204 6 Coal
One example is the United States Department of Energy’s Vision 21 Program,
which aims to develop the ultimate energy facility. The Vision 21 plant will have
zero emissions and no net discharges of wastewater, solid waste, sulfur dioxide,
nitrous oxide or carbon dioxide. If required, the plant will capture and store
(sequester) carbon dioxide to achieve zero emissions.
In this concept, hydrogen is produced from coal and water in the absence of air
or oxygen. The hydrogen is used to produce electricity in a solid oxide fuel cell.
The carbonation of calcium oxide (CaO) to calcium carbonate (CaCO3) sequesters
CO2 and assists in increasing the hydrogen yield. The calcium carbonate is dissociated
back into calcium oxide and a concentrated stream of carbon dioxide (CO2)
by the waste heat from the fuel cell. The carbon dioxide can then be injected into
ocean, or other geological reservoir, such as used-up natural gas reservoir. Also
calcium carbonate can be stored as solid waste. The basic schematic of a hypothesized
zero emission coal power plant is shown in Fig. 6.17.
6.12 Pollution Control from Coal Combustion
The major pollutants emitted during coal combustions are SO2, NOx, and particulates.
However, one of the objectives of clean coal technology is to capture CO2
too. Sulfur compounds present in coal convert to SO2 during the combustion process.
Although attempts have been made to remove sulfur compounds from coal
prior to combustion, post combustion flue gas desulphurization appears to be more
economical and technologically less challenging. Sulfur present in coal may be
broadly grouped into the following three categories:
Organic
30–70% of the total sulfur in coal are in this form and cannot be removed by
direct physical separation.
Sulfate
Less than 0.05% of total sulfur in coal is present as sulfates, which are
generally soluble in water.
Pyritic
0.5–3% of total sulfur in coal is in this form and is generally removed from
the coal during cleaning process and size reduction using gravity separation.
6.12.1 Removal of Organic Sulfur
Organic sulfur species in coals are mainly thiols, sulfides, disulfides, thiophenes
and their derivatives. A number of methods have been explored for removal of
organic sulfur prior to combustion. These include:
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6.12 Pollution Control from Coal Combustion 205
1. Solvent partitioning
2. Neutralization method
3. Hydrogenation reaction or sulfur reduction
4. Thermal decomposition
5. Oxidation
6. Sodium hydroxide treatment or nucleophilic displacement, and
7. Microbial removal
Fig. 6.17. Conceptual system for zero emission coal power plant. (Printed with permission from
[560]).
In this method, an organic solvent is used to dissolve the organic portion of the
sulfur compounds that are present in the coal. The solvent is regenerated and recycled
for economic operation. A number of solvents have been tested for removal of
6.12.1.1 Solvent Partitioning
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organic sulfur and are listed in Table 6.19. Some of the solvents were also used at
supercritical conditions to enhance the extraction process.
Table 6.19. Solvents proposed for removal of organic sulfur by solvent partitioning method.
Solvent Operating temperature % of organic sulfur
removed
n-Propanol [571] 30 43–61%
Tetrachloroethylene [572]a
120 43
Tetrachloroethylene [573] 120 50
Hydrogen peroxide (15%)
[574]
15–40 76% pyritic, 70% sulfate,
5% organic
Hydogen peroxide + 0.1N
H2SO4 [574]
15–40 ~100% pyritic, ~100%
sulfate, 26% organic
Methanol/water and methanol/KOH
[575]
– 33–62 total sulfur
Methanol [576] 500 86% total, 90% organic
Perchloroethylene [577–581] 120 5–30% fresh coal
30–60% weathered coal
Perchloroethylene [582] 120 70
Trichloroethane [583]
Potassium permanganate (6%)
[584]
Room temp 90% pyritic; 87% organic
Methanol/KOH (5% wt) [585] 350 >90%
Methanol and ethanol [586,
587]
Supercritical –
Acetone+water [588] Supercritical 61
Methanol + water and ethanol
+ water [589]
Supercritical 60% pyritic; 97% sulfate;
28% organic
CO2
CO2 + H3PO4
CO2 + methanol (10%) [590]b
450 (supercritical CO2) 50 Total
80 Total
60% Organic
Source: Reference [570].
a
Process involved copper chloride oxidation followed by tetrachloroethylene extraction.
b
Supercritical extraction under pyrolysis condition.
Thiols and mercaptans may be neutralized using an alkaline solution due to the
acidic nature of these two compounds. However, it should be noted that other
organic sulfur compounds, such as sulfides and disulfides, cannot be removed by
this method [591].
6.12.1.2 Neutralization Method
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6.12 Pollution Control from Coal Combustion 207
6.12.1.3 Hydrogenation Reaction
Sulfur compounds react with hydrogen producing hydrogen sulfide, which is then
scrubbed from the gas stream using an acid gas treatment process. The chemical
reactions of hydrogen with thiol compounds are shown below [591].
Ethanethiol: CH3CH2SH+H2 CH3CH3 + H2S
2-Propanethiol: (CH3)2CHSH + H2 CH3CH2CH3 + H2S
6.12.1.4 Thermal Decomposition
In this method, coal is heated to a high temperature in the absence of oxygen.
Sulfur containing compounds undergo the decomposition reaction liberating sulfur
as SO2 or H2S. In most of the cases, H2S is released. A number of researchers
proposed the use of a catalyst to lower the decomposition temperature for sulfur
compounds. Other compounds present in the coal are found to decompose at this
temperature [592–598].
Ethanethiol: CH3CH2SH CH2=CH2 + H2S
2-Propanethiol: (CH3)2CHSH CH3CH=CH2 + H2S
6.12.1.5 Oxidation Reaction
Sulfur compounds may be reacted directly with oxygen or other oxidizing agents
to convert them to water soluble sulfate compounds [599–601].
RSH +
2
1
O2 RSO2OH (sulfonic acid)
where ‘R’ represents CH3CH2 or (CH3)2CH groups.
6.12.1.6 Reaction with Sodium Hydroxide
Sodium hydroxide can react with sulfur compounds forming water soluble sodium
sulfide. A typical reaction with NaOH is shown below [602–607].
RSH + NaOH Na2S + 2H2O +R’CH=CH2
6.12.1.7 Microbial Removal
Certain microorganisms have the potential to remove sulfur from coal [608–622].
Microbial desulfurization of coal has shown various advantages including a higher
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208 6 Coal
pyrite removal efficiency and lower coal wastage compared to physical methods.
The costs are also lower compared to chemical methods because microbial methods
operate at ambient conditions with fewer chemicals. However, microbial processes
are slower, requiring days to complete. The best known pyrite-oxidizing bacteria is
Thiobacillus ferrooxidans, a gram-negative iron-, sulfur and metal sulfide-oxidizing
bacterium. Certain thermophilic bacteria have also shown to remove pyritic sulfur
from coal. These include Sulfolobus acidocaldarius. Sulfolobus, a member of archaebacteria,
oxidizes pyrite, elemental sulfur, certain metal sulfides and organic compounds
at temperature of up to 85 C. Other microorganisms capable of desulfurization
of coal include Thiobacillus thiooxidans and Leptospirillum ferrooxidans.
6.12.2 Removal of Pyritic Sulfur
Pyritic sulfur can be removed from coal prior to combustion by reacting it with
hydrogen, NaOH, or oxygen. The hydrogenation Reaction can be written as:
FeS2 + H2 FeS +H2S: occurs at 230°C
FeS + H2 Fe + H2S: not a favorable reaction
Oxidation Reaction
FeS2 + O2 FeSO4 + SO2 : FeSO4 soluble in water
Reaction with sodium hydroxide (NaOH)
FeS2 + NaOH Fe2O3 + Na2S + Na2S2O3 + H2O
Various other methods have been proposed to remove sulfur from coal prior to
combustion, however, all these processes still would require a post combustion
flue gas clean up system. As a result most of the current focus is to develop a better
flue gas desulfurization system to capture sulfur dioxide in the combustor as
soon as it is released.
6.12.3 Sulfate Sulfur
Most of the coals contain a very small percentage of sulfur in the sulfate form. Most
of the sulfates are also water soluble and generally are removed during the coal
cleaning process.
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6.13 Flue Gas Desulfurization and NOx Removal 209
6.13 Flue Gas Desulfurization and NOx Removal
A number of technologies have been proposed for flue gas cleaning. Several processes
are already in use commercially. A review of these processes has been provided
by a number of researchers [623–627]. Figure 6.18 shows these processes.
Based on the working principles of these technologies, they can be classified first
into two main categories: Once Through and Regenerable.
In the Once Through process, SO2 reacts with the sorbent, which is generally
disposed of as a waste. Most of the processes generate CaSO4, or better known as
gypsum, that can be used for other applications, such as soil treatment and plaster.
In the regenerable processes, sorbent is regenerated and recycled back to the
system. However, the main issue with the regenerable processes is how to store
the released SO2.
Fig. 6.18. Various methods for flue gas desulfurization. (Adapted with permission from [623]).
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210 6 Coal
Among the processes mentioned in Fig. 6.18, the following processes have
been employed commercially so far. The other processes are either in the experimental
or pilot plant stage. The Flue Gas Desulfurization (FGD) methods
currently used in the industry are listed below.
Lime and limestone FGD
Spray dryer absorption
Furnace injection of calcium sorbent (LIMB)
Calcium silicate injection (ADVACATE)
Combined spray drying and electrostatic precipitator (E-SOx)
Combined SO2/NOx removal processes
6.13.1 Wet Scrubber (Lime and Limestone FGD)
scrubbers are the most widely used technology for SO2 control throughout the
world. Generally, a slurry mixture of lime and limestone is used in a scrubber to
remove the sulfur dioxide. These are favored because of their availability and relaused
in a slurry mixture. The slurry is injected into a specially designed vessel
where it reacts with the SO2 in the flue gas. The preferred sorbent in operating wet
scrubbers is limestone followed by lime. The chemical reaction that takes place
with limestone or lime sorbent is shown below.
SO2 + CaCO3 = CaSO3 + CO2
Calcium sulfite (CaSO3) produced in the reaction is further oxidized to calcium
sulfate (gypsum). The excess oxygen (from excess air) in the flue gas can initiate
the oxidation reaction. In some design, a forced oxidation step, in situ or ex situ
(in the scrubber or in a separate reaction chamber), involving the injection of air is
carried out. The chemical reaction is shown below.
SO2 + CaCO3 + ½O2 + 2H2O = CaSO4.2H2O + CO2
reaction chamber providing large particle surface area for efficient contact and
subsequent reaction.
interval. The flue gas is dispersed through several opening or slots in the plate
holding the scrubbing liquid, which also provides large sorbent surface area.
This method was introduced in 1970 for flue gas desulfurization [628–630]. Wet
tive low costs. However, sodium- and ammonium-based sorbents have also been
Spray tower: Spray nozzles atomize the pressurized scrubbing liquid into the
Plate tower: The scrubber consists of a number of plates stacked at a certain
A variety of scrubbers have been designed to carry out the above two reactions
and a brief description of their operating principle is given below.
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6.13 Flue Gas Desulfurization and NOx Removal 211
Impingement scrubber: In this design, a vertical chamber incorporates perforated
plates with openings that are partially covered by target plates. The plates are
flooded with the sorbent slurry and the flue gas is accelerated upwards through the
perforations. The flue gas and sorbent liquid make contact around the target plate,
creating a turbulent frothing zone to provide the desired reaction contact.
Packed tower: A tower is packed with inert packings. The flue gas flows upward
through the packing material in the counter-current direction to the liquid
sorbent flow which is introduced at the top of the packing through a distributor.
Commercial wet scrubbing systems are available in many variations and proprietary
designs. Systems currently in operation include:
Lime/limestone/sludge wet scrubbers
Lime/limestone/gypsum wet scrubbers
Wet lime, fly ash scrubbers, and
Other wet scrubbers that utilize seawater, ammonia, caustic soda, sodium carbonate,
potassium and magnesium hydroxide based scrubbing solution
Wet scrubbers can achieve removal efficiencies as high as 99%. It is expected
that wet scrubbers, where the end product is gypsum, will become a more popular
FGD technology, since disposal of waste faces increasingly stricter governmental
regulations. However, wet scrubbing technology still needs to treat the waste
water before disposal. A flow diagram of the process is shown in Fig. 6.19.
Fig. 6.19. A schematic diagram of wet scrubbing system for flue gas desulfurization.
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212 6 Coal
Generally a high liquid to gas ratio is used to avoid scaling. In some units
forced oxidation was also tried to avoid scaling. A thiosulfate-forming additive is
mixed with the slurry to facilitate the removal of scales that might deposit on the
wall. It was also noted that by maintaining a certain pH, using an organic acid
buffer, SO2 removal could be enhanced.
6.13.2 Dry Sorbent Injection Method
This method of SO2 emission control relies on the atomization of a sorbent – most
commonly an aqueous lime slurry – in a reaction chamber upstream of a particulate
collection device. A basic schematic diagram of the process is shown in
Fig. 6.20. Two processes are currently practiced commercially for capture of SO2
from the flue gas: Furnace injection and Duct injection.
Fig. 6.20. Dry sorbent injection system.
6.13.2.1 Furnace Injection
Furnace injection systems are typically designed to operate at 15–25 C (27–45 F)
approach to the adiabatic saturation temperature of the flue gas. Dry sorbent is
This method for flue gas desulfurization evolved from spray drying technology.
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6.13 Flue Gas Desulfurization and NOx Removal 213
injected directly into the section of the furnace where temperature ranges between
950 C and 1,000 C. The fine droplets absorb SO2 and form the product calcium
sulfite and sulfate as the water evaporates. A downstream electrostatic precipitator
(ESP) or baghouse collects the dry salts along with fly ash present in the flue gas.
Use of a baghouse enhances the performance of the dry scrubber because additional
SO2 absorption occurs as the flue gas passes through the accumulation.
The reactions taking place in the furnace are as follows:
Calcination: CaCO3 CaO + CO2
Sulfation: CaO + SO2 +1/2 O2 CaSO4
Spray dry scrubbers are the second most widely used FGD technology. However,
their application is limited to flue gas volume from about 200 MWe plants
on average. Larger plants require the use of several modules to deal with the total
flue gas flow. This is why in general the technology is used in small to medium
sized coal-fired power plants. Spray dry scrubbers in commercial use have achieved
2
removal efficiency under certain conditions.
The Babcock & Wilcox Company (B&W) designed a limestone injection multistage
burner (LIMB) system to improve the efficiency of the system [631–637].
The description of the system is shown in Fig. 6.21. Humidification of the flue gas
before it enters an ESP is necessary to maintain normal ESP operation and to enhance
SO2 removal. The goal of LIMB process was to remove more than 50% SO2
and NOx from the flue gas. Combinations of three bituminous coals (1.6, 3.0, and
3.8% sulfur) and four sorbents were tested and overall removal efficiency in the
In the coolside process, dry sorbent is injected into the flue gas downstream of
the air preheater, followed by flue gas humidification (see Fig. 6.22). Humidification
enhances ESP performance and SO2 absorption. SO2 absorption is improved
To avoid CO2 release, dry powder of calcium oxide is mainly used as the sorbent.
However, a lime slurry, also called lime milk, can be atomized/sprayed into
the reactor vessel in a cloud of fine droplets. Water is evaporated by the heat of
the flue gas, thus does not require any waste water treatment facility. About 10 s
of residence time in the reactor is sufficient to allow for the SO2 and the other
acid gases such as SO3 and HCl to react simultaneously with the hydrated lime
to form a dry mixture of calcium sulfate/sulfite. The unreacted lime is recycled
and mixed with fresh lime slurry to enhance sorbent utilization. Other factors that
may affect the performance include flue gas temperature, SO2 concentration in the
flue gas and the size of the atomized or sprayed slurry droplets. The absorber construction
material is usually carbon steel making the process less expensive in
capital costs compared with wet scrubbers. However, the necessary use of lime in
the process increases its operational costs.
a removal efficiency in excess of 90% with some suppliers claiming >95% SO
range of 50–63% was reported when using lingo lime. B&W further modified the
design and called it the coolside process.
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2146Coal
Fig. 6.21. A limestone injection multistage burner (LIMB) designed by Babcock & Wilcox Co. (Adapted from [638]).
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6.13FlueGasDesulfurizationandNOxRemoval215
Fig. 6.22. The coolside process that couples flue gas humidification with hydrated lime injection into the duct. (Adapted from [639]).
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216 6 Coal
by dissolving sodium hydroxide (NaOH) or sodium carbonate (Na2CO3) in the
humidification water. The spent sorbent is collected with the fly ash, as in the
LIMB process. Bituminous coal with 3.0% sulfur was used in testing, and SO2
removal of 70% was reported. SO2 capture takes place according to the following
reactions:
Calcination: Ca(OH)2 + heat CaO + H2O
Sulfation: CaO + SO2 + 0.5 O2 CaSO4 + heat
Hydration: CaO + H2O Ca(OH)2 + heat
CaSO4 + 2H2O CaSO4 · 2H2O + heat
The additional reactions involving NaOH are as follows:
2NaOH + SO2 Na2SO3 + H2O + heat
2NaOH + SO2 + 0.5 O2 Na2SO4 + H2O + heat
6.13.2.2 Duct Injection
In this process, dry sorbent is injected in the flue gas duct between the air preheater
and particulate collector. Most commonly used sorbent is hydrated lime, however,
sodium bicarbonate has been also used. Approximately 50–60% SO2 is captured
with lime, and the capture efficiency may be increased to 80% by using sodium
bicarbonate. It is primarily used for those applications where a moderate degree of
desulfurization is required at low capital cost. However, sodium bicarbonate is
relatively expensive [640].
An advanced version of duct spray injection is the ADVAanced siliCATE
(ADVACATE) process [641]. ADVACATE uses an advanced silicate that is more
absorbent than lime. This process removes 90–95% of the sulfur dioxide and other
acidic gases from stacks of any coal-fired boiler. A schematic diagram of the
process is given in Fig. 6.23.
This dry duct injection system utilizes a fly ash-based throwaway sorbent to
remove sulfur dioxide. High surface area calcium silicate hydrates are made by
slurrying Ca(OH)2 (calcium hydroxide) with fly ash and recycled sorbents in
6.13.2.3 Calcium Silicate Injection (ADVACATE)
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6.13 Flue Gas Desulfurization and NOx Removal 217
water at elevated temperatures. The resulting sorbent has the handling properties
of a dry powder while maintaining moisture levels of up to 50–76% by weight.
The dry powder is injected into the duct, where sulfur dioxide removal takes
place. Some removal of SO2 also takes place in the particulate collection device.
Sulfur dioxide captured by dry powder is collected with the fly ash and is separated
into waste and recycle streams.
The calcium silicate formed has a large surface area capable of adsorbing a
large amount of water. Sulfur dioxide dissolves into the water to react with calfite
is the main product. The ADVACATE absorbent has been tested in a 10 MW
pilot plant, and 89% of SO2 removal and 61% of lime utilization were achieved
[642].
The Electric Power Research Institute estimates that the new process will cost
$85 per kW versus $215 per kW for conventional flue gas scrubbing.
Fig. 6.23. A schematic representation of ADVAanced siliCATE (ADVACATE) process.
The E-SOx technology combines improved electrostatic precipitation technology
with conventional spray drying FGD techniques for better efficiency [643, 644]. A
schematic diagram of the process is shown in Fig. 6.24.
6.13.2.4 Combined Spray Drying and Electrostatic Precipitator (E-SOx)
cium ions. The final products are calcium sulfite and calcium sulfate. Calcium sulLicensed
to Jiri Martinec<martinec@fme.vutbr.cz>
218 6 Coal
Fig. 6.24. The E-SOx process for enhancing flue gas desulfurization.
6.13.2.5 SOx -NOx Rox Box (SNRB)
This process combines hydrated lime and ammonia injection upstream of a hot,
catalytic baghouse (Box), where the solid products calcium sulfite and sulfate and
particulate (Rox) are removed, and the NOx is reduced to nitrogen and water. The
design of the burner is shown in Fig. 6.25.
Fig. 6.25. The burner configuration for simultaneous removal of SOx-NOx-ROx-BOx. (Adapted
from [638]).
A comparison of costs among various flue gas desulfurization methods is
shown in Table 6.20
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219
Table 6.20. A comparison of costs of various flue gas desulfurization processes.
Process Plant capacity
(MWe)
Sulfur content of
coal (%)
Targeted SO2
reduction (%)
Capital costs
($/kW)
Annual levelized costs
($/t of SO2 removed)
Wet limestone scrubber
Forced oxidation
Wallboard gypsum
Inhibited oxidation
Dibasic acid (additive)
Magnesium enhanced
300
300
300
300
300
1.7
2.6
2.6
2.6
2.6
90
90
90
90
90
209
243
234
211
189
540
476
476
463
477
Lime spray drying 300
300
1.7
2.6
90
90
160
173
490
439
Dry sorbent injection
Furnace injection
Duct injection
300
300
2.6
2.6
50
50
94
98
751
768
LIMB 100–500 1.5–3.5 60 31–102 392–791
Coolside 100–500 1.5–3.5 70 69–160 482–943
ADVACATE 300 2.6 90 84 327
6.13FlueGasDesulfurizationandNOxRemoval
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