Beyond dual-porosity modeling for the simulation of complex flow mechanisms in shale reservoirs
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  • 作者:Bicheng Yan ; Yuhe Wang ; John E. Killough
  • 关键词:Shale reservoir ; Random distribution ; Apparent permeability ; Multiple porosity modeling ; Upscaling
  • 刊名:Computational Geosciences
  • 出版年:2016
  • 出版时间:February 2016
  • 年:2016
  • 卷:20
  • 期:1
  • 页码:69-91
  • 全文大小:3,232 KB
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  • 作者单位:Bicheng Yan (1)
    Yuhe Wang (2)
    John E. Killough (1)

    1. Texas A&M University, College Station, TX, USA
    2. Texas A&M University at Qatar, Doha, Qatar
  • 刊物类别:Mathematics and Statistics
  • 刊物主题:Mathematics
    Mathematical Modeling and IndustrialMathematics
    Geotechnical Engineering
    Hydrogeology
    Soil Science and Conservation
  • 出版者:Springer Netherlands
  • ISSN:1573-1499
文摘
The state of the art of modeling fluid flow in shale reservoirs is dominated by dual-porosity models which divide the reservoirs into matrix blocks that significantly contribute to fluid storage and fracture networks which principally control flow capacity. However, recent extensive microscopic studies reveal that there exist massive micro- and nano-pore systems in shale matrices. Because of this, the actual flow mechanisms in shale reservoirs are considerably more complex than can be simulated by the conventional dual-porosity models and Darcy’s law. Therefore, a model capturing multiple pore scales and flow can provide a better understanding of the complex flow mechanisms occurring in these reservoirs. This paper presents a micro-scale multiple-porosity model for fluid flow in shale reservoirs by capturing the dynamics occurring in three porosity systems: inorganic matter, organic matter (mainly kerogen), and natural fractures. Inorganic and organic portions of shale matrix are treated as sub-blocks with different attributes, such as wettability and pore structures. In kerogen, gas desorption and diffusion are the dominant physics. Since the flow regimes are sensitive to pore size, the effects of nano-pores and micro-pores in kerogen are incorporated into the simulator. The multiple-porosity model is built upon a unique tool for simulating general multiple-porosity systems in which several porosity systems may be tied to each other through arbitrary connectivities. This new model allows us to better understand complex flow mechanisms and eventually is extended into the reservoir scale through upscaling techniques. Sensitivity studies on the contributions of the different flow mechanisms and kerogen properties give some insight as to their importance. Results also include a comparison of the conventional dual-porosity treatment and show that significant differences in fluid distributions and dynamics are obtained with the improved multiple-porosity simulation.

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