Storage

CO2 storage means injecting CO2 underground in suitable geological formations where the CO2 will remain safely stored for thousands of years. The technology for CO2 storage has been in use in several places since the 1970s, and experience with CO2 storage projects worldwide proves that CO2 can be stored safely without leakages.

Suitable geological formations are found in layers of porous rock which have space available for the CO₂ similar to the way a sponge has space available for water. To be sure that the CO₂ is contained in the porous rock layer, a solid, non-porous, layer of rock must lie on top of the porous layer, providing a 'cap' that does not allow CO₂ to permeate upwards.

CO2 storage in a saline aquifer below a caprock.

Geological storage of CO₂ can be undertaken in a variety of geological settings in sedimentary basins. Possible storage formations within these basins are oil fields, depleted gas fields, deep coal seams and saline formations. Other geological formations which may serve as storage sites include caverns and basalt and organic-rich shales.

CO₂ can also be injected into oil and gas fields to increase oil or gas production. This is referred to as enhanced oil recovery (EOR) and enhanced gas recovery (EGR). Some of the CO₂ injected for EOR and EGR will remain stored for thousands of years, but a large share of the CO₂ will come out again together with oil and gas produced from the reservoir.

Options for storing CO2 in deep underground geological formations

Our main emphasis on this web page will be on deep saline aquifer formations because they represent the largest CO₂ storage capacity. Saline formations are deep sedimentary rocks saturated with formation waters or brines containing high concentrations of dissolved salts. These formations are widespread and contain enormous quantities of water, but are unsuitable for agriculture or human consumption. Saline formations occur in sedimentary basins throughout the world.

The Sleipner Project in the North Sea is the best available example of a CO₂ storage project in a saline formation. The offshore gas field Sleipner, in the middle of the North Sea, has been injecting about 1 Mt CO₂ per year since September 1996 without any indication of leakages. 

In general, geological storage sites should have:

1. adequate capacity and injectivity
2. a satisfactory sealing caprock or confining unit and
3. a sufficiently stable geological environment to avoid compromising the integrity of the storage site.

Adequate porosity and thickness (for storage capacity) and permeability (for injectivity) are critical; porosity usually decreases with depth because of compaction and cementation, which reduces storage capacity.

The storage formation should be capped by extensive confining units such as shale, salt or anhydrite beds to ensure that CO₂ does not escape into the overlying, shallower rock units and ultimately to the surface. Extensively faulted and fractured sedimentary basins, or parts thereof particularly in seismically active areas, require careful characterization to be good candidates for CO₂ storage.

The CO₂ must be stored as a liquid, and not as a gas, because gaseous CO₂ occupies more space and leaks more easily than liquid CO₂. In practice, the CO₂ is compressed prior to injection to a dense fluid state known as ‘dense phase’ or ‘supercritical CO₂’. Supercritical CO₂ behaves like a liquid, and represents CO₂ temperatures higher than 31.1^oC and pressure greater than 73.9 bar.

Depending on the rate that the temperature increases with depth in the earth's crust, the density of CO₂ will increase with depth, until about 800 m or greater, where the injected CO₂ will be in a dense supercritical state. The efficiency of CO₂ storage in geological media, defined as the amount of CO₂ stored per unit volume, increases with increasing CO₂ density. Storage safety also increases with increasing density, because buoyancy, which drives upward migration, is stronger for a lighter fluid. 

‘Cold’ sedimentary basins, characterized by low temperature gradients, are more favourable for CO₂ storage because CO₂ attains higher density at shallower depths (700–1000 m) than in ‘warm’ sedimentary basins, characterized by high temperature gradients where dense-fluid conditions are reached at greater depths (1000–1500 m).

The presence of impurities (e.g., SOx, NO_x, H₂S) in the CO₂ gas stream affects the capacity for CO₂ storage in geological media. Gas impurities in the CO₂ stream affect the compressibility of the injected CO₂, and hence the total volume to stored. This will reduce the capacity for storage in free phase, because of the storage space taken by the impurities. In the case of CO₂ storage in deep saline formations, the presence of gas impurities affects the rate and amount of CO₂ storage through dissolution and precipitation. Additionally, leaching of heavy metals from the minerals in the rock matrix by SO₂ or O₂ contaminants is possible.

The storage site and its surroundings need to be characterized in terms of geology, hydrogeology, geochemistry and geomechanics (structural geology and deformation in response to stress changes). The greatest emphasis will be placed on the reservoir and its sealing horizons. However, the strata above the storage formation and caprock also need to be assessed because if CO₂ leaks it would migrate through them.

Documentation of the characteristics of any particular storage site will rely on data that have been obtained directly from the reservoir. These include:

• core and fluids produced from wells at, or near the proposed storage site
• pressure transient tests conducted to test seal efficiency
• indirect remote sensing measurements such as seismic reflection data, and
• regional hydrodynamic pressure gradients.

Integration of all of the different types of data is needed to develop a reliable model that can be used to assess whether a site is suitable for CO₂ storage.

Selection of storage sites will be based on characterization data. The most important data sets required for site selection are listed below:

• Geological site description from wellbores and outcrops are needed to characterize the storage formation and seal properties
• Seismic surveys are needed to define the sub-surface geological structure and identify faults or fractures that could create leakage pathways
• Formation pressure measurements are needed to map the rate and direction of groundwater flow, and

Water quality samples are needed to demonstrate the isolation between deep and shallow groundwater.

Computer simulation also has a key role in the design and operation of field projects for underground injection of CO₂. Predictions of the storage capacity of the site are vital to an initial assessment of economic feasibility. In a similar vein, simulation can be used in tandem with economic assessments to optimize the location, number, design and depth of injection wells.

During injection and monitoring operations, simulation models can be calibrated to match field observations. Then they can be used to assess the impact of possible operational changes, such as drilling new wells or altering injection rates, often with the goal of further improving recovery (in the context of hydrocarbon extraction) or of avoiding migration of CO₂ past a likely spill-point.

Numerical simulators currently in use in the oil, gas and geothermal energy industries provide important subsets of the required capabilities. They have served as convenient starting points for recent and ongoing development efforts specifically targeted at modelling the geological storage of CO₂.

Existing models for injection and storage of CO₂ are subject to considerable uncertainties because of complex geology. Measurements taken at wells provide information on rock and fluid properties at that location, but statistical techniques must be used to estimate properties away from the wells. When simulating a field in which injection or production is already occurring, a standard approach in the oil and gas industry is to adjust some parameters of the geological model to match selected field observations. This proves that the model is inaccurate, but it does provide additional constraints on the model parameters. However, better models and simulation tools are required.

The effectiveness of geological storage depends on a combination of physical and geochemical trapping mechanisms. The mechanisms are visualised in the figure below.

CO2 storage mechanisms. Left: The storage mechanism known as physical trapping of CO2 in a porous rock below low-permeability seals (caprocks). Middle: In the longer term, significant quantities of CO2 dissolve in the formation water. Right: CO2 can undergo a sequence of geochemical interactions with the rock and formation water.

Physical trapping

The most effective storage sites are those where CO₂ is immobile because it is trapped permanently under a thick, low-permeability seal. Sedimentary basins have such closed, physically bound traps or structures, which are occupied mainly by saline water, oil and gas. Structural traps include those formed by folded or fractured rocks, and the traps are formed by changes in rock type caused by variation in the setting where the rocks were deposited. When CO₂ is injected, care must be taken not to exceed the allowable overpressure to avoid fracturing the caprock or re-activating faults.

When CO₂ is injected into a formation, it displaces saline formation water and then migrates buoyantly upwards, because it is less dense than the water. When it reaches the top of the formation, it continues to migrate as a separate phase until it is trapped as residual CO₂ saturation or in the local structural trap within the sealing formation.

Trapping can also occur in saline formations that do not have a closed trap, but where fluids migrate very slowly over long distances.

Solubility trapping

In the longer term, significant quantities of CO₂ dissolve in the formation water and then migrate with the groundwater. Where the distance from the deep injection site to the end of the overlying impermeable formation is hundreds of kilometres, the time scale for fluid to reach the surface from the deep basin can be millions of years.

The primary benefit of solubility trapping is that once CO₂ is dissolved, it no longer exists as a separate entity, thereby eliminating the buoyant forces that drive it upwards.

Mineralisation

CO₂ in the subsurface can undergo a sequence of geochemical interactions with the rock and formation water that will further increase storage capacity and effectiveness, a mechanism known as geochemical trapping, or mineralisation. CO₂ dissolved in water will form ionic species that can react with the rock and form stable carbonate minerals. This is also referred to as mineral trapping, which the most permanent form of geological storage. Mineral trapping is believed to be comparatively slow, potentially taking thousands of years or longer. Nevertheless, the permanence of mineral storage, combined with the potentially large storage capacity present in some geological settings, makes this a desirable feature of long term storage.

Monitoring is needed for a wide variety of purposes. It can be used to document injection well behaviour and to measure injection rates, wellhead pressure and formation pressures. Monitoring also serves as a verification tool to quantify the injected CO₂ that has been stored and to demonstrate, with appropriate monitoring techniques, that CO₂ remains contained in the intended storage formations. This is currently the principal method for assuring that the CO₂ remains stored and that performance predictions can be verified. It can also be applied to detect leakage and to provide an early warning of any seepage or leakage that might require mitigating action.

Before monitoring of subsurface storage can take place effectively, a baseline survey must be taken. This survey will provide the point of comparison for subsequent surveys. This is particularly true of seismic and other remote-sensing technologies. Additionally, establishing baselines of natural CO₂ fluxes resulting from ecosystem cycling of CO₂ are useful for distinguishing natural fluxes from potential storage-related releases.

Standard procedures of monitoring currently in use include:

• routine measurements of injection rates and pressures,
• monitoring the distribution and migration of CO₂ in the subsurface,
• monitoring injection well integrity,
• monitoring local environmental effects, and
• monitoring network design and duration.

A number of standard technologies are available for monitoring but the applicability and sensitivity of the techniques in use are somewhat site-specific. Given the long-term nature of CO₂ storage, site monitoring may be required for very long periods. Existing monitoring technologies have a limited capacity for measurement and verification of stored CO₂, and it is therefore recommended that focus be directed at developing improved and new monitoring technologies.

Natural accumulations of relatively pure CO₂ are found all over the world in a range of geological settings, particularly in sedimentary basins, intra-plate volcanic regions and in faulted areas or quiescent volcanic structures. The CO₂ has been trapped in such natural reservoirs for many million of years, which is a clear indication that injected CO₂ can be stored for millions of years.

For instance, 200 Mt trapped in the Pisgah Anticline, northeast of the Jackson Dome in the USA, is thought to have been generated more than 65 million years ago. With no evidence of leakage, this site provides additional evidence of long-term trapping of CO₂. Conversely, some systems, typically spas and volcanic systems, are leaky and not useful analogues for geological storage, but can be useful for studying the health, safety and environmental effects of CO₂ leakage.

Underground natural gas storage projects that offer experience relevant to CO₂ storage have operated successfully for almost 100 years in many parts of the world. The majority of gas storage projects are in depleted oil and gas reservoirs and saline formations, although caverns in salt have also been used extensively. While underground natural gas storage is safe and effective, some projects have leaked, mostly caused by poorly completed, or improperly plugged and abandoned wells and by leaky faults.

Acid gas injection operations represent a commercial analogue for some aspects of geological CO₂ storage. Acid gas is a mixture of H₂S and CO₂, with minor amounts of hydrocarbon gases that can result from petroleum production or processing. In Western Canada, operators are increasingly turning to acid gas disposal by injection into deep geological formations. A total of 2.5 MtCO₂ and 2 MtH₂S had been injected in Western Canada by the end of 2003 with no detectable leakage. Acid gas injection occurs over a wide range of formation and reservoir types.

The best evidence that CO₂ can be stored safely is experience from CO₂ storage projects in operation. The offshore gas field Sleipner, in the middle of the North Sea, produces natural gas that contains up to 9 percent CO₂. Export quality of natural gas requires less than 2.5 percent CO₂, and the CO₂ is therefore separated from the natural gas. The CO₂ is injected into a sand layer containing salt water, called the Utsira formation, which lies 1000 meter below the sea bottom. About 1 million tonnes of CO₂ has been injected annually since 1996, and there have not been any indications of leakages.

Read more about storage safety

The risks due to storage of CO₂ in geological reservoirs fall into two broad categories: global risks and local risks. Global risks involve the release of stored CO₂ to the atmosphere that may contribute significantly to climate change if some fraction leaks from the storage formation. In addition, if CO₂ leaks out of the storage formation, local risks include hazards for humans, ecosystems and groundwater.

With regard to global risks, observations and analysis of current CO₂ storage sites, natural systems, engineering systems and models indicate that the likelihood or probability of leakage in appropriately selected and managed reservoirs is nearly absent, or very negligible over long periods of time. The risk of leakage is also expected to decrease over time as other mechanisms provide additional trapping.

With regard to local risks, there are two types of scenarios in which leakage may occur. In the first case, injection well failures or leakage of abandoned wells could create a sudden and rapid release of CO₂. This type of release is likely to be detected quickly and stopped using techniques that are available today for containing well blow-outs. Hazards associated with this type of release primarily affect living species in the vicinity of the release at the time it occurs. A concentration of CO₂ greater than 7–10% in the air would cause immediate dangers to human life and health.

Containing these kinds of releases may take hours to days and the overall amount of CO₂ released is likely to be very small compared to the total amount injected. These types of hazards are managed effectively on a regular basis in the oil and gas industry using engineering and administrative controls.

In the second scenario, leakage could occur through undetected faults, fractures or through leaking wells where the release to the surface is more gradual and diffuse. In this case, hazards primarily affect drinking-water aquifers and ecosystems where CO₂ accumulates in the zone between the surface and the top of the water table. Groundwater can be affected both by CO₂ leaking directly into an aquifer and by brines that enter the aquifer as a result of being displaced by CO₂ during the injection process. There may also be acidification of soils and displacement of oxygen in soils in this scenario.

Additionally, if leakage to the atmosphere were to occur in low-lying areas with little wind, or in sumps and basements overlying these diffuse leaks, humans and animals would be harmed if a leak were to go undetected. Humans would be less affected by leakage from offshore storage locations than from onshore storage locations.

Leakage routes can be identified by several techniques and by characterization of the reservoir. The figure below shows some of the potential leakage paths for a saline formation. When the potential leakage routes are known, the monitoring and remediation strategy can be adapted to address the potential leakage.

Some potential escape routes for CO2 injected into saline formations

Careful storage system design and site selection, together with methods for early detection of leakage (preferably long before CO₂ reaches the land surface), are effective ways of reducing hazards associated with diffuse leakage. The available monitoring methods are promising, but more experience is needed to establish detection levels and resolution. Once leakages are detected, some remediation techniques are available to stop or control them. Depending on the type of leakage, these techniques could involve standard well repair techniques or the extraction of CO₂ by intercepting its leak into a shallow groundwater aquifer. However, standards for remediation actions in case of leakages are yet to be established.

Knowledge regarding CO₂ geological storage is founded on basic knowledge in the earth sciences, on experiences of the oil and gas industry and on a large number of commercial activities involving the injection and geological storage of CO₂ conducted over the past 10–30 years. Nevertheless, CO₂ storage is a new technology and many questions remain.

At present there are no knowledge gaps that hinder full-scale implementation of geological storage of CO₂.  Important gaps in knowledge that need to be addressed with some urgency are:

1 - Improved Confidence
Risks of leakage from storage sites and abandoned wells need to be determined. This includes:

• Assessment of the environmental impacts of CO₂ seepage on the marine seafloor is required.
• Quantitative assessments of risks to human health is required.
• Methods for leakage detection must de established 

In addition, more leakage rates data from more storage sites or projects needs to be collected and reliable coupled.  Hydrogeological-geochemical-geomechanical simulation models to use as a prediction tools should be developed.

2 - Storage Capacity
There is a need to get universal agreement on a storage capacity assessment method, particularly for aquifers. This knowledge is needed to determine effective capacity for CO₂ storage in geological formations to derive policy and research initiatives. There is need for a full global data set – presently most data sets are from Australian, Japan, North America and Western Europe.

3 - Monitoring Techniques
Improvement of techniques for fracture detection and characterization of leakage potential are required.

4 - Costs
Only a few experience-based cost data from non CO₂-EOR storage sites are available; more would be useful.

5 - Regulation and Liability 
A framework has yet to be established on a global level. It should consider: the role of pilot projects, verification of CO₂ storage for accounting purposes, approaches for selecting, operation and monitoring of CO₂ storage sites in the short and long term, and stewardship and requirements for decommissioning of a storage project.

This web page is an updated and shortened version of the report “Carbon Dioxide Storage: Geological Security and Environmental Issues – Case Study on the Sleipner Gas Field in Norway” by former Bellona employee Semere Solomon.
Download report as PDF

• Storage safety

• Brochure on CO₂ storage from ZEP
• IPCC report on CO₂ capture and storage
• The Geocapacity project
• The CCP project