"Clean Coal" Technologies, Carbon Capture & Sequestration

(April 2010)

• 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. 

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 expects a 43% increase in its use from 2000 to 2020.

However, burning coal produces about 9 billion tonnes of carbon dioxide each year which is released to the atmosphere, about 70% of this being from power generation. Other estimates put carbon dioxide emissions from power generation at one third of the world total of over 25 billion tonnes of CO₂ emissions.

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 "zero emissions".

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 are now starting to receive substantial R&D funding.

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) will 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 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 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 (CCS) technologies are in the forefront of measures to enjoy “clean coal”.  CCS involves two distinct aspects: capture, and storage.

Table 1. Coal-fired power generation, thermal efficiency

countryTechnologyEfficiencyProjected efficiency with CCS

Table 1. Coal-fired power generation, thermal efficiency

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 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.

Capture of carbon dioxide from flue gas streams following combustion in air is much more difficult and expensive, as the carbon dioxide concentration is only about 14% at best.  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 an 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. 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.

Oxyfuel combustion, where coal is burned in oxygen rather than air, 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.

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 this oxygen-fed 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. These are separated before combustion and the hydrogen alone becomes the fuel for electricity generation (or other uses) while the concentrated pressurised carbon dioxide is readily disposed of.  No commercial scale power plants are operating with this process yet.

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.

Storage & sequestration of CO₂

Captured carbon dioxide gas can be put to good use, even on a commercial basis, for enhanced oil recovery. 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. 

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.

Overall in USA, 32 million tonnes of CO₂ is used annually for enhanced oil recovery, 10% of this from anthropogenic sources.

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 overall Utsira sandstone formation there, about one kilometre below the sea bed, is said to be capable of storing 600 billion tonnes of CO₂.

Another scheme separating CO2 and using it for enhanced oil recovery is at In Salah, Algeria.

West Australia's Gorgon natural gas project from 2009 will tap natural gas with 14% CO₂. Capture and geosequestration of this is expected to reduce the project's emissions from 13.3 to 5.3 million tonnes of CO2 per year, 3.0 million tonnes of the reduction being injected into geological reservoirs.

Injecting carbon dioxide into deep, unmineable coal seams where it is adsorbed to displace methane (effectively: natural gas) is another potential use or disposal strategy. Currently the economics of enhanced coal bed methane extraction are not as favourable as enhanced oil recovery, but the potential is large.

While the scale of envisaged need for CO₂ disposal far exceeds today's uses, they do demonstrate the practicality. Safety and permanence of disposition are key considerations in sequestration.

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.

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. 

Economics, R&D

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.

More recently the DOE had announced the $1.3 billion FutureGen project to design, build and operate a nearly emission-free coal-based electricity and hydrogen production plant. The FutureGen initiative would have comprised a coal gasification 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.

Construction of 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 pull its funding for project, expressing concerns over escalating costs..  Under the new Administration however, the project was reconsidered, and design work, geological investigations and a revised cost estimate are proceeding.  A decision on whether or not to embark upon construction is scheduled for early 2010, and the DOE has said that it is prepared to contribute over $1 billion to it.  As of early 2010 members of the FutureGen Alliance included domestic coal companies Peabody and BHP Billiton, plus E.On and China Huaneng Group. No domestic utilities remained, though Exelon had indicated an intention to join.

The 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.

In the UK a competition was launched by the UK government in November 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 will need to demonstrate post-combustion capture (including oxyfuel) on a coal-fired power station, with the carbon dioxide being transported and stored offshore. The project will 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. The winning project bid will be chosen by May-June 2009.

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 EUR 20-30 per tonne.

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 McKinseys estimated EUR 60-90/t reducing to EUR 30-45/t after 2030.

Gasification processes

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, 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%.

Present trends

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 with the cancellation of FutureGen this is in doubt.

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.

Sources:
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.
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 2004, Geological storage of CO₂, Energy 29, 1329-38.
Coal21 publications.
US DOE FutureGen Clean Coal Projects