Carbon capture and storage

Carbon capture and storage (CCS) is an approach to reduce emissions of greenhouse gases by capturing carbon dioxide (CO₂) from large point sources such as fossil fuel power plants and storing it instead of releasing it into the atmosphere. Technology for large scale capture of CO₂ is already commercially available and fairly well developed. Although CO₂ has been injected into geological formations for various purposes, the long term storage of CO₂ is a relatively untried concept and as yet (2007) no large scale power plant operates with a full carbon capture and storage system.

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. Rarely considered in such mathematics is the embodied carbon cost of the equipment and machinery needed to create this act of reverse-entropy.

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.

CO₂ capture

Capturing CO₂ can be applied to large point sources, such as large fossil fuel or biomass energy facilities, industries with major CO₂ emissions, natural gas processing, synthetic fuel plants and fossil fuel-based hydrogen production plants. Broadly, three different types of technologies exist: Post-combustion, pre-combustion, and oxyfuel combustion.

• In post-combustion, the CO₂ is removed after combustion of the fossil fuel - this is the scheme that would be applied to conventional power plants. Here, carbon dioxide is captured from flue gases at power plantss. The technology is well understood and is currently used in other industrial applications.

• The technology for pre-combustion is widely applied in fertilizer, chemical, gaseous fuel (H₂, CH₄), and power production In these cases, the fossil fuel is partially oxidized, for instance in a gasifier. The resulting syngas (CO and H₂) is shifted into CO₂ and more H₂. The resulting CO₂ can be captured from a relatively pure exhaust stream. The H₂ can now be used as fuel; the carbon is removed before combustion takes place.

• In Oxy-fuel combustion the fuel is burned in oxygen instead of air. To limit the resulting flame temperatures to levels common during conventional combustion, cooled flue gas is recirculated and injected into the combustion chamber. The flue gas consists of mainly carbon dioxide and water vapour, the latter of which is condensed through cooling. The result is an almost pure carbon dioxide stream that can be transported to the sequestration site and stored. Power plant processes based on oxyfuel combustion are sometimes referred to as "zero emission" cycles, because the CO₂ stored is not a fraction removed from the flue gas stream (as in the cases of pre- and post-combustion capture) but the flue gas stream itself. It should be noted, however, that a certain fraction of the CO₂ generated during combustion will inevitably end up in the condensed water. To warrant the label "zero emission" the water would thus have to be treated or disposed of appropriately. The technique is promising, but the initial air separation step demands a lot of energy.

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 much 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 much higher than from point sources, but may be feasible for dealing with emissions from diffuse sources like automobiles and aircraft.

CO₂ transport

After capture, the CO₂ must be transported to suitable storage sites. This is done by pipeline, which is generally the cheapest form of transport. In 2008, there were approximately 5,800 km of CO₂ pipelines in the United States. These pipelines are currently used to transport CO₂ to oil production fields where the CO₂ is injected in older fields to produce oil. The injection of CO₂ to produce oil is generally called "Enhanced Oil Recovery" or EOR. In addition, there are several pilot programs in various stages to test the long-term storage of CO₂ in non-oil producing geologic formations. These are discussed below.

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.

CO₂ storage (sequestration)

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.

Geological storage

Also known as geosequestration, this method involves injecting carbon dioxide, generally in supercritical form, directly into underground geological formations. Oil fields, gas fields, saline formations, unminable coal seams, and saline-filled basalt formations have been suggested as storage sites. Here, various physical (e.g., highly impermeable caprock) and geochemical trapping mechanisms would prevent the CO₂ from escaping to the surface. CO₂ is sometimes injected into declining oil fields to increase oil recovery (enhanced oil recovery). This option is attractive because the storage costs may be partly offset by the sale of additional oil that is recovered. Disadvantages of old oil fields are their geographic distribution and their limited capacity, as well as that the subsequent burning of the additional oil so recovered will offset much or all of the reduction in CO₂ emissions.

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.

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. This will reduce the distances 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. 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.

Ocean storage

Another proposed form of carbon storage is in the oceans. Two main concepts exist. The 'dissolution' type injects CO₂ by ship or pipeline into the water column at depths of 1000 m or more, and the CO₂ subsequently dissolves. The 'lake' type deposits CO₂ directly onto the sea floor at depths greater than 3000 m, where CO₂ is denser than water and is expected to form a 'lake' that would delay dissolution of CO₂ into the environment. A third concept is to convert the CO₂ to bicarbonates (using limestone) or hydrates.

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 on 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/tonTemplate:Vague. (2002 USD) This figure covers the cost of sequestration at the power plant and naval transport to the disposal site. [2]

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.

Mineral storage

"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.

The following table lists principal metal oxides of Earth's Crust. Theoretically up to 22% of this mineral mass is able to form carbonates.

Earthen Oxide	Percent of Crust	Carbonate
SiO2	59.71
Al2O3	15.41
CaO	4.90	CaCO3
MgO	4.36	MgCO3
Na2O	3.55	Na2CO3
FeO	3.52	FeCO3
K2O	2.80	K2CO3
Fe2O3	2.63	FeCO3
	21.76	All carbonates

Leakage

A major concern with CCS is whether leakage of stored CO₂ will compromise CCS as a climate change mitigation option. For well-selected, designed and managed geological storage sites, IPCC estimates that risks are comparable to those associated with current hydrocarbon activity. CO₂ could be trapped for millions of years, and well selected stores are likely to retain over 99% of the injected CO₂ over 1000 years. For ocean storage, the retention of CO₂ would depend on the depth; IPCC estimates 30–85% would be retained after 500 years for depths 1000–3000 m. Mineral storage is not regarded as having any risks of leakage. The IPCC recommends that limits be set to the amount of leakage that can take place.

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). [3]

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. [4]

"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." [4]

Phase I of the Weyburn Project in Weyburn, Saskatchewan, Canada has determined that the likelihood of stored CO₂ release is less than one percent in 5,000 years.

Cost of CCS

Capturing and compressing CO₂ requires much energy, significantly raising the running costs of CCS-equipped power plants. In addition there are added investment or capital costs. The process would increase the fuel requirement of a plant with CCS by about 25% for a coal-fired plant and about 15% for a gas-fired plant. The costs of storage and other system costs are estimated to increase the costs of energy from a power plant with CCS by 30-60%, depending on the specific circumstances.

Costs of energy with and without CCS (2002 US$ per kWh)

Type of power plant ⇒	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 for energy from new large-scale plants. Natural gas combined cycle costs are based on natural gas prices of US$2.80–4.40 per GJ (LHV). Energy costs for pulverized coal and integrated gasification combined cycle 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 Enhance Oil Recovery, 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). However, as the table above shows, the benefits do not outweigh the extra costs of capture.

Environmental effects

The merit of CCS systems is the reduction of CO₂ emissions by up to 90%, depending on plant type (see table below).

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%. 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 per MWh)

Type of power plant ⇒	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%]
NH3	0.002   [without: 0]	0.23   [+ 2200%]	--
Based on Table 3.5 in IPCC, 2005. Values in brackets are the percentage increase or decrease compared to similar power plants without CCS.

CO₂ Reuse

A potentially useful way of dealing with industrial sources of CO₂ is to convert it into hydrocarbons where it can be stored or reused as fuel or to make plastics. There are a number of projects investigating this possibility.:

Single Step methods: CO₂ + H₂ → Methanol

A proven process to produce a hydrocarbon is to make methanol. Methanol is rather easily synthesized from CO₂ and H₂. Based on this fact the idea of a methanol economy was born.

Single Step methods: CO₂ → Hydrocarbons

At the department of Industrial Chemistry and Engineering of Materials at the University of Messina, Italy there is a project to develop a system which works like a fuel-cell in reverse, whereby a catalyst is used that enables sunlight to split water into hydrogen ions and oxygen gas. The ions cross a membrane where they react with the CO₂ to create hydrocarbons.

2 Step methods: CO₂ → CO → Hydrocarbons

If CO₂ is heated to 2400 degrees celsius then it splits into carbon monoxide and oxygen. From there the Fisher-Tropsch process can be used to convert the CO into hydrocarbons. The required temperature can be achieved by using a chamber containing a mirror to focus sunlight on the gas. There are a couple of rival teams developing such chambers: 'Los Alamos Renewable Energy' and 'Sandia National Laboratories' both based in New Mexico. According to Sandia these chambers could provide enough fuel to power 100% domestic vehicles using 5800 square kilometers, but unlike biofuels this would not take fertile land away from crops but would be land that is not being used for anything else.

Example CCS projects

As of 2007, four industrial-scale storage projects are in operation. Sleipner [1] is the oldest project (1996) and is located in the North Sea where Norway's StatoilHydro strips carbon dioxide from natural gas with amine solvents and disposes of this carbon dioxide in a deep saline aquifer. The carbon dioxide is a waste product of the field's natural gas production and the gas contains more (9% CO₂) than is allowed into the natural gas distribution network. Storing it underground avoids this problem and saves Statoil hundreds of millions of euro in avoided carbon taxes. Since 1996, Sleipner has stored about one million tonnes CO₂ a year. A second project in the Snøhvit gas field in the Barents Sea stores 700,000 tonnes per year.

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 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 tonsTemplate:Vague 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 tonsTemplate:Vague 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.

Carbon Trap Technologies, L.P., (“CTT”) was formed in early 2007 to develop and to market a technology to chemically sequester carbon dioxide emissions from fossil fuel combustion, while producing useful products with significant market value.

In the Netherlands, an 68 MW oxyfuel plant ("Zero Emission Power Plant") is being planned and is expected to be operational in 2009.

Australia

The federal Resources and Energy Minister Martin Ferguson has opened the first geosequestration project in the southern hemisphere. The demonstration plant is near Nirranda South in South Western Victoria. (Template:Coord) The plant is owned by the CO2 Cooperative Research Centre. It is government funded. It will try to capture and compress 100,000 tonnes of carbon dioxide from natural gas. The plant will then try to store this in a depleted natural gas reservoir. This project is tiny by world standards as BP's Algerian plant is storing 1,000,000 tonnes each year.

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 plants.