Particulate Matter Control System
ESPs are most widely used for the control of fly ash from industrial and utility boilers and
have been used on coal-fired boilers for over 50 years. Particulate matter is generated from
boilers when fossil fuels (coal and oil) are burned to generate steam for industrial processes
or to produce electric power. Both hot-side and cold-side precipitators are used to
control particulate emissions. Other than some construction modifications to account for
the temperature difference of the flue gas handled, hot-side and cold-side ESPs are essentially
the same. Cold-side ESPs are used most often for collecting fly ash from coal-fired boilers. If the dust has high resistivity, cold-side units are used along with a conditioning agent such as sulfur trioxide
Dry Sulfur Dioxide (SO2) Control System
One technology for reducing sulfur dioxide (SO2) emissions from boilers is dry flue gas
desulfurization (FGD). In dry FGD, the flue gas containing SO2 is contacted with an
alkaline material to produce a dry waste product for disposal. This technology consists of
three different FGD methods:
• Injection of wet alkaline material (slurry) into a spray dryer with collection of dry particles
in an electrostatic precipitator or baghouse,
• Injection of dry alkaline material into the flue gas stream with collection of dry particles
in an ESP or baghouse, or
• Addition of alkaline material to the fuel prior to combustion
Spray dryers used in dry FGD are similar to those that have been used for over 40 years
in the chemical, food-processing, and mineral preparation industries. Spray dryers are vessels
where hot flue gas is contacted with a finely atomized, wet alkaline spray (see Figure). Flue gas enters the top of the spray dryer and is swirled by a fixed vane ring to cause
intimate contact with the slurry spray. Sodium carbonate solutions and lime slurries are the
most common alkaline material used. The slurry is atomized into extremely fine droplets
by rotary atomizers or two-fluid nozzles. In a rotary atomizer, slurry is broken into droplets
by centrifugal force as the atomizer wheel spins at a very high speed. In two-fluid nozzles,
slurry is mixed with compressed air, which forms the very small droplets. The high
temperature of the flue gas, 120 to 204°C (250 to 400°F), evaporates the moisture from the
wet alkaline sprays, leaving a dry, powdered product. The dry product is then collected in
an ESP or baghouse (Joseph and Beachler 1981).
They are particularly useful in meeting New Source Performance Standards (NSPS) that
require only 70% SO2 removal efficiency for utility boilers burning low-sulfur coal and as
retrofit applications for units having to meet the standards required by the 1990 Clean Air
Act Amendments (see Table).
Spray dryer absorbers systems can reduce SO2 emissions by 60 to 90%. They have been
used on boilers burning low-sulfur coal (usually less than 2% sulfur content) and are
attractive alternatives to wet scrubbing technology, particularly in the arid western U.S.
In dry injection systems, a dry alkaline material (sorbent) is injected pneumatically into
the gas stream by nozzles located in the ductwork prior to the flue gas entering the ESP.
Sodium-based sorbents are used more frequently than lime for industrial coal-fired boilers
but hydrated lime is prevalent for waste burning incinerators. Sodium bicarbonate is frequently
used because it is highly reactive with SO2. Sodium carbonate (soda ash),
although not as reactive as sodium bicarbonate, is also used (U.S. EPA 1980). SO2
removal efficiency for these systems is typically between 70 and 80%.
A third way to apply dry FGD is by adding alkaline material to the fuel (coal) prior to
combustion. In fluidized bed boilers, limestone or sometimes lime is added to the coal in
the fluidized burning bed. These systems are capable of removing more than 90% of SO2
from the boiler flue gas. Alkaline material can also be injected into the furnace through
ports or directly into the fuel burners. The SO2 removal is typically greater than 70% in
these systems.
ESPs are most widely used for the control of fly ash from industrial and utility boilers and
have been used on coal-fired boilers for over 50 years. Particulate matter is generated from
boilers when fossil fuels (coal and oil) are burned to generate steam for industrial processes
or to produce electric power. Both hot-side and cold-side precipitators are used to
control particulate emissions. Other than some construction modifications to account for
the temperature difference of the flue gas handled, hot-side and cold-side ESPs are essentially
the same. Cold-side ESPs are used most often for collecting fly ash from coal-fired boilers. If the dust has high resistivity, cold-side units are used along with a conditioning agent such as sulfur trioxide
Dry Sulfur Dioxide (SO2) Control System
One technology for reducing sulfur dioxide (SO2) emissions from boilers is dry flue gas
desulfurization (FGD). In dry FGD, the flue gas containing SO2 is contacted with an
alkaline material to produce a dry waste product for disposal. This technology consists of
three different FGD methods:
• Injection of wet alkaline material (slurry) into a spray dryer with collection of dry particles
in an electrostatic precipitator or baghouse,
• Injection of dry alkaline material into the flue gas stream with collection of dry particles
in an ESP or baghouse, or
• Addition of alkaline material to the fuel prior to combustion
Spray dryers used in dry FGD are similar to those that have been used for over 40 years
in the chemical, food-processing, and mineral preparation industries. Spray dryers are vessels
where hot flue gas is contacted with a finely atomized, wet alkaline spray (see Figure). Flue gas enters the top of the spray dryer and is swirled by a fixed vane ring to cause
intimate contact with the slurry spray. Sodium carbonate solutions and lime slurries are the
most common alkaline material used. The slurry is atomized into extremely fine droplets
by rotary atomizers or two-fluid nozzles. In a rotary atomizer, slurry is broken into droplets
by centrifugal force as the atomizer wheel spins at a very high speed. In two-fluid nozzles,
slurry is mixed with compressed air, which forms the very small droplets. The high
temperature of the flue gas, 120 to 204°C (250 to 400°F), evaporates the moisture from the
wet alkaline sprays, leaving a dry, powdered product. The dry product is then collected in
an ESP or baghouse (Joseph and Beachler 1981).
Spray dryer with ESP
A number of spray dryer FGD systems have been installed on industrial and utility boilers.They are particularly useful in meeting New Source Performance Standards (NSPS) that
require only 70% SO2 removal efficiency for utility boilers burning low-sulfur coal and as
retrofit applications for units having to meet the standards required by the 1990 Clean Air
Act Amendments (see Table).
Commercial spray dryer FGD systems using an ESP or a baghouse
Spray dryer absorbers systems can reduce SO2 emissions by 60 to 90%. They have been
used on boilers burning low-sulfur coal (usually less than 2% sulfur content) and are
attractive alternatives to wet scrubbing technology, particularly in the arid western U.S.
In dry injection systems, a dry alkaline material (sorbent) is injected pneumatically into
the gas stream by nozzles located in the ductwork prior to the flue gas entering the ESP.
Sodium-based sorbents are used more frequently than lime for industrial coal-fired boilers
but hydrated lime is prevalent for waste burning incinerators. Sodium bicarbonate is frequently
used because it is highly reactive with SO2. Sodium carbonate (soda ash),
although not as reactive as sodium bicarbonate, is also used (U.S. EPA 1980). SO2
removal efficiency for these systems is typically between 70 and 80%.
A third way to apply dry FGD is by adding alkaline material to the fuel (coal) prior to
combustion. In fluidized bed boilers, limestone or sometimes lime is added to the coal in
the fluidized burning bed. These systems are capable of removing more than 90% of SO2
from the boiler flue gas. Alkaline material can also be injected into the furnace through
ports or directly into the fuel burners. The SO2 removal is typically greater than 70% in
these systems.
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