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Carbon Capture and Storage

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Carbon Capture and Storage (CCS), or carbon sequestration, is a means of separating out carbon dioxide when burning fossil fuels, collecting it and subsequently “dumping” it underground or in the sea. CCS is an integrated concept consisting of three distinct components: CO2 capture, transport and storage (including measurement, monitoring and verification). All three components are currently found in industrial operation today, although mostly not for the purpose of CO2 storage.

A 2010 Government Accountability Office report noted that the largest demonstration of carbon capture in a coal plant was at a pilot scale (TRL 7) or less, and that demonstration of large scale integrated CCS systems is a technical challenge that is at least 10-15 years away from being realized.[1]

System Overview

CCS consists of three main components: (1) capture, (2), transport, and (3) storage.

Capture

By far the most energy intensive portion of the CCS process, carbon capture produces a concentrated stream of CO2 that can be compressed, transported and eventually stored. Some capture technologies are economically feasible under specific conditions while others remain in the research stages. To date, there has not been a single application of CCS to large scale (> 500 MW) power stations. Since every ton of coal burned produces 3.7 tons of CO2, the sheer volume of CO2 that must be disposed of makes CCS inherently impractical and overly expensive.[2]

Depending on the process or power station in question, three approaches to capture exist- pre-, post- and oxyfuel combustion:

  • Pre-combustion capture systems remove CO2 prior to combustion. This is accomplished via gasification. The gasification of a fossil fuel produces a “synthesis gas” (syn gas), which is primarily a mixture of carbon monoxide, methane and hydrogen. Before combustion, the syn gas is reacted with steam to produce CO2 that is subsequently scrubbed from the gas stream, usually by a physical or chemical absorption process. The result is a hydrogen-rich fuel that can be used in a range of applications. Pre-combustion systems are not a mature market technology but are intended for deployment in conjunction with Integrated Gasification and Combined Cycle (IGCC) technology. The use of IGCC for coal-based electricity production is limited with only four coal-based IGCC demonstration plants in operation globally.[3] Reliability, availability and cost of technology have hindered wider deployment of IGCC.[4]
  • Post-combustion techniques are the standard practice for removing pollutants, such as sulfur, from the flue gas of coal-fired power stations. Flue gas typically contains up to 14% CO2, which must be separated- either through absorption (chemical or physical), cryogenics and membrane technologies. For CO2 capture, chemical absorption with amines, such as monoethanolamine (MEA), is currently the process of choice.[5] Once recovered, the CO2 is cooled, dried and compressed for transport. Post-combustion systems are posited as a carbon mitigation solution for the existing fleet of coal-fired power plants around the globe. However, retrofitting a capture system to a power station requires major technical modifications. These alterations are quite costly and are accompanied by substantial decreases in generating efficiency. For example, an MEA retrofit of an existing 500 MWe subcritical pulverized coal (PC) power plant cuts efficiency by 14.5 %. Net electrical output is diminished by over 40% to 294 MWe. Such a retrofit is expected to impose capital costs of USD 1600/kWe.[6]
  • Oxyfuel combustion burns fossil fuels in 95% pure oxygen instead of air. This results in a flue gas with high CO2 concentrations (greater than 80%) that can be condensed and compressed for transport and storage. This method of CO2 capture is still in the demonstration phase.

Retrofitting Existing Coal Plants for Carbon Capture

According to the U.S. Department of Energy, it is not economical to retrofit existing coal plants with carbon capture technology:

Existing CO2 capture technologies are not cost-effective when considered in the context of large power plants. Economic studies indicate that carbon capture will add over 30 percent to the cost of electricity for new integrated gasification combined cycle (IGCC) units and over 80 percent to the cost of electricity if retrofitted to existing pulverized coal (PC) units. A recent study from the National Energy Technology Laboratory (NETL) confirms that additional alternatives need to be pursued to bring the cost of carbon capture down. In addition, the net electricity produced from existing plants would be significantly reduced - often referred to as parasitic loss - since 20 to 30 percent of the power generated by the plant would have to be used to capture and compress the CO2.[7]

Transport

Unless a power station is located directly above a geological storage area, captured CO2 must be delivered to a storage site. Pipelines are the most feasible transportation method for large amounts of CO2 for distances up to around 1,000 km. While they are a mature market technology, pipeline infrastructure for large-scale transport of CO2 is mostly lacking. Cost estimates for constructing a dedicated network of CO2 pipelines are US$ 20,989/in of pipeline diameter/km with annual operation and management costs of US$3,100/km.[8] The risk of corrosion and leakage should be taken into consideration when constructing pipelines, especially when moving CO2 through populated areas. On a local scale, release of CO2 leading to concentrations greater than 7–10 percent by volume in the air can immediately jeopardise life and health of exposed individuals. A natural example of a sudden emergence of a large volume of CO2 occurred in a volcanic active area at Lake Nyos in Cameroon in 1986. Large quantities of CO2 accumulated on the bottom of Lake Nyos were suddenly released. The released CO2 poured an invisible cloud over the valleys below, killing 1700 people and thousands of cattle in a range of 25 km.

CO2 can also be transported by ships as well as rail and road tankers. Transport of liquefied CO2 via ships is possible in some situations and may even be more economical than pipeline transport when long distances are involved. Road and rail transport, while technically feasible, is costly and unlikely to be utilized in utility scale CCS operations.[9]

Storage

The final component of CCS is the long-term isolation of CO2 from the atmosphere. A number of specific “storage options” and associated techniques are in varying stages of research and development. They largely include methods relating to geological and ocean storage. In conjunction with the actual physical storage of CO2 in these locations are the subsequent measuring, monitoring and verification (MMV) processes needed to ensure that the integrity of the storage site is maintained. Leakage of CO2 poses a threat not only to climate mitigation efforts but also to human health and the environment. Standard protocol and the precise tools for MMV await development. At present, substantial gaps exist with respect to a legal and regulatory framework that would govern the safe and long-term administration of CO2 storage, leaving significant questions about liability and risk unanswered.

Storage capacity in the United States and Canada

On November 17, 2008, the DOE released its second Carbon Sequestration Atlas for the United States and Canada. The Atlas identifies over 3,500 billion metric tons of carbon dioxide storage potential in oil and gas reservoirs, coal seams, and saline formations. The document suggests that these geologic formations could provide over 1100 years of CO2 storage.[10]

A study in March 2008 found that the United States will need to drill over 100,000 - and perhaps up to 3 times that number - injection wells to inject enough carbon dioxide and keep total emissions at 2005 levels. The study was based on data from the petroleum industry, which has been injecting CO2 for enhanced oil recovery for more than 30 years. As a comparison for feasibility, approximately 40,000 oil and gas wells are drilled each year in the U.S. All told, the total cost of such a carbon dioxide sequestration effort could easily top $1.5 trillion per year.[11]

The study concluded:[11]

Whether, when, and how much carbon dioxide sequestration will ever occur on a commercial scale remains in question, and to achieve it will be expensive and problematic. The proposition has yet to be properly addressed in either a real or a practical context.

2010 Study claims that models overestimate storage capacity

According to a peer-reviewed study published in the journal of Society of Petroleum Engineers in 2010, titled "Sequestering Carbon Dioxide in a Close Underground Volume", the authors argue that past calculations of CCS have been widely off, rendering the technology impractical. Writing for Casper, Wyoming's Star-Tribune, report author Prof. Michael Economides explains:

Earlier published reports on the potential for sequestration fail to address the necessity of storing CO2 in a closed system. Our calculations suggest that the volume of liquid or supercritical CO2 to be disposed cannot exceed more than about 1 percent of pore space. This will require from 5 to 20 times more underground reservoir volume than has been envisioned by many, including federal government laboratories, and it renders geologic sequestration of CO2 a profoundly non-feasible option for the management of CO2 emissions.
Injection rates, based on displacement mechanisms from enhanced oil recovery experiences, assuming open aquifer conditions, are totally erroneous because they fail to reconcile the fundamental difference between steady state, where the injection rate is constant, and pseudo-steady state, where the injection rate will undergo exponential decline if the injection pressure exceeds an allowable value.
The implications of our work are profound. They show that models that assume a constant pressure outer boundary for reservoirs intended for CO2 sequestration are missing the critical point that the reservoir pressure will build up under injection at constant rate. Instead of the 1-4 percent of bulk volume storability factor indicated prominently in the literature, which is based on erroneous steady-state modeling, our finding is that CO2 can occupy no more than 1 percent of the pore volume and likely as much as 100 times less.
We related the volume of the reservoir that would be adequate to store CO2 with the need to sustain injectivity. The two are intimately connected. The United States has installed over 800 gigawatts (GW) of CO2 emitting coal and natural gas power plants. In applying this to a commercial power plant of just 500 MW, which by the way produces about 3 million tons per year relentlessly, the findings suggest that for a small number of wells the areal extent of the reservoir would be enormous, the size of a small U.S. state. Conversely, for more moderate size reservoirs, still the size of the U.S.'s largest, Alaska’s Prudhoe Bay reservoir, and with moderate permeability there would be a need for hundreds of wells. Neither of these bode well for geological CO2 sequestration and the work clearly suggests that it is not a practical means to provide any substantive reduction in CO2 emissions.[12]

A research study published by the journal Nature Geoscience in June 2010 reported that storing carbon underwater or in the ground could create many long-term problems. Storing carbon in the ocean would contribute to acidification, stated the report. Additionally, underground storage areas also exhibit multiple issues, such as leakage. Gas would have to be stored for tens of thousands of years to avoid becoming a threat to future generations, a scenario similar to nuclear waste, stated the report.[13]

Commerialization of CCS: Barriers and Timelines

Financing

In November 2009 the World Coal Institute, a lobby group for the coal mining industry, released a report arguing that the "current CCS deployment is too slow to allow necessary global GHG emissions reductions goals to be achieved. There is an urgent need to fund demonstration projects and that funding needs to come from both governments as well as a robust carbon market."[14]

The coal lobby group argued that "reducing GHG emissions will require society to pay costs long before most benefits are realised. Success will therefore require strong political will and leadership. The appetite for this will largely hinge on public acceptance."[14]

"An effective programme to accelerate the widespread deployment of CCS," the coal lobby group argued, "should build public confidence in and acceptance of CCS as a mitigation option".[14] The lobby group argued that CCS could be funded by one or more of the following options:

Regulatory uncertainty

In its 2008 annual report, Massey Energy, a major U.S. coal mining company, stated that uncertainty over the prospects of CCS and its regulation could adversely affect the financial performance of the company. "Considerable uncertainty remains, not only regarding rules that may become applicable to carbon dioxide injection wells but also concerning liability for potential impacts of injection, such as groundwater contamination or seismic activity. In addition, technical, environmental, economic, or other factors may delay, limit, or preclude large-scale commercial deployment of such technologies, which could ultimately provide little or no significant reduction of greenhouse gas emissions from coal combustion," it stated.[15]

CCS and Increased Water Demands

Integrated Gasification Combined Cycle (IGCC), which converts coal into synthetic gas or syngas to extract more energy, is being promoted as a path toward carbon capture and storage; however as of 2009 capturing carbon dioxide (CO2) reduces plant efficiency and increases water usage. An Electric Power Research Institute study found CO2 capture equipment increases water consumption by approximately 23%.[16]

A consultancy report for an Australian government agency highlighted that CCS would also impose additional demands on finite water supplies. "Issues related to water availability and carbon dioxide emissions present long term challenges for electricity generators. This is because water-cooled, low-emission, thermal power plants are likely to be significantly more water intensive than current coal-fired power plants. For example, coal-fired power plants incorporating carbon capture and storage (CCS) could be one-quarter to one-third more water intensive," the report states.[17]

Timeline for Commercial Availability

One of the most controversial aspects of CCS is the projected date of commercial availability.

  • World Business Council on Sustainable Development (2006): "Commercial implementation is not expected for another 20 years."[18]
  • Electric Power Research Institute (2007): "[W]e believe that the greatest reductions in future U.S. electric sector CO2 emissions are likely to come from applying CCS technologies to nearly all new coal-based power plants coming on-line after 2020."[19]

CCS projects worldwide

Most of the major coal-based carbon capture and sequestration projects had been put on hold or cancelled by the close of 2011, although research and demonstration projects were continuing. In 2011, some eleven CCS projects have been put on hold or cancelled, according to the Global CCS Institute, while eight new research efforts were identified. [20] In 2010, some 22 projects were delayed or cancelled. [21]

The report noted a variety of reasons for the setbacks, including uncertain conditions in national economies and downscaling at utilities which had planned to include CCS in new-build power stations.[22]

Europe had 13 of the delayed or cancelled projects. According to the GCCSI: “There has been strong resistance to onshore storage in countries such as Germany and the Netherlands and, to a certain extent, in Denmark and Poland." Some of the cancelled Dutch projects included the Rotterdam Capture Storage and Demonstration Project to store 2 million tons of CO2, Shell's Barendrecht Carbon Capture and Storage Project, which aimed to store 10 million tonnes from the nearby Pernis oil refinery, and Shell's joint project with Essent to store carbon from a 1,000 MW power plant.[22]

In the UK, plans for CCS at RWE npower’s Tilbury Power Station and E.ON UK’s Kingsnorth Power Station have also been delayed. And the Longannet carbon capture project was scrapped in October, 2011. [23]

Three more projects were delayed or cancelled in Norway, as were a further two in Denmark and one each in Germany, Finland and the Czech Republic. Despite the cancellations, the report said Europe has a remaining 21 LSIPs in development, though these are progressing slower than those in the US. The European commission is holding a contest for around €4.5 billion in funding for CCS and renewable energy financed from the sale of 300 million EU allowances.[22]

Throughout the rest of the world, Australia is host to six LSIPs and China to five, while there were no LSIPs identified in key emitting countries such as Japan, India and Russia, the report added.[22]

North America had the highest number of active LSIPs with 31 in the US and eight in Canada. Their progress, the report noted, is partly due to opportunities for enhanced oil recovery, a method of producing oil from conventional oil reservoirs, involves injecting CO2 underground to create pressure in the reservoir, which pushes the oil up to the surface more easily.[22]

Major US Carbon Capture and Storage projects cancelled

Two major US projects, FutureGen 2.0 and AEP Mountaineer have also been cancelled or put on hold in 2011.

Mountaineer pilot plant was to have been created as an add-on unit at the Mountaineer Plant near New Haven, West Virginia, owned and operated by American Electric Power (AEP).[24]

Mountaineer Plant Deploys Carbon Capture and Sequestration.

In August 2009, AEP applied for funding from the U.S. Department of Energy's Clean Coal Power Initiative. The company asked for a $334 million grant to cover about half of the estimated costs of installing carbon capture and storage system. According to the grant application, the system would attempt to capture at least 90 percent of the carbon dioxide from 235 MW of the plant's 1,300 MW total capacity. The captured carbon dioxide, which was expected to be about 1.5 million metric tons per year, would have been injected into geologic formations about 1.5 miles under ground. The company could have had the system operational in 2015.[25]

In December 2009, AEP was awarded the $334 million grant from the Department of Energy for the CCS project at its Mountaineer plant.[26] The company noted that the "Mountaineer Plant CCS projects employ Alstom’s patented chilled ammonia process for post-combustion CO2 capture. The process uses ammonium carbonate to absorb CO2. The resulting ammonium bicarbonate is converted back to ammonium carbonate in a regenerator and is reused to repeat the process. The flue gas, cleaned of CO2, flows back to the stack and the captured CO2 is sent for storage."[27]

On July 14, 2011, American Electric Power said it had decided to cancel the project, saying they did not believe state regulators would let the company recover its costs by charging customers, thus leaving it no "compelling regulatory or business reason to continue the program." The federal Department of Energy had pledged to cover half the cost, but AEP said it was unwilling to spend the remainder in a political climate that had changed strikingly since it began the project. A senior Obama administration official said that the A.E.P. decision was a result of the political stalemate on climate change legislation, which failed to pass the Senate. Public service commissions of both West Virginia and Virginia turned down the company’s request for full reimbursement for the pilot plant, operating since 2009. West Virginia said earlier in 2011 that the cost should have been shared among all the states where AEP does business; Virginia hinted in July 2010 that it should have been paid for by all utilities around the United States, since a successful project would benefit all of them.[28][29]

Concerning AEP's statement that costs could not be passed along, West Virginia journalist Ken Ward noted: "It's not exactly true that utility commissions aren’t allowing companies to pass costs of projects like this on to consumers... The West Virginia PSC allowed AEP rate hikes to cover our state’s share of the costs. Virginia regulators seemed willing to do the same. [30] James Fallows of The Atlantic wrote: "This is the kind of project that (was) the best and urgently necessary hope to allow the US, China, and other countries to keep using coal ... while reducing carbon emissions. [31]

FutureGen was the premier US CCS project, and it was billed as "tomorrow's pollution free power plant" by the Department of Energy in 2003. [32] A project agreement was first signed in April 2007, but by January 2008 the project funding was in question, and the DOE announced a restructuring. Major partners initially included American Electric Power and Southern Company, but by June of 2009 both had withdrawn from the project.

DOE secretary Stephen Chu announced a restructured "FutureGen 2.0" on August 5, 2010. Instead of building a 275 MW coal-fired IGCC type plant in Mattoon, Illinois, "FutureGen 2.0" would be located at Ameren’s 200 megawatt Unit 4 in Meredosia, Illinois with advanced oxy-combustion technology. A pipeline would have carried 1 million tons per year of captured CO2 back to the original site in Mattoon, located in Coles County. However, Coles County withdrew from the FutureGen Alliance August 13, 2010.

The project's fate was not clear in the aftermath of the Ameren withdrawl on Nov. 10, 2011. According to the New York Times,FutureGen "was long seen as the nation’s best hope for taking a worldwide lead in developing ways to capture and bury carbon dioxide from coal burning." [33]

Other US projects cancelled in 2010 include the Southern Company million ton per year CCS project slated for the Barry Steam Plant in Alabama, and the Dominion CCS Hybrid Energy Center, which was to have been built alongside the Wise County Plant in far Southwestern Virginia.

Critiques of CCS

CCS Ranks poorly in study comparing energy sources according to global warming emissions and energy security

A detailed report from Stanford University, released in December 2008, reviewed and ranked major energy solutions to global warming and energy security. Mark Jacobson, a professor of civil and environmental engineering, conducted the first quantitative, scientific evaluation of the major, proposed energy-related solutions. His study assessed their potential for delivering energy for electricity and vehicles, their impacts on global warming, human health, energy security, water supply, water pollution, and wildlife, as well as their space requirements, reliability and sustainability. Jacobson found that the options getting the most attention are 25 to 1,000 times more polluting than the best available options.[34]

The study concluded that ethanol, nuclear, and coal with CCS are all dirty, inefficient and wasteful compared to wind, solar, geothermal and ocean energy, and that these cleaner energy sources could eliminate global warming gases, create energy security, and meet the world's ongoing energy needs entirely.[35][36]

Economics act against CCS retrofits

The Oil & Gas Journal, Didier Favreau, who is a senior analyst with IFP Energies nouvelles, Rueil-Malmaison, wrote that:

Economics will likely prevent retrofitting carbon capture and sequestration technologies to existing power plants with a capture efficiency <40% and a residual life <15 years.
Only capture of flue gases (postcombustion) is practical for existing units, although even this is often made difficult by space constraints. Other solutions use processes (oxycombustion or gasification), which cannot generally be adapted to existing installations except with major revamping.[37]

In July 2009, Harvard’s Belfer Center for Science and International Affairs published a study, “Realistic Costs of Carbon Capture” which concluded that First-of-a-Kind (FOAK) carbon capture and storage plants were "expected to be approximately $150/tCO2 avoided (with a range $120-180/tCO2 avoided), excluding transport and storage costs," coming out to 20 cents per kilowatt hour. The estimate was based on cost data from 2008.

Potential for contamination of drinking water

A 2010 study by Duke University scientists, "Potential Impacts of Leakage from Deep CO2 Geosequestration on Overlying Freshwater Aquifers" found that leaks from carbon dioxide injected deep underground could bubble up into drinking water aquifers near the surface, driving up levels of contaminants in the water tenfold or more in some places. The study was based on a year-long analysis of core samples from four drinking water aquifers.[38]

Researchers Mark Little and Robert B. Jackson collected core samples from four freshwater aquifers around the nation that overlie potential CCS sites and incubated the samples in their university lab for a year, with CO2 bubbling through them. The scientists found that tiny amounts of CO2 drove up levels of heavy metals, including manganese, cobalt, nickel, and iron in the water tenfold or more in some places. Some of these metals moved into the water quickly, within one week or two. They also observed potentially dangerous uranium and barium moving into the water over the entire year-long experiment. Further, when the CO2 buried deep underground escapes into groundwater, it forms carbonic acid, a chemical reaction very similar to the process that occurs when the oceans absorb CO2. The increased acidity caused by CO2 dissolved in water underground can cause metals to leach out of surrounding sand and rock.[39]

The study also identified four markers that scientists can use to test for early warnings of potential carbon dioxide leaks. "Along with changes in carbonate concentration and acidity of the water, concentrations of manganese, iron and calcium could all be used as geochemical markers of a leak, as their concentration increase within two weeks of exposure to CO2," Jackson said.[38]

Reports of CO2 leakage

On January 11, 2011 Saskatchewan farm couple Cameron and Jane Kerr released a consultant's report linking high concentrations of carbon dioxide in their soil to the 8,000 tonnes of the gas injected underground in the area every day by energy company Cenovus, in its attempt to enhance oil recovery and fight climate change through carbon capture. The couple own nine quarter-sections of land above a Weyburn oilfield in eastern Saskatchewan. The CO2 was supposed to have been injected permanently underground, but the couple says it is leaking out, killing animals and sending groundwater foaming to the surface.[40]

Cameron Kerr, 64, said he has farmed in the area all his life and never had any problems until 2003, when he agreed to dig a gravel quarry for a road to a plant owned by EnCana — now Cenovus — which had begun three years earlier to inject more than 13 million tons of carbon dioxide underground to force more oil out of the aging oil field. By 2005, Cameron Kerr had begun noticing problems in a pair of ponds which had formed at the bottom of the quarry - they developed algae blooms, clots of foam, and several colours of scum — red, yellow, and silver-blue. Sometimes, the ponds bubbled. Small animals — cats, rabbits, goats — were regularly found dead a few metres away. There were also explosions: "Just like you shook up a bottle of Coke and had your finger over it and let it spray," said Cameron. The water, wife Jane Kerr said, came out of the ground carbonated. Alarmed, the couple left their farm and moved to Regina.[40]

In 2006, Cameron Kerr said, the province's New Democrat government agreed to conduct a year-long study. That government fell to the Saskatchewan Party in the subsequent election and the year-long study was never done. Cameron Kerr said provincial inspectors did conduct a one-time check of air quality — on a day, he added, with 50-kilometre winds. Then the Kerrs sold some of their cattle and paid a private consultant for a study. Paul Lafleur of Petro-Find Geochem found carbon dioxide concentrations in the soil last summer that averaged about 23,000 parts per million — several times those typically found in field soils. Concentrations peaked at 110,607 parts per million. Lafleur used the mix of carbon isotopes he found in the gas to trace its source, which he said was "clearly the anthropogenic CO2 injected into the Weyburn reservoir" and that the "survey also demonstrates that the overlying thick cap rock of anhydrite over the Weyburn reservoir is not an impermeable barrier to the upward movement of light hydrocarbons and CO2 as is generally thought."[40]

Lafleur suggests the carbon dioxide could leak into area homes. The gas is not poisonous, but it can cause asphyxiation in heavy concentrations, which is what Cameron thinks happened to the animals around his ponds.[40]

The Alberta government has committed $2 billion to similar pilot projects in Alberta. The United States has committed $3.4 billion for carbon capture and storage. Norway has been injecting carbon dioxide into the sea floor since 1996. There are carbon capture and storage tests planned in Australia, Germany, Poland, the United Kingdom, China and Japan.[40]

US Policies and Programs

November 2010: EPA issues CO2 injection regulations

On November 22, 2010, the U.S. Environmental Protection Agency issued rules to protect drinking-water supplies from future efforts to bury pollution from coal-fired power plants. In an email accompanying the announcement, EPA administrator Lisa Jackson said: "The regulation is a major step in the federal government’s effort to promote a “promising technology” capturing carbon dioxide that otherwise would be emitted from smokestacks and injecting it into geologic formations such as deep-saline aquifers and depleted oil reservoirs."[41]

The drinking-water regulation governs the way carbon dioxide injection wells are located, built, tested, monitored and closed. A task force of 14 U.S. agencies said in August 2010 that carbon-capture technology is currently too expensive to be used without financial and regulatory support from the federal government. According to the task force: Rules governing the “environmental soundness of injecting and storing carbon dioxide underground” must be part of a federal plan to “facilitate widespread cost-effective deployment” of the pollution-control technology after 2020. A separate EPA rule also released that day dealt with measuring the amount of carbon dioxide that’s captured and stored, designed to deal with future regulations of greenhouse gases.[41]

2010 GAO report: CCS expensive and barriers remain to its development

According to a June 2010 US Government Accountability Office (GAO) report, "Coal plants: Opportunities Exist for DOE to Provide Better Information on the Maturity of Key Technologies to Reduce Carbon Dioxide Emissions", while CCS for fossil fuel-based utilities may not be ready for 10-15 years, and that even then use of the technology is contingent on overcoming a variety of economic, technical, and legal challenges, including legal protection for coal companies over the unknown long-term effects of carbon dioxide sequestration. The GAO notes government and academic reports finding that deployment of the technology could cause electricity rates to increase between 30% and 80%, and that CCS would use more electricity (to power the capture and sequestration of CO2) as well as more water. Additionally, stakeholders interviewed by the GAO noted that the largest demonstration of carbon capture in a coal plant was at a pilot scale (TRL 7) or less, and that demonstration of large scale integrated CCS systems is a technical challenge and is needed to demonstrate the performance and potential costs of these systems. GAO said that the Department of Energy (DOE)'s lack of data regarding the development of the technology "limits congressional oversight of DOE's expenditures" on CCS and efficiency research and development, and "it hampers policymakers' efforts to gauge the maturity of [CCS] technologies as they consider climate change policies."[42]

2010: Recommendations of Obama Inter-Agency Task Force on CCS

On August 12, 2010, President Obama’s Interagency Task Force on Carbon Capture and Storage (CCS), co-chaired by the U.S. Environmental Protection Agency (EPA) and the Department of Energy (DOE), delivered a series of recommendations to the president on overcoming the technical, financial, and legal barriers to the deployment of CCS. The president charged the task force in February 2010 with proposing a plan to bring five to 10 commercial demonstration projects online by 2016.[43]

The United States has made the largest government investment in carbon capture and storage of any nation: the DOE is currently pursuing multiple demonstration projects using close to $4 billion in federal funds, with an additional $7 billion in private investments.[43]

The report’s main findings and recommendations include:[43]

  • A Carbon Price for market predictability
  • Increased federal actions, money, and coordination of CCS efforts
  • Recommendations on Liability: The task force conducted analysis of options to address concerns around liability from storing carbon dioxide underground, given the unknown effects. It concluded that federal fines are not viable, but that four approaches merit further consideration: relying on existing frameworks, limits on claims, a trust fund, and transfer of liability to the federal government. Efforts to improve long-term liability and stewardship frameworks led by EPA, DOE, and the Department of Justice (DOJ) will continue in order to provide evaluation and recommendations in these areas by late 2011.

In short, the task force recommends more money and federal assistance plus limits on corporate liability to help make carbon capture viable one day.

European Policies and Programs

Schwarzenegger clause

In October 2008, the European Parliament's Environment Committee voted to support a limit on CO2 emissions for all new coal plants built in the EU after 2015. The so-called "Schwarzenegger clause" applies to all plants with a capacity over 300MW, and limits their annual CO2 emissions to a maximum of 500 grammes per kilowatt hour. The new emissions standard essentially rules out traditional coal plant technologies and mandates the use of Carbon Capture and Storage technologies. The Committee also adopted an amendment to support the financing of 12 large-scale commercial CCS demonstration projects, at a cost that could exceed €10 billion.[44][45]

However, in November 2008, the proposal to subsidize the CCS demonstration plants appeared to be headed for defeat. Several European countries have voiced opposition to the plan, including Spain, Germany, France, Denmark, Hungary, and Poland. Among the objections to the proposal include concerns that it puts too much investment in experimental carbon capture and not enough incentives for proven technologies like solar power and hybrid cars. European nations with the largest populations, including Spain and Germany, have extra votes and could force the research plan to be omitted from the larger EU climate and energy legislation. If the subsidy plan fails to pass, the pilot projects may not be able to secure financing.[46][47]

Canada policies and programs

Alberta's tar sands

On June 24, 2011, the province of Alberta said it would provide C$745 million to test carbon capture and sequestration technology on Royal Dutch Shell's Scotford Upgrader, which is similar to a refinery for processing heavy oil. The Canadian government will chip in an additional C$120 million, making the project one of the most expensive attempts to control carbon dioxide output from Alberta's oil sands region.

The deal is the first test of whether greenhouse gas output from upgraders can be controlled, according to Shell. Upgraders pump hydrogen and particles of a catalyst down into a well while simultaneously heating the oil sands, breaking the long chain hydrocarbons in the bitumen into smaller molecules that flow better and are easier to pump and store. The proposed CCS project -- which will receive the money over a 15-year time span -- would inject 1 million metric tons of C02 underground in saline rock formations. The injections would start in 2015.

Environmental groups say the CCS proposal actually would raise Alberta's emissions over time, since the province simultaneously changed the way companies can receive carbon offset credits under a provincial greenhouse gas law, allowing companies to receive double the credit to reduce overall emissions for every metric ton of pollution reduced via CCS projects that "store carbon dioxide permanently." That means companies will be able to avoid more emissions at their own facilities simply by counting CCS as a "double" offset under provincial law.[48]

Other Issues

Carbon Capture and Enhanced Oil Recovery

A March 2010 report by Advanced Resources International (ARI) of Arlington, VA found that US climate legislation, if enacted, could potentially lead to large volumes of captured carbon dioxide from power plants and other industrial sources, accelerating enhanced oil recovery (EOR) and boosting oil production by 3-3.6 million b/d by 2030, assuming all the captured CO2 were to be used for EOR. The report was prepared for the Natural Resources Defense Council.[49]

Mike Godec, ARI vice-president and author of the report, said most power plants likely to be equipped with carbon capture and storage technology are within 700 miles of oil basins having EOR potential.[49]

Department of Energy (DOE) funding under the Energy Policy Act of 2005 funds syngas CCS projects for EOR, such as Leucadia's Indiana Gasification SNG project and Mississippi Gasification SNG project.[50] Both plants will transport compressed CO2 for enhanced oil recovery in Texas oil fields via the Denbury Green Line pipeline system.[51]

2008 figures from the U.S. National Energy Technologies Laboratory show 90 million barrels of oil were extracted using Enhanced Oil Recovery from compressed CO2. The country has also spent $1 billion on 2,200 miles of CO2 transmission and distribution pipeline infrastructure.[52]

In December 2013 the EPA exempted carbon dioxide injection from strict hazardous waste laws, classifying the wells used to inject CO2 underground for oil production in a category that offers less protection for drinking water, and loosening the reporting and monitoring requirements that some experts say are necessary to ensure the carbon stays underground. Companies are fighting an EPA proposal that would require tougher regulations if the carbon comes from power plants covered by the new federal CCS rules.[53]

Carbon Capture and Coal Bed Methane

An $11.5 million research effort at Virginia Tech will examine coal bed methane formations as potential repositories for carbon capture, the university announced July 11, 2011.[54] Coal bed methane is another approach to CCS, along with enhanced oil recovery and deep saline structures. Coal bed methane deposits are more typical in Appalachia, and are around 4,000 feet deep, compared with 9,000 feet for saline structures. The coal bed approach also has smaller storage capacity and water pollution issues, but more economic potential in that CO2 could bring methane gas to the surface. An additional issue is that coal bed methane fields are closer to the surface and have a wider footprint, which means more landowners would have to be involved in negotiating liability issues. [55]

Carbon Capture and Fracking

A 2012 Environmental Science & Technology study found that many of the same shale rock formations where companies want to extract gas also sit above sites that have been envisioned for storing carbon dioxide underground. The problem with this overlap, the researchers found, is that shale-gas extraction involves fracturing rock that could be needed as an impenetrable cover to hold CO2 underground permanently and prevent it from leaking back into the atmosphere. The study reported that 80 percent of the potential area to store CO2 underground in the United States (based on NETL estimates) could be restrained by shale and tight gas development (based on DOE estimates). The numbers held when they examined potential CO2 storage sites close to the nation's largest greenhouse gas emitters, such as coal plants.[56]

Carbon Capture and Tremors/Leaks

A 2012 Proceedings of the National Academy of Sciences study found that rising pressure from large amounts of sequestered CO2 could trigger earthquakes. The temblors would likely be small, but could crack rock above the formations used for storage, providing pathways for the buoyant CO2 to leak back into the atmosphere. Lead author Mark Zoback, a geophysicist at Stanford University, said carbon capture and storage "is generally a good idea and can be done safely in many places. But we question whether it's a practical thing to do" at the scale of storing 1 billion tons of CO2 a year, which would be needed to help bring CO2 emissions down to 2000 levels by mid-century.[57]

Articles and resources

References

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  33. Matthew L. Wald "Coal Project Hits Snag as a Partner Backs Off" New York Times, Nov. 10, 2011.
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