&EPA
United States
Environmental Protection
Agency
Office of Air Quality
Planning and Standards
Research Triangle Park NC 27711
EPA-450/3-78-123
December 1978
Air
Industrial Boilers - Fuel
Switching Methods, Costs,
and Environmental Impacts
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EPA-450/3-78-123
Industrial Boilers - Fuel
Switching Methods, Costs, and
Environmental Impacts
by
J.M. Burke and M.D. Matson
Radian Corporation
8500 Shoal Creek Boulevard
Austin, Texas 78750
Contract No. 68-02-2608
EPA Project Officer: Kenneth R. Woodard
Emission Standards and Engineering Division
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Air, Noise, and Radiation
Office of Air Quality Planning and Standards
Research Triangle Park, North Carolina 27711
December 1978
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This report has been reviewed by the Emission Standards and Engineering Division of the Off ice of Air
Quality Planning and Standards, EPA,and approved for publication. Approval does not signify that the
contents necessarily reflect the views and policies of the Environmental Protection Agency, nor does
mention of trade names or commercial products constitute endorsement or recommendation for use.
Copies of this report are available through the Library Services Office (MD-35), U.S. Environmental
Protection Agency, Research Triangle Park, NC 27711, or from National Technical Information
Services, 5285 Port Royal Road, Springfield, Virginia 22161.
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CONTENTS
List of Figures -jV
List of Tables VI
1. Introduction 1
2. Summary 3
3. Conclusions 7
4. Fuel Switching Methods 8
Industrial Boilers 8
Fuel Switch From Gas to Oil 15
Fuel Switch From Gas and Oil to Coal 31
5. Factors Affecting Fuel Switching 112
Standard Boilers 113
Impact of ESECA and the NEP on Fuel Switching 115
Environmental Impact of Fuel Switching 123
Relative Costs of Fuel Switching Methods 130
Expected Fuel Switches 160
References 169
Appendices
A. Emission Factors for Industrial Boilers 174
B. Sample Combustion Calculation for Natural Gas 176
C. Estimated Costs for Low and Medium-Btu Gas and a Coal-Based
Liquid Fuel 181
D. Estimated Coal-Oil Mixture Costs 193
E. Estimated Annual Capital, O&M, and Fuel Costs For Fuel
Switching Scenarios 199
F. Estimated Annual Costs for Pollution Control Equipment 220
iii
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FIGURES
Number Page
4-1 Schematic of a water tube boiler 11
4-2 Relative size of a gas-, oil-, and coal-fired boiler
with the same capacity 13
4-3 Estimated capital costs of a gas to oil conversion based
on new boiler costs ($1978) 24
4-4 Estimated capital costs of a gas to oil conversion based
on oil storage costs ($1978) 25
4-5 Estimated operating and maintenance costs for a gas- and
oil-fired boiler 26
4-6 A comparison of stoker-, pulverized coal- and gas/oil-
fired boiler capital costs (1978$) 41
4-7 Projected capital costs for a stoker-fired boiler 44
4-8 Projected capital costs for a pulverized coal-fired boiler.. 45
4-9 Estimated operating and maintenance costs for a coal-fired
boiler 46
4-10 Comparison of operating and maintenance costs of a gas/oil-
fired boiler and a coal-fired boiler 48
4-11 Estimated capital costs for coal handling and storage
(1977$) 63
4-12 Estimated costs for ash handling equipment (1977$) 64
4-13 Estimated increase in operating and maintenance costs which
results from a switch to coal 66
4-14 Estimated cost of boiler modifications required to fire
COM ($1978) 78
1v
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FIGURES (Continued)
Number Page
4-15 Estimated capital costs for conversion of a residual
oil boiler to COM firing ($1978) 80
4-16 A comparison of COM preparation plant capital costs with
the capital cost of a pulverized coal-fired boiler
($1978) 81
4-17 Estimated operating and maintenance costs for a COM-fired
boiler 83
4-18 Estimated operating and maintenance costs for a COM
preparation plant 85
4-19 Estimated capital costs of modification to boiler fuel
supply' system and burners (1978$) 97
4-20 Estimated capital costs for modification of an oil boiler
to fire SRC-II ($1978) 107
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TABLES
Number Page
2-1 Fuel Switching Scenarios for Three Standard Boilers 5
2-2 Expected Fuel Switches for Three Standard Boilers 6
4-1 Relative Volumes of A Gas, Oil and Coal-Fired Boiler With
the Same Capacity 12
4-2 Recommended Flue Gas Velocities Through Tube Banks as a
Function of Fuel Type 14
4-3 Recommended Tube Spacing as a Function of Fuel Type 16
4-4 Furnace Design Parameters as a Function of Boiler Type 17
4-5 Estimated Change in Emissions Which Result From a Gas to
Oil Fuel Switch 27
4-6 A Comparison of Emissions from Oil-Fired Industrial Boilers
to "Typical" State Regulations 28
4-7 Available Coal Handling and Storage Equipment 35
4-8 Types of Pulverized-Coal Equipment 39
4-9 Estimated Price Difference Between Coal and Gas/Oil Required
for Boiler Replacement to be Economical 42
4-10 Operating and Maintenance Costs for a Coal-Fired Boiler as a
Percentage of Annual Costs 43
4-11 A Comparison of Estimated Industrial Coal-Fired Boiler
Emissions to Typical State Regulations 49
4-12 Estimated Emission Change Due to Fuel Switching 68
4-13 Characteristics of Coal-Oil Mixture Research Projects 76
4-14 Comparison of COM Selling Price with Price of Residual Oil... 82
V1
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TABLES (Continued)
Number Pa8e
4-15 Estimated Change in Emissions Which Results When Gas and
Oil Boilers Switch to COM Firing 86
4-16 A Comparison of Coal-Based Fuel Gas Compositions With the
Composition of Natural Gas 91
4-17 Relative Volume and Weight of Fuel and Flue Gas From the
Combustion of Low-Btu, Medium-Btu and Natural Gas 92
4-18 Estimated Performance of Unmodified Gas and Oil Boilers
Firing Different Coal-Based Fuel Gases 93
4-19 Properties of Typical Distillate and Residual Fuel Oils
and Coal-Liquids 103
4-20 Estimated Emissions Using SRC-II, H-Coal, and EDS Coal-
Liquids in Industrial Boilers. 109
4-21 Estimated Change in Emissions Which Results When Gas/
Oil-Fired Boilers Switch to Coal-Liquids 110
5-1 Standard Boiler Characteristics 114
5-2 Design Parameters for Standard Boilers Subject to Fuel
Switching 116
5-3 Estimated Fuel Costs Through 1990 With and Without Proposed
NEP Fuel Taxes 120
5-4 Annual Fuel Consumption of Standard Boilers 122
5-5 Estimated Emissions and Control Requirements for Fuel
Switching in a Gas Fired, Fire Tube Boiler 124
5-6 Estimated Emissions and Control Requirements for Fuel
Switching in a Distillate Oil Fired, Fire Tube Boiler 127
5-7 Estimated Emissions and Control Requirements for Fuel
Switching in a Residual Oil Fired, Water Tube Boiler 129
5-8 Summary of Control Requirements for Fuel Switching in
Standard Boilers 131
5-9 Estimated Costs of Coal-Based Fuels 135
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TABLES (Continued)
Numbe r Page
5-10 A Comparison of the Annual Costs for a 4.4 MW Natural Gas
Fired Boiler Before and After Switching Fuels 138
5-11 A Comparison of the Annual Costs for a 4.4 MW Gas Fired
Boiler Before and After Switching Fuels 141
5-12 Range of Potnetial Impact From the Fuel Tax/Investment
Credit Program on the Annual Costs of a 4.4 MW Gas
Fired Boiler 143
5-13 A Comparison of the Annual Costs for a 4.4 MW Distillate
Oil Fired Boiler Before and After Switching Fuels 146
5-14 A Comparison of the Annual Costs for a 4.4 MW Distillate
Oil Fired Boiler Before and After Switching Fuels 148
5-15 Range of Potential Impact From the Fuel Tax/Investment
Credit Program on the Annual Costs of a 4.4 MW Distillate
Oil Fired Boiler 151
5-16 A Comparison of the Annual Costs for a 44 MW Residual Oil
Fired Boiler Before and After Switching Fuels 154
5-17 A Comparison of the Annual Costs for a 44 MW Residual Oil
Fired Boiler Before and After Switching Fuels 156
5-18 Range of Potential Impact From the Fuel Tax/Investment
Credit Program on the Annual Costs of a 44 MW Residual
Oil Fired Boiler 159
5-19 Expected Fuel Switches for a 4.4 MW Natural Gas-Fired
Boiler 162
5-20 Design Parameters for a 4.4 MW Natural Gas Fired Boiler
After Switching Fuels 163
5-21 Expected Fuel Switches for a 4.4 MW Distillate Oil Fired
Boiler 164
5-22 Design Parameters for a 4.4 MW Distillate Oil Fired Boiler
After Switching Fuels 165
5-23 Expected Fuel Switches for a 44 MW Residual Oil Fired
Boiler 166
5-24 Design Parameters for a 44 MW Residual Oil Fired Boiler
After Switching Fuels 168
V111
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SECTION 1
INTRODUCTION
The Clean Air Act Amendments of 1977 require the Environmental
Protection Agency to coordinate and lead the development and implemen-
tation of regulations to limit air pollution. These regulations include
standards of performance for new and modified sources of pollution.
Specifically mentioned in the 1977 Clean Air Act Amendments are fossil
fuel fired steam generators. Accordingly, the Environmental Protection
Agency has undertaken a study of industrial boilers with intent to propose
standards of performance based on the results of these studies.
This study was conducted by Radian Corporation to develop background
information and data for use by the Emission Standards and Engineering
Division of the EPA. Existing industrial boilers were studied to determine
the potential for these boilers to become modified sources of pollution.
Specifically, the potential for existing boilers to switch fuels from gas
or oil to oil, coal, or a coal-based fuel was examined. In order to deter-
mine the potential for fuel switching in existing industrial boilers, the
technical, economic, environmental, and regulatory aspects of fuel switching
were considered.
As part of the EPA's program to develop standards of performance for
industrial boilers, seven "standard" or model boilers have been identified
as being representative of the existing industrial boiler population. Of
these seven, three are either gas or oil fired and these three served as a
basis for this study. As a result of an analysis of the technical aspects
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of switching fuels, potential fuel switching scenarios were determined for
the three standard boilers. A total of twenty scenarios were identified
and costs were determined for each scenario under several conditions.
Costs were estimated for the fuel switching scenarios without considera-
tion of environmental or energy regulations. Cost estimates were also pre-
pared which consider addition of pollution control equipment and the impact
of certain provisions of the National Energy Plan. Based on this series of
cost estimates, the impact of environmental and energy regulations on fuel
switching in existing industrial boilers was identified. In addition, the
most probable fuel switching methods to be employed by existing boilers were
determined. And the design parameters of the standard boilers after switch-
ing fuels by the most probable methods were estimated. However, the number
of boilers which are expected to switch fuels could not be determined. This
is because site specific data are required to perform an analysis which can
quantify fuel switching in existing industrial boilers, and these data are
not available.
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SECTION 2
SUMMARY
The objectives of this study were to determine which fuel switching
methods existing gas and oil fired boilers will use to switch fuels and to
determine the number of existing boilers which will switch fuels by each
method. Fuel switching methods were identified and analyzed for technical
feasibility. Based on this analysis, potential fuel switching scenarios
were developed and the associated costs were estimated. As a result, the
expected or most probable fuel switching methods have been identified. In
addition, a qualitative analysis of fuel switches in existing boilers was
performed. However, due to lack of site specific data, the number of boilers
which are expected to switch fuels by each method could not be quantified.
the following six fuel switching methods were identified as possible
candidates for use in existing industrial boilers:
1) gas to oil, boiler modification
2) gas/oil to coal, boiler replacement
3) gas/oil to coal, boiler modification
4) gas/oil to coal-oil mixture firing
5) gas/oil to coal-based gas firing
6) gas/oil to coal-based liquid firing
A technical analysis of these fuel switching methods indicated that each one
has some potential application to existing industrial boilers. However,
boiler modification to switch from gas/oil to coal firing does not appear
feasible except in cases where the boiler was originally designed to fire coal.
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The six fuel switching methods were then applied to three standard
boilers. These boilers are:
1) 4.4 MW, natural gas fired, fire tube boiler
2) 4.4 MW, distillate oil fired, fire tube boiler
3) 44 MW, residual oil fired, fire tube boiler
Based on the technical analysis of fuel switching methods, it was determined
that some fuel switching methods were not applicable to the standard boilers.
By considering various fuel characteristics, a total of twenty fuel switch-
ing scenarios was identified (Table 2-1). As shown, the natural gas and
distillate oil boilers have a more limited number of fuel switching options.
This is because these boilers cannot practically burn any fuel containing
ash (EG-016). The residual oil fired boiler on the other hand, is a con-
servatively designed unit and thus has more flexibility in the type of fuels
which can be burned.
Annual costs were estimated for each of the twenty fuel switching
scenarios presented in Table 2-1. Costs were determined for three cases.
In the first case, costs were estimated without consideration of any regu-
lations. This determined "base-line" costs. In the second case, costs
estimates included changes for pollution control equipment. For the third
case, the range of impact from provisions of the National Energy Plan were
determined. Based on these costs estimates, expected fuel switches were
determined.
Table 2—2 presents the fuel switching methods which are expected
to be employed by existing boilers similar to the three standard boilers.
As shown, small gas and oil fired units are not expected to switch fuels
except under the maximum impact of the National Energy Plan. The residual
oil fired boiler is expected to switch fuel to low-sulfur coal firing under
all conditions. However, because of the low coal prices used in the cost
analysis, the number of fuel switches to coal will be limited.
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TABLE 2-1. FUEL SWITCHING SCENARIOS FOR THREE STANDARD BOILERS
4.4 MW Natural Gas Fired
Fire Tube Boiler
4.4 MW Distillate Oil Fired
Fire Tube Boiler
44 MW Residual Oil Fired
Water Tube Boiler
Natural gas to distillate oil/
boiler modification
Natural gas to low-Btu gas/
boiler modification
Natural gas to medium-Btu gas/
boiler modification
Natural gas to high-sulfur
coal/boiler replacement
Natural gas to low-sulfur
eastern coal/boiler
replacement
Natural gas to low-sulfur
western coal/boiler
replacement
Distillate oil to low-Btu gas/
boiler modification
Distillate oil to medium-Btu
gas/boiler modification
Distillate oil to high-sulfur
coal/boiler replacement
Distillate oil to low-sulfur
coal/boiler replacement
Distillate oil to low-sulfur
western coal/bo Her
replacement
Residual oil to low-Btu gas/
boiler modification
Residual oil to medium-Btu gas/
boiler modification
Residual oil to COM I1/boiler
modification
Residual oil to COM 2l/boiler
modification
Residual oil to COM 31/boiler
modification
Residual oil to coal-based
liquid coal/boiler modifi-
cation
Residual oil to high-sulfur
coal/boiler replacement
Residual oil to low-sulfur
eastern coal/boiler
replacement
Residual oil to low-sulfur
western coal/boiler
replacement
1Analyses of coal-oil mixtures are presented in Table 4-15.
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TABLE 2-2. EXPECTED FUEL SWITCHES FOR THREE STANDARD BOILERS
Basis
Standard Boiler
4.4 MW Natural Gas Fired
Fire Tube Boiler
4.4 MW Distillate Oil Fired
Fire Tube Boiler
44 MW Residual Oil Fired
Water Tube Boiler
No regulations
None
None
Low-sulfur western coal
Typical State
Regulations
None
None
Low-sulfur western coal
Minimum Impact
of NEP
None
None
Low-sulfur western coal
Maximum Impact
of NEP
None
Medium-Btu gas
Low-sulfur western coal
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SECTION 3
CONCLUSIONS
The following major conclusions were reached as a result of this study;
1) Small (4.4 MW) existing gas and distillate oil fired boilers
are not expected to switch fuels unless the supply of gas and
oil becomes insecure.
2) If small gas and distillate oil fired boilers do switch fuels,
boiler replacement to permit coal firing is the most probable
fuel switching method. Modification of the boiler to permit
medium-Btu gas firing is also expected but because no medium-
Btu gas production facilities exist and the projected produc-
tion of medium-Btu gas is expected to be limited, this fuel
switching method will not have a significant impact on exist-
ing boilers.
3) Large (44 MW) residual oil fired boilers are expected to
switch fuels. However, the extent of fuel switching will
be limited.
4) A switch from residual oil to coal by boiler replacement is
the most likely switch. However, it appears that this will
only occur if the existing boiler is close to retirement
5) A switch to coal-oil mixture firing is a definite possibility
for residual oil fired boilers if the technology becomes devel-
oped and its reliability can be demonstrated.
6) No quantitative estimate of the number of boilers which will
switch fuels can be made. This is because data on the number
of boilers in a particular location are required to assess the
impact of the fuel tax/investment credit portion of the national
energy plan on fuel switching. However, based on an analysis of
the range of the impact from the NEP, the extent of fuel switch-
ing in existing boilers is expected to be very limited. And the
the most likely fuel switching method is boiler replacement to
permit coal firing.
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SECTION 4
FUEL SWITCHING METHODS
Dwindling supplies of natural gas and oil coupled with regulations aimed
at decreasing U.S. dependence on foreign oil have changed many industries
outlook on the type of fuels they should use in their steam generators. In
fact, a drive toward increased use of coal, an abundant resource in the U.S.,
has become national policy. Unfortunately, most steam generators in opera-
tion were designed for one specific fuel and to switch to a different fuel
can prove exceedingly difficult and expensive. This is especially true in
the case of a switch from gas or oil to coal.
Many factors must be considered and many uncertainties surround a fuel
switch. This section presents a discussion of the considerations for switch-
ing fuels in industrial boilers and a description of the various methods
which can be used to switch fuels. Included as background are a description
of the types of industrial boilers in use and design considerations for these
boilers.
4.1 INDUSTRIAL BOILERS
Industrial boilers range in capacity from 0.1 to over 450 MW1 (0.4 x 106
to 1500 x 106 Btu/hr). In general, these boilers fire either gas, oil, or
coal. And some have been designed to fire two or even all three of these
fuels. In addition, some industrial boilers are capable of firing waste
fuels such as bark, saw dust, coke oven gas, coffee grounds, etc.
1The symbol MW refers to heat input to the boiler.
8
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4.1.1 Description
Industrial boilers can be classified as sectional, fire tube, and water
tube. Sectional boilers are small units with an average capacity of 7.3 x
10~2 MW (0.25 x 106 Btu/hr). These units comprise 22.5 percent of the total
industrial boiler capacity in the United States and are only suitable for
very low pressures (0.21 MPa - 30 psia). Consequently, they are frequently
used as water heaters or in space heating applications.
Because of their small size, sectional boilers are not suitable candi-
dates for fuel switching. Therefore, no further consideration will be given
to these units.
Fire tube boilers represent 18.5 percent of the U.S. industrial boiler
capacity. These boilers usually are smaller than 9 MW (30 x 106 Btu/hr) and
they are only capable of firing gas or oil (PE-346)(EG-016). In a fire tube
boiler, hot combustion gases are circulated through metal tubes which are
immersed in boiler feedwater. Heat is transferred by convection from the
combustion gases to the water, and steam or hot water is produced.
The principal advantage of a fire tube boiler is its compact design.
These boilers are shipped preassembled and ready to be connected. They
have the highest capacity per unit volume of furnace of any boiler and
they are suited for applications where space is limited.
Water tube boilers represent 59 percent of the U.S. industrial boiler
capacity. They have capacities over 450 MW (1500 x 106 Btu/hr), but more
than 90 percent of these boilers are smaller than 30 MW (100 x 106 Btu/hr)
(PE-346).
There are two types of water tube boilers: packaged and field erected.
Packaged boilers are assembled in a shop and shipped (usually by rail) to
the location where they will be used. Because of the legal and practical
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limitations of rail shipping, package boilers are small (capacities less
than 15 MW - 50 x 106 Btu/hr). The advantage of these boilers is that they
are less expensive than the field erected type.
Field erected boilers are units which are assembled at the location
where they will be used. These boilers are usually large, with capacities
ranging from 15 MW to over 450 MW (50 x 106 to over 1500 x 106 Btu/hr). In
general, most pulverized coal, waste fuel, and larger (greater than 15 MW -
50 x 106 Btu/hr) gas, oil, and stoker-fired boilers are field erected
(SC-402).
In a water tube boiler, combustion takes place in a furnace whose walls
are lined with metal tubes containing boiler feedwater (Figure 4-1). This
furnace is known as the "radiant" section of the boiler because heat is
transferred from the combustion gases to the water by radiation.
Combustion gases are cooled from 1650°C (3000 °F) to below 1100°C
(2000°F) in the furnace. These gases then flow to the "convective" section
of the boiler. There, the gases pass through banks of tubes which are filled
with water or steam. And heat is transferred from the gases by convection.
Exit temperature from this section of the boiler is approximately 370°C
(700°F). Combustion gases then flow to an air preheater where they are
further cooled as combustion air is heated. The gases may also be processed
in one of several pollution control systems to remove participates, sulfur
oxides, etc.
4.1.2 Boiler Design Considerations
The most important influence on boiler design is the fuel to be burned.
This will determine the size of the boiler and the characteristics of the
heat transfer surfaces in both the "radiant" and "convective" sections of the
boiler. The following discussion examines how the properties of gas, oil,
and coal influence boiler design.
10
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/ Steam \
I Drtim I
Water tube
Walls
1100°C
Convective Section
Radiant Section
Combustion
Air
Burner•
rfl
—<
Jit
1650CC
c
c
c
:>
c
c
)
370°C
Figure 4-1. Schematic of a water tube boiler.
11
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Perhaps the most obvious impact of various fuels on boiler design is
the difference in boiler sizes. Figure 4-2 shows the relative size of a
gas-, oil-, and coal-fired boiler with the same capacity. As illustrated,
the oil boiler requires nearly one-third more area and is 20 percent taller
than the gas-fired unit. The coal-fired boiler requires 50 percent more
area and is 60 percent taller than the gas-fired unit. Total boiler
volume comparisons are shown in Table 4-1.
TABLE 4-1. RELATIVE VOLUMES OF A GAS, OIL, AND COAL-FIRED BOILER
WITH THE SAME CAPACITY1
Boiler Type Relative Volume
Gas 1.0
Oil 1.6
Coal 2.5
Source: BU-343
There are two properties of a fuel which determine the size of a
boiler. They are:
1) The furnace heat release rate of the fuel
2) The nature and quantity of ash in the fuel
The furnace heat release rate is related to heat input, radiant surface in
the furnace, moisture content of the fuel, and radiation losses from the
furnace. This fuel property is important because it determines the minimum
furnace size required to assure complete combustion of a particular fuel.
This in turn has a direct bearing on the thermal efficiency of the boiler.
Ash is an important fuel property for several reasons. First, fuels
with ash must have furnaces which are larger than the minimum determined
by the heat release rate. This is because ash becomes molten at furnace
temperatures. If the furnace is too small, molten ash or "slag" can deposit
12
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Coal
Oil
Gas
-1.25
D
1.25 L
1.2
D
1.1 L
D
1.6 H
1.2 H
H
Figure 4-2. Relative size of a gas-, oil-, and coal-
fired boiler with the same capacity (BU-343).
13
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on furnace walls. These deposits may increase resistance to heat transfer
in the furnace. In addition, slag deposits can form on the convection tubes
at the furnace outlet. This can plug the flue gas passage and raise the gas
pressure drop through the boiler.
A second reason why ash is an important fuel property is because it
influences the design of the convective heat transfer surfaces. For natural
gas and distillate oil, the convection tubes can be arranged very close
together. This is because there is no ash to plug the gas passages. Design
gas velocities through these tubes are only limited by the gas pressure drop
through the boiler. However, for residual fuel oil and coal boilers, con-
vection tubes must be placed relatively far apart to prevent plugging of
gas passages with ash. And blowers which use compressed air or high pres-
sure steam are required to periodically clean ash deposits from the tubes.
In addition, gas velocity through the tubes must be much lower in coal-fired
units. This is necessary to prevent erosion of the tubes by entrained ash
particles.
Table 4-2 illustrates some design gas velocities through convective
section tube banks for a boiler and economizer. As shown, a coal-fired
unit has a design gas velocity between 50 and 70 percent of that in a gas-
or oil-fired boiler. The design gas velocity in the economizer section of
a coal-fired unit is between 40 and 60 percent of a gas- or oil-fired unit.
TABLE 4-2. RECOMMENDED FLUE GAS VELOCITIES THROUGH TUBE BANKS
AS A FUNCTION OF FUEL TYPE1
Fuel Type
Natural Gas
Distillate Oil
Residual Oil
Coal
low ash
high ash
Boiler
(m/s)
30.5
30.5
30.5
19.8-21.3
15.2
Tubes
(ft/sec)
100
100
100
65-70
50
Economizer
(m/s)
30.5
30.5
30.5
15.2-18.3
12.2-15.2
Tubes
(ft/sec)
100
100
100
50-60
40-50
Source: SC-402
14
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Table 4-3 shows some recommended tube spacings for a superheater,
boiler, and economizer. As illustrated, the widest variation as a function
of fuels occurs in the superheater. Design spacing for a residual oil
superheater is up to three times that of a gas or distillate oil unit
while tube spacing in a coal-fired superheater ranges from four to eight
times the spacing in gas and distillate oil units.
Constituents of fuel ash can also impact the materials of construction
used in a boiler. The presence of compounds such as sodium, vanadium, and
sulfur in ash can result in corrosion. This corrosion may occur in both
the high- and low-temperature regions of the boiler. As a result, construc-
tion materials used in the boiler must be selected to resist corrosion.
Table 4-4 presents some typical furnace design parameters. The value
of these parameters is determined by the two fuel properties: furnace heat
release rate and the nature and quantity of ash. As shown, natural gas and
oil boilers have equal values for these parameters. But coal boilers have
a much lower design value (approximately 50 percent lower). This means that,
for a given capacity, a coal-fired boiler requires approximately twice the
radiant surface and twice the furnace volume of a gas- or oil-fired boiler.
Conversely, for a given size, a coal-fired boiler will have about one-half
the steam capacity of a gas- or oil-fired boiler.
4.2 FUEL SWITCH FROM GAS TO OIL
In recent years, industrial users of natural gas have found that their
supply of gas has become insecure. In addition, regulations have been enacted
which require a reduction in natural gas consumption by industrial steam
generators. As a result, many industrial boiler operators are looking for
an alternate fuel source. Oil is a fuel which can be substituted for
natural gas in an existing boiler.
15
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TABLE 4-3. RECOMMENDED TUBE SPACING AS A FUNCTION OF FUEL TYPE1'2
Superheater
Front
Fuel Type
Natural Gas
Distillate Oil
Residual Oil
Coal
low ash
high ash
(cm)
5
5
10-15
20
25-41
(in)
2
2
4-6
8
10-16
Rear
(cm)
5
5
5
8-15
10-15
(in)
2
2
2
3-6
4-6
Boiler
Economizer
Front Rear
(cm)
3
3
4
4
5
(in) (cm)
1 3
1 3
1.5 3
1.5 3
2 3-5
(in)
1
1
1
1
1-2
(cm)
3
3
3
3
3
(in)
1
1
1
1
1
Source: SC-402
2Tube spacing perpendicular to flue gas flow
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TABLE 4-4. FURNACE DESIGN PARAMETERS AS A FUNCTION OF BOILER TYPEJ
Heat released per unit area Heat released per
of effective radiant surface unit volume of furnace
(J/mz's)(10aBtu/hr?ftz) (J/m3-s)(103Btu/hr-ft3)
Boiler Type
Packaged,
natural gas
Field erected,
natural gas
Packaged,
oil-fired
Field erected,
oil-fired
Spreader stoker,
coal-fired
Pulverized,
coal-fired
630
630
630
630
220-380
250-410
200
200
200
200
70-120
80-130
520-1030
260-520
520-1030
260-520
150-230
260-310
50-100
25-50
50-100
25-50
15-22
25-30
Source: SC-402
17
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4.2.1 Boiler Modification - Gas to Oil
One method of reducing natural gas consumption in existing gas-fired
boilers is to modify these boilers for oil-firing. Oil, unlike coal, has
properties similar to natural gas, and only minor modifications are required
to convert an existing gas boiler to oil-firing. This is especially true
in the case of a conversion from gas to distillate oil.
Unfortunately, the supply of oil is as unsure as the supply of natural
gas, and any conversion represents a temporary solution at best. However,
it does appear that some gas to oil conversions will take place.
The following discussion examines the technical considerations of a
conversion from gas to oil. In addition, an estimate of the costs to
perform the required boiler modifications and an estimate of the change in
emissions are presented.
4.2.1.1 Process Description - Boiler Modification/Gas to Oil—
There are two possible types of gas to oil boiler conversions. The
first is a switch to distillate oil and the second is a switch to residual
oil. Because distillate oil is a very clean fuel, it can be burned in most
existing gas boilers without a significant impact. However, residual oil
is a fuel which contains significant quantities of both ash and sulfur.
As a result, combustion of residual oil in an existing gas-fired boiler
presents a more significant problem.
The extent to which an existing gas boiler must be modified to be capa-
ble of firing oil will depend on the original design, and each boiler con-
version will be very site specific. However, there are some general consider-
ations which can be examined. They are:
1) Furnace Size
2) Oil Storage Requirements
18
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3) Boiler Modifications
4) Pollution Control Requirements
The following discussion examines each of these considerations in detail.
Furnace size—Oil has a higher furnace heat release rate than natural
gas. This is particularly true in the case of residual oil. As a result,
for a given capacity, more heat will be absorbed in an oil-fired boiler's
furnace than in a gas-fired furnace.
Heat release is an important consideration when converting a gas boiler
to oil firing. Most boilers operate with a heat release rate which provides
some margin of safety. The extent to which a gas boiler that switches to
oil will be derated depends on how large this margin is. If the gas boiler
was operating with a high furnace heat release rate (relative to good design
practices), some derating of the boiler may be required when converting to
oil. But, if the boiler was operating with a large safety margin, no derat-
ing may occur. Derating will be necessary to maintain a safe heat release
rate. This is required to prevent hot spots on the furnace walls, and in
the case of oil with a high ash content, to prevent slag deposits from form-
ing in the furnace.
Oil storage—Possibly one of the major expenditures which will be
associated with a conversion from gas to oil will be the cost of installing
oil storage tanks. Good design practices require a 10 day storage capacity.
And the space required for oil storage may present a problem at some indus-
trial locations. However, storage facilities can be installed at a remote
location and the oil can be pumped to the boiler.
Boiler modification—The first modification which will be required when
converting from gas to oil is the installation of fuel supply lines and oil
burners. Since this equipment is similar for both gas- and oil-firing, its
installation should not present a problem.
19
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Because natural gas and oil burn with different flames and have
different furnace heat release rates, boilers designed to burn these fuels
are also different, and conversion of a gas boiler to oil-firing may require
modification of boiler internals.
The presence of ash in residual oil will have a significant impact on
boiler performance. Ash can deposit on superheater and reheater tubes
which will reduce heat transfer. Coupled with increased heat absorption
in the furnace, this reduces heat absorption in the convective section of
the boiler. As a result, design steam temperatures may not be obtainable,
even at full load.
In order to obtain design steam temperatures, the following modifica-
tions may be required.
1) The addition of heat transfer surface to the superheater or
reheater.
2) The removal of heating surface from the furnace. This can
be done by addition of a dividing wall which effectively
reduces the size of the furnace.
Unfortunately, space or other physical limitations may prevent making the
heating surface changes needed to permit the boiler to operate at design
steam conditions.
In addition to depositing on superheater and reheater tubes, ash can
deposit in the economizer and air preheater. This could result in plugging
of the flue gas passage. Therefore, soot blowers may be required to peri-
odically remove any ash deposits.
Modification of existing fans may be required in a gas to oil conver-
sion. The pressure drop through the boiler will increase and a check must be
made to determine if existing fans are capable of supplying sufficient combus-
tion air for oil-firing. Generally, existing fans will be suitable, although
the margin of capacity will be reduced.
20
-------
Modifications of the economizer and air preheater may also be required
when converting from gas to oil. If the existing boiler has a finned-tube
economizer, the space between the fins can plug with ash. This will increase
gas pressure drop and reduce heat transfer in the economizer. In order to
avoid these problems, a bare-tube economizer should be installed. The new
economizer will require more tubes for equivalent heat transfer surface area
and, therefore, will require more space.
If the existing gas-fired boiler has a regenerative air preheater, the
heating surface at the cold end may need to be replaced to prevent plugging
with ash. In addition, the metal temperature required to prevent acid dew-
point corrosion must be maintained. This may require addition of a steam
coil for heating the entering air, adding a system for air recirculation
from the air preheater outlet to the forced draft fan inlet, or removing
some air preheater surface to increase the temperature of the exit flue gas.
Pollution control—A fuel switch from natural gas to distillate oil
will not result in a significant change in emissions. However, combustion
of residual oil may. The exact impact of residual oil firing will depend
on the fuel properties. Particulate control equipment may be required if
fuel ash content is high and some sulfur dioxide removal may also be neces-
sary, depending on the sulfur content of the fuel.
Estimated emission changes which result from switching to oil are pre-
sented in section 4.2.1.3. In addition, a brief discussion of applicable
pollution controls is presented.
4.2.1.2 Costs of Boiler Modification - Gas to Oil—
Converting an existing boiler from gas- to oil-firing is feasible,
but only at the expense of outage time and money. The following discussion
examines the capital and operating costs of a gas to oil conversion.
21
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Capital costs—No detailed capital cost estimates have been published
for converting a gas boiler to oil-firing. However, as a general estimate,
one study indicated that a gas to oil conversion would require approximately
three weeks of downtime and would cost approximately ten percent of the cost
of a new gas/oil-fired boiler (SC-402). Figure 4-3 presents capital costs
for a gas to oil conversion based on this estimate. However, these costs
do not include the costs which result from the outage time required to
complete the conversion.
Another estimate of gas to oil conversion capital costs can be obtained
by examining the components of boiler cost which are associated with the
conversion. For example, oil storage and handling costs for a converted gas
boiler should be identical to those for a new oil boiler. In addition, these
costs represent the major cost of a gas to oil conversion. By assuming oil
storage and handling costs represent 75 percent of gas to oil conversion
costs, total capital costs can be estimated. Figure 4-4 presents estimated
conversion costs based on this assumption. The costs presented in Figure 4-4
represent 15 to 20 percent of new boiler costs.
Based on the cost data in Figures 4-3 and 4-4, it appears that modifi-
cations required to convert an existing gas boiler to oil-firing will have a
capital cost of less than 25 percent of the capital costs of a new boiler.
However, these costs do not include expenses associated with outage time
required for completion of boiler modifications. These expenses will be very
site specific and they may actually be eliminated if spare steam generating
capacity is available.
Operating and maintenance costs1—The operating and maintenance costs
(O&M) for gas and oil boilers are nearly identical, and very little change
should occur after a conversion from gas to oil. In fact, gas and oil O&M
Operating and maintenance costs do not include fuel costs.
22
-------
costs are so close that most cost estimators present only one estimate for
both gas- and oil-fired units (EN-761).
Figure 4-5 presents estimated O&M costs for a gas and oil-fired boiler.
As shown, these costs are relatively insensitive to boiler size below 30 MW
(100 x 10s Btu/hr). However, above 30 MW, these costs rise more rapidly.
This behavior is probably due to the fact that a base labor force is required
to operate a boiler plant regardless of size. At 30 MW, the labor require-
ments begin to increase exponentially with boiler size.
4.2.1.3 Environmental Impact—
Conversion of a gas-fired boiler to oil-firing may result in an increase
in emissions. If the conversion is from gas to distillate oil, the change
in emissions will be minimal, but if the conversion is from gas to residual
oil, significant increases in nitrogen oxide and sulfur dioxide emissions
may occur. The following discussion presents an estimate of the change in
emissions which result when an industrial boiler switches from gas to oil.
In addition, applicable emission control techniques are identified.
Estimated emissions—The estimated change in emissions which results
when a gas boiler is converted to oil firing is presented in Table 4-5.
Estimates are included for conversion from gas to both distillate and resid-
ual oil. As shown in Table 4-5, sulfur dioxide emissions increase somewhat
when a gas boiler is converted to distillate oil-firing. Emissions of other
criteria pollutants do not change markedly.
The conversion from gas to residual oil results in a significant in-
crease in sulfur dioxide emissions and a tripling in the emissions of nitro-
gen oxides. Again, emission rates of other criteria pollutants do not
change significantly.
-------
-01 10,000-
o
o
o
u
0)
o
o
1,000-
100-
10
IIII Milt
100
1 I I I I I I
1,000
I I I I I I
Boiler Capacity (MM)
Figure 4-3. Estimated capital costs of a gas to oil conversion
based on new boiler costs ($1978).
Source: (EN-761), (SC-402)
24
-------
1,000-
a
s
1
i
100 _
10
I I I
I I I 111
10
I I I
I I I I 11
100
I I I I I 111
Boiler Capacity (MW)
Figure 4-4. Estimated capital costs of a gas to oil conversion
based on oil storage costs ($1978).
Source: (IC-005)
25
-------
1,000-
o
o
100-
10-
I I I 11 III
10
I I I 11 III
100
1—I I I 11 III
Boiler Capacity (MW)
Figure 4-5. Estimated operating and maintenance costs for a
gas- and oil-fired boiler.
Load Factor: (4000 hrs/yr at 100 percent capacity)
Source: EN-761
26
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TABLE 4-5. ESTIMATED CHANGE IN EMISSIONS WHICH RESULTS FROM A GAS TO OIL FUEL SWITCH1
Change in Emission Rate
Pollutant
Participates
Sulfur dioxide
Nitrogen oxides as NO 2
Carbon Monoxide
Hydrocarbons as CHi*
Gas to
ng/J
7.7
215.0
43.0
8.2
1.8
distillate oil*
lb/10° Btu
1.8xlO"2
0.5
0.1
1.9xlO~2
4.2xlO~3
Gas to
ng/J
37.4
1332.8
86.0
8.2
1.8
residual oil*
lb/10" Btu
8 . 7xlO~2
3.1
0.2
1.9xlO~2
4.2xlO~3
Emission rates were calculated based on emission factors supplied by PEDCo (PE-348).
Fuel analyses are:
Sulfur
Ash
HHV
Natural Gas
Trace
Trace
37.3 (MJ/m3)
Distillate Oil
0.5 percent
Trace
38.8 (MJ/fc)
Residual Oil
3.0 percent
0.1 percent
41.8 (MJ/fc)
-------
TABLE 4-6. A COMPARISON OF EMISSIONS FROM OIL-FIRED INDUSTRIAL
BOILERS TO "TYPICAL" STATE REGULATIONS1
00
Emission rate
Distillate oil Residual oil
Pollutant
Particulates
Sulfur dioxide
Nitrogen oxides as N02
Carbon monoxide
Hydrocarbons as CHi*
Source: (PE-348)
2 Fuel analyses are:
ng/J
9.0
215.0
86.0
15.5
3.1
Sulfur
Ash
HHV
lb/10b Btu ng/J
2.1xlO~2 38.7
0.5 1332.8
0.2 133.3
3 . 6xlO~2 15 . 5
7.2xlO~3 3.1
Distillate Oil
0.5 percent
Trace
38.8 (MJ/A)
lb/10b Btu ng/J lb/10b Btu
9.0xlO~2 43.0 0.1
3.1 687.8 1.6
0.31 129.0 0.3
3.6xlO~2
7.2xlO~3
Residual Oil
3.0 percent
0.1 percent
41.8 (MJ/Jl)
-------
Table 4-6 compares emissions from distillate and residual oil boilers
with "typical" state regulations. These "typical" regulations were identi-
fied by PEDCo Environmental Specialists as representative of all regulations
(GI-155). Comparison of typical state regulations with estimated emissions
indicates the severity of the emission increase which results from a gas to
oil fuel switch. As shown, conversion to distillate oil will not result in
any emission rates which are higher than those allowed by the typical regu-
lations but conversion from gas to residual oil results in emission rates of
sulfur dioxide and nitrogen oxides which are above the typical regulations.
Pollution control equipment—A detailed examination of pollution control
equipment is being prepared as part of the study to develop background infor-
mation for industrial boiler NSPS. The following discussion briefly examines
the applicability of available pollution control technology to a gas-fired
boiler which has been converted to oil.
Particulate control - It does not appear that particulate control equip-
ment will be required by boilers which convert from gas to distillate oil,
and these controls may not be needed on gas boilers which convert to low-ash
residual oil. Because an existing gas-fired boiler does not have particulate
control equipment, it is unlikely that space is available for installation of
such equipment. It appears likely that before particulate control equipment
would be retrofitted to a gas-fired boiler, a supply of low-ash oil would be
obtained.
Sulfur dioxide control - Flue gas desulfurization (FGD) is the principal
control technique for removing sulfur dioxide from boiler flue gases.
However, in the case of residual oil, it is possible to treat the fuel prior
to combustion to remove sulfur. In a situation where an existing gas-fired
boiler requires SOg control after conversion, low sulfur fuel oil will prob-
ably be used to limit SOa emissions.
29
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The difficulty of retrofitting an FGD system to an existing boiler,
coupled with the increase in operating costs, the potential for a decrease
in overall system reliability and the need to dispose of by-product or
waste material produced by the FGD system will definitely limit the use of
FGD on converted gas boilers.
Nitrogen oxide control - There are two basic methods for controlling
nitrogen oxide emissions from industrial boilers. They are:
1) Combustion Modification
2) Flue Gas Treatment (FGT)
Combustion modifications limit NO emissions by limiting the formation
of NOV in the boiler. Flue gas treatment limits NOV emissions by removing
X X
it from the flue gas after it has been formed.
Based on the emission estimates presented in Table 4-6, it appears that
only a slight reduction in N0x emissions may be required by a boiler which
has converted from gas to oil. Combustion modifications appear best suited
for obtaining this reduction.
In general, combustion modifications are capable of reducing NOX
emissions from a boiler by 30 to 50 percent. They could easily be incor-
porated into the boiler modifications when the unit is converted from gas
to oil.
Flue gas treatment cannot be widely used in a retrofit application due
to space considerations. In addition, FGT technology has not been demon-
strated, and the cost of applying FGT is significantly higher than the cost
of combustion modifications.
30
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4.3 FUEL SWITCH FROM GAS AND OIL TO COAL
Operators of gas- and oil-fired industrial steam generators can switch
to coal as a fuel by several methods. These switching methods fall into two
categories. The first is direct combustion of coal. Switching methods in
this category include:
1) Replacement of an existing gas- or oil-fired boiler with a new
coal-fired unit. This could include fluidized bed combustion
of coal when the technology becomes developed.
2) Modification of an existing gas- or oil-fired boiler to permit
direct combustion of coal.
3) Modification of an existing gas- or oil-fired boiler to permit
combustion of a coal-oil slurry.
The second category of switching methods is conversion of coal. Switching
methods in this category include:
1) Gasification of coal to produce a fuel which can be burned in
an existing gas- or oil-fired unit.
2) Liquefaction of coal to produce a fuel which can be burned in
an existing gas- or oil-fired unit.
There are many factors which must be considered when examining the
possibility of switching to coal. The most important are:
1) Availability of Coal - Is the potential coal user located in an
area which has a supply of coal available? Are there transporta-
tion facilities to deliver coal to the users plant site? It is
assumed for the discussion in Section 4.0 that coal is available.
2) Handling and Storage - If coal is available, it is still necessary
to unload, transport, and store the coal within the plant. Is there
space available to install coal handling and storage equipment?
3) Equipment - Is it technically and physically possible to install
the equipment required to burn coal? This includes either the
required boiler modifications or the construction of a coal con-
version facility.
31
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4) Pollution Control - The direct combustion of coal can result in
increased emissions of particulates, sulfur dioxides, and other
pollutants. In addition, coal conversion facilities have the poten-
tial to emit pollutants from various process steps. Control equip-
ment may be required to prevent these emissions.
5) Ash Disposal - All coal contains noncombustible material known as
ash. Whether direct coal combustion or coal conversion is used
as a switching method, an ash waste stream will be produced. The
equipment required to handle this ash and the space to safely dis-
pose of it must be available.
6) Costs - The costs of conversion must be outweighed by the costs
of continuing to burn natural gas or oil. This cost may be due
to fuel price differential or it may be associated with lost pro-
duction due to shortages of natural gas and oil.
4.3.1 Boiler Replacement
One method to switch from firing gas/oil to coal in an industrial boiler
is to replace an existing gas/oil-fired boiler with one designed to fire coal.
This section presents a description of the various types of coal-fired boilers
which are available and examines factors which impact the replacement of a
gas/oil-fired boiler with a coal-fired unit. In addition, the costs of
boiler replacement are presented, and changes in emissions which result when
a gas/oil-fired unit is replaced by a new coal boiler are estimated.
4.3.1.1 Boiler Replacement - Process Description—
There are several factors which must be considered by an industrial
boiler operator who is considering replacement of an existing gas/oil boiler
with a coal-fired unit. These factors are:
1) Coal Availability
2) Auxiliary Equipment
3) Type of Boiler
4) Costs
5) Pollution Control
The following discussion examines the first three of these factors in more
32
-------
detail. Costs are addressed in Section 4.3.1.2 and Pollution Control is dis-
cussed in Section 4.3.1.3.
Coal availability—The first consideration in determining the feasibility
of replacing a gas/oil boiler is the availability of coal. An industrial
boiler operator must be able to obtain an adequate supply of coal to insure
continued production. Generally, the unreliability of a natural gas or oil
supply will be one of the reasons for switching to coal. So, before plans
for a fuel switch can progress, a supply of coal must be secured.
Several studies have been conducted which predict an adequate supply of
coal based on expected growth rates through 1985 (PR-203). However, other
studies have indicated that 250 new coal mines would be required by 1985 to
meet projected demand for coal (FU-100)- Because of these conflicting projec-
tions, it appears that coal availability must be determined on a case-by-case
basis.
Another factor which must be considered in conjunction with coal avail-
ability is the availability of transportation to deliver coal from the mine
to the site where it will be used. Generally, coal is delivered by rail or
truck, and barge transportation is common in some areas. In nearly all
instances, one, two or all three of these delivery systems are available.
However, existing transportation systems may not be capable of handling the
quantity of coal which will be needed by an individual plant site. This
aspect of fuel switching must be examined on an individual basis to determine
the transportation requirement.
Auxiliary equipment—Auxiliary equipment required as part of a new coal-
fired boiler includes coal handling and storage and ash handling equipment.
The primary consideration in selection of this equipment is the plant space
required to accommodate it. In many existing plants, space is limited or it
may not be available at all. This is especially true if the new boiler is
placed in the same location as the one which it is replacing. However,
33
-------
because a completely new unit is being installed, its location is restricted
only by land availability.
The actual design of a coal handling system is very site-specific.
Whether the system is simple or complex depends on how coal is received, how
the plant is situated, and what is expected from the system in terms of capa-
city, flexibility, etc. There are many kinds of handling equipment available
to meet individual plant requirements. A general list of these is presented
in Table 4-7. As shown, there are many methods for coal handling and storage
and combinations of these can result in a large variety of coal handling systems.
There are three basic types of ash handling systems in use. They are:
1) Vacuum
2) Pneumatic
3) Wet Sluicing.
The vacuum system is commonly used in plants which product 750 metric tons/day
or less of ash (approximately 220 MW - 750 x 106 Btu/hr). Key elements in
this system are: a conveyor pipeline for moving ash and dust from collecting
hoppers at the stack and furnace, an airtight receiver for separating ash and
air, an automatic discharge gate for channeling ash to a storage bin, an air
washer to collect ash and dust particles before discharge of the air, and a
steam, hydraulic, or mechanical exhauster.
For plants which produce between 750 and 2500 metric tons/day of ash,
pneumatic ash handling systems are employed. These systems are similaf to a
vacuum system. However, positive pressure rather than a vacuum provides the
driving force to convey the ash. Because pressure in a pneumatic system is
not limited (in a vacuum system the highest driving force is limited to the
difference between the vacuum and atmospheric pressure), larger quantities
of ash can be conveyed for longer distances.
34
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TABLE 4-7. AVAILABLE COAL HANDLING AND STORAGE EQUIPMENT1
Unloading
Storage
Handling
Ul
Rail Car and Barge Movers
Rail Car Thawing Equipment
Rail Car Shakers/Unloaders
Rotary-Car Dumpers
Cranes and Buckets
Self-Unloading Boats
Unloading Towers
Portable Conveyors
Lift Trucks with Scoops
Track Hoppers
Feeders
Weighing Equipment
Bulldozers
Scrapers and Carryalls
Bridges and Tramways
Cranes and Buckets
Conveyor Systems
Bins and Bunkers
Silos
Indicators
Alarms
Vibrators
Gates and Valves
Skip Hoists
Bucket Elevators
Belt Conveyors
Flight Conveyors
Screw Conveyors
Stacking Conveyors
Chutes
Lift Trucks
Monorails and Tramways
Source: PO-097
-------
Wet sluicing systems are employed in plants which produce over 2500
metric tons/day of ash. In general, these systems are only found in very
large power plants which require long-distance conveying of ash.
Boiler type—There are two basic types of coal-fired boilers: stoker-
fired and pulverized coal-fired. The type of boiler which is used to replace
an existing gas- or oil-fired unit will vary, depending on several factors,
the most important of which is size. In general, a stoker-fired boiler will
be used to replace units smaller than 75 MW (250 x 106 Btu/hr) and a pulver-
ized coal boiler will replace units larger than this. However, there are
some exceptions. Stokers have been constructed with capacities up to 150 MW
(500 x 106 Btu/hr) and some pulverized coal (p-c) boilers have capacities as
low as 25 MW (90 x 106 Btu/hr).
Stoker-fired boilers - In stoker-firing, coal is pushed, dropped, or
thrown onto a grate by a mechanical device called a stoker. Part of the coal
is vaporized to form a combustible gas which burns in the furnace above the
grate. The remaining coal is burned in the presence of air which flows up
through the grate. Ash, which remains after the combustion process is com-
plete, is usually removed from the furnace on a continuous basis by movement
of the grate.
Stoker-fired boilers can be divided into two general classes, depending
on the direction from which raw coal reaches the grate. These are overfeed
and underfeed stokers. The stokers classed as overfeed include the spreader
stoker and the mass-burning or crossfeed stoker. The class of underfeed
stokers includes single- and multiple-retort units.
Overfeed stokers can be further classified by the type of grate mechanism
they employ. Spreader stokers have stationary, dumping, agitating, vibrating,
oscillating, and reciprocating grate mechanisms while the mass burning stokers
have chain-grate and travelling-grate mechanisms.
36
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Spreader stoker - Spreader stokers are common in industry today. In fact,
they represent the majority of new stoker-fired boilers. One reason for this
is that they are capable of burning a wide range of coals from high-rank
eastern bituminous to lignite. In addition, these units are capable of fir-
ing many by-product waste fuels.
Spreader stokers are specified in boilers with capacities between 1.5 MW
(5 x 106 Btu/hr) and 150 MW (500 x 106 Btu/hr). Stationary grate units are
used for units at the low end of this range and moving grates at the high end.
In a spreader stoker, raw, sized coal is thrown into suspension in the furnace
by paddles, wheels, or air or steam jets. Fine coal particles in the incoming
stream of coal tend to burn in suspension during their travel across the fur-
nace. The larger pieces of coal fall to the grate and form a fuel bed.
Volatile components of this coal then vaporize and are burned in the furnace
while the remaining coal burns with air which is supplied from below the grate.
Approximately 20 to 25 percent of the coal fed to a spreader stoker burns in
suspension above the grate. As a result, the spreader stoker has a very fast
response to load swings and the load range extends from 20 percent to maximum
capacity. Unfortunately, the combustion of fine particles in suspension also
has a drawback. Suspension-burning results in increased particulate carryover
in comparison to other stokers, and much of this carryover is unburned com-
bustiles. As a result, a fly ash reinjection system is required.
Mass-burning stoker - Mass-burning stokers are either chain- or travelling-
grate, and they range in size from 2 MW (7.5 x 106 Btu/hr) to 75 MW (250 x
10s Btu/hr). The chain-grate stoker design was developed for bituminous coal
and the travelling-grate design for smaller sizes of anthracite.
In a mass-burning stoker, the grate resembles a wide conveyor belt. This
grate moves slowly from one end of the furnace (the feed end) to the other.
At the feed end, coal sized below 3.2 cm (1.25 inches) is supplied to the
•grate from a hopper. As the coal moves toward the opposite end of the fur-
nace, it is ignited, vaporization of volatile compounds occurs, and coke is
formed. This coke is burned and the fuel-bed gets progressively thinner.
37
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By the time the coal reaches the far end of the furnace, nothing remains but
ash which falls off the grate into an ash pit.
As a class, mass-burning stokers are well suited for a variety of solid fuels.
Peat, lignite, subbituminous, free-burning bituminous, or anthracite can be
burned. However, strongly caking bituminous coals present a problem. These
coals have a tendency to mat and prevent proper passage of air through the
fuel bed, causing unburned carbon to be discharged into the ash pit. Strongly
caking coals also impact a mass-burning stoker's ability to respond to rapidly
changing load.
Single- and multiple-retort stokers - Single-retort stokers range in size
from 1.5 MW (5 x 106 Btu/hr) to 15 MW (50 x 106 Btu/hr) while multiple-retort
stokers, although rarely purchased now, have been built in sizes ranging from
15 MW (50 x 106 Btu/hr) to 120 MW (400 x 106 Btu/hr) (PO-098).
Single- and multiple-retorts are underfeed stokers. As the name implies, raw
coal is fed onto the grate from below. Coal, sized below 3.2 cm (1.25 inches),
is pushed from a trough or retort located in the center of the grate onto the
grate. This coal, which is dried somewhat in the retort, ignites once on the
grate. Volatile material is vaporized and is burned in the furnace. The coke
formed is burned as it travels across the grate into an ash pit (BE-530).
Underfeed stokers, especially the multiple-retort type, were used extensively
some years ago. This was primarily due to the ability of the retort system
to burn highly caking coals. However, the high initial capital cost and high
maintenance costs associated with these units have made them less competitive
in the present industrial boiler market (FU-100)-
Pulverized coal-fired boilers - Pulverized coal (p-c) boilers only become
economical in sizes above 75 MW (250 x 106 Btu/hr) even though they are 3 to 5
percent more efficient than stoker-fired boilers. The reason for this is that
the capital and operating costs associated with coal pulverizers are higher
than the costs of stoker firing. Only in larger units do fuel savings out-
weigh the increased costs of p-c firing (PO-098).
38
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In a p-c boiler, raw coal is dried and pulverized in a coal mill to pro-
duce a fine, dry, powdered coal. Typical coal product from the mill is 70
percent less than 0.74 Urn (200 mesh) with less than 2 percent larger than
297 ym (48 mesh). This pulverized coal is then conveyed pneumatically to
the boiler. The air which dries and conveys the coal is primary combustion
air which has passed through the preheater.
Once the pulverized coal reaches the boiler it is injected into the fur-
nace where volatile components are vaporized. Enough air is introduced with
the coal to burn these volatiles. The char which remains is heated by com-
bustion of the volatiles and it burns in suspension in the furnace. Secondary
air, which is introduced around the burner, supplies oxygen for combustion
of the char.
Although p-c units are a single class of boilers, there are variations
in the type of pulverizer and the type of burners which are used. Table 4-8
presents a list of the various pulverizers and burners. The specific equip-
ment which is used at a particular plant will depend on coal characteristics
and the size of the boiler.
TABLE 4-8. TYPES OF PULVERIZED-COAL EQUIPMENT1
Burners
Pulverizers
Horizontal Burner
Circular Register Burner
Intervane Burner
Directional Burner
Ball Mill
Tube Mill
Roll-and-Race Pulverizer
Ball-and-Race Pulverizer
Bowl Mill
Attrition Mill
Source: PO-098
39
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The major advantage of a p-c boiler is the improved thermal efficiency
of this type of unit. Principal disadvantages are increased capital and
operating costs and increased particulate emissions over those associated
with a stoker-fired boiler. The increased costs are associated with the
initial price and high operating costs of the coal mills. The increased
particulate emissions result because suspension burning of the coal promotes
carryover of fly ash from the furnace. In stoker-firing, most of this ash
remains on the grate and is collected in the ash pit.
4.3.1.2 Costs of Boiler Replacement—
The costs of replacing an existing gas/oil-fired boiler have not been
estimated. However, costs of new coal-fired boilers are available.
The costs of a new boiler may be higher than the costs of replacing
an existing boiler. If existing fans, steam lines, feedwater treatment, etc.
can be used, costs of replacement may be approximately 15 percent less than
the cost of a new boiler (IC-005). But, if the new boiler must be installed
with all new facilities, savings will not be significant.
Capital costs—The capital costs for a new boiler include the direct
costs of land, permits, yardwork, fuel handling, storage, boiler house, boiler
equipment, ash handling, and utilities. In addition, indirect costs associated
with construction, engineering, contingency, and working capital are included.
Figure 4-6 presents a comparison of the capital costs of stoker-, pul-
verized coal-, and gas/oil-fired boilers. As illustrated, the costs of
these boilers increase exponentially as a function of boiler size. The
value of the exponent is approximately 0.8. The cost data presented in
Figure 4-6 are based on manufacturers prices. The Chemical Engineering
plant cost index was used to escalate costs to mid-1978.
The boiler costs presented in Figure 4-6 show that a p-c boiler costs
between 1.2 and 1.25 that of a stoker-fired unit. The economic breakpoint
40
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100,000 _
co
a
I
10,000 -
1,000
^_ Pulverized Coal-Fired
Stoker-Fired
^—Gas/Oil-Fir ed
10
III! I I I I II II I I I I I I I I I I
100 1000
Boiler Capacity (MW)
Figure 4-6. A comparison of stoker-, pulverized coal- and gas/
oil-fired boiler capital costs (1978$).l
Source: EN-761, CO-735
41
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between stoker firing and p-c firing occurs around 75 MW (250 x 106 Btu/hr).
The exact size where this occurs depends primarily on the cost of coal.
A comparison of stoker costs to gas/oil fired costs indicates that a
stoker requires 2.0 to 2.25 times more capital to install, while a p-c
boiler's capital costs are 2.5 to 2.7 times those of a comparably sized gas/
oil boiler. Because of these large cost differences, the driving force for
a voluntary fuel switch will be a high fuel price differential.
Table 4-9 presents estimated fuel price differentials required to make
coal-firing as economical as gas/oil-firing. The coal-fired boiler costs are
for stoker-fired units. As shown, coal prices must be 0.92 to 1.50 dollars/GJ
(0.97 to 1.58 $/106 Btu) lower than gas/oil prices. However, these estimates
do not include pollution control. One estimate indicates that control equip-
ment for a coal-fired boiler costs between thirty to fifty percent as much as
the boiler itself (IC-005). This would increase the required fuel price
differential to over 2.25 dollars/GJ (2.37 $/106 Btu).
TABLE 4-9. ESTIMATED PRICE DIFFERENCE BETWEEN COAL AND GAS/OIL
REQUIRED FOR BOILER REPLACEMENT TO BE ECONOMICAL1
Boiler Capacity2 Fuel Price Differential3*1*
(Gas-Coal)
MW 106 Btu/hr $/GJ $/106 Btu
25
50
100
200
85.3
170.6
341.3
682.6
1.50
1.28
1.21
0.92
1.58
1.36
1.28
0.97
1These costs are based on replacing a new gas/oil boiler.
2Costs are estimated at 4000 hrs/year operation at 100 percent
of capacity.
3This price differential is based on a 20 percent annual return
on capital.
**No pollution control equipment is included in this estimate.
42
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Figures 4-7 and 4-8 present projected capital costs for stoker and p-c
boilers respectively. Costs are projected for 1985, 1990, and 1995 based on
a linear extrapolation of historical boiler cost data supplied by Babcock
and Wilcox (SM-201).
Operating and maintenance costs—The operating and maintenance (O&M)
costs for a coal-fired boiler are presented in Figure 4-9. As illustrated,
these costs are relatively insensitive to boiler size below 30 MW (100 x
106 Btu/hr). However, above 30 MW, these costs increase rapidly (EN-761).
Table 4-10 presents O&M costs as a percentage of annualized costs. As
illustrated, these costs represent between 7 and 16 percent of the annualized
costs.
TABLE 4-10. OPERATING AND MAINTENANCE COSTS FOR A COAL-FIRED BOILER
AS A PERCENTAGE OF ANNUAL COSTS1
Operating and Maintenance Costs3
(% of Annualized Costs)
Boiler Capacity2
MW 106 Btu/hr
25 85.3
50 170.6
100 341.3
200 682.6
High Sulfur
Coal
15.6
14.8
12.2
9.9
Low Sulfur
Coal (eastern)
13.7
12.9
10.5
8.4
Low Sulfur
Coal (western)
12.2
11.4
9.1
7.3
1Annual costs are estimated at a 20 percent annual return on capital.
2Costs are estimated at 4000 hrs/year operation at 100 percent of capacity.
31978 costs for coal are: High Sulfur Coal - 0.70 $/GJ (0.74 $/106 Btu)
Low Sulfur Coal (eastern) - 1.13 $/GJ (1.19 $/106
Btu)
Low Sulfur Coal (western) - 1.58 $/GJ (1.67 $/106
Btu)
43
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loo.ooo-
o
o
o
a
a
u
a
u
•H
a.
10,000-
1,000-
r r i
10
i 111
100
i i i
i 111 r
1,000
I I I I I 111
Boiler Capacity (MW)
Figure 4-7- Projected capital costs for a stoker-fired boiler.
Source: EN-761, CO-735, SM-201
44
-------
o100,000-
8 :
o
u
a.
a
u
10,000-
1,000.
n TT
10
I I I I I
100
I I I NT
1,000
I I I I I I I I
Boiler Capacity (MW)
Figure 4-8. Projected capital costs for a pulverized coal-fired boiler
Source: EN-761, CO-735, SM-201
45
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1,000-
o
o
o
m
8
1-1
9
1
100 _
10'
I I I I I I 11 I I I I I I I 11
10 100
Boiler Capacity (MW)
I I I I I I I I I
Figure 4-9. Estimated operating and maintenance costs for a
coal-fired boiler.
Load Factor: (4000 hrs/yr at 100 percent capacity)
Source: EN-761
46
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Figure 4-10 compares coal-fired boiler O&M costs with those of natural
gas/oil. As illustrated, coal-fired costs are approximately four to five
times greater. The main reason for this cost increase is the difference in
labor requirements for boilers firing these fuels.
4.3.1.3 Environmental Impact—
Replacement of an existing gas/oil-fired boiler with a coal-fired unit
will result in an increase in uncontrolled emissions. However, pollution
control systems are available to reduce these emissions. The following dis-
cussion examines emissions from a coal-fired boiler. Emission estimates for
particulates, sulfur dioxide, nitrogen oxides, carbon monoxide, and hydro-
carbons are included. In addition, applicable emission control techniques
are identified.
Estimated emissions—Table 4-11 compares the estimated emissions from
four different coal-fired boilers to typical state regulations. These esti-
mates are for uncontrolled emissions and are based on emission factors devel-
oped by PEDCo Environmental Specialists (PE-348).
As shown in Table 4-11, all of the 12 cases have higher emission rates
of particulates than those allowed by the typical state regulations, 4 of the
12 have emission rates of sulfur dioxide which are above typical state limits,
and none of the emission rates for nitrogen oxides are higher than the typical
state regulations. The comparison in Table 4-11 indicates that sulfur oxide
and particulate pollution controls may be required by smaller units.
Pollution control equipment—A detailed examination of pollution
control techniques which are applicable to industrial boilers is being
conducted as part of the study to develop background information to support
industrial boiler NSPS. The following discussion briefly examines the
applicability of available pollution control technology to a new, coal-
fired industrial boiler.
47
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1,000 -
o
o
o
1
100 _
10
••-Coal-Fired Boiler
•*—Gas/Oil-Fired Boiler
TTTT 1 1 I I I I III
10 100
Boiler Capacity (MM)
Figure 4-10. Comparison of operating and maintenance costs of a
gas/oil-fired boiler and a coal-fired boiler.
Load Factor: (4000 hrs/yr at 100 percent capacity)
Source: EN-761
48
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TABLE 4-11.
A COMPARISON OF ESTIMATED INDUSTRIAL COAL-FIRED BOILER
EMISSIONS TO TYPICAL STATE REGULATIONS1
vo
High Sulfur Coal7 Low Sulfur
Boiler Type
Underfeed Stoker
Chalngrnte Stoker
Spreader Stoker
Pulverized Coal
'Source (PE-348)
Pollutant
partlculates
sulfur dioxide
nitrogen oxides as NOj
carbon monoxide
hydrocarbons as CIU
partlculatea
sulfur dioxide
nitrogen oxides as NO:
carbon monoxide
hydrocarbons as CIU
partlculates
sulfur dioxide
nitrogen oxides as NO:
carbon monoxide
hydrocarbons as CH»
partlculates
sulfur dioxide
nitrogen oxides as NO]
carbon monoxide
hydrocarbons as CH»
ng/J
945.8
1805.7
154.8
36.5
18.1
859.9
2450.8
107.5
36.5
18.1
1074.9
3611.6
249.4
36.5
18.1
2751.7
1719.8
254.5
18.1
5.6
High Sulfur Coal Low
2 Fuel analyses are:
Sulfur 3.5 percent
Ash 10.6 percent
HHV 27,500 (kJ/kg)
lb/10* Btu
2.2
4.2
0.36
8.5xlO~2
4.2xlO~2
2.0
5.7
0.25
8.5xiO~2
4.2x10"*
2.5
5.9
0.58
8.5xlO~z
4.2x10"'
6.4
4.0
0.59
4.2xlO~2
1.3xlO~2
Sulfur Eastern
0.9 percent
6.9 percent
32.150 (kJ/kg)
ng/J
S37.4
387.0
154.8
31.0
15.5
473.0
537.4
107.5
31.0
15.5
601.9
558.9
249.4
31.0
15.5
1547.8
387.0
254.5
15.5
4.7
Coal Low
Eastern Coal'
lh/10" Btn
1.25
0.9
0.36
7.2xlO~2
3.6x10"'
1.1
1.25
0.25
7.2xlO"2
3. 6x10" 2
1.4
1.3
0.58
7.2xlO"2
3.6xlO~2
3.6
0.9
0.59
3. 6x10" 2
l.lxlO~2
Sulfur Western
0.6 percent
5.4 percent
22,370 (kJ/kg)
Low Sulfur
ng/.l
601.9
387.0
154.8
44.7
22.4
533.1
515.9
107.5
44.7
22.4
687.9
537.4
249.4
44.7
22.4
1719.8
365.5
254.5
22.4
6.9
Coal
Western Coal2
lh/10* Btu
1.4
0.9
0.36
10.4x10"'
5.2x10"'
1.24
1.2
0.25
10.4xlO~2
5.2x10"'
1.6
1.25
0.58
10.4xlO~2
5. 2x10" *
4.0
0.85
0.59
5.2xlO~2
1.6xlO~2
Typical State Recnlat IUIIH
nR/J "Th'/in Bui
257.9
1075.0
301.0
_
-
257.9
1075.0
301.0
_
-
257.9
1075.0
301.0
_
-
257.9
1075.0
301.0
-
-
0.6
2.5
0.7
_
—
0.6
7.5
0.7
_
-
0.6
1.2
0.7
_
-
0.1
1.2
0.7
_
-
-------
Particulate control - There are four types of pollution control
equipment which can be used to reduce particulate emissions in flue gas
from an industrial boiler. They are:
1) Mechanical Collectors
2) Fabric Filters
3) Electrostatic Precipitators
4) Wet Scrubbers.
Mechanical collectors - Mechanical collectors are efficient devices for re-
moving relatively large particles from flue gas. They can be designed to
remove 98 percent of the particles above 5 ym (6.0 x 10 6 ft) at an inter-
mediate pressure drop (0.75 to 1.0 kPa - 3 to 4 inches HaO). These collec-
tion devices are more applicable to emissions from stoker-fired units than
p-c units. This is because over 90 weight percent of the particulate emis-
sions from a stoker-fired boiler are larger than 5 x 10 6m. This compares
with approximately 80 weight percent larger than 5 x 10 6m for p-c boilers
(HU-234).
Mechanical collectors may be required on a stoker-fired industrial boiler
to collect fly ash particles which contain unburned carbon. These particles
can be reinjected into the boiler to improve thermal efficiency. However,
it is unlikely that mechanical collectors will be used on industrial boilers
to meet emission regulations. In general, these devices are not efficient
enough to economically reduce emissions to required levels.
Fabric filters - Fabric filters are capable of removing over 99.5 percent
of incoming particulates from coal-fired flue gas and the collection effi-
ciency depends only on the physical properties of the fly ash. But these
filters operate at a intermediate pressure drop (1.0 to 1.5 kPa - 4 to 6
inches HaO) with consequent high operating costs.
50
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One study conducted by Enviro-Systems and Research, Incorporated indicated
that, although fabric filters have a higher operating cost than electro-
static precipitators, the lower capital costs of the filters make them
economically competitive on an annualized cost basis. This study was for
a low sulfur coal and the results may not apply to the high sulfur case.
However, it does appear that fabric filters are applicable for controlling
emissions from coal-fired industrial boilers (MC-120) .
Electrostatic precipitators - Electrostatic precipitators (ESP) have been
installed on many coal-fired boilers in the past. ESP's are capable of
removing 99.9 percent of particulates from an industrial boiler flue gas
and the pressure drop across an ESP is very low (0.25 to 0.5 kPa - 0.5 to
1.5 inches HjO).
Unlike a fabric filter, the collection efficiency of an ESP depends on the
chemical properties of the fly ash. As a result, ESP's may not be suitable
for application on all coal-fired boiler flue gases. This is particularly
true of flue gas from the combustion of western coals.
Wet scrubbers - Wet scrubbers are capable of removing over 99 percent of the
fly ash in the flue gas from a coal-fired boiler, but only at very high
pressure drops (5.0 to 7.5 kPa - 20 to 30 inches of water) with resultant
high operating costs. In addition, the water handling systems associated
with wet scrubbing add to the operating costs.
In general, wet scrubbers are not economical for particulate control.
However, if sulfur dioxide (SOa) is a problem, wet scrubbers can be used to
control emissions of both particulates and
Sulfur dioxide emissions - There are three methods which can be used to
limit SOz emissions from a new, coal-fired industrial boiler. They are:
51
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1) Use of Low Sulfur Coal Fuel
2) Physical and Chemical Coal Desulfurization
3) Flue Gas Desulfurization (FGD)
The first two of these methods limit SOa emissions by reducing the quantity
of sulfur in the fuel to the boiler while FGD removes SOa from the flue gas
leaving the boiler.
The use of low sulfur coal is the simplest method to limit SOa emissions.
However, the supply of low sulfur coal is limited. One study estimates that
only 9 percent of the United States coal reserves are low enough in sulfur
to meet current utility boiler NSPS (PE-289). As a result, low sulfur coal
will only be used on a limited basis in new coal-fired industrial boilers.
Physical and chemical coal cleaning are processes which treat a high
sulfur coal to produce a low sulfur coal product. Physical coal cleaning can
be adapted to remove up to 80 percent of coal pyrites (comprising 20 to 80
percent of total sulfur content depending upon the characteristics of the
coal) but, to accomplish this, more refined processing methods are necessary.
As a result, physical coal cleaning will have only a limited role in reducing
S02 emissions from coal-fired industrial boilers (ST-562).
Chemical coal cleaning has the potential for removing 95 percent of the
pyritic sulfur and 40 percent of the organic sulfur from coal. EPA is cur-
rently conducting tests on a prototype unit using an aqueous ferric sulfate
leaching process and is also evaluating seven or eight other processes for
future study. Commercialization of chemical coal cleaning processes is not
expected before the mid 1980's (ST-562).
Flue gas desulfurization appears to be the technology which will be
widely applied to limit SO emissions from new, coal-fired industrial boilers.
FGD systems are capable of achieving over 90 percent reduction in SO emis-
sions from coal-fired boiler flue gases. However, FGD systems are generally
52
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complex and they have the potential to reduce the reliability of the boiler
system. This could present a problem to many industrial users. In addition,
FGD systems produce a by-product or waste stream which contains the sulfur
that was removed from the flue gas. Disposal of this by-product or waste
will also limit FGD system applicability. Other considerations for an FGD
system include space requirements, and the high costs associated with these
systems.
Nitrogen oxide emissions - Nitrogen oxide emissions from industrial
boilers can be limited by combustion modifications and by flue gas treat-
ment (FGT). If new, coal-fired industrial boilers are required to reduce N0x
emission levels, it is likely that their design will incorporate combustion
modifications. This will reduce potential NO emissions between 30 and 50
percent.
Flue gas treating can reduce NOX emissions by up to 90 percent.
However, this technology has not been demonstrated in the United States and
it will be expensive. As a result, FGT will not be used to reduce NOX emis-
sions unless combustion modifications cannot meet regulations.
4.3.2 Boiler Modification - Gas/Oil to Coal
Modification of an existing gas- or oil-fired boiler to permit direct
combustion of coal is technically possible. However, in nearly all instances,
the extent of the modifications required makes direct combustion of coal
practically impossible. Exceptions to this statement are gas- and oil-fired
boilers which were originally designed to fire coal. Some of these boilers
may have the potential to convert to coal.
The following discussion examines the modifications which are required
to convert a gas/oil-fired boiler to coal. Two cases are presented. The
53
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first describes the conversion of a boiler which was not designed to burn
coal. The second describes the conversion of a gas/oil-fired boiler which
was originally designed to fire coal.
4.3.2.1 Process Description - Boiler Modification - Gas/Oil to Coal—
Conversion of a boiler not designed to fire coal—The design of a boiler
is based on the type of fuel which will be burned. The fuel handling equip-
ment, combustion equipment, heat transfer surfaces, fans, pollution control
equipment, etc. all depend on the fuel. Consequently, a change in fuels in
an existing boiler will necissitate a change in almost every facet of the
boiler design. This is especially true for a switch in fuels from gas/oil
to coal.
The most obvious and unavoidable impact of switching an existing gas/oil-
fired boiler to coal will be derating of the boiler. If no provision was
made for coal-firing during the design of a boiler, the boiler cannot be con-
verted to coal-firing without reducing capacity by at least 50 percent.
The two major reasons why this derating occurs are furnace size and flue
gas velocity.
Furnace size is important because for a given capacity, a coal-fired
boiler furnace is approximately twice as large as the furnace in a gas/oil-
fired boiler. Therefore, only about one-half as much coal (based on heat
input) can be fired in an existing gas/oil-fired unit. This reduction in
firing rate is necessary to reduce the furnace heat release rate in order
to prevent hot spots in the furnace, slag formation on furnace walls, and
plugging of gas passages in the convective section of the boiler.
Flue gas velocity is important because the ash in coal requires that
flue gas velocity in a coal-fired unit be less than in a gas/oil-fired unit
to prevent erosion of tubes in the convective section of the boiler. This
design constraint would reduce boiler capacity by 30 percent in a switch
from gas/oil to coal if flue gas quantities were the same for gas/oil and
54
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coal, but for a given heat input, a coal-fired boiler produces 20 to 40
percent more flue gas. As a result, boiler capacity must be reduced
between 40 to 60 percent based on flue gas velocity considerations (FR-198).
In addition to derating a boiler, major modifications are required
before coal can be successfully fired in an existing gas/oil boiler. These
modifications are:
1) Addition of coal handling and storage equipment,
2) Addition of coal firing equipment,
3) Addition of ash handling equipment,
4) Modification of the convective section of the boiler,
5) Modification of structural steel, ductwork, and fans, and
6) Addition/modification of pollution control equipment.
The following discussion examines each of these modifications in more
detail. This discussion is based on the assumption that an adequate supply
of coal is available and that facilities exist for receiving coal at the
plant site.
Coal handling and storage - The first requirements for converting to
coal are the facilities and equipment needed for storage and handling of
solid fuel. Storage consists of both active and stockpile storage. The
active storage feeds directly to the boiler. Good design practices usually
require a 5 to 10 day supply of coal in active storage. This should prevent
interruptions in the boiler feed due to failure of in-plant coal handling
equipment.
Stockpile storage is a 30 to 90 day supply of coal. This supply is usu-
ally maintained as a coal pile, stored in the open. However, dust problems
or other considerations may require that the stockpile be enclosed. A stock-
pile is maintained to prevent interruptions in the coal supply due to mining
or transportation strikes, etc.
55
-------
Coal handling equipment is required to move coal from the unloading area
to the stockpile and from the stockpile to the active storage. Coal handling
systems can consist of front-end loaders, bucket elevators, conveyor belts,
etc.
The space required for coal storage and handling is usually extensive.
In most cases, storage and handling will require several times the area
required by the boiler. And in many instances, this space is not available.
Coal firing equipment - Extensive modification of existing gas- and oil-
fired boilers is required to install coal firing equipment. This is espe-
cially true in the case of a conversion to stoker-firing. If stoker-firing
is used, the furnace will need to be rebuilt. At a minimum, it will be
necessary to remove the existing boiler front to accommodate the coal-feed
system, to mount a mechanical grate and drive system on the boiler floor,
and to install an air supply system under the grate, an overfire air system
above the grate, and an ash pit. This may necessitate raising the boiler
20 to 30 feet above the ground.
If an existing gas/oil-fired boiler is converted to pulverized coal
firing, coal mills must be installed to crush the coal feed. Ductwork must
be modified to reroute preheated combustion air through the coal mills.
This air is needed to dry the pulverized coal and to convey it to the boiler.
Other modifications include installation of pulverized coal burners, and
modification of the furnace floor to accommodate a bottom ash removal system.
Ash handling equipment - Existing gas and distillate oil boilers are not
designed to handle the ash which is in coal. And residual oil boilers are
designed to handle only a fraction of this ash. Therefore, conversion of a
gas/oil boiler to coal will require either installation or modification of
ash handling and disposal equipment.
56
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An ash handling system consists of conveying, storage, and disposal.
Most industrial operations use a vacuum system to convey ash. This system
uses the difference between atmospheric pressure and a vacuum to convey ash
from the boiler to an ash hopper. After ash has been collected in hoppers,
it is removed for disposal, usually in trucks.
Ash disposal is a major problem in many existing industrial plants.
Environmental and space considerations may require long-distance hauling of
ash. This can significantly impact the costs of disposal.
Convective section modifications - The convective section of a boiler
designed for gas/oil firing is markedly different from that of a boiler de-
signed for coal firing due primarily to the variation in ash content between
gas/oil and coal. The wide tube spacing in a coal-fired unit is designed to
prevent plugging of gas passages. For example, in a gas/oil-fired unit,
superheater tubes are spaced at 2.5 cm (1 inch) centers while in a coal-
fired unit the tubes must be spaced on 20 to 41 cm (8 to 16 inch) centers.
In order to fire coal in an existing unit, the tube spacing must be
modified. Modification will usually consist of removal of some of the tubes
from the superheater and boiler. In addition, soot blowers must be installed
to periodically remove any deposits of ash from the tubes.
Another modification which will be required is a change in the economizer
tubes. Most gas/oil-fired boilers have economizers with finned-tubes.
The fins provide extended surface area for heat transfer and permit the
economizer to be relatively compact. But the ash present in coal flue gas
will require a bare-tube economizer. This change is necessary to prevent
ash deposits from plugging gas passages and reducing heat transfer in the
economizer. Unfortunately, replacing or modifying the economizer will result
in a larger economizer because more bare tubes are required to maintain the
equivalent heat transfer surface area.
57
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Replacement or modification of the economizer will necessitate changes
in the ductwork and the boiler outlet. In addition, the air preheater may
require modifications to prevent acid corrosion.
Structural modification - Major structural modifications may be required
to convert an existing gas/oil-fired unit to coal firing. Gas and oil boilers
usually have solid floors and are bottom-supported. But coal-fired boilers
require ash removal system. Thus, they are top-supported. Conversion of a
bottom-supported boiler to coal firing will require the construction of new
foundations, supporting steel, platforms, and ductwork.
Another modification which may be required is the installation of an
induced-draft fan. Gas- and oil-fired boilers usually operate with a forced-
draft fan and a pressurized furnace. However, coal-fired boilers operate
with an induced-draft fan and a balanced pressure furnace. Therefore, it
may be necessary to modify ductwork and install a fan downstream of the air
preheater.
Pollution control equipment - Natural gas and distillate oil are very
clean fuels with respect to ash and sulfur. And they can usually be fired
without pollution control equipment. Residual oil has varying quantities of
ash and sulfur and residual oil boilers may require some particulate and
sulfur dioxide control equipment, but coal is a relatively dirty fuel.
Most coals have a very high (between 6 and 20 percent) ash content and
coal combustion will require particulate control. In addition, a large
fraction of the coal in the United States (over 90 percent) has a sulfur
content which will result in SOa emission rates above current utility boiler
NSPS if combusted without flue gas desulfurization. Therefore, major con-
sideration must be given to the pollution control equipment required in a
switch from gas/oil to coal (PE-289).
58
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At a minimum, gas and distillate oil boilers which are converted to coal
will require addition of particulate control equipment. In addition, problems
may arise with emissions of sulfur dioxide, nitrogen oxides, carbon monoxide.
and hydrocarbons. And in many cases the space required and cost of instal-
lation of pollution control equipment will prohibit a switch from gas/oil to
coal.
Conversion of a boiler originally designed to fire coal—There are some
industrial boilers currently burning clean fuels which were originally de-
signed to fire coal. One study estimates that less than A percent of the
manufacturing facilities burning gas and oil possess the capability to
switch to coal (BE-530). Of these boilers, only a limited number can actu-
ally be converted back to coal firing. For example, the Federal Energy
Administration identified 680 boilers as potential candidates for conversion
to coal. Of these, 425 were discarded as being too old or too small
(BA-669).
Reconversion of a boiler will depend on many factors such as the age
and size of the unit. Other factors will be site specific. The major con-
siderations are:
1) The condition of the original equipment associated with coal
firing.
2) The space available at the plant site for coal and ash
handling.
3) Pollution control equipment required to handle increased
emissions.
The following discussion examines each of these considerations in more detail.
Condition of coal firing equipment - The coal handling and burning
equipment for a boiler which has been converted to gas/oil will have deteri-
orated to some degree. And in many instances, this equipment may have been
completely removed from the plant. The degree of difficulty in converting
59
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back to coal will depend to a large extent on the condition of this equipment,
The conversion procedure can be as simple as lubrication and replacement of
a few parts or conversion can be practically impossible.
The difficulty in reconverting a boiler to coal firing will increase
as the length of time since coal was last fired increases. In many in-
stances, when oil or gas was substituted for coal, oil storage tanks
replaced the coal storage pile and much of the coal and ash handling
equipment was removed to keep the plant area clean. The longer the time
since conversion, the greater are the chances that this equipment was
removed. However, there are exceptions. Some plants retired the coal
and ash handling equipment with the expectation that coal firing might
become economical again. These plants should find reconverting a rela-
tively simple process (CO-735).
Space available - Coal firing requires considerably more space than gas
or oil firing. And in many cases, a converted coal-fired boiler may not have
this space available. Installation of oil storage tanks or general plant
expansion may have claimed the space originally occupied by coal and ash
handling facilities.
For example, a recent reconversion performed by Battelle's Columbus
Labs transformed an uncrowded boiler room into one which is now cramped for
space. The area of the steam plant approximately doubled and it had to be
extended from the boiler house to the parking lot (FU-100).
Pollution control - The most important consideration in reconverting a
boiler to coal-firing is the pollution control equipment required to meet
state and federal regulations. In many cases, especially in recent conver-
sions from coal to gas or oil, fuels were switched to meet regulations.
This probably resulted from an economic analysis which indicated fuel
switching was much less expensive than installation of pollution control
equipment.
60
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These boilers which were recently converted from gas/oil to coal are
probably the best candidates for reconversion from a technical standpoint.
But the costs of complying with emission regulations may prevent reconversion.
4.3.2.2 Costs of Boiler Modification - Gas/Oil to Coal—
The costs of converting an existing gas/oil-fired boiler to coal are not
well defined. Most experts agree that a fuel switch from gas/oil to coal in
a boiler not designed to fire coal will approach the costs of a new coal-fired
boiler. This is especially true if the capacity reduction which results from
fuel switching must be replaced by the purchase of additional steam generating
capacity.
The costs of converting a gas/oil-fired boiler originally designed to
fire coal back to coal are very site-specific. The unique nature of each
potential reconversion will determine the costs. The costs can range from
almost nothing to the costs of converting a gas/oil-fired boiler which was
not designed to fire coal.
No published cost data exist which specifically estimate the cost of
switching fuels from gas/oil to coal. But the costs of some of the required
boiler modifications have been estimated. The following discussion examines
these costs and presents published estimates for them.
Capital costs—Six modifications are required to convert an existing
gas/oil fired boiler to coal firng. They are:
1) Addition -of coal handling and storage equipment,
2) Addition of coal firing equipment,
3) Addition of ash handling equipment,
4) Modification of the convective section of the boiler,
5) Modification of structural steel, ductwork, and fans, and
6) Addition/modification of pollution control equipment.
61
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Of these modifications, capital cost estimates have been published for coal
handling, ash handling, and pollution control equipment.
Figure 4-11 presents capital costs of coal handling and storage equip-
ment. Figure 4-12 presents capital costs of ash handling equipment. The
costs of pollution control equipment will not be addressed in this report.
Individual Technology Assessment Reports (ITAR's) are being prepared which
contain detailed cost estimates for various pollution control technologies.
As illustrated in Figure 4-11, coal handling costs vary exponentially
as a function of boiler size. The approximate value for the exponent is 0.9.
Coal handling costs range from 6,700 to 12,500 dollars per MW of capacity
(2,000 to 3,700 dollars per 106 Btu/hr). Based on the boiler costs presented
in Section 4.3.1.2, coal handling costs are approximately 5 percent of the
costs of a new, coal-fired boiler.
Figure 4-12 shows ash handling costs for a coal-fired boiler. As
illustrated, these costs are nearly independent of boiler size for boilers
smaller than 75 MW (250 x 106 Btu/hr). Above this size, ash handling costs
vary exponentially with boiler size. The approximate value for the exponent
is 0.8. Ash handling costs range from 3,000 to 45,000 dollars per MW of
capacity (1,000 to 13,000 dollars per 106 Btu/hr). These costs represent
between 5 and 12 percent of the costs of a new, coal-fired boiler.
It is uncertain what percentage of the costs of converting an existing
gas/oil boiler to coal-firing are associated with coal and ash handling, but
some assumptions can be made. Based on the total modifications required, it
appears that coal and ash handling costs for a boiler modification have 2 to
3 times more impact on total costs than they do for new boiler costs. There-
fore, for conversion of an existing boiler, coal handling costs can be assumed
to represent 10 to 15 percent of the total costs and ash handling costs repre-
sent from 10 to 36 percent of the total costs. Assuming values of 12 and 20
percent for coal and ash handling costs respectively, the costs of boiler
62
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10,000-.
1,000 -
5
10
O Source: EN-761
Source: CO-735
I I I I I I I I I I I I I I II I I
10 100
Boiler Capacity (MW)
I I I I I
1000
Figure 4-11. Estimated capital costs for coal handling and storage
(1977$).
63
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10,000-]
1,000-
100-
10.
Q Source: EN-761
A Source: CO-735
I I I 1 I ITTT
10
I I I I I I I I I
100
Botler Capacity (MW)
I I I I I II 1 I
1000
Figure 4-12. Estimated costs for ash handling equipment (1977$)
64
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modification are approximately 40 percent of the costs of a new, coal-fired
boiler. If the cost of replacing the capacity which is lost by converting
from gas/oil to coal is added to the estimated costs of modification, total
cost to convert to coal and maintain full capacity is 97 percent of the cost
of a new, coal-fired boiler -
The costs presented above are just estimates, but it appears the costs
of boiler modification coupled with the costs of replacing lost capacity
make conversion of a gas/oil-fired boiler to coal impractical.
Operating and maintenance costs—The additional operating and mainten-
ance (O&M) costs which are incurred when a gas or oil boiler switches to
coal have not been estimated. However, a close approximation of the increased
costs is the difference between the O&M costs of a gas/oil-fired boiler and
the O&M costs of a coal-fired boiler. Figure 4-13 presents this difference
for various sizes of boilers. As shown, O&M costs will increase between
120,000 dollars per year for a 4.4 MW boiler to 550,000 dollars per year
for a 176 MW boiler.
The change in O&M costs which results from a switch to coal represents
a 4 to 5 fold increase. The main reason for this large cost increase between
coal- and gas/oil-fired boilers is the difference in the labor requirements
for boilers firing these fuels. A coal boiler requires additional personnel
to operate the boiler as well as extra operating personnel for the coal and
ash handling equipment (EN-761).
4.3.2.3 Environmental Impact—
In general, conversion of a gas/oil-fired boiler to coal will result in
an increase of uncontrolled emissions. But there are several types of pol-
lution control systems which can be used to limit emission increases or
actually reduce emissions. The following discussion examines the changes in
emissions of the five criteria pollutants: particulates, sulfur dioxide,
nitrogen oxides, carbon monoxide, and hydrocarbons. In addition, techniques
65
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bOO—i
400—
o
o
o
S 300-
o
u
I
200—
100 —
I
25
I
50
I
75
100
Boiler Capacity (MW)
I
125
I
150
I
175
I
200
Figure 4-13. Estimated increase in operating and maintenance costs which results
from a switch to coal.
Load factor: (4000 hrs/yr at 100 percent capacity).
Source: EN-761
-------
to control these emissions are identified. And the applicability of these
techniques to a converted boiler is examined.
Estimated emission changes—The change in emissions which results when
a gas/oil-fired boiler is converted to coal can be estimated by the differ-
ence in emissions between a gas/oil-fired boiler and coal-fired unit.
Table 4-12 presents the estimated change in uncontrolled emissions for 36
possible boiler conversions. As shown, there are significant increases in
particulate, sulfur dioxide, and nitrogen oxide emissions for 29 of the 36
cases. But there are actually some significant emission reductions in 6 of
the 36 cases. These reductions are in sulfur dioxide emissions, and they
result from converting to low-sulfur coal from high-sulfur oil.
Pollution control equipment—A detailed examination of pollution con-
trol techniques which are applicable to industrial boilers is being conducted
as part of the study to develop background information to support industrial
boiler NSFS. The following discussion examines special problems which arise
in applying pollution control to boilers which have switched fuels from gas/
oil to coal.
The primary consideration in applying pollution controls to industrial
boilers which have switched fuel from gas/oil to coal is the space available
for installation of control equipment. In most cases, space is simply not
available and installation of pollution control equipment is impractical if
not impossible. The case of a boiler which was originally designed to burn
coal may be different. If consideration was given to pollution control
during design, or if control equipment was included in the original instal-
lation, it may be possible to add suitable equipment to the boiler. This
is especially true in the case of particulate control equipment.
67
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TABLE -.-i:. ESTIMATED EMISSION CHANGE DUE TO FUEL SWITCHING
ON
00
Roller i .^nl i curs t Ion
After Furl Switch Pollutant
Package, Watertuhej Underfeed S t okpr
Flv ash
SO.
NOy as NO-
CPX
Hvdrorarbons as fH»
Natural uas
foal fr Voal li*
»4S. 8 M7.4
1 BOS .7 386 . 0
111.8 111.8
29.2 21.6
16.S 14.2
i l>'i "
To
iv.al M^
601 .0
186.0
111.8
17.4
21.1
Tn~Kaii'««.
~\ I
.
Pistillate oil" !.-•
i;,v>r7l " foal »2 f,-.ai tl
04S.R S17.4 (.01.0
1S00.7 172. P K2. P
»>« . f> 68 . S 6B . S
21. 1 15.S 20..'
15. P 12. S 10.1
i,
Oal M
SSB.O
(<)^7. 11
21 ,S
20.2
10,1
Package, U»trrluboL C ha Ing rate Stokci
Field
Field
Flv ash
SO.
W0y a« NO,
ccx
Hydrocarbons as CH«
Erected, Watertube. Spreader Stoker
Fly ash
SO,
HOX as HOj
OO
Hydrocarbons as CH«
Erected, Watertube. Pulverised Coal
Flv ash
SO,
N0( as WO,
OO
Hydrocarbons as CH»
B59.8
:s40.t-
64. S
29.2
16.8
1074.8
2536.5
206.4
29,2
16.8
2751,5
1719.7
210.7
10,7
4.1
472.9
517.4
64. S
23.6
14.2
601.9
558.9
206.4
23.6
14.2
1547.7
386.9
210.7
8.2
3.4
S17.4
515.9
64. S
37.4
21.1
687.9
537.4
206.4
37.4
21.1
1719.7
386.9
210.7
15.0
5.6
859.8
22 IS. 6
21. S
21.1
15.0
1074.8
2121.6
145.1
21.1
15. P
2751.5
1S04.7
167.7
(4.7)
1.3
472.0
122.4
21. S
15. S
12.5
601.9
343.9
145.3
1S.S
12. s
1547.7
172.0
167.7
(7.3)
0.4
517.4
WO. 9
21 . S
20.2
10.3
687.0
322.4
14S.J
29.2
10.3
1719.7
172.0
167.7
(0.4)
2.6
81t>.o
lOo^,3
l2SB.pl
21.1
IS.O
1031.8
1182.3
116,1
21,1
is.o
2708,5
150,5
120,4
(4,7)
1.3
420.
(816.
(258.
15.
12.
558.
(795.
116.
15.
12.
1504.
(1182.
120.
(7.
0.
o
01
01
s
•i
0
4)
1
s
s
7
31
4
1)
4
494.4
(818.1!
(258.01
20.2
10.1
644.9
(816.0)
116.1
29.2
19.1
1676.7
(1182.3)
120.4
(0.4)
2.6
'Source: (PF-348)
>F»el
Natural Gas
analyses are: Stt"ur Tr"ce
Ash Trace
HHV 17.3 (HJ/»'l
Distillate Oil Residual Oil
0,5 percent 3.0 percent
Trace 0.1 percent
311.8 (HI/I) 41.8 (HJ/t)
Coal
11
3. S percent
10.6 percent
37.500 (fcJftg)
Coal 12
0.0 percent 0.6
6.9 percent 5.4
32.150 (kj/k«) 22.
Coal f3
percent
percent
370 (kJ/k*)
-------
TABLE 4-12. Continued
vo
Change In Mission Rate (Ib/IO* Bta)
•oiler Configuration
After Ftoel Switch
Package. Watertnbe.
Package. Itetertnpe.
Pol lot MI t
Underfeed Stoker
Flv arii
SO,
•0 as HO,
CO
Hydrocarbons as Ok
Ohatngrate Stoker
Fly aril
SO,
•JO, as HO,
CO*
Hydrorartons as CB»
natural Gas1 To
Coal 11'
2.2
4.2
0.26
3.9x10"*
2.0
5.7
0.15
6.8xlO~*
Cnal 12'
1.25
0.9
0.26
5.5x10"'
3-3x10"'
1.1
1.25
0.15
5.5x10**
3.JX10'*
Coal IP
1.4
0.9
0.26
8,7x10"*
4.9x10"*
1.25
1.20
0.15
8.7x10**
4.9xlO~*
Distillate Oil' To
Coal II
2.2
3. TO
O.lft
4.9x10*'
3.5*10"'
2.0
5.2
0.05
4,9xlO~*
3.5x10**
Coal 12
1.25
0.4
0,16
3.6x10 '
2.9x10"'
1.1
0.75
0.05
3.6x10**
2.9x10**
Goat 13
1.4
0.4
0.16
6.8x10"*
4.5x10"'
1.25
0.7
O.OS
6.8x10"'
4.5x10"'
Residual Oil' To
Cnal II
2.1
1.15
0.05
4.9x10"'
3.5x10 *
1.9
2.55
(0.6)
4.9x10**
3.5,10-'
Coal 12
1.15
(2.25)
0.05
3.6xlO~*
2.9x10*'
1.0
(1.9)
(0.6)
3.6x10*'
2.9x10**
Coal 13
1.3
(2.25)
0.05
6.8x10**
4.5x10"'
1.15
(1.95)
(0.6)
6.8x10 *
4,5x10**
Field Erected. Uatertobe. Spreader Stoker
Fly ash
90,
HO as HO,
CO*
Hydrocarbons as CM,
2.5
5.9
0.48
3.9x10"*
1.4
1.3
0.48
3.3x10"*
1.6
1.25
0.48
8.7x10 *
4.9xlO~*
2.5
5.4
0.38
4.9x10**
3.5x10**
1.4
0.8
0.38
3.6x10**
2.9x10**
1.6
0.75
0.38
6.8x10 '
4.5x10"'
2.4
2.75
0.27
4.9x10**
3.5x10**
1.3
O.8S)
0.27
3.6x10*'
2.9x10"*
1-5.
(1.9)
0.27
6.8x10**
4.5x10"*
Field Erected. Matertabe. Pul^erlted Goal
'Source: (PE- 348)
*Foel Analyses are:
Fly ash
90,
NDg as HO,
00
Hydrocarbons as CM*
natural Cas
Sulfur Trace
Arii Trace
mn 37.3 (HG/nJ)
6.4
4.0
0.49
1.0x10*'
Distillate
3.6
0.9
0.49
1.9x10"*
0.8x10"*
4.0
0.9
0.49
3,5x10*'
1.3,10*'
Oil Residual Oil
0.5 percent 3.0
Trace 0. 1
38.8 (NT./t) 41.8
pferc^nt
percent
(Kl/l)
6.4
3.5
0.39
O.lxlO"*)
0.3xlO~l
Coal 11
3.5 percent
10.6 percent
3.6
0.4
0.39
(1.7x10*
0.1x10"*
4.0
0.4
0.39
*) (O.lxlO"')
0.6x10**
Coal 12
0.9
6.9
27,500 (kJ/ks) 32.
percent
percent
ISO (kj/k*>
6.3
0.35
O.J8
(1.1x10**)
0.3x10"*
Coal 13
0.6 percent
5.4 percent
3.5
(2.75)
0.28
(1.7xlO~*)
O.lxlO"'
3.9
(2.75)
0.28
(0.1x10"*)
0.6xlO"s
22,370 (kJ/k*)
-------
Particulate emissions - An industrial boiler which converts to coal
firing will probably require particulate control equipment. The most appli-
cable control equipment includes fabric filters and electrostatic precipi-
tators. The major limitation to application of this equipment is the space
required for installation. In addition, the cost of retrofitting control
equipment may be prohibitive.
Sulfur dioxide emissions - It is unlikely that a boiler which converts
from gas/oil to coal will have the space for installation of a flue gas
desulfurization system. Therefore, it appears that use of low sulfur coal
is the most applicable method of reducing SOa emissions from a gas/oil-fired
boiler which has been converted to coal.
Nitrogen oxide emissions - Combustion modifications can be used to
reduce NO emissions from converted boilers, and their applicability is
not limited but their effectiveness is. Total NOX reductions will range
from 30 to 50 percent, depending on boiler type (BL-147). Flue gas treat-
ment is not applicable to gas/oil-fired units which convert to coal. Space
and cost factors make application of FGT impractical if not impossible.
4.3.3 Coal-Oil Mixture Combustion
Conversion of a gas/oil-fired boiler to coal firing can prove very
difficult and costly. In fact, from a technical and economic standpoint
it appears that boiler replacement is more feasible than converting an
existing gas/oil boiler to coal. But there is one method for firing coal
in an existing gas/oil boiler which appears to be potentially attractive.
This is coal-oil mixture (COM) combustion.
Combustion of a coal-oil mixture may offer a near-term method of firing
coal in existing gas/oil boilers. It appears that many existing boilers can
be converted to COM firing with a minimum of modification, derating, outage
70
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time, and cost. However, the technology of COM combustion has not been
demonstrated for long-term use and some unanswered questions remain.
The following discussion examines the COM combustion process, its
status of development, and potential process problems which have not been
resolved. In addition, estimates are presented for the costs of required
boiler modifications, the cost of preparing COM, and emissions from COM
combustion in an existing boiler.
4.3.3.1 Process Description - Coal-Oil Combustion—
Coal-oil mixture combustion appears to be a promising method of
switching existing gas/oil-fired boilers to coal. However, there are
several factors which must be considered in using COM. These factors
include:
1) COM preparation,
2) Boiler modifications,
3) Status of development,
4) Costs, and
5) Pollution control.
The following discussion examines the first three of these factors in detail.
Costs are presented in Section 4.3.3.2 and pollution control is discussed
in Section 4.3.3.3.
COM Preparation—Preparation of coal-oil mixture is a fairly complex
process although commercially available equipment is employed. The prepara-
tion process requires facilities for receiving, storing, handling, and
pulverizing coal. In addition, oil storage facilities and equipment for
mixing the coal and oil are needed. Because of the preparation process
requirements, preliminary analyses have indicated that operators of small
industrial boilers will not use on-site COM preparation. Only operators
of large boilers will actually prepare COM on-site while smaller facilities
will purchase COM from a large, central facility (BE-531).
71
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The actual economic breakpoint between on and off-site preparation has
not been determined. One study prepared by the Department of Energy indi-
cates that a 35 MW (VL25 x 106 Btu/hr) boiler is too small to accommodate
on-site COM preparation, but a 180 MW C\>625 x 106 Btu/hr) boiler will
support a COM preparation plant (BE-531).
Coal-oil mixture is prepared by first pulverizing coal to a very fine
powder. This powdered coal is then mixed with residual fuel oil to form a
fuel slurry which can be pumped like oil and fired by modified conventional
oil burners.
The degree of pulverization required to produce a stable coal-oil mix-
ture will vary depending on the coal, the oil, and any additives which are
included. A study conducted by General Motors, Inc. indicated that stable
coal-oil mixtures can be prepared with pulverized coal which ranges in size
from 15 ym to 75 ym (4.9 x 10~5 to 2.5 x 10~* ft) (BR-493) .
Currently, there are three different coal pulverization systems being
examined for preparation of COM. One uses conventional coal pulverizers.
A second uses a wet ball mill which grinds the coal with residual oil. And
the third system uses wet grinding of coal in a high-speed disperser.
The maximum concentration of coal which can be used in a coal-oil mix-
ture will vary depending on the application. Tests have been conducted
with coal concentrations ranging from 20 to 50 weight percent.
Coal concentration will have a significant impact on the performance of
the boiler and the costs of COM firing. Obviously, a higher coal concentra-
tion may adversely impact system performance. Higher coal concentrations
increase fuel viscosity and therefore make COM more difficult to pump. In
72
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addition, higher concentrations can result in erosion of pipes and burners,
increased emissions of participates and sulfur dioxide, and boiler derating.
To date, some problems have been encountered with the stability of
coal-oil mixtures. During storage, coal can settle out of the COM and pro-
duce a non-homogenous mixture. This can cause problems by plugging lines
and in some tests, it has resulted in tripping the boiler.
There are several approaches which can be taken to assure COM stability.
The first is simply to prepare a mixture which will remain homogenous for an
indefinite period of time. This can be accomplished by pulverizing the coal
to below 15 ym (4.9 x 10 5 ft) or by addition of emulsifying agents which
prevent the coal from settling out of the mixture. Both techniques are
expensive and may not necessarily represent an optimum solution to the
stability problem.
A second approach to COM stability is to provide continuous agitation
of the mixture during storage and transportation. This approach is feasible
and provides for a lower cost mixture, but operational difficulties occur.
Installation and maintenance of the agitation system is required. In
addition, provisions must be made for flushing of fuel lines during periods
when the boiler is down.
Finally, the COM can be prepared as a remixable liquid. This approach
employs an additive to prevent hard packing of the coal during storage and
transportation. The COM can then be mixed to uniformity prior to pumping
or combustion.
Boiler modifications—Coal-oil mixtures can be fired in existing boilers
using conventional oil burners. However, some modifications of the boiler
are required, and the extent of the modifications will depend on the type
of boiler which is being converted.
73
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Conversion of a gas boiler to COM firing will require significant
modifications. These modifications will be similar to those required to
convert a gas-fired unit to residual oil-firing. They include.
1) Installation of COM supply and storage systems.
2) Installation of oil burners.
3) Modification of furnace or superheater to obtain design
steam temperatures.
4) Addition of soot blowers to remove ash deposits from
convection tubes.
5) Modification or replacement of the economizer to prevent
plugging of the gas passage.
6) Modification of the air preheater to prevent acid corrosion.
7) Installation an ash removal and handling system.
A more detailed examination of these modifications appears in Section 4.2.1.1.
The modifications required to convert a distillate oil boiler to COM
firing will not be as significant as those required to convert from gas
firing to COM with some modification. Existing oil storage and supply lines
can be used. Addition of agitators to the storage facilities may be required.
Actual modification of the boiler internals will be similar to those for
a gas to COM switch. Soot blowers and ash handling systems will be needed.
In addition, modification of the superheater, preheater, and economizer may
be necessary, depending on the specific boiler design.
Conversion of a residual oil boiler to COM firing is the most feasible
fuel switch of the three. And it can be done with a minimum of modifications.
Soot blowers and ash handling systems are already available in most residual
oil boilers and the existing storage, fuel supply lines, and burners can be
used.
74
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Modifications required to switch from residual oil to COM include
installation of fuel strainers in supply lines to capture oversize particles
or agglomerates and replacement of existing pumps with equipment designed to
handle an abrasive slurry. If the COM used has not been stablizied, an
agitation system must be added to the oil storage tanks. In addition, fuel
supply lines may need to be rerouted to eliminate areas where settling can
occur and the oil burners may require modification to prevent blockages in
restricted passages.
Status of development—Coal-oil mixture combustion was first proposed
in 1879, and it has been examined several times since then. However, in the
past, the availability of relatively inexpensive gas and oil has limited
COM development.
Recently, gas and oil prices have increased and supplies have become
uncertain. As a result, there is renewed interest in COM combustion. In
1974, General Motors (GM) began testing COM as an industrial boiler fuel, and
in 1975, GM received funds from the U.S. Energy Research and Development
Administration (now U.S. Department of Energy - DOE) to continue research
into COM firing. Since that time, DOE has increased its involvement in COM
combustion.
Currently, there are four COM research projects in progress and the
GM project has been completed. The specific details of these projects are
presented in Table 4-13. As shown, these projects are examining COM firing
in several existing boilers including industrial units which were originally
designed for gas/oil firing.
To date, research on COM combustion has indicated that coal-oil mixtures
can be fired in existing equipment withja minimum of modification. However,
further development of COM combustion is required before the application of
this process to industrial boilers will expand.
75
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TABLE 4-13. CHARACTERISTICS OF COAL-OIL MIXTURE RESEARCH PROJECTS1
Prime Contractor
Interlake, Inc.
New England Power
Service Company
Acurex Corporation
General Motors
Pittsburgh Energy
Research Center
(DOE)
Test Unit
Application Capacity
Blast Furnace 1100 MTon/rlay
Injection
Oil-fired 225 HW
Utility Boiler
Designed for Coal
Oil-fired 30 MW
Industrial Boiler
Designed for Gas/011
011-flred 44 MW
Industrial Boiler
Designed for Gas/01 t
011-flred 9 MW
Industrial Boiler
Designed for Gas/011
Furl
dlT Conj
No. 6 Illinois
No. 6 Virginia
Went Virginia
Kentucky
No. 6 Virginia
No. 6 Pittsburgh No. 8
No. 6 Bituminous
Sub-bituminous
Co.! 1
Concentration Cnn 1 Use
(Percent) (MTon/day)
50 46
30 145
35 22
50 79
40 6
COM Preparat Inn
On Site Wet-Grinding
Dlsperser with
Additive
On Site Exist Ing Pul-
verizers with Mixer
and Additive
On Site Wet-Grim! Ing
Ball Mill with Add HI'
On Site Homogenatlon
of Water-ln-Oll with
Additive
On Site Mixtures Pre-
pared with Additive
and without Additive
'Source: (FR-277)
-------
Some areas which require further development are:
1) The preparation of stable coal-oil mixtures has not been
optimized.
2) The erosion of pumps, valves, and piping by coal-oil mixtures
has not been quantified.
3) The applicability of commercial instrumentation for control
of COM firing has not been evaluated.
4) The feasibility of transporting COM from a central facility
to a plant site using conventional fuel handling systems has
not been investigated.
It is expected that the current DOE programs will develop these areas
of COM preparation and firing.
4.3.3.2 Costs of Coal-Oil Mixture Combustion—
Combustion of coal-oil mixture in an existing gas or oil-fired boiler is
a promising method for switching from gas/oil to coal. However, because COM
preparation and combustion technology are in an early stage of development,
only tentative cost estimates have been prepared. More accurate costs should
be developed as part of DOE's COM research program but this work is not
completed. As a result, the costs presented in this report are estimates
based on engineering judgement.
Capital costs—There are two distinct capital costs associated with
COM combustion; the costs of boiler modification required to permit COM
firing in an existing unit and the costs of equipment required to prepare
COM from coal and oil feedstocks.
Figure 4-14 presents capital cost estimates for the boiler modifications
required to fire COM. Costs are presented as a function of size, and as
illustrated, they increase exponentially with size. The value of the expon-
ent is 0.9. These costs are from a study prepared by Arthur G. McRee and
Company (CH-476). Included in the estimates are the costs of particulate
77
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§ 10,000-
o
o.
•J
i.ooo-
100.
10
I I I I 11 I I I I I I I 11
100 1,000
Boiler Capacity (MM)
I I I T f TTTI
Figure 4-14. Estimated cost of boiler modifications required
to fire COM ($1978).
Source: CH-476
78
-------
control equipment, soot blowers, ash handling equipment, boiler modifications.
and COM storage and handling equipment. The costs required to replace any
capacity which may be lost due to boiler derating are not included. This cost
may exceed the costs of the boiler modifications.
The capital costs presented in Figure 4-14 are for conversion of a gas/
oil-fired boiler to COM. And these costs represent approximately 12 percent
of the costs of a new, coal-fired boiler. However, these costs are higher
than the costs of converting a residual oil boiler to COM firing. A residual
oil boiler already has soot blowers, ash handling equipment, and oil handling
and storage facilities which can be used after conversion. In addition,
particulate control equipment may be available.
Figure 4-15 presents an estimate of boiler modification costs for a
conversion from residual oil to COM. These costs were estimated by DOE's
Pittsburgh Energy Research Center. The estimate includes the costs of all
modifications required to retrofit a residual oil boiler to COM firing, but
no pollution control costs are included.
A comparison of the cost for converting a gas/oil boiler to COM with
the cost of converting a residual boiler to COM firing shows that the cost
of the latter conversion is approximately 10 percent of the cost of the
former. This means that the capital costs of converting a residual oil
boiler to COM are only a small fraction of the capital costs of a new coal-
fired boiler.
A second capital cost associated with a switch from gas/oil to COM is
the cost of a COM preparation facility. These costs include capital costs
for coal handling and storage, oil handling and storage, coal pulverization,
and coal-oil mixing equipment. Figure 4-16 compares capital cost estimates
of a COM preparation plant with the costs of a new, pulverized coal-fired
boiler. As shown, COM preparation plant costs are between 10 and 20 percent
of the costs of a new, coal-fired unit.
79
-------
o
o
m
o
o
a.
a
100-
10-
10
I I I I I I I I I
100
r i
Boiler Capacity (MM)
I I I I I I
1,000
I I I I I I I I I
Figure 4-15. Estimated capital costs for conversion of a residual
oil boiler to COM firing ($1978).
Source: BE-531
80
-------
100.000-
§
o
3
—*
I
10.000-
1,000-
P-C Boiler
,<• COM
Preparation
Plane
100
1 r
TTT
I
T
II 11
10,000
1,000
Equivalent Boiler Capacity (MW)
I I I I I I 11
Figure 4-16. A comparison of COM preparation plant capital costs
with the capital cost of a pulverized coal-fired boiler ($1978).
Source: EN-761, CH-476
81
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The COM preparation plant costs presented are only for large facilities
(greater than 100 MW equivalent - V350 x 106 Btu/hr) . This is because on-
site COM preparation is not economical for small industrial boilers.
Table 4-14 compares estimated selling prices for COM as a function of prep-
aration plant size with the cost of residual oil. As illustrated, COM is
less expensive than oil for very large (7400 MW equivalent) preparation
plants. This indicates that only very large industrial complexes will find
on-site COM preparation attractive. Small industrial boilers which convert
to COM will probably purchase fuel from a large, central preparation plant.
TABLE 4-14. COMPARISON OF COM SELLING PRICE WITH PRICE
OF RESIDUAL OIL1
Plant Size
(equivalent MW)
120
1100
7400
COM Cost
($/GJ)
3.25
2.44
2.29
($/106 Btu)
3.43
2.58
2.47
Residual Oil Cost
($/GJ) ($/10b Btu)
2.35 2.48
2.35 2.48
2.35 2.48
Source: CH-476
Operating and maintenance costs—The operating and maintenance costs
associated with COM combustion have not been determined, although they should
not be much different than the O&M costs for a residual oil-fired boiler.
Some increase can be expected but the extent of this increase will depend on
how COM firing effects boiler operation. Potential problems with plugging
and erosion of burners, pipes, etc. will dictate how much additional O&M
costs are incurred.
Figure 4-17 presents estimated O&M costs for a COM-fired boiler. These
costs are based on an average of coal- and oil-fired boiler O&M costs. And
they should represent conservative O&M costs which can be expected for a
COM-fired unit. These costs are approximately three times the O&M costs of
a residual oil boiler.
82
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1,000-
§
100_
10-
III
10
I I I
I I
100
I I I I I 111
Boiler Capacity (MW)
Figure 4-17. Estimated operating and maintenance costs for a
COM-fired boiler.
Load factor: (4000 hrs/yr at 100 percent capacity).
Source: EN-761
83
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The O&M costs of a COM preparation facility have been estimated by
DOE's Pittsburgh Energy Research Center. This estimate was for a large
(13,000 MW) facility, and O&M costs were approximately 2.3 percent of
annualized costs. Assuming this percentage is accurate over the size
range from 100 to 13,000 MW, COM preparation plant O&M costs can be
estimated.
Figure 4-18 presents estimated COM preparation plant O&M costs as a
function of plant capacity. These costs are based on annualized costs which
were estimated by Arthur G. McKee and Company and the above assumption.
4.3.3.3 Environmental Impact—
Conversion of a gas- or oil-fired boiler to COM firing will result in a
change in uncontrolled emissions. And the extent of the change will depend
on the properties of the coal and oil used to prepare the mixture. The fol-
lowing discussion presents an estimate of the emissions which result when a
boiler converts from gas and oil to COM. In addition, applicable emission
control techniques are identified.
Estimated emissions—The estimated change in uncontrolled emissions
of criteria pollutants which results when gas and oil boilers convert to
COM firing are presented in Table 4-15. As shown, converting from gas or
distillate oil will result in significant increases in emissions of particu-
lates and sulfur dioxide. This may result in a requirement for some type
of particulate and SOa control on a gas or distillate oil boiler. Conversion
of a residual oil boiler to COM firing will result in a significant increase
in uncontrolled particulate emissions. But, COM firing lowers SOa emissions
in the two cases where low-sulfur coal is used to prepare the fuel. This
indicates that some additional particulate control may be required after
conversion but if low-sulfur coal is used, no additional SOa control equip-
ment will be necessary.
84
-------
u
>s
m
u
a
3
1,000-
100-
10'
100
I I I I I 11 I I I I I I I 11 I
1,000 10,000
Equivalent Boiler Capacity (MW)
Figure 4-18. Estimated operating and maintenance costs for a COM
preparation plant.
Load Factor: (6400 hrs/yr at 100 percent capacity).
Source: CH-476
85
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TABLE 4-15.
00
ESTIMATED CHANGE IN EMISSIONS WHICH RESULTS WHEN GAS
AND OIL BOILERS SWITCH TO COM FIRING1
Change In Emission Rate (ng/J)
Pol lutant
Particulars
Sulfur dioxide
Nitrogen oxide as NO;
Carbon monoxide
Hydrocarbons as CHs
Gas
COM I COM
1084 671
1497 942
151 151
8.5 7
2.6 2
to2
2 COM 3
607
1020
151
.6 9.4
.3 2.9
COM 1
1084
1285
108
0.3
0.8
Distillate Oil to2
COM 2
671
731
108
(0.6)
0.5
Change in Emission Rate (lb/10*
Pollutant
Partlculates
Sulfur dioxide
Nitrogen oxide an NO;
Carbon monoxide
Hydrocarbons as CtK
Gas
COM 1 COM
2.5 1
3.5 2
0.35 0
2.0 x 10~? 1.8 x
6.0 x 10~J 5.4 x
to2
2 COM 3
.6 1.4
.2 2.4
.35 0.35
10"2 2.3 x 10"7
10~3 6.7 x 10~3
COM 1
2.5
3.0
0.25
0.1 x 10"7
1.8 x 10"3
Distillate Oil to2
COM 2
1.6
1.7
0.25
(0.1 x 10"2) 0
1.2 x 10"' 2
Residual Oil to2-'
COM 3
607
808
108
1.5
1.2
Btu)
COM 3
1.4
1.9
0.25
.4 x 10"2 0.
.5 x 10~3 1.
COM 1
1045
147
60
0.3
0.8
COM 2 COM 3
632 568
(408) (330)
60 60
(0.6) 1.5
0.5 1.2
Residual Oil to2'3
COM 1
2.4
0.4
0.14
1 x 10"2 (0
8 x 10"3 1
COM 2 COM J
1.5 1.3
(0.9) (0.7)
0.14 0.14
.1 x 10"2) 0.4 x 10"7
.2 x 10"3 2.5 x 10"'
'Based on emission factors in PI-348
2 Fuel analyses are:
Natural Gas
Sulfur Trace
Ash Trace
HHV 37.3(MJ/m3)
Distillate Oil
0.5 percent
Trace
38.8(MJ/l)
Residual Oil
3.0 percent
0.1 percent
41.8(MJ/*)
COM 1
3.25
5.35
35,900(kJ/kg)
COM 2
1.95
3.5
38.200(kJ/kg)
COM 3
1.8
2.25
33,300(kJ/kg)
'The specific gravity of residual oil is assumed to be 0.95.
-------
Pollution control equipment—A detailed examination of pollution
control equipment which is available for controlling emissions from
industrial boilers is being prepared as part of the study to develop
background information for industrial boiler NSPS. The following dis-
cussion briefly examines the applicability of available pollution control
to gas- and oil-fired boilers which have switched to COM firing.
Particulate emissions - A substantial increase in uncontrolled
particulate emissions will result when a gas or oil boiler switches to
COM combustion. As a result, some particulate control will probably
be required to comply with state regulations. However, in many existing
boilers, there is not adequate space available for control equipment to
be installed. And, this may prohibit some boilers from switching from
gas/oil to COM.
Electrostatioc precipitators and fabric filters can be used to control
particulate emissions from COM-fired boilers. The choice of equipment will
be site-specific and depend on characteristics of the boiler system. How-
ever, ESP's will probably be the predominant choice. This is because exist-
ing fan capacity should permit use of an ESP without modification while use
of a fabrif filter could require additional fan capacity.
Sulfur dioxide emissions - A switch from gas or distillate oil to COM
can result in a significant increase in SOz emissions from an industrial
boiler. But a switch from high sulfur residual oil (3.0 percent sulfur)
to COM prepared with low sulfur coal (less than 3.0 percent) can result in
a reduction of 802 emissions. In the case in which SOa emissions decrease,
no additional SOa control should be required. However, in the case where
emissions increase, flue gas desulfurization may be needed.
Because of the difficulty of retrofitting an FGD system to an existing
boiler, coupled with the increase in boiler system operating costs, the
87
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potential for decreased system reliability, and the need to dispose of by-
product or waste material produced by an FGD system, it does not appear
that COM-fired boilers will use FGD to control S02 emissions. A more attrac-
tive and feasible alternative is to prepare coal-oil mixture using low-sulfur
residual oil and low-sulfur coal. This can result in very low emissions of
S02- If some reduction of S02 is required, the use of dry-alkali injection
may be feasible.
Dry-alkali injection is an FGD system which does not require a scrubber.
A dry alkali power (e.g., NaHCOa) is injected into an existing flue gas duct
and collected in a fabric filter. S02 reacts with the alkali material in
the duct and the filter. SOz removal efficiencies between 50 and 80 percent
have been reported (BE-465).
Nitrogen oxide emissions - Combustion modifications can be used to con-
trol nitrogen oxide emissions from boilers firing COM. A study conducted by
Acurex Corporation indicated that combustion modifications which are cur-
rently used for pulverized coal-fired boilers are effective in reducing NO
X
emissions produced by COM combustion. However, no general control efficien-
cies have been determined because both the chemical and physical properties
of the COM impact the effectiveness of combustion modifications (BU-342).
4.3.4 Coal Gasification
Coal gasification is a process which can permit existing gas/oil-fired
industrial boilers to switch to coal as a fuel source. This process converts
coal from a solid to a gaseous fuel which has properties (e.g., heat release
rate) similar to natural gas. And the coal-based gas can be burned in exist-
ing gas/oil-fired boilers with a minimum of modifications. The following
discussion describes the gasification process and examines the boiler modifi-
cations required to convert an existing gas/oil-fired boiler to coal-based
gas firing. In addition, estimates are presented for the costs of applying
88
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gasification to industrial boilers and for the change in emissions which
results when coal-based gas is fired in an existing gas/oil boiler.
4.3.4.1 Process Description - Coal Gasification—
Gasification of coal and subsequent combustion of the fuel gas in an
existing boiler is a technically feasible method of switching from gas or
oil to a coal-based fuel. However, the gasification process is complex and
there are many factors which must be examined when considering coal gasifi-
cation as a method of switching fuels. Some of the more important are:
1). The type of gasification process employed,
2) Boiler modifications required to fire coal-based gas,
3) Gas purification requirements,
4) On-site vs. off-site gasification,
5) Costs of gasification, and
6) Pollution control required by a converted boiler.
The following discussion examines the first four of these factors in detail.
Costs are discussed in Section 4.3.4.2 and pollution control is discussed in
Section 4.3.4.3.
Type of gasification process—Coal gasification is the reaction of coal,
water vapor, and oxygen to produce a gaseous fuel which has properties simi-
lar to natural gas. And the higher heating value (HHV)1 of the fuel produced
will depend on the type of gasification process used. There are three types
of gasification processes; low-, medium-, and high-Btu gasification. Low-Btu
gasification uses air as the source of oxygen in the gasification reaction
and produces a fuel gas with a heating value of approximately 5.6 MJ/m3
(150 Btu/scf). Medium-Btu gasification uses pure oxygen and produces a fuel
gas with a heating value of about 13.0 MJ/m3 (350 Btu/scf). High-Btu gasifi-
cation further processes medium-Btu gas to produce a fuel gas with a heating
value of approximately 37.0 MJ/m3 (1000 Btu/scf).
Higher heating value is defined as the heat content of the fuel plus the
heat of vaporization of any water in the fuel.
89
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Currently there are approximately 70 different gasifiers which have been
or are under development. In addition, there are many different unit opera-
tions in each of these processes. The actual choice of a specific gasifica-
tion system will depend on many factors including the coal properties,
required gasifier size, etc. Therefore, the discussion presented here will
focus on the choice between low-, medium-, and high-Btu gasification.
The major reactions which occur during coal gasification are:
C + %02 -»• CO (4-1)
C + 2H2 ->• CHi» (4-2)
C + H20 -»• CO + H2 (4-3)
CO + H20 + C02 + H2 (4-4)
CO + 3H2 + CHi» + H20 (4-5)
Carbon monoxide (CO) and hydrogen (H2) are the major reaction products. Low-
Btu gas contains approximately 20 percent CO and 15 percent H2 with the bal-
ance composed principally of nitrogen (N2) . Medium-Btu gas contains approxi-
mately 50 percent CO and 40 percent H2 with the balance mostly carbon dioxide
(C02). High-Btu gas is produced by first processing medium-Btu gas in a
shift conversion reactor where the following reaction occurs:
CO + H20 •»• C02 + H2 (4-4)
The gas is then processed in a reactor where methane (CHif) is produced by
two reactions:
CO + 3H2 •> OH* + H20 (4-5)
C02 + 4H2 -*• CHi» + 2H20 (4-6)
Table 4-16 compares typical volumetric analyses for final product low-,
medium-, and high-Btu gases to that of natural gas. As illustrated, the
90
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high-Btu gas is almost identical to natural gas while the composition of the
low- and medium-Btu gases is very different.
As shown in Table 4-16, high Btu gas is nearly identical to natural
gas. And it can be burned in existing gas/oil boilers with essentially no
modifications. However, production of high Btu-gas requires additional
equipment and results in a lower efficiency for the gasification process.
Consequently, combustion of high-Btu gas in an industrial boiler is not
economically attractive. Rather, low- or medium-Btu gas will be the choice
for use as a boiler fuel.
TABLE 4-16. A COMPARISON OF COAL-BASED FUEL GAS COMPOSITIONS
WITH THE COMPOSITION OF NATURAL GAS
Component
(vol %-dry)
-COa
CO
H2
CHi,
C2H6
N2
Low-Btu Gas1
13.4
15.1
22.4
6.2
-
42.9
Medium-Btu Gas1
6.0
55.9
37.4
-
-
0.7
High-Btu Gas2
1.8
-
4.2
92.9
-
1.1
Natural Gas1
-
-
-
90.0
5.0
5.0
Source: BA-477
2Source: EL-052
Both low- and medium-Btu gas appear attractive for use in industrial
boilers. Low-Btu gas is attractive because the gasification process is
relatively simple. Low-Btu gasifiers can be operated at atmospheric pres-
sure and they do not require an oxygen plant for operation. Medium-Btu
gas is attractive because combustion of medium Btu gas produces approxi-
mately the same quantity of flue gas as combustion of natural gas. There-
fore it can be burned in existing boilers more readily than low-Btu gas.
Boiler modification—Because the composition of low- and medium-Btu
gas differs from that of natural gas, the coal-based fuels will burn
differently in an existing gas/oil-fired unit. As a result, some boiler
91
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modifications will be required to permit combustion of coal-based gas in
existing units. In addition, boiler derating may occur although in some
cases, modification of the boiler will permit full capacity operation while
firing coal-based gas.
The difficulty of converting an existing gas/oil-fired boiler to a coal-
based fuel gas will increase as the heating value of the coal-based gas de-
creases. This is due to the fact that for a given firing rate, the volume
and weight of both fuel and flue gas increases significantly as the fuel
heating value goes down. Table 4-17 compares the relative volume and weight
of fuel and flue gas for natural gas with that for low- and medium-Btu gas.
TABLE 4-17. RELATIVE VOLUME AND WEIGHT OF FUEL AND FLUE GAS FROM THE
COMBUSTION OF LOW-BTU, MEDIUM-BTU, AND NATURAL GAS1
Relative Volume
Fuel
Combustion Air
Flue Gas
Relative Weight
Fuel
Combustion Air
Flue Gas
Low-Btu Gas
5.8
0.7
1.1
6.0
0.7
1.1
Medium-Btu Gas
3.3
0.8
0.9
2.8
0.8
0.9
Natural Gas
1.0
1.0
1.0
1.0
1.0
1.0
1Details of combustion calculations are contained in Appendix B.
As shown, combustion of both low- and medium-Btu gas requires significantly
higher fuel flow rates than natural gas. And fuel lines in existing boilers
will not be capable of handling the increased flows. As a result, coal-based
gas consumption will require modification of existing fuel supply headers and
burners.
Combustion of low-Btu gas increases the volume and weight of flue gas
by approximately 10 percent as compared to natural gas. This results in
92
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increased pressure drop in the boiler and some derating. In addition, the
pattern of heat absorption in the boiler changes. This results in a loss of
efficiency and in some cases can result in tube metal temperatures which
exceed design temperatures.
Combustion of medium-Btu gas does not result in any significant
changes in flue gas volume or weight. And only minor changes in the boiler
heat absorption pattern occur. As a result, most existing boilers can burn
medium-Btu gas with little or no modification to the boiler itself. Only
changes in the fuel supply system and burners are required.
Table 4-18 presents the results of a study which was performed by
Babcock and Wilcox (BA-477). This study examined the use of various grades
of low- and medium-Btu gas in existing utility boilers. And although
these boilers do differ somewhat from industrial units, the results of this
study are applicable.
TABLE 4-18. ESTIMATED PERFORMANCE OF UNMODIFIED GAS AND
OIL BOILERS FIRING DIFFERENT COAL-BASED FUEL GASES1
Fuel HHV
(MJ/m3)
3.7
4.8
6.3
11.2
15.3
Original
(Btu/scf)
100
130
170
300
410
Design
Gas
Efficiency
(%)
82
83
82
88
85
85
Boiler
Capacity
(%)
<50
90
95
100
100
100
Oil
Efficiency
(%)
81
83
82
89
86
90
Boiler
Capacity
(%)
<50
<50
<50
85
85
100
Source: BA-477
Table 4-18 shows boiler capacity and efficiency for gas- and oil-fired
units which have been converted to coal-based gas firing. The only modifi-
cation of the,existing units was to the fuel supply and burners. As
93
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illustrated, medium-Btu gas can be fired in existing gas boilers with
essentially no modification and no loss of efficiency or capacity.
However, as the heating value of the gas declines below 11.2 MJ/m3
(300 Btu scf), the boiler capacity and efficiency decline and the
complexity of the modifications required to achieve full capacity
increase. The combustion of coal-based gas in existing oil boilers
reqults in some derating and loss of efficiency for all the coal-based
gases studied. But as shown in Table 4-18, the trend of lower capacity
and efficiency with lower heating value still holds.
In general, medium-Btu gas can be fired in existing boilers with
little or no modification to the boiler itself. However, as the heating
value of the gas declines, the required modifications become more exten-
sive. Use of very low-Btu gas in existing gas/oil-fired boilers may
result in such extensive modifications that coal-based gas firing is
impractical.
Gas purification—Fuel gas from a gasifier contains a variety of
compounds in addition to the major components identified in Table 4-16.
These compounds include ash, tars, oils, H2S, COS, CSa, NHs, cyanides,
phenols, and thiocyanates. Direct combustion of raw gasifier gas in an
industrial boiler could result in emission rates for particulates, sulfur
dioxide, and nitrogen oxides which may require pollution control equipment
to reduce emissions to acceptable levels. However, it is possible to clean
coal-based gas prior to combustion and thus reduce or eliminate the require-
ment for emission controls.
Purification of raw gasifier gas is simpler than cleaning flue gases
from a boiler for several reasons. First, purification of the fuel gas
stream requires treatment of less than one-half the volume of gas which
must be treated when flue gas cleaning is used. Second, commercially
proven technology is available to remove reduced sulfur species from
fuel gas. And finally, removal of sulfur compounds from fuel gas produces
94
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elemental sulfur which is easily handled and can be sold while many flue
gas desulfurization systems produce a solid waste which must be disposed
of in an environmentally acceptable manner.
Currently, there are many available gas purification processes and the
choice of a particular system will depend on several factors. But some gen-
eral statements can be made about the gas purification system which may be
used. First, any gas purification system will remove essentially all the
ash, tars, and oils present in the raw fuel gas. Second, nearly all the
fuel bound nitrogen (e.g., NHs) will be removed. And finally, the sulfur
content of the product gas can be reduced to any specified level.
On-site vs. off-site gasification—Gasification is not being exten-
sively used to supply boilers with fuel at this time. The primary reason
for this is that natural gas and oil are significantly less expensive than
the fuel gas which could be produced by a gasifier. This is especially
true for small (less than 75 MW equivalent - 250 x 106 Btu/hr) units. Only
for very large (over 1200 MW equivalent - 4000 x 106 Btu/hr) gasification
facilities does the benefit of scale begin to level fuel gas costs. Be-
cause of this, current projections indicate that most coal-based gas which
will be used as a fuel in existing boilers will be produced at a large cen-
tral gasification facility (OL-065). These facilities will not become avail-
able until an economic incentive exists to produce medium-Btu gas.
4.3.4.2 Costs—
There are two costs associated with the use of gasification as a fuel
switching method. The first is the cost of the gasifier and associated
process equipment such as a gas purification system. In the case of a
small boiler, this cost would be reflected in the cost of fuel gas pur-
chased from a central gasification facility. These costs are not addressed
in this section. They will be developed as part of an ITAR which is being
prepared for synthetic fuels.
95
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The second cost associated with a gas/oil to coal-gas fuel switch is
the cost of modifications required to permit firing of coal gas in an exist-
ing boiler. This also includes costs due to a change in boiler operating
and maintenance costs which results when a boiler switches to coal-gas.
These costs are examined in the following discussion.
Capital costs—The capital costs of the modifications required to permit
firing of low- or medium-Btu gas in a gas/oil-fired boiler will depend on
the extent of the modifications. If the modifications include only required
changes in the fuel supply system and the burners, one cost will be incurred.
But, if the modifications include changes in the boiler required to offset
derating which may result from switching fuels, a higher cost will be incurred,
Figure 4-19 presents estimated costs required to modify the fuel supply
system and burner to permit firing of low- and medium-Btu gas in an existing
oil boiler. No estimates of modification costs have been prepared for a gas
to coal-gas conversion but these costs can be approximated by the costs of
an oil to coal-gas conversion. As shown in Figure 4-19, the costs of con-
verting to low-Btu gas firing are approximately 25 percent higher than the
costs of converting to medium-Btu gas firing. This is due to the fact that
low-Btu gas will require larger fuel supply lines, and the installation of
burners will be more difficult.
The costs of modifying an existing boiler to fire low- and medium-Btu
gas at full capacity have not been estimated for industrial size boilers.
But, these costs have been estimated for utility boilers. They can be ap-
plied to industrial boilers by assuming that the relative change in cost as
a function of gas heating value is the same for both utility and industrial
boilers. Based on this assumption, the cost of modifying an oil boiler to
fire low-Btu gas (5 MJ/m3 - 130 Btu/scf) at full capacity is over sixteen
times the cost of modifications required to fire medium-Btu gas (11.2 MJ/m3 -
300 Btu/scf) at full capacity. And the cost of modifying an existing gas
boiler to fire low-Btu gas at full capacity is over four times the cost of
modifications required to fire medium-Btu gas at full capacity (BA-477).
96
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1000_
§
o
eg
o
u
2
Tt
A
100-
10.
. Low-Btu Gas
.Medium-Btu Gas
I I I
10
I II 1 1
100
I I I I I I I I
1000
I I I I I I I I
Boiler Capacity (MW)
Figure 4-19. Estimated capital costs of modification
to boiler fuel supply system and burners (1978$).
Source: SC-273
97
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Operating and maintenance costs—Combustion of low- or medium-Btu gas
in an existing boiler is essentially identical to combustion of natural gas
from the standpoint of operating and maintenance costs. Therefore, O&M costs
should not change when an existing gas/oil-fired industrial boiler switches
to low- or medium-Btu gas firing.
4.3.4.3 Environmental Impact—
Conversion of an existing gas/oil-fired boiler should not result in any
significant increase in emissions of particulate, sulfur dioxide, carbon
monoxide, or hydrocarbons. In addition, the nitrogen oxide emissions may not
change. One study prepared by Babcock and Wilcox indicated that there i,s
some potential for increased N0x emissions (BA-477). However, another study
prepared by Battelle Columbus Laboratories predicted that no significant
change in NO emissions can be expected (BA-448). Additional information on
this topic should be developed as part of an ITAR which is being prepared
for synthetic fuels.
4.3.5 Coal Liquefaction
Coal liquefaction is a technology which may permit existing gas/oil-
fired industrial boilers to switch to coal as a fuel source. Liquefaction
processes are designed to convert solid fossil fuels, such as coal and oil
shale, to a liquid fuel which has properties (e.g., viscosity, heating value)
similar to fuel oils used by existing industrial boilers. The following
discussion describes various coal liquefaction processes, the types of fuels
which are produced by coal liquefaction, and the boiler modifications
required to convert an existing gas/oil-fired boiler to coal-liquid firing.
In addition, estimates are presented for the costs of applying coal lique-
faction to industrial boilers and for the change in pollutant emissions which
may result when coal-liquids are fired in an existing gas/oil boiler.
98
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4.3.5.1 Coal Liquifaction - Process Description—
The liquefaction of coal and subsequent combustion of the liquid fuel
in an existing boiler is a technically feasible method of switching from gas
or oil to a coal-derived fuel. Currently, processes which produce coal-
liquids are not sufficiently developed to even marginally contribute to the
fuel demands of industrial boilers, but the potential for coal liquefaction
processes to provide a substantial share of the future U.S. energy demands
is evident. There are many factors which must be examined when considering
coal liquefaction as a method of switching fuels. Some of the more impor-
tant factors are:
1) Type of liquefaction process employed
2) Boiler modifications required to fire coal-liquids
3) Coal-liquid purification requirements
4) On-site versus off-site liquefaction
5) Costs associated with liquefaction
6) Pollution control required for a converted boiler
The following discussion examines the first four of these factors in
Costs are discussed in Section 4.3.5.2 and pollution control is discussed
in Section 4.3.5.3.
Type of liquefaction process—The basic reaction of coal liquefaction
is similar to thermal cracking in the petroleum refining industry. The
addition of molecular hydrogen (Ha) across a carbon-carbon bond causes
separation of the large carbon chains found in coal into smaller chains as
shown Jn oqualion 4-7;
H H
I I
R-C-C-R + H2 + R-CH3 + H3C-R (4-7)
I i
H H
.where R is a hydrocarbon structure such as (-CH3), (-CH2CH3), (-CH2CH2CH3),
etc.
99
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In coal, the (R) groups are generally composed of complex aromatic hydro-
carbons.
When coal is formed, gases diffuse out of it, leaving voids and fissures.
Liquefaction processes introduce solvent into these voids, causing the coal
to dissolve. Hydrogen can then be added to the dissolved coal to form rela-
tively low molecular weight compounds. If hydrogen is not added, the coal
will polymerize into asphaltenes.
The ability to provide hydrogen for reaction with dissolved coal by
increasing mass transfer is very important. In fact, the major difference
between various coal liquefaction processes is the method of hydrogen trans-
fer.
There are three types of coal liquefaction processes. They are:
1) hydrogenation,
2) carbonization, and
3) gasification/coal-liquid synthesis (Fischer-Tropsch Synthesis)
Hydrogenation is gaining prominence over the other systems because it is
in an advanced stage of development, provides more flexible utilization of
product fuel, has a higher overall conversion efficiency, and shows better
market potential and economic advantages. Hydrogenation involves the direct
conversion of coal to liquids by addition of hydrogen to coal at elevated
temperature and pressure. Three types of hydrogenation are typified by the
method of hydrogen transfer used in the reactor.
In noncatalytic hydrogenation, coal is slurried with a hydrogen-rich
solvent and reacted with hydrogen gas. This reaction generally produces a
liquid that solidifies at ambient temperature, but by recycling the coal-
solvent slurry, additional hydrogenation occurs and a less viscous product
can be obtained. The Solvent Refined Coal (SRC) process uses this method.
100
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SRC-I fuel is a solid having lower sulfur and ash content than the base
coal, but SRC-I is only suited as an alternate fuel for coal-fired boilers
and cannot be used in existing gas/oil-fired units. SRC-II fuel is produced
by recycling coal-solvent slurry. This is a coal-liquid which possesses
properties similar to residual fuel oil.
In catalytic hydrogenation, pulverized coal is slurried with coal-derived
oil, mixed with hydrogen, and fed to a reactor which utilizes a hydrodesul-
furization (cobalt-molybdenum) catalyst to increase the rate of hydrogen
transfer. This method is employed by the H-Coal process.
In solvent hydrogenation, no hydrogen gas or catalyst is used in the
reactor. Instead, a solvent is used to provide hydrogen to the free radicals
as they break away from the coal polymer. This solvent, known as a "donor",
is composed of organic compounds which boil between 200-480°C (400-900°F)
and which must be regenerated after they are depleted of hydrogen. The
Exxon Donor Solvent (EDS) process employs this method of hydrogenation.
In the carbonization system, coal is converted to liquid by application
of heat, either without the direct addition of hydrogen (pyrolysis), or with
the addition of hydrogen (hydrocarbonization). Most of the carbon is re-
jected as a solid, but liquid products are recovered which have a higher
hydrogen/carbon ratio than the original coal. This process does not have
a high conversion efficiency of coal to liquid fuel. Therefore, it is not
well suited to producing an industrial boiler fuel.
The liquefaction process which uses gasification followed by coal-liquid
synthesis is very complex, and the costs of producing liquid fuel by this pro-
cess are not competitive with other liquefaction systems. Therefore, this
system is not a feasible method of switching from gas/oil to a coal-based fuel.
Boiler modifications—The extent of the modifications required for
combustion of coal-liquids in gas/oil-fired industrial boilers will depend
on the composition and physical properties of the coal-derived liquid fuel
101
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to be used. An existing boiler can burn a coal-liquid fuel which resembles
distillate or residual oil with some modifications, but if the fuel is
markedly different from distillate or residual oil, significant changes
in the boiler may be required.
A comparison of physical and chemical characteristics of representative
distillate and residual fuel oils and coal-liquids is presented in Table 4-19.
The distillate and residual fuel oils are No. 2 and No. 6, respectively.
Coal-liquids in the table are SRC-II, H-Coal distillate, and EDS distillate.
In comparison, all of the coal-liquids exhibit lower hydrogen content than
either of the fuel oils. Also, sulfur and nitrogen contents in these coal-
liquids are considerably higher than No. 2 fuel oil. The coal-liquids heat
of combustion is not significantly different from that of the fuel oils.
To date, there are only limited data on storage and combustion of liquids
from any liquefaction processes. The only facility in the United States
currently conducting tests on coal-liquids is the 22 MW Plant Mitchell power
station of the Georgia Power Company. Only limited tests on industrial
boilers have been performed with SRC-II, H-Coal, and EDS liquid fuels. More
extensive boiler tests are being planned for SRC-II in August, 1978. Tests
on H-Coal and EDS fuel products will be initiated in 1979 and 1980, respec-
tively.
Due to the lack of data on the combustion of coal-liquids in industrial
boilers, a complete estimation of the boiler modifications required to fire
gas/oil boilers with coal-liquids cannot be made. However, an estimate of
these modifications can be made based on the physical and chemical character-
istics of the coal-liquids.
Because the composition of coal-derived liquid fuels differs from that
of distillate and residual fuel oils, the coal-derived fuels will burn
differently in existing gas/oil-fired units. As a result, some boiler modi-
fications will be required in order to permit combustion of coal-liquids in
existing industrial boilers. In some cases, boiler derating may occur, but
102
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o
CO
TABLE 4-19. PROPERTIES OF TYPICAL DISTILLATE AND RESIDUAL
FUEL OILS AND COAL-LIQUIDS1
Fuel
Elemental composition, wt%
Hydrogen
Sulfur
Nitrogen
Oxygen
Trace contaminants, ppm wt
Titanium
Sodium
Potassium
Calcium
Vanadium
Lead
Iron
Chloride
Gravity, °API
Aromatic carbon, %
Flash point, C
Heat of combustion, MJ/kg
Petroleum
No. 2
(distillate)
12.9
0.5
0.008
<0.01
<1.0
0.55
0.37
0.17
<0.1
-
0.2
-
33.6
19.0
67.2
45.4
Petroleum
No. 6
(residual)
10.7
3.0
0.23
0.5
DNA2
DNA
DNA
DNA
DNA
DNA
DNA
DNA
14.0
DNA
DNA
42.8
SRC-II
7.4
0.37
0.62
3.9
20.0
0.39
0.19
0.35
0.9
0.9
61.0
35.0
5.3
74.0
82.2
39.4
H-Coal
9.1
0.10
0.39
1.5
0.59
0.08
0.14
0.1
<1.0
10.3
-
-
14.7
55.0
90.5
42.1
EDS
10.0
0.3
0.2
1.9
DNA
DNA
DNA
DNA
DNA
DNA
DNA
DNA
18.0
-
91.1
44.2
Source: HI-220
2DNA - Data not available
-------
with the implementation of appropriate modifications, ma-giimim capacity can
probably be maintained.
The conversion of an existing gas-fired boiler to coal-liquids firing
will not be significantly different from converting a gas-fired unit to
residual fuel oil. The important factors to consider are:
1) Furnace size - Coal-liquids will have a higher furnace heat
release rate than natural gas. Therefore, more heat will be
absorbed in an oil-fired boiler's furnace than a gas-fired
furnace. Derating will be necessary to maintain a safe heat
release rate.
2) Coal-liquid storage - The space required for a min-iimiai of
10 day fuel storage may present a problem at some industrial
locations.
3) Coal-liquid firing equipment - Fuel supply lines and burners
will have to be replaced to accoraodate coal-liquid instead of
gas.
->) Boiler internal modification - Because of higher heat release
rates and the presence of ash, addition of heat transfer surface
to the superheater or reheater may be required. The removal of
heating surface from the furnace may also be required. Soot
blowers may be required to periodically remove any ash deposits.
Other items which may need checking or modification are fans,
economizers, and air preheaters.
5) Pollution control - The exact impact of residual-type coal-liquids
will depend on the fuel properties. Particulate and sulfur dioxide
emissions are most likely to be affected by a switch from natural
gas to coal-liquid fuels.
A more detailed analysis of switching fro* a gas to liquid fuel can be found
in Section 4.2.1.
The conversion of an existing oil-fired boiler (distillate or residual)
to coal-liquids firing will require a •jn-i»n» of modifications. Only factors
which are affected by the change of physical or chemical characteristics in
the oil feedstock are of real concern. The primary iteas to consider are
higher viscosities which can increase the pressure drop in fuel supply lines
104
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and reduce fuel flow, and Increased pollutant emissions which may result from
higher ash and sulfur in the coal-liquids.
Coal-liquid purification—Any compound which is in the coal feedstock
to a liquefaction facility may be present in the coal-liquids produced. In
the process of conversion to coal-liquids, a number of organic or inorganic
compounds «ak-iyig up the coal polymer may be transformed into an unwanted or
potentially hazardous substance. Purification of the coal-liquids to remove
unwanted and potentially toxic compounds has been limited principally to fil-
tration, hydrodesulfurization, and vacuum distillation. These operations
have been able to substantially reduce the presence of particulates, sulfur
compounds, fuel-bound nitrogen, and hazardous hydrocarbons from ths final
coal-liquid product.
On-site versus off-site liquefaction—Another factor which must be
seriously considered before any gas/oil-fired industrial boiler switches
to coal-derived liquids as its principal source of fuel is whether the coal-
liquids should be produced on-site or purchased from an off-site supplier.
The predominant criteria for selecting the appropriate route for any speci-
fic industry is the economic impact realized through on-site or off-site
application to existing or future facilities.
On-site production of coal-liquids for use by industrial boilers seems
to be limited to a small number of applications. Only industries where the
demand for large, continuous supplies of liquid fuel are high would be able
to realize the economies of scale associated with a coal liquefaction facility.
Any industry that requires only small amounts of fuel would not find the
installation of a coal liquefaction plant to their advantage. In these
smaller applications, off-site production and purchase from a central supplier
would be the appropriate choice.
4.3.5.2 Costs of Liquefaction—
There are two major costs associated with the installation of a coal
liquefaction facility. The first of these is the cost of purchasing and
105
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installing the principal equipment necessary to transform the solid coal to
a useable coal-liquid. This cost may be realized directly by those indus-
tries who choose to produce coal-liquids onsite and indirectly by those
industries who choose to purchase coal-liquids from a central supplier.
The second cost is that associated with the conversion of an existing gas/
oil-fired boiler to coal-liquids firing. These costs will be reflected in
modifications made to the existing boiler system and changes in boiler
operating and maintenance costs which result when a gas/oil boiler switches
to coal-liquids.
Capital costs—Insufficient data are available at this time to estimate
the initial capital costs incurred when installing a coal liquefaction
facility. These costs will not be addressed in this section. They will be
developed as part of an ITAR which is being prepared for synthetic fuels.
Very limited data are available on the costs of modifications required
to permit firing of coal liquids in an existing industrial boiler. Figure
4-20 presents the cost modification versus boiler capacity for switching an
oil-fired boiler to SRC-II fuel. Data on the costs incurred for switching
to H-Coal or EDS fuels are not available, but may be considered similar to
those for SRC-II.
No reliable estimates for the costs of switching from gas to coal-
liquids exist. The most reasonable approach to estimating such costs would
be to assume that these costs would be similar to those required for switching
from gas to residual fuel oil. These costs have been presented in Figures
4-3 and 4-4.
Operating and maintenance costs—Combustion of a coal-liquid fuel in an
existing boiler is essentially identical to combustion of residual fuel oil
from the standpoint of operating and maintenance. Therefore, O&M costs
should not change significantly when an existing gas/oil-fired boiler switches
to firing coal-liquid fuel.
106
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1,000-
§
o
CO
3
a.
a
y
100-
10
I I I I I I I I I
10
I I I I I I I 11
100
Boiler Capacity (MW)
I I I I I
Figure 4-20. Estimated capital costs for modification of an
oil boiler to fire SRC-II ($1978).
Source: SC-273
107
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4.3.5.3 Environmental Impact—
Conversion of an existing gas/oil-fired boiler to coal-liquids firing
may result in an increase in emissions. If the conversion is from gas to
coal-liquids, significant increases in emissions of particulates, sulfur
dioxide, and nitrogen oxides may occur. If the conversion is from oil to
coal-liquid, changes in emissions will not be nearly as significant.
Increased emissions will more likely result if the switch is from distillate
fuel oil to coal-liquids, rather than residual fuel oil to coal-liquids.
The following discussion presents an estimate of the change in emissions
which result when an industrial boiler switches from gas, distillate oil, or
residual oil to coal-liquids.
Estimated emissions—The estimated emissions which result from combustion
of the coal-liquids, SRC-II, H-Coal, and EDS are presented in Table 4-20.
These estimates are based on the assumption that coal-liquids have physical
and chemical properties similar to residual oil, and that with the exception
of NO , the residual oil emission factors developed by PEDCo apply (PE-348).
The estimated changes in emissions which result when a natural gas,
distillate oil, or residual oil boiler is converted to SRC-II, H-Coal, or
EDS coal-liquid firing are presented in Table 4-21. As shown, the conversion
from natural gas to any of the coal-liquids causes an increase in emissions
of particulates, sulfur dioxide, and nitrogen oxides. Emissions of other
criteria pollutants do not change markedly.
In the conversion from distillate fuel oil to coal-liquids, some
decrease in sulfur dioxide emissions may occur. Slight decreases in carbon
monoxide and hydrocarbons would also be predicted.
If coal-liquids replace residual fuel oil in boilers, no significant
change in emissions would be noted for particulates, carbon monoxide, or
hydrocarbons, but substantial reductions of sulfur dioxide and nitrogen oxide
emissions would occur.
108
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TABLE 4-20. ESTIMATED EMISSIONS USING SRC-II, H-COAL, AND
EDS COAL-LIQUIDS IN INDUSTRIAL BOILERS
SRC-II
Pollutant
Particulates1
Sulfur dioxide1
Nitrogen oxides2
as NO 2
Carbon monoxide1
Hydrocarbons l
as CHi»
(ng/J)
40.4
181.0
110-226
15.0
2.3
(lb/106 Btu)
9.4 x 10~2
0.4
0.3-0.5
3.5 x 10~2
5.3 x 10~3
H-Coal
(ng/J)
37.8
46.0
110-226
14.0
2.1
(lb/106 Btu)
8.8 x 10~2
0.1
0.3-0.5
3.3 x 10~2
4.9 x 10~3
(ng/J)
36.0
131.0
110-226
13.4
2.0
EDS
(lb/106 Btu)
8.4 x 10~2
0.3
0.3-0.5
3.1 x 10~2
4.7 x 10~3
o
VO
Source: PE-348
2Source: HI-220
-------
TABLE 4-21.
ESTIMATED CHANGE IN EMISSIONS WHICH RESULTS WHEN GAS/OIL-FIRED
BOILERS SWITCH TO COAL-LIQUIDS
Ch.inp.e In Emission Rate (ng/J)
Pollutant
Partlculates'
Sulfur dioxide1
Nitrogen oxide2
as N02
Carbon monoxide'
Hydrocarbons'
aa CH%
Pollutant
Partlculates'
Sulfur dioxide1
Nitrogen oxide2
as NO:
Carbon monoxide"
Hydrocarbons'
as CH*
SRC-II
39.0
80.7
110-226
7.7
1.0
SRC-II
9.0 x 10~2
0.2
0.2S - 0.5
1.8 x 10~2
2.3 x 10"'
Natural Gas to
H-Coal
36.4
45.7
110-226
6.7
0.8
Natural Gas to
H-Coal
8.5 x 10~2
0.1
0.25 - 0.5
1.6 x 10~2
1.9 x 10"'
Distillate Fuel Oil
EDS
34.6
130.7
110-226
6.1
0.7
SRC-II
31.4
(34.0)
24-140
(0.5)
(0.8)
Change in
H-Coal
28.8
(169.0)
24-140
(1.5)
(1.0)
Emission Rate ('.
Distillate Fuel Oil
EDS
8.0 x 10"2
0.3
0.25 - 0.5
1.4 x 10"1
1.6 x 10"J
SRC-II
7.3 x 10"2
(0.08)
0.06 - 0.33
(0.1 x 10~2)
(1.9 x 10~s)
H-Coal
6.7 x 10~2
(0.4)
0.06 - 0.33
(0.3 x 10~2)
(2.3 x 10~3)
to
EDS
27.0
(84.0)
24-140
(2.1)
(1.1)
lb/10' Btu)
to
EDS
6.3 x 10"2
(0.2)
0.06 - 0.33
(0.5 x 10~2)
(2.6 x 10~3)
Residual Fuel Oil
SRC-II
1.7
(1281.2)
(23-93)
(0.5)
(0.8)
H-Coal
(0.9)
(1337.2)
(23-93)
(1.5)
(1.0)
Residual Fuel Oil
SRC-II
0.4 x 10"2
(3.0)
(0.05-0.21)
(0.1 x 10"2)
(1.9 x 10"')
H-Coal
(0.2 x 10"2)
(3.1)
(0.05-0.21)
(0.3 x 10"2)
(2.3 x 10"3)
to
EDS
(2.7)
(1247.2)
(23-93)
(2.1)
(1.1)
to
EDS
(0.6 x 10"')
(2.9)
(0.05-0.21)
0.5 X 10~7
2.6 x 10"3
'Source: PE-348
^Source: HI- 220
-------
Pollution control equipment—Based on the estimates presented in Table
4-21, it appears that the emissions which will result from the combustion
of coal-liquid fuels may require some control. Although particulate and
sulfur dioxide emission rates are below current utility boiler NSPS, nitrogen
oxide emission rates may not be, but combustion modifications should be
capable of reducing NO emissions to acceptable levels.
Ill
-------
SECTION 5
FACTORS AFFECTING FUEL SWITCHING
Six methods for switching fuels in existing industrial boilers were
identified in Section 4. They are:
1) gas to oil, boiler modification
2) gas/oil to coal, boiler replacement
3) gas/oil to coal, boiler modification
4) gas/oil to coal-oil mixture firing
5) gas/oil to coal-based gas firing
6) gas/oil to coal-based liquid firing
The first of these methods is for switching from gas to oil. The remaining
five are for switching from gas/oil to coal or a coal-based fuel. While all
of these fuel switching methods are technically feasible, some are more eco-
nomically attractive than others. In order to determine which fuel switching
methods are more likely to be employed by existing industrial boilers, the
costs of switching by each method and the regulations which apply to fuel
switching must be compared.
This section presents a discussion of the relative costs, applicable
regulations, and the environmental impacts associated with each fuel switch-
ing method. The costs and other factors are determined for each fuel switch-
ing method applied to three standard boilers. These standard boilers were
developed by PEDCo Environmental Specialists, Inc. as background for NSPS
which are being prepared for industrial boilers.
112
-------
The costs presented in this section include fuel costs and the
estimated capital costs of any modifications required to switch fuels.
Costs are presented for three cases. In the first case, the only capital
costs which are included are the costs for boiler conversion. The second
case includes capital costs associated with pollution control in addition
to the capital costs of boiler conversion. And the third case presents
costs based on provisions of the National Energy Plan. The regulations
considered in this section include the current fuel switching mandate defined
in the Energy Supply and Environmental Coordination Act (ESECA) of 1974 (as
amended) and the impact of applicable provisions of the National Energy Plan
(NEP). The environmental impacts which are presented include an estimate of
the uncontrolled emissions of criteria pollutants from three standard boilers
for each applicable fuel switching method.
5.1 STANDARD BOILERS
In order to assess the costs and environmental impact of the fuel
switching methods defined in this report, specific boiler configurations
must be examined. These specific boiler configurations, referred to as
"standard boilers", are representative of boilers which comprise the exist-
ing industrial boiler population. The standard boilers which are presented
and examined in this section were developed by PEDCo Environmental Special-
ists, Inc. as the result of a characterization of the U.S. industrial boiler
population by fuel, firing mechanism, type, and capacity.
The use of standard boilers will facilitate the assessment of fuel
switching in industrial boilers. This is because fuel switching in a
standard boiler is easily defined while fuel switching in industrial boilers
as a class is more general and less well defined. Specifics of costs,
emissions, and regulatory impact can be quantified for standard boilers.
And because the standard boilers are representative of the industrial
boiler population, the results of an assessment using standard boilers
are widely applicable.
113
-------
Seven standard boilers have been identified as part of the study to
develop background information in support of industrial boilers NSPS.
Characteristics of these boilers are presented in Table 5-1. As shown,
four of the seven standard boilers are coal-fired. Therefore, only the
following three standard boilers are candidates for fuel switching by the
methods considered in this study:
1) Gas-fired, fire tube boiler
2) Distillate oil-fired, fire tube boiler
3) Residual oil-fired, water tube boiler
Design parameters for these boilers are presented in Table 5-2. The
parameters include capacity, fuel characteristics, load factor, and flue
gas characteristics.
TABLE 5-1. STANDARD BOILER CHARACTERISTICS1
Boiler Configuration
Package,
Package,
Package ,
fire
fire
water
tube,
tube,
tube
scotch
scotch
, underfeed
Boiler Capacity
MW (106Btu/hr) . Fuel
4
4
8
.4
.4
.8
15
15
30
Natural Gas
Distillate
Coal
Oil
stoker
Package, water tube, chaingrate
stoker
Package, water tube
Field erected, water tube,
spreader, stoker
Field erected, water tube,
pulverized coal
22
44
44
58.6
75
150
150
200
Coal
Residual Oil
Coal
Coal
i
Source: PE-348.
114
-------
The following sections will examine fuel switching in each of the
three standard boilers. Costs will be determined based specifically on
the capacities and load factors presented in Table 5-2. In addition, the
impact of fuel switching on the standard boiler design parameters will be
estimated.
5.2 IMPACT OF ESECA AND THE NEP ON FUEL SWITCHING
The embargo on petroleum during the winter of 1973-74 made clear that
continued dependence on oil and natural gas was leading the nation (and the
world) toward a severe energy crisis. The 1973-74 embargo resulted in long
gasoline lines, reduced speed limits, increased energy prices, and a growing
awareness of the limits of domestic energy sources, particularly domestic
supplies of oil and natural gas.
One Congressional response to the energy crisis was the passage of the
Energy Supply and Environmental Coordination Act of 1974 (ESECA) , as amended
by the Energy Policy and Conservation Act of 1975 (EPCA). This act was de-
•
signed to increase the use of coal in industrial and utility boilers, thereby
decreasing U.S. dependence on natural gas and foreign oil.
Under the provisions of ESECA (as amended) the administrator of the
Federal Energy Administration (FEA) was authorized to prohibit power plants
and major fuel burning installations (MFBI's)1 from burning natural gas or
petroleum products as their primary energy source and to require that power
plants and MFBI's in the early planning process be designed and constructed
to be capable of burning coal as their primary energy source. Currently,
the Economic Regulatory Administration of the Department of Energy (DOE) has
the authority originally granted to the administration of the FEA and this
authority expires on December 31, 1978 (SC-538).
A major fuel burning installation is defined as a single combustion source
having a capacity above 30 MW (100 x 106Btu/hr) or a group of combustion
sources at a single site with a combined capacity over 75 MW (250 x 10s
Btu/hr).
115
-------
TABLE 5-2.
Design P;ir;tmi'ter
DESIGN PARAMETERS FOR STANDARD BOILERS SUBJECT TO FUEL SWITCHING1
Cnpac ity
(MW)
(10sBtu/hr)
Natural Cas Fired,
Fin- Tube Boiler
4.4
15
Distillate Oil Fired,
Firi' Tiibt- Hoi Icr
ReslHnnl Oil Fired,
W.-Mri Tubf Boiler
4.4
15
4.4
150
Fuel Analysis
Z Sulfur
% Ash
HI1V
Trace
Trace
37.3 (HI/m3)
1000 (Btu/ft3)
0.5
Trace
38.8 (HI/V)
139,000 (Btu/gal)
3.0
0.1
41.8 (MJ/».)
149,800 (Btu/gal)
Excess Air (Z)
15
15
15
Flue Gas Flow Rate
(Nm3/hr)
(acfm)
5370
5200
5160
5000
45400
46700
Flue Gas Temperature
177
350
177
350
204
400
Load Factor (Z)
45
45
55
Emission Rate
parti ml ntes
sulfur dioxide
nitrogen oxides as NOj
carbon monoxide
hydrocarbons ns C1U
(kg/hr)
0.02
O.OOS
0.68
0.12
0.02
:ib/hr)
0.05
0.01
1.50
0.26
0.05
(kg/hr)
0.14
3.34
1.36
0.25
0.05
(tb/br)
0.115
7.35
3.00
0.54
o.n
(kp/hr) (Ih/hr)
0 6.1
21).8
21.]
2.3
0.5
13.5
470.4
46. r>
5.0
1.0
'Source: PE-348
-------
Before existing power plants or MFBI's can be prohibited from burning
petroleum products on natural gas, the following conditions must be met
(FE-260).
1) The power plant or MFBI had on June 22, 1974, or thereafter
acquired or was designed with the necessary plant equipment
and capability to burn coal, or has been required to meet
a design and construction requirement under ESECA.
2) Issuance of a prohibition order is practicable and consis-
tent with the purposes of ESECA.
3) Coal and coal transportation facilities will be available
during the period the prohibition order will be in effect.
4) For power plants, the prohibition order will not impair
the reliability of service in the area served by the power
plant.
In selecting major fuel burning installations for receipt of a
prohibition order, DOE must consider, among other factors, the location
of the installation, the production or output of the installation, the
purpose for which coal would be burned, the quantity of natural gas or
petroleum products presently burned, and the practicability of burning
coal given the short-term variation of demand for output by the installation.
DOE is required by ESECA to issue prohibition orders to power plants
for which it makes the above findings, but its authority to issue prohibi-
tion orders to qualified MFBI's is discretionary (FE-260).
At present, the authority granted DOE under ESECA has limited MFBI
prohibition orders. Only industrial boilers larger than 30 MW (100 x 106
Btu/hr) which were originally designed to fire coal are being ordered to
convert to coal (DE-339). Therefore, the provisions of ESECA will only
impact one of the three standard boilers which are candidates for fuel
switching. This is the residual fuel oil-fired boiler which has a capacity
117
-------
of 44 MW (150 x 10s Btu/hr). However, only a fraction of the industrial
boilers represented by the residual oil-fired standard boiler were origi-
nally designed to fire coal.
A survey of MFBl's was conducted by FEA in the spring of 1975. This
survey was designed to determine the number of industrial boilers firing
oil and gas which were originally designed to fire coal. Currently, only
cumulative results of this survey are available. A total of 1242 gas/oil
fired MFBl's was identified which had previously burned coal or were built
with coal burning capability (FE-260). The inventory of the U.S. industrial
boiler population prepared by PEDCo indicates that there are a total of
4251 existing gas/oil fired boilers with capacities above 30 MW (100 x 106
Btu/hr)(PE-346). In addition, 1281 non-boiler gas/oil fired MFBl's were
identified (BR-508). Therefore, approximately 22 percent of all gas/oil
fired MFBl's have or had coal burning capability. Assuming that this per-
centage is equal for boilers and non-boilers, approximately 22 percent of
the industrial boilers represented by the residual oil fired standard boiler
may be required to switch to coal-firing under the provisions of ESECA. The
gas- and distillate oil-fired standard boilers are not required to switch to
coal under ESECA.
There are two facets of the National Energy Plan which impact fuel
switching in existing industrial boilers. The first is a regulatory pro-
gram which has provisions similar to ESECA. The major provisions of this
program are:
1) A prohibition on the use of natural gas or oil in new
industrial boilers with capacities above 30 MW (100 x
10s Btu/hr) and in all new power plants.
2) Authority to prohibit existing MFBl's which have the
capability to burn coal from burning gas or oil on a
case-by-case basis, or in categories.
118
-------
3) Authority to prohibit categories of new non-boilers with
capacities greater than 30 MW (100 x 106 Btu/hr) from
burning gas or oil.
4) A prohibition on the use of natural gas in any power plant
after 1990.
5) Discretionary authority to prohibit use of gas or oil
in existing MFBI's and power plants in categories or
on a case-by-case basis.
6) Authority to limit the use of gas or oil in combination
with coal in existing MFBI's and power plants on a case-
by-case basis.
7) Exemptions for economic, environmental, fuel availability,
and technical reasons.
The impact of the regulatory portion of the NEP on fuel switching in
existing boilers is identical to the impact of ESECA. One of the primary
differences between the regulatory program and ESECA is that the burden of
proof in determining if an existing boiler can feasibly fire coal is no
longer DOE's responsibility. Under the NEP, the boiler operator must prove
that coal cannot be fired before an exemption will be granted (SC-538)
(US-768).
The second facet of the NEP which impacts fuel switching is a fuel
tax/investment credit program. This program provides for a fuel tax on
natural gas and oil and a credit for investment in coal firing equipment.
The maximum annual investment credit is limited to the annual fuel tax
incurred. However, the investment credit can be carried over from year
to year and applied to any fuel tax incurred in the future.
The following discussion of the fuel tax/investment credit program is
based on a report prepared by the Executive Office of the President and
released in June, 1977 (US-768).
119
-------
TABLE 5-3. ESTIMATED FUEL COSTS THROUGH 1990 WITH AND WITHOUT PROPOSED NEP FUEL TAXES
Fuel Type
1978'
$/GJ $/loVu
High-Sulfur Coal 0.70 0.74
Low-Sulfur Eastern Coal 1.10 1.16
Low-Sulfur Western Coal 0.40 0.42
Residual Oil 2.09 2.21
Distillate Oil 2.84 3.00
Natural Gaa 1.85 1.95
COH l' 1.81 1.91
COM 2s 1.94 2.05
COH 3' 1.77 1.87
'Source: PE-348
'Source: US- 768
*See Appendix D for details.
Fuel Cost
1985' 1985 with Tax' 19901 1990 with Tax
$/
-------
The gas and oil fuel tax portion of this program will be phased in
between 1979 and 1985. For oil, the tax rate, adjusted for inflation1,
begins at $0.19/GJ ($0.20/106Btu) in 1979 and rises to $0.93/GJ ($0.98/
106Btu) in 1985. For natural gas, the tax rate will be equal to the dif-
ference between the price of distillate oil and the price of natural gas.
Table 5-3 presents estimated fuel costs for coal, natural gas, distillate
oil, residual oil, and three coal-oil mixtures in 1978, 1985, and 1990.
In addition, the costs of natural gas, oil, and COM under the proposed
tax structure are presented. The before-tax fuel costs shown in Table 5-3
are based on 1978 fuel prices and a 7 percent annual escalation rate (PE-348).
The fuel taxes which are part of the National Energy Plan are only
applicable to industrial users who consume over 0.53 fJ/yr (0.5 x 1012Btu/
yr) and these taxes are phased in between 0.53 and 1.6 fJ/yr (0.5 to 1.5 x
1012Btu/yr). Therefore, consumers using less than 1.6 fJ/yr (1.5 x 1012
Btu/yr) pay only a fraction of the fuel taxes presented in Table 5-3. But
consumers using over 1.6 fJ/yr (1.5 x 1012Btu/hr) pay the full amount of
the tax. The exact method for computing fuel tax as a function of consump-
tion has not been defined. For this study, the tax rate is assumed to in-
crease linearly between 0 and 100 percent for consumption ranging from 0.53
to 1.6 fJ/yr (0.5 to 1.5 x 10l2Btu/yr).
Table 5-4 presents the annual fuel consumption of the three standard
boilers described in Section 5.1. As shown, only the residual oil fired
unit consumes enough fuel to be impacted by the fuel tax. However, because
the fuel tax applies to a fuel consumer rather than an individual boiler,
the gas- and distillate oil-fired standard boilers may be impacted by the
fuel tax provisions of the NEP. Unfortunately, the extent of this impact
is difficult to assess because there are no data available which correlate
1Thc NEP calls for a tax of $0.14/GJ ($0.15/106Btu) in 1979 and $0.47/GJ
($0.50/106Btu) in 1985 based on 1975 doUars. The costs presented here
are based on 7 percent inflation.
121
-------
fuel consumption of a plant and the number and type of steam generators in
the plant.
TABLE 5-4. ANNUAL FUEL CONSUMPTION OF STANDARD BOILERS1
Annual Fuel Consumption
Boiler Configuration (fj/yr) (Btu/yr)
Gas Fired, Fire Tube 6.2 5.9 x 1010
Distillate Oil Fired, Fire Tube 6.2 5.9 x 1010
Residual Oil Fired, Water Tube 7.6 7.2 x 1011
1 Source: PE-348
The investment credit portion of the NEP permits a firm to reduce its
fuel tax by investing in coal firing equipment. For each dollar invested,
fuel tax will be reduced by a dollar. However, the investment in coal
firing equipment will result in some increased costs. This is because
the reduction of fuel taxes will increase a firm's net income. As a result
of this increase in income, a firm's revenue taxes will increase. The
actual costs of any investment will be the amount by which a firm's revenue
taxes increase. Assuming a tax rate of 48 percent results in a capital cost
of 48 cents for each dollar invested (US-768).
A quantitative analysis of how the fuel tax/investment credit program
impacts the three standard boilers is difficult. This is because the fuel
tax/investment credit program applies to a plant rather than an individual
boiler. But since the five gas/oil to coal fuel switching methods are all
investments in coal-firing equipment, the relative impact of the tax program
will be similar for each fuel switching method. However, the uncertainty
surrounding the quantitative impact of the tax program will prevent an
accurate estimate of how many industrial boilers will switch fuels as a
result of the program.
122
-------
5.3 ENVIRONMENTAL IMPACT OF FUEL SWITCHING
Switching fuels from gas to oil or gas/oil to coal will result in an
increase in emissions of one or more of the criteria pollutants. This sec-
tion presents estimates of the emission rate of the criteria pollutants from
the standard boilers before and after fuel switching. In addition, these
emission rates are compared with "typical" state regulations for sulfur
dioxide, nitrogen oxides, and particulates and the degree of control required
to comply with these "typical" regulations is presented. The "typical" state
regulations were developed by PEDCo Environmental Specialists as a result of
a comprehensive survey of state air pollution laws.
5.3.1 Gas-Fired. Fire Tube Boiler
A fire tube boiler is designed to fire natural gas or distillate oil.
Fuels containing ash cannot be used in these boilers because there is no
practical means of keeping the heat transfer surfaces of the boiler clean
without shutting down (EG—016). Therefore, only the fuel switching methods
which result in combustion of ash-free fuels are applicable to fire tube
boilers. These methods are:
1) gas to distillate oil, boiler modification
2) gas/oil to coal-based gas
In addition, boiler replacement is a viable method of switching fuels.
Table 5-5 presents an estimate of the uncontrolled emissions before
and after switching fuels in a gas-fired, fire tube boiler. Table 5-5 also
presents emission rates permitted by typical state regulations and the
degree of control, expressed as percent removal, required to meet the
typical regulations. Emission rates from a coal fired boiler are only
123
-------
TABLE 5-'3.
Boiler ConriRiir.it ton
iirii'.tn.i] Design After Fuel Switch
ESTIMATED EMISSIONS AND CONTROL REQUIREMENTS FOR FUEL
SWITCHING IN A GAS FIRED, FIRE TUBE BOILER
(..-is-FI i
F| re'
Nut Applicable
t;.ns-Fired, Fire Tiilu-
Cos-Fired, Fire I'nlie
r.as-Flred, Fire Tnl.e
Gas-Fired. Fire Tube
Distillate Oil-
Fired, Fire lube
Lov/Medlum-Btu C.as-
Fired, Fire Tnl.e
Coal-Fired, Spreader
Stoker, High Sulfur
Coal
Coal-Fired, Spreader
Stoker, Low Sulfur
Western Coal
Potlulnnt
Kmisslnn Itntr'
(ng/J) (Ih/ld'niu)
"I'vp ii-.il" Sl.-ito Ili-giil.-i( I-1
(lig/.l) (ll./10CBtu)
St'iii-,,-; pr- MR pxropt whore noted.
s..nr. e: '.l-l '>•>.
l-rnKv itr li>w/mpdlnm-Btii p.;is firing are assumed cc|iial to those of naLiirnl gas except for n It i
.I r,.in M.I i:.-.|,,i,
pnrt 1 dilates
sul fur dioxide
nitrogen oxides as NO2
carbon monoxide
hydrocarbons ns CHi.
part Iculates
sulfur dioxide
nitrogen oxides as Nl'r
carbon monoxide
hydrocarbons as CIU
part Iculates1
sulfur dioxide'
nitrogen oxides as NO;'
carbon monoxide
hydrocarbons as Ch\'
T
participates
sulfur dioxide
nitrogen oxides as NO;
carbon monoxide
hydrocarbons ns CIU
•r
participates
sulfur dioxide
nitrogen oxides as NO;
carbon monoxide
hydrocarbons as CIU
1.4
0.3
43
7.3
1.3
9
215
86
16
3
1.4
0.3
21-65
7.3
1.1
1075
3612
249
37
18
688
537
249
45
22
1.3 x 10 '
0.6 x 10 '
n.i
1.7 x Hf"
3.0 x 10"1
2.1 x 10"'
0.5
0.2
3.6 x 10 J
7.2 x 1C"'
3.1 x 10"'
6.0 x 10 '
0.05-0.15
1.7 x ]0"2
3.0 x 10"'
2.5
5.9
0.6
8.5 x 10"2
4.2 x 10"2
1.6
1.25
0.6
10.4 x 10"?
*>.2 x 10 *
NA
NA
86
_
-
43
688
129
_
-
NA
NA
86
_
-
258
1075
301
_
-
258
1075
301
_
-
NA
NA
0.7
-
-
(I.I
1.6
11.3
-
-
NA
NA
0.2
-
-
0.6
2.5
0.7
.
-
0.6
2.5
0.7
_
-
II
II
II
-
"
0
1)
II
-
-
II
n
(i
-
-
Ib
70
II
-
-
63
0
I)
-
-
oxides. Tlic r*«if»e prt»si'n( nl for NO<
, I. HIS
^rrent ..f the
emission rate for natural gns.
-------
presented for a spreader stoker. This is because these emission rates are
similar to those from other,stoker-fired units. In addition, spreader
stokers represent over 50 percent of the installed stoker-fired boiler
capacity. No emission rates are shown for low-sulfur eastern coal because
these emissions are nearly identical to those from low-sulfur western coal
(see Section 4.0).
As shown in Table 5-5, a fuel switch from natural gas to distillate
oil, or low/medium-Btu gas will not require any pollution control to meet
the typical state regulations. However, the emission rates presented for
low/medium-Btu gas are based on fuel gas purification prior to combustion.
The actual degree of gas purification will depend on the specific regula-
tions which apply to combustion of low/medium-Btu gas.
Switching from natural gas to coal by boiler replacement will result
in the requirement for some pollution control. If high sulfur coal is
fired in the new boiler, both particulate and sulfur dioxide control equip-
ment will be required. Because a relatively low degree particulate removal
is needed to comply with the typical regulation, a wet scrubber designed to
remove SOj should provide adequate particulate control. If low sulfur coal
is fired in the new boiler, only particulate control will be required. Again,
a relatively low degree of particulate removal is required and a low cost
mechanical collector should provide adequate control.
5.3.2 Distillate Oil Fired. Fire Tube Boiler
Fuel switching in a distillate oil-fired, fire tube boiler is identical
to fuel switching in a gas-fired, fire tube unit. However, the gas to oil
fuel switch does not apply. Therefore, the fuel switching methods which
can be employed are:
1) Boiler replacement to permit coal firing
2) Boiler modification to permit low/medium-Btu gas firing
125
-------
Table 5-6 presents estimates of the emissions from the distillate oil
fired standard boiler before and after fuel switching. In addition, typical
state regulations and the degree of control required to comply with these
regulations are included.
As shown in Table 5-6, a switch from distillate oil to low/medium Btu
gas will result in a reduction of all criteria pollutant emissions from the
boiler and no control equipment will be required. However, switching from
distillate oil to coal by boiler replacement will result in an increase in
emissions and some pollution control equipment will be required to meet the
typical state regulations. If high sulfur coal is fired in the new boiler,
both particulate and S02 control equipment will be required. By incorporat-
ing a wet scrubber into the new boiler design, emissions of these two pollu-
tants can be reduced below the required levels. If low sulfur coal is fired
in the new boiler, only particulate control will be required to comply with
the typical state regulations. Because relatively low removal efficiency is
required (63 percent), a low cost, mechanical collector should provide ade-
quate control.
5.3.3 Residual Oil Fired, Water Tube Boiler
A residual oil boiler is designed to fire a fuel which contains both
ash and sulfur. As a result, the presence of ash handling equipment and
design parameters such as tube spacing, furnace volume, and materials of
i
construction make a residual oil fired boiler a candidate for switching to
coal by the following methods:
1) Boiler replacement to permit coal firing
2) Boiler modification to permit direct firing of coal
3) Boiler modification to permit coal-oil mixture combustion
4) Boiler modification to permit low/medium-Btu gas firing
5) Boiler modification to permit firing of coal-based liquids.
126
-------
TABLE 5-6. ESTIMATED EMISSIONS AND CONTROL REQUIREMENTS FOR FUEL
SWITCHING IN A DISTILLATE OIL FIRED, FIRE TUBE BOILER
Boiler Configuration Pollutant
Original Design After Fuel Switch
Distillate 011-
Flred, Fire Tube
Distillate Oil-
Fired, Fire Tube
Distillate 011-
Flred, Fire Tube
Distillate 011-
Flred. Fire Tube
Not Applicable
participates
sulfur dioxide
nitrogen oxides as NO]
carbon monoxide
hydrocarbons as CIU
Low/Medlum-Btu Gas
Fired, Fire Tube . j
partlculates
sulfur dioxide1
nitrogen oxides as NO}3
carbon monoxide
hydrocarbons as CH»3
Coal-Fired, Spreader
Stoker, High Sulfur
Coal partlculates
sulfur dioxide
nitrogen oxides as NOj
carbon monoxide
hydrocarbons as CH»
Coal- Fired, Spreader
Stoker, Low Sulfur
Western Coal partlculatea
sulfur dioxide
nitrogen oxides as NOj
carbon monoxide
hydrocarbons as CH*
Emission Rate1 "Typical" State Regulation2
(ng/J) (lb/10'Btu) (ng/J) (lb/10(Btu)
9
215
86
16
3
1.4
0.3
21-65
1.3
1075
3612
249
37
18
688
537
249
45
22
2.1 x
0.5
0.2
3.6 x
7.2 x
3.3 x
6.0 x
10'2
10'2
10" '
10's
10""
0.05-0.15
3.0 x
2.5
5.9
0.6
8.5 x
4.2 x
1.6
1.25
0.6
0.1
5.2 x
AU
10~s
10"2
10'2
10~2
43
688
129
_
-
NA
NA
86
-
258
1075
301
-
-
258
1075
301
_
-
0.1
1.6
0.3
_
-
NA
NA
0.2
-
0.6
2.5
0.7
_
-
0.6
2.5
0.7
_
-
Degree of Control Requlrec
(Z removal)
0
0
0
_
-
0
0
0
-
76
70
0
_
-
63
0
0
_
-
'Source: PE-348 except where notPd.
*Source: CI-155.
'Emission rates for low/nedium-Btu gas firing arc assumed equal to those of natural gas except for nitrogen oxides. The range presented for NOX emissions
Is ±50 percent of the emission rate for natural gas.
-------
Table 5-7 presents an estimate of the uncontrolled emissions of
criteria pollutants before and after switching fuels in a residual oil
fired boiler. In addition, emission rates permitted by typical state
regulations and the degree of control required to meet these regulations
are included.
No separate estimates are presented in Table 5-7 for boiler replace-
ment and boiler modification to permit direct firing of coal. This is
because the emissions which result from employing either of these fuel
switching methods should be identical. No estimate is presented for low-
sulfur eastern coal or COM prepared with low-sulfur eastern coal. This is
because emission rates and control requirements are similar to those for low-
sulfur western coal. Also, Table 5-7 only contains emission estimates for
one of the three coal-based liquid fuels. SRC-II is presented as represen-
tative because emissions from combustion of this fuel are similar to those
which result from combustion of other coal-based liquid fuels.
As shown in Table 5-7, all but one of the six fuel switching scenarios
will result in a system which requires some pollution control. The excep-
tion is a switch from residual oil to low/medium-Btu gas.
Switching to direct firing of high sulfur coal will require both par-
ticulate and sulfur dioxide control. And, if a new, coal-fired boiler is
used to replace the existing residual oil boiler, the required control equip-
ment should be included in the boiler design. However, if the boiler is
modified to fire coal, sulfur dioxide and particulate control equipment may
be available. This is due to the fact that the fuel characteristics of the
residual oil fired standard boiler would have required some sulfur dioxide
control prior to fuel switching. However, existing control equipment will
have to be modified. Switching from residual oil to direct-firing of high
sulfur coal more than doubles the quantity of sulfur dioxide which must be
removed from the flue gas. This will significantly increase the size of
both raw materials handling and waste/by-product disposal equipment.
128
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TABLE 5-7. ESTIMATED EMISSIONS AND CONTROL REQUIREMENTS FOR FUEL SWITCHING
IN A RESIDUAL OIL FIRED, WATER TUBE BOILER
NJ
VO
Boiler Configuration
Original Daalgn After Fuel Switch
laaloWl 011-Flred
laaldual Mi-Find
iMidnal Oil-Find
laaldual Oil-Find
laatdual Oil-Find
laaldual Oil-Find
laaldual Oil-Find
not Applicable
Coal-Fired, Spreader
Stoker. High Sulfur
Coal
Coal-Fired. Spreader
Stoker. Low Sulfur
Ueataro Coal
COM-Flrad, laald-
Ugh Sulfur Coal'
COH-Flred. Beald-
U» Sulfur Coal'
lov/Medlm Itu Gee-
fired'
SIC-II Fired
Falhitant
partlculataa
aulfur dloxlda
nitrogen oxldaa aa »0,
carbon nonoxlda
bydrocarbona aa CB»
partlculatea
aulfur dloxlda
nitrogen oxidea aa KOi
carbon nanoxlde
bydrocaTbone aa CB*
particnlatea
aulfur dioxide
nitrogen oxidea aa BO,
carbon nonoxida
bydrocarboua aa CB%
partlculataa
aulfur dioxide
nitrogen oxldaa aa NOa
carbon nonoxida
bydrocarbona aa CB%
partlculatea
aulfur dioxide
nitrogen oxidea ae KOt
carbon nonoxida
hjdrocarbone aa Ok
partlculatea
aulfur dioxide
nitrogen oxidea aa MJOi
carbon nonoxida
bydrocarbona aa CH»
partlculataa
aulfur dloxlda
nitrogen oxldaa aa ROt
carbon nonoxlda
hjdrocarbooa aa CRt
tnlai
(ng/J)
39
1333
129
16
3
1075
3612
249
37
18
688
S37
249
45
22
1075
1497
194
16
4
607
1020
194
17
4
1.4
0.3
21-6S
7.3
1.3
40
81
133-269*
15
2.3
lion lace1
(lb/10'ltu)
9.0 x 10"'
3.1
0.3
3.6 x 10"«
7.2 x 10"'
2.5
5.9
0.6
8.5 x 10"1
4.2 x 10"*
1.6
1.25
0.6
10.4 x 10"'
5.2 x 10"'
2.5
3.5
0.43
3.7 x 10 *
9.3 x 10"'
1.4
2.4
0.45
4.0 x 10~*
9.3 X 10"'
3.3 x 10"'
0.6 x 10"'
0.05-0.15
1.7 x 10"1
3.0 x 10*'
9.3 x 10"1
0.2
0.35-0.63'
3.5 x 10"'
5.3 x 10"'
"Typical"
(ni/J)
43
688
129
_
-
258
1075
301
_
-
238
1073
301
_
-
ISO*
880*
213'
.
-
130*
880'
213*
_
-
MA
IA
86
_
-
43
688
129
_
-
State legulatlon*
(lb/10'ltu)
0.1
1.6
0.3
_
-
0.6
2.5
0.7
_
-
0.6
2.5
0.7
_
-
0.33'
2.03'
0.3*
.
-
0.33*
2.05*
0.5*
_
-
MA
MA
0.2
_
-
0.1
1.6
0.3
_
—
Degree of Control Required
(I lenonl)
0
48
0
_
-
76
70
0
_
-
63
0
0
_
-
86
41
0
_
-
75
14
0
_
-
0
0
0
_
-
0
0
16-52
_
-
'Sourca: PE-348 axcapt vhara notad.
'Sourca: CI-U5 axcapt vhara notad.
'Etolaaloa rataa for COM ara baaad on a 50:50 coal/oil nlxtura by valsht. Saa Tabla 4-15 for datalla.
'Tbaaa valuaa ara tha avaraaa of tba coal and tba oil atandarda contalnad In CI-155.
'Bnlaalona rate* an aaauaad aqual to thoaa of natural gai axcapt for NOH. Tha ranga praaantad la ±50 parcant of tha aalaalon rata for natural gaa.
'Sourca: 81-220
-------
Switching from residual oil to direct firing of low-sulfur western
coal will result in the requirement for particulate control. If boiler
replacement is used to switch fuels, a mechanical collector can be included
in the design to provide sufficient control. If the residual oil boiler is
modified to fire coal directly, it may be necessary to retrofit a mechanical
collector. However, because some SOa removal was required prior to the fuel
switch, it may be possible to use existing equipment for particulate control.
Switching from residual oil to COM-firing will require both sulfur
dioxide and particulate control in order to comply with typical state regu-
lations. However, sulfur dioxide emissions do not change significantly as
a result of switching fuels. In addition, the residual oil-fired boiler
required S02 control prior to switching fuels. Therefore, existing SOa
removal equipment should prove adequate for controlling SOz emissions from
COM firing. The existing equipment may need to be augmented by a mechanical
collector to provide adequate particulate removal to meet the typical state
regulations.
Switching from residual fuel oil to SRC-II, a coal-based liquid fuel,
will result in increased emissions of nitrogen oxides. These emissions will
require some control to comply with typical state regulations. However, it
does appear that combustion modifications should provide a sufficient degree
of control to reduce NOX emissions below the required level.
Table 5-8 presents a summary of the control requirements for each fuel
switch discussed in this section. In addition, the control equipment which
appears best suited for obtaining the required degree of removal is identi-
fied. The information on control equipment presented in Table 5-8 is used
as a basis for control equipment cost estimates presented in Appendix F.
5.4 RELATIVE COSTS OF FUEL SWITCHING METHODS
In order to determine which methods are most likely to be used for
switching fuels in industrial boilers, the relative costs of each fuel
130
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TABLE 5-8. SUMMARY OF CONTROL REQUIREMENTS FOR FUEL SWITCHING IN STANDARD BOILERS
Fuel Switch
•
Gas to Distillate Oil
Gas to Lov/Medlun-Btu Gas
Gas to High-Sulfur Coal
Gas to Low-Sulfur Coal
Distillate Oil to Low/Mediua-
Btu Gaa
Distillate Oil to High-Sulfur
Coal
Distillate Oil to Low-Sulfur
!_, Coal
M Residual Oil to High-Sulfur
Coal
Residual Oil to Low-Sulfur
Coal
Residual Oil to COM 1 2
Residual Oil to COM 32
Residual Otl to Luw/Medium-
Btu Gas
Residual Oil to SRC- I I
Participates
Control Required Type of Control
(Z>
None
None
76 Wet scrubber
63 Mechanical
collector
None
76 Wet scrubber
63 Mechanical
collector
76 Wet scrubber
63 Mech.mir.aJ
collector
86 Mechanical
collector
75 Mechanical
collector
None
None
SOj N0y
Control Required Type of Control Control Required Type of Contru
(X) (»
None None
None None
70 Wet scrubber None
None None
None None
70 Wet scrubber None
None None
70 Wet scrubber None
None None
41 Wet scrubber1 None
14 Wet scrubber* None
None | None
None 16-52 Combust li>n
modi f li-.it Ions
'itils assumes th.it a wet scrubber was employed by the existing unit to reduce SO] emissions to levels required by typical state regulations.
'Analyses oF these fuels are presented In Table 4-15.
-------
fuel switching is to determine an annual cost which includes the cost of
fuel, capital charges for equipment, modifications and pollution control,
operating and maintenance costs, and any costs associated with current and
proposed regulations. This section presents estimated annual costs for
fuel switching in the three standard boilers defined in Section 5.1. For
each standard boiler, annual costs are estimated for three cases. The first
case estimates costs without pollution control and the second case includes
an annual charge for pollution control required to reduce emissions below
the level required by typical state regulations. The third case presents
costs which define the potential impact of the fuel tax/investment credit
program which is part of the National Energy Plan. These cost estimates are
based on the capital and operating and maintenance cost estimates presented
in Section 4, the fuel prices presented in Section 5.2, and additional costs
which are presented in this section.
Basically, there are three major components of the annual costs of
operating an industrial boiler. These components are:
1) Capital Costs,
2) Operating and Maintenance Costs, and
3) Fuel Costs.
In addition, a fourth cost associated only with fuel switching is the cost
of replacing boiler capacity which may be lost as a result of a fuel switch.
For the analysis presented here, the cost of replacing lost capacity is
assumed to be a capital cost which equals a percentage of the capital cost
of a new, coal-fired boiler. The capital cost of the new boiler used to
estimate the cost of lost capacity is equal to that for a unit with a capac-
ity of the existing boiler. The percentage of boiler costs which represents
the cost of lost capacity is assumed to equal the percentage reduction in
boiler capacity which results from switching fuels.
The following discussion defines the three major components of the
annual cost.
132
-------
Capital Costs
The capital cost component of the annual costs is determined by a
capital charge rate which is based on the capital investment required to
modify or replace an existing industrial boiler. This rate is a percentage
of the capital cost of modification/replacement which represents, as an
annual cost, a return on capital investment, depreciation of equipment,
taxes, insurance, etc. PEDCo Environmental Specialists have developed
a standard capital charge rate for industrial boilers. This capital
charge rate varies as a function of equipment life and is defined by
Equation 5-1.
Capital Charge Rate - °-1(1 * °'^ +0.04 (5-1)
(1 + 0.1) -1
where N = number of years of equipment life
The above capital charge rate assumes a 10 percent return on investment.
In addition, general and administrative costs, taxes, and insurance are
assumed to be 4 percent of capital investment. For equipment with a 15
year life, the capital charge rate equals 17 percent of total capital in-
vestment and for equipment with a 30 year life, the capital charge rate
equals 14.6 percent of total capital investment.
The capital charge rates defined by Equation 5-1 will be used in
developing the annual costs of switching fuels. A 30 year life is assumed
for all boiler replacement capital costs and a 15 year life is assumed for
capital costs associated with boiler modification and pollution control
equipment.
Operating and Maintenance Costs
Operating and maintenance costs consist of fixed and variable compo-
nents. The fixed cost components are incurred each year, regardless of the
133
-------
load factor or utilization of the boiler. The variable components, on
the other hand, are directly proportional to the load factor. The operating
and maintenance costs used in the comparison presented here are based on
costs developed by Energy and Environmental Analysis, Inc. For 4000 hrs/yr
operation, these costs are presented in Section 4.0 of this report. The load
factors used in computing the operating and maintenance costs are those of
the standard boilers defined in Section 5.1.
Fuel Costs
Annual fuel costs are computed by multiplying the fuel price per unit
of energy by the annual energy consumption of a boiler. The annual energy
consumption of the three standard boilers is presented in Table 5-4, Fuel
prices for natural gas, distillate and residual oil, high- and low-sulfur
coal and various coal-oil mixtures are detailed in Table 5-3. However, the
costs of coal-based fuels are required before the annual costs of all fuel
switching methods can be computed.
Table 5-9 presents the estimated cost of low- and medium-Btu gas and
coal-based liquid fuel. These costs were computed using published estimates
for capital and operating costs. These published costs were adjusted to
standard plant sizes by assuming that plant cost increases exponentially
with size. The value of the exponent was assumed to be 0.6. A 30 year
plant life is assumed which results in a capital charge rate of 14.6 percent
per year. Fuel costs were based on the fuel prices presented in Table 5-3.
Capital and operating costs were estimated for 1985 and 1990 by extrapola-
tion of the Chemical Engineering Plant Cost Index. Details of how these
costs were calculated appear in Appendix C.
The cost of low-Btu gas is presented for two cases which represent the
the two standard boiler sizes. On-site generation of low-Btu gas is
assumed. As shown in Table 5-9, low-Btu gas costs range from $3.40 to
$7.55/GJ ($3.59 to $7.96/106Btu) in 1978. These costs are higher than
most current estimates for one reason. Because the gasification facilities
134
-------
TABLE 5-9. ESTIMATED COSTS OF COAL-BASED FUELS1
Fuel
1978
($/GJ) ($/106Btu)
Low-Btu Gas2
44 MW 3.40 3.59
4.4 MW 7.55 7.96
Medium-Btu Gas3>lf 3.21 3.39
Coal-Baaed Liquid Fuel5'6 4.89 5.16
Cost
1985 1990
($/GJ) ($/106Btu) ($/GJ) ($/106Btu)
5.44 5.74 7.52 7.93
11.93 12.59 16.52 17.43
5.12 5.40 7.14 7.53
7.74 8.17 10.82 11.42
10
01 1
See Appendix C for details.
2Based on capital and operating costs from AS-068.
3Based on capital and operating costs from OL-065.
*Distribution costs are assumed to be 5 percent of product gas costs.
5Based on capital and operating costs from NA-419.
6Distribution costs are assumed to be 10 percent of product fuel costs.
-------
are assumed to be tied directly to the boiler, the utilization of the
gasifier is low (45 to 55 percent). As a result, the capital cost and
fixed operating and maintenance costs are charged on a relatively small
quantity of product gas. Most current estimates are based on 90 percent
utilization of a gasifier which will substantially reduce the estimated
gas prices.
The costs of medium-Btu gas and coal-based liquid fuels are based on
a large central production facility. The capacity of these facilities is
1500 MW (^5000 x 106Btu/hr) and 90 percent utilization is assumed. These
costs include transportation of products from the production site to the
user' s plant.
5.A.I Annual Costs - Fuel Switching in a 4.4 MW Gas-Fired, Fire Tube Boiler
There are three technically feasible fuel switching methods which can
be applied to a gas fired, fire tube boiler. In addition, there are differ-
ences in fuel characteristics which result in a variation of the annual cost
of switching fuels by a particular method. Combination of the three appli-
cable fuel switching methods with the fuel characteristics examined in Section
4 results in the following fuel switching scenarios:
1) Boiler modification, natural gas to distillate oil
2) Boiler modification, natural gas to low-Btu gas
3) Boiler modification, natural gas to medium-Btu gas
4) Boiler replacement, natural gas to high-sulfur coal
5) Boiler replacement, natural gas to low-sulfur eastern coal
6) Boiler replacement, natural gas to low-sulfur western coal
Each of these scenarios represent potential fuel switches and each scenario
will result in a different annual cost for boiler operation. Therefore,
in order to determine which fuel switching scenarios are more likely to
occur, annual costs must be determined for each one. Additional scenarios
136
-------
can also be developed but it appears that the six presented here are
representative. However, the considerations surrounding a fuel switch
are site-specific and it is impossible to account for all the variations
which exist. The annual costs associated with the fuel switching scenarios
defined above were estimated for three cases. In the first case, the annual
costs were estimated in absence of any environmental or energy regulations.
The second case presents cost estimates which include a capital charge for
pollution control equipment. And for the third case, the annual costs are
estimated based on the range of impacts from the fuel tax/investment credit
portion of the National Energy Plan.
Case 1 - Fuel Switching Costs, No Regulations
Table 5-10 compares the estimated annual costs for six fuel switching
scenarios with the cost of continuing to fire natural gas. The annual costs
are divided into three cost components: capital charges, O&M costs, and
fuel costs. The capital charges in Table 5-10 represent incremental costs
and they do not include capital charges which are associated with the exist-
ing boiler. Costs are estimated for-the years 1978, 1985, and 1990 and the
cost of pollution control equipment is not Included. Details of how these
costs were calculated are presented in Appendix E.
The costs presented in Table 5-10 represent a base-case which defines
the annual cost of operating a 4.4 MW (15 x 106 Btu/hr) natural gas-fired
boiler before and after switching fuels. These costs do not include any
charges which result from environmental or energy regulations. As shown
in Table 5-10, there are no fuel switching scenarios which result in a lower
annual cost than the annual cost of continuing to fire natural gas. There-
fore, if fuel switching is going to occur in small, natural gas fired, fire
tube boilers, the economics of boiler operation must be changed by regula-
tions or by an additional factor such as fuel availability.
137
-------
TABLE 5-10.
A COMPARISON OF THE ANNUAL COSTS FOR A 4.4 MW NATURAL GAS FIRED BOILER
BEFORE AND AFTER SWITCHING FUELS1'2
LO
00
Fuel switch
None
Natural gas to distillate oil
Natural gas to low-Btu gas
Natural gas to medium-Btu gas
Natural gas to high-sulfur coal'
Natural gas to low-sulfur eastern coal
Natural gas to low-sulfur western coal
rTT— n m
Cost component
Capital1
0 & M
Fuel
Total
Capital3
0 & M
Fuel
Total
Capital3
0 & M
Fuel
Total
Capital3
0 & M
Fuel
Total
Capital3
0 & M
Fuel
Total
Capital3
0 & M
Fuel
Total
Capital'
0 & M
Fuel
Total
197B
3.8 x 10"
1.2 x 105
1.5B x 10'
1.1 x 10*
3.8 x 10"
1.8 x 105
2.29 x 105
1.1 x 10*
3.8 x 10*
4.7 x 10s
5.19 x 105
3.2 x 103
3.8 x 10*
2.0 x 105
2.41 x 10'
1.1 x 10s
1.7 x 10s
4.4 x 10*
3.24 x 10a
1.1 x 10s
1.7 x 10s
6.9 x 10*
3.49 x 10*
1.1 x 10s
1.7 x 10s
2.5 x 10*
3.05 x 10s
Cost ($/yr)
1985
6.1 x 10*
1.9 x 10s
2.51 x 10*
1.7 x 10*
6.1 x 10*
2.9 x 105
3.68 x 10'
1.7 x 10*
6.1 x 10*
7.4 x 105
8.18 x 105
5.1 x 10'
6.1 x 10*
3.2 x 105
3.86 x 105
1.8 x 10s
2.7 x 10s
7.0 x 10*
5.20 x 10'
1.8 x 105
2.7 x 10s
1.1 x 10s
5.60 x 10"
1.8 x 10s
2.7 x 105
4.0 x 10*
4.90 x 10"
1990
8. 7 x 10*
2.6 x 10'
3.47 x 10K
2.4 x 10"
8.7 x 10*
4.0 x 105
5.11 x 10"1
2.4 x 10"
8.7 x 10*
1.0 x 10"
1.11 x 106
7.1 x 103
8.7 x 10*
4.5 x 10*
5.44 x 10'
2.5 x 10s
3.8 x 10s
9.9 x 10*
7.29 x 10'
2.5 x 105
3.8 x 105
1.5 x 10*
7.80 x 10'
2.5 x 105
3.8 x 105
5.6 x 10*
6.86 x 10"
'See Appendix E for details.
2Does not include pollution control costs.
Capital costs represent incremental costs.
-------
The order of preference for the fuel switching scenarios based on
annual costs and in the absence of regulatory impact is as follows:
1) Natural gas to distillate oil
2) Natural gas to medium-Btu gas
3) Natural gas to low-sulfur western coal
4) Natural gas to high-sulfur coal
5) Natural gas to low-sulfur eastern coal
6) Natural gas to low-Btu gas
The cost of switching to both medium-Btu gas and distillate oil are essen-
tially identical. Therefore, it would appear that either of these fuel
switches have an equal probability of occurring. However, there are no
large central gasification facilities in the U.S., so a switch to distillate
oil is the most likely scenario. In the absence of regulations, this fuel
switch will only occur if the boiler's natural gas supply becomes unreliable
and an economic penalty is incurred as a result of the unreliability.
The annual cost which results from switching from natural gas to
coal by boiler replacement is nearly constant, regardless of the type of
coal fired. The costs of firing coal are approximately 50 percent higher
than the costs of firing medium-Btu gas or distillate oil. Therefore,
boiler replacement does not appear to be an economically feasible fuel
switch for the natural gas-fired, fire tube boiler.
The cost of firing low-Btu gas is the highest of all the fuel switching
scenarios examined. There are two major reasons for this. First, the cost
of low-Btu gas fuel is high. This is due to the low utilization of the
gasifier (45 percent) which results from tying the gasifier directly to
the boiler. The second reason for the high cost of firing low-Btu gas is
the capital charge associated with the boiler derating (5 percent) which
occurs as a result of switching to low-Btu gas.
139
-------
In summary, it appears that, in the absence of regulations, an existing
4.4 MW (15 x 106 Btu/hr), natural gas fired, fire tube boiler will not switch
fuels if a secure supply of natural gas is available. If the natural gas
supply is not secure, the most likely fuel switch to occur would be to dis-
tillate oil. Medium-Btu gas is competitive with distillate oil if the gas
is produced in a large (1500 MW equivalent - 5000 x 10s Btu/hr) facility.
However, this type of facility is not expected to have a significant impact
for several years. A recent study by SRI International indicates that medium-
Btu gas produced in a large central facility will account for 7.3 percent of
the energy consumption of three major industries in 1985 and 13 percent by
the year 2000 (OL-065).
A fuel switch from gas to coal by boiler replacement is not likely to
occur. However, if no gas or oil is available, the next choice is to replace
the existing boiler with a coal fired unit. Low-Btu gas is not competitive
with other fuel switching methods when applied to a 4.4 MW (15 x 10s Btu/hr)
boiler.
Case 2 - Fuel Switching Costs, Typical State Regulations
In order to determine the true annual costs of firing a variety fuels,
the cost of pollution control required to meet applicable regulations must
be included. However, applicable regulations vary from one location to
another, so an exact determination of pollution control requirements and
thus costs, is difficult. PEDCo Environmental Specialists have identified
"typical" state regulations which apply to industrial boilers (GI-155).
The pollution control requirements for each of the fuel switches under
typical regulations are defined in Section 5.3. These requirements are
used as a basis for the costs of pollution control which must be included
in the cost of switching fuels.
Table 5-11 compares the estimated annual costs of six fuel switching
scenarios with the cost of continuing to fire natural gas. The costs pre-
sented in Table 5-11 includes the cost of pollution control. The pollution
140
-------
control requirements are those identified in Table 5-8. Costs are based on
estimates prepared by the Industrial Gas Cleaning Institute (IN-181) and
Energy and Environmental Analysis (EN-761). A 15 year life is assumed for
the pollution control equipment which results in a capital charge rate of
17 percent. Details of how the costs in Table 5-11 were derived appear in
Appendix F.
TABLE 5-11. A COMPARISON OF THE ANNUAL COSTS FOR A 4.4 MW GAS FIRED
BOILER BEFORE AND AFTER SWITCHING FUELS1*2
Fuel Switch Annual Cost ($/yr)
1978 1985 1990
None 1.58 x 10s 2.51 x 10s 3.47 x 10s
Natural gas to distillate oil 2.29 x 105 3.68 x 10s 5.11 x 10s
Natural gas to low-Btu gas 5.19 x 105 8.18 x 10s 1.11 x 10e
Natural gas to medium-Btu gas 2.41 x 105 3.86 x 10s 5.44 x 105
Natural gas to high-sulfur coal 4.19 x 10s 6.71 x 10s 9.41 x 10s
Natural gas to low-sulfur 3.59 x 10s 5.77 x 10s 8.03 x 10s
eastern coal
Natural gas to low-sulfur 3.15 x 10s 5.07 x 10s 7.07 x 10s
western coal
*See Appendices E and F for details.
2Includes cost of pollution control.
As shown in Table 5-11, the relative costs of the six fuel switching
scenarios do not change markedly. In fact, the only scenarios which are
impacted by pollution control costs are the fuel switches to coal. As a
result of adding pollution control costs, high-sulfur coal-firing becomes
the most expensive boiler replacement option and firing of any type of coal
becomes less competitive on an annual cost basis. If the estimates were
based on more relaxed regulations, the annual costs approach those presented
141
-------
in Table 5-10. Application of more restrictive pollution control regulations
will only serve to make coal-firing less economically attractive and a switch
to coal less likely to occur.
Case 3 - Fuel Switching Costs, Energy Regulations
In addition to the costs which result from environmental regulations,
the annual costs of switching fuels in an existing 4.4 MW (15 x 10s Btu/hr)
gas fired fire tube boiler may be impacted by provisions of the National
Energy Plan which are currently under consideration. The provisions of the
NEP are detailed in Section 5.2 but the impact of these provisions on the
three standard boilers cannot be quantified. This is due to the fact that
the proposed fuel tax/investment credit portion of the NEP is site-specific
rather than being specific to a particular size of boiler (US-768).
In order to estimate the potential impact of the fuel tax/investment
credit portion of the NEP, two cases were examined. The first assumes that
only the minimum fuel tax is paid and no investment credit is received. For
the 4.4 MW (15 x 106 Btu/hr) boiler, the annual costs which result from this
assumption are identical to those presented in Table 5-11. The second case
assumes that tax is paid on all fuel used by the boiler and the capital in-
vestment required to switch to coal is completely covered by investment cred-
it. Annual costs for these two cases are presented in Table 5-12 and details
of how these costs were determined appear in Appendices C, D, and E.
The costs presented in Table 5-12 are for the years 1985 and 1990.
Although the fuel tax/investment credit program is scheduled to begin in
1979, it will not be fully implemented until 1985 (US-768). As shown in
Table 5-12, the full impact of the NEP will effect the six fuel switching
scenarios in two ways. First, the cost of firing natural gas and distillate
oil increases significantly. As a result, the cost of firing medium-Btu gas
becomes competitive with the cost of firing natural gas. Second, the annual
142
-------
TABLE 5-12. RANGE OF POTENTIAL IMPACT FROM THE FUEL TAX/INVESTMENT CREDIT PROGRAM ON THE
ANNUAL COSTS OF A 4.4 MW GAS FIRED BOILER1'2
Fuel Switch
Annual Cost ($/yr)
Minimum Fuel Tax
No Investment Credit
1985 1990
None
Natural
Natural
Natural
Natural
Natural
Natural
gas to distillate oil
gas to low-Btu gas
gas to medium-Btu gas
gas to high-sulfur coal
gas to low-sulfur eastern coal
gas to low-sulfur western coal
2.51
3.68
8.18
3.86
6.71
5.77
5.07
x 10s
x 105
x 10s
x 10s
x 10s
x 10s
x 10s
3
5
1
5
9
8
7
.47
.11
.11
.44
.41
.03
.07
x 10s
x 10s
x 106 .
x 10s
x 10s
x 10s
x 10s
Maximum Fuel Tax
Maximum Investment Credit
1985 1990
3.
4.
4.
3.
5.
4.
4.
51
18
99
89
27
73
03
x 10s
x 105
xlO5
x 10s
x 105
x 10s
x 10s
4.87
5.91
6.98
5.48
7.42
6.63
5.67
x 105
x 10s
x 10s
x 10s
x 10s
x 10s
x 10s
1See Appendices E and F for details.
2Includes the cost of pollution control.
-------
cost of firing coal is reduced and, as a result, this fuel switching option
becomes competitive with distillate oil firing for the low-sulfur western
coal scenario.
Although the fuel tax/investment credit program does change the relative
economics of the six fuel switching options, the cost of continuing to fire
natural gas and the limited supply of medium-Btu gas will restrict fuel
switching. And since the costs shown in Table 5-12 represent the maximum
impact of the fuel tax/investment credit program, a small fraction of the
existing 4.4 MW (15 x 106 Btu/hr) natural gas-fired, fire tube boilers may
find medium-Btu gas firing economical. Therefore, the extent of fuel switch-
ing in small gas-fired boilers will be determined by fuel availability. The
fuel switching scenarios which are most likely to occur if natural gas is not
available are:
1) Natural gas to low-sulfur western coal
2) Natural gas to distillate oil
3) Natural gas to low-sulfur eastern coal
Because distillate oil may also be difficult to obtain, the most probable
fuel switch will be to low-sulfur western coal,
5.4.2 Annual Costs - Fuel Switching in a 4.4 MW Distillate Oil-Fired
Fire Tube Boiler
There are two technically feasible fuel switching methods which can be
applied to a distillate oil fired, fire tube boiler. In addition, there are
differences in fuel characteristics which result in a variation of the annual
cost of switching fuels. Combination of the two applicable fuel switching
methods with the fuel characteristics examined in Section 4 results in the
following fuel switching scenarios:
1) Boiler modification, distillate oil to low-Btu gas
2) Boiler modification, distillate oil to medium-Btu gas
144
-------
3) Boiler replacement, distillate oil to high-sulfur coal
4) Boiler replacement, distillate oil to low-sulfur eastern coal
5) Boiler replacement, distillate oil to low-sulfur western coal
Each of these scenarios represent potential fuel switches and each scenario
will result in a different annual cost for boiler operation.
Annual costs were estimated for each of the five scenarios defined
above and these costs were examined for three cases. The first case esti-
mates the annual costs associated with firing various fuels in absence of
any environmental or energy regulations. The second case presents cost
estimates which include a capital charge for pollution control equipment
which is required to meet typical state regulations. And for the third
case, annual costs are estimated based on the provisions of the fuel tax/
investment credit program which is part of the National Energy Plan.
Case 1 - Fuel Switching Costs, No Regulations
Table 5-13 compares the estimated annual costs for the five fuel switch-
ing scenarios defined above. The annual costs are divided into three com-
ponents: capital charges, O&M costs, and fuel costs. The capital charges
in Table 5-13 represent incremental costs associated with fuel switching and
they do not include capital charges for the existing boiler. Costs are esti-
mated for the years 1978, 1985, and 1990. Capital charges and O&M costs were
developed for the years 1985 and 1990 by extrapolation of the Chemical Engi-
neering Plant Cost Index. Mid-year values for the index were estimated to be
345 and 480 for 1985 and 1990, respectively. No costs are included for pollu-
tion control but a capital charge is included to account for boiler derating.
Details of how the costs in Table 5-13 were calculated appear in Appendix E.
As shown in Table 5-13, there are no fuel switching scenarios which
have an annual cost lower than that resulting from continued combustion of
145
-------
TABLE 5-13.
A COMPARISON OF THE ANNUAL COSTS FOR A 4.4 MW DISTILLATE OIL FIRED
BOILER BEFORE AND AFTER SWITCHING FUELS1'2
Fuel Switch Cost Component
None
Distillate oil to )ow-Btu gas
Dint 11 late oil to medium-Bin gas
Distillate oil to high-sulfur coal
Distillate oil to low-sulfur eastern conl
Distillate oil to low-sulfur western coal
Capital'
0 & H
Fuel
Total
Capita)'
0 & H
Fuel
Total
Capital'
0 & M
Fuel
Total
Capital'
0 & H
Fuel
Total
Capital'
0 & H
Fuel
Total
Capital'
0 & H
Fuel
Total
3
1
2
f>
3
4
5
2
3
2
2
1
1
4
1
1
1
6
3
1
1
2
3
Cost
1978
-
.8
.8
.18
.8
,R
.7
.76
.2
.8
.0
.60
.1
.7
.4
.24
.1
.7
.9
.49
.1
.7
.5
.05
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10*
10'
10'
10*
10*
10'
10'
10*
10*
10'
10'
10'
10'
10*
10'
10'
10'
10*
10'
10s
10'
10*
liT
6.
2.
3.
1.
6.
7.
9.
1.
6.
3.
4.
1.
2.
7.
5.
1.
2.
1.
5.
1.
2.
4.
4.
($/)
198")
-
1
9
51
1
1
4
11
6
1
2
17
8
7
0
20
8
7
1
60
8
7
0
90
mr-
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
n)
1990
10*
10'
1(T
10s
10"
10s
10*
10*
10*
10'
10"
105
10s
10»
10"
10s
10'
10'
10'
10'
10'
10'
10"
-
8.7
4.0
4.87
1.5
8.7
1.0
1.24
4.9
8.7
4.5
5.86
2.5
3.8
9.9
7.29
2.5
3.8
1.5
7.80
2.5
3.8
5.6
6.86
x 10*
x 10'
x 10'
x \0"
x 10*
x 10'
x 10"
x 10*
x 10*
x 10s
x 10'
x 10s
x 10*
x 10*
x 10"
x 10'
x 10'
x 10'
x 10"
x 10'
x 10'
x 10*
x 10'
'See Appendix E for details.
'Does not Include pollution control costs.
'capital costs represent Incremental costs.
-------
distillate oil. And while the cost of medium-Btu gas combustion is close
to that of distillate oil firing, the use of medium-Btu gas is expected to
be limited.
The order of preference for the fuel switching scenarios based on annual
costs is as follows:
1) Distillate oil to medium-Btu gas
2) Distillate oil to low-sulfur western coal
3) Distillate oil to high-sulfur coal
4) Distillate oil to low-sulfur eastern coal
5) Distillate oil to low-Btu gas
The annual costs of firing coal are nearly constant regardless of the
fuel characteristics. These costs are approximately 50 percent higher than
the cost of firing distillate oil. Therefore, boiler replacement does not
appear to be an economically feasible fuel switching method for a 4.4 MW
distillate oil-fired, fire tube boiler. However, if a fuel switch is re-
quired for reasons of fuel availability, the most likely scenario will be
a switch to coal by boiler replacement.
The annual cost of firing low-Btu gas is nearly three times the annual
cost of distillate oil firing. The reasons for this are the high cost of
producing low-Btu gas and the estimated boiler derating (50 percent) (BA-477)
which results when low-Btu gas is fired in an existing oil boiler.
In summary, in the absence of regulations, fuel switching is not eco-
nomically feasible in a 4.4 MW (15 x 10s Btu/hr) distillate oil fired, fire
tube boiler. Firing medium-Btu gas is competitive but no facilities cur-
rently produce this fuel. Projections indicate medium-Btu gas will have
a limited penetration into the U.S. fuels market by 1985. Switching to
coal firing is not economically attractive but if distillate oil supplies
become insecure, this fuel switch will occur. Low-Btu gas firing is not
147
-------
competitive with other fuel switching options and it results in almost a
300 percent increase in annual costs for the boiler.
Case 2 - Fuel Switching Costs, Typical State Regulations
Table 5-14 compares the estimated annual costs for five fuel switching
scenarios with the annual costs of operating a 4.4 MW (15 x 10s Btu/hr)
distillate oil-fired, fire tube boiler. The costs presented in Table 5-14
include capital charges for pollution control equipment. The degree of con-
trol required and the type of pollution control equipment used are defined
in Table 5-8. Details of how pollution control costs were calculated appear
in Appendix F.
TABLE 5-14. A COMPARISON OF THE ANNUAL COSTS FOR A 4.4 MW DISTILLATE
OIL FIRED BOILER BEFORE AND AFTER SWITCHING FUELS1'2
Fuel Switch Annual Cost ($/yr)
1978 1985 1990
None 2.18 x 10s 3.51 x 10s 4.87 x 10s
Distillate oil to low-Btu gas 5.76 x 10s 9.11 x 10s 1.24 x 106
Distillate oil to medium-Btu gas 2.60 x 105 4.17 x 10s 5.86 x 10s
Distillate oil to high-sulfur coal 4.19 x 10s 6.71 x 105 9.41 x 10s
Distillate oil to low-sulfur 3.59 x 10s 5.77 x 10s 8.03 x 10s
eastern coal
Distillate oil to low-sulfur 3.15 x 105 5.07 x 105 7.07 x 105
western coal
!See Appendices E and F for details.
2Includes the cost of pollution control.
148
-------
Addition of capital charges for pollution control equipment does not
significantly change the annual costs of the five fuel switching scenarios
examined. In fact, the annual costs of firing both low- and medium-Btu gas
do not change and the cost of firing the low-sulfur coals increases by less
than 5 percent. Only the high-sulfur coal costs are impacted by pollution
control costs. The addition of capital charges for pollution control makes
high-sulfur coal firing the most expensive of the three coal firing scenar-
ios, but low-Btu gas combustion still has the highest annual cost.
It must be emphasized that the costs presented in Table 5-14 are based
on the typical state regulations identified in Section 5.3. If more restric-
tive regulations are applied to the fuel switching scenarios, the cost of
firing coal becomes higher. If more relaxed regulations are applied, the
cost of firing high-sulfur coal will decline while the costs of firing low
sulfur coal should not change significantly. However, regardless of the
degree of control required, it appears that the relative costs of firing
distillate oil, medium-Btu gas, coal, and low-Btu gas will not change.
Case 3 - Fuel Switching Costs, Energy Regulations
The fuel tax/investment credit program which is part of the National
Energy Plan has the potential to impact the annual cost of operating a
boiler (US-768). However, because the fuel tax/investment credit program
is site specific rather than specific to a class of boilers, its impact on
annual costs cannot be quantified. In order to estimate the potential im-
pact, the annual costs of firing various fuels were estimated for two cases.
The first case determines what the minimum impact of the tax program will
be. For a 4.4 MW (15 x 10s Btu/hr) distillate oil fired, fire tube boiler,
there is no impact. No fuel tax is incurred because of the low annual fuel
consumption by the boiler. In addition, no investment credit is available.
The second case estimates what the maximum impact of the tax program might
be. In this case, all the oil consumed is subject to the maximum tax rate
and all capital investments in coal-firing equipment, including on-site
149
-------
gasification, are eligible for investment credit. This case could only
occur if the distillate oil fired boiler is part of a large industrial com-
plex which consumes 1.6 fJ/yr (1.5 x 1012 Btu/yr) or more of natural gas,
distillate, or residual oil (US-768).
Table 5-15 compares the estimated annual costs for five fuel switching
scenarios with the cost of firing distillate oil under the two cases defined
above. The first case is identical to the costs presented in Table 5-14
while the second case reflects the full impact of the fuel tax/investment
credit program. As shown, the second case results in changes in the rela-
tive costs of firing various fuels. Medium-Btu gas firing becomes the lowest
cost scenario and firing low-sulfur western coal becomes competitive with
distillate oil firing. The annual cost of firing low-sulfur eastern coal is
about 20 percent above that of western coal, but it may be attractive in some
areas of the country. High-sulfur coal and low-Btu gas firing still do not
appear attractive. The change in the relative costs of firing fuels will
have several impacts. First, the low cost of medium-Btu gas should encour-
age the construction of central gasification facilities. Second, because
the cost of firing low-sulfur coal is essentially equal to the cost of firing
distillate oil, distillate oil fired boilers which are retired will tend to
be replaced with coal-fired units. This is especially true if the supply of
distillate oil becomes uncertain. However, it appears unlikely that a sig-
nificant fraction of the distillate oil-fired, fire tube boilers will be
subject to the full impact of the fuel tax/investment credit program. There-
fore, no significant fuel switches are expected in the class of boilers rep-
resented by the 4.4 MW (15 x 10s Btu/hr) unit.
5.4.3 Annual Costs - Fuel Switching in a 44 MW Residual Oil-Fired Water
Tube Boiler
There are five technically feasible fuel switching methods which can
be applied to a residual oil-fired, water tube boiler. In addition, there
are differences in fuel characteristics which result in a variation of the
150
-------
TABLE 5-15. RANGE OF POTENTIAL IMPACT FROM THE FUEL TAX/INVESTMENT CREDIT PROGRAM ON THE
ANNUAL COSTS OF A 4.4 MW DISTILLATE OIL FIRED BOILER1*2
Fuel Switch Annual Cost ($/yr)
None
Distillate oil
Distillate oil
Distillate oil
Distillate oil
Distillate oil
Minimum Fuel Tax
No Investment Credit
1985 1990
3.51 x 10s 4.87 x 10s
to low-Btu gas 9.11 x 10s 1.24 x 10s
to medium-Btu gas 4.17 x 10s 5.86 x 10s
to high-sulfur coal 6.71 x 10s 9.41 x 105
to low-sulfur eastern coal 5.77 x 105 8.03 x 10s
to low-sulfur western coal 5.07 x 10 7.07 x 10s
Maximum Fuel Tax
Maximum Investment Credit
1985 1990
4.01 x 10s 5.67 x 105
5.42 x 10s 7.59 x 106
3.98 x 10s 5.61 x 10s
5.27 x 10s 7.42 x 10s
4.73 x 10s 6.63 x 10s
4.03 x 10s 5.67 x 10s
1See Appendices E and F for details.
2Includes the cost of pollution control.
-------
annual costs of switching fuels. Combination of the five applicable fuel
switching methods with the fuel characteristics examined in Section 4 results
in fourteen fuel switching scenarios, nine of which are listed below.
1) Boiler modification, residual oil to low-Btu gas
2) Boiler modification, residual oil to medium-Btu gas
3) Boiler modification, residual oil to COM 1
4) Boiler modification, residual oil to COM 2
5) Boiler modification, residual oil to COM 3
6) Boiler modification, residual oil to coal-based liquid fuel
7) Boiler replacement, residual oil to high-sulfur coal
8) Boiler replacement, residual oil to low-sulfur eastern coal
9) Boiler modification, residual oil to low-sulfur western coal
For each of the nine fuel switching scenarios listed, annual costs were
estimated. Costs were not estimated for boiler modification to permit
firing various coals and boiler modification to permit firing of specific
coal-based liquid fuels.
The reason costs are not presented for modification to permit coal
firing is because costs are essentially equal to the costs of boiler replace-
ment. Therefore, it seems unlikely that any existing boilers will be modi-
fied to permit coal firing unless the capability to fire coal was included
in the boiler design. And, while the survey of MFBI's indicates that 22
percent of existing MFBI's were designed with coal capability, it is impossi-
ble to estimate the costs of reconverting these units.
Costs were not estimated for the three coal based liquid fuels dis-
cussed in Section 4 because no cost data for production of these fuels
were available. Instead, a general cost estimate for production of coal
based liquid fuels by a solvent extraction, catalytic hydrogenation lique-
faction process was used. Therefore, the scenario which examines coal-based
liquid fuel is not representative of any specific process. Rather, the costs
are assumed to be representative of liquefaction technology in general.
152
-------
Annual costs of the nine fuel switching scenarios defined above are
estimated for three cases. In the first case, costs are estimated without
consideration of the impact of current or proposed environmental and energy
regulations. This defines base-line annual costs for the fuel switching
scenarios. The second case presents estimated annual costs for the fuel
switching scenarios which include pollution control equipment. The degree
of control required and the type of control equipment used are defined in
Table 5-8. The third case projects a range of annual costs which may result
from implementation of the proposed fuel tax/investment credit program which
is part of the National Energy Plan.
Case 1 - Fuel Switching Costs, No Regulations
Table 5-16 compares the estimated annual costs for nine fuel switching
scenarios with the cost of continuing to fire residual oil in an existing
44 MW (150 x 10s Btu/hr) water tube boiler. Based on the costs presented
in Table 5-15, the order of preference for the fuel switching scenarios is:
1) Residual oil to low-sulfur western coal
2) Residual oil to COM 3
3) Residual oil to COM 1
4) Residual oil to COM 2
5) Residual oil to high-sulfur coal
6) Residual oil to low-sulfur eastern coal
7) Residual oil to medium-Btu gas
8) Residual oil to low-Btu
9) Residual oil to coal-based liquid fuel.
As shown in Table 5-16, the annual costs of the first five scenarios are
competitive with the cost of continuing to fire residual oil. Within the
accuracy of the cost estimates, the annual costs of firing high-sulfur coal,
low-sulfur western coal, COM, and residual oil are equal. The cost of firing
low-sulfur eastern coal, medium-Btu gas, low-Btu gas, and coal-based liquid
153
-------
TABLE 5-16. A COMPARISON OF THE ANNUAL COSTS FOR A 44 MW RESIDUAL OIL
FIRED BOILER BEFORE AND AFTER SWITCHING FUELS
I ,2
Ui
Fuel Switch
Hone
Residual oil to lov-Btu gae
Residual oil to acdiuB-Btu gas
Residual oil to COM 1
Residual oil to CON 2
Residual oil to COM 3
Residual oil to coal-baaed liquid fuel
Residual oil to hlgh-iulfur coal
Residual oil to low-sulfur eastern coal
Residual oil to low-sulfur western coal
Coat Component
Capital'
0 & M
Fuel
Total
Capital'
0 & H
Fuel
Total
Capital'
0 & H
Fuel
Total
Capital'
0 & H
Fuel
Total
Capital'
0 & M
Fuel
Total
CnnUnl'
0 & H
Fuel
Total
Capital'
0 & M
Fuel
Total
Capital'
0 & H
Fuel
Total
Capital*
0 & H
Fuel
Total
Capital'
0 & N
Fuel
Total
1978
7.7 x 10'
1.6 x 10'
1.68 x 10'
5.3 x 10s
7.7 x 10'
2.6 x 10'
3.21 x 10'
1.7 x 105
7.7 x 10'
2.4 x 10*
2.65 x 10'
1.1 x 10»
1.9 x 10'
1.4 x 10'
1.60 x 10*
1.1 x 10*
1.9 x 10§
1.5 x 10'
1.70 x 10'
1.1 x 10'
1.9 x 10s
1.4 x 10'
1.60 x 10'
2.2 x 10s
7.7 x 10'
3.7 x 10'
4.00 x 10'
8.6 x 10s
3.2 x 10s
S.3 x 10'
1.71 x 10'
8.6 x 10s
3.2 x 10s
8.4 x 10*
2.02 x 10*
8.6 x 10'
3.2 x 10'
3.0 x 10s
1.48 x 10*
Annual Cost ($/yr)
1985
1.2 x 10'
2.6 x 10'
2.72 x 10'
8.3 x 10'
1.2 x 10s
4.1 x 10'
5.05 x 10'
2.6 x 10'
1.2 x 10'
3.9 x 10'
4.28 x 10'
1.9 x 10'
3.0 x 10'
2.2 x 10'
2.52 x 10'
1.9 x 10»
3.0 x 10'
2.4 x 10'
2.72 x 10*
1.9 x 10*
3.0 x 10s
2.2 x 10'
2.52 x 10*
3.4 x 10'
1.2 x 10'
5.9 x 10*
6.36 x 10'
1.4 x 10'
5.1 x 10'
8.6 x 10s
2.77 x 10'
1.4 x 10*
5.1 x 10'
1.3 x 10'
3.21 x 10*
1.4 x 10'
5.1 x 10'
4.8 x 10s
2.39 x 10*
1990
1.7 x 10s
3.6 x 10'
3.77 x 10'
1.2 x 10'
1.7 x 10s
5.7 x 10*
7.07 x 10*
3.7 x 10'
1.7 x 10'
5.4 x 10'
5.94 x 10'
2.6 x 10'
4.2 x 10s
3.1 x 10'
3.55 x 10'
2.6 10'
4.2 10s
3.3 10'
3.75 10*
2.6 10*
4.2 10'
3.0 10'
3.45 x 10'
4.9 x 10s
1.7 10s
8.2 10*
8.86 10'
1.9 10'
7.1 10»
1.2 x 10'
3.81 x 10'
1.9 x 10'
7.1 x 10s
1.9 x 10'
4.51 x 10*
1.9 x 10*
7.1 x 10s
6.8 x 10s
3.29 x 10'
'See Appendix E for details.
'Does not Include pollution control costs.
Capital costs represent Incremental costs.
-------
fuels are not competitive with the other fuel switching scenarios. Details
of how the costs presented in Table 5-16 were calculated appear in Appendix E.
Although the values presented for annual costs in Table 5-16 indicate
that some of the fuel switching scenarios do have lower annual costs than
those associated with firing residual oil, the accuracy of the cost estimates
and the bases used in developing these estimates make it impossible to dis-
tinguish between the costs of firing residual oil, high-sulfur coal, low-
sulfur western coal, and COM. Therefore no significant fuel switching is
expected based on the costs in Table 5-16. If any fuel switching does occur,
it will be a result of a site specific analysis which is the only method of
accurately defining costs associated with various fuel switching scenarios.
Also, the costs presented in Table 5-16 do not include any pollution control
equipment and therefore they do not reflect the costs which will be incurred
if an existing boiler which switches fuels must comply with state regulations.
Case 2 - Fuel Switching Costs, Typical State Regulations
Table 5-17 compares the estimated annual costs for nine fuel switching
scenarios with the annual costs of operating a 44 MW (150 x 10s Btu/hr)
residual oil-fired, water tube boiler. These costs include capital charges
for pollution control equipment which is required to reduce the level of
criteria pollutant emissions below that permitted by typical state regula-
tions. As shown in Table 5-17, the cost of firing low-sulfur western coal
and all three coal-oil mixtures remain competitive with the cost of con-
tinuing to fire residual oil even when capital charges for pollution control
equipment are included in annual costs. In fact, the scenario in which high-
sulfur coal is fired is the only case in which a significant change in costs
results from applying pollution control equipment. This is because firing
high-sulfur coal requires a flue gas desulfurization system in order to
comply with the SOa emission limits defined by the typical state regulations.
The cost of firing low-sulfur coal and COM increases by less than 5 percent
because only a moderate degree (less than 90 percent removal) of particulate
control and no additional SOz controls are required.
155
-------
TABLE 5-17. A COMPARISON OF THE ANNUAL COSTS FOR A 44 MW RESIDUAL OIL
FIRED BOILER BEFORE AND AFTER SWITCHING FUELS1'2
Fuel Switch
Annual Cost ($/yr)
1978
None
Residual
Residual
Residual
Res idual
Residual
Residual
liquid
Residual
Residual
eastern
Res idual
western
oil to
oil to
oil to
oil to
oil to
oil to
fuel
oil to
oil to
coal
oil to
coal
low-Btu gas
medium-Btu gas
COM 1
COM 2
COM 3
coal-based
high-sulfur coal
low-sulfur
low- sulfur
1.
3.
2.
1.
1.
1.
4.
2.
2.
1.
68
21
65
66
76
66
03
34
08
54
x 106
x 106
x 10s
x 106
x 106
x 10s
x 106
x 10s
x 106
x 10s
2
5
4
2
2
2
6
3
3
2
1985
.72
.05
.28
.60
.80
.60
.40
.77
.29
.47
x 106
x 10s
x 106
x 10s
x 106
x 106
x 106
x 106
x 10s
x 10s
3
7
5
3
3
3
8
5
4
3
1990
.77
.07
.94
.66
.86
.56
.92
.21
.62
.40
x 106
x 106
x 10s
x 106
x 106
x 10s
x 106
x 10s
x 10s
xlO6
aSee Appendices E and F for details.
2Includes the cost of pollution control.
If more restrictive environmental regulations are applied to the fuel
switching scenarios, firing low-sulfur western coal and COM will become less
competitive with continued firing of residual oil and a fuel switch will be
less likely. If more relaxed environmental regulations are applied to the
fuel switching scenarios, no major changes will occur. The only scenario
which will be impacted is high-sulfur coal firing. Less restrictive regu-
lations will make this scenario more competitive with residual oil firing.
156
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Case 3 - Fuel Switching Costs, Energy Regulations
The fuel tax/investment credit program which is part of the National
Energy Plan will impact the annual cost of operating a 44 MW (150 x 106 Btu/
hr) boiler. However, because the fuel tax/investment credit program is site
specific rather than specific to a single boiler, it is difficult to quantify
the impact of the program on annual costs (US-768). In order to determine
what the impact of the tax program might be, the annual costs of firing
various fuels were estimated for two cases. The first case determines what
the minimum impact of the tax program will be. This assumes that the boiler
under consideration is the only unit located at a particular site. For a 44
MW (150 x 106 Btu/hr) residual oil-fired boiler with a load factor of 55 per-
cent, the oil burned will be subject to 23 percent of the full fuel tax rate
defined in Table 5-3. This assumes that the tax rate increases linearly from
0 to 100 percent of the maximum as annual fuel consumption increases from
0.53 to 1.6 fJ/yr (0.5 to 1.5 x 1012 Btu/yr). No investment credit is given
to capital expenditures for coal firing equipment in this case.
The maximum impact of the fuel tax/investment credit program is also
estimated. This case assumes that the 44 MW (150 x 10s Btu/hr) residual
oil boiler is part of a larger fuel burning installation which consumes
more than 1.6 fJ/yr (1.5 x 1012 Btu/yr) of gas and oil. In addition, it
is assumed that all capital investment in coal firing equipment including
modifications required to permit firing of COM and coal-based gas and liquid
fuels are eligible for full investment credit.
Table 5-18 presents estimated annual costs for firing various fuels
under the minimum and maximum impacts of the fuel tax/investment credit
program. Under the minimum impact case, only the cost of firing residual
oil is affected and this cost increases by less than 5 percent. Under the
maximum impact case, significant changes occur in the relative costs of
firing various fuels. The annual cost of firing low-sulfur western coal
by boiler replacement is approximately 50 percent of the cost of firing
157
-------
residual oil. In addition, the annual costs of firing low-sulfur eastern
coal, high-sulfur coal, low-Btu gas, and the three coal-oil mixtures are
over 15 percent lower than the cost of continuing to fire distillate oil.
Details of how these costs were calculated appear in Appendices E and F.
There are several reasons why the relative costs of firing various
fuels changes so markedly. First, the fuel tax results in nearly a 50
percent increase in the annual cost of firing residual oil. Second, the
annual cost of firing coal is reduced approximately 30 percent due to the
investment credit, which is applied to the capital charges associated with
the boiler and pollution control equipment. The cost of producing low-Btu
gas is also reduced because investment credit is applied to the capital cost
of the gasifier. Third, although the cost of COM firing increases due to the
fuel tax on the oil which is used to prepare the mixture, coal comprises a
significant fraction (50 percent by weight) of the fuel. As a result, COM
costs only increase 25 percent as compared to nearly 50 percent for residual
oil. In addition, the capital cost of converting to COM firing is reduced
by the investment credit.
The cost of converting to both medium-Btu gas and coal-based liquid
fuel are not changed significantly. This is due to the fact that these
fuels are produced in a large central facility which is not eligible for
an investment credit.
The annual costs presented in Table 5-18 indicate that the NEP can have
a significant impact on the cost of firing various fuels in an existing 44 MW
(150 x 106 Btu/hr) residual oil fired boiler. The minimum impact of the tax
will make both coal and COM firing economically attractive. The most prob-
able result of this will be that if a boiler is ready to be retired, it will
be replaced with a low-sulfur, coal-fired unit. And, if COM firing becomes a
developed technology, there will be a definite economic incentive for its use.
158
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TABLE 5-18. RANGE OF POTENTIAL IMPACT FROM THE FUEL TAX/IN VESTMENT CREDIT PROGRAM ON THE ANNUAL
COSTS OF A 44 MW RESIDUAL OIL FIRED BOILER1'2
Ln
Fuel Switch
Annual Cost ($/yr)
Minimum Fuel Tax
No Investment Credit
1985 1990
None
Residual
Residual
Residual
Residual
Residual
Residual
Residual
Residual
Residual
oil
oil
oil
oil
oil
oil
oil
oil
oil
to
to
to
to
to
to
to
to
to
low-Btu gas
medium-Btu gas
COM 1
COM 2
COM 3
coal based liquid fuel
high-sulfur coal
low-sulfur eastern coal
low-sulfur western coal
2.82
5.05
4.28
2.60
2.80
2.60
6.40
3.77
3.29
2.47
x 106
x 106
x 10s
x 106
x 106
x 10s
x 106
x 106
xlO6
x 106
3.97
7.07
5.94
3.66
3.86
3.56
8.92
5.21
4.62
3.40
x 10s
x 106
x 10s
x 106
x 106
x 10s
x 106
x 106
x 106
x 106
Maximum Fuel Tax
Maximum Investment Credit
1985 1990
3.42
3.42
4.14
3.06
3.16
2.96
6.09
2.75
2.52
1.70
x 10s
x 106
x 106
x 10s
x 10s
x 10s
x 10s
x 106
x 106
x 10s
4.77
4.72
5.75
4.20
4.40
4.20
8.48
3.82
3.59
2.37
x 10s
x 10s
x 106
x 10s
x 106
x 106
x 10s
x 10s
xlO6
x 10s
1See Appendices E and F for details.
2Includes the cost of pollution control.
-------
The maximum impact of the fuel tax/investment credit program will be
to make fuel switching from residual oil to coal, COM and low-Btu gas very
attractive from an economic standpoint. Of these fuel switches, conversion
to coal firing via boiler replacement is the most probable scenario. How-
ever, if a firm is unable to raise capital for a new boiler and if the tech-
nology becomes established, a switch to COM firing will occur. Switching
fuels from residual oil to low-Btu gas is attractive but it is the least
likely of the options examined and this scenario will probably only occur
in isolated cases. Switching fuels to either medium-Btu gas or a coal-based
liquid fuel do not appear to be economically attractive options for the 44 MW
(150 x 10s Btu/hr) residual oil fired water tube boiler.
5.5 EXPECTED FUEL SWITCHES
Estimation of the number and type of fuel switching which will occur
in existing industrial boilers is a complex problem. Fuel switching is
influenced by many factors including energy regulations, environmental con-
siderations, costs, fuel availability, boiler characteristics, boiler loca-
tion, plant size, etc. The impact of energy regulations, environmental
considerations, and costs have been examined for the following boilers:
1) 4.4 MW (15 x 10s Btu/hr) natural gas-fired, fire tube boiler
2) 4.4 MW (15 x 106 Btu/hr) distillate oil-fired, fire tube boiler
3) 44 MW (150 x 10s Btu/hr) residual oil-fired, water tube boiler
However, data are not available to permit a detailed examination of some
of the other factors which can influence fuel switching. As a result, an
estimate can be made of the expected, or most probable, fuel switches under
a specific set of conditions. But, the number of boilers which will switch
fuels by a particular method cannot be determined. Quantification of fuel
switching requires site specific data which are not available.
160
-------
This section identifies the fuel switches which are expected to occur
in the three standard boilers. The expected fuel switches are identified
under the following four sets of conditions:
1) No regulations apply to boiler.
2) Boiler must comply with "typical" state regulations by addition
of pollution control equipment.
3) Boiler must comply with "typical" state regulations and the
minimum impact of the fuel tax/investment credit program on
annual costs is estimated.
4) Boiler must comply with "typical" state regulations and the
maximum impact of the fuel tax/investment credit program on
annual costs is estimated.
In addition, to identify expected fuel switches, this section estimates the
design parameters for the three standard boilers after fuel switching.
5.5.1 4.4 MW Natural Gas-Fired, Fire Tube Boiler
The annual costs associated with fuel switching in a 4.4 MW (15 x 106
Btu/hr) natural gas fired, fire tube boiler were estimated for four sets of
conditions. Based on these estimates, the expected fuel switches were deter-
mined and are presented in Table 5-19. As shown, the natural gas-fired
boiler is not expected to switch fuels. However, if any fuel switch will
take place, distillate oil and medium-Btu gas are the most probable choices.
A switch to low-sulfur western coal is also likely where the fuel tax/
investment credit program has maximum impact. However, these fuel switches
will not occur unless a serious natural gas supply problem is encountered
and the industrial boiler operator incurs a cost penalty as a result of
supply interruptions.
Table 5-20 presents estimated values for the design parameters of the
4.4 MW (15 x 106 Btu/hr) natural gas-fired boiler after switching fuels to
distillate oil, medium-Btu gas, and low-sulfur coal. Pollutant rates are
161
-------
for uncontrolled emissions. The values presented in Table 5-20 are based on
the information which is contained in Section 4.0 of this report and on the
design parameters for standard boilers prepared by PEDCo Environmental
Specialists Inc. (PE-348).
TABLE 5-19. EXPECTED FUEL SWITCHES FOR A 4.4 MW NATURAL GAS-FIRED BOILER
Rank1
1st
2nd
3rd
No
Regulations
None
Distillate
oil
Medium-Btu
gas
Typical State
Regulations
None
Distillate
oil
Medium-Btu
gas
Basis
Minimum Impact
of NEP
None
Distillate
oil
Medium-Btu gas
Maximum Impact
of NEP
None
Medium-Btu
gas
Low -sulfur
western coal
1The rank is based on the annual costs in Tables 5-10, 5-11, and 5-12.
5.5.2 4.4 MW Distillate Oil Fired. Fire Tube Boiler
The annual costs associated with fuel switching in a 4.4 MW (15 x 10
Btu/hr) distillate oil-fired, fire tube boiler were estimated for four sets
of conditions. Based on these estimates, the expected fuel switches were
identified and are presented in Table 5-21. As shown, the distillate oil
fired boiler should not switch fuels except under the maximum Impact of the
fuel tax/investment credit portion of the National Energy Plan. Under maxi-
mum Impact of the NEP, a switch to medlum-Btu gas is expected based on costs.
However, only a small fraction of existing boilers will switch to medlum-Btu
gas. This is because a limited supply of medium-Btu gas is projected through
the year 2000.
Table 5-21 indicates that under the conditions of no regulations,
typical state regulations, and minimum Impact of the National Energy Plan,
162
-------
TABLE 5-20. DESIGN PARAMETERS FOR A 4.4 MW NATURAL GAS FIRED BOILER
AFTER SWITCHING FUELS1
Design Paras*Mr
Capacity
(WO
UO'Btu/hr)
Foal Analysta
X Sulfur
Z Ash
HOT
E»caas Air («)
Floa CM Flo» Bate
(••Vhr)
)
Flue Gas Vastteratun
CO
CF)
load Factor (X)
Batsslon Bata*
parttcnlataa
aolfur dioxide
nlttttgvn oxide* mm M0|
carbon •moxldc
hydrocarbmc aa CT>
Distillate Oil Fired.
Fir* Tube Boiler
4.4
IS
0,5
Trace
M.8 (HI /I)
139.000 (Btu/KiQ)
IS
5160
5000
177
350
45
(kR/hr) «b/hr)
0.14 0.315
3.34 7.35
1.36 3.00
0.15 0.54
0.05 0.11
Medina Btn Cas Fired.
Fire Tube Boiler
4.4
15
Trace
Trace
11.2 (HJ/« )
300 (Btu/acf)
IS
4640
4500
177
350
45
(kg/hr) (Ib/hr)
0.023 0.05
0.004 0.01
0.341-1.02 0.75-2.25
0.117 0.26
0.02 0.045
Uw Sulfur Coal Stoker Fired.
ttetrr Tube Boiler*
4.4
15
0.6
5.4
22.370 (kJ/ke.)
9.600 (Btu/lb)
50
6450
6250
177
350
45
(kg/hr)
-------
the second and third most probable fuel switches are to medium-Btu gas firing
and low-sulfur western coal-firing, respectively. Under the maximum impact
of the NEP, low-sulfur western coal is the second most likely fuel switch.
No fuel switching is expected for the first three cases, but if the supply
of distillate oil to the boiler becomes unsure, some switching may occur.
A limited number of boilers will switch to medium-Btu gas and some may switch
to low-sulfur western coal by boiler replacement.
TABLE 5-21. EXPECTED FUEL SWITCHES FOR A 4.4 MW DISTILLATE OIL FIRED BOILER
Rank1 Basis
No Typical State Minimum Impact Maximum Impact
Regulations Regulations of NEP of NEP
1st None None None Medium-Btu gas
2nd Medium-Btu Medium-Btu Medium-Btu gas None
gas gas
3rd Low-sulfur Low-sulfur Low-sulfur Low-sulfur
western coal western coal western coal western coal
*The rank is based on the annual costs in Tables 5-13, 5-14, and 5-15.
Table 5-22 presents estimated values for the design parameters of the
4.4 MW (15 x 10s Btu/hr) distillate oil-fired boiler after switching fuels
to medium-Btu gas and low-sulfur western coal. Pollutant rates are for
uncontrolled emissions. The values presented in Table 5-22 are based on
information contained in Section 4.0 of this report and PEDCo's "Design
Parameters For Standard Boilers" (PE-348).
5.5.3 44 MW Residual Oil-Fired, Water Tube Boiler
The annual costs associated with fuel switching in a 44 MW (150 x 106
Btu/hr), residual oil-fired, water tube boiler were estimated for four sets
of conditions. Based on these estimates, the expected fuel switches were
164
-------
TABLE 5-22. DESIGN PARAMETERS FOR A 4.4 MW DISTILLATE OIL FIRED
BOILER AFTER SWITCHING FUELS1
ON
Design Parameter
Capacity
(MH)
(10*Btu/hr)
Fuel Analysis
Z Sulfur
Z Ash
HHV
Excess Air Z
Flue Gas flow Rate
(H»'/hr)
(acfm)
Flue Gas Temperature
(*C)
CP)
Load Factor Z
Emission Rate1
part leu la tea
sulfur dioxide
nitrogen oxides as NOj
carbon monoxide
hydrocarbons as C1U
Hedlum-Btu Gas Fired.
Fire Tube Boiler
3.7
12.8
Trace
Trace
11.2 (Hi/in')
300 (Btu/scf)
15
3945
3825
177
350
45
(kg/hr) (Ib/hr)
0.02 0.04
0.003 0.009
0.29-0.87 0.64-1.91
0.10 0.22
0.017 0.038
Low-Sulfur Coal Stoker Firrd.
Water Tube Boiler'
4.4
15
0.6
5.4
22,370 (kJ/kg)
9.600 (Btu/lb)
50
6450
6250
177
350
45
(kg/hr) (Ib/hr)
9.59 21.1
6.00 13.2
2.45 5.4
0.75 1.66
0.35 0.78
'The Information In this table is based on data presented In Section 4.0.
2Assumes underfeed stoker (Source: PE-348).
'Uncontrolled.
-------
identified and are presented in Table 5-23. As shown, the residual oil
fired boiler is expected to switch fuels under all the conditions examined.
For the case where no regulatory impact is included in the annual cost esti-
mates, the following five fuel switching scenarios are economically competi-
tive with residual oil firing.
1) Residual oil to low-sulfur western coal firing
2) Residual oil to COM 1 firing
3) Residual oil to COM 2 firing
4) Residual oil to COM 3 firing
5) Residual oil to high-sulfur coal firing
The annual costs associated with each of these scenarios are approximately
equal to or lower than the cost of continuing to fire residual oil.
TABLE 5-23. EXPECTED FUEL SWITCHES FOR A 44 MW RESIDUAL OIL FIRED BOILER
Rank1
No
Regulations
Basis
Typical State Minimum Impact Maximum Impact
Regulations of NEP of NEP
1st Low-sulfur
western coal
Low-sulfur
western coal
Low-sulfur
western coal
Low-sulfur
western coal
2nd
COM 1, COM 3 COM 1, COM 3
COM 1, COM 3
Low-sulfur
eastern coal
3rd COM 2, high-
sulfur coal
COM 2
COM 2
High-sulfur
coal
4th
None
None
None
COM 1, COM 2,
COM 3
1The rank is based on the annual costs in Tables 5-16, 5-17, and 5-18.
For the cases in which typical state regulations and the maximum impact
of the NEP are included in annual costs, the first four fuel switching sce-
narios listed above are the most likely to occur. Again, the annual costs
166
-------
for each of these scenarios are equal to or less than the cost of continuing
to fire residual oil. For the case in which the maximum impact of the NEP
is included in the annual costs, the most probable fuel switch is to low-
sulfur western coal firing. The second most likely switch is to low-sulfur
eastern coal while the other alternatives are either high-sulfur coal firing
or coal-oil mixture firing.
The expected fuel switches presented in Table 5-23 all have annual
costs which are competitive with the cost of continuing to fire residual
oil. However, this does not mean that the boilers which currently fire
residual oil will begin switching fuels. Additional factors which are not
included in the cost estimates that form the basis for Table 5-23 must be
considered. For conversion to coal firing, the availability of space at
the plant site is a key factor. In addition, the price of coal on which
the expected fuel switches are based represent minemouth costs and they
are probably not typical of fuel costs to industrial users. For conversion
to COM firing, the status of development of the technology must be consid-
ered. It is unlikely that this technology will be used extensively by indus-
try until the reliability of COM firing is demonstrated. Because of these
considerations, it does not appear that existing residual oil fired boilers
will switch fuels extensively and the fuel switching method which is most
likely to be employed is coal firing by boiler replacement.
Table 5-24 presents estimated values for the design parameters of the
44 MW (150 x 106 Btu/hr) residual oil fired boiler after switching fuel to
three coal-oil mixtures, and high- and low-sulfur coals. Pollutant rates
are for uncontrolled emissions. The values presented in Table 5-24 are
based on information contained in Section 4 of this report, and in PEDCo's
"Design Parameters For Standard Boilers" (PE-348).
167
-------
TABLE 5-2A. DESIGN PARAMETERS FOR A 44 MW RESIDUAL OIL FIRED BOILER AFTER SWITCHING FUELS1
00
Design Parameter
Capacity
(MH)
UO'Blu/hr)
Fuel_Anal ys Is
Z Sulfur
Z Ash
imv
Excess Air Z
Flue Gas Flow Rate
(Nm'/hr)
(acfm)
Flue Gas Temperature
CC)
CF)
Load Factor Z
Emission Rate*
particulars
aul fur dioxide
nitrogen oxides as NOj
carbon monoxide
hydrocarbons as CH«
COM 1 Fired,
Water Tube Bnl lor
44
150
3.25
5.35
35,900 (kJ/kg)
15,400 (Btu/lb)
32.5
54,330
54,270
190
375
55
(kn/hr) (Ib/hr)
171.82 378.0
237.27 522.0
30.68 67.5
2.51 5.52
0.61 1.35
COM 2 Fired,
Wafer Tube Bollpr
44
ISO
1.95
1.50
38.200 (kJ/kg)
16,400 (Rtu/lti)
32.5
53,980
53,920
190
375
55
(kg/hr) (Ib/hr)
106.36 234.0
149.32 128.5
30.68 67.5
2.36 5.19
0.58 1.27
COM 3 Fired,
Water Tube Holler
44
150
1.80
2.25
33,300 (kJ/kg)
14.100 (Btu/lb)
32.5
52,510
52,450
190
375
55
(kg/hr) (Ib/hr)
96.14 211.5
161.59 355.5
30.68 67.5
2.70 5.94
0.66 1.45
Illgh-Sul fur Conl
Stoker Fired,
Water Tube Roller'
44
150
3.5
10.6
27,500 (kJ/kg)
11,800 (Btn/hr)
50
66,870
64 . 800
177
350
55
(kg/hr) (Ib/hr)
172.22 378.88
404.73 890.40
39.61 87.15
5.78 12.72
2.90 6.17
I.ow-Sul fur
F.aslcrn Conl
Stoker Fired,
Wnler Tube Bo 1 Icr'
44
150
0.9
6.9
32,150 (k.I/kg)
13,800 (Btu/lb)
50
62,750
60,800
177
350
55
(kg/hr) (Ib/hr)
95.71 210.56
88.85 195.48
39.61 87.15
4.94 10.86
2.47 5.43
Low* Sit 1 fur
WPS I. -MI Cn.il
St'ikrr Ktrril,
W.-H IT Tnhi> Knl li'l
'>!<
ISII
0.6
5.4
22.170 (k.I/kg)
9,600 (Rtu/ll.)
50
64, RIO
62,800
177
350
55
(kg/hr) (Ib/lir)
107.77 237.02
85.18 187.40
39.61 87.15
7.10 15.62
3.55 7.80
The Information In this table Is based on data presented In Section 4.0.
'Assumes fl spreader stoker (Source: PE-348).
'Uncontrolled.
-------
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172
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TECHNICAL REPORT DATA
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