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Coupled Flow Simulation and Geomechanical Modeling on CO2 Storage in a Saline Aquifer

Received: Jul. 23, 2018    Accepted: Sep. 03, 2018    Published: Sep. 28, 2018
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Abstract

As an option to mitigate the increasing level of greenhouse gas emission, a number of Carbon Capture and Storage (CCS) testing and pilot projects have been brought up all over the world. In general, there are three types of CO2 storage formations, such as deep saline aquifers, depleted oil and gas reservoirs, and un-mineable coal seams. This study is focused on the deep saline aquifer which has the largest potential for CO2 storage. There are a lot of uncertainties associated with this type of storage, such as storage capacity, geomechanical properties, and sealing behaviour of the caprock. Pressure (and temperature) changes during CO2 injection and storage can have significant impact on the stress and strain field and may cause relevant geomechanical problems. This paper shows a case study of a synthetic saline aquifer storage site, where a 15-year injection at a rate of 15 MT/year was simulated. Sealing performance and leakage risk were evaluated. A number of sensitivity studies were conducted to analyse the impacts of different rock properties on CO2 leakage potentials. Coupled flow simulation and geomechanical modeling was performed to monitor stress-strain evolutions and to predict failure potentials in response to pressure changes during CO2 injection and storage. The findings show that CO2 leakage is most sensitive to caprock permeability. Other factors such as reservoir properties, boundary conditions, and perforation intervals also have certain degree of influence on the leakage. During the 15-year injection, there is no significant risk of potential failure; however, this may happen in local area due to formation heterogeneity.

DOI 10.11648/j.earth.20180705.13
Published in Earth Sciences ( Volume 7, Issue 5, October 2018 )
Page(s) 216-226
Creative Commons

This is an Open Access article, distributed under the terms of the Creative Commons Attribution 4.0 International License (http://creativecommons.org/licenses/by/4.0/), which permits unrestricted use, distribution and reproduction in any medium or format, provided the original work is properly cited.

Copyright

Copyright © The Author(s), 2024. Published by Science Publishing Group

Keywords

CO2 Storage, Flow Simulation, Geomechanical Modeling, Saline Aquifer

References
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[2] Underschultz, J., D. Kevin, M. Karsten, S. Sandeep, W. Terry, and W. Steve, 2017, Carbon capture and storage, Sustainability in the mineral and energy sectors, United States: Taylor & Francis Group, p. 437-452, doi: 10.1201/9781315369853-24.
[3] Metz, B., O. Davidson, H. De Coninck, M. Loos, and L. Meyer, 2005, IPCC Special Report on Carbon Dioxide Capture and Storage: Cambridge University Press, doi:10.1021/es200619j.
[4] Rutqvist, J., 2012, The Geomechanics of CO2 Storage in Deep Sedimentary Formations: Geotechnical and Geological Engineering, v. 30, no. 3, p. 525–551, doi: 10.1007/s10706-011-9491-0.
[5] Joshua A., L. Chiaramonte, S. Ezzedine, W. Foxall, Y. Hao, A. Ramirez, and W. McNab, 2014, Geomechanical behavior of the reservoir and caprock system at the In Salah CO2 storage project, PNAS, doi: 10.1073/pnas.1316465111.
[6] Andersen, O.A., H.M. Nilsen, S.E. Gasda, 2017, Vertical Equilibrium Flow Models with Fully Coupled Geomechanics for CO2 Storage Modeling, Using Precomputed Mechanical Response Functions, Energy Procedia, v. 114, p. 3113-3131, doi: 10.1016/j.egypro.2017.03.1440.
[7] Mathieson, A., J. Midgely, I. Wright, N. Saoula, and P. Ringrose, 2011, In Salah CO2 storage JIP: CO2 sequestration monitoring and verification technologies applied at Krechba, Algeria: Energy Procedia, v. 4, p. 3596–3603, doi:10.1016/j.egypro.2011.02.289.
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[11] Pickup, G. E., M. Jin, P. Olden, E. J. Mackay, and M. Sohrabi, 2011, A Sensitivity Study on CO2 Storage in Saline Aquifers, in SPE EUROPEC/EAGE Annual Conference and Exhibition: Society of Petroleum Engineers, p. SPE143054, doi:10.2118/143054-MS.
[12] Leverett, M. C., 1940, Capillary Behavior in Porous Solids: Spe, v. SPE 941152, p. 152 – 169.
[13] Mathias, S., 2012, ANNEX A2: CO2 Storage Liabilities in the North Sea – An Assessment of Risks and Financial Consequences -- Cap Rock Study.
[14] Hou, Z., M. L. Rockhold, and C. J. Murray, 2012, Evaluating the impact of caprock and reservoir properties on potential risk of CO2 leakage after injection: Environmental Earth Sciences, v. 66, p. 2403–2415, doi:10.1007/s12665-011-1465-2.
[15] Zimmer, M. A., 2003, Seismic velocities in unconsolidated sands: Measurements of pressure, sorting, and compaction effects: Stanford University.
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[17] Ajienka, J., F. Egbon, and U. Onwuemena, 2009, Deep Offshore Fracture Pressure Prediction in the Niger Delta – A New Approach, in the 33rd Annual SPE International Technical Conference and Exhibition: p. SPE 128339.
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[19] Olden, P., G. Pickup, M. Jin, E. Mackay, S. Hamilton, J. Somerville, and A. Todd, 2012, Use of rock mechanics laboratory data in geomechanical modelling to increase confidence in CO2 geological storage: International Journal of Greenhouse Gas Control, v. 11, p. 304–315, doi:10.1016/j.ijggc.2012.09.011.
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  • APA Style

    Lu Ji. (2018). Coupled Flow Simulation and Geomechanical Modeling on CO2 Storage in a Saline Aquifer. Earth Sciences, 7(5), 216-226. https://doi.org/10.11648/j.earth.20180705.13

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    ACS Style

    Lu Ji. Coupled Flow Simulation and Geomechanical Modeling on CO2 Storage in a Saline Aquifer. Earth Sci. 2018, 7(5), 216-226. doi: 10.11648/j.earth.20180705.13

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    AMA Style

    Lu Ji. Coupled Flow Simulation and Geomechanical Modeling on CO2 Storage in a Saline Aquifer. Earth Sci. 2018;7(5):216-226. doi: 10.11648/j.earth.20180705.13

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  • @article{10.11648/j.earth.20180705.13,
      author = {Lu Ji},
      title = {Coupled Flow Simulation and Geomechanical Modeling on CO2 Storage in a Saline Aquifer},
      journal = {Earth Sciences},
      volume = {7},
      number = {5},
      pages = {216-226},
      doi = {10.11648/j.earth.20180705.13},
      url = {https://doi.org/10.11648/j.earth.20180705.13},
      eprint = {https://download.sciencepg.com/pdf/10.11648.j.earth.20180705.13},
      abstract = {As an option to mitigate the increasing level of greenhouse gas emission, a number of Carbon Capture and Storage (CCS) testing and pilot projects have been brought up all over the world. In general, there are three types of CO2 storage formations, such as deep saline aquifers, depleted oil and gas reservoirs, and un-mineable coal seams. This study is focused on the deep saline aquifer which has the largest potential for CO2 storage. There are a lot of uncertainties associated with this type of storage, such as storage capacity, geomechanical properties, and sealing behaviour of the caprock. Pressure (and temperature) changes during CO2 injection and storage can have significant impact on the stress and strain field and may cause relevant geomechanical problems. This paper shows a case study of a synthetic saline aquifer storage site, where a 15-year injection at a rate of 15 MT/year was simulated. Sealing performance and leakage risk were evaluated. A number of sensitivity studies were conducted to analyse the impacts of different rock properties on CO2 leakage potentials. Coupled flow simulation and geomechanical modeling was performed to monitor stress-strain evolutions and to predict failure potentials in response to pressure changes during CO2 injection and storage. The findings show that CO2 leakage is most sensitive to caprock permeability. Other factors such as reservoir properties, boundary conditions, and perforation intervals also have certain degree of influence on the leakage. During the 15-year injection, there is no significant risk of potential failure; however, this may happen in local area due to formation heterogeneity.},
     year = {2018}
    }
    

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  • TY  - JOUR
    T1  - Coupled Flow Simulation and Geomechanical Modeling on CO2 Storage in a Saline Aquifer
    AU  - Lu Ji
    Y1  - 2018/09/28
    PY  - 2018
    N1  - https://doi.org/10.11648/j.earth.20180705.13
    DO  - 10.11648/j.earth.20180705.13
    T2  - Earth Sciences
    JF  - Earth Sciences
    JO  - Earth Sciences
    SP  - 216
    EP  - 226
    PB  - Science Publishing Group
    SN  - 2328-5982
    UR  - https://doi.org/10.11648/j.earth.20180705.13
    AB  - As an option to mitigate the increasing level of greenhouse gas emission, a number of Carbon Capture and Storage (CCS) testing and pilot projects have been brought up all over the world. In general, there are three types of CO2 storage formations, such as deep saline aquifers, depleted oil and gas reservoirs, and un-mineable coal seams. This study is focused on the deep saline aquifer which has the largest potential for CO2 storage. There are a lot of uncertainties associated with this type of storage, such as storage capacity, geomechanical properties, and sealing behaviour of the caprock. Pressure (and temperature) changes during CO2 injection and storage can have significant impact on the stress and strain field and may cause relevant geomechanical problems. This paper shows a case study of a synthetic saline aquifer storage site, where a 15-year injection at a rate of 15 MT/year was simulated. Sealing performance and leakage risk were evaluated. A number of sensitivity studies were conducted to analyse the impacts of different rock properties on CO2 leakage potentials. Coupled flow simulation and geomechanical modeling was performed to monitor stress-strain evolutions and to predict failure potentials in response to pressure changes during CO2 injection and storage. The findings show that CO2 leakage is most sensitive to caprock permeability. Other factors such as reservoir properties, boundary conditions, and perforation intervals also have certain degree of influence on the leakage. During the 15-year injection, there is no significant risk of potential failure; however, this may happen in local area due to formation heterogeneity.
    VL  - 7
    IS  - 5
    ER  - 

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  • Sinopec Star Petroleum Corporation Limited, Beijing, China

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