Controlling Multiple Emissions from Coal-fired Power
Plants
Paper # 45376
Reynaldo Forte, U.S. Environmental Protection Agency, Clean Air Markets Division,
Washington, DC 20460
Ravi K. Srivastava, U.S. Environmental Protection Agency, National Risk Management
Research Laboratory, Research Triangle Park, NC 27711
E. Stratos Tavoulareas, Energy Technologies Enterprises Corp., 1112 Towlston Rd., McLean,
VA 22102
Rui Afonso, Energy and Environmental Strategies, 50 Old Faith Road, Shrewsbury, MA 01545
Wojciech Jozewicz and Michiel Doom, ARCADIS Geraghty & Miller, P.O. Box 13109,
Research Triangle Park, NC 27709
Prepared for presentation at:
A&WMA 95th Annual Conference & Exhibition, Baltimore, MD, June 23-27, 2002
ABSTRACT
Technologies capable of simultaneously controlling multiple pollutants of emissions from
electric utility sources can be quite beneficial. Such technologies can provide options for meeting
numerous regulatory requirements and, in some cases, represent the only practical method of
providing the necessary environmental benefits. For example, in a constrained plant layout,
application of a particular multipollutant control technology may be the only viable option. In
addition, a multipollutant control system may be capable of operating with a lower energy
requirement than a traditional one using a series of controls in succession, each targeting a
different pollutant.
This paper presents and analyzes nine existing and novel control technologies designed to
achieve multipollutant emissions reductions. It provides an evaluation of multipollutant emission
control technologies that are potentially available for coal-fired power plants of 25 megawatts
(MW) capacity or larger in the United States. Some of these technologies are combinations of
commercial technologies that are being used to control at least one pollutant while others are
under development with the specific goal of controlling multiple pollutants. Issues related to
cost, byproduct management, residue or waste disposal, and scaleup are currently being
addressed to make these technologies more cost-effective and broadly applicable.
The paper primarily addresses technologies that are capable of simultaneously controlling
nitrogen oxides (NOx), sulfur dioxide (S02), and mercury emissions from electric utility sources.
Technologies that are capable of simultaneously controlling S02 and mercury are also addressed
because of high interest in controlling mercury emissions. The information provided for each
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technology includes: a brief technology description, the level of commercial readiness and
industrial experience, and emission control performance. Three of the evaluated control
technologies are capable of achieving simultaneous reductions of S02, NOx, and mercury and
show potential to achieve above 80 % reductions of all three pollutants.
INTRODUCTION
Recent changes in the structure of the electric utility industry — including the shift towards
restructuring, the growing demand for electricity generation, and environmental needs — are
driving additional reductions of multiple pollutants. Historically, industry has developed and
implemented control technologies in incremental steps to mitigate emissions of sulfur dioxide
(S02), nitrogen oxides (NOx), particulate matter, and other pollutants, as driven by air pollution
requirements. Control technologies that are capable of simultaneously reducing emissions of
multiple pollutants may offer the potential to achieve this at lower cost and reduced footprint
when compared to conventional controls.
This paper presents and analyzes various control technologies designed to achieve multi-
pollutant emissions reductions. Having up-front knowledge of environmental performance, cost,
and limitations of multipollutant control technologies can help power companies select effective
and less expensive compliance strategies at individual plants, compared with compliance choices
made when the requirements are addressed individually.
BACKGROUND
Electricity is critical to the functioning of residential, commercial, and industrial sectors in the
U.S. More than 3,170 traditional electric utility plants and 2,110 non-utility power plants are
responsible for ensuring an adequate and reliable source of electricity to consumers in their
service territories1. While electricity plays a critical role in sustaining the Nation's economic
growth, the unintended byproducts of electricity generation can have an undesirable effect on the
environment and public health. Most of these health impacts result from emissions produced
through the combustion of fossil fuels (coal, oil, and natural gas) which supply about 70 % of the
Nation's requirements for electricity generation.
As a result, power plants are currently required to reduce emissions of NOx and S02. The
revision of the National Ambient Air Quality Standards (NAAQS) for particulate matter (PM)
and ozone may also affect power plant emissions. These revisions may require electric utility
sources to adopt control measures designed to reduce concentrations of fine (less than 10 p.m in
diameter) PM in the atmosphere. In addition, the U.S. Environmental Protection Agency (EPA)
has recently determined that regulation of mercury emissions from these sources is appropriate
and necessary. Concurrently, legislation has been proposed in both the previous and current
Congresses that would require simultaneous reductions of multiple emissions, and the
Administration's National Energy Policy2 recommends the establishment of "mandatory
reduction targets for emissions of three main pollutants: sulfur dioxide, nitrogen oxides and
mercury." On February 14, 2002, President Bush proposed a far-reaching effort to decrease
power plant emissions, the Clear Skies Initiative. This proposal is intended to aggressively
reduce air pollution from electricity generators and improve air quality throughout the Country.
The Clear Skies Initiative3 is designed to decrease air pollution by 70 %, using a proven, market-
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based approach that could save consumers millions of dollars. The Clear Skies Initiative calls
for:
•	Decreasing S02 emissions by 73 %, from current emissions of 11 million tons to a cap of
4.5 million tons in 2010, and 3 million tons in 2018,
•	Decreasing NOx emissions by 67 %, from current emissions of 5 million tons to a cap of
2.1 million tons in 2008, and to 1.7 million tons in 2018, and
•	Decreasing mercury emissions by 69 % by implementing the first-ever national cap on
mercury emissions. Emissions will be cut from current emissions of 48 tons to a cap of 26
tons in 2010, and 15 tons in 2018.
This paper focuses on control technologies that promise to simultaneously control NOx, SO2, and
mercury emissions from coal-fired power plants since these plants generate slightly over 50 % of
the electricity generated in the United States. The coal-burning electric power industry is a major
source of various air pollutant emissions including S02, NOx, and mercury. During 1998, fuel-
combustion electric utilities contributed 67 % of the total S02, 25 % of the NOx, and 35 % of the
mercury emitted.4
DEFINITION OF MULTIPOLLUTANT CONTROL TECHNOLOGIES
This paper describes the technologies identified as multipollutant control technologies and which
have reached a stage of development beyond pilot scale. Multipollutant control technologies are
defined as options which integrate in-situ and/or post-combustion controls of at least two of the
S02, NOx, and mercury pollutants, either in one process or a combination of coordinated and
complementary (synergistic) processes. In addition to the above definition, two other criteria are
applied in selecting the technologies described in this paper. These are: (1) there should be at
least one installation in operation in a power plant worldwide as of July 1, 2001, and (2) while it
is acceptable for the technology to be used even in a slipstream (not the entire power plant), the
size of the technology installation should be at least 5MW or equivalent.
Using the above definition and criteria, a literature search was performed (using technical papers
from conferences, the internet, technical reports by organizations such as Department of Energy
(DOE), EPA, Electric Power Research Institute (EPRI), and contacting vendors and utilities) and
the technologies were identified. The gathered information was analyzed based on the review
criteria and findings summarized in this paper. The paper describes post-combustion controls
(environmental control options) with a focus on technologies capable of simultaneously reducing
S02, NOx, and mercury emissions. A limited discussion of processes for the control of SO2 and
mercury emissions is also included because of the significant role they may play in controlling
mercury from existing power plants. Wherever possible, for each S02-NOx-mercury technology
presented in the paper, the following information is provided: a brief technology description,
commercial readiness and industry experience, the emission control performance, and issues and
barriers associated with the technology.
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SIMULTANEOUS S02, NOx, AND MERCURY CONTROL
The results of the literature search and assessment revealed three technologies capable of
simultaneously reducing SO2, NOx, and mercury emissions: 1) Activated Coke, 2) Electro-
Catalytic Oxidation, and 3) SCR and Wet FGD. These technologies are discussed in the ensuing
section of the paper.
Activated Coke
The activated coke process5 involves three steps: 1) adsorption, 2) desorption, and 3) (optional)
by-product recovery. In the first step (adsorption), flue gas passes through a bed of activated coke
moving downwards in a two-stage adsorber at a constant flow rate. The porous activated coke
consists of carbon with large surface area. In the first stage, SO2 is removed by adsorption into
the activated coke where it forms sulfuric acid (H2S04) and is maintained in the coke inner
surface at temperatures of 100 to 200 °C (212 to 392 °F). The adsorber acts also as a particulate
control device, reducing particulates below 0.012 grain/scf when the inlet is kept below 0.207
grain/scf. In the second stage of the adsorption process, the activated coke acts as a catalyst in the
decomposition of NOx to nitrogen and water with injection of ammonia (NH3) in the activated
coke bed. The chemical reaction occurs in the 100 to 200 °C (212 to 392 °F) temperature range.
As the activated coke is loaded with H2S04, its adsorption capacity declines. Further, unreacted
NH3 reacts with H2SO4 to form ammonium sulfate l(NH4)2S04]. To regenerate the activated
coke, it is conveyed by a bucket elevator to a desorber where the (NH4)2S04 is heated up and
decomposed to nitrogen, S02, and water. The reactions take place in the 300 to 500 °C (572 to
932 °F) temperature range. After cooling, the activated coke passes through a vibrating screen to
eliminate smaller particles (fines) and then is recycled back into the adsorber. Fines are returned
the boiler as fuel for combustion. S02-rich gas can be reduced to hydrogen sulfide (H2S) in a
reduction column and then to elemental sulfur in a Claus unit. Alternatively, the process can
produce H2S04.
Mercury can be removed also by adsorption. Once adsorbed on the coke, mercury must be
collected in a form suitable for disposal. One method proposed is the use of a selenium filter,
which absorbs the mercury from the flue gas and forms mercuric selenide (HgSe), a chemically
stable compound. The selenium filter is considered commercial and is expected to have 98 % Hg
collection efficiency during the filter life (usually 4-5 years). Once spent, the selenium filter has
to be disposed of in a hazardous waste facility. Other methods of mercury removal/disposal are
also considered, but none has been tested yet.
Activated coke is a carbonaceous material produced by steam activation at approximately 900 °C
(1,650 °F). It has high mechanical strength against abrasion and crushing. Its surface area is 150-
250 m2/g, less than conventional activated carbon but much higher than metallurgical coal.
The process is commercially available in Japan and Germany. It was originally developed by
Deutsche Montan Technologie and demonstrated at a 93,000 SCFM plant, the Kellerman
generating station of STEAG GmbH. Mitsui Mining Co., Ltd. of Japan (Mitsui) obtained a
license from Deutsche Montan Technologie and tested it in a pilot facility from 1981 to 19836.
Installations of the Mitsui activated coke process in Japan 7*8 and Germany include (designed for
both S02 and NOx control unless otherwise indicated):
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•	18,700 scfm at Mitsui's power generating station (1984).
•	124,500 scfm at Idemitsu Kosan's refinery on a residual fluidized-bed catalytic
cracking process (1987).
•	280,000 and 404,600 scfm boilers at EVO GmbH's Arzberg power station in
Germany (1987).
•	404,600 scfm at Hoechst AG's power station in Frankfurt, Germany (1989).
•	10,000 scfm at Electric Power Development Corp.'s Wakamatsu power station
(1990).
•	1,163,000 scfm (350 MW) Atmospheric Fluidized-Bed Combustion (AFBC) boiler at
Electric Power Development Corp.'s Takehara power station (1995). This facility,
designed only for NOx reduction, achieved above 80 % NOx reduction.
•	2,000,000 scfm (600 MW) power plant (Electric Power Development Corp.'s Isogo
station) burning low-sulfur Australian coal. The Activated Coke (AC) process is
designed for 95 % SO2 removal; no NOx reduction was sought.
¦	"7 R
SO2 control efficiency has ranged from 90 to 98 %, and NOx control efficiency 60 to 80 % ' .
NOx reduction is higher for lower S02 concentrations at the inlet of the adsorber; for example,
1000 ppm S02 concentration may result in NOx reduction in the 35-40 % range, while 200 ppm
SO2 concentration will raise NOx reduction to above 70 %. NOx reduction is also affected by the
amount of ammonia (NH3) injected (a NH3/NOx ratio typically in the 0.5-1.0 range results in
above 70 % NOx reduction), the oxygen (02) concentration of the flue gas (lower excess 02
results in lower NOx reduction), and the inlet gas temperature. Based on pilot- scale tests earned
out by Mitsui, 90-99 % mercury removal is projected. These tests resulted in 99+ % mercury
reduction at operating temperatures of 150 to 180 °C (302 to 356 °F).
The main issue associated with this technology is the high cost of activated coke. Also, during
start-up! it takes longer to bring up the temperature in the DeNOx system. Therefore, NOx
reduction in cycling units may suffer during start-up unless they are designed to utilize an
external heat source to prepare the DeNOx reactor.
Electro-Catalytic Oxidation™
The Electro-Catalytic Oxidation (ECO) process9 treats flue gas in three steps to achieve multi-
pollutant removal. First, a majority of the ash in the flue gas stream is removed in a conventional
dry ESP. Following the ESP, a barrier discharge reactor oxidizes the gaseous pollutants to higher
oxides. For example, nitric oxide (NO) is reacted to form nitric acid (HN03), S02 is converted to
H2SO4, and mercury is oxidized to mercuric oxide (HgO). Products of the oxidation process are
then captured in a wet electrostatic precipitator (WESP) that also collects fine particulate matter.
Liquid effluent from the WESP may be treated to remove collected ash then delivered to a
system to produce concentrated H2S04 and HNO3 for sale. The ECO system is designed to be
retrofitted into the last fields of an existing ESP. If the ESP does not have adequate space to fit
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the ECO system, some or all components could be built downstream of the ESP. In the latter
case, the downtime of the plant is reduced, but additional space (footprint) is needed. The H2SO4
and HNO3 produced and captured in the WESP effluent can be made into salable byproducts
such as concentrated acids, gypsum, or fertilizer.
Oxidation of gaseous pollutants in the barrier discharge reactor is the key component of the ECO
process. Oxidation is accomplished through generation of a non-thermal discharge or plasma. In
a dielectric barrier discharge, energetic electrons are produced throughout the reactor without
heating the gas stream to high temperatures, requiring less energy (about 5 % of the gross
electricity output) than plasma discharges. Dielectric barrier discharges can be operated over a
wide range of temperatures and pressures and have been widely used for commercial ozone (03)
generation10"13.
To form a barrier discharge, a dielectric insulating material is placed between two discharge
electrodes. Typically, the material has a high dielectric strength and high dielectric constant (e.g.,
glass or ceramic) and covers one of the two electrodes. High voltage applied to the electrodes
causes the gas in the gap to break down. Presence of the dielectric barrier prevents this
breakdown from forming an arc with its resulting energy consumption. Instead, breakdown is in
an array of thin filament current pulses or "microdischarges." They arc well distributed spatially
over the discharge gap. Typical duration of a microdischarge is of the order of a few
nanoseconds, and electron energies range from 1 to 10 electron volts. The electron energies
formed in the microdischarge are ideal for generating gas-phase radicals, such as hydroxyl (OH)
and atomic oxygen (O), through collision of electrons with water and oxygen molecules present
in the flue gas stream, as shown in Equations (1) through (3):
O2 + e	—> O + O + e	(1)
H20 + e —» OH + H + e	(2)
O + H20 -> 20H	(3)
In a flue gas stream, these radicals simultaneously oxidize NOx, S02, and Hg to form HNO3 and
NO2, H2SO4, and HgO, respectively. The above reactions leading to radical formation and the
subsequent oxidation reactions can be made to occur at low temperatures, 65 to 150 °C (150 to
300 °F).
Presence of a dielectric barrier allows for several possible electrode configurations, including
coaxial cylinders, cylindrical electrodes with plates, and parallel plate electrodes. Different
reactor designs have little effect on overall conversion efficiency. This allows for spacing that
reduces the potential for plugging of the reactor and results in a minimal pressure drop across the
reactor. Aerosols formed by the oxidation reactions, including HgO, HNO3, and H2SO4, exit the
barrier discharge reactor in the flue gas stream. At this point, the gas enters a condensing WESP
where aerosols, fine particulate matter, and other air toxic compounds are collected.
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The byproducts of the ECO process are raw sulfur, HNO3, and H2SO4, which can be used to
produce fertilizer and gypsum. Of course, the extent to which these by-products would be
actually used depends on economics (supply and demand of competing products) in the local
market (around the power plant).
The technology is in the demonstration stage. It was originally tested at laboratory scale (1 and
100 scfm). Then, it was tested at pilot scale at First Energy's R.E. Burger #5 unit14,15 (a 156-MW
unit), where a slipstream of 2000-4000 scfm (equivalent to approximately 2 MW) was used to
assess the performance of the ECO process. The pilot-scale tests were carried out in early 2000.
Presently, a demonstration project is planned at First Energy's R.E. Burger plant. The technology
will be tested at a slipstream (110,000 scfm or 7.4 % of the total flue gas) of equivalent 50 MW
scale. The first results from this demonstration project are expected in late 2002.
At First Energy's R.E.Burger station (2 MW pilot scale), the technology achieved 76, 44, and 68-
82 % of NOx, S02, and mercury emission reduction, respectively 16. Also measured were 88 %
hydrochloric acid (HC1) reduction and 96-97 % removal of PM with aerodynamic diameters of
less than 2.5 |xm (PM2.5). These results were achieved with 337 ppm NOx in the inlet of the ECO
system, approximately 40% higher than in a similar installation with low NOx burners. The
demonstration at Eastlake 5 (50 MW) is projected (by Powerspan Corp.) to achieve 70,40-50,
and 70+ % NOx, SO2, and mercury emission reduction, respectively, in addition to 90 % PM2.s
removal
As the process is scaled up, the main uncertainty is whether it can achieve the performance
(emission reduction), which was achieved at smaller scale. Additionally, the estimated energy
consumption of the ECO system is expected to be 5 % of the gross energy production at the
plant. Finally, some uncertainty exists with regard to the salability of the byproducts in terms of
both their suitability (meeting market specifications) and price.
SCR + Wet FGD
The contribution of selective catalytic reduction (SCR) technology to mercury reduction
originates from the fact that SCRs have been shown to oxidize elemental mercury. Hence, the
synergism with wet scrubbers, which are effective in capturing oxidized mercury. Both SCR and
wet scrubber [wet flue gas desulfurization (FGD)] technologies are discussed below.
SCR - NOx Control. SCR technology 17 reduces NOx through a catalytically enhanced reaction
of NOx with ammonia, reducing NOx to water and nitrogen. This reaction takes place on the
surface of a catalyst, which is "housed" in a "reactor" vessel. The reactor ensures that the flue gas
is uniformly distributed over the catalyst as well as determining the flue gas velocity. Typical
catalyst materials are titanium/vanadium on a "coated" substrate structure that may take various
forms (e.g., plate, honeycomb). SCR system configurations are generally referred to by the
location of the SCR relative to the power plant:
•	"high-dust" - SCR located between the economizer and air preheater, upstream of the
ESP.
•	"low-dust" - SCR located between a hot-side ESP and the air preheater.
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• "tail-end" - SCR located after the air preheater, ESP, and FGD. This approach requires
the flue gas to be reheated prior to entering the SCR,
Ammonia (anhydrous or aqueous) is injected into the flue gas upstream of the SCR reactor
through a nozzle grid designed to ensure its uniform distribution in the flue gas and then through
the catalyst.
Wet FGD. Wet FGD refers to the most widely used S02 control technology worldwide
(approximately 200 GW of installed capacity)18. The most commonly used FGD technology uses
a wet limestone scrubber with in-situ forced oxidation to remove S02 from the flue gas while
producing a gypsum-grade byproduct. This is accomplished typically in a vertical vessel, with
flue gas contacting and reacting with limestone slurry to produce calcium sulfite/sulfate. Through
controlled oxidation of the reaction products, a salable byproduct in the form of commercial
grade gypsum may be produced. The intimate contact between gas and liquid is ensured through
different design approaches, usually involving several counterflow spray levels and mass transfer
"trays" to optimize gas/liquid interactions. The technology has evolved over the years through
"mechanical" improvements, which have included better gas and liquid distribution within the
scrubber, droplet size and size distribution, as well as "chemistry" improvements such as the
addition of organic acids (e.g., adipic acid, a dibasic organic acid, DBA), which not only improve
overall S02 capture but also help the settling characteristics of the waste products. Several
commercial variations of the technology exist based on reagent type, vessel design, etc.
Both technologies, SCR and wet FGD, are widely used commercially worldwide. In Germany,
for example, essentially all coal-fired boilers are equipped with SCR technology combined with
wet scrubbers. Over 50,000 MW of capacity is deployed worldwide. In the U.S., the technology
is being deployed at a rapid pace.19 Therefore, both SCR (for NOx control) and wet scrubbers
(for SO2 control) are readily commercially available.
As indicated before, the contribution of SCR technology to mercury reduction comes from the
fact that SCRs have been shown to oxidize elemental mercury. With respect to SCR performance
on mercury oxidation, testing is on-going at pilot- and full-scale sites 20 "23. Efforts by B&W 2
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Studying mercury oxidation has become a focus in efforts to enhance SCR and, in turn, wet FGD
technology. Further testing on the speciation of mercury must be conducted to gain a better
understanding of oxidation potential, oxidation vs. catalyst age, as well as fundamental
mechanisms. As SCR and wet FGD technologies are increasingly combined for N0X/S02
reduction, efforts to increase our knowledge and improve the ability of the SCR to oxidize
elemental mercury will result in a significant and inexpensive way to also control mercury
emissions.
Table 1. Selected SCR Test Results.
Control Unit
Control Unit-Status
Inlet Mercury
Oxidation
(% of total)
Outlet Mercury Oxidation
(% of total)
Pilot SCR
No ammonia
8-12
2-10
Full-scale SCR
Normal
10-18
4-7
Full-scale SCR
No ammonia
10-18
50
NH3 injection system
Normal
50-87
67-85
NH3 injection system
No ammonia
50-87
70-90
SIMULTANEOUS S02 AND MERCURY CONTROL
Dry scrubbers, advanced dry FGD systems, sorbent injection, modified wet FGD, and a wet
FGDAVESP combination can control S02 and mercury simultaneously. These technologies are
discussed below.
Dry Scrubbers
Dry scrubbers (spray dryers) are capable of reducing multiple pollutants (specifically S02 and
mercury) and are typically used in low- to medium-sulfur coal-fired power plants. "Dry" refers to
the fact that the flue gas leaving the scrubber is not saturated as in wet FGD (wet scrubbers). The
technology is suitable for new and retrofit applications. Spray dryers have been installed on
utility and industrial boilers, as well as hazardous and municipal waste incinerators.
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This technology, while predominantly used on low- and medium-sulfur coals, can be applied to
plants burning higher-sulfur coal as well, although this may be limited by the capacity of the
existing particulate control device (in retrofit situations) to accommodate the increase in
particulate loading (the quantity of sorbent is proportional to the S02 concentration and the
desired reduction sought, therefore increases with higher sulfur and reductions required). The
quantity of sorbent for a given application is typically referred to in terms of calcium-to-sulfur
ratio or stoichiometry and ranges from about 1.0 to 2.0 for S02 removals of 75 to 90+ %.
Spray dryers are a commercial and well-established technology in the U.S. and abroad, with over
11,000 and 7,000 MW of installed capacity, respectively I8. The technology was first used in the
early 1980s, and has been deployed in bituminous, subbituminous, and lignite applications.
¦JQ
Significant experience was gained in the U.S. through extensive testing programs .
Spray dryers are capable of very high S02 reductions (up to 95 %). Data from the International
Energy Agency's (lEA's) coal research indicates S02. reductions from 70 to 96 % with a median
value of 90 %, comparable to that of wet FGD technology. This performance reflects applications
with coals of less than 2 % sulfur18. Information and experience with mercury is less available
than for S02. However, a number of test programs as well as the recent EPA's Mercury
Information Collection Request (ICR) program have yielded some insight into the potential
mercury reductions in spray dryers25"27. It is important to recognize that the performance of the
spray dryers is typically reported together with the associated particulate control device [ESP or
fabric filter (FP)]. In other words, mercury reductions are reported from the inlet to the spray
dryer to the outlet of the ESP or FF. In a 1994 study 29, spray dryers captured mercury in a wide
but not fully understood range (6-96 %), based on data for seven installations on coal-fired power
plants. Although at that time, mercury speciation was not measured, the amount of mercury
removal increased with coal chlorine content, suggesting that spray dryers preferentially remove
oxidized mercury. The wide range in the reduction values indicates a lack of understanding of
basic physical and chemical processes talcing place in the control devices.
The efficiency of mercury removal by dry scrubbers is related to mercury speciation, as well as a
number of other factors. Additional information on mercury speciation and operating parameters
in spray dryer power plants is necessary to better understand and predict mercury reduction
performance. "Dedicated" mercury sorbents such as activated carbon should increase mercury
capture potential.
Advanced Dry FGD
Advances in dry scrubbing technology have focused on the general concept of increasing
gas/solids mixing, hence reducing residence times in the absorber and allowing for more rapid
evaporative cooling (1-2 vs. about 10 seconds in the conventional spray dryer). From a
configuration perspective, these designs for the most part, represent variations of Circulating
Fluid Bed (CFB) technology with differentiating design features specific to each vendor. As in
conventional spray dryers, lime slurry or hydrated lime is the typical sorbent used. A generic
description is presented below, followed by brief descriptions of specific technologies offered by
the major vendors. They include Circulating Dry Scrubbing (CDS) offered by LURGI, Gas
Suspension Absorbers (GSAs) by FLS Miljo, Reflux Circulating Fluidized-Bed absorbers
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(RCFBs) by WIJLFF GmbH, and the Rapid Absorption Process (RAP) by Beaumont
Environmental.
The CFB absorber is a vertical reactor where a dense material bed of recycle products (ash and
sorbent) ensures high gas/solids contact and more rapid cooling. The flue gas flows up through
the bed, with sorbent typically being sprayed in a slurry into the gas upstream of the bed. CDS-
LURGI technology uses a circulating fluid bed to establish a zone of high particle density. The
technology is used with hydrated lime injection for control of acid gases, and the bed is enhanced
with activated carbon for mercury adsorption 30 "32. GSA uses a cyclone to recycle products into a
dense bed, which allows for rapid evaporative cooling as with the other technologies B M. Flue
gas from the boiler flows directly into the bottom of the GSA vessel. Simultaneously, a lime-
slaked slurry is atomized into the reactor, flowing upward with the flue gas. The RCFB
introduces an internal reflux within the circulating fluidized-bed designed to increase the
gas/solid mixing and sorbent residence time 35'36. As with the other technologies, gas temperature
is controlled via internal water injection and SO2 reduction via the amount of sorbent supply. The
RAP uses a flash-drying reactor technology combined with an external mixing chamber3?'38.
Differently from circulating fluid beds, lime slurry is introduced into a recycle transfer bin where
it is mixed with recycle products, and then introduced into the reactor. Rapid cooling occurs as
the products are introduced into the reactor.
While not widely used in the U.S. at present, the four CFB-based technologies are commercial,
with installations in the U.S. and abroad. The first commercial CFB installation in the U.S. was
deployed on an 80-MW, coal-fired unit. Next, a 55-MW unit was installed, followed by pilot-
scale multipollutant control tests on a 321-MW coal-fired boiler. FLS Miljo offers GSA
commercially, with over 35 installations worldwide in operation since 1986. WULFF GmbH
commercially offers the RCFB. The technology is in full commercial use in plants ranging from
3 to 300 MW for the simultaneous removal of SO2 and mercury. RAP technology is currently
being demonstrated at the Southern Research Institute's (SRl's) combustion test facility. In
addition, a full-scale demonstration program at the Medical College of Ohio is currently
proceeding.
In general, the advanced scrubbers are capable of 90+ % SO2 reduction 39'40. With respect to
mercury control, less information is available, but high removal rates have been reported. CFB
without activated carbon injection achieved 50% capture of the mercury vapor. Mercury was
reduced by 80 % when the CFB was injected with iodine-impregnated activated carbon. For
GSA, the results of mercury removal tests ranged from about 41.5 to 89.5 %, without the use of
activated carbon. Mercury reduction by RCFB using activated coke is in the 90 % range.
In summary, similar to spray dryers, SO2 performance is well documented for the CFB-based
absorbers. Mercury capture can potentially be up to 90+ %, but is not well understood at present.
Opportunity to add "dedicated" mercury sorbent (e.g., activated carbon) will increase overall
mercury removal potential.
Sorbent Injection Processes
Sorbent Injection Processes refer to the use of sorbent materials, typically in a powder or slurry
form, which are injected into the flue gas upstream of a particulate control device. Inherently,
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sorbent injection is directly related to the type of particulate control used with it, as these devices
offer additional contact time for the reactions to take place, Sorbent injection technologies
received significant "attention" in the U.S. in the 1980s. More recently, the technology has seen
renewed interest driven by the need to control emissions of mercury from power plants. Two
types of sorbent hold promise for mercury removal: activated carbon and combined SO,/mercury
sorbents.
Activated Carbon for Mercury Control. The most commonly studied sorbent for mercury control
has been activated carbon. Commercially, activated carbons are available in a range of particle
sizes, as well as other performance characteristics 41 such as capacity and reactivity. Furthermore,
special activated carbon products, such as iodine- and sulfur-impregnated, are also available and
have been studied 42,43. DOE is currently sponsoring a full-scale demonstration of activated
carbon injection, which is scheduled for completion in 2003. The overall performance of the
technology is a function of many factors, including sorbent characteristics, as well as plant
configuration and operating conditions. Reduction levels from 50 to 90 % are possible and
anticipated for the range of technology configurations and activated carbons available. One
potential issue associated with activated carbon injection may be the deployment of new kilns
and furnaces that would be necessary to increase the production of activated carbon to meet the
potential market for coal-fired boilers. The current market for activated carbon is 250,000
tons/yr. Once mercury regulations are fully implemented, this could increase the demand to 2-3
million tons/yr."
Combined Mercury and SO2 Sorbents. The technologies for combined mercury/S02 and/or multi-
pollutant sorbent injection involve the same approaches described in the previous sections, while
using a combination of sorbents (e.g., activated carbon plus hydrated lime) or single, multi-
pollutant-capability sorbents. Pilot test programs have 44 45 documented the performance of
combined sorbents (activated carbon plus hydrated lime). Combining activated carbon with
hydrated lime can reduce the amount of carbon required (for an equivalent mercury removal) by
35 to 50%. Pilot tests of limestone furnace injection, followed by a cyclone separator, also
showed good removal of mercury from flue gas in a pilot-scale unit burning eastern bituminous
coals 46. Much laboratory activity has focused on the development of novel and enhanced
sorbents 47,48. Based on this experience, sorbent injection technology for combined S02-mercury
reduction represents a viable, although not fully quantified, approach for multipollutant control.
Laboratory investigations of calcium-based sorbents for mercury control47'49 have shed light on
the mechanisms involved, offering the potential for more efficient use of such sorbents across a
range of applications. Fly ash, hydrated lime, AD VAC ATE™, and all calcium-based sorbents
captured mercuric chloride (HgCl2) from simulated flue gas at 100 °C (212 °F) (although less
than commercial activated carbon). Addition of S02 to the gas mixture decreased the sorption of
HgCI2, suggesting that there is competition for the same alkaline sites between the two species.
In contrast, the calcium-based sorbents showed little or no removal of elemental mercury (Hg°)
in the absence of S02. Addition of S02 to the gas greatly enhanced the uptake of Hg°, suggesting
the possibility of some chemical reaction on the surface. More recently, hydrated lime and
silicates have been evaluated for mercury, NOx, and S02 capture in bench-scale tests. Oxidant-
enhanced silicate sorbents indicated enhanced mercury capture. The practical significance of
these results is that it is possibly more effective to separate the injection of sorbents dedicated to
12
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bulk acid gas removal (lower cost alkaline sorbents), from the higher porosity, oxidant-enhaneed
sorbents for mercury control 47,48. Unfortunately, while these studies offer a great deal of new
understanding about the chemical and physical interactions between the flue gas, mercury, and
sorbent, the results cannot yet be directly translated to full-scale performance.
Pilot scale testing44,41 with activated carbon, sodium, and calcium sorbents in a
COHPAC/TOXF.CQN configuration has shown the ability to inject activated carbon
simultaneously with other sorbents. Activated carbon performance was enhanced when tested
with hydrated lime. Similar mercury capture of 80+ % was obtained with much lower levels of
activated carbon when combined with hydrated lime.
Wet FGD Processes
As discussed earlier, wet FGD is the most widely used SO2 control technology in the World.
Therefore, the fact that wet-FGD has been shown to be efficient in capturing oxidized mercury in
the flue gas 50-54 is significant. This fact has triggered a number of developments geared towards
understanding and promoting the oxidation of elemental mercury in the flue gas of wet-FGD-
equipped plants. These efforts have focused mostly on the catalyst-enhanced oxidation and
reagent injection approach for mercury oxidation. In addition, and as a result of developments in
WESP and the compatibility of WESPs with wet FGD, the wet scrubber/WESP combination
represents another system approach to combined SO2 and mercury capture, as will be discussed
later. Because these various processes are predicated on well-known, conventional, and widely
used FGD technology, only the "add-on" technology components are discussed here.
The two major areas of development underway in the area of mercury oxidation in the flue gas,
upstream of wet scrubbers, involve catalytic oxidation 52,54 and oxidation resulting from reagent
injection 53'5S. The catalytic oxidation approach involves the deployment of a catalyst in the flue
gas to oxidize elemental mercury. While catalyst development and testing is at the laboratory
scale, full-scale application would likely involve a conventional support structure (e.g.,
honeycomb) placed between the particulate control device and the wet scrubber. A number of
catalyst materials have been investigated at several test sites including carbon, palladium, iron,
and high carbon flyash 55 with varying degrees of success.
Reagent-based oxidation involves the introduction of dedicated reagents into the flue gas or the
scrubber itself. In both cases, the objective is to promote the conversion of elemental mercury to
an oxidized form. The flue gas injection approach is expected to promote the conversion of HC1
to Cl2 in the flue gas, thereby providing a pathway for the formation of HgCl2 The direct
scrubber injection approach involves the addition of small amounts of a proprietary reagent into
the scrubber recirculation system53.
At present, catalytic oxidation is at laboratory and pilot-scale development stages. Tests have
identified several catalyst materials successful in oxidizing elemental mercury. Further testing of
these catalysts has focused on two issues associated with the catalytic oxidation process: 1)
catalyst life, and 2) the applicability of the process for the U.S. electric utility industry 52,54.
Results to date suggest that larger-scale testing is warranted at this time.
13
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In the course of several reagent-based oxidation tests conducted for wet scrubber enhancement, a
reagent was found which significantly improved mercury removal while having no negative
effects on scrubber operation. The technology is currently being demonstrated on a 55-MW scale
and further scale-up of the technology is planned53.
In laboratory and pilot-scale catalytic oxidation tests, Hg° oxidation was measured in the 70 to 95
% range. In particular, palladium, carbon, and high-carbon flyash-based catalysts, exhibited high
levels of performance. Further, tests to address catalyst longevity, while preliminary, indicate that
the palladium catalyst (little deactivation at close to 4000 hours), and three of the five tested
retained better than 70 % oxidation of the inlet elemental mercury at the end of the 5-month test
period 52. Results from two series of reagent-based oxidation testing indicated that high levels of
mercury removal (up to 86 %) were repeatedly achieved with small amounts of proprietary
reagents with no adverse effects on scrubber operation or S02 removal. This is in comparison to
baseline (no reagent) removal of mercury across the scrubber of about 72 %53.
Wet FGD with WESP
In the WESP, the collecting surface is cleaned with a liquid, as opposed to mechanical cleaning
for ESP. As a result, the two technologies differ in the nature of particles that can be removed,
the overall efficiency of removal, and the design and maintenance parameters 56,57. While dry
ESPs are typically limited to power levels of 100-500 W per 1,000 cfm, WESPs can handle
power levels as "high as 2,000 W per 1,000 cfm. As a result, WESPs can handle a wide variety of
pollutants and flue gas conditions and are highly efficient on submicron particles and acid mist.
WESPs have also been found to be most efficient in treating flue gases with high moisture
content and/or sticky particulate matter. WESPs are compatible with and easily integrated into a
system design with a wet FGD. In fact, integration of the WESP within the wet scrubber is a
design option with many synergisms and attractive features 22 such as: 1) compact footprint, 2)
ability to integrate the handling of the wash water and solids from the WESP with scrubber
slurry, and 3) ability to collect the fine sulfuric acid mist that typically escapes the scrubber due
to its very small droplet size.
Wet ESPs have been used for almost a century as standard technology in abating the submicron
particle S03 mist in H2SO4 plants. It was until recently, however, a relative unknown technology
to the electric power industry. WESP has been retrofitted on Northern States Power Company's
Sherco Station in a wet FGD/WESP configuration. In addition, a WESP system was recently
installed at Potomac Electric Power Company's Dickerson Generating Station, converting an
existing dry ESP to hybrid operation, by replacing the third field of the existing ESP to wet
operation 56. Two more power plant applications are underway: 1) a 5,000 cfm slipstream at
Bruce Mansfield Station; and 2) a plate-type WESP for integration with Powerspan's ECO
technology to be demonstrated at First Energy's Eastlake Station.
When integrated with upstream technology, including wet scrubbers, multiple pollutants can be
removed by WESPs. At a hazardous waste facility, a two-stage WESP following a scrubber
achieved 99.9 % removal of all acid gases, dioxins/furans, PM2.5, and metals. It achieved 78 %
removal of mercury56'57. At a mining operation, a combined scrubber and WESP system
14
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achieved an SO2 removal of 99 % 56'51. In pilot-scale tests at SRI5S, a plate-type WESP yielded
the following emission reductions: SO2, 10-25 %; SO3, -65 %; PM, 90-99 %; and Hg, -30 %.
Several conditions determine the efficiency of a WESP system and should be considered in each
specific design. These include air distribution, sparking, and corona current suppression.
Integration with wet scrubbers can offer significant advantages to wet scrubber operations,
specifically in H2S04 mist control. Material performance will be key to overall cost of the
technology as expensive alloys may reduce market appeal,
CONCLUSIONS
This paper presented various existing and novel control technologies designed to achieve multi-
pollutant emissions reductions. It provided an evaluation of multipollutant emission control
technologies that are available for coal-fired power plants of 25-megawatt (MW) capacity or
larger in the United States. The paper primarily addressed technologies that are capable of
simultaneously controlling NOx, SO2, and mercury emissions from electric utility sources.
Technologies that are capable of simultaneously controlling SO2 and mercury were also
addressed because of high interest in controlling mercury emissions.
The technology reviews are based on several sources of information including technology
vendors, technical papers, expert consultations, reports published by the DOE, and trade
publications. The results of this review reveal that:
•	The number of technologies under development, demonstration, or already commercially
available is significant.
•	A number of technologies have been widely used in power plants and/or industrial
applications.
•	A couple of technologies, which are not commonly used in the U.S., have been used in
other countries.
•	Three of the evaluated control technologies are capable of achieving simultaneous
reductions of S02, NOx, and mercury and show potential to achieve above 80 %
reductions of all three pollutants.
The environmental control technologies are summarized in Table 2. This summary includes the
status of commercialization: pilot (P), demonstration (D), and commercial (C); environmental
performance relative to S02, NOx, and mercury; and applicability. Some of these technologies
are combinations of commercial technologies that are being used to control at least one pollutant,
while others are under development with the specific goal of controlling multiple pollutants.
Issues related to cost, byproduct management, residue or waste disposal, and scale up are
currently being addressed to make these technologies more cost-effective and broadly applicable.
15
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Table 2. Summary of Environmental Control Technologies.
Technology
Status
Emission Reductions
Applicability
SO->/NO*/Mcrcurv
Control



Activated Coke
C
S02: 90-98%; NOx: 60-80%;
lie: 90-99%
New and retrofit
Electro-Catalytic
Oxidation
D
S02: 40-50%; NOx: 60-80%;
Hg: 70+%
New and retrofit
SCR + Wet FGD
C
S02: 95%; NOx: 90-95%;
Hg: 86+% (bituminous coals)
Plants with SCR and wet
scrubber technologies
S07/Mercurv Control



Dry Scrubbers
(conventional)
C
S02: >95%; Hg: 5- 85%
Low- to medium-sulfur coals
S02 Sorbents
P/C
S02: 40-85%; Hg: n/a
Units with ESP or FF for
particulate control
Activated Carbon with
S02 Sorbent Processes
P/C
S02: 40-85%; Hg: n/a
Units with ESP or FF for
particulate control
Wet FGD with
Mercury Oxidation
Processes
P
S02: 95%; Hg: 80+%
Wet scrubber plants
Wet FGD with WESP
C/P
S02: 99%; Hg: 80+%
Integration with wet scrubbers,
retrofit dry ESPs, new units
Advanced Dry FGD
P/C
S02: 90-98%; Hg: <90%
Low- to medium-sulfur coals
16
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19
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21
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KEY WORDS
Multipollutant control, selective catalytic reduction, wet ESP, wet scrubber
22
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r.rjrj, t, rrr TECHNICAL REPORT DATA
INKrlKL- Klr-r-bbb (Please read Instructions on the reverse before completing
	
1. REPORT NO. 2.
EPA/600/A-02/082
3. RE
4. TITLE AND SUBTITLE
Controlling Multiple Emissions from Coal-fired Power
Plants
5. REPORT DATE
6. PERFORMING ORGANIZATION CODE
7. author(s) r.Forte (EPA/CAMD),R.Srivastava (EPA/APPCD),
S.Tavoulareas (ETEC), R.Afonso (EES), and W.Jozewicz/
M.Doorn (ARCADIS)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Energy Technologies Enterprises Corp.,McLean,VA 22102.
Energy aND Environmental Strategies,Shrewsbury,MA 01545.
ARCADIS Geraghty & Miller,Inc.,P0 Box 13109, RTP,NC,
27709
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-C99-201/2-045 (ARCADIS)
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Published paper; 5-9/01
14. SPONSORING AGENCY CODE
EPA/600/13
15.supplementary notes appq) project officer is Ravit K. Drivastava, Mail Drop E305-01,
919/541-3444. For presentation at A&WMA 95th Annual Conference, Baltimore, MD,
6/23-27/02.
I6'abstract rj^e paper presents and analyzes nine existing and novel control technolo-
gies designed to achieve multipollutant emissions reductions. It provides an evaluation
of multipollutant emission control technologies that are potentially available for
coal-fired power plants of 25 MW capacity or larger in the U.S. The paper primarily
addresses technologies that are capable of simultaneously controlling nitrogen oxides
(NOx), sulfur dioxide (S02), and mercury emissions from electric utility sources. Tech-
nologies that are capable of simultaneously controlling S02 and mercury are also ad-
dressed because of high interest in controlling mercury emissions. Provided for each
technology are a brief technology description, the level of commercial readiness and
industrial experience, and emission control performance. Three of the evaluated control
technologies are capable of simultaneously reducing S02, NOx, and mercury and show
potential to achieve above 80% reductions of all three pollutants. Issues related to
cost, byproduct management, residue or waste disposal, and scaleup are currently being
addressed to make these technologies more cost effective and broadly applicable.
17. KEY WORDS AND DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. cosati Field/Group
Air Pollution Mercury (Metal)
Emission
Coal
Combustion
Electric Power Generation
Nitrogen Oxides
Sulfur Dioxide
Air Pollution Control
Stationary Sources
13B
14G
21D
21B
10A
07B
18. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
22
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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