STATUS OF S02 SCRUBBING TECHNOLOGIES
Wojciech Jozewicz and Carl Singer
ARCADIS Geraghty & Miller, Inc.
P.O. Box 13109
Research Triangle Park, NC 27709
Ravi K. Srivastava*
U.S. Environmental Protection Agency
National Risk Management Research Laboratory
Air Pollution Prevention and Control Division
Research Triangle Park, NC 27711
Peter E. Tsirigotis
U.S. Environmental Protection Agency
Office of Atmospheric Programs
Acid Rain Division
Washington, DC 20005
Abstract
Sulfur dioxide (SO2) scrubbers may be used by some electricity generating units to meet the
requirements of Phase II of the Acid Rain SO2 Reduction Program, which begins on January 1,
2000. Additionally, the use of wet scrubbers can result in reduction of fine particle precursor and
mercury emissions from combustion units. It is timely, therefore, to examine the current status of
SO2 scrubbing technologies.
This paper presents the extent of current SO? scrubber applications on electricity generating units
in the United States and abroad. The technical performance of recent SO2 scrubber installations is
discussed. A review of recently reported technical innovations to SO2 scrubbing technologies is
also provided. Data on mercury removal achieved with scrubbers are presented and discussed.
Current advances in scrubbing technologies to improve mercury capture are also presented.
* Corresponding author
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Introduction
A number of health and environmental impacts are associated with sulfur dioxide (S02) gas in the
environment. The major health concerns associated with exposure to high concentrations of S02
include effects on breathing, respiratory illness, and aggravation of existing cardiovascular
disease. In addition to the health impacts, SO2 leads to acid deposition in the environment. This
deposition causes acidification of lakes and streams and damage to foliage of trees and
agricultural crops. Additionally, acid deposition accelerates the decay of buildings and
monuments. Moreover, while airborne, S02 and its particulate matter derivatives contribute to
visibility degradation. Considering these deleterious health and environmental impacts, it is
imperative that emissions of S02 into the environment be controlled.
S02 is formed during combustion of sulfur-containing fuels such as coal and oil. Electric power
generating units comprise the key source of S02 emissions in the U.S. In 1994, these units
contributed to 70 percent of the national S02 emissions1. In response to the need to control S02
emissions, the Acid Rain S02 Reduction Program2 was established under Title IV of the Clean Air
Act Amendments of 1990 (CAAA). This two-phase program Is designed to reduce S02 emissions
from the power generating industry.
Phase I of the Acid Rain S02 program began on January 1, 1995, and will end on December 31,
1999. In 1997, 423 power generating units affected under Phase I emitted 5.4 million tons; i.e.,
1.7 million tons below the allowable 7.1 million tons of S023. Thus the S02 emissions in 1997
reflect a 23 percent reduction from the allowable amount.
Phase II of the Acid Rain S02 program begins on January I, 2000. To meet the requirements of
this phase, some power generating units may use flue gas desulfurization (FGD) technologies.
Additionally, the use of these technologies can result in the reduction of line particle precursor
and mercury emissions from combustion units. It is timely, therefore, to examine the current
status of FGD (or SC^ scrubbing) technologies.
This paper presents the extent of current FGD technology applications on combustion units in the
United States and abroad. The technical performance of recent FGD technology installations is
discussed. A review of recently reported technical innovations to FGD technologies is also
provided. Data on mercury removal achieved with scrubbers are presented and discussed.
Current advances in FGD technologies to improve mercury capture are also presented.
FGD Technologies
For the purpose of this paper commercially available FGD technologies have been divided into
three categories: wet, dry, and other. Wet FGD technologies include wet once-through
(throwaway) and gypsum by-product processes. Dry FGD technologies include the following
throwaway processes: spray drying, sorbent injection (furnace and duct), and circulating fluidized
bed (CFB). Other FGD technologies include regenerable processes with sodium sulfite (Wellman-
Lord) or magnesium oxide sorbent, and combined sulfur oxide/nitrogen oxide (SOx/NOx)
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removal processes. Processes within each category and discussed in this paper are presented in
Table 1.
Table 1
FGD Processes Discussed
FGD Technology Processes
Category
Wet Limestone Slurry
Lime
Dolomitic Lime
Sodium Carbonate
Seawater
Dry Spray Drying
Duct or Furnace Injection
Circulating Fluidized Bed
Other Regenerable Sodium Sulfite
Regenerable Magnesium Oxide
Combined SOxNOx
Wet FGD technologies are well established and use proven equipment components. For wet FGD
technologies, flue gas contacts alkaline slurry most often in a counterflow, vertically oriented
spray tower. Over the years, several process variations have been designed to improve the
technical reliability of wet FGD technology.
Limestone Forced Oxidation Process
Gypsum scaling and dewatering problems that plagued early wet limestone processes were
alleviated by the introduction of the limestone forced oxidation (LSFO) process. Consequently,
the LSFO process has become the preferred process for wet FGD technology worldwide. LSFO
offers the advantage of controlled oxidation of reaction products and scale-free operation of the
wet scrubber. Depending on site-specific conditions, LSFO may produce a salable byproduct in
the form of commercial grade gypsum that could be used for wallboard manufacturing4. A
variation of LSFO, recently demonstrated in the United States, is the jet bubbling reactor. This
process uses a jet bubbling reactor that combines limestone slurry reaction, forced oxidation, and
gypsum crystallization in one process vessel5.
Limestone Inhibited Oxidation Process
The limestone inhibited oxidation process was designed to control oxidation in the scrubber. In
this process, emulsified sulfur or sodium thiosulfate is added to the slurry feed to prevent
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oxidation to gypsum in the absorber's internals6. The waste product, calcium sulfite, having no
commercial value, is typically landfilled.
Organic acids, such as adipic acid, a dibasic organic acid (DBA), can be added to limestone slurry
in wet limestone processes (both forced or inhibited oxidation) to improve SO2 removal and
sorbent utilization7. The increased SO2 removal efficiency, in the presence of DBA, is a result of
its ability to increase limestone dissolution rate, and its buffering action (limiting the pH drop) in
the slurry. The added benefit of DBA use is the improved settling characteristics of waste solids.
Lime and Dolotnitic Lime Processes
The lime process uses hydrated lime slurry in a countercurrent spray tower. The process may be
designed to utilize alkalinity of both fly ash and sorbent. The dolomitic lime process is a variation
of the lime process in that it uses a special type of lime, dolomitic lime8.
In the dolomitic lime process, greater solubility of magnesium salts compared to calcitic sorbents
allows for the scrubbing liquor to contain significantly more alkalinity. Therefore, dolomitic lime
processes are able to achieve high efficiencies and do so in absorber towers that are significantly
smaller than their calcitic lime sorbent counterparts. Dolomitic lime processes allow for a
significant decrease of liquid-to-gas ratio (UG) (compared to LSFO) for a given target S02
removal. For example, to remove 90 percent of SO2 at 4.6 m/s (15 ft/s) fiuc gas velocity, an L/G
of 95 (gal/1,000 acfm) was required for LSFO process compared to 26 (gal/1,000 acfm) for
dolomitic lime process9. However, waste solids from dolomitic lime slurry processes have poorer
dewatering characteristics than solids from calcitic limestone slurry processes. The best
dewatcring operation of dolomitic lime processes occurrs when low solids concentration is
maintained along with moderate to low sulfite oxidation levels10.
Sodium Carbonate Process
In this process, SO2 is contacted with a spray of sodium carbonate solution. Products of the
reaction are sodium sulfite and sodium sulfate. Sodium carbonate processes have been applied on
some units due to the special sorbent availability at particular sites.
Seawater Process
This process utilizes a natural alkalinity of seawater to neutralize S02. Seawater is used as a
sorbent in a once-through mode of operation. The scrubber effluent flows to the treatment plant
where it is air-sparged to oxidize absorbed SOi into sulfate11.
Dry FGD technology produces a dry waste product following the contact of sorbent slurry or dry
sorbent with the flue gas. This FGD technology is usually associated with downstream baghouses
for particulate matter control. A downstream baghouse allows for SO2 removal occurring in the
baghouse as the flue gas passes through the collected spent sorbent. Three dry FGD technology
processes are considered in this paper: the lime spray drying process, the dry sorbent injection
process, and the circulating fluidized bed process (CFB process).
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Lime Spray Drying Process
Lime spray drying is a viable and proven process lor boiler systems tiring low to moderate sulfur
fuels and requiring moderate SO2 removal efficiency12. Process variations (rotary disc or two
fluid nozzle) involve the contacting of a finely atomized slurry of hydrated lime with flue gas at
the boiler exit temperature, usually at about 150 °C. Issues that limit the use of the lime spray
drying process with high-sulfur coals include the ability of the existing particulate matter control
device to handle the increased loading and the SO2 removal requirement.
Dry Sorbent Injection Processes
Dry sorbent injection processes arc based on flue gas contacting a finely dispersed sorbent.
Depending on the injection point of the sorbent (furnace or duct), dry FGD becomes a furnace
injection (FI) process or a duct injection (DI) process. In the FI process, a dry sorbent (most
often calcium hydroxide) is injected directly into the furnace in the temperature-optimized region
above the flame13. Flue gas downstream of the boiler's air prehcater can be humidified either
directly in the duct or in a humidifier/reactor to promote low temperature reaction of unused
sorbent with S02. Fly ash, reaction products, and any unreacted sorbent are collected in the
particulate matter control device. Solids from the particulate matter control device are often
recycled to boost the usage of alkaline material. In the DI process, a dry sorbent (most often
calcitic) is injected into the humidified flue gas downstream of the boiler's air preheater14. Fly
ash, reaction products, and any unreacted sorbent are collected in the particulate control device.
Recycling of (regenerated) solids from the particulate matter control device can increase the usage
of alkaline material.
Duct Spray Drying Process
In the duct spray drying process, flue gas contacts atomized lime slurry directly in the flue gas
duct15. This configuration precludes the need for a contacting spray-dryer-like vessel, while
providing the benefit of slurry droplets rather than dry solids contacting the flue gas for much
faster reaction. However, duct spray drying does place constraints on the amount of water that
can be evaporated, given the available residence time, the desired approach to saturation, and the
flue gas temperature.
Circulating Fluidized Bed Process
In the CFB process, dry sorbent (most often calcitic) is contacted with a humidified flue gas in a
CFB. The flue gas, laden with reaction products, is treated in a particulate matter control device.
Fart of the particulate matter removed by the control device is recirculated into the bed to
increase the usage of sorbent16
Sodium Sulfite Process
The sodium sulfite process (also known as the Wellman-Lord process) takes place in a
counterflow scrubber where pretreated flue gas contacts a sodium sulfite solution17. The product
of the reaction is a sodium sullite/bisulfite liquor. The liquor is subsequently regenerated in
evaporators that decompose bisulfite, expel concentrated S02, and crystalize sodium sulfite. The
concentrated S02 is suitable for sulfuric acid or elemental sulfur production.
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Magnesium Oxide Process
In this process, magnesium oxide slurry is used to absorb SO2. Hydrogen chloride and hydrogen
fluoride arc removed in a prescrubbcr. The magnesium sulfite/sulfate product is dried and
calcined in a kiln to regenerate magnesium oxide. The S02 captured during calcination may be
used to produce sulfuric acid or elemental sulfur17.
Combined SO^NOx Processes
Combined SCVNO* scrubbing processes currently are at the demonstration stage. An example
may be the combined SO2 and NOx high velocity scrubber that uses dolomitic lime scrubbing and
corona reactor18. Another process utilizes a low temperature oxidation of nitric oxide (NO) by
ozone injection, followed by a wet scrubber19.
Technology Applications
The following review is based on the CoalPower3 database from the International Energy
Agency's Coal Research Centre in London, England, and released in November 199820. The
database contains information on the world's coal fired power stations and their units,
environmental control systems, emission standards, and the names and addresses of electricity
generating units and companies supplying environmental control systems.
The first demonstrations of modern wet FGD technology were conducted in the United States
during the 1960s. The review of the database indicates that, of the existing wet FGD technology
systems in the United States, the LaCygne Unit 1 (894 MWC) and Cholla Unit 1 (114 MWC),
installed at boilers operated by Kansas City Power & Light and Arizona Public Service Co.,
respectively, are the two oldest ones, both installed in 1973. Worldwide, the oldest existing wet
FGD technology system is on Omuta Unit 1 (156 MWC, operated by Mitsui Aluminum Co.) in
Japan. A U.S. supplier installed this system in 1972. Among the existing dry FGD technology
systems in the United States, the oldest is on Riverside Unit 7 (150 MWC), installed in 1980 at
boiler operated by Northern States Power Co. The oldest dry FGD technology systems outside of
the United States were installed in 1985, on Duernrohr Unit 1 (405 MWC) in Austria and on
Saevenaes Unit HP3 (40 MWC) in Sweden. These units are operated by Verbundkraft
Elektrizitactswerke GmbH and Goeteborgs Energia AB, respectively.
Table 2 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
229,000 MWe generating capacity, worldwide. Of FGD systems installed on this capacity, 86.8
percent consist of wet FGD technology, 11.1 percent of dry FGD technology, and the balance of
various other FGD technologies. Through 1998, about 100,000 MWC of capacity in the United
States were equipped with FGD technology. Of these FGD systems installed, 82.9 percent
consist of wet FGD technology, 14.4 percent of dry FGD technology, and the balance of various
other FGD technologies. These percent shares of the three FGD technology categories installed
are shown in Figure I.
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Table 2
Through 1998, Capacity (MWC) Equipped with FGD Technology
Technology United States Abroad World Total
Wet
Dry
Other*
Total FGD
82,859
14,386
2,798
100,043
116,374
11,008
2,059
129,441
199,233
25,394
4,857
229,484
Other FGD technology includes regenerable sodium sulfite (Wellman-Lord), magnesium oxide, and combined SO, and NO, processes
The pattern of installations in the U.S. and abroad reflects that wet FGD technologies
predominate over other FGD technologies. It is generally recognized that high S02 removal
efficiency coupled with cost effectiveness have been responsible for the overwhelming popularity
of wet FGD technologies, and predominantly so wet-limestone-based FGD technology. While the
earlier wet FGD systems produced only waste by-product sludge, more recently many produce
salable by-product gypsum. This has probably increased the selection of wet FGD technologies to
some extent.
U.S.
Abroad
Worldwide
2.7%
14.4%
82.9%
8.5%
1.6%
89.9%
11.1 %
2.1%
86.8%
~w«
mDry
~ Other
Figure 1
Percent Shares of the Three FGD Technologies Installed
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It is interesting to examine the percent shares of the various wet FGD technologies installed
through 1998. Table 3 shows statistics describing wet FGD technology systems at power plants.
Of the worldwide wet FGD technology population, 82 percent are limestone processes and 15.8
percent arc lime (including dolomitic lime) processes. Correspondingly, in the United States,
limestone processes constitute 67 percent and lime (including dolomitic lime) processes constitute
29.6 percent of the total wet FGD technology installed. The attractiveness of dolomitic lime and
sodium carbonate processes depends on the availability of special sorbents required by them.
Limited availability of these special sorbents abroad has possibly limited the application of the two
processes. In the U.S., dolomitic lime and sodium carbonate processes have been applied on
some units due to special sorbent availability at particular sites.
Table 3
Through 1998, Capacity (MWe) Equipped with Wet FGD Technology
Process
United States
Abroad
World Total
Limestone
55,540
107,790
163,330
Lime
14,196
6,976
21,172
Dolomitic Lime
10,292
50
10,342
Sodium Carbonate
2,756
75
2,831
Seawater
75
1050
1,125
Other*
-
433
433
Total Wet FGD
82,859
116,374
199,233
Other processes include regenerate sodium sulfite (Wellman-Lord). magnesium oxide, and combined SO, and NO, processes
Table 4 shows statistics describing the pattern of use of dry FGD technologies. Of the worldwide
capacity equipped with dry FGD technology, 73.6 percent use spray drying processes. This
compares with 80.6 percent for spray drying processes in the U.S. Almost all of the remaining
installations of dry FGD technology use sorbent injection, which includes furnace (with and
without a downstream humidifier) and duct (calcium as well as sodium) injection. The dominance
of spray drying processes within the dry FGD technology category possibly is a result of these
processes being more economical than wet FGD technology for low to moderate sulfur coal
applications. These processes have been commercial in the U.S. since the early 1980s and abroad
since the mid-1980s. Other dry technology processes are considered to be niche applicatioas for
retrofit systems where only limited SO2 removal is required.
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Table 4
Through 1998, Capacity (MWC) Equipped with Dry FGD Technology
Process United States Abroad World Total
Spray Drying 11,555 7,100 18,655
Sorbent Injection 2,696 3,233 5,929
CFB 135 675 810
Total Dry FGD 14,386 i 1,008 25,394
Further understanding of recent FGD technology selections made by the U.S. electricity
generating industry can be gained by examining the 19,154 MW< generating capacity with
relatively recent FGD technology installations in the U.S. As reflected by the CoalPower3
database, froml991 through 1995, 14,366, 3,353, and 1,435 MWC of capacity was equipped with
LSFO, dolomitic lime, and spray drying processes, respectively. These data reflect that a majority
of these recent installations have selected LFSO processes.
Tabic 5 shows statistics describing the installation of FGD systems on worldwide electric power
plants. Through 1998, FGD systems have been installed on 678 units worldwide. Of the installed
FGD systems, 534 were wet FGD technology, 123 were dry FGD technology, and the balance
consisted of other FGD technologies. Through 1998, 235 units in the U.S. were equipped with
FGD technology. Of the installed FGD systems, 178 were wet FGD technology, 49 were dry
FGD technology, and the balance consisted of other FGD technologies.
Table 5
Through 1998, Number of Units Equipped with FGD Technology
Technology United States Abroad World Total
Wet 178 356 534
Dry 49 74 123
Other* 8 13 21
Total FGD 235 443 678
Other FGD technology includes regenerable sodium sulfite (Weliman-Lord), magnesium oxide, and combined SO, and NOt processes
Combining the data from Table 5 with those from Table 2 allows calculation of representative unit
sizes for each of the technologies considered here. These representative unit sizes are shown in
Table 6. Note that these representative sizes were arrived at by dividing the MWe shown in Table
2 by the pertinent number of units shown in Table 5.
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Tabic 6
Through 1998, Representative Unit Size (MWC) Equipped with FGD Technology
Technology United States Abroad World Total
Wet 466 327 373
Dry 294 149 206
Other* 350 158 231
Other FGD technology includes regenerable sodium sulfite (Wellman-Lord). magnesium oxide, and combined SO, and NO» processes
As seen in Table 6, the installations of wet FGD technology in the U.S., as well as those abroad,
appear to be on larger unit sizes compared to installations of dry or "Other" categories of FGD
technologies.
Performance and Applicability of Selected Technologies
As discussed above, various wet limestone processes and spray drying processes are the dominant
processes at present in terms of the capacity equipped with them over the last 30 years.
Therefore, the remainder of this paper will focus on the issues related to these processes.
Accurate SO2 reduction performance data for FGD processes installed to date are not readily
available at this time. However, an estimate of performance can be obtained by examining the
design SO2 removal efficiencies of these processes reported in the CoalPower3 database.
Table 7
Design SO2 Removal Efficiencies
FGD Technology Range of Design Median of Design
Efficiency, percent Efficiency, percent
Wet Limestone Processes 52-98 90
Lime Spray Drying Processes 70-96 90
Table 7 shows design SO2 removal efficiencies for wet limestone and lime spray drying processes.
The data in the above table reflect that wet scrubber systems have been designed for high levels of
SO2 removal (96 to 98 percent). Most wet limestone systems appear to be capable of 90 percent
SO2 removal. Note that lime spray drying has a shorter period of application compared to
limestone-based scrubbing (1980s onwards versus 1970s onwards). Therefore, the broader range
of efficiencies for limestone-based scrubbing compared to lime spray drying may reflect
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that: 1) over the longer period of application, improvements have been made in limestone-based
scrubbing processes and 2) SO2 reduction requirements may have had an effect as welL
Advanced, state-of-the-art wet scrubbers are capable of routinely achieving SO2 removal
efficiencies of over 95 percent. This is evidenced in the recently reported performance of the
LSFO process. The high velocity LSFO process with state-of-the-art design options, described
below, is reportedly capable of removing more than 99.6 percent of S0221. Spray dryers are
reported to often achieve greater than 90 percent SO2 removal on coals with 1 to 2 percent
sulfur22. CoalPower3 data indicate that all spray dryers installed during the period from 1991 to
1995 have a design SO2 removal efficiency of between 90 and 95 percent.
The performance of wet limestone and spray drying processes has improved significantly over the
period of their application. To investigate this improvement, the median design SO2 removal
efficiency was determined for the pertinent populations of wet limestone and spray dryer
installations for each of the three decades: 1970-1979, 1980-1989, and 1990-1999. The design
efficiencies reported in the CoalPower3 database were used to determine median design SO2
removal efficiency. Note that, since the lime spray drying process became commercial in the early
1980s, no median efficiency could be characterized for the 1970s for this process. For each of the
last three decades, median design SO2 removal efficiencies, as well as ranges of reported design
S02 removal efficiencies, for the wet limestone and spray drying processes are shown in Figure 2.
As can be seen from this figure, a steady improvement of the design SO2 removal efficiency can
be noted for wet limestone and spray drying processes. Note that this improvement may, in part,
be due to the increasing need to control S02 emissions. However, the trends do reflect that the
SO2 removal efficiency for the processes considered has improved with time.
There are some technical constraints against using the spray drying process on applications with
high sulfur coal. In the U.S., this process has primarily been used in retrofit applications on units
burning low sulfur coal8. There has been a great deal of discussion regarding the use of this
process on units with higher sulfur coal and required removal efficiency of over 80 percent. For
each spray dryer, there exists a maximurti solids concentration (sorbent slurry concentration)
above which the slurry cannot be easily atomized. High sulfur coal applications may require
sorbent slurry concentrations in excess of the maximum since the amount of water that can be
evaporated is a function of the desired approach to adiabatic saturation and temperature of the
flue gas.
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100
&
S
o
I
90 -
80 -
70
dL
o1
60 -
cs
83
50 -
ol
// Wet Limestone
Spra/ Drying
~ Mecn
1970s
1980s
1990s
Figure 2
Design SO2 Removal Efficiencies for Wet Limestone and Spray Drying Processes
Another technical constraint may be the physical size of the unit which is a function of the amount
of flue gas to be treated. Successful operation of a spray dryer is dependent on a uniform mixing
of finely atomized sorbent slurry with flue gas. For large spray dryer vessels, the limited
penetration of the atomized sorbent slurry may compromise control efficiency by creating a
portion of flue gas stream that is not contacted with a slurry.
Advancements
Over the last 30 years, significant advancements have been made in wet limestone processes.
Some of these advancements have been aimed at improving the performance and cost-
effectiveness of established processes while others have focused on developing new processes.
At present, several technical options exist for upgrading the performance of the existing
23
installations using wet limestone processes. These options include ;
• increasing sorbent amount used per mole of flue gas;
• increasing the reactivity of the limestone slurry with organic acid (e.g., DBA) addition;
• sorbent substitution;
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• increasing 1VG by increasing the recycle slurry flow rate (requires more pumping power);
• installing a perforated tray or other device to increase mass transfer; and
• reducing the amount of gas that is bypassed (requires more fan power).
In general, using the above options the existing installations may normally be upgraded to achieve
removal efficiencies of 95 percent or more.
When considering the feasibility of upgrade scenarios, interrelations between increased SO2
removal efficiency and many physical and technical parameters require a thorough evaluation. For
example, the addition of more sorbent would require the expansion of the reagent preparation
capacity and may require better or increased sorbent preparation (milling) capacity. Any increase
in efficiency will result in increased waste output, requiring increased slurry transport, dewatcring,
and waste disposal capacity24.
Economics of FGD processes, affected by technical advancements and regulatory requirements,
are driving numerous conversions of existing older wet FGD systems to more advanced ones.
These conversions are aimed at achieving improved SO2 removal efficiencies and/or waste
minimization. Limestone wet FGD systems can be converted to dolomitic lime ones to increase
SO: removal efficiency. For example, an inhibited oxidation limestone wet scrubber designed for
85 percent removal at an L/G of 70 (gal/1,000 acfm) and 3 mIs (10 ft/s) velocity has been
converted to dolomitic lime25. Following the conversion, SO2 removal efficiency increased to
96.7 percent at an L/G of 23 (gal/1,000 acfm). In another example of a vintage wet FGD
upgrade, conversion of an inhibited oxidation wet FGD process to an LSFO with DBA addition
was initiated in 199726. The objective of this conversion was to initiate production of
commercial-grade gypsum in place of calcium sulfite waste, which used to be fixated via
pozzolanic reaction with lime and fly ash prior to disposal in a landfill.
Several advanced design, process, and sorbent options are now available for new wet FGD
scrubbers27. These options are shown in Table 8.
When implemented, some of these advanced design options are capable of providing high SO2
removal and/or the operational efficiency of wet scrubbers.
Among design improvement options, construction of large capacity modules (single module per
unit) results in significant capital savings (up to 35 percent) compared to the baseline multi-
module design28,29. Increased Hue gas velocity in the scrubber allows for a reduced vessel size.
The reduced vessel size is possible because of increased mass transfer coefficients resulting from
higher gas/liquid relative velocity, increased turbulence, and increased percentage of droplets
suspended within the scrubber 8-21-30-31. Utilization of a cocurrent flow pattern provides a benefit
32
in the form of a reduced pressure drop across the vessel .
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Table 8
Advanced Options for New Wet FGD Scrubbers
Option
Approach
Design
large capacity modules
increased flue gas velocity in scrubber
cocurrent flow
improved mist eliminator
improved hydraulics
new materials of construction
Sorbent
organic acid buffering
ultraflne limestone grind
direct use of pulverized limestone
Process
wet stack
in-situ oxidation
wastewater evaporation system
gypsum stacking for final disposal
A considerable amount of fluid dynamics modeling effort has been invested in design
advancements for mist eliminators33. Modifications include shape (forward tilt into the gas flow),
spacing (additional drainage), and orientation (horizontal better than vertical for high velocity
scrubbers). These modifications benefit the user with an improved efficiency of mist eliminator
cleaning, reduced liquid/particulate matter carryover, and minimized droplet re-entrainment.
Design modifications also include improved hydraulics to increase gas/liquid contact throughout
the system. Improvements include: air rotary sparger (a device to provide better mixing and air
distribution in the reaction tank)34, optimized placement and selection of nozzles, and installation
of wall rings to eliminate sneakage close to the wall21. Finally, the advanced wet scrubber design
includes new materials of construction such as alloys, clad carbon steel, and fiberglass to provide
corrosion resistance at an optimum cost35.
Among improved sorbent options, the use of organic acid buffering (such as with DBA) allows a
reduced vessel size and/or increased efficiency through increased sorbent utilization. This
translates into a reduced L/G, number of pumps, and power consumption. Ultraflne limestone
grind improves limestone dissolution in the reaction tank (reaction tank size reduction) and even
in a spray zone21,36. An additional option is to implement the direct use of pulverized limestone
(i.e., pulverized limestone is bought directly from the supplier), eliminating the need for on-site
grinding and slaking.
Some process modifications are aimed at increasing the energy efficiency of the process and
include operation with a wet stack (no gas reheat) and a wastewater evaporation system. The
latter is accomplished by liquid purge injection into the hot flue gas upstream of the electrostatic
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precipitator (ESP). Other process options include in-situ forced oxidation, which results in waste
with better dewatering characteristics for disposal37.
Some of the advanced options (e.g., improved hydraulics, new materials of construction, and
ultrafine grinding) may be applicable to new spray drying systems.
Over the last few years, another interesting wet FGD process has been under development. This
process, wet ammonia FGD, has the potential to improve waste management in conjunction with
SO2 removal efficiency in excess of 95 percent38. Operators of conventional wet limestone FGD
processes may be confronted with saturated markets for commercial-grade gypsum of FGD
origin. The wet ammonia FGD process offers the unique advantage of an attractive ammonium
sulfate by-product that can be used as fertilizer.
This process also has the potential for becoming a promising option for units burning high sulfur
coal as it is also capable of removing other acid gases (e.g., sulfur trioxide [SO3] and hydrogen
chloride [HC1J) in addition to S02. While HC1 emissions can be reduced concurrently with SO2
emissions using currently commercial FGD technology, the removal of SO3 and control of
sulfuric acid (H2SO4) aerosol is not as straightforward. Depending on the type of FGD
technology, a considerable portion of H2SO4 aerosol may exit the stack as a respirable fine
particulate emission and may cause a visible plume39.
Other Potential Benefits of FGD
Mercury emissions from coal-fired power generation sources are reported to be almost 33 percent
of the total anthropogenic emissions in the U.S.40. Control of these emissions Is complicated by
the very low (usually below 1 ppm) mercury concentrations in the flue gas. Mercury species
present in the flue gas include elemental mercury vapor (IIg°) and oxidized mercury (Hg*") forms.
The capability of existing FGD processes to remove mercury from flue gas is affected by the form
of mercury present.
Conventional wet scrubbers can remove water-soluble Hg** compounds (e.g., mercuric chloride)
from flue gas. A wide range of mercury removal efficiency (0 to 96 percent) has been reported
for wet scrubber applications on bituminous-coal-fired power generation units . A major part of
Hg°, the most volatile of the trace metal species, can pass through particulate matter control
devices as well41, if left uncontrolled. Bench-scale research is underway to develop a fixed
catalytic bed to oxidize Hg°. Pilot-scale tests have demonstrated potential for removing
approximately 85 percent of total mercury emissions using a wet limestone process, with a
scrubber configured as a tray tower and operated at an L/G of approximately 70 (gal/1,000
acfm)41. Further pilot-scale evaluations continue to examine mercury speciation and develop
control options.
A recent mercury measurement program conducted on six full-scale coal-fired boilers equipped
with limestone or lime processes has demonstrated an average mercury removal across the wet
FGD system to be 54 percent (ranging from 45 to 67 percent). The ESP inlet and stack flue gas
15
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speciation data indicated 80 to 95 percent removal of Hg^ across the ESP and wet FGD system.
The statistical analysis of results showed a significant correlation between mercury removal and
scrubber slurry pH42.
Pilot-scale tests with the spray drying process have demonstrated a 64 percent total mercury
emission reduction across the spray dryer41. Using spray dryers, a range of 55 to 96 percent
reductions in mercury emissions has been shown on some full-scale, bituminous-coal-fired
28
boilers . Significantly lower reduction of 6 to 23 percent was reported for some subbituminous-
coal-fired boilers. It is thought that the higher mercury removal efficiencies seen on bituminous-
coal-fired boilers are related to the higher coal chlorine concentration in these coals compared to
subbituminous coals41.
As shown in Table 1, the duct injection process can be used to control S02 emissions. If, in this
process, a sorbent appropriate for mercury capture (e.g., activated carbon) is co-injected along
with the sorbent for S02 capture, then emissions of SO2 and mercury may be reduced. However,
the duct injection process has been used sparingly and is considered to be beyond the scope of this
paper.
In summary, the amount of mercury removed in a scrubber is believed to be a function of mercury
speciation. Wet scrubbers may be able to remove approximately half of the mercury from the flue
gas, depending on the coal fired. Spray dryers have been found to be able to remove between 6
to 96 percent of total mercury, depending on the type of coal fired. Currently, bench- and pilot-
scale research is underway to understand mercury speciation and develop control options.
Summary
This paper reviews SO2 scrubbing technologies. This review was aided by the information
available in the International Energy Agency's CoalPower3 database released in November 1998.
The pattern of past installations in the U.S., as well as abroad, reflects that wet FGD technologies
have been predominantly selected over other FGD technologies. It is generally recognized that
high S02 removal efficiency, coupled with operational reliability, has been responsible for the
selection of wet FGD technologies. Furthermore, the ability to produce a usable byproduct has
also contributed to their widespread use.
Most dry FGD installations employ lime spray drying processes. Most of the spray drying process
applications are on units burning low to medium sulfur coals. Other dry FGD technology
processes are considered to be niche applications for retrofit systems where only limited S02
removal is required.
The data reflect that some scrubber systems have been designed for high levels of SO2 removal
(96 to 98 percent) and that most scrubber systems appear to be capable of removing at least 90
percent of S02. The broader range of efficiencies for limestone-based scrubbing compared to
spray drying may reflect that: 1) over the longer period of application, improvements have been
16
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made in limcstonc-bascd scrubbing processes and 2) SO2 reduction requirements may have had an
effect as well.
Over the last 30 years, significant advancements have been made in wet limestone processes.
Some of these advancements have been aimed at improving the performance and cost-
effectiveness of established processes, while others have focused on developing new processes.
Using some of these advancements, existing older installations may be upgraded to achieve
removal efficiencies of 95 percent or more, while new installations may be able to achieve more
than 99 percent SO2 removal. The wet ammonia FGD process is under development. This
process offers an attractive ammonium sulfate by-product that can be used as fertilizer.
Moreover, the process also has the potential for becoming a promising option for units burning
high sulfur coal as it is also capable of removing other acid gases (e.g., SO3 and HC1) in addition
to SO2.
The amount of mercury removed in a scrubber is believed to be a function of mercury speciation.
A recent mercury measurement program has demonstrated an average mercury removal across a
wet FGD system to be 54 percent (ranging from 45 to 67 percent). The ESP inlet and stack flue
gas speciation data indicated 80 to 95 percent removal of oxidized mercury across the ESP and
FGD system. Spray dryers have been found to be able to remove between 6 and 96 percent of
total mercury, depending on the type of coal fired. Currently, bench- and pilot-scale research Ls
underway to understand mercury speciation and develop control options.
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18
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19. Anderson, M.H., A.P. Skelley, E. Goren, and J. Cavello, "A Low Tempertaure Oxidation
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21. Klingspor, J.S., and C. Brogren, "LS-2, Two Years of Operating Experience," Presented
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DC (1997).
23. Froelich, D., J. Landwehr, and D. Geschwind, "Compliance Options for Phase II of the
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32-37 (1995).
25. Inkenhaus, W., L. Loper, M. Babu, and K. Smith, "AEC Lowman Station FGD
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26. Straight, R.S., and J.D. Colley, "Conversion of the 1600 MW Mill Creek Generating
Station to Production of Commercial-Grade Gypsum," Presented at the Mega
Symposium, Washington, DC (August 1997).
27. Keeth, P., P. Ireland, and P. Ratlcliffe. "Utility Response to Phase I and Phase II Acid
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(March 1995).
28. DePriest, W., and J.M. Mazurek, "Key Issues for Low-Cost FGD Installation," Presented
at the Second International Conference on Energy and Environment: Transitions in East
Central Europe, Prague, Czech Republic (October-November 1994).
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London, England, 1997.
30. Gohara, W.F., T.W. Strock, and W.H. Hall, "New Perspective of Wet Scrubber Fluid
Mechanics in an Advanced Tower Design," Presented at the Mega Symposium,
Washington, DC (August 1997).
19
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31. Klingspor, J.S., and G.E. Bresowar, "Advanced, Cost Effective Limestone Wet FGD,"
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No. 2, pp. 101-106 (1991).
33. Kingston, W.H., D.K. Anderson, and W.F. Bauver II, "High Velocity Mist Elimination for
Wet FGD Application," Presented at the Mega Symposium, Washington, DC (August
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34. Weiler, H., and W. Ellison, "Wet Gypsum-Yielding FGD Experience Using Quicklime
Reagent," Presented at the Mega Symposium, Washington, DC (August 1997).
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40. Brenner, R., Framework for the Future, presented at the Conference on Air Quality,
McLean, VA, December 1998.
41. Redinger, K.E., A.P. Evans, R.T. Bailey, and P.S. Nolan, "Mercury Emissions Control in
FGD Systems," Presented at Mega Symposium, Washington, DC (1997).
42. DeVito, M.S., and W.A. Rosenhoover, "Flue Gas Ilg Measurements from Coal-Fired
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20
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NRMRL- RTP-P-430 (Pu f|| fIff/fTll'/|If'lflf 1 ffPIiTllllT *%tomPieting)
1. REPORT NO. 11 11 "¦"¦IIIIIIlll ||f| IJI
600/A-99/059 P399 1715S3
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Status of SO2 Scrubbing Technologies
S. REPORT DATC
6. PERFORMING ORGANIZATION COOC
7.authoris)W. Jozewicz and C. Singer (ARCADIS), R. Sri-
vastava (EPA, APPCD), and P. Tsirigotis (EPA,
ARD)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND AOORESS
ARCADIS Geraghty and U. S. EPA
Miller, Inc. OAP, Acid Rain Div.
PC Box 1310S Washington, DC 20005
RTP, NC 27709
10. PROGRAM ELEMENT NO.
11. CONTHACl /GRANT NO.
68-C-99-201
12. SPONSORING AGENCY NAME ANO AOORESS
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; 5-9/99
14. SPONSORING AGENCY CODE
EPA/600/13
is.supplementary notes APPCD project officer is Ravi K. Srivastava, Mail Drop 65, 919/
541-3444. For presentation at Mega Symposium,'Atlanta, GA, 8/16-20/99.
16.abstractpaper presents the extent of current sulfur dioxide (SC2) scrubber
applications on electricity generating units in the IJ. S. and abroad. The technical
performance of recent SC2 scrubber installations is discussed. Recently reported
technical innovations to SC2 scrubbing technologies are also reviewed. Data on mer-
cury removal achieved with scrubbers are presented and discussed. Current advan-
ces in scrubbing technologies to improve mercury capture are also presented.
(NOTE: SC2 scrubbers may be used by some electricity generating units to meet the
requirements of Phase II of the Acid Rain S02 Reduction Program, which begins on
January 1, 2000. Additionally, the use of wet scrubbers can result in reduction of
fine particle precursor and mercury emissions from combustion units. It is timely,
therefore, to examine the current status of S02 scrubbing technologies.)
17. KEY WORDS ANO DOCUMENT ANALYSIS
a. DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution
Sulfur Dioxide
Scrubbers
Electric Power Plants
Mercury (Metal)
Particles
Pollution Control
Stationary Sources
Acid Rain
Particulate
13 B
07R
07 A, 131
10B
14 G
18. DISTRIBUTION statfmfnt
Release to Public
19. SECURITY CLASS {This Report)
Unclassified
21. NO. OF PAGES
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
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