CO2 Sequestration [Over-pressure Evolution; Geo-mechanical Stability]
1. The percentage of CO2 emissions captured by CCUS technology @ global-scale has increased from 0.04% in 2000 to 0.12% in 2020. With only a couple of operational large-scale carbon capture and storage facilities globally so far (ACTL-Canada: 15 million metric tons per annum; Petrobras Santos Basin-Brazil: 11), would it remain feasible to store around 10 Gt of CO2 per annum in deep geological formations by 2050?
2. (a) scCO2 (with liquid-like density) still remains to be lighter than the resident brine and makes it easy to float; (b) scCO2 behaving as a low gas-like dynamic viscosity still remains to be lower-viscous than the resident brine and makes it easy to flow. If scCO2 could still float and flow easily with reference to the resident brine, how about its chances of escape in the long run (following CO2 injection, which essentially generates over-pressure; and in turn, reducing the effective stresses, which artificially induces deformations and brings the stress state closure to failure conditions)?
3. In reality, it is extremely difficult to arrest the leakage of CO2 from primary cap-rocks. In a typical sedimentary basin, whether, CO2 trapping from secondary rocks would at some point escape and reach groundwater aquifers (despite maintaining fault stability)?
Practically feasible to avoid (felt) induced seismicity in order to have a successful deployment of geological carbon storage?
4. Do we have a well-defined theory for estimating the evolution of over-pressure build-up (fluid pressure distribution) with time for CO2-brine multi-phase fluid flow (while considering, the compressibility of CO2)?
What exactly drives (driving mechanisms) the evolution of over-pressure followed by CO2 injection?
How exactly to take into account the following:
(a) The buoyant effect of CO2 within the injection well?
(b) In the presence of significant buoyant effect within the injection well, how could we expect the CO2 injection rate would remain to be uniformly distributed along the entire thickness of the injection well?
(c) The fraction of injected CO2 that does not reach the bottom of the storage formation?
5. Whether the injection rate of CO2 at the early stages should preferably be lower in order to avoid a sharp increase in over-pressure (i.e., to avoid encountering, relatively low values of relative permeability to CO2 as the pores start to desaturate) that critically influences the cap-rock stability?
Suresh Kumar Govindarajan
Professor (HAG)
IIT Madras
26-Aug-2024
You do not mention the solubility of CO2 in the brine to be found at the bottom of disused oil and gas wells.
The following article implies that about 35% solubility is to be expected: Article The Solubility of Carbon Dioxide in Water at Various Tempera...
At pressures of more than 150 bar, (above the critical pressure), it is possible that a stable hydrate will be formed, but I am having difficulty finding data on the internet. I think experiments need to be done. I certainly saw a David Attenborough TV programme that showed pools of something at great depths in the ocean which had high concentrations of CO2 ; this may have been a hydrate. The temperature there would be 4 degC .
If hydrates of CO2 do form at elevated pressures and at the temperatures found in the geological formations of disused oil and gas wells, this needs to be investigated. Certainly, it is well known that as oil and gas wells are depleted, CO2 concentrations in the produced oil or gas tend to increase substantially, implying that it lies below the hydrocarbons and may be in solution or in compounds with the brine.
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