What is GCS?

Geological carbon sequestration

The method of geo-sequestration or geological storage involves injecting carbon dioxide directly into underground geological formations. Declining oil fields, saline aquifers, and unminable coal seams have been suggested as storage sites. Caverns and old mines that are commonly used to store natural gas are not considered, because of a lack of storage safety.

CO2 has been injected into declining oil fields for more than 40 years, to increase oil recovery. This option is attractive because the storage costs are offset by the sale of additional oil that is recovered. Typically, 10-15% additional recovery of the original oil in place is possible. Further benefits are the existing infrastructure and the geophysical and geological information about the oil field that is available from the oil exploration. Another benefit of injecting CO2 into Oil fields is that CO2 is soluble in oil. Dissolving CO2 in oil lowers the viscosity of the oil and reduces its interfacial tension which increases the oils mobility. All oil fields have a geological barrier preventing upward migration of oil. As most oil and gas has been in place for millions to tens of millions of years, depleted oil and gas reservoirs can contain carbon dioxide for millennia. Identified possible problems are the many 'leak' opportunities provided by old oil wells, the need for high injection pressures and acidification which can damage the geological barrier. Other disadvantages of old oil fields are their limited geographic distribution and depths, which require high injection pressures for sequestration. Below a depth of about 1000 m, carbon dioxide is injected as a supercritical fluid, a material with the density of a liquid, but the viscosity and diffusivity of a gas. Unminable coal seams can be used to store CO2, because CO2 absorbs to the coal surface, ensuring safe long-term storage. In the process it releases methane that was previously adsorbed to the coal surface and that may be recovered. Again the sale of the methane can be used to offset the cost of the CO2 storage. Release or burning of methane would of course at least partially offset the obtained sequestration result – except when the gas is allowed to escape into the atmosphere in significant quantities: methane has a higher global warming potential than CO2.

Saline aquifers contain highly mineralized brines and have so far been considered of no benefit to humans except in a few cases where they have been used for the storage of chemical waste. Their advantages include a large potential storage volume and relatively common occurrence reducing the distance over which CO2 has to be transported. The major disadvantage of saline aquifers is that relatively little is known about them compared to oil fields. Another disadvantage of saline aquifers is that as the salinity of the water increases, less CO2 can be dissolved into aqueous solution. To keep the cost of storage acceptable the geophysical exploration may be limited, resulting in larger uncertainty about the structure of a given aquifer. Unlike storage in oil fields or coal beds, no side product will offset the storage cost. Leakage of CO2 back into the atmosphere may be a problem in saline-aquifer storage. However, current research shows that several trapping mechanisms immobilize the CO2 underground, reducing the risk of leakage.

A major research project examining the geological sequestration of carbon dioxide is currently being performed at an oil field at Weyburn in south-eastern Saskatchewan. In the North Sea, Norway's Statoil natural-gas platform Sleipner strips carbon dioxide out of the natural gas with amine solvents and disposes of this carbon dioxide by geological sequestration. Sleipner reduces emissions of carbon dioxide by approximately one million tonnes a year. The cost of geological sequestration is minor relative to the overall running costs. As of April 2005, BP is considering a trial of large-scale sequestration of carbon dioxide stripped from power plant emissions in the Miller oilfield as its reserves are depleted.

In October 2007, the Bureau of Economic Geology at The University of Texas at Austin received a 10-year, $38 million subcontract to conduct the first intensively monitored, long-term project in the United States studying the feasibility of injecting a large volume of CO2 for underground storage. The project is a research program of the Southeast Regional Carbon Sequestration Partnership (SECARB), funded by the National Energy Technology Laboratory of the U.S. Department of Energy (DOE). The SECARB partnership will demonstrate CO2 injection rate and storage capacity in the Tuscaloosa-Woodbine geologic system that stretches from Texas to Florida. Beginning in fall 2007, the project will inject CO2 at the rate of one million tons per year, for up to 1.5 years, into brine up to 10,000 feet (3,000 m) below the land surface near the Cranfield oil field about 15 miles (24 km) east of Natchez, Mississippi. Experimental equipment will measure the ability of the subsurface to accept and retain CO2.