Module 5 CO2 storage options and trapping mechanisms

Original text: W. D Gunter, for APEC Capacity Building in the APEC Region, Phase II Revised and updated by CO2CRC and ICF International


Geological storage is one option for storing CO2 from the atmosphere as a means of combating climate change. These sinks are most suitable for utilization by large CO2 emission point sources with relatively pure CO2 waste streams.

This training module outlines the major types of formations which can store CO2 geologically and the way in which the CO2 is trapped in these formations.

Learning objectives

By the end of this module you will:

  • Understand the concept of geological carbon storage;
  • Be familiar with the various CO2 storage options in sedimentary basins and their potential for storage;
  • Be familiar with current practices and special issues related to each of these storage options;
  • Know the techniques used for trapping CO2 in sedimentary basins and their relative security; and
  • Understand the technical challenges for CO2 storage in sedimentary basins.

Geological storage

Geosphere sinks are naturally occurring reservoirs that historically, on a geologic time basis, have been sinks for carbon. Humans have extracted carbon from these sinks in the form of oil, gas and coal, to use for energy. These same reservoirs, including deep aquifers, can be used to store carbon dioxide, reducing the amount of CO2 available in the global carbon balance.

Carbon dioxide storage in sedimentary basins

The geological storage of CO2 requires access to large subsurface volumes, mainly in the rock pore space, which can act as sealed pressurized containers. The pore space is initially occupied by formation fluids such as brines, hydrocarbons and other gases (e.g., H2S and CO2). These fluids are displaced in CO2 storage operations. The pressure to keep CO2 at a liquid-like density is found at depths usually below 800 metres.

Only sedimentary basins, which hold the largest pore-based volumes, are generally suitable for geological storage of CO2. Sedimentary basins are subsiding regions of the Earth's crust that, by their shape, permit the net accumulation of sediments that result from various processes, such as:

  • erosion of pre-existing rocks exposed on land (e.g., sands and muds);
  • deposition of organic material;
  • precipitation from water (e.g., salts); and
  • volcanism (deposition of volcanic ash).

As these sediments are piled and buried, they undergo a process of lithification and become sedimentary rocks, such as sandstones, carbonates, shales, coal, salt rock, tuffs and bentonites. Sedimentary basins are suitable for CO2 storage because they possess the right type of porous and permeable rocks for storage and injection, such as sandstones and carbonates, and the low permeability-to-impermeable rocks needed for sealing, such as shales and evaporitic beds.

Other types of rocks are igneous and metamorphic rocks. Igneous rocks are rocks that crystallized from magma, and are of two types: plutonic (have crystallized at great depth, such as granite), and volcanic (have crystallized at surface, such as basalts). Metamorphic rocks are formed by re-crystallization of existing rocks at great pressure and temperature (e.g., slate, gneiss and schist). Igneous and metamorphic rocks generally are not suitable for CO2 storage because they do not possess the necessary porosity and permeability would allow injection and storage.

Theoretical global storage capacity is estimated to be in the range of 8,000 to 15,000 GtCO2 (IEA, 2009). This suggests that we theoretically have the capacity to store most, if not all, of the CO2 needed to prevent the build-up of harmful levels of CO2 in the atmosphere.

Carbon dioxide storage options

Currently considered storage options for CO2 in geological media include:

  • Injection into depleted oil and gas fields;
  • Deep aquifers;
  • Using CO2 for enhanced oil recovery (EOR);
  • Enhanced coal bed methane recovery (ECBM);
  • Deep unmineable coal seams; and
  • Enhanced gas recovery (EGR).

Figure 5.1: There are a range of geological storage opportunities (courtesy of CO2CRC).

Storage options EOR, ECBM and EGR have the added benefit of direct economic incentives. They are reservoirs that typically begin as a commercially developed site to enhance recovery of fossil fuel fluids and have a secondary benefit of providing a storage site for CO2. These are considered most likely to be implemented in regions with an absence of any carbon cap and trade system. However, some might argue a disadvantage of these options is that the fuels recovered will result in a net gain in CO2 released into the atmosphere.

Depleted oil & gas reservoirs

There are advantages for using depleted oil and gas reservoirs as CO2 sinks, as the trapping mechanisms and reservoir properties are well known and some of the existing infrastructure can be utilized (Figure 5.8). However, there could be potential problems with reservoirs that have had a large number wells penetrating into the reservoirs, as these could act as leakage pathways for CO2.

An abandoned oil reservoir can often have a large quantity of oil remaining in it. As such, it is very unlikely that it will be used as a storage facility unless some form of enhanced oil recovery is incorporated into the CO2 storage scheme. This can be contrasted with an exhausted gas reservoir, where normally up to 90% of the original content would have been removed and the reservoir can genuinely be regarded as depleted and available for CO2 storage.

The total global storage potential of all oil and gas fields in the world is estimated to be 670 Gt of CO2 (180 Gt C) assuming the entire volume can be displaced with CO2 at some time in the future. The distribution between oil and gas is 150 Gt CO2 (40 Gt C) and 520 Gt CO2 (140 Gt C) respectively. This is comparable to the estimates in the Second Assessment Report of the Intergovernmental Panel on Climate Change (IPCC).

Appropriate CO2 purification and pressurization steps are needed in order to reduce impurities and other substances in the CO2 stream. This is because impurities in the CO2 can significantly reduce the amount which can be stored, enhance corrosion and increase capital costs. Legal questions also need to be resolved regarding ownership of the residual hydrocarbons in the CO2 filled reservoirs.

Deep aquifers

Carbon dioxide storage into low to high permeability deep aquifers in sedimentary basins has been shown to be a technically feasible storage option. Carbon dioxide is an ideal candidate for aquifer storage because of its high density and high solubility in water at the relatively high pressures which exist in deeper aquifers. Deep aquifers have the largest potential capacity for CO2 storage

Figure 5.2: Storage in deep aquifers (courtesy of CO2CRC).

Deep aquifers contain high salinity water and could host large amounts of CO2 trapped by the formation pressure. The determining factors are pressure and temperature in the reservoir and the integrity of the reservoir. At depths of 800 metres and greater, the temperature and pressure of the CO2 would be above the supercritical condition, which is desirable from a storage perspective. Global estimates of the capacity of this storage option vary greatly due to different assumptions with respect to aquifer volumes, percent of the reservoir filled, density of CO2 under reservoir conditions, and the volume suitable for storage. It ranges from 87 Gt C to 14,000 Gt C if structural traps are not required for secure storage.

Enhanced Oil Recovery (EOR)

Enhanced oil recovery refers to those methods that are used to increase the recovery of oil above the amounts that could be recovered during primary or secondary recovery. The carbon dioxide may be injected into the gas cap of an oil reservoir in order to provide additional pressure drive for oil recovery. Alternatively, the CO2 may be injected as a flood and used to "sweep" the residual oil. The use of CO2 in miscible floods is a proven technology (Figure 5.3), and its activity continues to increase in the U.S. When CO2 is injected into the reservoir, it dissolves in the oil, thus reducing its viscosity and moves the oil towards the producing well. Inherently, there is always CO2 co-produced with the oil. However, it will be captured and reinjected into the reservoir. For immiscible floods, significantly more CO2 may be left in the reservoir.

Figure 5.3: Schematic of a miscible CO2 flood for enhanced oil recovery, EOR (courtesy of ARC).

In the case of EOR, the oil-carbon dioxide mixture is separated at the surface and the oil is used as fuel in the normal way. While this produces more carbon dioxide, the solution to that problem is clear. The carbon dioxide that is returned to the surface could be re-used for more oil recovery or disposed of in deep aquifers. It should be noted that EOR is likely the first and most economic line of carbon dioxide mitigation processes, though other methods will become more viable as technology develops. The recycling of gases in EOR and EGR is possible because there is a close association of the fossil fuel resources of sedimentary basins and the greenhouse gas emitting industry that is based on those fuels.

Globally, the EOR–CO2 sink has an estimated capacity of 20 to 65 Gt C. It must be noted that not all operations are equally suited for EOR. Use of this sink is restricted to economies that have oil reservoirs suitable for EOR–CO2 recovery techniques. Use of CO2 for EOR is capable of storing a large quantity of CO2, resulting in a net reduction in CO2, but the overall return on investment (either positive or negative) is highly dependent on factors such as the price of oil, price of CO2 and individual reservoir characteristics. The specific criteria which should be considered when screening reservoirs for suitability to CO2 storage are outlined in detail in Module 6.

Figure 5.4: EOR operations in Weyburn, Saskatchewan, Canada (courtesy of EnCana).

In Canada, EnCana Ltd. of Calgary, Alberta is buying carbon dioxide from the Great Plains coal-gasification plant at Beulah, North Dakota, USA. The plant produces pipeline quality synthetic natural gas, and other products, by gasification of lignite from local mines. The carbon is piped 320 km to be used for EOR in the Weyburn Field, Saskatchewan. In 2005, the Midale field nearby (operated by Apache Canada) became part of the project known as the IEA GHG Weyburn-Midale CO2 Monitoring and Storage Project and is in its final phase. EnCana is injecting 7000 tonnes/day and Apache is injecting 1800 tonnes/day (PTRC website). In 2008, the total of stored CO2 was more than 12 million tonnes (Preston et al, 2009).

This association of available waste carbon dioxide and a distant oil field using carbon dioxide for enhanced oil recovery is economically viable after expenditures of more than a billion dollars.

The advantages of using carbon dioxide for EOR operations and injecting it into depleted oil and gas reservoirs are:

  • Opportunity to increase oil production – the main attraction to using CO2 storage techniques for oil and gas is the higher recovery of the fuel from a reservoir. The use of CO2 can aid in the recovery of up to approximately 10 – 12% of the remaining fuel;
  • Cost effectiveness – following from increased opportunity to produce additional hydrocarbon resources, EOR provides an economically attractive way to increase production from operational oil reservoirs. This revenue stream can offset the cost of capture, transport and injection of carbon dioxide;
  • Availability of secure storage – there is an opportunistic association between hydrocarbon production and the presence of reservoirs suitable for CO2 injection. The geological processes that allowed the accumulation of hydrocarbons also permit the secure storing of injected carbon dioxide; and
  • Availability of supporting infrastructure - the technology and infrastructure for oil and gas production can be readily adapted for carbon dioxide injection; this ranges from knowledge of exploration for and production from reservoirs, through all aspects of gas separation, the handling of high pressure fluids and pipelining, to ensuring safe operations and appropriate environmental studies.

Enhanced Gas Recovery

The much higher densities and viscosities of CO2 compared to a natural gas composed predominately of methane imply that injection of CO2 into the base of a depleted homogenous natural gas reservoir would act as a push gas (Figure 5.5). This would mean that if CO2 is injected down dip in the reservoir the natural gas could be produced from the top of the reservoir. Simulation has confirmed that this could be an attractive technology for certain gas reservoirs. In the case of heterogeneous reservoirs, there is a risk that CO2 may preferentially follow higher permeability paths and early breakthrough of the CO2 to the production well may occur. For these cases, more complex reservoir management strategies will be required.

Approximately 90% of the gas in a given reservoir can be extracted through primary processes. The reason for a much higher rate of extraction through primary processes (as compared with oil) is due to the fuel's high compressibility and lower viscosity (compared to oil). Oil is less compressible and does not expand as much as gas. It, therefore, requires a secondary or tertiary recover process to provide sufficient pressure for extraction. For these reasons, CO2 has been used for EOR in practice but CO2 injection for EGR is still being tested.

Figure 5.5: Schematic of enhanced gas recovery using CO2 to displace the natural gas (EGR) (courtesy of ARC).

Enhanced Coal bed Methane Recovery

The use of coal beds as a reservoir rock for storing CO2 is novel. Coal beds contain significant amounts of methane gas - called coal bed methane or CBM - adsorbed in the coal. Current commercial technologies first dewater the coal in order to release the adsorbed gas (Figure 5.6). On the other hand, by injecting CO2 into the coal beds, the CO2 is adsorbed in the coal pore matrix, releasing the methane. Experimental results show that two to ten molecules of CO2 can be adsorbed in the coal matrix for every molecule of methane it displaces. The use of CO2 for CBM recovery would have the same effect as enhanced oil recovery and is classified as an enhanced coal bed methane recovery (ECBM).

Figure 5.6: Example of a coal bed methane well (courtesy of ARC).

Burlington Resources in the US ran the world's first large scale ECBM pilot utilizing CO2 injection located in the San Juan Basin, New Mexico. The global estimates of coal bed methane resources are on the order of 84 – 262 x 1012 cubic meters. Converting these estimates to CO2 storage capacity (assuming two molecules of CO2 displacing one molecule of CH4) yields a potential of 82 to 263 Gt C. Other trials are in Canada and in China (the Qinshui Basin Project).

The bulk of the world's coal bed methane resource occurs in United States, China, Russia (the Asian portion), Kazahkstan, and India. Australia, portions of Africa, Central Europe, and Canada also contain varying amounts of this resource. It is too early to determine the potential global storage capacity for this application, as it is still in piloting stage. The attractiveness of disposing of CO2 in coal beds is that it can be coupled directly with the production of methane. Carbon dioxide is much more strongly adsorbed to the coal than methane and premature breakthrough of the injected CO2 is not expected. Therefore recycling of the CO2 would not be necessary.

The permeability of the coal seam is a significant factor. While it is theoretically possible to sequester CO2 in deep coal without the recovery of CBM, the permeability will be low in most cases and further reduced by the swelling that occurs when CO2 is adsorbed to the coal. Therefore, from a reservoir engineering perspective and from and economic perspective, in most circumstances CO2 storage would accompany or follow CBM production (Golding et al., 2008). Trials in Japan (Yubari) and Poland (Recopol) have examined the injection of CO2 into virgin coals and the associated coal bed methane produced.

ECBM is different compared to other storage options, as a pure stream of CO2 is not required. Separation of the gas takes place in the coal bed due to the coals varying sorption selectivity for different gases. For example if the gas (a mixture of N2 and CO2) is injected into a coal seam, the N2 will pass through and be produced with the methane while the CO2 will remain trapped in the coal seam.

Alternatively, N2 in the flue gas can be separated and released to the atmosphere, and a pure stream of CO2 can be directly injected into the coal seam, Figure 5.7. The choice depends on the specific economics of a project.

Figure 5.7: Schematic of enhanced coal bed methane recovery (ECBM) (courtesy of ARC).

Trapping carbon dioxide in sedimentary basins

When CO2 is injected, it is not dissolved in formations water. It is free-phase, or immiscible. At reservoir temperatures, it is less dense than the formation water and rises upwards due to buoyancy force. Therefore, there needs to be a trapping mechanism that keeps the CO2 in the subsurface for thousands of years or longer.

There are several ways in which dense carbon dioxide can be trapped at 800 m or deeper in saline formations or fossil fuel reservoirs in sedimentary basins.

  • Structural/stratigraphic trapping - traps CO2 as a buoyant fluid within geological structures and flow system (also known as physical trapping or hydrogeological trapping).
  • Residual trapping - CO2 is trapped as small droplets by interfacial (or surface) tension.
  • Solubility trapping - the CO2 dissolves into the surrounding formation water making that water about 1% more dense.
  • Mineral trapping - dissolved CO2 reacts with the reservoir rock, forming solid carbonate minerals.

Each of these trapping mechanisms are described below:

Structural/stratigraphic trapping

In structural/stratigraphic trapping, CO2 is trapped below low permeability rock which prevents it from migrating to the surface. Under these circumstances, CO2 could be trapped for geological time periods. CO2 must be trapped below sealing layer, such as shale or mudstone, to avoid rapid migration of CO2 to the surface. If the top of the trap is closed, such as is the case with most oil and gas reservoirs, the CO2 could be expected to remain in the trap for geological time periods. There are analogues for long-term storage of CO2 in naturally occurring CO2 reservoirs which are currently producing commercial grade CO2 for use in industry (beverages, dry cleaning etc.) and for EOR.

Sedimentary basins have many such closed, physically-bound traps, called reservoirs, in which the fluid is largely static. Some of these are occupied by oil and gas, with the remainder being occupied by formation water. The available volumes in petroleum reservoirs is very small compared to deep saline formations

However, most of these closed traps have held fluids securely over geological time and, obviously, would be the first targets for geological storage. In addition, the production of oil and natural gas from sedimentary basins creates low-pressure storage space that can be repressurized with CO2. Examples of trap types are traps bounded by unconformities, facies change, anticlines and non-transmissive faults (Figure 5.8). Obviously, these would be very attractive for CO2 storage due to their long history of containment.

Figure 5.8: Representations of structural and stratigraphic closed traps. a) structural trap – anticline b) structural trap – fault trap c) stratigraphic trap – unconformity d) stratigraphic trap – change in rock type/pinchout (courtesy of CO2CRC).

Carbon dioxide can be injected into deep saline formations by displacing the formation water (Hitchon, 1996). Where CO2 is injected into horizontal or gently dipping reservoirs that are laterally unconfined (with little sealing layers), it can remain in the reservoir moving very slowly for a long time – such deep saline formations characteristically have slow groundwater flow rates of the order of cm/yr (Bachu et al., 1994). CO2 is expected to migrate under the force of buoyancy towards the sealing layer or the earth's surface. The pathway that the CO2 takes is determined by the complex plumbing of the sedimentary basin. Only a few sedimentary basins will leak significantly over human time scales, or the time scale required to stabilize atmospheric CO2 concentrations associated with climate change (hundreds of years).

If the aquifer is well-bounded by aquitards, migration of the CO2 towards the surface would be slow--only over geologic time. A volume of CO2 injected into such a deep open hydrogeological trap can take over a million years to travel upward in the aquifer to reach the surface and be released into the atmosphere -distances from the deep injection sites to discharge at outcrop can be of the order of 100s of kilometres. The timeframe needed to stabilize CO2 atmospheric concentrations is of the order of hundreds of years. During that time, the CO2 could dissolve in the formation water or be trapped as a mineral (see below).

Figure 5.9: Deep saline formations can store carbon dioxide over geological timeframes (courtesy of CO2CRC).

Careful characterisation of the potential reservoir is required because buoyant CO2 will seek out the interconnected high permeability pathways, including interconnected aquifers, faults, fractures and and wellbores. These potential leakage points will carry the CO2 upwards where it could eventually discharge at the surface on much shorter time scales (e.g. human life).

The hydrodynamic trapping efficiency is significantly enhanced when the flow of formation waters is driven downward in the aquifer by erosional rebound, as is the case of Cretaceous aquifers in the Alberta basin (Figure 5.10).

Figure 5.10: Diagrammatic cross-section through the Alberta sedimentary basin, Canada, showing main flow types and systems (after Bachu, 1995).

Residual trapping

When CO2 is injected into a deep saline formation in a situation where it can migrate away from the injection well, it forms a plume of free-phase CO2. This plume will migrate under the influence of gravity, displacing the formation water. When injection ceases, tail of the plume of free-phase CO2 that is not in the final free-phase accumulation is at low saturation in the pores and trapped by interfacial tension with the formation water in the pore space between the rock. This is called residual trapping. Eventually, this residually trapped CO2 will dissolve into the formation water up to the point where the water becomes fully saturated with CO2.

Figure 5.11: The tail of the carbon dioxide plume is snapped of and trapped residually (courtesy of CO2CRC).

Residual trapping involves trapping CO2 at the irreducible saturation point, segregating the CO2 bubble into droplets that become trapped in individual or groups of pores.

Geochemical trapping – solubility trapping and mineral trapping

The chemistry of formation water and rock mineralogy play an important part in determining the potential for carbon dioxide capture through geochemical reactions (see Gunter et al., 2000). More important, these reactions store the carbon dioxide as a dissolved phase (solubility trapping) or ionic complex (ionic trapping) in the formation water or in solid phases as carbonate minerals (mineral trapping). In the case of storage in unmineable coal seams, the CO2 is trapped as an adsorbed phase in coal (adsorption trapping). In this respect, the unique feature of mineral trapping is that the carbon dioxide is sequestered in a form that is immobile.

Solubility trapping

If the CO2 is injected into deep saline aquifers, the injected CO2 can dissolve in the formation water on an engineering time scale (decades) (Law and Bachu, 1996). Over longer periods of time (centuries to millennia) all the injected CO2 can dissolve (McPherson and Cole, 2000) if the structure allows it. The amount of dissolved CO2 normally decreases with depth as a result of increasing temperature and formation-water salinity characteristic of many sedimentary basins (Bachu and Adams, 2003).

Carbon dioxide dissolves in the aqueous phase and alters the pH (acidity/alkalinity) through reactions coupled to the dissociation of water. Reactions of the following type occur when carbon dioxide dissolves in water:

H2O + CO2↔ H2CO3↔ HCO3-+ H+

Initially, some of the carbon dioxide is held in the aqueous phase as bicarbonate. Only minor amounts of bicarbonate ion and the proton will be produced (thereby lowering the pH), no matter how high the pressure of carbon dioxide. This is the reason that formation water alone is not an acceptable long term sink for carbon dioxide.

The proton, released when the CO2 dissolves in the formation water, results in acid conditions in the water and, therefore, enhances the possibility of attack on the silicate and carbonate minerals present in the aquifer.

Mineral trapping

The dissolved CO2, being acidic, can attack silicate and carbonate minerals present in the aquifer in free ions of elements such as calcium (Ca), magnesium (Mg), and iron (Fe) being released, while at the same time neutralizing the pH shift (i.e. acidity) caused by the dissolved carbon dioxide and allowing more bicarbonate ions to form. This is referred to as "ionic trapping" The reactions fix the CO2 as an ionic species in the formation water that does not boil off when the pressure is released.

One of the fastest geochemical precipitation reactions is the precipitation of calcium carbonate, which occurs when free calcium ions exist in the presence of bicarbonate ions in supersaturated amounts, and is most effective at high pH values. The reaction produces calcite, and it is this reaction that forms the theoretical basis for the storage of carbon dioxide as the mineral calcite.

Ca2+ + HCO3-↔ CaCO3 + H+

Silicate minerals such as anorthite can be transformed to kaolinite and calcite in the following reaction:

The role of the silicate minerals in the above reaction is to neutralize the acid added to the formation water by the addition of carbon dioxide. There are similar reactions for the formation of calcium-magnesium carbonate (dolomite) and iron carbonate (siderite). Thus, unlike the storage of carbon dioxide in the oceans or by other means, the reactions that may occur in the aquifer are such that the carbon dioxide is permanently fixed as a mineral—this method is called mineral trapping. For the more complex minerals commonly found in aquifers, the reaction is of the form:

Feldspars + Clays + CO2 = Kaolinite + Calcite + Dolomite + Siderite + Quartz

where the carbon dioxide is permanently fixed as the carbonate minerals calcite, dolomite and siderite. Carbon dioxide mineral traps are most effective when the aquifer contains minerals that are proton sinks— that is, the basic silicate minerals such as the feldspars and clay minerals. Consequently, mineral trapping of carbon dioxide is favoured in aquifers containing an abundance of clay minerals—typically, siliciclastic (sandstone) aquifers are favoured over carbonate aquifers.

Relative securing of trapping methods

The most secure hydrogeological traps are closed stratigraphic or structural geologic traps, which have been well characterised. Oil and gas reservoirs would be typically very well characterized, and although the capacity of these traps for CO2 storage is small relative to open hydrodynamic traps in deep sedimentary basins, they are likely to be used first as they are known to be secure, having held oil and gas for geological time.

Storage of CO2 as carbonate minerals is the most secure form of storage, but the reactions that trap the CO2 in carbonate minerals are slow on the human time scale, but relatively fast on a geological time scale. Over longer time periods, mineral trapping may become a long-term stable sink for CO2. The extent and rate at which this occurs depends on the mineralogy and brine chemistry of the sedimentary rocks contacted by CO2.

As the capacity of closed traps is exhausted and more is learned about the rates of residual and geochemical trapping, the large storage capacity available in open hydrodynamic traps will be utilized. This will only be possible when the security of the geological storage of CO2 can be enhanced by geochemical reactions of the CO2 with basic silicate minerals.

Figure 5.12: Over time, the security of the trapped CO2 increases as different types of trapping become significant (courtesy of CO2CRC).

In the sedimentary basins, suitably located injection sites far from the basin edge and injection at depths greater the 800 m (the minimum depth for injection of carbon dioxide at liquid-like density) will result in geologically long times before any emergence of carbon dioxide at the surface occurs-if at all. By that time, if ionic or mineral trapping have not occurred, the pressure of carbon dioxide will have been reduced to such an extent (from the original injection pressure) due to solution, diffusion, dispersion and residual trapping that the emergence will be a relatively harmless event, occurring over a much longer period than the original injection period.


Sedimentary basins, fossil fuel resources, and greenhouse gas emissions are all closely associated. To exploit the fossil fuels is to release the greenhouse gases, mainly carbon dioxide, to the atmosphere. This does not have to be so. Rather than discharge carbon dioxide to the atmosphere, it can be stored in deep aquifers in the same sedimentary basins from which the fuel was extracted - some of the strata can be hydrocarbon-bearing (reservoirs) with the carbon dioxide enhancing oil or gas production.

Injection and storage technologies, developed by the oil and gas industry, are fairly mature. The volume of storage depends on the current and ultimate pressures of the reservoir or aquifer. Experience in injection of CO2 has been gained from repressurizing oil reservoirs using CO2 in enhanced oil recovery, from acid gas re-injection, and similar technology is being developed for production of methane from coal beds (i.e. coalbed methane or CBM). The ultimate capacity of geological storage of carbon dioxide is likely huge, contingent upon identifying secure traps in sedimentary basins.

Some of the short term challenges include:

  • Determining the implications of pressure build-up in a storage formation;
  • Determining where the displaced water goes in a large scale injection and what the risk is to ground water;
  • How to reliably predict the size of the CO2 plume and where it migrates;
  • How to gain confidence in site selection;
  • Cost effective monitoring strategies and detection limits; and
  • If a leak occurs, determining how it can be fixed, the cost of fixing it and how long it will take.


The geological storage of CO2 requires access to large subsurface volumes in the rock pore space which can act as sealed pressurized containers.

Currently considered storage options for CO2 in geological media include:

  • Injection into depleted oil and gas fields;
  • Deep aquifers;
  • Using CO2 for enhanced oil recovery (EOR);
  • Enhanced coal bed methane recovery (ECBM);
  • Deep unmineable coal seams; and
  • Enhanced gas recovery (EGR).

Saline aquifers have the largest capacity for all feasible sedimentary basins for CO2 storage. The volume of pore space in aquifers far exceeds that of oil, gas and coal bed reservoirs.

Saline aquifer storage of CO2, depleted oil/gas reservoir storage of CO2 and enhanced oil recovery are currently being demonstrated. Enhanced coal-bed methane recovery is being explored. Enhanced gas recovery also being investigated.

CO2 must be trapped in sedimentary basins in order to ensure storage for geological time periods. This trapping can be through structual/stratigraphic trapping, residual trapping, solubility/ionic trapping and/or mineral trapping.

In structural or stratigraphic trapping, CO2 is trapped below low permeability rock which prevents it from migrating to the surface. Under these circumstances, CO2 could be trapped for geological time periods. Often closed traps also hold oil and natural gas which could be tapped during CO2 storage.

The most secure hydrogeological traps are closed stratigraphic or structural geologic traps, which have been well characterized during their exploitation for oil and gas. They have a smaller capacity but are likely to be used first of the options.

Trapping occurs in deep saline aquifers with slow flow rates. Injected CO2 replaces saline formation water. It will remain in the reservoir moving very slowly for a long period of time.

Residual trapping involves trapping CO2 at the irreducible saturation point, segregating the CO2 bubble into droplets which become trapped in individual or groups of pores.

Injected CO2 can dissolve in the formation water over a geological time scale. Silicate or carbonate minerals present in the aquifer will neutralize the acidic CO2 added to the formation. These reactions fix the CO2 as an ionic species in the formation water that does not boil off when the pressure is released.

Mineral trapping occurs when carbon dioxide reacts with the reservoir rocks to form carbonate minerals. Mineral trapping is the most secure form of storage, but reactions occur slowly on the geological time scale.

The preferential adsorption of CO2 onto the coal matrix because of its higher affinity to coal than that of methane is a form of geochemical trapping.

The trapping mechanisms become more secure over time.



Gunter, W.D., Rick Chalaturnyk, Stefan Bachu, Don Lawton, Doug Macdonald, Ian Potter, Kelly Thambimuthu, Malcolm Wilson and Michelle Heath. The CANiSTORE Program: Planning options for technology and knowledge base development for the implementation of geological storage research, development and deployment in Canada. Alberta Research Council, Inc., Canada, 94p, 2004.

Gunter, W.D., S. Wong, D.B. Cheel and G. Sjostrom . Large CO2 Sinks: Their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Applied Energy 61, 209-227, 1998.

Hitchon, B., Gunter, W.D., Gentzis, T., and Bailey, R.T. Sedimentary basins and greenhouse gases: a serendipitous association. Energy Conversion and Management, 40, 825-843, 1999.

IPCC. IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change [Metz, B., O. Davidson, H. C. de Coninck, M. Loos, and L.A. Myers (eds.)]. Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA, 442pp, 2005.

Enhanced Oil Recovery

Shaw, J and S, Bachu. Screening, evaluation, and ranking of oil reservoirs suitable for CO2- flood EOR and carbon dioxide sequestration. J. Canadian Petroleum Technology 41 #9, 51-61, 2002.

Preston, C., Whittaker, S., Rostron, B., Chalaturnyk, R., White, D., Hawkes, C., Johnson, J. W., Wilkinson, A., and Sacuta, N. IEA GHG Weyburn-Midale CO2 monitoring and storage project – moving forward with the final phase. In Energy Procedia 1 (1) pp1743-1750, 2009.

Enhanced Gas Recovery

Oldenburg, C. M., K. Pruess & S.M. Benson. Process modeling of CO2 injection into natural gas reservoirs for carbon sequestration and enhanced gas production, Energy and Fuels, 15, 293-298, 2001.

Coal Beds

Wong, S., W.D. Gunter, D.H.-S. Law, & M.J. Mavor. Economics of flue gas injection and CO2 sequestration in coalbed methane reservoirs, In: Fifth International Conference on Greenhouse Gas Control Technologies (GHGT-5), (eds. D.J. Williams, R.A. Durie, P. McMullan, C.A.J. Paulson and A. Y. Smith), CSIRO Publishing, Collingwood, VIC, AU, 543-548, 2001.

Golding, S. D., Uysal, I. T., Esterle, J. S. Massarotto, P and Rudolph, V. A comparative review of carbon geosequestration options. Presentation at the 2008 Asia Pacific Coalbed Methane Symposium, Brisbane, Queensland, 22-24 September, 2008.

Depleted Oil and Gas Reservoirs

Bachu, S. and J. Shaw. Evaluation of the CO2 sequestration capacity in Alberta's oil and gas reservoirs at depletion and the effect of underlying aquifers. J. Canadian Petroleum Technology 42 #9, 51-61, 2003.

Adam, D. The North Sea bubble. Nature, 411, 518, 2001.

Deep Aquifers

Gunter, W.D., S.Bachu, D.Law, V.Marwaha, D.L.Drysale, D.E.MacDonald and T.J.McCann. Technical and economic feasibility of CO2 disposal in aquifers within the Alberta Sedimentary Basin, Canada, , Energy Convers. Mgmt. 37, 1135-1142,1996.

Trapping mechanisms

Bachu, S. Sequestration of carbon dioxide in geological media: Criteria and approach for site selection, Energy Conversion and Management, 41:9, 953-970, 2000.

Bachu, S. Screening and ranking of sedimentary basins for sequestration of CO2 in geological media. Environmental Geology, 44:3, 277-289, 2003.

Bachu, S. & J.J. Adams. Sequestration of CO2 in geological media in response to climate change: Capacity of deep saline aquifers to sequester CO2 in solution. Energy Conversion and Management 44, 3151-3175, 2003.

Bachu, S., Gunter, W.D. & Perkins, E.H. Aquifer disposal of CO2: Hydrodynamic and mineral trapping, Energy Conversion and Management. 35, 269-279, 1994.

Gunter, W.D., S. Bachu and S. M. Benson. The role of hydrogeological and geochemical trapping in sedimentary basins for secure geological storage for carbon dioxide. In: Baines, S. and R.H. Worden (eds.), Geological Storage of Carbon Dioxide, Geological Society, London, Special Publications, 233, Bath, U.K. In press, 2004.

Gunter, W.D., E.H. Perkins and Ian Hutcheon. Aquifer disposal of acid gases: Modelling of water-rock reactions for trapping acid wastes. Applied Geochemistry 15, 1085-1095, 2000.

Gunter, W.D., S. Wong, D.B. Cheel and G. Sjostrom . Large CO2 Sinks: Their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Applied Energy 61, 209-227, 1998.

Gunter, W.D., T.Gentzis, B.A.Rottenfusser and R.J.H. Richardson. Deep Coalbed Methane in Alberta, Canada: A Fuel Resource with the Potential of Zero Greenhouse Gas Emissions, Energy Convers. Mgmt. 38 Suppl., S217-S222, 1997.

Hepple R., & Benson, S.M. 2003. Implications of surface leakage on the effectiveness of geologic storage of carbon dioxide as a climate change mitigation strategy. In: Sixth International Conference on Greenhouse Gas Control Technologies, Kyoto, Japan, Sept.30-Oct.4, 2002.

Hitchon, Brian (editor). Aquifer Disposal of Carbon Dioxide; Hydrodynamic and Mineral Trapping – Proof of Concept, Geoscience Publishing Ltd, Sherwood Park, Alberta, Canada, 165p, 1996.

Law, D. H-S. and S. Bachu. Hydrogeological and numerical analysis of CO2 disposal in deep aquifers in the Alberta sedimentary basin, Energy Conversion and Management, 37, 1167-1174, 1996.

McPherson, B. J. O. L. and B. S. Cole. Multiphase CO2 flow, transport and sequestration in the Powder River basin, Wyoming, USA, Journal of Geochemical Exploration, 69-70(June), 65-70, 2000.


General information about geological storage of CO2