Keywords

power plant emissions; environmental controls; coal cleaning; low NO_x burners; selective catalytic reduction; SCR; selective non-catalytic reduction; flue gas scrubber; flue gas desulphurization; FGD; spray dryer; electrostatic precipitator; baghouse filter; cyclone filte

Pre-Combustion Coal Cleaning

Most environmental processing associated with coal combustion focuses on removing pollutants after combustion has taken place. However, it is also possible to treat the fuel prior to combustion in order to reduce the quantity of pollutants it contains. As discussed earlier, there are two primary approaches to coal cleaning, physical cleaning and chemical cleaning. Chemical cleaning involves treating coal with a chemical reagent. Processes of this type are being developed but are not yet employed commercially. Physical separation relies on a difference in density between coal and it common impurities. This is applied quite widely during coal preparation. Physical cleaning can reduce the amount of sulfur in some coals and it can remove some heavy metals. However it will not eliminate the need for further processing of flue gases to these pollutants.

Combustion Strategies to Reduce Nitrogen Oxide Production

Coal cleaning can help to reduce the generation of sulfur dioxide by removing the precursor, sulfur, from the coal. While nitrogen bound in coal is an important source of nitrogen oxides, managing the generation of nitrogen oxides by removing nitrogen from coal is generally not possible. Attempts have been made to chemically treat coal to remove this nitrogen but none has achieved commercial viability.

The bound nitrogen in coal comes from organic materials that originated in the plants that were coal’s precursors. How much remains depends on the type of coal. Anthracite usually contains less than 1% nitrogen, bituminous coals can contain up to 3% while the amount in lignite is usually less than 2%.

The nitrogen bound in coal accounts for around 75% of the nitrogen oxides generated during combustion in a typical large pulverized coal furnace. The remaining 25% comes from the air used to supply oxygen for the combustion reaction. Since air contains around 78% nitrogen, this provides a plentiful supply.⁴ One way of reducing the production of nitrogen oxides in this way is to remove nitrogen from air, so that the combustion plant is supplied with pure oxygen. This is not a strategy that has been employed simply to reduce nitrogen oxide production in pulverized coal-fired power stations, though it can be of value when considering carbon dioxide capture. However, control of the combustion process itself is used to minimize production.

Nitrogen oxides are formed when nitrogen in the coal and in air reacts with oxygen in the combustion air. The three main products are nitrogen oxide (NO), nitrogen dioxide (NO₂), and nitrous oxide (N₂O). Together, these are referred to as NO_x. Of the three individual oxides, NO is the most important, accounting for around 90–95% of the nitrogen oxide production. This is the most stable form of oxidized nitrogen at the temperatures encountered in a pulverized coal furnace. Nitrogen dioxide contributes most of the remaining 5–10%, with nitrous oxide accounting for 0.1–1% of the total.

The formation of nitrogen oxides from both fuel nitrogen and nitrogen from air is relatively slow at low temperatures but accelerates at higher temperatures and can be rapid at the elevated temperatures in the flame of a pulverized coal burner. The reaction mechanisms involved can be complex, often involving a third component in addition to nitrogen and oxygen, a component which helps to break a chemical bond releasing reactive nitrogen atoms. However, the extent of the reaction can be limited by controlling the amount of oxygen available in the hottest part of the combustion flame. If there is too little oxygen available that which is present will preferentially react with carbon instead of nitrogen, reducing overall nitrogen oxide generation.

In a typical pulverized coal-fired boiler, coal and primary air are admitted into the furnace together through a burner. Secondary air is then added from ducts around the burner in order to manage the ratio of carbon to oxygen within the flame. If insufficient oxygen is admitted at this stage, then the combustion of the coal will not proceed to completion and it will take place under reducing conditions which limit NO_x production. Further air is then introduced around the heart of the fireball, where the temperature is lower and this allows the combustion process to finish, with the remaining carbon being converted into carbon dioxide. This type of “staged combustion” can reduce the production of nitrogen oxides by around 30–55%.

The addition of the oxygen needed to complete the combustion process can be delayed longer, allowing the combustion gases to start to cool before introducing more air higher up the furnace as the gases begin to rise and exit the combustion chamber. Using “overfire air,” as this technique is called, in conjunction with more limited oxygen addition during staged combustion in the main combustion zone can reduce overall production of nitrogen oxides by up to 60%.⁵ A pulverized coal boiler using these low NO_x strategies is shown in cross-section in Figure 6.1.

A third combustion strategy is called “reburning.” This involves introducing further pulverized coal or even natural gas above the combustion zone, again in a region where the combustion gases have started to cool. The additional fuel will react with oxygen but under the cooler, relatively reducing conditions, it will actually steal oxygen from nitrogen oxides that have already been formed. When this is combined with staged combustion and overfire air, a reduction in the production of nitrogen oxides of 70% compared to an unmodified boiler can be achieved.

Yet another means of controlling NO_x formation is with flue gas recirculation. This involves taking around 20–30% of the flue gas, at a temperature of 350–400°C, and mixing it with the combustion air that is fed with coal into the burner. The effect of this is to dilute the oxygen in the combustion air, reducing the overall combustion temperature and hence reducing nitrogen oxide production.

Using these techniques will help reduce the production of nitrogen oxides but the concentration within the flue gases, even with the best low NO_x combustion designs, is usually higher than emission limits prescribed for large combustion plants. The typical concentration from a large pulverized coal boiler with an optimized low NO_x burner is around 700 mg/m³. Plants with fluidized bed boilers can achieve lower levels because of the lower temperature at which combustion takes place. A large lignite-fired fluidized plant may be able to keep the NO_x concentration below 300 mg/m³. This is still well above the limit in Table 6.2, so additional measures are also required.

Sulfur Dioxide Capture

The sulfur found in coal occurs in two forms. In one, the sulfur is contained within separate particles of sulfur compounds, most often iron pyrites, mixed with the coal. The second form involves a variety of organic carbon compounds that also contain sulfur. The actual proportion of each varies from coal to coal. The total sulfur content can be well below 1% (these are termed low-sulfur coals) but is more commonly around 2–3% and it can be as high as 10%.

There are various strategies for reducing the sulfur dioxide emissions from a coal-fired power plant. Cleaning the coal is one. Coal cleaning processes, described earlier, can remove the pyritic sulfur contained in coal but they cannot remove the organic sulfur since this is bound chemically to the carbon, so the effectiveness of this approach will depend upon the coal. Another strategy where emissions are controlled by legislation is to burn a low-sulfur coal. In the USA, for example, the production of low-sulfur coal from Wyoming has increased massively since the introduction of legislation to control sulfur emissions from coal plants. However, this can affect overall costs if low-sulfur coal has to be transported long distances.

The alternative, and the most common approach adopted today, is to capture the sulfur dioxide from the flue gases that emerge from the plant furnace. This can be carried out in a number of ways. The most common is by using a process called wet scrubbing, which involves a sorbent carried in a liquid to capture the pollutant. Where water is scarce, spray dryer absorbers using sorbent slurries which contain much less water can also be used. Both usually employ a sorbent material that is used once but there are some systems where the sorbent is regenerated and recycled through the absorption system. Dry sorbent injection systems have also been employed. Some more complex processes that involve capture of sulfur dioxide and nitrogen oxide together have been tested. Besides these, it is possible to capture sulfur dioxide directly in a fluidized bed boiler, as discussed earlier.

While a variety of chemicals will react with and capture sulfur dioxide, by far the most popular is limestone, calcium carbonate. When finely ground and carried in water, the material will react rapidly with sulfur dioxide to produce a mixture of calcium sulfite and calcium sulfate. Additional oxidation using air can convert most of the sulfite to sulfate. Limestone is extremely abundant in the earth’s surface while the final product of these reactions, calcium sulfate, gypsum, can be recycled as a building material.

Limestone is most suited to wet absorption systems. For dry or semi-dry systems, calcium oxide (CaO, lime) or calcium hydroxide (Ca(OH)) are normally used. Sodium carbonate has also been employed.

In fact, the simplest and cheapest method of capturing sulfur dioxide is simply to inject a powder of finely ground lime into the hot flue gases after they have exited the power plant boiler. The particles become entrained with the flue gases, mixing with them, and the particles of calcium oxide react with the sulfur dioxide relatively rapidly at the elevated temperature. Water vapor may also be injected to aid the reaction. Provided the transit time is adequate, and the temperature high enough, the result is a flue gas laden with particles of calcium sulfite, some calcium sulfate, as well as ash from the coal, and unreacted lime. All these particles are then removed using a particle filtration system, producing a residue that is a mixture of calcium–sulfur compounds and ash. Using this method, around 30–60% of the sulfur content of the flue gases can be removed. This may be adequate if the coal already has a low sulfur content but in most cases this will not allow the flue gases to meet local emission standards. In this case a more effective method is required.

Spray drier absorption also results in a dry particular product but is more effective than simple injection. In this case the lime is first mixed with water to generate a slurry and this is then sprayed into the path of the flue gases as a cloud of fine droplets in the spray dry absorber chamber. Sulfur dioxide is absorbed in the droplets and reacts with the lime, producing calcium sulfite and calcium sulfate. Other acid gases such as sulfur trioxide and hydrogen chloride, which may also be present, will also be absorbed, while the residence time of flue gases within the absorption chamber is sufficient to evaporate the water, leaving dry particles. A schematic of a spray drier absorption system is shown in Figure 6.2.

As with the sorbent injection system, the particles must be removed from the flue gas using a filtration system. If this is fitted after the spray drier absorber, then the material collected will be a mixture of fly ash and calcium/sulfur compounds as with the dry injection system. An alternative, commonly employed in Europe when this system is used, is to have two particle collection systems. The first, before the spray drier absorber, collects all the fly ash while the second collects the calcium sulfur compounds formed by sulfur capture. This results in a much purer product that can be more readily recycled for building or other purposes.

The spray drier absorber system is simpler and cheaper than the main alternative high-performance sulfur removal system, wet scrubbing, but it is less effective and the reagents are more expensive. It is often used on smaller power plants but less so on large facilities and accounts for 12% or less of all the coal plant capacity fitted with sulfur capture.

The most effective, and the most popular, system for capturing sulfur dioxide is wet scrubbing. This is similar to the dry absorption techniques outlined above but employs a liquid rather than a slurry or dry powder as the capture reagent. The capture reagent in wet scrubbing is usually powdered limestone although calcium hydroxide can also be used.

In a typical wet flue gas desulfurization (FGD) system limestone is ground to a fine powder and them mixed with water. Typically this “lime wash” contains 10% limestone. The lime wash is pumped through nozzles and sprayed down from the top of a spray tower through which the flue gases travel from the bottom to the top. The hot flue gases evaporate some of the water which exits with the flue gases as water vapor. Meanwhile the sulfur dioxide (and some other acidic gases) dissolve in the water and then react with the limestone particles to produce calcium sulfite. The liquid is collected at the bottom of the tower and pumped away. In many wet FGD systems air is blown through the resulting calcium sulfite solution to promote its oxidation to calcium sulfate, a process called forced oxidation. This provides a more saleable product. The resulting gypsum is then separated from water and can be sold. Figure 6.3 shows a cross-section of a typical spray tower.

A wet scrubbing system can capture between 90 and 98% of the sulfur in the flue gases from a coal plant. With additives that can be pushed as high as 99%. The process is complex, akin to adding a chemical processing plant to a coal-fired power plant, but is currently the most effective method available. It is used on many large coal-fired power plants across the globe and usually forms part of every new coal station.

An alternative to the traditional wet FGD scrubbing system is a seawater FGD system. Seawater is naturally alkaline and will absorb sulfur dioxide, producing soluble sulfates and sulfites. The process is similar to the wet FGD system described above, with seawater replacing the lime wash. After the seawater has passed through the absorption tower it is collected and returned to the sea. This system can remove 98–99% of the sulfur dioxide in the exhaust gases of a coal plant but is only feasible at plants that are located at the shoreline of a sea.

A range of other, more complex, systems have been tested in the past for sulfur removal but most have not found commercial application. One of the more interesting of these is the use of activated carbon or charcoal. The can be made from coke and is capable of absorbing pollutant gases such as sulfur dioxide and nitrogen oxide onto its surface. It can remove other pollutants too, such as hydrogen chloride and mercury. The spent activated carbon is then regenerated with the release of the absorbed sulfur which can be extracted as pure sulfur.

Nitrogen Oxide Capture

While low NO_x combustion strategies discussed earlier can help reduce the quantity of nitrogen oxides found in the flue gases from a coal-fired power plant, they cannot reduce it to a level that will comply with emission limits in most jurisdictions. As a consequence, further action is necessary to reduce the NO_x concentration below the legal limit. Two processes are commonly used for this purpose. Both involve adding a reagent, usually either ammonia or urea, to the flue gases then encouraging it to react with the nitrogen oxides to reduce them back to molecular nitrogen. One relies on the temperature of the flue gases to achieve its aim, while the other uses a metallic catalyst to promote the reaction between the reagent and the NO_x.

The first, and simplest, of these methods involves the injection of ammonia or urea into the flue gases soon after they leave the boiler, when the temperature is between 870°C and 1200°C.⁶ Between these temperatures the ammonia will react spontaneously with nitrogen oxides to produce a mixture of nitrogen and water vapor which is then carried away with the flue gases. This process is generally called selective non-catalytic reduction (SNCR). It can remove between 35 and 60% of the nitrogen oxides produced during combustion.

SNCR will be effective if the nitrogen oxide concentrations are already low. However, it can lead to ammonia contamination of fly ash and to the release of ammonia into the atmosphere with the flue gases, a phenomenon called ammonia slip. This can be controlled using feedback to ensure the amount of ammonia being injected is just sufficient for the concentration of NO_x present but ammonia slip is always a problem. The technique has been in use since the mid-1970s in Japan and it is also used in Europe and the USA. It is best suited to smaller plants as it can be difficult to implement effectively in very large coal-fired boilers.

The alternative process, which is called selective catalytic reduction (SCR), requires ammonia or urea to be mixed with the flue gases and then passed over a solid catalyst that facilitates the reaction, converting NO_x into molecular nitrogen and water vapor. The process normally takes place at a point where the flue gases are between 300°C and 400°C. The catalytic process is very efficient and allows precise control of the amount of ammonia to match the NO_x present, minimizing the amount of ammonia slip. An emission reduction of 80–90% can be achieved.

There are three main configurations for SCR. The first, called high dust, involves placing the SCR reactor before the dust collection system in the plant. Figure 6.4 shows the typical layout. This is the most common arrangement, particularly with dry bottom boilers where little slag is generated. However, the fly ash can erode the solid catalyst in the SCR reactor so in some plants a low dust configuration is adopted with the SCR reactor placed after the dust collection system. The disadvantage of this is that the dust collection must occur at a relatively high flue gas temperature in order to ensure the gases reach the SCR reactor at a high enough temperature. Another low dust configuration, called tail-end SCR, provides a more compact design.

The basic form of the catalyst for SCR is most commonly a titanium oxide into which vanadium has been dispersed as the active catalytic ingredient. However, most catalysts are proprietary and they can have much more complex structures with other elements added to improve efficacy. Activate carbon can also be used as the catalyst, often carried on a moving bed.

One of the problems that can be caused by SCR systems is the production of sulfur trioxide from any sulfur dioxide present in the flue gases. This extremely acid gas forms sulfuric acid in contact with water, making it highly corrosive. As a consequence of this SCR was initially used only for plants burning low-sulfur coals. However, with effective wet scrubbing FGD systems it has been possible to apply SCR to plants that burn high-sulfur coals.

In addition to these two methods, it is possible to remove NO_x using a wet scrubbing system similar in concept to that described for wet FGD systems above. The reagent sprayed into the flue gas stream in this case is a solution sodium hydroxide, although hydrogen peroxide has also been used. The reaction that takes place leads to the formation of soluble nitrites and nitrates which must be isolated for disposal. Wet scrubbing is not normally used in power stations for NO_x removal.

Combined Sulfur and Nitrogen Oxide Removal

The capture of sulfur dioxide and that of nitrogen oxides, each involve addition of a complex chemical system to a coal-fired power plant. If these could be combined into a single process it would be a major simplification and could reduce costs significantly. Several attempts have been made to develop combined systems of this type but none has achieved major commercial success.

One, already mentioned, involves using an activated carbon as the capture agent. Carbon particles, usually formed from coke, are extremely porous and provide a very large surface area, while the carbon itself will readily form bonds with many compounds. If the activated material is slowly cycled through a tower, up which the flue gases pass, nitrogen oxides, sulfur dioxide, metals such a mercury, and other acidic gases such as hydrogen chloride, will be adsorbed onto the surface of the carbon.

The bond formed between the carbon and these molecules is not strong and if the activated adsorbent is removed from the tower and then heated in a separate reactor, the pollutant molecules will be released and can be collected and processed while the carbon can be recycled. In one version of this system, sulfur can be recovered as a by-product. However, the system has never been able to prove itself commercially.

Another approach that has been tried is to use a beam of electrons to convert and capture pollutant molecules. In this system, the flue gases are exposed to an intense beam of electrons in the presence of ammonia gas. The electrons activate both sulfur dioxide and nitrogen oxides, allowing them to react with ammonia to produce a mixture of ammonium sulfate and ammonium nitrate, which can be sold as a fertilizer. This system was initially developed in Japan and later tested in Germany but has never been marketed commercially.

More recently, scientists have explored the possibility of oxidizing nitrogen oxides in the flue gases using either ozone or hydrogen peroxide injection, leaving a range of higher oxides of nitrogen which will then react with limestone or lime in a wet FGD scrubber of spray drier absorber. This process, if developed commercially, is likely to be targeted at small boilers and waste incineration plants where it can be used to capture a range of pollutants at relatively low cost.

Particulate (Dust) Removal

In most large coal-fired power stations a large part of the ash residue from coal combustion is carried away with the flue gases, entrained in the form of fine particles. If allowed to escape into the atmosphere these will create a plume of smoke before eventually falling to earth as a layer of fine dust. Modern emission regulations require that this material be captured before flue gases are allowed to exit the stack of the power plant.

There are two principal systems that are used for removing particulates from the flue gas of a coal-fired power station, electrostatic precipitators (ESPs) and fabric (baghouse) filters. Cyclones can also be used to capture particulate material but they tend to be used on smaller plants.

The ESP was invented by the American scientist Frederick Cottrell. It utilizes a system of plates and wires to apply a large voltage across the flue gas as it passes through the precipitator chamber. The flue gases, when they enter the ESP, pass through an array of wires that are held at a high negative voltage relative to ground so that they generate a corona of ionized gas around them. As the particles pass through this corona they become charged. Once charged they are attracted to large vertical plates that are held at ground voltage. This is shown in Figure 6.5. Periodically the plates are vibrated or “rapped” causing the layer of charged particles that has built up on the surface of each to fall into a collector at the bottom of the ESP.

ESPs are extremely efficient. A new ESP will remove between 99.0% and 99.7% of the particulates from flue gas. However, it must be tuned to the particular coal being burned in the power plant. Where coals of different types and from various sources are to be burnt, the alternative may be more effective. The ESP can handle both dry and wet particles but it is less effective when the ash has a high electrical resistivity.

Bag filters, or baghouses, are tube-shaped filter bags through which the flue gas passes on its way to the power plant stack. Particles in the gas stream are trapped in the fabric of the bags from which they are removed using one of a variety of bag-cleaning procedures. These include using supersonic blasts of air to dislodge particles so that they fall to the base of the unit and can be removed. These filters can be extremely effective, removing over 99% of particulate material. They are generally less cost-effective than ESPs for collection efficiencies up to 99.5%. Above this, they are more cost-effective. A system that combines a baghouse-style filtration system with an ESP is under development too. This aims to provide a cost-effective high removal efficiency system, but has not yet been extensively demonstrated.

Baghouse filters require regular replacement, which can make them expensive to operate. ESPs are expensive to construct but are much more economical to operate.

Cyclone filters, which capture particles by imparting a centrifugal force on them, are used in CFB boilers to trap particles escaping the combustion zone but they are not usually used to capture particles in large power plants. They are relatively cheap to build, are able to operate at high temperatures and have low maintenance costs. However, they are only effective with dry particles and they are not efficient at removing small particles from flue gases.

Mercury Removal

Most coals contain a small amount of mercury and this can easily end up being discharged in the flue gas from a coal-fired power plant. The metal has an impact on many parts of the human body and exposure is always harmful. According to the US Environmental Protection Agency coal-burning power plants are the major anthropogenic source of mercury in the environment. The organization has estimated that 50% of the mercury released in US coal plants falls on the USA with the rest being carried further afield. Globally, mercury from coal combustion plants is likely to be spread across all continents.

The regulation of mercury emissions from coal plants has been under discussion for many years. Regulations controlling the level of emissions from power plants are due to be introduced this decade and may necessitate additional measures to ensure that limits are not exceeded.

Dust removal systems in power plants will generally remove around 25% of the mercury released during combustion. When a wet scrubbing sulfur removal system is also installed this can increase to 40%–60%. Adding SCR can lead to 95% removal with bituminous coals. However sub-bituminous coals and lignites do not respond so well so alternative measures may be needed to reduce mercury emissions to below regulatory limits.

The injection of activated carbon particles has been used to remove impurities, such as mercury, in waste incineration plants and this appears to offer the best solution where further mercury capture is necessary. The carbon particles will then be removed in the dust removal system through which the flue gases pass at a later stage. It is expected that plants will eventually need to remove 90% or more of the mercury released during combustion.