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Effect of outer boundary condition, reservoir size, and CO 2 effective permeability on pressure and CO 2 saturation predictions under carbon sequestration conditions

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  • Liwei Zhang
  • Robert M. Dilmore
  • Grant S. Bromhal

Abstract

A TOUGH2 simulation was conducted to investigate how the change of key model parameters affects pressure and CO 2 saturation response to CO 2 injection into a deep CO 2 storage reservoir. Given a domain of 100 × 100 km and a formation permeability of 10-super-−13 m-super-2, outer boundary condition does not have a significant impact on pressure increase and CO 2 saturation results. In a simulation period of 30 years of CO 2 injection + 100 years of post CO 2 injection, with a total CO 2 injection volume of 6.3×10-super-7 m-super-3 at T = 47°C and P = 10.5 MPa (equivalent mass of 30 million tonnes of CO 2 ), there is no pressure difference between the no flow boundary case and the open boundary case given a domain size of 100 x 100 km (a total storage formation pore volume of 10-super-11 m-super-3 at T = 47°C and P = 10.5 MPa), and the maximum CO 2 plume radius difference is 0.5%. However, given a domain size of 10 × 10 km, outer boundary condition significantly affects pressure simulation results. At t = 130 years, the pressure increase in the no flow boundary case is 56.5 times of the pressure increase in the open boundary case at the cell 50 m away from the injection well. For the 10 × 10 km case, the impact of outer boundary condition on CO 2 saturation results is relatively small. The change in formation permeability significantly affects pressure increase results, while the change in CO 2 relative permeability model only affects pressure increase results at cells close to the CO 2 injector. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd

Suggested Citation

  • Liwei Zhang & Robert M. Dilmore & Grant S. Bromhal, 2016. "Effect of outer boundary condition, reservoir size, and CO 2 effective permeability on pressure and CO 2 saturation predictions under carbon sequestration conditions," Greenhouse Gases: Science and Technology, Blackwell Publishing, vol. 6(4), pages 546-560, August.
    • Handle: RePEc:wly:greenh:v:6:y:2016:i:4:p:546-560
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    File URL: http://hdl.handle.net/10.1002/ghg.1586
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    Cited by:

    1. Jing, Jing & Yang, Yanlin & Tang, Zhonghua, 2021. "Assessing the influence of injection temperature on CO2 storage efficiency and capacity in the sloping formation with fault," Energy, Elsevier, vol. 215(PA).
    2. Liwei Zhang & Robert Dilmore & Nicolas Huerta & Yee Soong & Veronika Vasylkivska & Argha Namhata & Yan Wang & Xiaochun Li, 2018. "Application of a new reduced‐complexity assessment tool to estimate CO2 and brine leakage from reservoir and above‐zone monitoring interval (AZMI) through an abandoned well under geologic carbon stora," Greenhouse Gases: Science and Technology, Blackwell Publishing, vol. 8(5), pages 839-853, October.
    3. Ram Kumar & Scott Campbell & Eric Sonnenthal & Jeffrey Cunningham, 2020. "Effect of brine salinity on the geological sequestration of CO2 in a deep saline carbonate formation," Greenhouse Gases: Science and Technology, Blackwell Publishing, vol. 10(2), pages 296-312, April.
    4. Emad A. Al†Khdheeawi & Stephanie Vialle & Ahmed Barifcani & Mohammad Sarmadivaleh & Yihuai Zhang & Stefan Iglauer, 2018. "Impact of salinity on CO2 containment security in highly heterogeneous reservoirs," Greenhouse Gases: Science and Technology, Blackwell Publishing, vol. 8(1), pages 93-105, February.

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