The flue gas desulfurization market is dominated by a few key players. These companies use a variety of strategies to gain a competitive edge and increase their market share.
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FGD wastewater is highly corrosive and contains many contaminants from coal and limestone, including high concentrations of total dissolved solids (TDS), suspended solids (TSS), chlorides, fluorides, nitrates and nitrites.
Power plants that use coal to produce electricity are a major source of pollution, particularly sulfur dioxide (SO2). The SO2 in the flue gas is toxic and can damage human health and vegetation. Power plants can reduce their SO2 emissions by installing flue gas desulfurization (FGD) scrubbers. These devices are capable of removing SO2 from the air and converting it into gypsum, a construction material.
The FGD market has experienced significant growth in recent years, thanks to increasing environmental regulations. However, there are several factors that could impede this market&#;s growth. These include regulatory constraints, coal characteristics, scrubber designs, and layouts. As a result, the power plant industry has opted for energy-efficient FGD systems. However, these can be expensive to operate. In addition, the system requires a large amount of energy for operating pumps and slurry and water pumps.
Depending on the type of FGD system, there are two ways to remove SO2. The most popular method is wet FGD scrubbing. This process involves spraying the flue gas with a mixture of water and limestone (scrubbing slurry). The slurry absorbs the SO2 in the flue gas and neutralizes its acidity. The slurry is also abrasive and can damage downstream equipment. Therefore, the slurry is often made of corrosion-resistant materials and reheated above its dew point to prevent erosion.
In addition to reducing SO2 emissions, FGD scrubbers can also remove particulates from the flue gas. This can improve the performance of electrostatic precipitators. This is important because it will enable them to function better and help meet clean air standards. Furthermore, the FGD market will benefit from new technology that allows the slurry to be recirculated. This will increase the scrubbing surface area and minimize SOx emissions.
FGD systems reduce SO2 emissions from coal- and oil-fired power plants by removing sulfur oxides from the flue gas before it is released. These oxides are pollutants that can cause a variety of environmental problems, including acid rain formation and particulate pollution. Sulfur oxides are also harmful to the environment, human health, and animal life. Fortunately, these emissions can be reduced by using FGD technology in fossil-fuel power plants and other facilities that emit sulfur dioxide, such as metal smelters, petroleum refineries, cement and lime kilns, and chemical and mineral processing operations.
In a wet FGD system, the flue gases enter a scrubber spray tower. There, they are sprayed with an alkaline slurry of ground limestone and water. The slurry reacts with the SO2 to remove it from the gas. After the scrubbing process, the slurry is stored in an effluent holding tank.
An alternative to a wet system is a dry scrubbing injection system, which injects powdered reagent directly into the furnace. This method uses less space and requires no byproduct disposal, but it has lower efficiency than a wet system. It can be used for plants up to 1,000 MW in size.
Another method is to use a seawater-based FGD system, which can be used for power plants that are located near the ocean. This system produces no byproducts and can be used for plants up to 1,000 mw in size. However, it does require substantial power for pumping seawater into the scrubber.
While end-of-pipe technologies like FGDs can help reduce SO2 emissions, they do not address global warming. To do that, we must reduce fossil fuel use, either by reducing energy use per unit of economic production or by substituting low- and non-carbon fuels for high-carbon fuels.
While the market for FGD systems has been growing, some factors could impede growth in the future. For example, many of the systems have complex components and processes that consume a lot of energy. In addition, the amount of water needed for scrubbing can be a significant cost factor. To reduce this cost, companies can implement rubber lining for their scrubbers. This coating protects equipment from corrosive and abrasive chemicals in the scrubbing solution.
Coal contains a number of chemicals that, when burned, combine with oxygen to form sulfur dioxide (SO2). When released into the air, SO2 can irritate the respiratory systems of people and animals, reduce visibility, and contribute to acid rain formation. It can also kill vegetation, damage water quality, and corrosion metal and concrete structures, reducing their lifespan. Because of its detrimental effects, strict environmental regulations have been put in place that limit SO2 emissions.
To mitigate these issues, plants employ flue gas desulfurization technologies to scrub SO2 from the exhaust of coal-powered power stations. One such technology is the scrubber, which is designed to eliminate SO2 from the exhaust by spraying wet limestone slurry over the polluted flue gas. The limestone reacts with the SO2 in the flue gas to form calcium sulfite or calcium sulfate, which then is collected in a liquid slurry. The slurry is then recycled.
Wet FGD systems can achieve SO2 removal efficiencies of greater than 90%. Dry systems, on the other hand, are able to achieve only about 80%. To improve their efficiency, wet FGD scrubbers can be modified by changing the design of recirculation nozzles, which are used to spray the wet slurry in the scrubber tower. This allows for a larger contact surface between the dirty flue gas and the slurry, improving SO2 removal.
While removing SO2 from the flue gases, a scrubber also reduces other pollutants. These include mercury and nitrogen oxides, which are harmful to human health in both their elemental and oxidized forms. Using electrostatic precipitators or fabric filters, these substances can be captured and removed from the exhaust. It is also possible to capture particulate matter through a scrubber, preventing it from being released into the atmosphere. This helps to reduce air pollution, which can negatively affect the respiratory and cardiovascular systems of people and animals.
The flue gas produced when fossil fuels are burned at a power plant or industrial facility contains many pollutants, including sulfur dioxide and mercury. This waste can affect air quality at a local and regional level if not properly treated or disposed of. Fortunately, several technologies exist for cleaning flue gases, and they all use scrubbers in one form or another. These include wet scrubbing with limestone or lime slurry, spray dry scrubbing using alkaline sorbents, and catalytic reactions that remove nitrogen oxides and sulfur dioxide in addition to other contaminants.
The primary method used to reduce sulfur dioxide is wet scrubbing. This involves passing the flue gas through a scrubber, where a mixture of water and limestone reacts with the SO2 in the gas to produce calcium sulfite and gypsum. The gypsum is then dried to produce a material called FGD gypsum, which is a valuable byproduct of the scrubbing process. This material is used in wallboard and cement production, as well as in soil amendment applications. It is also a source of supplemental phosphates, which are beneficial to agricultural and construction activities.
In some cases, the gypsum can be used to offset the cost of wet scrubbing. However, this is not always economically feasible because it requires a large amount of energy to heat the slurry. The type of fuel a power plant uses also influences the costs. High sulfur fuels are more expensive to scrub, while low sulfur fuels are cheaper.
Another way to reduce SO2 is by removing it from the fuel prior to combustion. This is known as hydrodesulfurization, and it can be achieved through fluidized bed combustion or by adding lime to the fuel during combustion. In either case, the resulting slurries are mixed with water before they are fed into the scrubber.
The most recent technologies to reduce SO2 include advanced wet and dry scrubbing systems. These are designed to remove SO2 and mercury from the exhaust gases of coal-fired plants. Wet scrubbing with limestone and water is a proven technology, and it can be used to achieve high levels of SO2 removal. Dry scrubbing is more effective at removing SO3 than SO2, and it can also remove mercury. Its performance is dependent, however, on the type of coal being used and other operating conditions.
Before flue gas desulfurization was installed, the emissions from the Four Corners Generating Station in New Mexico contained a significant amount of sulfur dioxide.
Flue-gas desulfurization (FGD) is a set of technologies used to remove sulfur dioxide (SO2) from exhaust flue gases of fossil-fuel power plants, and from the emissions of other sulfur oxide emitting processes such as waste incineration, petroleum refineries, cement and lime kilns.
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Since stringent environmental regulations limiting SO2 emissions have been enacted in many countries, SO2 is being removed from flue gases by a variety of methods. Common methods used:
For a typical coal-fired power station, flue-gas desulfurization (FGD) may remove 90 per cent or more of the SO2 in the flue gases.[2]
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Methods of removing sulfur dioxide from boiler and furnace exhaust gases have been studied for over 150 years. Early ideas for flue gas desulfurization were established in England around .
With the construction of large-scale power plants in England in the s, the problems associated with large volumes of SO2 from a single site began to concern the public. The SO
2 emissions problem did not receive much attention until , 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 SO
2 controls on all such power plants.[3]
The first major FGD unit at a utility was installed in at Battersea Power Station, owned by London Power Company. In , an FGD system similar to that installed at Battersea went into service at Swansea Power Station. The third major FGD system was installed in at Fulham Power Station. These three early large-scale FGD installations were suspended during World War II, because the characteristic white vapour plumes would have aided location finding by enemy aircraft.[4] The FGD plant at Battersea was recommissioned after the war and, together with FGD plant at the new Bankside B power station opposite the City of London, operated until the stations closed in and respectively.[5] Large-scale FGD units did not reappear at utilities until the s, where most of the installations occurred in the United States and Japan.[3]
In , the U.S. Congress passed the Clean Air Act of (CAA). The law authorized development of federal regulations in the United States covering emissions from both stationary (industrial) and mobile sources, which were subsequently published by the U.S. Environmental Protection Agency (EPA). In , Congress amended the law to require more stringent controls on air emissions.[6] In response to the CAA requirements, the American Society of Mechanical Engineers (ASME) authorized the formation of the PTC 40 Standards Committee in . This committee first convened in with the purpose of developing a standardized "procedure for conducting and reporting performance tests of FGD systems and reporting the results in terms of the following categories: (a) emissions reduction, (b) consumable and utilities, (c) waste and by-product characterization and amount."[7] The first code draft was approved by ASME in and adopted by the American National Standards Institute (ANSI) in . The PTC 40- Standard was available for public use for those units affected by the Clean Air Act Amendments. In , the PTC 40 Committee reconvened following EPA publication of the Clean Air Interstate Rule (CAIR) in .[8] In , the revised PTC 40 Standard was published. This revised standard (PTC 40-) covers Dry and Regenerable FGD systems and provides a more detailed Uncertainty Analysis section. This standard is currently in use today by companies around the world.
As of June , there were 42 FGD units in operation, 36 in Japan and 6 in the United States, ranging in capacity from 5 MW to 250 MW.[9] As of around and , FGD units were being used in 27 countries, and there were 678 FGD units operating at a total power plant capacity of about 229 gigawatts. About 45% of the 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.[10][11][12]
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The International Maritime Organization (IMO) has adopted guidelines on the approval, installation and use of exhaust gas scrubbers (exhaust gas cleaning systems) on board ships to ensure compliance with the sulphur regulation of MARPOL Annex VI. [13] Flag States must approve such systems and port States can (as part of their port state control) ensure that such systems are functioning correctly. If a scrubber system is not functioning properly (and the IMO procedures for such malfunctions are not adhered to), port States can sanction the ship. The United Nations Convention on the Law Of the Sea also bestows port States with a right to regulate (and even ban) the use of open loop scrubber systems within ports and internal waters.[14]
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Fossil fuels such as coal and oil can contain a significant amount of sulfur. When fossil fuels are burned, about 95 percent or more of the sulfur is generally converted to sulfur dioxide (SO2). Such conversion happens under normal conditions of temperature and of oxygen present in the flue gas. However, there are circumstances under which such reaction may not occur.
SO2 can further oxidize into sulfur trioxide (SO3) when excess oxygen is present and gas temperatures are sufficiently high. At about 800 °C, formation of SO3 is favored. Another way that SO3 can be formed is through catalysis by metals in the fuel. Such reaction is particularly true for heavy fuel oil, where a significant amount of vanadium is present. In whatever way 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.
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Most FGD systems employ two stages: one for fly ash removal and the other for SO2 removal. Attempts have been made to remove both the fly ash and SO2 in one scrubbing vessel. However, these systems experienced severe maintenance problems and low removal efficiency. In wet scrubbing systems, the flue gas normally passes first through a fly ash removal device, either an electrostatic precipitator or a baghouse, and then into the SO2-absorber. However, in dry injection or spray drying operations, the SO2 is first reacted with the lime, and then the flue gas passes through a particulate control device.
Another important design consideration associated with wet FGD systems is that the flue gas exiting the absorber is saturated with water and still contains some SO2. These gases are highly corrosive to any downstream equipment such as fans, ducts, and stacks. Two methods that may minimize corrosion are: (1) reheating the gases to above their dew point, or (2) using materials of construction and designs that allow equipment to withstand the corrosive conditions. Both alternatives are expensive. Engineers determine which method to use on a site-by-site basis.
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Schematic design of the absorber of an FGDSO2 is an acid gas, and, therefore, 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 calcium sulfite (CaSO3) and may be expressed in the simplified dry form as:
CaCO3
(s) +SO2
(g) &#;CaSO3
(s) +CO2
(g)When wet scrubbing with a Ca(OH)2 (hydrated lime) slurry, the reaction also produces CaSO3 (calcium sulfite) and may be expressed in the simplified dry form as:
Ca(OH)2
(s) +SO2
(g) &#;CaSO3
(s) +H2O
(l)When wet scrubbing with a Mg(OH)2 (magnesium hydroxide) slurry, the reaction produces MgSO3 (magnesium sulfite) and may be expressed in the simplified dry form as:
Mg(OH)2
(s) +SO2
(g) &#;MgSO3
(s) +H2O
(l)To partially offset the cost of the FGD installation, some designs, particularly dry sorbent injection systems, further oxidize the CaSO3 (calcium sulfite) to produce marketable CaSO4·2H2O (gypsum) that can be of high enough quality to use in wallboard and other products. The process by which this synthetic gypsum is created is also known as forced oxidation:
CaSO3
(aq) + 4H2O
(l) +O2
(g) &#; 2 (CaSO4·2H2O
(s))A natural alkaline usable to absorb SO2 is seawater. The SO2 is absorbed in the water, and when oxygen is added reacts to form sulfate ions SO2&#;4 and free H+. The surplus of H+ is offset by the carbonates in seawater pushing the carbonate equilibrium to release CO2 gas:
SO2
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(g) +H2O
(l) +&#;
1
/
2
&#;O2
(g) &#;SO
2&#;
4
(aq) + 2H+
HCO
&#;
3
+H+
&#;H2O
(l) +CO2
(g)In industry caustic soda (NaOH) is often used to scrub SO2, producing sodium sulfite:
NaOH
(aq) +SO2
(g) &#;Na2SO3
(aq) +H2O
(l)[15][
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To promote maximum gas&#;liquid surface area and residence time, a number of wet scrubber designs have been used, including spray towers, venturis, plate towers, and mobile packed beds. Because of scale buildup, plugging, or erosion, which affect FGD dependability and absorber efficiency, the trend is to use simple scrubbers such as spray towers instead of more complicated ones. The configuration of the tower may be vertical or horizontal, and flue gas can flow concurrently, countercurrently, or crosscurrently with respect to the liquid. The chief drawback of spray towers is that they require a higher liquid-to-gas ratio requirement for equivalent SO2 removal than other absorber designs.
FGD scrubbers produce a scaling wastewater that requires treatment to meet U.S. federal discharge regulations.[16] However, technological advancements in ion-exchange membranes and electrodialysis systems has enabled high-efficiency treatment of FGD wastewater to meet recent EPA discharge limits.[17] The treatment approach is similar for other highly scaling industrial wastewaters.
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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.
For simultaneous removal of SO2 and fly ash, venturi scrubbers can be used. In fact, many of the industrial sodium-based throwaway systems are venturi scrubbers originally designed to remove particulate matter. These units were slightly modified to inject a sodium-based scrubbing liquor. Although removal of both particles and SO2 in one vessel can be economic, the problems of high pressure drops and finding a scrubbing medium to remove heavy loadings of fly ash must be considered. However, in cases where the particle concentration is low, such as from oil-fired units, it can be more effective to remove particulate and SO2 simultaneously.
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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 the 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.
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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.
Counter-current packed towers are infrequently used because they have a tendency to become plugged by collected particles or to scale when lime or limestone scrubbing slurries are used.
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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 "spent caustic" 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.
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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. Since the sodium sulfite solution is not consumed, it is called a regenerative treatment. The application of this reaction is also known as the Wellman&#;Lord process.
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.
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A new, emerging flue gas desulfurization technology has been described by the IAEA.[18] 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 . The Pomorzany power plant in Poland also started up a similar sized unit in and that plant removes both sulfur and nitrogen oxides. Both plants are reported to be operating successfully.[19][20] However, the accelerator design principles and manufacturing quality need further improvement for continuous operation in industrial conditions.[21]
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[20] 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 nitrogenous fertilizer. In addition, it can be used to lower the nitrogen oxide content of the flue gas. This method has attained industrial plant scale.[19][22]
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Flue gas desulfurization scrubbers have been applied to combustion units firing coal and oil that range in size from 5 MW to 1,500 MW. Scottish Power are spending £400 million installing FGD at Longannet power station, which has a capacity of over 2,000 MW. Dry scrubbers and spray scrubbers have generally been applied to units smaller than 300 MW.
FGD has been fitted by RWE npower at Aberthaw Power Station in south Wales using the seawater process and works successfully on the 1,580 MW plant.
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 US dollars) are:
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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 elemental sulfur is then separated and finally recovered at the end of the process for further usage in, for example, agricultural products. Safety is one of the greatest benefits of this method, as the whole process takes place at atmospheric pressure and ambient temperature. This method has been developed by Paqell, a joint venture between Shell Global Solutions and Paques.[24]
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