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Though worldwide coal-fired power generation is declining, the residual effects of the technology remain. The greatest concern is mitigating the impacts of potentially toxic materials stored in ash ponds and wet flue gas desulfurization (WFGD) wastewaters. Where do these coal impurities originate?
While certain impurities accumulate during the plant growth phase, many originate from external sources, which are heavily influenced by the geographical location and environmental conditions during coal formation. Fuel-bound nitrogen is the main contributor to the formation of nitrogen oxides (NO x) during combustion. As air (which contains 78% elemental nitrogen (N 2)), is used for combustion, NO x is formed through the reaction of N 2 and O 2 in the furnace. However, this process typically produces less NO x compared to that originating from fuel-bound nitrogen.
Peat exhibits a high moisture content. However, even in mature coals, such as bituminous, many cracks and crevices allow the passage of water, the primary source of impurities. Iron sulfide (FeS 2), a commonly found impurity, is believed to have originated from swamps flooded with brackish water containing sulfates. Anaerobic bacterial decomposition of sulfates resulted in the formation of sulfides, which subsequently combined with iron. FeS 2 is among the most troublesome impurities in many bituminous coals. Often, physical washing is employed to reduce pyrite concentrations before coal transport to the power plant.
Soil, like many natural minerals, consists of complex metallic silicates. As a result, nearly all coals contain significant quantities of silicon and aluminum. If the coal is located near limestone deposits, calcium and magnesium may reach relatively high proportions as well.
Large scale ash production adds complexity to coal combustion. The minerals listed in the table above, as well as others, possess distinct melting points that are affected when these minerals are combined. Thus, at the height of coal-fired boiler construction in the mid-20th century, the design and size of boilers were based on the type of coal to be combusted and the characteristics of the resulting ash. Depending upon the mineral combination, ash can exhibit acidic or basic chemistry, which influences fireside fouling and corrosion.
The three most common coal boiler types for power generation were the cyclone, wall-fired, scrand tangentially-fired (T-fired) design. In cyclone boilers, coal is ground to pebble size and injected into the cyclone barrels, the location of primary combustion. Most of the ash (up to 80% in some cyclone units) is tapped in the molten state from the bottom of the boiler, appropriately named bottom ash. This ash must be quenched with water prior to removal from the boiler. Wall-fired and T-fired boilers utilize pulverized coal ground into a fine powder. Combustion in these units takes place directly within the main furnace. Up to 80% of the ash departs as fly ash, with the remaining bottom ash removed as a solid.
Requirements to lower sulfur dioxide emissions led to unforeseen difficulties that plagued many of the bituminous coal units in the last century. However, at many facilities, plant management opted for an alternative strategy, transitioning from high-sulfur bituminous coals to low-sulfur Powder River Basin (PRB) coals. As a result, this became a large source of business for the major western railroads, who began hauling millions of tons of coal to Midwestern and Eastern power plants.
The change to PRB coal in boilers designed for bituminous coal came at a significant cost, however. In addition to the much longer transportation distances, the primary issue emerged from the change in the ash characteristics. PRB ash transitions from a solid phase to a completely molten phase over a narrow temperature range, whereas the change is more gradual for bituminous coals. Additionally, though the ash content of PRB coal is relatively low, the calcium percentage is higher. These factors, and others, caused severe slagging problems in many bituminous-designed units, and employment of specialty firms to blast hard deposits with dynamite was not uncommon.
While coal is derived from the biologically and chemically altered remains of terrestrial plant life, oil originates from the remnants of marine organisms. In this process, sea creatures buried with mud and silt decompose under temperature and pressure to produce organic deposits. In this instance, however, the distinct composition of marine organisms, as opposed to vegetation, results in the formation of smaller organic molecules that are subsequently liquefied. Often, the liquid was filtered through rock formations and collected in pockets. These pockets were the sources of the “gushers” that American prospectors once found in the United States and can still be found in other areas of the world. In other instances, oil became entrapped within sedimentary formations and remained difficult to extract until the development of hydraulic fracturing technology.
As is evident, oils become denser and more viscous moving from No. 1 to No. 6. Fuel oil No. 2 is a common fuel for light-off and warm-up of coal-fired boilers.
Natural gas is commonly found in independent pockets or associated with oil or coal fields. More recently, the development of horizontal hydraulic fracturing, or “fracking,” has opened many additional large deposits of natural gas and oil that were formerly trapped in shale sediments. The prime component of natural gas is methane (CH 4), although other hydrocarbons may be present, most notably ethane (C 2 H 6), which is the next compound in the alkane series.
Natural gas has become the primary fossil fuel for power production, as it is easy to handle, has a pipeline infrastructure in place, burns cleanly, and produces fewer pollutants than other fuels. Of the primary fossil fuels, natural gas has the highest heating value per unit weight. This, along with the great increase in supplies produced by fracking, has led to the proliferation of combined cycle power units, some of which operate above 60% net efficiency. Because natural gas is a clean fuel as delivered, combustion products (ash, slag) are non-existent.
Solid combustion byproducts are often accompanied by their own set of difficulties. For example, furnace designs could be solely based on heat transfer considerations in the absence of ash 3. The inorganic minerals present in the fuel do not combust during the combustion process. Consequently, they are either expelled from the boiler or accumulate on the internal surfaces of the boiler. In general, coal plants are designed around ash characteristics and removal requirements.
The data reveals several interesting details.
First, the ash content of the two western subbituminous coals is lower than that of all other coals, although lower ash content does not necessarily indicate less fouling.
Second, all coals contain significant amounts of silica and aluminum, which come from the complex aluminosilicates that make up much of the earth’s crust.
Third, there is the variable content of iron, the alkali metals sodium and potassium, and the alkaline earth metals calcium and magnesium. These significantly influence ash melting temperatures and other properties, which influence slagging and fouling.
Fourth are the variable sulfur concentrations. Separate from air pollution, sulfur compounds play a direct role in boiler tube corrosion.
The ash constituents are all reported as oxides. This is the standard method for reporting ash analyses, but, as shown in Table 5-5, the original minerals are typically more complex. An initial item to note from Table 5-6 is the definition of bituminous and lignitic ash. Bituminous ash has a higher concentration of ferric oxide than calcium and magnesium oxides combined. The definition of lignitic ash is the reverse; the concentration of ferric oxide is less than the combined amount of calcium and magnesium oxides.
When examining ash chemistry and its impact on boilers, it is crucial to first consider the concept of ash melting behavior, commonly referred to as fusibility. The ASTM has developed a test for determining the melting characteristics of ash. The test involves forming an ash sample into a small pyramid, subjecting it to controlled heating, and measuring deformation characteristics. The four parameters are Initial Deformation Temperature (IT), Softening Temperature (ST), Hemispherical Temperature (HT), and Fluid Temperature (FT).
These characteristics are defined as follows:
Table 5-7 shows that fusibility temperatures may change markedly with a shift from oxidizing to reducing atmospheres. Generally, this is due to the conversion of iron to various oxidation states.
This data allows an examination of slagging and fouling characteristics of ash. Slagging is the buildup of deposits on furnace walls subjected to radiant heat. Fouling is the deposition of ash residue on convective heating surfaces.
Slag formation is directly influenced by the fusibility properties of ash. The combustion zone of the boiler is the highest heat area, and ash is often molten in this region. When completely molten, ash flows readily. However, ash viscosity can often increase dramatically with just a small temperature drop. Ash particles within the IT-HT temperature range may form highly adhesive particles that bond tightly to tube walls. Heavy slagging reduces heat transfer in the waterwalls, which increases superheater and reheater gas temperatures. Slagging may extend into further reaches of the boiler if heat transfer degrades in the furnace.
Each mineral compound in ash influences fusibility. Interactions between minerals further complicate the issue.
The minerals formed during coal combustion can be categorized as either basic or acidic. If these minerals were placed individually in water, they would produce solutions that are either basic or acidic to varying degrees. The basic minerals are iron, calcium, magnesium, sodium, and potassium oxides. The acidic minerals are silica, alumina, and titanium dioxide. The ratio of basic to acidic minerals in ash significantly influences melting temperatures.
The ratio of silica to alumina also influences melting temperatures. When mixed with basic partners, silica tends to produce lower ash melting temperatures than if the acidic component was alumina.
Another important parameter is the iron/calcium ratio, where the ferric oxide (Fe 2 O 3) portion of iron is considered. The fluxing action among iron and calcium is complex, but the general trend is that lower Fe 2 O 3/CaO ratios tend to lower the ash softening temperature.
Dolomite is a prevalent form of limestone where calcium is significantly supplemented with magnesium. It has a similar effect with iron as simple calcium oxide. With two coals of similar base content, the one with the higher percentage of dolomite will tend to have higher fusion temperatures.
This definition was established to explain the effects of iron under oxidizing or reducing conditions. In a boiler fired with excess air at the main burners, most of the iron in the coal reacts to form Fe 2 O 3. In a reducing atmosphere, such as in a boiler utilizing overfire air for NO x control, the iron present in the reducing zone will exhibit the presence of ferrous oxide (FeO) and potentially some metallic iron (Fe). These compounds each lower ash melting temperatures.
As silica percentage increases compared to the other fluxing agents iron, calcium oxide, and magnesium oxide, the ash viscosity increases.
Sodium and potassium lower ash melting temperatures. Alkalis are important in relation to superheater and reheater fouling, as outlined in the next section.
As is evident, a wide variety of factors influence slagging properties. It is impossible to completely predict the slagging properties of a coal, though a set of calculations for evaluating slagging potential have been developed 2. Slag control efforts are apparent in boiler design. Cyclone units, which gained popularity during the 1960s, were designed to generate molten slag within the cyclone barrels and the lower sections of the boiler. The molten slag was subsequently drained in its liquid form into a water-filled slag tank. This is known as the wet bottom concept (which refers to the molten slag, not the water-filled slag tank). The ratio of bottom ash to fly ash in a cyclone unit is approximately 80% to 20%. Most pulverized coal units operate differently. The tiny coal particles burn quickly, and the fine ash residue is carried upward with furnace flow. In a properly designed system, most of the ash that contacts the furnace walls has already solidified and does not stick. In these types of units, the distribution of ash is essentially inverted, with up to 80% of the ash escaping as fly ash and approximately 20% being collected as bottom ash. Because the bottom ash does not discharge in a molten state, these are known as dry bottom units.
Fouling is most prominent in the boiler convection pass, primarily in the superheater and reheater areas. Fouling is caused by the deposition of fly ash particles on tube and duct surfaces. In the absence of furnace upsets, the ash particles entering the convection pass are expected to remain in solid form and, on their own, should not exhibit a significant tendency to adhere to the equipment. However, combustion generates volatile alkali compounds of sodium and potassium that condense on tube surfaces and ash particles, giving them much stronger adhesion tendencies.
The concentration of sodium and potassium in the flue gas is related to how these two elements are bound within the original fuel. Sodium and potassium that are combined with silicates tend to remain stable throughout the process. However, a percentage of the alkalis exist as simple salts, primarily chlorides, or are organically bound in the coal. These “active” alkalis vaporize during the combustion process and form the oxides Na 2 O and K 2 O. The relatively lower temperatures in the convective pass of the boiler allow the alkalis to condense.
Generally, the bulk of active alkalis exist as chloride salts, so a measure of coal chlorine content is a reasonable guideline to determine the relative fouling potential.
Another important relationship between sodium and fouling is that a greater active sodium content increases the strength of ash deposits. Figure 5.3 below shows that this is true for both bituminous ash and lignitic ash coals. In both cases, but particularly for lignitic ash, the ash strength increases significantly with increasing sodium oxide content.
Greater sintering strength equates to increasing difficulty in removing deposits with sootblowers. Further, sintering strength can be greatly reduced by washing the coal to reduce the active alkali concentration.
Fouling of convective pass equipment and surfaces causes a number of problems. Buildups on superheater tubes reduces heat transfer efficiency, but buildups also cause channeling or “laning” of the flue gas. This increases linear velocity through open areas, which may lead to an increase in erosion on other tubes. It is not uncommon for tube failures to be caused by ash erosion. Excessive ash buildups between superheater pendants may cause bridging of material between pendant sections. Slag and ash deposits in the upper sections of the radiant portion of the boiler may break loose and damage or puncture furnace floor tubes when they strike bottom.
The accumulation of ash deposits in the convective pass can also have adverse effects from a corrosion perspective. As ash deposits build up, volatile alkalis and sulfur trioxide (SO 3) produced during combustion diffuse through the ash to initiate corrosion reactions. Figure 5.4 illustrates one example of the morphology of a coal ash corrosion deposit.
Outlined below are two reactions that illustrate how deposits can accumulate and lead to the corrosion of tube metal:
3K 2 SO 4 + Fe 2 O 3 + 3SO 3 → 2K 3 Fe(SO4)3 _Eq. 1_K 2 SO 4 + Al 2 O 3 + 3SO 3 → 2KAl(SO 4)2 _Eq. 2_
Whereas sodium is the prime culprit in deposit formation and strength, potassium appears to be the chief alkali initiating corrosion reactions. In this example, three layers have developed. The first is an outer layer, which is mostly fly ash. The intermediate layer is white- to yellow-colored and shows a marked increase in potassium and SO 3 concentration. As the figure illustrates, this layer has replaced original tube metal. The inner layer is a thin black band located at the tube surface and is the site of active corrosion. Iron content is high because of its proximity to the base metal, and the compounds within this layer include iron sulfides and sulfates.
In contrast to these examples of high-temperature fouling and corrosion, low-temperature corrosion of air heaters and outlet ducts will occur if the flue gas temperature is allowed to drop below the acid dew point. A small amount of the sulfur combusted in the boiler converts to SO 3. If the temperature drops too low at the back end of the boiler, the SO 3 will combine with moisture to produce sulfuric acid, H 2 SO 4. Although the sulfuric acid concentration may be minimal, the liquid is quite corrosive to carbon steel. Exit gas temperatures must be maintained above the dew point temperature through the boiler backpass (and electrostatic precipitator if the unit has one) to prevent corrosion.
Oil contains significantly lower mineral content than coal, resulting in less complex oil ash deposition problems. Typically, oil ash does not cause corrosion of waterwall tubes. Because of the low-melting ash despoits, the superheater and reheater are often the problematic areas. Additionally, as with coal combustion products, back-end corrosion due to acid dew point corrosion is a possibility.
The primary cause of ash corrosion is vanadium, which originates from soil minerals and the organic matter that decomposed to form oil. Oils may contain virtually no vanadium to almost 400 parts-per-million (ppm). Vanadium released in combustion forms several oxides, V 2 O 3, V 2 O 4, and V 2 O 5. These oxides combine with alkali salts to form low-melting compounds that accumulate on tube surfaces. Equation 3 illustrates a typical reaction.
Na 2 SO 4 + V 2 O 5 → 2NaVO 3 + SO 3 _Eq. 3_
The melting point of NaVO 3 is 1,165°F (629°C). Sodium-vanadium compounds with low melting points exhibit direct corrosive effects on steel, and the corrosion rate accelerates with increasing metal temperature. Control methods include selecting low-vanadium oil, designing boilers to reduce metal temperatures, implementing effective sootblower designs to keep tubes clean, and using chemical additives to manage corrosion.
Chemical addition to the fuel feed is sometimes utilized to reduce slagging and fouling. Common additives include alumina and magnesium compounds like magnesium oxide. These compounds modify the chemistry and melting point of ash deposits, making them less adherent and more easily removable through sootblowing. Additive feed is most common at plants that were switched from bituminous to PRB coals.
Although decarbonization efforts continue to diminish the fossil fuel power industry, specifically coal plants, many will temporarily remain to ensure grid stability. Fireside chemistry is complex, where changes in fuel source, operational conditions, and other factors can lead to slagging, fouling, and corrosion. Most plants now have sophisticated instrumentation and control room computer displays that allow operators to monitor conditions throughout the boiler and downstream flue gas path. This technology is critically important for consistent and reliable operation, particularly in this era when even large units must regularly cycle up and down in load.
The first national air pollution legislation in the United States was the Clean Air Act of 1963. This initial legislation was designed to guide the states in dealing with air pollution control issues. Additional regulations were proposed and passed later in the 1960s, but the turning point came with the establishment of the Environmental Protection Agency (EPA) in 1970 and the subsequent passage of the Clean Air Act Amendments (CAAA) in December of that year.
The EPA, under Congressional authority, was tasked with developing National Ambient Air Quality Standards (NAAQS), which, with passage of the 1990 CAAA, evolved into the stipulation that each state would be responsible for meeting the NAAQS for six criteria air pollutants; nitrogen oxide, sulfur dioxide, carbon monoxide, ozone, particulate matter, and lead. This section examines three of the items from this list: nitrogen oxides, sulfur dioxide, and particulate matter.
The progression is:
NO x is a primary element of acid rain and contributes to ground-level ozone formation, particularly in large cities where atmospheric pollutants become concentrated. The term NO x is all-inclusive, as fossil-fuel combustion produces several oxides of nitrogen, most notably nitrogen oxide (NO) and nitrogen dioxide (NO 2). A typical ratio of NO to NO 2 produced in the furnace is 9 to 1. In plants equipped with a sulfur dioxide scrubber, NO 2, which is water soluble, will wash out of the flue gas. However, NO is only slightly soluble, and because it usually makes up about 90% of the NO x, scrubbing is not an effective treatment process.4
When nitrogen oxides enter the atmosphere, several problems arise. NO x participates in a series of complex photochemical reactions with volatile organic compounds that produce ground-level ozone (O 3). While the high level of ozone in the earth’s atmosphere protects us from harmful solar radiation, ground-level ozone causes respiratory problems, especially in the very young, the elderly, smokers, asthmatics, and people with other lung problems. Upon release from the boiler, much of the NO converts to NO 2, which, like its SO 2 counterpart, combines with water to form an acid, in this case nitric acid (HNO 3).
Nitrogen oxides produced during coal combustion are generally grouped into two categories: thermal NO x and fuel NO x. Thermal NO x is generated by the high heat of combustion and results from the reaction of atmospheric nitrogen (N 2) and oxygen (O 2). Even in pulverized coal units, thermal NO x may only account for a quarter of all NO x emissions, as thermal NO x formation does not become notably pronounced until temperatures reach 2,800ºF. A well-known technique to reduce thermal NO x is flue gas recirculation, in which a portion of the flue gas is recycled to the furnace inlet. This lowers furnace temperatures slightly, but enough to significantly limit thermal NO x production.
Fuel NO x is a different story. Most nitrogen in coal is organically bound to carbon atoms, and these bonds are much easier to break than those of N 2. As the coal combusts, individual nitrogen atoms are released. As opposed to molecules, nitrogen atoms are very reactive and quickly attach to oxygen.
Control of nitrogen oxide formation and discharge generally falls into two categories: concurrent combustion control and post combustion control. Low-NO x burners (LNB) and overfire air (OFA) belong to the first category. The detailed chemistry of LNB and OFA methodology is complex, but the basics are as follows. When coal or any other fossil fuel is burned with an excess of oxygen, combustion of the carbon content proceeds to completion, as expressed as below:
C + O 2 → CO 2 _Eq. 1_
Energy-wise, this reaction is favorable and gives off substantial heat. When sub-stoichiometric amounts of oxygen are introduced into the process, a portion of the coal undergoes partial oxidation to carbon monoxide, potentially leaving some unburned carbon:
C + ½O 2 → CO _Eq. 2_
Carbon monoxide seeks oxygen atoms to complete the reaction to carbon dioxide. When insufficient oxygen is available, the molecules will take oxygen from nitrogen oxides, which is the basis behind LNB and OFA. The fuel is initially combusted in an oxygen-lean environment to allow the formation of reduced carbon species. These reduced carbon compounds strip oxygen from NO x and allow nitrogen atoms to combine into N 2. The chemistry becomes complex because of the high number of molecular interactions that take place, even during the brief time that the molecules are at the burner front. A nitrogen oxide molecule may give up its oxygen atom(s) to carbon, only to combine with another oxygen. This process may happen repeatedly before the nitrogen atom meets another nitrogen atom to form N 2. Many intermediate chemical species are produced during combustion, and the interactions that eventually reduce NO x levels are rather complex. The remaining air for combustion is injected at a higher elevation in the furnace to convert the residual unburned carbon and carbon monoxide to CO 2.
With OFA, the area of reducing conditions between the burners and the OFA ports represents a frequent problem. During conventional combustion, excess air is injected with the fuel to ensure most of the carbon in the coal burns to completion. The excess air establishes an oxidizing atmosphere in the furnace where the boiler tubes develop an oxide coating. In systems utilizing OFA, the combustion products located between the main burners and the OFA feed points contain reducing compounds, including sulfides. These may react with the metal in tube walls to form iron sulfides that are not protective like their counterpart oxides. Corrosion and spalling of tube material can occur in the reducing environment between the burners and OFA injection nozzles.
The combination of low-NO x burners and OFA has proven capable of lowering NO x emissions to levels close to 0.15 lb./MBtu (0.064 kg/10 6 kJ). A common supplement to LNB/OFA is post combustion control with selective catalytic reduction (SCR).
Typical SCR reactions are illustrated in the following two equations.
4NO + 4NH 3 → 4N 2 + 6H 2 O _Eq. 3_2NO 2 + 4NH 3 + O 2 → 3N 2 + 6H 2 O _Eq. 4_
Ammonia reacts with NO x to generate elemental nitrogen, with the reactions taking place in fixed catalyst beds in the flue gas stream. A variety of materials are viable to serve as SCR catalysts, most commonly titanium dioxide, vanadium pentoxide, precious metals, and zeolites (aluminosilicates). The ideal operating range of the transition metal (titanium, vanadium) catalysts is generally 450ºF to 850ºF, while the zeolites operate at a higher temperature range of approximately 850ºF to 1,050ºF. The most common structural configuration is a block-type catalyst manufactured in honeycomb configuration.
SCR introduces several potential complicating factors to plant operations. An excess of ammonia must be added to reduce NO x to low levels. A portion of the ammonia will undergo oxidation to nitrogen on the catalyst bed; however, some ammonia will pass through the bed unreacted. This phenomenon is referred to as ammonia slip. Ammonia is considered a regulated substance for accident prevention, as it can react with other pollutants to form fine particulate matter.5 A common limit for ammonia discharge in flue gas is 2 parts per million. These limits are important to maintain fly ash quality, particularly if that ash is subsequently utilized as an additive in construction materials.
SCR catalysts gradually degrade over the life of the material. The extent of catalyst poisoning will vary based on the catalyst’s composition and its content of arsenic, phosphorus, and other elements or compounds. As would be expected, the lead (first) catalyst bed exhausts first. A common replacement method is to move all beds one place forward and put the new catalyst bed at the trailing location after the lead bed is removed.
The reaction of ammonia with sulfur trioxide in the flue gas results in the formation of ammonium sulfate [(NH 4)2 SO 4] and ammonium bisulfate (NH 4 HSO 4). Both compounds contribute to fouling and corrosion of downstream equipment, particularly air heaters, with ammonium bisulfate being especially problematic. Another problem with ammonia derives from its’ storage on plant grounds. The EPA classifies anhydrous ammonia and aqueous ammonia at or above 20 percent concentration as regulated toxic substances. Consequently, urea conversion has become more common to generate ammonia for SCR systems.
Urea is an agricultural chemical that can be hydrolyzed to produce ammonia and carbon dioxide. Hydrolysis systems at power plants allow ammonia to be generated per demand without storage of hazardous ammonia.
Particulate matter was one of the first pollutants from coal-fired boilers to be recognized as problematic. Boiler type significantly influences particulate formation. In traditional cyclone boilers, most of the ash (up to 80%) exits as bottom ash in a molten state, which is then solidified in a water-filled slag tank. Fly ash volume is relatively low in cyclone boilers. Few of these units remain because of their age, low efficiency, and propensity to produce large amounts of NO x. In pulverized-coal units, where up to 80% of the ash may exit with the flue gas, particulate concentrations are quite high. All plants require capture of at least 99% of these particulates. Two major processes, electrostatic precipitation and fabric filter collection, have been popular for particulate control.
An electric potential is induced between the collecting plates and solid electrodes (or wires in older units), where a negative potential is applied to the electrodes and a positive potential to the plates. As the flue gas passes through the precipitator, the particles develop a negative electrical charge from the electrodes. The particles are then attracted to and accumulate on the plates. The plates are periodically shaken (rapped) by mechanical vibrators, causing the ash to fall to the bottom of the precipitator where it is collected in hoppers for discharge through the ash disposal system.
To slow the linear velocity of the gas to ensure the particles have sufficient time to develop a charge, the ESP is much larger than the entry flue gas duct. A typical entering velocity may be 60 feet per second, while flow through the precipitator may only be 4–5 feet per second. ESPs consist of a series of cells where ash removal efficiency is around 75% per cell. When combined in series, it is possible to see overall efficiencies of 99%. The distance between collecting plates in an ESP may range from 9–16 inches, with the negative electrode evenly centered between collecting plates.
Numerous factors influence precipitator performance, including:
Mechanical factors affecting performance:
Operational factors affecting performance:
Another widely used particulate removal technique is fabric filtration, commonly known as baghouses. In this process, the flue gas passes through a fine mesh fabric filter and particulates collect on one side of the filter. Periodic vibrations dislodge the ash, and it falls to hoppers for collection. Figure 5.1.6 shows the generic outline of a popular type, the pulse-jet fabric filter.
The bags are mounted on wire frames within the vessel. Flue gas enters from the side, is deflected by, and flows around a baffle plate, then passes through the bags. Fly ash remains on the exterior of the bags as the flue gas exits the top of the vessel. Periodically, a jet of air is blown through the bags to dislodge the ash, which falls to hoppers below. Baghouses typically feature several compartments, each containing rows of filters.
Redundancy is incorporated by automatically isolating individual compartments from the flue gas stream, followed by pulse cleaning. This prevents the ash from being re-entrained in the flue gas. Cloth-to-air ratio, filter diameter and length, and flue gas temperature are each factors that baghouse design engineers must consider. Progressive improvements in cloth design allow baghouses to operate at temperatures of up to 500ºF. Though such materials can withstand high temperatures; they are still susceptible to fires if unburned carbon accumulates in the cloth. Baghouse fires can be extremely dangerous, in large part because opening access doors to combat the fire introduces additional oxygen. Additionally, when water is sprayed on the fire, burning coal particles tend to float. Because of this, foam or CO 2 suppression systems are more suitable to combat baghouse fires.
As the baghouse operates as a filtering medium, unlike the electrical charge process of an electrostatic precipitator (ESP), its removal efficiency remains consistent across various ash properties. This is a prominent factor that has increased baghouse popularity vs. ESPs.
Upon the announcement of the original Clean Air Act (Air Quality Act, 1967) regulations and subsequent amendments in the 1960s and 1970s, many plants were required to install scrubbers to remove sulfur dioxide from boiler flue gas, particularly if the desire was continued use of Eastern and Midwestern bituminous coal.
Initially, the most popular method was wet-limestone scrubbing. A generic flow diagram of a spray-type, wet-limestone scrubber is provided below.
This process exemplifies an aqueous acid-base chemistry reaction implemented on an industrial scale. Unlike most laboratory experiments, however, both the acid and the base do not initially exist in liquid form. SO 2 is a gas and limestone is a solid, thus additional steps are required to induce and maximize the chemical reactions.
Sulfur dioxide is first absorbed into the liquid phase as it contacts the slurry sprays.
SO 2 + H 2 O ⇌ H 2 SO 3 _Eq. 5_
Some theoretical chemists contend that true H 2 SO 3 does not exist, asserting instead that SO 2 retains its molecular character and is surrounded by water molecules. However, when SO 2 is added to water, the pH drops, which indicates that Eq. 5 is correct and the following dissociation reaction is accurate.
H 2 SO 3 ⇌ H+ + HSO 3– ⇌ H+ + SO 3 2–_Eq. 6_
Another argument for the formation of H 2 SO 3 and its dissociated products, bisulfite (HSO 3–) and sulfite (SO 3 2–) ions, is based on the observation that calcium carbonate (CaCO 3), the principal component of limestone, is only slightly soluble in water but will dissolve almost completely in well-designed scrubbing systems.
CaCO 3+ H+→Ca 2++ HCO 3–_Eq. 7_
Combining Eqs. 5, 6, and 7 illustrates the fundamental scrubbing process.
CaCO 3 + 2H+ + SO 3 2– → Ca 2+ + SO 3 2– + H 2 O + CO 2↑_Eq. 8_
In the absence of any other reactants, calcium and sulfite ions will precipitate as a hemihydrate, where water is included in the crystal lattice of the scrubber byproduct.
Ca 2++ SO 3 2–+ ½H 2 O→CaSO 3·½H 2 O↓_Eq. 9_
Proper operation of a scrubber is dependent upon the efficiency of the above-listed reactions. pH control with reagent feed is particularly important. Many wet-limestone scrubbers operate at a solution pH of around 5.6–5.8. An overly acidic scrubbing solution hinders the transfer of SO ₂ from gas to liquid. Conversely, if the pH rises to 6.0 or higher, it indicates an overfeed of limestone.
Oxygen in the flue gas significantly influences chemistry. Aqueous bisulfite and sulfite ions react with oxygen to produce sulfate ions (SO 4 2–).
2SO 3 2– + O 2 → 2SO4 2–_Eq. 10_
Approximately the first 15 mole percent of sulfate ions co-precipitate with sulfite to form calcium sulfite-sulfate hemihydrate [(0.85CaSO 3·0.15CaSO 4)·½H 2 O]. Any sulfate above the 15 percent mole ratio precipitates with calcium as gypsum (CaSO 4·2H 2 O).
Ca 2++ SO 4
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