CO2 Sequestration in Deep Saline Aquifers
1. In the context of long term fate of CO2, why does most of the injected CO2 prefer to remain within a radius of 3 km laterally?
2. In the long run, whether, structural/stratigraphic trapping can be ignored with reference to hydrodynamic, solubility, residual & mineral trapping?
3. If structural/stratigraphic trapping plays a vital role during early phase of CO2 injection, then, can we expect a substantial amount of ‘free scCO2’ during the injection period (of 5/10/20 years)?
4. How quickly, the mass of CO2 dissolved in the brine gets enhanced upon ceasing CO2 injection?
5. When exactly the convective mixing between CO2-saturated brine and unsaturated brine is expected to commence; and how long will it prolong?
6. How long buoyant forces are expected to dictate the CO2 migration and trapping?
7. Do we have a clear delineation between the periods of dominant buoyant forces; dominant capillary forces; dominant viscous forces?
Or
CO2 plume spread will always be dictated by a combination of all the above forces?
8. Upon injecting CO2 into deep saline formations, it tends to migrate upwards due to dominant buoyant forces (density of scCO2 still lower than brine density).
How quickly, vertically migrated CO2 will try to dissolve into brine, in the upper portions of the aquifer?
And, how quickly does the increasing acidity induce mineral dissolution and complexing with dissolved ions (towards forming bicarbonates)?
To what extent, such dissolution complexing processes would tend to enhance CO2 solubility, an in turn, solubility trapping?
9. With time, most of the free CO2 gas getting accumulated below the cap-rock, and then spreading laterally, what would be the fraction of CO2 that remains associated with capillary trapping?
10. How does the thickness of perforations in the injection well (@ bottom of the permeable formation between impermeable layers in vertical direction) dictate the resulting CO2 plume spread?
(a) bottom one-fifth of the injection well remaining perforated;
(b) bottom one-fourth of the injection well remaining perforated.
11. How does CO2 injection rate would dictate the resulting CO2 plume spread?
(a) @ a constant rate of 0.5 Mt/year for 20 years;
(b) @ a constant rate of 1 Mt/year for 10 years;
(c) @ a constant rate of 0.5 Mt/year for 10 years;
(d) @ a constant rate of 1 Mt/year for 20 years.
12. During CO2 injection period, how exactly to capture the evolution of porosity and permeability changes resulting from kinetic mineral precipitation/dissolution; and its associated instability in fluid dynamics?
Feasible to capture the associated convective mixing?
Dr Suresh Kumar Govindarajan
Professor[HAG]
IIT-Madras
26-Feb-2025
Suresh Kumar Govindarajan
Most of the injected CO₂ remains within a lateral radius of approximately 3 km within the reservoir due to several geological and physical factors:
Due to these factors, most of the injected CO₂ remains within a relatively confined area around the injection site, typically within a 3 km radius, unless geological conditions allow for further expansion.
In the context of the long-term fate of injected CO2, especially in geological sequestration scenarios such as carbon capture and storage (CCS), most of the injected CO2 tends to remain within a lateral radius of about 3 km from the injection point primarily due to the interplay of several geological and physical factors:
1. The geological formations selected for CO2 storage typically have specific characteristics in terms of permeability and porosity that are conducive to containing fluids within a confined space. These properties influence how the CO2 moves through the rock matrix and help to limit its lateral spread.
2. This occurs when CO2, injected as a supercritical fluid, moves through the pore spaces of the rock and gets trapped by capillary forces within those pores. This process effectively immobilizes the CO2, preventing it from migrating far from the injection site.
3. Supercritical CO2 is less dense than the brine commonly found in deep geological formations, giving it a tendency to rise towards the surface. However, the relatively high viscosity and the confining pressure at depth also serve to slow down its lateral movement, confining it largely to the area near the injection well.
4. Structural features such as faults, folds, or impermeable rock layers (cap rocks) can act as barriers that restrict the lateral and vertical migration of CO2. These geological barriers are critical in defining the extent of the area where CO2 can reside.
5. The presence of groundwater flow can influence the movement of CO2. In some cases, the natural flow of groundwater can help to contain the CO2 within a certain radius by creating a dynamic equilibrium that limits its spread.
6. Continuous injection of CO2 leads to an increase in pressure within the formation. This pressure build-up can reduce the mobility of CO2 by decreasing its effective permeability, thereby confining it to the vicinity of the injection zone.
These factors collectively contribute to the phenomenon where injected CO2 predominantly remains within a limited lateral distance from its point of injection, enhancing the predictability and safety of CO2 sequestration projects.
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