SERA
United States
Environmental Protection
Agency
National Risk Management
Research Laboratory
Cincinnati, OH 45268
Research and Development
EPA/600/SR-00/093 November 2000
Project Summary
Controlling SO2 Emissions: An
Analysis of Technologies
Ravi K. Srivastava and Wojciech Jozewicz
Sulfur dioxide (SO2) scrubbers may
be used by electricity generating units
to meet the requirements of Phase II of
the Acid Rain SO2 Reduction Program.
Additionally, the use of scrubbers can
result in reduction of mercury and par-
ticulate matter emissions. It is timely,
therefore, to review the commercially
available flue gas desulfurization (FGD)
technologies that have an established
record of performance.
The review of FGD technologies pre-
sented in this report describes these
technologies, assesses their applica-
tions, and characterizes their perfor-
mance. Additionally, the report
describes some of the advancements
that have occurred in FGD technolo-
gies. Finally, the report presents an
analysis of the costs associated with
applications of limestone forced oxida-
tion, lime spray dryer, and magnesium-
enhanced lime FGD processes. The
information presented in the report
should be useful to parties evaluating
FGD technology applications.
This Project Summary was developed
by the National Risk Management Re-
search Laboratory's Air Pollution Pre-
vention and Control Division, Research
Triangle Park, NC, to announce key find-
ings of the research project that is fully
documented in a separate report of the
same title (see Project Report ordering
information at back).
Introduction
Coal-fired electric power generating
units account for the majority of sulfur
dioxide (SO2) emissions in the United
States (U.S.). To mitigate SO2 emissions
from electric power generating units, the
Acid Rain SO2 Reduction Program was
established under Title IV of the Clean
Air Act Amendments of 1990 (CAAA). This
two-phase program was designed to re-
duce SO2 emissions from the power gen-
erating industry. Phase I of the Acid Rain
SO2 Reduction Program began on Janu-
ary 1, 1995, and ended on December 31,
1999. Phase II of the Acid Rain SO2 Re-
duction Program began on January 1,
2000. To meet the requirements of this
phase, some power generating units may
use flue gas desulfurization (FGD) tech-
nologies. Additionally, the use of these
technologies can result in the reduction
of fine particle precursor emissions and
mercury emissions from combustion units.
Therefore, it is timely to examine the cur-
rent status of FGD technologies.
The review of FGD technologies presented
in the report describes these technologies,
assesses their applications, and charac-
terizes their performance. Additionally, the
report describes the advances that have
occurred in FGD technologies. Finally, the
report presents an analysis of the costs
associated with FGD applications.
FGD Technologies
Commercially available FGD technolo-
gies can conventionally be classified as
regenerable and once-through, depend-
ing on how sorbent is treated after it has
sorbed SO2. In once-through technolo-
gies, the spent sorbent is disposed of as
a waste or a by-product. In regenerable
technologies, SO2 is released from the
sorbent during regeneration and may be
further processed to yield sulfuric acid,
elemental sulfur, or liquid SO2. Both once-
through and regenerable technologies
can be further classified as either wet or
dry. In wet processes, wet slurry waste or
by-product is produced, and flue gas leav-
ing the absorber is saturated. In dry pro-
cesses, dry waste material is produced,
and flue gas leaving the absorber is not
saturated.
FGD technology applications were re-
viewed based on information provided in
the CoalPowerS Database, available from
the International Energy Agency's Coal
Research Centre in London, England.
This database lists commercial FGD ap-
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plications. The review reveals that regen-
erable FGD processes are being used
only marginally, with once-through FGD
processes involved in the vast majority of
applications. Therefore, for this work, FGD
technologies were grouped into three
major categories:
• Wet FGD (consisting of once-through
wet FGD),
• Dry FGD (consisting of once-through
dry FGD), and
• Regenerable FGD (consisting of wet
and dry regenerable FGD).
Moreover, as regenerable technologies
are used only marginally, their coverage
in the report is limited.
The following paragraphs briefly de-
scribe commercially available FGD tech-
nologies, based on information in the
CoalPowerS Database.
Wet FGD Technologies
In these technologies, SO2-containing flue
gas contacts alkaline (lime or limestone)
aqueous slurry in an absorber. The most
often used absorber application is the
counterflow vertically oriented spray tower.
In the absorber, SO2 dissolves in the slurry
and initiates a reaction with dissolved al-
kaline particles. The absorber slurry efflu-
ent, containing dissolved SO2, is held in a
reaction tank, which provides retention time
for finely ground lime or limestone par-
ticles in the slurry to dissolve, and to com-
plete the reaction with the dissolved SO2.
As a result of this reaction, sulfite/sulfate
crystallization occurs in the reaction tank,
and available alkalinity of the slurry is de-
pleted. Fresh slurry is added to the reac-
tion tank to compensate for this depletion
and thereby maintain a desired level of
alkalinity. The slurry is recirculated from
the reaction tank into the absorber. Reac-
tion products from the reaction tank are
pumped to the waste handling equipment,
which concentrates the waste. From the
waste handling equipment, the concen-
trated waste is sent for disposal (ponding
or stacking) or, alternatively, processed
to produce a saleable gypsum (calcium
sulfate dihydrate) by-product.
Limestone Forced Oxidation
Over the years, limestone forced oxi-
dation (LSFO), which minimizes scaling
problems in the absorber, has become
the preferred process for wet FGD tech-
nology worldwide. Gypsum scale typically
forms via natural oxidation when the frac-
tion of calcium sulfate in the slurry (slurry
oxidation level) is greater than 15%. In LSFO,
scaling is prevented by forcing oxidation
of calcium sulfite to calcium sulfate by
blowing air into the reaction tank (in-situ
oxidation), or into an additional hold tank
(ex-situ oxidation). The gypsum thus
formed is removed as usual and, as a con-
sequence, the concentration of gypsum
in the slurry recycled to the absorber de-
creases. In LSFO systems used to produce
saleable gypsum, nearly complete oxida-
tion (over 99%) is achieved.
Limestone-Inhibited Oxidation
Another wet limestone process, de-
signed to control oxidation in the absorber,
is limestone-inhibited oxidation (LSIO). In
LSIO, emulsified sodium thiosulfate
(Na2S2O3) is added to the limestone slurry
feed to prevent the oxidation to gypsum
in the absorber by lowering the slurry oxida-
tion level to below 15%. In general, solids
dewatering is more difficult in LSIO,
compared to LSFO, due to the higher
level of sulfites. The LSIO chemistry is par-
ticularly efficient in applications with high
sulfur coals.
Lime and Magnesium-Lime
The lime process uses calcitic lime
slurry in a counterflow spray tower. This
slurry is more reactive than limestone
slurry, but is more expensive. Magnesium-
enhanced lime (MEL) is a variation of the
lime process in that it uses a special type
of lime. MEL is able to achieve high SO2
removal efficiencies in significantly smaller
absorber towers compared to calcitic lime.
Additionally, MEL needs less slurry, com-
pared to LSFO, for the same level of SO2
removal.
Dry FGD Technologies
In these technologies, SO2-containing
flue gas contacts alkaline (most often lime)
sorbent. As a result, dry waste is pro-
duced that is generally easier to dispose
of than waste produced from wet FGD
processes. The sorbent can be delivered
to flue gas in an aqueous slurry form
[lime spray drying (LSD)] or as a dry pow-
der [duct sorbent injection (DSI), furnace
sorbent injection (FSI), and circulating flu-
idized bed (CFB)]. LSD and CFB require
dedicated absorber vessels for sorbent to
react with SO2, while in DSI and FSI, new
hardware requirements are limited to sor-
bent delivery equipment. In dry processes,
sorbent recirculation may be used to in-
crease its utilization.
Lime Spray Drying
LSD is most often used by sources that
burn low-to-medium-sulfur coal. In a spray
dryer, simultaneous heat and mass trans-
fer between alkali in a finely dispersed
aqueous lime slurry and SO2 result in a
series of reactions and a drying of pro-
cess waste. Studies indicate that most
SO2 capture in the spray dryer occurs
when the sorbent is still moist. Therefore,
deliquescent additives may be used to
increase the duration of time in which the
sorbent remains moist.
Duct Sorbent Injection
DSI is intended to provide SO2 control
directly in the flue gas duct between the
air preheater and the particulate control
device. In this process, dry sorbent (most
often hydrated lime) is injected into the
flue gas downstream of the boiler's air
preheater. Water is injected separately
from the sorbent. Fly ash, reaction prod-
ucts, and any unreacted sorbent are col-
lected in the particulate control device.
Furnace Sorbent Injection
In FSI, dry sorbent is injected directly
into the furnace where temperatures are
between 950 and 1000 °C. Sorbent par-
ticles (most often calcium hydroxide, some-
times calcium carbonate) decompose and
become porous solids with high surface
area. Calcium sulfate, and any remaining
unreacted sorbent, leave the furnace with
the flue gas and are captured as solids in
a particulate collection device.
Circulating Fluidized Bed
In CFB, dry sorbent (hydrated lime) is
contacted with a humidified flue gas in a
CFB. The bed provides a long contact
time between the sorbent and flue gas
because sorbent passes through the bed
several times. CFB is characterized by
good SO2 mass transfer conditions from
the gas to the solid phase. However, due
to a higher particulate matter concentra-
tion downstream of the fluidized bed, im-
provements to the existing electrostatic
precipitator may be needed to maintain
the required particulate emission levels.
Regenerable FGD Technologies
Regenerable FGD technologies find
only marginal application in the U.S. and
throughout the world. These processes
involve comparatively high operation and
maintenance (O&M) costs, relative to other
FGD processes, and the return from sale
of the product does not offset a significant
portion of the increased process cost. Re-
generable FGD technologies discussed
in the report include four wet processes
(sodium sulfite, magnesium oxide, sodium
carbonate, and amine) and one dry pro-
cess (activated carbon). These processes
produce a concentrated stream of SO2 that
can be used for sulfuric acid production.
Technology Applications
FGD technology applications were re-
viewed based on the information in the
CoalPowerS Database, available from the
International Energy Agency's Coal Re-
search Centre in London, England. Find-
ings of this review are described below.
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Table 1 shows statistics describing the
installation of FGD systems at fossil-fuel-
fired electric power plants through 1998.
FGD systems were installed to control
SO2 emissions from over 226,000 MWe of
generating capacity worldwide. Of this
capacity, 86.8% utilizes wet FGD tech-
nologies, 10.9% dry FGD technologies,
and the remainder FGD technologies. A
similar pattern of FGD technology appli-
cation can be seen in the U.S. Through
1998, almost 100,000 MWe of capacity in
the U.S. was equipped with FGD technol-
ogy. Of this capacity, 82.9% utilizes wet
FGD technologies, 14.2% dry FGD tech-
nologies, and the remainder regenerable
FGD technologies.
Of the U.S. electricity generating ca-
pacity equipped with wet FGD technolo-
gies, 68.9% uses limestone processes.
Also 80.4% of the U.S. generating capac-
ity, equipped with dry FGD technologies,
uses LSD. A similar pattern of FGD tech-
nology usage is observed in overseas
applications. Limestone processes are
used for 93.2% of the overseas electric
generating capacity equipped with wet
FGD technologies. Also 64.8% of over-
seas generating capacity, equipped with
dry FGD technologies, uses LSD.
Recent FGD technology selections
made by the U.S. electricity generating
industry can be further understood by ex-
amining recent FGD technology installa-
tions in the U.S. Between 1991 and 1995,
19,154 MW of U.S. electric generating
capacity was retrofitted with FGD tech-
nologies. Of this capacity 75, 17.5, and
7.5% were equipped with LSFO, MEL,
and LSD, respectively.
Based on the data presented above,
FGD processes of choice have been wet
limestone FGD, MEL, and LSD. Of the
wet limestone processes, LSFO has been
used in recent applications.
Performance
An estimate of the SO2 reduction per-
formance of FGD technologies was ob-
tained by examining the design SO2
removal efficiencies reported in the
CoalPowerS Database. These data re-
flect that the median design efficiency for
all units using wet limestone processes is
about 90%. However, advanced, state-of-
the-art wet scrubbers are capable of achiev-
ing SO2 removal efficiencies of over 95%.
High velocity LSFO, with state-of-the-art
design options, is reportedly capable of
removing more than 99.6% of SO2 under
test conditions. The data also reflect that
the median design efficiency for all units
using LSD is 90%. However, recent LSD
applications, installed between 1991 and
1995, have design SO2 removal efficien-
cies between 90 and 95%.
It is useful to examine the improvement
in performance of wet limestone and LSD
processes over the period of their appli-
cation. Figure 1 shows ranges and medi-
ans of design SO2 removal efficiency for
the pertinent populations of wet limestone
FGD and LSD installations in each of the
last three decades. A steady improve-
ment in design SO2 removal efficiency is
evident for these processes. This improve-
ment may be due, in part, to more strin-
gent SO2 control requirements. However,
the trends do reflect that the SO2 removal
efficiencies for the processes considered
have improved with time.
Advances
Over the last 30 years, significant im-
provements have been made in the wet
limestone processes. Some of these ad-
vances have been aimed at improving
the performance and cost-effectiveness
of established processes, while others
have focused on developing new pro-
cesses.
Performance Improvements
Several technical options are available
for upgrading the SO2 removal perfor-
mance of existing wet FGD installations.
Some of the important options include
increasing the reactivity of the limestone
slurry with organic acid addition, install-
ing a perforated tray or other device to
increase mass transfer, and reducing the
amount of flue gas that is bypassed.
Several advanced design, process, and
sorbent options are also available for new
wet FGD installations. Some of these in-
clude using large capacity modules, in-
creasing flue gas velocity in the absorber,
and buffering with organic acid. These
advanced options are capable of provid-
ing high SO2 removal and/or increased
operational efficiency.
New Process-Ammonia Scrubbing
Over the last few years, a promising
wet FGD process has been under devel-
opment. This process, wet ammonia FGD,
has the potential to improve waste man-
agement in conjunction with providing SO2
removal efficiency in excess of 95%. At
Table 1. Electrical Generating Capacity (MWe) Equipped with FGD Technologies Through 1998.
Technology United States Abroad World
Wet
Dry
Regenerable
Total FGD
82,092
14,081
2,798
98,971
114,800
10,654
2,394
127,848
196,892
24,735
5,192
226,819
100
o
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present, the wet ammonia FGD process
offers the unique advantage of an attrac-
tive ammonium sulfate by-product that can
be used as fertilizer. In addition, this pro-
cess is also capable of removing other
acid gases (e.g., sulfur trioxide and hy-
drogen chloride).
The attractiveness of the ammonia
scrubbing process appears to depend on
the ability of the plant to sell ammonium
sulfate fertilizer. An evaluation of ammo-
nium sulfate prices over a period of 11
years has indicated a sustained increase.
This has been explained by its value as a
nutrient for selected crops and its ability
to replenish the sulfur deficiency in soils.
FGD Technology Costs
LSFO, LSD, and MEL have been the
processes of choice in recent U.S. appli-
cations. Therefore, in this work, state-of-
the-art cost models were developed for
these processes. These state-of-the-art
models are collectively called the State-
of-the-art Utility Scrubber Cost Model
(SUSCM) and are expected to provide
budgetary cost estimates for future appli-
cations. The following paragraphs briefly
describe and provide results for the state-
of-the-art LSFO, LSD, and MEL cost mod-
els developed in this work.
LSFO and LSD Costs
EPA's Coal Utility Environmental Cost
Workbook (CUECost) provides budget-
ary cost estimates (+30% accuracy) for
LSFO and LSD applications based on
user-defined design and economic crite-
ria. CUECost provided the starting point
for the LSFO and LSD cost models devel-
oped in this work. First, sensitivity analy-
ses were conducted with CUECost LSFO
and LSD algorithms to identify variables
that have a minor impact on cost (i.e., a
deviation of less than 5% over selected
baselines). These sensitivity analyses re-
vealed that, for both LSFO and LSD ap-
plications, the majority of cost impacts
can be captured with capacity, heat rate,
coal sulfur content, and coal heating value.
Next, variables other than the last four
were fixed at typical values in the corre-
sponding CUECost algorithms to arrive
at simplified LSFO and LSD cost models.
Then, the simplified LSFO and LSD cost
models were validated with published
data. Validation results reflect that on
average LSFO and LSD simplified cost
models predict the published costs within
+ 10.5 and 15.6%, respectively.
The simplified LSFO and LSD cost
models were then further adjusted with
cost-effective design choices to arrive at
the respective state-of-the-art models.
These design choices were based on in-
formation available on commercial appli-
cations. For LSFO, these choices included
largest absorber size corresponding to
900 MWe, absorber constructed of rub-
ber-lined carbon steel (RLCS) or alloy,
use of dibasic acid for pH buffering, and
either gypsum stacking waste disposal or
wallboard production. Similarly, for LSD
the cost-effective design choices included
largest absorber size corresponding to
275 MWe and RLCS absorber.
MEL Costs
In MEL, sorbent (magnesium-enhanced
lime slurry) is prepared in a similar man-
ner to that used in LSD, and this sorbent
is contacted with flue gas in an absorber
similar to a typical LSFO absorber. How-
ever, because MEL sorbent is more reac-
tive than LSFO sorbent, less flue gas
residence time is needed in the MEL ab-
sorber. As such, a MEL absorber is
smaller than a corresponding LSFO ab-
sorber. Further, MEL waste handling
equipment operates in a fashion similar
to that in LSFO, producing gypsum by-
product. Considering these characteris-
tics of MEL, for costing purposes this
process can be considered to be a com-
bination of LSFO and LSD. Therefore, the
LSFO and LSD algorithms developed as
described above were used appropriately
to develop the MEL cost model.
As for LSFO and LSD, cost-effective
design choices were made to arrive at a
state-of-the-art MEL cost model. These
choices included largest absorber size
corresponding to 275 MWe, absorber con-
structed of RLCS or alloy, and wallboard
production.
The comparison of capital and O&M
costs for three technologies considered
here is shown in Table 2. Ranges of costs
are given in 1998 constant dollars for
units between 100 and 1000 MWe. Table
2 shows that capital cost for LSFO used
on a small unit (100 MWe) is higher than
that of MEL used on the same unit. For a
large unit (1000 MWe), capital cost is lower
for LSFO. Fixed O&M cost is similar for
LSFO and MEL over the entire unit size
range considered. However, variable O&M
cost is lower for LSFO than for MEL,
largely due to the difference in the sor-
bent cost ($15/ton for LSFO versus $507
ton for MEL).
Table 2. Cost in 1998 Constant Dollars for Selected FGD Technologies.
Technology
LSFO"
LSD=
MELd
Capacity Range"
MWe
100-1000
100-1000
100-1000
Capital Cost
$/kW
542-195
363-140
384-238
Fixed O&M
$/kW-yr
18-7
12-4
16-8
Variable O&M
mills/kWh
1 .80-1 .78
2.24-2.24
2.02-2.01
a Unit has a heat rate of 10,500 Btu/kWh and a capacity factor of 90%.
b 4.0% sulfur coal application, SO2 removal of 95%.
0 2.0% sulfur coal application, SO2 removal of 90%.
d 4.0% sulfur coal application, SO2 removal of 96%.
W. Jozewicz is with ARCADIS Geraghty & Miller, Inc., Research Triangle Park, NC
27711.
Ravi K. Srivastava is the EPA Project Officer (see below).
The complete report, entitled "Controlling SO2 Emissions: An Analysis of Technolo-
gies," (Order No. PB2001-101224; Cost: $33.00 A07, subject to change) will be
available only from:
National Technical Information Service
5285 Port Royal Road
Springfield, VA 22161
Telephone: (703) 605-6000
(800) 553-6847(U.S. only)
The EPA Project Officer can be contacted at:
Air Pollution Prevention and Control Division
National Risk Management Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
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