CarbonNet report principles of geomechanics and CO2 storage: A step towards best practice
Contributed by: Dr Chris Consoli, Senior Consultant - Storage
A CarbonNet Project study shows that their storage site would not be prone to seismicity and that the selected site is suitable for the permanent storage of CO2.
The CarbonNet Project is investigating the feasibility of a commercial scale CCS network. Bringing together multiple sources within the Latrobe Valley into a shared distribution network for injection into the nearshore Gippsland Basin.
The study published on the Global CCS Institute’s website titled “Principles for Best Practice Geomechanics for CCS Injection Operations and its Application to the CarbonNet Project”, found the basin in which the CarbonNet Project site is targeting has the ideal geological conditions for storage.
To reach those conclusions, the Project’s authors outlined a series of guidelines which could potentially impact the stability of a hypothetical storage site. Those guidelines were then applied to the CarbonNet Project. The study found that the Gippsland Basin, which will host the CO2 in a nearshore site has very thick and extensive storage formations, which have become depleted in pressure from years of water extraction for farming, coal mining, and oil and gas production. This means that despite the basin being under stress, large-scale injection (5 million tonnes per annum of CO2) would not fracture the injection zone or surrounding geology. The depleted storage formation according to modelling will enable the target injection capacity of 125 million tonnes of CO2 to be achieved without causing any instability.
It is envisaged that these guidelines could form the basis of future site selection and operational best practices. Following these guidelines will enable all future CO2 storage operations to inject and store CO2 under safe conditions and ensure permanent storage.
Modelled pressure response after 125 Mt of injection at the CarbonNet Project's potential storage site. Note the total amount pressure increase is 16 bars, which is below the threshold which results in geological instability.
Geomechanical instability in the form of fracture and fault movement can occur from the injection and buoyancy-driven migration of CO2. This is caused by increasing formation fluid pressure on the storage formation’s rock matrix and the rock matrix of the overlying caprocks.
“A small proportion (about 10 per cent) of active injection wells experience some degree of geomechanical instability, evidenced by induced seismic events (Weingarten et al, 2015).” CarbonNet report.
To avoid fracturing the rock matrix, the injection pressure must be below the weakest failure pressure of the rock, known as the Mohr-Coulomb failure threshold. Increasing pressures beyond the threshold can result in mechanical failure of the rock resulting in shear-slip on existing fractures, and ultimately the creation of new fractures. Moreover, not only is the area immediately around the injection zone affected, but buoyancy pressure due to the migrating CO2 means the pressure increase will extend over the entire CO2 plume and will continue post-injection.
However, changes in pressure and the effect on rock strength are a well-known factor in all industries that deal in the subsurface, particularly the oil and gas industry.
This has led to the development of simple monitoring tools, such as pressure and temperature recorders, at the wellhead and in the well itself. Of the 150 sites that are injecting CO2, there have been few reported cases of leakage being caused by geomechanical stability. It is one easily manageable factor in most geologic basins, but cannot be overlooked.