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Carbon dioxide storage in geologic formations includes oil and gas reservoirs, unmineable coal seams, and deep saline reservoirs. These are structures that have stored crude oil, natural gas, brine and CO2 over millions of years.
The primary goal of our carbon storage research is to understand the behavior of CO2 when stored in geologic formations. For example, studies are being conducted to determine the extent to which the CO2 moves within the geologic formation, and when CO2 is injected, what physical and chemical changes occur within the formation. This information is key to ensure that carbon storage will not affect the structural integrity of an underground formation, and that CO2 storage is secure and environmentally acceptable. The goals of this effort are to predict geologic storage capacity to within +/- 30 percent, and permanence of geologic storage up to 99 percent.
Oil and Gas Reservoirs. In some cases, production from an oil or natural gas reservoir can be enhanced by pumping CO2 into the reservoir to push out the product, which is called enhanced oil recovery. The United States is the world leader in enhanced oil recovery technology, using about 32 million tons of CO2 per year for this purpose. Enhanced oil recovery (EOR) represents an opportunity to use man-made CO2 to recover additional oil while permanently storing CO2 in the formation.
In an enhanced oil recovery application, the integrity of the CO2 that remains in the reservoir is well-understood and very high, as long as the original pressure of the reservoir is not exceeded. The scope of this EOR application is currently economically limited to point sources of CO2 emissions that are near an oil or natural gas reservoir.
Coal Bed Methane. Coal beds typically contain large amounts of methane-rich gas that is adsorbed onto the surface of the coal. The current practice for recovering coal bed methane is to depressurize the bed, usually by pumping water out of the reservoir. An alternative approach is to inject CO2 into the bed. Tests have shown that the adsorption rate for CO2 to be approximately twice that of methane, giving it the potential to efficiently displace methane and remain stored in the bed. CO2 recovery of coal bed methane has been demonstrated in limited field tests, but much more work is necessary to understand and optimize the process.
The recovered methane provides a value-added revenue stream to the carbon sequestration process, similar to the by-product value gained from enhanced oil recovery, thus improving economics of carbon storage. The U.S. coal resources are estimated at 6 trillion tons, and 90 percent of it is currently unmineable due to seam thickness, depth, and structural integrity. Another promising aspect of CO2 storage in coal beds is that many of the large unmineable coal seams are near electricity generating facilities that can be large point sources of CO2 gas. Thus, limited pipeline transport of CO2 gas would be required. Integration of coal bed methane with a coal-fired electricity generating system can provide an option for additional power generation with low emissions.
Saline Formations. Storage of CO2 in deep saline formations does not produce value-added by-products, but it has other advantages. First, the estimated carbon storage capacity of saline formations in the United States is large, making them a viable long-term solution. It has been estimated that deep saline formations in the United States could potentially store more than 12,000 billion tonnes of CO2.
Second, most existing large CO2 point sources are within easy access to a saline formation injection point, and therefore storage in saline formations is compatible with a strategy of transforming large portions of the existing U.S. energy and industrial assets to near-zero carbon emissions via low-cost carbon storage retrofits.
Assuring the environmental acceptability and safety of CO2 storage in saline formations is a key component of this program element.The determination that CO2 will not escape from formations and either migrate up to the earth's surface or contaminate drinking water supplies is a key aspect of carbon storage research. Although much work is needed to better understand and characterize sequestration of CO2 in deep saline formations, a significant baseline of information and experience exists. For example, the oil industry routinely injects brines from the recovered oil into saline reservoirs as part of enhanced oil recovery operations, and the U.S. Environmental Protection Agency (EPA) has permitted some hazardous waste disposal sites that inject liquid wastes into deep saline formations.
Geologic Storage Technology
DOE is supporting the development of tools and protocols to improve the ability to predict future capacity in geologic storage systems within +/- 30 percent, assess and minimize the impacts of CO2 and co-contaminants on geophysical processes, and improve our understanding of injectivity. Additionally, simulation models and tools are being developed in order to more accurately predict the flow of the CO2 in the target formations, chemical changes that may occur in the reservoir, and geomechanical effects that increased pressures might have on the target formation and seal(s). Improved models that can simulate faults/fractures, the subsurface behavior of system fluids, and geochemical/mechanical/flow effects are needed. Research continues to develop innovative, advanced simulation models that can be readily integrated with advanced MVA technologies and risk assessment protocols. These models will include full coupling of multiple physical and chemical processes and describe the effects of the coupled processes on CO2 transport.