A study of safe CO₂storage capacity in saline aquifers: a numerical study

Abstract

SUMMARY An effective way of reducing greenhouse gas content in the atmosphere is carbon dioxide (CO2) geo‐sequestration in saline aquifers. The main objective of this study is to develop a 3‐D numerical model to identify the optimum CO2 storage capacity in saline aquifers by studying the factors affecting it and the possibility of the injected CO2 back‐migrating into the atmosphere. A 1000m×1000m×184 m saline aquifer, lying 800 m below the ground surface, was therefore considered to develop a model using the COMET 3 reservoir simulator. The effects of injecting CO2 properties (injection pressure) and the aquifer's properties (depth, temperatures and salinity) on the CO2 storage capacity were examined first. According to the results of the model, CO2 storage capacity increases with increasing injection pressure and salinity and decreasing depth and temperature, and 100% variations in injection pressure, depth, temperature and salinity levels cause the CO2 storage capacity to be changed by 54%, 36%, 18% and 1.8%, respectively. The next stage of the study involved the determination of cap rock failure due to CO2 injection pressure and the identification of the factors influencing it. A detailed parametric study was conducted, with changes to the depth, temperature and salinity with respect to injection pressure, to detect the effects of these factors on the optimum CO2 injection pressure. According to the results, optimum CO2 injection pressure clearly depends on the aquifer depth and the effects of salinity and temperature are negligible. An increment of 0.8 to 1.4 km in aquifer depth causes the optimum injection pressure to be increased from 19.55 to 42 MPa, which is about 105 and 107 higher than the effects of temperature (20 to 110 °C increment) and salinity level (100,000 to 160,000 ppm increment), respectively. The model can be used effectively in field studies to safely enhance CO2 storage capacity in saline aquifers. Copyright © 2012 John Wiley & Sons, Ltd.

CO2-induced mechanical behaviour of Hawkesbury sandstone in the Gosford basin: An experimental study

“…In many sequestration projects, the injection of CO 2 is the most important step, and needs to be carefully conducted and monitored for the longterm integrity of the sequestration project. The captured CO 2 is injected into the aquifer in a compressed form as a super-critical phase fluid (temperatureZ31.48°C, pressureZ7.38 MPa [33]). The injected CO 2 is then trapped in the aquifer through a number of mechanisms including solubility trapping, residual trapping, mobility trapping and mineral trapping, with solubility trapping being the dominant trapping mechanism for rock mineral alteration, while mineral trapping makes a small contribution to rock mineral alteration [10] during CO 2 sequestration.…”

CO2/brine/rock interactions in Lower Tuscaloosa formation

“…Candidate geological formations for possible CO 2 sequestration include: depleted oil and gas reservoirs, unmineable coal seams, basalt formations, shale intervals, and deep saline aquifers . Recent studies have been reported regarding the sequestration of CO 2 in geological formations, including a storage capacity estimate for saline aquifers, effects on coal, coupling with enhanced oil recovery, and a modeling study of CO 2 storage project in the Cranfield reservoir, Mississippi . The greatest estimated capacity for CO 2 sequestration is reportedly in deep saline aquifers…”

“…2 Recent studies have been reported regarding the sequestration of CO 2 in geological formations, including a storage capacity estimate for saline aquifers, effects on coal, coupling with enhanced oil recovery, and a modeling study of Original Research Article: CO 2 /brine/rock interactions in Lower Tuscaloosa formation Y Soong et al CO 2 storage project in the Cranfield reservoir, Mississippi. [3][4][5][6][7] The greatest estimated capacity for CO 2 sequestration is reportedly in deep saline aquifers. 8 The Lower Tuscaloosa formation in the Southeast region of the USA is recognized as a promising candidate reservoir for carbon sequestration.…”

Understanding the significance ofin situcoal properties for CO2sequestration: An experimental and numerical study

“…The COMET3 numerical simulator is effectively used to understand CO 2 storage in subsurface reservoirs . In this study, flow rate was estimated using the COMET3 numerical simulator.…”

“…where Q is the gas flow rate (m 3 /s), dP/dt is the pressure gradient over time (MPa/s), V is the downstream volume (m 3 ) and b is the adiabatic compressibility of the gas (1/MPa). The COMET3 numerical simulator is effectively used to understand CO 2 storage in subsurface reservoirs [19]. In this study, flow rate was estimated using the COMET3 numerical simulator.…”