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.
| Published in | Earth Sciences (Volume 7, Issue 5) |
| DOI | 10.11648/j.earth.20180705.13 |
| 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), 2018. Published by Science Publishing Group |
CO2 Storage, Flow Simulation, Geomechanical Modeling, Saline Aquifer
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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
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
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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Download@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://article.sciencepublishinggroup.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}
}
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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