Carbon Capture and Storage (CCS) is a technology designed to reduce atmospheric greenhouse gas concentrations by capturing carbon dioxide (\(\text{CO}_2\)) from large emission sources, such as power plants and industrial facilities. The captured \(\text{CO}_2\) is then stored permanently, primarily through geological sequestration, which involves injecting the substance deep underground. While CCS offers a promising pathway for climate change mitigation, its large-scale deployment faces significant technical and geological challenges. The main difficulty lies in balancing the massive scale of injection required with the need for absolute geological stability over thousands of years.
How Geologic Carbon Storage Works
The process begins with the \(\text{CO}_2\) being captured and compressed into a dense, liquid-like state known as a supercritical fluid. This supercritical \(\text{CO}_2\) is then transported to an injection site and pumped into specific deep geological formations, typically at depths greater than 800 meters. Storing the \(\text{CO}_2\) at this depth ensures the pressure and temperature conditions keep it in this dense fluid state, maximizing the storage volume.
The most common formations selected for storage are deep saline aquifers, which are porous rocks saturated with brine, or depleted oil and gas reservoirs. These formations are chosen because they possess a high-permeability reservoir rock, such as sandstone, to hold the \(\text{CO}_2\). Overlying this reservoir must be a thick, impermeable layer known as the caprock, often composed of shale or mudstone, which acts as a physical seal to prevent the buoyant \(\text{CO}_2\) from migrating upward.
The Primary Containment Challenge: Preventing Leakage
Ensuring the long-term containment of the injected \(\text{CO}_2\) is a primary difficulty with underground carbon storage. The buoyant supercritical fluid naturally tries to rise through the caprock, meaning the integrity of this seal is paramount. If the caprock is compromised, the \(\text{CO}_2\) could migrate into shallower groundwater or return to the atmosphere, negating the storage operation’s purpose.
Leakage pathways can occur through various natural and man-made features that compromise the geological structure. Existing or reactivated faults and natural fractures within the caprock represent potential conduits for upward migration. Furthermore, the numerous abandoned oil and gas wells that penetrate many potential storage formations pose an additional and sometimes poorly mapped risk for leakage.
Thorough site characterization is necessary to assess the caprock’s sealing capacity, including its thickness, continuity, and ability to withstand the increased pressure. The risk of leakage is managed through structural trapping, where the \(\text{CO}_2\) is held beneath the caprock, and dissolution trapping, where the \(\text{CO}_2\) dissolves into the formation brine over time. Loss of containment presents an environmental hazard and limits the site’s overall storage capacity due to reservoir pressure loss.
The Risk of Induced Seismicity
A second major technical difficulty is the risk of induced seismicity, or man-made earthquakes, caused by the injection process. Pumping vast volumes of fluid into the subsurface significantly increases the pore pressure within the reservoir rock. This pressure increase can diffuse outward and eventually reach pre-existing, geologically stable faults in the surrounding rock, including the deeper basement rock.
When pore pressure rises, it acts to counteract the confining stress that holds a fault in place, effectively reducing the friction on the fault plane. If a pre-existing fault is close to its failure point, this reduction in friction can cause the fault to slip, releasing stored elastic energy as an earthquake. This mechanism of fault lubrication and reactivation is a concern for all high-volume fluid injection projects.
Examples of injection-related seismicity have been documented at various sites, such as the Illinois Basin–Decatur Project, where microseismicity was observed below the injection zone. While most induced events are small, a larger event could potentially damage the caprock or injection wells, creating new leakage pathways for the stored \(\text{CO}_2\). Managing this risk requires careful pressure control, often by injecting at controlled rates or co-producing brine from the reservoir to maintain a stable pressure regime.
Ensuring Long-Term Safety and Monitoring
Mitigating the difficulties of containment and induced seismicity requires a comprehensive monitoring strategy that spans the entire project lifecycle. Surface and subsurface monitoring techniques are deployed to ensure the \(\text{CO}_2\) plume remains within the designated storage complex and to track pressure changes. This includes deploying networks of seismic sensors to detect small microseismic events that could indicate fault instability.
Advanced techniques such as time-lapse seismic surveys are used to image the subsurface periodically, allowing operators to track the movement and distribution of the \(\text{CO}_2\) plume over time. Pressure gauges placed in observation wells provide data on the pressure front’s diffusion, which is used to manage injection rates and mitigate the risk of fault reactivation. Groundwater testing in overlying aquifers is also routinely conducted to detect any unintended migration of \(\text{CO}_2\) or brine.
The long-term success of geological storage relies on robust regulatory oversight that manages the transfer of liability and ensures monitoring continues for decades, or even centuries, after injection ceases. These regulatory frameworks require extensive baseline data collection and the development of detailed plans for risk mitigation and remediation.