About CCS

Injection & storage

Detailed site characterisation: Geoscience and engineering characterisation


Injectivity is the rate at which CO2 can be injected into a given reservoir and the ability of the CO2 plume to migrate away from the injection well. Factors which affect injectivity include the viscosity ratio of CO2 to other formation fluids, the injection rate and the relative permeability of the reservoir.

Core samples can be used to determine the porosity and permeability of the reservoir rock. Wireline logs of existing wells give one dimensional data, so rock properties have to be inferred through the use of well log correlation, the use of analogues and seismic interpretation. Static reservoir models should be constructed to map reservoir distribution and horizontal and vertical connectivity.

CO2 dissolution into formation water can result in CO2-water-rock interactions which may alter the pore system of the rock, so the mineralogical composition of the reservoir should be included in evaluating injectivity.

In deep saline formations, which typically have low permeability, the ideal objective is high permeability near the wellbore to improve injectivity and lower permeability outside the radius of influence of the wellbore to increase residence times.


Supercritical CO2 is less dense than water and has the tendency to be driven upward due to buoyancy forces. Loss of CO2 can occur through migration through the top seal, faults and fractures or via wells.

Factors that contribute to containment include:

The distribution and continuity of the seal The seal capacity (maximum CO2 column height retention)

The top seal is called the cap rock. Good cap rock is uniform, regionally extensive, thick, strong and unlikely to be weakened though CO2–water–rock reactions.

The seal capacity is dependent on the capillary pressure properties of the sealing rock and physio-chemical properties of CO2 and the formation water such as density, wettability and interfacial tension. Water pumping tests can be used to measure the rate of leakage across the cap rock. The sealing capacity of rock can also be estimated by mercury injection capillary pressure (MICP) analysis of core samples. This analysis determines the capillary pressure that is required to move mercury through the pore system of the sample. This pressure is converted to an equivalent CO2 brine pressure and then used to determine CO2 column height.
Integrity of reservoir and seal rock The potential for CO2-water-rock interaction
When the CO2 is injected, it increases the pressure in the formation which can potentially reactivate pre-existing faults or generate new fractures. The maximum sustainable fluid pressure for CO2 injection can be determined through geomechanical modelling. The injected CO2may react chemically with the rock. Detailed reservoir petrology, water chemistry and pressure-temperature conditions enable mineral reactions with CO2 to be predicted. Mineral precipitation of CO2 can lead to mineral trapping and hence greater containment security.
Migration pathways Intraformational seals which act as localised barriers
The structural orientations and dips in the reservoir can be predicted using stratigraphic, subsurface wireline and seismic data. Because the injected CO2 is more buoyant than water, it will migrate vertically to the top of the reservoir. Once there, the geometry of the seal will have a strong influence on the subsequent migration direction and rate. Other characteristics that need to be identified are the trapping mechanisms. The presence of siltstones and shales within the reservoir formation can reduce the vertical flow of the CO2 and create a more complex migration pathway. Such siltstones and shales contribute to the degree of stratigraphic heterogeneity of the formation. In a homogenous formation, the buoyant CO2 will migrate vertically up to the top of the reservoir.
Formation water flow direction and rate
Understanding the flow system of the existing formation water within a reservoir is important to determine how effective hydrodynamic trapping will be. Using hydrodynamic models, the impact of vertical connectivity, horizontal continuity and low permeability zones on the migrating CO2 plume can be assessed.


CO2 storage capacity is an estimate of the amount of CO2 that can be stored in subsurface geological formations. It is influenced by the density of CO2 at subsurface conditions, the amount of interconnected pore volume of the reservoir rock and the nature of the formation fluids.

>> More about storage capacity

Data Sources

Seismic data

Seismic data is based on how sound waves are reflected by fluid in the subsurface. It uses variation in structure, density and velocity to build a picture of the subsurface. Uncertainty associated with seismic data should be documented. This uncertainty can be reduced by using it alongside other data sources such as well logs and core data.

>> More about seismic data collection

Well log and core data

Well log (or wireline) data provides continuous measurement of the physical properties of rocks and fluids along the borehole. Such properties include resistivity, conductivity, sonic properties and radioactivity. From this information, grain size, porosity, density and the composition of formation fluids can be inferred. Such properties can be confirmed using core samples.

Results can be correlated between wells and the accuracy of this correlation influences the quality of the geological interpretation of the data. Consequently, the uncertainty in the data is reduced with dense well spacing.

Wireline tests or drill stem tests can provide data such as formation pressure, permeability, fluid type, density and location of fluid. Formation pressure is an important aspect of hydrogeological modelling, injectivity studies, geomechanical modelling, seal capacity estimates, flow modelling and determining horizontal and vertical connectivity in reservoirs.


The reservoir models can be improved using existing high quality data (such as an outcrop or good subsurface data) for the same depositional environment as that of the potential storage site. These analogues can provide information about the possible dimensions, orientation and structure of a reservoir body of the outcrops or subsurface formations e.g. it is possible to estimate the width of a reservoir from the information obtained from a well core.

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