What is site selection and monitoring of geologic CO2 storage?
Several technological carbon removal pathways, including direct air capture and bioenergy with carbon capture and storage, depend on geologic storage for permanent removal of captured CO2, as does point source carbon capture, for example, on power plants. There are two general processes used for geologic storage: the first involves the injection of captured CO2 into suitable underground geologic formations that can store CO2 in their pore spaces and prevent it from leaking. The second is injection of CO2 into certain types of rock rich in magnesium and calcium where the CO2 reacts to form solid carbonate minerals (e.g., calcite, magnesite, etc.) that permanently store it in solid form.
In the former, CO2 can be injected into geologic formations like saline aquifers, where it is stored permanently. CO2 can also be permanently stored as part of the process of enhanced oil recovery (EOR), where it is injected to produce additional oil from oil reservoirs. This has been practiced for decades, but the goal is generally oil production rather than carbon removal so the storage is incidental. (CO2 may also be injected into depleted oil and gas reservoirs not associated with EOR.)
When storing CO2 in geologic formations, selection of a suitable site and monitoring after injection are needed to ensure that injected CO2 is not leaking to the surface or into drinking water supplies. Other technological removal processes, like some variations of mineralization, can capture and store CO2 in the same step. And utilization of captured CO2 in products, like concrete or fuel, traps CO2 for varying lifetimes – from days to nearly permanently. In these cases monitoring storage could come through life cycle assessments that quantify the net carbon impact of the process or product in a certain timeframe, or other techniques that are not yet standardized.
As carbon removal and CO2 utilization are scaled up, monitoring processes will need to be developed and standardized for all approaches to ensure safe and effective storage.
How does site selection and monitoring storage of technological carbon removal work?
Ensuring effective storage of CO2 injected into geologic formations begins with site selection, which includes consideration of CO2 mitigation effectiveness and impacts on the local environment. The key properties of a suitable site include those that are deeper than 1 km in the Earth with high permeability to ensure sufficient storage capacity (i.e., 50-100 MtCO2/project), with annual injection rates on the order of millions of tons of CO2. These geologic reservoirs must be both highly porous and permeable with suitable rocks being sandstone, limestone, dolomite, or basalt. In order to minimize leakage the formations require an impermeable caprock that may be made of shale or anhydrite.
Before construction or operation begins, project owners or operators must develop testing and monitoring plans and submit them to the EPA. During CO2 injection, project operators must make sure the characteristics of the CO2 stream match that on the permit, and must continually collect data on injection pressure, rate and volume, as well as the pressure of the resulting CO2 plume. They must also periodically monitor corrosion of well materials, groundwater quality, and mechanical integrity of the well. Monitoring of air and soil may also be required. Once injection is complete, monitoring of the CO2 plume and pressure are required to ensure safety of drinking water supplies and avoid potential induced seismicity. Seismic imaging is typically used to track movement of the CO2 plume; to understand pressure buildup, readings can be taken at the injection well and at monitoring wells; and detecting leakage can be done through infrared imaging or other techniques like groundwater monitoring.
For storage through mineralization, the goal is for CO2 to be converted to a stable carbonate form. Mineralization represents the safest storage mechanism when it comes to leakage because it chemically converts CO2 to solid form so it cannot escape as a gas. Suitable sites are restricted to those where certain types of reactive rock (e.g. basalt, peridotite) exist near the surface and sufficient temperature and pressure can be achieved. Monitoring is needed for potential leaks to the surface before mineralization occurs, to understand movement and reactivity of injected gases, and to avoid induced seismicity from pressure buildup.
Key design considerations
The U.S. Environmental Protection Agency (EPA) has developed a set of policies for site characterization and monitoring of underground injection of CO2 for geologic storage in saline formations (known as Class VI wells) and enhanced oil recovery (EOR, Class II wells). As the carbon removal industry scales up, existing policy may need to evolve based on continuing experience:
What is the appropriate length of time for liability for potential leakage or other malfunction of Class VI wells to fall on the project developer? How does this timeline affect environmental safety as well as the incentive to invest in such projects?
What entity takes over responsibility for monitoring and remediation in the long term (after project developer liability expires)? How long does that responsibility last?
To what extent should states be granted primacy to develop and enforce their own regulations around site selection and monitoring based on state-specific circumstances?
To what extent should the amount of stored CO2 be prioritized and maximized in EOR operations (Class II wells)? Currently, because CO2 is an expense for EOR, the operator has an incentive to reduce the amount of CO2 injected compared to the amount of oil produced, but reversing this would increase the net carbon benefit of CO2-EOR.
Injection of CO2 into the ground has been happening since the 1970s through EOR, where CO2 is injected into depleted oil reservoirs to produce additional oil. As the oil is produced, the injected CO2 ultimately takes the place of that oil in the pore spaces of the rocks. Dedicated CO2 sequestration has also been taking place in a handful of projects around the world (including in the U.S.), starting in the mid-1990s. Storage through mineralization has been piloted in Washington State (as well as in Iceland).
The U.S. EPA has established guidelines for siting, operating, and closing different types of injection wells through the Underground Injection Control program of the Safe Drinking Water Act. Class II wells, where CO2 could be injected for enhanced oil recovery, are generally regulated by states to which EPA has delegated primacy, and these regulations vary state by state.
The guidelines for Class VI geologic storage wells were established in 2010 and to date the EPA has issued six permits to two projects. Four permits, which have since expired, were issued to the FutureGen Alliance in Morgan County, Illinois, and two permits to the Archer Daniels Midland (ADM) ethanol plant—a government-supported demonstration plant in Decatur, Illinois, that is capturing and sequestering 0.9 MtCO2 per year.
The Class VI permitting process includes consideration of siting, site characterization, construction, operation, monitoring, and site closure of Class VI wells, including post-injection monitoring for up to 50 years to ensure that injected CO2 has stabilized and no longer poses a threat to drinking water. It requires in-depth modeling and analysis to predict the behavior of, and area affected by, injected CO2, as well as a plan of action in case the injected CO2 does not behave according to expectations and endangers drinking water supplies. Individual states can apply for Class VI primacy to approve applications within their state instead of EPA. North Dakota is thus far the only state with this authority, having applied in June 2013 and been granted primacy in April 2018.
- National Academies of Science, Engineering and Medicine: Chapter 7: Sequestration of Supercritical CO2 in Deep Sedimentary Geologic Formations: https://www.nap.edu/read/25259/chapter/9