CCS applied to a modern conventional power plant could reduce CO2 emissions to the atmosphere by approximately 80-90% compared to a plant without CCS. Capturing and compressing CO2 requires much energy and would increase the fuel needs of a coal-fired plant with CCS by about 25%. These and other system costs are estimated to increase the cost of energy from a new power plant with CCS by 21-91%. These estimates apply to purpose-built plants near a storage location: applying the technology to preexisting plants or plants far from a storage location will be more expensive.
Storage of the CO2 is envisaged either in deep geological formations, in deep ocean masses, or in the form of mineral carbonates. In the case of deep ocean storage, there is a risk of greatly increasing the problem of ocean acidification, a problem that also stems from the excess of carbon dioxide already in the atmosphere and oceans. Geological formations are currently considered the most promising sequestration sites, and these are estimated to have a storage capacity of at least 2000 Gt CO2 (currently, 30 Gt per year of CO2 is emitted due to human activities). IPCC estimates that the economic potential of CCS could be between 10% and 55% of the total carbon mitigation effort until year 2100 (Section 8.3.3 of IPCC report).
Costs of energy with and without CCS (2002 US$ per kWh)
|Natural gas combined cycle||Pulverized coal||Integrated gasification combined cycle|
|Without capture (reference plant)||0.03 - 0.05||0.04 - 0.05||0.04 - 0.06|
|With capture and geological storage||0.04 - 0.08||0.06 - 0.10||0.06 - 0.09|
|With capture and Enhanced oil recovery||0.04 - 0.07||0.05 - 0.08||0.04 - 0.08|
|All costs refer to costs for energy from newly built, large-scale plants. Natural gas combined cycle costs are based on natural gas prices of US$2.80–4.40 per GJ (LHV based). Energy costs for PC and IGCC are based on bituminous coal costs of US$1.00–1.50 per GJ (LHV. Note that the costs are very dependent on fuel prices (which change continuously), in addition to other factors such as capital costs. Also note that for EOR, the savings are greater for higher oil prices. Current gas and oil prices are substantially higher than the figures used here. All figures in the table are from Table 8.3a in [IPCC, 2005].|
The cost of CCS depends on the cost of capture and storage which vary according to the method used. Geological storage in saline formations or depleted oil or gas fields typically cost US$0.50–8.00 per tonne of CO2 injected, plus an additional US$0.10–0.30 for monitoring costs. However, when storage is combined with enhanced oil recovery to extract extra oil from an oil field, the storage could yield net benefits of US$10–16 per tonne of CO2 injected (based on 2003 oil prices). This would likely negate some of the effect of the carbon capture when the oil was burnt as fuel. However, as the table above shows, the benefits do not outweigh the extra costs of capture.
Generally, environmental effects from use of CCS arise during power production, CO2 capture, transport and storage. Issues relating to storage are discussed in those sections.
Additional energy is required for CO2 capture, and this means that substantially more fuel has to be used, depending on the plant type. For new supercritical pulverized coal (PC) plants using current technology, the extra energy requirements range from 24-40%, while for natural gas combined cycle (NGCC) plants the range is 11-22% and for coal-based gasification combined cycle (IGCC) systems it is 14-25% [IPCC, 2005]. Obviously, fuel use and environmental problems arising from mining and extraction of coal or gas increase accordingly. Plants equipped with flue gas desulfurization (FGD) systems for SO2 control require proportionally greater amounts of limestone and systems equipped with SCR systems for NOX require proportionally greater amounts of ammonia.
IPCC has provided estimates of air emissions from various CCS plant designs (see table below). While CO2 is drastically reduced (though never completely captured), emissions of air pollutants increase significantly, generally due to the energy penalty of capture. Hence, the use of CCS entails a reduction in air quality.
Emissions to air from plants with CCS (kg/(MW·h))
|Natural gas combined cycle||Pulverized coal||Integrated gasification combined cycle|
|CO2||43 (-89%)||107 (−87%)||97 (−88%)|
|NOX||0.11 (+22%)||0.77 (+31%)||0.1 (+11%)|
|SOX||-||0.001 (−99.7%)||0.33 (+17.9%)|
|Ammonia||0.002 (before: 0)||0.23 (+2200%)||-|
|Based on Table 3.5 in [IPCC, 2005]. Between brackets the increase or decrease compared to a similar plant without CCS.|
An alternate method, which is under development, is chemical looping combustion (CLC). Chemical looping uses a metal oxide as a solid oxygen carrier. Metal oxide particles react with a solid, liquid or gaseous fuel in a fluidized bed combustor, producing solid metal particles and a mixture of carbon dioxide and water vapor. The water vapor is condensed, leaving pure carbon dioxide which can be sequestered. The solid metal particles are circulated to another fluidized bed where they react with air, producing heat and regenerating metal oxide particles that are recirculated to the fluidized bed combustor.
A few engineering proposals have been made for the more difficult task of capturing CO2 directly from the air, but work in this area is still in its infancy. Global Research Technologies demonstrated a pre-prototype in 2007 . Capture costs are estimated to be higher than from point sources, but may be feasible for dealing with emissions from diffuse sources like automobiles and aircraft . The theoretically required energy for air capture is only slightly more than for capture from point sources. The additional costs come from the devices that uses the natural air flow.
COA conveyor belt system or ships can also be used. These methods are currently used for transporting CO2 for other applications.
According to the Congressional Research Service, "There are important unanswered questions about pipeline network requirements, economic regulation, utility cost recovery, regulatory classification of CO2 itself, and pipeline safety. Furthermore, because CO2 pipelines for [enhanced oil recovery] are already in use today, policy decisions affecting CO2 pipelines take on an urgency that is, perhaps, unrecognized by many. Federal classification of CO2 as both a commodity (by the Bureau of Land Management) and as a pollutant (by the Environmental Protection Agency) could potentially create an immediate conflict which may need to be addressed not only for the sake of future CCS implementation, but also to ensure consistency of future CCS with CO2 pipeline operations today. . For a review of federal jurisdictional issues related to CO2 pipelines and reviewing agency jurisdictional determinations under the Interstate Commerce Act and the Natural Gas Act, see Adam Vann and Paul W. Parfomak, "Regulation of Carbon Dioxide (CO2) Sequestration Pipelines: Jurisdictional Issues", updated April 15, 2008 (Order Code RL34307)(http://opencrs.cdt.org/getfile.php?rid=63645).
Various forms have been conceived for permanent storage of CO2. These forms include gaseous storage in various deep geological formations (including saline formations and exhausted gas fields), liquid storage in the ocean, and solid storage by reaction of CO2 with metal oxides to produce stable carbonates.
Unminable coal seams can be used to store CO2 because CO2 adsorbs to the surface of coal. However, the technical feasibility depends on the permeability of the coal bed. In the process of absorption the coal releases previously absorbed methane, and the methane can be recovered (enhanced coal bed methane recovery). The sale of the methane can be used to offset a portion of the cost of the CO2 storage. However, burning the resultant methane would produce CO2, which would negate some of the benefit of sequestering the original CO2.
Saline formations contain highly mineralized brines, and have so far been considered of no benefit to humans. Saline aquifers have been used for storage of chemical waste in a few cases. The main advantage of saline aquifers is their large potential storage volume and their common occurrence. The major disadvantage of saline aquifers is that relatively little is known about them, compared to oil fields. To keep the cost of storage acceptable the geophysical exploration may be limited, resulting in larger uncertainty about the aquifer structure. 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.
For well-selected, designed and managed geological storage sites, IPCC estimates that CO2 could be trapped for millions of years, and the sites are likely to retain over 99% of the injected CO2 over 1,000 years.
The environmental effects of oceanic storage are generally negative, but poorly understood. Large concentrations of CO2 kills ocean organisms, but another problem is that dissolved CO2 would eventually equilibrate with the atmosphere, so the storage would not be permanent. Also, as part of the CO2 reacts with the water to form carbonic acid, H2CO3, the acidity of the ocean water increases. The resulting environmental effects on benthic life forms of the bathypelagic, abyssopelagic and hadopelagic zones are poorly understood. Even though life appears to be rather sparse in the deep ocean basins, energy and chemical effects in these deep basins could have far reaching implications. Much more work is needed here to define the extent of the potential problems.
The time it takes water in the deeper oceans to circulate to the surface has been estimated to be in the order of 1600 years, varying upon currents and other changing conditions. Costs for deep ocean disposal of liquid CO2 are estimated at US$40−80/ton. (2002 USD) This figure covers the cost of sequestration at the powerplant and naval transport to the disposal site. 
The bicarbonate approach would reduce the pH effects and enhance the retention of CO2 in the ocean, but this would also increase the costs and other environmental effects.
An additional method of long term ocean based sequestration is to gather crop residue such as corn stalks or excess hay into large weighted bales of biomass and deposit it in the alluvial fan areas of the deep ocean basin. Dropping these residues in alluvial fans would cause the residues to be quickly buried in silt on the sea floor, sequestering the biomass for very long time spans. Alluvial fans exist in all of the world's oceans and seas where river deltas fall off the edge of the continental shelf such as the Mississippi alluvial fan in the gulf of Mexico and the Nile alluvial fan in the Mediterranean Sea.
"Carbon sequestration by reacting naturally occurring Mg and Ca containing minerals with CO2 to form carbonates has many unique advantages. Most notably is the fact that carbonates have a lower energy state than CO2, which is why mineral carbonation is thermodynamically favorable and occurs naturally (e.g., the weathering of rock over geologic time periods). Secondly, the raw materials such as magnesium based minerals are abundant. Finally, the produced carbonates are unarguably stable and thus re-release of CO2 into the atmosphere is not an issue. However, conventional carbonation pathways are slow under ambient temperatures and pressures. The significant challenge being addressed by this effort is to identify an industrially and environmentally viable carbonation route that will allow mineral sequestration to be implemented with acceptable economics.
In this process, CO2 is exothermically reacted with abundantly available metal oxides which produces stable carbonates. This process occurs naturally over many years and is responsible for much of the surface limestone. The reaction rate can be made faster, for example by reacting at higher temperatures and/or pressures, or by pre-treatment of the minerals, although this method can require additional energy. The IPCC estimates that a power plant equipped with CCS using mineral storage will need 60-180% more energy than a power plant without CCS.
|Earthen Oxide||Percent of Crust||Carbonate||Enthalpy change|
It should also be noted that at the conditions of the deeper oceans, (about 400 bar or 40 MPa, 280 K) water–CO2(l) mixing is very low (where carbonate formation/acidification is the rate limiting step), but the formation of water-CO2 hydrates is favorable. (a kind of solid water cage that surrounds the CO2). 
To further investigate the safety of CO2 sequestration, we can look into Norway's Sleipner gas field, as it is the oldest plant that stores CO2 on an industrial scale. According to an environmental assessment of the gas field which was conducted after ten years of operation, the author affirmed that geosequestration of CO2 was the most definite way to store CO2 permanently. 
"Available geological information shows absence of major tectonic events after the deposition of the Utsira formation [saline reservoir]. This implies that the geological environment is tectonically stable and a site suitable for carbon dioxide storage. The solubility trapping [is] the most permanent and secure form of geological storage." 
The Weyburn project is currently the world's largest carbon capture and storage project. Started in 2000, Weyburn is located on an oil reservoir discovered in 1954 in Weyburn, southeastern Saskatchewan, Canada. The CO2 for this project is captured at the Great Plains Coal Gasification plant in Beulah, North Dakota which has produced methane from coal for more than 30 years. At Weyburn, the CO2 will also be used for enhanced oil recovery with an injection rate of about 1.5 million tonnes per year. The first phase finished in 2004, and demonstrated that CO2 can be stored underground at the site safely and indefinitely. The second phase, expected to last until 2009, is investigating how the technology can be expanded on a larger scale.
The fourth site is In Salah, which like Sleipner and Snøhvit is a natural gas reservoir located in In Salah, Algeria. The CO2 will be separated from the natural gas and re-injected into the subsurface at a rate of about 1.2 million tonnes per year.
A major Canadian initiative called the Alberta Saline Aquifer Project (ASAP) is a consortium of 34 compaies that are developing a pilot site for commercial scale carbon capture and storage in a saline aquifer. The inital pilot will sequester 1,000 tonnes per day in 2010, while the commercial phase could see 10,000 tonnes per day as soon as 2015.
Another Canadian initiative called the Integrated CO2 Network (ICO2N) is a proposed system for the capture, transport and storage of carbon dioxide (CO2). ICO2N members represent a group of industry participants providing a framework for carbon capture and storage development in Canada.
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. The region has the potential to store more than 200 billion tons of CO2 from major point sources in the region, equal to about 33 years of U.S. emissions overall at present rates. 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 (25 km) east of Natchez, Mississippi. Experimental equipment will measure the ability of the subsurface to accept and retain CO2.
Currently, the United States government has approved the construction of what is touted as the world's first CCS power plant, FutureGen. On January 29, 2008, however, the Department of Energy announced it was withdrawing funding from FutureGen, as it had originally been proposed, casting considerable doubt on the future of the project and in the view of some effectively terminating the project.
Examples of carbon sequestration at an existing US coal plant can be found at utility company Luminant's pilot version at its Big Brown Steam Electric Station in Fairfield, Texas. This system is converting carbon from smokestacks into baking soda. Skyonic plans to circumvent storage problems of liquid CO2 by storing baking soda in mines, landfills, or simply to be sold as industrial or food grade baking soda. GreenFuel Technologies Corp. is piloting and implementing algae based carbon capture, circumventing storage issues by then converting algae into fuel or feed.
In the Netherlands, an 68 MW oxyfuel plant ("Zero Emission Power Plant") is being planned and is expected to be operational in 2009.
In the United States, four different synthetic fuels projects are moving forward which have publicly announced plans to incorporate carbon capture and storage.
American Clean Coal Fuels, in their Illinois Clean Fuels project, is developing a 30,000 Barrel Per Day Biomass and Coal to Liquids project in Oakland Illinois, which will market the CO2 created at the plant for Enhanced Oil Recovery applications. The project is expected to come online in late 2012.
Baard Energy, in their Ohio River Clean Fuels project, are developing a 53,000 BPD Coal and Biomass to Liquids project, which has announced plans to market the plant’s CO2 for Enhanced Oil Recovery.
Rentech is developing a 29,600 barrel per day coal and biomass to liquids plant in Natchez Mississippi which will market the plant’s CO2 for enhanced oil recovery. The first phase of the project is expected in 2011.
DKRW is developing a 15,000-20,000 Barrel Per Day coal to liquids plant in Medicine Bow Wyoming, which will market it plant’s CO2 for enhanced oil recovery. The project is expected to begin operation in 2013.
This plant does not propose to capture CO2 from coal fired power generation. There is no project anywhere in the world storing CO2 stripped from the products of combustion of coal burnt for electricity generation at coal fired power stations.
|The extra processes involved in CCS incur an additonal energy penalty.||The technology is expected to use between 10 and 40% of the energy produced by a power station. Wide scale adoption of CCS may erase efficiency gains of the last 50 years, and increase resource consumption by one third.|
|Storing carbon underground is risky.||It is claimed that safe and permanent storage of CO2 cannot be guaranteed and that even very low leakage rates could undermine any climate mitigation efforts. However, the IPCC conclude that the proportion of CO2 retained in appropriately selected and managed geological reservoirs is very likely to exceed 99% over 100 years and is likely to exceed 99% over 1,000 years .|
|CCS is expensive.||CCS could lead to a doubling of plant costs, and an electricity price increase though CCS may be economically attractive in comparison to other forms low carbon electricity generation . It is claimed by opponents to CCS that money spent on CCS will divert investments away from sustainable solutions to climate change.|