CO2 Sequestration in Deep Saline Aquifers

1. How approximate would it remain to be, modelling the injection of CO2 into Deep Saline Aquifer (DSA) as a single-phase radial encroachment, having known that injection of CO2 into DSA remains to be a multi-phase flow phenomenon, where a slightly compressible scCO2 drives the brine radially outward, while, also migrating upward due to buoyancy?

2. Since, the injection and radial migration of an immiscible CO2-phase into an initially brine saturated formation involves simultaneous flow of CO2 and brine, can we still simply model a steady-state injection of CO2 as a super-critical fluid using Darcy’s law?

3. Is it not necessary to couple CO2 dissolution and buoyant floating in order to deduce their combined effect on the final distribution of CO2 (as only a fraction of the total injected volume of CO2 would remain to be available to float towards the top, while the remaining volume of CO2 remains dissolved in the resident brine phase)?

4. How exactly to deduce the relative permeability values towards estimating the velocity with which the buoyant floating of CO2 occur at any given radius?

5. Whether the radial velocity in the near field would always remain to be larger than the vertical velocity component?

6. How approximate would it remain to be, modeling the dissolution of free phase CO2 in the formation water as an instantaneous equilibrium dissolution process?

7. Which of the following 3 pathways would remain to be more significant, towards estimating the escape of CO2 due to leakage through the confining layers?

(a) vertical migration as a free phase through fractures;

(b) buoyancy driven flow through permeable zones of a brine saturated cap rock;

(c) diffusion as a dissolved phase through a brine saturated cap rock.

8. How exactly to deduce the thickness of CO2 bubble floating near the top confined layer, towards estimating the vertical buoyant pressure exerted on the top confining layer by CO2 bubble floating at the top?

9. How exactly, the effect of injection pressure and permeability remain to have a correspondence with that of the injection rate?

10. Since, the injection rate remains to be an important operational variable that has a significant impact on the cost, safety, duration and ultimate success of any deep well injection operation, how exactly a deep well injection operation running with the injection rate remain to differ from that of running with the injection pressure held constant?

11. Whether CO2 injection rate directly determines the total mass of carbon sequestered in any period of time and the rate of growth of the CO2 bubble around the injector?

12. Given the operational limits set on the injection pressures, to avoid fracture, initiation of seismic events or well blow out, whether, will it always remain to be advantageous to inject CO2 at high rates to achieve a larger radius of review around the injector, which may also result in access to a larger formation volume for ultimate mineral sequestration?

13. Whether formation porosity directly determines the total sequestration capacity of the formation?

14. Whether formation permeability directly determines the feasible rate of injection within the constraints on the injection well’s operational pressure?

15. Whether the effect of an increase in permeability would remain to be qualitatively similar to that of increasing the rate of CO2 injection?

16. Whether a formation with the lower porosity requires a larger area of review to capture the same injected volume of CO2?

17. Whether the dissolution of CO2 would likely remain to be a rate limited process, governed by the morphology of the CO2–brine contact, CO2 phase pressure, temperature and the brine composition?

Or,

a rate limited dissolution model using a variable CO2 dissolution rate would be required to simulate the dissolution non-equilibrium?

18. To what extent, fluid injection wells remain to lose their initial injectivity due to the plugging of formation around the injector by particles, oil droplets and precipitates? Whether the resulting formation damage and injectivity decline would be of concern?

In such cases, what would be the effect of mineral trapping of CO2 on injectivity decline?

19. Feasible to simulate experimentally, the way, the injected CO2 initially grows as a bubble radially outward; and the way, the bubble eventually dissolving in the formation brine, and then, floating towards the top due to buoyancy, and then, settling near the top confining layer?

20. Whether, an increase in injection rate would always increase the dimensions of the bubble and, eventually, would increase, the total volume of CO2 sequestered?

Dr Suresh Kumar Govindarajan

Professor [HAG]

IIT Madras

13-March-2025