United States Industrial Environmental Research
Environmental Protection Laboratory
Agency Research Triangle Park NC 27711
tprbents and Fabri
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Interagency
Energy/Environment
R&D Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
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The nine series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
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RESEARCH AND DEVELOPMENT series. Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program. These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
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essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
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This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-79-005
January 1979
Evaluation of Dry Sorbents
and Fabric Filtration for FGD
by
S.J. Lutz, B.C. Christman, B.C. McCoy,
S.W. Mulligan, and K.M. Slimak
TRW, Inc.
Northwestern Bank Building. Suite 200
201 North Roxboro Street
Durham, North Carolina 27701
Contract No. 68-02-2165
Task No. 10
Program Element No. EHE624A
EPA Project Officer: Charles J. Chatlynne
Industrial Environmental Research Laboratory
Office of Energy, Minerals and Industry
Research Triangle Park, NC 27711
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
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DISCLAIMER
This report has been reviewed by the Industrial Environmental Research
Laboratory - RTF, U.S. Environmental Protection Agency, and approved for
publication. Approval does not signify that the contents necessarily reflect
the views and policies of the U.S. Environmental Protection Agency, nor does
mention of trade names or commercial products constitute endorsement or
recommendation for use.
ii
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ABSTRACT
The use of conventional baghouses has long been an accepted method for
treating exhaust gases from certain industrial and combustion sources. With
the advent of more stringent particle control standards and the expanded use
of low sulfur coals, interest in baghouses as a control device for large
utility combustion sources is growing. In recent years, certain baghouse
vendors and natural resource companies having an interest in materials which
are potential SCk sorbents, have promoted the use of the baghouse as a flue
gas desulfurization (FGD) device. SO* removal is accomplished by introducing
powdered, dry sorbent into the gas stream or by precoating the baghouse fabric
with sorbent. In some instances, experimental studies were conducted and
reported.
In order to further evaluate the concept prior to embarking on expensive
field test work, EPA requested that TRW conduct a more thorough study to in-
clude independent assessment of sorbent costs, system capital costs, system
operating costs and disposal costs. The basic objective of the present study
is to determine whether or not the apparent economic advantage exhibited by
the concept remains in tact after independent, third-party evaluation and
whether the economic (and other) advantages are sufficiently large to warrant
further development of the process at field installations.
The evaluation shows that the dry sorbent baghouse FGD process exhibits
an economic advantage when compared with current lime and limestone scrubbing
technology when applied to western power plants burning low sulfur coal.
Further demonstrations on the pilot plant scale for the dry sorbent baghouse
technology have been recommended, particulary at elevated temperatures. The
need for substantial user (electric utility) commitment in order to justify
the considerable capital investment needed to open a commercial-scale sorbent
(nahcolite) mine may represent the greatest barrier to the commercialization
of this process.
iil
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CONTENTS
Abstract ................. . ............... iii
Figures ................................. v
Tables ................................. v1
1. Executive Summary ........................ 1
Sorbent Supply and Costs .................. 2
Waste Disposal ....................... 2
Economics ......................... 3
2. Introduction .......................... 5
3. Conclusions ........................... 7
4. Recommendations ......................... 10
5. Discussion ........................... 11
System Design ....................... 11
Sorbent Supply and Costs ................. .' 38
Waste Disposal ....................... 51
Economics ......................... 74
6. English to Metric Conversion .................. 106
Converting Units of Measure ................ 106
7. References ........................... 107
Appendices
A. Sample Calculations for Determination of Capital Costs
from Basic Matrix ........................ 109
B. Capital Costs for Varying Input Parameters ...........
C. Operating Costs for Varying Input Parameters .......... 12°
D. Magnesium Oxide as a Baghouse Sorbent .............. 137
References ......................... 144
iv
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FIGURES
Number Page
1 Collection Efficiency of Baghouse at NUCLA Generating
Plant 13
2 Collection Efficiency of Baghouse at Sunbury Steam-
Electric Station 14
3 Major Coal Deposits within 750 Mile Radius of Nahcolite
Mine 17
4 Kinetics of Nahcolite Decomposition to Na2C03 25
5 Effect of Thermal Comminution on Particle Size of
Sorbent Material 27
6 Effect of Temperature on SOg Removal Efficiency 28
7 Effect of Stoichiometric Ratio on Removal Efficiency ... 30
8 Removal Efficiency 33
9 Removal Efficiency Vs. Time 35
10 Flow Chart - Solids Handling System, Base Design 37
11 Flow Chart - Flue Gas System, Base Design 35
12 Flow Chart - SolIds Handling System, Retrofit Design . . . 4C
13 Flow Chart - Flue Gas System, Retrofit Design 41
14 Green River Formation 43
15 Dimensions of Finished Landfill Cell 67
16 Typical Clay Isolation Unit 6f
17 Lengthwise View of Finished Landfill Cell 6?
18 Cost Estimation Methodology 7f
19 Capital Costs Versus Percent Sulfur Content in As-Fired
Coal for Various Baghouse Temperatures 9C
20 Capital Costs Versus Coal Heating Value in As-Fired Coal
for Various Baghouse Temperatures 91
21 Operating Costs Versus Percent Sulfur Content in As-
Fired Coal for Various Baghouse Temperatures 9f.
22 Operating Costs Versus Coal Heating Value 1n As-Fired
Coal for Various Baghouse Temperatures 9P
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FIGURES (Continued)
Number Page
D-l MgS03 w* MgO '+ S02 139
D-2 MgS04*» MgO + S02 + 1/2 02 140
TABLES
Number Page
1 Committed Fossil Fueled Generating Plants 1977-1986. ... 15
2 Available Coal Comparative Analysis 18
3 S02 Emission Regulations for Selected States 20
4 Planned Maximum Nahcolite Production Rates 46
5 Mine Development Costs and Nahcolite Prices 49
6 Composition of Raw and Spent Nahcolite 52
7 Rates of Waste Generation 55
8 Solubilities of Some Waste Materials in Spent Nahcolite
and Scrubber Sludge 55
9 Capital and Operating Costs for Land Disposal 72
10 Calculation of Inflators 79
11 Allocation of Capital Expense Items to Chemical
Engineering Price Indices 84
12 Estimation Coefficients for use in Basic Capital Cost
Matrix 85
13 Allocation of Module Costs, Base Case 87
14 Baghouse Nahcolite Process - Total Average Annual Operat-
ing Costs, Regulated Utility Economics 97
15 Cost Comparison of Dry Sorbent/Baghouse FGD System to
Limestone Slurry FGD Process 103
16 Limestone Scrubber - Total Average Annual Operating Costs,
Regulated Utility Economics 104
17 Comparison of Total Average Annual Operating Costs
Flue Gas Desulfurization Processes 105
18 Conversion Factors 106
D-l Temperature Dependence of MgO Conversion 142
v1
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SECTION 1
EXECUTIVE SUMMARY
The use of dry chemical sorbents 1n conjunction with a conventional bag-
house to remove sulfur oxides from flue gases has been examined 1n several
test programs conducted by potential users and vendors of baghouses, fabrics,
and sorbent materials. These various test programs have served to prove the
technical feasibility of the process, but have not examined, 1n detail, the
economic aspects of a dry sorbent/baghouse flue gas desulfurlzatlon (FGD)
system. In order to provide additional Input to further decisions regarding
development of the concept, a study was undertaken to estimate costs and
evaluate problems associated with a typical commercial Installation. By
estimating costs using a situation which approximates a "best case" and com-
paring these costs with a currently available FGD system, it was possible to
determine if the dry sorbent/baghouse FGO process represents a substantial
breakthrough 1n FGO technology and can be expected to attain substantial
market penetration 1n the future.
"Best case" conditions were selected after examination of: current
trends in boiler design, coal supplies 1n the vicinity of potential sorbent
supplies, S0« removal requirements, and available experimental data on dry
sorbent performance. The conditions that were selected for detailed economic
evaluation were:
t A new 500 MW boiler
• 1% sulfur western coal
• 750 mile (1,200 km) distance from nahcolite
supplies
• Semi-arid region with the water table 50 ft
(15 m) below the surface
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• 400°F Baghouse temperature
• 70% SQy removal required
It is important to note that, although additional refinement of conditions may
produce a slightly lower-cost base-case.for this study, any conditions which
are site specific or narrow in application would be unrealistic since the
equivalent of ten 500 MW installations would be required to support one cor-
mercial-scale nahcolite mine. This is approximately 4% of the power output
of the committed fossil-fueled generating plants for the period 1977-1986.
SORBENT SUPPLY AND COSTS
Data indicate that nahcolite (raw NaHC03) is the only practical material
for consideration in the dry sorbent/baghouse F6D process. The total recover-
able reserves of nahcolite are large enough to support even the most wide-
spread application of the process and can be mined at reasonable cost. It is
most important, however, to note that nahcolite is not currently mined an
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landfill design involves protecting the placed material from intrusion by
groundwater, surface water and rainwater in order to prevent leaching, rather
than attempting to contain leachate, as is necessary with disposal of wet
materials such as scrubber sludge. The existence of vast natural deposits of
soluble materials such as sodium chloride, trona and nahcolite indicates that
conditions can exist which protect these from water intrusion and thus enable
storage for very long periods of time. A cost estimate of $6 per ton of
material placed is detailed in Section 5.
ECONOMICS
In order to determine if the dry sorbent/baghouse process can be expected
to achieve commercial market penetration upon successful completion of a de-
velopment program, an independent cost estimate for a typical commercial in-
stallation was prepared. To the extent practical, estimating procedures
(2\
consistent with those used by TVAV ' in their costing of commercial F6D pro-
cesses were used. Independent estimates for sorbent supply and waste disposal
were prepared and all costs were adjusted to a 1977 basis. The valid com-
parison of the dry sorbent/baghouse FGD system to the limestone scrubbing
process required that both desulfurization processes use the same physical
conditions and inputs (I.e., both were located at a site in Wyoming burning
1% sulfur coal with an ash content of 10%). Also, both Included particle
control capable of meeting the Federal New Source Performance Standard of
0.1 Ib. particulate matter emitted per million BTU's of heat input.
Using capital costs as a basis of comparison, the dry sorbent/baghouse
system is significantly lower in cost than the limestone scrubbing system,
even taking into account the accuracy of the cost estimating procedures
developed by TVA. Using the capital costs derived in this report, the dry
sorbent/baghouse FGD system is seen to be slightly less than 40 percent of
the costs for a limestone scrubber serving a similar power unit. The differ-
ences are not so great when comparing the annual1 zed operating costs of the
two systems; in this comparison, the dry sorbent/bagheuse system is estimated
to be approximately 35 percent less than the limestone scrubber. However, in
view of the accuracy of the cost estimations, this difference may or may not
be significant. Nonetheless, the dry sorbent/baghouse does show promise as a
viable alternative to the present state-of-the-art in flue gas desulfurization.
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The possibility of developing a regenerable dry sorbent/baghouse process
using magnesium oxide as the sorbent was examined and 1s. discussed In Appendix
D. Kinetic data show that such a system 1s not feasible.
RECOMMENDATIONS
The dry sorbent/baghouse flue gas desulfurization process appears to
demonstrate an economic advantage over other currently available technologies
for flue gas desulfurization, when applied to western power plants burning
low sulfur coal as fuel. Further demonstrations of this process should be
pursued. A pilot plant study appears warranted to provide confirming
technical and cost data.
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SECTION 2
INTRODUCTION
The use of conventional baghouses, employing fabrics for filtration of
particulate matter, has long been an accepted method for treating exhaust
gases from certain industrial and combustion sources. With the advent of
more stringent particle control standards and the expanded use of low sulfur
coals, interest in baghouses as a control device for large utility combus-
tion sources is growing. This is due to ever increasing costs for electro-
static precipitators which are not well suited for extremely high efficiency
operation with low sulfur flue gases. In recent years, certain baghouse
vendors and natural resource companies having an interest in materials which
are potential S02 sorbents, have promoted the use of the baghouse as a flue
gas desulfurization (FGD) device. SOg removal is accomplished by introduc-
ing powdered, dry sorbent into the gas stream or by precoating the baghouse
fabric with sorbent. In some instances, experimental studies were conducted
and reported.
In the Spring of 1976, a short study of the dry sorbent/baghouse FGD
concept was undertaken by TRW, under contract to EPA's Industrial Environ-
mental Research Laboratory at Research Triangle Park, North Carolina. The
objectives of this study included^ ':
• Gather and evaluate available data and reports
concerning the concept.
• Qualitatively evaluate the range of conditions
and situations for which the concept is practical.
• Discuss the state of development of baghouses,
fabrics, and operating modes as they impact the
dry sorbent concept.
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• Examine sorbent supply, waste disposal and possible
regeneration.
• Define problems and knowledge gaps concerning the
concept.
• Recommend future work necessary to generate infor-
mation to completely assess prospects for commercial-
ization, range of applicability, and impact of the
concept.
At approximately the same time, the Electric Power Research Institute (EPRI)
/Q\
contracted with Bechtel Corporation for a study with very similar objectives
Both the TRW/EPA study and the Bechtel/EPRI studies concluded that,
based on available information, the dry sorbent/baghouse FGD concept holds
considerable promise of economic advantage under certain geographic, process
and regulatory constraints. The optimistic view of the concept must, however,
be tempered by.the fact that experimental data are sketchy, certain major
institutional and financial barriers exist, and, most significantly, the
available cost estimates were prepared and presented by firms having a poten-
tial financial benefit in the eventual commercialization of the process.
i
In order to further evaluate the concept prior to embarking on expensive
field test work, EPA requested that TRW conduct a more thorough study to in-
clude independent assessment of sorbent costs, system capital costs, system
operating costs and disposal costs. The basic objective of the present study
is to determine whether or not the apparent economic advantage exhibited by
the concept remains intact after independent, third-party evaluation and
whether the economic (and other) advantages are sufficiently large to warrant
further development of the process.
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SECTION 3
CONCLUSIONS
/o\
Published experimental data v ' indicate that nahcolite (impure NaHCOJ is
the most promising sorbent for use in the dry sorbent baghouse flue gas de-
sulfurization (FGD) concept. Available data are adequate for cost estimation
that is on the order of -20 percent to +50 percent accurate. These data are
not, however, sufficient to permit potential users (electric utility compa-
nies) to accept commercial bids with confidence. A recent and rather exten-
sive pilot test conducted by Wheelabrator-Frye, Inc., Superior Oil Co., and a
midwestern utility consortium may well provide sufficient data upon which to
base a commercial design. The extent to which these data will be made public
is not known at this time.
The reserves of nahcolite are adequate to supply even very extensive
application of the dry sorbent/baghouse FGD concept to western and midwestern
low sulfur coal-fired boilers. The material is not currently mined. A rea-
sonable commercial price for nahcolite (70 percent assay) is $25 per ton at
the mine mouth and $32.50 per ton at a power plant located approximately 750
miles (1,200 kilometers) from the mine site (northwestern Colorado^ IRI and
Superior Oil have confirmed that a firm commitment for supplying nahcolite to .
several large baghouse FGD installations would be necessary before any of the
three nahcolite lease holders would be able to invest_the significant sums of
money required to open a nahcolite production mine.
The wastes generated by a 500 MW application of the dry sorbent/baghouse
FGD process can be disposed of in an environmentally acceptable manner. The
basic disposal concept involves a landfill designed specifically to preclude
groundwater, surface water and rainfall from entering the deposit of soluble
waste material. The prevention of groundwater intrusion is accomplished
through careful site selection and exclusion of surface water and rainfall by
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combination of dikes and an impermeable (butyl rubber) membrane placed over
the landfill site. Landfill costs for the concept and design described in
this report are estimated at $6 per ton of waste.
The dry sorbent/baghouse FGD process, when costed in the base case selected
for analysis in this study (500 MW, new installation, 1 percent sulfur coal,
400°F baghouse temperature), shows capital costs of $46 per KW and an annualized
operating cost of 2.60 mills per kWh. This is 35% lower than the base case
limestone FGD process using those inputs which give a flue gas composition of
4.3 x 106 Ib/hr flow, 36,550 Ib/hr ash, 8.17 x 103 Ib/hr S02 and 3.8 x 105 Ib/hr
moisture, equivalent to the nahcolite/baghouse FGD system. The TVA cost estimates
were computed to be $119 per kW and 4.08 mills per kWh for the capital costs and
annualized operating costs, respectively. Even in view of the accuracy of the
cost estimating methods (-20% to +50%), the cost differences between the dry
sorbent/baghouse FGD system and the limestone scrubbing FGD process must be
considered promising. This, in conjunction with the fact that the limestone
scrubber is considered one of the more economical of flue gas desulfurization
schemes, makes the dry sorbent/baghouse system seem quite favorable.
However, since the proposed concept is extremely sensitive to the amount
of sulfur removed (more than 40 percent of the annualized operating costs for
the dry sorbent/baghouse system is for sorbent and waste disposal compared
with 3% for the limestone scrubbing process), applications to high sulfur
coal-firing may not be economically competitive with the limestone scrubber.
Experimental data ' ' indicate that nahcolite utilization may approach
100% if the dry sorbent baghouse is operated at about 525°F (274°C). This
potential improvement in utilization would decrease the costs associated with
sorbent and disposal by about 30 percent over the base case studied 1n this
report. Since these costs represent slightly less than 45 percent of the
total annual cost, a potential savings of nearly 15 percent is possible. This
savings would be somewhat offset by increased capital costs associated with
the higher flue gas temperatures. The net effect should amount to an approx-
imate 10 percent reduction in the base cost of 2.60 mills per k'Wh. The new
cost of 2.34 mills per kWh is lower than the limestone scrubbing cost of 4.08
mills per kWh by approximately 40 percent.
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The use of MgO as a dry sorbent in a regeneration scheme was briefly
examined. Kinetic data developed in Appendix D show that such a system, in
conjunction with the baghouse FGD concept is not feasible.
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SECTION 4
RECOMMENDATIONS
The dry sorbent/baghouse flue gas desulfurizatlon pro'cess appears to
demonstrate an economic advantage over other currently available technologies
for flue gas desulfurization, when applied to western power plants burning
low sulfur coal as fuel. Thus, further demonstrations of the dry sorbent
FGD process utilizing nahcolite as a sorbent should be pursued. Since
the results of this analysis demonstrate that the dry sorbent process
FGD system becomes economically advantageous when operated at temperatures
in excess of those used for current demonstrations, a pilot plant study
appears warranted to provide confirming technical and cost data for this study.
Since operation at extreme elevated temperatures of approximately 525°F
(274°C) holds some additional promise for cost reduction due to increased
utilization of the sorbent, the development of better test data at these
temperatures should be pqrsued. The use of existing test facilities may be
a possible route to obtain technical data in this area.
The data from tests currently in operation with Wheelabrator Frye, Inc.,
and Superior Oil Co., should be examined when they become available. Results
from these tests should be used to confirm data obtained from other sources
in developing the assumptions used in preparing this report. Additionally,
these tests may provide some additional data on nahcolite utilization rates
that can be expected at elevated temperatures.
10
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SECTION 5
DISCUSSION
SYSTEM DESIGN
The applicability of dry sorbent baghouse as an acceptable means of flue
gas desulfurization (FGD) is dependent on many technical and environmental
considerations. The system design as developed in this report has resulted
from a systematic evaluation of these considerations, and represents a first
order optimized design for the dry sorbent/baghouse FGD system as applied to
those power plants for which this type of FGD system is most applicable.
Generating Station Design
The design parameters of the power generating station have been chosen
to represent those found at typical modern plants. Wherever possible, the
parameters used by the Tennessee Valley Authority in their report Detailed
Cost Estimates for Advanced Effluent Desulfurization Processes^ ' are adopted
in this design. This design consistency allows the process design data and
economic criteria developed in this report to be directly compared with those
found for the other major flue gas desulfurization processes located in the
southwestern United States,
Type of Plant—
A new plant installation of the dry sorbent/baghouse FGD system is ex-
pected to yield the most beneficial results. The plant operating parameters
can be established on the basis of the overall installation rather than on
only the power generation section, thus resulting in an overall increase in
plant efficiency. Installation costs are minimized and costly modification
of existing structures and equipment are eliminated. Other benefits of a
baghouse operation can be considered in the evaluation of plant design.
11
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Choice of Fuels—There are three basic types of fossjl fuels used for
power production: oil, gas, and coal. Of these three, natural gas is in
increasingly short supply and few if any new plants will be relying on this
form of energy. The use of oil for power production is common in certain
coastal and oil producing regions of the United States, but the future supply
of this energy source is becoming increasingly doubtful for long term utili-
zation. Coal, on the other hand, is plentiful in many parts of the United
States, thus assuring its long-term availability.
Coal has an additional property which makes the dry sorbent baghouse
advantageous over other FGD systems. Particle collection to provide opacity
control has become increasingly important as Federal and state regulations
for this parameter grow increasingly more stringent. This is particularly
true for power plants burning low sulfur western coal. The resistivity of
the fly ash produced by the combustion of this coal makes the particles
exceedingly difficult to collect by normal methods, e.g., electrostatic pre-
cipitators. Fortunately, the baghouses supplied for dry sorbent FGD will
also provide exceptional particle control. Baghouses installed in fossil-
fired power plants typically provide a particle collection efficiency great-
er than 99.5 percent. Figures 1 and 2 present collection efficiency data
obtained by test at the NUCLA Generating Plant and at Sunbury Steam-Electric
Station, respectively.
Fuel Transportation—It is assumed for the purpose of this study that
coal is delivered to the generating station by railroad, , where it is un-
loaded and stored in piles for use. This is the most common method of coal
transportation, although other methods have been utilized .in specific cases.
It has therefore been assumed that the existing rail spur would be available
to handle the transportation of the dry sorbent to the power plant.
Size—The major capital expenses involved in the construction of a dry
sorbent baghouse are relatively insensitive to size. These are the fresh
sorbent unloading facilities, the design engineering expenses, and to a
limited extent the baghouse itself. It is therefore important to select an
appropriate station size for consideration in this study. Table 1 summarizes
all presently committed new fossil fueled generating capacity for the next
12
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fv.l
99.6
99.7
g
5
99.6
99.5
99.4
99.3
99.2
99.1
99.0
46
PARTICLE SIZE,
10
FIGURE 1. COLLECTION EFFICIENCY OF BAGHOUSE AT NUCLA GENERATING PLANT
(3)
13
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A. Curve based on average of all runs except those with one set of
substrates and run 16
B. Curve based on average of all used bag runs
Note: Curves are believed to be biased toward lower removal efficiency
for Sinn and larger particles because of use of a cyclone percollec-
tor on the inlet samples.
99.J
10
12
FIGURE 2.
2466
PARTICLE SIZE, in
COLLECTION EFFIUENCY~OF BAGHOUSE~AT SUNBURY"STEAM-ELECTRIC
STATION^
14.
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10 years. From these figures it 1s readily apparent that the average size of
all new generating units is 500 megawatts. This has therefore been
selected as the appropriate plant size on which to base this design estimate.
TABLE 1. COMMITTED FOSSIL FUELED GENERATING PLANTS 1977-1986^
Year
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
Total
Number of
Plants
37
34
37
31
32
. 25
24
20
'21
9
270
Combined
MW Capacity
17,160
14,424
16,656
15,421
14,515
13,732
12,959.
11,307
11,770
4,688
132,632
Average
MM Capacity
464
424
450
497
454
549
540
565
560
521
491
Location of Plant—
The dry sorbent baghouse FGD system requires a considerable amount of raw
materials for operation. Because of this, the transportation of the sorbent
material becomes a significant factor 1n the operating costs of the facility.
Additional constraints are placed on the choice of plant location because of
particularities of the waste disposal system which must necessarily be de-
signed for each specific site.
Region—He have limited our review of plant locations to an area within
approximately 750 miles (1200 kilometers) of the source of sorbent supply.
This area Includes most or all of the following states: Arizona, California,
.'Colorado, Idaho, Kansas, Montana, Nebraska, Nevada, New Mexico, North Dakota,
Oklahoma, Oregon, South Dakota, Texas, Utah, Washington, and Wyoming. This
does not Imply that dry sorbent baghouses are not practical in other regions;
however the operating costs incurred for this type of system in such a region
would certainly be greater than for the considered situation.
15
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Local Geology—The power plant is situated on level ground suitable for
industrial construction without excessive foundation and ground preparation
work. Rainfall is assumed to be average for an arid area typical of the
southwest United States.
The waste disposal location is assumed to be approximately 15 miles
(24 kilometers) from the power plant. It has a flat terrain, predominantly
composed of clay soils. The water table is greater than 100 feet (30.5
meters) below surface area; there is no perched water table; and there are
no surface streams in the immediate area.
Coal —
The operating costs and removal efficiency of the dry sorbent FGD pro-
cess are dependent on ash content, sulfur content, and hea'ting value of the
coal. These coal parameters have a considerable effect on the design and
sizing of the specific components. It is therefore necessary to assign
specific parameters to the assumed coal supply to evaluate the capital costs
of such an installation.
Coal Availability—Coal deposits are plentiful in the southwest region
which is considered for the plant location. The actual supply for specific
plants is assumed to be mined locally. Figure 3 shows the major coal depos-
its^ ' within a 750 mile (1200 kilometers) radius of northwest Colorado, which
is the assumed location of the sorbent supply.
Coal Analysis—A comparative analysis of each of the available coal de-
posits is illustrated in Table 2. The sulfur content of the specific coal
used will affect the amount of sorbent necessary to achieve a given S02 removal
from the flue gas. The sulfur content of the available coals range from 0.27
to 1.3 percent. The ash content of the specific coal used will determine the
amount of material collected in the baghouse, thus affecting the baghouse
sizing, waste storage sizing, and waste disposal operations. The ash content
of the available coals ranges from 3.4 to 13.8 percent. The heating value of
the coal used will determine the amount of coal which is necessarily combusted
to produce a given heat output from the power plant. An increased coal heat-
ing value will decrease both the amount of fly ash (for a given power output)
produced and the rate of sorbent consumption. The heating values of the
16
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ARIZONA I NEW MEXIC°
1 -6
1 - BOULDER
2 - GUNNISON
3 - LAS ANIMAS
4 - CARBON
5 - VALLEY
6 - SOCORRO
7 - PERKINS
8 - CARBON
9 - LINCOLN
10 - SHERIDAN
FIGURE 3. MAJOR COAL DEPOSITS WITHIN 750 MILE RADIUS OF NAHCOLITE MINE
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available coals range from 6,000 to 13,500 Btu/lb (14,000 to 31,400 joules/gm)
For the base case used in this study each of these three parameters have been
evaluated, based on the number and size of deposits, to establish the follow-
ing norm coal analysis:
1.0 percent sulfur by weight
10.0 percent ash by weight
10,500 Btu/lb (24,000 joules/gm) heating value
Variations from this assumed coal analysis will produce predictable effects
on the capital and operating costs.
TABLE 2. AVAILABLE COAL COMPARATIVE ANALYSIS
rc(6)
State
Colorado
Montana
New Mexico
South Dakota
Utah
Wyoming
County
Boulder
Gunnison
Las Am' mas
Carbon
Valley
Socorro
Perkins
Carbon
Lincoln
Sheridan
Coal
Type
Subbit.
Bit.
Bit.
Subbit.
Lig.
Bit.
Lig.
Bit.
Bit.
Subbit.
S %
0.27
0.43
0.70
1.1
1.3
0.82
1.2
0.6
1.0
1.1
Ash %
5.4
3.4
12.8
11.2
9.1
13.8
9.0
5.6
5.5
7.9
Heating
Value
10,000
13,^00
13,000
10,500
6,700
12,300
6,000
12,500
13,300
9,000
Flue Gas—
i
Certain parameters of the flue gas are sensitive to utility operation and
boiler design as well as coal analysis. For these parameters, specific values
have been assumed for the purposes of this study. In particular, the flue gas
flow rate and boiler exit temperature have been chosen to correspond to these
values used in the TVA study
(2).
18
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4.3 x 106 Ib/hr (1.95 x 106 kg/hr) mass flow rate
8.9 x 105 scfm (1.51 x 106 m3/hr)
890°F (477°C) boiler exit temperature
Chemical analysis of the flue gas at boiler exit is assumed to contain
the constituents listed below. The proportions of each constituent are con-
sidered to be typical of western coal-firing^ .
N2 - 74% S03 - 1.0% of the S02 value
02 - 4.8% NO - .06%
C0£ - 12.3% HC1 - .01%
S02 - Variable H20 - 8.8%
Flue Gas Desulfurization Requirements--
The amount of S02 removal required for plant operation varies with
plant location and coal analysis. Because of the large amounts of sorbent
required for a full-size commercial plant, the sorbent handling system de-
sign, site storage facilities, and baghouse sizing are affected by this
parameter.
Federal and State Regulations—The Federal New Source Performance
Standards concerning the S0« emissions from a fossil-fired power generating
station are currently under revision. Although the new regulations are ex-
pected to require 85% removal for most of the available coal types, these
anticipated regulations have not been used for this report due to their
uncertainty. The existing regulations are based on an allowable emission
rate which is proportional to the power output of the plant. This regula-
tion is 1.2 Ibs of S02 per million Btu (5.16 x 10 g/joule) heat input
to the boiler. Several states in the southwest have set considerably more
stringent regulations for S02 emissions. Most of these are consistent with
the Federal method and only differ in the amount of S02 emissions that are
allowable. Utah has set a regulation requiring 80% removal independent of
plant size or fuel analysis. Table 3 illustrates the various regulations
currently affecting these power plants.
19
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TABLE 3. S02 EMISSION REGULATIONS FOR SELECTED STATES
State
Federal Emission
Requirements
f. (Ib SO,, per
10 Btu Heat Input)
State Emission
Requirements
p. (Ib S09 per
10° Btu Heat Input)
Ari zona
Colorado
Kansas
Montana
Nebraska
Nevada
New Mexico
North Dakota
South Dakota
Texas
Utah
Wyomi ng
1
1
1
1
1
1
1
1
1
1
1
1
.2
.2
.2
.2
.2
.2
.2
.2
.2
.2
.2
.2
0.8
0.3 or 150 ppm
1.2
l'.2
1.2
0.21
0.34
1.2
1.2
1.2
80% Removal
0.2
Removal Requirements
by Locati on—The most common
situation for south-
western power plants will be for a plant to purchase fuel from the nearest
coal source. A good estimation of removal requirements is then to evaluate
each of the coal deposits in Table 2 with the assumption that a power plant
is situated in close proximity to the deposit, and within the same state. The
percent SOp removal for each of the deposit locations are as follows:
Boulder - 48%
Gunnison 47%
Las Animas - 71%
Carbon
Valley
Socorro
Perkins
Carbon
Lincoln
Sheridan
- 40%
- 68%
- 73%
- 69%
- 80%
- 86%
- 91%
20
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Base Design Removal Assumptions—It can be seen from the above listing
of S02 removal requirements that 3 of the deposits require little S02 removal
capability (approximately 40-50 percent), 3 require extensive removal capabil-
ity (approximately 80-90 percent), and the remaining 4 deposits require a
moderate removal capacity (65-75 percent). Based on these data, 70 percent
S02 removal has been used as the baseline removal requirement for this study.
Sorbent Supply—
Nahcolite is the principal sorbent under consideration for FGD processes.
It is found in conjunction with oil shale deposits in the Green River forma-
tion of northwestern Colorado. This report assumes a typical assay of
nahcolite ore of 70 percent sodium bicarbonate.
Process Design
The process design contained herein represents an estimation of full load
operating parameters calculated for the generating station design described in
the preceding section. Combustion parameters are included for coal consump-
tion, combustion air requirements, and particular flue gas characteristics.
Process design, from a functional standpoint, is presented for a plant using
a baghouse flue gas desulfurization system as depicted in this report. This
design is based on a careful review of previous test work with dry sorbent
flue gas desulfurization to ascertain the effect of various design manipula-
tions on overall plant effectiveness. From this analysis, a particular oper-
ating plan has been established to make full use of the dry sorbent capabil-
ities and to minimize operating costs. ^
Coal Combustion—
The process of coal combustion to produce heat for steam generation is a
normal industrial operation, occurring with great frequency throughout the
world. No radical or improved designs are expected in this technology, and
none are considered in this report. The combustion calculations included in
this report are based on historical utility boiler operations and are pre-
sented to display the basic operating parameters upon which the flue gas
desulfurization system design hrs been based.
21
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Coal Requirements— The Tennessee Valley Authority has established the
basic heat rate requirement for their operating system' - The fuel Btu
input requirements to produce a fixed power generation is a function of the
unit size and time of construction. This relationship can be stated as:
Power Unit Input Heat Requirement
Size. MW Status Heat Rate, Btu/kWh
1 ,000 New 8,700
1,000 Existing 9,000
500 New 9,000
500 Existing 9,200
200 New 9,200
200 Existing 9,500
The design of a new 500 MW utility boiler may therefore assume a heat rate of
9,000 Btu/kWh (9,500 kjoules/kWh). The quantity of coal required to produce
500 MW of electricity, assuming a coal heat value, of 10,500 Btu/lb (24,400
jouTes/gram) is:
Qlb/hr = (50° MW) (9'°°° Btu/kwh)
= 4.3 x 105 Ib/hr (2.0 x 105 kq/hr)
Fly Ash Production—The coal assumptions included an ash content of 10
percent by weight. A review of typical utility operations demonstrate that
;approximately 15 percent of the ash content of the coal becomes bottom asti
and is not carried by the flue gas stream. The balance, or 85 percent, is
assumed to produce fly ash. The amount of fly ash is therefore:
Qlb/hr = (4'3 x 1()5 lb/hr) (0'85) (0-10)
= 36,550 Ib/hr (16,575 kg/hr)
Fly ash loading is another parameter required for flue gas desulfurization
system design. It is stated in terms of grains per standard cubic foot (gr/
scf) and is calculated as follows:
22
-------
Loading = (36,550 Ib/hr) (6,998 gr/lb) x (3)
(0.01667 hr/m1n) ( - 1 - )
8.9 x 10s scf/min
= 4.8 gr/scf (dry) (10.9 grams/m3) (at air
preheater entrance)
Sulfur Dioxide Content of Flue Gas— Results of tests performed on utility
boilers^ ' demonstrate that approximately 95% of the sulfur content of the as-
fired coal becomes S02 in the flue gas, with the balance of the sulfur remain-
ing in the ash. The molecular weight of sulfur is 32' and oxygen is 16. One
pound of sulfur can therefore produce 2 Ibs of SOp. The basic coal analysis
assumed a sulfur content of the coal of 1.0% by weight. The rate of S02
emission is therefore given by:
Qlb/hr = (4-3 x 10b Ib/hr) (0.01) (0795) (2) ~ (4)
= 8.17 x 103 Ib/hr (3.7 x 103 kg/hr) S02
Since the molecular weight of S02 is 64, the pound-moles (Ib-mole) of S02
produced is:
« • t
Vmole/hr " <8'17 * ™* lb/hr> fr Ib/lb-mole* <5)
= 128 Ib-mole/hr (57.8 x 103 g-mole/hr) S02
Sorbent System Design-
Several materials have been suggested for use in a dry sorbent baghouse
flue gas desulfurization program. These include trona and nahcolite, which
are naturally occurring sodium bicarbonate formations, pure sodium bicarbon-
ate, and magnesium oxide. Of these, nahcolite has proven to be the most
reactive, and therefore the most advantageous to use. Nahcolite has therefore
been the sorbent material included in this design study. This is not meant to
imply that nahcolite is the only economically feasible sorbent for this appli-
cation, but rather that it is the only substance that has been studied and
tested in sufficient depth to provide adequate data on material performance
on which to base a full scale plant design.
23
-------
Mechanism of Reaction Process—Dry process desulfurization with nahcolite
involves the reaction of NaHCOg and Na2C03 contained in the nahcolite ore with
S02 in the flue gas stream. Genco and Rosenberg (1976) postulate that desul-
furization occurs via the following 4 reactions:
2NaHC03(s) + S02(g)^=± Na2S03(s) + C02(g) + H20(g) (6)
2^0)3(5);^ Na2C03(s) + H20(g) + C02(g) (7)
NaC03(s) -i- S02(g) ^ Na2$03(s) + C02(g) (8)
Na2S03(s) + 1/2 02(g) > Na2S04(s) (9)
Reaction (7), the decomposition of NaHC03 to form Na2C03, proceeds much faster
than the reaction of S02 with NaHC03(6) or Na2C03(8) (Bechtel 1976). Genco
and Rosenberg (1976), simulating typical dry process desulfurization con-
ditions, showed that in spent nahcolite a 1:1 ratio of Na2C03 to Na2S03 and a
2:1 ratio of Na2S03 to Na2S04 exists. Based on these data, the expected ratios
of NaHC03, Na2C03, Na2$03, and Na2$04 are, respectively, 1:12:26:10 in spent
nahcolite.
Sizing of Injected Sorbent—It is apparent that the reaction of S02 with
nahcolite is affected by several factors. First is the speed with which the
NaHC03 is decomposed into Na2C03. This process is clearly a direct function
of particle size, with the finer materials decomposing at a significantly
faster rate. Figure 4, which illustrates this observation, has been devel-
oped from data taken by the Superior Oil Company tests with a countercurrent
reactor at the Cherokee Station of Public Service of Colorado'8'. It can be
seen from these data that for a fixed bed of sorbent, such as a collected layer
in a baghouse, the rate of reaction of S02 with nahcolite may become limited
by the rate of decomposition of sodium bicarbonate to sodium carbonate. To
prevent this situation, it is necessary to maintain the sorbent size below a
certain maximum particle diameter, which is determined by physical and chem-
ical constraints of the operating system. Since standard baghouse technology
will be utilized for the dry sorbent baghouse FGD system, it is necessary to
provide adequate flexibility '''or variations in baghouse cleaning cycle timing.
This cycle timing is determined by pressure drop across the baghouse
24
-------
ro
en
lOOr
TEMPERATURE OF DECOMPOSITION;
' / 7 ~*
300°.+
© - 200 + 400 MESH
X -3B4DESH
A - 6 * 10 MESH
[•] -3-1/2 * 4 MESH
GO - 1/2" + 3«" MESH
0.4
0.6
0.8
1.0
1.2
1.4
1.6 1.8 2.0
TIME. HR
21 2.4
2.6
2.8
3.0
3.2 3.4
3.6
FIGURE 4. KINETICS OF NAHCOLITE DECOMPOSITION TO Na,CO,
1973). THE SUPERIOR OIL COMPANY. i
(8)
(FIXED BED TEST DATA TAKEN DURING NOV.-DEC.,
-------
compartments and may be required at intervals as frequent as .40 minutes.
Based on the Superior tests at Cherokee, it 1s necessary to provide the
nahcolite at approximately -200 mesh to ensure a supply of reactive material
for reaction with S02 at 300°F.
Superior's test at Cherokee also Included some test work on combustion
zone injection of sorbent material. One very Important finding of this test
procedure was that nahcolite underwent a process of thermal comminution dur-
ing its combustion zone residence. This process results in a cracking of
nahcolite particles, thus providing a considerable size reduction. Figure 5
illustrates this phenomenon. It is interesting to note that the mass mean
diameter of sorbent particles was reduced by a factor of 38, from 68 microns
to 1.8 microns. Although it is possible to take advantage of this phenomenon
by reducing the amount of sorbent preparation necessary before injection, it
is doubtful that many utilities would agree to sorbent Injection within the
boiler due to the increased probability of slagging problems as a result of
a significant increase in noncombustible solids in the combustion area.
Temperature of Reaction—Various tests performed on the dry sorbent
process have demonstrated the strong dependence of removal efficiency on the
gas temperature at the reaction site. Figure 6 illustrates this relationship
based on test data taken with nahcolite by the Air Preheater Company during
their tests at the Mercer Generating Station of Public Service Electric and
Gas Company of New Jersey. Increasing the gas temperature dramatically in-
creases the reaction rate, especially within the temperature range of 250°
to 600°F (120° to 320°C). Since economic criteria will ultimately determine
the applicability of the dry sorbent baghouse FGD process, 'it 1s necessary to
consider here the effect of temperature on operating cost. To maintain a
given required removal efficiency, the stoichlometric ratio can be reduced if
the temperature is increased by a corresponding amount. This effectively
reduces the amount of sorbent material required per ton of'coal combusted,
thus directly decreasing the operating costs of:
1) Nahcolite supply
2) Waste disposal
26
-------
-80-
NJ
l—<
C/l
O
i_i
u_
1-4
O
Ul
Q.
Ul
in
ui
i 1
SIZE DISTRIBUTION
BEFORE THERMAL
COMMINUTION
SIZE DISTRIBUTION
AFTER THERMAL
COMMINUTION
I 111
.4 .6 .8 1
I
4
1 I I
6 8 10
r
20
ii i i
40 60 80 100 200
PARTICLE SIZE, MICRONS
FIGURE 5. EFFECT OF THERMAL COMMINUTION ON PARTICLE SIZE OF SORBENT MATERIAL
-------
100-
90-
80-
70-
NAHCOLITE TEST
0.95
-------
Its effect on capital costs will be mixed, decreasing the cost of solids
handling and waste disposal facilities and increasing the costs of the bag-
house and air preheater sections.
The upper limit on reaction temperature is principally due to limitations
on baghouse design. Standard baghouse designs and bag materials are generally
applicable up to temperatures in the neighborhood of 550°F (288°C). To be
consistent with current design philosophy, 400°F (204°C) has been chosen as a
base design parameter; however, it is realized that operation at this temper-
ature will provide less than optimum operation. This is due to a decrease in
overall plant thermal efficiency dictated by the discharge of vast quantities
of waste heat. The economic advantage of operation at an elevated temperature
in the neighborhood of 550°F (288°C) is illustrated in a subsequent section
of this report dealing directly with flue gas desulfurization economics.
Stoichiometric Ratio—The required removal efficiency of the F6D system
is a function of the chemical analysis of the as-fired coal, the boiler effi-
ciency, and the applicable Federal and state regulations. Based on the as-
sumptions stated earlier, a 70 percent SOg removal efficiency is required for
this design.
Removal efficiency and reaction temperature of the dry sorbent system
determine the average Stoichiometric ratio for the sorbent system. Contact
time will also exert an influence on the stoichiometric ratio, but this effect
is relatively small when compared to efficiency and temperature within the
range of practical variations in contact time. Figure 7 illustrates this
relationship based on test data by The Air Preheater Company at Mercer Gener-
ating Station(9' and by American Air Filter Company^10^ during bertch-sale
test work. From these experimental results, it can be seen that at 400°F
(204°C), a S02 removal efficiency of 70 percent will require a stoichiometric
ratio of approximately 1.0. At a stoichiometric ratio of 1.0, the average
utilization of nahcolite will equal the efficiency of 70 percent. This factor
identifies the quantity of sorbent necessary by determining the net loss of
unreacted sorbent as being 30 percent.
It should be noted here that the determination of stoichiometric ratio
has been based on the experimental data from a limited number of tests. Data
not published at the time of this report suggest that higher efficiencies
29
-------
CO
o
100-
80-
60-
40-
512°F
20-
0.5
I I I
1.0 1.5 2.0
STOICHIOMETRIC RATIO, NAHCOLITE
I
2.5
FIGURE 7. EFFECT OF STOICHIOMETRIC RATIO ON REMOVAL EFFICIENCY
-------
may be attainable for a given Stoichiometric Ratio and temperature than
suggested by Figure 7. Results of this type indicate that a Stoichiometric
Ratio below 1.0 may be used for the dry sorbent baghouse process. This will
increase the sorbent utilization, thus decreasing the amount of sorbent re-
quired and hence reduce the FGD system operating costs. _
Contact Time— Air Preheater Company^ ' found "There is a definite
advantage by injecting the additive further upstream of the filter house to
increase retention time." Their study found increases of from 17 to 27 per-
cent in S0« removal efficiency. To prevent possible equipment damage due to
the high particle load of the flue gas stream containing bqth fly ash and
nahcolite, the injection point for the sorbent should not be upstream of any
air preheater or other flue gas handling equipment. The principal Injection
point for the base design is therefore Immediately downstream of the air pre-
heater.
Sorbent Usage— As previously determined, the base design plant will have
a flue gas concentration of 128 moles/hr of SCL. The amount of nahcolite
required for plant operation is therefore determined as that amount required
to react 70 percent (the required removal rate) of this flue gas component.
The amount of SOg removal is:
Qmole/hr = (128 mole/hr) (°-7°)
= 88 mole/hr
Two moles of NaHCOg are required to react chemically with one mole of S02-
The quantity of NaHCOg required 'to. react with 88 moles/hr of SOg 1s:
mole/hr>
=176 mole/hr NaHC03
At a Stoichiometric ratio of 1.0, the nahcolite utilization equals the
S02 removal efficiency of 70 percent. The amount of NaHCOg required is there
fore increased to allow for this utilization:
31
-------
= °76 m°le/hr)
= 250 mole/hr NaHC03
One mole of NaHC03 weighs 84 pounds (38 kg). Therefore, 250 mole/hr of NaHC03
is equivalent to:
Q1b/hr = (250 mole/hr) (84 Ib/mole) (13)
21,000 Ib/hr (9,500 kg/hr).
Nahcolite ore is assumed to assay at approximately 70 percent NaHCO^. The
quantity of nahcolite required for this process is therefore given by:
Qlb/hr= (21,0001b/hr) (^ (14)
= 30,000 Ib/hr nahcolite (13,600 kg/hr)
Injection Method—The principal injection point for the sorbent is
immediately downstream of the air preheater. Tests performed on this config-
uration with continuous injection identify an initial period after the com-
mencement of the test during which the removal efficiency is considerably
reduced. A typical test result of this type is presented in Figure 8. This
phenomenon can be explained by the observation that the actual S02 removal
takes place both in the flue gas stream and on the bag surface. Removal
efficiency will therefore be at a reduced level until the nahcolite coating
on the bag reaches some minimum coating thickness. Optimum performance of the
dry sorbent FGD system must therefore require a combination of nahcolite in-
jection immediately downstream of the air preheater and some preliminary pre-
coating of the filter bags. This configuration will prevent the initial
removal efficiency loss and provide the most beneficial removal efficiency
during continuous operation.
32
-------
L-8 Q-10000 SR-1.131 FR-2.33
L-14 0-14900 SR-1.137 FR-3.46
Time (Minutes) __ __ 16°
FIGURE 8. REMOVAL EttlCIENCY^
L = Test Designation
Q = Flow Rate, acfm
SR = StoicMometrir Ratio
FR = Filter Ratio, Ft3M/Ft2
Air to Cloth Ratio—The air to cloth ratio (A/C) is defined as the actual flow
rate of air passed through the baghouse in cubic feet per minute divided by the
active cloth filter area in square feet. The active cloth area is the actual bag
surface passing flue gas at any instant, and does not include unused surfaces such
as bags undergoing cleaning. Air to cloth ratios will affect deposit characteristics,
collector efficiency, pressure drop, and maintenance requirements. Of these, the most
important 1s pressure drop requirements. Greater A/C ratios wi11 1ncrease
the differential pressure across the bag surface. Induced draft fans are
required to move the flue gas through the baghouse. The capital costs of
these fans increase with pressure drop, as do the operating costs. Dry
sorbent baghouses will be located upstream of the induced draft fans, and
will therefore be operated at less than atmospheric pressure, the magnitude
of this negative pressure is directly proportional to the differential pressure
across the filter bags. Construction costs for the baghouse structure increase
rapidly with pressure drop due to the increase in structural rigidity necessary
to withstand the differential pressure without structural damage.
33
-------
A pressure drop of approximately 4 Inches (10 cm) of water 1s considered
by Wheel abrator-Frye representatives^21 ' to be the optimum pressure drop attain-
able with standard baghouse configurations for pulverized coal -fired power
plants. Various tests performed on the dry sorbent baghouse concept demon-
strate that this pressure drop can be maintained with air to cloth ratios
ranging from 2.4 to 3.4; the main variation between these being the cycle
timing for the baghouse operation. We have chosen an air to cloth ratio of
3.0 for the base design to allow reasonable operating limits on cycle timing.
This value is consistent with recent commercial proposals by baghouse manu-
facturers for pulverized coal -fired power plants.
Precoat Sorbent Usage—The quantity of nahcolite required for use in
precoating the filter bags is fundamentally based on achieving a minimum
fg\
precoat thickness. Tests by Air Preheater Company v ' on a dry sorbent baghouse
with all bags cycled in parallel demonstrated a specific removal efficiency
time dependence as illustrated in Figure 9. The active filter bag area was
2 2
4,300 ft (400 m ) and the bag was coated with sorbent at the rate of
25 Ib/min (11 kg/min). From Figure 9, peak efficiency was reached after
1.7 minutes had elapsed. The amount of sorbent material that had deposited
on the filter bags at this time can be calculated as:
t
A o = (1.7 min) (25 Ib/min) ( } J (15)
lb/ft^ 4,300 ft*
= 0.01 lb/ft2 (0.05 kg/m2)
This is the amount of precoat which is therefore necessary to minimize the
effect of initial S02 removal loss.
At an air to cloth ratio of 3.0, the base design flow of 1.5 x 10 acfm
(4.2 x 104 m3/min) will require 5.0 x 105 ft2 (4.6 x 104 m2) of active bag
area. Assuming a baghouse cycle time permitting an average on-stream bag
exposure of 50 minutes per cycle, the nahcolite required for the filter bag
precoating is given as follows:
Qlb/hr = (0'01 lb^ft) (5-° x 1() ft/50 m1n) (60 min/hr) 06)
= 6,000 Ib/hr (2,724 kg/hr)
34
-------
100
a
0)
•r-
U
•r-
t
UJ
Time (.Minutes).
FIGURE 9. REMOVAL EFFICIENCY VS. TIME
(9)
Injection Sorbent Usage—The amount of nahcolite required for injection
downstream of the air preheater is therefore the balance of the material, or
24,000 Ib/hr (10,876 kg/hr).
Total Material Collected by Baghouse—Specifications for several of the
baghouse design parameters have been developed in the preceeding sections.
An additional parameter required for the baghouse design is the total amount
of material that will be collected on the filter bags. This total will be a
combination of the fly ash and dry sorbent. The sorbent consumption rate will
be 30,000 Ib/hr (13,600 kg/hr) and the fly ash production rate will be 36,550
Ib/hr (16,575 kg/hr). The resultant solids loading on the filter bags will be
66,550 Ib/hr (30,175 kg/hr), or 0.097 lb/ft2 (0.47 kg/m2) of bag surface.
Physical Design
A physical design for the dry sorbent baghouse flue1 gas desulfurization
system must be established to ascertain equipment needs and develop an econom-
ic model. Design methods and sizing criteria follow standard procedures for
the power industry; however, in.process storage capacity and equipment, spares
have been minimized for consistency with the design philosophy present in the
TVA study, "Detailed Cost Estimates for Advanced. Effluent Desulfurization
Processes." The design data presented in the following sections have been
used only to establish a base design system. The sensitivity of the capital
35
-------
and operating costs of this design, to variations in process design and coal
parameters, is illustrated in the subsequent section on economics. Once an
optimum operating point is established for any specific installation, the
specific hardware requirements are then reevaluated.
Layout, Base Design System—
The base design system has been developed as an illustrative tool for the
dry sorbent system. It represents a careful evaluation of all existing test
work on this process. Figure 10 depicts the solids handling portion of the
plant.
Nahcolite is delivered to the plant by railroad in covered hopper cars.
Cars are unloaded semi automatically and the nahcolite is transferred to
covered silos for normal plant storage. The railroad unloading facility is
sized to accommodate 75 tons (68 metric tons) per hour, based on operating on
a 40 hour work week. All nahcolite transfer/conveying systems, both before
and after the milling operation, are of the pneumatic conveying type. The
nahcolite transfer system from railroad unloading to site storage will include
an automatic switching system to distribute the sorbent among four 200,000
cu. ft. (5,663 cu. meter) storage silos. This provides an on-site sorbent
storage of 32 days plus whatever amount is contained within the railroad
hopper cars not yet unloaded, typically 3 to 5 day's worth. Nahcolite is trans-
ferred from these silos to a surge tank which feeds directly into the mill. The
surge tank is sized for a capacity of 8,000 cu. ft. (230 cu. meter), or eight
hours of operation. Two mills are provided, each having a capacity of milling
20,000 Ib/hr (9,000 kg/hr) of nahcolite to -200 mesh (less than 0.074 mm).
Included with the mill is a 4,500 cu. ft. (130 cu. meter) receiver tank which
collects the milled sorbent.
Two rotary feeders draw the milled sorbent from the receiver tank and
meter it to the two points of nahcolite injection. Sorbent and fly ash are
collected on filter bags within the baghouse and are subsequently convenyed
to a waste material silo for removal. The baghouse is designed to handle 1.5
x 106 acfm (4.25 x 104 cu. meter/min) of flue gas at 400°F (200°C) at an air
to cloth ratio of 3:1. The waste material silo is sized to accommodate
300,000 cu. ft. (8,500 cu. meter) of combined sorbent/fly ash material, which
36
-------
FLUE GAS
CO
-J
NAHCOLITE
STORAGE
OFF SITE
DISPOSAL
FLOW
(Ib/hr)
1
CRUSHED
NAHCOLITE
30,000
2
MILL
OUTLET
30,000
3
NAHCOLITE
TO INJECTION
24,000
4
NAHCOLITE
TO PRECOAT
6,000
5
SPENT
ABSORBENT/
FLY ASH
64,400
FIGURE 10. FLOW CHART - SOLIDS HANDLING SYSTEM, BASE DESIGN
-------
will allow an accumulation of 5 days'worth of operation without disposal.
Trucks will be used to haul the waste material from the plant site.
Figure 11 represents the corresponding flue gas handling system for the
base design system. To allow the baghouse to be operated at elevated temper-
atures in the range of 400 to 550°F (200 to 290°c), without wasting an exces-
sive amount of heat energy, a split air preheater design has been utilized.
Flue gas exiting from the economizer at approximately 705°F (375°C) is cooled
to the baghouse operating temperature by the first stage air preheater.
Cleaned flue gas exiting the baghouse is then cooled to the stack temperature
of 225°F (110°C) by the second stage air preheater, the heat recovered from
both stages being used to preheat the boiler combustion air. A bypass damper
is provided around the first stage air preheater so that when the plant is
operated at reduced loads the baghouse can be maintained at the desired tem-
perature.
Layout, Retrofit System--
The economics of the dry sorbent baghouse system are most favorable for
design inclusion within a new plant. This occurs principally because of the
sensitivity of capital and operating costs to baghouse temperature. Retrofit
systems must operate at available flue gas conditions, typically in the neigh-
borhood of 275°F (135°C). Operation at these temperatures will be more costly
and the dry sorbent/baghouse concept will therefore maintain its economic
advantage over other FGD processes only for limited situations.
The nahcolite handling system remains essentially the same as for the
base design system except that the flow rates will vary from that design as
illustrated in Figure 12. Injection of dry sorbent material should be down-
stream of any existing equipment, such as electrostatic precipitators, to
prevent any solids collection at points other than in the baghouse. Figure
13 represents the corresponding flue gas flow chart.
SORBENT SUPPLY AND COSTS
Of paramount importance in the successful utilization of the proposed
dry sorbent-fabric filter FGP system is an adequate supply of suitable dry
38
-------
CO
vo
COMBUSTION
AIR
TEMPERATURE
CF)
aou
UO6 Ib/hr)
1
COMBUSTION
AIR INLET
110
4.0
2
COMBUSTION AIR
TO STAGE 1 AIR
PREHEATER
292
4.0
3
COMBUSTION AIR
TO BOILER
655
4.0
4
BOILER
FLUE GAS
890
4.3
5
ECONOMIZER
OUTLET
70S
4.5
6
auE GAS
TO BAGHOUSE
400
4.7
7
FLUE GAS
FROM BAGHOUSE
375
4.7
6
1.0. FAN
INLET
225
4.9
9
FLUE GAS
TO STACK
225
4.9
FIGURE 11. FLOW CHART - FLUE GAS SYSTEM, BASE DESIGN
-------
MILL
HOPPER
NAHCOLITE
STORAGE
FAN
FLUE GAS -
INJECTION
PRECOAT
BAGHOUSE
WASTE STORAGE
OFF SITE
DISPOSAL
FLOW
(Ib/hr)
1
CRUSHED
NAHCOLITE
65,000
2
MILL
OUTLET
65,000
3
NAHCOLITE
TO INJECTION
59,470
4
NAHCOLITE
TO PRECOAT
5,530
5
SPENT ""
ABSORBENT/
FLY ASH
99,400
FIGURE 12. FLOW CHART - SOLIDS HANDLING SYSTEM, RETROFIT DESIGN
-------
TEMPERATURE
(•F)
aou
(106 Ib/hr)
1
COMBUSTION
AIR INLET
110
3.8
2
COMBUSTION AIR
TO BOILER
550
3.8
3
BOILER
FLUE GAS
890
4.1
4
ECONOMIZER
OUTLET
705
4.4
5
RUE GAS
TO BAGHOUSE
215
4.7
6
RUE GAS
FROM BAGHOUSE
260
4.7
7
FLUE GAS
TO STACK
260
4.7
FIGURE 13. FLOW CHART - FLUE GAS SYSTEM, RETROFIT DESIGN
-------
sorbent at a reasonable cost. This section addresses both the cost and avail-
ability of the most promising of the sorbents, nahcolite.
Scope of Analysis
Some materials such as raw trona (sodium sesquicarbonate [NagCO
2^0]) could have potential for use as a dry S02 sorbent, however, these
other sorbents are not considered in the present analysis for one or more of
the following reasons:
• Insufficient reactivity and other performance- related
data were available for process economics to be
assessed in some cases, such as trona.
• Other potential sorbents, such as magnesium oxide,
limestone, and lime, were eliminated because of their
low reactivities and the consequent high sorbent con-
sumption and' waste generation rates.
It should be noted that trona has at least one significant advantage over
nahcolite: it is currently being mined in the Green River Basin of Wyoming in
large quantities by such companies as Allied Chemical Corporation, FMC Corpo-
ration, Stauffer Chemical Corporation, and Texasgulf, Incorporated. Although
the trona is used only as a raw material for soda ash (Na^COo) manufacture at
this time, it is not difficult to envision the sale of raw trona for FGD
purposes should a sufficient market develop.* In view of trona's ready avail-
ability, an experimental program for the baghouse FGD concept should include
at least brief tests of trona to define its performance as an SO sorbent.
/\
The western United States includes several known deposits of nahcolite,
but for FGD purposes, the economically significant nahcolite deposits are all
found in the Piceance Creek Basin of northwestern Colorado (Figure 14). The
deposits are part of the Green River Formation, which includes the Green River
Basin of southwestern Wyoming.
*However, it is difficult to make estimates of the possible market price of
raw trona, because the preseit depletion allowance is based in part on the
value of the final product, soda ash.
42
-------
GREAT DIVIDE BASIN
CO
ROCK /^^\
RINGSX%3 \
ICEANCE BASIN
RIFLE
WYOMING
COLORADO
SAND WASH BASIN
GRAND MESA
FIGURE 14. GREEN RIVER FORMATION (DARK SECTION IDENTIFIES THE MAHOGANY ZONES)^8)
-------
This geographic area has therefore been chosen to base the present
analysis on.
There are numerous sodium lease holders in the Piceance Creek region;
however, three companies—Industrial Resources, Incorporated (IRI), Rock
School Corporation, and Superior Oil Company—appear to hold some of the most
promising leases for nahcolite. In addition, these companies have all pre-
pared detailed mining* and production cost estimates for nahcolite. These
estimates, together with an independent economic assessment by TRW, constitute
the overall economic analysis for nahcolite production.
General Considerations
Nahcolite is found in the unleached portion of the oil shales of the
Colorado Plateau. It is found both in a disseminated form in the oil shale
and in beds interlayered with the oil shale. The beds vary in purity from 30
to 90 percent nahcolite and range from a few inches to twenty plus feet in
thickness. Overlying the beds of interest, which vary from 1,500 to 2,500
feet (460 to 760 meters) below the surface, lies a large aquifer which must
be penetrated in order to obtain access to the nahcolite.
The construction techniques necessary to penetrate this highly permeable
aquifer and to operate a shaft through it constitute the largest unknown fac-
tor in the mining of the nahcolite. In recognition of this fact, the U.S.
Bureau of Mines has drilled an 8-foot (2.4 meters) diameter test shaft to a
depth of approximately 2,300 feet (700 meters) through the aquifer to the
bottom of the oil bearing shales in the area. The experimental shaft is
located in Horshoe Draw, Section 30, Township 1 South, Range 97 West about
30 miles (48 kilometers) from Rifle, Colorado. The first shaft station will
be operational by the end of 1978. This station is in the embedded layer
of nahcolite, 1,660 feet (500 meters) below ground level, and is expected
to yield 1,100 tons (1,000 metric tons) of nahcolite ore. A second shaft
station in the disseminated layer of nahcolite is expected to be operation-
al early in 1979, producing a similar quantity of ore.
44
-------
The second largest cost factor that has to be considered as differenti-
ating oil shale mining from some other mining modes is the matter of possible
explosive atmospheres. The Mining Enforcement and Safety Administration
(MESA) had tentatively assigned a "gassy" mine classification to oil shale
mining, a classification which automatically specifies certain operational
requirements for egress and .ventilation, as well as the use of equipment which
has passed Bureau of Mines "permissibility" (ability to operate in an explo-
sive atmosphere) testing schedules. During the 10th Oil Shale Symposium at
the Colorado School of Mines in April 1977, a paper was presented on the
expected dust/fume atmosphere of an oil shale mine. If these expectations
hold true, it will mean an additional 25 to 50 percent cost for underground
equipment.
Nahcolite Reserves and Mining Methods
As previously noted, the Piceance Creek Basin of the Green River Forma-
tion in northwestern Colorado contains the principal nahcolite deposits as
shown in Figure 14. The mahogany zone is a kerogen-rich oil shale layer
which overlies much of the richer nahcolite deposits. Because of the mutual
occurrence of nahcolite with oil shale and dawsonite (NaAlCOgtOH^), some
lease holders have postulated the joint mining of all three materials. This
would be of obvious benefit in developing nahcolite production.
Nahcolite Reserves-
Oil shale exploration in the Piceance Creek Basin has resulted in the
production of numerous core drillings. Based on the assays of these core
samples, the Bureau of Mines estimates the total nahcolite reserves in the
(8)
basin to be about 30 billion tons (27 billion metric tonsr • Much of this
is either unrecoverable or of very low assay; however, the total reserves
appear to be easily adequate for FGD applications.
Several organizations have developed mining plans for nahcolite, and the
potential supply should satisfy even extensive application of the dry sorbent-
baghouse system. Maximum production rates from some of the prominent com-
panies are shown in Table 4.
45
-------
TABLE 4. PLANNED MAXIMUM NAHCOLITE PRODUCTION RATES (8»22'23)
Production Rate
Tons/Year Mine Life
Organization (Metric Tons/Year) Years
Cleveland Cliffs Iron Co. 481,800 15
(Rock School Corp.) (437,080)
Industrial Resources, Inc. 2,273,000 40*
(2,062,000)
Superior Oil Co. 1,095,000 ^25+
(993,400)
*This estimate is based on the recoverable reserves in the
nahcolite bed to be developed.
This is for nahcolite-only case without coproduction of oil
shale.
The total production from the above three mines alone is sufficient to
satisfy the nahcolite demand of over thirty-five 500 MW coal burning plants
with the characteristics of the TRW base case design. If the demand develops,
there seems little doubt that the nahcolite supply will also be developed.
It should be noted that the nahcolite from the IRI mine is of high assay
(>70%) and can be sold on a run-of-mine (ROM) basis. The other two mines
produce lower assay material which requires concentration prior to sale. The
production rates given are for the as-sold nahcolite.
Mining Methods—
The conventional mining schemes proposed for use in mining the bedded
nahcolite parallel the standard room and pillar methods used for mining other
bedded deposits such as salt, potash, trona and coal. Structurally, the
pillar requirements will more closely parallel the mining of potash and trona
which are mined at similar depths. Because of the MESA assignment of a fire
hazardous situation for mining in oil shale, the entry, exit and ventilation
requirements would more close y parallel coal mining.
46
-------
'A standard mining cycle would be followed. It consists of drilling,
placing explosives and blasting; loading the ore; transporting the ore;
placing roof support; and repeating the cycle. Each of these portions of the
cycle require the exclusive use of a room to avoid interference and keep the
various crews continuously occupied. In order to keep a continuous flow of
ore to the secondary and main haulage systems, a large number of these work-
ing sections are required. At maximum production, the cycle would be expected
to produce the equivalent of two rounds (300 tons(270 metric tons)) per shift or
600 tons (540 metric tons) per section per day. Thus, with four rooms to a sec-
tion, a mine producing 10,000 tons (9,000 metric tons) per day in two shifts (245
working days per year or approximately 2.5 million tons .[2.3 million me-tric tons]
per year) would require some 17-18 working sections.
The operation of the basic mining cycle is best exemplified by a review
of the plans of Industrial Resources, Inc. (IRI) as presented to TRW by the
courtesy of their management. IRI plans to open a nahcolite mine in the area
of Township 7 South, Range 101 West, in Colorado. They plan to use a two
boom jumbo drilling rig with a Notary drill on each boom for producing forty
1-1/2 inch (3.8 cm) diameter holes for explosives detonated for each round
to be used in breaking the ore. After the ore is broken, it will be loaded
and trammed to a feeder by a seven cubic yard (5.35 cubic meter) front end
loader. From the feeder, the ore is transferred to a secondary haulage con-
veyor belt 36-inches (91 cm) in width which in turn feeds the 42-inch (107 cm)
width main haulage belt. The main haulage belt feeds both a live storage area
and intermediate storage silos (ore pockets underground) which in turn feed
into ore pockets by the shaft which load into 25 ton (23 metric tons) skips for
hoisting to the surface for crushing and/or further processing. To complete
the cycle, after the broken ore is removed, IRI plans to install high-strength
roof bolts on a 4 by 4.5 foot (1.2 by 1.4 meters) pattern in the rooms for
support of the roof during subsequent mining operations.
The Cleveland Cliffs plan also calls for a conventional vertical mine,
but the shafts are smaller (12-foot (3.6 meter) production shaft and a 7-foot
(£.1 meter) access shaft) than those for the IRI plan. The Superior plan is
significantly different in that Inclined access will be used.
47
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In the northeastern part of the Piceance Creek Basin, minable nahcolite
strata appear quite near the surface at the North Outcrop. Superior plans to
access the nahcolite by means of an 11,500 foot (3,505 meters) inclined tunnel
This plan should substantially reduce the difficulties involved in sinking a
vertical shaft through a fractured, highly permeable aquifer.
Reference was made earlier to the similarity of various mining methods.
This analogy can be carried even further in the case of potash mining in
New Mexico and Saskatchewan where the deposits were also overlain by large
aquifers. In New Mexico, a method of shaft sinking for the potash mines was
used which might prove applicable to the nahcolite deposits. In sinking the
shafts to the potash, a series of holes were drilled and cased in a circle
outside the planned dimensions of the shaft. Ammonia refrigerant was then
circulated until the entire perimeter and much of the central area was frozen
(two to three years) and the shaft was excavated through the frozen zone,
lined and sealed and then the outer area was allowed to thaw. Most of these
shafts were constructed many years ago and today it may be that chemical
grouts could provide a simpler solution though the more recent Canadian mines
also used freezing. In any case, this example points up the difficulties of
this type of shaft sinking.
Mining Capital Costs and Nahcolite Pricing
Since there is no established market for nahcolite, its selling price can
only be established by preparing a complete, detailed mine design and estimat-
ing the costs, or by analogy with similar types of mining and their costs.
Because of the inherent limits of accuracy caused by the shaft sinking situa-
tion in the oil shale area, TRW selected to develop its cost estimates by
analogy. On the other hand, Cleveland-Cliffs Iron Co., Industrial Resources,
Inc., and Superior Oil Company all used detailed mine plans in developing
their cost estimates. Consequently, the TRW estimates should be viewed as
rough checks on the validity of the other cost analyses. The various cost
estimates are summarized in Table 5.
Previous work by TRW established the costs of mining thick bedded coal
by conventional room and pillar methods at $9.28 per ton ($10.23 per metric ton)
without a shaft. Recent work by Bechtel for the U.S. Bureau of Mines
48
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TABLE 5. MINE DEVELOPMENT COSTS AND NAHCOLITE PRICES
•£>
VO
Organization
Cleveland-Cliffs Iron Co.1"
a
Industrial Resources, Inc.
Superior 011 Co.**
TRW-Coal Analogy
TRW-Hanure Salts Analogy
Production
Tons/Yr
146,000
321 ,000
482,000
500,000
1 ,000,000
2,273,000
1,095,000
2,500,000
2,500,000
Rate*
(Metric Ton/Yr)
(132,000)
(291, 000) S
(437,000)S
(454,000)
(907,000)
(2,062,000)
(993,000)
(2,268,000)
[2,268,000}
Reproduction
Costs
$ 8,727,000
9,316,000
9,316,000
$28,370,000
35,770,000
44,030,000
$40,000,000
$12,000,000
12,000,000
Sales
S/Ton
25-30
20-30
20-30
35
25
17
Price, F.O.B. Mine
(S/Netrlc Ton)
(28-33)V
(22-33)V
(22-33)7
(39)
(28)
(19)
Not available
10.30
13
(11.35)
(14)
*Th1s is the rate for salable material, not necessarily the same as the gross mine output.
fThese data were provided through the courtesy of Mr. J.H. Smith, Rock School Corp.
The ranges result from differing assumptions regarding depletion allowances and return-on-investment.
These production rates are based on the same physical plant, but the lower rate is a 2-shifts per day basis and
the higher is a 3-shifts per day basis.
fThese data were provided through the courtesy of Mr. Jacques Dulin, Industrial Resources, Inc.
**These data were abstracted from reference (8).
-------
estimated the costs of shaft sinking to the appropriate depth at approximately
$4 million in stable ground with no problems. Factoring this amount to allow
for unstable ground and adding the costs for the necessary headframe and
hoists leads to a total of approximately $12 million. A discounted cash flow
analysis with a 15 percent rate of return yields, over a 20-year mine life,
approximately $1.00 per ton ($1.10 per metric ton) in additional add-ons to the
selling price for a total price of $10.30 per ton ($11.35 per metric ton) F.O.B.
the mine.
Potash is normally sold after processing for potassium chloride which is
presently selling at $0.65 per unit (KgO) or $39 per ton ($43 per metric ton).
Manure salts (20% K20) is sometimes sold for a flux in the metals industry. It
is a run-of-mine material with a minimal amount of processing (similar to
crushed nahcolite) and sells for approximately a KgO equivalency with the KC1
or $13.00 per ton ($14.33 per metric ton) F.O.B. the mine.
Both of these industries are mature and highly competitive with under-
ground coal mines competing with strip mining costs and the oversupply of
potash from the Canadian mines driving that market.
Given these situations and the fact that a start-up industry such as
nahcolite mining must command greater than a 15 percent discounted cash flow
rate of return in order to attract capital,'it would appear that the IRI
estimates for a 2.3 million ton per year (2.1 million metric ton per year) mine of
$17.00 per ton ($18.75 per metric ton) are reasonable. This is_in good agreement
with the Cleveland Cliffs sales price estimates ($20-30 per ton ($22-33 per metric
ton)) when one considers the lower production rates of the latter operation
and the higher assay product (^80%). As the nahcolite Industry matures, it
is reasonable to expect the price to be driven downward.
Conclusions
In summary, nahcolite has the following advantages for use in the pro-
posed baghouse flue gas desulfurization system:
• The material has good operational characteristics
in the system.
50
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• There are enormous nahcoUte reserves, sufficient
for any foreseeable F6D applications.
• The potential selling prices from various sources
are reasonable for FGD use.
The major disadvantages of nahcolite with regard to economics are:
• The material is not currently being mined.
• None of the major nahcolite deposits are easily
accessible, and large capital investments will
be required for mine development.
The preceding disadvantages pose a dilemma for application of nahcolite
to FGD:
o The nahcolite- lease holders cannot proceed with
mine development without an assured market.
9 Potential nahcolite consumers cannot commit them-
selves to the installation of nahcolite-baghouse
FGD systems without a guaranteed supply.
Overcoming this situation will likely require either third party—Federal
government—involvement or the formation of consortia of either sellers or
buyers. In view of the capital requirements and the many technical unknowns
involved in opening a mine for nahcolite, a guarantee to the mine developer(s)
is not an unreasonable requirement. IRI has stated that a guaranteed market
of 500,000 tons/year (450,000 metric ton year) would be sufficient to open
a mine, but_this figure is dependent on the economic conditions.
WASTE DISPOSAL
Composition and Quantity of Baghouse Wastes
Baghouse filter cake from dry process FGD with nahcolite is composed of
spent nahcolite and fly ash. Table 6 compares the composition of nahcolite
ore with the expected composition of spent nahcolite. Since the reactions of
desulfurization^11'—NaHCOg conversion to Na2C03, substitution of S02 to form
Na2S03, and Na2S03 oxidation to NagSO^-- average only 70 percent completion
under FGD conditions, both reactants and products are present in the spent
51
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TABLE 6. COMPOSITION OF RAW AND SPENT NAHCOLITE
(2)
Raw Nahcolite % Dry
Constituent Weight
NaHC03 70
Na2C03 _3
SUBTOTAL 73
MgC03 3
H20 - 2
Other Materials 22
CaC03
Si02
A1203
Fe2°3
FeS2
Na20
K?0
£f
Organic Sulfur
Organic Carbon
TOTAL 100
Spent Nahcolite
Constituent
NaHC03
Na2C03
Na,SOo
£ O
Na2S04
SUBTOTAL. . . .
MgC03-MgS04
H20
Other Materials
CaC03
Si02
A1203
Fe203
FeS2
Na20
K20
Organic Sulfur
Organic Carbon
TOTAL
% Dry
Weight
1
17
35
14
... 67
4
2
27
. . 100
52
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nahcolite. Levels of NaHCOg are low 1n the spent nahcolite while Na2C03
levels have increased because the formation of Na2C03 is nearly 100 percent
and proceeds much faster than subsequent reactions with sulfur.
On a dry weight basis the total percentage of sodium compounds in spent
nahcolite is about six percent below the percentage of sodium compounds in
nahcolite ore. This weight loss is due to the evolution of C02 and H20
during reaction with S02. With a raw nahcolite utilization rate of 30,000
Ibs/hr (13,600 kg/hr), 24,700 Ibs/hr (11,200 kg/hr) of spent nahcolite are
generated.
The main constituents in the fly ash portion of baghouse filter cake are
Na20, KgO, CaO, MgO, BaO, carbon, Fe203, S, A1203> Si02, Ti02, and P205.
Minor constituents include mercury, zinc, selenium, cadmium, and nickel.
With a 4.3 x 105 Ibs/hr (2.0 x 105 kg/hr) coal utilization rate, 10 percent
ash content in the coal, and 85 percent of total ash released as fly ash,
36,500 IDS (16,600 kg) of fly ash are generated per hour. The total quantity
of waste produced per hour from nahcolite F6D is 61,300 Ibs (27,800 kg); 40
percent is spent nahcolite, and remaining 60 percent is fly ash.
Table 7 shows the rate of baghouse filter cake generation on an hourly,
daily and yearly basis. The uncompacted volume refers to the volume occupied
by the baghouse filter cake as it is discharged from the storage silo. The
o
density of the uncompacted waste is 40 Ibs/cu ft (640 kg/m ). The compacted
volume is the volume of the waste after compaction in a landfill. Dunlin
and Rosar^1*) indicate a density of 74.3 Ibs/cu ft (1,190.2 kg/m3) for com-
pacted waste. Each year the planned 500 MW FGD system, then, will generate.
214,200 T (190,000 metric ton) of baghouse filter cake with a compacted volume
of 5.85 million cu ft (163,000 m3).
Comparisons of Wastes from Dry Process FGD with Nahcolite and Wet Process FGD
with Alkali Scrubbing
The study of disposal of wastes from dry process FGD with nahcolite
Injection began with a study of available techniques for disposal of wastes
generated by wet process FGD systems as well as research and development on
disposal of wet process wastes. The purpose of the review of wet process
waste disposal was to identify technologies which could be applied to the
disposal of the baghouse filter cake, to determine areas where the problems
53
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of disposal for the two types of wastes were similar and dissimilar, and
finally to use the degreee of environmental protection achieved by wet
process disposal systems as an indication of the denree of environmental
protection needed for the dry waste.
One important difference in the waste qenerated by wet and dry process
FGD systems is the water content. The dry process waste contains a maximum
of two percent water while the water content of the wet process scrubber
sludqe is approximately 50 percent. As shown in Table 8, the wastes also
differ in solubility. Scrubber sludqe from lime/limestone systems is
primarily calcium sulfate with a relatively low solubility of 2 q/1.
Approximately one percent of the sludqe is MqSO^, however, which is hiqhly
soluble (260 - 700 g/1). The solubility of sodium compounds 1n spent nahco-
lite varies from 48 q/1 to 700 g/1. Although dry material is more easily
disposed of on land, this is balanced by the fact that the sodium comoounds
of the dry process waste are approximately 100 times more water soluble than
the calcium compounds.
The quantities of waste generated in the dry FGD system are qreater
than quantities produced in lime/limestone scrubbinq systems primarily
because the products of desulfurization as well as fly ash are contained in
the waste. In many lime/limestone systems fly ash is removed by electro-
static precipitation prior to desulfurization. The two wastes are disposed
of separately. In dry process FGD with nahcolite, fly ash and spent nahcolite
are not separated, and the entire material must be disposed of according to
the requirements of the sodium constituents. On a dry weight basis the
lime/limestone scrubbinq wastes are approximately 40 percent of the dry
process baqhouse wastes. On a wet weiqht basis lime/limestone scrubbinq
wastes are much closer in weiqht to dry process wastes due to the hiqh
water content of the scrubber sludqe.
Both lime/limestone scrubber sludqe and baghouse wastes contain heavy
metals. This is due to heavy metals in the fly ash. The heavy metal content
is higher in dry process flue gas desulfurization due to the higher ( 60
percent) fly ash content.
54
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7,000 Hr. Year
TABLE 7. RATES OF WASTE GENERATION
Unit of Time
Hour
24-Hour Day
Baghouse Waste
Wt. Generated
30.6 T
(27.8 metric ton)
735 T
(667 metric ton)
Uncompacted
Vol ume
1,530 cu ft
(43.3 m3)
36,700 cu ft
(1,000 m3)
Compacted
Vol ume
820 cu ft
(23 m3)
19,800 cu ft
(560 m3)
214,200 T
10,710,000 cu ft
O
(194,300 metric ton) (300,000 m )
5,770,000 cu ft
(163,00 m3)
TABLE 8. SOLUBILITIES OF SOME WASTE MATERIALS IN
SPENT NAHCOLITE AND SCRUBBER SLUDGEt9'
Waste Material
Compound
Solubility
(Grams/Liter of Water)
Spent Nahcolite
Lime/Limestone
Scrubber Sludge
NaHS03
NaS03
Na2S03
7H20
Na2S04 (Thenardite)
Na2S04
7H20
Na2S04 • 10H20 (Mirabilite)
MgS04
MgS04 • 7H20 (Epsomite)
CaS04 • 2H20 (Gypsum)
MgS04
MgS04 • 7H20 (Epsomite)
Very Soluble
125
328
48
195
110
260
710
2.4
260
710
55
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Although relatively little research has been conducted on disposal of
spent nahcolite and fly ash, research on methods for disposal of sludge from
lime/limestone FGD has been under way for several years. These procedures
were reviewed for their potential application to spent nahcolite/fly ash
waste disposal and to determine the degree of environmental protection that
would need to be achieved in disposal of spent nahcolite/fly ash. (For a
summary of spent scrubber sludge disposal research and development, the
reader is referred to the 1974 and 1976 Proceedings: Symposium on Flue Gas
Desulfurization' ' '.) From this review it was determined that very little
information from scrubber sludge disposal techniques is directly applicable
to disposal of dry process wastes. Insolubilization and disposal techniques
for scrubber sludge have been developed in response to three properties:
• High water content (50 percent)
• Difficulties in dewatering
• Relatively low solubility of CaS04
The low water content (<2 percent) and high solubility of spent nahcolite
preclude the use of most techniques for scrubber sludge.
Also, the degree of environmental protection achieved by various
disposal processes for wet scrubber sludge was not a useful guideline for
spent nahcolite/fly ash disposal. At the present time, research, develop-
ment, and demonstration of several scrubber sludge disposal techniques is
being carried out. A review of these techniques and discussions with
experts in scrubber sludge disposal^ ' indicated that no consensus has
been reached on what degree of environmental protection is acceptable.
Specific disposal techniques compared included land disposal, ocean
disposal, mine replacement, and insolubilization techniques to reduce the
concentration of leachate residuals. The associated land fill designs
generally allow for some leachate migration from the site. Because of the
high solubility of the waste, complete containment is required for spent
nahcolite/fly ash wastes.
Ocean disposal has been considered for both scrubber sludge and baghouse
filter cake. Jones" ' identified four environmental concerns related to
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ocean disposal of scrubber sludge: 1) ocean floor sedimentation—Particle
sizes of scrubber sludge are much smaller than the naturally occurring
coarse-grained sand particles which are most conducive to the marine life
found on the continental shelf; 2) an Increase 1n levels of suspended solids
1n the water column; 3) sulflte toxldty and COD—COD 1s created by oxida-
tion of sulflte 1n the waste to sulfate, and 4) the presence of trace
elements such as mercury, zinc, selenium, cadmium, and nickel in concentra-
tions 1n excess of acceptable levels for the marine environment.
For nahcolite/fly ash wastes ocean floor sedimentation would also be
a problem. The sediment would largely reflect the small particle size of the
fly ash component; the sodium compounds in spent nahcolite are expected to
dissolve quickly.
The possible increase in suspended solids in the water column near the
disposal area would also be due primarily to fly ash. With the small
particle sizes of fly ash, some difficulties in settling would be expected.
The problem of suspended solids would be about equally significant to both
scrubber sludge and baghouse filter cake.
The problems of sulfite toxicity may be more significant with spent
nahcolite/fly ash waste. Approximately 15 percent of the baghouse filter
cake will be sodium sulfite. Trace element contamination in both types of
wastes is primarily due to fly ash.
When comparing ocean disposal of wet process and dry process FGD wastes,
the environmental problems are similar, although the sulfite toxicity is a
more significant problem in the dry process waste. Sulfite content may be
reduced by increasing the temperature of the flue gas stream and/or by
increasing the reaction time "» '. Further study is needed to evaluate the
sulfite toxicity problem and to determine under what conditions, if any,
ocean disposal of spent nahcolite/fly ash would be advisable.
The techniques for mine disposal of wet process sludges are significantly
different from dry process techniques and offer little useful information.
Some of the problems encountered in a wet process system are leachate from
the mine disposal site and stability of the material. The techniques for
57
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insolubilization of lime/limestone scrubbing waste are also not transferable
for dry process waste.
In summary, research, development and demonstration of techniques for
disposal of lime/limestone sludges are still being carried out. No set of
criteria for disposal,which could potentially give guidance to baghouse
filter cake waste,has been devised. No disposal method is considered totally,
environmentally,and economically acceptable for scrubber sludges. Therefore,
the experience gained in scrubber sludge disposal can only provide some
indication of avenues to explore and possible problems to be aware of.
Guidelines for Disposal/Reuse Investigations
The following assumptions were established to provide a framework from
which disposal options were assessed: 1) Surface runoff and leachate to
groundwater would need to be avoided in any acceptable disposal technique
since leachate from the untreated waste would contain high concentrations
of sodium compounds,and 2) Due to the nature of the waste few techniques and
possibly no technique would be suitable (environmentally and economically)
for all areas of the United States, i.e., techniques for disposal of spent
nahcolite/fly ash tend to be site specific.
Waste Disposal Options - General
Open Dumping, Discharge to Surface Streams, and Deep Well Injection-
Open dumping and discharge of wastes to surface streams were considered
inappropriate for disposal of nahcolite/fly ash. Due to the high solubility
of the waste material, levels of dissolved solids in leachate would exceed
existing water quality standards.
Deep well disposal has been used for several types of waste materials.
Further research is needed to determine the feasibility of deep well disposal
for spent nahcolite. In addition to the common problems of deep well
disposal--creating high subsurface pressures, and controlling the migration
of injected wastes—problems specific to spent nahcolite deep well disposal
include the large volumes of the waste and the need for slurrying.
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Disposal in Brine Ponds--
Discharge of spent nahcolite waste materials to brine ponds may be envi-
ronmentally acceptable. These ponds contain high concentrations of several
of the compounds in spent nahcolite. The primary drawbacks to this method
of disposal are that it is highly site specific and would probably not be
able to accept the typically large quantities of baghouse filter cake generated.
Brine pond disposal is probably feasible only for those few small power plants
that are located adjacent to a brine pond.
The use of other water catchment basins such as playa lakes and dry desert
basins as disposal sites present significant environmental problems. The surface
of such basins is generally porous; leachate from spent nahcolite/flyash would
potentially increase salinity and trace element levels in the ground water.
Ocean Disposal —
As was discussed in the section comparing scrubber sludge and spent nahcolite
disposal, ocean disposal of baghouse filter cake has several environmental problems
and requires further study to determine its appropriateness for spent nahcolite/fly
ash. The sulfite content is the most significant of the potential problems. Sodium
sulfite is toxic to certain marine organisms and also can be expected to reduce
oxygen levels in the disposal area through oxidation of sulfite to sulfate. Research
would be needed on ways to reduce sulfite concentrations in spent nahcolite. Studies
would be needed to determine whether any-dispersed disposal techniques would reduce
the sulfite toxicity problem.
A second consideration is that the cost of ocean disposal will reflect the
large shipping costs associated with the transfer of the spent nahcolite/flyash mix-
ture from its most applicable location to the nearest ocean. At a shipping rate of
1% per ton-mile this would increase the plant operating cost approximately 0.065^/KW.
Mine Replacement--
Although the high solubility of spent nahcolite/flyash precludes its use as
fill material in worked out strip mine areas, replacement of the spent waste
in worked out areas of nahcolite ore mines is a promising technique for disposal.
The geological characteristics of areas where highly soluble nahcolite ore
exists would also provide adequate protection from ground and surface waters.
Mine replacement of spent nahcolite may be a means of avoiding subsidence in
worked out areas. Economics may be favorable since costs of site preparation
59
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will have been borne by the mining operations. Empty cars returning to the mine
site foV nahcolite ore can be used to transport the spent nahcolite/flyash and
thus reduce transportation costs.
Potential problems include the following: 1) With the small particle
size of fly ash, dusting will be a significant problem. Techniques such as
wetting the waste material may be required to control this problem, but
wetting of the waste may not be desirable due to high solubility. 2) The
fact that in most cases nahcolite is mined simultaneously with oil shale
reduces the feasibility of mine replacement. Nahcolite usually exists as a
layer above or below shale, and the cavern created by mining activities may
make replacement less feasible. 3) Disposal quantities of spent nahcolite/
fly ash are approximately twice the amount of nahcolite ore injected into
the FGD system. Additional cars will be required to return the waste to the
mine site, and at the most only one-half of the FGD waste could be replaced
in the mine. Mine replacement is therefore only a partial disposal solution
at best, and some additional means for disposal or reuse of the waste would
also be needed.
Land Fill Disposal —
Land disposal is one of the most widely practiced techniques for dis-
posal of waste material. Advantages are generally low costs for disposal
where land costs are low. By varying site designs, degrees of protection
of surface and subsurface water can be achieved.
For spent nahcolite/fly ash the problems with land disposal are as
fol1ows:
1. Avoiding any contact with water during or after burial
1n a landfill—Due to the high solubility of the waste,
landfill leachate or groundwater 1n contact with the
waste could easily have a dissolved solids content of
50,000 mg/1 (see Table 8). Current standards for dis-
solved solids range from 50-250 mg/1. Also, ground-
water contact with the waste or water percolation
through the waste would be expected to seriously de-
crease the stability of the waste.
60
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To guard against groundwater penetration, the lowest
level of the landfill should be approximately 10
feet about the 100 year high level of the water
table. During disposal activities contact with
rainfall or snow must also be avoided.
Since rainfall runoff may percolate into the waste,
the area selected for land disposal of spent
nahcolite/fly ash would need to be away from sur-
face streams and free of temporary water tables
close to the surface. Surface contours and berms
would be required to directed runoff from adiacent
areas away from the disposal site.
2. Area runoff—Spent nahcolite/fly ash falling on
surrounding areas during waste transportation and
disposal can cause area runoff to contain high
concentrations of COD and dissolved solids.
3. Impermeable subsurface barriers—It is difficult
to ensure the impermeability of subsurface barriers.
Concrete, asphalt, butyl rubber, hypalon, vinyl,
and clay are among the materials used to line the
bottoms of landfills. None of these can seal a
landfill indefinitely. For example, asphalt and
concrete are sufficiently porous to allow the
passage of small quantities of water. A typical
rate for concrete is 25 pints/sq yd/yr. Also
cracking is a problem with both asphalt and concrete.
Rubber, polyethylene and vinyl will effectively
prevent leachate from leaving a disposal site;
however, the thinness of these materials renders them
susceptible to rupture by heavy equipment during
the disposal operation*
4. Determining when a subsurface barrier fails--
General ly observation wells located around the
61
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perimeter of a site are used to monitor for landfill
leachate and thus indicate barrier failure. However,
these wells do not monitor the groundwater beneath
the disposal site. Much of the area where barrier
failure may occur is actually not monitored.
5. Barrier repair— Once a subsurface barrier has
failed, repairs are time-consuming and costly
because the waste above the repair site must be
removed. Due to the large quantities of FGD
wastes involved in the present study, barrier
failure and repair could be a significant problem.
Although the above problems are important, they are not insurmountable.
In certain instances, landfill disposal is an environmentally appropriate
technique. Land disposal of spent nahcolite fly ash is best suited to arid
and semi -arid areas.
Insolubilization by Aqueous Coprecipitation ( "Persona " Process )--
Dulin et al.^12^, have demonstrated the feasibility of insolubillzing
sodium suTfate by coprecipitation with acid ferric ions to form the insoluble
double salts, natrojarosite and sideronatrite. The double salts produced are
less soluble than calcium sulfate and do not tend to form sludges since the
precipitate is generally an easily dewaterable granular crystalline solid.
The greatest drawback to this technique is the availability of the acidic
iron solution for use in the coprecipitation process. Copper smelter/cement
copper operations do have an iron-rich barren liquor which can be coprecipi-
tated with spent nahcolite to produce natrojarosite and sideronatrite.
Additional sources of acidity and ferric ions may be sulfuric acid from flue
gas side streams and iron values in fly ash or bottom ash, waste acid mine
water such as black water or gob leachate which typically contains both
sulfuric acid and ferric ion values, and other waste from various industrial
processes.
Insolubilization by Dry Sintering ("Sinterna" process )--
Dulen et a1.v fcy, report that the solubility of spent nahcol1te/fly ash
waste can be reduced to below that of gypsum by pelletization of the waste
62
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material and sintering. The typical-solubility range is 50-1000 mg/1 of
sodium. The solubility of the sintered pellet increases as the proportion of
spent nahcolite increases. Dulin et al.'12', report that no trace elements
were detected in the leachate. Some evolution of S02 does occur during
sintering; quantities released have ranged upward from 0.4 percent of the
starting materials. The sintered product has approximately twice the density
of compacted baghouse filter cake, i.e., 155 Tbs/cu ft (2483 kg/m3).
Disposal of the relatively insoluble sintered pellets would probably
require less stringent measures for leachate control although some protection
from the environment would be needed. The material would probably require
contouring to facilitate runoff and a final surface cover of clay. Vegeta-
tion could then be planted on the surface and the land could be recovered for
a multitude of uses such as parking lots, parks and buildings. The landfill
area should be protected from groundwater. The sintered pellets would also
be suitable for disposal in strip mining sites. Possibilities for use as a
product include concrete aggregate and road bed base.
Except for economic constraints, land disposal of sintered pellets
appears to be widely applicable. In arid areas the sinterna process may be
non-competitive with disposal of untreated baghouse waste in clay isolation
cells. Estimates in 1976 of costs for the Sinterna process on an annual
basis are $8.50/T. This figure does not include costs for waste hauling and
disposal, and for the minimal amount of land contouring that would probably
be required.
Methods for Recovery/Use as a Product—
In each of these cases below, the applicability of the spent nahcolite/
fly ash is limited but appears promising in certain site-specific situations.
Pulp and Paper Mills—In some cases spent nahcolite may be used by a
d?}
craft paper plant for bleaching purposes11 '. Because the filter cake is
fly ash contaminated and because the market is small only a small part of
the dry FGD waste could be used in this way.
Glass Manufacturing—The spent nahcolite and glass batch fines collected
in a baghouse of a glass manufacturing plant may be recycled to the glass
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batch. Nahcolite gangue material (silica, alumina, Ca/MgCO,, potassium,
feldspars, and analcime) is compatible with glass*batch formulations.
Further,glass manufacturing requires sodium sulfate. As glass manufacturing
facilities change to coal-fired furnaces this process will become more
attractive. The flue gases would contain more SOp and ash fines if coal were
to be used. The process is potentially a closed loop system since the wastes
from -S02 emissions are directly used in glass manufacture. Glass manufactur-
ing facilities can accept more spent nahcolite/fly ash than would be gener-
ated on site; however, a consistent composition of the material would be
required for glass batch formulation.
Integrated Pyrometallurgical Copper Smelter/Cement Copper Facility—In
an integrated pyrometallurgical copper smelter/cement copper operation spent
nahcolite would be used to reduce the iron content of one of the process streams
and in the process would be converted to less soluble material. Soe.cifi-
cally, spent nahcolite is forwarded to the cement copper operation where it
is reacted under oxidizing conditions with the ferrous ions in the "barren
liquor." The sodium compounds in spent nahcolite are coprecipitated as the
insoluble double salts sideronatrite and natrojarosite. The liquor, now
free of ferrous ion, is returned to the leach dumps. Using sodium sulfite/
sulfate waste in this manner would actually create a leaching liquor of
greater reaction efficiency due to the lower concentration of iron salt in
the solution. From the standpoint of the baghouse waste material the con-
version products, sideronatrite and natrojarosite, are disposed of via
landfill.
Waste Disposal - Specific
From the general review of waste disposal methods, it was determined
that most methods are site specific. This led to'a study of the disposal
methods that could be used in the mid-western region of the U.S. where
construction of the test facility is recommended. Climate, geology, and
facility size are important determinants of appropriate disposal methods.
The Mid-west is typically a semi-arid region with rainfall of 20 inches
(0.5 m) or less per year and a water table at 50 ft (15 m) or more below the
surface. Common plant communities include short grass prairie and creosote
64
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bush. Soil types range from sandy to clay; the soil varies from slightly
to highly alkaline.
Of the disposal methods discussed in the previous section, the following
were considered most appropriate for the type of waste and the region:
• "Sinterna" process and land disposal
• Land disposal without insolutilization
• Mine replacement
• Integrated copper processing
Of these, burial in clay isolation cells and insolubilization via briquetting
and sintering ["Sinterna" process) followed by land burial were given in-
depth consideration. Although promising, use in an integrated copper
processing facility was too site specific to be given further study. It
was felt that not enough was known about nahcolite mining methods, distance
of test facility from mine mouth, and so forth to allow further consideration
of mine replacement at the present time.
Burial in Clay Isolation Cells—
The general discussion of disposal methods lists several potentially
serious environmental problems which must be addressed if land burial of
waste material is planned. Svec, et al.^16^, EPA^17^, and TRW^18^, along
with many others have documented damage to land, surface water, and ground
water due to the improper use of land disposal methods. Since no commonly
used landfill design adequately addressed all potential environmental
problems, a new design is suggested for disposal of spent nahcolite/fly ash.
Site Requirements—Because of the high solubility of the spent
nahcolite/fly ash waste material it is imperative that the water table be
at least 10 feet (3 m) below the bottom surface of the landfill; this level
for the water table should represent the one hundred year high point. The
site must also be free of surface streams flowing on either a continuous or
an intermittent basis. Although soil at the disposal site can in fact be of
any kind, fill will be locatec in a clay soil.
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Recommended Landfill Design—The only suitable land disposal method is one
that avoids ground water and surface contamination by keeping the waste from
contacting water during and after disposal operations. If this difficult task
is accomplished, there will be no leachate generated and hence the waste will
be successfully isolated. The recommended landfill design does not employ a
subsurface barrier due to difficulties in maintenance and due to difficulties
in determining when a barrier has been penetrated. Instead of a subsurface
barrier, a barrier across the surface of a finished cell has been utilized.
A surface barrier allows for routine and frequent inspections for barrier
failure, and any needed repairs can be made quickly and economically without
disturbing the waste. Replacement of the barrier can take place as needed
and the perpetual maintenance necessary to insure that the waste does not con-
taminate ground water or surface water is possible. The landfill can also be
located in virtually any kind of terrain, i.e., not necessarily in clay slice
no leachate will be generated. The landfill will also maintain its integrity
even during mild geological disturbances as long as a major shift in the water
table does not occur. This technique for land disposal successfully addresses
each of the central environmental problems for land disposal stated in the
previous sections, provided that this landfill design is accompanied by land
siting which provides protection from ground water and temporary perched water
tables.
To keep the waste dry durrlng disposal operations, the clay isolation
concept was utilized. We have used a slight modification of the trench
method" ' although the basic concepts of the design could also be applied
to the area method or to an area-trench combination method. The trench
method was chosen because the specific surface contours of the disposal site
are not known. As is shown in Figure 15 the floor of the excavation site
is tilted to one corner. This is to direct rainfall to one point where the
water can be pumped to an evaporation pond. (Periodically, the residue will
be removed from the pond and replaced in the disposal site.) The difference
between points A and D is 18 ft (5.5 m). During disposal operations this
slope will be maintained. Whon a cell is completely filled, final grading
will be done to achieve the contour shown.
66
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490'
S V M / _
^
80'!
1 1
.,-/
A
t ;
62' ,.'
K
-
>-*--- • 4
>B .j.
75'
1
s
^
€
Scale: 1/10" = 10'
FIGURE 15. DIMENSIONS OF FINISHED LANDFILL CELL
The basic building block for the landfill is the clay isolation unit.
The waste material generated from one day's operation will be transported to
the site, compacted, and covered with a one foot layer of clay which is also
compacted. This forms the clay isolation unit. Thus, each day the soluble
sodium sulfite is encapsulated in an essentially impermeable cell of clay.
It is important that the clay soil material have low permeability so that any
rainfall will run off of the sloping surface rather than penetrate the ma-
terial. As subsequent units are added to form a layer, the height of a unit
constitutes a layer height.
When the sodium waste is delivered to the landfill operation by truck,
it is dumped at the toe of a previously finished cell. A crawler dozer
spreads the spent product up at a 30 degree slope to the previous cell. The
thickness of the spread layer is kept less than 1-1/2 ft (0.3-0.5 m) in order
to obtain better compaction by the tractor dozer. At least five passes by
the tractor are required over the spread material in order to assure greater
volume reduction. For each truckload, the material is handled in the same
67
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manner. By the end of the work day, the unit (containing 735 T (667 metric ton)
of waste) will have a trapezoid cross section approximately 13 ft (4.0 m) high,
18 ft (5.5 m) wide, and 87 ft (26.5 m) long, as shown in Figure 16. The cell
is covered with 1 ft (0.3 m) of compacted clay-Uke material.
FIGURE 16. TYPICAL CLAY ISOLATION
For one landfill cell, a total of four layers are employed, and the
final cover for the top will be a compacted thickness of 3 ft (0.9 m) of
soil with the butyl liner installed above the clay. A butyl liner was
selected because of its guaranteed resistance to the effects of weathering
over a minimum of 20 years.
Because of the importance of keeping the material dry, disposal opera-
tions will cease during rainfall. A silo with 8 days storage capacity has
been planned so that ample time will be allowed for covered storage during
rainfall and the subsequent drying periods.
Figure 17 shows a cross-section along the length of one finished land-
fill cell. Each of the trapezoidal shaped squares represents one day's
operation, one unit. Line AB~ represents the flat surface of the surrounding
area and shows that the surface of the landfill is sloped to a center point,
E. Line CD is parallel to the surface and indicates the slope of the floor
of the landfill. For every 20 ft (6.1 m) of length, there is a 1 ft (0.3 m)
downward slope of the landfill floor. Also, the floor of the landfill is
tilted 1 ft (0.3 m) for every 20 ft (6.1 m) of width.
The sloping floor somewhat increases the complexity of this landfill;
however, this is simplified by the fact that once the slope is achieved, the
contour is maintained throughout the first three levels of filling. The
68
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Scale: 1/16" = 4'
FIGURE 17. LENGTHWISE VIEW OF FINISHED LANDFILL CELL
-------
tilting of the floor is then changed in the fourth and final level to create
the final surface contour as shown in Figure 17.
There are several ways that each landfill cell could be filled. For
instance, the first level could be completely filled before the second layer
is added. This method of filling is not recommended because, to the extent
possible, the rainfall should collect in an area where there is no fill ma-
terial. The 4-day sequence plan shown in Figure 17 has been chosen. This
is based on placing 4 cells across the bottom of the landfill and then fill-
ing above these 4 areas for 4 subsequent, 4-day periods. At the end of
slightly over 2 weeks then the first subcell of the landfill will be complete-
ly filled with waste material and final contour developed. The next 4 days of
operation will then be placed on the bottom of the landfill and the process
repeated. This will continue until the entire site has been filled.
When a site has been filled and the final contouring accomplished, the
lining material of butyl rubber will be installed across the surface. The
lining material will be secured by sandbags placed at 3 ft (0.9 m) intervals
across the surface. The lining material will be inspected as needed for signs
of failure. The expected lifetime for a butyl liner is a minimum of 20 years.
Sandbags and liners will be replaced as needed.
One landfill cell will require approximately 1 acre (0.4 hectare) of
land. About 71,000 tons (64,400 tonne) of spent nahcolite/fly ash can be
placed 1n one landfill cell. This represents approximately 1/3 of the annual
amount of waste generated by the 500 MW test facility. Therefore, 3 acres
(1.2 hectares) of land per year would be required for land disposal of the
spent nahcollte/fly ash. A minimum of 60 acres (24 ' hectares) would be re-
quired for a plant with an expected 20 year life.
Surface Contours at the Disposal Site—To prevent the entry of runoff
from adjacent areas Into disposal sites, a protective berm 1s constructed
around the perimeter. The area outside of the berm is graded as needed to
direct runoff away from the disposal area. Within the berm, the surface would
be contoured to direct runoff water to the evaporation pond. The evaporation
pond would be of sufficient size to accept all water falling to the area.
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Environmental Assessment—The surface sealing method for disposal of
spent nahcollte/fly ash eliminates the problems of ground water and surface
water contamination. Two environmental effects remain. First, the water
that falls onto the disposal area will be prevented from" reaching the
water table and to that extent will reduce the level of the water table.
Because the area involved is relatively small, this effect is expected to be
insignificant. Second, the land will be unavailable for use for other pur-
poses. The waste would be easily retrieved for conversion to other useful
products, however.
Insolubilization by Pelletization and Sintering - "Sinterna" Process-
As described in the general discussion of disposal methods, the solubil-
ity of spent nahcolite/fly ash waste material may be significantly decreased
by the application of the "Sinterna" process. The solubility is decreased
approximately three orders of magnitude; the solubility range of the sintered
pellets is 50 - 1,000 mg/1. In the arid/semi-arid area under consideration
In this study where the material could be disposed of on the surface in large
piles with runoff directed to a large evaporation pond. Alternatively, the
sintered pellets could be disposed of by more conventional landfill techniques.
Daily soil cover would still be necessary to minimize water penetration and
dusting.
Economics
In determining the cost for disposal of spent nahcolite/fly ash waste
material, it was assumed that the power plant would own the land needed for
disposal and that the roads leading to the disposal area are in place.
Land Disposal in Clay Isolation Cells-
In order to determine costs for land disposal, the following landfill
operating conditions were assumed:
t A disposal site location within 15 miles (24 kilometers)
t A 7 day, 8 hour per day operating schedule
0 6 hours of average daily operation for each vehicle
Table 9 shows the breakdown of capital and operating costs. The
capital costs are low since land and road msts are not included and since
71
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TABLE 9. CAPITAL AND OPERATING COSTS FOR LAND DISPOSAL*
Capital Operating
Costs Costs
(Actual (Actual
Item Dollars) Dollars)
Site Preparation
Fence 24,200
Administration Building 25,000
Maintenance Building 25,000
Well 5,000
Pump 2,000
Fuel Tank and Pump 5,000
SUBTOTAL 86,200
Waste Hauling
Tractor Rentals, 5 Ea. 108,000
Trailer Rental, 4 Ea. 27,700
Maintenance 10,000
Fuel 23,100
Personnel (8), Including Fringes & 30% 178,000
SUBTOTAL 346,800
Excavation and Filling
Equipment Rental 388,800
Fuel 35,000
Maintenance 12,000
Personnel (18), including Fringes @ 30% 400,000
SUBTOTAL 835,800
Liner
Installation 1,200 7,000
Butyl Rubber Liner Material 79,700
Contingency, 20 Year Basis 30,000
SUBTOTAL 1,200 116,700
TOTAL CAPITAL COSTS 87,400
TOTAL ANNUAL OPERATING COSTS .1,299,300
*Based on a 500 Mw plant, 7000 hrs/year operation, burning 1,0% sulfur coal
with a heating value of 10,500 Btu/lb.
72
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all trucking and excavating equipment costs are based on lease arrangements.
Of the total cost per ton for disposal, only $0.02 is due to capital costs.
The operating costs are due primarily to equipment* manpower, and
liner costs. The first step in determining equipment costs was to determine
the size of equipment needed. One of the determining factors for equipment
size was the storage silo. It was estimated that a minimum of 10 minutes
would be needed for bringing a truck in, loading, and pulling away from the
storage silo. A 30 percent factor was then added to total 13 minutes.
Assuming a 6 hour day for hauling, 28 trailers could be loaded each day.
Based on an average daily generation of 750 T (680 metric ton), each load would
weigh 27 T (24metric ton). Since the 15 mile (24 kilometers) round trip to the
landfill was estimated to take 50 minutes, 4 waste hauling vehicles were
used. Equipment costs were determined by receiving quotes from venders.
Large scale, off the road equipment is used for waste hauling. As is shown
in Table 10, 4 tractor-trailer waste haulers (plus 1 backup tractor), 1 road
grater, 4 crawler tractors, and 1 self-loading scraper are required.
Operation of this equipment on a 7-day basis, direction of vehicles,
maintenance, and supervision requires 26 people. Labor rates have been based
(9)
on cost escalations from the TVA study of FGD processes^ '. The methods by
which the escalation was derived are explained In the Economics Section.
Liner costs include price quotes for the actual liner and a contingency
set aside for maintenance and liner replacement after the power plant ceases
operation.
The annual operating costs for disposal of baghouse filter cake from
the 500 MW test facility are $1,300,000. The cost per ton in 1977 dollars
is $6.10.
"Sinterna" Process of Insolubilization-
In-depth costs were not developed in this study for the "Sinterna"
process. Quotes received from Industrial Resources Inc. estimate a cost
per ton of $8.40 (June 1976 dollars) for briquetting and sintering. This
does not include the additional cost for disposal which we estimate to be
$5.60/ton if land burial is used and $3/ton if surface disposal and evap-
oration ponds are used.
73
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ECONOMICS
The choice of FGD systems for use at any particular site is principally
dependent on the relative costs for the various available systems. These
costs will vary for specific installations in accordance with unit size, com-
bustion coal analysis, and emissions regulations. Both capital costs and
annual operating costs are considered in this evaluation. Representative
costs for other flue gas desulfurization schemes are included for comparison
purposes.
Methodology
This section develops the basic tools and techniques used in evaluating
the capital and operating costs of the dry sorbent baghouse system. Equipment
has been broken down into categories and each category has been assigned a
specific set of indices relating it to various inflation indices. A method
of combining the various economic factors, such as equipment costs, installa-
tion labor, contractor fee, is presented and applied to the dry sorbent tags-
house system.
Cost Indices—
Cost indices are a means of estimating the cost of a certain piece of
equipment at any desired point in time by knowing the equipment cost at some
other point in time. Since they are an invaluable aid in predetermining
planned plant costs, Chemical Engineering publishes monthly tabulations of
plant cost indices which are subdivided into several equipment categories.
Price indices are given for selected group headings such as fabricated
equipment, pumps and compressors, construction labor, and are a numer-
ical representation of the relative increase of each division for which an
index is given referenced to a preset base period (which, in this case, is
1957-1959).
To determine an estimated cost for any item of equipment, a previous cost
for a similar item must be known. The previous cost is divided by the cost
index for the time period during which that cost was incurred and the result
is multiplied by the cost index for the time period for which the estimated
cost is desired.
74
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Item Categorization—Each item of equipment associated with the dry
sorbent FGD system has been classified into specific categories associated
with the economic indices. This has allowed the effective comparison of
individual costs with those of other FGD processes. Categories used for this
assessment are:
Equipment
Materials Handling
Excavation
Foundations
Engineering
Contractor
Contingincy
Other Construction Costs
Estimating Factors-
Process costs have generally been derived from an extrapolation of
material acquisition costs, based on a known or assumed relationship between
the various individual costs associated with a given equipment system. This
relationship will differ depending on the specific type of equipment con-
sidered, the amount of new or uncommon technology, and the labor intensiveness
f •
of the installation.
Cost Estimation Technique—Individual equipment costs are combined with
associated design, procurement, and construction costs to develop a total
module cost. The total module costs are then added to provide a total system
cost. When not directly available, each of the associated design, procure-
ment, and construction costs are estimated from the equipment costs in accor-
dance with the method of K.M. Guthrie^ '. Figure 18 depicts the methodology
used for the establishment of these costs. Factors k-| through Ky are coeffi-
cients relating the various components of a module cost and are individually
established for each equipment classification. A brief description of each
component cost is as follows:
75
-------
FIGURE 18. COST ESTIMATION METHODOLOGY
-------
Cot>t (E) - The purchase price of the major item(s)
of equipment that contribute to an individual cost module.
Ete£d MatytijoZ Co&te (m) - The purchase price of the total
amount of materials necessary for the erection and operation
of the individual cost module, except those contained in (E).
flcteet Laboi (L) - All field labor, excluding fringe ben-
efits, assuming an average mix of crafts, associated with
the individual cost module.
, Duty, Taxe6 (f) - Freight charges, taxes, and
licenses are based on normal rates for shipment within the
continental U.S.
Con&Viuction OveA/iead (c) This component includes labor
fringe benefits, PICA, Federal and state unemployment
insurance, workmen's compensation, supervisory personnel,
temporary construction facilities, heavy equipment leasing,
purchase small tools, and miscellaneous support equipment
and services.
(e) - Engineering services directly attrib-
utable to the individual cost module plus a proportionate
amount of the total project engineering not directly
attributable to any individual cost module. Engineering
also includes costs associated with procurement, drafting,
and all indirect and overhead office costs associated
with the project engineering.
Contingency (h) - The cost of unlisted items and insuffi-
cient scope definition expected to be incurred in the
individual cost module. .
Fee (F) - The portion of the total contractor
fee attributable to the individual cost module.
Index Assignment— To allow an updated estimation of module costs, we have
developed various "inflators" which are an indication of the increase in the
individual component costs which make up the module cost. These "inflators"
77
-------
are computed for such classifications as engineering rates; freight, duty,
and taxes; field-erected steel structures; and rentals, and are developed
using Chemical Engineering price indices, the Consumer price index and in-
creases in PICA rates as determined by the U.S. Department of Health, Educa-
tion, and Welfare. Table 10 gives the breakdown of the "inflators" calculated
as well as the means of determining their numerical value.
Estimation Coefficients—After having generated the "inflators" to up-
date the component costs to 1977 dollars, it is possible to establish estima-
tion coefficients as discussed in the Cost-Estimation Technique section which
reflect conditions in February 1977. Since the Chemical Engineering plant
cost indices are used to update several historical cost estimations to pre-
sent-day dollars (i.e., February 1977 dollars), it is necessary to ascertain
what effect each of the given indices will have on the aforementioned head-
ings.
In order to develop a cost index for each category, an estimate of the
percent effect each plant cost index has is shown in Table 11. These coeffi-
cients are established by discounting or appreciating the applicable coefficients
(based on the piece of capital equipment being analyzed) in reponse to the change
in the value of the inflators being used. Sample calculations for the determina-
tion of the estimation coefficients for the system ID fans are given in Appendix
A.
Using the same general procedure as outlined by the above sample calcu-
lations, estimation coefficients are derived for the various modules estab-
lished for the nahcolite/baghouse process and are given in Table 12-
Capital Costs
The costs associated with the design, procurement, erection and start-
up of a dry sorbent baghouse flue gas desulfurization system employing the
previously described process parameters has been established as a base case.
Individual equipment costs are identified, module costs are calculated in
accordance with the above procedure, and from these the total project cost is
determined. The effect on tlrs total cost due to the differences in design
anticipated for specific installations are then evaluated.
78
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TABLE 10. CALCULATION OF INFLATORS
1. LABOR RATES
Using construction labor indices of Chemical Engineering:
July, 1968 = 119.8
February, 1977 = 176.1
-inflator = 1.4699
j INFLATOP: 1.
2. ENGINEERING RATES
Using engineering and supervision indices of Chemical En^ijieeriricj:
July, 1968 = 109.1
February, 1977 - 154.4
-inflator = 1.4152
INFLATOR: 1.4152
3. FREIGHT, DUTY, TAXES
Using consumer price indices as determined by U.S. Bureau of Labor
Statistics:
July, 1968 = 100.0 (made base year)
February, 1977 = 170.3
inflator = - = 1-7030
INFLATOR: 1.7030
79
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TABLE 10. (Continued)
4. FIELD-ERECTED STEEL STRUCTURES
Using the following price indices from Chemical Engineering in propor-
tion given:
Pipe, valves, fittings 20%
Fabricated equipment 40%
Structural supports 40%
1968 index:
(.2)016.5) + (.4)(109.2) + (.4)(105.2) = 109.06
1977 index:
(.2)(238.1) + (.4)(208.5) + (.4)(219.2) = 218.70
inf later = 1 = 2.0053
INFLATOR: 2.0053
5. SOLIDS-HANDLING EQUIPMENT
Using the following price indices from Chemical Engineering in propor-
tion given:
Pipe, valves, fittings 10%
Process machinery 30%
Pumps, compressors 30%
Structural supports 30%
1968 index:
(.1)016.5) + (.3)011.7) + (.3)015.3) + (.3)(105.2) = 111.31
1977 index:
(.1)(238.1) + (.3) (206.1) + (.3)(234.3) + (.3)(219.2) = 221.69
inf later = -^ = 1.9916
INFLATOR: 1.9916
CConttnued)
80
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TABLE 10. (Continued)
6. PUMPS, MOTORS
Using pumps and compressor price indices from Chemical Engineering:
July, 1968 = 115.3
February, 1977 - 234.3
.
nflator = = 2.0321
INFLATOR: 2.0321
7. CONSTRUCTION OVERHEAD
Using increase in consumer price index (CPI) as determined by U.S.
Bureau of Labor Statistics, increase in FICA (SS) as determined by U.S.
Department of Health, Education, and Welfare, and increase in construc-
tion cost price index (CCPI) from Chemical Engineering:
(SS) FICA 7%
(SS) Unemployment insurance 7%
(CPI) Employment benefits 16%
(CPI) Insurance 20%
(CCPI) Construction equipment 50%
(.07)(0.5395) + (.07)(.5395) + (.16)(.703) + (.20)'.703,
(.50)0.1069) = 0.8821
-inflator = 0.8821
INFLATOR: 0.8821
(Continued)
81
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TABLE 10. (Continued)
8. RENTAL
Using construction cost price indices from Chemical Engineering:
July, 1968 = 1165.5
February, 1977 = 2508.9
inflator = rzir = 2.1526
INFLATOR: 2.1526
9. GENERAL EQUIPMENT COSTS
Using equipment, machinery, supports, price indices from Chemical
Engineering:
July, 1968 = 110.9
February, 1977 = 213.7
inflator - = 1.9270
INFLATOR: 1.9270
10. CONTINGENCY
Using following price indices from Chemical Engineering in proportion
given:
Construction labor 10%
Buildings 10%
Engineering and supervision 10%
Fabricated equipment 10%
Process machinery 10%
Pipe, valves, and fittings 10%
Process instruments 10%
Pumps and compressors 10%
Electrical equipment 10%
Structural supports and miscellaneous 10%
(Continued)
82
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TABLE 10. (Concluded)
10.
CONTINGENCY (Continued)
1968 index:
(.1)019.8) + (.1)014.9) + (.1)009.1) + (.1)009.2) +
(.1)011.7) + (.1)016.5) + (.1)(120.1) + (.1)015.3) +
(.1)(91.1) + (.1)(105.2) = 111.29
1977 index:
(.1)076.1) + (.1)(194.4) + (.1)054.4) + (.1)(208.5) +
(.1)(206.1) + (.1)(238.1) + (.1)(199.6) + (.1)(234.3) +
(.1)(154.9) + (.1)(219.2) = 198.56
-inflator =
= 1-7842
INFLATOR: 1.7842
1 1 .
CONTRACTOR
Using following price indices from Chemical Engineering in proportion
given:
Construction labor 50%
Engineering and supervision 50%
1968 index:
(.5)019.8) + (.5)009.1) = 114.45
1977 index:
(.5)076.1) + (.5)(154.4) = 165.25
inflator =
= 1.4439
INFLATOR: 1.4439
83
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TABLE 11. ALLOCATION OF CAPITAL EXPENSE ITEMS TO CHEMICAL ENGINEERING PRICE INDICES
\^ CHEMICAL
\, ENGINEERING
\. PRICE
\INDEX
^^w^
INVESTMENT \.
INPUT \^^
EQUIPMENT
MATERIALS HANDLING
EXCAVATION
FOUNDATIONS
ENGINEERING
CONTRACTOR
CONTINGENCY
OTHER CONSTRUCTION COSTS
r— o
3> O
CO Z
O CO
73 -H
73
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50%
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en
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•— i 73
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so;
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73
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Iff,
Itf
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>— 1 ^^ HH
-HP- -0
— 1 < m
i— i m-
Z CO
ffj»
CO
20%
10%
10
i— I T3
Z xD
CO O
—1 O
73 m
(= CO
2 CO
m
z
CO
10K
10%
r> -o
O d
•a ~a
3D CO
m
CO
CO
o
73
CO
20%
5$
10%
10%
m m
O r~
cz m
•— < o
TJ —1
3 70
m i— <
z o
-H >
10%
10%
2 3» co co
t— i Z C -H
CO O "O 73
O "O C
m o o
1— 73 — 1
1— -H <=
J» CO 33
Z 3=»
co j» m
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2. Z
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73 Z
< m
, •— < m
co 30
H- 4 *-H
m i— • o z
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cr i
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3(K
50-
10%
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locr;
505
10%
10%
—1
^^
3>
100%
10$
100%
100%
100%
100%
100%
100 «
-------
TABLE 12. ESTIMATION COEFFICIENTS FOR USE IN BASIC CAPITAL COST MATRIX
MILL SURGE TANK
BAGHOUSE PRECOAT
INJECTION SYSTEM
NAHCOLITE INJECTION
SYSTEM TO DUCT
CONVEYING SYSTEM
CONVEYOR AND
FEEDING NETWORK
OF MILL
DUCT SYSTEM*
SITE STORAGE SILO
ASH DISPOSAL SILO
STORAGE DAY TANK
MILL
BAGHOUSE
ID FANS
ASH DISPOSAL
SCREW CONVEYOR
0.086
0.150
0.150
0.150
0.150
N.A.
6.086
0.086
0.086
0.429
N.A.
0.256
N.A.
0.007
0.360
0.360
0.360
0.360
N.A.
0.007
0.007
0.185
0.106
N.A.
0.246
N.A.
0.068
0.068
0.068
0.068
0.068
N.A.
0.068
0.068
0.068
0.068
N.A.
0.067
0.068
0.168
0.183
0.183
0.183
0.183
0.154
0.168
0.168
0.176
0.174
N.A.
0.177
0.183
0.096
0.097
0.097
0.097
0.097
0.097
0.096
0.096
0.096
0.086
N.A.
0.096
0.097
0.140
0.148
0.148
0.148
0.148
0.148
0.140
0.140
0.140
0.143
0.150
0.145
0.148
0.021
0.022
0.022
0.022
0.022
0.022
0.021
0.021
0.021
0.022
0.030
0.021
0.022
N.A. = NOT APPLICABLE '
*VALUES DETERMINED BASED ON CONVEYING SYSTEM COEFFICIENTS AND ID FAN
COEFFICIENTS
85
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Equipment Costs—
Evaluation of module costs required that the cost of each component thai,
is included in the nahcolite/baghouse system be known or reasonably estimated.
To ascertain each individual equipment cost, one of two methods was employed:
obtaining costing information from various vendors or utilizing estimates from
historical data.
New Equipment Cost Quotes—For the majority of equipment costs used in
this study, vendors were solicited to establish costing data for individual
pieces of capital equipment. In order to accurately gauge the cost of eac-"
piece of equipment, a minimum of two different manufacturers were asf-ed to
submit quotes and the more reasonable of the two obtained bids was used.
Vendors, for the most part, represented major manufacturing concerns who.
have much expertise in the electrical generation, pollution abatement field.
They were asked not only to submit bids for the cost of the desired piece of
equipment, but to also estimate the cost of erection, cost of ancillary equip-
ment, if any, and any other related costs. In some instances, the quoted
price included the cost of engineering, erection, foundations, and the like
while, in other cases, only the bare equipment costs were ascertalnable.
Estimates from Historic Data—Costs of the major storage tanks (those
that are utilized to store the raw, unmilled nahcolite and the baghouse
wastes) were developed from estimations based on the TVA study. However,
; since these costs are given in 1975 dollars, it was necessary to update them
to February 1977. This was done by utilizing the applicable plant cost
price indices given in Chemical Engineering.
Base Case Evaluation—
From the above equipment costs, an estimate of the individual module
costs, which make up the total project costs, can be calculated
by use of the capital cost estimating structure as shown in Figure 18. From
this matrix, it is possible to determine such capital items as labor costs;
freight, duty, and taxes; engineering costs; contingency costs; and other
costs that are included in the individual module costs. Once the module
costs have been computed, the total capital cost can be estimated. Table 13
86
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TABLE 13. ALLOCATION OF MODULE COSTS, BASE CASE
EQUIPMENT COSTS
FIELD MATERIAL
COSTS
DIRECT MATERIAL
COSTS
DIRECT LABOR
DIRECT COSTS
FREIGHT, DUTY,
TAXES
CONSTRUCTION
OVERHEAD
ENGINEERING
BARE MODULE
COSTS
CONTINGENCY
COMPLETE MODULE
COSTS
CONTRACTOR
TOTAL MODULE
COSTS
NAHCOLITE
UNLOADING
SECTION
3,500,000
INCLUDED
3,500,000
INCLUDED
3,500,000
157,800
643,300
258,800
4,559,900
674,900
5,234,800
115,200
5,350.000
SITE
STORAGE
SILO
1 ,200,000
103,200
1,303,200
8,400
1,311.600
81 ,600
220,300
125,100
1 ,738,600
243,400
1,982,000
41,600
2,023,600
CONVEYORS
74.000
11,100
05,100
26,600
111,700
5.000
20,400
8,300
145.400
21,500
166.900
3,700
170,600
CONVEYORS
AND FEEDING
SURGE NETWORK
TANK OF MILL
50.000
4.300
54,300
400
54,700
3,400
9,200
5,200
72.500
10,200
82,700
1,700
84,400
60,000
9,000
69,000
21 ,600
90,600
4,100
16,600
6,700
118,000
17,500
135,500
3,000
138,500
MILL
180,000
77,200
257,200
19,100
276,300
12.200
48.100
22,100
358.700
51.300
410.000
9,000
419,000
STORAGE
DAY
TANK
38,000
3,300
41.300
7.000
48,300
2,600
8,500
4,000
63.400
8,900
72,300
1,500
73,800
87
-------
EQUIPMENT COSTS
HELD MATERIAL
COSTS
DIRECT MATERIAL
COSTS
DIRECT LABOR
DIRECT COSTS
FREIGHT. DUTY.
TAXES
CONSTRUCTION
OVERHEAD
ENGINEERING
BARE MODULE
COSTS
CONTINGENCY
COMPLETE MODULE
COSTS
CONTRACTOR
TOTAL MODULE
COSTS
INJECTION
TO DUCTS
16.000
2.400
18,400
5,800
24,200
1,100
4,400
1,800
31,500
4,700
36,200
800
37,000
BAGHOUSE
INJECTION
16,000
2,400
18,400
5,800
24,200
1,100
4,400
1,800
31,500
4,700
36,200
800
37,000
BAGHOUSE
8,500,000
INCLUDED
B, 500, 000
INCLUDED
8,500,000
INCLUDED
INCLUDED
INCLUDED
8,500,000
1,275,000
9,775,000
293.300
10,068,300
ID FANS
495,000
126,700
621,700
121,800
743,500
33.200
149,300
59,700
985,700
142,900
1,128,600
23,700
1,152,300
DUCTS
200,000
INCLUDED
200,000
INCLUDED
200,000
2,400
30,800
4,100
247,300
35,100
282, 400
6,000
288,400
ASH
DISPOSAL 1
CONVEYOR
25,000
INCLUDED
25,000
25,000
50,000
1,700
9,200
2,800
63,700
9,400
73,100
1,600
74,700
ASH
DISPOSAL
SILO
450,000
38.700
48B.700
3,200
491,900
30,600
82,600
46,900
652,000
96,500
748,500
16,500
765,000
WASTE
DISPOSAL
87,400
INCLUDED
87,400
INCLUDED
87,400
INCLUDED
INCLUDED
INCLUDED
87,400
INCLUDED
87,400
INCLUDED
87,400
88
-------
gives a breakdown of each of the module costs which make up the total capital
cost.
Sensitivity Analysis—
Since many elements of the capital cost estimate are highly dependent on
the magnitude of the input parameters, it is necessary to determine the sen-
sitivity of this variance. This is done for the following c^se1::
1) Effect of fuel heating value
2) Effect of baghouse operating temperature
3) Effect of varying the sulfur content of the
fuel
The results of this analysis are presented graphically in Figures 19 and 20.
Calculated data upon which these figures are based are contained in Appendix
6. In order to facilitate the discussion of the assumptions made in the
capital cost sensitivity analysis, the process has been broken up into the
same components that appear in Table 13, capital costs.
Nahcolite Unloading Section—The capital cost for the nahcolite unloading
section was assumed to vary linearly with the weight of the nahcolite being
consumed by the process.
Site Storage Silo—Since the capital cost of the site storage silo is
determined by the weight of the steel used to fabricate the silo, and this,
in turn, is predetermined by the quantity of nahcolite being stored, the
capital cost was varied linearly with the weight of nahcolite being consumed
by the process.
Conveyors—We have solicited quotes for the cost of several conveying
systems (all pneumatic), each capable of handling a different quantity of
nahcolite. A graph was made of the cost of the conveyor per pound of
nahcolite conveyed versus the design capacity. From this graph, it was then
possible to interpolate the cost of a conveying system for any load-handling
capacity.
Surge Tank—As in the case of the site storage silo, the cost of the
surge tank was determined by the quantity of steel necessary to manufacture
89
-------
70 -
60 -
50-
i/i
»—
o.
«
u
30 -
20-
0.5
1
1.0
PERCENT SULFUR IN COAL
(Cow. BATING VALUE 10,900 BTU/LB)
1.5
2.0
FIGURE 19. CAPITAL COSTS VERSUS PERCENT SULFUR CONTENT IN AS-FIRED COAL FOR VARIOUS BAGHOUSE TEMPERATURES
-------
CO
cc.
-
to
o
o
40 -
35 ~
30-
25 -
20-
15-
10
T
r i r i i : i
7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000
COAL HEATING VALUE lBTLJ/1-b)
(1.0% SULFUR IN COAL)
FIGURE 20. CAPITAL COSTS VERSUS COAL HEATING VALUE IN AS-FIRED COAL
FOR VARIOUS BAGHOUSE TEMPERATURES
-------
the tank. Thus, the capital cost varied linearly with the weight of nahcolite
being consumed by the process.
Conveyors and Feeding Network of Mi 11--Since this system utilizes a
pneumatic conveying system, the graph used in the conveyors section was again
utilized to determine the variance of the capital cost with changing load
conditions.
Mill--The capital cost of the mill was assumed to vary linearly with the
quantity of nahcolite being processed by the mill. This assumption was based
upon the fact that the mill is made up of module sections, i.e., several
mills are used in parallel to handle large quantities of material. However,
the cost of the mill was not allowed to decrease below $50,000, since this
was felt to be the minimum cost for an installed product, irrespective of the
quantity involved.
Storage Day Tank—Again, as in the case of the other storage tanks, the
capital cost of the storage day tank is dependent upon the weight of steel
utilized in erecting the tank. Thus, the cost was assumed to vary linearly
with the amount of nahcolite consumed.
Injection Systems—The capital cost of the injection systems was deter-
mined by use of the graph for the variance of cost per quantity of nahcolite
transported versus the total quantity of nahcolite consumed.
Baghouse—A curve relating the baghouse cost per CFM versus the total
flue gas flow rate was provided by a baghouse manufacturer. This relation-
ship was factored to represent the baghouse cost established in the base
design system and then used to estimate the resulting costs for variations
in baghouse sizing.
ID Fans—It was assumed that the capital cost of the induced draft fans
varied linearly with the volume of flue gas being drawn through the fans.
Though this is not strictly correct, it was felt that within the confines of
the error bounds of the total capital cost estimation, the error involved is
small with respect to the total system error.
Ducts—The capital cost of a fully installed insulated duct was found to
be almost linear with flue gas ilow rate down to about 1,200,000 cubic feet
92
-------
per minute (34,000 cubic meters per minute) and deviated about 20% (on the
low side) from linearity between 400,000 cubic feet per minute (11,000 cubic
meters per minute) and 1,000,000 cubic feet per minute (28,000 cubic meters
per minute).
Ash Disposal Conveyor—Since a pneumatic conveyor is used for the ash
disposal conveyor, the capital cost variation with changes in the quantity of
waste from the baghouse was found using the graph for conveyor cost estima-
tion. However, it was necessary to determine the capital cost of the system
based on two variables—the quantity of fly ash and the quantity of spent
nahcolite. Thus, because the base case input parameters dictated a baghouse
waste of approximately 50% fly ash and 50% spent nahcolite, half of the base
case conveyor cost is proportional to the amount of nahcolite used in the
process and half the base case cost is proportional to the amount of fly ash
present in the flue gas; both portions of the ash disposal conveyor cost
estimate were determined utilizing the pneumatic conveyor cost estimate graph.
Ash Disposal Silo—As in the case of the ash disposal conveyor, the base
case capital cost estimate for the ash disposal silo is evenly split between
the cost due to the spent nahcolite and the cost due to the fly ash. However,
in this case, since silo costs are directly related to the quantity of steel
used in the fabrication of the silo, half the base case cost was varied
linearly with nahcolite usage and half was varied linearly with fly ash
generated.
Retrofit Case Evaluation—
In order to estimate the capital costs associated with retrofitting an
existing pulverized coal-fired utility boiler with a nahcolite/baghouse flue
gas desulfurization process, one need only consult the 275°F operating tem-
perature lines on Figure 19 and Figure 20 showing the variance of capital
costs with fuel heating value and with percent sulfur present in the fuel.
Operating Costs
The costs associated with the ongoing operation of the dry sorbent bag-
house FGD system were estimater for the base design. These costs were then
varied by sensitivity analysis techniques to establish the corresponding
operating costs for the specific alternative operating conditions analyzed 1n
93
-------
the preceding section. Included for consideration within operating costs were
pure operational costs such as raw materials, labor, and utilities consump-
tion, plant overhead costs, and maintenance costs, including labor and
materials.
Plant Availability—
In selecting the nahcolite/baghouse operating parameters, every attempt
was made to keep the conditions as equivalent to the TVA study as possible.
For example, in both the TVA study and the nahcolite baghouse study, a 500
megawatt, coal-fired power plant was used. Also, in both cases, the amount
of S02 emitted per million BTU of heat input was maintained at approximately
0.5 pounds. In addition, a plant operating year of 7000 hours which gives a
plant availability of 80% was assumed for both the TVA study and the nahcolite/
baghouse system.
Source of Operating Costs—
s
Each of the various costs associated with the operation and maintenance
of the dry sorbent/baghouse FGD system has been established on the basis of
historical data, manufacturers recommendations, and estimations of current
utility and material costs. The basis for each item has been established as
fol1ows:
Raw Materials—Since a market for nahcolite does not exist at the
present time, it was only possible to estimate the cost of nahcolite. The
three major lease-holders of mineral rights to land containing nahcolite
deposits estimate nahcolite costs at $25 per ton for nahcolite assaying at
70% sodium bicarbonate minimum. For a more detailed discussion of nahcolite
costs, see the section on sorbent supply and costs.
To estimate the shipping costs of nahcolite from the mine mouth to the
proposed power plant site, it was assumed that a unit train could be utilized.
It has been assumed that the average distance from any one of the proposed
mine mouths to the power plant would be 750 miles (1,200 kilometers). With
these assumptions, it was estimated that the cost of nahcolite transportation
(to include hauling filled cars from the mine to the power plant and return-
ing the empty cars back to the Mine mouth) would be in the vicinity of one
cent per ton-mile.
94
-------
From the above cost estimates, it is calculated that the cost of
nahcolite delivered to the power plant would be $32.50 per ton ($35.82 per
metri c ton).
Electrical Consumption—The only utility consumed by the nahcolite/bag-
house system to any appreciable degree is electricity. To estimate the annual
electrical power consumption, an inventory was made of the major consumers of
electricity, such as ID fans, baghouse, conveyors and the mill. These power
requirements were converted to kilowatt hours (based on a 7000 hour annual
operating period) and were factored up by 10% to realize the power consumed
by any ancillary equipment as well as such incidentals as lighting and envi-
ronmental control. Electrical costs are estimated to be $.018/kWh.
Labo>—Labor requirements were established on the basis of the complexity
of the dry sorbent baghouse system, comparative requirements for similar
solids handling operations, and recommendations from the baghouse manufactur-
ers. Labor required for system maintenance and bag replacement were not
included in this section but were included as part of the maintenance costs.
Labor costs were based on an average of crafts and were assumed to be $8.81
per hour.
It was estimated that a total of 9.0 man-years would be needed to effec-
tively operate the nahcolite/baghouse flue gas desulfurization process. The
following breakdown is given as to the allocation of man-years for the bag-
house system:
2.0 man-years to supervisory personnel
2.0 man-years to nahcolite unloading
1.0 man-years to general baghouse operation
3.0 man-years to system operations
1.0 man-years to waste unloading
Analysis—Analysis costs were estimated for the nahcolite/baghouse sys-
tem by assuming the utilization of two full-time chemists at the above rate
plus the additional cost of laboratory supplies.
95
-------
Maintenance—Maintenance costs for the baghouse were estimated at
$289,000 per year. This figure includes materials such as bag replacement
every 2 years, clamps and hardware, and the labor required to perform this
maintenance. This figure is based on estimates given by various baghouse
manufacturers. Yearly maintenance costs for the balance of the dry sorbent
system were assumed to be approximately 4 percent of the capital investment
for this portion of the system.
Waste Disposal—Waste disposal costs for the nahcolite/baghouse system
were estimated to be $6 per ton of combined spent nahcolite/fly ash, as out-
lined in the waste disposal section. A cost of $5.90 per ton has been as-
sumed as typical landfill costs for pure fly ash. The actual waste disposal
costs attributed to the nahcolite/baghouse system were determined by calculat-
ing the total landfill costs of the combined material at $6 per ton less the
cost of operating a standard design landfill for the fly ash produced at
$5.90 ton.
Base Case Evaluation--
An estimation of the yearly cost for operating the dry sorbent baghouse
based on the above criteria has been performed. Table 14 presents these data
in 1977 dollars.
Sensitivity Analysis--
For the nahcolite/baghouse flue gas desulfurization scheme, a sensitiv-
ity analysis was prepared with the following variations in operating param-
eters being investigated:
(1) Fuel heating value
(2) Percent sulfur in fuel
(3) Baghouse operating temperature
The results of this analysis are presented graphically in Figures 21 and 22.
Calculated data upon which these figures are based are contained in Appendix
C.
To simplify the discussion of the operating costs sensitivity analysis,
the components of the total operating cost will be examined individually to
ascertain their variance to differing input conditions.
96
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TABLE 14. BAGHOUSE NAHCOLITE PROCESS - TOTAL AVERAGE ANNUAL OPERATING COSTS,
REGULATED UTILITY ECONOMICS*
Total Annual
Annual Quantity Unit Cost, $ Cost, $
Direct Costs
Delivered Raw Materials
Nahcollte 110,250 tons 32.50/ton 3,583,100
Conversion Costs
Operating Labor and Supervision 18,000 man-hrs. 8.81/man-hr. 158,600
Utilities
Electricity 37,620,000 kWh 0.018/kWh 677,200
Maintenance
ID
^ Labor and Materials 713,600
Analyses 55,700
SUBTOTAL DIRECT COSTS 5,188,200
Indirect Costs
Average Capital Charges at 14.9% of Total
Capital Investment 3,081,700
Overhead
' Plant, 20X of Conversion Costs J67'200
Administrative, 10% of Operating Labor 15,900
SUBTOTAL INDIRECT COSTS 3,2B»,«0
Annual Cost for Trucking and Off-Site Disposal
of Sodium Solids at $6.00/ton 496,100
[ TOTAL ANNUAL OPERATING COSTS 8,9(9,100 I
*500MH new coal-fired power plant, l.OX S 1n fuel; 70X SO. removal; off-site solIds disposal.
-------
30 -
to
O
o
° 20-
IO
CO
o
c_>
CD
O.
o
10-
0.5
1.0
1.5
2.0
FIGURE 21.
PERCENT SULFUR IN COAL
(COAL HEATING VALUE 10,500 BTU/lb)
OPERATING COSTS VERSUS PERCENT SULFUR CONTENT IN AS-FIRED COAL FOR VARIOUS BAGHOUSE TEMPERATURES
-------
20-
<:
o
to
o
o
CO
10 5
LU
o.
o
10-
I
I
I
I
7,000
8,000 9,000
10,000 11,000 12,000 13,000
COAL HEATING VALUE (BTU/lb)
14,000 15,000
FIGURE 22.
(1.0% SULFUR IN COAL)
OPERATING COSTS VERSUS COAL HEATING VALUE IN AS-FIRED COAL FOR VARIOUS BAGHOUSE TEMPERATURES
-------
Delivered Raw Materials—Since this cost is entirely determined by the
quantity of nahcolite consumed in the proposed process, the operating cost
for delivered raw materials is linearly related to the annual amount of
nahcolite utilized.
Electricity Consumption--E1ectrical power consumption was divided into
four constituents: ID fans, baghouse, conveyors, and the nahcolite milling
operations. Since the ID fans and baghouse are proportional to the quantity
of flue gas being transported through the system, their portion of the power
consumption were varied linearly with the flue gas flow rate. The conveyors
operating costs were adjusted according to the graph developed in the capital
cost sensitivity analysis section which plotted cost per quantity transported
versus load handling capacity. Mill operating costs are a linear function of
quantity of nahcolite processed and were adjusted accordingly.
Labor—It was assumed that the operating and supervisory personnel re-
quired to adequately run the baghouse process was not a function of varying
input parameters and therefore was held constant at 9.0 man-years.
Analyses—Because a certain number of analyses must be performed to
ensure the proper working environment in the baghouse process and the number
of analyses done is not affected by the input conditions, the operating costs
were held constant.
Maintenance—Maintenance operating costs, including both the cost of
replacement baghouse materials and the direct Investment costs excluding
the baghouse costs, were varied 1n the following manner: the baghouse re-
placement materials cost was varied linearly with the quantity of flue gas
handled by the baghouse, while the direct investment cost was a direct compu-
tation from the direct investment associated with the applicable process
Indirect Costs—Since all the indirect costs are computed as certain
percentages of costs already discussed, their dependence on the varying of
input parameters will vary with the base costs. No direct manipulation of
these costs was required.
Waste Disposal Costs—Due to the operating costs for the waste disposal
section being dependent only upon the quantity of spent nahcolite (soluble
100
-------
sodium salts) being produced by the baghouse system, the costs were varied
linearly with the quantity of nahcolite consumed in the process.
Retrofit Case Evaluation—
As in the case of the capital cost retrofit case evaluation, an estimate of
the operating costs for the nahcolite/baghouse flue gas desulfurization process
can be obtained by using the 275°F operating temperature line for the plots de-
picting operating costs versus percent sulfur in coal and operating costs versus
coal heating value. The 275°F operating temperature corresponds to the typical
air preheater exi-t temperature of most existing utility boilers of comparable size.
Comparison with Limestone Scrubber—
In order to fully evaluate the cost impact of the nahcolite/baghouse
process, it was necessary to develop accurate cost projections for alter-
native flue gas desulfurization processes. This analysis has been limited
to consideration of the limestone scrubber, as this is the prominant method
available today and-also-presents the least-cost option of the presently
available systems. The cost projections for a limestone flue gas desulfu-
rization scrubbing system attached to a new 500 MW coal-fired power plant,
located in the area of study, were developed from a TVA computer program.
Input criteria for this program were chosen 1n such a way that the calcula-
ted flue gas streams from the boiler matched the assumed flue gas stream
composition for the nahcolite/baghouse system as described elsewhere in
this report.
Since the nahcolite/baghouse process accomplishes both fly ash particle
removal and flue gas desulfurization within the same piece of equipment,
additional costs have been Included within the limestone scrubber cost pro-
jections to include the cost of comparable particle removal. This parti-
cle removal 1s equivalent to the Federal New Source Performance Standards
of 0.1 Ib particulate matter per million Btu heat input, and requires a parfi-
cle removal rate of 98.8% of all entrained fly ash. The TVA program allowed
consideration of two configurations for particle control. The first of
these involved no upstream particle removal but took credit for 40% parti-
cle removal within the limestone scrubber itself. The second alternative
Included a 33% efficient mechanical collector upstream of the scrubber. Since
this second alternative would still require an electrostatic predpitator or
_equiv'alent device capable of removing 97.3% of the parti cul ate matter in. order to
101
-------
guarantee achievement of the New Source Performance Standard at the outlet
of the scrubber, the cost of this alternative was demonstratively higher than
the first alternative, and hence, was not included in the detailed cost
comparison.
Cost projections for electrostatic preclpitator of equivalent performance
for the nahcolite/baghouse system were determined from projections made by the
Industrial Environmental Research Laboratory of the Environmental Protection
Agency. These projections indicated that a 500 MW power plant burning 1%
sulfur coal with a 10% ash content would require a total turn key cost for
the electrostatic precipitator of 28.5 million dollars (1977 dollars). Oper-
ating and maintenance costs were further determined from this program to be
$250,000 per year. The annualized operating cost for trucking and off-site
disposal of the fly ash constituent of the collected particulate matter was not
included in the dry sorbent/baghouse F6D system. This cost has therefore not
been included within the annualized operating costs for the limestone scrub-
ber system. Table 15 presents a comparison of the capital costs of the dry
sorbent/FGD baghouse system and the limestone slurry FGD system.
Annualized operating costs for the limestone scrubber FGD system have
jbeen established by using the TVA cost projections program in conjunction
with site specific cost data developed for the western nahcolite baghouse
system. Additionally, sources of limestone 1n the Green River, Wyoming area
were contacted to determine the realistic cost of obtaining limestone at the
plant site 1n the quantities needed for the equivalent limestone slurry
process. Table 16 presents a breakdown of the total average annual operating
costs for the limestone scrubber system assumed for this cost comparison. A
comparison of the annualized operating costs for the nahcolite/baghouse FGD
system and the limestone slurry FGD system is presented in Table 17.
102
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TABLE 15. COST COMPARISON OF DRY SORBENT/BAGHOUSE FGD SYSTEM WITH
LIMESTONE SLURRY FGD PROCESS
EQUIPMENT
M1
L1
MATERIALS-HANDLING
M1
L1
PARTICLE REMOVAL
EXCAVATION
FOUNDATIONS
M
L2
ENGINEERING
CONTRACTOR
CONTINGENCY
OTHER CONSTRUCTION COSTS
TOTAL
IN 1977 DOLLARS
BAGHOUSE
NAHCOLITE
PROCESS
(400°F)
(COMBINED)
16727
191
85
—
2
24
96
547*
518
2596
1969
22755
(103 DOLLARS)
LIMESTONE
SLURRY
PROCESS
12099
4072
680
293
28500
1386
123
510
1803
681
4657
4476
59280
M = MATERIALS, L = LABOR
1 MINIMUM IN-PROCESS STORAGE; ONLY PUMPS ARE SPARED.
2 CONSTRUCTION LABOR SHORTAGES WITH ACCOMPANYING OVERTIME PAY
INCENTIVE NOT CONSIDERED.
* ENGINEERING COSTS FOR THE BASIC BAGHOUSE PACKAGE IS INCLUDED IN
EQUIPMENT COSTS.
103
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TABLE 16. LIMESTONE SCRUBBER - TOTAL AVERAGE ANNUAL OPERATING COSTS,
REGULATED UTILITY ECONOMICS
Annual Quantity
Unit Cost, $
Total Annual
Cost, $
Direct Costs
Raw Materials
Limestone
Subtotal Raw Materials
Conversion Costs
Operating Labor and Supervision
Utilities
Steam
Process Water
Electricity
Maintenance
Labor and Material
Analyses
Operation and Maintenance of ESP
SUBTOTAL DIRECT COSTS
Indirect Costs
Average Capital Charges at 14.92 of Total
Capital Investment
Overhead
Plant, 20% of Conversion Costs
Administrative, 10X of Operating Labor
SUBTOTAL INDIRECT COSTS
35,000 tons
20,700 man-hr.
644,310 M Ibs.
205,960 M gal.
49,090,180 kWh
2,990 hr.
$10.32/ton
8.81/man-hr.
1.26/M Ibs.
0.0951/M gal.
0.018/kWh
15.00/hr.
Annual Cost for Trucking and Off-Site Disposal
of Calcium Solids at $4.364/Ton
TOTAL ANNUAL OPERATING COSTS
361,200
182,400
811,800
19,600
883',600
1.891,100
44,900
250,000
4,444,600
8.832.700
816,700
18,200
9,667,600
183,300
14,295,500
-------
TABLE 17. COMPARISON OF TOTAL AVERAGE ANNUAL OPERATING COSTS
FLUE GAS DESULFURIZATION PROCESSES
NAHCOLITE/
BAGHOUSE PROCESS
(400°F)
(IN 1977 DOLLARS)
LIMESTONE
SLURRY
PROCESS
DIRECT COSTS
INDIRECT COSTS
WASTE DISPOSAL
TOTAL
5,188,200
3,264,800
496,100
8,949,100
4,444,600
9,667,600
183,300
14,295,500
105
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SECTION 6
ENGLISH TO METRIC CONVERSION
CONVERTING UNITS OF MEASURE
EPA policy is to express all measurements in metric units. When imple-
menting this practice will result in undue cost or lack of clarity, conversion
factors are provided for the nonmetric units used in this report. Table 18
below provides appropriate factors for this report.
TABLE 18. CONVERSION FACTORS
Multiply
English Unit
By
Conversion
To Obtain
Metric Unit
Acre-Feet
British Thermal Unit
British Thermal Unit/Pound
Cubic Feet/Minute
Cubic Feet
Cubic Feet
Degree Fahrenheit
Feet
Gallon
Gallon/Minute
Grains
3
Grains/ft
Inches
Pounds
Mile
Pound-Moles
Tons (Short)
1233.5
1054.8
2325.4
0.028
0.028
28.32
0.555(°F-32)
0.3048
3.785
0.0631
0.06480
2.288
2.54
0.454
1.609
453.6
0.907
Cubic Meters
Joules
Joules/Kilogram
Cubic Meters/Minute
Cubic Meters
Liters
Degree Centigrade
Meters
Liters
Liters/Second
Grams
3
Grams/m
Centimeters
Ki1ograms
Kilometer
Gram-Moles
Metric Tons (1000 Kilograms)
106
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SECTION 7
REFERENCES
1. TRW. Evaluation of Dry Sorbent and Fabric Filtration for FGD.
EPA Contract No. 68-02-1412, Task Order No. 19. 28 June 1976.
2. McGlamery, G. G., R. L. Torstrick, W. J. Broadfoot, J. P. Simpson,
L. J. Henson, S. V. Tomlinson, and J. F. Young. Detailed Cost
Estimates for Advanced Effluent Desulfurization Processes. EPA-
600/2-75-006, Office of Research and Development, U.S. Environmental
Protection Agency. January 1975. 418 pp.
3. Bradway, R. M., and R. W. Cass. Fractional Efficiency of a Utility
Boiler Baghouse NUCLA Generating Plant. EPA-600/2-75-013-a, Office
of Research and Development, U.S. Environmental Protection Agency.
August 1975. 137 pp.
4. Cass, R. W., and R. M. Bradway. Fractional Efficiency of a Utility
Boiler Baghouse: Sunbury Steam-Electric Station. Office of Research
and Development, U.S. Environmental Protection Agency. March 1976.
231 pp.
5. Rittenhouse, R. C. New Generating Capacity: Who's Doing What. Power
Engineering. Volume 81. Number Four. April 1977. pp. 62-69.
6. Potter, P. J. Power Plant Theory and Design. The Ronald Press Company,
New York, New York, Second Edition, 1959. 702 pp.
7. Adams, R. C., T. E. Eggleston, J. L. Haslbeck, R. C. Jordan, and
E. Pulaski. Demonstration of We11man-Lord/Allied Chemical FGD Technology:
Boiler Operating Characteristics. EPA-600/7-77-014, Office of Research
and Development, U.S. Environmental Protection Agency. February 1977.
254 pp.
8. Bechtel Corporation. Evaluation of Dry Alkalis for Removing Sulfur
Dioxide from Boiler Flue Gases. EPRI FP-207 (Research Project 491-1).
Final Report. October 1976. 144 pp.
9. Liu, H., and R, Chaffee. Final Report on Evaluation of Fabric Filter as
Chemical Contactor for Control of Sulfur Dioxide from Flue Gas. A1r
Preheater Company, Incorporated. December 1969. 159 pp.
10. Doyle, D. J. Fabric and Additive Remove S02- Electrical World.
• February 15, 1977. pp. 32-34.
107
-------
11. Genco, J. M. and H. S. Rosenberg. Sorption of S02 on Ground Nahcolite
Ore. Journal of the Air Pollution Control Association. Volume 26.
Number 10. October 1976. pp. 989-990.
12. Dulin, J. M. and E. C. Rosar. Advances in Disposal of Sodium Salts
Wastes Produced by SOX Emissions Control Processes, Cooling Towers, and
Water Demineralizers. Presented at the Annual Meeting of the Air
Pollution Control Association, Session No. 9, "Waste Disposal Without
Environmental Degradation." June 11, 1974. 31 pp.
13. Proceedings: Symposium on Flue Gas Desulfurization. New Orleans,
Louisiana. March 1976. Volume II. EPA-600/2-76-136b, Office of
Research and Development, U.S. Environmental Protection Agency.
May 1976. pp. 565-700.
14. Proceedings: Symposium on Flue Gas Desulfurization - Atlanta, November
1974. Volume II. EPA-650/2-74-126b, Office of Research and Development,
U.S. Environmental Protection Agency. December 1974. pp. 851-1028.
15. Jones, J. W. Disposal of Flue-Gas-Cleaning Wastes. Chemical Engineering
Volume 84. Number 4. February 14, 1977. pp. 79-85.
16. Burnham, A. K., G. V. Clader, J. S. Fritz, G. A. Junk, H. J. Svec, and
R. Vick. Identification and Estimation of Neutral Organic Contaminants
in Potable Water. Analytical Chemistry. Volume 44. 1972. pp. 139.
17. Keith, L. H., and S. H. Hercules. Environmental Applications of Advanced
Instrumental Analyses: Assistance Projects, FY 69-71. EPA-R2-73-155,
Office of Research and Monitoring, U.S. Environmental Protection Agency.
May 1973. 83 pp.
18. Ghassemi, M. Analysis of a Land Disposal Damage Incident Involving
Hazardous Waste Materials: Dover Township, New Jersey. EPA Contract
No. 68-01-2956, Task Order 68-01-3187, Office of Solid Waste Management
Programs, U.S. Environmental Protection Agency. May 1976. 121 pp.
19. Sorg, T. J., and H. L. Hickman, Jr. Sanitary Landfill Facts. Public
Health Service Publication No. 1792. Reprinted, EPA, 1971. 30 pp.
20. Guthrie, K. M. Capital Cost Estimating. Chemical Engineering. Volume
76. Number 6. March 24, 1969. pp. 114-142.
21. Personal Correspondence with Mr. J. Phelan, Wheelabrator-Frye 2/77.
22. Personal Correspondence with Mr. J. H. Smith, Rock School Corp. 1977.
23. Personal Correspondence with Mr. Jacques Dulin, Industrial Resources Inc.,
1977.
108
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APPENDIX A
SAMPLE CALCULATIONS FOR DETERMINATION OF CAPITAL COSTS FROM BASIC MATRIX
(All subscripts refer to year for which parameters are valid)
= equipment costs = 495000
E1977
1968 inflator* for pumps and motors
(*inflators derived in Table 11)
P _ 495000 = ,,.,,-01 c/i
C1968 " 2.0321 "M*''OH
m!968 = fleld maten"al lost costs = (ki» 1968^E1968^
= (0.27)(243591.54)
= 65769.715
m,g77 = (inflator for general equipment costs)(r
= (1.9270)(65769.715)
= 126735.68
. _ m!977 _ 126735.68
~^KT 1977 " Enn-,, " 495000
kl* 1977 = °'256
109
-------
L1968 = direct labor costs - (k2> 1968)(E1968)
= (0.34)(243591.54)
= 82821.123
= (inflator for labor rates)(L-jggg)
- (1.4699)(82821.123)
= 121742.89
. L1977 121742.89
V 1977 " E197? " 495000
k2, 1977 = 0.246
f!968 = fre19nt» duty> and taxes costs = (k3»
= (0.08) (243591.54)
= 19487.323
f,g77 = (inflator for freight, duty, and taxes
- (1.7030)(19487.323)
= 33186.911
u - fT977 _ 33186.911
~*K3' 1977 " E " 495000
= 0.067
110
-------
M1968 = direct material cos*s = E1968 * m!968
= 243591.54 + 65769.715
= 309361.255
M1968 + L1968 = d1rect costs
» 309361.255 + 82821.123
= 392182.378
C1968 = construction overhead costs = (k4, 1968)(M1968 + Llgg8)
= (0.178)(392182.378)
= 69808.461
C1977 = ^nflator for construction overhead) (
= (1.8821) (69808. 461)
= 131386.5
(Mlg77) +
= (495000 + 126735.68) + 121742.89
= 743478.57
C1977 131386.5
743478.57
k4, 1977 = 0.177
111
-------
e!968 = en9ineerin9 costs = (k5> 1968)(M1968}
= (0.136)(309361.25)
- 42073.13
e,g-,7 (inflator for engineering rates)(e-|9cp)
= (1.4152)(42073.13)
59542.54
. _ G1977 59542.54
W5' 1.977 M]977 621735.68
1977 = °'096
B1968 = bare m°dule COStS = {M1968 + "-19681 + f!968 + C1968 + e!968
= (392182.378) + 19487.323 + 69808.461 + 42073.13
523551.292
h!968 = Contln9ency costs = (k6' 1968)(B1968}
= (0.15)(523551.292)
= 78523.693
hlg77 = (inflator for contingency) (hlg6Q)
= (1.7841)(78523.693)
= 140099.41
B1977 = (M1977 + L1977^ + f!977 + C1977 + e!977
= (743478.57) + 33186.911 + 131386.5 + 59542.54
= 967594.521
. = h!977 = 140099.41
~~^K6' 1977 B 967594.521
kg, lg77 = 0.145
112
-------
S1968 = comPlete module costs - Blgg8 +
= 523551.292 t 78523.693
602083. 9H5
F
1968
= (0.026) (602083. 985)
= 15654.183
= (inflator for contractor) (15654. 183)
= (1.5023)05654.183)
= 23516.851
S1977 = (M1977 + L1977.) + f!977 + C1977 + e!977 " h!977
= 743478.57 + 33186.911 + 131386.5 + 59542.54 + 140099.41
= 1107693.9
u i^F1977 . 23516.851
~*K7' 1977fSig77 1107693.9
. 1977 = 0.021
113
-------
APPENDIX B
CAPITAL COSTS FOR VARYING INPUT PARAMETERS
CAPITAL COST
COAL ANALYSIS: % S = 1.
ITEM
A. DESIGN PARAMETERS
Flue Gas Flow
Moles S02/hr
Efficiency
Nahcolite Usage (Ib/hr)
B. ITEM COSTS
Unloading
Site Storage
Conveyor
Surge Tank
Conveyor
Mill
Storage Tank
Injection Conveyor
Injection Conveyor
Baghouse
I.D. Fans
Ducts
Ash Conveyor
Ash Silo
Air Preheater
Waste Disposal
SENSITIVITY
ANALYSIS
0 HEATING VALUE = 8,000
275°F
1.68 x 106
168
.79
69,200
12,340,700
4,667,800
369,200
194,700
299,700
966,500
170,200
80,100
80,100
10,792,300
1,290,600
305,700
118,200
1,281,300
2,186,200
87,400
400° F
1.97 x 106
168
.77
52,600
9,380,300
3,548,000
280,600
148,000
227,800
734,600
129,400
60,900
60,900
11,591,100
1,513,400
330,200
98,800
1,066,900
2,563,600
87,400
525°F
2.25 x 106
168
.79
31 ,900
5,353,900
2,151,800
178,700
89,700
145,100
445,500
78,500
38,800
38,800
12,812,000
1,728,500
351 ,400
76,500
799,500
2,928,000
87,400
TOTAL 35,230,700 31,821,900 27,304,100
114
-------
'Ci
CAPITAL COST
COAL ANALYSIS: % S = 1.
ITEM
A. DESIGN PARAMETERS
Flue Gas Flow 1
Moles S02/hr
Efficiency
Nahcolite Usage (Ib/hr)
B. ITEM COSTS
Unloading
Site Storage
Conveyor
Surge Tank
Conveyor
Mill
Storage. Tank
Injection Conveyor
Injection Conveyor
Baghouse
I.D. Fans
Ducts
Ash Conveyor
Ash Silo
Air Preheater
Waste Disposal
SENSITIVITY
ANALYSIS
0 HEATING VALUE = 10
275°F
.28 x 106
128
.70
44,800
7,989,300
3,021,900
239,000
126,100
194,000
625,700
110,200
51,800
51 ,800
9,157,100
983,300
226,900
89,700
966,200
1,665,700
87,400
4QO°F
1.5 x 106
128
.70
30,000
5,350,000
2,023,600
170,600
84,400
138,500
419,000
73,800
37,000
37,000
10,068,300
1,152,300
288,400
74,700
765,000
1,952,000
87,400
,500
525°F
*>
1.72 x 106
128
.70
21,500
3,834,200
1,450,200
131,900
60,500
107,100
300,300
52,900
28,600
28,600
10,798,000
1,321,300
309,200
66,200
665,200
2,238,300
87,400
TOTAL
25,586,100
22,722,000
21,479,900
115
-------
CAPITAL COST
COAL ANALYSIS: % S = 1
ITEM
A. DESIGN PARAMETERS
Flue Gas Flow
Moles S02/hr
Efficiency
Nahcolite Usage (Ib/hr)
B. ITEM COSTS
Unloading
Site Storage
Conveyor
Surge Tank
Conveyor
Mill
Storage Tank
Injection Conveyor
Injection Conveyor
Baghouse
I.D. Fans
Ducts
Ash Conveyor
Ash Silo
Air Preheater
Waste Disposal
SENSITIVITY
ANALYSIS
.0 HEATI-NG VALUE = 1
275°F
1.04 x 106
103
.63
29,400
5,243,000
1,983,100
169,400
82,700
137,500
410,600
72,300
36,700
36,700
8,047,500
798,900
240,500
74,400
767,300
1,353,400
87,400
400°F
1.21 x 106
103
.63
19,700
3,513,200
1,328,800
124,000
54,400
100,700
275,100
48,500
26,900
26,900
8,833,000
929,500
259,600
64,500
642,000
1,576,600
87,400
3,000
525* F
1.39 x 106
103
.63
15,600
2,783,000
1,052,300
108,200
43,900
87,800
217,900
38,400
23,500
23,500
9,538,000
1,067,800
278,000
61,000
589,000
1,808,900
87,400
TOTAL 19,541,400 17,891,100 17,808,600
116
-------
CAPITAL COST
COAL ANALYSIS: % S = 0.
ITEM
A. DESIGN PARAMETERS
Flue Gas Flow
Moles S02/hr
Efficiency
Nahcolite Usage (Ib/hr)
B. ITEM COSTS
Unloading
Site Storage
Conveyor
Surge Tank
Conveyor
Mill
Storage Tank
Injection Conveyor
Injection Conveyor
Baghouse
I.D. Fans -
Ducts
Ash Conveyor
Ash Silo
Air Preheater
Waste Disposal
SENSITIVITY
ANALYSIS
5 HEATING VALUE = 10
275°F
1.28 x 106
64
.40
10,400
1,854,700
701 ,500
96,500
29,300
78,400
145,300
25,600
20,900
20,900
9,157,100
983,300
266,900
58,500
521 ,800
1,665,700
87,400
400° F
1.50 x 106
64
.40
6,100
1 ,087,800
411,500
71,600
17,200
58,100
85,200
15,000
15,500
15,500
10,068,300
1,152,300
288,400
53,000
466,300
1,952,000
87,400
,500
525°F
1.72 x 106
64
.40
6,100
1,087,800
411,500
71,600
17,200
58,100
85,200
15,000
' 15,500
15,500
10,798,200
1 ,321 ,300
309,200
53,000
466,300
2,238,300
87,400
TOTAL 15,713,800 15,845,100 17,051,100
-------
CAPITAL COST
COAL ANALYSIS: % S = 1.
ITEM
A. DESIGN PARAMETERS
Flue Gas Flow
Moles S02/hr
Efficiency
Nahcolite Usage (Ib/hr)
B. ITEM COSTS
Unloading
Site Storage
Conveyor
Surge Tank
Conveyor
Mill
Storage Tank
Injection Conveyor
Injection Conveyor
Baghouse
I.D. Fans
Ducts
Ash Conveyor
Ash Silo
Air Preheater
Waste Disposal
SENSITIVITY
ANALYSIS
5 HEATING VALUE = 10
275°F
1.28 x 106
191
.80
89,400
15,943,000
6,030,300
476,900
251,500
387,200
1 ,248,600
219,900
103,400
103,400
9,157,100
983,300
266,900
141,800
1,542,300
1,665,700
87,400
400°F
1.50 x 106
191
.80
64,300
11,466,800
4,337,200
343,000
180,900
278,500
898,100
158,200
74,400
74,400
10,068,300
1,152,300
288,400
112,400
1,218,000
1,952,000
87,400
,500
525°F
1.72 x 106
191
.80
36,700
6,544,800
2,475,500
202,000
103,200
164,000
512,600
90,300
43,800
43,800
10,798,200
1,321,300
309,200
81 ,600
861 ,500
2,238,300
87,400
TOTAL
38,608,700
32,690,300
25,877,500
118
-------
CAPITAL
COAL ANALYSIS: % S
ITEM
A. DESIGN PARAMETERS
Flue Gas Flow
Moles S02/hr
Efficiency
Nahcolite Usage (Ib/hr)
B. ITEM COSTS
Unloading
Site Storage
Conveyor
Surge Tank
Conveyor
Mill
Storage Tank
Injection Conveyor
Injection Conveyor
Baghouse
I.D. Fans
Ducts
Ash Conveyor
Ash Silo
Air Preheater
Waste Disposal
COST SENSITIVITY ANALYSIS
= 2.0 HEATING VALUE =10,500
400° F
1.50 x 106
255
.85
100,000
17,833,300
6,745,300
533,500
281 ,300
433,100
1,396,700
246,000
115,700
115,700
10,068,300
1,152,300
288,400
154,100
1,679,200
1,952,000
87,400
525°F
1.72 x 106
255
.85
52,000
9,273,300
3,507,600
277,400
146,300
225,200
726,300
127,900
60,200
60,200
10,798,200
1,321,300
309,200
98,100
1,059,200
2,238,300
87,400
TOTAL
43,082,300
30,316,100
119
-------
APPENDIX C
OPERATING COSTS FOR VARYING INPUT PARAMETERS
COAL ANALYSIS: % S - 0.5 HEATING VALUE 10,500 TEMPERATURE = 275°F
Annual
Quantity
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
36,400
tons
18,000/
man-hr.
29,467,379
32.50/
ton
8.81/
man-hr.
0.018/
kUh
1,183,000
158,600
530,400
608,900
49,400
2,530,300
2,341,400
269,500
15,900
2,626,800
163,800
5,320,900
ion
-------
COAL ANALYSIS: % S = 1.0 HEATING VALUE = 10,500 TEMPERATURE = 275°F
Annual•
Quantlty
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
156,800
tons
18,000 /
man-hr.
36,265,777
32.50/
ton
8.81/
man-hr.
0.018/
kWh
5,096,000
158,600
652,800
608,900
49,400
6,565,700
3,812,300
293,900
15,900
• 4,122,100
705,600
.11,393,400
121
-------
COAL ANALYSIS: %S= 1.5 HEATING VALUE 10,500 TEMPERATURE = 275°F
Annual
Quanti ty
Un.it
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
312,900
tons
18.000/
man-hr.
46,509,309
32.50/
ton
8.81/
man-hr.
0.018/
kWh
10,169,300
158,600
837,200
608,900
49,400
11,823,400
5,752,700
330,800
15,900
6,099,400
1,408,100
19,330,900
122
-------
COAL ANALYSIS: % S = 0.5 HEATING VALUE = 10,500 TEMPERATURE = 400°F
Annual
Quanti ty
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcoli te
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
'5
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
21,350
tons
18.000/
man-hr.
32,883,803
32.50/
ton
8.81/
man-hr.
0.018/
kWh
693,900
158,600
591,900
713,600
49,400
2,207,400
2,360,900
302,700
15,900
2,679,500
96,100
4,983,000
123
-------
COAL ANALYSIS: %S = 1.0 HEATING VALUE = 10,500 TEMPERATURE = 400°F
Annual
Quanti ty
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
110,250
tons
18,000/
man-hr.
37,620,000
32.50/
ton
8.81/
man-hr.
0.018/
kWh
3,583,100
158,600
677,200
713,600
55-,700
5,188,200
3,385,600
321,000
15,900
3,722,500
496,100
9,406,800
124
-------
COAL ANALYSIS: % S = 1.5 HEATING VALUE = 10,500 TEMPERATURE = 400°F
Annual
Quantity
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
225,050
tons
18,000
man-hr.
45,205,899
32.50/
ton
8.81/
man-hr.
0.018/
kWh
7,314,100
158,600
813,700
713,600
49,400
9,049,400
4,870,900
347,100
15,900
5,233,900
1,012,700
15,296,000
125
-------
COAL ANALYSIS: % S = 2.0 HEATING VALUE = 10,500 TEMPERATURE = 400°F
Annual
Quanti ty
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
350,000
tons
18.000/
man-hr.
53,411,060
32.50/
ton
8.81/
man-hr.
0.018/
kWh
11,375,000
158,600
961,400
713,600
49,400
13,258,000
6,419,300
376,600
15,900
. 6,811,800
1,575,000
.20,227,300
126
-------
COAL ANALYSIS: % S = 0.5
HEATING VALUE =
10,500 TEMPERATURE
= 525°F
~ .
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Annual
Quanti ty
21 ,350
tons
18,000
man-hr.
37,345,252
Unit
Cost, $
32. 50/
ton
8.81/
man-hr.
0.018/
kWh
Total
Annual
Cost, $
693,900
158,600
672,200
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
818,300
49,400
2,392,400'
2,540,600
339.700
15,900
2,896,200
96,100
5,384,700
127
-------
COAL ANALYSIS: %S- 1.0 HEATING VALUE = 10,500 TEMPERATURE = 525°F
Annual
Quantity
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
75,250
tons
18.000/
man-hr.
40,296,583
32.50/
ton
8.81/
man-hr.
0.018/
kWh
2,445,600
158,600
725,300
518,300
49,400
4,197,200
3,200,500
350,300
15,900
3,566-, 700
338,600
8,102,500
128
-------
COAL ANALYSIS: % S = 1.5 HEATING VALUE = 10.500 TEMPERATURE = 525°F
Annual
Quantity
Unit
Cost, $
Total
Annual
Cost, S
Direct Costs
Delivered Raw Material
Nahcollte
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
128,450
tons
18.000/
man-hr.
43,489,074
32.50/
ton
8.817
man-hr.
0.018/
kWh
4,174,600
158,600
7*2,200
818,300
49,400
. 5,983,700
3,855,800
361,800
15,900
4,233,500
578,000
10,795,200
129
-------
COAL ANALYSIS: % S = 2.0
HEATING VALUE =
10,500 TEMPERATURE
= 525°F
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Annual
Quanti ty
182,000
tons
18.000/
man-hr.
46,842,338
Unit
Cost, S
32. 50/
ton
8.81/
man-hr.
0.018/
kWh
Total
Anr.ua '
:-.= •., s
5,915,000
158,600
343,200
Maintenance
Labor and Materials 818,300
Analyses 49,400
SUBTOTAL DIRECT COSTS 7,784,500
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment 4,517,100
Overhead
Plant, 20% of Conversion
Costs 373,900
Administrative, 10% of
Operating Labor 15,900
SUBTOTAL INDIRECT COSTS 4,906,90d
Annual Cost for Sodium
Disposal at $6.00/ton 819,000
TOTAL ANNUAL OPERATING COSTS 13,510,400
130
-------
COAL ANALYSIS: % S = 1.0 HEATING VALUE = 8,000 TEMPERATURE = 275°F
Annual
Quantity
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
242,200
tons
18,000/
man-fir.
49,983,152
32.50/
ton
8.81/
man-hr.
0.018/
kWh
7,871,500
158,600
899,700
799,200
49,400
9,778,400
5,249,400
381,400
15,900
5,646,700
.16,515,000
131
-------
COAL ANALYSIS: % S = 1.0 HEATING VALUE = 13,000 TEMPERATURE = 275°F
Annual
Quanti ty
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
102,900
. tons
18,000/
man-hr.
28,152,486
32.50/
ton
8.81/
man-hr.
0.018/
kWh
3,344,300
158,600
506,700
494,800
49,400
4,553,800
2,911,700
241,900
15,900
3,169,500
463,100
8,186,400
132
-------
COAL ANALYSIS: % S = 1.0 HEATING VALUE = 8,000 TEMPERATURE = 4008F
Total
Annual Unit Annual
Quantity Cost, $ Cost, $
Direct Costs
Delivered Raw Material
NahcolUe 184,100 32.50/ 5,983,300
tons ton
Conversion Costs
Operating Labor 18,000/ 8<81/ 158,600
and Supervision man-hr. man-hr.
Utilities
Electricity 52,055,944 0.018/ 937,000
kWh
Maintenance
Labor and Materials 937,200
Analyses 49,400
SUBTOTAL DIRECT COSTS 8,065,500
Indirect Costs
Average Capital Charges at
14.9% of Total Capital 4 74^ 500
Investment * *
Overhead
Plant, 20% of Conversion ,,, .„
Costs 416,400
Administrative, 10% of n__
Operating Labor 15,900
SUBTOTAL INDIRECT COSTS 5,173,800
Annual Cost for Sodium
Disposal at $6.00/ton 828,500
TOTAL ANNUAL OPERATING COSTS 14,067,800
133
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COAL ANALYSIS: % S = 1.0 HEATING VALUE = 13.000 TEMPERATURE = 400°F
Annual
Quantity
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
68,950
tons
18.000/
man-hr.
29,582,217
32.50/
ton
8.81/
man-hr.
0.018/
kWh
2,240,900
158,600
532,500
575,600
49,400
3,557,000
2,665,800
263,200
15,900
2,944,900
310,300
6,812,200
134
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COAL ANALYSIS: % S = 1.0 HEATING VALUE = 8.000 TEMPERATURE = 525°F
Annual
Quanti ty
Unit
Cost, $
Total
Annual
Cost, $
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
111,650
tons
18.000/
man-hr.
53,210,094
32.50/
ton
8.81/
man-hr.
0.018/
kWh
3,628,600
158,600
957,800
1,070,400
49,400
5,864,800
2,653,500
447,200
15,900
3,116,600
502,400
9,483,800
135
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COAL ANALYSIS: % S = 1.0 HEATING VALUE = 13,000 TEMPERATURE = 525°F
Annual
Quanti ty
Unit
Cost, $
Total
Annual
Cost, S
Direct Costs
Delivered Raw Material
Nahcolite
Conversion Costs
Operating Labor
and Supervision
Utilities
Electricity
Maintenance
Labor and Materials
Analyses
SUBTOTAL DIRECT COSTS. . . .
Indirect Costs
Average Capital Charges at
14.9% of Total Capital
Investment
Overhead
Plant, 20% of Conversion
Costs
Administrative, 10% of
Operating Labor
SUBTOTAL INDIRECT COSTS. . .
Annual Cost for Sodium
Disposal at $6.00/ton
TOTAL ANNUAL OPERATING COSTS
54,600
tons
18,000/
man-hr.
32,453,162
32.50/
ton
8.81/
man-hr.
0.018/
kWh
1,774,500
158,600
584,200
661,300
49,400
3,228,000
4,068,300
290,700
15,900
4,374,900
245,700
7,848,600
136
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APPENDIX D
MAGNESIUM OXIDE AS A BAGHOUSE SORBENT
CONCEPT
Magnesium oxide powder could, based on its theoretical reactions with
gaseous S02> be used as a sorbent material in conjunction with a baghouse FGD
installation. Magnesium oxide is, however, too expensive to be considered as
a feed material to a "throwaway" process and can only demonstrate practical
economics when used in a regenerable scheme. The regeneration of magnesium
sulfate and sulfite to the active oxide form is accomplished by calcination
and a dry product is obtained. In the currently-developed magnesium oxide wet
FGD process, the regenerated magnesium oxide must be slurried with water, used
in the wet scrubber, and the spent magnesium salts must then be separated by
centrifuge and dried prior to calcination. The use of a baghouse would elim-
inate these "wet" steps and holds considerable promise. The feasibility and
economic practicality rests on two questions:
• Is magnesium oxide sufficiently reactive to obtain
reasonable SOp removal efficiency when used in a bag-
house at temperatures compatible with bag fabrics?
• Is a two stage baghouse system less expensive to
build and operate than the "wet" portions of the
current magnesium oxide FGD process (including
particle control)?
The first question must, of course, be answered affirmatively before the
economic analysis required to answer the second is warranted.
DISCUSSION
The thermochemical feasibility of using magnesium oxide (MgO) as a dry
sorbent in a flue gas desulfurization scheme utilizing a baghouse as a
137
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collection medium was undertaken. This means of sulfur dioxide removal showed
interest because MgO has the potential for not only absorbing S0« in the tem-
perature range of interest (that of a typical flue gas from a pulverized coal
utility boiler) but also is capable of being regenerated from the spent
sorbent by means of thermal decomposition. In order to analyze the use of MgO
in the dry additive/baghouse flue gas desulfurization system, it was necessary
only to examine the chemistry of the absorbing section since the regeneration
process has been well established through demonstration.
In the absorption step, a two baghouse design would be necessary in order
to avoid collection of fly ash on the absorbing filter cake, thereby decreas-
ing its efficiency due to dilution effects and possible blinding of the sorb-
ing surface. More important, however, is the fact that the "all dry" magne-
sium oxide regeneration scheme does not lend itself to separation of collected
fly ash and the sorbent.
The first baghouse would be used to collect the fly ash contained in the
flue gas while MgO would be injected between the first and second baghouse.
Theoretically, S09 is absorbed by the MgO in accordance with the follow-
(1 2)
ing reactionsv ' .
1) MgO + S02 = MgS03
S02 + 1/2 02 = S03
2) MgO + S03 = MgS04
Figure D-l ^ ' illustrates the dependence of the reaction equilibrium of
equation (1) on temperature. At a temperature of approximately 350°F (180°C)
the flue gas S09 will combine with the MgO to reach an equilibrium sufficient
6
to meet the New Source Performance Standards of 1.2 Ib SO/,/10 Btu. At temper-
atures below this the reaction will favor increased S0« removal and vice versa.
Thermal regeneration is possible at temperatures above 660°F (350°C) and improves
with increasing temperature.
Figure D-2^ ' illustrates the corresponding relationship for equation (2).
The combination of MgO with SO^ to meet NSPS levels is favored at temperatures
at or below 1500°F (820°C). This reaction is not reversible at practical
conditions.
138
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4 -J
2 -J
CO
VO
5
»«
i
if
S-f
If
- 2 -I
- 4
- 6
- 8 H
-10
1.2 Ib S02/
106 BTU
200 300
400 500 600 700
TEMPERATURE - DEGREES CENTIGRADE
FIGURE D-
MgS03 ^ MgO -H S02
i
800
900
-------
-30 -
-26 -
-22 -
o -18
-------
From a thermodynamic standpoint, SOp capture by MgO would seem to be
quite favorable in the temperature range associated with boilers. Nonetheless*
operating within the thermodynamically-favored temperature range does not guaran-
tee sufficient reductions in the S0« level since the reaction rates of the various
ongoing reactions dictate the chemistry of the system. That is, kinetic consi-
derations nay override otherwise favorable thermodynamics.
To facilitate the determination of the multitude of possible reaction
rates at which the S02 could interact with MgO, an upper bound of 83QPC was
chosen (which is the thermodynamic constraint put on the system by the NSPS
for S02) while a lower limit of 135°C (which gives the optimum recovery of
heat in the process from an economic point of view) was imposed. Extensive
research has been done by Pechkovskii' ' and Marier and Dibbs^ ' on the
absorption of S02 by MgO in the temperature range of 600-900°C. Certain
points should be noted, however, in inferring any conclusions from their work
about the uptake of S02 in the flue gas desulfurization scheme under question.
In his determination of S02 reaction rates with MgO, Pechkovskvi used a gas
atmosphere which contained 2,5 percent S02 and 97.5 percent air (volume per-
cents) which has a ten times greater percentage of SOp by volume than the
typical flue gas stream from a pulverized coal power plant. This, however,
wbujd tend to increase the percent conversion of MgO since the reaction rate
is also dependent upon the concentrations of the reacting constituents. Also,
\
Pechkovskii ran his experiments for a 15 minute period, which is two orders of
I o
magnitude (10 ) greater than the contact times envisioned for a dry sorbent/
bughouse flue gas desulfurization process. Again, percent conversions of MgO
deduced from Pechkovskii's work would tend to be greater than those expected
from the MgO/baghouse operation.
Both Pechkovskii and Marier and Dibbs have demonstrated the catalyzing
effects of Fe203 on the oxidation of S02 to S03. Though Fe203 is a major
constituent of fly ash, its effect on the S02 in the flue gas is expected to
be negligible due to the unreactive state of the fly ash. Due to the high
temperatures in the boiler, the particulate matter tends to fuse, thereby
decreasing the surface area for reaction (both on the surface of the particle
and in the pore structure); this results in an appreciable decrease in the
catalytic properties of the Fe203 in the fly ash. For this reason, S02 cap-
ture by MgO in the baghouse would be predominantly by non-catalyzed reactions.
141
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Extrapolation of reaction rates of S02 uptake by Mgo from an Arrhem'us
plot given in Figure F-3 (data from which derived given in Table F-l) gives the
following results:
Percent Conversion by
Temperature Weight of MqO*
135°C 0.03%
830°C 3.65%
*Percent conversion in a 15 minute run.
These two percent conversions bracket the expected conversion rate (which is
determined by the temperature chosen to optimize the system). Since the
greatest utilization rate of MgO in a one-pass system would be on the order
of 4 percent and such a conversion is obtained only at temperatures well
above baghouse operating temperature limits, it is obvious that to obtain
sufficient utilization rates of MgO, a multi-pass recycle stream would have
to be incorporated. The low uptake per pass would result in unreasonably
large recycle rates and thus render the overall scheme unworkable.
TABLE D-1. TEMPERATURE DEPENDENCE OF MqO CONVERSION
Percent Conversion of MgO
Temperature °C. (Weight Percent)
600 1.7
700 2.5
800 3.4
900 4.3
Gas Composition: 2.5% (by weight) S02
97.5% (by weight) Air
142
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U>
GAS CONTENT
2.5% (vol) S02
97.556 (vol) AIR
f x 10-
1.60
4- 1.60
1.50 + 1.50
1.40 -|- 1.40
1.30 4-N.-30
1.20 -|- 1.20
1.10 -|- 1.10
i.oo -\- i.oo
0.90 -4- 0.90
1 i r i i i
-0.50 -0.40 -0.30 -0.20 -0.10 0 0.10 0.20 O.JO 0.40 0.50 0.60
LOG k (k IN UNITS OF X CONVERSION OF HgO IN 15 HINDUS)
FIGURE D-3. ARRHENIUS PLOT OF S02 UPTAKE WITH Mi|0
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APPENDIX 0
REFERENCES
1. Applicability of Metal Oxides to the Development of New Processes for
. Removing S02 from Flue Gases. Final Report. Volume II. Section 8.
Report done by Tracer for National Air Pollution Control Administration
under contract PH 86-68-68. 1969. pp. 308-310.
2. Fundamental Study of Sulfur Fixation by Lime and Magnesia. Final Report.
Report done by Battelle Memorial Institute for Taft Sanitary Engineering
Center (Public Health Service) under contract PH 86-66-108. 1966. p. 6.
3. Murthi, K., D. Harrison and R. Chan. Reaction of Sulfur Dioxide with
Calcined Limestones and Dolomites. Environmental Science and Technology.
Voltpe 5. Number 9. 1971. p. 776. '
4..; Pechkovskii, V. V. Reactions of Sulfur Dioxide with Metal Oxides in an
Oxidizing Atmosphere. Journal of Applied Chemistry of the U.S.S.R..
Volume -30; Number 11. 1957. p. 1643.
5. Marier, P. and Dibbs, H. P. The Catalytic Conversion of S02 to S03 by
Fly -Ash and the Capture of S02 and SO, by CaO and MgO. Thermochemica
Acta. Volume 8. 1974. p. 155.
144
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-600/7-79-005
2.
3. RECIPIENT'S ACCESSION-NO.
\. TITLE AND SUBTITLE
Evaluation of Dry Sorbents and Fabric Filtration
for FGD
6. REPORT DATE
January 1979
6. PERFORMING ORGANIZATION CODE
AUTHOR
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