User:Milton Beychok/Sandbox

(PD) Photo: National Park Service
Before flue gas desulfurization was installed, the emissions from this power plant in New Mexico contained excessive amounts of sulfur dioxide

Flue gas desulfurization (FGD) is the most commonly used 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.

As sulfur dioxide is responsible for acid rain formation, stringent environmental protection regulations have been enacted in a great many countries to limit the amount of sulfur dioxide emissions from power plants and other industrial facilities.

SO₂ is now being removed from flue gases by a variety of methods:

• Wet scrubbing using a slurry of sorbent, usually limestone or lime, to scrub the gases.
• Spray-dry scrubbing using similar sorbent slurries.
• Dry sorbent injection systems.

For a typical coal-fired power station, FGD technology will remove 95 percent or more of the SO₂ in the flue gases.

Tall flue gas stacks (i.e., chimneys) were once built to disperse the sulfur dioxide emissions. However, that only leads to the transport of the emissions to other regions. For that reason, a number of countries also have regulations limiting the height of flue gas stacks.

History

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.

FGD chemistry

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:

CaCO₃ (solid) + SO₂ (gas) → CaSO₃ (solid) + CO₂ (gas)

When wet scrubbing with a Ca(OH)₂ (lime) slurry, the reaction also produces CaSO₃ (calcium sulphite) and can be expressed as:

Ca(OH)₂ (solid) + SO₂ (gas) → CaSO₃ (solid) + H₂O (liquid)

When wet scrubbing with a Mg(OH)₂ (magnesium hydroxide) slurry, the reaction produces MgSO₃ (magnesium sulphite) and can be expressed as:

Mg(OH)₂ (solid) + SO₂ (gas) → MgSO₃ (solid) + H₂O (liquid)

Some FGD systems go a step further and oxidize the CaSO₃ (calcium sulphite) to produce marketable CaSO₄ · 2H₂O (gypsum):

CaSO₃ (solid) + ½O₂ (gas) + 2H₂O (liquid) → CaSO₄ · 2H₂O (solid)

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:

Venturi-rod scrubbers

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.

Spray towers

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.

Facts and statistics

The information in this section was obtained from a US EPA published fact sheet.

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:

• For wet scrubbers larger than 400 MW, the cost is $200 to $500 per ton
• For wet scrubbers smaller than 400 MW, the cost is $500 to $5,000 per ton
• For spray dry scrubbers larger than 200 MW, the cost is $150 to $300 per ton
• For spray dry scrubbers smaller than 200 MW, the cost is $500 to $4,000 per ton

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.

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.

External links

• Schematic of desulfurization plant
• 5000 MW FGD Plant (includes a detailed process flow diagram)
• New innovative design using Gas Suspension Absorption
• Flue Gas Desulfurization Fact Sheet