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Reality – fossilised plant matter, or coal, remains an important source of energy around the world and will continue to do so for some decades, and the reason why there is a desperate drive to find cleaner ways to convert it into energy. By Alan Titchall.
Methods of converting coal to energy has certainly moved on since Charles Dickens wrote Hard Times and has progressively become a lot cleaner through new technologies to produce high thermal efficiencies and far less emissions. Washing coal to reduce its emissions of ash and sulphur dioxide is already standard practice, while electrostatic precipitators and fabric filters remove 99 percent of the fly ash from flue gases – a waste product from coal combustion used in building materials such as concrete. Flue gas desulphurisation also reduces sulphur dioxide by up to 97 percent. However, while C02 capture technologies have been deployed for over six decades by the oil, gas, and chemical industries (producing syngas, chemicals and liquid fuels) they are relatively new to the coal thermal power generation industry. Post and pre-combustion captureNewer clean coal technology aimed at commercial-scale coal power stations comes under the general title of ‘Carbon Capture and Storage’, or CCS, and is divided between pre-combustion capture (or gasification), and post-combustion involving separating the CO2 from other exhaust gases after combustion of the fossil fuel, similar to the methods above used to remove pollutants. This capture of C02 from flue gas streams after combustion in air can be an expensive option that can consume up to 25 percent of the plant’s total output, but one of the cheaper post-combustion options is the method of oxyfuel combustion (also called oxyfiring) where the coal is burned in pure oxygen to fuel a conventional steam generator. By avoiding nitrogen going into the combustion chamber, the amount of C02 in the power station exhaust stream is greatly concentrated, making it easier to compress and capture by amine scrubbing. Amine chemicals are the most commonly used process for all post-combustion C02 capture. The power plant’s flue gas is ‘bubbled’ through an amine solution that bonds with the C02 while other gases continue up through the flue. The C02-saturated amine solution is then removed from the amines, ‘captured’ and stored, while the amines chemicals are then recycled. The advantage of post-combustion technologies such as oxyfiring is that it can be retrofitted to older coal plants. The disadvantage is that the initial process of separating oxygen from air requires a lot of energy, pushing up the electricity costs of the plant. Coal gasificationPre-combustion capture technology involves separating the C02 before the fuel is burned and the two techniques leading this technology are ‘Integrated Gasification Combined Cycle’ (IGCC), and ‘Pressurised Fluidised Bed Combustion’ (PFBC). Pre-combustion capture using IGCC also opens up a wider range of possibilities for coal energy because it also produces hydrogen. The gasification is produced by feeding coal (or any other fuel), water, and oxygen into a gasifier under heat and pressure to reduce the coal to synthesis gas or ‘syngas’ – a mixture of carbon monoxide and hydrogen, along with solid waste by-products such as ash and slag, which can be used in making concrete or roads. The syngas is then used to generate electricity through a combined cycle gas turbine with a secondary steam turbine to generate power. The carbon monoxide (C0) is oxidised with water to produce a gas steam that is hydrogen and C02. The C02 is separated before combustion and compressed into a supercritical fluid for transport and geological storage. The hydrogen can be used to generate power in an advanced gas turbine and steam cycle or in fuels cells – or a combination of both. The ‘Combined Cycle’ in the IGCC title refers to the use of gas in a turbine generator whose waste heat is passed to a steam turbine system – using the syngas as efficiently as possible. However, gasifying coal is another expensive option. Back in 2005, the US Department of Energy has estimated a cost of US$1491 per kilowatt of installed capacity for an IGCC plant, versus US$1290 for a conventional pulverized coal station. Operating costs are also high, likely to be up to double, but the advantages of IGCC over conventional coal power plants, other than lower emissions, also includes thermal efficiency as it uses less coal. Coal gasification also produces a range of chemicals and by-products for industrial use and transport fuels and is often touted as a pathway to a hydrogen-economy as a source of hydrogen. The basic IGCC concept was first successfully demonstrated on a commercial scale at the pioneer Cool Water Project in Southern California in the mid 1980s. Currently, there are two commercial-size, coal-based IGCC plants in the United States (a 262MW plant in Indiana and a 250MW plant in Florida), another two in Europe (Holland and Spain), one in Japan that has been operating since the early 1990s. New-generation IGCC power plants are planned in the US and are expected to come online between 2012 and 2020, while others are planned in the UK and Germany. It is said the future of IGCC hinges on the question – whether energy affordability or carbon neutrality will be the bigger issue, and whether carbon capture and storage will actually work? C02 storageThe principles of carbon capture and storage are already deployed in various fields of commercial activity. Over 32 million tonnes of C02 is already ‘captured’ around the world and used for the likes of recovering oil. The first large scale storage of C02 was demonstrated with the Sleipner gas field in Norway in 1996 when tonnes of compressed liquid CO2 (separated from methane), were injected into a deep natural reservoir below the sea bed. It is said that the US$80 million cost of this sequestration project was returned in just 18 months through European carbon tax savings. Since then, around one million tonnes of C02 has been stored each year at the Sleipner project. The technology for C02 transportation is now well-established. C02 is largely inert and easily handled and is already transported in high-pressure pipelines. As C02 is pumped deep underground, it is compressed by the higher pressures and becomes essentially a liquid. The gas dissolves in salty water and the C02 saturated water, heavier than the water around it, sinks to the bottom of the rock formation. Geographical features suited for C02 storage fall into three categories; deep saline formations; depleted oil and gasfields; and un-mine-able coal seams. Deep saline formations are underground formations of permeable reservoir rock, such as sandstones, that are saturated with very salty water and covered by a layer of impermeable cap rock. Saline aquifers have the largest storage potential globally, but are the least explored . In contrast, depleted oil and gas fields are very well-explored and geologically defined, with a proven ability to store hydrocarbons over geological time spans of millions of years. In the ‘enhanced oil recovery’ industry, C02 is injected into an oilfield to aid production through increasing the pressure in the reservoir. Coal seam storage involves another form of trapping in which the injected C02 is accumulates on the surface of the insitu coal in preference to other gases (such as methane) that its displaces. Coal seam storage is most likely to be feasible when undertaken in conjunction with enhanced coal bed methane recovery (ECBM) in which the commercial production of coal seam methane is assisted by the displacement effect of the C02.
Energy NZ Vol.4 No.6 November-December 2010 |
Over 20 percent of the world’s energy demands are currently met by coal and almost 40 percent of the world’s electricity is generated from it.