-------
including uncontrolled net plant heat rate, similar to one of
the 500 MW plants considered in this study. The energy penalty
data for the 500 MW plant can then be multiplied by 400,000 kW
to determine the energy penalty for the 400 MW plant.
The second method of expressing the energy penalty data
is as a percent of the energy input to an uncontrolled plant with
the same net heat rate and net generating capacity. This method
identifies, for a given generating capacity, the percentage in-
crease in energy consumption resulting from control of S02 emis-
sions .
An examination of the data in Tables 4-4 through 4-6
shows that on a per kilowatt or percentage basis, power plant
capacity has little influence on the energy requirements of the
emission control systems. Therefore, it is only necessary to
look at one plant capacity to compare the different levels and
means of controlling S02 emissions. Since 500 MW plants were
examined for all thirteen control cases, the data for this plant
capacity were selected for the comparative analyses.
4.1.1
Comparison by S02 Control Level
Three S02 emission control levels were examined:
0.52 g S02/MJ (1.2 Ib S02/106 B.tu) of heat
input (the existing NSPS)
90% SO2 removal by FGD
0.22 g S02/MJ (0.5 Ib S02/106 Btu) of heat
input
Comparisons of the energy requirements for the control systems
achieving these three control levels are presented in the follow-
ing sections.
-30-
-------
0.52 g S02/MJ
The energy requirements for the five cases which control
SO2 emissions to the existing NSPS of 0.52 g S02/MJ (1.2 Ib S02/
106 Btu) of heat input are shown in Figure 4-1. In addition to
indicating the total energy penalties for the control cases, the
data in Figure 4-1 are separated into the type of energy required,
i.e., steam, electricity, natural gas or fuel oil for the FGD
process, diesel fuel oil for unit trains and coal losses from
physical coal cleaning or transporting coal. The following ob-
servations can be made from the data in Figure 4-1:
The smallest energy penalty is imposed by
use of the nonregenerable FGD processes.
The three nonregenerable FGD processes
(limestone, lime and double-alkali) im-
pose approximately equal energy penalties.
The limestone process requires slightly
more energy than the lime and double-alkali
processes.
Of the two regenerable FGD processes, the
Wellman-Lord/Allied process requires over
twice as much energy as the MgO process.
Shipping low sulfur western coal to the
Midwest requires from 25 to over 100 percent
more energy than burning a high sulfur coal
and using a nonregenerable FGD process.
Phyically cleaning coal prior to combustion
and also using the limestone or, lime FGD
-31-
-------
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3.6% SULFUR.
27,9Mjyfca
COAL
7.0%SULFUR. 0.6 % SULFUR. 0.8% SULFUR. 3.5% SULFUR.
27.9 M J/cg 20.9MJ/kg 25.6 MJ/kg 27.9 M J/kg
COAL COAL COAL COAL
Figure 4-1,
Energy requirements for S02 and particulate
control - 0.52 g S02/MJ control level, 500 MW plant
-32-
-------
process requires about three times the
energy required when dnly the' FGto process
is used.
90% SO2 Removal by FGD
The energy requirements for the four control cases
which achieve 90 percent SO 2 removal are shown in Figure 4-2.
As was true for the 0.52 g S02/MJ control level, use of any of
the nonregenerable FGD processes requires about the same amount
of energy and the nonregenerable FGD processes impose much less
of an energy penalty than the regenerable FGD processes. With
respect to changes in the sulfur content of the coal, the energy
requirements of the nonregenerable FGD processes change very
little (about a 10 percent increase when the sulfur content of
the coal doubles from 3.5 to 7.0 percent). However, the energy
requirements of the regenerable FGD processes show a strong de-
pendence on the sulfur content of the coal. Doubling the coal
sulfur content from 3.5 to 7.0 percent increases the energy re-
quirements of the MgO process by about 50 percent and of the
Wellman-Lord/Allied process by about 100 percent. This arises
because the S02 recovery operations represent 55 to 85 percent
of the energy required by these processes.
0.22 g S02/MJ
The energy requirements for the four cases which con-
trol S02 emission to 0.22 g S02/MJ (0.5 Ib S02/106 Btu) of heat
input are shown in Figure 4-3. As for the other two control
levels, the energy requirements of the limestone and lime FGD
processes are essentially equal. The two control cases which
include physical coal cleaning followed by use of the lime or
limestone FGD process again illustrate the significant energy
penalty associated with physical coal cleaning.
-33-
-------
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Figure 4-2.
Energy penalties for S02 and particulate
control - 90% removal control level,
500 MW plant.
-34-
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COAL COAL COAL
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COAL
Figure 4-3.
Energy requirements for SO2 and particulate
control - 0.22 g.S02/MJ control level, 5.00 MW plant.
-35-
-------
4.1.2
Comparison by Coal Used
The energy requirements of the model S02 emission
control systems are compared in this section with respect to the
coal used. These comparisons identify the different energy pen-
alties incurred by complying with the three emission control
levels.
3.5% Sulfur Eastern Goal
The emission control cases which use the 3.5 percent
sulfur, 27.9 MJ/kg eastern coal are shown in Figure 4-4. For
the control cases which use only an FGD process for S02 control,
the energy penalty for achieving 90 percent S02 removal is only
slightly higher (about 10 percent) than for complying with the
existing NSPS of 0.52 g S02/MJ (1.2 lb S02/106 Btu) of heat
input. For the control cases which use physical coal cleaning
in conjunction with the lime or limestone FGD process, there is
essentially no difference in the energy penalties for complying
with the existing NSPS or for reducing S02 emission to 0.22 g
S02/MJ (1.2 lb S02/106 Btu) of heat input. However, the energy
penalty for using coal cleaning with the lime or limestone FGD
process is almost three times the energy penalty for using the
lime or limestone FGD process as the only S02 control technique.
7.0% Sulfur Eastern Coal
The energy requirements for the three control cases
which utilized the 7.0 percent sulfur coal are shown in Figure
4-5. For the limestone and lime FGD processes the energy pen-
alty for achieving 90 percent S02 removal is about equal to the
penalty for meeting the existing NSPS. Physical coal cleaning
followed by FGD requires over one and one-half times the energy
that is required by FGD alone.
-36-
-------
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Figure 4-4. Energy requirements for SOa
control - 3.57o sulfur coal,
and particulate
500 MW plant
-37-
-------
i ert.t.n. R^ COAL CLEANING LOSSES
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Figure 4-5.
Energy requirements for S02 and particulate
control - 7.0% sulfur coal, 500 MW plant.
-38-
-------
Low Sulfur Western Coals
The energy requirements for the four control cases
which utilize the low sulfur western coals are shown in Figures
4-6 and 4-7. The data in these figures show the very small dif-
ference in energy requirements for using the limestone or lime
FGD process to achieve either 90 percent SQz removal or 0.22 g
S02/MJ (0.5 Ib S02/106 Btu) of heat input. This is expected due
to the similar properties of the two western coals. !
4.2
Energy Penalty Projections
The following projections of new coal-fired electric
generating capacity which would be affected by a revised S02 new
source performance standard were supplied by the EPA:
New Coal-Fired Generating Capacity
1983 through 1987 65,000 MW
1983 through 1997 316,000 MW
The EPA also indicated that the average annual operating factor
for this new capacity would be 65 percent. The energy penalty
data presented previously were used with these capacity projec-
tions to estimate the future effect of a revised NSPS on the
energy penalties of S02 emission controls. It was assumed for
these calculations that the new capacity would be installed in
the form of 500 MW power plants. However, the mix of coal feeds
and S02 control methods for these new plants and future S02 emis-
sion standards were not known. In order to illustrate what the
minimum and maximum energy penalties may be, the projected new
generating capacities were multiplied by the energy requirements
for each of the 500 MW model power plant/S02 control systems.
These estimated energy penalties for 1987 and 1997 are listed in
Table 4-7 and 4-8, respectively.
-39-
-------
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Figure 4-6. Energy requirements for S02 and particulate
control - low heating value Western coal.
500 MW plant.
-40-
-------
STEAM AND ELECTRICITY
i
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Figure 4-7.
Energy requirements for SOz and particulate
control - high heating value Western coal
500 MW plant.
-41-
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-43-
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While the open literature contains many projections of
future U.S. energy demands, these projections vary considerably.
The following data are an average of several projections (BA-538)
1987
1997
Projected U.S. Energy Consumption
110 x 1018 J (100 x 1015 Btu)
130 x 1018 J (120 x 1015 Btu)
These projections were used to calculate the "percent of Total
U.S. Energy Consumption" data shown in Tables 4-7 and 4-8.
The data in Tables 4-7 and 4-8 indicated that in 1987
controlling S02 emissions from new sources, -i.e., those that come
on-line after 1982, would increase U.S. energy consumption by an
estimated 0.1 to 0.8 percent. In 1997 the increase in U.S. energy
consumption is estimated to be 0.4 to 3.4 percent. The lower end
of these ranges represents use of the nonregenerable FGD processes.
The high end of the ranges represents combustion of 7 percent
sulfur coal and removing 90 percent of the S02 by the Wellman-Lord/
Allied FGD process. At the present time the limestone and lime
are the most widely used FGD processes. This trend is anticipated
to continue through 1997. Therefore, estimates of 0.1 percent and
0.4 percent for 1987 and 1997, respectively, are probably more
accurate. For a given means of controlling S02 emissions, the
data indicated that to achieve 90 percent S02 removal requires
about 10 percent more energy than is required to meet the existing
NSPS.
The S02 emission controls would also derate the projected
65,000 MW of new generating capacity installed in 1983-1987 by an
estimated 2,300 MW. The projected 316,000 MW of new generating
capacity installed in 1983-1997 would be derated by an estimated
11,000 MW.
-44-
-------
REFERENCES
BA-538 Balzhiser, Richard E., "Energy options to the year
2000", Chem. Eng. 73 (1977) Jan. 3, p. 74. ..
BU-116 Buck, P. and N. Savage, "Determine Unit - Train
Requirements", Power 118(1), 90 (1974) pp. 90-91.
CH-307 Choi, P. S., et-al., S02 reduction in non-utility
combustion sources — technical and economic comparison
of alternatives, final report. EPA 600/2-75-073,
Contract No. 68-02-1323, Task 13. Columbus, Ohio:
Battelle-Columbus Laboratories, Oct. 1974, .pp. 76, 77.
CO-129 Council on Environmental Quality, Energy & The
Environment; Electric Power. Washington, B.C.,
1973, p. 40. :
CO-380 "Coal Preparation and Unit-Train Loading", Coal Age
1970 (July), pp. 188-202.
CO-644 Cooper, Tom, Private Communication, Combustion
Engineering, September 23, 1977.
DE-064 Deurbrouck, A. ¥., Sulfur Reduction Potential of the
Coals of the United States. Report of Investigations
7633. Pittsburgh, PA.: Pittsburgh Energy Research
Center, 1972, pp. 16-19.
EN-587 Environmental Protection Agency, Office of Research
and Development, Industrial Process Profiles:for
Environmental Use, 26 volumes. EPA 600/2-77-023 a-2,
EPA Contract No. 68-02-1319, Task 34. Austin, TX.,
Radian Corporation, various dates. (Volume R, pp. 24-25)
-45-
-------
REFERENCES (Continued)
FI-102 "Fine-Coal Treatment and Water Handling", Coal Age 66
(12), 67 (1961), p. 79.
KA-227 Kaplan, Norman, "Introduction to Double-Alkali Flue
Gas Desulfurization Technology", Presented at the EPA
Flue Gas Desulfurization Symposium, New Orleans,
Louisiana, March 1976, p. 411.
KO-174 Koehler, George and James A. Burns, The Magnesia
Scrubbing Process as Applied to an Oil-Fired Power
Plant, Final Report. EPA-600/2-75-057, EPA Contract
No. EPA 70-114. N.Y., Chemical Construction Corp.,
October 1975, p. 4.
LO-071 Lowry, H.H. ed., Chemistry of Coal Utilization,
2 vols. and supplementary volume. N.Y., Wiley, 1945,
1963 (Supplementary volume), pp. 325-331.
MC-136 McGlamery, G.G., et al., Detailed Cost Estimates for
Advanced Effluent Desulfurization Processes.
Interagency Agreement EPA IAG-134 (D), Pt. A.
Research Triangle Park, N.C., Control Systems Lab.,
NERC, 1974, pp. 13-17, 19-24, 30-68, 134-141.
OT-051 Ottmers, D.M., Jr., et al., Evaluation of Regenerable
Flue Gas Desulfurization Processes, revised report,
2 vols., EPRI RP 535-1. Austin, TX, Radian Corp.,
July 1976, pp. 254, 320, 427-428.
-46-
-------
REFERENCES (Continued)
RA-215 Radian Corporation, A Western Regional Energy Develop-
ment Study, 4 vols. Final Report. Radian Project No.
100-064, PB 246264/6ST, PB 246265/3ST, PB 246266/1ST,
PB 246267/9ST. Austin, TX., August 1974. Vol. II,
pp. 577, 578, 586.
RO-325 Robinson, Jerry, Private Communication, Battelle
Research Corporation, 7 June 1977.
SA-311 Saleem, Abdus, Private Communication, Chemico,
1 June 1977.
SO-138 Soo, S. L., et al. , The Coal Future, Appendix F, Coal
Transportation, Unit Trains, Slurry and Pneumatic
Pipelines. PB 248-652, NSF-RA-N-75-037-F. Urbana,
Illinois, University of Illinois at Urbana-Champaign,
Center for Advanced Computation, June 1975, pp. A6, A7.
WE-003 (Paul) Weir Company, An Economic Feasibility Study of
Coal Desulfurization, 2 vols. PB 176 845, PB 176 846.
Chicago, IL, October 1965, Vol. I, pp. 3-4.
WH-101 White, David Mills, An Analysis of Transportation
Alternatives for Meeting Texas Industrial Demand of
Western Coal Through the Year 2000. Master's Thesis,
University of Texas at Austin, August 1976, p. 43.
ZO-008 Zonis, Irwin S., et al., "The Production and Marketing
of Sulfuric Acid from the Magnesium Oxide Flue Gas
Desulfurization Process", Presented at the Flue Gas
Desulfurization Symposium, Atlanta, GA., November 1974,
Essex Chemical Corp., 1974, p. 5.
-47-
-------
APPENDIX A
LIMESTONE FGD PROCESS
-------
1.0
LIMESTONE FGD PROCESS
The limestone flue gas desulfurization process uses
an aqueous slurry of limestone to absorb S02 from flue gases.
It is a nonregenerable desulfurization process since the S02
sorbent is continuously consumed, being discharged from the
process along with the absorbed S02 as a calciun? sulfite/sulfate
sludge. Figure A-l is a simplified flow scheme of the limestone
FGD process selected for examination in this study.
Flue gas from the power plant air preheater enters a
variable throat venturi scrubber. Liquor injected into the
venturi removes approximately 99 percent of the flue gas parti-
culate matter and a small amount of S02. Following particulate
removal, the flue gas enters a two-bed, mobile bed absorber.
Limestone slurry recirculated to this absorber can remove about
90 percent of the S02 present in the flue gas. The overall chemis-
try of the SO 2 removal process can be represented by the follow-
ing two reactions:
CaC03
CaC03
S02
%02
CaS0
C0
(1-D
(1-2)
The flue gas exiting the S02 absorber is heated in an indirect
steam reheater and compressed in an induced draft fan before
entering the power plant stack for discharge to the atmosphere.
A portion of the recirculating liquor in the particu-
late scrubbing loop is directed to a lined settling pond where
fly ash and calcium solids settle out. Clarified pond water is
returned to the S02 absorbers. Makeup limestone slurry for the
S02 absorbers is prepared on-site by crushing, grinding and
slurrying limestone.
A-2
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1.1
Base Case - Limestone FGD Process
Material and energy balances were calculated for the
base case limestone FGD process - 90 percent removal of the SC-2
from the flue gas from a 500 MW power plant burning a 3.5 per-
cent sulfur coal. The information used to prepare the material
balance (see Table A-l) and calculate energy requirements was
obtained from the open literature (MC-136).
The limestone process consists of six basic processing
operations:
1.1.1
Raw material handling and preparation
Particulate scrubbing
SO2 scrubbing
Reheat
Fans
Calcium solids disposal
Raw Material Handling and Preparation
The raw material handling and feed preparation processing
operation takes raw limestone and converts it into a slurry for
use as makeup reagent to the SOa absorbers. Equipment in this area
includes storage bins, conveyors, crushers, grinders, slurry
tanks, a dust collection system and pumps. For the base case
design in which 6.30 kg/s (50,000 Ib/hr) of limestone (90 percent
CaCOs) are handled, the electric power requirements are estimated
at 790 kW.
A-,4
-------
TABLE A-l. BASE CASE MATERIAL BALANCE--LIMESTONE FGD PROCESS
Stream
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Stream
No. Description
Coal to Boiler
Combustion Air to
Boiler
Flue Gas to Air
Pr eh eater
Gas to Particulate
Scrubber
Gas to Reheater
Steam to Gas Reheater
Gas to I.D. Fans
Flue Gas to
Atmosphere
Slurry to Particulate
Scirubber
Makeup Water
Slurry to SO 2
Scrubber
Slurry to Settling
Pond
Makeup Limestone
Makeup Limestone
Rate
kg/s Nm3/s mVs Temperature, °K
47.3
570 430 317
555 421 647
611 464 428
637 518 325
8.88 517
637 518 346
637 518 353
1372 1.24
41.1 0.04
6048 5.8
69.0 0.06
6.3
Slurry
10.0
0.006
A-5
-------
1.1.2
Particulate Scrubbing
Included in the particulate scrubbing operation are
variable throat venturi scrubbers, effluent hold tanks with
agitators and scrubbing liquor recirculation pumps. To achieve
approximately 99 percent removal of the flue gas particulate
matter, the venturi scrubbers are operated at a liquid to gas
ratio (based on exit flue gas conditions) of 2 m3/1000 m3 (15
gal/1000 acf). The electric power requirements for the re-
circulation pumps and agitators are estimated to be 920 kW.
1.1.3
SO2 Scrubbing
The S02 absorbers selected for the limestone FGD pro-
cess are mobile bed absorbers. Hold tanks with agitators and
scrubbing liquor recirculation pumps are also required. To
effect 90 percent S02 removal in the base case design, a liquid
to gas ratio (based on exit flue gas conditions) of approximately
9.3 m3/100'0 m3 (70 gal/1000 acf) is required. The electric
power requirements for S02 scrubbing are estimated to be 3,220
kW. !
1.1.4
Reheat
Scrubbed flue gas from a wet scrubbing process is
normally reheated to obtain a stack exit temperature of about
353°K (175°F). This can be achieved by combustion of an auxil-
iary fuel with direct injection of the hot combustion gases into
the scrubbed flue gas or by indirect heating with steam. The
latter method was selected because the reheat steam can be ob-
tained from the power plant boiler. Since some reheat is pro-
vided by the induced draft fans downstream of the reheater,
A-6
-------
approximately 21°K (38°F) of additional reheat are required.
For the base base, the reheat energy requirements are estimated
to be 15.6 MJ/s (53.2 x 106 Btu/hr). At an available steam heat
content of 1.75 MJ/kg (755 Btu/lb), the steam requirements for
the reheater are 8.88 kg/s (70,400 Ib/hr).
1.1.5
Fans
Induced draft fans located downstream of the flue gas
reheater are used to overcome the pressure drop of the flue gas
as it passes through the limestone FGD process. For the base case
design, which has a pressure drop of 6.5 kPa (26 in. H20), the
electric power requirements for the fans are estimated to be
6,150 kW.
1.1.6
Calcium Solids Disposal
This process operation includes a pond feed tank with
agitator, a lined settling pond and pumps for transporting the
fly ash/calcium solids slurry to the settling pond and returning
pond water to the scrubbing system. Since the calcium solids
represent about 60 percent of the total solids directed to the
settling pond, the energy requirements for solids disposal are
prorated using this factor. For the base case design in which
2.58 kg/s (10.3 ton/hr) of SOa are removed, the electric power
requirements for disposal of the resulting calcium solid are
estimated at 100 kW.
1.1.7
Utilities and Services
Utilities and services such as instrument air,
lighting, heating, cooling, etc., are required for the limestone
FGD facilities. For the base case design, the electric power
requirements for utilities and services are estimated at 60 kW.
A-7
-------
1.1.8
Base Case Summary
The electricity and steam requirements for the base
case limestone FGD process are summarized in Table A-2. As
shown by the data in this table, a 500 MW power plant burning
a 3.5 percent sulfur coal without any S02 emission controls
would require an energy input of 1.32 GJ/s (4.50 x 109 Btu/hr).
Reducing the S02 emissions from this plant by 90 percent with
a limestone FGD system would derate the power plant by 18 MW.
This assumes that all of the energy requirements of the FGD
system are obtained from the power plant. The uncontrolled
plant net heat rate is 2,640 J/kW-s (9,000 Btu/kW-hr). Since
the net heat rate for the controlled plant is 2,740 J/kW-s
(9,350 Btu/kW-hr), the energy penalty of the'S02 control system
is 100 J/kW-s (350 Btu/kW-hr).
A percentage breakdown of the energy requirements for
the base case limestone FGD process are shown below.
Raw material handling and preparation - 4%
Particulate scrubbing - 5%
S02 scrubbing -18%
Reheat -37%
Fans . -34%
Calcium solids disposal -<1%
Utilities and services -<1%
The particulate scrubbers, reheaters and fans account for about
75 percent of the base case limestone system energy requirements.
Since the energy requirements for these process operations depend
essentially only on the flue gas flow rate, a very large portion
of the total system energy requirements are insensitive to the
S02 concentration in the flue gas. This indicates that for a
given power plant capacity, the energy requirements for the S02
A-8
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emission control systems which use the limestone FGD process should
be approximately equal. Differences which do occur result from
the dependence of the raw material handling and preparation and
S02 scrubbing operations on flue gas S02 concentration and S02
r emoval 1eve1.
1.2
Base Case Extrapolation
The electricity and steam requirements for all of the
S02 control cases which use the limestone FGD process can be ex-
trapolated from the base case data. The electric power require-
ments for the raw material handling and preparation, and calcium
solids disposal operations am proportional to the amount of S02
removed. For particulate scrubbing, reheat, and utilities and
services, the electric power and steam requirements can be related
to the flue gas flow rate exiting the power plant air preheater.
The following extrapolation factors were identified for these
five segments of the limestone FGD process:
Raw material handling and preparation
Particulate scrubbing
Reheat
Calcium solids disposal
Utilities and services
306 kW/(kg S02 rem./s)
1.98 kw/(Nm3/s)
33.5 kJ/Nm3
38.7 kW/(kg S02 rem./s)
0.13 kW/(Nm3/s)
The electric power requirements for the S02 scrubbers
and fans are dependent on the S02 concentration in the flue gas
and the desired S02 removal level. Methods of calculating the
power requirements for these operations are described below.
1.2.1 S02 Scrubbing
Variables which determine the amount of S02 that can
A-10
-------
be removed in a mobile bed absorber include:
• the liquid to gas ratio,
• the gas velocity,
• the scrubbing liquor pH,
• the inlet S02 concentration,
• the height of the bed, number of beds, and
diameter of packing, and
• the chloride and magnesium ion concentration
in the scrubbing liquor.
Based on test data for limestone wet scrubbing using a turbulent
•bed contactor (a type of mobile bed) at the TVA Shawnee plant,
Bechtel Corporation developed the following semi-empirical cor-
relation relating the above variables to S02 removal.
T1 S02 = 1 - exp[-2.05 x 10 "* x (L/G)
0 • 81 0 • 36
x v exp[4.3 x 10~3 x v x (h/d + N)
+ 0.81 x pH± + 7.9 x 10 5 x (Mg) - 1.7
x
~5
x Y± + 1.3 x 10~ x (Cl)]] (1-3)
where
nS02
L/G
v
h
d
N
= fraction of S02 removal
Y
Cl
Mg
liquid to gas ratio
outlet conditions
gal/1000 cf at
gas velocity, ft/s
height of bed, in
diameter of packing, in
number of beds
inlet scrubbing liquor pH
inlet S02 concentration, ppm
inlet scrubbing liquor chloride
concentration, ppm
effective inlet scrubbing liquor
magnesium concentration, ppm
A-11
-------
The following values, which are typical of those used
in the development of the Bechtel correlation, were assumed for
use in Equation (1-3) :.
V
h
d
N
•PH±
Cl
Mg
= 10 ft/s
= 15 in.
= 1.5 in .
= 2
= 6.0
= 3,000 ppm
= 0 ppm
Substituting these values into Equation (1-3) gives
= 1 - exp[-4.7 x 10"" x (L/G) °'81 exp[5.4 - 1.7 x l(f * x Y ] ] (1-4)
Equation 1-4 was developed from data which included inlet S02
concentrations of 1500-4500 ppm. Although use of low sulfur
western coals produces inlet S02 concentrations of about 500
ppm, it is felt that Equation 1-4 will give reasonable estimates
of L/G's for these inlet S02 concentrations. Since the power
requirements for S02 scrubbing are directly related to the
scrubbing liquor flow rate, knowledge of the required L/G and
the flue gas flow rate permits calculation of the electric power
requirements. Table A-3 lists the L/G's calculated from Equa-
tion (1-4).
1.2.2
Fans
Flue gas flow rate and pressure drop are the two major
variables which affect the-energy requirements of fans. For the
A-12
-------
low pressure drops which fans must overcome, the following
equation can be used to calculate power requirements:
power required, kW =
Q x AP
(1-5)
where Q » flue gas flow rate, m3/s
AP = pressure drop, kPa
e = 0.690 = energy conversion efficiency of
fan and motor
Table A-3 lists the system pressure drops for the control cases
examined. These pressure drops were calculated from the base
case data and a relationship developed by Bechtel for the
dependence of pressure drop on L/G in a turbulent contact
absorber.
A-13
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-------
APPENDIX B
LIME FGD PROCESS
-------
1.0
LIME FGD PROCESS
The lime flue gas desulfurization process is very simi-
lar to the limestone FGD process. The major difference is the
source of alkalinity used to absorb SOz. As the name of the
systems imply, the lime process uses a lime slurry while the
limestone process uses a limestone slurry. The overall chemistry
of the lime process can be represented by the following reac-
tions .
CaO + S02 -> CaS03
CaS03 + %02 -*•
(1-1)
(1-2)
Figure B-l is a simplified flow scheme of the lime FGD process
s.elected for examination in this study.
1.1
Base Case - Lime FGD Process
Material and energy balances were calculated for the
base case lime FGD process--90 percent removal of the SOa from
the flue gas from a 500 MW power plant burning a 3.5 percent
sulfur coal. The information used to prepare the material
balance (see Table B-l) and calculate energy requirements was
obtained from the open literature_(MC-136)•
There are six general process operations in the lime
FGD process:
Raw material handling and preparation
Particulate scrubbing
SO2 scrubbing
Reheat
Fans
Calcium solids disposal
B-2
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Stream
1
2
3
4
5
6
7
8
9
10
11
12
13
14
Stream
No. Description
Coal to Boiler
Combustion Air to
Boiler
Flue Gas to Air
Preheater
Gas to Particulate
Scrubber
Gas to Reheater
Steam to Gas Reheater
Gas to I.D. Fans
Flue Gas to
Atmosphere,
Slurry to Particulate
Scrubber
Makeup Water
Slurry to SO 2
Scrubber
Slurry to Settling
Pond
Makeup Lime
Makeup Lime
Slurry
Rate
kg/s Nmd/s
47.3
570 430
555 421
611 464
637 518
8.88
637 518
637 518
1372
41.1
6048
69.0
2.9
25.3
mVs Temperature, °K
317
647
428
325
517
346
353
1.24
0.04
5.8
0.06
0.02
B-4
-------
The particxalate scrubbing and reheat operations are identical
to those in the limestone process. Tor the base case design,
the electric power requirements for particulate scrubbing are
estimated to be 920 kW. The steam requirements for the reheater
are estimated to be 8.88 kg/s (70,400 Ib/hr).
1.1.1
Raw Material Handling and Preparation
The raw material handling and feed preparation opera-
tion is designed to receive pebble lime and prepare a 25 percent
solids slurry for use as makeup reagent for the SOa absorbers.
Major equipment items include conveyors, storage bins, vibrators,
slakers, a slurry surge tank and pumps. For the base base
design in which 2.93 kg/s (23,200 Ib/hr) of lime (95 percent CaO)
are handled, the electric power requirements are estimated to
be 80 kW.
1.1.2
SO2 Scrubbing
The S02 absorbers selected for the lime FGD process
are mobile bed absorbers. Hold tanks with agitators and
scrubbing liquor recirculation pumps are also required. To
effect 90 percent S02 removal in the base case design, a liquid
to gas ratio (based on exit flue gas conditions) of approxi-
mately 6.7 m3/1000 m3 (50 gal/1000 acf) is required. The
electric power requirements for SOZ scrubbing are estimated to
be 2,300 kW.
1.1.3
Fans
Induced draft fans located downstream of the reheater
are used to overcome the pressure drop of the flue gas as it
passes through the lime FGD process. For the base case design
B-5
-------
which has a pressure drop of 6.4 kPa (26 in. H20), the electric
power requirements for the fans are estimated to be 6,100 kW.
1.1.4
Calcium Solids Disposal
The calcium solids produced in the S02 absorber are
disposed of in lined settling ponds. For the base case design
in which 2.58 kg/s (10.3 ton/hr) of S02 are removed, the elec-
tric power requirements for disposal of the resulting calcium
solids are estimated to be 60 kW.
1.1.5
Utilities and Services
The utilities and services required by the lime FGD
process are similar to those for the limestone process. For
the base case design, the electric power requirements for utili-
ties and services are estimated to be 60 kW.
1.1.6
Base Case Summary
The electricity and steam requirements for'the base
case lime FGD process are summarized in Table B-2. As before,
a 500 MW power plant burning a 3.5 percent sulfur coal without
any S02 emission controls would require an energy input of 1.32
GJ/s (4.50 x 109 Btu/hr). Reducing the S02 emissions from this
plant by 90 percent with a lime FGD system would derate the
power plant by 16 MW. This assumes that all energy requirements
of the FGD system are obtained from the power plant. The un-
controlled plant net heat rate is 2,640 J/kW-s (9,000 Btu/kW-hr)
Since the net heat rate for the controlled plant is 2,730 J/kW-s
(9,320 Btu/kW-hr), the energy penalty of the S02 control system
is 90 J/kW-s (320 Btu/kW-hr).
B-6
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B-7
-------
A percentage breakdown of the energy requirements for
the base case lime FGD process are shown below:
Raw material handling and preparation -
Particulate scrubbing
S02 scrubbing
Reheat -
Fans
Calcium solids disposal
Utilities and services
6%
14%
41%
38%
The particulate scrubbers, reheaters and fans account for about
80 percent of the lime system energy requirements. Since the
energy requirements for these operations depend essentially
only on the flue gas flow rate, a very large portion of the
total system energy requirements are insensitive to the SO2 '
concentration in the flue gas. This indicates that for a given
power plant capacity, the energy requirements for the S02
emission control systems which use the lime FGD process should
be approximately equal. Differences which do occur result from
the dependence of the raw material handling and preparation and
S02 scrubbing operations on flue gas S02 concentration and S02
removal level.
1.2
Base Case Extrapolation
The electricity and steam requirements for all of the
S02 control cases which use the lime FGD process can be extra-
polated from the base case data. The electric power require-
ments for the raw material handling and preparation, and calcium
solids disposal operations are proportional to the amount of
S02 removed. For particulate scrubbing, reheat, and utilities
and services, the electric power and steam requirements can be
B-8
-------
related to the flue gas flow rate exiting the power plant air
preheater. The following extrapolation factors were identified
for these five segments of the lime FGD process:
Raw material handling
and preparation
Particulate scrubbing
Reheat
Calcium solids disposal
Utilities and services
-30.9 kW/(kg S02 rem./s)
-1.98 kW/(Nm3/s)
- 33.5 kJ/Nm3
-38.7 kW/(kg S02 rem./s)
-0.13 kW/(Nm3/s)
The power requirements for the S02 scrubbers and fans
are dependent on the S02 concentration in the flue gas and the
desired S02 removal level. Methods of calculating the power
requirements for these operations are described below.
1.2.1
S02 Scrubbing
Bechtel Corporation developed an equation for the
lime process that is similar in form to that used for calculating
L/G's for the S02 absorber in the limestone process.
n
S02
x (L/G)1'12 x v°*65 exp[0.0039 x v x (h/d + N)
+ 0.18 x pH± + 1.5 x lO"1" x (Mg) - 2.2 x 10 * x Y±]
(1-3)
where
nS02
L/G
v
h
= fraction of S02 removal
= liquid to gas ratio, gal/1000 cf at
outlet conditions
= gas velocity, ft/s
= height of bed, in
B-9
-------
d
N
pHi
Yi
Mg
= diameter of packing, in
= number of beds
= inlet scrubbing liquor pH
= inlet S02 concentration, ppm
= effective inlet scrubbing liquor
magnesium concentration, ppm
The following values which are typical of those used
in the development of the Bechtel correlation, were assumed for
use in Equation (1-3):
v = 12.5 ft/s
h =15 in.
d = 1.5 in.
N = 2
pH± =8.0
Cl = 3,000 ppm
Mg =0 ppm
Substituting these values into Equation (1-3) gives
'S02
= 1 - exp[-5.2 x 10~3 x (L/G)1*12 exp[2.0 - 2.2 x 10 * x Y±]] (1-4)
Equation 1-4 was developed from data which included inlet S02
concentrations of 2000-4000 ppm. Although some coals used in
this study produce inlet S02 concentrations outside .this range,
it is felt that Equation 1-4 will give reasonable estimates of
L/G's for these inlet S02 concentrations. Since the power
requirements for S02 scrubbing are directly related to the
scrubbing liquor flow rate, knowledge of the required L/G and
B-10
-------
the flue gas flow rate permits calculation of the electric power
requirements. Table B-3 lists the L/G's calculated from Equa-
tion (1-4).
1.2.2
Fans
The equation for calculating the power requirements
for induced draft fans is given by Equation 1-5 in Appendix A.
The pressure drops for use in Equation 1-5 are given in Table
B-3 for the lime FGD control cases.
B-ll
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E-12
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r
APPENDIX C
MAGNESIA SLURRY FGD PROCESS
-------
1.0
MgO SLURRY FGD PROCESS
The magnesia slurry (MgO) flue gas desulfurization
process uses an aqueous slurry of MgO to absorb S02 from flue
gases. The process is termed regenerable since the scrubbing
slurry is thermal regenerated to produce MgO and S02. The MgO
is recycled to the scrubbing system while the S02 is converted
into sulfuric acid. Figure C-l is a simplified flow scheme of
the MgO slurry FGD process selected for examination in this
s tudy.
Flue gas from the power plant air preheater first
enters a variable throat venturi scrubber. A fly ash slurry is
injected into this venturi to remove particulates and chlorides,
The flue gas next enters a second venturi wherein S02 is ab-
sorbed by injection of magnesia slurry. The overall chemistry
of the S02 absorption step can be represented by the following
reaction.
MgO + S02 -* MgS03
(1-D
Flue gas exiting the second venturi is heated in an indirect
steam reheater and compressed in an induced draft fan prior to
entering the power plant stack for discharge to the atmosphere.
A portion of the recirculating S02 absorber scrubbing
liquor is continuously removed and directed to the regeneration
facilities. Here, MgS03 solids are separated from the liquor
and thermally regenerated in an oil-fired fluid bed calciner.
The calcination reaction is the reverse of Reaction 1-1. The
regenerated MgO is recycled to the scrubber, while the S02 is
sent to a conventional contact sulfuric acid plant. Makeup
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magnesia slurry is prepared on-site by slurrying recycle and
fresh MgO.
1.1
Base Case-MgO FGD Process
Material and energy balances were calculated for the
base case MgO FGD process - 90 percent removal of the S02 from
the flue gas from a 500 MW power plant burning a 3.5 percent
sulfur coal. The information used to prepare the material
balance (see Table G-l) and calculate energy requirements was
obtained from the open literature (MC-136).
process:
1.1.1
There are nine general operations in the MgO FGD
Raw material handling and preparation
Particulate/Chloride Removal
S02 scrubbing
Reheat
F.ans
Slurry processing
Cake drying
MgS03 calcining
• Sulfuric acid production
Raw Material Handling and Preparation
The raw material handling and feed preparation opera-
tion includes equipment for receiving coke and fresh MgO and
for storing, conveying and slurrying fresh and recycle MgO.
The equipment is designed to handle 0.038 kg/s (300 Ib/hr) of
fresh MgO (98% purity), 2.09 kg/s (16,600 Ib/hr) of recycle MgO
C-4
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and 0.0275 kg/s (218 Ib/hr) of coke. Based on these flow rates,
the electric power requirements are estimated to by 180 kW.
1.1.2
Particulate/Chloride Removal
Included in the particulate/chloride scrubbing operation
are variable throat venturi scrubbers, effluent surge tanks and
recirculating slurry, makeup water and slurry disposal pumps.
The venturi scrubbers operate at a gas phase pressure drop of
2.1 kPa (8.5 in. H20) and a liquid to gas ratio (based on exit
flue gas conditions) of 2 m3/1000 m3 (15 gal/1000 acf). For
the base case design, the electric power requirements for par-
ticulate scrubbing are estimated to be 1,090 kW.
1.1.3
SO, Scrubbing
The S02 scrubbing operation includes variable throat
venturi scrubbers and magnesia slurry recirculation pumps. The
scrubbers operate at an L/G (based on exit flue gas conditions)
of 2.7 mVlOOO m3 (20 gal/1000 acf) and a gas phase pressure
drop of 1.1 kPa (4.5 in. H20). For the base case MgO process,
the electric power requirements for the. S02 scrubbing operation
are estimated to be 910 kW.
1.1.4
Reheat
As for the limestone and lime FGD processes, indirect
steam reheaters are used to heat the scrubbed flue gas prior to
discharge to the atmosphere. For the base case design which
requires approximately 18°K (33°F) of reheat, the reheater heat
duty is estimated at 13.9 MJ/s (47.4 x 106 Btu/hr). A portion
of this heat duty, 0.85 MJ/s (2.9 x 106 Btu/hr), is assumed to
be provided by steam generated in the MgS03 calcining area.
C-6
-------
Thus, the power plant boiler must provide only 13.0 MJ/s (44.5
Btu/hr). At an available steam heat content of 1.75 MJ/kg
(755 Btu/lb), the steam rate to the reheater is 7.44 kg/s
(59,000 Ib/hr).
1.1.5
Fans
To overcome the pressure drop of the flue gas as it
passes, through the MgO FGD process, induced draft fans are lo-
cated downstream of the flue gas reheater. For the base case
design which has a pressure drop of 5.7 kPa (23 in. H20), the
electric power requirements for the fans are estimated to be
5,420 kW.
1.1.6
Slurry Processing
The slurry processing operation receives a slipstream
of the recirculating liquor from the S02 absorbers. This liquor,
which contains MgS03«6H20 solids, is first screened to remove
some of the water and then heated indirectly by steam to convert
the MgS03-6H20 to MgS03'3H20. The resulting slurry is centri-
fuged, with the centrifuge cake being sent to the cake drying
operation while the centrate is returned to the S02 absorbers.
Based on the removal of 2.58 kg/s (10.3 tons/hr) of S02, the
electric power requirements for the slurry processing operation
are estimated at 380 kW. The heat requirements are obtained
from steam produced in the waste heat boiler in the MgS03 cal-
cination operation.
1.1.7
Cake Drying
Included in the cake drying operation are an oil-fired
fluid bed dryer, an air blower, a cyclone, a fabric filter, an
C-7
-------
induced draft fan, conveyors, and a MgS03 storage silo. The
centrifuge cake from slurry processing is thermally dried in
the fluid bed dryer by hot gases produced from the combustion of
fuel oil. The dryer offgases are treated for particulate re-
moval before being discharged to the atmosphere through the
power plant flue gas stack. For treating the MgS03 produced by
removing 2.58 kg/s (10.3 ton/hr) of S02 , the electric power re-
quirements for the cake drying operation are estimated at 410
,k¥. The heat rate for the fluid bed dryer is estimated at
16.0 MJ/s (54.4 x 106 Btu/hr). Based on use of No. 6 fuel oil
with a heating value of 41.5 GJ/m3 (149,000 Btu/gal), the fuel
oil requirements are 0.000384 m3/s (365 gal/hr).
1.1.8
MgS03 Calcining
MgS03 from the cake drying operation is calcined in
an oil-fired fluid bed calciner to produce MgO for recycle to
the S02 scrubbers and S02 for sulfuric acid production. Equip-
ment in the calcining operation include feeders for MgS03 and
coke, conveyor-elevators, an oil-fired fluid bed calciner, a
combustion air blower, a waste heat boiler, a fabric dust
filter and a recycle MgO storage silo. For treating the MgS03
produced by removing 2.58 kg/s (10.3 ton/hr) of S02, the electric
power requirements for the calcining operation are estimated at
380 kW. The heat rate for the fluid bed calciner is estimated
at 17.4 MJ/s (59.6 x 106 Btu/hr). Based on use of No. 6 fuel
oil requirements are 0.000420 m3/s (400 gal/hr). The waste heat
boiler produces the equivalent of 4.23 MJ/s (14.4 x 106 Btu/hr)
of steam. 3.38 MJ/s (11.5 x 106 Btu/hr) of this steam is sent
to the slurry processing operation, while the remaining 0.85
MJ/s (2.9 x 106 Btu/hr) is credited to the flue gas reheater
heat duty.
C-8
-------
1.1.9
Sulfuric Acid Production
The sulfuric acid production operation in the. MgO FGD
process is a conventional contact sulfuric acid plant. Based on
a capacity of about 4.20 kg/s (400 ton/day) of 98 percent sul-
furic acid, the electric power requirements for sulfuric acid
production are estimated to be 1260 kW.
1.1.10
Utilities and Services
The utilities and services required by the. MgO FGD
process are similar to those for the limestone process. For the
base case design, the electric power requirements for utilities
and services are estimated to be 140 kW.
1.1.11
Base Case Summary
The electricity, steam, and fuel oil requirements for
the base case MgO FGD process are summarized in Table C-2.
As before a 500 MW power plant burning 3.5 percent sulfur coal
without any S02 emission controls would require an energy input
of 1.32 GJ/s (4.50 x 109 Btu/hr). Reducing the S02 emissions
from this plant by 90 percent with a MgO FGD system would derate
the power plant by 16 MW. This assumes that all electricity
and steam requirements of the FGD system are obtained from the
power plant. The uncontrolled plant net heat rate is 2640 J/kW-s
(9,000 Btu/kW-hr). Since the net heat rate for the controlled
plant is 2730 J/kW-s (9310 Btu/kW-hr), the energy penalty of the
S02 control system is 90 J/kW-s (310 Btu/kW-hr). However, the
base case MgO process also requires 0.000804 m3/s (765 gal/hr)
of fuel oil. This is equivalent to 33.4 MJ/s (114 x 106 Btu/hr).
Based on the controlled plant capacity of 484,000 kW, the ad-
ditional energy penalty associated with the fuel oil requirements
C-9
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is 70 J/kW-s (240 Btu/kW-hr). Therefore, the overall S02
system penalty is 160 J/kW-s (550 Btu/kW-hr).
control
A percentage breakdown of the energy requirements for
the base case MgO FGD process are show below.
Raw material handling and preparation
Particulate/chloride removal
S02 scrubbing
Reheat
Fans
Slurry processing
Cake drying
MgS03 calcining
Sulfuric acid production
Utilities and services
4%
3%
20%
19%
1%
23%
25%
4%
Particulate/chloride scrubbers, S02 scrubbers, reheaters, and fans
account for almost 50 percent of the MgO system energy require-
ments. The energy requirements for these operations depend es-
sentially only on flue gas flow rate. The S02 recovery operations
slurry processing, cake drying, MgSO3 calcining and sulfuric
acid production - also account for about one-half of the total
system's energy requirements. Since the energy requirements for
these operations are proportional to the amount of S02 removed,
the energy requirements of the MgO system will exhibit a strong
dependence on the amount of S02 removed.
1.2
Base Case Extrapolations - MgO FGD Process
The electricity, fuel oil, and steam requirements for
the three control cases which use the MgO FGD process can be
extrapolated from the base case data. The electric power and
C-ll
-------
fuel oil requirements for the raw material handling and prepara-
tion, slurry processing, cake drying, MgSO3 calcining, and sul-
furic acid production operations are proportional to the amount
of SO2 removed. The electric power and steam requirements for
particulate/chloride removal, the reheaters and utilities and
services can be related to the amount of flue gas exiting the
power plant air preheater. The following extrapolation factors
were identified for these eight segments of the MgO FGD process.
Raw material handling
and preparation
Particulate/chloride
removal
Reheat
Slurry processing
Cake drying
MgSOs calcining
Sulfuric acid production-
Utilities and services
68.0 kW/(kg S02 rem./s)
2.34 kW/(Nm3/s)
28.1 kJ/Nm3
146 kW/(kg SO2 rem./s)
157 kW/(kg SO2 rem./s)
0.000149 m3 oil/(kg S02 rem./s)
145 kW/(kg S02 rem./s)
0.000162 m3 oil/(kg S02 rem./s)
473 kW/(kg S02 rem./s)
0.310 kW/(Nm3/s)
The electric power requirements for the S02 scrubbers
and the I.D. fans are dependent on the S02 concentration in the
flue gas and the desired S02 removal level. The energy require-
ments for these two operations in the three control cases which
use the MgO FGD process are described below.
1.2.1
S02 Scrubbing
The coal sulfur contents and desired S02 control levels
for the three control cases which utilize the MgO process are:
C-12
-------
Coal Sulfur Content
3.5%
3.5% - base case
7.0%
S02 Control Level
0.52 g S02/MJ of heat input
90% S02 removal
90% SO2 removal
For the first control case listed above, a venturi scrubber with
a gas phase pressure of 0.75 kPa (3 in. H20) (KO-174) and an
L/G of 2.7 m3/1000 m3 (20 gal/1000 acf) was selected. The elec-
tric power requirements for this scrubber used in a 500 MW power
plant are estimated to be 910 kW. The second control case is
the base case and as mentioned previously, the electric power
requirements for S02 scrubbing are also established at 910 kW.
To remove 90 percent of the S02 produced by combustion
of a 7.0 percent sulfur coal requires two contacting stages
(SA-311). Therefore, for this case, a spray tower system
integral to a venturi scrubber was selected as the S02 absorber.
The spray system and venturi each operate at an L/G of 2.7
m3/1000 m3 (20 gal/1000 acf) and have a total pressure drop of
1.6 kPa (6.5 in. H20). For this S02 absorber used in a 500 MW
power plant the electric power requirements for S02 scrubbing
are estimated to be 1820 kW.
1.2.2
Fans
The equation for calculating the power requirements
for induced draft fans is given in Equation 1-5 in Appendix A.
The pressure drops for use in this equation are shown, below for
the three control cases which use the MgO process.
C-13
-------
Coal
3.5% sulfur
3.5% sulfur
7.0% sulfur
S02 Control Level
0.52 g S02/MJ of heat input
90% removal
90% removal
A'P kPa (in. H?0)
6.22 (25)
5.73 (23)
5.35 (21.5)
C-14
-------
APPENDIX D
WELLMAN-LORD/ALLIED FGD PROCESS
-------
1.0
WELLMAN-LORD/ALLIED FGD PROCESS
The Wellman-Lord/Allied (W-L/A) flue gas desulfuriza-
tion process is an aqueous, regenerable S02 control process.
A solution of sodium sulfite is used to absorb S02 from the flue
gas. The scrubbing liquor is thermally regenerated to produce
an S02 stream which is then converted into elemental sulfur.
Figure D-l is a simplified flow scheme of the W-L/A process
selected for examination in this study.
Flue gas from the power plant air preheater enters a
variable throat venturi scrubber. A fly ash slurry is injected
into this venturi to remove particulates and chlorides. The
flue gas next enters a three-plate valve-tray absorber. S02 is
absorbed by a soultion of sodium sulfite which is recirculated
over each plate. The overall chemistry of the S02 absorption
step can be represented by the following reaction:
Na2S03 + H20
S0
2NaHS0
(1-1)
The desulfurized flue gas is heated in an indirect steam reheater
and compressed in an induced draft fan prior to entering the
power plant stack for discharge to the atmosphere.
A portion of the recirculating S02 scrubbing solution
is continuously removed and directed to the regeneration facili-
ties. Here, the solution is cooled to crystallize any Na2SO,t
formed by oxidation of sulfite in the absorber. The NA2S0lf is
then separated, dried and recovered as a solid by-product. The
liquid separated from the Na2S01( is sent to an evaporator/
crystallizer wherein the reverse of Reaction 1-1 takes place.
The S02 liberated serves as the feed to the Allied Chemical sul-
fur recovery process. A solution of soda ash and antioxidant
D-2
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are prepared on-site, mixed with the Na2S03 crystals recovered
from the evaporator/crystallizer and recycled to the S02
absorbers.
1.1
Base Case - Wellman-Lord/Allied FGD Process
Material and energy balances were calculated for the
base case W-L/A FGD process--90 percent removal of the S02 from
the flue gas from a 500 MW power plant burning a 3.5 percent
sulfur coal. The information used in preparing the material
balance (see Table D-l) and in calculating energy requirements
was obtained from the open literature (MC-136).
There are eight general process operations within
the W-L/A FGD process.
Raw material handling and feed preparation
• Particulate/chloride removal
SO2 scrubbing
Reheat
Fans
Purge treatment
SO2 regeneration
SO2 reduction
1.1.1 Raw Material Handling and Preparation
Included in the raw material handling and feed pre-
paration operation are equipment for receiving and storing soda
ash and antioxidant, and producing a mixture of these chemi-
cals for use as makeup reagent to the S02 absorbers. Based on
handling 0.344 kg/s (2650 Ib/hr) of soda ash (99.8% Na2C03)
and 5.71 g/s (45.3 Ib/hr) of antioxidant, the electric power
requirements are estimated to be 60 kW.
D-4
-------
TABLE D-l.
BASE CASE MATERIAL BALANCE--
WELLMAN-LORD/ALLIED FGD PROCESS
Stream
Stream No. Description
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Coal to Boiler
Combustion Air to
Boiler
Gas to Air
Preheater
Gas to Particulate
Scrubber
Gas to SO 2
Scrubber
Gas to Reheat er
Steam to Reheater,
Gas to I.D. Fan
Gas to Atmosphere
Slurry to Particulate
Scrubber
Liquor to Purge
Treatment
Liquor to Evaporator/
Crystallizer
Natural Gas
Elemental Sulfur
Reduction Unit
Tail Gas
Dryer Off Gas
Rate
kg/s NmVs m3/s
47.3
570 430
555 421
611 464
664 522
662 518
7.57
662 518
662 518
1231 1.20
11.7 0.009
19.7 0.015
0.42 0.50
1.18
2.98 2.43
23.7 18.2
Temperature, °K
317
647
428
326
326
517
346
353
367
950
383
D-5
-------
1.1.2
garticulate/Chloride Removal
Included in the particulate/chloride removal operation
are variable throat venturi, scrubbers, effluent hold tanks and
recirculating slurry, makeup water and slurry disposal pumps.
The venturi scrubbers operate at a gas phase pressure drop of 2.1
kPa (8.5 in H20) and an overall liquid to gas ratio (based on
exit flue gas conditions) of 2 m3/10003m (15 gal/1000 acf).
For the base case design, the electric power requirements for
the particulate scrubbing operation are estimated to be 1020 kW.
1.1.3
S02 Scrubbing
Included in the S02 scrubbing operation are three-
plate valve tray absorbers and scrubbing solution reciruclation
pumps for each absorber plate. The absorbers operate at a
pressure drop of 2.5 kPa (10 in. H20) and, based on exit flue
gas conditions, a liquid to gas ratio for each plate of 0.4 m3/
1000 m3 (3 gal/1000 acf). For the base case design, the electric
power requirements for S02 scrubbing are estimated to be 320 kW.
1.1.4
Reheat
As for the other FGD processes, indirect steam re-
heaters are used to heat the scrubbed flue gas prior to discharge
to the.,atmosphere. For the base case design which requires
.approximately 20°K (36°F) of reheat, the rcheater heat duty is
estimated at 13.3 MJ/s (45.3 x 106 Btu/hr). At an available
steam heat content of 1.75 MJ/kg (755 Btu/lb), the steam rate
to the reheater is 7.57 kg/s (60,000 Ib/hr).
D-6
-------
1.1.5
Fans
To overcome the pressure drop of the flue gas as it
passes through the W-L/A FGD process, induced draft fans are
located downstream of the flue gas reheater. For the base case,
design which has a pressure drop of 6.6 kPa (26 in. H20), the
electric power requirements for the fans are estimated to be
6200 kW.
1.1.6
Purge Treatment
The purge treatment operation is designed to take a
slipstream of the S02 absorber effluent and treat it for removal
of sodium sulfate. The following equipment items are required:
Ethylene glycol refrigeration, system
Chiller/ crystallizer tank with agitator
Feed cooler
Centrifuge
Conveyors'
Pump s
Rotary dryer
Fabric dust filter
Induced draft fan
The purge stream is first cooled in the feed cooler and sent to
the cooler/crystallizer. Na2S04 solids formed upon cooling are
next separated in a centrifuge. The centrate is directed to the
SO 2 regeneration operation while the solids are dried in a
rotary dryer by air heated by an indirect stream/ air heater.
The dryer off-gases are treated for removal of entrained NazSO^
and then combined with the flue gas stream exiting the power
plant preheater. The sodium sulfate by-product is sent to
storage.
D-7
-------
For the base case design in which 2.58 kg/s (10.3 ton/hr)
of S02 are removed from the flue gas, the electric power require-
ments for purge treatment are estimated to be 930 kW. The heat
duty for the steam/air heater is 4.51 MJ/s (15.4 x 106 Btu/hr).
However, 2.66 MJ/s (9.07 x 106 Btu/hr) of this is assumed to be
provided by steam produced in the S02 reduction operation. The
heat duty that must be obtained from the power plant boiler is
therefore 1.85 MJ/s (6.33 x 106 Btu/hr). At an available steam
heat content of 1.75 MJ/kg (755 Btu/lb), the steam requirements
are 1.06 kg/s (8380 Ib/hr).
1.1.7
SO2 Regeneration
The SO2 regeneration operation includes evaporator/
crystallizers, pumps, condensers, condensate strippers, com-
pressors and dissolving tanks. The evaporator/crystallizers
produce an overhead stream of S02 and H20 and a concentrated
slurry of NaaSOi*. The H20 is removed from the overhead stream
by cooling in water-cooled condensers. The condensate is mixed
with the concentrated NasSCK slurry, makeup soda ash and anti-
oxidant and recycled to the S02 absorbers. The S02 is compressed
and directed to the S02 reduction operation.
Based on removing 2.58 kg/s (10.3 ton/hr) of S02, the
electric power requirements for S02 regeneration are estimated
at 1670 kW. The heat requirements are estimated at 79.1 MJ/s
271 x 106 Btu/hr). Based on steam available from the power
plant boiler with a useful heat content of 1.75 MJ/kg (755 Btu/lb),
the steam requirements are estimated at 45.3 kg/s (359,000 Ib/hr).
D-8
-------
1.1.8
SOZ Reduction
The S02 reduction operation includes a complete unit
for the reduction of S02 to elemental sulfur. The reduction oper-
ation is based on a proprietary process developed by Allied
Chemical. The heart of the process is the catalytic reduction
of a major portion of the S02 to elemental sulfur and smaller
amounts of H2S. The reductant is usually natural gas, although
the use of reducing gases containing CO arid H2 such as are avail-
able from refineries or the gasification of coal have been tested
The two predominate reduction reactions are
2S02
3S02
2CH
.C02 4- 2H20 + 2S
-*• 2C02 + 2H20 + 2H2S
(1-2)
(1-3)
The H2S produced from Reaction 1-3 and unreacted S02
are then converted to sulfur in a series of converter-condensers.
2H2S + S02 -*• 2H20
3S
(1-4)
Since the three sulfur forming reactions are exothermic, a
significant amount of useful energy is recovered in waste heat
boilers.
Based on removing 2.58 kg/s (10.3 ton/hr) of S02, the
electric power and natural gas requirements of the S02 reduction
operation are estimated to be 320 kW and 0.573 m3/s (72,800 scfh),
respectively. This operation produces a steam heat credit of
3.46 MJ/s (11.8 x 106 Btu/hr) of which 0.804 MJ/s (2.73 x 106
Btu/hr) is used within the area for maintaining the by-product
sulfur in a liquid state while in storage. The remaining
2.66 MJ/s (9.07 x 106 Btu/hr) are credited to the purge treat-
ment operation.
D-9
-------
1.1.9
Utilities and Services
The utilities and services required by the W-L/A FGD
process are similar to those for other FGD processes. For the
base case design, the electric power requirements for utilities
and services are estimated to be 70 kW.
1.1.10 Base Case Summary
The electricity, steam and natural gas requirements
for the base case W-L/A FGD process are summarized in Table D-2
As before, a 500 MW power plant burning a 3.5 percent sulfur
coal without any S02 emission controls would require an energy
input of 1.32 GJ/s (4.50 x 10* Btu/hr). Reducing the S02
emissions by 90 percent with a W-L/A FGD system would derate
the power plant by 51 MW. This assumes that the electricity
and steam requirements of the control system are obtained from
the power plant. The uncontrolled plant net heat rate is 2640
J/kW-s (9000 Btu/kW-hr). Since the net heat rate for the
controlled plant is 2940 J/kW-s (10,000 Btu/kW-hr), the energy
penalty of the S02 control system is estimated at 300 J/kW-s
(1080 Btu/kW-hr).
The natural gas requirements of the control system are
0.573 mVs (72,800 scfh). This is equal to 22.4 MJ/s (76 x 106
Btu/hr) based on a natural gas energy content of 39.1 MJ m3
(1050 Btu/scf). Since the controlled power plant capacity is
449,000 kW, the additional energy penalty associated with the
natural gas requirements is 50 J/kW-s (170 Btu/kW-hr). There-
fore, the overall S02 control system penalty is 350 J/kW-s
(1190 Btu/kW-hr).
D-10
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A percentage breakdown of the energy requirements
for the W-L/A FGD process are shown below.
2%
1%
10%
10%
3%
60%
15%
Raw material handling and preparation -
Particulate/chloride removal
SO2 scrubbing
Reheat
Fans
Purge treatment
SO2 regeneration
SO2 reduction
Utilities and Services
The S02 recovery operations—purge treatment, S02 regeneration and
SO2 reduction-- account for about 80 percent of the total energy
requirements for the W-L/A process. Since the energy require-
ments for these operations are proportional to the amount of S02
removed from the flue gas, the energy requirements of the whole
process will also be a strong function of the amount of S02
removed.
1.2
Base Case Extrapolations - W-L/A FGD Process
The electricity,. natural.gas and steam requirements
for the three control cases which use the W-L/A FGD process can
be extrapolated from the base case data. For the raw material
handling and preparation, purge treatment, S02 regeneration and
SO2 reduction operations, the energy requirements are propor-
tional to the amount of S02 removed. For the particulate/chloride
scrubbers, reheaters and utilities and services, the electric
power and steam requirements can be related to the flue gas
flow rate exiting the power plant air preheater. The following
extrapolation factors were identified for these seven segments
of the W-L/A FGD process operations:
D-12
-------
Raw material handling and
preparation
Particulate/chloride
removal
Reheat
Purge treatment
SO2 regeneration
SO2 reduction
Utilities and services
-24.8 k¥/(kg SO2 rem./s)
-2.20 kJ/(Nm3/s)
-28.6 kJ/(Nm3)
- 359 kW/(kg S02 rem./s)
717 kJ/(kg S02 rem./s)
- 646 kW/(kg S02 rem./s)
306 MJ/(kg SO2 rem./s)
- 114 kW/(kg SO2 rem./s)
0.221 m3CHif/(kg S02 rem./s)
0.15 kW/(Nm3/s)
The L/G's and pressure drops for the S02 absorbers
are dependent on the flue gas S02 concentrations and
the desired S02 removal level. However, in a sodium based
scrubbing system like the W-L/A process, S02 removal is only
minimally dependent on L/G and pressure drop. Therefore, the
base case L/G and system pressure drop were used for the three
control cases which use the W-L/A process. The electric power
requirements for the S02 scrubber and fans are then proportional
to the flue gas flow rate and the following extrapolation factors
were used:
SO2 Scrubbing - 0.69 k¥/(Nm3/s)
Fans - 13.4 k¥/(Nm3/s)
D-13
-------
APPENDIX E
DOUBLE-ALKALI FGD PROCESS
-------
1.0
DOUBLE-ALKALI FGD PROCESS
The double-alkali (D-A) flue gas desulfurization
process is essentially a hybrid process. The S02 absorption
step utilizes a sodium based scrubbing liquor similar to that
used in the Wellman-Lord/Allied process. Unlike the W-L/A
process which recovers elemental sulfur, the D-A process is a
nonregenerable process since the absorbed S02 is disposed of as
a calcium based sludge. This portion of the D-A process is
similar to the lime FGD process. Figure E-l is a simplified
flow scheme of the D-A FGD process selected for examination
in this study.
Flue gas from the power plant air preheater first
enters a variable throat venturi scrubber, A fly ash slurry is
injected into this venturi to remove particulates and chlorides.
The flue gas next enters a mobile bed absorber where the S02 is
absorbed by a recirculating solution of sodium sulfite. The
overall chemistry of the S02 absorption step can be represented
by the following reaction.
NA2S03 + S02+H20
2NaHS0
(1-D
The scrubbed flue gas is heated in an indirect steam reheater
and compressed in an induced draft fan prior to entering the
power plant stack for discharge to the atmosphere.
The S02 absorber effluent is reacted with lime slurry,
causing calcium sulfite/sulfate to precipitate. A portion of
the lime treated liquor is directed to a clarifier where soda
ash is added to reduce the amount of dissolved calcium in the
liquor and provide the necessary makeup of sodium ions. Calcium
solids are removed from the clarifier, and sent to a lined pond
for disposal, while the clarifier overflow is returned to the
SO2 absorbers.
E-2
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-------
1.1
Base Case - D-A FGD Process
Material and energy balances were calculated for the
base case D-A FGD process-- 90 percent removal of the S02 from
the flue gas from a 500 MW power plant burning a 3.5 percent
sulfur coal. The material balance for the base case D-A process
is given in Table E-l.
There are six general process operations in the D-A
FGD process:
Raw material handling and preparation,
Particulate/chloride removal,
SO2 scrubbing,
Reheat,
Fans, and
Calcium solids disposal.
1.1.1
Raw Material Handling and Preparation
The raw material handling and feed preparation opera-
tion includes equipment for receiving and storing soda ash and
pebble lime, and producing lime slurry and a solution of soda
ash. The lime slurry is used to precipitate calcium sulfite
and calcium sulfate from the S02 scrubbing liquor. The solution
of soda ash serves the dual purpose of softening the treated
SO2 scrubbing liquor and providing the required sodium ion
makeup. Based on handling 0.214 kg/s (1700 Ib/hr) of soda
ash (99.8 percent Na2C03) and 2.26 kg/s (17,900 Ib/hr) of lime
(95 percent CaO), the electric power requirements for this opera-
tion are estimated to be 100 kW (MC-136). The soda ash requirements
were calculated by assuming 0.05 mole of makeup soda ash were
required per mole of S02 removed, while the lime makeup was
based on stoichiometric requirements (KA-227).
E-4
-------
TABLE E-l. BASE CASE MATERIAL BALANCE--DOUBLE-ALKALI FGD PROCESS
Stream No.
1
2
3
4
5
6
7
8
9
10
11
12
13
Stream
Description
Coal to Boiler
Combustion Air to
Boiler
Gas to Air
Preheater
Gas to Particulate
Scrubber
Gas to SO 2
Absorber
Gas to Reheat'er
Steam to Reheat er
Gas to I.D. Fan
Gas to Atmosphere
Slurry to
Particulate
Scrubbing
Slurry to S02
Absorber
Makeup Lime
Makeup Soda Ash
Rate
kg/s Nm3/s mVs
47.3
570 430
555 421 •
611. 464
635 500
637 518
8.88
637 518
637 518
1231 1.2
1568 1.2
2.9
0.21
Temperature, °K
317
647
428
326
325
517
346
"353
E-5
-------
1.1.2
Particulate/Chloride Removal
The venturi scrubbers used for control of particulates
and chlorides in the D-A FGD process are essentially identical
to the venturi scrubbers used in the MgO process. Based on an
L/G of 2 m3/1000 m3 (15 gal/1000 acf), the electric power re-
quirements for particulate scrubbing are estimated to be 1090 kW
(MC-136).
1.1.3
SO2 Scrubbing
Included in the S02 scrubbing operation are mobile bed
absorbers, scrubbing liquor hold tanks and liquor recirculation
pumps. The S02 absorbers operate at an L/G of 2 m3/1000 m3
(15 gal/1000 scf) and a pressure drop of 2.1 kPa (8.5 in. H20).
For the base case design, the electric power requirements for
S02-scrubbing are estimated to be 860 kW (MC-136).
1.1.4
Reheat
As for the other FGD processes, indirect steam reheat-
ers are used to heat the scrubbed flue gas prior to discharge
to the atmosphere. For the base case design which requires
approximately 21°K (38°F) of reheat, the reheater heat duty is
estimated at 15.6 MJ/s (53.2 x 106 Btu/hr). At an available
steam heat content of 1.75 MJ/kg (755 Btu/lb), the steam rate
to the reheater is estimated at 8.88 kg/s (70,400 Ib/hr) (rC-136)
1.1.5
Fans
To overcome the pressure drop of the flue gas as it
passes through the D-A FGD process, induced draft fans are
located downstream of the flue gas reheater. For the base case
design which has a system pressure drop of 5.7 kPa (23 in. H20),
the electric power requirements for the fans are estimated to
be 5510 kW (MC-136).
E-6
-------
1.1.6
Calcium Solids Disposal
SO2 absorber effluent which has been treated with
lime slurry is sent to clarifiers for softening with a solution
of soda ash. The CaC03 solids formed here and the CaS03 and
CaSOit solids formed by the lime treatment are removed from the
bottom of the clarifier and directed to centrifuges. The solids
from the centrifuges are washed with water and then combined
with the effluent from the particulate scrubbers for disposal
in a lined settling pond. Pond water is recycled to the raw
material handling and feed preparation operation. The clarifier
overflow and centrifuge wash are recycled to the S02 absorbers.
Based on handling the solids formed by removing 2.58 kg/s
(10.3 ton/hr) of S02, the electric power requirements for cal-
cium solids disposal are estimated at 250 kW (MC-136).
1.1.7
Utilities and Services
The utilities and services required by the double-
alkali FGD process are similar to those for the limestone pro-
cess. For the base case design, the electric power requirements
for utilities and services are estimated to be 60 kW (MC-136).
1.1.8
Base Case Summary
The electricity and steam requirements for the base
case D-A FGD process are summarized in Table E-2. As before,
a 500 MW power plant burning 3.5 percent sulfur coal without
any S02 emission controls would require an energy input of 1.32
GJ/s (4.50 x 109 Btu/hr). Reducing the S02 emissions from this
plant by 90 percent with a D-A FGD system would derate the
power plant by 15 MW. This assumes that all energy needs of
the FGD system are obtained from the power plant. The
E-7
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-------
uncontrolled plant net heat rate is 2640 J/kW-s (9000 Btu/kW-hr)
Since the net heat rate for the controlled plant is ,2720 J/kW-s
(9280 Btu/kW-hr), the energy penalty of the SO2 control system
is 80 J/kW-s (280 Btu/kW-hr).
A percentage breakdown of the energy requirements for
the base case D-A FGD process are shown below.
Raw material handling and preparation -
Particulate/chloride removal
SO 2 scrubbing
Reheat
Fans
Calcium solids disposal
Utilities and services
Particulate/chloride scrubbers, reheaters, and fans account for
over 90 percent of the D-A system energy requirements. The en-
ergy requirements for these areas depend essentially only on the
flue gas flow rate. Therefore, the energy requirements for the
D-A process will depend very little on inlet flue gas S02 con-
centration or SO2 removal level.
7%
6%
46%
38%
2%
1.2
Base Case Extrapolations
The electricity and steam requirements for the three
control cases which use the D-A FGD process can be extrapolated
from the base case data. The electric power requirements for the
raw material handling and preparation, and calcium solids disposal
operations are proportional to the amount of S02 removed. For the
particulate/chloride scrubbers, reheaters, and utilities and ser-
vices, the electric power and steam requirements can be related
to the flue gas flow rate exiting the power plant air preheater.
E-9
-------
The following extrapolation factors were identified for these
five segments of the D-A FGD process:
Raw material handling and
preparation
Particulate/chloride
removal
Reheat
Calcium solids disposal
Utilities and services
38.8 k¥/(kg S02 rem./s)
2.34 kW/(Nm3/s)
33.5 kJ/Nm3
95.6 kW/(kg S02 rem./s)
0.14 kW/(Nm3/s)
While the L/G and pressure drop required by the SOz
absorbers are dependent on the flue gas SOz concentration and
the desired S02 removal level, this dependence in a sodium-based
scrubbing system like the double-alkali pricess is minimal.
Therefore, the base case L/G and system pressure drop were used
for the three control cases which use the D-A process. The
electric power requirements for the S02 scrubbing and fans areas
are then proportional to the flue gas flow rate and the following
extrapolation factors were used:
SO2 scrubbing
Fans
- 1.84 kW/(Nm3/s)
- 11.9 kW/(Nm3/s)
E-10
-------
APPENDIX F
PHYSICAL COAL CLEANING
-------
1.0
PHYSICAL COAL CLEANING
Physical coal cleaning processes remove impurities from
coal via a mechanical separation process. In most cleaning oper-
ations, this separation of impurities is based on a gravity dif-
ference between coal (which is relatively light) and contaminants
such as pyrite (FeS2), ash, and rock (which are heavier) (WE-003) ,
Historically, ash and rock removal were the primary objectives
of coal cleaning. However, the need for reducing sulfur dioxide
emissions has recently focused more attention on the sulfur re-
moval aspects of physical coal cleaning.
Sulfur occurs in a coal seam in three basic forms:
pyritic, organic, and sulfate. In any given coal the amount of
sulfate sulfur is negligible. Physical coal cleaning is re-
stricted to removal of the pyritic sulfur from coal. This is
due to the fact that the organic sulfur in coal is chemically
bound and requires a chemical extraction process for removal.
The effectiveness of a physical coal cleaning process
in removing sulfur from coal is both coal and process specific
(DE-064). Data' related to the ability to physically clean the
3.5 and 7,0 percent sulfur coals examined in this study were
not available. Therefore, it was necessary to select a gener-
alized coal cleaning plant. Figure F-l is a simplified flow
scheme of a physical coal cleaning facility depicting common
process areas (LO-071, CO-380). The coal cleaning plant repre-
sented by this flow scheme was selected for this study.
The following four process areas are present in the
coal cleaning facilities shown in Figure F-l. Listed under
each area are various operations which may be utilized in an
individual cleaning process.
F-2
-------
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1.1
Initial Coal Preparation
1) Storage
2) Rough Cleaning/Primary Breaking
3) Raw Coal Sizing
Fine Coal Processing
1) Wet Cleaning
2) Desliming
Coarse Coal Processing
Water Management/Refuse Disposal
1) Dewatering
2) Drying
3) Water Recovery
4) Refuse Disposal
Initial Coal Preparation
Prior to the actual cleaning process, run-of-mine
(R.O.M.) coal must undergo initial preparation. This involves
preliminary crushing of the coal to remove large rock fractions
and to liberate entrained impurities such as clay, rock, and
other inorganic materials including pyrite. The first crushing
step is followed by a screening operation,, secondary crushing,
and a second screening step which produces two coal streams;
one containing a fine fraction (usually less than 6.5 mm) and
the other containing coarse particles (nominally 76 x 6.5 mm).
These two coal streams are then fed to their respective process
areas where the actual cleaning operation takes place (CO-380,
LO-071).
F-4
-------
1.2
Fine Coal Processing'
The process feed stream of less than 6,5 mm ooal is
slurried with water as it enters the fine coal processing area.
This slurry is then subjected to a desliming operation which
removes a suspension containing approximately 50 percent of
minus 200 mesh material (FI-102) .
After desliming, the oversize coal fraction (greater
than 28 mesh) is pumped to the fine coal cleaning process.
Here, fine coal particles undergo gravity separation in one of
several wet cleaning devices. This removes a percentage of the
ash and pyritic sulfur to produce a clean coal product. The
product stream from this operation is then fed to the drying
area of the plant and refuse material is further processed in
the water treatment section.
The slimes removed from the fine coal are fed to a
froth flotation process. Upon entering the flotation process
area, the slime suspension is treated with a frothing agent
which selectively floats coal particles in the flotation mach-
ines while allowing pyrite and ash impurities to settle. The
float product is then sent to the dewatering area while reject
material is processed in the water treatment and recovery area.
1.3
Coarse Coal Processing
Feed to the coarse coal processing area of the plant
consists of oversize material (76 x 6.5 mm particles) from the
initial preparation area. This feed stream is slurried with
water prior to cleaning in one of the many types of process
equipment currently employed in coarse coal cleaning. Here,
impurities are separated from the coal using differences in
F-5
-------
coal and reject densities. It is also common practice to re-
move a middling fraction from the separation operation and fur-
ther process it by means of recycle or by feed to another
cleaning process. These cleaning operations result in two
streams being removed from the coarse coal processing area: a
product and reject stream. After the coarse cleaning operation,
the product stream is pumped to the dewatcsring and drying area
of the plant while the reject stream is processed in the water
treatment and recovery area.
1.4
Water Management/Refuse Disposal
Dewatering and drying equipment handle the product
flows from both the fine and coarse coal preparation areas.
Typically, cleaning plants employ mechanical dewatering oper-
ations to separate coal slurries into a low-moisture solid and
a clarified supernatant. The solid coal sludge produced in the
dewatering step can then be mechanically or thermally dried to
further reduce the moisture while the supernatant from the de-
watering process is returned to the plant's water circulation
system.
The water treatment and recovery section of a cleaning
plant processes refuse slurries containing both coarse material
and reject slimes. Here, the refuse slurry is dewatered in
thickeners and settling ponds. The supernatant from this oper-
ation is returned for reuse in the plant while the refuse is
buried and revegetated to prevent spontaneous ignition.
The coal product from the dewatering and drying area
of the plant can be further processed. This may involve crush-
ing and screening operations to separate the product into vari-
ous product sizes.
F-6
-------
1.5
Physical' CcTaT 'Cleaning Design Premises
As mentioned previously, the design of a physical
coal cleaning plant is dependent on the properties of the coal
to be cleaned. However, physical coal cleaning data were not
available for the 3.5 and 7.0 percent sulfur coals considered
in this study. In order to develop energy requirements for
the coal cleaning plant, several assumptions had to be made.
These assumptions are discussed in the following paragraphs.
To achieve sulfur removal levels of about 40 percent
would require a fairly sophisticated cleaning plant. In general,
as a cleaning plant becomes more sophisticated or complex, its
energy recovery efficiency also increases. Therefore, a 95
percent energy recovery--95 percent of the input coal energy
was recovered 'in the clean coal product—was used (RO-325) .
Other assumptions used in calculating the energy re-
quirements of a coal cleaning plant were (CH-307):
(1) The electric power requirements for a
278 kg/s (500 ton/hr) cleaning plant
are 2980 kW.
(2) The heat duty of a thermal dryer is
534 kJ/kg (230 Btu/lb) of coal dried.
(3) One half of the clean coal product
(the coal fines) is thermally dried.
(4) Heat for the thermal dryers is supplied
by burning a portion of the clean coal
product.
F-7
-------
(5) 50% of the ash content of the coal
is removed.
(6) The average heating value of the
clean coal is 29.2 MJ/kg (12,500 Btu/lb).
Based on ;these assumptions, the estimated compositions of the
physically cleaned 3.5 and 7.0 percent sulfur coals are as
shown in Table F-l. The energy requirements and throughput for
physical coal cleaning plants supplying coal to 500 MW and 25 MW
power plants are summarized in Table F-2.
When assessing the energy penalty of the coal, cleaning
process, the electricity requirements are assumed to be obtained
from the power plant and are reflected in the power plant's net
heat rate. The penalty associated with the coal lost and used
in the cleaning process are debited to the control system by re-
quiring an increase in the coal feed rate to the cleaning plant.
TABLE F-l. COMPOSITIONS OF PHYSICALLY CLEANED COALS
Physically cleaned
3.5% sulfur coal
Physically cleaned
7.0% sulfur coal
MAF Coal. wt. %
Ash, wt. %
H20, wt. %
Sulfur, wt. %
Heating Value, MJ/kg
87.1
6.6
6.3
2.2
29.2
87.1
6.6
6.3
4..4
29.2
F-8
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APPENDIX G
COAL TRANSPORTATION
-------
1.0
GOAL TRANSPORTATION
Unit trains are the major method used to transport
coal over long distances. Unit trains are railroad systems
dedicated solely to the movement of coal from a coal mine or
coal preparation plant to an end user. For this study, unit
trains are used to transport western coal from a mine in the
Four Corners area of New Mexico to a power plant in Ohio. The
total one-way train distance between these two points is assumed
to be 2,100 km (1,300 miles). The following assumptions were
used in calculating the energy requirements of a unit train:
1) Each unit train consists of 100 coal cars
with a coal capacity of 91,000 kg (100 ton)
(WH-101).
2) Each unit train uses 5 locomotives rated at
2,700 k¥ (3,600 HP) with the following diesel
fuel oil consumption (WH-101, RA-215):
At full power:
At reduced power:
0.00022 m3/s (200 gal/hr)
per locomotive
0.000029 m3/s (28 gal/hr)
per locomotive
3) Four hours each are required for loading and
unloading while the train moves at reduced
power (BU-116, RA-215).
4) One hour is required for passing a large city
and for undergoing each federal inspection,
while the train moves at reduced power (BU-116,
RA-215).
G-2
-------
5) One large city every 180 km (110 miles)
and one federal inspection every 800 km
(500 miles).
6) Average train speed in open country is
48 km/hr (30 mph) when loaded and 96 km/hr
(60 mph) when empty (SO-138)..
7) One percent of the total train load is
lost as coal dust blow-off which occurs
primarily during loading and unloading
(CO-129).
8) Diesel fuel oil has a heating value of
38.4 GJ/m3 (138,000 Btu/gal).
Table G-l shows how these assumptions were used to calculate the
energy required to transport low sulfur western coal to a Midwest
power plant. The energy penalties for the control systems which
examine transporting low sulfur western coal are given in Table
G-2.
G-3
-------
TABLE G-l. CALCULATION OF ENERGY REQUIREMENTS
FOR TRANSPORTING WESTERN COAL
Basis: One round trip unit train delivery
# of hours at reduced power:
Passing large cities (24) - 24
Undergoing federal - 4
inspection (4)
Loading - 4
Unloading - 4
Total - 36 hrs.
# of hours at full power:
En route to power plant - 43
Return to mine - 22
Total - 65
TOTAL duration of trip - 101 hrs.
Fuel Consumption:
@ reduced power
@ full power
Total
Average
734 GJ
9,460 GJ
10,190 GJ
28.0 MJ/s
Windage Losses, Total -
Average -
90,800 kg
0.25 kg/s
Coal Transported, MJ/kg coal
Average Fuel Consumption, MJ/s
Average Windage Losses, MJ/s
Total average Energy Consumed or Lost, MJ/s
Total average Energy Consumed or Lost, MJ/kg coal
J?.P_r
- 28.
- 5.
- 33.
- 1.
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25.6
28.0
6.4
34.4
1.38
G-4
-------
TABLE G-2. ENERGY PENALTY -- COAL TRANSPORTATION
Coal
Power Plant Size
MW
Coal Rate
kg/s
Transportation
Energy Penalty
MJ/s J/kW-s
0.4% Sulfur; 20.9 MJ/kg
0.4% Sulfur; 20.9 MJ/kg
0.6% Sulfur; 25.6 MJ/kg
0.6% Sulfur; 25.6 MJ/kg
25
500
25
500
3.26
63.0
2.66
51.6
4.3
84
3.7
71
170
170
150
140
G-5
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
4. TITLE AND SUBTITLE
The Energy Requirements fen
from Coal-Fired Steam/Elecl
7. AUTHOR(S)
W. C. Thomas
9. PERFORMING ORGANIZATION NAME AN
Radian Corporation
P. 0. Box 9948
Austin, Texas 78766
2.
c Controlling S02 Emissions
trie Generators
?<
D ADDRESS
12. SPONSORING AGENCY NAME AND ADDRESS
Environmental Protection Agency
Office of Air Quality Planning and Standards (MD-13)
Research Triangle Park, North Carolina 27711
3. RECIPIENT'S ACCESSION-NO.
5. REPORT DATE
January, 1978
6. PERFORMING ORGANIZATION CODE
8. PERFORMING ORGANIZATION REPORT NO.
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-02-2608
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES ~~ —
The _ report is an .analysis of the energy required by various methods of reducing
sulfur dioxide emissions from coal-fired boilers. The energy required for limestone,
lime double alkali, magnesium slurry and Wellman-Lord/Alied flue gas scrubbing
systems is presented. The variation of energy requirements with coal sulfur content,
emission level achieved and plant size is presented. The energy required to
transport low sulfur coal to the mid-west or to physically clean sulfur from the
coal is presented also.
|17. KEY WORDS AND DOCUMENT ANALYSIS
[a. DESCRIPTORS
18. DISTRIBUTION STATEMENT
Release Unlimited
b. IDENTIFIERS/OPEN ENDED TERMS
19. SECURITY CLASS (This Report)'
Unclassified
20. SECURITY CLASS (This page)
Unclassified
c. COSATI Field/Group
21. NO. OF PAGES
124
22. PRICE
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