[ Skip to content]

  UK Carbon Capture & Storage Research Centre

You are here: UK Carbon Capture & Storage Research Centre >> What is CCS?

Supported by

Supported by the RCUK Energy Programme and the EPSRC.

CO2 Storage

Research Area Champions: Jerry Blackford, Stuart Haszeldine, Martin Blunt, Andy Chadwick & Jon Gluyas.

In order to have an impact on man-made emissions very large volumes of captured CO2 must be safely stored and excluded from the atmosphere. The largest available sink we have is subsurface geological formations, where CO2 can be stored in the pore space of sedimentary rocks. These formations mainly consist of highly porous sandstones which are capped by low permeability rock formations such as shales. In order to maximise the security of geological storage reservoirs are typically greater than 800 m below the Earth's surface. At this depth CO2 is in a dense supercritical state which is less buoyant than the gas phase. Being in a dense phase is also advantageous to storage capacity. A tonne of CO2 at STP (0˚C and 1 atm) has a volume of 509m2, if the geothermal and lithostatic gradients are 35 ˚C/km and 22.5MPa/km respectively then the same mass of CO2 will have a volume of only 2.5m2 if it is stored 1km below the surface. The UK has a huge potential for offshore geological storage with numerous potential storage reservoirs within the northern and central North Sea Basin, the southern North Sea Basin and the East Irish Sea Basin. It has been estimated that the UK has 16-20Gt (i.e. 16 – 20,000,000,000 tonnes) and 19-716Gt worth of storage capacity in abandoned hydrocarbon fields and saline aquifers respectively. This is enough to store over 500 years of the UK's annual emissions. Important aspects of geological storage not only include storage security but also injection strategies and monitoring techniques.

Storage BGS

Storage Security

There are four principle geological processes which can physically or chemically trap injected CO2 within the storage reservoir. Structural and stratigraphic trapping involves low permeability layers, such as a shale caprock, or geological structures, such as anticlines. These low permeability layers prevent the buoyant ascent of CO2 as they have a high capillary entry pressure which basically means that the pore fluid in the low permeability layer is at a significantly higher pressure than ascending CO2. Solubility trapping occurs when CO2 dissolves into brine (pore water containing large amounts of salt) and becomes an aqueous phase. This brine/CO2 mixture is denser than the surrounding brine and so will sink towards the bottom of the reservoir. Dissolution of CO2 into brine produces a mild acid which can then undergo chemical reaction with silicate minerals rich in Ca, Mg and Fe to form solid carbonate minerals. This process, known as mineral trapping, is the most stable and permanent form of storage, however it is a slow process that takes place over hundreds to many thousands of years. Residual trapping occurs when blobs of CO2, at a range of scales, become isolated as reservoir brine flows into the tail of a migrating CO2 plume. This trapping mechanism could well prove to be the most important as experimental work has shown that up to 70% of injected CO2 can be immobilised in this manner.

Cartoon of geological trapping mechanisms
Burnside & Naylor, DEVEX, 12 May 2011.


Injection of CO2 is a highly technical challenge- CO2 must be injected from the surface to hundreds of metres depth through an injection well which typically has a length to width ratio of 10,000:1. The process of injecting CO2 increases the pressure in the reservoir both through the force of injection and the addition of large volumes of CO2. Great care must be taken during injection as this pressure increase may reactivate old faults or create new ones through hydrofracture. Most formations at depth are underpressured- that is the hydrostatic pressure of the pore fluid is less than that of the lithostatic pressure caused by the weight of the rocks above the formation. Over pressure and formation of fractures occurs when the hydrostatic pressure increases above the fracture gradient (the point at which the rock breaks and accepts fluid) of the formation. For depleted oil and gas fields the pressure can be safely raised to near the pressure prior to hydrocarbon production. There is a trickier challenge for injection into saline aquifers as increased fluid pressures may lead to the storage reservoir becoming overpressured depending on the permeability and lateral continuity of the reservoir.


The aim of monitoring injected CO2 is to demonstrate the effectiveness of a storage project and to check for any possible leakage. Migration of CO2 from the storage reservoir could possibly occur through poorly sealed and improperly abandoned wellbores or transmissive faults and fractures in the caprock. An escape of CO2 from storage could be detected through losses in the reservoir, migration in the rock above the reservoir and elevated CO2 concentrations in the surface environment. There is a range of monitoring techniques that can be deployed to monitor the migration of CO2 in the reservoir and detect leakage of CO2. For monitoring the reservoir seismic imaging and downhole pressure/temperature measurements are key tools;, gravimetry, electromagnetics and other techniques can also add useful information. For leakage monitoring onshore, surface or atmospheric techniques such as eddy covariance, open path lasers, soil gas flux and concentration measurements can be deployed. Leakage into the marine environment can be detected, and to a degree measured, using seabed and water-column acoustic imaging and sampling, water geochemistry, benthic chambers, and observation of seabed fauna. The success of any of these methods for accurately quantifying leakage from a CCS site will depend on their ability to locate and define the physical extent of a leak and their ability to accurately separate baseline (initial data collected prior to injection) from leakage flux rates. It is also worth noting that should a CO2 storage project leak it would be in line for financial penalties under various pieces of legislation.

2006 3D Seismic image of Sleipner
3D seismic image of the CO2 plume (bright reflections under the reservoir topseal) at Sleipner in 2006 (courtesy of BGS and the CO2ReMoVe project).
  Contact: Elizabeth Vander Meer | This page was Last modified: 14 Mar, 2012 | Hosted on servers at UoE School of GeoSciences