Too late to be of use, much too expensive, ineffective, and unsafe Dr. Mae-Wan Ho
Carbon capture and storage (CCS) is intended to reduce the impact of burning fossil fuels by capturing CO2 from concentrated sources such as power stations and storing it underground (see Box). CCS has wide support among governments as world oil supply is failing to meet demand while many countries still have large coal reserves.
Coal-fired power plants account for half of America’s electricity, and coal produces more carbon dioxide than any other commonly used fuel . The coal-mining industry has been promoting CCS as “clean coal”, and even some environmental groups see it as a way of bridging the energy gap until renewable energies can be more widely deployed.
The Bush administration was the first to commit to a large scale coal-fired power plant to be fitted with CCS, and intended as a flagship project for the world.
But on 30 January 2008, the US Department of Energy (DOE) withdrew support from the project, citing soaring cost and advances in electricity-generating technology in recent years [2, 3].
The non-profit public-private partnership FutureGen Alliance, which included industry giants such as Rio Tinto, American Electric Power Service Corp, Anglo American, BHP Billington, and China’s largest coal-based power company, China Huaneng Group, was launched in 2005 in response to Bush’s February 2003 call for a programme to demonstrate “the world’s first near-zero-emissions coal-fired power plant.”.
DOE described FutureGen in 2005 as a $950-million initiative for integrated gasification combined cycle (IGCC) technology to produce hydrogen and electricity while providing capture and storage of CO2. At the time there were few IGCC projects. “Now, more than 33 IGCC projects have begun the permitting process,” said Clay Sell, deputy energy secretary.
DOE first became aware that FutureGen’s estimated budget for the plant to be built in Mattoon Illinois had almost doubled to $1.8 billion in March 2007; of which 74 percent would have to be paid by the DOE and the rest by industry. The consensus was that costs would only increase.
DOE intends to concentrate research on CCS, leaving IGCC to power developers. On the same day that it announced withdrawal from FutureGen, DOE issued a Request for Information from industry by 3 March 2008 on the costs and feasibility of building “clean coal” facilities that achieve FutureGen’s intended goals. By the end of the year, this should lead to a competitive tender for federal funding to equip clean coal plants of at least 300 MW with CCS technology.
FutureGen was not the only project to be abandoned. By the end of 2007, at least 11 CCS projects were scrapped in the UK, Canada and Norway . Plans for new projects had stagnated, and the pace of development for existing projects slowed considerably.
In May 2008, Rio Tinto and UK oil producer BP dropped plans (through a subsidiary called Hydrogen Energy) to construct an Australian CCS coal-fired power generation plant Kwinana, admitting there was no guarantee that the rock formations at the intended site for carbon storage would seal it in . The project would have cost AUS$1.5 billion to AUS$2 billion and capture around 4 million tonnes of CO2 a year.
To put these CCS projects in perspective the world’s total greenhouse gas emissions is 28 Gt CO2 equivalents a year and rising .
But these failures appeared to have done nothing to dampen the enthusiasm of governments or proponents for CCS. By May 2008, the US Senate Appropriation Committee unanimously approved a resolution to force the DOE to continue financing FutureGen out of the “war supplemental package” that includes funding for Iraq and Afghanistan wars as well as domestic spending on hurricane recovery, veterans education, food aid and federal highways .
In June 2008, UK’s Royal Society joined with science academies from other industrialised nations and five other countries including China and India to call on government to set an agreed timetable for fitting power stations with CCS by next year to avoid “dangerous and irreversible” climate change .
Carbon capture and storage involves the capture of CO2 in a concentrated and compressed form that can be transported and pressure-injected underground for permanent storage at appropriate sites [3, 8].
Capturing CO2 is by far the most energy intensive part of CCS. Capture can be done by flue gas separation post-combustion, by ‘oxyfuel combustion’, or by pre-combustion separation. Pre- and post-combustion separation typically removes 85-95 percent of the CO2, while oxy-fuel can remove up to 98 percent.
Flue gas separation is the standard practice and currently applied in about a dozen facilities worldwide. The flue gas is passed through a chemical solvent that absorbs CO2. The CO2 is recovered in a concentrated form and compressed for transport to the storage site, while the solvent is regenerated. The most commonly used CO2 absorbent is monethanolamine (MEA). Newer methods are being developed that tethers the amine to silica  and may increase the efficiency of the process both in terms of CO2 captured and energy use.
Oxy-fuel combustion depends on burning the fossil fuel in pure or enriched (95 percent) oxygen, so that flue gas contains mostly CO2 and H2O, from which CO2 can be removed easily. However, oxygen needs to be separated from nitrogen in the intake air, and this is costly. To date, this method has only been demonstrated at laboratory and pilot scale up to 3 MW.
Pre-combustion separation is usually applied in coal Integrated Gasification Combined Cycle (IGCC) power plants, and involves turning coal first into a mixture of CO (carbon monoxide) and H2 (hydrogen). The CO is made to react with steam to generate more H2 and CO2, the latter is removed leaving H2 for the turbine to generate electricity, or for hydrogen fuel cell to run vehicles. This method is not economical at the moment, and significant technical challenges remain.
Options for transport include pipelines, ships, rail and road, with pipelines the most likely. Transport by pipelines requires compression of the gas to a liquid state. Pipeline transport is currently used in the US, which has more than 2 500 km of CO2 pipelines in the western half of the country where 50 Mt/y – an amount equivalent to the annual output of about sixteen 500 MW coal-fired power stations – is carried away for enhanced oil recovery (see below) projects in west Texas and elsewhere. No such infrastructure currently exists in Europe for moving CO2 from power stations to storage sites.
Both ocean and geological storage sites have been proposed, which includes subsequent monitoring and verification to ensure that the storage sites are intact, and the CO2 does not escape.
Ocean storage involves injecting the CO2 at great depths, preferably below 3 000 m, where the pressure is sufficient to compress CO2 into a dense liquid that sinks to the sea bed to form CO2 lakes. This option is seen as so risky that it is now generally discredited. It is not a permanent store, and the CO2 will eventually dissolve and disperse into the overlying seawater, acidifying the oceans with drastic consequences on marine life. The oceans are already under great pressure from pollution, destructive over-fishing, increasing commercial exploitation and global warming; most worrying of all, they are failing to absorb the normal share of anthropogenic CO2 released into the atmosphere  (see Save our oceans, save our planet series, SiS 31), Also, these storage sites are impossible to control or monitor, and are effectively prohibited by current international legislation .
Geological storage involves injecting the CO2 into permanent rock formations sealed by dense impermeable rock layers more than 800 m below ground. Four options have received the greatest attention: deep saline aquifers, depleted oil and gas reservoirs, enhanced oil recovery and deep coal seams.
*Deep saline aquifers are porous rocks containing very salty water; and provide an estimated storage capacity for 1 000 Gt CO2, but safety and environmental protection are as yet undemonstrated.
*Depleted oil and gas reservoirs are probably the best characterised, and have the potential capacity of 675-900 Gt CO2.
*Enhanced oil recovery (EOR) involves injecting CO2 into existing oil and gas reservoirs to enhance extraction of oil. The best known project is in southeastern Saskatchewan, Canada, at the Weyburn Field that uses waste CO2 piped from a gasification plant in North Dakota. For every tonne of CO2 injected, one tonne of oil is extracted. Over the 25 year lifespan of the project, it is expected that about 18 Mt of CO2 will be injected into the ground to yield approximately 130 m barrels of oil. This option is most favoured by CCS advocates, but it has yet to prove feasible or economical on a large enough scale.
* Deep coal seams that cannot be mined can be used for adsorption of CO2. In the process, methane is released that could be recovered and used to offset the costs of CCS. But a great deal of uncertainty remains over the technical aspects as well as storage capacity.
Tere are grave doubts over the efficacy, economic viability, and safety of CCS, especially over its ability to meet the world’s energy needs while mitigating climate change. As Greenpeace International’s report , False Hope, Why carbon capture and storage won’t save the climate charges, “the technology is largely unproven and will not be ready in time to save the climate.”
It is clear that CCS as an integrated technological package will not be ready in time to counteract dangerous climate change. The earliest possible commercial deployment is not expected before 2030 . The Intergovernmental Panel on Climate Change (IPPC) tells us that to avoid the worst impacts of climate change, global greenhouse gas (GHG) emissions have to peak by 2015 and start falling thereafter to 50 percent of 1990 levels by 2050. Its special report  does not see CCS to be commercially viable before the latter half of the present century; and even then, plants responsible for 40 to 70 percent of electricity sector CO2 emissions will not be suitable for carbon capture.
CCS wastes energy as it uses between 10 to 40 percent of the energy produced by a power station , thereby erasing the efficiency gains of the last 50 years and increase resource consumption by one third . Power stations with CCS not only require more energy, it will need 90 percent more freshwater than those without.
CCS is expensive, and could double the plant costs, resulting in an electricity price increase of 21 to 91 percent .
In Australia, CCS would lead, at best, to a 9 percent emissions reduction in 2030 and a cumulative reduction from 2005 to 2030 of only 2.4 percent, partly due to the lack of suitable carbon storage facility. In contrast, a modest improvement in energy efficiency at zero or negative cost could decrease emissions in 2030 by about the same amount, and cumulative emissions by twice as much.
The International Energy Agency describes a “capture-ready” plant as one “which can be retrofitted with CO2 capture when the necessary regulatory or economic drivers are in place”, which is so vague to make any station theoretically capture ready. In the UK, a new coal-fired power plant at Kingsnorth, Kent, is being sold as capture ready, but until then, it will pump out around 8 million tonnes of CO2 per year, the total annual emissions of Ghana.
The IEA estimates that for CCS to deliver any meaningful climate mitigation effects by 2050, 6 000 projects each injecting a million tonnes of CO2 per year into the ground would be required. It is not clear that it can be done, and whether there are enough storage sites close to the power plants, as transport of CO2 over distances greater than 100 kilometres is likely to be prohibitively expensive.
CCS is certainly not a solution for mitigating climate change. It prolongs our dependence on fossil fuels and accelerates the production of CO2, massive amounts of which ‘stored’ at our peril because of the constant threat of leakage and escape (see below). Most of all, CCS squanders ever dwindling resources that should be invested instead in renewable energies such as solar, wind, and biogas from anaerobic digestion of biological wastes, and in developing other much more promising, safer, and cost-effective options  (Which Energy?, I-SIS Publication).
recent study commissioned by the German federal government confirms that compared with renewable energy options such as wind and solar, CCS will increase CO2 emissions 10 to 40 fold and raise the cost of electricity by 100 percent  (Renewable versus Carbon Capture and Storage, SiS 39)
CCS is extremely expensive because the power plant has to be specially constructed with the necessary infrastructure for transport and for storing the carbon. Financial considerations have been the major factor responsible for the string of collapses in CCS projects around the world.
In June 2008, the executive at RWE Npower, a company hoping to build a big new coal-fired power station fitted with CCS at Tilbury on the Thames Estuary, expressed concerns over both the cost and the timescale. Mr. Chris Elston said such coal-fired stations “could easily double the cost of electricity”, and furthermore, it could take 20 years before CCS can be deployed across Britain’s coal-fired stations.
One proposal to make CCS more economically attractive is ‘enhanced oil recovery’ (EOR) (see Box), injecting CO2 into an underground reservoir to force out the remaining oil or gas, thereby increasing the amount that can be extracted and extending the life of the oil field up to 20 years. The British Miller oil and gas field became uneconomical in 2005, and oil giant BP sought government subsidies to initiate an EOR project that would allow access to an estimated 57 barrels of extra oil. But the potential profits from the recovered oil could not compensate for difference between the costs of CCS, estimated at €38 per tonne, and the price of carbon credits, then at €21 per tonne. BP tried to convince the UK government to bridge the gap with a tax break of over 50 percent, and a guaranteed subsidised rate of return. The UK government decided that all proposed CCS projects had to compete for funding and tax relief; and BP cancelled its plans .
The Norwegian government abandoned a similar project after the Statoil-Hydro and Shell companies withdrew on economic grounds.
The Norwegian government is, nevertheless, committed to covering all additional construction and operation costs to ensure CCS from two natural gas-fired power plants on the Norwegian west coast, Kårsto and Monstad. The Kårsto plant, which emits around 1 million tonnes of CO2 a year, began operating in November 2007. High gas costs and low electricity returns meant it has hardly been functioning. Full scale CCS was promised from 2009, but is now postponed to 2012 or beyond, due to significant technological constraints. The capture plant, pipeline to the storage location, and the control facility for the storage process have yet to be built. At the Mongstad refinery that was to be the “European CCS test centre”, two pilot plants are under construction, with the aim of capturing 100 000 tonnes of CO2 per year from 2011. Yet, until 2014 at the earliest, the captured CO2 will simply be released back into the atmosphere because the pipelines to the storage sites won’t be in place.
Before the collapse of FutureGen, its costs had ballooned to US£1.8 billion and still threatening to increase.
As long as CO2 is stored in geological sites, there is a risk of slow leakage or large scale escape that will impact the surrounding environment and negate the climate mitigating effect.
A natural example of the danger of CO2 escape occurred at Lake Nyos Cameroon in 1986 following a volcanic eruption, which released large quantities of the CO2 accumulated at the bottom of the lake. It killed 1 700 people and thousands of cattle within a 25 km radius .
A 2006 US Geological Survey pilot field experiment was carried out to test deep geological disposal of carbon dioxide in a saline sedimentary rock formation in Frio, Texas. The researchers found that the buried CO2 dissolved large amounts of the minerals in the rocks responsible for keeping the gas contained . The CO2 dissolved in the salty water, turning it to acid. The acidified brine dissolved other minerals, including metals such as iron and manganese, organic material and relatively large amounts of carbonates that naturally seal pores and fractures in geological sites. Carbonate is also found in the cements used to seal abandoned oil and gas wells. Dissolving these carbonate seals could release CO2 into the atmosphere. The contaminated brine could further leak into aquifers and contaminate drinking and irrigation water. The lead scientist in the field experiment Yousif Kharaka warned  that the results are “a cautionary note” that calls for “detailed and careful studies of injection sites” and for “a well thought out monitoring programme to detect early leaks of CO2 into shallow potable groundwater or to the atmosphere.”
The environmental risks of geological CO2 storage include :
Local escapes of CO2 pose a threat of asphyxiation to humans and animals. CO2 is denser than air and tend to accumulate in low-lying, poorly ventilated areas, and becomes a health hazard at levels greater than 3 percent, as demonstrated in Lake Nyos incident in Cameroon. CO2 rising to the shallow subsurface can have lethal effects on plants and subsoil animals and contaminate groundwater. Soil acidification and suppression of root respiration has been reported in volcanic and earthquake zones. In Mammoth Mountain, California, the release of CO2 following several small earthquakes was sufficient to kill a hundred acres of trees. Migration of CO2 can acidify water and mobilize toxic heavy metals. Its injection underground can build pressure, displace brines and cause seismic activities. The increased extraction associated with CCS and more fossil fuel use also mean greater environmental damage .
CCS is considered so risky on a large scale that industry is unwilling to fully invest in it without a framework that protects it from long-term liability . Some utilities are unwilling to make CO2 available for storage unless they are released of ownership upon transfer of the CO2 off the property of the power station. Potential operators are ensuring that they only retain liability for permanently stored carbon for ten years.
FutureGen was not only promised unprecedented public funds to the tune of US$1.3 billion, it was also protected from financial and legal liability in the event of an unanticipated release of CO2, and even had its insurance policies paid for.
CCS is diverting funds away from renewable energy options. The US DOE’s 2009 spending on CCS is $623.5 million, a 26.4 percent increase over 2008, at the same time that it is scaling back programmes on renewable energy and efficiency by 27.1 percent to US$145.2 million .
Australia has three cooperative research centres for fossil fuels, one focussing on CCS; but there is not a single research centre for renewable energy technology. In Norway, petroleum-based research receives over five times more funding than renewable energy research; a gap further widened by a recent commitment of more than 20 billion NOK (US$4 billion) for two CCS projects aimed at capturing 2 MtC annually.
Meanwhile, the renewable energy market is booming. In 2007, global annual investment in renewables exceeded US$100 billion . New Zealand plans to achieve carbon neutrality by mid-century. It already obtains 70 percent of its electricity from renewable resources and aims to increase it to 90 percent by 2025. Germany increased its use of renewable energies by 300 percent in the past ten years.
Article first published 09/07/08
Got something to say about this page? Comment