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
Trang 1FLUIDIZED 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 1550F)
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
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 1550F and 1650F. 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
Trang 2maintaining 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 F
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 F 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 partiparti-cle 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
Trang 3turbine 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:
PSso
2( (y 340)z(520)) / (yz) where PSso
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/
Trang 4joule 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:
PSNO
x
w x y z
Where PSNO
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 NOx 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 NOx 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 NOx emissions were less than 0.25 lb/million Btu. 11 The NSPS for NOx 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
Trang 5continuous; 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 1600F 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 1480F Limestone No
1359 was most effective in the range of 1500–1550F 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–
1600F 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 1800F 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
Trang 6exist 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:
One or more of the following reactions were proposed to
occur in the upper portion of the combustor:
CaS1 O1 2 CaOSO2
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 oxynitro-gen during combustion and later forms
acid rain in very much the same manner as with sulfur
Oxides of nitrogen (NOx) 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
N2 O2 UNO
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 NOx 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 NOx emissions
As with SO 2 reduction bed composition has an important effect on NOx It has been determined through experimenta-tion and experience that limestone also decreases NOx 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 usconduct-ing 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:
CaOSO2 UCaSO3 CaSO3 2NOUCaSO (NO3 )2 CaSO (NO3 )2 UCaSO4N O2
N O2 UN21O2
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 2 UCaSO4S2 4CaS6SO2 U4CaSO33S2
Based on this process it was determined that the following reaction might also be possible
CaS4NOUCaSO42N 2
Trang 7Preliminary 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 194F and 1202F 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 reacreduc-tion 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 1112F, 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 1500F
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
4NH34NO O 2U4N26H O2
4NH32NO2O2 U3N26H O.2
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 2200F 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
Trang 8Other problems associated with bubbling beds are
scale-up and turn-down Scale-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.1a Text no 2a Test no 3a Baghouseb Full-scale residues
CaSO4 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
CaCO3 3.4 3.2 5.2 6.8 4.6
Fe2O3 10.7 9.5 9.1 10.6 15.9
Other mainly SiO2 and C 27.3 20.8 33.8 19.5 24.2
LOIc (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, D50 mm 0.2 0.04 0.04
Optimum water content percenta 14.5–17.5 32 26.5–30.5
Unconfined compressive strength, kPab
Curing period, days
0 230–360 — —
7 150–290 — 4120
10 260–425 385 —
Freeze/thaw cycles
6 540–1020 Sample destroyed —
a As determined by standard Proctor test
b Samples were cured at 100 percent relative humidity at 23 ± 2 C for periods shown
TABLE 2 Geotechnical properties of the pilot-scale rig composite and baghouse samples and full-scale unit residues
Trang 9material 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 1,000C) 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
(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