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