Trubchinina O.O.

ДНУ, Hydrometeorology & Geoecology Department, student of the 4-th year of study

Scientific director: Candidate of Biology L.V.Dotsenko

FLUEGAS DESULFURIZATION SYSTEMS AT MODERN THERMAL POWER PLANTS

Nowadaysit is important to work out new ways to control pollution of the environment.

Fluegas desulfurization is commonly known as FGD and isthe technology used for removing sulfur dioxide(SO₂) from the exhaust flue gasesin powerplants that burn coal or oil to producesteam for the steam turbinesthat drive their electricity generators.

As a result of stringentenvironmental protection regulations regarding SO₂ emissions thathave been enacted in a great many countries, SO₂ is now beingremoved from flue gases by a variety of methods, with the following being themost common:

Wet scrubbing using a sorbent, usually limestoneor lime,or seawaterto scrub the gases.

Spray-dry scrubbing using similar sorbent slurries.

Dry sorbentinjection systems.

For a typical coal-fired powerstation, FGD will remove 95 percent or more of the SO₂ in the fluegases.

Most FGD systems employ twostages: one for fly ashremoval and the other for SO₂ removal. Attempts have been made toremove both the fly ash and SO₂ in one scrubbing vessel. However,these systems experienced severe maintenance problems and low simultaneousremoval efficiencies. In wet scrubbing systems the flue gas normally passesfirst through a fly ash removal device, either an electrostatic precipitator ora wet scrubber, and then into the SO₂ absorber. However, in dryinjection or spray drying operations, the SO₂ is first reacted withthe sorbent and then the flue gas passes through aparticulate control device.

Another important designconsideration associated with wet FGD systems is that the flue gas exiting theabsorber is saturated with water and still contains some SO₂. (Nosystem is 100% efficient.) Therefore, these gases are highly corrosive to anydownstream equipment - i.e., fans, ducts, and stacks. Two methods that minimizecorrosion are: 1) reheating the gases to above their dew pointand; 2) choosing construction materials and design conditions that allowequipment to withstand the corrosive conditions. The selectionof a reheating method or the decision not to reheat (thereby requiring the useof special construction materials) are very controversial topics connectedwith FGD design.

SO₂ is an acid gas andthus the typical sorbent slurries or other materials used to remove the SO₂from the flue gases are alkaline. The reaction taking place in wet scrubbingusing a CaCO₃ (limestone)slurry produces CaSO₃ (calcium sulfite). In wet scrubbers also canbe used Ca(OH)₂ (the product of reaction is calciumsulfite) and Mg(OH)₂ (the product of reaction is magnesium sulfite).

To partially offset the cost ofthe FGD installation, in some designs, the CaSO₃ (calcium sulfite)is further oxidized to produce marketable CaSO₄ · 2H₂O (gypsum).This technique is also known as forcedoxidation.

A venturi scrubberhas two main sections of duct. The first section accelerates the gas stream tohigh velocity. When the liquid stream is injected at the throat, which is thepoint of maximum velocity, the turbulence caused by the high gas velocityatomizes the liquid into small droplets, which creates the surface areanecessary for mass transfer to take place. The higher the pressure drop in the venturi, the smaller the droplets and the higher the surfacearea. The penalty is in power consumption.

For simultaneous SO₂and fly ash removal, venturi scrubbers can beused.  In fact, removal of both particlesand SO₂ in one vessel can be economically attractive. In cases wherethe particle concentration is low, such as from oil-fired units, simultaneousparticulate and SO₂ emission reduction can be effective.

A spray toweris the simplest type of scrubber. It consists of a tower with spray nozzles,which generate the droplets.

As explained above, alkalinesorbents are used for scrubbing flue gases to remove SO₂. Dependingon the application, the two most important are limeand sodium hydroxide(also known as caustic soda).Lime is typically used on large coal or oil fired boilers as found in powerplants, as it is very much less expensive than caustic soda. The problem isthat it results in a slurry being circulated throughthe scrubber instead of a solution. This makes it harder on the equipment. Aspray tower is typically used for this application. The use of lime results ina 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 productsindustry.

Caustic soda is limited tosmaller combustion units because it is more expensive than lime, but it has theadvantage that it forms a solution rather than a slurry.This makes it easier to operate. It producesa solution of sodium sulfite/bisulfite (depending onthe pH), or sodium sulfate that must be disposed of. This is not a problem in akraft pulp mill for example, where this can be a source ofmakeup chemicals to the recovery cycle.

It is possible to scrub sulfur dioxideby using a cold solution of sodium sulfite.

A new, emerging flue gasdesulfurization technology has been described by scientists. It is a radiationtechnology where an intense beam of electronsis fired into the flue gas at the same time as ammoniais added to the gas. No radioactivityis required or created in the process. The electron beam is generated by adevice similar to the electron gunin a TV set. This device is called an accelerator.

The action of the electron beamis to promote the oxidation of sulfur dioxide to sulfur(VI)compounds. The ammonia reacts with the sulfur compounds thus formed to produce ammonium sulfatewhich can be used as a fertilizer. In addition, it can be used to lower thenitrogen oxide content of the flue gas.

Flue gas desulfurizationscrubbers 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 millioninstalling FGD at Longannet power station which has acapacity of over 2 GW.

Approximately 85% of the flue gasdesulfurization units installed in the US are wet scrubbers, 12% are spray dry systems and 3% are dry injection systems.

The highest SO₂removal efficiencies (greater than 90%) are achieved by wet scrubbers and thelowest (less than 80%) by dry scrubbers. However, the newer designs for dryscrubbers are capable of achieving efficiencies in the order of 90%.

In spray drying and dry injectionsystems, the flue gas must first be cooled to about 10-20 °C above adiabatic saturationto avoid wet solids deposition on downstream equipment and plugging of baghouses.

The capital, operating andmaintenance costs per short tonof SO₂ removed (in 2001 US dollars) are:

Forwet scrubbers larger than 400 MW, the cost is $200 to $500 per ton

Forwet scrubbers smaller than 400 MW, the cost is $500 to $5,000 per ton

Forspray dry scrubbers larger than 200 MW, the cost is $150 to $300 per ton

Forspray dry scrubbers smaller than 200 MW, the cost is $500 to $4,000 per ton

An alternative to removing sulfurfrom the flue gases after burning is to remove the sulfur from the fuel beforeor during combustion. Hydrodesulfurization of fuel has been used for treating fuel oilsbefore use. Adding lime to the fuel during combustion is effective. The limereacts with the SO₂ to form sulfates which become part of the ash.

Unfortunately, in Ukraine alltypes of scrubbers for desulfurization are used only at the level of scientificexperiment.

Information sources

1. Thomas Elliott, Kao Chen, 1997. Standard handbookof power plant engineering (2-nd edition).