|Capturing carbon dioxide from thermal plant emissions and, ideally, putting it to use could offer an economical route to a low-carbon economy
Rising concern over the power sector’s emissions has brought CCS into increasing prominence. In March 2013, the UK is expected to choose its first major CCS power project, which will also be the world’s first not to be associated with enhanced oil recovery (EOR) and the first to pipe its emissions offshore.
The decision will throw a spotlight onto CCS in Europe and prime further development in a sector where progress has often been slow.
For its advocates, CCS is the only low-carbon power technology that can compete with nuclear in scale and consistency. Through their baseload applications, CCS projects should also deliver huge emissions savings at a lower cost per unit than intermittent rival technologies such as solar and wind.
Campaigners also underscore that, instead of being stored, captured CO2 can be put to use. Turning a climate change threat into a raw material for a new sustainable carbon cycle would clearly be a technological triumph. But is it feasible and how much carbon could be consumed?
The emergence of CCU
In fact, with the exception of EOR, utilisation processes are yet to be fully commercialised, and the quantities of CO2 they utilise are insignificant. Yet algal biofuels and carbon-based material production – as well as EOR – could increasingly add value to CCS projects, particularly those for smaller-scale, high concentration industrial emissions, where capture is currently not required.
|Algal biofuels and chemicals based on captured CO2 could add much-needed value to CCS projects
On paper, CCS certainly makes good sense as an emissions reduction option for the power industry. Excluding it as a technology would increase global green investment costs to 2050 by 40 per cent, according to the International Energy Agency (IEA). What is more, CCS or CCU is the only known way of dealing with emissions from unavoidable sources such as steel and cement production.
Despite this, the IEA complains that CCS is often excluded from the supportive policies and funding targeted at low-carbon technologies, which means governments may fail to follow the least cost route to lower emissions. High up-front costs also weaken the appeal of CCS, which in some circumstances can lack the energy security benefits offered by wind or solar, and is also unfashionable among environmentalists.
Globally, eight large-scale EOR-driven CCS projects currently store about 23 million tonnes of CO2 per year (mntCO2/year), according to the Global Carbon Capture and Storage Institute (GCCSI). Although concern over unreliable storage was largely responsible for halting another eight projects in 2012, none of these existing plants has experienced reservoir leakage.
A further eight projects are under construction, including two linked to power plants. These will raise storage to more than 36 mntCO2/year by 2015, or about 70 per cent of the IEA’s CCS target for the year. Looking further ahead, though, CCS is expected to fall increasingly short of the agency’s objectives.
While CCU could improve the economics of CCS projects, it operates on a different scale, says Professor Peter Styring of Sheffield University in the UK. While a utilisation advocate, he estimates that CCU could absorb just 10 per cent of emissions.
“There’s no competition between utilisation and storage, because each has a separate main purpose,” he says. “Utilisation is not so much about controlling emissions, it is more about ensuring a secure carbon chemical supply chain in the future.”
As well as to mitigate climate change, governments seek to achieve economic stability, establish sustainable industries, maintain employment and ensure energy security, he adds.
“Currently the most profitable use of CO2 is to make Asprin,” he says. “But the world’s demand would be satisfied by a partial off take from a small waste plant in Sheffield. On the other hand the synthetic kerosene and diesel markets are huge.”
Using CO2 for transport fuels could provide an alternative to the hydrogen-based energy system many expect to replace fossil fuels, saiys Professor Styring. And using CO2 in aviation fuels could be essential because no other fuel, including hydrogen, has yet proved technically viable, he adds.
He believes that intermittent renewables could provide energy to produce fuels based on CO2 during periods of low grid demand. In this way, CO2 utilisation would effectively store intermittent renewable energy, both in terms of carbon and electrons.
Dr Ward Goldthorpe, CCS programme manager for the UK Crown Estate, considers that utilisation could improve project economics by attaching a value to the CO2. “Using some of the carbon as a raw material or for EOR is welcome to help facilitate storage projects. They are certainly not mutually exclusive. We need to juggle in a bit of everything,” he said.
Enhanced gas recovery, coalbed methane injection and uses in other unconventional hydrocarbon development could also be complementary to CCS, he added.
So far only the EU has a structural incentive for CCS through the emissions trading scheme (ETS), but prices are well below the levels needed for private development, given the costs and perceived investment risk of the relatively untested technology. Additional subsidies are being provided through competitive process in the UK and EU, while other governments including Canada, Australia, China and the US have also sponsored development by more than $20 billion globally to date.
CCU deserves similar backing, saus Professor Styring. Whenever CCS is proposed, CCU should be considered, and CCU should also be promoted more by organisations like the IEA and United Nations, in his view.
UK edges ahead in CCS
The UK is taking a leading role in CCS with a comprehensive support policy combining a subsidy for early plants, with guaranteed long-term market-linked power prices.
CCS is earmarked to meet 7 gigatonnes (Gt) of carbon savings within a legally-binding target of 42 Gt to 2050 under a least cost scenario. The UK’s Energy Technology Institute estimates a 1 per cent per year GDP saving to 2050 through using CCS rather than renewable technologies to meet the targets.
What is more, the UK’s recent decision to back shale gas development and push ahead with new gas-fired power plants has knock-on implications for CCS, making it even more critical to the country’s binding emissions reduction strategy.
In the UK, the CCS Cost Reduction Task Force (CRTF) predicts the sector will be able to generate electricity at a levelised cost approaching à‚£100 ($160)/MWh by the early 2020s, and at a cost significantly below that soon after.
Costs will fall though transforming existing large offshore hydrocarbon gathering structures into CO2 storage clusters (including EOR operations), which would take gas from multiple onshore CO2 emitters through large, shared pipelines, with high usage, says Dr Goldthorpe.
“Third party access regulations will be based on those of oil and gas in the UK, which is one of the most efficient and competitive regimes in the world,” he adds. “Access to storage is more difficult. The UK is unique in reforming markets to achieve results, which is why the first [EU] power-to-storage project will be here.”
The CRTF also expects capture costs to fall following the first couple of projects, while dedicated funding through the new Green Bank, along with rising private finance as investor confidence improves, should bring down capital costs. Longer term, the CRTF expects EOR in some central North Sea oil fields to further improve economics.
At the end of the first quarter of 2013, the UK’s Department of Energy and Climate Change (DECC) is expected to provide funds of up to $1 billion to one or more of four projects vying to be the first large power-to-storage project in the UK and across the world without EOR.
The subsidy is aimed at kick-starting the industry, which requires heavy up-front investment if it is to be cost competitive by the 2020s. Two of the projects will need new pipelines to offshore storage sites, while the other two will use existing pipeline infrastructure. Three of the projects take CO2 from coal-fired power stations and one from a gas-fired station, which could be the world’s first gas-to-CCS project. Funding is also expected to come from the European Commission.
“The project chosen in March will be the first not associated with EOR worldwide at commercial scale. It will also be the first to collect the gas onshore for deposit offshore,” says Dr Goldthorpe. “Eventually the central North sea will be able to offer storage to Europe where coal use is on the rise.”
The UK’s electricity market system – which allows for guaranteed payments around market-linked Contract for Difference (CfD) feed-in tariffs (FiTs) – has created the best environment globally for power-linked CCS, says Dr Jeff Chapman of the UK Carbon Capture and Storage Association (CCSA).
While costs are expected to be above à‚£100/MWh in the first projects, even this is far below the equivalent solar price. And once transport and storage networks are started, costs are expected to fall sharply, he adds. “It is being realised that we cannot do without fossil fuels in the near term, and CCS tackles that and global warming at the same time.”
Dr Chapman sees national environmental policy as dictated as much by economic as environmental considerations. “The UK has backed CCS, Germany didn’t. It went for a failed industrial strategy tailored around solar manufacturing that has been undercut by the Chinese. Our strategy complements UK strengths in oil and gas engineering, and could provide a home for all the CO2 that the current ramp up in German coal use is creating.”
On the other hand, Professor Styring laments the lack of UK interest in utilisation. “If the development of CO2 utilisation were a 100-metre race, the Germans already have a 20-metre head start. They have invested heavily in utilisation techniques creating a centre of excellence in Germany,” he says. Yet he also sees policy as reflecting nations’ efforts to play to their strengths through industrial development strategies.
For Dr Goldthorpe, though, the UK is overlooking the commercial aspects of CCS and CCU. “Elsewhere, carbon projects have proceeded on the basis of synergistic business models, whereas in the UK it is in response to carbon reduction targets enshrined in law, and is simply CCS.” In his view, a carbon tax of $70-100/tonne would put enough value on UK carbon to ensure its disposal until EOR became easier to work into projects from 2020.
Professor Stuart Haszeldine of Edinburgh University also sees a need to bolster the commercial case for CCS. “The UK has 3-7 billion barrels of additional oil that could make the [CCS] proposition more attractive”. But lengthy new pipelines will be required and developers are restricted to existing wells by the cost of digging new ones, he adds.
New platforms may also be needed and flow control remains a problem, says Dr Goldthorpe.
The UK CCSA warmly welcomed recent UK energy legislation, saying it provided that “much needed investment certainty” for CCS. But there were no special incentives for carbon utilisation in the bill – all the competing projects are pure storage, with EOR seen only as a medium-term goal.
CCS makes a patchy start
Despite promising credentials, CCS is behind schedule. Meeting the IEA’s global emission targets requires that 130 CCS projects are on-stream by 2020. As well as the 16 now operating or under construction, only another 51 projects are planned for then, according to the GCCSI. Worse yet, although some industrial CCU projects exist, no CCS projects have been developed for iron, steel or cement manufacturers. “The lack of traction of CCS is due to a lack of traction on climate change,” says Dr Goldthorpe. But others see specific issues for CCS: high energy costs and uncertainty over storage sites, as well as high-capital costs that are particularly disabling in the wake of the banking crisis.
Public protests have curtailed at least three CCS projects worldwide. But more projects have been scuppered by technical glitches, largely associated with uncertainty over storage capacity and leakage. “Capture can be repeated but storage is different every time,” says Sheila Banes of geology firm Senergy.
Reservoir integrity represents the longest lead time for any CCS project, with certifying for each site requiring several years, although no operating CCS sites has yet recorded any leakage, and most experts believe CO2 is likely to behave much like other gases in petroleum formations, with which they are familiar.
Some governments – notably Germany – also reject CCS. “The German government has directed no funds towards CCS for three reasons: a lack of storage, public perception, and it couldn’t find a way to make it profitable,” says Professor Styring.
For Dr Goldthorpe, initial project financing has run up against Europe’s financial and banking crisis. “It’s all fallen on its face a bit [in Europe],” he says. Peripheral countries are unable to match EU funds, leaving projects languishing on the drawing board, he adds.
“The component technologies [of CCS] are understood, the issue for CCS is the size of upfront capital costs, but as the infrastructure is put in place costs will fall.”
New technology is steadily bringing down CCS’s high capture costs, although not as quickly as early optimists had predicted. Capture costs are expected to fall to €35-50 ($40-70)/tonne of CO2 (tCO2) in the early 2020s from €50-70/tCO2 now, according to the GCCSI. The UK’s DECC is targeting a capture cost of less than $40/tCO2 for “second generation technologies” and less than $10/tCO2 captured for “transformational technologies”. These goals assume 90 per cent CO2 capture, compared to current capture levels around 65-80 per cent in coal-fired plants.
The other costs are highly variable. Transportation costs depend on distance, existing infrastructure and ownership, while storage costs relate to the ease of injection and monitoring at reservoirs. But if CCS did get going as planned, experts expect suitable storage sites including depleted oil and gas fields to soon be used up, giving an idea of the huge volumes involved.
Eight CCS projects are currently operating, including two offshore natural gas processing developments with saline reservoir storage, two CO2 EOR projects, and BP’s gas processing and storage project in Algeria. All these projects are run by oil companies, who add value to the CO2 by finding a profitable use for it (i.e. EOR), are keen to show green credentials and have deep enough pockets to meet the high-capital costs.
In the US, Southern Company’s post-combustion 582 MW Plant Barry – which derived added value from EOR – recently became the world’s largest integrated CCS coal-fired project. Of the eight projects under construction and listed by the GCCSI, two were selected for support under the US Department of Energy’s Clean Coal Power Initiative, and both involve EOR. In CCU, the US is funding a range of projects that include making carbonates with flue gas from aluminium smelters and cement plants, as well as producing plastics and algal biofuels through coal-fired sources.
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In August, Australia brought on stream a large algal biofuel plant fed with CO2 from a neighbouring ethanol plant. Germany and Spain host similar plants and even India now has an algal project in the state of Orissa, which takes CO2 from a state aluminium plant.
But a huge reliance on coal-fired generation in developing nations – particularly China and India – makes large-scale CCS vital for global emission cuts. So far, only 19 developing countries are looking at CCS, mostly linked to EOR and with little impact on emissions, according to the GCCSI.
China is an honourable exception, hosting five of the nine new projects announced last year. Chinese support for CCS is also strong through the country’s 12th Five-Year Plan. The Huaneng Group, the country’s largest generator now has two CCS pilot projects underway.
But for emerging economies the IEA’s global emission reduction targets look especially challenging. To hit the agency’s goal, a staggering 70 per cent of CCS deployment by 2050 will need to occur in developing countries.