Coal - is it a competitor to new nuclear?

8 January 2010

The International Energy Agency (IEA) has clearly demonstrated in recent editions of its World Energy Outlook that their reference case for world energy growth is environmentally unsustainable. Coal is today an extremely important fuel and on current trends and government policies will undoubtedly remain so. Some 23% of world primary energy needs are currently met by coal and 39% of electricity is generated from it, while about 70% of world steel production depends on coal feedstock. Coal is the world’s most abundant and widely distributed fossil fuel source and by 2030, spurred on by increasing use in China and India (both of whom have abundant coal reserves), the dependence on coal could even increase.

However, burning coal releases about 9 billion tonnes of carbon dioxide (CO2) to the atmosphere each year, with about 70% of this coming from power generation. CO2 emissions from power generation are about one third of the world total (over 25 billion tonnes) and ‘decarbonising’ this sector is now a major objective in long-term IEA energy scenarios. The objective is constraining the level of carbon in the atmosphere at either 550 or 450 parts per million (ppm) by 2050. Clearly a lot can be achieved by energy-saving but weaning the electricity generation sector off its addition to carbon must also play a major part.

The obvious way of decarbonising power generation is moving to renewable energy technologies, but there are obvious concerns about their effectiveness. A further large-scale but clean power generation technology is therefore necessary. Nuclear is the obvious answer, and is already technically well-proven. Yet nuclear suffers from a variety of concerns – none of them new – that still threaten to abort or delay any nuclear renaissance. Given this, is there anything on offer which may potentially prolong coal’s central role in world energy, without adverse environmental effects?

As many coal-fired power stations are approaching retirement, their replacement certainly gives much scope for cleaner electricity, nuclear or otherwise. Development of a variety of new ‘clean coal’ technologies is certainly underway, with an important challenge to commercialise them economically in order to use the enormous world reserves but with zero emissions. This field is now moving towards coal gasification, producing a concentrated and pressurised carbon dioxide stream followed by its separation and geological storage, known as carbon capture and storage/sequestration (CCS).

The elements of clean coal technologies have in fact been applied in developed countries for many years. For example, coal cleaning by ‘washing’ has been standard practice for some time and greatly reduces emissions of ash and sulphur dioxide when the coal is burned. Electrostatic precipitators and fabric filters can also remove 99% of the fly ash from the flue gases. Flue gas desulphurisation reduces the output of sulphur dioxide to the atmosphere by up to 97%, the task depending on the level of sulphur in the coal and the extent of the reduction. It is widely used where needed in developed countries. Increased thermal efficiency of plant, up to 45% now, means that newer plants create fewer emissions per kWh than older ones. Indeed, 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.

Ultimately, however, the aim is now to achieve CCS and this has become the ‘Holy Grail’ in ensuring coal remains a significant part of any world energy mix. There is indeed a long tradition of using waste products from coal combustion, as the European Union uses half of its coal fly ash and bottom ash in building materials (where fly ash can replace cement), and almost 90% of the gypsum from flue gas desulphurisation. But CCS takes this a whole lot further.

CCS involves two distinct aspects: capture and storage. On capture, a number of means exist to capture CO2 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 levels in power plant emissions. The separation of CO2 is well-proven when CO2 has been taken from natural gas wells where it is mixed with methane. Capture of CO2 from flue gas streams following combustion in air is much more difficult and expensive, as the concentration is only about 14% at best. 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 process. In oxyfuel combustion, coal is burned in oxygen rather than air, so the flue gas is mostly CO2 and hence can be more readily 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. They could be retrofitted to existing pulverised coal plants, which are the backbone of electricity generation in many countries.

Integrated Gasification Combined Cycle (IGCC) plants use coal and steam to produce hydrogen and carbon monoxide (CO) from the coal. These are then burned in a gas turbine with secondary steam turbine (i.e. 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 plans to add a shift reactor to oxidise the CO with water so that the gas stream is basically just hydrogen and CO2. These gases 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. However, no commercial scale power plants are operating with this process yet.

“Work is being done to improve the economic viability of CCS with a view to reducing the cost of carbon sequestered to an equivalent of…0.25 cents per kWh or a 10% increment on electricity generation costs

Captured carbon dioxide gas is already put to good use on a commercial basis for enhanced oil recovery in the USA. Overall over 32 million tonnes of CO2 is used annually for this. 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.

Injecting carbon dioxide into deep, unmineable coal seams where it is adsorbed to displace methane 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, current extraction methods do demonstrate the practicality of the technique. Safety and permanence of disposition are key considerations in sequestration. Indeed large-scale storage of CO2 from power generation will require an extensive pipeline network in densely populated areas, which clearly has important safety implications. But given that rock strata have held CO2 and methane for millions of years there seems no technical reason that carefully-chosen chosen ones cannot hold sequestered CO2

The obvious disadvantage of CCS, as opposed to nuclear power, is that it remains technically unproven on a large scale. The economics are also somewhat questionable, even with high carbon taxes or a significant emissions trading regime, but that complaint is also made by nuclear’s critics too. Yet they cannot reasonably claim that nuclear technology doesn’t work on a large scale.

Even the World Coal Institute noted that in 2003 the high cost of CCS made it uneconomic, given estimates of an additional 3.5 to 5.5 US cents per kWh relative to coal burned at 35% thermal efficiency. But a lot of work is being done to improve the economic viability of CCS with a view to reducing the cost of carbon sequestered to an equivalent of as little as 0.25 cents per kWh or a 10% increment on electricity generation costs.  These targets seem rather unrealistic but a lot of research and funding continues in this direction.

For example, the US Department of Energy (DOE) developed a $1.3 billion FutureGen project  to design, build and operate a nearly emission-free coal-based electricity and hydrogen production plant. This would comprise a coal gasification plant with additional water-shift reactor, to produce hydrogen and carbon dioxide. About 700,000 tonnes of CO2 (some 60% of throughput) per year would then be separated by membrane technology and sequestered geologically and the hydrogen burned in a 275MWe generating plant and in fuel cells. 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. Construction was due to start in 2009 for operation in 2012, but in January 2008 the DOE announced that it would pull its funding for the project, expressing concerns over escalating costs. Under the Obama Administration, however, the project has been reconsidered and design work, geological investigations and a revised cost estimate are to proceed.  A decision on whether or not to embark upon construction is scheduled for early 2010, but the DOE has said that it is prepared to contribute over $1 billion.

Anticipated costs of CCS vary from study to study rather like all the estimates of nuclear generation costs, and depend crucially on a few underlying assumptions. Figures from an Intergovernmental Panel on Climate Change (IPCC) mitigation working group in 2005 for IGCC put the capture and sequestration cost at 1.0-3.2 cents per kWh, thus increasing electricity cost for IGCC by 21-78% to 5.5 to 9.1 cents per kWh. The energy penalty in that was 14-25% and the mitigation cost $14-53 per tonne of CO2 (or $51-200 tonne of carbon) avoided. Other studies by the IEA and McKinseys estimate the mitigation cost as rather higher, but believe that the cost could be halved over time.

What is clear is that there are significant costs involved in CCS as well as the need to overcome the remaining technical challenges in large scale employment. Nuclear power is a much more mature technology and although there are undoubtedly economic challenges to be overcome, notably on the capital cost of plants, it remains the only large-scale technology available today to supply low emissions base load electricity. So CCS should be seen as a possible complement to nuclear in a clean energy world, rather than a competitor, with large scale exploitation unlikely until the 2020s at the earliest. In other words, it should be seen in a similar time frame to the next generation of nuclear reactors, namely Generation IV. Yet these should offer significant economic and other advantages over today’s nuclear reactors, so CCS may still struggle to find a place. The arrival of G4 reactors may sound the death knell for coal as a large scale energy resource.

Author Info:

Steve Kidd is Director of Strategy & Research at the World Nuclear Association, where he has worked since 1995 (when it was the Uranium Institute). Any views expressed are not necessarily those of the World Nuclear Association and/or its members.

In western Kazakhstan, units with a capacity of 220MW can be deployed. In other areas, 600MW units can be used.

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