Mansour Soroush, NTNU; Dag Wessel-Berg, SINTEF Petroleum; Ole Torsaeter,
Amir Taheri and Jon Kleppe, NTNU
After injecting CO2 into subsurface brine for storage, it will be trapped in
the reservoir through various mechanisms. In the beginning, the geological
trapping mechanism dominates and the CO2 plume is moving upward below a cap
rock. Then brine will imbibe the formation and some parts of the CO2 will be
trapped in the pore paces. Later on injected CO2 will dissolve in the brine and
increases its density. As a result, the heavier brine will move into deeper
parts of the reservoir and density driven convection mixing will occur. This is
known as the solubility trapping mechanism.
Here in this study, density driven phenomena in CO2 storage in brine and the
influencing parameters are the prime targets. We find particularly interesting
results for this through Hele-Shaw cell experiments and numerical simulations.
Hele-Shaw flow is defined to occur between two parallel flat plates separated
by a small gap. In each experiment the cell is filled with fresh water and a
shim prevents it to leak. Then liquid with higher density is placed on top.
Several tests including water of varying salinity at the top of the cell have
been conducted, and the results are interpreted separately and compared with
the base experiment.
More extensive studies and sensitivity analysis is done based on a simulation
model constructed on the reservoir properties of a brine formation, with wide
range of affecting parameters, including density differences, permeability
variations and the effect of diffusion coefficients. It has been also attempted
to investigate the effect of anisotropy and heterogeneity on the CO2 state
Possible risks of increasing greenhouse gases in the atmosphere have motivated
feasibility studies of geological storage of CO2 that is produced by different
industrial sources including power plants, refineries, cement factories and
other sources. This study deals with processes that occur during CO2 storage in
brine formations. There are other potential storage sites including depleted
oil and gas reservoirs, coal beds, but the main motivation for using brine
formation as storage site for CO2 is availability and possible larger volume
that will results in reduction in transmission cost (Benion and Bachu, 2005).
The main challenge is how to use these brine formations that provide the
largest potential capacity to store CO2 (Benson, 2008).
In CO2 storage, after injecting CO2 into the brine it will trap in to the
reservoir through various mechanisms. Each trapping mechanism has different
timescale. In the beginning the structural and geological trapping mechanism
dominates, which is the trapping of the CO2 plume moving upward below a cap
rock (IPCC report, 2005).
After CO2 injection and movement of CO2 upward, brine will imbibe the formation
bearing the injected CO2 and some fraction of the gas will be trapped in the
pore spaces. Capillary forces prevent complete drainage of CO2 and this
residual saturation remains trapped in the pores. Depending on the salinity,
pressure and temperature range and heterogeneities of brine formation, and
other reservoir parameters, injected CO2 will dissolve more and more in the
brine and increases its density. As a result, the heavier brine will move into
deeper parts of the reservoir and convection driven movement will be activated.
This mechanism is called the solubility trapping mechanism. Finally, a fraction
of the CO2 may be converted to stable carbonate minerals. This process is
called mineral trapping. Mineral trapping is believed to be a comparatively
slow process, potentially taking thousand years or longer (IPCC report,