EPA
TECHNOLOGY
TRANSFER
FLUE GAS
AND SULFURC
AX
SCRlfflNG
PREPARED
US.
ENVRONMENW
POECT1ON
AGENCY
-------
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EPA
TECHNOLOGY
TRANSFER
FLUE GAS
LTSULFURiZATCN
ANDSULFURC
ACID
PRODUCTION
MA MAGNESIA
SCRUBHNG
PREPARED EY
U.S.
ENVIRONMENTAL
FOECTDN
AGENCY
EPA-625/2-75-007
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Boston Edison oil-fired power plant
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The 1970 amendments to the Clean Air Act
provided increased impetus to programs directed
to decreasing sulfur dioxide (SO2) emissions from
existing sources. These amendments also required
the development of national emission standards
for new sources.
It is estimated that approximately 20 million
tons per year of sulfur must be removed from coal
and fuel oil or from their combustion gases to meet
SO2 air quality standards. Approximately 55 per-
cent of the SO2 emissions in the United States re-
sult from the combustion of coal and oil at power-
generating stations.
There are only three methods available to
substantially reduce SO2 emissions from these
power generating stations: (1) switching to low sul-
fur fuels; (2) desulfurizing or converting the fuel
prior to combustion; or (3) desulfurizing the gases
produced by combustion. Because of the limited
availability of low sulfur fuels and the relative in-
fancy of coal desulfurization/conversion technol-
ogy, flue gas desulfurization (FGD) processes are
expected to make the most significant impact on
abatement of SO2 emissions until at least 1985.
FGD processes are generally divided into two
categories: "throwaway" and "regenerable."
Throwaway processes involve absorption of the
flue gas SO2 with the subsequent precipitation of a
solid that is disposed of as a waste material. In
regenerable processes, on the other hand, the SO2
is absorbed and recovered in a manner such that its
fixed sulfur value can be converted into usable and
salable sulfur byproducts, such as sulfuric acid,
elemental sulfur, or liquid SO2 . Commercial appli-
cation of FGD technology by electric power plants
has been limited in this country principally to the
use of throwaway processes. These processes use
aqueous slurries of lime or limestone as the SO2
absorption media and produce a calcium sulfite/
sulfate sludge for disposal. In some cases the dis-
posal of this sludge has been a problem for utility
plants operating in areas where sludge disposal
costs are high and disposal area is limited.
About 40 million tons of sulfuric acid are man-
ufactured per year in the United States. The major
portion is obtained by burning mined elemental
sulfur to SO2 , and processing the SO2 to sulfuric
acid. Regenerable FGD processes have the capability
of substituting sulfur collected from flue gases for
the mined sulfur. Power-generating stations, opera-
ting in areas where land is scarce and having the
proper combination of technology, markets, and
transportation, could find regenerable FGD proc-
esses to be the most economical solution for meet-
ing SO2 emission requirements.
One of the more promising regenerable flue
gas desulfurization processes is based upon the re-
action of magnesium oxide (magnesia) with SO2,
forming magnesium sulfite. The magnesium sulfite
solids are separated by centrifugation, dried to
remove moisture, and then calcined to regenerate
magnesium oxide for recycle and SO2 for conver-
sion into sulfuric acid. Once properly conditioned,
the SO2 can be used by existing as well as new sul-
furic acid plants.
Although laboratory and pilot work had been
done on the process by 1970, several major ques-
tions on full-scale application of the process re-
mained.
(1) The ability to efficiently remove sulfur
oxides from the flue gases.
(2) The ability to continually regenerate a
reactive magnesium oxide.
(3) The quality of the product sulfuric acid.
J4J Mechanical and materials reliability.
(5) Projected construction and operating costs.
(6) Transport and storage properties of the
magnesium sulfite and regenerated mag-
nesium oxide.
In 1970, the U.S. Environmental Protection
Agency and the Boston Edison Company agreed to
provide the funds for the construction and 2-year
operation of a large prototype sulfur dioxide re-
covery plant based upon magnesia slurry scrubbing.
The Chemico-Basic magnesia process was chosen.
The SO2 absorption plant was installed at Boston
Edison's Mystic Station in Everett, Massachusetts,
and the regeneration facility at Essex Chemical's
Rumford, Rhode Island, sulfuric acid plant. The
process was scaled up from a small pilot plant han-
dling 1,500 cubic feet per minute (cfm) of gas to
a full-size unit designed for 450,000 cfm.
The prototype plant operated from April 1972
to June 1974 on a 155-megawatt (Mw) boiler at
the Boston Edison facility. During this same time
period the system's ability to regenerate and re-
use magnesium oxide was demonstrated and over
5,000 tons of sulfuric acid were produced from
magnesium sulfite at the Essex Chemical facility
and sold in the commercial market. Mechanical
and chemical problems that developed during the
prototype operation at both Boston Edison and
Essex Chemical were solved by either direct modi-
fication to the plants or by recommended solutions
considered applicable to new magnesia scrubbing
installations. The scrubbing system demonstrated
a consistent ability to achieve SO2 removal effi-
ciences in excess of 90 percent using regenerated
magnesium oxide.
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FGD and H2S04 production via magnesia scrubbing
The magnesia slurry process can be generally
split into two major operating areas:
(1) SO2 scrubbing, slurry dewatering, and mag-
nesium sulfite drying, which were inte-
grated into the Boston Edison plant opera-
tions.
(2) Magnesium oxide regeneration and sulfuric
acid production, which were integrated in-
to the Essex Chemical plant operations at
Rumford, Rhode Island.
The dried magnesium sulfite was transported
by truck to the Essex Chemical plant, and regen-
erated magnesium oxide was returned to Boston
Edison.
Boston Edison SO2 Recovery System
Figure 1 is a process flow sheet for the opera-
tions associated with the magnesia slurry SO2 re-
covery system on Boston Edison's Mystic Station
Unit No. 6 boiler.
Flue gas is ducted into the venturi scrubber,
with an additional induced draft fan operating at
the discharge of the existing fan. Since fuel oil was
being burned at the Boston plant, there was no
need for particulate matter removal.1
At the venturi scrubber, the flue gas is con-
tacted concurrently with an aqueous recycled
slurry containing magnesium oxide (MgO), mag-
nesium sulfite (MgSO3}, and magnesium sulfate
(MgSO4). The absorption reaction takes place be-
tween sulfur dioxide and magnesium oxide, re-
sulting in the formation of magnesium sulfite.
Some of the SO2 may also react with MgSO3 in
the presence of water to form magnesium bisulfite
(Mg(HSO3)2), which then reacts immediately with
the excess MgO present to yield additional MgSO3.
MgO, in slight excess (2.5 percent) of the amount
necessary for reacting with all of the SO2 present
in the flue gas, is maintained in the slurry. A por-
tion of the sulfur trioxide (SO3) present in the
flue gas is absorbed in the slurry and reacts to
form MgSO4. Additional amounts of MgSO4 are
also formed due to oxidation of a portion of the
magnesium sulfite.
The aqueous slurry used as the scrubbing
media contains the hydrated crystals of MgO,
MgSO3, and MgSO4, as well as a solution that is
saturated with each of these components. A con-
tinuous side-stream of this recycled slurry is di-
verted to a centrifuge, where partial dewatering
produces a moist cake containing crystals of
MgSO3 • 3H20, MgSO3 • 6H2O, MgSO4 • 7H2O
and unreacted MgO. The liquor removed from the
crystals is returned to the main recirculating slurry
stream. MgO, regenerated from the Essex Chemical
plant, is combined with water and is then added to
the recirculating slurry as make-up. The resulting
1 For coal-fired applications, however, particulate matter
removal would be required to avoid large-scale contamina-
tion of the magnesia slurry with fly ash.
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OIL
TO
MgS03 FUEL
SILO AIR
MgS03
SILO
MgO FROM ACID PLANT
Figure 1. Process flow sheet—Boston Edison
SO2 recovery system
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ANNULUS
SPRAYS
GAS
INLET
TANGENTIAL
WASH
CLEAN GAS
OUTLET
TO STACK
INTERMITTENT
MIST
ELIMINATOR
SPRAYS
CONE
WASH
VENTURI
THROAT
ANNULUS
ENVELOPE SIZE: 31 FEET IN DIAMETER
50 FEET HIGH
TO RECYCLE AND CENTRIFUGE
Figure 2. Cross-sectional view of venturi scrubber
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Magnesia scrubber during construction
combined slurry is recycled to the scrubber for con-
tinuous SO2 recovery. The wet solids are conveyed
to an oil-fired direct-contact dryer where free and
bound moisture is removed. The dry magnesium
sulfite is then stored for shipment to the sulfuric
acid plant.
The scrubbing unit was installed to treat all of
the flue gas from the Unit No. 6 boiler at Boston
Edisoa's Mystic Station. Unit No. 6 burns 9,700
gallons per hour of No. 6 fuel oil at its current
rated capacity of 155 Mw and was placed in com-
mercial operation in May 1961.
Since the SO2 scrubbing system was retrofitted
into an existing boiler, an additional booster fan
was installed to provide the required pressure.
The venturi scrubber must provide good con-
tact of the gas with the liquid and not allow any
solids buildup. The venturi must also be designed
to operate at a minimum pressure drop to keep the
scrubber's energy consumption low. The Chemico-
designed venturi scrubber used at Boston Edison is
shown in figure 2.
The slurry is introduced into the venturi
through three points: (1) a nozzle that irrigates the
c6Yie within the venturi throat; (2) annulus sprays
located above the torus surrounding the cone; and
(3) tangential nozzles located in the top shelf of
the scrubber. The slurry flow is downward across
the venturi throat creating a curtain of liquor
through which the flue gas passes. The flue gas
rapidly accelerates to a high velocity at the throat
where impact with the slurry causes atomization
into fine droplets, SO3 is mixed with the dispersed
slurry and reacts with the magnesium salts. The
slurry is continuously;recycled from the conical
bottom of the venturi:scrubber, which also serves
as a storageVese/voir for the system. The flue gas
and entrained slurry-leaving the throat.enter the
separator portipns-.Of the scrubber through a cen-
tral downcomer. The sl.urry droplets fall to the,
sump of thescrubber While the flue gas passes
upward through misteliminators;for further re-
rrfoval of entrained materials. Trie cleaned flue gas
exits the scrubber and enters the stack for dis-
charge to,the atmosphere. •'-,-'
The removal of some participate matter, princi-
pally carbonaceous material in the l-S-^m size
range, also occurs in the scrubber. Unlike fly ash
from coal combustion, the presence of carbon
particles from oil combustion does not affect the
reuse of MgO, since carbon is consumed in the
regeneration step as a reductant for magnesium sul-
fate. The slurry of MgSO3, MgSO4,and unreacted
MgO is then recirculated to the scrubber. To main-
tain equilibrium conditions, a continuous bleed of
the recirculated slurry removes, as MgSO3'arrtl...
MgSO4, the same amount of sulfur that the Slurry
absorbs from the flue gas. This bleed stream isV
taken from the discharge of the slurry recycle
pumps and is set at a level that maintains the de-
sired solids concentration in the recirculated slurry.
MgO must be added to the recirculating slurry to
replace the magnesium salts'which are removed by
the bleed stream. This is done by adding MgO
makeup slurry at a rate .that maintains the recycle
skiny in the desired pH range of from 6.8 to 7.5.
The wet solids from the centrifuge (at about 40
percent surface water) arV transported by means of
a screw Conveyor to a countercurrent, direct "oil-
fired rotary:dryer where eventually all surface
moisture and most of the water of hydration are
driven off.
Offgas exits the dryer at about 450° F and
passes through a cyclone dust collector where en-
trained solids are removed and conveyed to the
storage silo. The dryer offgas then passes through
an induced draft fan and is ducted back to the
scrubber, which captures and reuses paniculate
matter from the dryer.
The dryer product, which consists of an-
hydrous MgO (< 1%), MgSO3, MgSO4, and inerts,
is transported by a bucket elevator and screw con-
veyor to an existing storage silo. Material from the
silo is transferred by means of screw feeders to a
belt conveyor, where it is gravity fed into trucks
for transport to the MgO regeneration plant at
Rumford, Rhode Island.
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Operational S02 recovery system
Essex chemical plant,
Rumford, Rhode Island
Essex Chemical—MgO Regeneration and
Sulfuric Acid Production
The chemical plant operations convert the mag-
nesium sulfite-magnesium sulfate mixture received
from the power plant back into magnesium oxide
for recycle to the Boston Edison plant. In addition,
the SO2 produced from the regeneration of MgO is
cleaned, cooled, and dried to make it suitable for
feed to the existing sulfuric acid plant.
Essex Chemical's single absorption contact sul-
furic acic) plant in Rumford, Rhode Island, was
built in 11928 and upgraded in 1949. With a nomi-
nal capacity of 50 tons per day of 98 percent
H2S04, this plant by today's standards is relatively
small. This capacity closely matches the propor-
tional sulfur output from the power plant's Unit
No. 6 boiler. The plant was originally designed to
use elemental sulfur as a raw material. Subsequent
modifications made under the EPA program
adapted {he plant to acid production from cal-
ciner gas land/or sulfur burning.
The process sequence for regeneration used at
Essex Chemical is shown in figure 3. The heart of
the process is the calcination step, in which the fol-
lowing major reactions occur:
MgSO3 -> MgO + SO2
2C + O2 -* 2CO
Mgso4 + co -> Mgo + so2
co
The calciner is fed a weighed mixture of the
magnesium sulfite/sulfate solids received from the
power plant. If the amount of carbon present in
the dried solids received from the power plant is
inadequate for the reduction of magnesium sulfate
to magnesium oxide, the calcination reaction re-
quires the addition of coke.
The dried solids-carbon mixture moves
countercurrently to the combustion gases that are
formed by the direct firing of fuel oil. Since com-
bustion gases dilute the SO2 produced by the re-
generation reaction, the calciner firing rate is main-
tained at the minimum level required for proper
calcining conditions. Temperatures at the middle
of the calciner are kept at approximately 1 250° F.
Prior to discharge at the calciner's fired end,
the MgO product is cooled to 250° F by direct
heat exchange with the oil burner's secondary
combustion air. The magnesium oxide is then
moved to a storage silo by a screw conveyor and
bucket elevator. A vibrating hopper assists in the
transfer of the MgO from the storage silo to the
trucks used to return the MgO to the power plant.
The SO2 cycle continues as the SO2-rich gases
are discharged from the calciner's feed end. These
gases then pass through cyclone dust collectors,
where an entrained fine paniculate product is re-
moved and returned to the calciner.
Before its use in the acid plant, this SO2 -rich
gas stream must be cooled and cleaned of dust and
acid mist. A weak acid venturi scrubber performs
the necessary cooling and cleaning functions in
two sections:
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SO2 GAS CLEANING
CONVEYOR
CONCENTRATED SO2 GAS TO
EXISTING SULFURIC ACID PLANT
WEIGHB WEIGH
FEEDERiFEEDER
CONVEYOR
REGENERATED
MgO
MgO RETURN TO POWER PLANT
MgS03 FROM POWER PLANT
Figure 3. Process flow sheet—Essex Chemical MgO
regeneration system
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Calciner with mechanical rappers
(1) The venturi section, where the gases are
cooled to the adiabatic saturation tempera-
ture and also scrubbed of particulate mat-
ter by a stream of recirculated weak acid
scrubbing liquor.
(2) A packed tower, where the gases are
further cooled by direct contact with a
cool recirculated weak acid stream. This
step is required since the gases leaving the
venturi section are saturated with water
vapor. By maintaining the exit temperature
of the scrubber gas below 100° F, the
introduction of more water than can be
accepted by the sulfuric acid plant produc-
ing 98 percent acid is avoided. A purge
stream is diverted from the recirculating
scrubber liquor to an SO2 stripping tower
and then to a neutralizing step prior to
discharge. This stream is necessary to main-
tain suspended solids, temperature, and
pH of the recirculating scrubber liquor at
specified levels.
The scrubbed gas stream is then transported
through polyester pipe to the existing acid plant,
where the gas is dried by contact with 93 percent
sulfuric acid. After the gas stream leaves the dry-
ing tower, it is sent to an entrainment separator,
which insures that no entrained acid will reach the
main blower.
The dried gases are then drawn through the
main blower and enter the cold heat exchanger.
Here, the waste heat from the gas exiting the sec-
ondary converter is recovered by preheating the
relatively cold calciner gas before it enters the
existing converter heat exchanger. Downstream
of the converter heat exchanger, acid production is
the same as conventional acid production from the
burning of elemental sulfur.
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Magnesia scrubbing system with dryer in foreground
A major objective of this project was to identify
and resolve operating problems which were expected
in the first large-scale application of this new process.
The project did experience several problems that
were not previously encountered. These problems
were either solved by either direct modification to
the two plants or solutions were recommended
that were considered applicable to new magnesia
scrubbing installations. The use of procedures de-
veloped as a result of this project should insure
reliable startup and operation for future plants.
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Table 1.
Test results
S02 REMOVAL EFFICIENCY
(PERCENT)
90
80
70
60
50
40
AP= 12 in. H20
AP = 6in. H2O '
X" AP = 3 in. H20 " ^— ^
_
/AP - 2 in. HjO^^.
/
i i i i i
200 600 1 ,000 1 ,400 1 ,800 2,000
INLET S02 (ppm)
Figure 4.
Effect of AP and inlet SO2 Concentra-
tion on SO2 removal efficiency
% of total stream
Item
Water
Solids MgO MgSO3 MgS04 and
inerts
Recycle shirry 20* 1.4 6.7 12.4
Centrifuge cake 63 1.4 57.8 4.1
I
Dryer product 80 2.6 65.0 11.8
Cajctoer fefed 79 2.8 63,9 12.7
Calciner product 94.5 86.1 8.4
* Approximately 10% as suspended solids Jn the slurry.
80
37
20
21
5.5
Table 2.
Typical composition of major
product streams
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S02 OUTLET
CONCENTRATION
(PPM)
120
110
100
90
80
70
5.00 5.50
6.00 6.50 7,00
SLURRY RECYCLE PH
7.50
Figure 5.
Effect of slurry recycle pH on SO2 out-
let concentration
Boston Edison SO2 Recovery System
The chemical and mechanical performance of
the scrubbing system itself was excellent. None of
the internal plugging problems which plagued the
early operations of the lime and limestone processes
were encountered. The plastic lining of the scrubber
was in sound condition after 2 years of operation.
Erosion and corrosion were experienced in the car-
bon steel recirculating slurry piping. The use of
rubber-lined pumps, valves, and piping in certain
areas of this system is now considered as the most
practical solution to this problem. The SO2 removal
efficiency was excellent over a wide range of
operation.
Table 1 lists the results of four controlled tests
at varying flue gas rates and SO2 inlet concentrations.
These were contract performance tests and were con-
ducted by a third party, York Research.
A correlation of SO2 removal efficiency as a
function of inlet SO2 concentration and pressure
drop across the scrubber was developed based on
actual test data and is shown graphically in figure
4. In this same figure, the excellent operability
range of the system is shown by the consistently
high removal efficiency curves for pressure drops
above 6 inches of water.
In addition, the scrubbing system faced frequent
boiler outages during the last 6 months of the proj-
ect. Repeatedly, the scrubbing system demonstrated
its ability to maintain high SO2 removal efficiencies
while cycling with the boiler. The scrubber could
also operate from a cold start of the boiler and
could provide efficient scrubbing during the entire
startup sequence.
The major control variables used to control the
scrubbing operation were the recycle slurry pH and
percent solids. The effect of pH on SO2 concentra-
tion is shown in figure 5. The effect was controlled
by adjusting the rate of MgO addition. Typical com-
positions of the recircuiating slurry are shown in
table 2, along with other key streams. The amount
of solids in the slurry was controlled by adjusting
the rate of bleed from the recycle slurry.
The majority of the operating problems experi-
enced at the power plant operation were closely tied
to the solids-handling system. Many of these prob-
lems were due to the nature of the magnesium sulfite
crystals obtained from the scrubber. Although large,
easily separated magnesium sulfite hexahydrate
(MgSO3 • 6H2O) crystals were expected, any sus-
tained operation of the scrubber resulted in the pro-
duction of many fine magnesium sulfite trihydrate
(MgSO3 • 3H2O) crystals.
This unexpected occurrence resulted in crystal
properties different from those used in the design
of the solids-handling system and the dryer, and
was the primary process problem encountered in
the project. Modifications eventually were required
in all of the process areas handling magnesium sul-
fite crystals to allow for operation with large
amounts of the trihydrate present.
The rotary dryer, used for removing free and
bound water from the centrifuge slurry solids, was
found to be at the center of these initial operating
problems. Since this dryer was designed for opera-
tion with the relatively coarse hexahydrate crystals,
the fine trihydrate crystals caused excessive dusting,
buildup of solids, and loss of drying ability. The fol-
lowing modifications led to reliable drying:
(1) The dryer operation and internal configura-
tion were modified to allow the dryer to act
as a granulatorfor the fine crystals.
(2) A scalping screen and lump breakers were
installed at the dryer discharge to handle
large agglomerations of dried magnesium sul-
fite from the dryer.
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(3) High dust losses from the dryer because of
the fine crystal size were corrected by piping
the dryer offgas to the venturi scrubber.
(4) Hammers were installed on the dryer shell
to prevent the buildup of solids.
(5) The dryer conveyor was lengthened to allow
wet centrifuge cake to be added at a point
further into the dryer,
(6) The mixing of the dry material, removed
from the cyclone dust collector operating
on the dryer offgases, with the wet centri-
fuge solids created a mixture which would
"set up" on the screw conveyor. A pneu-
matic conveyor system was installed to
transport this material directly to the
MgSO3 silo.
As the first regenerated magnesium oxide arrived
at the power plant for reuse, other problems in sol-
ids handling developed. The calcined magnesia re-
turned from the acid plant contained a fraction of
a larger-than-desirable particle size as well as some
overburned MgO particles that would not react with
water to form a reactive slaked slurry. A pulverizer
was installed to grind this oversized MgO to that
which was usable. This pulverizer was eventually
transferred to the acid plant. In addition, magnesium
oxide returning from the acid plant initially showed
a lower reactivity than expected. This was corrected
by heating the MgO slurry tank to 180° F to increase
the slaking rate of the MgO.
The combined effects of corrosion and erosion
were experienced in all pumps, valves, and piping
that handled the scrubbing slurry. Because the pro-
totype plant was designed for only a 2-year period
of operation, cast iron and carbon steel were used
in these areas and quickly failed. Rubber or plastic
lining is now considered necessary in slurry-handling
applications.
While centrifuge performance was generally sat-
isfactory, improved internal washing techniques
were required to reduce wear and improve reliability.
The availability of the SO2 recovery system to
the Boston Edison Unit No. 6 boiler ranged from a
low of 1 3 percent to a high of 87 percent during
the April 1972 and J une 1974 operating period.
Many of the lower-valued availabilities were caused
by the problems discussed above. During the last
4-month period of the recovery system's operation,
the monthly availabilities were 87 percent, 81 per-
cent, 57 percent, and 80 percent. The lowest re-
ported value was due to the lack of MgO for SO2
removal, caused by problems in the sulfuric acid
plant and an intentional emptying of the MgO silos
during a controlled system test.
Essex Chemical — MgO Regeneration and
Sulfuric Acid Production
After solving several initial operating problems,
which are discussed in the following paragraphs, the
chemical plant was consistently able to manufacture
high quality 98 percent sulfuric acid, which was sold
in the commercial market. Over 5,000 tons of H2SO4
were made from captured flue gas sulfur. During this
same period, 3,000 tons of magnesium oxide were
regenerated and shipped to the power plant for reuse.
The continued ability of the system to operate
efficiently with regenerated magnesium oxide was a
major variable investigated during the project. The
occasional formation of a small amount of less reac-
tive MgO was observed. This was generally accom-
panied by an increase in density of the magnesia.
Data from this test program were correlated by re-
gression analysis with operating conditions and the
percentage of carbon in the feed to predict opera-
ting conditions which would result in a low-bulk-
density magnesia. This correlation is shown in
figure 6 and indicates that the formation of low-
bulk-density (high-reactivity) magnesia is favored
by low calciner temperature and an increased
amount of carbon in the calciner feed.
Mechanical problems at the chemical plant were
centered around the calciner operation. One such
problem was air leakage into the calciner's firing
hood. The calciner must operate very near neutral
or at reducing conditions in order to allow for the
reduction of magnesium sulfate to magnesia. A con-
siderable amount of effort was expended in tight-
ening up seals and reducing air leakage. The prob-
lem was finally solved by the installation of a friction
seal.
Another problem occurred when oil was fired
during the startup of the cold calciner. Hydrocarbon
vapors not removed by the scrubbing equipment
entered the sulfuric acid towers, which immediately
caused the charring and blackening of the acid. This
problem was solved by installing a fan and a short
stack, which allowed the startup vapors to bypass
the sulfuric acid plant. This system was used only
when heating up the calciner and was never operated
during periods of SO2 generation.
MgO Losses
During the early period of operation, magnesium
oxide losses were excessive due primarily to spills
and required cleanouts caused, as previously de-
scribed, by the solids-handling problems.
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BULK DENSITY (LB/FT
45 r-
40
35
30
25
20
15
10
%C =0.5
%C - 1.0
%C = 1.5
%C = 2.0
700 800 900 1000 1100 1200 1300 1400 1500 1600 1700
M1DKILN TEMP (DEGREES F)
Figure 6.
Effect of midkiln temperature and calciner feed carbon on magnesia bulk-density
Boston Edison
In the final 4 months of operation, however,
the bulk of these problems was solved, and a care-
ful measurement was made of system losses. During
these 4 months, 1,500,000 pounds of regenerated
material were recycled to the power plant as scrub-
ber slurry makeup. A 13-day test to identify each
specific loss point was also conducted. The measure-
ments showed a loss over the entire power plant
operation of 0.37 ton per operating day, distributed
as follows:
Loss to stack
Scrubber overflow
Miscellaneous accounted
for losses
Unaccounted for losses
Total
0.13 ton per day
0.14 ton per day
0.07 ton per day
0.03 ton per day
0.37 ton per day
With an average MgO consumption of 10.61
tons per day during this period, this total loss
amounted to 3.5 percent of MgO consumption at
the power plant. The design loss at this same loca-
tion was predicted to be 5 percent.
Essex Chemical
The greatest losses for this project occurred at
the regeneration plant in Rumford, where 0.5 ton
per day was scalped off the calciner product as
large lumps before the pulverization process. Fu-
ture system design will provide for the reclaiming
of these losses. In addition, 1.5 tons per day were
lost from the neutralizer overflow. In subsequent
designs, this large loss can be recovered for recycle
by separation of solids in the neutralizer overflow.
Thus, almost all of the regeneration plant losses can
be reclaimed by improved design at new regenera-
tion plants.
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The economics of flue gas dcsulfurization with
magnesia and the subsequent production of sulfuric
acid are complex issues and vary widely with the
availability of nearby markets for sulfuric acid, as
well as the price differential between high- and low-
sulfur fuels.
In this report, the economics of a large-scale ar-
rangement similar to that of Boston Edison and
Essex Chemical are examined. The power plant
ships dried magnesium sulfite to the chemical plant
and receives regenerated dry magnesium oxide. A
fee must be paid to the chemical plant for conver-
sion. The savings, which the power plant realizes
from the lower fuel costs it enjoys because of its
ability to use less expensive high-sulfur fuel, allow
it to make this payment. A mutually beneficial sit-
uation exists when the power plant pays a fee that
permits a profitable operation for the chemical com-
pany, yet also allows savings for the power plant.
Although every effort was made to present re-
alistic cost figures, there are many variations specific
to each plant. Companies are encouraged to compare
their situations with the base costs used in this pres-
entation. Some reevaluation will no doubt be re-
quired to fit each specific location.
Table 3.
Basis for costs and economics
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Table 4.
Annual cost for a 500-Mw oil-fired {2.5% S) unit shipping dried MgS03 to a chemical plant
The economics under the set of conditions de-
fined in table 3 are examined for the case where
the sulfur output from two 500-Mw units burning
3.5-percent sulfur coal are shipped to a sulfuric
acid plant within 50 miles of the power plants. Ref-
erence materials used for this economic analysis are
also shown in table 3.
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Table 5.
Annual cost for a 500-Mw coal-fired (3.5% S) unit shipping dried MgS03 to a chemical plant
A similar analysis is made for four 500-Mw
plants burning 2.5 percent sulfur oil and feeding
their magnesium sulfite output to a central sulfuric
acid plant for regeneration. The costs for a com-
pletely new chemical plant and for an existing plant
modified to accept magnesium sulfite are estimated.
The investment and annualized costs for a single
500-Mw unit of the power plant in each case are
given in tables 4 and 5. These costs were derived
from the first four reference materials listed in
table 3 and were checked for general conformance
with engineered costs for a proposed installation.
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TableG.
Annual incremental manufacturing cost for an existing H2S04 plant
(calcination and S02 preparation facilities added)
The chemical plant would be of equal size in both
instances. Manufacturing costs are given in table 6
for modifying an existing plant and table 7 for a
new plant.
These economics are based upon definitive esti-
mates for the case stated which are expected to be
typical for many conditions. The costs for modifi-
cation of the existing sulfuric acid plant are more
difficult to evaluate, and will vary with the availabil-
ity of physical space for retrofitting. The economics
would be more favorable if the sulfuric acid plant
were built adjacent to the power plant, since trans-
portation costs are significant. The first reference
material listed in table 3 is recommended for infor-
mation on the sensitivity of the economics.
One option could be where a chemical plant
takes the magnesium sulfite slurry, assumes respon-
sibility for drying as well as calcining, and returns a
magnesium oxide slurry. Although each situation
may favor different arrangements, the economics
given in this section outline general conditions
for consideration of this technology.
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60
50
CHEMICAL PLANT
BEFORE TAX ROI
ON TOTAL
INVESTMENT
40
30
20
10
MODIFIED EXISTING
*SCHEMICAL PLANT
POWER PLANT
S3.00/BBL DIFFERENTIAL
NEW
^CHEMICAL
PLANT
POWER PLANT
$2.00/BBL DIFFERENTIAL
-13.0
2.5
2.0
1.5
50
75 100 125 150
PAYMENT TO CHEMICAL PLANT ($/TON MgO)
SAVINGS FOR
POWER PLANT
(MILLS/KWhr)
1.0
0.5
175
Figure 7.
Oil-fired power plant economics
Figure 7 summarizes the economics for the oil-
fired situation under the base conditions. The sav-
ings in mills per kilowatt-hour (mills/kWhr), which
the power plant would realize as a result of its abil-
ity to use high-sulfur oil, is plotted against the fee
paid to the chemical company for several price dif-
ferentials between high- and low-sulfur oil. The
before-tax return on investment (ROI) for the
chemical plant, as a function of this same fee, is
also plotted for both the building of a new chemical
plant and the modifying of an existing one.
Figure 7 points out areas of mutual benefit to
both parties. Since the price differential for % per-
cent and 2/2 percent fuel oil is currently $3 per
barrel (bbl), even at processing fees of $125 to
$150 per ton of magnesium oxide (which would
offer a 20- to 40-percent before-tax ROI to the
chemical company building a new plant just to
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CHEMICAL PLANT
BEFORE TAX ROI
ON TOTAL
INVESTMENT
60
50
40
30
20
10
POWER PLANT
$17.50/TON
DIFFERENTIAL
MODIFIED
EXISTING
CHEMICAL
PLANT
NEW
CHEMICAL
PLANT
POWER PLANT
DIFFERENTIAL
POWER PLANT
$12.50/TON
DIFFERENTIAL
—13.0
2.5
2.0
1.5
1.0
0.5
SAVINGS FOR
POWER PLANT
(MILLS/KWhr)
50 75 100 125 150
PAYMENT TO CHEMICAL PLANT ($/TON MgO)
175
Figure 8.
Coal-fired power plant economics
process the magnesium sulfite), savings of 1.8 to
2.1 mills/kWhr would be realized.
The preliminary economics for an existing sul-
furic acid plant, equipped with a calcination unit
and modified to receive wet SO2, appear even more
favorable; this option offers savings of 2.1 to 2.4
mills/kWhr at the 20- to 40-percent before-tax ROI
and fees of $50 to $75 per ton of magnesium oxide.
Figure 8 outlines the economics for the same
sulfuric acid plant processing the magnesium sulfite
from two 500-Mw coal-fired (3.5 percent) sulfur
units. The areas of mutual interest under the as-
sumed conditions are once again clearly shown for
this case. Favorable economics are offered by a coal
differential of $17.50 or $15 per ton. At $12.50
per ton, reasonable economics could be obtained
only if an existing sulfuric acid plant were geograph-
ically situated in an optimal location.
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Table 7.
Annual manufacturing cost for a new 700-TPD H2S04 plant regenerating MgO
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This technology has special application in geo-
graphical areas near sulfuric acid markets and where
land availability is limited for the disposal of sludges
produced from throwaway flue gas desulfurization
processes. It should also be of special interest to
chemical or fertilizer companies that are paying pre-
mium prices for low-sulfur fuel for their power gen-
eration and have existing uses and markets for sul-
furic acid.
Since the manufacture and sale of sulfuric acid
is a specialized area outside the realm of power plant
operations, an effective solution for both the chem-
ical industry and the utility companies would appear
to be the toll processing of the magnesium sulfite
solids into reusable magnesium oxide and sulfuric
acid by chemical companies. This could relieve the
power plants of becoming involved in the manufac-
ture and sale of sulfuric acid, and could minimize
major market disruptions to chemical companies
that could occur if power companies began to mar-
ket large amounts of byproduct sulfuric acid.
The application of the calciner's high-SO2 con-
centration offgas to other conventional sulfur-
fixing production techniques, such as the produc-
tion of elemental sulfur and liquid SO2, is highly
plausible. Such byproduct alternatives could alle-
viate problems associated with sulfuric acid market
fluctuation or, for that matter, the nonavailability
of a local sulfuric acid market.
Although the prototype plant was applied to
an oil-fired boiler, the use of coal is not expected
to affect the use of the technology as long as ade-
quate provisions are made to remove fly ash from
the flue gas prior to contact with the magnesia
slurry. On this basis, and utilizing design and proc-
ess experience gained, a Chemico-Basic magnesia
scrubbing system has been installed at the Potomac
Electric Power Company's coal-fired Dickerson
Unit No. 3 boiler in Maryland, and is being operated
in conjunction with regeneration and acid produc-
tion at the Essex Chemical plant at Rumford, Rhode
Island. Data obtained after 8 months of operation
have not indicated any major differences from the
operation at Boston Edison and Essex.
A United Engineers-designed magnesia slurry
system has been applied to approximately 120 Mw
at the Philadelphia Electric Company's coal-fired
Eddystone No. 1 Unit, and is currently under-
going startup. The magnesium sulfite will be re-
generated at the Olin Chemical sulfuric acid plant
in Paulsboro, New Jersey.
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For further information:
The detailed Project Report on this project is currently
being prepared. If you wish to be notified when this final
report is available, write:
Technology Transfer
Environmental Protection Agency
Washington, D.C. 20460
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