United States
Environmental Protection
Agency
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
vvEPA
Technology Transfer
Summary Report
Sulfur Oxides Control
Technology Series:
Flue Gas Desulfurization
i
Wellman-Lord
Process
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Technology Transfer
EPA 625/8-79-001
Summary Report
Sulfur Oxides Control
Technology Series:
Flue Gas Desulfurization
Wellman-Lord
Process
February 1979
This report was developed by the
Industrial Environmental Research Laboratory
Research Triangle Park NC 27711
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li'i !lWT'"l9'^M'ri«.!fm '«
is if
. ' :.
Wellman-Lord flue gas desulfurization system. Northern Indiana Public Service Company
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The EPA Engineering
Applications/1 nf ormation
Transfer
Summary Report Series
This new U.S. Environmental
Protection Agency (EPA) Summary
Report series presents a summary
of engineering alternatives that
can be used to solve existing
environmental problems. Methods
for controlling sulfur dioxide
emissions constitute the first area
chosen for this hew series, with
the initial report discussing the
Wellman-Lord process. Future
summary reports will deal with
other flue gas desulfurization (FGD)
processes and with engineering
alternatives related to other
environmental problems.
The Industrial Environmental
Research Laboratory (IERL),
in Research Triangle Park,
North Carolina, !is responsible
for evaluating the reliability and
cost effectiveness of FGD
processes. The Wellman-Lord
process is a proven, viable
regenerable FGD system producing
elemental sulfur. This report
serves as a technical briefing of
FGD control technologies for
engineers, managers, and decision
makers who require information
about sulfur dioxide control
alternatives. i
IERL has initiated an Engineering
Application/Information Transfer
(EA/IT) series that makes the latest
technical information available to
the environmental community. In
addition to the Summary Report
series, other IERL EA/IT publica-
tions include the Databook series,
FGD Quarterly Reports, the EPA
Industrial Surveys, and the EPA
Utility FGD Surveys. The IERL/RTP
laboratory also publishes research
reports of ongoing 862 programs
including the proceedings of the
annual FGD symposium.
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Introduction
The Wellman-Lord flue gas
desulfurization (FGD) process,
shown schematically in Figure 1, is
being studied by the Environmental
Protection Agency (EPA) as part of
an extensive program of technology
development in the* area of flue
gas desulfurization. In this
regenerable process, sulfur dioxide
(SOa) is removed frpm flue gases
with a sodium sulfite scrubbing
solution. The concentrated SOa
stream that is produced can be
processed into elemental sulfur or
sulfuric acid.
There are currently more than two
dozen operating Wellman-Lord FGD
installations in the United States
and Japan. Several more units are
under construction. Since 1971,
these installations have controlled
the SOa emissions from Claus
and sulfuric acid plants and from
oil-fired boilers. Notable are the
installations at the Japan Synthetic
Rubber Company in Chiba, Japan,
and Northern Indiana Public
Service Company's (NIPSCO)
D. H. Mitchell Station in
Gary, Indiana.
Key
Flue gas/off-gas
Cleaned flue gas
Absorption liquor
Sulfur dioxide
Other systems
Desulfurized
flue gas
Flue
gas
Wellrnan-
Lord FGO
process
Concentration
S02
S02
processing
Sulfur
byproducts
Figure 1.
Typical Wellman-Lord System Followed by SO2 Processing as
Applied to a Power Plant Operation
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The Wellman-Lord installation at
NIPSCO, sponsored in part by EPA,
is significant because it is the first
application of the process to a
coal-fired boiler and the first
application to an American utility.
This system is demonstrating SO2
removal efficiencies greater than
90 percent in a regenerate
process. The results of this study
establish the Wei!man-Lord FGD
process as a viable SC>2 emission
control system for the utility
industry.
This report summarizes the
Wellman-Lord FGD operation, and
provides a basic understanding of
the significant processes for a
reader who is unfamiliar with FGD
technology. All equations are in
the un-ionized form to simplify the
presentation.
Wellman-Lord Fiecovery System at Northern Indiana
Public Service Company Dean H. Mitchell Plant with
320,000 stdftVmin treated flue gas
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Process Description
The Wellman-Lordiprocess consists
of four basic steps:
1. Flue gas pretreatment
2. 862 absorption:
3. Purge treatment
4. Sodium sulfite regeneration
A fifth step, the processing of
SO2 into sulfur byproducts, is not
a part of the Wellman-Lord
process but is generally associated
with Wellman-Lord installations.
Figure 2 illustrates, the process
flow for a typical Wellman-Lord
system installed on a coal- or
oil-fired boiler.
Boiler flue gas is pretreated by
contact with water in a venturi
prescrubber. This step cools
and saturates the gas, absorbs
corrosive chlorides, and removes
some of the particles remaining
in the gas after upstream particle
removal efforts.
The flue gas then flows to an
absorber where it is contacted
with a sodium sulfite solution. The
SO2 in the flue gas reacts with
the sodium sulfite to produce
sodium bisulfite. In a side reaction,
some sodium sulfate is formed
by direct oxidation of sodium
sulfite.
Desulfurized flue gas leaves the
absorber, is reheated if necessary,
and is exhausted through the
stack to the atmosphere. The
effluent from the absorption tower,
rich in sodium bisulfite and also
containing some sodium sulfite
and sodium sulfate, is split into
two streams. Approximately
15 percent of the effluent is routed
to a purge treatment for sulfate
removal. The remaining 85 percent
goes to a regeneration process.
-------
The purge stream is cooled in
a chiller and a mixture of sodium
sulfate and sodium sulfite is
crystallized out of the solution.
This crystalline mixture is removed
from the process and dried for sale
or disposal.
Regeneration is accomplished in
an evaporator where the
remainder of the scrubber effluent
is heated to convert sodium
bisulfite to sodium sulfite and to
drive off sulfur dioxide. The
regenerated sodium sulfite is
dissolved and recycled to the
absorber. Sodium lost during the
purge operation:is replenished
by adding sodium carbonate and
makeup water tb the feed
dissolving tank.;
The fifth step, SOa processing,
uses the sulfur dioxide byproduct
from the Wellman-Lord process.
The output of the Wellman-Lord
process is a gas stream of about
85 percent SO^, the remainder
is mostly water vapor. This
concentrated SO2 stream may be
dried and marketed without further
processing, reduced to elemental
sulfur, or oxidized and reacted with
water to form sulfuric acid.
Flue gas/off^
Cleaned flue gas
Absorption liquor
Sulfur dioxide
I I Other systems
Sulfur or
sulfuric.acid
Figure 2.
Typical Wellman-Lord Process
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Pretreatment
During pretreatment, flue gas is
compressed with a booster blower
and passed through a venturi
as shown in Figure 3(a). The
prescrubber cools and saturates
the gas while removing most
particles and chlorides and some
sulfur dioxide. Prescrubber inlet
temperatures range from 120° C
to 200° C (250° F to 400° F); exit
temperatures range from 50° C
to 55° C (120° Fto 130° F).1
An acidic waste stream results
from the absorption of chlorides
and some SOa in the prescrubber.
Alkaline fly ash can neutralize
some of this acid, but supplemental
alkali (lime) treatment may be
necessary. The neutralized waste
stream flows to a disposal pond as
a 5-percent solids slurry.
Absorption :
Absorption of SO2 from the
prescrubbed flue gas takes place
in an absorption tower, shown in
Figure 3(b). The flue gas enters the
bottom of the absorber and flows
countercurrently to the sodium
sulfite liquor. The li.quor absorbs
SO2 from the flue gas and is
continuously withdrawn from the
bottom of the absorber. A mist
eliminator removes! entrained liquor
from the gas stream, which is then
routed to the stack.
Removal of SO2 from the flue gas
involves absorption and then
reaction with sulfite to form sodium
bisulfite, as described by:
Na2SO3 + SO2+ H2O
2NaHSOs
(D
Makeup solution also reacts with
SO2 in the absorber to form
additional sodium sulfite according
to the following reaction:
Na2COf+SO2 +- (2)
Na2SOf + CO2
Part of the sodium sulfite is
oxidized to sodium sulfate in the
absorber as follows:
Na2SOf+ VfeOa »- Na2SO4 (3)
The sodium sulfate is unreactive
and of no further use to the
Wellman-Lord system.
8
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Flue gas/off-gas
Cleaned flue gas
Absorption liquor
Sulfur dioxide
Other systems
inversion \JV I I
reactant xil-I SOg I. . w
"*- " ^| processing I l
'-£/ Purge "7
\ off-gas \
!
,, _ »(
' Refrigeration | j.
» system (i |-
< crystallizer£__
i \T Bhyiene *\_J*
jL. *glyS?^ ^
Sodium sulfate
and sulfite
byproducts
Figure 3.
Wellman-Lord Process: (a) Flue Gas Pretreatment Operation and (b) S02
Absorption and Venting System :
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Purge Treatment
About 15 percent of the bisulfite-
rich stream leaving the absorber is
routed to the purge treatment area
for removal of the sodium sulfate.
As illustrated in Figure 4(a), the
purge stream is precooled by heat'
exchange with cold sulfate-free
liquor returning from purge
treatment. The stream then enters
a chiller-crystallizer where it is
further cooled to 0° C (32° F),
causing a mixture of sodium
sulfate and sodium sulfite to
crystallize out. Cooling for the
chiller-crystallizer is provided by
a refrigeration system.
The sodium sulfate/sodium sulfite
slurry is centrifuged to produce a
90-percent-solids cake. The
clarified liquor, essentially sulfate
free, is used to precool the
incoming purge stream and is
returned to the absorber liquor
stream entering the regeneration
step.
In addition to the primary purge
stream, a small amount of liquor is
removed from the evaporators to
help prevent a buildup of
impurities that result from
regeneration. This secondary purge
stream is added to the solids
cake from the centrifuge before
drying. The crystalline byproduct
from the drying is a- mixture of
anhydrous sodium sulfate
(70 percent) and sodium sulfite,
with small quantities of
thiosulfates, pyrosulfites, and
chlorides.2 ;
Off-gas from the dryer is cleaned,
generally in a cyclone and/or
baghouse, and recovered dust is
added to the dryer product. The
cleaned off-gas is routed to the
main flue gas stream upstream of
the prescrubber and processed
with the flue gas for SC>2 recovery.
Regeneration
The equipment used for sulfite
regeneration consists of a forced
circulation evaporator-crystal I izer
(or simply, evaporator), a
condenser, a condensate stripper,
and a feed dissolving tank.3 The
evaporator may be a single-effect
unit (heated by low pressure
steam) or multiple effect (having
secondary units heated by
overhead vapors from the previous
unit). A schematic representation
of the regeneration process is
given in Figure 4(b).
10
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Flue gas/pff-gas
Cleaned flue gas
Absorption liquor
Sulfur dioxide
Other systems :.
(b)
Conversion
reactant
Sulfur
byproducts
S02.
conversion
off-gas
Tray
absorption
tower
Vacuum
evaporator-
crystallizer
Vacuum
evaporator-
crystallizer
Absorber
surge
tank
S Makeup /
-* water V
- . Purge
;>To neutralization :' precooler
and disposal. '
Cyclone
and dust
collector
Centrifugate
tank
(a)
Sodium sulfate
and sulfite
byproducts
Figure 4.
Wellman-Lord Process: (a) Sodium Sulfate Purge System and (b) Regeneration Process with
Double-Effect Evaporators ;
11
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The absorption reaction is reversed
in the evaporator with the addition
of heat. Sodium sulfite is
regenerated according to the
following reaction:
* + 2HSO3
Na2S03 I + H20 + S02
(4)
This regeneration reaction is
limited by the equilibrium
concentration of sulfite ion in
solution. Since sodium sulfite is
less soluble than sodium bisulfite,
it is continuously removed from
solution by crystallization, thus
driving the regeneration reaction
(Equation 4) forward. This sodium
sulfite slurry goes directly to the
feed dissolving tank. The high
temperature also causes the
formation of small amounts of
sodium sulfate and sodium
thiosulfate according to the
reactions illustrated in Equations
(5) and (6).
The overhead stream from the
evaporator is passed through a
condenser to remove most of the
water vapor and to;concentrate the
SO2. The condensate is steam
stripped to remove idissolved SO2
and is then routed to the feed
dissolving tank. The overhead
stream from the condenser, which
contains about 15 percent volume
water and 85 percent volume
S02,1 is routed to an SO2
processing area.
2Na2SO? (5)
Na2S2Of + 2S02 + 3H2O
(6)
Na2S2C>3 + H2O
In the feed dissolving tank a
makeup solution of sodium
carbonate in water is added to
the stripped condensate and
regenerated sulfite liquor from
the evaporator. The makeup
compensates for water lost from
the system and for sodium purged
as nonregenerable salts. The
contents of the tank are agitated
and the resulting solution is fed
to the absorber where it begins
the absorption-regeneration
cycle again.
Sulfur Dioxide Processing
The present market demand for
dry compressed SO2 is quite low.
However, the concentrated high
purity SO2 stream from the
Wellman-Lord process may be
processed into one of two
marketable products: sulfuric acid
or elemental sulfur. Sulfuric
acid is produced by the Contact
Process; any of several S02
reduction processes may be used
to produce elemental sulfur.4
Integrated System
The processes described above
are part of the integrated system
shown in Figure 5. This figure
shows the relationship between
the processes.
12
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-t-v>- .~~-^^ ,~,:~...
\ Conversion XJJ
-,-.' rsacta.rit /'--
Vacuum
evaporator-
crystallizer
Key
Flue gas/off-gas
I8ggg.ll Cleaned flue gas
BMBB Absorption liquor
IF ; "' H Sulfur dioxide
\: '"j'-'l Other systems
SO2
processing
H
1 Sulfur
byproducts
S02
5
Vacuum
evaporator-
crystallizer
Condenser
< Absorber f
liquor Sv
_ Purge from
/ absorber
fventuri _
| surge |~ .
tank |,£--'.i
^T35" ' : ' ;.--'-' Purge
l- ~' '.j> To neutralization precooler
and disposal
1 Refrigeration
L
g"*"aft*WMm^r?mnB
|Centrifugate|
1 tank
X 90% solids'
f slurry
Sodium sulfate
and sulfite
byproducts
Figure 5.
Well man-Lord FGD Process
13
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Design Considerations
A complete discussion of the
design considerations involved in
the construction and operation of
a Wellman-Lord FGD system is
beyond the scope of a summary
report. However, trie following
discussion contains enough
information on design
considerations to p'ermit a
macroscopic analysis of the
process.
Pretreatment
The Wellman-Lord iprocess requires
a cool, essentially particle-free
gas for optimum operation of the
absorber. A venturj-type
prescrubber is preferred for use
in the Wellman-Lord installation
because it removes 70 to 80
percent of the particles remaining
in the flue gas after treatment
with an electrostatic precipitator
(ESP). The employment of an ESP
at the NIPSCO installation has
reduced the dust loading to a
design maximum of 0.47 g/m3
(0.2 gr/actual ft3). The prescrubber
was designed to handle this dust
loading and has demonstrated the
ability to handle considerably
greater loading for short periods.5
This feature provides some system
protection in the event of upset
conditions in the ESP.
Absorber
The primary factors to be
considered in design of the
absorber are the quantity of gases
to be cleaned, the'SO2 content,
and the desired SOa removal
efficiency. These factors control
the size of the booster fan, the size
and number of absorbers, and the
packing of the number of trays in
each absorber. Thus, they have
significant impact on capital and
operating costs.
Davy Powergas, Inc., which
markets the Wellman-Lord FGD
system, offers two types of
absorption units: a packed tower
for small volume applications and
a tray tower for large volume
applications.4 The tray unit is
generally built in a square
configuration and may contain
three to five trays depending on
the inlet SC>2 concentration and
the SC>2 removal efficiency
required.1
A single absorber is capable of
handling flue gas flow rates as
high as 175 normal m3/s
(370,000 stdft3/min). However,
higher volume applications require
multiple absorbers. Because
concentrated sodium sulfite
solution has a large absorptive
capacity for S02, the feed liquor
flow rate may be relatively low.
A recirculation system for each
of the trays assures optimum
hydraulic characteristics.1
One design requirement for the
absorber installed at the NIPSCO
installation is effective operation
at boiler output ranging from
46 MW to 110 MW. This
turndown requirement was met
by redesigning the absorber trays
to give a greater pressure drop
and an increased liquid/gas
contact time. Tray redesign also
reduced the required liquid/gas
ratio over the trays from 0.3
I/normal m3 (3 gal/1,000 stdft3)
to about 0.1 I/normal m3
(1 gal/1,000 stdft3).6 Superficial
gas velocity in the absorber is
about 3 m/s (10ft/s).
14
.
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The formation of sodium sulfate
in the absorber has received much
attention. The undesirable product
is formed by direct oxidation of
sodium sulfite and by the reaction
of sodium sulfite with sulfur
trioxide:
Na2SOf + 1/2O2 -A*- Na2SC>4 (3)
2Na3SO| + SO3 + H2O *-
Na2SC>4 + 2Na2HSOs (7)
The oxidation of sodium sulfite
shown in reaction (3) is the
major source of sodium sulfate
production in the Wellman-Lord
system.7 Because S03 contained
in the flue gas was absorbed in
the prescrubber, reaction (7) does
not contribute significantly to
sodium sulfate production in the
absorber.
Davy Powergas has determined
that the oxidation rate of sodium
sulfite in the absorber is a
function of the following factors:
Temperature and oxygen content
of the flue gas
pH of the absorber liquor
Absorber contact efficiency
Impurities in the liquor
Sodium sulfite concentration
Liquor recirculation rate in
the absorber
The first three of these factors are
system dependent variables and
therefore have a relatively "fixed
effect on the sodium sulfite
oxidation rate. The remaining
operational factors can be adjusted
within design constraints to
minimize oxidation.8-9
Wellman-Lord absorber and evaporator for removal of SO2 from refinery
tail gas, Richmond, California, Chevron U.S.A. Inc.
-------
The temperature of the entering
flue gas is fixed at the adiabatic
saturation temperature of the gas,
about 52° C (125° F) for flue gas
systems. Flue gas oxygen content
is related to the amount of excess
combustion air supplied to the
boiler and to any leakage that
occurs. The system pH, which
ranges from 5.5 to 7.0, is
controlled by the sodium
sulfite/bisulfite equilibrium.
The final system dependent
variable, absorber contact
efficiency, remains constant from
one application to the next, since
basic absorber design is standard.
Impurities in the absorber liquor
have some impact on the oxidation
of sodium sulfite. The most
effective means of controlling
the presence of these impurities
is efficient particle removal
upstream of the absorber. In
addition to upstream particle
removal, filtration of the circulating
liquor can prevent buildup of
impurities in the absorber system.9
A 25-percent increase in sulfite
oxidation has been observed for
oil-fired boiler applications of the
Wellman-Lord system, compared
with applications where fly ash is
not present (e.g., an acid plant
tail gas). Metal ions in the fly
ash could be contributing to
increased oxidation by acting as
catalysts through reversible
equilibria (e.g., Fe"1"2 .< * Fe+3).8
Short-term tests indicate that fly
ash from a coal-fired system has
the same effect as fly ash from an
oil-fired system. Long-term data on
sodium sulfite oxidation in a
coal-fired system will be obtained
from the NIPSCO installation.8
The concentration of sodium
sulfite in the absorber liquor can
be adjusted to reduce oxidation.
The solubility of oxygen decreases
rapidly with increasing sodium
sulfite concentration. Therefore,
operating the absorber with the
sodium sulfite concentration of
the liquor at or near the saturation
point reduces the mass transfer of
oxygen into the solution, and thus
reduces sodium sulfite oxidation.
I
Oxygen absorption ;in the system
is liquid-film controlled, and
therefore is proportional to the
liquor recirculation;rate. The
oxidation rate of sodium sulfite
can be reduced by 'reducing the
recirculation rate to the minimum
that will maintain required
removal. :
Purge System
In addition to the control of sodium
sulfite oxidation in the absorber,
several other approaches have
been investigated in an attempt to
reduce the loss of sodium and the
amount of sodium carbonate
makeup required for operation of
the Wellman-Lord system. One
successful method is a fractional
crystallization technique that
minimizes the amount of sodium
sulfite in the purge stream and
increases the concentration of
sodium sulfate in the purged solids
to about 70 percent. Fractional
crystallization has been employed
in three Japanese installations.
The first demonstration of this
technique in the United States is
at the NIPSCO installation.
Reheating
Reheating of the desulfurized flue
gas may be necessary to prevent
condensation of water vapor as
the gas is ejected from the stack
to the atmosphere. Such reheating
may be accomplished by heat
exchange with high pressure
steam. The NIPSCO installation
includes a direct-fired gas reheater
that can raise the flue gas
temperature by 30° C (50° F).
Regeneration System
The regeneration processing
area consists of a single- or
multiple-effect evaporator and
ancillary equipment such as
condensers, a condensate stripper,
and a feed dissolving tank.
Because all this equipment is
widely used by industry, the
design criteria are well defined.
The major item of equipment in
the regeneration processing area
is the evaporator. The design
parameters of this unit have been
developed to ensure continuous,
long-term operation, and
experience with existing
Wellman-Lord systems has proven
its reliability. As a result, the
primary concern in operating the
evaporator is efficient management
of the energy required for
reversing the absorption reaction.
The evaporator is normally
designed to use low pressure
steam as the energy supply,
thereby meeting the largest energy
requirement of the Wellman-Lord
process in a cost-effective manner.
A single-effect evaporator unit is
employed at the NIPSCO
installation. For very large
installations, or in the case of
high cost steam, the regeneration
systems might be operated with
multiple-effect evaporators.
Double-effect units, like those
illustrated in Figures 4(b) and 5,
reduce steam consumption by 40
to 45 percent and may be a
practical and economical design.10
This feature is especially important
for large installations where the
reduced operating expense will
more than offset the increased
capital costs.
16
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In a double-effect evaporator the
bisulfite-rich stream from the
absorber, combined with the
clarified liquor from the purge,
is split between two evaporator
units, with 60 percent going to the
first unit and 40 percent to the
second. The first unit operates at
90° C (200° F) and is heated with
low pressure steam in an external
shell and tube heat exchanger.
Normal operating pressure in the
steam chest is 120 to 140 kPa
(17 to 20 psig) with a steam feed
pressure of 210 kPa (30 psig). The
SO2 and water vapor driven off
in the overhead from the first unit
are used to heat the second,
which operates at about 80° C
(170° F).2
The liquor from each evaporator
contains about 45 percent
undissolved solids, primarily
sodium sulfite.2 Operating at such
a high solids concentration
eliminates the need to centrifuge
the liquor stream going to the
dissolving tank.
Sulfur Dioxide Processing
Because of the low demand for dry
compressed SO2, direct marketing
of the gas is not generally
considered a viable option. The
concentrated SO2 product stream
may be further processed into
marketable sulfur or sulfuric acid.
The Allied Chemical Corporation
process for conversion of S02 to
elemental sulfur has been
integrated with the Wellman-Lord
FGD process at the NIPSCO
installation. The Allied process
uses natural gas as a reductant
and employs a two-stage reactor
system.
In the first stage, SO2 and natural
gas are fed to a reactor containing
a proprietary catalyst. About
40 percent of the inlet S02 is
converted directly to sulfur in this
reactor. Hydrogen sulfide is also
produced, and the reaction
conditions are adjusted to produce
a 2:1 ratio of H2S to SO2 in the
product gases. This gas stream
then enters the second stage, a
Claus reactor, for recovery of
additional sulfur.
The overall reaction involved is:
CH4+2SO2'-+-
2S + CO2 + 2H2O
(8)
At installations where sulfuric acid
production is integrated with the
Wellman-Lord system, conversion
of SO2 to H2SC>4 is accomplished
in a conventional contact sulfuric
acid plant.
Because sulfur dioxide processing
varies with the end product
desired, the design considerations
presented here are of a cursory
nature.
Some of the aspects of sulfur and
sulfuric acid production that must
be considered are cost, storage,
and transportation. Sulfur
production is generally a more
complex process and requires
more equipment than sulfuric acid
production; therefore, the capital
costs are higher. In addition, raw
material and utility costs for
sulfur production are approximately
double the costs for sulfuric acid
production.4
However, the weight and volume
of sulfuric acid produced from a
given quantity of SO2 are
approximately three times the
weight and volume of sulfur that
could be produced from the same
quantity of SO2. Consequently,
three times the storage and
transportation capacity required
for sulfur production is needed
when sulfuric acid is produced. In
addition, sulfuric acid requires
more careful handling owing to its
corrosive nature.
In view of the foregoing, an
obvious trade-off exists between
the reduced raw material and
utility costs of acid manufacture
and the lower storage and
transportation costs of sulfur
production.
Site-specific considerations, such
as raw material availability and
marketability of the end product,
will also affect the final SO2
conversion process decision.
17
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Environmental
Considerations
The Wellman-Lord; process can
achieve SO2 removal efficiencies
of greater than 90 percent.
Operating commercial installations
have demonstrated that the
process can consistently maintain
SO2 emissions below 200 parts
per million volume! (ppmv). If
emissions regulations permit,
however, the process can be
"turned down" in the interest
of lower utility costs.
The Wellman-Lord! process
requires efficient particle removal
from the flue gas upstream of
the absorber. An ESP is used
upstream of the prescrubber at
the N1PSCO plant, :but any efficient
particle removal device will do.
Particles removed by the
prescrubber exit in a slurry that
may be pumped to an ash disposal
pond or other disposal site. The
slurry occasionally; requires
neutralization before disposal. The
quantity of paniculate solids in the
waste stream is not necessarily
increased by the use of the
Wellman-Lord process. The same
amount would result from particle
removal efforts necessary for
compliance with current emission
control standards for any coal-fired
boiler.
An additional consideration is
disposal of the sodium
sulfate/sodium sulfite cake from
the purge treatment operation.
The primary source of the sodium
sulfate is the oxidation of sodium
sulfite in the absorber, as
discussed under Design
Considerations. Based on an
empirical oxidation rate,2 a
Wellman-Lord process applied to
a new 500-MW power unit
burning 3.5 percent sulfur coal
would produce 1,240 kg/h (2,735
Ib/h) of mixed anhydrous sodium
sulfate (70 percent) and sodium
sulfite (30 percent). This represents
about 8.7 Gg (9,600 tons) of mixed
salts per year if the plant operates
7,000 hours at 100 percent
capacity.
Although this sodium
sulfate/sodium sulfite byproduct
has a somewhat limited
economic value, a market may
exist in the paper industry where
the cake might be used to replenish
sulfur in the pulping liquor.
Process emissions could result
from entrained mist in the gas
leaving the absorber and from
fugitive dust escaping the sodium
sulfate drying operation. These
emission sources have been
successfully controlled, however,
by installing a well-designed
mist eliminator on the absorber
and a well-designed dust control
system on the dryer.6
,
18
-------
Wellman-Lord sulfur recovery unit on refinery tail ga|s system, El Segundo, California, Chevron U.S.A. Inc.
-------
Status of Development
In 1965, Wellman-Lord
Engineering, Inc., initiated
research to develop a process to
recover SC>2 from flue gases.
After reviewing the literature,
Wellman-Lord researchers decided
to pursue some laboratory work
done in the 1930's.: Further
development work provided the
data needed for preparation of a
preliminary design.
i
In 1967, a 0.9 normal mVs
(1,900 stdftVmin) pilot system
was installed and operated at a
generating station of the Tampa
Electric Company. The initial
design was based on potassium
sulfite/bisulfite chemistry.
The data gathered from this small
pilot unit were used to design,
construct, and operate a 22
normal mVs (47,000 stdftVmin)
FGD system at Baltimore Gas &
Electric Company's Crane Station.
This demonstration;system, known
as the Maryland Clean Air
Demonstration Plant, developed
scaling problems in1 the absorber
and inordinately high steam
consumption in the; evaporators.
The problems with the Maryland
demonstration planjt led
Wellman-Lord Engineering, Inc.,
to abandon the potassium
sulfite/bisulfite system in favor
of a sodium system. The
sodium-based system is preferred
because sodium bisulfite is more
soluble than sodium sulfite; the
opposite is true of the analogous
potassium salts.
There are several advantages to
this difference in solubility
behavior. First, as sulfite liquor
absorbs SOa, it becomes less
saturated in sodium salts. As a
result, there is virtually no
possibility of scaling or plugging in
the absorber. In addition, the
sodium system can operate with
a highly concentrated recirculating
liquor that substantially reduces
steam costs in the regeneration
processing area. Finally, capital
costs of the sodium system are
lower because smaller sized
equipment can be used to process
the more concentrated liquor.11
The first sodium sulfite system
was installed for Olin Corporation
in 1970 to treat a 20 normal mVs
(45,000 stdftVmin) stream of acid
plant tail gas. Despite some initial
difficulties, the plant operated
successfully.12
In 1971, Wellman-Lord
Engineering, Inc., was bought by
Davy International, Ltd., and is
now known as Davy Powergas,
Inc. During 1971, the
Wellman-Lord process was applied
to an oil-fired industrial boiler at
the Japan Synthetic Rubber
Company located in Chiba, Japan.
Again, the plant was operated
successfully after some initial
difficulty. This unit has since been
able to achieve greater than
90 percent removal of SOa with
an on-stream factor of over
97 percent.1 Continued
improvements have been achieved
in both design and operating
techniques as experience with
system operations has increased.
20
-------
-------
The Wellman-Lord process has
since been applied to other
sources of S02. More than two
dozen plants were on stream as of
late 1977 in the United States. In
addition, Davy Powergas, owner of
the Wellman-Lord process, has a
number of contracts in various
stages of completion. Tables 1 and
2 summarize all known planned
and completed Wellman-Lord
systems.
The 220-MW unit at Chuba Electric
Power's Nagoya Station in Japan
and the 115-MW unit at the
NIPSCO installation are significant
examples of power plant
applications of the Wellman-Lord
technology.
Before the startup of the two new
installations by Public Service of
New Mexico, at Stations No. 1 and
No. 2 in Fruitland, New Mexico,
the Chuba installation was the
largest Wellman-Lord system. It
also has a relatively'long operating
history of 3 years.2 The system is
installed on an oil-fired base-load
unit and has followed rapid load
swings from 35 to 1p5 percent of
plant nameplate capacity. Thus, its
flexibility and turndown capabilities
are well proven. The ability to
follow such load swings is
provided by the large storage
capacity for the bisulfite-rich liquor
leaving the absorber. This
Wellman-Lord unit has proven
very successful, consistently
Table 1.
Wellman-Lord Installations in the United States
Company and
location
achieving 90 percent removal of
SO2 with a high (97 percent or
more) on-stream factor.11
The NIPSCO installation integrates
the Wellman-Lord S02 recovery
process with the Allied Chemical
SO2 reduction process. This
installation is significant because it
is the first application of the
Wellman-Lord system to a utility
boiler in the United States, the
first EPA-supported demonstration
facility to byproduce elemental
sulfur, and the first application of
the process to a coal-fired boiler
anywhere in the world. It is
anticipated that this demonstration
will produce valuable information
that will establish the
Feed gas origin
Gas volume treated
normal m3/s
stdftVmin
Startup
date
Units on stream:
Olin Corporation Sulfuric acid plant
Paulsboro NJ
Standard Oil of California Claus plant
El Segundo CA
Allied Chemical Corporation Sulfuric acid plant
Calumet IL
Olin Corporation Sulfuric acid plant
Curtis Bay MD
Standard Oil of California Claus plant
Richmond CA
Standard Oil of California Claus plant
El Segundo CA
Standard Oil of California Claus plant
Richmond CA
Northern Indiana Public Service
Company 115-MW coal-fired with 80% load
Gary IN factor and recovery capacity
Public Service Company of
New Mexico 375-MW coal-fired boiler system,
Water flow NM San Juan Station No. 1
Public Service Company of
New Mexico 375-MW coal-fired boiler system,
Waterflow NM San Juan Station No. 2
Units in design or construction: '
Getty Oil Company 60-MW mixed fuel boiler system,
Delaware City DE Delaware City No. 1
Getty Oil Company 60-MW mixed-fuel boiler system,
Delaware City DE Delaware City No. 2
Getty Oil Company 60-MW mixed-fuel boiler system,
Delaware City DE Delaware City No. 3
Public Service Company of
New Mexico 550-MW coal-fired boiler system,
Watorflow NM San Juan Station No. 3
Public Service Company of
New Mexico 550-MW coal-fired boiler system,
Waterflow NM San Juan Station No. 4
20.1
13.4
13.4
34.8
13.4
13.4
13.4
105
840
43,000
28,000
28,000
74,000
28,000
28,000
28,000
223,000
1,780,000
235
1,121
520,000
2,400,000
1970
1972 ,
1973
1973
1975
1975
1976
1977
1978
1980
1981
22
-------
Well man-Lord process as a viable
FGD system for use by the utility
industry in controlling SC>2
emissions.
Although the design and operation
of the Wellman-Lord system have
proven relatively successful,
improvement efforts are underway.
Currently, the areas receiving the
most intensive investigation are
the design of the regeneration and
purge treatment systems. Recent
innovations include the use of
multiple-effect evaporators,
because of their reduced steam
requirements, and the fractional
crystallization technique, which
can minimize loss of sulfite in
the purge.
Efforts have also been directed
toward developing a process for
converting sodium sulfate to a
form (e.g., Na2CO3 or NaOH) that
could be returned to the system.
Various techniques employed by
the paper industry indicate that
sodium sulfate conversion or
reduction is possible. The
economic feasibility is still
uncertain, however, and some
technical problems are unresolved.
Davy Powergas has investigated
the use of an antioxidant to reduce
the quantity of isodium sulfate
formed in the system. The cost of
using the antioxidant was greater,
however, than the cost of
replacing the sodium purged as
sodium sulfate. Therefore, use of
an antioxidant has been
discontinued in favor of the
various operational techniques
for minimizing oxidation.
With a significant number of
commercial plants in operation, as
shown in Tables 1 and 2, the
Wellman-Lord Process has been
demonstrated on a large scale for
extensive periods of time. However,
the NIPSCO installation will
examine the operability of the
system with coal-fired flue gas and
and the integration of
Wellman-Lord absorption/regen-
eration technology with the Allied
Chemical SO2 reduction process.
Table 2.
Wellman-Lord Installations in Japan
Company and
location
Feed gas origin
Gas volume treated
normal ms/s
stdftVmin
Startup;
date
[oa_Nenryo Claus pfant
Kawasaki
tan Synthetic Rubber Company Oil-fired boiler I
Chiba
fpiuba Electric............ ....^............. '_ 220-MW oil-fired power plant
jpfe^Nagoya . . .
y^pan Synthetic Rubber Company ....... Oil-fired boiler,
|ii-Yokkaichi ------ ., --,._ -.- -,--, """f';~ .--.'" ; :.
Kashima Oil Company Claus plant
^j'Kashirna....;'::. :._v .V?:.'.;'-. . ;'T;;; ...:'-'''.. ,.,.'.'.';.'' :- .:.".'.-.-.'
gujpitomo Chiba Chemical Company.......... Oil-fired boiler: . ..
K^'Sodeguara ." ' ' .".'. . ; '; '*.. ' ~.~'.'.*. '.'/'
i Film .'...'.'.".'........................... Oil-fired boiler '..'.. . . .'-.'.
jgM-Fujinomiya ; "'''''..''..
|Xp_a Nenryo : ........ Claus plant \ ' .
(Ste^ Hatsushima . . . . . . '.;..'
ployp Rayon ...... ..;........ Oil-fired boiler
fc;---. Nagoya ' .''.'" . . / ..". , '.-'-: ; "..'
tguroitomo Chiba Chemical.Company...... Oil-fired boiler/'
g^- Niiharna ...'.''. . - ' 'I . .
feSMn Paikyowa Petrochemical Company...... Oil-fired boiler . . .. .
B£^-:Yokkaichi . ' . ...... ....!;.., .'..." .'.. .;,-.'. .',!',' ...-.,'
^^{t^Jbis.hJihemical ,.:l..,v,....................... j.pii-fired'boiler,"' .... ... ..
Jl|p..-:Mizushirna : , ... ...-....-..". . .'.:.
iKurashiki Rayon ,. Oil-fired boiler
E; Okayama ."'""'. - - . . - :.-.--.-- -
Rutsubishi Chemical Oil-fired.boiler j
yJF^ Mizushima . '-- .: .. .... ;
I Mitsubishi .Chemical ............,.......,,....,,.. ... .Oil-ficed, boiler'.. : . .-. L. ;
Kurosaki . ..' . --..-.-. ,,,...., .^ .....-.., ^ ...., .
fjapan National Railroads 200-MW oil-fired power plant
Kawasaki . '..'...'.'. ' .'.'-'"' I
t^JjuKy Electric .Company 100-MW oil-fired power plant
Niigata . .'."'; ' ': .'.''..
18.3
55.4
174
125
"'' 8.93
..IPO .
4.47
97.4
40.6
113
167
111
174
1.49 ''"'
194
105
39,000
117,000
368,000
265,000
T9,QOO
2)2,000
84,000
9,500
206,000
86,000
239,000
'; 354,000
235,000
369,000
316,000
414,000
222,000
19711 *
1971 ,
1973 '*-
1973 ^
1974 ;J
1974 !
1975"°
' ' ^
1975*
1975 *
:,1975 j
1976 ^
1976"'
.1976 J
1976 *
1976 *
1976 ,
1977
23
-------
Raw Material and
Utility Requirements
In comparison with a lime or
limestone scrubbing system, the
Wellman-Lord process has a
relatively low raw material
requirement and a relatively high
energy requirement. Regeneration
reduces soda ash consumption,
thus minimizing raw material
requirements. However, the
regeneration system requires
substantial quantities of energy, in
the form of steam, for conversion
of sodium bisulfite to sodium
sulfite.
Table 3 illustrates the estimated
raw material and utility require-
ments for three Wellman-Lord
systems. This information is based
on a study performed by the
Tennessee Valley Authority in
1974.13 Therefore, the values
presented in Table 3 do not reflect
recent process innovations. For
example, the steam requirements
in Table 3 can be reduced 40 to
45 percent if double-effect
evaporators are employed. In
addition, the use of fractional
crystallization can reduce by
approximately 75 percent the
quantity of makeup sodium
carbonate required.
The information presented in
Table 3 is based on converting
the SO2 ^stream from the
evaporators to elemental sulfur via
the Allied Chemical SO2 reduction
process. This process is
responsible for the natural gas
requirement. The heat credit is
generated by 862 reduction.
Use of a different SO2 conversion
process would change these and
other raw material and utility
requirements.
24
-------
Table 3. ;
Estimated Annual Raw Material and Utility Requirements for the
Wellman-Lord FGD Process :
Component
New coal-fired plant
200 MW
500 MW
1,000 MW
|K-----.- - i :.. - - . -
jjiaw materials:
t Lime
Sodium carbonate
f" Antioxidant3
V""' Catalyst15
>j^_.
|TOlities:c
^~- Natural gas
'"- Steam
Heat credit
4 Process water
= 1^.. , - ElgQtj-jQJty _ ^ t
49 7 Mg (54 8 tons)
3 45 Gg (3 80 x 1 03 tons)
58 9 Mg (65 tons)
$4 900
5 83 hm3 (205 9 x 106 ft3)
0 397 Tg (874 1 x 1 06 Ib)
27 1 TJ (25 7 x 1 o9 Btu)
154 hm3 (407 x 109 gal)
1 09 TJ (30 32 x 1 Q6 kWh)
121 6 Mg (134 1 tons)
843 Gg (9 30 x 103 tons)
1440 Mg (158 5 tons)
$12000
14 27 hm3 (503 9 x 106 ft3)
0971 Tg (2 138 x 109 Ib)
66 4 TJ (62 9 x 1 09 Btu)
37 7 hm3 (9 9 x 109 gal)
267 TJ (74 1 9 x 1 06 kWh)
235 0 Mg (259 2 tons) n
16 33 Gg (1800 x 103 tons)
278 0 Mg (306 5 tons)
$23 200
... 4
27 58 hm3 (974 0 x 1 06 ft3)
1 88 Tg (4 1 33 x 1 o9 Ib)
128 TJ (121 5 x 109 Btu)
72 8 hm3 (193 x 1 09 gal)
R1fi T I (14^ 4 x ir)6 IrWhl
9
Ib
aAntioxidant may not be necessary for system operation.
Catalyst for the Allied Chemical Process.
?- Using single-effect evaporators. Expect 40% to 50% reduction in utility costs for double-effect units. See Potter, Brian J., and
F7 Earl, Christopher B., "Wellman-Lord S02 Recovery Process," AlChE Symp. Ser. 70(1 37), 1 60-1 64, 1 974.
yviote.- Base; Stack gas heat to 79.4° C (175° F). Operating time of 7,000 h/yr. 3.5% sulfur coal. 90% SOa removal.
i-SOURCE: McGlamery, G. G., Torstick, R. L, Broadfoot, W. J., Simpson, J. P., Henson, L. J., Tomlinson, S. V., and Young, J. F.,
tPetailed Cost Estimates for Advanced Effluent Desulfurization Processes, NTIS No. Pb 242541, EPA 600/2-75-006, Interagency
_ Agreement EPA IAG-134(D), Part A, Research Triangle Park NC, Control Systems Lab., NERC, January 1975.
j
25
-------
Costs
The estimated and actual costs of
an FGD system can vary widely
depending on the assumptions
made, conditions of operation,
options included, degree of
redundancy, and othjer factors.
This report presentsjthe details of
a series of cost estimates for the
Wellman-Lord process that were
prepared by the Tennessee Valley
Authority.13-14
Table 4 delineates the capital and
the average annual revenue
requirements for Wellman-Lord
systems installed on different
sizes and types of boilers firing
a variety of fuels. These costs may
vary and depend on numerous
site-specific factors. The reader is
encouraged to compare any
specific situation with the base
used to estimate the cost in
Table 4. Some reevaluation will be
required for each specific location
regarding availability and cost of
raw materials, energy sources,
physical plant, and environmental
factors.
Table 5 presents the annual
operating costs for a Wellrnan-Lord
FGD system. Specific components
are identified along with examples
illustrating the contribution of each
component to the annual operating
cost.
26
-------
Absorber Recirculation Piping
27
-------
Table 4.
Estimated Capital and Average Annual Revenue Requirements for the Wellman-Lord FGD Process
with Recovery of Elemental Sulfur
System characteristics '
Size
(MW)
200
200
200
500
500
500
600
500
500
500
500
500
1.000
1,000
1.000
Application
New
New
Existing
New
New
New
New
New
New
New
Existing
Existing
New
New
Exisiting
Fuel
Type
Coal
Oil
Coal
Coal
Coal
Coal
Coal
Oil
Oil
Oil
Coal
Oil
Coal
Oil
Coal
%S
3.5
2.5
3.5
2.0
3.5
3.5
5.0
1.0
2.5
4.0
3.5
2.5
3.5
2.5
3.5
Plant life
(yr)
30
30
20
30
30
30
30
30 ,
30
30
25
25
30
30
25
% S02
removal
90
90
90
90 ,
80
90
90
90
90
, 90
90 /
90
90
90
90
Total capital
investment8
106$
22.39
14.36
23.60
36.80
40.41
42.39
47.21
21.00
26.50
30.93
43.35
33.62
64.20
40.59
67.04
$/kW
112.0
71.7
118.0
73.6
80.8
84.8
94.4
42.0
53.0
61.9
86.7
67.2
64.2
40.6
67.0
Average annual .
revenue requirements
106$
9.24
6.46
10.87
14.55
17:43
18.78
22.86
8.94
13.08
17.04
22.19
15.32
31.19
22.22
38.81
mills/kWh
6.60
4.62
7.76
4.16
4.98
5.37
6.53
2.55
3.74
4.87
6.34
4.38
4.46
3.17
5,54
mills/MJ .
1.83
1.28
2.16
1.16
1.38 ,:
1 .49
1.81
0.71
1.04
1 .35 ,
1.76 ":
1.22
1.24
0.88
1 .54 ,.
Total capital investments = captial investment + working capital.
1978 costs. Average capacity factor for the plant lifetime = 48.5%. The average annual revenue requirements reflect total capital
investment and operating costs.
Mote,Base: Single-effect evaporators. Midwest plant location. 3-year project beginning mid-1975. Average cost basis in mid-1977
costs. Minimum process storage. Only pumps have additional capacity, On-site disposal in a clay-lined pond. No overtime pay. No
fly ash disposal. No credit given for recovery of sulfur.
SOURCE; McGlamery, G. G., Faucett, H. L, Torstick, R. L, and Hensori, L J., "Flue Gas Desulfurization Economics," in Proceedings:
Symposium on Flue Gas Desulfurization, New Orleans, March 1976, Volume 1,NTIS No. Pb 255317, EPA 600/2-136a (pp. 79-99),
May 1976.
28
-------
Table 5.
Annual Operating Costs for a Wellman-Lord FGD System on a New 500-MW Boiler
V
^
Component
Annual quantity
Unit cost ($)
Annual
operating costs
/103 $a
mills/kWh,
Direct costs
ptesr"-
p;
&r
fe,
-
fe^
a^
IK"
B^
t ,
t-
3
£
pi-
-
,
Delivered raw materials:
Lime
^ Sodium carbonate
~- Antioxidantb
Catalyst0
- Total raw materials
Conversion costs:
Utilities:
. _ _ Natural gas
Steam
Heat credit
Process water
Electricity
Total utilities
Operating labor and
supervision
Maintenance: 6% of
direct investment
Total conversion costs
121 6 Mg(1341 tons)
8,440 Mg (9,300 tons)
144,000 kg (31 7,100 Ib)
- i ,~~
14429,000 m3
(509 50 x 106ft3)
969,71 OMgb, 068 9 x
103 tons)
66370 GJ (6290 x 109
Btu)
37,670,000 m3
(995 34 x io7 gal)
267 080 GJ (741 90
x 10s kWh)
46,500 man-hours
46 30/Mg (42 00/ton)
86 00/Mg (78 00/ton)
6.06/kg (2.75/lb)
_ _ ^,
^
0 071 /m3 (2 00/1 03 ft3)
3 09/Mg (2 80/ton)
1 09/GJ (0001 2/1 03
Btu)
0011/m3(004/103gal)
7,50/GJ (0.027/kWh)
10.00/man-hour
56
725.4
872.0
180
1,621 0
1,0190
2,992.9
(723)
398.1
2,003.1
6,340.8
465.0
1,573.8
1 *37 4
85170
0.001
0.207
0249
0.005
0462
0.291
0.855
(0.021)
0.114
0.572
1.811
0133
0.450
n r^Q
2.433
*
%
(k
w
"3
-,
«
39
Indirect costs:
it-
1st
»«*-""
|*
r
i*"
te~=s~
Capital charges: 14.9%
of capital investment
Overhead:
Plant: 20% of conversion costs
Administrative and marketing: 10% of
operating labor and analyses
-Total indirect costs
STotal annual operating costs
6,315.7
1,7323
60.2
8,108.2
18,246.2
"
1.804
0.495
0017
2.31 6
5.211
^
i
fe- - 1
Calculations for annual operating cost are based on values expressed in customary U.S. units. A slight variation exists for most values
SI units are used in the calculation ^
ntioxidant may not be necessary for system operation.
pCatalyst for the Allied Chemical Process^
"'Base Remaining life of power plant, 30 years Coal burned 1 19 Tg/yr (1 31 x 1Q6 tons/yr) Boiler efficiency, 2 6 J/J Stack
reheat to 79 4° C (175° F) Power unit on stream time, 7,000 h/yr Midwest plant location, 1978 operating costs Total capital
pjiyestment, $42,387,000; subtotal direct investment, $26,230jpOp; Working capital, $1,411,OOJO. Investment and operating costs for
j|y ash excluded 90% S02 removal No credit given for recovery of sulfur
^SOURCES McGlamery, G G , Torstick, R L Broadfoot, W J, Simpson, J P, Henson, L J , Tomlmson, S V., and Young, J F,
Detailed Cost Estimates for Advanced Effluent Desulfumation Process. NTIS No Pb 242541, EPA 600/2-75-006, Interagency
{Agreement EPA IAG-134(D), Part A, Research Triangle Park NC, Control Systems Lab., NERC, January 1975. McGlamery, G. G.,
jFaucett, H L, Torstick, R L and Henson, L G , "Flue Gas Desulfunzation Economics," in Proceedings Symposium on Flue Gas
£>esulfunzation. New Orleans, March 1976, volume 1, NTIS No. Pb 255317, EPA 600/2-76-136a (pp 79-99), May 1976
I """f" *
29
-------
Installation Space
The installation space required for
a typical Wellman-Lord FGD
system applied to a new 500-MW
boiler burning 3.5 percent sulfur
coal is illustrated in Figure 6. The
total estimated requirement for the
FGD unit is 7,000 m2 (7.5 x
104 ft2 or 1.7 acres).
Approximately 43 percent of the
required space, is devoted to the
pretreatment and absorption
processing area; approximately
57 percent is needed for the
reduction, regeneration, and purge
treatment processing areas.
Retrofit applications generally
require more space and additional
duct work may be required for
connecting the FGD system to the
existing plant. The pretreatment
and absorption processing area
must be located adjacent to the
power unit, but other process
components can be located some
distance away.13
The land area requirements for
disposal of paniculate waste are
not included in the above estimate.
In any case, integration of the
Wellman-Lord system would not
increase the land area requirement
beyond that necessary for disposal
of waste from the ESP/venturi
scrubber operating to reduce
particle emissions to legal levels.
30
-------
Key
Flue gas/off-gas
Cleaned flue gas
Absorption iliquor
Sulfur dioxide
Other systems
Figure 6.
Typical Wellman-Lord Installation Requirements
31
-------
Abbreviations
actual ft3 actual cubic feet
Btu British thermal unit
°C degree centigrade
°F degree fahrenheit
ft3 cubic feet
g grams
gal '. gallons
Gg ', gigagrams (109 g)
GJ gigajoules (109 J)
gr grains
hm3 ', cubic hectometer (1 x 1Q6 m3)
h hour
J , joule
kg kilogram (103 g)
kW ;. kilowatt (103 watt)
kWh kilowatt-hour
I liter
Ib pound
m meter
Mg megagrams (106 g)
MW megawatt (106 watt)
normal m3 normal cubic meter (0° C)
Pa pascal
ppm parts per million (wt)
ppmv , parts per million (volume)
stdft3 \ standard cubic foot (60° F)
stdftVmin '. standard cubic feet per
minute (60°)
Tg teragrams (1012 g)
TJ terajoules (1012 J)
yr year
32
-------
References
1Baily, E.E., "Continuing Progress
for Wellman-Lord S02 Process,"
in Proceedings: Symposium on
Flue Gas Desulfurization,
Atlanta, November 1974,
Volume II, NTIS No. Pb 242573,
EPA 650/2-74-1266 (pp.
745-759), December 1974.
2Stuebner, D.O.> meeting notes,
Davy Powergas, Inc., Lakeland
FL, November 1975, Radian
Project No. 200-116, Radian
Corporation, Austin TX,
December 1975.
3PEDCO-Envirohmental Special-
ists, Inc., Flue Gas Desulfurization
Process Cost Assessment, Draft
Report, Contract No. 68-01-3150,
Technical Series Area 4, Task 2,
Cincinnati OH,:May 1975.
4Ottmers, Jr., D.M., Aul, Jr.,
E.F., Delleney, R.D., Brown, G.D.,
Page, G.C., and Stuebner, D.O.,
Evaluation of Advanced
Regenerable Flue Gas Desulfuri-
zation Processes, Draft Report,
Radian Project No. 200-116,
EPRI Contract No. RP 535-1,
Radian Corporation, Austin TX,
March 1975.
5Mann, E.L., "Power Plant Flue
Gas Desulfurization by the
Wellman-Lord SO2 Process,
Part 1, The Dean H. Mitchell
Station (Northern Indiana Public
Service Company)." in Proceed-
ings: Symposium on Flue Gas
Desulfurization, Atlanta,
November 1974, Volume II, NTIS
No. Pb 242573, EPA 650/2-74-
126b (pp. 739-744), December
1974.
33
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6Davy Powergas, unpublished
data.
'Tsushima, Yoshio, "First
Japanese-Made Sulfur Dioxide
Recovery Plant of the Wellman-
Lord Process," Chem. Econ. Eng.
Rev. 3(12), 21-24, 32, 1971. '
8Schmidt, Max "Fundamental
Chemistry of Sulfur Dioxide
Removal and Subsequent
Recovery Via Aqueous
Scrubbing," Int. J. Sulfur Chem.
PartB7(\), 11. 1972.
9Schneider, Raymond T., and
Earl, Christopher B., "Application
of the Wellman-Lord S02
Recovery Process to Stack Gas
Desulfurization," in Proceedings:
Symposium on Flue Gas
Desulfurization, New Orleans,
May 1973, NTIS No. Pb 230901,
EPA 650/2-73-038 (pp. 641 -655),
December 1973.
10Potter, Brian H., and Earl,
Christopher B., "Wellman-Lord
SO2 Recovery Process," AlChE
Symp. Ser. 70(137), 160-164,
1974.
11 Craig, T.L, "Recovery of Sulfur
Dioxide from Stack Gases: The
Wellman-Lord S02 Recovery
Process," presented at the
Industrial Coal Conference,
Lexington KY, April 8, 1977.
12Potter, B.H., and Craig, T.L.,
"Commercial Experience with an
SO2 Recovery Process," CEP
68(8), 53, 1972.
13McGlamery, G.G., Torstick, R.L,
Broadfoot, W.J., Simpson, J.P.,
Henson, L.J., Tomlinson, S.V.,
and Young, J.F., Detailed Cost
Estimates for Advanced Effluent
Desulfurization Processes, NTIS
No. Pb 242541, EPA 600/2-
75-006. Interagency Agreement
EPAIAG-134(D), Part A,
Research Triangle Park NC,
Control Systems Lab., NERC,
January 1975.
14McGlamery, G.G., Faucett, H.L,
Torstick, R.L., and Henson, L.G.,
"Flue Gas Desulfurization
Economics," in Proceedings:
Symposium on Flue Gas
Desulfurization, New Orleans,
March 1976, Volume I, NTIS
No. Pb 255317, EPA 600/2-
76-136a (pp. 79-99), May 1976.
34
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This report has been reviewed by
the Industrial Environmental
Research Laboratory, U.S.
Environmental Protection Agency,
Research Triangle Park NC, and
approved for publication. Approval
does not signify that the contents
necessarily reflect the views and
policies of the U.S. Environmental
Protection Agency, nor does
mention of trade names or
commercial products constitute
endorsement or recommendation
for use.
Any comments on or questions about this report or requests for
information regarding EPA flue gas desulfurization programs should
be addressed to:
Process Technology Branch
Utilities and Industrial Power Division
IERL, US EPA(MD-61)
Research Triangle Park NC 27711
This summary report was prepared by the RADIAN Corporation under
EPA Contract No. 68-02-2608. Mr. C. E. Hudak and Mr. J. M. Burke are
the principal contributors. Mr. R. Michael McAdams is the EPA Project
Officer. Chevron.U.S.A. Inc. and several utility companies provided
the photographs.
35
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