'Clean Coal' Technologies, Carbon Capture & Sequestration
(Updated June 2016)
- Coal is a vital fuel in most parts of the world.
- Burning coal without adding to global carbon dioxide levels is a major technological challenge which is being addressed.
- The most promising 'clean coal' technology involves using the coal to make hydrogen from water, then burying the resultant carbon dioxide by-product and burning the hydrogen.
- The greatest challenge is bringing the cost of this down sufficiently for "clean coal" to compete with nuclear power on the basis of near-zero emissions for base-load power.
- There is typically at least a 20% energy penalty involved in 'clean coal' processes.
- World R&D on CCS exceeded $1 billion per year over 2009 to 2013, then fell sharply.
Coal is an extremely important fuel and will remain so. Some 23% of primary energy needs are met by coal and 39% of electricity is generated from coal. About 70% of world steel production depends on coal feedstock. Coal is the world's most abundant and widely distributed fossil fuel source. The International Energy Agency (IEA) expects a 43% increase in its use from 2000 to 2020.
However, burning coal produces almost 14 billion tonnes of carbon dioxide each year which is released to the atmosphere, most of this being from power generation.
Development of new 'clean coal' technologies is addressing this problem so that the world's enormous resources of coal can be utilised for future generations without contributing to global warming. Much of the challenge is in commercialising the technology so that coal use remains economically competitive despite the cost of achieving low, and eventually 'near-zero', emissions. The technologies are both costly and energy-intensive.
As many coal-fired power stations approach retirement, their replacement gives much scope for 'cleaner' electricity. Alongside nuclear power and harnessing renewable energy sources, one hope for this is via 'clean coal' technologies, such as carbon capture and sequestration (CCS). However in its 2014 Energy Technology Perspectives the IEA notes that “CCS is advancing slowly, due to high costs and lack of political and financial commitment. Few major developments were seen in 2013, and policies necessary to facilitate the transition from demonstration to deployment are still largely missing.” For its low-carbon 2DS scenario, “the rate of capture and storage must increase by two orders of magnitude” by 2025.
Managing wastes from coal
Burning coal, such as for power generation, gives rise to a variety of wastes which must be controlled or at least accounted for. So-called 'clean coal' technologies are a variety of evolving responses to late 20th century environmental concerns, including that of global warming due to carbon dioxide releases to the atmosphere. However, many of the elements have in fact been applied for many years, and they will be only briefly mentioned here:
- Coal cleaning by 'washing' has been standard practice in developed countries for some time. It reduces emissions of ash and sulfur dioxide when the coal is burned.
- Electrostatic precipitators and fabric filters can remove 99% of the fly ash from the flue gases – these technologies are in widespread use.
- Flue gas desulfurisation reduces the output of sulfur dioxide to the atmosphere by up to 97%, the task depending on the level of sulfur in the coal and the extent of the reduction. It is widely used where needed in developed countries.
- Low-NOx burners allow coal-fired plants to reduce nitrogen oxide emissions by up to 40%. Coupled with re-burning techniques NOx can be reduced 70% and selective catalytic reduction can clean up 90% of NOx emissions.
- Increased efficiency of plant – up to 46% thermal efficiency now (and 50% expected in future) means that newer plants create less emissions per kWh than older ones. See Table 1.
- Advanced technologies such as Integrated Gasification Combined Cycle (IGCC) and Pressurised Fluidised Bed Combustion (PFBC) enable higher thermal efficiencies still – up to 50% in the future.
- Ultra-clean coal (UCC) from new processing technologies which reduce ash below 0.25% and sulfur to very low levels mean that pulverised coal might be used as fuel for very large marine engines, in place of heavy fuel oil. There are at least two UCC technologies under development. Wastes from UCC are likely to be a problem.
- Gasification, including underground coal gasification (UCG) in situ, uses steam and oxygen to turn the coal into carbon monoxide and hydrogen.
- Sequestration refers to disposal of liquid carbon dioxide, once captured, into deep geological strata.
Some of these impose operating costs and energy efficiency loss without concomitant benefit to the operator, though external costs will almost certainly be increasingly factored in through carbon taxes or similar which will change the economics of burning coal.
However, waste products can be used productively. In 1999 the EU used half of its coal fly ash and bottom ash in building materials (where fly ash can replace cement), and it used 87% of the gypsum from flue gas desulfurisation.
Carbon dioxide from burning coal is the main focus of attention today, since it is implicated in global warming, and the Kyoto Protocol requires that emissions decline, notwithstanding increasing energy demand.
Carbon capture and storage or sequestration (CCS) technologies are in the forefront of measures to enjoy 'clean coal'. CCS involves two distinct aspects: capture, and storage.
The energy penalty of CCS is generally put at 20-30% of electrical output, though since no full commercial systems are yet in operation, this is yet to be confirmed. US and European figures below suggest a small or even negligible proportion.
Table 1. Coal-fired power generation, thermal efficiency
||Projected efficiency with CCS
||Black ultra-supercritical WC
||Black supercritical WC
||Black supercritical AC
||own ultra-supercritical WC
||own supercritical WC
||own supercritical AC
||Black ultra-supercritical PCC
||Black supercritical PCC
||Black supercritical PCC
||Black PCC & IGCC
||Black supercritical PCC
OECD Projected Costs of Generating Electricity 2010, Tables 3.3.
PCC= pulverised coal combustion, AC= air-cooled, WC= water-cooled.
Capture & separation of CO2
A number of means exist to capture carbon dioxide from gas streams, but they have not yet been optimised for the scale required in coal-burning power plants. The focus in the past has often been on obtaining pure CO2 for industrial purposes rather than reducing CO2 levels in power plant emissions.
Where there is carbon dioxide mixed with methane from natural gas wells, its separation is well proven. Several processes are used, including hot potassium carbonate which is energy-intensive and requires a large plant, a monoethanolamine process which yields high-purity carbon dioxide, amine scrubbing, and membrane processes.
Development of CCS for coal combustion has lost momentum in the last few years, partly due to uncertainty regarding carbon emission prices.
In mid-2010 the IEA published a report says CCS was challenging, and quoting $26 billion committed in the previous two years to CCS projects. There were 80 large-scale integrated CCS projects under way, 5 of them operating. It said that “notable efforts" were being made and "increased action”, but "rapid progress is now required" if CCS is to be deployed by 2020.
Capture of carbon dioxide from flue gas streams following combustion in air is much more difficult and expensive than from natural gas streams, as the carbon dioxide concentration is only about 14% at best, with nitrogen most of the rest, and the flue gas is hot. The main process treats carbon dioxide like any other pollutant, and as flue gases are passed through an amine solution the CO2 is absorbed. It can later be released by heating the solution. This amine scrubbing process is also used for taking CO2 out of natural gas. There is a significant energy cost involved. For new power plants this is quoted as 20-25% of plant output, due both to reduced plant efficiency and the energy requirements of the actual process.
No commercial-scale power plants are operating with this process yet. At the new 1300 MWe Mountaineer power plant in West Virginia, less than 2% of the plant's off-gas is being treated for CO2 recovery, using chilled amine technology. This has been successful. Subject to federal grants, there are plans to capture and sequester 20% of the plant's CO2, some 1.8 million tonnes CO2 per year.
Where coal is burned in oxygen rather than air, it means that the flue gas is mostly CO2 and hence it can more readily be captured by amine scrubbing – at about half the cost of capture from conventional plants. A number of oxyfuel systems are operational in the USA and elsewhere, and the FutureGen 2 project involves oxy-combustion. Such a plant has an air separation unit, a boiler island, and a compression and purification unit for final flue gas.
The Integrated Gasification Combined Cycle (IGCC) plant is a means of using coal and steam to produce hydrogen and carbon monoxide (CO) from the coal and these are then burned in a gas turbine with secondary steam turbine (ie combined cycle) to produce electricity. If the IGCC gasifier is fed with oxygen rather than air, the flue gas contains highly-concentrated CO2 which can readily be captured post-combustion as above.
Further development of the IGCC process will add a shift reactor to oxidise the CO with water so that the gas stream is basically just hydrogen and carbon dioxide, with some nitrogen. The CO2 with some H2S & Hg impurities are separated before combustion (with about 85% CO2 recovery) and the hydrogen alone becomes the fuel for electricity generation (or other uses) while the concentrated pressurised carbon dioxide is readily disposed of. (The H2S is oxidised to water and sulfur, which is saleable.) No commercial-scale power plants are operating with this process yet but see demonstration project sections below.
Currently IGCC plants typically have a 45% thermal efficiency.
Capture of carbon dioxide from coal gasification is already achieved at low marginal cost in some plants. One (albeit where the high capital cost has been largely written off) is the Great Plains Synfuels Plant in North Dakota, where 6 million tonnes of lignite is gasified each year to produce clean synthetic natural gas.
Oxy-fuel technology has potential for retrofit to existing pulverised coal plants, which are the backbone of electricity generation in many countries.
In China, the major utility China Datang Corp is teaming with Alstom to build two demonstration CCS projects. A 350 MWe coal-fired plant at Daqing, Heilongjiang province, will be equipped with Alstom's oxy-firing technology, and a 1000 MWe coal-fired plant at Dongying, Shandong province, will use an Alstom's post-combustion capture technology, either chilled ammonia or advanced amines. The two projects are expected to be operational in 2015 and each capture over one million tonnes of CO2 per year, which would be about 40% of output from Daqing and 15% from Dongying, though Alstom says that the actual levels of capture and storage have not yet been defined and will be in the scope of the first feasibility studies of the respective projects. Adjacent oilfields will be used for sequestration, enabling enhanced oil recovery.
Storage & sequestration of carbon dioxide
There are three main categories of geological storage for CO2: oil and gas replacement – notably enhanced oil recovery (EOR), coal seam storage, and deep saline aquifers. The first can have direct economic benefit offsetting the cost. To 2014, 55 million tonnes of CO2 had been sequestered with monitoring. At the end
of 2015, 15 large-scale operational projects had a total potential capture rate of 28 Mt CO2 per year,
but only 7.5 Mt/yr (27%) of the captured CO2 was being stored with appropriate monitoring and verification, according to the IEA's Energy Technology Perspectives.
Enhanced oil recovery
Captured carbon dioxide gas can be put to good use, even on a commercial basis, for enhanced oil recovery (EOR), and a majority of CCS projects are oriented thus. This is well demonstrated in West Texas, and today over 5800 km of pipelines connect oilfields to a number of carbon dioxide sources in the USA. The CO2 acts to reduce the viscosity of the oil, enhancing its flow to recovery wells. It is then separated and re-injected.
At the Great Plains Synfuels Plant, North Dakota, some 13,000 tonnes per day of carbon dioxide gas is captured and 5000 t of this is piped 320 km into Canada for enhanced oil recovery. This Weyburn oilfield sequesters about 85 cubic metres of carbon dioxide per barrel of oil produced, a total of 19 million tonnes over the project's 20-year life. The first phase of its operation has been judged a success.
Chevron’s Rangely project in the Rocky Mountain area injects 3 million tonnes of CO2 per year supplied by pipeline for EOR in sandstone formations 1800 m deep.
Overall in the USA, over 6200 km of pipelines transport up to 72 million tonnes of CO2 per year that the oil industry uses in enhanced oil recovery, 55 Mt from natural sources, 17 Mt anthropogenic. This produces 281,000 barrels of domestic oil per day, or 6% of US crude oil production. The EOR industry has captured, transported, and injected large volumes of CO2 for oil recovery over four decades with no major accidents, serious injuries or fatalities. Present EOR technology has the potential to recover at least an additional 26 billion barrels of US oil, and improved technology could double this, while sequestering over 20 billion tonnes of CO2. The USA in 2011 set up a National Enhanced Oil Recovery Initiative (NEORI) to help realize CO2-EOR’s full potential as a national energy security, economic and environmental strategy. Its central recommendation is for a production tax credit for CO2 capture and sequestration with EOR.
In Texas, the Port Arthur demonstration project aims to capture 1 Mt/yr of CO2 from two steam methane reformers at Valero Energy Corporation’s refinery, selling it for use in enhanced oil recovery. Another scheme separating CO2 and using it for enhanced oil recovery is at In Salah, Algeria.
Depleted oil and gas fields
Total in France has been testing the first complete industrial-scale CCS chain in Europe. CO2 is captured from a 30 MW boiler modified for oxycombustion, piped 27 km, and injected into a depleted gas field 4500 metres deep. Over two years 120,000 tonnes of CO2 is expected to be stored (50,000 t so far to early 2013), and intensive monitoring is being undertaken over three years.
In Australia the CO2CRC Otway project injected approximately 65,000 t CO2 into a depleted gas reservoir in Victoria between April 2008 and August 2009. This made it the largest injection project using a depleted oil or gas field in the world.
Injecting carbon dioxide into deep, unmineable coal seams where it is adsorbed to displace methane is another potential use or disposal strategy. The displacement effect means that coal seam CO2 injection could be most effective as part of the commercial production of coal seam methane (also known as coal bed methane, effectively: natural gas), an increasingly important and relatively new energy source.
Storage in coal seams is different since the CO2 is adsorbed in the coal matrix instead of being held within the pores of the rocks as in saline aquifers and oil-gas systems. The properties of the coal strongly influence whether CO2 will adsorb into it. Currently the economics of enhanced coal bed methane extraction with CO2 disposal are often not as favourable as with enhanced oil recovery, but the potential is large as coal seam gas is increasingly tapped.
These are underground formations of deep porous sedimentary rock such as sandstone, that are saturated with salty water which is unfit for human consumption or agricultural use, and covered by a layer of impermeable cap rock (such as shale or clay), which acts as a seal. Once injected into the formation, the CO2 dissolves into the saline water in the reservoir rock. CO2 storage in deep saline formations usually takes place at depths below 800 metres. At this depth, the CO2 will be at high enough pressures to remain in a liquid-like state
The world's first industrial-scale CO2 storage was at Norway's Sleipner gas field in the North Sea, where about one million tonnes per year of compressed liquid CO2 separated from methane is injected into a deep reservoir (saline aquifer) about a kilometre below the sea bed and remains safely in place. The US$ 80 million incremental cost of the sequestration project was paid back in 18 months on the basis of carbon tax savings at $50/tonne. (The natural gas contains 9% CO2 which must be reduced before sale or export.) The Utsira sandstone formation there, about one kilometre below the sea bed, is said to be capable of storing 600 billion tonnes of CO2. In 2007 the Snohvit project, with 8% reservoir CO2 content, joined Sleipner in CCS there.
West Australia's Gorgon natural gas project will tap natural gas with 14% CO2. Capture and geosequestration of this is expected to reduce the project's total emissions from 6.7 to 4.0 million tonnes of CO2 per year. The project will have capacity for up to 3.4 million tonnes per year of pressurised supercritical CO2 to be injected into the Dupuy formation – a saline aquifer 2500 metres deep below Barrow Island. This is at least 80%, and ultimately 95%, of the reservoir CO2 extracted. This will be the world's largest commercial-scale CO2 injection facility and the Gorgon joint venture is investing approximately $2 billion in the design and construction of it. The Australian Government has committed $60 million to the Gorgon Carbon Dioxide Injection Project as part of the Low Emissions Technology Demonstration Fund.
Some CO2 injection to saline aquifers involves acid gas, disposing of hydrogen sulphide and CO2 separated for a natural gas stream. Chevron’s Acheson Field in Canada was one of the first to use this acid gas injection.
Saline formations have the largest storage potential globally and a number of CO2 storage demonstration projects are proving their effectiveness to maximise storage capacity and containment.
While the scale of envisaged need for CO2 disposal far exceeds today's uses, they do demonstrate the possibility. Safety and permanence of disposition are key considerations in sequestration.
IEA member governments spent less than $400 million per year on CCS up to 2008, but the total then jumped to over $1 billion from 2009 to 2013, before falling sharply in 2014. In 2012 this was about 6.6% of their total energy research, development and demonstration (RD&D) expenditure. The share of CCS in fossil fuel RD&D expenditure increased significantly, from around 20% in 2008 and 2009 to over 50% in 2010-13.
Research on geosequestration is ongoing in sevaral parts of the world. The main potential appears to be deep saline aquifers and depleted oil and gas fields. In both, the CO2 is expected to remain as a supercritical gas for thousands of years, with some dissolving.
In 2016 it was reported that Iceland had trialled pumping CO2 and water into hot underground rocks and turning it into limestone over about two years.
Large-scale storage of CO2 from power generation will require an extensive pipeline network in densely populated areas. This has safety implications.
Given that rock strata have held CO2 and methane for millions of years there seems no reason that carefully-chosen chosen ones cannot hold sequestered CO2. However, the eruption of a million tonnes of CO2 from Lake Nyos in Cameroon in 1986 asphyxiated 1700 people, so the consequences of major release of heavier-than-air gas are potentially serious.
Producing oxygen for oxyfuel and IGCC
Today most oxygen is recovered cryogenically from liquid air, which is a relatively expensive process.
The main prospective means of economically producing large amounts of oxygen is the ion transport membrane (ITM) process. It is being developed for use in feeding integrated gasification combined cycle (IGCC), oxyfuel combustion, and other advanced power generation systems including underground coal gasification. In the USA, EPRI is involved on behalf of the electric utilities in helping to scale-up ITM technology for clean energy.
ITM technology uses a ceramic material which, under pressure and temperature, ionizes and separates oxygen molecules from air. No external source of electrical power is required. Relative to traditional cryogenic air separation units, ITM technology could decrease internal power demand by as much as 30% and capital costs by approximately 30% in the oxygen supply systems at oxyfuel and IGCC power plants.
The oxygen requirements for the power generation industry could grow substantially in supporting advanced coal-based power generation and integrated carbon capture technology. EPRI estimates the current US power generation industry share of the oxygen market is about 4%, but it could become the dominating market driver, accounting for more than 60% of the future market, or approximately two million tones per day of oxygen by 2040.
The World Coal Institute noted that in 2003 the high cost of carbon capture and storage (estimates of US$ 150-220 per tonne of carbon, $40-60/t CO2 – 3.5 to 5.5 c/kWh relative to coal burned at 35% thermal efficiency) made the option uneconomic. But a lot of work is being done to improve the economic viability of it, and the US Dept of Energy (DOE) was funding R&D with a view to reducing the cost of carbon sequestered to US$ 10/tC (equivalent to 0.25 c/kWh) or less by 2008, and by 2012 to reduce the cost of carbon capture and sequestration to a 10% increment on electricity generation costs. These targets now seem very unrealistic.
A 2000 US study put the cost of CO2 capture for IGCC plants at 1.7 c/kWh, with an energy penalty 14.6% and a cost of avoided CO2 of $26/t ($96/t C). By 2010 this was expected to improve to 1.0 c/kWh, 9% energy penalty and avoided CO2 cost of $18/t ($66/t C), but these numbers now seem unduly optimistic.
Figures from IPCC Mitigation working group in 2005 for IGCC put capture and sequestration cost at 1.0-3.2 c/kWh, thus increasing electricity cost for IGCC by 21-78% to 5.5 to 9.1 c/kWh. The energy penalty in that was 14-25% and the mitigation cost $14-53/t CO2 ($51-200/tC) avoided. These figures included up to $5 per tonne CO2 for transport and up to $8.30 /t CO2 for geological sequestration.
In 2009 the OECD’s International Energy Agency (IEA) estimated for CCS $40-90/t CO2 but foresees $35-60/t by 2030, and McKinsey & Company estimated €60-90/t reducing to €30-45/t after 2030.
ExxonMobil is proposing that, where amine scrubbing is employed, the whole power plant exhaust is directed to a carbonate fuel cell which will generate over 20% more power overall, instead of costing 10% of the power due to diversion of steam. The CO2 still needs to be disposed of.
FutureGen demonstration projects, USA
About 2005 the DOE announced the $1.3 billion FutureGen project to design, build and operate a nearly emission-free coal-based electricity and hydrogen production plant. Some $250 million of the funding was to be provided by industry, from about eight companies. The FutureGen initiative would have comprised a coal gasification (IGCC) plant with additional water-shift reactor, to produce hydrogen and carbon dioxide. It would also involve development of the ITM oxygen separation technology. About 700,000 tonnes of CO2 (some 60% of throughput) per year would then be separated by membrane technology and sequestered geologically. The hydrogen would have been be burned in a 275 MWe generating plant and in fuel cells. Later FutureGen figures referred to 90% CO2 capture and 330 MWe gross, 240 MWe net generation.
Construction of this original FutureGen was due to start in 2009, for operation in 2012, with target of 90% carbon capture. The project was designed to validate the technical feasibility and economic viability of near-zero emission coal-based generation. In particular it aimed to produce electricity with only a 10% cost premium and to show that hydrogen can be produced at $3.80 per GJ, equivalent to petrol at 12.7 cents per litre. In December 2007 Mattoon Illinois was chosen as the site of the demonstration plant. However, in January 2008 the DOE announced that it would withdraw its funding for the project, expressing concerns over escalating costs – its 74% share having doubled to $1.3 billion. The Mattoon site in Coles County was subsequently sold.
Under the new Administration in 2010 however, the project was reconsidered, and design work, geological investigations and a revised cost estimate proceeded. In August 2010 DOE said that it would abandon the original FutureGen idea and would now retrofit unit 4 of Ameren's existing oil-fired plant in Meredosia, Illinois, with oxy-combustion rather than IGCC, calling this FutureGen 2.0 – "a clean-coal repowering program and carbon dioxide storage network." It would burn pulverised coal and capture over 90% of the CO2 produced (1.3 Mt/yr over 30 years), to produce 166 MWe net. A pipeline would link it to a regional CO2 storage hub, and a site will be sought for this to enable sequestration in the Mt Simon Formation. Ameren would use B&W technology for oxy-combustion repowering of the plant, and FutureGen Alliance will focus on the pipeline and storage, with a view to also drawing on other CO2 sources within 160km, so that some 500 million tonnes capacity was sought.
The DOE said that it would be prepared to contribute $1.1 billion of the $1.65 billion cost to it as a public-private partnership involving the FutureGen Industrial Alliance (FGA), Ameren Energy Resources, Babcock & Wilcox, and Air Liquide Process & Construction, Inc. Late in 2010 members of the FGA included domestic coal companies Peabody, BHP Billiton, Rio Tinto and Consol Energy, plus E.On. No domestic utilities remained, though Exelon had indicated an intention to join. In December 2012, the Illinois Commerce Commission mandated that Commonwealth Edison (ComEd) and Ameren Illinois had to purchase the electricity from the project for 20 years, but the utilities challenged this on the grounds of cost.
After identifying a suitable sequestration site in Morgan County, the design phase of the project was announced in February 2013. Construction was due be completed in 2015, with the project being on line mid-2016, but this was delayed as most members of the FGA dropped out, leaving only Peabody, Glencore and Anglo American. In February 2015 DOE cancelled further funding for the project, after having spent $202 million on it.
Other demonstration projects
The US Department of Energy (DOE) has said that funding would be made available to assist other projects that aim to add carbon capture and storage (CCS) to existing coal plants, but will no longer include hydrogen production as part of the project. Over half of the CO2 capture projects in development or operation globally are in North America, and all but one of these is oriented to provide CO2 for enhanced oil recovery (EOR).
Duke Energy Corp in the USA is building a $3 billion, 618 MWe, IGCC plant at Edwardsport, Indiana ($4850/kW). This is a regulated plant, but Duke says that consumers will not be asked to pay for more than $2.72 billion of its final construction cost, excluding financing.
Summit Power Group's Texas Clean Energy Project (TCEP) at Penwell is a 377 MWe IGCC power plant burning coal with CCS, capturing 90% of CO2 and 90% of NOx. It has $450 million funding from DOE Clean Coal Power Initiative towards its $2.4 billion cost. It was due to operate from 2015, but construction start is now possibly 2016. Of the 2.9 t/yr of CO2 captured, 83% will be used for enhanced oil recovery in the West Texas Basin. Of the 377 MWe, 106 MW will be used to run the major project equipment on site, 16 MW will be used to compress CO2, and 42 MW will be used to produce urea, leaving 214 MWe for the grid. In December 2015 Summit signed an engineering, procurement and construction (EPC) contract with China Huanqui Contracting & Engineering Corporation (HQC), a subsidiary of China National Petroleum Corporation (CNPC), and SNC-Lavalin.
Also in Texas, the Petra Nova project near Houston, a partnership of US DOE, NRG Energy and JX Nippon, plans to capture 1.6 million tonnes of CO2 per year (90%) from NRG's WA Parish 240 MWe power plant and use it for enhanced oil recovery. In a post-combustion process the flue gas will be cooled and the CO2 removed by amine scrubbing. The CO2 is released from the solvent with low-pressure steam. The Petra Nova Parish plant is due to start up late in 2016, and will be the largest post-combustion carbon capture project installed on an existing coal-fueled power plant.
Southern Company's Kemper County Energy Facility in Mississippi was due to start up in 2015, but costs have blown out from $3 billion to $6.6 billion. It aims to gasify coal then capture CO2 and burn hydrogen.
Net Power, backed by Toshiba, Exelon and others, is starting to construct a 50 MWe plant with oxy-fuel combustion of natural gas and recycled CO2 driving a turbine (Allam cycle) so that the plant produces only electricity, water and pipeline-ready CO2. The pilot plant is expected to operate from 2017.
In Canada, a 110 MWe coal-fired plant is the world’s only commercial-scale CCS power station, operating from early 2015. SaskPower’s Boundary Dam unit 3 plant came on line in October 2014. Prior to upgrading it at a cost of C$ 1.47 billion, with C$ 900 million of this for the CCS system, it produced 139 MWe and released 3604 t CO2 per day. It now releases 354 t/day, so captures about 90%, more than one million tonnes per year.
The Quest project in Canada’s oil sands commissioned in 2015 captures up to 1 million tonnes of CO2 per year from hydrogen production at the Scotford Oil Sands Upgrader for storage at a depth of about 2 km in an onshore saline aquifer.
The CCPilot 100+ project at Ferrybridge in West Yorkshire, UK, has commenced operation. It can capture 100 tonnes of CO2 per day from 5 MWe of coal-fired power plant. Operator is Scottish & Southern Energy in collaboration with Vattenfall and Doosan Babcock. It uses a post-combustion amine scrubbing process and is subsidised by the government. Vattenfall expects to apply experience from it to a much larger demonstration plant at Jaenschwalde in Germany, to operate from 2015.
In the UK a competition was launched by the UK government in 2007 to support a coal-fired power plant demonstrating the full chain of CCS technologies (capture, transport, and storage) on a commercial scale. The winning project bid would have to demonstrate post-combustion capture (including oxyfuel) on a coal-fired power station, with the carbon dioxide being transported and stored offshore. The project would have to capture around 90% of the CO2 emitted by the equivalent of 300MW-400MW generating capacity. The successful project bid should demonstrate the entire CCS chain by 2014. A further CCS commercialisation competition was launched in 2012, and in 2013 the government selected two proposals, the White Rose Project and the Peterhead project, which were both funded to undertake engineering work. It was envisaged that the companies would make final investment decisions about the end of 2015, with the government taking funding decisions then. However, in November 2015 the government announced withdrawal of funding for both projects.
Scottish & Southern Energy and Shell UK agreed in November 2011 to build the first commercial-scale CCS demonstration project at Peterhead in the northeast of Scotland, at a cost of £1 billion. The project aimed to design and develop a full chain, post-combustion CCS facility which would capture 85% to 90% of the CO2 from one 385 MW combined cycle gas turbine unit at SSE's Peterhead Power Station. It was planned that the 1 million tonnes per year of CO2 would then be pumped 100 km to Shell's Goldeneye gas field 2.5 km beneath the North Sea which will have ceased production using, as far as possible, existing infrastructure. Some £1bn from the EU and UK government was expected for the project. Earlier Scottish Power cancelled plans for a similar project at Longannet coal-fired power station. Shell said it remained committed to CCS.
Capture Power Ltd had applied for planning permission for a 448 MWe coal-fired unit with oxyfuel combustion and CCS at the Drax power station in Yorkshire. This White Rose project was designed to capture 90% of carbon emission, about 2 million tonnes per year, which would be piped by National Grid to to a ‘saline rock formation’ below the North Sea. The EU in 2014 provided €300 million funding.
In Denmark a pilot project at the 420 MWe Elsam power plant is capturing CO2 from post-combustion flue gases under the auspices of CASTOR (CO2 from Capture to Storage). Flue gases are passed through an absorber, where a solvent captures about 90% of the CO2. The pregnant solution is then heated to 120°C to release pure CO2 at the rate of about one tonne per hour for geological sequestration. Cost is expected to be €20-30 per tonne.
Zero Emission Platform (ZEP), founded in 2005, is a European CCS lobby group involving major utilities. ZEP serves as advisor to the European Commission on the research, demonstration and deployment of CCS. However, early in 2015 RWE, Vattenfall and Gas Natural Fenosa (also apparently EdF) dropped out, pleading restricted time and budget and saying that “we do not have the necessary economic framework conditions in Europe to make CCS an attractive technology to invest in.”
In Netherlands, the Rotterdam Opslag and Afvang Demonstratieproject (ROAD, Rotterdam Capture and Storage Demonstration Project) set up by E.On and GdF Suez aims to capture 1.1 Mt CO2/yr from a 250 MWe coal-fired plant at the Maasvlakte-3 plant in Rotterdam.
In Germany, Vattenfall’s Schwarze Pumpe lignite power plant started a 30 MW pilot CCS project in 2007, but never proceeded past this and the company will abandoned the project in 2018. In 2014 Vattenfall announced it will abandon CCS altogether.
Rest of world
In China, the first phase of Huaneng Group’s $1.5 billion GreenGen project – a 250 MWe oxyfuel IGCC power plant burning syngas (mainly hydrogen and carbon monoxide) from coal feed – commenced operation at Tianjin in 2012 and has been fully operational since 2014. The second phase involves a pilot plant which draws about 7% of the syngas from the IGCC power plant, shifts CO and water to CO2 and H2, then separates the CO2 from the H2 after desulphurisation, and produces electricity from hydrogen. The 60,000 to 100,000 tpa CO2 is used for enhanced oil recovery. Phase 3 will be a 400 MWe commercial IGCC plant with CCS to capture up to 2 million tonnes of CO2 per year, from about 2020.
The Uthmaniyah project in the Eastern Province of Saudi Arabia commissioned in 2015 will capture around 800,000 tonnes of CO2 per year from the Hawiyah natural gas liquids recovery plant to be injected for enhanced oil recovery (EOR) at the Ghawar oilfield.
In Australia the $240 million Callide Oxyfuel project in Queensland aims to demonstrate oxyfuel capture technology retrofitted to a 30 MW unit of an existing coal-fired power plant and to research how it might be applied to new power stations. The plant was commissioned in 2012 and was to run for an extended test period until November 2014. By mid-2013 the project had demonstrated CO2 capture rates from the oxyfuel flue gas stream to the CO2 capture plant in excess of 85%, and produced a high quality CO2 product suitable for geological storage. The project achieved more than 10,000 hours of oxy-combustion and more than 5,000 hours of carbon capture from Callide A. The plant was then decommissioned. CS Energy led the project and is working closely with an international team of partners including IHI Corporation (Japan), J-Power (Japan), Mitsui & Company (Japan), and Xstrata Coal.
Also in Australia the $150 million Delta Post Combustion Capture project hosted at Delta’s 1320 MWe Vales Point coal-fired power station in NSW aimed to demonstrate capture and sequestration of 100,000 t/yr of CO2 by 2015. However, after massive losses the plant was sold for a token sum in November 2015, with no mention of the CCS project.
Both Australian projects were funded by federal and state governments and the coal industry.
In conventional plants coal, often pulverised, is burned with excess air (to give complete combustion), resulting in very dilute carbon dioxide at the rate of 800 to 1200 g/kWh.
Gasification converts the coal to burnable gas with the maximum amount of potential energy from the coal being in the gas.
In Integrated Gasification Combined Cycle (IGCC) the first gasification step is pyrolysis, from 400°C up, where the coal in the absence of oxygen rapidly gives carbon-rich char and hydrogen-rich volatiles.
In the second step the char is gasified from 700°C up to yield gas, mostly CO, leaving ash. With oxygen feed, the gas is not diluted with nitrogen.
The key reactions today are C + O2 to CO, and the water gas reaction: C + H2O (steam) to CO & H2 – syngas, which reaction is endothermic.
In gasification, including that using oxygen, the O2 supply is much less than required for full combustion, so as to yield CO and H2. The hydrogen has a heat value of 121 MJ/kg – about five times that of the coal, so it is a very energy-dense fuel. However, the air separation plant to produce oxygen consumes up to 20% of the gross power of the whole IGCC plant system. This syngas can then be burned in a gas turbine, the exhaust gas from which can then be used to raise steam for a steam turbine, hence the "combined cycle" in IGCC.
To achieve a much fuller clean coal technology in the future, the water-shift reaction will become a key part of the process so that:
- C + O2 gives CO, and
- C + H2O gives CO & H2, then the
- CO + H2O gives CO2 & H2 (the water-shift reaction).
The products are then concentrated CO2 which can be captured, and hydrogen. (There is also some hydrogen from the coal pyrolysis), which is the final fuel for the gas turbine.
Overall thermal efficiency for oxygen-blown coal gasification, including carbon dioxide capture and sequestration, is about 73%. Using the hydrogen in a gas turbine for electricity generation is efficient, so the overall system has long-term potential to achieve an efficiency of up to 60%.
The clean coal technology field is moving in the direction of coal gasification with a second stage so as to produce a concentrated and pressurised carbon dioxide stream followed by its separation and geological storage. This technology has the potential to provide what may be called "zero emissions" – in reality, extremely low emissions of the conventional coal pollutants, and as low-as-engineered carbon dioxide emissions.
This has come about as a result of the realisation that efficiency improvements, together with the use of natural gas and renewables such as wind will not provide the deep cuts in greenhouse gas emissions necessary to meet future national targets.
The US DOE sees "zero emissions" coal technology as a core element of its future energy supply in a carbon-constrained world. It had an ambitious program to develop and demonstrate the technology and have commercial designs for plants with an electricity cost of only 10% greater than conventional coal plants available by 2012, but this is at least postponed.
Australia is very well endowed with carbon dioxide storage sites near major carbon dioxide sources, but as elsewhere, demonstration plants will be needed to gain public acceptance and show that the storage is permanent.
Natural gas as alternative fuel
There are many advocates for the use of natural gas as an alternative to coal for electricity generation, on the grounds that it emits much less CO2 per kWh generated. This is true on almost any basis of comparison, but it ignores the global warming potential of leaked natural gas, and the CO2 emissions in transporting it as LNG (up to one third of the energy is consumed in transport). Leakage of 3% of the natural gas will bring it into approximate parity with coal-fired electricity in terms of global warming effect.
There is a range of ways of using natural gas primarily for power generation:
Central Heat and Power (CHP) – Typically burn in a combined cycle gas turbine (CCGT) for electricity, using exhaust gas to heat steam boiler to make more electricity, and finally using "the exhaust stream to heat buildings or other purposes. Thermodynamic efficiencies of 80% for this have been reported.
Combined cycle gas turbine – On its own, the best efficiency is GE's H series, which claims 60% efficiency.
Direct gas turbine – high 30's% efficiency, or straight steam boiler with about 40% efficiency (now obsolete).
All of these have potential for CCS. Methane when burned gives CO2 and water, the latter is easily separated. With high efficiencies the nitrogen proportion should be less that that with low efficiency, such as most coal.
Prime Minister's Science Engineering and Innovation Council, Australia 2002, Beyond Kyoto report
David Cain & staff, Rio Tinto, pers. comm.
Smith, D 2002, CO2 capture articles in Modern Power Systems, Nov-Dec 2002
World Coal Institute, publications on Clean Coal Technologies
Australian Coal Association (integrated into the Minerals Council of Australia in 2013)
World Coal Institute, Sustainable Entrepreneurship: the Way Forward for the Coal Industry
International Energy Agency 2002, Key World Energy Statistics
International Energy Agency 2002, Solutions for 21st Century – Zero emissions technologies for fossil fuels
US DOE 27/2/03 announcement
US DOE NETL 21/3/03, Carbon sequestration – technology roadmap and program plan.
Gale, J., Geological storage of CO2: What do we know, where are the gaps and what more needs to be done?, Energy, Vol. 29, issue 9, pages 1329-1338 (2004)
Draft Environmental Impact Statement/Environmental Review and Management Programme for the Proposed Gorgon Development, Chapter 13: Greenhouse Gas Emissions – Risks and Management, Chevron Australia, September 2005
US DOE Clean Coal Research
National Enhanced Oil Recovery Initiative (NEORI), Carbon Dioxide Enhanced Oil Recovery: A Critical Domestic Energy, Economic, And Environmental Opportunity, February 2012
Michel J.H., Lost hopes for CCS – added urgency for renewable energy, Air Pollution & Climate Secretariat, Air Pollution and Climate Series 28, June 2013
International Energy Agency, Energy Technology Perspectives 2016