Geological storage


According to IPCC the maximum amount of carbon that might be sequestered by global afforestation and reforestation activities for the period 1995-2050 was estimated at 60-87 Gt C (70% in tropical forests, 25 % in temperate forests, and 5% in boreal forests). The issue most important is to decrease the rate of deforestation: there are 13 billion meters squared of tropical regions that are deforested every year. There is potential for these regions to reduce rates of deforestation by 50% by 2050, which would be a huge contribution to mitigate the global warming.

Not all sedimentary basins are appropriate for CO2 storage: too shallow formations or rock-dominated ones, with no permeability are no suitable for CO2 storage.

Places that are suitable for this purpose are places with:

  • Thick acumulation of sediments
  • Permeable rocks satured with saline water: saline formations
  • Extensive covers of low porosity rocks: seals
  • Structural simplicity

CO2 can remain trapped underground by means of different mechanisms that include:

  • Trapping below an impermeable, confining layer
  • Retention as an immobile phase trapped in the pore spaces of the storage formation
  • Dissolution in the in situ formation fluids; and adsorption onto organic matter in coal and shale.

Despite CCS (Carbon Capture and Sequestration) in geological formations is presented as a new way to combat the climate change by means of storing CO2, it must take into account the need of carring out the processes of CCS in a environmentanlly friendly form.


  • The direct discharge of CO2 in the sea, seabed, lakes and other open places should be excluded
  • Abandoned oil and gas fields have a big amount of perforations that must be sealed to avoid possible leakages

Types of geological storage


In oil and gas reservoirs, the displacement of in situ fluids by injected CO2 can result in most of the pore volume being available for CO2 storage. These reservoirs (except Enhanced Oil Recovery) will not be avaliable for CO2 storage until the hydrocarbons are depleted. In hydrocarbon reservoirs with little water encroachment, the injected CO2 will normally occupy the pore volume previously occupied by oil or natural gas. However, not all the pore space will be available for CO2  storage because some residual water can be trapped in the pore space.

In open hydrocarbon reservoirs, a significant fraction of the pore space will be invaded by water, decreasing the pore space available for CO2 storage. Oil and gas field reservoirs have a lower estimate storage capacity of 675 GtCO2 and an upper of 900 GtCO2. If undiscovered oil and gas fields were included, this amount would increase to 900–1200 GtCO2.


Oil and gas abandoned field are suitable for CO2 storage because:

  • Oil and gas accumulated in traps did not escape: they are relatively safe.
  • Their structure and physical properties have been studied and characterized
  • Computer models can predict the movement, displacement behaviour and trapping of CO2

The capacity of the reservoir will be limited by the need to avoid exceeding pressures that can damage the caprock. Shallow reservoirs usually have a low CO2 storage capacity since CO2 may be in the gas phase. Abandoned oil and gas fields are easier to assess than are saline formations because the geological structure are usually well characterized from existing wells.


Opportunities for enhanced oil recovery (EOR) have increased the interest in CO2 storage. Although not being designed for CO2  capture, EOR projects have demonstrated an associated storage of CO2. EOR uses a miscible flooding that contains CO2, with an incremental oil recovery of 7-23% of the original oil in place. These mechanisms can use oil swelling and viscosity reduction for injection of immiscible fluids or completely miscible displacement in high-pressure applications in which more than 50% of the injected CO2 returns with the produced oil and is usually separated and re-injected into the reservoir (this minimizes the operating costs).

The remaining CO2  is trapped in the reservoir by irreducible saturation and dissolution in reservoir oil that it is not produced and in pore space that is not connected to the flow path for the producing wells.

The depth of the reservoir normally is more than 600 m.

Injection of immiscible fluids must often be enough for heavy- to-medium-gravity oils. The more desirable miscible flooding is applicable to light, low-viscosity oils. For miscible floods, the reservoir pressure must be higher than the minimum miscibility pressure needed for achieving miscibility between reservoir oil and CO2, depending on oil composition and gravity, reservoir temperature and  purity of CO2.

To achieve effective removal of the oil, thin (less than 20 meters), high angle, homogeneous reservoirs with a low vertical permeability are required. For horizontal reservoirs, the absence of natural water flow, major gas cap and major natural fractures are preferred. The density difference between the lighter CO2 and the reservoir oil and water leads to movement of the CO2 along the top layerof the reservoir.

Consequently, reservoir heterogeneity may have a positive effect, slowing down the rise of CO2 to the top of the reservoir and forcing it to spread laterally, giving more complete invasion of the formation and better storage potential. It is shown that the use of CO2 enhanced oil recovery for CO2 storage can be a lower cost solution than saline formations and depleted oil and gas fields.


However, there are studies that prove that the injection of 1 ton of CO2 in a EOR project would allow the extraction of 0,6 tons of petrol that generate 3m2 tons of CO2. For this reason, coolmyplanet refuses EOR projects.


Although up to 95% of original gas in place can be produced, CO2 could  be injected into depleted gas reservoirs to enhance gas recovery by repressurizing the reservoir. The natural gas which is in the field is mixed with the CO2 that is injected and degrades gas production. This is one of the reason because this technique was believed to receive less attention. However, this mix have physical propierties for reservoir repressurization. These propierties include density: CO2 has higher density than CH4 and also a lower mobility. Due to these two propierties CO2 can migrate down and this will stabilize the displacement between CO2 injected and methane (the original gas in the field)

Wells are located at the upper layers of the reservoir to make easier the CO2 injection. Heterogeneity causes an increase in CO2 but the re-pressurization can happen before that CO2 advance that avoids major problems. Costs associated with CO2 capture must be reduced since it is the most costly part of the cycle of Carbon Capture and Sequestration. It is proved that CO2 injection is a good way to capture CO2 while enhancing methane recovery. To conclude, the process of EGR with CO2 injection is economically and technically possible and even favourable


Unlike EOR projects, EGR projects work with natural gas which is more environmentally friendy than petrol.


Saline formations are other kind of geological reservoirs. Their theoretical storage capacity range from 1000 to 104 GtCO2. They are deep sedimentary rocks saturated with brines containing high concentrations of dissolved salts. These formations contain enormous quantities of water, but they are not suitable for agriculture or human consumption. Saline brines can be used  by the chemical industry and formation waters of varying salinity are used in health spas and for producing low-enthalpy geothermal energy.

Geothermal energy is likely to increase. For this reason, potential geothermal areas may not be suitable for CO2 storage. Areas with a great geothermal energy potential are generally less suitable for CO2 geological storage because of the high degree of faulting and fracturing and the sharp increase of temperature with depth. In very arid regions, deep saline formations may be considered for water desalinization.

The CO2 is injected into poorly cemented sands about 1000 m below the sea floor. The sandstone contains secondary thin shale or clay layers, which cause the internal movement of injected CO2. The upper layer is a seal which is an extensive thick shale or clay layer. The saline formation into which CO2 is injected has a very large storage capacity. Reservoir studies have shown that the CO2-saturated brine will become denser and sink,eliminating the potential for long-term leakage.



Its theoretical storage capacity varies from 3 to 200GtCO2. Coal contains fractures that give permeability to the system. Between cleats, solid coal has micropores into which gas molecules from the cleats can diffuse and be adsorbed. Coal can adsorb many gases and may contain up to 25 normal m3 methane per tonne of coal at coal seam pressures. It has a higher affinity to adsorb gaseous CO2 than CH4. The volumetric ratio of adsorbable CO2:CH4 ranges from as low as one for mature coals such as anthracite, to immature coals such as lignite. Gaseous CO2 injected through wells will flow,  will diffuse into the coal matrix and  will be adsorbed onto the coal micropore surfaces, freeing up gases with lower affinity to coal such as the methane. The process of CO2 trapping in coals seams for temperatures and pressures above the critical point is not well understood.

The transition temperature depends on:

  • The maturity of the coal
  • The maceral content
  • The ash content
  • The confining stress

Some studies suggest that injected CO2 may react with coal, further highlighting the difficulty in injecting CO2 into low-permeability coal. If CO2 is injected into coal seams, it can displace methane, thereby enhancing CBM recovery. Carbon dioxide ECBM has the potential to increase the amount of produced methane to nearly 90% of the gas, compared to conventional recovery of only 50% by reservoir-pressure depletion alone

Favourable areas for CO2 ECBM include:

  • Adequate permeability
  • Suitable coal geometry
  • Simple structure
  • Homogeneous and confined coal seam that are laterally continuous and vertically isolated
  • Adequate depth
  • Suitable gas saturation conditions
  • Ability to dewater the formation

If the coal is never mined or depressurized, it is likely CO2 will be stored for long time, but, as with any geological  storage option, disturbance of the formation could void any storage.



Flows and  intrusions of basalt occur, with large volumes present around the world. Basalt has low porosity, low permeability and low pore-space continuity and any permeability is associated with fractures through which CO2 will leak unless there is a caprock that avoid it. Basalt may can trap CO2, because injected CO2 may react with silicates in the basalt to form carbonate minerals. However,  these basalts formations appear unlikely to be suitable for CO2 storage (maybe in a future they will be).


The potential for storage of CO2 in oil or gas shale is currently unknown, but the large volumes of shale suggest that storage capacity may be significant. If location criteria (such as minimum depth) are developed and applied to these shales, then volumes could be limited, but the very low permeability of these shales is unlikely to allow the  injection of large volumes of CO2.


Storage of CO2 in salt caverns differs from natural gas and compressed air storage because in the latter case, caverns are cyclically pressurized and depressurized on a daily-to-annual time scale, whereas CO2 storage must be effective on a large time scale. Owing to the creep properties of salt, a cavern filled with supercritical CO2 will decrease in volume, until the pressure inside the cavern equalizes the external stress in the salt bed.


The efficiency in CO2 storage depends on the nature and sealing capacity of the rock in which mining occurs. Heavily fractured rock, would be difficult to seal. Mines in sedimentary rocks may offer some CO2-storage opportunities. Abandoned coal mines also produce the adsorption of CO2 onto coal remaining. However, the rocks above coal mines are strongly fractured, which increases the risk of gas leakage.

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