1, the FE-SEM images revealed that the OM could be divided into dark part and bright part (Figs. 10a-10d). The dark part generally enclosed mineral grains and occupied the interparticle pore space. Similarly, in the shale samples from Dalong Formation of the Well EJ1, the OM showed the void-filling characteristics, flow structure and enclosure of mineral grains (Figs. 11a-11f). Wood et al. (2018) and Loucks and Reed (2014) documented the exclusive petrographic characteristics of bitumen and pyrobitumen, including void-filling habit, enclosure of minerals, smoothly curved margin and flow structure which can be used to distinguish them from depositional kerogen. The measured Ro of the OM was in the range of 1.22%-1.37%, which was in the early stage of condensate oil and wet gas window. In addition, the occurrence of many light oil inclusions with blue fluorescence was a direct evidence that Dalong shales had generated the liquid-phase oil at their maximum burial depth before uplift. (Fig. 8). In Dalong samples taken from Well EJ1, the presence of pure CH4 inclusions was consistent with the measured Ro of the adjacent Dalong shales (2.62%-2.97%), which was in the later stage of the dry gas window. The OM in Dalong shales had undergone a high degree of thermal evolution and generated a large amount of CH4 during secondary cracking. Considering the thermal maturity, petrographic characteristics, and hydrocarbon inclusions within the calcite veins, it can be inferred that the nonporous dark part in the OM from Dalong shales in Well XY1 was the bitumen or migrated oil expulsed into interpaticle pore spaces from the adjacent oil-prone kerogen, while the OM particles with spongy pores in the OM from Dalong shales of Well EJ1 was pyrobitumen. For the bright part OM with granular texture inside and serrated outline from Dalong shales of Well XY1, we speculated that they were kerogen, and the internal pores were gas-related due to gas-prone maceral degradation.

  • Many previous studies have found that shales in the dry gas window with high TOC tended to develop larger pore volumes due to the conversion of OM into hydrocarbons (Cao et al., 2018; Bernard et al., 2012b; Curtis et al., 2012; Loucks et al., 2009). In the study, the TOC of Dalong shales taken from Well EJ1 had a positive linear relationship with micropore volume and mesopore plus macropore volume with correlation coefficients of 0.84 and 0.94, respectively (Figs. 13a, 13c). This was also consistent with the observations from the FE-SEM images (Fig. 12), where there were abundant OM pores of different sizes, ranging from several nanometers to hundreds of nanometers in the pyrobitumen. In contrast, the TOC of Dalong shales taken from Well XY1 had a weak correlation with micropore volumes and was negatively correlated with mesopore plus macropore volumes (Figs. 13a, 13c). This result was also observed in many other shales in the oil window, indicating that TOC content was not the only factor controlling pore development for the samples in the oil window (Ardakani et al., 2018; Xiong et al., 2016; Zhu et al., 2014; Milliken et al., 2013).

    Figure 13.  Relationship between TOC and pore volume.

    The pore volumes of Longtan shales of Well XY1 showed a positive correlation with the TOC content for samples with low TOC content (Fig. 13b). When the TOC content was higher than 7%, the micropore volume generally remained constant. It was notable that this trend could be observed in both the CO2 and CH4 adsorption. The XY-10, XY-11, and XY-12 samples had approximately the same maximum CO2 and CH4 adsorption capacity (Figs. 3, 5). Moreover, the mesopore plus macropore volumes dramatically decrease and showed a negative correlation with TOC content greater than 10% (Fig. 13d). Similarly, it can be seen from the N2 adsorption isotherm that the adsorption capacity of the coal sample experienced an abrupt drop (Fig. 3). Cao et al. (2018) also noticed that the TOC content increased with porosity before declining after a peak of 6.16% TOC content and explained that the shale samples with higher TOC content tended to contain more nonporous vitrinite, resulting in low pore volumes in high TOC content samples. FE-SEM images showed that there are large differences in the development of pores from different maceral debris in Longtan shales (Fig. 11). Some kerogen debris developed many pores with diameters ranging from several nanometers to hundreds of nanometers and even a few micrometers (Fig. 11c), whereas the adjacent OM were nonporous (Fig. 11b). Therefore, the negative correlation phenomenon, saturation of CO2 and CH4 adsorption capacity and decline of N2 adsorption capacity of the coal sample could be attributed to the change in the proportion of macerals with different primary pore development. We assumed that the shales located close to the coal seam with high TOC content would develop more nonporous woody debris.

    Comparing the XY-7 (Type-Ⅲ) and XY-10 (Type-Ⅱ) samples of which the thermal maturity and TOC were similar, with the exception of the OM type, the micropore and mesopore volumes and gas adsorption capacity of XY-10 was obviously larger than that of XY-7 (Figs. 3, 5; Table 2). As revealed by FE-SEM images, some of terrestrial woody debris in the shale sample from Longtan Formation in Well XY1 had developed many rounded pores with diameter ranging from hundreds of nanometers to a few micrometers, whereas the kerogen from Dalong shales just developed few irregular micropores, sparsely distributed in kerogen. Therefore, it can be concluded that the primary pores in terrestrial woody debris from Longtan shales in Well XY1 might be the reason contribute to lager pore volumes and gas adsorption capacity than those from Dalong shales with similar thermal maturity do.

  • Thermal maturity has been proven to be a predominant factor controlling the formation of OM pores (Guo et al., 2018; Ardakani et al., 2017). In Dalong shales of Well XY1 which was in the early stage of the condensate oil and wet gas window, there was no obvious correlation between TOC content and pore volumes (Figs. 13a, 13c). Comparing the XY-1 and XY-7 samples of which the OM type and mineral compositions were similar, with the exception of the TOC values (3.69% and 6.79%, respectively), the two samples with significant different TOC had the similar volumes of micropores, mesopores, and macropores. In addition, the N2 adsorption capacity of the eight samples from Dalong Formation in Well XY1 which had different TOC content almost coincided with each other (Fig. 3b), indicating that these samples had similar mesopore and macropore volumes. However, by comparing the over-mature sample EJ-2 and sample XY-7, of which the TOC content, OM type, and mineral compositions were almost same, the pore volume and gas adsoption capacity of EJ-2 was obviously larger than that of XY-7.

    Mastalerz et al. (2013) studied the pore structure of Mississippian New Albany shales covering thermal maturity from immature to over-mature, and concluded that the interconnected bitumen network would exert an adverse impact on total pore porosity due to occupying the pore space within the mineral grains. Löhr et al. (2015) found that primary porosity started to decline when in the oil window, and explained this as the masking of pores by retained bitumen. As revealed by FE-SEM images of the samples from Dalong Formation, Well XY1 (Figs. 10a-10d), some interparticle pores were clogged by bitumen. Furmann et al. (2016) found the reduction of porosity with thermal maturity increasing from 0.43% to 0.90% and attributed this to occupation of pore spaces by the increasing bitumen content. The impact of pore occlusion by bitumen has been evaluated by Valenza et al. (2013) who compared the porosity and surface areas of extracted samples with untreated samples which had a thermal maturity ranging from 1.0% to 1.5% (vitrinite reflectance and equivalent determined on bitumen).

    They found that there was a notable increase in surface areas in the extracted samples, and interpreted this phenomenon as the opening of former blocked pore spaces occupied by bitumen. Thus, pore occlusion by bitumen generated in the oil window was one of the predominant factors that caused the reduction in pore volume of samples from Dalong Formation in Well XY1.

    In addition, FE-SEM images (Figs. 10, 13) show that kerogen in Well XY1 mainly developed a small amount of speckled micropores and bituemen was nearly nonporous whereas abundant OM pores with a diameter ranging from several nanometers to hundreds of nanometers were densely distributed in the pyrobitumen in Well EJ1. The generation of gaseous hydrocarbons during secondary cracking have been commonly thought to be the main factor that contributed to the formation of secondary OM pores densely distributed in the nanoporous pyrobitumen (Misch et al., 2019; Bernard et al., 2012a; Curtis et al., 2012). Ding et al. (2019) proposed that the cause of secondary OM pores was gas expansion, and that the secondary OM pores only occurred when the gas expansion force was large enough. Han et al. (2017) noted that during the oil window to gas window, a large number of secondary OM pores were formed, which accounted for a large proportion of the increase in porosity. The OM in Well XY1 did not experience high temperature thermal evolution and only a small number of them were converted into gaseous hydrocarbons, which corresponded with the presence of a small quantity of gas inclusions within the calcite veins. Consequently, it led to the formation of few secondary OM pores. The occlusion of the interparticle pore spaces by bitumen and only formation of a small number of OM pores all contributed to the phenomenon above. Therefore, the increase in pore volumes of Type-Ⅱ shales with maturity was related to the generation of gaseous hydrocarbons and formation of pyrobitumen with numerous pores inside.

    Terrestrial woody maceral debris exhibits completely different pore development characteristics during thermal maturity. For instance, Liu et al. (2017) found that cellular pores in inertinite can be observed in New Albany shales with thermal maturity ranging from 0.55% to 1.41%, while vitrinite was nonporous due to the low H/C ratio and poor hydrocarbon-producing ability. Fishman et al. (2012) observed isolated and rounded pores within the terrestrial kerogen macerals in Kimmeridge Clay Formation mudstone and stated that these OM pores were primarily occurring. As shown by FE-SEM images (Figs. 11, 12), the maceral debris in Longtan shales in the wet gas window had developed denser pores than it did in Dalong shales in the dry gas window. This phenomenon implied that these rounded pores in the kerogen debris were the primary pores inherited from the original plant structure (Figs. 11a-11c, 12h, 12i), and were not the product of thermal evolution.

  • TOC content was generally considered to be the most important factor controlling the CH4 storage capacity of shale because numerous nanopores inside the OM would provide abundant sorption sites for CH4 (Peng et al., 2019; Dang et al., 2017; Liu et al., 2017). Figure 14a shows that Langmuir CH4 adsorption capacity of the sample from Dalong Formation had a positive correlation with TOC content. This positive relationship has also been found in many other studies, indicating that most nanopores are related to the OM (Dang et al., 2017; Xia et al., 2017). However, the CH4 adsorption capacity of sample EJ-1 (TOC=5.52%) was twice that of sample XY-7 (TOC=6.79%). This phenomenon was attributed to thermal maturity, as high thermal maturity samples formed more OM pores with larger surface areas and contributed significantly to the CH4 adsorption capacity. The CH4 adsorption capacity of the samples from Longtan Formation gradually saturated and kept steady with the increase in TOC content when the TOC content was higher than 7.17% (Fig. 14b). The CH4 adsorption capacity saturation phenomenon was related to the differences in OM pore development in samples with a high TOC content. As shown in Figs. 13b, 13d, when the TOC content reached 7.17%, the corresponding micropore volumes did not increase accordingly, while the mesopore plus macropore volumes even showed declining trend. Consequently, the reduction in pore volumes exerted an adverse effect on CH4 adsorption capacity of the samples with high TOC content.

    Figure 14.  Relationship between TOC and methane Langmuir capacity.

  • The geochemical and pore characteristics of Longtan and Dalong Formation samples from Well XY1 and Dalong Formation samples in Well EJ1s were investigated. Based on the results, the following conclusions were reached.

    (1) The measured Ro values for the shales in wells XY1 and EJ1 were in the range of 1.22%-1.43% and 2.62%-2.97%, respectively, indicating that Longtan and Dalong Formation shales in Well XY1 were in the early stage of the condensate oil and wet gas window, while Dalong Formation shales in Well EJ1 were in the later stage of the dry gas window. Many light oil inclusions mixed with a small amount of gas inclusions were found in calcite veins from Dalong Formation in Well XY1, whereas only pure CH4 inclusions were developed in the calcite veins from Dalong Formation in Well EJ1.

    (2) The controlling factor for OM pore development in Dalong shales (Type-Ⅱ) and Longtan shales (Type-Ⅲ) of Well XY1 was OM type. In Longtan shales of Well XY1, some terrestrial woody debris developed many rounded pores with different sizes, ranging from several nanometers to hundreds of nanometers, whereas the kerogen from overlying Dalong shales with similar thermal maturity just developed only a small number of spot-like micropores. The terrestrial woody debris in Type-Ⅲ OM of Longtan shales had more primary pores inherited from original plant organism, which might contribute to larger gas adsorption capacity than that of Dalong shales of Well XY1 did.

    (3) The controlling factor for OM pore development in the shale samples from Type-Ⅱ Dalong Formations in wells XY1 and EJ1 was thermal maturity. In Dalong shales of Well XY1 (Ro= 1.22%-1.43%), the gas-prone maceral with relatively low thermal maturity formed only a small number of spot-like micropores, and the bitumen with rarely observable pore generated from oil-prone maceral also exerted an adverse effect on pore structure by blocking and occupying some of interparticle pore space. In contrast, in Dalong shales of Well EJ1 (Ro=2.62%-2.97%), there were irregular pores, densely developed in the pyrobitumen with diameter ranging from several to hundreds of nanometers. Thermal maturity made a significant contribution to the formation of OM pores, resulting in larger pore volumes and gas adsorption capacity of Type-Ⅱ shale samples in the dry gas window.

  • We would like to thank the National Key R & D program of China (No. 2017YFE0103600), the National Natural Science Foundation of China (Nos. 41830431, 41672139) and the China National Science and Technology Major Projects (No. 2016ZX05034002-003) for financial assistance to this research. The final publication is available at Springer via https://doi.org/10.1007/s12583-019-1237-6.

Reference (72)

Catalog

    /

    DownLoad:  Full-Size Img  PowerPoint
    Return
    Return