ENCYCLOPEDIA OF ENVIRONMENTAL SCIENCE AND ENGINEERING - FLUIDIZED BED COMBUSTION pps

402 F FLUIDIZED BED COMBUSTION INTRODUCTION The technology for reacting suspended coal particles with a gas fl owing through them dates back to the 1920s when the Winkler gas generator was developed in Germany. The petroleum industry was responsible for the commercial expansion of fl uidization techniques in the U.S. (1940s), particularly in the use of solids which catalytically crack vaporized heavy oils to produce gasoline and other petro- leum fuels. The application of fl uidized bed combustion (FBC) technology (to various solid fuels) is widespread in the U.S. and in other countries for all types of industrial processes. More than 350 atmospheric fl uidized bed units are operating in North America, Europe and Asia. FBC is part of the answer to the question—how do we control our major emissions from coal sources? Briefl y an FBC boiler is a fi nely divided bed of solid fuel particles in admixture with limestone particles which are suspended or conveyed by primary combustion air moving in the vertical upward direc- tion. The limestone reacts with sulfur dioxide to remove it from the fl ue gas. The low uniform temperature (ca 1550ЊF) has a benefi cial effect on nitrogen oxide suppression. The emission from coal combustion schemes of nitrogen oxides (NO x ) and sulfur dioxide (SO 2 ), together with carbon oxides (CO and CO 2 ), particulate matter and solid wastes must always be compared when evaluating various alternative schemes. The potential consequences of gaseous emissions, include the greenhouse effect and acid rain, which have received much publicity in recent years. The practical FBC limit of SO 2 removal is currently about 95%. Nitrogen oxide formation is lower than with conventional pulverized coal (PC) boiler NO x control. TYPES OF FLUIDIZED BED COMBUSTORS (FBCS) FBCs are generally referred to as either circulating (CFB) or bubbling beds. However, the bubbling type may be classifi ed according to whether reaction takes place at atmospheric (AFB) or under pressurized conditions (PFB). A. Circulating Fluidized Bed Combustors In the basic CFB combustor, coal or some other type of fossil fuel, e.g., natural gas or petroleum, is injected into the com- bustor together with a calcium based material such as lime- stone or dolomite to be used as a sorbent for SO 2 . The bed material is entrained by fl uidizing air usually in the velocity range of 12–30 ft/sec. The entrained material is forced into a refractory-lined cyclone located between the combustor and the convective pass. The separated larger particles are reintroduced at the bottom of the combustion chamber or, as in some designs, to an external heat exchanger. The mean bed particle size is usually between 50 and 300 microns. Combustion temperature will vary but generally is kept between 1550ЊF and 1650ЊF. 1 In this temperature range SO 2 sorption is optimized and the formation of nitrogen oxides is minimized. The heavier solids fall to the bottom of the cyclone and are recirculated at a ratio of between 15:1 and 100:1 (solids to feed). The carbon content of the bed is usually about 3–4%. Calcium sulfate, ash, and calcined limestone make up the bulk of the recirculated material. The fl ue gas exits the top of the cyclone, travels through the convective pass and typically goes into an economizer (heat exchanger—superheated steam produced) and into a tubular air preheater. From there the gas may enter an electrostatic precipitator or a bag house dust collector (for removal of fi ne particulate matter from the gas). An induced draft fan is fi nally employed to force the gas up a stack and into the atmosphere. Combustion air is provided at two levels of the combus- tor. Primary air enters through the bottom of the combustor and is evenly distributed by a gas distributor plate. Secondary air enters through a number of ports in the sidewalls of the combustor. Hence, there are two staged areas of combustion within the combustor. In the lower combustor, combustion takes place under reducing conditions. In the upper com- bustor nitrogen oxides are further reduced as is particulate matter. The admission of secondary air is also benefi cial in controlling the temperature of the combustor as well as in © 2006 by Taylor & Francis Group, LLC FLUIDIZED BED COMBUSTION 403 maintaining the transport (entrainment) of the bed material throughout the length of the combustor. The density of the bed naturally varies with the combustor height, with density increasing towards the bottom. Steam may be produced at several locations. Water-walls fi xed to the upper portion of the combustor extract heat gen- erated by the combustor. The convective pass also emits heat associated with the hot fl ue gas and solids which pass through it. External heat exchangers are also employed for the steam production. These heat exchangers (EHE’s) are unfi red, dense fl uidized beds, which extract heat from the solids which fall to the bottom of the cyclone(s). More than one cyclone may be employed. The heat exchange is accom- plished before the material is returned to the combustor. The external heat exchanger is a device which can, thus, be used as an effective additional method for controlling combustor temperature. The heat transfer coeffi cients to the water-walls usually lie between 20 and 50 Btu/hr. ft. 2 ЊF. B. Bubbling Fluidized Bed Combustors Bubbling fl uidized bed combustors are characterized by distinct dense beds. The bed material may be recirculated as in the case of CFB’s, but at substantially lower recycle ratios (between 2:1 and 10:1). Particle velocities are usu- ally between 2–15 ft/sec and a small amount of bed material is separated out (elutriated) as compared with CFB’s. The mean bed particle size generally lies between 1000 and 1200 microns. As with CFB’s, the fuel used is usually coal or some other type of fossil fuel. Limestone or some other sorbent material is also used to decrease SO 2 emissions. The feed material may be fed either over the bed or under the bed. The manner of the feeding is an important design criterion in that it effects boiler control, emissions control (especially for SO 2 ) and combus- tion effi ciency. Many bubbling bed designs incorporate over- bed feeding in which the feed is “thrown” into the combustor by pressurized air. This overbed method can often be a disad- vantage because throwing distance is limited. Hence, a long, narrow boiler is often required. The underbed method of feeding is often associated with plugging and erosion problems. However, these problems can be avoided with proper design considerations. The Tennessee Valley Authority (TVA) has designed a 160 MW bubbling bed unit at its Shawnee station in Kentucky. The facility was constructed at a cost of $232,000,000 (1989). EPRI believes that most retrofi ts would fall into the $500–1000/kW range (1989 dollars) and that the levelized generation cost would be 5–10% less than a conventional unit with downstream fl ue gas treatment. 1a The coal used for this unit is crushed to less than ¼ inch and dried with fl ue gas to less than 6% moisture. The fuel then passes through a fl uidized bottle splitter with a central inlet and fuel lines arranged concentrically around the inlet. The feed material is forced into the combustor from the bottles, which are pressurized, by blowers. Each bottle acts as an individual burner and can be used to control load in the same way as cutting a burner in and out. 2 When overbed feeding is used, the fi ne material in the fuel has a tendency to elutriate too swiftly. If the fuel is fed underbed, the fi nes will have a longer residence time. Excess CO generation can result with the excessive burning of fi nes. This in turn can lead to overheating which could cause superheater controls to trip-off. Ash-slagging is another potential problem asso- ciated with overheating. Sometimes it may be necessary to recycle the fl y-ash in order that carbon is more thoroughly burned and sorbent more completely utilized. In-bed combustor tubes are generally used to extract heat (create steam). The heat transfer coeffi cient range is higher than that of CFB’s, i.e., 40–70 Btu/hr.ft 2 ЊF. Erosion of the tubes is a problem which is ever present in the bubbling bed combustor. The problem worsens as bed particle velocity increases. Horizontally arranged tubes are more susceptible to erosion than are vertical tubes. Various methods of erosion protection include metal spray coatings, studding of the tube surfaces with small metal balls, and wear fi ns. Occasionally recycled cold fl ue gas is used in lieu of tubes. Waterwalls located in the upper portion of the combustor are also used (as with CFB’s) to extract heat. The lower portion is refractory lined. Combustor free-board is usually between 15 and 30 ft. The typical convective pass, cyclone, air heater, particle separator scenario closely resembles that of the CFB. C. Pressurized Fluidized Bed Combustors (PFBCs) The pressurized fl uidized bed combustor is essentially analo- gous to the bubbling bed combustor with one exception—the process is pressurized (10 to 16 atmospheres) thereby allow- ing the fl ue gas to drive a gas turbine/electric generator. This gas turbine along with a stream-driven turbine creates a very effi cient “combined cycle” arrangement. PFBCs may also be “turbocharged,” i.e., before the fl ue gas enters the gas turbine, heat is extracted via a heat exchanger. Steam created by the energy transfer is used to drive the compressor which pressurizes the system. There is no energy excess to drive an electric generator in this case. Deeper beds (typically 4 m.) may be used in PFBCs because they are pressurized. The residence time of a parti- cle in the bed is longer than that of a particle in the shallower bed of a bubbling bed combustor. The fl uidizing velocity (typically 1 m/s) is also lowered because of pressurization. As mentioned before, lower velocities minimize the amount of in-bed tube erosion. Two other benefi ts of pressurization are a reduced bed cross-sectional area and reduced boiler height. Since combustor effi ciency and sorbent utilization are excellent, recycle is rarely needed. However, when very unre- active fuels are burned, recycling of fi nes may be necessary. Since PFBCs are pressurized, certain design character- istics must be taken into consideration, especially in regard to the gas turbine. This turbine supplies the combustion and fl uidizing air for the bed. Unlike conventional AFBC’s the turbine inlet air is dependent upon certain temperature and pressure conditions since this inlet air is actually the exhaust gas from the combustor. To compensate for variations in load and subsequent changes in the exhaust gas conditions the gas © 2006 by Taylor & Francis Group, LLC 404 FLUIDIZED BED COMBUSTION turbine must be fl exible. An effective turbine should be able to accept low gas temperatures, be minimally affected by unremoved fi nes in the gas, compensate for low load condi- tions, and allow the gas velocity through the hot gas clean up (HGCU) system and excess air to remain near constant over much of the load range. Most FBC systems incorpo- rate a free-wheeling low pressure and constant velocity high pressure shaft design to accomplish the aforementioned requirements. The HGCU system generally consists of one or several cyclones. Sometimes a back-end fi lter at conven- tional pressuers and temperatures is used in addition. The gas turbine accounts for approximately 20% of a FBC’s total power output while the steam turbine creates the remainder. 5 The steam turbine is powered from steam created via combustor tubes and is totally independent of the exhaust gas and gas turbine. Steam turbine perfor- mance is therefore only affected by fuel/feed conditions. Two types of fuel feeding are generally used for FBC’s— dry and wet. For fuels with high heating values the fuel is mixed with water to create a paste (20–25% water). With this method there is naturally no need for coal drying, and evaporated water creates additional mass fl ow through the gas turbine. Dry fuel feeding is more benefi cial with low heating value fuels. FEDERAL AIR EMISSIONS STANDARDS The standards of performance for fossil-fuel-fi red steam gen- erators (constructed after August 17, 1971) were last revised by the federal government as of July 1, 1988. Regulated facilities include fossil-fuel-fi red steam gen- erating units of more than 73 megawatts (heat input rate 250,000,000 Btu/hr.) and fossil-fuel and wood-residue-fi red steam generating units capable of fi ring fossil fuel at a heat input rate of more than 73 megawatts. Existing fossil-fuel-fi red units which have been modifi ed to accommodate the use of combustible materials other than fossil fuels are regulated in a different manner. Within 60 days after the maximum production rate is attained by a regulated facility, the facility must conduct performance tests and provide the E.P.A. with the results of the tests. The tests must also take place before 180 days after the initial start-up of a facility. Each test is specifi c and used for the determination of such things as nitrogen oxide emis- sion. These test methods and procedures may be found in 40 C.F.R. (Code of Federation Regulations) Part 60.46. 6 After a performance text is completed, a facility must not discharge pollutants into the atmosphere at levels greater than those established and listed in the federal regulations. Gases may not contain more than 43 nanograms of par- ticulate matter per joule heat input (0.10 lb. per million Btu) where particulate matter is defi ned as a fi nely divided solid or liquid material, other than uncombined water as measured by the reference methods specifi ed in 40 C.F.R. Part 60.46. These gases must also not exhibit greater than 20% opac- ity except for one six-minute period per hour of not more than 27% opacity. Opacity is defi ned as “the degree to which emissions reduce the transmission of light and obscure the view of an object in the background.” Less stringent standards have been developed for the three following facilities. 6 The Southwestern Public Service Company’s Harrington Station No. 1 in Amarillo, Texas must meet an opacity of not greater than 35%, except that a maximum of 42% opac- ity is permitted for not more than six minutes in any hour. The Interstate Power Company’s Lansing Station Unit No. 4 in Lansing, Iowa must meet an opacity of not greater than 32%, except than a maximum of 39% opacity is permitted for not more than six minutes in any hour. The Omaha Public Power District’s Power Station in Nebraska City, Nebraska must meet an opacity of not greater than 30%, except that a maximum of 37% opacity is permitted for not more than six minutes in any hour. Gases may not contain more than 30 nanograms per joule heat input (0.80 lb. per million Btu) of sulfur dioxide (SO 2 ) derived from liquid fossil fuel or liquid fossil fuel and wood residue. 520 ng/joule heat input (1.2 lb. per million Btu) is the maximum allowable SO 2 discharge from gases derived from solid fossil fuel or solid fossil fuel and wood residue. When different fossil fuels are burned simultaneously in any combination, the SO 2 emission standard is calculated by the following formula: PS so 2 ϭϩ ϩ(( ) ( ))/( )y 340 520zyz where PS so 2 is the prorated standard in ng/joule heat input derived from all fossil fuels or fossil fuels and wood resi- due fi red, y is the percentage of total heat input derived from liquid fossil fuel, and z is the percentage of total heat input derived from solid fossil fuel. The SO 2 emission standard for Units 1 and 2 at the Central Illinois Public Service Company’s Newton Power Station must comply with the 520 ng/joule requirement if the units individually comply with the 520 ng/joule require- ment or if the combined emission rate from both unites does not exceed 470 ng/joule (1.1 lb/million Btu) combined heat input to both units. It is interesting to note that the federal SO 2 emission limit for West German coal fi red boilers is 2.5 lB./Mbtu (avg.) for boilers of between 18 and 110 MW and 0.51b./MBtu (avg.) for boilers of over 110 MW. 7 Gases may not contain more than 86 ng/joule heat input (0.20 lb/million Btu) of nitrogen dioxide (NO 2 ) derived from gaseous fossil fuel. 129 ng/joule heat input (0.30 lb/million Btu) is the maximum allowable NO 2 discharge from gases derived from liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue. 300 ng/joule (0.70 lb/million Btu) is the maximum allow- able NO 2 from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fossil fuel containing 25%, by weight, or more of coal refuse). 260 ng/joule (0.60 lb/ million Btu) is the maximum allowable NO 2 from lignite or lignite and wood residue with the exception that 340 ng/ © 2006 by Taylor & Francis Group, LLC FLUIDIZED BED COMBUSTION 405 joule is the limit for lignite which is mined in North Dakota, South Dakota, or Montana and which is burned in a cyclone fi red unit. When different fossil fuels are burned simultaneously in any combination, the nitrogen oxide emission standard is calculated by the following formula: PS NO x wxyz wxyz ϭ ϩϩ ϩ ϩϩϩ ()()()() . 260 86 130 300 Where PS NO x is the prorated standard in ng/joule heat input for nitrogen oxides (except nitrous oxide) derived from all fossil fuels or fossil fuels and wood residue fi red, w is the percentage of total heat input derived from lignite, x is the percentage of total heat input derived from gaseous fossil fuel, y is the percentage of total heat input derived from liquid fossil fuel and z is the percentage of total heat input derived from solid fossil fuel (except lignite). There is no standard for nitrogen oxides when burning gaseous, liquid, or solid fossil fuel or wood residue in com- bination with a fossil fuel that contains 25%, by weight, coal refuse. Coal refuse is defi ned as “the waste products of coal mining, cleaning and coal preparation operations (e.g., culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.” 6 The NO x emission standards for West Germany and Japan are even more stringent than those of the U.S. 7 For new and existing West Germany boilers of over 110 MW, the limit is 0.16 lb./MBtu (6% O 2 ). For Japanese boilers built after 1987, the limit is 0.33 lb./MBtu. PROMINENT FBC INSTALLATIONS IN THE U.S. Recently, in order to reduce SO 2 emissions, Northern States Power Company (NSP) converted its Black Dog pulverized coal-fi red boiler to that of a bubbling bed combustor. This unit is the largest of its kind in the world; its capacity is 130 megawatts. NSP received a new Emissions Permit from the Minnesota Pollution Control Agency (MPCA) for the upgraded unit. The emissions standards set forth in this permit are less strin- gent than those of the federal standards for particulate matter and SO 2 . In the event that utilities should become regulated, the operating parameters of the system or the system itself would have to be modifi ed. 10 The most recent literature available to the author (April 1988) stated that limestone was being added to the bed in order to lower SO 2 emissions suffi ciently to help NSPS stan- dard. The control of particulate matter was diffi cult at the onset. However, this problem was resolved by changing the bed material to an inert fi red-clay material. NO x emissions requirements have easily been met. The Tennessee Valley Authority (TVA) has built a 160 MW bubbling bed combustor for the utility’s Shawnee steam plant in Paducah, Kentucky. It has been operating sporadi- cally since autumn of 1988. A pilot plant (20 MW) was completed in 1982 and had brought forth some very promising results. With a Ca : S ratio of 2 to 2.5 (typical range) and a recycle ratio of 2 to 2.5 the SO 2 retention was approximately 90%. 11 This result has been matched by the scaled-up plant. The pilot plant has both an underbed and overbed feed system. Overbed feed does not produce as great a combustion effi ciency as that achieved by the underbed method. This would be expected due to the lack of control over fi nes in the feed. NO x emissions were less than 0.25 lb/million Btu. 11 The NSPS for NO x is 0.7 lb/million Btu for solid fuel. The original underbed feed system was determined to be inadequate because of plugging and erosion problems. The system was redesigned and proved to be successful. The feed system is one of pressurized bottles mentioned earlier in this report under “Bubbling Bed Combustors.” As stated in the “Introduction,” fl uidized bed combus- tion can be used for many different types of industrial pro- cesses. An example of this is the installation of the direct alkali recovery system at Associated Pulp and Paper Mills’ Burnie, Tasmania mill. In this process, sodium carbonate (residual) found in soda-quinone black liquor (a waste product) reacts with ferric oxide to produce sodium ferrite in the combustor (bub- bling bed). The sodium ferrite is then contacted with water to yield sodium hydroxide (desired) and ferric oxide. The ferric oxide is returned to the combustor to be reused. It is interest- ing to note that most of the steam produced in this process is created from the extraction of heat from the exhaust gas and not from bed tubes. The exhaust gas is cleaned via a fabric fi lter and the dust collected is palletized. The pellets are later used in the process. The fl uidizing air is heated from the heat extracted from the hot sodium ferrite after it has been removed from the combustor. Since there is no sulfur involved in this process the exhaust gas is easily cooled, thereby allowing greater pro- duction of high-pressure steam. 13 The title for the world’s largest CFB probably belongs to the nuclear generating station owned by Colorado-Ute Electric Association. The original 25-year-old plant was replaced because it was uneconomical to operate. The capac- ity of the new plant is 110 MW. In May of 1988 on EPRI (Electric Power Research Institute) assessment began and is scheduled to continue until May of 1990. As of April 1988, the unit was reported to be easy to operate, responsive to load variations, and easily restarted following a trip. However in 1989 opera- tional diffi culties were reported. SO 2 emissions standards were expected to be easily met and NO x emissions were well under the limit. Final determination of the optimum Ca : S ratio still needed to be determined. Particulate matter emissions are expected to be less than 0.03 lbs/million. Btu because of the addition a new baghouse to the existing three baghouses. Some valuable information has been learned from the unit thus far, e.g., control of coal feed size has been impor- tant in maintaining the bed quality and agglomerations can be avoided if the feed is started in short bursts prior to being © 2006 by Taylor & Francis Group, LLC 406 FLUIDIZED BED COMBUSTION continuous; this is to allow the temperature rise to be more uniform. 14 One of the larger commercial units in the U.S. is located in Colton, California and was installed for Cal-Mat Co. The 25 MW CFB was constructed because electric utility rates were rising and the availability of power was uncertain. The company manufactures cement—a process requiring much electricity. Since the company had easy access to coal and limestone as well as a large quantity of heat from its kilns, CFB technology became an effective solution to their energy needs. Bottom ash waste and fl yash could also be used in the cement-making process. As could be expected, the air pollution controls instituted by the state of California are very strict. However, a permit was granted to CalMat in a relatively short period of time because of the fi ne performance demonstrated by this unit. The exhaust gases were found to contain SO 2 at 30 lb/hr., NO x at 57 lb/hr. and CO at 24 lb/hr. 15 There were initial problems with equipment and systems, however, these were eventually eliminated. Bed retention and temperature control problems have also been resolved through modifi cations of the air fl ows and nozzles. PFBC’s have been installed in Sweden, the U.S. and Spain. Two PFBC modules of 200 MW each have been installed in Vartan, Stockholm. The fi rst unit is due for start-up in late 1989. The Swedish emission standards are very strict and include special restrictions on noise and dust since the units are located very close to a residential area. A 200 MW combined cycle PFBC will be installed by American Electric Power (AEP) at its Tidd Power Plant at Brilliant, Ohio. Test results from joint studies proved PFBC technology to have environmental benefi ts surpassing those of traditional boilers with fl ue gas desulfurization systems (FGD), selective catalytic reduction, etc. A 200 MW PFBC will be installed by Empresa Nacional de Electricidad S.A. (ENDESA) at its Escatron Power Plant as a retrofi t for an existing unit. 90% sulfur removal and a NO x decrease of 30% are expected. Many different technolo- gies were considered but PFBC was chosen because of the high sulfur/ash/moisture black lignite coal that they burn. 16 NO X /SO 2 FORMATION AND CONTROL Fossil fuels naturally contain sulfur in varying percentages. As fuel is burned the sulfur combines with oxygen to form SO x , and primarily, SO 2 . When emitted into the atmosphere this SO 2 can combined with water vapor to form sulfuric acid (and sulfurous acid to a lesser extent). This is a part of the basic mechanism by which acid rain is created. In order to control sulfur dioxide emissions, the oldest and still most common method used is to react the gas with limestone or a similar calcium based material. Crushed lime- stone (CaCO 3 ) can be fed continuously to a conventional coal boiler or fl uidized bed where it calcines to lime (CaO) and then reacts with SO 2 in the presence of oxygen to form calcium sulphate (CaSO 4 ). This material precipitates to the bottom of the combustor and is removed. Coal particle size has a defi nite impact on desulfuriza- tion. Bed composition also has an effect on sulfur removal. A typical bed might be composed of coarse partially sul- fated limestone and ash (produced by combustion). The par- ticle size of the coal and limestone would probably be equal however combustor operation conditions such as fl uidizing velocity will dictate the particle size. An alternate scenario might be to pulverize the limestone and introduce it to a bed composed of ash or some other type of refractory material. Fines naturally have shorter residence times than do coarse materials and, hence, would probably have to be recycled to increase effi ciency. A series of experiments were carried out by Argonne National Laboratory 17 using three different types of lime- stones to test their effects on sulfur capture during com- bustion. The average particle size of the limestone was 500–600 micrometers. The Ca : S ratio was 2.3–2.6 and the combustion temperature was 1600ЊF. SO 2 removal was 74 to 86%. The test proved that the amount of SO 2 removal was relatively independent of the type of limestone used. The test also proved that particle size did not have much of an effect on SO 2 removal. The explanation offered for this observation was that although larger particles are less reac- tive than smaller particles, the increased residence time in the combustor of larger particles compensates for the lower reactivity. Dolomite was also evaluated for SO 2 capture. In two experiments, Tymochtee dolomite was added to a bed composed of alumina at Ca : S ratios of 1.5 and 1.6. The average particle size was 650 micrometers. The SO 2 remov- als were 78% and 87% respectively. MgO is contained within the dolomite matrix and is believed to keep the par- ticles more porous such that sulfation is greater, especially in larger particles. Combustion temperature had a marked effect on SO 2 removal in these experiments. Dolomite No. 1337 was most effective in reducing SO 2 at 1480ЊF. Limestone No. 1359 was most effective in the range of 1500–1550ЊF. Both sorbents achieved approximately 91% SO 2 removal. The average particle size was approximately 500 micrometers. Pulverized limestone No. 1359 with an average particle size of 25 micrometers was most effective in the range of 1550– 1600ЊF. The extent of calcination is more dependent upon bed temperature for fi nely pulverized limestone. The greater the calcination, the greater the reactivity with SO 2 . An unusual fi nding occurred in that Tymochtee dolomite was observed to be most effective in SO 2 removal at 1800ЊF. For all of the other sorbents the SO 2 removal was very poor at this temperature. Explanations for this phenomenon have been proposed. One explanation suggests that above a certain temperature the sorbent’s pores close thereby ending sulfona- tion. Depending upon the sorbent’s structure and composition, this temperature would be different for each sorbent. Another explanation involves the effect of fl uidized bed gas circulation on bed chemistry. An emulsion phase and a gas bubble phase © 2006 by Taylor & Francis Group, LLC FLUIDIZED BED COMBUSTION 407 exist in any gas-solid fl uidized bed. Excess gas which is not needed for fl uidization circulates back and forth between the two phases. This gas does not react with the sorbent until it reaches the emulsion phase. All of the oxygen in the lower portion of the emulsion phase reacts with the fuel to from CO. As the bubbles rise through the bed, air exchanges between the bubbles and the emulsion phase. The upper portion of the emulsion phase contains excess oxygen. The following reac- tion was thus proposed as one which takes place in the lower portion of the combustor: CaSO CO CaS CO 42 ϩϩ4 U 4 . (1) One or more of the following reactions were proposed to occur in the upper portion of the combustor: CaS 1 O CaO SO 22 ϩϩ 1 2 U (2) CaS CaO SO 2 ϩ 344CaSO 4 U ϩ (3) CaS CaSO 4 ϩ 2O 2 U . (4) Reactions 2 and 3 would limit the unit’s ability to remove sulfur because of the regeneration of SO 2 . This regeneration of SO 2 is so dependent upon temperature that it could very possibly be an explanation as to why SO 2 removal generally suffers at high temperatures. Nitrogen also occurs naturally in fossil fuels. This nitro- gen reacts with oxygen during combustion and later forms acid rain in very much the same manner as with sulfur. Oxides of nitrogen (NO x ) are also responsible for the cre- ation of “smog.” As nitrogen dioxide (NO 2 ) absorbs light of certain wavelengths it dissociates photochemically to form nitric oxide (NO) and atomic oxygen. This atomic oxygen is very reactive and readily combines with O 2 to from ozone (O 3 ). Ozone in turn oxidizes hydrocarbons in the air to form aldehydes. Ozone and the aldehydes are components of smog. NO 2 is the reddish-brown gas which can often be seen on the horizons of cities such as Los Angeles. The principal oxide of nitrogen formed during com- bustion is nitric oxide. Nitrogen in the fuel combines with oxygen in the fl uidizing air as follows: 1 2 1 2 N O NO. 22 ϩ U The kinetics of NO decomposition are slow enough so that equilibrium levels are not achieved. Various experiments conducted by Argonne National Laboratory as well as by other researchers have proven that most of the nitrogen forming NO x is from the fuel and not from the air. This has been easily demonstrated by substituting an inert gas (such as argon) for nitrogen in the fl uidizing air and then comparing the results to those of combustion with standard fl uidizing air. As previously mentioned in this report two-stage com- bustion is an effective method of decreasing NO x emissions. As with SO 2 reduction bed composition has an important effect on NO x . It has been determined through experimenta- tion and experience that limestone also decreases NO x emis- sions. Skopp and Hammons 18 observed that when using a limestone bed two factors were changing with time which could have been responsible for decreasing NO emissions: the CaSO 4 concentration in the bed was increasing and so was the SO 2 concentration. The increase in CaSO 4 sug- gested that it could be a selective catalyst for reduction of NO. The increasing SO 2 concentration suggested that there might be a reaction occurring between it and the NO which was lowering the NO. This was investigated by conduct- ing experiments using synthetic NO—SO 2 —N 2 gas mix- tures. The results showed that no reaction in the gas phase occurred. There was also no reaction between the NO and SO 2 over CaSO 4 . However, there was a reaction occurring over a bed of 20% sulfated lime. This reaction was found to have a negative temperature dependence. The following mechanism was proposed by Skopp and Hammons 18 as an explanation for their results: CaO SO CaSO 23 ϩ U CaSO NO CaSO (NO 332 ϩ 2 U ) CaSO (NO CaSO N O 32 42 ) U ϩ NO N O 222 U ϩ 1 2 . Esso researchers investigated the possibility of NO being produced by CO catalyzed by CaSO 4 . The rate of this reac- tion was found to increase with increasing temperature. Argonne researchers 17 investigated the use of metal oxides, among them, aluminum oxide (Al 2 O 3 ), zirconium oxide (ZrO 2 ) and cobalt oxide (Co 3 O 4 ). At the time these experiments were conducted, the literature had indicated that these metal oxides were effective in reducing or catalytically decomposing NO. The results showed that the addition of Al 2 O 3 and ZrO 2 did nothing to reduce NO formation during combustion in a fl uidized bed. The addition of Co 3 O 4 actu- ally increased rather than decreased the formation of NO. A study was conducted by McCandless and Hodgson 20 for the U.S.E.P.A. on the use of metal sulfi des as a way to reduce NO emissions. The following is well known as the “Thiogen” process and has been used in the recovery of sulfur from SO 2 CaS 2SO CaSO S 242 ϩϩU 4CaS SO CaSO S 232 ϩϩ64 3U . Based on this process it was determined that the following reaction might also be possible CaS 4NO CaSO 2N . 42 ϩϩU © 2006 by Taylor & Francis Group, LLC 408 FLUIDIZED BED COMBUSTION Preliminary studies indicated that the reaction did pro- ceed and could be an effective method for NO x control. Nineteen metal sulfi des were used. All but one reduced NO to N 2 at temperatures between 194ЊF and 1202ЊF. However, a weight loss did occur indicating that an undesirable side reaction was taking place—probably the formation of SO 2 . Some metal SO 4 was formed in most of the tests. However, the alkaline earth sulfi des were determined to be the most stable. It was also found that the temperature at which the reduc- tion reaction occurs can be lowered if certain catalysts such as NaF and FeCl 2 are mixed with the sulfi des. Reaction tem- perature was again reduced when the sulfi de/catalyst combi- nation was impregnated on alumina pellets. Tests were also conducted involving synthetic fl ue gas containing 1000 ppm NO, 1% O 2 , 18% CO 2 and the remainder N 2 . Using this gas in combination with the CaS showed that NO was signifi - cantly reduced above temperatures of 1112ЊF, by using the sulfi de/catalyst combination. The results of the experiments showed that between 0.372 and 0.134 grams of NO were reduced per gram of metal sulfi de. Between 0.76 and 0.91 grams was achieved when using the impregnated alumina pellets. The authors recommended that more research be done to evaluate the economical implications of using these materials. Several other interesting facts known about NO x con- trol and found in the literature are that increasing fl uidizing velocity decreases NO x , NO x is not signifi cantly affected by excess air, and NO x production increases at lower tempera- ture, especially below approximately 1500ЊF. For conventional coal-fi red boilers the most common approach to control NO x and SO x simultaneously is the combination of selective catalytic reduction (SCR) and wet- limestone or spray dryer fl ue gas desulfurization (FGD). The SCR process converts NO x to N 2 and H 2 O by using ammo- nia as a reducing agent in the presence of a catalyst. The catalytic reactor is located upstream from the air heater and speeds up the reaction between the NO x and the ammonia, which is injected into the fl ue gas in vapor form immediately prior to entering the reactor. The reduction reactions are as follows: 21 44 46NH NO O N H O 3222 ϩϩ ϩU 42 36NH NO O N H O. 32222 ϩϩ ϩU It can be seen that the amount of NO 2 removed primarily depends on the amount of NH 3 used. Although SCR technol- ogy has proved to be an effective means to reduce NO x with removal results as high as 90% in some European facilities, the U.S. does not consider the technology economically fea- sible. In addition to the high cost there are the undesirable effects of unreacted NH 3 , by-product SO 3 and increased CO production to consider. There are also catalyst deactivation problems caused by contamination by trace metals in the fl y ash and by sulfur poisoning. The Japanese have improved on the design of catalysts and their arrangement within the reactor. However, these modifi cations are still too new to evaluate their merit. 22 U.S. industry also feels that more data has to be generated for the medium to high sulfur coals most commonly used in this country. Since characteristics such as high sulfur, low fl yash alkalinity and high iron content are common in U.S. coal, and these qualities do infl uence SO 3 production, SCR would not appear to be one of the likely options for U.S. industry at least in the near future. Exxon has developed a process called “Thermal deNO x ” which makes use of ammonia injection into the fl ue gas at temperatures of between 1600 and 2200ЊF. This process is claimed to remove NO x by up to 90%. years, CFB’s have become the dominant FBC choice in industry. The most common problems that have been associated with bubbling beds include erosion of the inbed tubes. This can be reduced through the use of studding, fi ns, etc. as previously men- tioned in this report. However, CFB’s are also prone to ero- sion, i.e., the waterwalls, as well as the refractory lining. Agglomeration is another common problem associated with bubbling beds. Sand can fuse in localized hot spots to form clinkers or “sand babies” especially when the fuel has a high concentration of alkali compounds. 9 In severe cases, agglomerations can cause the bed to defl uidize, block air ports, and make bed material removal more diffi cult. Sulfur removal is more diffi cult with bubbling beds. In general, large quantities of double-screen stoker coal must be used to attain the high sulfur removal rate displayed by CFB’s. Most overbed feed bubbling beds in existence must use coals which contain less than 10% fi nes. This can often be quite costly. As previously mentioned, underbed feed also has problems associated with it. Since low fl uidizing veloci- ties are required with underbed feed, the bed plan area must be larger and, subsequently, contain a higher density of feed ports. This serves to complicate the already unreliable feed system. In order to utilize the sorbent better, the recycle ratio has to be increased. However, above a certain recycle ratio, and in-bed tubes might have to be removed in order to maintain combustor temperature, compromising the CFB design. NO x control is better with CFB’s than with bubbling beds. This is because of the aforementioned stage combus- tion which is physically unachievable in bubbling beds due to the large bed plan area and low fl uidizing velocity. On average, 0.1 lb/million Btu less NO x is produced by CFB’s than by bubbling beds. As of the present, there are no federal regulations gov- erning CO emissions. However, some states have promul- gated regulations. As would be expected with overbed feed bubbling bed combustors, the CO emissions are high. While emissions of over 40 ppmv are common with bubbling beds, CFB’s are usually under 100 ppmv. 3 This is due to better circulation and recycle. There is not much data on CO emis- sions for underbed feed bubbling beds. However, it evidently reduces CO more than does overbed. Unfortunately, with CFB’s there is a trade-off between SO 2 /NO x and CO. Staged combustion will increase CO emissions as the primary to secondary air ratio becomes smaller. SCR/SNR specifi c to CO also may cause an increase in NO x . © 2006 by Taylor & Francis Group, LLC FLUIDIZED BED COMBUSTION 409 Other problems associated with bubbling beds are scale- up and turn-down. Scale-up is limited because of the feed distribution problem and turn-down is usually more frequent because of the erosion problem. Incidentally, it should have been mentioned before, that, in general, FBC’s take longer to start up and turn down than conventional boilers because of the large amounts of bed material which must be heated or cooled. The major advantage which PFBC’s hold over AFBC’s is that NO x , SO 2 , and CO are weakly linked. Thus, 60 mg/ MHJ NO x can be attained while at the same time only 50 mg/ MJ SO 2 (or less) and 10 mg/MJ (or less) CO are produced. Another advantage of PFBC’s is that the waste contains negligible lime, sulfi des, and sulfi tes. The decreased lime concentration makes the waste less reactive and probably renders it nonhazardous. The decreased sulfi tes makes the Concentration (wt percent) Component Test no.1 a Tex t no. 2 a Test no. 3 a Baghouse b Full-scale residues CaSO 4 26.1 31.6 21.7 27.7 26.1 CaS 0.8 0.6 0.7 5.2 0.45 Free CaO 24.8 28.3 24.7 15.7 23.5 CaCO 3 3.4 3.2 5.2 6.8 4.6 Fe 2 O 3 10.7 9.5 9.1 10.6 15.9 Other mainly SiO 2 and C 27.3 20.8 33.8 19.5 24.2 LOI c (corrected) 11.4 5.4 5.1 8.0 4.3 Sum 104.5 99.4 100.3 — 99.0 a Composite pilot-scale residues. b Calculated from TGA and other analyses. c LOI indicated loss on ignition. TABLE 1 Major chemical components of composite residues: pilot and full-scale CFBC units Pilot-scale composite residues Pilot-scale baghouse residue Full-scale residue Specific gravity 2.83–3.07 2.58 2.95 Mean size, D 50 mm 0.2 0.04 0.04 Optimum water content percent a 14.5–17.5 32 26.5–30.5 Unconfined compressive strength, kPa b Curing period, days 0 230–360 — — 3 — — 2470 7 150–290 — 4120 8 — 309 — 10 260–425 385 — 12 — 461 — 28 — — 4660 Freeze/thaw cycles 4 — 201 — 6 540–1020 Sample destroyed — 7 — — 3200 15 — — 880 a As determined by standard Proctor test. b Samples were cured at 100 percent relative humidity at 23 ± 2ЊC for periods shown. TABLE 2 Geotechnical properties of the pilot-scale rig composite and baghouse samples and full-scale unit residues © 2006 by Taylor & Francis Group, LLC 410 FLUIDIZED BED COMBUSTION material a good candidate for use in cement kilns and con- crete. The maximum sulfur content per ASTM standards is 1.2% by weight or 3.1% by weight as sulfi tes. The material has been found useful for building roads, manufacturing gravel and formed bricks or tiles, and for roofi ng and fl ooring material. 3 Other advantages of PFBC’s include compactness because of smaller bed requirements, plant cycle effi cien- cies of 40–42% and subsequent reduced fuel costs, and unit modularity for ease in increasing future capacity. 8 Disadvantages include in-bed tube erosion and potential damage to the gas turbine if the hot gas clean-up is ineffec- tive. It should be noted that the technology is too new to accurately assess its advantages versus its disadvantages. CHARACTERIZATION OF SOLID WASTES FROM FLUIDIZED BEDS The characterization and use of fl uidized-bed-combus- tion coal/limestone ash is discussed in the articles of Behr- Andres and Hutzler 23 and Anthony et al. 24 The former dealt with the use of the mixture in concrete and asphalt. The latter presented chemical and physical properties for the waste Hot-gas cleanup (HGCU) technologies have emerged as key components of advanced power generation technologies such as pressurized fl uidized-bed combustion (PFBC), and integrated gasifi cation combined cycle (IGCC). The main difference between HGCUs and conventional particulate removal technologies (ESP and baghouses) is that HGCUs operate at higher temperatures (500 to 1,000ЊC) and pres- sures (1 to 2 MPa), which eliminates the need for cooling REFERENCES 1. Robert H. Melvin and Reid E. Bicknell, “Startup and Preliminary Operation of the Largest Circulating Fluid-Bed Combustion Boiler in a Utility Environment—NUCLA CFB Demonstration Project,” Paper Presented at the 50th American Power Conference, Chicago, Illinois, April 18–20, 1988 p. 2. 2. Jason Makansi and Robert Schweiger, “Fluidized-bed boilers,” Power, May 1987, p. 9. 3. Efficiency and Emissions Improvements by Means of PFBC Retrofits (Finspong, Sweden: Asea PFBC Component Test Facility, S-61220, 1988), p. 2. 4. Taylor Moore, “Fluidized bed at TVA,” EPRI Journal, March 1989, p. 27. 5. Asea Babcock PFBC Update, 1, No. 3 (Fall 1988), n. pag. 6. Code of Federal Regulations, Vol. 40, Part 60, Revised as of July 1988. 7. Charles Sedman and William Ellison, “German FGD/DeNO x Expe- rience,” Presented at the Third Annual Pittsburgh Coal Conference, Pittrsburgh, Pennsylvania, September 1986. 8. Asea Babcock PFBC Update, 1, No. 2 (Summer 1988), n. pag. 9. Jason Makansi, “Users pause, designers wrestle with fluid-bed boiler scaleup,” Power, July 1988, p. 2. 10. David Osthus, John Larva, and Don Rens, “Update of the Black Dog Atmospheric Fluidized-Bed Combustion Project,” Paper Presented at the 50th American Power Conference, Chicago, Illinois, April 18–20, 1988, p. 1. 11. Bob Schweiger, ed., “Fluidized-bed boilers achieve commercial status worldwide,” Power, Feb. 1985, p. 9. 12. R.A. Cochran and D.L. Martin, “Comparison and Assessment of Cur- rent Major Power Generation Alternatives,” Presented at the Power-Gen Exhibition and Conference for Fossil and Solid Fuel Power Generation in Orlando, Florida, Boston, Massachusetts, Dec. 1988, p. 2. 13. Sheldon D. Strauss, “Fluidized bed keys direct alkali recovery,” Power, Feb. 1985, p. 1. 14. Melvin and Bicknell, p. 6 (see 1). 15. Bob Schweiger, ed., “U.S.’s largest commercial CFB burns coal cleanly in California,” Power, Oct. 1986, p. 2. 16. Efficiency and Emissions Improvement by Means of PFBC Retrofits, p. 10. 17. A.A. Jonke et al. , “Reduction of Atmospheric Pollution by the Appli- cation of Fluidized-Bed Combustion,” Argonne National Laboratory, Publication No. ANL/ES-CEN-1002, 1970, n. pag. 18. A. Skopp and G. Hammons, “NO x Formation and Control in Fluidized-Bed Coal Combustion Processes,” ASME Winter Annual Meeting, Nov./Dec., 1971. 19. Jason Makansi, “Meeting future NO x caps goes beyond furnace modi- fications,” Power, September 1985, p. 1. 20. Reduction of Nitric Oxide with Metal Sulfides, Research Triangle Park: U.S. E.P.A., EPA-600/7078–213, Nov. 1978, pp. 1–5. 21. Ibid, p. 3. 22. Ed Cichanowicz, “Selective catalytic reduction controls NO x in Europe,” Power, August 1988, p. 2. 23. Christina B. Behr-Andres and Neil J. Hutzler, “Characterization and use of fluidized-bed-combustion coal ash,” Journal of Environmental Engineering, November/December 1994, p. 1488–506. 24. E.J. Anthony, G.G. Ross, E.E. Berry, R.T. Hemings. and R.K. Kissel, “Characterization of Solid Wastes from Circulating Fluidized Bed Combustion”, Trans. of the ASME Vol. 117, March 1995, 18–23. JAMES SANDERSON Environmental Protection Agency Washington, D.C. FISH ECOLOGY: see POLLUTION EFFECTS ON FISH; THERMAL EFFECTS ON FISH ECOLOGY © 2006 by Taylor & Francis Group, LLC (see Tables 1 and 2 above). of the gas. See Website (2005): h ttp://www.worldbank.org/ html/fpd/em/power/EA/mitigatn/aqpchgas.stm . CHARACTERIZATION OF SOLID WASTES FROM FLUIDIZED BEDS The characterization and use of fl uidized -bed- combus- tion coal/limestone ash is discussed in the articles of Behr- Andres and Hutzler 23 and Anthony. 1988, p. 2. 23. Christina B. Behr-Andres and Neil J. Hutzler, “Characterization and use of fluidized- bed- combustion coal ash,” Journal of Environmental Engineering, November/December 1994,. Group, LLC FLUIDIZED BED COMBUSTION 409 Other problems associated with bubbling beds are scale- up and turn-down. Scale-up is limited because of the feed distribution problem and turn-down is