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Flue gas desulfurization
Flue gas desulfurization (FGD) is the current state-of-the art technology used for removing sulfur dioxide (SO2) from the exhaust flue gases in power plants that burn coal or oil to produce steam for the steam turbines that drive their electricity generators.
In 1988 Prince Charles of Britain said, "I would have thought that the Central Electricity Generating Board was doing too little and too late. Our responsibilities do lie in not exporting our problems abroad." His words highlighted the fact that sulfur dioxide exhaust should be removed, rather than emitted high into the atmosphere where it affects many more people. A number of countries now have regulations limiting the height of flue gas stacks.
As a result of stringent environmental protection regulations regarding SO2 emissions that have been enacted in a great many countries, SO2 is now being removed from flue gases by a variety of methods:
For a typical coal-fired power station, FGD will remove 95 percent or more of the SO2 in the flue gases.
Additional recommended knowledge
Methods for removing sulfur dioxide from boiler and furnace exhaust gases have been studied for over 150 years. Early concepts useful for flue gas desulfurization appear to have germinated in England circa 1850.
With the construction of large scale power plants in England in the 1920s, the problems associated with large volumes of SO2 from a single site began to concern the public. The SO2 emissions problem did not receive much attention until 1929, when the House of Lords upheld the claim of a landowner against the Barton Electricity Works of the Manchester Corporation for damages to his land resulting from SO2 emissions. Shortly thereafter a press campaign was launched against the erection of power plants within the confines of London. This outcry led to the imposition of SO2 controls on all such power plants.
During this period, major FGD installations went into operation in England at the Battersea Power Station, the Swansea Power Station, and the Fulham Power Station. The first major FGD installation on a utility was put into operation at the Battersea Station, owned by the London Power Company, in 1931. In 1935, an FGD system similar to that installed at Battersea went into service at the Swansea Power Station. The third major FGD system was installed in 1938 at the Fulham Power Station. These three early large-scale FGD installations were abandoned during World War II. Large-scale FGD units did not reappear in commercial operation at utilities until the 1970s, where most of the activity occurred in the United States and Japan.
As of June 1973, there were 42 FGD units, ranging in size from 5 MW to 250 MW, in operation: 36 in Japan and 6 in the United States. As of about 1999-2000, FGD units were being used in 27 countries and there were 678 FGD units operating on a total power plant capacity of about 229 gigawatts. About 45% of that FGD capacity was in the U.S., 24% in Germany, 11% in Japan and 20% in various other countries. Approximately 79% of the units, representing about 199 gigawatts of capacity were using lime or limestone wet scrubbing. About 18% (or 25 gigawatts) utilized spray-dry scrubbers or sorbent injection systems.
Sulfuric acid mist formation
Fossil fuels such as coal and oil contain significant amounts of sulfur. When burned, about 95 percent or more of the sulfur is generally converted to sulfur dioxide (SO2). This happens under normal conditions of temperature and of oxygen present in the flue gas. However, there are circumstances under which this may not be the case.
For example, when the flue gas has too much oxygen and the SO2 is further oxidized to sulfur trioxide (SO3). Actually, too much oxygen is only one of the ways that SO3 is formed. Gas temperature is also an important factor. At about 800 °C, formation of SO3 is favoured. Another way that SO3 can be formed is through catalysis by metals in the fuel. This is particularly true for heavy fuel oil, where significant amounts of vanadium are present. In whatever way that SO3 is formed, it does not behave like SO2 in that it forms a liquid aerosol known as sulfuric acid (H2SO4) mist that is very difficult to remove. Generally, about 1% of the sulfur dioxide will be converted to SO3. Sulfuric acid mist is often the cause of the blue haze that often appears as the flue gas plume dissipates. Increasingly, this problem is being addressed by the use of wet electrostatic precipitators.
Scrubbing with a basic solid or solution
SO2 is an acid gas and thus the typical sorbent slurries or other materials used to remove the SO2 from the flue gases are alkaline. The reaction taking place in wet scrubbing using a CaCO3 (limestone) slurry produces CaSO3 (calcium sulfite) and can be expressed as:
When wet scrubbing with a Ca(OH)2 (lime) slurry, the reaction also produces CaSO3 (calcium sulphite) and can be expressed as:
When wet scrubbing with a Mg(OH)2 (magnesium hydroxide) slurry, the reaction produces MgSO3 (magnesium sulphite) and can be expressed as:
Some FGD systems go a step further and oxidize the CaSO3 (calcium sulphite) to produce marketable CaSO4 · 2H2O (gypsum):
Types of wet scrubbers used in FGD
To promote maximum gas-liquid surface area and contact time, a number of wet scrubber designs have been used. Common ones are:
A venturi scrubber is a converging/diverging section of duct. The converging section accelerates the gas stream to high velocity. When the liquid stream is injected at the throat, which is the point of maximum velocity, the turbulence caused by the high gas velocity atomizes the liquid into small droplets, which creates the surface area necessary for mass transfer to take place. The higher the pressure drop in the venturi, the smaller the droplets and the higher the surface area. The penalty is in power consumption.
Packed bed scrubbers
A packed scrubber consists of a tower with packing material inside. This packing material can be in the shape of saddles, rings or some highly specialized shapes designed to maximize contact area between the dirty gas and liquid. Packed towers typically operate at much lower pressure drops than venturi scrubbers and are therefore cheaper to operate. They also typically offer higher SO2 removal efficiency. The drawback is that they have a greater tendency to plug up if particles are present in excess in the exhaust air stream.
A spray tower is the simplest type of scrubber. It consists of a tower with spray nozzles, which generate the droplets for surface contact. Spray towers are typically used when circulating a slurry (see below). The high speed of a venturi would cause erosion problems, while a packed tower would plug up if it tried to circulate a slurry.
As explained above, alkaline sorbents are used for scrubbing flue gases to remove SO2. Depending on the application, the two most important are lime and sodium hydroxide (also known as caustic soda). Lime is typically used on large coal or oil fired boilers as found in power plants, as it is very much less expensive than caustic soda. The problem is that it results in a slurry being circulated through the scrubber instead of a solution. This makes it harder on the equipment. A spray tower is typically used for this application. The use of lime results in a slurry of calcium sulfite (CaSO3) that must be disposed of. Fortunately, calcium sulfite can be oxidized to produce by-product gypsum (CaSO4 · 2H2O) which is marketable for use in the building products industry.
Caustic soda is limited to smaller combustion units because it is more expensive than lime, but it has the advantage that it forms a solution rather than a slurry. This makes it easier to operate. It produces a solution of sodium sulfite/bisulfite (depending on the pH), or sodium sulfate that must be disposed of. This is not a problem in a kraft pulp mill for example, where this can be a source of makeup chemicals to the recovery cycle.
Scrubbing with sodium sulfite solution
It is possible to scrub sulfur dioxide by using a cold solution of sodium sulfite, this forms a sodium hydrogen sulfite solution. By heating this solution it is possible to reverse the reaction to form sulfur dioxide and the sodium sulfite solution.
In some ways this can be thought of as being similar to the reversible liquid-liquid extraction of an inert gas such as xenon or radon (or some other solute which does not undergo a chemical change during the extraction) from water to another phase. While a chemical change does occur during the extraction of the sulfur dioxide from the gas mixture, it is the case that the extraction equilibrium is shifted by changing the temperature rather than by the use of a chemical reagent.
Gas phase oxidation followed by reaction with ammonia
A new, emerging flue gas desulfurization technology has been described by the IAEA. It is a radiation technology where an intense beam of electrons is fired into the flue gas at the same time as ammonia is added to the gas. The Chendu power plant in China started up such a flue gas desulfurization unit on a 100 MW scale in 1998. The Pomorzany power plant in Poland also started up a similar sized unit in 2003 and that plant removes both sulfur and nitrogen oxides. Both plants are reported to be operating successfully. However, the accelerator design principles and manufacturing quality need further improvement for continuous operation in industrial conditions.
No radioactivity is required or created in the process. The electron beam is generated by a device similar to the electron gun in a TV set. This device is called an accelerator. This is an example of a radiation chemistry process where the physical effects of radiation are used to process a substance.
The action of the electron beam is to promote the oxidation of sulfur dioxide to sulfur(VI) compounds. The ammonia reacts with the sulfur compounds thus formed to produce ammonium sulfate which can be used as a fertilizer according to the IAEA. In addition, it can be used to lower the nitrogen oxide content of the flue gas. This method has attained industrial plant scale.
Facts and statistics
Flue gas desulfurization scrubbers have been applied to combustion units firing coal and oil that range in size from 5 MW to 1500 MW. Scottish Power are spending £400 million installing FGD at Longannet power station which has a capacity of over 2 GW. Dry scrubbers and spray scrubbers have generally been applied to units smaller than 300 MW.
Approximately 85% of the flue gas desulfurization units installed in the US are wet scrubbers, 12% are spray dry systems and 3% are dry injection systems.
The highest SO2 removal efficiencies (greater than 90%) are achieved by wet scrubbers and the lowest (less than 80%) by dry scrubbers. However, the newer designs for dry scrubbers are capable of achieving efficiencies in the order of 90%.
In spray drying and dry injection systems, the flue gas must first be cooled to about 10-20 °C above adiabatic saturation to avoid wet solids deposition on downstream equipment and plugging of baghouses.
The capital, operating and maintenance costs per short ton of SO2 removed (in 2001 US dollars) are:
Alternative methods of reducing sulfur dioxide emissions
An alternative to removing sulfur from the flue gases after burning is to remove the sulfur from the fuel before or during combustion. Hydrodesulfurization of fuel has been used for treating fuel oils before use. Fluidized bed combustion adds lime to the fuel during combustion. The lime reacts with the SO2 to form sulfates which become part of the ash.
|This article is licensed under the GNU Free Documentation License. It uses material from the Wikipedia article "Flue_gas_desulfurization". A list of authors is available in Wikipedia.|